Part 1.
RAILROAD COMMISSION OF TEXAS
Chapter 3.
OIL AND GAS DIVISION
16 TAC §3.14
The Railroad Commission of Texas (Commission) proposes amendments
to §3.14, relating to Plugging. The Commission proposes these amendments
as a result of changes to Texas Natural Resources Code, §89.011, made
by Senate Bill 310, 77th Legislature (2001), which became effective September
1, 2001. The Commission also proposes other amendments to allow for Commission
approval of variances to certain requirements of the rule and for clarification
purposes.
Senate Bill 310 amended §89.011 of the Texas Natural Resources Code
to require that an operator plugging a well after September 1, 2001, verify
the placement of the plug at the base of the deepest fresh water zone required
to be protected, if usable quality water zones are present. The well is considered
to have been properly plugged only when such verification is satisfactory
and meets Commission requirements. The Commission has been enforcing this
statutory requirement since September 1, 2001, and now proposes to amend §3.14
to incorporate this statutory requirement.
Statutory amendments to §89.011, Texas Natural Resources Code, also
established that the duty of an operator to properly plug a well that is being
plugged back to produce fresh water for the use of the landowner ends only
when the well has been properly plugged in accordance with Commission requirements,
and the surface owner has obtained a permit for the well from the groundwater
conservation district, if applicable. The Commission proposes to amend §3.14(a)(4)
to state that the Commission will consider an application for a landowner
to condition an abandoned well for fresh water production only if the landowner
submits a signed statement attesting that one of the following four facts
exists: there is no groundwater conservation district for the area in which
the well is located; there is a groundwater conservation district for the
area where the well is located, but the groundwater conservation district
does not require that the well be permitted or registered; the landowner has
registered the well with the groundwater conservation district for the area
where the well is located; or the landowner has obtained a permit from the
groundwater conservation district for the area where the well is located.
In addition, the Commission proposes to add language regarding the requirement
that the duty of the operator to properly plug the well ends only when the
well has been properly plugged in accordance with Commission requirements
up to the base of usable quality water stratum; the Commission has approved
the application to condition the well for usable quality water production
operations; and the surface owner has registered the well with, or has obtained
a permit for the well from, the groundwater conservation district, if applicable.
Because the "permitting" requirements of the various groundwater conservation
districts are not uniform, the Commission's proposed language reflects the
fact that the groundwater conservation districts require a permit for water
wells, require registration of water wells, or neither. Information concerning
the various groundwater conservation districts can be found at www.texasgroundwater.org.
The Commission proposes to delete or modify some of the definitions currently
contained in §3.14(a)(1) and add new definitions. The Commission proposes
to add definitions for "approved cementer," "groundwater conservation district,"
and "related piping" for the purpose of clarification. The Commission also
proposes to delete the definitions for "bay well," "offshore well," and "land
well," because these terms are used nowhere else in this rule. These terms,
however, are defined and used in §3.78 of this title (relating to Fees,
Performance Bonds and Alternate Forms of Financial Security Required To Be
Filed). The Commission proposes to amend the definition of "usable quality
water strata" to reflect the fact that the Texas Natural Resource Conservation
Commission is now the Texas Commission on Environmental Quality. The Commission
also proposes to amend the definition of "To serve surface notice" to make
the rule language and forms consistent.
Throughout the section, the Commission proposes to amend language to clarify
which Commission personnel have the authority to grant the various necessary
approvals. In addition, the Commission proposes to change the term "assistant
director of well plugging" to "deputy director of field operations" to reflect
the correct title.
In §3.14(a)(3), the Commission proposes to add a clarifying statement
that the Commission's approval of a notice of intent to plug and abandon a
well does not relieve an operator of the requirement to comply with the requirements
in subsection (b)(2) to plug the well, produce the well, or obtain an extension
to plug the well, test the well, or obtain financial assurance for the well.
In §3.14(b)(2)(A), the Commission proposes to correct a citation in
subclause (V).
The Commission proposes to amend §3.14(b)(2)(E), to clarify that inactive,
bonded wells that are over 25 years old must be tested to determine whether
the well poses a potential threat of harm to natural resources.
In §3.14(b)(4)(A), the Commission proposes to clarify that the Commission
may plug or replug any dry or inactive well, after notice and opportunity
for hearing, if any formation fluid is leaking from the well, not just oil
or gas.
In §3.14(d)(2), the Commission proposes to incorporate the statutory
requirement from Senate Bill 310 to require that the operator verify the placement
of the plug required at the base of the usable quality water stratum by tagging
the plug with tubing or drill pipe or by an alternate method approved by the
district director or the district director's delegate. In addition, the Commission
proposes to add to this paragraph language to clarify the current requirement
that plugs be set as necessary to separate multiple usable quality water strata.
The Commission also proposes to amend §3.14(d)(4) to include language
providing for approval of plugging materials other than cement. The Commission
proposes to require that any such request be submitted in writing to the deputy
director of field operations in Austin and include all pertinent information
to support such a request. The Commission proposes as the overall standard
for approval of a request to use alternate plugging material, that the alternate
plugging material and method will insure that the well does not pose a potential
threat of harm to natural resources.
Section 3.14(d)(9) currently requires the use of a mud-laden fluid with
specific characteristics during plugging. In response to requests from a member
of the Oil Field Cleanup Advisory Committee, the Commission proposes to allow
for approval of requests for the use of alternate fluids between plugs.
In §3.14(d)(10), the Commission proposes to make a conforming amendment
to delete the reference to §3.94, relating to Disposal of Oil and Gas
NORM Waste, which was repealed by the Commission on February 11, 2003, and
replace it with a reference to new §4.614(b) relating to Authorized Disposal
Methods, which the Commission adopted on that same date. The effective date
of new §4.614 is March 3, 2003.
The Commission has received comment that the current language in §3.14(d)(12)
is confusing because it could be read to imply that all surface and subsurface
piping on a lease or other facility must be removed after plugging. The Commission
proposes to amend the language in §3.14(a)(1)(J) and (d)(12), to clarify
that only related surface and subsurface piping that is less than three feet
beneath the ground surface must be removed within 120 days after plugging
work is complete.
Finally, the Commission proposes to amend the language in subsections (e),
(f), and (g) to clarify the placement and minimum length for plugs required
with respect to usable quality water strata.
Leslie Savage, Oil and Gas Division planner, has determined that for each
year of the first five years the amendments as proposed will be in effect,
there will be minimal fiscal implications to state government as a result
of enforcing or administering the amendments. The Commission is currently
enforcing the requirement to tag the plug at the base of the deepest usable
quality water zone. Although some Commission staff time will be necessary
to evaluate requests for variances to the requirements for plugging materials
and other fluids used during plugging, this time will be balanced by the time
Commission staff will save not having to explain many of the parts of the
current rule clarified in this rulemaking. There are no fiscal implications
for local governments.
The cost of compliance with the amendments for the individual, small business,
or micro-business operator will vary according to the number of the operator's
wells, but the Commission does not believe that the amendments will result
in any additional cost. In fact, the Commission believes that operators may
actually save money when the Commission is able to approve plugging of wells
with alternative materials as provided for in this proposed rulemaking.
David Cooney, Assistant Director, Environmental Section, Office of General
Counsel, has determined that for each year of the first five years that the
amendments will be in effect, there will be a public benefit in that the possibility
of pollution of surface or subsurface water will be lessened by clearer regulations.
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
. 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 Mr. Cooney at (512) 463-6977. The status of Commission rulemakings
in progress is available at www.rrc.state.tx.us/rules/proposed.html.
The Commission proposes amendments to §3.14 pursuant to
Texas Natural Resources Code, §§81.051 and 81.052, which provide
the Commission with jurisdiction over all persons owning or engaged in drilling
or operating oil or gas wells in Texas and the authority to adopt all necessary
rules for governing and regulating persons and their operations under Commission
jurisdiction and pursuant to Texas Natural Resources Code §§85.202(a)
and 91.101(a)(3) which require the Commission to adopt rules requiring the
proper plugging of wells, preventing injury to adjoining property, preventing
pollution of surface and subsurface water, and confining oil, gas, and water
to the strata in which they are found; and §89.011, which requires an
operator to verify the placement of a plug at the base of the deepest freshwater
zone required to be protected.
Cross-reference to statute: Texas Natural Resources Code, §§81.051,
81.052, 85.202(a)(2), 85.2021(c), 89.011, 91.101(3), and 91.103-91.107.
Issued in Austin, Texas, on February 25, 2003.
§3.14.Plugging.
(a)
Definitions and application to plug.
(1)
The following words and terms, when used in this section,
shall have the following meanings, unless the context clearly indicates otherwise:
(A)
(No change.)
(B)
Approved cementer--A cementing
company, service company, or operator approved by the Commission to mix and
pump cement for the purpose of plugging a well in accordance with the provisions
of this section. The term shall also apply to a cementing company, service
company, or operator authorized by the Commission to use an alternate material
other than cement to plug a well.
[
[
[
(C) - (E)
(No change.)
(F)
Groundwater conservation district--Any
district or authority created under §52, Article III, or §59, Article
XVI, Texas Constitution, that has the authority to regulate the spacing of
water wells, the production from water wells, or both.
(G)
[
(i)
on a Commission-approved form;
(ii)
by a third party surety, insurance company, or financial
institution approved by the Commission; and
(iii)
to secure the timely and proper plugging of a specified
well and remediation of the wellsite in accordance with Commission rules.
[
[
(H)
[
(I)
[
(J)
Related piping--The surface
piping and subsurface piping that is less than three feet beneath the ground
surface between pieces of equipment located at any collection or treatment
location. Such piping would include piping between and among headers, manifolds,
separators, storage tanks, gun barrels, heater treaters, dehydrators, and
any other equipment located at a collection or treatment location. The term
is not intended to refer to lines, such as flowlines, gathering lines, and
injection lines that lead up to and away from any such collection or treatment
location.
(K)
(No change.)
(L)
To serve [
(M)
(No change.)
(N)
Usable quality water strata--All strata determined by the
Texas [
(O)
(No change.)
(2)
(No change.)
(3)
The operator shall cause the notice of its intention to
plug to be delivered to the district office at least five days prior to the
beginning of plugging operations. The notice shall set out the proposed plugging
procedure as well as the complete casing record. The operator shall not commence
the work of plugging the well or wells until the proposed procedure has been
approved by the district
director or the director's delegate
[
(4)
The landowner and the operator
may file an application to condition an abandoned well located on the landowner's
tract for usable quality water production operations. The application shall
be made on the form prescribed by the Commission, the Application of Landowner
to Condition an Abandoned Well for Fresh Water Production.
(A)
Standard for Commission Approval. Before the
Commission will consider approval of an application:
(i)
the landowner shall assume responsibility for
plugging the well and obligate himself, his heirs, successors, and assignees
to complete the plugging operations;
(ii)
the operator responsible for plugging the well
shall place all cement plugs required by this rule up to the base of the usable
quality water strata; and
(iii)
the landowner shall submit:
(I)
a signed statement attesting to the fact that:
(-a-)
there is no groundwater conservation district
for the area in which the well is located; or
(-b-)
there is a groundwater conservation district
for the area where the well is located, but the groundwater conservation district
does not require that the well be permitted or registered; or
(-c-)
the landowner has registered the well with
the groundwater conservation district for the area where the well is located;
or
(II)
a copy of the permit from the groundwater conservation
district for the area where the well is located.
(B)
The duty of the operator to
properly plug ends only when:
(i)
the operator has properly plugged the well in
accordance with Commission requirements up to the base of the usable quality
water stratum;
(ii)
the landowner has registered the well with,
or has obtained a permit for the well from, the groundwater conservation district,
if applicable; and
(iii)
the Commission has approved the application
of landowner to condition an abandoned well for fresh water production.
[
(5)
The operator of a well shall serve [
(b)
Commencement of plugging operations and extensions.
(1)
(No change.)
(2)
Plugging operations on each dry or inactive well shall
be commenced within a period of one year after drilling or operations cease
and shall proceed with due diligence until completed. Plugging operations
on delinquent inactive wells shall be commenced immediately unless the well
is restored to active operation. For good cause, a reasonable extension of
time in which to start the plugging operations may be granted pursuant to
the following procedures.
(A)
Wells that have been inactive for less than 36 months.
(i)
The Commission or its delegate may administratively grant
an extension of up to one year of the deadline for plugging a well that is
operated by an unbonded operator and has been inactive, without a return to
active operation, for a period of less than 36 months if the following criteria
are met:
(I) - (IV)
(No change.)
(V)
The operator has tested the well in accordance with the
provisions of subparagraph (E) of this
paragraph
[
(-a-) - (-b-)
(No change.)
(VI)
(No change.)
(ii)
A plugging extension granted under this subparagraph may
not extend the period of inactivity beyond 36 months.
(B) - (D)
(No change.)
(E)
The operator of any well more than 25 years old that becomes
inactive and subject to the provisions of this paragraph
or
[
(i)
In general, a fluid level test is a sufficient test for
purposes of this subparagraph. The operator
shall
[
(ii)
No test other than a fluid level test shall be acceptable
without prior approval from the district
director or the director's delegate
[
(iii)
Notwithstanding the provisions of clause (ii) of this
subparagraph, a hydraulic pressure test may be conducted without prior approval
from the district
director or the director's delegate
[
(iv) - (v)
(No change.)
(3)
(No change.)
(4)
The Commission may plug or replug any dry or inactive well
as follows:
(A)
After notice and hearing, if the well is causing or is
likely to cause the pollution of surface or subsurface water or if oil
,
[
(i)
Neither the operator nor any other entity responsible for
plugging the well can be found; or
(ii)
Neither the operator nor any other entity responsible
for plugging the well has assets with which to plug the well.
(B) - (C)
(No change.)
(5)
(No change.)
(c)
(No change.)
(d)
General plugging requirements.
(1)
(No change.)
(2)
Cement plugs shall be set to isolate each productive horizon
and usable quality water strata.
Plugs shall be set as necessary to separate
multiple usable quality water strata by placing the required plug at each
depth as determined by the Texas Commission on Environmental Quality or its
successor agencies. The operator shall verify the placement of the plug required
at the base of the deepest usable quality water stratum by tagging with tubing
or drill pipe or by an alternate method approved by the district director
or the district director's delegate.
(3)
(No change.)
(4)
All cement for plugging shall be an approved API oil well
cement without volume extenders and shall be mixed in accordance with API
standards. Slurry weights shall be reported on the cementing report. The district
director or the director's delegate may require that specific cement compositions
be used in special situations; for example, when high temperature, salt section,
or highly corrosive sections are present.
An operator shall request approval
to use alternate materials other than cement to plug a well by filing with
the deputy director of field operations or the director's delegate a written
request providing all pertinent information to support the use of the proposed
alternate material and plugging method. The deputy director of field operations
shall determine whether such a request warrants approval, and shall approve
such a request only if the proposed alternate material and plugging method
will insure that the well does not pose a potential threat of harm to natural
resources.
(5)
Operators shall use only cementers approved by the
deputy director of field operations
[
(A)
A cementing company, service company, or operator seeking
designation as an approved cementer shall file a request in writing with the
district director of the district in which it proposes to conduct its initial
plugging operations. The request shall contain the following information:
(i) - (iii)
(No change.)
(iv)
an inventory of the type of equipment to be used to mix
and pump cement
or other alternate materials as approved by the deputy
director of field operations or the director's delegate
; and
(v)
(No change.)
(B)
No request for designation as an approved cementer will
be approved until after the district director or the director's delegate has:
(i)
inspected all equipment to be used for mixing and pumping
cement
or other alternate materials as approved by the deputy director
of field operations or the director's delegate
; and
(ii)
witnessed at least one plugging operation to determine
if the cementing company, service company, or operator can properly mix and
pump cement
or other alternate materials as approved by the deputy director
of field operations or the director's delegate according
to the specifications
required by this rule.
(C)
The district director or the director's delegate shall
file a letter with the
deputy director of field operations or the director's
delegate
[
(D)
Designation as an approved cementer may be suspended or
revoked for violations of Commission rules. The designation may be revoked
or suspended administratively by the
deputy director of field operations
or the director's delegate
[
(i)
the cementer has been given written notice by personal
service or by registered or certified mail informing the cementer of the proposed
action, the facts or conduct alleged to warrant the proposed action, and of
its right to request a hearing within 10 days to demonstrate compliance with
Commission rules and all requirements for retention of designation as an approved
cementer; and
(ii)
the cementer did not file a written request for a hearing
within 10 days of receipt of the notice.
(6)
An operator may request administrative authority to plug
its own wells without being an approved cementer. An operator seeking such
authority shall file a written request with the district director and demonstrate
its ability to mix and pump cement
or other alternate materials as approved
by the deputy director or the director's delegate
in compliance with
this subsection. The district director or the director's delegate
shall
[
(7)
The district director
or the director's delegate
may
require additional cement plugs to cover and contain any productive horizon
or to separate any water stratum from any other water stratum if the water
qualities or hydrostatic pressures differ sufficiently to justify separation.
The tagging and/or pressure testing of any such plugs, or any other plugs,
and respotting may be required if necessary to insure that the well does not
pose a potential threat of harm to natural resources.
(8)
(No change.)
(9)
Mud-laden fluid of at least 9-1/2 pounds per gallon with
a minimum funnel viscosity of 40 seconds shall be placed in all portions of
the well not filled with cement
or other alternate material as approved
by the deputy director of field operations or the director's delegate
.
The hole shall be in static condition at the time the cement plugs are placed.
The district director
or the director's delegate
may grant exceptions
to the requirements of this paragraph if a deviation from the prescribed minimums
for fluid weight or viscosity
will
[
(10)
Non-drillable material that would hamper or prevent reentry
of a well shall not be placed in any wellbore during plugging operations,
except in the case of a well plugged and abandoned under the provisions of §3.35
or
§4.614(b)
[
(11)
(No change.)
(12)
The operator shall fill the rathole, mouse hole, and cellar,
and shall empty all tanks, vessels, related piping and flowlines that will
not be actively used in the continuing operation of the lease within 120 days
after plugging work is completed. Within the same 120 day period, the operator
shall remove all such tanks, vessels,
and
related [
(e)
Plugging requirements for wells with surface casing.
(1)
When insufficient surface casing is set to protect all
usable quality water strata and such usable quality water strata are exposed
to the wellbore when production or intermediate casing is pulled from the
well or as a result of such casing not being run, a cement plug shall
be a minimum of 100 feet in length and shall extend at least 50 feet above
and
[
(2)
When sufficient surface casing has been set to protect
all usable quality water strata, a cement plug shall be placed across the
shoe of the surface casing. This plug shall be a minimum of 100 feet in length
and shall extend at least 50 feet above the shoe and at least 50 feet below
the shoe.
(3)
If surface casing has been set deeper than 200 feet below
the base of the deepest usable quality water stratum, an additional cement
plug shall be placed inside the surface casing across the base of the deepest
usable quality water stratum. This plug shall be a minimum of 100 feet in
length and shall extend
at least
[
(4)
Plugs shall be set as necessary
to separate multiple usable quality water strata by placing the required plug
at each depth as determined by the Texas Commission on Environmental Quality
or its successor agencies.
(f)
Plugging requirements for wells with intermediate casing.
(1)
For wells in which the intermediate casing has been cemented
through all usable quality water strata and all productive horizons, a cement
plug meeting the requirements of subsection (d) (11) of this section shall
be placed inside the casing and centered opposite the base of the deepest
usable quality water stratum, but extend no less than 50 feet above and below
the
base of the deepest usable quality water
stratum.
(2)
(No change.)
(3)
Plugs shall be set as necessary
to separate multiple usable quality water strata by placing the required plug
at each depth as determined by the Texas Commission on Environmental Quality
or its successor agencies.
(g)
Plugging requirements for wells with production casing.
(1)
For wells in which the production casing has been cemented
through all usable quality water strata and all productive horizons, a cement
plug meeting the requirements of subsection (d) (11) of this section shall
be placed inside the casing and centered opposite the base of the deepest
usable quality water stratum and across any multi-stage cementing tool.
This plug shall be a minimum of 100 feet in length and shall extend at least
50 feet below and 50 feet above the base of the deepest usable quality water
stratum.
(2)
(No change.)
(3)
The district director
or the director's delegate
may
approve a cast iron bridge plug to be placed immediately above each perforated
interval, provided at least 20 feet of cement is placed on top of each bridge
plug. A bridge plug shall not be set in any well at a depth where the pressure
or temperature exceeds the ratings recommended by the bridge plug manufacturer.
(4)
Plugs shall be set as necessary
to separate multiple usable quality water strata by placing the required plug
at each depth as determined by the Texas Commission on Environmental Quality
or its successor agencies.
(h)
Plugging requirements for well with screen or liner.
(1)
If practical, the screen or liner shall be removed from
the well.
(2)
If the screen or liner is not removed, a cement plug in
accordance with subsection (d)(11) of this section shall be placed at the
top of the
screen or
liner.
(i)
Plugging requirements for wells without production casing
and open-hole completions.
(1)
Any productive horizon or any formation in which a pressure
or formation water problem is known to exist shall be isolated by cement plugs
centered at the top and bottom of the formation. Each cement plug shall have
sufficient slurry volume to fill a calculated height as specified in subsection
(d)(11) of this section.
(2)
If the gross thickness of any such formation is less than
100 feet, the tubing or drill pipe shall be suspended 50 feet below the base
of the formation. Sufficient slurry volume shall be pumped to fill the calculated
height from the bottom of the tubing or drill pipe up to a point at least
50 feet above the top of the formation, plus 10% for each 1,000 feet of depth
from the ground surface to the bottom of the plug.
(j)
The district director
or the director's delegate
shall
review and approve the notification of intention to plug in a manner so as
to accomplish the purposes of this section. The district director
or
the director's delegate
may approve, modify, or reject the operator's
notification of intention to plug. If the proposal is modified or rejected,
the operator may request a review by the
deputy
director of field
operations. If the proposal is not administratively approved, the operator
may request a hearing on the matter. After hearing, the examiner shall recommend
final action by the Commission.
(k)
(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 February 26, 2003.
TRD-200301431
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
Subchapter B. REQUIREMENTS FOR NATURAL GAS AND HAZARDOUS LIQUIDS PIPELINES
16 TAC §8.120
The Railroad Commission of Texas proposes new §8.120,
relating to Notice of New Pipeline Construction Across More Than Three Counties.
The proposed new rule sets forth the requirements of Texas Natural Resources
Code, §81.056, enacted by Senate Bill 310, 77th Legislature (2001).
Proposed new §8.120(a) sets forth the scope of the rule. The rule
applies only to a new pipeline system or the extension of an existing pipeline
system that crosses more than three counties and for which construction began
on or after September 1, 2001. In addition, three terms are defined in this
section. The term "crosses more than three counties" means "crosses four or
more counties." For purposes of this section, the term "construction" means
any activity conducted during the initial construction of a new pipeline or
an extension of an existing pipeline, regardless of ownership of the extension,
including the removal of earth, vegetation, or obstructions along the proposed
pipeline right-of-way. The term does not include surveying or acquiring the
right-of-way; clearing the right-of-way with the consent of the owner; repairing
or maintaining an existing pipeline or pipeline facility; or installing valves
or meters or other devices or fabrications on an existing pipeline if such
devices or fabrication do not result in an increase in the length of the pipeline.
Finally, the term "construction project" means the construction of a new pipeline
system that crosses more than three counties or the construction of an extension
of an existing pipeline system if the extension crosses more than three counties.
Proposed new §8.120(b) requires that at least 30 days but not more
than one year before the start of construction, a pipeline operator must publish
newspaper notice of the construction project in accordance with subsection
(c) of the rule. In addition, no later than the first day of publication,
the operator is required to provide a copy of the information listed in subsection
(c)(1)-(4) to the county judge and commissioners and county clerk of each
county that contains part of the proposed route of the construction project;
the county fire marshal in each county that contains part of the proposed
route of the construction project, if such office has been established by
that county; and the regional water planning group established by Texas Water
Code, §16.053, in each regional water planning area that contains part
of the proposed route of the construction project.
Proposed new §8.120(c) requires that the operator publish notice of
the construction project in a newspaper of general circulation in each county
with a population of 10,000 or more that contains part of the proposed route
of the construction project. In the alternative, the operator may publish
notice of the construction project in a newspaper of general circulation in
each county that contains part of the proposed route of the construction project.
The notice must be published in a section of the newspaper containing news
items of state or local interest. The published notice of the construction
project must be at least three inches by five inches in size, exclusive of
the plat, and must contain the name, business address, and telephone number
of the operator and of the operator's authorized representative, if any; a
narrative description of the geographic location of the construction project;
a plat that includes the location of the construction project, including the
beginning and end points of the construction project, a north arrow, the scale,
geographic subdivisions appropriate for the scale, by inset or otherwise,
landmarks or other features such as roads and highways in relation to the
proposed route of the construction project, and a listing of each federal
and state highway that will be crossed by the construction project; and the
following statement, completed as appropriate for each county that contains
part of the proposed route of the construction project: "A copy of application
forms and a map showing the location of the pipeline construction project
is available for public inspection at the offices of the (name of county)
County Clerk, located at: (the physical address of the County Clerk) and at
the offices of the Railroad Commission of Texas, Gas Services Division, Pipeline
Safety Section, 9th Floor, 1701 North Congress Avenue, Austin, Texas 78701.
Questions about the pipeline construction project should be directed to (name
of pipeline operator or designated contact, mailing address, telephone number,
and, if available, e-mail address). Any person desiring to submit comments
regarding the pipeline construction project that is the subject of the notice
may do so by mailing or otherwise delivering a letter referring to the construction
project (by docket number if available) and any comments to: Gas Services
Division, Pipeline Safety Section, Railroad Commission of Texas, P.O. Box
12967, Austin, Texas 78711-2967. Comments may also be submitted by electronic
mail to pipelinecomments@rrc.state.tx.us. Comments should be submitted to
the Railroad Commission within 30 days of the date this notice is published
in this newspaper."
Proposed new §8.120(d) states the method by which an operator demonstrates
compliance with the requirements of the proposed new section and of Texas
Natural Resources Code, §81.056. Operators must file with the Gas Service
Division, Pipeline Safety Section, proof of publication of notice. This is
done by filing an original publisher's affidavit with the tear sheet attached,
from every newspaper in which notice was published. The tear sheet must include
the printed date of publication. Operators must also file proof of delivery
of notice, by filing an affidavit affirming delivery by hand or by certified
mail, return receipt requested, to each individual required to receive notice,
as shown on a mailing list attached to the affidavit. The attached mailing
list must include the names, addresses, and certified mail receipt numbers
or notations of hand delivery and the date of receipt for the county judge,
the commissioners, and the county clerk of each county that contains part
of the proposed route of the construction project; the county fire marshal
in each county that contains part of the proposed route of the construction
project, if such office has been established by that county; and the regional
water planning group established by Texas Water Code, §16.053, in each
regional water planning area that contains part of the proposed route of the
construction project.
Proposed new §8.120(e) sets forth the procedures by which the Gas
Services Division will review submissions to determine compliance with the
requirements of Texas Natural Resources Code, §81.056, and of the rule.
Within 14 days of receiving documents submitted in compliance with subsection
(d) of the rule, the Pipeline Safety Section assistant director will notify
the operator that the documents are either complete and accepted for filing,
or are incomplete and require specified additional documents.
If the assistant director determines that the documentation of notice is
incomplete, the operator has 30 days, or any longer time that the operator
may request that the assistant director may approve, to complete the documentation.
If the operator does not complete the documentation within the specified time
period, the assistant director will send the operator notice of intent to
dismiss the matter without prejudice. The operator may either submit the required
documentation or request a hearing on the documentation as it exists at that
time. If the operator does not either submit the required documentation or
file a request for hearing, the assistant director will dismiss the matter
without prejudice to refiling and may not approve or issue a permit to operate
(T-4 permit) the construction project that is the subject of the matter being
dismissed. If the operator requests a hearing, then the assistant director
will forward the request for hearing and the file to the Office of General
Counsel for further handling.
Once the assistant director determines that the documentation is complete,
the review must be completed within 30 days. The assistant director will review
the documentation to determine whether the documentation on its face shows
that the construction project that is the subject of the documentation complies
with the applicable statutes and Commission rules. The assistant director
will also review and consider any comments from members of the public about
the construction project that is the subject of the documentation, under Texas
Natural Resources Code, §81.056(c)(2), pertaining to public safety, the
environment, and conservation. Pursuant to Texas Natural Resources Code, §81.056(d),
the assistant director is not to consider comments on matters not within the
jurisdiction of the Commission, such as the finances of the pipeline owner
or operator; nuisance; noise; property values; access; easements; condemnation
proceedings; or aesthetics.
The assistant director will review the published newspaper notice to determine
whether the plat and the narrative portion complied with the requirements
of subsection (c) regarding published notice. The assistant director will
also review the affidavits of publication and of delivery of notice to determine
whether the operator complied with the notice requirements of subsection (b).
Upon completion of the review, the assistant director will prepare a written
recommendation and will forward the recommendation and the file to the Office
of General Counsel. If the assistant director received comments from the public,
the recommendation will also include a statement whether the comments did
or did not pertain to a matter within the jurisdiction of the Commission and
whether the assistant director recommends that a hearing be held with respect
to any of the issues raised by the comments.
Proposed new §8.120(f) provides that the Office of General Counsel
Assistant Director, Gas Services Section, will review the operator's documentation
and the recommendation from the Gas Services Division Assistant Director,
Pipeline Safety Section, to determine whether the operator has complied with
the requirements of subsections (b) and (c) of the rule and with Texas Natural
Resources Code, §81.056. The assistant director will review the recommendation
of the Pipeline Safety Section to determine whether there is a need to conduct
a hearing.
If an operator has requested a hearing or if the Pipeline Safety Section
assistant director recommends that a hearing be conducted, the Office of General
Counsel will handle the matter in accordance with the procedural requirements
of Texas Government Code, Chapter 2001 (the Administrative Procedure Act),
and Chapter 1 of Title 16 of the Texas Administrative Code. If the Gas Services
Section assistant director determines that the operator has substantially
complied in all material respects with the requirements of Texas Natural Resources
Code, §81.056, and with the requirements of this section, and that no
hearing need be conducted, the assistant director will prepare an order certifying
compliance and will present it to the Commission.
Mary McDaniel, assistant director, Gas Services Division, Pipeline Safety
Section, has determined that for each of the first five years the proposed
new section is in effect there will be no fiscal implications for state government
as a result of enforcing or administering this rule. The review of documentation
of notice submitted by operators in compliance with the rule, the preparation
of a recommendation, the handling of any hearings under the rule, and the
preparation of an order for the Commission will be handled by the current
staff and within the current budget. There will be no fiscal implications
for local governments.
Ms. McDaniel has also determined that for each year of the first five years
that the proposed new rule will be in effect, the public benefit will be prior
notice of some pipeline construction projects and an opportunity to ask questions
of the pipeline operator and to submit comments to the Commission regarding
those projects. Not all pipeline construction projects will be subject to
the notice requirements of this rule, and not all aspects of a pipeline construction
project are within the jurisdiction of the Commission.
Pursuant to Texas Government Code, §2006.002(c), Ms. McDaniel has
also estimated that there will be a cost of compliance for pipeline owners
or operators that are small businesses, micro-businesses, or individuals.
Those small business, micro-business, or individual pipeline operators that
begin construction of a new pipeline system or an extension of an existing
pipeline system that crosses more than three counties will be required to
give notice of the construction project. At a minimum this will require publication
of notice in newspapers of general circulation in each county with a population
of more than 10,000 and containing part of the proposed route of the construction
project; this could be only one county, or every county of the proposed route
of the construction project. In addition, small business, micro-business,
or individual pipeline operators with a construction project subject to the
rule will be required to deliver notice to county officials, fire marshals,
and the regional water planning group or groups for a minimum of four counties.
Further, pipeline operators may receive questions from citizens regarding
pipeline construction projects; there is no way to estimate the number or
type of telephone calls, letters, or electronic mail inquiries a pipeline
operator might receive. For any construction project that might be the subject
of a hearing at the Commission, the small business, micro-business, or individual
pipeline operator would incur the expenses associated with attending a hearing
(travel, meals, and lodging) and perhaps with retaining legal counsel and
other experts. Pursuant to Texas Government Code, §2006.002(a), the Commission
has determined that even if there is an adverse economic effect on small businesses
or micro-businesses, considering the purpose of the statute under which the
proposed new rule is to be adopted, it would not be feasible to reduce any
adverse impact on small businesses or micro-businesses. The rule is intended
to state the methods by which pipeline operators may comply with the statutory
notice requirements in Texas Natural Resources Code, §81.056, and any
measure that might reduce an adverse impact on small businesses or micro-businesses
would undermine the effectiveness of the notice requirements in the statute.
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 should refer to Gas Utilities Docket No. 9371. 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 Mary McDaniel
at (512) 463-7058. The status of Commission rulemakings in progress is available
at www.rrc.state.tx.us/rules/proposed.html.
The Commission proposes new §8.120 pursuant to Texas Natural
Resources Code, §81.056, which requires that the Commission, before approving
any permit for the operation of a pipeline, certify that at least 90 days
but no more than one year before the date the commission approves the permit
the person requesting the permit has provided a copy of the application to
the county judge and commissioners of each county that contains part of the
proposed route; the county fire marshal in each county that contains part
of the proposed route, if such office has been established by that county;
and the regional water planning group established by §16.053, Water Code,
in each regional water planning area that contains part of the proposed route;
and to review and consider comments from members of the public regarding the
project that is the subject of the notice; and 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.
Cross-reference to statute: Texas Natural Resources Code, §§81.051,
81.052, and 81.056.
Issued in Austin, Texas, on February 25, 2003.
§8.120.Notice of New Pipeline Construction Across More Than Three Counties.
(a)
Scope and definitions.
(1)
This section sets forth the requirements for compliance
with Texas Natural Resources Code, §81.056, and applies only to a new
pipeline system or the extension of an existing pipeline system that crosses
more than three counties and for which construction began on or after September
1, 2001.
(2)
The term "crosses more than three counties" means "crosses
four or more counties."
(3)
For purposes of this section, the term "construction" means
any activity conducted during the initial construction of a new pipeline or
an extension of an existing pipeline, regardless of ownership of the extension,
including the removal of earth, vegetation, or obstructions along the proposed
pipeline right-of-way. The term does not include:
(A)
surveying or acquiring the right-of-way;
(B)
clearing the right-of-way with the consent of the owner;
(C)
repairing or maintaining an existing pipeline or pipeline
facility; or
(D)
installing valves or meters or other devices or fabrications
on an existing pipeline if such devices or fabrication do not result in an
increase in the length of the pipeline.
(4)
The term "construction project" means the construction
of a new pipeline system that crosses more than three counties or the construction
of an extension of an existing pipeline system if the extension crosses more
than three counties.
(b)
At least 30 days but not more than one year before the
start of construction, a pipeline operator shall publish newspaper notice
of the construction project in accordance with subsection (c) of this section.
In addition, no later than the first day of publication, the operator shall
provide a copy of the information listed in subsection (c)(1)-(4) of this
section to:
(1)
the county judge and commissioners and county clerk of
each county that contains part of the proposed route of the construction project;
(2)
the county fire marshal in each county that contains part
of the proposed route of the construction project, if such office has been
established by that county; and
(3)
the regional water planning group established by Texas
Water Code, §16.053, in each regional water planning area that contains
part of the proposed route of the construction project.
(c)
Publication of notice. The operator shall publish notice
of the construction project in a newspaper of general circulation in each
county with a population of 10,000 or more that contains part of the proposed
route of the construction project. In the alternative, the operator may publish
notice of the construction project in a newspaper of general circulation in
each county that contains part of the proposed route of the construction project.
The notice shall be published in a section of the newspaper containing news
items of state or local interest. The published notice of the construction
project shall be at least three inches by five inches in size, exclusive of
the plat, and shall contain the following information:
(1)
the name, business address, and telephone number of the
operator and of the operator's authorized representative, if any;
(2)
a narrative description of the geographic location of the
construction project;
(3)
a plat that includes:
(A)
the location of the construction project, including the
beginning and end points of the construction project;
(B)
a north arrow;
(C)
the scale;
(D)
geographic subdivisions appropriate for the scale;
(E)
by inset or otherwise, landmarks or other features such
as roads and highways in relation to the proposed route of the construction
project; and
(F)
a listing of each federal and state highway that will be
crossed by the construction project; and
(4)
the following statement, completed as appropriate for each
county that contains part of the proposed route of the construction project:
"A copy of application forms and a map showing the location of the pipeline
construction project is available for public inspection at the offices of
the (name of county) County Clerk, located at: (the physical address of the
County Clerk) and at the offices of the Railroad Commission of Texas, Gas
Services Division, Pipeline Safety Section, 9th Floor, 1701 North Congress
Avenue, Austin, Texas 78701. Questions about the pipeline construction project
should be directed to (name of pipeline operator or designated contact, mailing
address, telephone number, and, if available, e-mail address). Any person
desiring to submit comments regarding the pipeline construction project that
is the subject of the notice may do so by mailing or otherwise delivering
a letter referring to the construction project (by docket number if available)
and any comments to: Gas Services Division, Pipeline Safety Section, Railroad
Commission of Texas, P.O. Box 12967, Austin, Texas 78711-2967. Comments may
also be submitted by electronic mail to pipelinecomments@rrc.state.tx.us.
Comments should be submitted to the Railroad Commission within 30 days of
the date this notice is published in this newspaper."
(d)
Compliance requirements. An operator shall demonstrate
compliance with the requirements of this section and of Texas Natural Resources
Code, §81.056, by filing with the Pipeline Safety Section the following:
(1)
Proof of publication of notice, by filing an original publisher's
affidavit with the tear sheet attached, from every newspaper in which notice
was published. The tear sheet shall include the printed date of publication.
(2)
Proof of delivery of notice, by filing an affidavit affirming
delivery by hand or by certified mail, return receipt requested, to each individual
required to receive notice under subsection (b) of this section, as shown
on a mailing list attached to the affidavit. The attached mailing list shall
include the names, addresses, and certified mail receipt numbers or notations
of hand delivery and the date of receipt for each of the following:
(A)
the county judge, the commissioners, and the county clerk
of each county that contains part of the proposed route of the construction
project;
(B)
the county fire marshal in each county that contains part
of the proposed route of the construction project, if such office has been
established by that county; and
(C)
the regional water planning group established by Texas
Water Code, §16.053, in each regional water planning area that contains
part of the proposed route of the construction project.
(e)
Gas Services Division review. The Gas Services Division
Assistant Director, Pipeline Safety Section, shall review all documents submitted
in compliance with subsection (d) of this section pursuant to the following
procedures.
(1)
Within 14 days of receiving documents submitted in compliance
with subsection (d) of this section, the assistant director shall notify the
operator that the documents are either complete and accepted for filing, or
are incomplete and require specified additional documents. The assistant director
shall provide such notice in writing by regular mail or by electronic mail,
provided that the operator submits a written request that communications regarding
completeness or incompleteness be communicated by electronic mail and supplies
an accurate electronic mail address.
(2)
If the assistant director determines that the documentation
of notice is incomplete, the following procedures shall apply:
(A)
The operator shall complete the documentation within 30
days of receiving notice from the assistant director that the documentation
is incomplete or within any longer time that the operator may request that
the assistant director may approve.
(B)
If the operator does not complete the documentation within
the specified time period, the assistant director shall send the operator
notice of intent to dismiss the matter without prejudice. Within 10 days of
issuance of a notice of intent to dismiss the matter for failure to complete
the documentation, the operator may either submit the required documentation
or request a hearing on the documentation as it exists at that time.
(C)
If the operator does not either submit the required documentation
or file a request for hearing within 10 days of the issuance of a notice of
intent to dismiss the matter, the assistant director shall dismiss the matter
without prejudice to refiling and shall not approve or issue a permit to operate
(T-4 permit) the construction project that is the subject of the matter being
dismissed.
(D)
If the operator requests a hearing pursuant to subparagraph
(B) of this paragraph, the assistant director shall forward the request for
hearing and the file to the Office of General Counsel for further handling.
(3)
If the assistant director determines that the documentation
is complete, the assistant director shall complete the review within 30 days
pursuant to the following procedures:
(A)
The assistant director shall review the documentation to
determine whether the documentation on its face shows that the construction
project that is the subject of the documentation complies with the applicable
statutes and Commission rules.
(B)
The assistant director shall also review and consider any
comments from members of the public about the construction project that is
the subject of the documentation, under Texas Natural Resources Code, §81.056(c)(2),
pertaining to public safety, the environment, and conservation. Pursuant to
Texas Natural Resources Code, §81.056(d), the assistant director shall
not consider comments on matters not within the jurisdiction of the Commission,
such as the finances of the pipeline owner or operator; nuisance; noise; property
values; access; easements; condemnation proceedings; or aesthetics.
(C)
The assistant director shall review the published newspaper
notice to determine whether the plat and the narrative portion complied with
the requirements of subsection (c) of this section.
(D)
The assistant director shall review the affidavits of publication
and of delivery of notice to determine whether the operator complied with
the notice requirements of subsection (b) of this section.
(4)
Upon completion of the review, the assistant director shall
prepare a written recommendation and shall forward the recommendation and
the file to the Office of General Counsel. If the assistant director received
comments from the public, the recommendation shall also include a statement
whether the comments did or did not pertain to a matter within the jurisdiction
of the Commission and whether the assistant director recommends that a hearing
be held with respect to any of the issues raised by the comments.
(f)
Office of General Counsel review. The Office of General
Counsel Assistant Director, Gas Services Section, shall review the operator's
documentation and the recommendation from the Gas Services Division Assistant
Director, Pipeline Safety Section, pursuant to the following procedures:
(1)
The assistant director shall review the operator's documentation
to determine whether the operator has complied with the requirements of subsections
(b) and (c) of this section and with Texas Natural Resources Code, §81.056.
(2)
The assistant director shall review the recommendation
of the Pipeline Safety Section to determine whether there is a need to conduct
a hearing.
(3)
If an operator requests a hearing pursuant to subsection
(e) (2) (D) of this section or if the Pipeline Safety Section recommends pursuant
to subsection (e)(4) of this section that a hearing be conducted, the Office
of General Counsel shall handle the matter 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.
(4)
If the assistant director determines that the operator
has substantially complied in all material respects with the requirements
of Texas Natural Resources Code, §81.056, and with the requirements of
this section, the assistant director shall prepare an order certifying compliance
and shall present it to the Commission.
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 February 26, 2003.
TRD-200301416
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
The Railroad Commission of Texas withdraws the versions of proposed
new §8.235, relating to Community Liaison and Public Awareness for Natural
Gas Pipelines, and §8.310, relating to Community Liaison and Public Awareness
for Hazardous Liquids and Carbon Dioxide Pipelines, published in the September
27, 2002, issue of the
Texas Register
(27
TexReg 9063) and proposes new versions of §8.235, relating to Natural
Gas Pipelines Public Education and Liaison, and §8.310, relating to Hazardous
Liquids and Carbon Dioxide Pipelines Public Education and Liaison.
The Commission proposes revised §8.235 and §8.310 to implement
Texas Utilities Code, §121.2015, and Texas Natural Resources Code, §117.011,
respectively, which were enacted by Senate Bill (SB) 310, 77th Legislature
(2001). As re-written the proposed new rules address issues raised by the
comments filed regarding the proposal published on September 27, and both
implement the requirements of SB 310 and support the Commission's current
enforcement provisions for emergency response liaison found in 49 CFR Parts
192 and 195. In addition to providing guidance for compliance with the emergency
response and liaison provisions found in the federal regulations, new provisions
for the education of school districts with school buildings or recreational
facilities located within 1000 feet of a pipeline are also included. Proposed
new §8.310 applies to operators of hazardous liquid and carbon dioxide
transmission pipelines; there are slightly different requirements for operators
of natural gas transmission pipelines in proposed new §8.235.
The Commission received comments on the September 27 proposals of new §8.235
and §8.310 from seven interested persons, including the Texas Oil and
Gas Association, the Association of Texas Intrastate Natural Gas Pipelines,
Kinder Morgan, Energas, Valero Logistics Operations, Enbridge, and Koch Industries.
The Commission agrees that, as proposed on September 27, §8.235 and §8.310
were not clear. The Commission interprets the provisions in SB 310 as clarifying
and providing guidance in meeting the requirements for conducting public education
and liaison sessions imposed by 49 CFR §192.615 and §192.616 and
49 CFR §§195.402, 195.408, and 195.440. The statutory provisions
enacted by SB 310 require operators to conduct liaison sessions face-to-face
with fire, police, and other appropriate public emergency response officials
as much as possible, but also allowed other means of compliance if face-to-face
meetings could not be conducted. Revised proposed new §8.235 and §8.310,
as with the September 27 proposals, are not intended to require pipeline operators
to take on new emergency response activities; rather, they are intended to
augment the federal requirements found in 49 CFR Parts 192 and 195.
Revised proposed new §8.235 and §8.310 address many of the concerns
raised by the commenters on the September 27 proposals. One issue raised by
all of the commenters was the need to provide definitions for liaison activities,
community liaison activities, and public education and liaison plan. As set
out in the revised proposals, the activities required by both rules are those
already required under the federal pipeline safety regulations; there is no
need to re-define those same terms for the purpose of this rule. Another comment
made by all of the industry representatives was the need to clarify the applicability
of the 1,000-foot distance criterion for the public education required for
schools. The proposed new rules would establish the applicability of the rule
to any pipelines that are located within 1,000 feet of a public school building
or recreation area, but there are different requirements for natural gas pipelines,
hazardous liquids pipelines, and carbon dioxide pipelines.
A point of particular concern by the commenters was the requirement that
the emergency response plan be presented to school districts during the annual
budget meetings. Many comments expressed concern regarding the difficulty
in meeting the demands to meet with a school board at a time when the board
would be focusing on budget issues. The proposed new rules provide an alternative
that the Commission finds comports with the policy underlying Texas Natural
Resources Code, §117.012(h).
Last, operators were looking for guidance in what should be included in
the presentation to the school board. Revised proposed new §8.310 provides
a short list of items that are required to be presented to the school board
during the public education session. Further guidance about public education
and liaison activities is also available in a proposed American Petroleum
Institute (API) document, API RP1162. The Recommended Practice (API RP1162),
entitled Public Awareness Programs for Pipeline Operators, provides guidance
for operators in how to establish and deliver a public education and awareness
program.
Revised proposed new §8.235 and §8.310 are similar in requiring
pipeline operators to conduct liaison activities in person except as otherwise
provided by each section. Subsection (a) of each rule requires each operator
of a pipeline or the operator's designated representative to communicate and
conduct liaison activities with fire, police, and other appropriate emergency
response officials. The liaison activities are those required by 49 CFR Part
192.615(c)(1)-(4), for natural gas pipelines, and 49 CFR Part 195.402(c)(12),
for hazardous liquids pipelines.
Subsection (b) of each revised proposed new rule sets out the methods by
which pipeline operators are required to arrange meetings in person with emergency
response officials. Operators are required to attempt to schedule a meeting
in person by mail, fax, telephone, or e-mail. Natural gas pipeline operators
may use only one of those methods. Hazardous liquid and carbon dioxide pipeline
operators must exhaust, in sequence, all of them, but once a meeting has been
scheduled, no further attempts to make contact are necessary. If a scheduled
meeting does not take place, both rules require the operator or operator's
representative to make one more effort to re-schedule the meeting in person
using one of the listed methods before proceeding to arrange a conference
call.
Subsection (c) of both revised proposed new rules permits pipeline operators
to conduct community liaison activities by means of a telephone conference
call if the meeting cannot be conducted in person. The natural gas pipeline
operator or the operator's representative must make an effort to conduct a
community liaison meeting by telephone conference call with the officials
by one of the listed methods. The hazardous liquid or carbon dioxide pipeline
operator or the operator's representative must exhaust, in sequence, all of
the listed methods; however, once a telephone conference call is scheduled,
no further attempts to make contact are necessary. If a scheduled conference
call does not take place, both rules require the operator or operator's representative
to make one more effort to re-schedule the community liaison telephone conference
call with the officials using one of the listed methods before proceeding
to proceeding to mail the liaison information pursuant to subsection (d) of
both rules.
Subsection (d) of both revised proposed new rules permits the community
liaison information to be delivered by mailing the information by certified
mail, return receipt requested, if the operator or the operator's representative
has made the efforts required by subsections (b) and (c) but has not successfully
arranged and held either a meeting in person or a telephone conference.
Subsection (e) of each revised proposed new rule is different. Under revised
proposed new §8.235(e), an 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 recreational area must notify the Commission
and provide the specified information. Clearly, Texas Natural Resources Code, §117.012,
includes specific provisions for the safety education of school districts
with school buildings located within 1,000 feet of a hazardous liquid or carbon
dioxide pipeline. There are no similar provisions for natural gas pipelines
in Texas Utilities Code, §121.2015. However, Texas Utilities Code, §121.201,
authorizes the Commission by rule to "adopt safety standards for the transportation
of gas and for gas pipeline facilities." The extension of the requirement
to provide the Commission with information about school districts with natural
gas pipelines within 1,000 feet of a school building or recreational area
falls within the broad authority granted to the Commission to enhance public
safety.
Under revised proposed new §8.310(e), an owner or operator of a hazardous
liquids or carbon dioxide pipeline or pipeline facility any part of which
is located within 1,000 feet of a public school building or recreational area
must: (1) consult with the fire department in whose jurisdiction the school
is located or another appropriate local emergency response entity regarding
the emergency response plan prepared as required by 49 CFR Part 195; and (2)
present the plan at the first annual budget meeting of the board of trustees
of the school district in which the school is located after the plan is developed
and at subsequent annual budget meetings of the board of trustees of the school
district on the request of the board. If the operator is unable to make the
presentation at the annual budget meeting, the operator may make the presentation
at any other meeting of the board of trustees that is mutually agreeable to
the operator and the board. This alternative is not specifically provided
in Texas Natural Resources Code, §117.012(h), but the Commission finds
that it is consistent with the policy underlying the requirement that pipeline
emergency response plans be presented in a public meeting, and it provides
some scheduling flexibility for both operators and school boards.
Revised proposed new §8.310(f) provides general guidance to operators
of hazardous liquids and carbon dioxide pipelines in the presentation of public
education information to school districts and lists specific information that
must be included in the presentation. Pipeline operators may use proposed
API Recommended Practice 1162 as guidance in preparing and presenting the
public education program for school districts required by this section. The
liaison presentation must contain the following components: (1) a description
of the pipeline and pipeline facilities within 1000 feet of a school building
or recreational area; (2) a list of the products carried by the pipelines
and material safety data sheets for the products; (3) general facility maps;
(4) names and phone numbers of pipeline emergency response personnel to contact
in the event of an emergency; (5) provisions for an emergency preparedness
drill; and (6) information regarding the prevention of third party damage
to the pipeline.
Revised proposed new §8.235(f) and §8.310(g) prescribe record-keeping
requirements. Operators must maintain records documenting compliance with
the liaison activities required by the revised proposed new rules. Records
of attendance and acknowledgment of receipt by the emergency response officials,
school board, or school principal must be retained for five years from the
date of the event that is commemorated by the record. Records of certified
mail and/or telephone transmissions undertaken in compliance with subsections
(b) and (c) of these sections satisfy the record-keeping requirement.
Mary McDaniel, assistant director, Gas Services Division, Pipeline Safety
Section, has determined that for each of the first five years the proposed
new sections are in effect there will be no fiscal implications for state
government as a result of enforcing or administering these rules. Operators
of natural gas pipelines and hazardous liquids pipelines should already have
emergency response plans in place pursuant to the requirements of 49 CFR Parts
192 and 195.
There may be fiscal implications for any local governments that participate
in community liaison meetings in person with pipeline operators or their representatives,
unless the local government is already participating in such meetings in person,
and for those local governments whose fire departments or other emergency
response entities would be required to consult with the owner or operator
of each interstate or intrastate natural gas, hazardous liquid or carbon dioxide
pipeline or pipeline facility, any part of which is located within 1,000 feet
of a public school building or recreational area, to develop an emergency
response plan. There may be fiscal implications for school districts in which
there is a school within 1,000 feet of a hazardous liquid or carbon dioxide
pipeline or pipeline facility because of the requirement that the board of
trustees of such a school district entertain the presentation of the emergency
response plan at the first annual budget meeting after the plan is developed,
and at subsequent annual budget meetings of the board of trustees of the school
district on the request of the board. The Commission does not have data showing
which school districts have schools within 1,000 feet of a hazardous liquid
or carbon dioxide pipeline or pipeline facility or how many schools or school
districts might be affected by this requirement.
Ms. McDaniel has also determined that the public benefit anticipated as
a result of the new sections will be a general improvement of the communication
between pipeline operators and local emergency response entities. Specifically
there is an anticipated increase in the overall safety of occupants of school
facilities as emergency response officials become more aware of any hazardous
liquid or carbon dioxide pipeline facilities located near school buildings
or recreational areas, as well as the occupants becoming more aware of the
proper procedures to follow in the event of an emergency involving pipeline
facilities. Interested persons would have the opportunity to attend an open
meeting of the local school board at which the safety education regarding
a hazardous liquid or carbon dioxide pipeline or pipeline facility is presented
to become more informed about emergency response plans.
The requirements in the proposed new rules are consistent with the Commission's
current enforcement procedures regarding liaison activities. However, all
operators of pipelines or pipeline facilities may incur additional costs in
identifying public school buildings or recreational areas that are within
1,000 feet of a pipeline. Operators of hazardous liquid or carbon dioxide
pipelines or pipeline facilities will incur the costs of preparing and presenting
information to the local school boards. Much of the information should already
be included in the emergency response plans prepared pursuant to 49 CFR Parts
192 and 195; the additional costs would be incurred by reproducing documents
and attending school board meetings. The Commission has no information on
the number or type of pipelines or pipeline facilities that are located within
1,000 feet of a public school building or recreational area.
There should be only minimal additional costs for individual, small business,
or micro-business pipeline operators to comply with the proposed new rules.
The operators should have already developed and put in place appropriate emergency
response plans pursuant to 49 CFR Parts 192 and 195. The cost for individual,
small business, or micro-business pipeline operators to comply with revised
proposed new §8.310(f) cannot be determined, because the Commission has
no data available as to whether there are individual, small business or micro-business
operators of hazardous liquids or carbon dioxide pipelines or pipeline facilities
within 1,000 feet of a school or recreational area, or the number of such
operators the proposed rule will affect.
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 90 days after publication in the
Texas Register
and should refer to Gas Utilities Docket No. 9330. 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 Mary McDaniel
at (512) 463-7058. The status of Commission rulemakings in progress is available
at www.rrc.state.tx.us/rules/proposed.html.
Subchapter C. REQUIREMENTS FOR NATURAL GAS PIPELINES ONLY
16 TAC §8.235
The Commission proposes revised new §8.235 pursuant to
Texas Utilities Code, §121.2015, which requires the Commission to adopt
rules regarding public education and awareness relating to gas pipeline facilities
and community liaison for responding to an emergency relating to a gas pipeline
facility and mandates that the Commission require operators or their designated
representatives to communicate and conduct liaison activities with fire, police,
and other appropriate public emergency response officials by meetings in person
except as provided by §121.2015; and Texas Utilities Code, §121.201,
which authorizes the Commission by rule to "adopt safety standards for the
transportation of gas and for gas pipeline facilities" and to take any other
requisite action in accordance with 49 U.S.C. Section 60101,
et seq.,
or a succeeding law. The requirement that operators of natural
gas pipelines or pipeline facilities provide information to the Commission
about school districts with natural gas pipelines or pipeline facilities within
1000 feet of a school building or recreational area falls within the broad
authority granted to the Commission to enhance public safety.
Cross-reference to statute: Texas Natural Resources Code, §117.012;
Texas Utilities Code, §121.201 and §121.2015.
Issued in Austin, Texas on February 25, 2003.
§8.235.Natural Gas Pipelines Public Education and Liaison.
(a)
Liaison activities required. Each operator of a natural
gas pipeline or natural gas pipeline facilities or the operator's designated
representative shall communicate and conduct liaison activities with fire,
police, and other appropriate public emergency response officials. The liaison
activities are those required by 49 CFR Part 192.615(c)(1)-(4). These liaison
activities shall be conducted in person, except as provided by this section.
(b)
Meetings in person. The operator or the operator's representative
may conduct the required community liaison activities as provided by subsection
(c) of this section only if the operator or the operator's representative
has made an effort to conduct a community liaison meeting in person with the
officials by one of the following methods:
(1)
mailing a written request for a meeting in person to the
appropriate officials by certified mail, return receipt requested;
(2)
sending a request for a meeting in person to the appropriate
officials by facsimile transmission; and
(3)
making one or more telephone calls or e-mail message transmissions
to the appropriate officials to request a meeting in person.
(4)
If a scheduled meeting does not take place, the operator
or operator's representative shall make an effort to re-schedule the community
liaison meeting in person with the officials using one of the methods in paragraphs
(1)-(3) of this subsection before proceeding to arrange a conference call
pursuant to subsection (c) of this section.
(c)
Conference call. If the operator or operator's representative
cannot arrange a meeting in person after complying with subsection (b) of
this section, the operator or the operator's representative shall make an
effort to conduct community liaison activities by means of a telephone conference
call with the officials by one of the following methods:
(1)
mailing a written request for a telephone conference to
the appropriate officials by certified mail, return receipt requested;
(2)
sending a request for a telephone conference to the appropriate
officials by facsimile transmission; and
(3)
making one or more telephone calls or e-mail message transmissions
to the appropriate officials to request a telephone conference.
(4)
If a scheduled telephone conference call does not take
place, the operator or operator's representative shall make an effort to re-schedule
the community liaison telephone conference call with the officials using one
of the methods in paragraphs (1)-(3) of this subsection before proceeding
to mail the liaison information pursuant to subsection (d) of this section.
(d)
Mailing liaison information. If the operator or the operator's
representative has made the efforts required by subsections (b) and (c) but
has not successfully arranged and held either a meeting in person or a telephone
conference, the community liaison information required to be conveyed may
be delivered by mailing the information by certified mail, return receipt
requested.
(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 recreational area
shall notify the Commission by filing with the Gas Services Division, Pipeline
Safety Section, the following information:
(1)
the name of the school;
(2)
the street address of the school; and
(3)
the identification (system name) of the pipeline.
(f)
Records. The operator shall maintain records documenting
compliance with the liaison activities required by this section. Records of
attendance and acknowledgment of receipt by the emergency response officials,
school board, or school principal shall be retained for five years from the
date of the event that is commemorated by the record. Records of certified
mail and/or telephone transmissions undertaken in compliance with subsections
(b) and (c) of this section satisfy the record-keeping requirements of this
subsection.
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 February 26, 2003.
TRD-200301422
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §8.310
The Commission proposes revised new §8.310 pursuant to
Texas Natural Resources Code, §117.011, which gives the Commission jurisdiction
over all pipeline transportation of hazardous liquids or carbon dioxide and
over all hazardous liquid or carbon dioxide pipeline facilities as provided
by 49 U.S.C. §60101,
et seq
., and §117.012,
which directs the Commission to adopt rules regarding public education and
awareness concerning hazardous liquid or carbon dioxide pipeline facilities
and community liaison for the purpose of responding to an emergency concerning
a hazardous liquid or carbon dioxide pipeline facility and mandates that the
Commission require operators of hazardous liquids or carbon dioxide pipelines
or pipeline facilities to conduct liaison activities with fire, police, and
other appropriate public emergency response officials by meetings in person
except as otherwise provided by §117.012.
Cross-reference to statute: Texas Natural Resources Code, §117.012;
Texas Utilities Code, §§121.201 and 121.2015.
Issued in Austin, Texas on February 25, 2003.
§8.310.Hazardous Liquids and Carbon Dioxide Pipelines Public Education and Liaison.
(a)
Liaison activities required. Each operator of a hazardous
liquid or carbon dioxide pipeline or pipeline facilities or the operator's
designated representative shall communicate and conduct liaison activities
with fire, police, and other appropriate public emergency response officials.
The liaison activities are those required by 49 CFR Part 195.402(c)(12). These
liaison activities shall be conducted in person, except as provided by this
section.
(b)
Meetings in person. The operator or the operator's representative
may conduct required community liaison activities as provided by subsection
(c) of this section only if the operator or the operator's representative
has exhausted, in sequence, all of the following efforts to conduct a community
liaison meeting in person with the officials:
(1)
mailing a written request for a meeting in person to the
appropriate officials by certified mail, return receipt requested;
(2)
sending a request for a meeting in person to the appropriate
officials by facsimile transmission; and
(3)
making one or more telephone calls or e-mail message transmissions
to the appropriate officials to request a meeting in person.
(4)
At any time the operator or operator's representative makes
contact with the appropriate officials and schedules a meeting in person,
no further attempts to make contact under this section are necessary. However,
if a scheduled meeting does not take place, the operator or operator's representative
shall make an effort to re-schedule the community liaison meeting in person
with the officials using one of the methods in paragraphs (1)-(3) of this
subsection before proceeding to arrange a conference call pursuant to subsection
(c) of this section.
(c)
Conference call. If the operator or operator's representative
cannot arrange a meeting in person after complying with subsection (b) of
this section, the operator or the operator's representative shall make the
following efforts to conduct community liaison activities by means of a telephone
conference call with the officials:
(1)
mailing a written request for a telephone conference to
the appropriate officials by certified mail, return receipt requested;
(2)
sending a request for a telephone conference to the appropriate
officials by facsimile transmission; and
(3)
making one or more telephone calls or e-mail message transmissions
to the appropriate officials to request a telephone conference.
(4)
At any time the operator makes contact with the appropriate
officials and schedules a telephone conference call, no further attempts to
make contact under this section are necessary. However, if a scheduled telephone
conference call does not take place, the operator or operator's representative
shall make an effort to re-schedule the telephone conference call with the
officials using one of the methods in paragraphs (1)-(3) of this subsection
before proceeding to mail the liaison information pursuant to subsection (d)
of this section.
(d)
Mailing liaison information. If the operator or the operator's
representative has made all of the efforts required by subsections (b) and
(c) but has not successfully arranged either a meeting in person or a telephone
conference, the community liaison information required to be conveyed may
be delivered by mailing the information by certified mail, return receipt
requested.
(e)
Proximity to public school. Each owner or operator of a
hazardous liquid or carbon dioxide pipeline or pipeline facility any part
of which is located within 1,000 feet of a public school building or recreational
area shall:
(1)
consult with the fire department in whose jurisdiction
the school is located or another appropriate local emergency response entity
regarding the emergency response plan prepared as required by 49 CFR Part
195; and
(2)
present the plan:
(A)
at the first annual budget meeting of the board of trustees
of the school district in which the school is located after the plan is developed;
and
(B)
at subsequent annual budget meetings of the board of trustees
of the school district on the request of the board.
(3)
If the operator is unable to make the presentation at the
annual budget meeting, the operator may make the presentation at any other
meeting of the board of trustees that is mutually agreeable to the operator
and the board.
(f)
Components of presentation. Pipeline operators may use
proposed API Recommended Practice 1162, entitled Public Awareness Programs
for Pipeline Operators, as guidance in preparing and presenting the public
education program for school districts required by this section. The liaison
presentation shall contain the following components:
(1)
a description of the pipeline and pipeline facilities within
1,000 feet of a school building or recreational area;
(2)
a list of the products carried by the pipelines and material
safety data sheets for the products;
(3)
general facility maps;
(4)
names and phone numbers of pipeline emergency response
personnel to contact in the event of an emergency;
(5)
provisions for an emergency preparedness drill; and
(6)
information regarding the prevention of third party damage
to the pipeline.
(g)
Records. The operator shall maintain records documenting
compliance with the liaison activities required by this section. Records of
attendance and acknowledgment of receipt by the emergency response officials
and school board or school district superintendent shall be retained for five
years from the date of the event that is commemorated by the record. Records
of certified mail and/or telephone transmissions undertaken in compliance
with subsections (b) and (c) of this section satisfy the record-keeping requirements
of this subsection.
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 February 26, 2003.
TRD-200301423
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
Subchapter C. REQUIREMENTS FOR NATURAL GAS PIPELINES ONLY
16 TAC §8.240
The Railroad Commission of Texas withdraws its proposal to
adopt new §8.340, relating to Discontinuance of Service, published in
the October 25, 2002, issue of the
Texas Register
, and proposes revised new §8.240, relating to Discontinuance
of Service, which applies when a natural gas service customer ceases taking
service at a particular location. Following publication of the original proposed
new rule on October 25, 2002, the Commission received comments from several
affected natural gas distribution operators and other industry groups. Based
on the comments, the Commission has revised the proposed new rule and withdraws
its original proposal.
The revised proposed new rule supplements the federal pipeline safety rule,
found at 49 CFR §192.727(d), and provides more detailed direction to
providers of natural gas service with respect to the time for complying with
the federal safety standard. The proposed rule is also supported by a December
24, 2002, Department of Transportation, Office of Pipeline Safety (OPS),
response letter to Mr. Richard Lonn, Atlanta Gas Light Company. This response
also confirms the interpretation given by OPS on October 11, 1978, regarding
the applicability of §192.727 when "an interim period exists when gas
service is not requested by another party."
Commission rule §7.70(a) sets forth minimum safety standards for pipelines,
and requires that all gas pipeline facilities and the transportation of gas
within this state, except those facilities and that transportation of gas
which are subject to exclusive federal jurisdiction under the Natural Gas
Pipeline Safety Act, 49 United States Code Annotated, §60101
et seq.
, be designed, constructed, maintained, and operated in accordance
with the Minimum Safety Standards for Natural Gas, 49 Code of Federal Regulations
(CFR) Part 192, as amended March 21, 2002, and with the additional regulations
set out in that section. Nevertheless, the Commission learned, some natural
gas service providers in Texas have waited for as long as 90 days, and perhaps
longer, to comply with one of the three steps listed in §192.727(d).
Therefore, the Commission proposed new §8.340 to clarify the actions
required for compliance with the federal rule.
The Commission received comments on the October 25, 2002, proposal from
Texas Gas Association, TXU Gas Distribution, City Public Service of San Antonio,
Atmos Energy Corporation, Southern Union Gas Company, and the American Gas
Association. Four of the commenters currently utilize closure practices with
time frames longer than those in the October 25 proposal. The comments suggested
that the Commission wait for the formal interpretation from OPS regarding
"soft close" to allow for a consensus standard throughout the United States.
The federal interpretation has been issued, and the Commission's revised proposed
new rule defines what the Commission consider to be an acceptable time frame
before natural gas service must be discontinued in accordance with §192.727.
Other comments suggested that the two-day and five-day time frames were too
inflexible. Based on information received after the rule was published on
October 25, the Commission agrees that most customer transfer notifications
are received within 10 days. Therefore, this revised proposal modifies the
October 25 version of new §8.340 to allow 15 days for the transfer of
service to a new customer.
As revised, proposed new §8.240 requires that upon receiving notification
from a customer to discontinue natural gas service at that customer's service
location, each provider of natural gas service must take one of the three
steps specified in 49 CFR §192.727(d) within 15 days. A provider of natural
gas service is not required to take any of the three steps specified in 49
CFR §192.727(d) if the natural gas service provider is notified to transfer
natural gas service to another customer or if there is information filed with
the gas company to transfer the service to the owner or manager of the service
location during an interim time period. The revised proposed new rule also
sets forth requirements for the operator to notify the customer regarding
the "turn off" time frame as well as requiring closure procedures to be included
in the operations and maintenance manual.
The Commission finds that the revised proposed new rule achieves a balance
between the desires of natural gas service providers to accommodate their
customers and the public interest in the safe transportation of gas and safe
operation of gas pipeline facilities in this state and the prevention of potentially
catastrophic accidents, property damage and loss, and personal injury or loss
of life.
Mary McDaniel, Assistant Director for Pipeline Safety, Gas Services Division,
has determined that for each year of the first five years that the revised
proposed new rule will be in effect, there will be no fiscal implications
for state government as a result of enforcing or administering the section.
The Commission's pipeline safety inspectors will include compliance with the
section in their regular safety inspections, without the need for additional
personnel or budget. There will be no fiscal implications for local governments,
because under Texas Government Code, §121.202, only the Commission has
jurisdiction over pipeline safety matters affecting the transportation of
gas and gas pipeline facilities in this state.
Ms. McDaniel has also determined that for each year of the first five years
that the proposed new rule will be in effect, the public benefit will be generally
increased confidence that an unoccupied residence or business will not present
an opportunity for unauthorized persons to activate gas service lines that
have been deactivated or abandoned, or are not currently in use. This should
have the salutary effect of preventing potentially catastrophic accidents,
property damage and loss, and personal injury or loss of life, and possibly
reduce the demand on public emergency response resources.
Pursuant to Texas Government Code, §2006.002(c), Ms. McDaniel has
also estimated that there will be no cost of compliance for small business,
micro-business, or individual natural gas service providers that are currently
complying with the federal safety standards within the proposed time limits.
For those small business, micro-business, or individual natural gas service
providers that either are not complying with the federal safety standard or
that might be required to comply within a shorter time period, compliance
within the proposed time limits might have an impact on the provider's cash
flow,
i.e.,
the expense of making the physical
termination of gas service to a service location would be incurred sooner
than it is under the provider's current practice. Pursuant to Texas Government
Code, §2006.002(a), the Commission has determined that even if there
is an adverse economic effect on small businesses or micro-businesses, considering
the purpose of the statute and the federal rule under which the proposed new
rule is to be adopted, it would not be feasible to reduce any adverse impact
on small businesses or micro-businesses. The rule is intended to prevent potentially
catastrophic accidents, property damage and loss, and personal injury or loss
of life; any measure that might reduce an adverse impact on small businesses
or micro- businesses would undermine the effectiveness of setting time limits
for compliance by all natural gas service providers.
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
; comments should refer to Gas Utilities Docket No. 9336.
For further information, call Mary McDaniel at (512) 463-7058. The status
of Commission rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
The Commission proposes revised new §8.240 pursuant to Texas
Utilities Code, §121.201, which authorizes the Commission to adopt rules
that contain safety standards for the transportation of gas and for gas pipeline
facilities in this state; to inspect records and facilities to determine compliance
with adopted safety standards; and to take any other requisite action with
respect to the transportation of gas and gas pipeline facilities in this state
to the maximum degree permissible under 49 U.S.C. Section 60101
et seq.
, or a succeeding law.
Cross-reference to statute: Texas Utilities Code, §121.201.
Issued in Austin, Texas on February 25, 2003.
§8.240.Discontinuance of Service.
(a)
Upon notification from a customer to discontinue natural
gas service at that customer's service location, each provider of natural
gas service shall take one of the three steps specified in 49 CFR §192.727(d)
within 15 calendar days provided that:
(1)
the natural gas service provider has given the customer
information regarding the length of time gas service may remain on at the
service location; and
(2)
procedures for service discontinuance are included in the
operator's operations and maintenance manual.
(b)
A provider of natural gas service is not required to take
any of the three steps specified in 49 CFR §192.727(d) if the natural
gas service provider receives notice to transfer natural gas service to another
customer or if there are provisions to transfer service to an owner or manager
of the service location.
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 February 26, 2003.
TRD-200301424
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
Subchapter C. CLASSIFICATION, REGISTRATION, AND EXAMINATION
16 TAC §13.80
The Railroad Commission of Texas proposes new §13.80,
relating to CNG Continuing Education Requirements. The purpose of the proposed
new section is to establish a continuing education program for CNG licensees
as required by Senate Bill (SB) 310, 77th Legislature (2001), as codified
at Texas Natural Resources Code, §116.034(h).
Pursuant to proposed new §13.80, the LP-Gas Section will conduct a
continuing education course for all CNG licensees. The course will be four
hours in length and will be given at the Commission's offices in Austin of
the Commission by LP-Gas Section field staff. Each individual holding a CNG
license and each CNG licensee representative, as the term "representative"
is defined under §13.3(42) of this title (relating to Definitions), must
attend the course once every four years in order to maintain licensed status;
individuals holding a CNG license and CNG licensee representatives holding
active CNG licenses as of the effective date of this rule must attend a course
by September 1, 2004. Individuals and CNG licensee representatives obtaining
a CNG license after the effective date of this rule will have four years from
the date the license is issued to attend a course.
There will be no charge to individuals holding a CNG license and CNG licensee
representatives for attending a course. A course will be given one day in
March and August of each year. The Commission will post on its web site notice
of the date and time of a course at least 30 days before the course is given.
The Commission intends to offer the first course in March of 2004 and will
include written notice of the March 2004 course in subsequent correspondence
to licensees.
Currently in Texas there are a total of 57 individuals who hold a CNG license
or are CNG licensee representatives. Due to the limited number of individuals
who are required to take the course, the Commission does not expect to incur
any additional expense in offering the course because current Commission resources,
e.g., offices, field inspectors, and funds received for license renewal, will
be adequate for the Commission to meet its undertaking pursuant to proposed
new §13.80.
Proposed new §13.80(a) applies the continuing education requirements
to individuals holding a CNG license and to individuals who are CNG licensee
representatives, as defined in §13.3(42). Proposed new §13.80(b)
mandates that only individuals are credited with completing a required continuing
education course, provided such individuals hold a CNG license or are a CNG
licensee representative. Proposed new §13.80(c) mandates that individuals
must attend the entire continuing education course in order to receive credit
for attendance.
Proposed new §13.80(d) provides that continuing education courses
will be offered twice a year at the LP-Gas Section offices in Austin. The
continuing education courses will offered one day in both March and August.
The Commission will post on its web site notice of the date and time of the
course at least 30 days before a course is offered.
Proposed new §13.80(e) provides that the Commission will not charge
a fee to individuals taking a course. Proposed new §13.80(f) requires
individuals holding a CNG license and CNG licensee representatives to attend
and complete a continuing education course at least one time every four years.
Subsection (f) also provides that the LP-Gas Section will determine the course
content and that the course will cover, at a minimum, the Commission's adopted
rules and regulations, and safety procedures for handling CNG.
Proposed new §13.80(g) provides that individuals holding a CNG license
and CNG licensee representatives who are licensed as of the effective date
of §13.80, must attend and complete a continuing education course offered
by the Commission by September 1, 2004. Subsection (g) further provides that
an individual who becomes licensed or becomes a CNG licensee representative
after the effective date of §13.80 must attend and complete a course
within four years from the date his or her license becomes active.
Proposed new §13.80(h) provides that an individual who holds a CNG
license or who is a CNG licensee representative who fails to complete the
continuing education course requirements under §13.80 will not be allowed
to renew his or her license until successfully completing a Commission course.
Byron Caffey, assistant director, Gas Services Division, LP- Gas Section,
has determined that for each year of the first five years the proposed new
section will be in effect, there will be no fiscal implications for state
or local governments as a result of enforcing or administering the new section.
The course will be given in currently available facilities, which will result
in no fiscal impact on state government. The Commission will use its existing
trained field staff to administer the course two times per year in Austin.
The Commission does not anticipate providing written materials or incurring
any additional costs as a result of offering the course to CNG licensees.
Currently, there are a total of 57 individuals who either hold CNG licenses
or are CNG licensee representatives that will be required to attend a course
one time every four years. The Commission intends to offer the first course
in March of 2004. Mr. Caffey projects the number of new licensees who will
be required to attend the course each year during fiscal years 2005 through
2007 to be fewer than 10. Mr. Caffey projects that new licensees attending
the course during fiscal years 2005 through 2007 will not have any fiscal
impact on the Commission or state government. There are no fiscal implications
for local governments.
Mr. Caffey has also determined that for each year of the first five years
the new section is proposed to be in effect, the public benefit will be improvement
in safety and clarification of the Commission's requirements for CNG activities.
Mr. Caffey has determined that requiring individuals holding CNG licenses
and CNG licensee representatives to remain informed on the Commission's adopted
rules and regulations, and safety procedures for handling CNG will increase
awareness of safety issues by these individuals and therefore increase safety
to the public.
There is some anticipated economic cost to small businesses, micro-businesses,
and individuals required to comply with the new section. As a result of the
proposed rule, all individuals holding a CNG license and CNG licensee representatives
will be required to take a continuing education course for four hours at the
LP-Gas Section offices in Austin. Although there is no fee for the course,
individuals holding a CNG license and CNG licensee representatives could incur
certain expenses such as transportation, lodging, and meals. These costs will
vary based on the distance, mode of travel, and the type of accommodations
each licensee prefers.
Pursuant to Texas Government Code, §2006.002(c), the Commission cannot
determine the cost for individual, small business, or micro-businesses holding
CNG licenses or employing CNG licensee representatives because the costs associated
with compliance will vary depending on the different situations and choices
made by each licensee. The Commission assumes that there are CNG licensees
that meet the definitions of "micro-business" and "small business" set forth
in Texas Government Code, §2006.001(1) and (2), respectively; however,
the Commission does not have data showing the expense for each employee, the
expense for each hour of labor, or the total sales revenue for any CNG licensee.
In addition, the costs for any particular CNG licensee will vary based on
that licensee's situation. Therefore, the Commission is not able to determine
the exact cost of compliance based on the cost for each employee, the cost
for each hour of labor, or the cost for each $100 of sales pursuant to Texas
Government Code, §2006.002(c). Thus, pursuant to Texas Government Code, §2006.002,
the Commission finds that, considering the purpose of Texas Natural Resources
Code, Chapter 116, it is not feasible to reduce any adverse effect the proposed
new rule could have on individuals, small businesses, or micro- businesses.
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 should refer to LP-Gas Docket No. 1726. 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 Mr. Caffey at (512) 463-5762.
The status of Commission rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
The new section is proposed under the Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to the work of compression and liquefaction, storage, sale or dispensing,
transfer or transportation, use or consumption, and disposal of compressed
natural gas or liquefied natural gas, and §116.034(h), as added by Section
57, SB 310, 77th Legislature (2001), which mandates the Commission to recognize,
prepare, or administer continuing education programs for its licensees.
Cross reference to statute: Texas Natural Resources Code, Chapter 116,
Sections 116.012 and 116.034(h), as added by SB 310, 77th Legislature (2001).
Issued in Austin, Texas on February 25, 2003.
§13.80.CNG Continuing Education Requirements.
(a)
The continuing education requirements in this section apply
only to an individual holding a CNG license and to an individual who is a
CNG licensee's representative, as the term "representative" is defined in §13.3(42)
of this title (relating to Definitions).
(b)
Successful completion of the continuing education requirements
shall be credited to and accrue to only an individual holding a CNG license
and to a CNG licensee's representative.
(c)
An individual who attends a CNG continuing education course
shall receive credit only if the individual attends the entire course.
(d)
CNG continuing education courses shall be available two
times per year at the Commission's LP-Gas Section in Austin. The CNG continuing
education courses shall be available one day in March and one day in August.
The exact date and time of the courses will be posted on the Commission's
web site at least 30 days prior to the date of the course.
(e)
The Commission shall offer the CNG continuing education
course at no charge to individuals holding a CNG license and CNG licensee
representatives.
(f)
Once every four years, each individual holding a CNG license
and each CNG licensee representative shall attend and complete a course that
is administered by the Commission.
(1)
The LP-Gas Section shall determine the course content which
shall include the Commission's adopted rules and regulations, and safety procedures
for handling CNG.
(2)
The course shall be four hours in length and shall be administered
by LP-Gas Section field inspectors.
(g)
Each individual holding a CNG license and each CNG licensee
representative who is licensed as of the effective date of this rule shall
attend and complete a course offered by the Commission no later than September
1, 2004. Each individual holding a CNG license and each CNG licensee representative
who is licensed after the effective date of this rule shall attend and complete
a course within four years from the date his or her license becomes active.
(h)
Each individual holding a CNG license and each CNG licensee
representative who fails to complete a course under the requirements of this
rule shall not be allowed to renew his or her license until that individual
or representative completes a CNG continuing education course given by the
Commission.
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 February 26, 2003.
TRD-200301426
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
The Railroad Commission of Texas proposes the repeal of 16 TAC Chapter
13, Subchapter G, §§13.2001, 13.2007, 13.2010, 13.2013, 13.2016,
13.2019, 13.2020, 13.2022, 13.2025, 13.2028, 13.2031, 13.2034, 13.2037, 13.2040,
13.2043, 13.2046, 13.2049, and 13.2052, Subchapter H, §§13.2101,
13.2104, 13.2107, 13.2110, 13.2113, 13.2116, 13.2119, 13.2122, 13.2125, 13.2128,
13.2131, 13.2134, 13.2137, and 13.2140, Subchapter J, §§13.2301,
13.2304, 13.2307, 13.2310, 13.2313, 13.2316, 13.2319, 13.2322, 13.2325, and
13.2328, Subchapter K, §§13.2401, 13.2404, 13.2407, 13.2410, 13.2413,
13.2416, 13.2419, 13.2422, 13.2425, 13.2428, 13.2431, 13.2434, 13.2437, and
13.2440, Subchapter L, §§13.2501, 13.2504, 13.2507, 13.2510, 13.2513,
and 13.2516, Subchapter M, §§13.2601, 13.2604, 13.2607, 13.2610,
13.2613, 13.2616, 13.2619, 13.2622, 13.2625, 13.2628, 13.2631, 13.2634, 13.2637,
13.2640, and 13.2643, and Subchapter N, §§13.2701, 13.2704, 13.2705,
13.2707, 13.2710, 13.2713, 13.2716, 13.2719, 13.2722, 13.2725, 13.2728, 13.2731,
13.2734, 13.2737, 13.2740, 13.2743, 13.2746, and 13.2749, relating to the
Regulations for Liquefied Natural Gas (LNG). The Commission proposes the repeals
in order to separate the LNG rules and the compressed natural gas (CNG) rules
(which are found in 16 TAC Chapter 13, Subchapters A - F) into their own individual
chapters to avoid confusion over having both fuels covered in one chapter.
In concurrent proposals, the new LNG rules will be proposed in Chapter 14
and the review proposed for the LNG rules as required under Texas Government
Code, §2001.039.
Byron Caffey, Assistant Director, LP-Gas Section, Gas Services Division,
has determined that for each year of the first five years the repeals are
in effect there will be no fiscal implications for state or local governments
as a result of the repeals because the rules will continue to exist in new
Chapter 14.
Mr. Caffey 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 the
repeals and the concurrently proposed new rules in Chapter 14 will be clarification
of the Commission's requirements for LNG. There is no anticipated economic
cost of compliance associated with the 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 30 days after publication in the
Texas Register
and should refer to LP-Gas Docket No. 1613. 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 Byron Caffey at (512) 463-5762.
The status of Commission rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
Subchapter G. GENERAL APPLICABILITY AND REQUIREMENTS
16 TAC §§13.2001, 13.2007, 13.2010, 13.2013, 13.2016, 13.2019, 13.2020, 13.2022, 13.2025, 13.2028, 13.2031, 13.2034, 13.2037, 13.2040, 13.2043, 13.2046, 13.2049, 13.2052
(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 repeals are proposed under Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to liquefied natural gas activities to protect the health, welfare,
and safety of the general public.
Cross-reference to statute: Texas Natural Resources Code, §116.012.
Issued in Austin, Texas, on February 25, 2003.
§13.2001.LNG Advisory Committee.
§13.2007.Definitions.
§13.2010.LNG Report Forms.
§13.2013.Licenses and Related Fees.
§13.2016.Licensing Requirements.
§13.2019.Examination and Course of Instruction.
§13.2020.Employee Transfers.
§13.2022.Denial, Suspension, or Revocation of Licenses or Certifications, and Hearing Procedure.
§13.2025.Designation of Outlet and Operations Supervisor (Branch Manager).
§13.2028.Franchise Tax Certification and Assumed Name Certificates.
§13.2031.Insurance Requirements.
§13.2034.Self-Insurance Requirements.
§13.2037.Components of LNG Stationary Installations Not Specifically Covered.
§13.2040.Filings and Notice Requirements for Stationary LNG Installations.
§13.2043.Temporary Installations.
§13.2046.Filings Required for School Bus, Mass Transit, and Special Transit Vehicles.
§13.2049.Report of LNG Incident/Accident.
§13.2052.Application for an Exception to a Safety Rule.
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 February 26, 2003.
TRD-200301432
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§13.2101, 13.2104, 13.2107, 13.2110, 13.2113, 13.2116, 13.2119, 13.2122, 13.2125, 13.2128, 13.2131, 13.2134, 13.2137, 13.2140
(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 repeals are proposed under Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to liquefied natural gas activities to protect the health, welfare,
and safety of the general public.
Cross-reference to statute: Texas Natural Resources Code, §116.012.
Issued in Austin, Texas, on February 25, 2003.
§13.2101.Uniform Protection Requirements.
§13.2104.Uniform Safety Requirements.
§13.2107.Stationary LNG Storage Containers.
§13.2110.LNG Container Installation Distance Requirements.
§13.2113.Maintenance Tanks.
§13.2116.Transfer of LNG.
§13.2119.Transport Vehicle Loading and Unloading Facilities and Procedures.
§13.2122.Transfer Systems, Including Piping, Pumps, and Compressors, Used for LNG and Refrigerants.
§13.2125.Hoses and Arms.
§13.2128.Communications and Lighting.
§13.2131.Fire Protection.
§13.2134.Container Purging Procedures.
§13.2137.Employee Safety and Training.
§13.2140.Inspection and Maintenance.
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 February 26, 2003.
TRD-200301433
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§13.2301, 13.2304, 13.2307, 13.2310, 13.2313, 13.2316, 13.2319, 13.2322, 13.2325, 13.2328
(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 repeals are proposed under Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to liquefied natural gas activities to protect the health, welfare,
and safety of the general public.
Cross-reference to statute: Texas Natural Resources Code, §116.012.
Issued in Austin, Texas, on February 25, 2003.
§13.2301.Applicability.
§13.2304.General Facility Design.
§13.2307.Indoor Fueling.
§13.2310.Emergency Refueling.
§13.2313.Fuel Dispensing Systems.
§13.2316.Filings Required for Installation of Fuel Dispensers.
§13.2319.Automatic Fuel Dispenser Safety Requirements.
§13.2322.Protection of Automatic and Other Dispensers.
§13.2325.LNG Transport Unloading at Fueling Facilities.
§13.2328.Training, Written Instructions, and Procedures Required.
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 February 26, 2003.
TRD-200301434
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§13.2401, 13.2404, 13.2407, 13.2410, 13.2413, 13.2416, 13.2419, 13.2422, 13.2425, 13.2428, 13.2431, 13.2434, 13.2437, 13.2440
(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 repeals are proposed under Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to liquefied natural gas activities to protect the health, welfare,
and safety of the general public.
Cross-reference to statute: Texas Natural Resources Code, §116.012.
Issued in Austin, Texas, on February 25, 2003.
§13.2401.General Provisions for Piping Systems and Components.
§13.2404.Piping Materials.
§13.2407.Fittings Used in Piping.
§13.2410.Valves.
§13.2413.Installation of Piping.
§13.2416.Installation of Valves.
§13.2419.Welding at Piping Installations.
§13.2422.Pipe Marking and Identification.
§13.2425.Pipe Supports.
§13.2428.Inspection and Testing of Piping.
§13.2431.Welded Pipe Tests.
§13.2434.Purging of Piping Systems.
§13.2437.Pressure and Relief Valves in Piping.
§13.2440.Corrosion Control.
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 February 26, 2003.
TRD-200301435
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§13.2501, 13.2504, 13.2507, 13.2510, 13.2513, 13.2516
(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 repeals are proposed under Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to liquefied natural gas activities to protect the health, welfare,
and safety of the general public.
Cross-reference to statute: Texas Natural Resources Code, §116.012.
Issued in Austin, Texas, on February 25, 2003.
§13.2501.Liquid Level Gauging.
§13.2504.Pressure Gauges.
§13.2507.Vacuum Gauges.
§13.2510.Emergency Failsafe.
§13.2513.Electrical Equipment.
§13.2516.Electrical Grounding and Bonding.
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 February 26, 2003.
TRD-200301436
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC 13.2601, 13.2604, 13.2607, 13.2610, 13.2613, 13.2616, 13.2619, 13.2622, 13.2625, 13.2628, 13.2631, 13.2634, 13.2637, 13.2640, 13.2643
(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 repeals are proposed under Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to liquefied natural gas activities to protect the health, welfare,
and safety of the general public.
Cross-reference to statute: Texas Natural Resources Code, §116.012.
Issued in Austin, Texas, on February 25, 2003.
§13.2601.Applicability.
§13.2604.System Component Qualification.
§13.2607.Vehicle Fuel Containers.
§13.2610.Installation of Vehicle Fuel Containers.
§13.2613.Engine Fuel Delivery Equipment.
§13.2616.Installation of Venting Systems and Monitoring Sensors.
§13.2619.Installation of Piping.
§13.2622.installation of Valves.
§13.2625.Installation of Pressure Gauges.
§13.2628.Installation of Pressure Regulators.
§13.2631.Wiring.
§13.2634.Vehicle Fueling Connection.
§13.2637.Signs and Labeling.
§13.2640.System Testing.
§13.2643.Maintenance and Repair.
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 February 26, 2003.
TRD-200301437
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§13.2701, 13.2704, 13.2705, 13.2707, 13.2710, 13.2713, 13.2716, 13.2719, 13.2722, 13.2725, 13.2728, 13.2731, 13.2734, 13.2737, 13.2740, 13.2743, 13.2746, 13.2749
(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 repeals are proposed under Texas Natural Resources
Code, §116.012, which authorizes the Commission to adopt rules and standards
relating to liquefied natural gas activities to protect the health, welfare,
and safety of the general public.
Cross-reference to statute: Texas Natural Resources Code, §116.012.
Issued in Austin, Texas, on February 25, 2003.
§13.2701.DOT Requirements.
§13.2704.Registration of LNG Transports.
§13.2705.Decals and Fees.
§13.2707.Testing Requirements.
§13.2710.Markings.
§13.2713.Pressure Gauge.
§13.2716.Supports.
§13.2719.Electrical Equipment and Lighting.
§13.2722.Liquid Level Gauging Devices.
§13.2725.Exhaust System.
§13.2728.Extinguishers Required.
§13.2731.Manifests.
§13.2734.Transfer of LNG on Public Highways, Streets, or Alleys.
§13.2737.Parking of LNG Transports and Container Delivery Units, and Use of Chock Blocks.
§13.2740.Uniform Protection Standards.
§13.2743.Inspection of Transport Containers.
§13.2746.Delivery of Inspection Report to Licensee.
§13.2749.Issuance of LNG Form 2004 Decal.
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 February 26, 2003.
TRD-200301438
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
The Railroad Commission of Texas proposes new 16 TAC Chapter 14, relating
to the Regulations for Liquefied Natural Gas (LNG) including new Subchapter
A, §§14.2001, 14.2007, 14.2010, 14.2013, 14.2016, 14.2019, 14.2020,
14.2022, 14.2025, 14.2028, 14.2031, 14.2034, 14.2037, 14.2040, 14.2043, 14.2046,
14.2049, and 14.2052, relating to General Applicability and Requirements;
new Subchapter B, §§14.2101, 14.2104, 14.2107, 14.2110, 14.2113,
14.2116, 14.2119, 14.2122, 14.2125, 14.2128, 14.2131, 14.2134, 14.2137, and
14.2140, relating to General Rules for All Stationary LNG Installations; new
Subchapter D, §§14.2301, 14.2304, 14.2307, 14.2310, 14.2313, 14.2316,
14.2319, 14.2322, 14.2325, and 14.2328, relating to General Rules for LNG
Fueling Facilities; new Subchapter E, §§14.2401, 14.2404, 14.2407,
14.2410, 14.2413, 14.2416, 14.2419, 14.2422, 14.2425, 14.2428, 14.2431, 14.2434,
14.2437, and 14.2440, relating to Piping Systems and Components for All Stationary
LNG Installations; new Subchapter F, §§14.2501, 14.2504, 14.2507,
14.2510, 14.2513, and 14.2516, relating to Instrumentation and Electrical
Services; new Subchapter G, §§14.2601, 14.2604, 14.2607, 14.2610,
14.2613, 14.2616, 14.2619, 14.2622, 14.2625, 14.2628, 14.2631, 14.2634, 14.2637,
14.2640, and 14.2643, relating to Engine Fuel Systems; and new Subchapter
H, §§14.2701, 14.2704, 14.2705, 14.2707, 14.2710, 14.2713, 14.2716,
14.2719, 14.2722, 14.2725, 14.2728, 14.2731, 14.2734, 14.2737, 14.2740, 14.2746,
and 14.2749, relating to LNG Transports.
In a concurrent rulemaking, the Commission has proposed the repeal of the
current LNG rules from Chapter 13, Subchapters G, H, and J - N, in order to
separate the LNG rules and the compressed natural gas (CNG) rules into their
own individual chapters and to avoid confusion over having both fuels covered
in one chapter.
The Commission proposes the new rules in Chapter 14 with the identical
rule numbers as they currently have in Chapter 13, except the rule numbers
will begin with "14" instead of "13." Many of the new rules in Chapter 14
include different language from the rules as they currently exist in Chapter
13, as explained in the following paragraphs. In general, there are five types
of language changes: statutory changes resulting from Senate Bill 310 (SB
310), 77th legislature (2001); changes to address issues related to professional
engineering practices; changes approved by the Commission's LNG Advisory Committee;
non-substantive changes such as wording, punctuation, or organization; and
no changes other than the rule number.
Senate Bill 310 Changes
The first group of changes result from SB 310 and are found in §14.2016(f).
The new wording addresses license and license renewal requirements and requires
a renewal fee of 1 1/2 times the renewal fee required in §14.2013(b)
(relating to Licenses and Related Fees) if a person's license has expired
for 90 calendar days or fewer, and a renewal fee of two times the renewal
fee required in §14.2013(b) if the license has expired for more than
90 calendar days but less than one year. If a person's license has been expired
for one year or longer, that person may not renew, but shall complete the
requirements for a new license. New subsection (f)(4) allows a person who
was previously licensed in this state, moved to another state, and is currently
licensed and has been in practice in the other state for the two years preceding
the date of application to obtain a new license without reexamination. The
person shall pay a fee to the Commission that is equal to two times the renewal
fee required in §14.2013. The wording in subsection (f)(4)(A) and (B)
requires the person to submit proof of having been in practice and licensed
in good standing in the other state, as well as requiring the person to comply
with other licensing requirements such as insurance.
Section 14.2019(a)(4) and (5) include new wording based on SB 310 establishing
the times when applicants may take the rules examination; that a minimum score
of at least 75% is required (this is not required by SB 310, but is consistent
with the minimum score for LP-gas examinations); that the Commission will
notify individuals of examination results within 30 days; and that a testing
service may be used. A new sentence in paragraph (5)(C) states that an individual
who fails an examination may request in writing that the Commission furnish
an analysis of the individual's performance on the examination.
New subsection (e) addresses another SB 310 issue regarding expired certificates.
Any renewal submitted after the August 31 deadline shall be considered expired.
If an individual wishes to renew a certification that has been expired for
less than one year, the individual shall submit the annual renewal fee and
late filing fee, and proof of successful completion of the examination required
for certification. Upon verification that the individual's certificate has
not been suspended, revoked, or expired for one year or longer, the Commission
shall renew the individual's certificate.
Professional Engineering Changes
The second group of changes address professional engineering activities.
These changes will make the LNG rules as consistent as possible with the Commission's
LP-gas rules (16 TAC Chapter 9), especially with regard to Commission procedures,
deadlines, and fees, and are mostly non-substantive. These types of wording
changes are found in §§14.2010(21), 14.2037, 14.2040, 14.2310, and
14.2316.
LNG Advisory Committee Changes
The third group of changes were discussed and approved by the Commission's
LNG Advisory Committee. The committee approved changes to §§14.2007,
14.2010, 14.2013, 14.2016, 14.2019, 14.2031, and 14.2040 which are substantive
in nature. Specifically, amendments to §14.2007 amend the definition
of "mass transit vehicle" and add definitions for "transport" and "transport
system." The new wording clarifies these terms which are commonly used in
these regulations. In §14.2010, two new forms are added (in paragraphs
(13) and (19)), while other changes are made for clarification. Section 14.2013(b)(2)
and (5) include minor clarifications. Section 14.2016(e)(3) adds license categories
15 and 20 to category 50 as categories that include testing activities.
In §14.2019(f) and in the table, the one-hour course currently in §13.2019
has been deleted and the reference to the 32-hour course has been changed
to the Category 35 course of instruction. Course attendees shall pay the course
fee as established by the division director.
Proposed §14.2031 includes the addition of license categories 15 and
25 to the table in the row requiring product liability insurance; this is
a current Commission practice consistent with the LP-gas and CNG rules. Also,
new language in subsection (b) describes certificates of insurance and requirements
for these; the language tracks the Commission's corresponding CNG rule.
Proposed language requiring LNG Form 2019 is added in §14.2040(a);
this form will be required when a person purchases an existing LNG installation
and wishes for it to remain in LNG service. In addition, the notice requirements
in subsections (c) and (d) wherein real property owners must be notified of
a new LNG installation or an addition to an existing LNG installation are
changed from current §13.2040. The distances in which notification is
required--currently up to 900 feet for certain installations--are proposed
to be decreased to 500 feet for all installations. The Commission finds this
acceptable because of the tremendous safety equipment included in any LNG
installation; in addition, this is the same notice requirement in the Commission's
LP-gas and CNG regulations. The aggregate water capacities of 15,540 and 214,348
gallons are the equivalent gas volumes to the requirements in the LP-gas rules
for 10,000 and 120,000 gallons aggregate water capacities, respectively.
In new §14.2043, language in new subsection (h) requires temporary
installations to comply with DOT rules, as well as the Commission's applicable
Pipeline Safety rules.
Section 14.2104 clarifies the activities of Category 15, 20, and 50 licensees
regarding examination and inspection of containers.
In §14.2310, new subsection (d) is added, stating that emergency refueling
vehicles are not required to be registered with the Commission.
In the table in §14.2637, the change from current §13.2637 is
found in the second row, where the language "(not required for systems installed
by OEM or OEM's subcontractor)" is added for clarification. In addition, the
table in current §13.2637 contains an asterisk under the "Engine Compartment"
column for the row requiring the maximum allowable working pressure; that
asterisk is deleted from the §14.2637 table because that sign or label
is not required.
Section 14.2640(d) clarifies that Category 20 and 50 licensees, as well
as Category 15 licensees, may perform these activities.
In §14.2701, subsection (b) is changed because effective October 1,
1998, the United States Department of Transportation's jurisdiction expanded
from strictly interstate to intrastate operations of hazardous materials transportation,
including LNG. In §14.2704, the table in §13.2704 is not retained,
but the requirements regarding current registration fees, forms, and procedures
are more accurately specified. Registration fees are proposed to be $270 for
each transport truck, semi-trailer, or other motor vehicle equipped with an
LNG cargo tank. The fee to transfer each such unit to a new owner is $100
per vehicle. These fees are currently charged and do not represent any increase
in amounts.
Proposed §14.2707 deletes references to registered testing laboratories
and adds references to the Commission's appropriate license categories. The
testing procedures in current §13.2707(b) are deleted and a reference
to 49 CFR §338 is added to cover these procedures.
Proposed §14.2749 clarifies that either a decal or a letter of authority
issued by the Commission shall serve to verify that a particular LNG transport
has been properly registered. Proposed new subsection (f) allows a small amount
of LNG to be introduced into a new container if it will provide the fuel to
deliver the unit to its new location.
Current §13.2743, relating to Inspection of Transport Containers,
is not proposed as a new rule in Chapter 14. The LNG advisory committee recommended
it be deleted because LNG transports must comply with United States Department
of Transportation specification MC-338, so inspection by the Commission is
unnecessary.
Other Non-substantive Changes
The fourth group of changes are non-substantive and include changes in
wording, punctuation, or organization to provide better clarity or consistency.
For example, references to the LP-Gas Division have been changed to reflect
the current organization of the Commission. Citations to statutes or other
Commission rules have been corrected. Rules including these types of non-substantive
changes are §§14.2001, 14.2007(5), (13), (21), (28), and (35), 14.2016(c),
14.2022, 14.2052, 14.2122, 14.2125, 14.2137, 14.2407. 14.2416, 14.2607, 14.2610,
14.2619, and 14.2705.
Section 14.2019(b)(5) clarifies current procedures that a trainee who takes
the rules examination shall cease performing LP-gas activities which require
certification until the individual is notified of a passing score, even if
time remains in the 45-day trainee period.
In §14.2040(c)(5), the Commission has added some additional wording
regarding objections; this wording clarifies the procedures and makes the
LNG rule consistent with the LP-gas rules. New subsection (l) addresses current
Commission practice regarding physical inspections of stationary installations
and is modeled after the same requirement in the CNG rules. Similarly, new
subsections (m) regarding hearings, (n) regarding material variances, and
(o) regarding fees for re-inspections specify current Commission practices.
Section 14.2046 is reworded from current §13.2046 to use active voice
and to clarify the procedures for LNG Form 2503 and the Commission inspection
of vehicles.
Section 14.2052(d) contains new wording regarding objections to requests
for an exception to a safety rule. These objections must be in writing, filed
at the Commission within 18 calendar days of the postmark of the application,
and shall be based on facts that tend to demonstrate that the proposed exception
would have an adverse effect on public health, safety, or welfare. The Commission
may decline to consider objections based solely on claims of diminished property
or esthetic values in the area.
Section 14.2110 clarifies some distance requirements for containers with
aggregate water capacities of 93,241 gallons or more, underground containers,
and LNG dispensers or points of transfer; the distances are based on the industry
standard, NFPA 59A,
Standard for the Production,
Storage, and Handling of Liquefied Natural Gas (LNG)
.
Section 14.2313 corrects a reference to nationally-recognized testing laboratories
to the correct references of Category 15, 20, or 50 licensees.
No Changes Other Than Rule Numbers
Many of the LNG rules have no wording changes other than the chapter number
in the rule changing from 13 to 14. These include §§14.2001, 14.2020,
14.2034, 14.2049, 14.2101, 14.2107, 14.2113, 14.2116, 14.2119, 14.2128, 14.2131,
14.2134, 14.2140, 14.2301, 14.2304, 14.2307, 14.2139, 14.2322, 14.2325, 14.2401,
14.2404, 14.2410, 14.2413, 14.2419, 14.2422, 14.2425, 14.2428, 14.2431, 14.2434,
14.2437, 14.2440, 14.2501, 14.2504, 14.2507, 14.2510, 14.2513, 14.2516, 14.2601,
14.2604, 14.2613, 14.2616, 14.2622, 14.2625, 14.2628, 14.2631, 14.2634, 14.2643,
14.2710, 14.2713, 14.2719, 14.2722, 14.2725, 14.2728, 14.2731, 14.2734, 14.2737,
14.2740, and 14.2746.
In a separate proposal, the Commission proposes the rule review for the
LNG rules required under Texas Government Code, §2001.039. The separate
rule review documents will be filed with the
Texas
Register
concurrently with this rulemaking.
Byron Caffey, Assistant Director, LP-Gas Section, Gas Services Division,
has determined that for each year of the first five years the sections are
in effect there will be no fiscal implications for state or local governments
as a result of enforcing or administering the sections because the rules already
exist. In §14.2019(d), the $20 certificate renewal fee is increased to
$25, which is consistent with the similar LP-gas fee. However, there are very
few LNG certificate holders, so there will be little revenue effect on the
Commission from this increase.
In the table in §14.2031, the Commission proposes to add Category
15 to the product liability insurance requirement. This corresponds to the
Commission's applicable LP-gas rule. Also, new language proposed in subsection
(b) does not add any further fiscal implications but clarifies other insurance
requirements; the proposed language also corresponds to the Commission's LP-gas
rule.
In §14.2040, proposed amendments to subsections (c) and (d) should
decrease the fiscal implications for LNG installations because the notice
requirement which currently extends up to 900 feet from the proposed container's
location is being decreased to 500 feet. This will result in most cases in
the LNG applicant having to notify a smaller number of real property owners
in that notice area.
Mr. Caffey has also determined that for each year of the first five years
the sections are in effect the public benefit anticipated as a result of enforcing
the sections will be the better understanding of the rule requirements for
the LNG industry and the general public. The anticipated economic cost to
individuals or small businesses required to comply with the proposed amendments
will be the same as the fiscal implications discussed in the preceding paragraphs.
Mr. Caffey has also determined that for each year of the first five years
the sections are in effect the public benefit anticipated as a result of enforcing
the sections will be the proper registration of LNG transports to ensure that
these transports are safe for use in Texas. There is no anticipated economic
cost to small businesses and to individuals required to comply because the
current $270 registration fee and $100 transfer fee are not being changed.
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 should refer to LP-Gas Docket No. 1613. 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 Byron Caffey at (512) 463-5762.
The status of Commission rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
Subchapter A. GENERAL APPLICABILITY AND REQUIREMENTS
16 TAC §§14.2001, 14.2007, 14.2010, 14.2013, 14.2016, 14.2019, 14.2020, 14.2022, 14.2025, 14.2028, 14.2031, 14.2034, 14.2037, 14.2040, 14.2043, 14.2046, 14.2049, 14.2052
The new rules are proposed under Texas Natural Resources Code, §116.012,
which authorizes the Commission to adopt rules and standards relating to liquefied
natural gas activities to protect the health, welfare, and safety of the general
public; and under Senate Bill 310, 77th Legislature (2001), as codified at
Texas Natural Resources Code, §§116.032, 116.033, 116.034, and 116.0346.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on February 25, 2003.
§14.2001.LNG Advisory Committee.
(a)
Definitions. The following words and terms, when used in
this section, shall have the following meanings, unless the context clearly
indicates otherwise.
(1)
Commission--The Railroad Commission of Texas.
(2)
Committee--The LNG Advisory Committee of the Railroad Commission
of Texas.
(3)
Consumer representative--A member of the committee who
is not engaged in the business of producing, distributing or retailing LNG
and who is not engaged in the business of designing, manufacturing, distributing
or retailing LNG equipment or performing LNG related research or other services,
but who is an end user of LNG fuel, including but not limited to a consumer
of LNG as an automotive or other transportation fuel.
(4)
Division--The Gas Services Division, LP-Gas Section, of
the Railroad Commission of Texas.
(5)
Fiscal year--September 1 of a year through August 31 of
the following year.
(6)
Industry representative--A member of the committee who
is engaged in the business of producing, distributing or retailing LNG or
who is engaged in the business of designing, manufacturing, distributing or
retailing LNG equipment or performing LNG related research or other services.
(7)
Local government representative--A member of the committee
who is a fire marshal for a city or county.
(8)
LNG--Liquefied natural gas, as that term is defined in
Texas Natural Resources Code, Chapter 116.
(9)
Member--An industry representative, a consumer representative,
or a representative of local government who serves on the LNG Advisory Committee
of the Railroad Commission of Texas.
(10)
Presiding officer--The chairman of the LNG Advisory Committee
of the Railroad Commission of Texas.
(b)
Establishment; Duration. The LNG Advisory Committee of
the Railroad Commission of Texas is hereby established effective January 1,
1995. The committee is abolished on August 31, 2002, unless the commission
amends this subsection to establish a different date.
(c)
Purpose and Duties. The purpose of the committee is to
give the commission the benefit of the members' collective business, environmental,
and technical expertise and experience to help the commission develop and
implement rules for the safe use of LNG. The committee's sole duty is to advise
the commission. The committee has no executive or administrative powers or
duties with respect to the operation of the division. All such powers and
duties rest solely with the commission.
(d)
Composition of Committee; Membership Terms. The committee
shall be composed of eight members, seven of whom are voting members. The
seven voting members shall include three LNG consumers, three members of the
LNG industry, and one representative from local government; one industry representative
shall be a registered professional engineer licensed to practice in the State
of Texas. All members serve at the pleasure of the commission, for a period
of two years. The director of the Liquefied Petroleum Gas Division shall serve
as an ex officio, non-voting member of the committee.
(e)
Nominations for Committee Membership. Any person may nominate
a candidate or candidates for membership on the committee. Nominations shall
be in writing and submitted by November 15, 1994, for the initial committee,
and by January 1 of each odd-numbered year thereafter. Nominations may be
submitted to the commission, a commissioner, or the director of the division
for transmission to the commission.
(f)
Appointment of Members. All members of the committee are
appointed by and serve at the pleasure of the commission. The commission shall
appoint members of the first committee by January 1, 1995, and by August 31
of each odd-numbered year thereafter, such that the composition of the committee
meets the requirements of subsection (d) of this section. If a member resigns
or otherwise vacates his or her position prior to the end of his or her term,
the commission shall appoint a replacement who shall serve the remainder of
the unexpired term.
(g)
Reimbursement of Members' Expenses. The commission shall
not reimburse members for travel or other expenses related to service on the
committee.
(h)
Presiding Officer; Other Officers. The committee shall
elect from its members a presiding officer who shall report the committee's
advice and attendance in writing to the commission. The committee may elect
other officers at its pleasure.
(i)
Subcommittees. The committee may organize itself into subcommittees.
One member of each subcommittee shall serve as the chair of that subcommittee.
The subcommittee chairs shall make written reports regarding their subcommittee's
work to the presiding officer.
(j)
Meetings. The committee shall meet at the call of the presiding
officer or the commission. Committee and subcommittee meetings are open to
the public.
(k)
Committee Records. The division staff shall record and
maintain the originals of the minutes of each committee and subcommittee meeting.
The division shall maintain a record of actions taken by the committee and
shall distribute copies of approved minutes and other committee documents
to the commission and the committee members.
(l)
Evaluation of Committee Costs and Benefits. By October
1 of each year, the division director shall evaluate for the previous fiscal
year and report to the commission:
(1)
the committee's work;
(2)
the committee's usefulness; and
(3)
the costs related to the committee's existence, including
the cost of commission staff time spent in support of the committee's activities.
(m)
Report to Legislative Budget Board. The commission shall
biennially report to the Legislative Budget Board the information developed
under subsection (l) of this section in evaluating the committee's costs and
benefits.
§14.2007.Definitions.
The following words and terms when used in the Regulations for Liquefied
Natural Gas shall have the following meanings unless the context clearly indicates
otherwise.
(1)
Administrative Procedure Act--Texas Government Code, Chapter
2001.
(2)
Aggregate water capacity--The sum of all individual container
capacities as measured by weight or volume of water when the containers in
a battery at an installation are full.
(3)
ANSI--American National Standards Institute.
(4)
API--American Petroleum Institute.
(5)
Approved--Authorized by the Division or the Commission.
(6)
ASME--American Society of Mechanical Engineers.
(7)
ASME Code--The American Society of Mechanical Engineers
Boiler and Pressure Vessel Code, Section I, Section IV, Section VIII, and
Section IX.
(8)
Automatic fuel dispenser--A fuel dispenser which requires
transaction authorization.
(9)
Branch manager--See "Operations supervisor."
(10)
Certified--Authorized to perform LNG activities under
the direction of a licensee as set forth in the Texas Natural Resources Code.
Certification alone does not allow an employee to perform those activities
which require licensing.
(11)
Combustible material--A solid material which, in the form
in which it is used and under the conditions anticipated, can be ignited and
will burn, support combustion, or release flammable vapors when subjected
to fire or heat.
(12)
Commercial installation--An LNG equipment installation
located on premises other than a single-family dwelling used primarily as
a residence.
(13)
Commission--The Railroad Commission of Texas or an operating
division of the Commission or a division's employees.
(14)
Company representative--An owner or employee of a licensee
designated by that licensee to take any required courses and exams and to
actively supervise LNG operations of the licensee.
(15)
Container--Any LNG vessel manufactured to the applicable
sections of the API Code, ASME Code, or DOT requirements in effect at the
time of manufacture.
(16)
Container appurtenances--Components installed in container
openings, including but not limited to pressure relief devices, shutoff valves,
backflow check valves, excess flow check valves, internal valves, liquid level
gauges, pressure gauges, and plugs.
(17)
Conversion--The changes made to a vehicle to allow it
to use LNG as a motor fuel.
(18)
Design pressure--The pressure for which a system or portion
of that system is designed.
(19)
Dike--A structure used to establish an impounding area.
(20)
Dispensing system--That combination of valves, meters,
hoses, piping, electrical connections, and fuel connections used to distribute
LNG to mobile or motor fuel containers.
(21)
Division--The Director of the Gas Services Division of
the Railroad Commission of Texas or the director's delegate.
(22)
DOT--The United States Department of Transportation.
(23)
Employee--Any individual who renders or performs any services
or labor for compensation, including individuals hired on a part-time or temporary
basis, full-time or permanent basis; independent contractors; and owner-employees.
(24)
Failsafe--Design features which provide for safe conditions
in the event of a malfunction of control devices or an interruption of an
energy source or an emergency shutdown.
(25)
Final approval--The authority issued by the Commission
or the Railroad Commission allowing the introduction of LNG into a container
and system.
(26)
Fired equipment--Any equipment in which the combustion
of fuels takes place.
(27)
Fixed-length dip tube--A pipe with a fixed open end positioned
inside a container at a designated elevation to measure a liquid level.
(28)
General Rules of Practice and Procedure of the Railroad
Commission of Texas--Chapter 1 of this title (relating to Practice and Procedure).
(29)
Ignition source--Any item, substance, or event having
adequate temperature and energy release of the type and magnitude sufficient
to ignite any flammable mixture of gases or vapors that could occur at a site.
(30)
Impounding area--An area defined through the use of dikes
or the topography at the site for the purpose of containing any accidental
spill of LNG.
(31)
Individual--One human being. (See also "Person".)
(32)
Interim approval--The authority issued by the Railroad
Commission of Texas following a public hearing allowing construction of an
LNG installation.
(33)
Labeled--The attachment to equipment or materials of a
label, symbol, or other identifying mark of a nationally recognized testing
laboratory or a Category 50 licensee which conducts product evaluation, periodically
inspects production of listed equipment or materials, and which publishes
its findings in a list indicating that the equipment either meets appropriate
standards or has been tested and found suitable for use in a specified manner.
(34)
LFL--Lower flammability limit.
(35)
Licensed--Authorized to perform LNG activities through
the issuance of a valid license by the Commission.
(36)
Licensee--A person which has applied for and been granted
an LNG license by the commission.
(37)
Listed--The inclusion of equipment or materials in a list
published by a nationally recognized testing laboratory or a Category 50 licensee
which conducts product evaluation, periodically inspects production of listed
equipment or materials, and whose listing states either that the equipment
or material meets appropriate standards or has been tested and found suitable
for use in a specified manner.
(38)
LNG--Natural gas, consisting primarily of methane, that
has been condensed to liquid by cooling.
(39)
LNG system--A system of safety devices, containers, and
other LNG equipment installed at a facility or on a vehicle and designed for
use in the sale, storage, transportation for delivery, or distribution of
LNG.
(40)
LNG transport--Any vehicle or combination of vehicles
and LNG containers designed or adapted for use or used principally as a means
of moving or delivering LNG from one place to another, including but not limited
to any truck, trailer, semi-trailer, cargo tank, or other vehicle used in
the distribution of LNG.
(41)
Mass transit vehicle--Any vehicle which is owned or operated
by a political subdivision of a state, city, or county, and which is used
primarily in the conveyance of the general public.
(42)
Maximum allowable working pressure--The maximum gauge
pressure permissible at the top of completed equipment, containers, or vessels
in their operating position for a design temperature.
(43)
Mobile fuel container--An LNG container mounted on a vehicle
and used to store LNG as the fuel supply for uses other than motor fuel.
(44)
Mobile fuel system--An LNG system to supply fuel to an
auxiliary engine other than the engine used to propel the vehicle or for other
uses on the vehicle.
(45)
Motor fuel container--An LNG container mounted on a vehicle
and used to store LNG as the fuel supply to an engine used to propel the vehicle.
(46)
Motor fuel system--An LNG system to supply LNG as a fuel
for an engine used to propel the vehicle.
(47)
NEC--National Electric Code (NFPA 70).
(48)
NFPA--National Fire Protection Association.
(49)
Noncombustible material--A solid material which in no
conceivable form or combination with other material will ignite.
(50)
Nonlicensee--A person not required to be licensed, but
which shall comply with all other applicable Regulations for Liquefied Natural
Gas.
(51)
Operations supervisor--An individual who actively supervises
LNG operations at an outlet.
(52)
Outlet--A site operated by an LNG licensee at which the
business conducted materially duplicates the operation for which the licensee
is initially granted a license.
(53)
Person--An individual, sole proprietor, partnership, firm,
joint venture, corporation, association, or any other business entity, state
agency or institution, county, municipality, school district, or other governmental
subdivision.
(54)
Point of transfer--The point at which a connection is
made to transfer LNG from one container to another.
(55)
Pressure relief valve--A valve which is designed both
to open automatically to prevent a continued rise of internal fluid pressure
in excess of a specified value (set pressure) and to close when the internal
fluid pressure is reduced below the set pressure.
(56)
Pressure vessel--A container or other component designed
in accordance with the ASME Code.
(57)
Primary component--Those safety-related components which
may be stressed to a significant level, those whose failure would permit release
of flammable fluids, and those subject to thermal shock. Primary components
include but are not limited to the following parts of a single-wall tank or
of the inner tank in a double-wall tank: seals, gaskets, shell plates, bottom
plates, roof plates, knuckle plates, compression rings, shell stiffeners,
manways, and nozzles including reinforcement, shell anchors, pipe, tubing,
forging, and bolting.
(58)
Property line--That boundary which designates the point
at which one real property interest ends and another begins. (See also "Right-of-way".)
(59)
PSF--Pounds per square foot.
(60)
PSI--Pounds per square inch.
(61)
PSIG--Pounds per square inch gauge.
(62)
PSIA--Pounds per square inch absolute.
(63)
Public transportation vehicle--A vehicle for hire or service
to the general public including but not limited to taxis, buses, and airport
courtesy cars.
(64)
Railroad Commission of Texas--The members of the Railroad
Commission of Texas.
(65)
Repair to container--The correction of damage or deterioration
to an LNG container, the alteration of the structure of such a container,
or the welding on such a container in a manner which causes the temperature
of the container to rise above 400 degrees Fahrenheit.
(66)
Right-of-way--The strip of land over which a public roadway
such as a street, alley, or highway is built, or land occupied by a railroad
for its main line.
(67)
School--A public or private institution which has been
accredited through the Texas Education Agency or the Texas Private School
Accreditation Commission.
(68)
School bus--A vehicle that is sold or used for purposes
that include carrying students to and from school or related events.
(69)
Special transit vehicle--A vehicle which is primarily
used by a school or mass transit authority for special transit purposes such
as transport of mobility impaired individuals.
(70)
TEMA--Tubular Exchanger Manufacturers Association.
(71)
Temporary installation--A dispensing station, either skid-mounted
or on a transport unit, that is intended to be used for a finite period of
time.
(72)
Tentative approval--The authority issued by the Commission
without a hearing allowing construction of an LNG installation.
(73)
Thermal expansion relief valve--A pressure relief valve
that is activated by pressure created by a fluid temperature rise.
(74)
Trainee--An individual employed by a licensee for a period
not to exceed 45 days without that individual having successfully completed
the required examinations for the LNG activities to be performed.
(75)
Transfer area--That portion of an LNG refueling station
where LNG is introduced into or dispensed from a stationary installation.
(76)
Transfer system--All piping and equipment used in transferring
LNG between containers.
(77)
Transition joint--A connector fabricated of two or more
metals used to join piping sections of two different materials.
(78)
Transport--Any bobtail or semi-trailer equipped with one
or more containers.
(79)
Transport system--Any and all piping, fittings, valves,
and equipment on a transport, excluding the container.
(80)
Ultimate consumer--The person controlling LNG immediately
prior to its ignition.
(81)
Vaporizer--A device other than a container that receives
LNG in liquid form and adds sufficient heat to convert the liquid to a gaseous
state.
(82)
Water capacity--The amount of water in gallons required
to fill a container.
§14.2010.LNG Report Forms.
Under the provisions of the Texas Natural Resources Code, Chapter 116,
the Commission has designated the following forms for use by the division.
(1)
LNG Form 2001. Application for License.
(2)
LNG Form 2001A. Branch Outlet List.
(3)
LNG Form 2003. Liquefied Natural Gas License.
(4)
LNG Form 2004. Liquefied Natural Gas Transport Vehicle
Identification.
(5)
LNG Form 2005. Manufacturer's Data Report.
(6)
LNG Form 2007. Liquefied Natural Gas Truck Registration.
(7)
LNG Form 2008. Manufacturer's Report of Pressure Vessel
Repair, Modification, or Testing.
(8)
LNG Form 2016. Application for Examination.
(9)
LNG Form 2016A. Certified Employee Transfer Certification.
(10)
LNG Form 2018. Statement of Lost or Destroyed License.
(11)
LNG Form 2018B. Statement of Lost or Destroyed LNG Form
2004.
(12)
LNG Form 2020. Report of LNG Incident/Accident.
(13)
LNG Form 2019. Transfer of Liquefied Natural Gas Bulk
Storage Plants.
(14)
LNG Form 2021. Notice of Intent to Appear.
(15)
LNG Form 2023. Statement in Lieu of Container Testing.
(16)
LNG Form 2025. Application and Notice of Exception to
the Regulations for Liquefied Natural Gas.
(17)
LNG Form 2026. Franchise Tax Certification.
(18)
LNG Form 2027A. Application for Qualification as Self-Insurer,
Motor Vehicle Liability.
(19)
LNG Form 2027B. Application for Qualification as Self-Insurer,
General Liability.
(20)
LNG Form 2028. Application to Use Irrevocable Letter of
Credit.
(21)
LNG Form 2500. Application for Installation.
(22)
LNG Form 2500A. Notice of Proposed LNG Installation.
(23)
LNG Form 2501. Completion Report for Commercial Installations
of Less Than 15,540 Gallons Aggregate Capacity.
(24)
LNG Form 2503. Application to Install an LNG System on
School Bus, Mass Transit, or Special Transit Vehicles.
(25)
LNG Form 2504. Notice of Subsequent Installation or Conversion.
(26)
LNG Form 2505. Testing Procedures Certification.
(27)
LNG Form 2995. Certification of Political Subdivision
of Self-Insurance for General Liability, Workers' Compensation, and/or Motor
Vehicle Liability Insurance.
(28)
LNG Form 2996A. Certificate of Insurance, Workers' Compensation
and Employer's Liability or Alternative Accident/Health Insurance.
(29)
LNG Form 2996B. Statement in Lieu of Filing Certifying
Workers' Compensation Coverage, Including Employer's Liability Insurance or
Alternative Accident/Health Insurance.
(30)
LNG Form 2997A. Certificate of Insurance, Motor Vehicle
Bodily Injury, and Property Damage Liability.
(31)
LNG Form 2997B. Statement in Lieu of Motor Vehicle Bodily
Injury, and Property Damage Liability Insurance.
(32)
LNG Form 2998A. Certificate of Insurance, General Liability.
(33)
LNG Form 2998B. Statement in Lieu of General Liability
Insurance and/or Completed Operations and Products Liability Insurance.
§14.2013.Licenses and Related Fees.
(a)
A prospective licensee may apply to the commission for
one or more licenses specified in subsection (b)(1) - (8) of this section.
Fees required to be paid shall be those established by the commission and
in effect at the time of licensing or renewal.
(b)
The license categories and fees are as follows:
(1)
A Category 15 license for container manufacturers and/or
fabricators authorizes the manufacture, fabrication, assembly, repair, installation,
testing, and sale of LNG containers, including LNG motor or mobile fuel containers
and systems, and the repair of transport and transfer systems for use in Texas.
The original license fee is $1,000; the renewal fee is $600.
(2)
A Category 20 license for transport outfitters authorizes
the subframing, testing, and sale of LNG transport containers; the testing
of LNG storage containers; the installation, testing, and sale of LNG motor
or mobile fuel containers and systems; and the installation and repair of
transport systems and motor or mobile fuel systems for use in Texas. The original
license fee is $400; the renewal fee is $200.
(3)
A Category 25 license for carriers authorizes the transportation
of LNG by transport, including the loading and unloading of LNG. The original
license fee is $1,000; the renewal fee is $300.
(4)
A Category 30 license for general installers and repairmen
authorizes the sale, repair, service, and installation of stationary containers
and LNG systems. The original license fee is $100; the renewal fee is $70.
(5)
A Category 35 license for retail and wholesale dealers
authorizes the storage, sale, transportation, and distribution of LNG and
all other activities included in this section, except the manufacture, fabrication,
assembly, repair, subframing, and testing of LNG containers. The original
license fee is $750; the renewal fee is $300.
(6)
A Category 40 license for general public dispensing stations
authorizes the storage, sale, and dispensing of LNG into motor and mobile
fuel containers. The original license fee is $150; the renewal fee is $70.
(7)
A Category 45 license for motor fuel authorizes the sale
and installation of LNG motor or mobile fuel containers, and the sale, repair,
and installation of LNG motor or mobile fuel systems. The original license
fee is $100; the renewal fee is $50.
(8)
A Category 50 license for testing laboratories authorizes
the testing of LNG containers, LNG motor fuel systems or mobile fuel systems,
transfer systems, and transport systems for the purpose of determining the
safety of the containers or systems for LNG service, including the necessary
installation, disconnection, reconnection, testing, and repair of LNG motor
fuel systems or mobile fuel systems, transfer systems, and transport systems
involved in the testing of containers. The original license fee is $200; the
renewal fee is $100.
(c)
An original manufacturer of a new motor vehicle powered
by LNG, or a subcontractor of a manufacturer who produces a new LNG powered
motor vehicle for the manufacturer, is not subject to the licensing requirements
of this title, but shall comply with all other Regulations for Liquefied Natural
Gas.
(d)
Public or private entities performing LNG activities for
their own vehicles are not required to be licensed. Public or private entities
performing any LNG activities for the general public are required to be licensed.
§14.2016.Licensing Requirements.
(a)
Applicants for a license or license renewal shall file
with the Commission LNG Form 2001 designating a company representative who
shall be an owner or employee of the licensee, and shall be directly responsible
for actively supervising LNG operations of the licensee. A licensee may have
more than one company representative.
(1)
An applicant for license shall not engage in LNG activities
until its company representative has successfully completed the management
examination administered by the Commission.
(2)
The licensee shall notify the commission in writing upon
termination of its company representative and shall at the same time designate
a replacement by submitting a new LNG Form 2001.
(3)
The licensee shall cease LNG activities if, at the termination
of its company representative, there is no other qualified company representative
of the licensee acknowledged and recorded by the commission. The licensee
shall not resume operation until such time as it has a qualified company representative,
unless it has been granted an extension of time in which to comply as specified
in §14.2052 of this title (relating to Application for an Exception to
a Safety Rule).
(b)
Licenses issued under this chapter expire one year after
issuance at midnight on the last day of the month prior to the month in which
they are issued.
(c)
Persons engaged in LNG activities, including licensees
and non-licensees, shall maintain a copy of the current version of the Regulations
for Liquefied Natural Gas adopted by the Commission and shall provide at least
one copy to each company representative and operations supervisor. The copies
shall be available to employees during business hours.
(d)
Licensees and operations supervisors at each outlet shall
have all current licenses and certificates available for inspection during
regular business hours.
(e)
In addition to complying with other licensing requirements
set out in the Texas Natural Resources Code and the Regulations for Liquefied
Natural Gas, applicants for license or license renewal in the following categories
shall comply with the specified additional requirements:
(1)
A Category 15 licensee shall file with the commission for
each of its outlets legible copies of:
(A)
its current DOT authorization. A licensee may not continue
to operate after the expiration date of the DOT authorization; and
(B)
its current ASME Code, Section VIII certificate of authorization.
If ASME is unable to issue a renewed certificate of authorization prior to
the expiration date, the licensee may request in writing an extension of time
from the commission not to exceed 60 calendar days past the expiration date.
The licensee's request for extension shall be received by the commission prior
to the expiration date of the ASME certificate of authorization and shall
include a letter or statement from ASME that ASME is unable to issue the renewal
certificate of authorization prior to expiration and that a temporary extension
will be granted for its purposes. A licensee shall not continue to operate
after the expiration date of an ASME certificate of authorization until the
licensee files a current ASME certificate of authorization with the commission,
or the commission grants a temporary extension.
(2)
A Category 15 or 20 licensee making repairs on ASME containers
shall file with the commission a legible copy of its current "U" certificate
of authorization for the repair of ASME containers by the National Board of
Boiler and Pressure Vessel Inspectors.
(3)
A Category 15, 20, or 50 licensee shall file a properly
completed LNG Form 2505 with the Commission, certifying that the applicant
will follow the testing procedures indicated. The LNG Form 2505 shall be signed
by the company representative designated on LNG Form 2001.
(f)
For license renewals, the Commission shall notify the licensee
in writing at the address on file with the Commission of the impending license
expiration at least 30 calendar days prior to the expiration date. Renewals
shall be submitted to the Commission along with the license renewal fee specified
in §14.2013 of this title (relating to Licenses and Related Fees) on
or before the last day of the month in which the license expires renewal date
in order for the licensee to continue LNG activities. Failure to meet the
renewal deadline shall result in expiration of the license. If a person's
license expires, that person shall immediately cease performance of any LNG
activities authorized by that license.
(1)
If a person's license has been expired for 90 calendar
days or fewer, the person shall submit a renewal fee that is equal to 1 1/2
times the renewal fee required in §14.2013 of this title (relating to
Licenses and Related Fees). Upon receipt of the renewal fee, the Commission
shall verify that the person's license has not been suspended, revoked, or
expired for more than one year. After verification, if the licensee has met
all other requirements for licensing, the Commission shall renew the license,
and the person may resume LNG activities authorized by the license.
(2)
If a person's license has been expired for more than 90
calendar days but less than one year, the person shall submit a renewal fee
that is equal to two times the renewal fee required in §14.2013 of this
title (relating to Licenses and Related Fees). Upon receipt of the renewal
fee, the Commission shall verify that the person's license has not been suspended,
revoked, or expired for more than one year. After verification, if the person
has met all other requirements for licensing, the Commission shall renew the
license, and the person may resume LNG activities authorized by the license.
(3)
If a person's license has been expired for one year or
longer, that person may not renew, but shall comply with the requirements
for issuance of an original license.
(4)
A person who was licensed in this state, moved to another
state, and is currently licensed and has been in practice in the other state
for the two years preceding the date of application, may obtain a new license
without reexamination. The person shall pay to the Commission a fee that is
equal to two times the renewal fee required by §14.2013 of this title
(relating to Licenses and Related Fees).
(A)
As a prerequisite to licensing pursuant to this provision,
the person shall submit, in addition to an application for licensing, proof
of having been in practice and licensed in good standing in another state
continuously for the two years immediately preceding the filing of the application;
(B)
A person licensed under this provision shall be required
to comply with all requirements of licensing other than the examination requirement,
including but not limited to the insurance requirements as specified in §14.2031
of this title (relating to Insurance Requirements).
§14.2019.Certification Requirements.
(a)
This section applies to all licensees and their employees
who perform LNG activities, and to any ultimate consumer who has purchased,
leased, or obtained other rights in any vessel defined by this chapter as
an LNG transport, including any employee of such ultimate consumer if that
employee drives or in any way operates such an LNG transport. Only paragraph
(2) of this subsection applies to an employee of a state agency or institution,
county, municipality, school district, or other governmental subdivision.
Driving a motor vehicle powered by LNG or fueling of motor vehicles for an
ultimate consumer by the ultimate consumer or its employees do not in themselves
constitute LNG activities.
(1)
No individual may work or be employed in any capacity which
requires contact with LNG or LNG systems until that individual has submitted
to and passed a commission examination measuring the competence of that individual
to perform the LNG activities anticipated and the individual's working knowledge
of the Texas Natural Resources Code and the Regulations for Liquefied Natural
Gas related to the type of LNG work anticipated. Table 1 of this section specifies
which requirements, indicated with an asterisk, apply to each category of
license.
(2)
Employees of an ultimate consumer not required to submit
to examination under this section shall be properly trained by an individual
who passed the examination in the installation, maintenance, and storage of
LNG, LNG systems, and vehicles fueled by LNG, and in the operation of equipment
during the filling of and dispensing from storage containers. Such training
shall also include the protection of containers and equipment against damage
or tampering by unauthorized persons.
(3)
An individual wishing to submit to examination by the commission
shall file LNG Form 2016 along with the appropriate fee listed in subsection
(c) of this section with the commission prior to examination. The commission
shall notify the individual in writing of acceptance of LNG Form 2016.
(4)
An individual who has filed LNG Form 2016 and the applicable
nonrefundable examination fee may take the rules examination at the Commission's
Austin office between the hours of 8:00 a.m. and 2:00 p.m., Monday through
Friday, except for state holidays, and at other designated times and locations
around the state. Applicants who wish to take the rules examination at sites
other than the Austin office shall submit LNG Form 2016 and the applicable
fee to the Commission's Austin office at least three business days prior to
the examination date in order to receive an admittance letter from the Commission.
The admittance letter shall be required at all exam sites other than the Austin
office.
(5)
Within 30 days of the date an individual takes an examination,
the Commission shall notify the individual of the results of the examination.
The individual shall pass the rules examination with a score of at least 75%.
(A)
If the examination is graded or reviewed by a testing service,
the Commission shall notify the individual of the examination results within
14 days of the date the Commission receives the results from the testing service.
If the notice of the examination results will be delayed for longer than 90
days after the examination date, the Commission shall notify the individual
of the reason for the delay before the 90th day. The Commission may require
a testing service to notify an individual of the individual's examination
results.
(B)
Successful completion of any required examination shall
be credited to the individual.
(C)
Any individual who fails an examination shall be immediately
disqualified from performing any LNG activities covered by that examination
and shall not retake the same examination for at least 24 hours, unless approved
by the assistant director for the LP-Gas Section, Gas Services Division, or
another designated Commission employee. If requested in writing by an individual
who failed the examination, the Commission shall furnish the individual with
an analysis of the individual's performance on the examination.
(b)
A licensee or ultimate consumer other than a political
subdivision may employ an individual as a trainee for a period not to exceed
45 calendar days without that individual having successfully completed the
rules examination, subject to the following conditions:
(1)
The trainee shall be directly and individually supervised
at all times by an individual who has successfully completed the rules examination
for those areas of work being performed by the trainee.
(2)
The licensee or ultimate consumer other than a political
subdivision shall ensure that LNG Form 2016 is on file with the Commission
for each trainee at the time the trainee begins supervised LNG activities.
The trainee shall then have 45 calendar days to pass the applicable rules
examination.
(3)
A trainee who fails the rules examination shall cease to
perform any LNG activities covered by the examination failed.
(4)
A trainee who has been in training for a total of 45 days
in any combination and with any number of employers shall cease to perform
any LNG activities for which the trainee is not currently certified.
(5)
Once a trainee has taken the rules examination, the training
period shall cease and the individual shall perform no LNG activities which
require certification until the individual is notified by the Commission that
the individual passed the examination.
(c)
The applicant shall pay to the commission a $50 examination
fee for each management-level examination and a $20 fee for each employee-level
examination in advance of each required examination. Examination fees are
nonrefundable. An applicant who fails an examination shall pay the full examination
fee for each subsequent examination.
(d)
The Commission shall notify licensees of any employees'
pending renewals, or shall notify the individual if not employed by a licensee,
in writing, at the address on file with the Commission no later than March
15 of a year for the May 31 renewal date of that year. To maintain active
status, a certificate holder shall pay the $25 annual renewal fee to the Commission
on or before May 31 of each year. Individuals who hold more than one certificate
shall pay only one annual renewal fee.
(1)
Failure to pay the annual renewal fee by the renewal deadline
shall result in a lapse of certification unless the late filing fee in paragraph
(2) of this subsection is paid. If an individual's certification has been
expired for one year or longer, that individual shall comply with the requirements
of subsection (a) of this section. If an individual's certification lapses
or expires, that individual shall immediately cease performance of any LNG
activities that require certification. An individual may regain certified
status only by successfully completing the examination required for the certification
and meeting the requirements of paragraph (2) of this section.
(2)
Any lapsed or expired renewals submitted after May 31 of
each year shall include a $20 late-filing fee in addition to the renewal fee
and proof of successful completion of the examination required for the certification
no later than close of business on August 31 or, if August 31 falls on a weekend
or state holiday, close of business on the last business day before August
31. Upon receipt of the renewal fee, late-filing penalty, and proof of successful
completion of the examination required for the certification, the Commission
shall verify that the individual's certification has not been suspended, revoked,
or expired for one year or longer. After verification, the Commission shall
renew the certification and the individual may resume LNG activities.
(e)
Expired certifications. Any renewal submitted after the
August 31 deadline shall be considered expired. If an individual wishes to
renew a certification that has been expired for less than one year, that individual
shall submit the annual renewal fee and late filing fee, and proof of successful
completion of the examination required for certification. Upon verification
that the individual's certificate has not been suspended, revoked, or expired
for one year or longer, the Commission shall renew the individual's certification
and the individual may resume LNG activities.
(f)
Applicants for license shall attend the applicable courses
of instruction as specified in Table 1 of subsection (a) of this section.
The Category 35 course of instruction shall be held in Austin or any Commission-approved
facility at times to be determined by the Commission, shall include at a minimum
training over container installation, refueling facilities, motor fuel installations,
and stationary installations, and shall not exceed 40 hours. Course attendees
shall pay the fee to the Commission for the course. The fee shall be established
by the division director and may vary as needed to cover the costs for a particular
seminar in any given location. The seminar fee does not include the required
examination fee.
§14.2020.Employee Transfers.
When a previously certified individual is hired, the licensee shall
notify the Commission by filing a properly completed and signed LNG Form 2016A
along with a $10 filing fee, which shall be received by the Commission or
postmarked within ten calendar days of such hiring. Notice shall include the
employee's name as recorded on a current driver's license or Texas Department
of Public Safety identification card, employee social security number, name
of previous licensee-employer, and LNG related work to be performed.
§14.2022.Denial, Suspension, or Revocation of Licenses or Certifications, and Hearing Procedure.
(a)
The Commission may deny, suspend, or revoke a license or
certificate for any individual who fails to comply with the requirements of
this chapter. If the Commission determines that an applicant for a new license
or certificate, or renewal of a license or certificate has not met the requirements
of this chapter, the Commission shall notify the applicant in writing of the
reasons for the proposed denial. In the case of an applicant for license or
certificate, the notice shall advise the applicant:
(1)
that the application may be resubmitted within 30 calendar
days of receipt of the denial, with all cited deficiencies corrected. If an
applicant resubmits the application for a new license or certificate, or renewal
of a license or certificate within 30 calendar days of receipt of the denial
with all deficiencies corrected, the Commission shall issue the new license
or certificate, or the renewal of the license or certificate; or
(2)
if the applicant disagrees with the Commission's determination,
the applicant may request a hearing in writing within 30 calendar days of
receiving the notice of denial.
(b)
An applicant receiving a notice of denial of a license,
certificate, or license or certificate renewal may request a hearing to determine
whether the applicant did comply in all respects with the requirements for
the category or categories of license or certification sought.
(1)
Upon receipt of a written request for hearing, the Commission
shall schedule a hearing within 30 days following the receipt of the request
for hearing to determine the applicant's compliance or noncompliance with
the licensing or certification requirements for each category of license or
certification sought. The Commission shall conduct the hearing in compliance
with the Texas Government Code, Chapter 2001, the general rules of practice
and procedure of the Railroad Commission of Texas in Chapter 1 of this title
(relating to Practice and Procedure), and any other applicable rules.
(2)
If, after hearing, the Commission finds that the licensee
or certified individual may not comply within the specified time, the Railroad
Commission of Texas may enter an order calling a public hearing to be conducted
in compliance with the Texas Government Code, Chapter 2001, the general rules
of practice and procedure of the Railroad Commission of Texas in Chapter 1
of this title (relating to Practice and Procedure), and any other applicable
rules.
(c)
If the Commission finds through means including but not
limited to inspection, review of documents, or complaint by a member of the
general public or any other person, that a license or certificate shall be
suspended or revoked because of a probable or actual violation of or noncompliance
with Chapter 116 of the Texas Natural Resources Code or the Regulations for
Liquefied Natural Gas, the Commission shall notify the licensee or certified
individual in writing of the alleged violation or noncompliance.
(1)
The notice shall specify the acts, omissions, or conduct
constituting the alleged violation or noncompliance, and shall designate a
date at least 30 days but less than 45 days after the licensee or certified
individual receives the notice by which the violation or noncompliance shall
be corrected or discontinued. If the Commission determines the violation or
noncompliance may pose imminent peril to the health, safety, or welfare of
the general public, the Commission may notify the licensee or certified individual
orally with instruction to immediately cease the violation or noncompliance.
When oral notice is given, the Commission shall follow it with written notification
no later than five days after the oral notice.
(2)
The licensee or certified individual shall either report
the correction or discontinuance of the violation or noncompliance within
the time frame specified in the notice or request in writing an extension
of time in which to comply. The request for extension of the time to comply
shall be received by the Commission within the same time frame specified in
the notice for correction or discontinuance.
§14.2025.Designation of Outlet and Operations Supervisor (Branch Manager).
(a)
The Commission shall designate whether a site is an outlet
for the purpose of this chapter. Criteria used by the Commission in determining
the designation of an outlet include but are not limited to:
(1)
distance from other LNG activities operated by the licensee;
(2)
whether the operation duplicates the primary LNG operation;
and
(3)
whether the operation is directly supervised on a routine
basis.
(b)
A licensee maintaining more than one outlet shall file
LNG Form 2001A with the Commission designating an operations supervisor (branch
manager) at each outlet. The operations supervisor shall pass the management
examination administered by the Commission before commencing or continuing
the licensee's operations at the outlet.
(c)
An operations supervisor may be a company representative
of the licensee; however, an individual may be designated as an operations
supervisor at only one outlet unless approved by the Commission.
(d)
The operations supervisor shall be directly responsible
for actively supervising LNG operations of the licensee at the designated
outlet.
§14.2028.Franchise Tax Certification and Assumed Name Certificates.
(a)
Corporations or limited liability companies applying for
an original or renewal license shall file LNG Form 2026 with the Commission
prior to the issuance of such license certifying that its Texas franchise
taxes are either current or are not applicable to the company. An applicant
may file a Certificate of Account Status issued by the office of the Comptroller
of Public Accounts with the Commission as an alternative to filing the LNG
Form 2026. Making a false statement as to franchise tax status is grounds
for denial, suspension, or revocation of the license granted by the Commission.
(b)
Any applicant for license shall list all names on LNG Form
2001 under which LNG activities requiring licensing are to be conducted. Any
company performing LNG activities under an assumed ("doing business as" or
"DBA") name shall file with the Commission copies of the assumed name certificates
which are required to be filed with the respective county clerk's office and/or
the Secretary of State's office.
§14.2031.Insurance Requirements.
(a)
Pursuant to the Texas Natural Resources Code, Chapter 116,
the Commission has adopted the minimum amounts of insurance for LNG licensees
authorized by the State of Texas specified in Table 1 of this section.
(b)
A licensee or applicant for license shall file a valid
certificate of insurance as proof of insurance before the Commission grants
or renews a license.
(1)
Certificate of insurance shall be valid only when issued
by an insurance carrier authorized to do business in Texas, or by a surplus
lines insurer that meets the requirements of the Texas Insurance Code, article
1.14-2, and rules adopted by the Texas Department of Insurance under that
article.
(2)
Certificates of insurance filed with the Commission shall
have one of the endorsements specified in Table 1 of subsection (a) of this
section attached to the policy. Endorsements may not be cancelled without
cancellation of the attached policy.
(3)
Certificates of insurance shall be continuous in duration
and shall remain on file with the Commission during the entire period that
the license is in effect.
(4)
Documentation other than a certificate of insurance may
be accepted by the Commission as evidence of required insurance provided that
the documentation contains the same information as required on a certificate
of insurance. The alternative documentation may be accepted for a period not
to exceed 45 days. During the temporary period, a licensee shall file with
the Commission an amended certificate of insurance which complies with the
requirements of this section.
(5)
Cancellation of a certificate of insurance becomes effective
if:
(A)
the Commission receives written notice stating the insurer's
intent to cancel a policy of insurance and giving a minimum of 30 calendar
days' notice before such cancellation;
(B)
the Commission receives an acceptable replacement certificate
of insurance;
(C)
the licensee voluntarily surrenders a license and the rights
and privileges conferred by the license;
(D)
the Commission receives a statement made by the licensee
stating that the licensee is not actively engaging in any operations which
require a particular type of insurance and will not engage in those operations
unless and until all certificates of insurance required for those operations
are filed with the Commission; or
(E)
the Railroad Commission of Texas issues an order following
a hearing related to a certificate of insurance.
(c)
Each endorsement issued and attached to a certificate of
insurance shall require the insurance carrier, noted as "company" on the certificate
of insurance, to give the Commission 30 days' written notice before the insurance
cancellation. The 30-day notice commences from the date the Commission receives
the notice.
(d)
A licensee or applicant for a license that employs or contemplates
employing any employees in LNG activities shall file LNG Form 2996A with the
Commission. A licensee or applicant for a license that does not employ or
contemplate employing any employees in LNG activities shall file LNG Form
2996B in lieu of a certificate of workers' compensation, including employers'
liability insurance, or alternative accident and health insurance. The licensee
or applicant for a license shall file the required insurance certificate and
forms with the Commission before hiring any employee.
(e)
A Category 25 or 35 licensee or applicant for a license
or ultimate consumer that operates or contemplates operating a motor vehicle
equipped with an LNG transport container shall file LNG Form 2997A with the
Commission. A Category 25 or 35 licensee or applicant for a license or ultimate
consumer that does not operate or contemplate operating a motor vehicle equipped
with an LNG transport container or does not transport or contemplate transporting
LNG by vehicle in any manner shall file LNG Form 2997B in lieu of a certificate
of motor vehicle bodily injury and property damage insurance if this certificate
is not otherwise required. The licensee or applicant for a license shall file
the required insurance certificate and forms with the Commission before operating
a motor vehicle equipped with an LNG cargo container or transporting LNG by
vehicle in any manner.
(f)
A Category 15 licensee or applicant for a license that
engages in or contemplates engaging in any LNG operations that would be covered
by completed operations and product liability insurance shall file LNG Form
2998A with the Commission. A Category 15 licensee or applicant for a license
that does not engage in or contemplate engaging in any LNG operations that
would be covered by completed operations and product liability insurance shall
file LNG Form 2998B in lieu of a certificate of completed operations and product
liability insurance. The licensee or applicant for a license shall file the
required insurance certificate and forms with the Commission before engaging
in any operations that require completed operations and product liability
insurance.
(g)
A licensee or applicant for a license that engages in or
contemplates engaging in any operations that would be covered by general liability
insurance shall file LNG Form 2998A with the Commission. A licensee or applicant
for a license that does not engage in or contemplate engaging in any operations
that would be covered by general liability insurance shall file LNG Form 2998B
in lieu of a certificate of general liability insurance. The licensee or applicant
for a license shall file the required insurance certificate and forms with
the Commission before engaging in any operations that require general liability
insurance.
(h)
Notwithstanding the requirements specified in Table 1 of
subsection (a) of this section that each licensee carry a policy of workers'
compensation insurance, the licensee may protect its employees by obtaining
accident and health insurance coverage from an insurance company authorized
to write such policies in Texas as an alternative to workers' compensation
coverage. The alternative coverage shall be in the amounts specified in Table
1 of subsection (a) of this section.
§14.2034.Self-Insurance Requirements.
(a)
This section applies to a licensee's general liability
insurance, including premises and operations coverage. This section shall
not apply to worker's compensation insurance, including employer's liability
coverage.
(b)
A licensee applying for self-insurance shall file LNG Form
2027 with the Commission, along with materials which will allow the Commission
to determine whether:
(1)
the net worth of the applicant is adequate in relationship
to the size of operations and the extent of its request for self-insurance
authority. The applicant shall demonstrate that it will maintain a net worth
sufficient to ensure that it will meet its statutory obligations to the public
to pay all claims relating to general liability, including premises and operations
coverage; and
(2)
the applicant has a sound self-insurance program. The applicant
shall demonstrate that it has established and shall maintain an insurance
program that will protect the public against all claims involving LNG activities
to the same extent as the minimum limits specified in Table 1 of §14.2031
of this title (relating to Insurance Requirements). Such a program may include
but not be limited to one or more of the following: reserves; irrevocable
letter of credit, as specified in subsection (h) of this section; sinking
funds; third-party financial guarantees; parent company or affiliate sureties;
excess insurance coverage; or other similar arrangements.
(c)
The Commission may consider applications for approval of
other securities or agreements, or may require any other information which
may be necessary to ensure the application satisfies that the security or
agreement offered will afford adequate security for protection of the public.
(d)
The Commission may approve a licensee's application for
self-insurance if the licensee demonstrates to the Commission its ability
to satisfy its obligations for the minimum insurance requirements specified
in §14.2031 of this title (relating to Insurance Requirements). The Commission
may approve the licensee as a self-insurer for a specific time period or for
an indefinite period until further action is taken by the Commission.
(e)
The applicant shall file semi-annual reports and annual
statements with the applicant's financial status and status of its self-insurance
program with the Commission during the period of its self-insurer status by
March 10 and September 10 of each year.
(f)
After ten days' notice to the applicant, the Commission
may require the applicant to appear and demonstrate that it continues to have
adequate financial resources to pay all general liability, including premises
and operations coverage, claims, and that it remains in compliance with the
other requirements of this section. If the applicant fails to do so, the Commission
shall revoke its self-insurer status and may order that the licensee is ineligible
for self-insurance in the future.
(g)
A state agency or institution, county, municipality, school
district, or other governmental subdivision may meet the requirements for
workers' compensation coverage or general liability and/or motor vehicle liability
insurance by submitting LNG Form 2995 as evidence of self-insurance coverage
if permitted by the state workers' compensation act, Texas Civil Statutes,
Article 8308-1.01, et seq; Texas Civil Statutes, Articles 8309b, 8309d, 8309g,
8309g-1, and 8309h; and Texas Natural Resources Code, §116.036, by submitting
LNG Form 2995 to the Commission.
(h)
Letters of credit filed with LNG Form 2028 shall:
(1)
be issued by a federally chartered and federally insured
bank authorized to do business in the United States;
(2)
be irrevocable during their terms;
(3)
be payable to the Commission in part or in full upon demand
and receipt from the Commission of a notice of forfeiture; and
(4)
not apply to the licensing requirements for worker's compensation
insurance, including employer's liability coverage.
§14.2037.Components of LNG Stationary Installations Not Specifically Covered.
Components of LNG stationary installations which are not specifically
covered by the Regulations for Liquefied Natural Gas shall not be placed into
LNG service until the Commission has determined the installation complies
with the rules in this chapter. The Commission may require any change to a
proposed stationary installation which the Commission may consider necessary
to ensure the LNG installation is safe for LNG service. If the affected party
disagrees with the Commission's determination, the party may request a hearing
as described in §14.2022 of this title (relating to Denial, Suspension,
or Revocation of Licenses or Certifications, and Hearing Procedure). However,
the installation shall not be placed into LNG operation until the Commission
has determined the installation complies with the rules in this chapter.
§14.2040.Filings and Notice Requirements for Stationary LNG Installations.
(a)
No LNG container shall be placed into LNG service or an
installation operated or used in LNG service until the requirements of this
section, as applicable, are met and the facility is in compliance with all
applicable rules in this chapter and all statutes, in addition to any applicable
requirements of the municipality or the county where an installation is or
will be located. A person who purchases an existing LNG installation shall
file LNG Form 2019 with the Commission within 10 calendar days of the purchase
in order for the installation to remain in LNG service.
(b)
Prior to the construction of a stationary installation
which would result in an aggregate water capacity of 15,540 gallons or more,
the applicant shall submit LNG Form 2500 and a non-refundable $50 application
fee to the Commission including site plans and plans and specifications for
the installation at least 30 days prior to construction.
(1)
Plans and specifications shall be sealed by a registered
professional engineer licensed and in good standing to practice in the State
of Texas and who is qualified in the area of the design and construction of
LNG facilities.
(2)
Plans and specifications shall include fire protection
which complies with §14.2131 of this title (relating to Fire Protection).
(3)
If the applicant modifies the plans and specifications
before tentative or interim approval is granted by the Commission, the plans
and specifications shall be resealed by a registered professional engineer
licensed to practice in the State of Texas and resubmitted to the Commission.
A non-refundable fee of $30 shall be required for any resubmission.
(c)
Prior to the installation of an LNG container resulting
in an aggregate water capacity of 15,540 gallons or more, the applicant or
licensee shall send a copy of LNG Form 2500, LNG Form 2500A, and a plat by
certified mail, return receipt requested, to all owners of real property situated
within 500 feet of the proposed container location(s). The applicant or licensee
shall submit LNG Form 2500 to the Commission at the same time LNG Form 2500
and LNG Form 2500A are mailed to the real property owners.
(1)
Notice shall be considered sufficient when the applicant
or licensee has provided evidence that a complete LNG Form 2500, LNG Form
2500A, and a plat have been sent to all real property owners. The applicant
or licensee may obtained names and addresses of owners from current county
tax rolls.
(2)
The applicant or licensee shall notify owners of real property
situated within 500 feet of the proposed container location(s) if the current
aggregate water capacity of the installation is more than doubled in a 12-month
period or if the resulting aggregate water capacity of the installation will
be more than 214,348 gallons.
(3)
The applicant or licensee shall retain the return receipts
for Commission review, if requested.
(4)
The site plan or drawing shall describe the facility's
property or a 250-foot diameter (measured from the proposed container's location
on the site), whichever is smaller, and include all containers, buildings,
structures, geographical or topographical features, or any other features
or activities relating to LNG which could affect the health, safety and welfare
of the general public. The site plan or drawing shall include a scale or legend
to indicate the distances or measurements described.
(5)
Objections shall be filed with the Commission within 18
days of the postmarked date on the notice letter. If the Commission finds
that the objection is not proper, the Commission shall notify the property
owner and the property owner shall have ten days from the date of the Commission's
postmarked letter to correct the objection. If one or more of the adjoining
property owners files an objection and a written request for a hearing with
the Commission, the hearing shall be conducted as soon as possible and a recommendation
presented to the Commission within 90 days following the hearing. When possible,
the hearing shall be held in a location near the proposed site.
(A)
The Commission shall review all objections within 10 business
days of receipt. An objection shall be in writing and shall include a statement
of facts showing that the proposed installation:
(i)
does not comply with the rules in this chapter, specifying
which rules are violated;
(ii)
does not comply with the statutes of the State of Texas,
specifying which statutes are violated; or
(iii)
constitutes a danger to the public health, safety, and
welfare, specifying the exact nature of the danger. The Commission does not
consider public health, safety, and welfare to include such factors as the
value of property adjacent to the installation, the esthetics of the proposed
installation, or similar considerations.
(B)
Upon review of the objection, the Commission shall either:
(i)
schedule a public hearing as specified in §14.2022
of this title (relating to Denial, Suspension, or Revocation of Licenses or
Certifications, and Hearing Procedure); or
(ii)
notify the objecting party in writing within 10 business
days of receipt requesting further information for clarification and stating
why the objection is being returned. The objecting entity shall have 10 calendar
days from the postmark of the Commission's letter to file its corrected objection.
Clarification of incomplete or non-substantive objections shall be limited
to two opportunities. If new objections are raised in the objecting party's
clarification, the new objections shall be limited to one notice of correction.
(6)
Temporary installations which are used during peak demand
times such as during cold weather or emergencies are not required to comply
with these notice requirements. However, a sign shall be installed at the
site and brochures or other similar means of notification shall be available
at the site to advise the public of the need and use for the temporary installation.
(d)
Unless considered to be in the public interest by the Commission,
the applicant or licensee does not need to notify owners of real property
situated within 500 feet of the proposed container location(s) of an addition
to an existing LNG facility provided the current aggregate water capacity
is not more than doubled in a 12-month period; however, if the resulting aggregate
water capacity will exceed 214,348 gallons, the applicant or licensee shall
provide notice as specified in subsection (c) of this section.
(e)
The Commission shall grant tentative or interim approval
prior to the setting of the LNG container and construction of the LNG installation.
(f)
When an LNG container is replaced with a container of the
same or less overall diameter and length or height, and installed in the identical
location of the existing container at an LNG storage installation of 15,540
gallons aggregate water capacity or more, the applicant shall file LNG Form
2501 with the Commission.
(1)
LNG Form 2500, LNG Form 2500A, and LNG Form 2501, including
site plans and plans and specifications, are not required to be filed prior
to installation of pull-away devices, or emergency shutoff valves (ESV's),
or when maintenance and improvements are being performed to the piping system
at existing previously approved LNG installations having an aggregate water
capacity of 15,540 gallons or more.
(2)
A nonrefundable fee of $50 shall be submitted with each
LNG Form 2500. A nonrefundable resubmission fee of $30 shall be included with
each incomplete or revised set of plans and specifications resubmitted.
(3)
The proposed installation shall not be operated or used
in LNG service until approved by the Commission.
(g)
Upon completion of a commercial installation having an
aggregate water capacity of less than 15,540 gallons, the applicant shall
submit LNG Form 2501, postmarked or physically delivered to the Commission,
within ten calendar days after completion of such installation. LNG Form 2501
shall state that:
(1)
the installation complies with the statutes and Regulations
for Liquefied Natural Gas;
(2)
any necessary LNG licenses have been issued; and
(3)
the installation has been placed in LNG service.
(h)
A nonrefundable fee of $10 for each LNG container listed
on LNG Form 2501 shall be submitted with each LNG Form 2501 required to be
filed by the applicable subsections of this section. A nonrefundable resubmission
fee of $20 shall be included for each LNG Form 2501 resubmitted.
(i)
The Commission shall review all applications within 21
business days of the receipt of all required information and shall notify
the applicant as follows:
(1)
If the Commission administratively approves the installation,
the Commission shall notify the applicant in writing within 21 business days.
(2)
If the Commission declines to administratively approve
the installation, the Commission shall notify the applicant in writing, specifying
the deficiencies, within 21 business days. The applicant may modify the submission
and resubmit it for approval, or may request a hearing on the matter in accordance
with the General Rules of Practice and Procedure of the Railroad Commission
of Texas.
(j)
When the Commission notifies an applicant of an incomplete
LNG Form 2500 or LNG Form 2500A, the applicant has 120 calendar days from
the date of the notification letter to resubmit the corrected application
or the application will expire. After 120 days, the applicant shall file a
new application to reactivate Commission review of the proposed installation.
(1)
The applicant may request in writing an extension of the
120-day time period. The request shall be postmarked or physically delivered
to the Commission before the expiration date. The Commission may extend the
application period for up to an additional 90 days.
(2)
If the tentatively approved installation is not completed
within one year from the date tentative approval was granted, the application
will expire. Prior to the date of expiration, the applicant may request in
writing an extension of time of up to 90 days to complete the installation.
If the applicant fails to request an extension of time within the time period
prescribed in this subsection, the applicant will be required to submit a
new application before the original installation can be completed.
(3)
Prior to the installation of an LNG container referenced
in this section in a heavily populated or congested area, the Commission shall
determine whether the proposed installation poses a threat to the health,
safety, and welfare of the general public. The Commission shall determine
restrictions on LNG container capacities in accordance with the following:
(A)
density of the population within 500 feet of the LNG installation;
(B)
nature of the land use on those pieces of property located
within 500 feet of the LNG installation;
(C)
vehicular traffic in the area;
(D)
types and numbers of roadways in the area;
(E)
type of operations on the premises;
(F)
potential ignition sources in the area;
(G)
existence of dangerous or combustible materials in the
area that might be affected in an emergency situation;
(H)
the number of members of the general public who are concentrated
in the area; and
(I)
other factors related to the public health, safety, and
welfare.
(k)
The Commission shall examine plans and specifications to
ensure that they have been sealed by a qualified professional engineer licensed
to practice in the State of Texas. The Commission shall review site plans
to determine whether the installation complies with the distance requirements
in this chapter. The Commission shall determine whether the subject of the
submission poses a threat to the health, safety, and welfare of the general
public.
(1)
If the Commission declines to approve administratively
the submission, the Commission shall notify the applicant of this decision
in writing within 21 calendar days. The applicant may modify the submission
and resubmit it for approval within 21 calendar days after receiving the notice,
or may request a hearing to be conducted in accordance with the General Rules
of Practice and Procedure of the Railroad Commission of Texas. The subject
of the submission shall not be operated or used in LNG service in this state
until approved by the Commission following a hearing.
(2)
LNG Form 2005, LNG Form 2008, and any other documentation
pertinent to the installation may be requested by the Commission in order
to further determine compliance with the Regulations for Liquefied Natural
Gas.
(l)
Physical inspection of stationary installations.
(1)
Aggregate water capacity 15,540 gallons or more. The applicant
shall notify the Commission when the installation is ready for inspection.
If the Commission does not physically inspect the facility within 30 calendar
days of receipt of notice that the facility is ready for inspection, the applicant
may operate the facility conditionally until the initial complete inspection
is made. If any safety rule violations exist at the time of the initial inspection,
the applicant may be required to cease LNG operations until the applicant
corrects the violations.
(2)
Aggregate water capacity of less than 15,540 gallons. After
receipt of LNG Form 2501, the Commission shall conduct an inspection as soon
as possible to verify the installation described complies with the Regulations
for Liquefied Natural Gas. The applicant may operate the facility prior to
inspection if the facility fully complies with the Regulations for Liquefied
Natural Gas. If any LNG statute or safety rule violations exist at the time
of the initial inspection at a commercial installation, the Commission may
immediately remove the subject container, including any piping, appliances,
appurtenances, or equipment connected to it from LNG service until the applicant
corrects the violations.
(m)
If the Commission finds after a public hearing that the
proposed installation complies with the Regulations for Liquefied Natural
Gas and the statutes of the State of Texas, and does not constitute a danger
to the public health, safety, and welfare, the Commission shall issue an interim
approval order. The construction of the installation and the setting of the
container shall not proceed until the applicant has received written notification
of the interim approval order. Any interim approval order shall include a
provision that such approval may be suspended or revoked if:
(1)
the applicant has introduced LNG into the system prior
to final approval; or
(2)
a physical inspection of the installation indicates that
it is not installed in compliance with the submitted plat drawing for the
installation, the Regulations for Liquefied Natural Gas, or the statutes of
the State of Texas; or
(3)
the installation constitutes a danger to the public health,
safety, and welfare.
(n)
Material variances. If the Commission determines the completed
installation varies materially from the application originally accepted, the
applicant shall correct the variance and notify the Commission of the correction
of the variance or resubmit the application. The Commission's review of such
resubmitted application shall comply with the procedure described in this
section.
(o)
In the event an applicant has requested an inspection and
the Commission inspection identifies violations requiring modifications by
the applicant, the Commission may assess an inspection fee to cover the costs
associated with any additional inspection, including mileage and per diem
rates set by the legislature.
§14.2043.Temporary Installations.
(a)
Temporary installations shall comply with the following
requirements:
(1)
Prior to the completion of a temporary installation with
an individual or aggregate water capacity of 15,540 gallons or less, the licensee
or non-licensee shall file LNG Form 2501, including proof of the local fire
marshal's approval if the installation is within such jurisdiction.
(2)
Prior to the completion of a temporary installation with
an individual or aggregate water capacity of 15,541 gallons or more, the licensee
or non-licensee shall file LNG Form 2500, including plans and specifications,
and proof of the local fire marshal's approval if the installation is with
such jurisdiction.
(b)
Temporary installations shall be limited to one year. If
the temporary installation needs to remain in service for more than one year,
the licensee or nonlicensee responsible for the temporary installation shall
inform the Commission of this extension of time at least 30 days prior to
the expiration of the one-year period.
(c)
Temporary installations shall be protected by guardrailing
as specified in §14.2101(f) of this title (relating to Uniform Protection
Standards) unless otherwise approved by the Commission.
(d)
Temporary installations shall comply with the electrical
requirements specified in Subchapter F of this chapter (relating to Instrumentation
and Electrical Services).
(e)
Temporary installations shall be mounted on a secure surface,
not to include bare earth.
(f)
Temporary installations are not required to have impounding
areas.
(g)
The Commission may inspect temporary installations for
compliance with these requirements.
(h)
Any temporary installation subject to the jurisdiction
of United States Department of Transportation under 49 Code of Federal Regulations,
Part 193, shall comply with the applicable DOT rules and any requirements
of the Commission's Gas Services Division, Pipeline Safety Section.
§14.2046.Filings Required for School Bus, Mass Transit, and Special Transit Vehicles.
(a)
After the manufacture of or the conversion to an LNG system
on any vehicle to be used as a school bus, mass transit, public transportation,
or special transit vehicle, the manufacturer, licensee, or ultimate consumer
making the installation or conversion shall notify the Commission in writing
on LNG Form 2503 that the applicable LNG-powered vehicles are ready for a
complete inspection to determine compliance with the Regulations for Liquefied
Natural Gas.
(b)
If the Commission's initial complete inspection finds the
vehicle in compliance with the Regulations for Liquefied Natural Gas and the
statutes, the vehicle may be placed into LNG service. For fleet installations
of identical design, an initial inspection shall be conducted prior to the
operation of the first vehicle, and subsequent vehicles of the same design
may be placed into service without prior inspections. Subsequent inspections
shall be conducted within a reasonable time frame to ensure the vehicles are
operating in compliance with the Regulations for Liquefied Natural Gas. If
violations exist at the time of the initial complete inspection, the vehicle
shall not be placed into LNG service and the manufacturer, licensee, or ultimate
consumer making the installation or conversion shall correct the violations.
The manufacturer, licensee, or ultimate consumer shall file with the Commission
documentation demonstrating compliance with the Regulations for Liquefied
Natural Gas, or the Commission shall conduct another complete inspection before
the vehicle may be placed into LNG service.
(c)
The manufacturer, licensee, or ultimate consumer making
the installation or conversion shall be responsible for compliance with the
Regulations for Liquefied Natural Gas, statutes, and any other local, state,
or federal requirements.
(d)
If the requested Commission inspection identifies violations
requiring modifications by the manufacturer, licensee, or ultimate consumer,
the Commission shall consider the assessment of an inspection fee to cover
the costs associated with any additional inspection, including mileage and
per diem rates set by the legislature.
§14.2049.Report of LNG Incident/Accident.
(a)
If an incident or accident occurs during transport, as
a result of a pullaway, or where LNG is or is suspected to be the cause, the
licensee or nonlicensee owning, operating, or servicing the installation shall
notify the division by telephone as soon as possible after the licensee or
nonlicensee has knowledge of the incident or accident if any of the following
occurs:
(1)
a spill of 25 gallons or more of LNG;
(2)
property damage of $1,000 or greater; or
(3)
an injury requiring transport to a medical facility.
(b)
Any transport unit required to be registered with the Commission
in accordance with §14.2704 of this title (relating to Registration and
Transfer of LNG Transports) which is involved in an accident where there is
damage to the tank, piping appurtenances, or any release of LNG resulting
from the accident shall be reported to the Commission, regardless of the accident
location. Any LNG-powered motor vehicle used for school transportation or
mass transit, including any state-owned vehicle, which is involved in an accident
resulting in a release of LNG or damage to LNG equipment shall be reported
to the Commission, regardless of the accident location.
(c)
The telephone notification shall include the following
information:
(1)
the date and time of the incident or accident;
(2)
type of structure or equipment involved;
(3)
resident's or operator's name;
(4)
physical location;
(5)
number and type of injuries or fatalities;
(6)
whether fire, explosion, or leak has occurred;
(7)
whether LNG is currently leaking; and
(8)
whether immediate assistance from the division is requested.
(d)
The individual making the telephone notification shall
leave his or her name and telephone number.
(e)
Following the initial telephone report of any of the incidents
or accidents described in this section, the licensee shall file LNG Form 2020
with the division. The form shall be postmarked within 14 calendar days of
the date of initial notification to the division.
§14.2052.Application for an Exception to a Safety Rule.
(a)
Any person may apply for an exception to the provisions
of this chapter by filing LNG Form 2025 along with supporting documentation
and a $50 filing fee, with the Commission.
(b)
The application shall contain the following:
(1)
the section number of any applicable rules for which the
exception is being requested;
(2)
the type of relief desired, including the exception requested
and information which may assist the Commission in comprehending the requested
exception;
(3)
a concise statement of facts which support the applicant's
request for the exception, such as the reason for the exception, the safety
aspects of the exception, and the social or economic impact of the exception;
(4)
for stationary installations, regardless of size, a description
of the acreage and/or address upon which the subject of the exception will
be located. The description shall be in writing and shall include:
(A)
a site drawing;
(B)
sufficient identification of the site so that determination
of property boundaries can be made;
(C)
a plat from the applicable appraisal district indicating
the ownership of the land; and
(D)
the legal authority under which the applicant, if not the
owner, is permitted occupancy.
(5)
the name, business address, and telephone number of the
applicant and of the authorized agent, if any;
(6)
an original signature in ink by the applicant filing the
application or by the applicant's authorized representative; and
(7)
a list of the names and addresses of all interested entities
as defined in subsection (d) of this section.
(c)
Notice of the application for an exception to a safety
rule shall include the following items and procedures:
(1)
The applicant shall send a copy of LNG Form 2025 by certified
mail, return receipt requested, to all affected entities on the same date
on which the form is filed with or sent to the Commission. The applicant shall
include a notice to the affected entities that any objection shall be filed
with the Commission within 18 calendar days of the postmark. The applicant
shall file all return receipts with the Commission as proof of notice.
(2)
If an exception is requested for a stationary site, the
affected entities to whom the applicant shall give notice shall include but
not be limited to:
(A)
persons and businesses owning or occupying property adjacent
to the site;
(B)
the city council or fire marshal, if the site is within
municipal limits; and
(C)
the county Commission, if the site is not within any municipal
limits.
(3)
If an exception is requested for a non-stationary installation,
affected entities to whom the applicant shall give notice shall include but
not be limited to:
(A)
the Texas Department of Public Safety; and
(B)
all processed gas loading and unloading facilities used
by the applicant.
(4)
The Commission may require an applicant to give notice
to persons in addition to those listed in paragraphs (2) and (3) of this subsection
if doing so will not prejudice the rights of any entity.
(d)
Objections to the requested exception shall be in writing,
filed at the Commission within 18 calendar days of the postmark of the application,
and shall be based on facts that tend to demonstrate that, as proposed, the
exception would have an adverse effect on public health, safety, or welfare.
The Commission may decline to consider objections based solely on claims of
diminished property or esthetic values in the area.
(e)
The Commission shall review the application within 21 business
days of receipt of the application. If the Commission does not receive any
objections from any affected entities as defined in subsection (c) of this
section, the division director may grant administratively the exception if
the director determines that the installation, as proposed, does not adversely
affect the health or safety of the public. The Commission shall notify the
applicant in writing by the end of the 21-day review period and, if approved,
the installation shall be installed within one year from the date of approval.
The Commission shall also advise the applicant at the end of the objection
period as to whether any objections were received and whether the applicant
may proceed. If the director denies the exception, the Commission shall notify
applicant, in writing, of the reasons and any specific deficiencies. The applicant
may modify the application to correct the deficiencies and resubmit the application
along with a $30 resubmission fee, or may request a hearing on the matter
in accordance with the General Rules of Practice and Procedure of the Railroad
Commission of Texas. To be granted a hearing, the applicant shall file a written
request for hearing within 14 calendar days of receiving notice of the administrative
denial.
(f)
A hearing shall be held when the Commission receives an
objection, as set out in subsection (d) of this section from any affected
entity or when the applicant requests one following an administrative denial.
The Commission shall mail the notice of hearing to the applicant and all objecting
entities by certified mail, return receipt requested, at least 21 calendar
days prior to the date of the hearing. Hearings will be held in accordance
with the Texas Government Code, Chapter 2001, et seq., the general rules of
practice and procedure of the Railroad Commission, and the rules in this chapter.
(g)
Applicants intentionally submitting incorrect or misleading
information are subject to penalties as set out in Texas Natural Resources
Code, §91.143, and the filing of incorrect or misleading information
shall be grounds for the Commission to dismiss an application with prejudice.
(h)
After hearing, the Commission may grant exceptions to this
chapter if the Commission finds that granting the exception will not adversely
affect the safety of the public.
(i)
For good cause shown, the division may grant a temporary
exception of 30 days or less to the examination requirements for company representatives
and operations supervisors. Good cause includes but is not limited to death
of a sole proprietor or partner. Applicants for temporary exceptions shall
comply with applicable safety requirements and the division shall obtain information
showing that the exception will not be hazardous to the public.
(j)
A request for an exception shall expire if it is inactive
for three months after the date of the letter in which the applicant was notified
by the Commission of an incomplete request.
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 February 26, 2003.
TRD-200301439
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§14.2101, 14.2104, 14.2107, 14.2110, 14.2113, 14.2116, 14.2119, 14.2122, 14.2125, 14.2128, 14.2131, 14.2134, 14.2137, 14.2140
The new rules are proposed under Texas Natural Resources Code, §116.012,
which authorizes the Commission to adopt rules and standards relating to liquefied
natural gas activities to protect the health, welfare, and safety of the general
public; and under Senate Bill 310, 77th Legislature (2001), as codified at
Texas Natural Resources Code, §§116.032, 116.033, 116.034, and 116.0346.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on February 25, 2003.
§14.2101.Uniform Protection Requirements.
(a)
This section applies to the protection from tampering and
damage of stationary LNG installations, including LNG transfer systems, dispensing
systems, and storage containers.
(b)
Protection shall be maintained in good condition at all
times in accordance with the standards set forth in this subsection. The Commission
may impose additional requirements to ensure the safety of personnel and the
general public.
(c)
Stationary LNG installations shall be protected from tampering
and damage by either fencing or guardrails, or a combination of both as specified
in this section. The operating end of the container, including the material
handling equipment and the entire dispensing system, and any part of the LNG
transfer system, dispensing system, or storage container which is exposed
to vehicular traffic shall be protected from damage by the vehicular traffic
to which it is normally exposed. The protection shall extend at least 24 inches
beyond any part of the LNG transfer system, dispensing system, or storage
container.
(d)
Stationary LNG installations may use fencing which is located
more than 25 feet from any point of the LNG transfer system, dispensing system,
or storage containers. If such perimeter fencing is used, the LNG transfer
system, dispensing system, or storage containers shall also be protected from
the normal vehicular traffic to which they are subjected by guardrails at
the operating end of the equipment, including all material handling equipment.
Guardrails shall be located at least 24 inches beyond any part of the protected
equipment which is exposed to vehicular traffic.
(e)
Fencing at LNG stationary installations shall comply with
the following:
(1)
Fencing material shall be solid construction of noncombustible
material or chain link with wire at least 12 1/2 American wire gauge in size.
(2)
Fencing shall be at least six feet in height at all points.
Fencing may be five feet in height when topped with at least three strands
of barbed wire, with the strands four inches apart.
(3)
Uprights, braces, and cornerposts shall be composed of
noncombustible material if located within the minimum distances specified
for ignition sources or combustible materials set forth in §14.2110 of
this title (relating to LNG Container Installation Distance Requirements)
for the enclosed LNG transfer system, dispensing system, or LNG containers.
(4)
A minimum clearance of 24 inches shall be maintained between
the fencing and any part of an LNG transfer system, dispensing system, or
storage container that is part of a stationary installation.
(f)
Guardrails at LNG stationary installations shall comply
with the following:
(1)
Vertical supports for guardrails shall be at least four-inch
concrete-filled schedule 40 steel pipe or material of equal or greater strength.
The vertical supports shall be capped on top, anchored in concrete at least
36 inches below the ground, and rise at least 30 inches above the ground.
Supports shall be spaced four feet apart or less.
(2)
The top of the horizontal guardrailing shall be secured
to the vertical supports at least 30 inches above the ground. The horizontal
guardrailing shall be at least three-inch schedule 40 steel pipe or other
material with equal or greater strength. The horizontal guardrailing shall
be welded or bolted to the vertical supports with bolts of sufficient size
and strength to prevent damage to the protected equipment under normal conditions
including the nature of the traffic to which the protected equipment is exposed.
(3)
Openings in the horizontal guardrailing shall not exceed
36 inches. A means of temporarily removing the horizontal guardrailing and
vertical supports to facilitate the handling of heavy equipment may be incorporated
into the horizontal guardrailing and vertical supports. In no case shall the
protection provided by the horizontal guardrailing and vertical supports be
decreased. Transfer hoses from the bulkhead shall be routed only over the
horizontal guardrailing or through the 45-degree opening in front of the bulkhead.
(4)
A minimum clearance of 24 inches shall be maintained between
the railing and any part of an LNG transfer system, dispensing system, or
storage container.
(g)
Stationary LNG installations shall comply with the sign
and lettering requirements specified in Table 1 of this section and the following:
(1)
Unless colors are specified, lettering shall be a color
in sharp contrast to the background color of the sign and shall be easily
readable.
(2)
Signs shall be visible from each point of transfer;
(3)
Signs on emergency shutdown devices shall be permanently
affixed;
(4)
Signs bearing the words, "NATURAL GAS," shall be located
on all operating sides of dispensers; and
(5)
Signs indicating the licensee's name shall be located at
either the vehicle dispenser or refueling area, or at the loading or unloading
area.
(h)
At least two monitoring sensors shall be installed at all
stationary installations to detect hazardous levels of LNG. Sensors shall
activate at not more than 25% of the lower flammable limit of LNG. If the
level exceeds one-fourth of the LFL, the sensor shall either shut the system
down or activate an audible and visual alarm. The number of sensors to be
installed shall comply with the area of coverage for each sensor and the size
of the installation. The sensors shall be installed and maintained in accordance
with the manufacturer's instructions.
§14.2104.Uniform Safety Requirements.
(a)
In order to determine the safety of a container, the Commission
may request the manufacturer's data report on that container. The Commission
may also request that containers and assemblies be examined by a Category
15, 20, or 50 licensee equipped for and experienced in the testing of LNG
containers and equipment. The Category 15, 20, or 50 licensee shall file a
comprehensive report on its findings with the Commission. This requirement
may be applied even though an acceptable LNG Form 2023 is on file at the Commission.
(b)
Any stationary LNG container previously in LNG service
which has not been subject to continuous LNG pressure or inert gas pressure
shall be inspected by a currently licensed Category 15, 20, or 50 licensee
to determine if the container shall be leak-tested or re-certified. A copy
of the inspector's written report shall be filed with the Commission. The
container shall not be used until the Commission grants approval.
(c)
Any stationary LNG container which has been subject to
continuous LNG or inert gas pressure need not be tested prior to installation
provided an acceptable LNG Form 2023 is filed with the Commission when LNG
Form 2500 is submitted for any facility requiring submission of plans and
specifications.
(d)
When installed for use, containers shall not be stacked
one upon another except when designed by the manufacturer for stacking.
§14.2107.Stationary LNG Storage Containers.
(a)
Used LNG containers shall meet the requirements of §14.2104
of this title (relating to Uniform Safety Requirements) and any other applicable
rules prior to being reused in LNG service.
(b)
ASME, DOT and API containers shall be identified by attachment
of a stainless steel nameplate in a location that will remain visible after
the container is installed and by a method which will minimize corrosion of
the nameplate, its means of attachment, and the container. The nameplate shall
be marked with the following information:
(1)
manufacturer's name and date of construction of container;
(2)
nominal liquid capacity (in barrels or gallons);
(3)
design pressure (in psig) for methane gas at the top of
the container;
(4)
maximum permissible density of liquid to be stored;
(5)
maximum level to which container may be filled with stored
liquid;
(6)
maximum level to which container may be filled with water
for test, if applicable; and
(7)
minimum temperature in degrees Fahrenheit for which the
container was designed.
(c)
Openings on storage containers shall be marked with a sign
or tag showing the function of the opening. The markings shall remain readable
during all operating conditions and shall be located to minimize the effects
of possible frosting.
(d)
Shop-fabricated and shop-tested LNG containers shall be
leak-tested to 90% of the pressure relief valve setting after being installed
and filled with LNG.
§14.2110.LNG Container Installation Distance Requirements.
(a)
LNG containers shall be installed in accordance with the
following minimum distance requirements:
(1)
Containers with aggregate water capacities up to 15,540
gallons shall be located at least 25 feet from any building, property line,
stationary ignition sources, or other aboveground flammable liquids;
(2)
Containers with aggregate water capacities from 15,541
to 93,240 gallons shall be located at least 50 feet from any building, property
line, stationary ignition sources, or other aboveground flammable liquids;
(3)
Containers with aggregate water capacities of 93,241 gallons
or more shall be located at least 100 feet from any building, property line,
stationary ignition sources, or other aboveground flammable liquids.
(4)
Underground LNG containers shall be located at least 15
feet apart, regardless of size.
(5)
LNG dispensers or points or transfer shall be located at
least 25 feet from the nearest building not associated with the LNG facility
and from any line of adjoining property that can be built upon.
(b)
Operating industrial trucks with only one container mounted
on each truck may be stored inside buildings. Extra containers shall not be
stored inside buildings. Operating industrial trucks shall be stored in an
area that will reduce the likelihood of an accident. Service valves shall
be closed whenever a truck with a mounted container is stored. A venting system
shall be used any time a vehicle not in operation is inside a building to
allow safe relief valve venting.
(c)
Stationary LNG containers and piping shall not be placed
in the area directly beneath or above an electric transmission, distribution,
or customer service line and the area six feet to either side of that line.
If this distance is not adequate to prevent the line and the associated voltage
from contacting the LNG container in the event of breakage of any conductor,
then other suitable means of protection designed and constructed to prevent
such contact with the container may be used if approval is received from the
Commission. The request for approval shall be in writing and shall specify
the manner in which the container will be protected from contact, including
specifications for the materials to be used. If the Commission does not approve
the proposed protection, then the container shall be located a sufficient
distance from the line to prevent such contact.
§14.2113.Maintenance Tanks.
(a)
Stationary installations which include vehicle maintenance
areas may have a container permanently installed outside the maintenance area
to remove LNG from a vehicle if the removal of the LNG is necessary to perform
maintenance or repairs. The container shall comply with the following requirements:
(1)
The container shall have a maximum water capacity of 200
gallons; and
(2)
The transfer of LNG from the vehicle into the maintenance
container shall take place outside any building.
(b)
The container mounted on the mobile refueling vehicle described
in §14.2307 of this title (relating to Indoor Fueling) may be used to
store fuel from a vehicle requiring maintenance provided both the mobile refueling
vehicle and the vehicle requiring maintenance are outside any building during
the transfer of fuel.
§14.2116.Transfer of LNG.
(a)
Venting of LNG is prohibited as part of routine activities,
except for the following:
(1)
as provided for in §14.2119 of this title (relating
to Transport Vehicle Loading and Unloading Facilities and Procedures); and
(2)
through a trycock installed on a stationary storage tank
during filling of the tank.
(b)
LNG being transferred into stationary storage containers
shall be compatible in composition or temperature and density with the LNG
already in the container. When making transfers into fueling facility containers,
the LNG shall be transferred at a pressure that will not exceed the set pressure
of the pressure relief device.
(c)
When the composition or temperature and density are not
compatible, measures shall be taken to prevent an excessive rate of vapor
evolution.
(d)
At least one licensed or certified individual shall be
in attendance while unloading is in progress.
(e)
Ignition sources shall not be permitted within 25 feet
of the transfer area or within the distances specified as classified areas
in Table 1 of §14.2513 of this title (relating to Electrical Equipment)
while transfer of LNG is in progress.
(f)
Measuring instruments shall be provided to determine that
containers are not overfilled.
§14.2119.Transport Vehicle Loading and Unloading Facilities and Procedures.
(a)
Transport vehicle loading and unloading facilities shall
meet the following requirements:
(1)
Rack structures shall be constructed of noncombustible
material such as steel or concrete.
(2)
Transfer piping, pumps, and compressors shall be installed
with the following protective measures:
(A)
protection from damage from vehicle movements in compliance
with the guardrail and fencing requirements of §14.2101 of this title
(relating to Uniform Protection Requirements);
(B)
isolation valves at both ends of containers with less than
2,000 gallon capacity, and a remote operating valve, automatic closure, or
check valve to prevent backflow on containers of 2,000 gallons or more capacity;
(C)
isolation valving and bleed connections to depressurize
hoses and arms and minimize venting before disconnecting;
(D)
hoses and arms equipped with a shutoff valve at the free
end;
(E)
a check valve on piping for liquid transfer to minimize
accidental release; and
(F)
a line relief valve between every pair of isolation valves.
(3)
Where multiple products are loaded or unloaded at the same
location, loading arms, hoses, and manifolds shall be marked to indicate the
product or products handled by each system.
(4)
Operating status indicators shall be provided in the transfer
area.
(b)
Written procedures covering normal transfer and emergency
operating procedures shall be available for all transfer operations. The procedures
shall be kept current and available to all employees engaged in transfer operations.
(c)
Prior to beginning transfer operations, the following checks
shall be made:
(1)
Gauge readings shall be obtained or inventory established
to prevent overfilling of the receiving vessel.
(2)
Transfer connections shall be checked to ensure they are
gastight and liquidtight.
(3)
Unless required for transfer operations, LNG or flammable
liquid transport vehicle engines shall be turned off. Brakes shall be set
and wheels chocked to prevent movement of the vehicle prior to connecting
for transfer. The engine shall not be started until the transport vehicle
has been disconnected and any released vapors have dissipated.
(4)
Prior to loading LNG into a transport vehicle tank which
does not have a positive pressure or is not in exclusive LNG service, a test
shall be made to determine the oxygen content in the receiving container.
If the oxygen content in either case exceeds 1.0% by volume, the container
shall not be loaded until suitably purged.
(5)
An LNG transport vehicle shall be positioned prior to transfer
so that it can exit the area without backing when the transfer operation is
complete.
(d)
During transfer operations, the following checks shall
be made:
(1)
Levels shall be checked during the transfer operations.
(2)
Pressure and temperature conditions shall be observed during
the transfer operations. If any unusual variance in pressure occurs, transfer
shall be stopped until the cause has been determined and corrected.
(e)
No repair shall be performed on the transfer system while
transfer is taking place.
§14.2122.Transfer Systems, Including Piping, Pumps, and Compressors, Used for LNG and Refrigerants.
(a)
Transfer systems and pumps used for transfer of LNG and
refrigerants shall be provided with means for precooling to reduce the effect
of thermal shock and overpressure.
(b)
Check valves shall be provided as required to prevent backflow
in transfer systems and shall be located as close as practicable to the point
of connection to any system from which backflow might occur.
(c)
In addition to a locally mounted device to shut down the
pump or compressor drive, a readily accessible, remotely located device shall
be provided at least 25 feet away from the equipment to shut down the pump
or compressor in case of emergency. The device shall be marked in accordance
with the table in §14.2101 of this title (relating to Uniform Protection
Requirements). Remotely located pumps and compressors used for loading or
unloading tank vehicles shall be provided with shut-down controls at the transfer
area and at the pump or compressor site.
(d)
Pressure gauges shall be installed on each pump and compressor
discharge.
(e)
Valves shall be installed so that each pump or compressor
can be isolated for maintenance. Where pumps or centrifugal compressors are
installed for operation in parallel, each discharge line shall be equipped
with a check valve.
(f)
Pumps and compressors shall be provided with pressure relief
devices to limit the discharge pressure to their maximum allowable working
pressure.
§14.2125.Hoses and Arms.
(a)
Hoses and arms used for transfer shall be suitable for
the temperature and pressure of the operating conditions. Hoses shall be designed
to have a bursting pressure of at least five times the maximum allowable working
pressure of the equipment to which it is attached.
(b)
Loading hoses or arms shall be supported to prevent displacement
of the hoses and arms that results in greater stresses than those allowed
in Appendix A of ANSI B31.3.
(c)
Couplings used for connection of a hose or arm shall be
suitable for operating conditions and shall be designed for frequent coupling
and uncoupling.
(d)
Hoses shall be tested at least annually to the setting
of the relief valve that protects the hose.
(e)
Hoses shall be visually inspected for damage or defects
before each use and shall not be used if any damage or defect is found.
§14.2128.Communications and Lighting.
(a)
Emergency communications shall be provided near transfer
locations so that the operator can contact remotely located personnel who
are associated with the transfer operations.
(b)
Transfer areas shall be illuminated during hours of darkness.
§14.2131.Fire Protection.
(a)
Fire protection shall be provided for all LNG facilities,
as determined by sound fire protection engineering principles, analysis of
local conditions, hazards within the facility, and exposure to or from other
property. The evaluation shall determine at a minimum type, quantity, and
location of:
(1)
equipment necessary for the detection and control of fires,
leaks, and spills of LNG, flammable refrigerants, or flammable gases;
(2)
equipment necessary for the detection and control of potential
non-process and electrical fires;
(3)
the methods necessary for protection of the equipment and
structures from the effects of fire;
(4)
fire protection water systems;
(5)
fire extinguishing and other fire control equipment;
(6)
the availability and duties of employees and the availability
of local emergency response organizations during an emergency; and
(7)
the protective equipment and special training needed by
employees for their emergency duties.
(b)
A detailed emergency response manual shall be prepared
for potential emergency conditions. The procedures shall include but not be
limited to:
(1)
shut-down or isolation of all or part of the equipment
to ensure that the escape of gas or liquid is promptly stopped or reduced
as much as possible;
(2)
use of fire protection equipment;
(3)
notification of emergency response organizations and public
authorities;
(4)
first aid; and
(5)
duties of employees.
(c)
The emergency procedure manual shall be available in the
operating area and shall be updated as required by changes in equipment or
procedures.
(d)
Employees engaged in LNG activities shall be trained in
emergency duties and procedures. Refresher training shall be conducted at
least once every two years.
(e)
Fire control measures shall be coordinated with the local
fire and emergency response organizations.
(f)
Safety and fire protection equipment shall be visually
inspected at least once a month and tested at least once a year. Documentation
shall be maintained on inspections and tests for at least two years or consistent
with other safety record retention schedules, whichever is greater.
(g)
Maintenance on fire control equipment shall be scheduled
so that a minimum of equipment is out of service at any one time and fire
protection safety is not compromised. Access routes for movement of fire control
equipment to an LNG fueling facility shall be maintained at all times.
(h)
Fire extinguishing and other fire control systems shall
follow the local fire marshal's requirements and recommendations for the protection
of specific hazards.
(i)
Dry chemical fire extinguishers suitable for extinguishing
gas fires shall be provided at each stationary LNG installation.
§14.2134.Container Purging Procedures.
(a)
Only experienced and qualified personnel shall be responsible
for container purging procedures.
(b)
Prior to placing an LNG container into service, the air
shall be displaced by an acceptable inerting procedure as described in American
Gas Association Purging Principles and Practice, 1975 edition.
(c)
Prior to taking a container out of service, the natural
gas in the container shall be purged by an acceptable inerting procedure.
(d)
The oxygen content of the container during purging operations
shall be determined by an acceptable oxygen analyzer.
§14.2137.Employee Safety and Training.
(a)
Employees shall be advised of the hazards relative to LNG
facility operations.
(b)
Protective clothing and equipment shall be provided to
employees for both normal operations and emergency response.
(c)
Employees who handle and dispense LNG shall be trained
in proper handling, operating duties, and procedures.
(d)
Employees shall be trained upon employment and as needed
thereafter, but no less than every two years. Training shall include the following:
(1)
information on the nature, properties, and hazards of LNG
in both the liquid and gaseous phases;
(2)
specific instructions on the facility equipment to be used;
(3)
use and care of protective equipment and clothing;
(4)
standard first aid;
(5)
response to emergency situations such as fire, leaks, and
spills;
(6)
good housekeeping practices;
(7)
the emergency response plan; and
(8)
evacuation and fire drills.
(e)
Licensees or ultimate consumers shall retain employee safety
training records for the past four years.
§14.2140.Inspection and Maintenance.
(a)
Licensees shall have a preventive maintenance program in
place which includes a schedule of written procedures for regular testing
and inspection of facility systems and equipment.
(b)
Components and their related support systems shall be maintained
in a condition that is compatible with their operation or safety purpose by
repair, replacement, or other means.
(c)
If a safety device is taken out of service for maintenance,
the component served by the device shall also be taken out of service unless
the same safety function is provided by an alternate means.
(d)
If the inadvertent operation of a component taken out of
service could cause a hazardous condition, that component shall have a weather-resistant
tag attached to the controls with the words, "DO NOT OPERATE," or similar
notice.
(e)
The operations supervisor shall retain permanent records
of dates and maintenance activities performed.
(f)
Welding, cutting, and similar operations shall be prohibited
within 25 feet of the container and the transfer area during transfer operations
and shall be conducted only as specifically authorized in a manner to prevent
accidental ignition of LNG or flammable fluids.
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 February 26, 2003.
TRD-200301440
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§14.2301, 14.2304, 14.2307, 14.2310, 14.2313, 14.2316, 14.2319, 14.2322, 14.2325, 14.2328
The new rules are proposed under Texas Natural Resources Code, §116.012,
which authorizes the Commission to adopt rules and standards relating to liquefied
natural gas activities to protect the health, welfare, and safety of the general
public; and under Senate Bill 310, 77th Legislature (2001), as codified at
Texas Natural Resources Code, §§116.032, 116.033, 116.034, and 116.0346.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on February 25, 2003.
§14.2301.Applicability.
This subchapter applies to the design, construction, installation,
and operation of containers, pressure vessels, pumps, vaporization equipment,
buildings, structures, and associated equipment used for the storage and dispensing
of LNG as an engine fuel for vehicles of all types.
§14.2304.General Facility Design.
(a)
LNG fueling facilities shall be designed with provisions
for securing all equipment in accordance with §14.2101 of this title
(relating to Uniform Protection Requirements).
(b)
Structures and support of LNG fueling facility equipment,
piping, controls, and tanks shall be constructed of noncombustible material.
(c)
Dikes, grading, or diversion curbs shall be provided to
prevent combustible or hazardous liquids from encroaching on the LNG refueling
facility.
(d)
LNG shall not be vented to the atmosphere under normal
operations unless the vent leads to a safe point of discharge. Vent pipes
or stacks shall have the open end suitably protected to prevent entrance of
rain, snow, and other foreign material. Vent stacks shall have provision for
drainage.
(e)
Instructions identifying the location and operation of
emergency controls shall be conspicuously posted in the facility area.
(f)
LNG fueling facility containers, liquid impoundment areas,
and points of transfer shall be located according to the distances specified
in §14.2110 of this title (relating to LNG Container Installation Distance
Requirements).
(g)
LNG fueling facility containers may be sited above or below
grade. Soil susceptible to freezing from contact with containers shall be
heated directly or protected with an air space.
(h)
Containers having outer jackets made of materials subject
to corrosion shall be protected against corrosion.
(i)
Vehicles delivering LNG to a facility or vehicles being
fueled from a facility shall not be considered ignition sources. Vehicles
containing fuel-fired equipment, such as recreational vehicles and catering
trucks, shall be considered ignition sources unless the fuel-fired equipment
is shut off completely before the vehicle enters an area in which ignition
sources are prohibited.
(j)
LNG fueling facilities which transfer LNG at night shall
have permanent lighting at points of transfer and operation, including at
least two lights with a total of at least two footcandles of power.
(k)
Temperature monitoring systems shall be provided where
the foundations supporting cryogenic containers and equipment could be adversely
affected by freezing or frost heaving of the ground.
§14.2307.Indoor Fueling.
(a)
Buildings reserved exclusively for LNG fueling shall be
constructed of noncombustible or limited combustible material. Windows and
doors shall be located to permit ready egress in case of emergency.
(b)
Buildings used for indoor fueling shall meet the following
requirements:
(1)
Indoor fueling facilities that are within a local fire
marshal's jurisdiction shall obtain written approval from the local fire marshal,
either by signature, seal, or stamp on LNG Form 2500 or on a separate letter.
(2)
Indoor fueling facilities that are outside a local fire
department's jurisdiction shall comply with the requirements of the Uniform
Building Code.
(c)
LNG Form 2500, including plans and specifications, shall
be filed with the Commission, as specified in §14.2040 of this title
(relating to Filings Required for Stationary LNG Installations).
§14.2310.Emergency Refueling.
(a)
Licensees and nonlicensees, such as mass transit authorities,
may use a mobile refueling vehicle for emergency refueling provided it complies
with the following requirements:
(1)
The gross vehicle weight (GVW) shall not exceed the GVW
rating. Installation of the container shall not adversely affect the vehicle.
(2)
The vehicle used to transport the container shall comply
with all DOT and Texas placarding requirements.
(3)
The LNG cargo container shall have a maximum water capacity
of 200 gallons.
(4)
The container, fittings, and transfer equipment shall be
properly secured against displacement.
(b)
The individual performing the transfer of LNG shall be
properly trained in all aspects of LNG transfer.
(c)
Prior to the mobile refueling vehicle being placed into
service, the licensee or non-licensee shall file with the division a drawing
showing the mounting, type of container, water capacity of the container,
type of vehicle to be used, and the method of mounting. The vehicle shall
not be placed into service until the division ensures that it complies with
the applicable rules.
(d)
Emergency refueling vehicles are not required to be registered
with the Commission.
§14.2313.Fuel Dispensing Systems.
(a)
Compliance with this section does not ensure conformity
with other state and federal regulations, such as those of the Texas Natural
Resources Conservation Commission or the United States Environmental Protection
Agency. Retail LNG dispensers shall comply with the applicable weights and
measures requirements of the Texas Department of Agriculture relating to dispensing
accuracy.
(b)
Appurtenances and equipment placed into LNG service shall
be listed by a Category 15, 20, or 50 licensee unless:
(1)
the appurtenances or equipment are specifically prohibited
for use by another section of the Regulations for Liquefied Natural Gas; or
(2)
there is no test specification or procedure developed by
a testing laboratory for the appurtenances or equipment.
(c)
Appurtenances and equipment that are labeled but not listed
and are not prohibited for use by the Regulations for Liquefied Natural Gas
shall be acceptable and safe for LNG service over the full range of pressures
and temperatures to which they will be subjected under normal operating conditions.
(d)
The Commission may require any documentation sufficient
to substantiate any claims made regarding the safety of any valves, fittings,
and equipment.
(e)
Drive-away protection shall be provided.
(f)
Emergency shut-down devices shall be distinctly marked
for easy recognition according to the requirements of Table 1 of §14.2101
of this title (relating to Uniform Protection Requirements) and shall activate
a valve installed at the dispensing area that shuts off the power and gas
supply to the dispensers. ESD devices shall be located as follows:
(1)
For containers with water capacity of 93,240 gallons or
less, an ESD device shall be located between 35 and 50 feet from the container.
(2)
For containers with water capacity of 93,241 gallons or
more, an ESD device shall be located between 60 and 75 feet from the container.
(g)
Manually operated container valves shall be provided for
each container.
(h)
Manually operated shutoff valves shall be installed in
manifolds as close as practicable to a container or group of containers.
(i)
The use of hoses or arms in a fueling installation is limited
to:
(1)
a vehicle fueling hose;
(2)
an inlet connection to compression equipment; or
(3)
a section of metallic hose not exceeding 36 inches in length
in a pipeline to provide flexibility where necessary. Metallic hose shall
be installed so that it will be protected against damage and be readily visible
for inspection. The manufacturer's identification shall be retained for each
section of metallic hose used.
(j)
When a hose or arm of nominal three-inch diameter or larger
is used for liquid transfer, or nominal four-inch diameter or larger is used
for vapor transfer, an emergency shutoff valve shall be installed in the piping
of the transfer system less than ten feet from the nearest end of the hose
or arm. If the flow is away from the hose, a check valve may be used as the
shutoff valve. If a liquid or vapor line has two or more legs, an emergency
shutoff valve shall be installed in each leg.
(k)
The fill line on storage containers shall be equipped with
a backflow check valve to prevent discharge of LNG from the container in case
of line, hose, or fitting rupture.
(l)
A fueling connection and mating vehicle receptacle shall
be used to transfer LNG or gas vapor to or from the vehicle.
(m)
An interlock device shall be provided so that the hose
coupling cannot be released while the transfer line is open. Interlock devices
are not required for transports when transferring fuel to a stationary tank.
(n)
The maximum delivery pressure shall not exceed the maximum
allowable working pressure of the vehicle and fuel tanks.
(o)
Where excess flow check valves are used, the closing flow
shall be less than the flow rating of the piping system that would result
from a pipeline rupture between the excess flow valve and the equipment downstream
of the excess flow check valve.
§14.2316.Filings Required for Installation of Fuel Dispensers.
After the installation of a fuel dispenser, LNG Form 2501 shall be
filed with the Commission along with the required fees set forth in §14.2040
of this title (relating to Filings Required for Stationary LNG Installations).
Site plans shall detail the area within 150 feet of the dispenser and the
fuel storage container or to the facility's property line, whichever is less.
Tentative approval shall be granted if the site plans indicate the installation
will meet the requirements of the Regulations for Liquefied Natural Gas and
the Natural Resources Code. Final approval shall be issued only after a field
inspection confirms that the installed dispenser meets all the requirements
of the Regulations for Liquefied Natural Gas.
§14.2319.Automatic Fuel Dispenser Safety Requirements.
(a)
Automatic fuel dispensers shall be fabricated of material
suitable for LNG and resistant to the action of LNG under service conditions.
Pressure containing parts shall be stainless steel, brass, or other equivalent
cryogenic material. Aluminum may be used for approved meters.
(b)
Electric installations within dispenser enclosures and
the entire pit or open space beneath dispensers shall comply with NEC, Class
1, Group D, Division 1, except for dispenser components located at least 48
inches above the dispenser base which NEC states are intrinsically safe.
(c)
Valves, metering equipment, and other related equipment
installed on a automatic dispensers shall meet all applicable requirements
of the Regulations for Liquefied Natural Gas.
(d)
Automatic dispensers shall be protected from damage by
vehicle collision by fencing and guardrails installed in accordance with §14.2101
of this title (relating to Uniform Protection Requirements).
(e)
A device shall be installed in the liquid piping so that
displacement of an automatic dispenser will result in the displacement of
such piping on the downstream side of the device.
(f)
The fueling nozzle shall prevent LNG from being discharged
unless the nozzle is connected to the vehicle.
(g)
A key, card, or code system shall be used to activate the
automatic dispenser.
(h)
Automatic dispensers shall incorporate cutoff valves with
opening and closing devices which ensure the valves are in a closed position
when dispensers are deactivated.
(i)
LNG fuel storage installations which include automatic
dispensers shall be equipped with an emergency shut-down device for the entire
LNG installation located at least 20 feet from the nearest dispenser or storage
area. The emergency shut-down device shall be distinctly marked for easy recognition
in compliance with the requirements of §14.2101 of this title (relating
to Uniform Protection Requirements).
(j)
If automatic dispensers are to be used during hours of
darkness, permanent adequate lighting shall be provided to facilitate proper
operations.
§14.2322.Protection of Automatic and Other Dispensers.
(a)
Dispensers shall be secured to a concrete island at least
six inches above the normal grade and two inches above the grade of any other
liquid fuel dispenser.
(b)
Dispensers shall be protected against collision damage
by support columns or other such protection installed at the approach ends
of the concrete island.
(c)
If the protection described in subsections (a) and (b)
of this section cannot be provided, the dispensers shall be protected as specified
in §14.2101 of this title (relating to Uniform Protection Requirements).
§14.2325.LNG Transport Unloading at Fueling Facilities.
Procedures and requirements for LNG transport unloading at fueling
facilities shall be as specified in §14.2119 of this title (relating
to Transport Vehicle Loading and Unloading Facilities and Procedures) of this
chapter.
§14.2328.Training, Written Instructions, and Procedures Required.
(a)
Dispensers may be operated only by an individual who has
been properly trained in all aspects of the operation and safety procedures.
(b)
Any individual who operates a dispenser shall be provided
with written instructions and safe operating procedures by the licensee. Step-by-step
operating instructions provided by the manufacturer shall be posted at or
on each dispenser and shall be readily visible to the operator during transfer
operations. The instructions shall describe each action necessary to operate
the dispenser.
(c)
Licensees or ultimate consumers shall maintain a current
list of all individuals trained in the safe operation of dispensers.
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 February 26, 2003.
TRD-200301441
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§14.2401, 14.2404, 14.2407, 14.2410, 14.2413, 14.2416, 14.2419, 14.2422, 14.2425, 14.2428, 14.2431, 14.2434, 14.2437, 14.2440
The new rules are proposed under Texas Natural Resources Code, §116.012,
which authorizes the Commission to adopt rules and standards relating to liquefied
natural gas activities to protect the health, welfare, and safety of the general
public; and under Senate Bill 310, 77th Legislature (2001), as codified at
Texas Natural Resources Code, §§116.032, 116.033, 116.034, and 116.0346.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on February 25, 2003.
§14.2401.General Provisions for Piping Systems and Components.
Piping systems shall comply with ANSI B31.3, Chemical Plant and Petroleum
Refinery Piping. The additional provisions of this subchapter apply only to
pressurized piping systems and components for LNG, flammable refrigerants,
flammable liquids, and flammable gases, and unpressurized or low pressure
piping systems, including vent lines and drain lines which handle LNG, flammable
refrigerants, flammable liquids, and flammable gases with service temperatures
below -20 degrees Fahrenheit.
§14.2404.Piping Materials.
(a)
Piping materials, including gaskets and thread compounds,
shall be suitable for use with LNG throughout the range of temperatures to
which they will be subjected. The temperature limitations for pipe materials
shall be as specified in ANSI B31.3.
(b)
Piping which would be exposed during an emergency to the
cold of an LNG or refrigerant spill or the heat of an ignited spill when either
exposure could result in a failure of the piping which would significantly
increase the emergency shall be:
(1)
made of material that is suitable for both its normal operating
temperature and the extreme temperatures to which it might be subjected during
an emergency;
(2)
protected by insulation or other means to delay failure
due to such extreme temperatures until corrective action may be taken by the
operator; or
(3)
capable of being isolated and having the flow stopped in
piping that would be exposed only to the heat of an ignited spill during the
emergency.
(c)
Piping insulation used in areas where the mitigation of
fire exposure is necessary shall be made of material which will not propagate
fire and shall maintain any properties which are necessary during an emergency
when exposed to fire, heat, cold, or water.
(d)
Furnace lap-weld, furnace butt-weld, cast iron, malleable
iron, and ductile iron pipe shall be prohibited.
(e)
When longitudinal or spiral weld pipe is used (welded with
or without filler metal), the weld and heat-affected zone shall comply with
ANSI B31.3, 323.2.2, and §14.2419 of this title (relating to Welding
at Piping Installations).
(f)
Threaded pipe shall be at least schedule 80.
(g)
A liquid line, excluding loading arms or hoses, on a storage
container, cold box, or other major item of insulated equipment external to
the outer shell or jacket whose failure can release a significant quantity
of flammable fluid shall not be made of aluminum, copper, or copper alloy,
or other material which has low resistance to flame temperatures unless such
material is protected against fire exposure. Transition joints may be used
if they are protected against fire exposure.
§14.2407.Fittings Used in Piping.
(a)
Cast iron, malleable iron, and ductile iron shall not be
used in fittings.
(b)
Threaded nipples shall be at least schedule 80.
(c)
Bends are permitted only in accordance with ANSI B31.3,
329.
(d)
Solid plugs or bull plugs made of at least schedule 80
shall be used for threaded plugs.
(e)
Compression-type couplings shall not be used where they
will be subjected to temperatures below -20 degrees Fahrenheit unless such
couplings meet the requirements of ANSI B31.3, 318.
§14.2410.Valves.
(a)
Cast iron, malleable iron, and ductile iron shall not be
used in valves in piping.
(b)
Extended bonnet valves with or without bellows seals should
be used for service temperatures below -50 degrees Fahrenheit.
§14.2413.Installation of Piping.
(a)
Bolted connections shall be designed to withstand thermal
contraction and expansion.
(b)
Pipe joints larger than two-inch nominal diameter shall
be welded or flanged. Joints of four-inch nominal diameter or less may be
threaded where necessary for special connections to equipment provided that
the special connection is not subject to fatigue-producing stresses. The number
of threaded or flanged joints shall be kept to a minimum. Dissimilar metals
shall only be joined by flanges or transition joint techniques which will
not be adversely affected by LNG.
(c)
Gasket material shall withstand as much as practicable
exposure to fire.
(d)
Piping and tubing shall be installed as directly as possible
with provisions for expansion, contraction, jarring, vibration, and settling.
Underground piping shall be buried at least 18 inches below the ground surface
unless otherwise protected. Refrigerated piping shall not be buried unless
the surrounding soil is heated.
§14.2416.Installation of Valves.
(a)
Valves shall be installed to prevent leaking or malfunction
due to freezing. Cryogenic liquid valves shall be installed at an angle greater
than 45 degrees from horizontal.
(b)
Isolation valves shall be provided on container, tank,
and vessel connections, except for connections:
(1)
for relief valves. Shutoff valves are only permitted at
connections for relief valves in accordance with ASME Code, Section VIII,
Division 1, Paragraphs UG-125(d) and Appendix M, Paragraphs M-5 and M-6;
(2)
for liquid level alarms required by §14.2501 of this
title (relating to Liquid Level Gauging); or
(3)
that are blind-flanged or plugged.
(c)
Shutoff valves shall be located inside the impounding area
as close as practicable to the containers, tanks, and vessels.
(d)
Internal valves shall be designed and installed so that
any failure of the nozzle will be downstream of the seat of the internal valve
itself.
(e)
The number of shutoff valves installed shall be kept to
the minimum required for efficient and safe operation of each facility.
(f)
Piping systems shall be designed to limit the contained
volume that could be discharged in the event of a piping system failure. Sufficient
valves which can be operated both at the installed location and from a remote
location to shut down the process and transfer systems in the event of an
emergency shall be installed.
(g)
Container connections larger than one-inch pipe size through
which liquid can escape shall be equipped with:
(1)
a valve which closes automatically if exposed to fire;
or
(2)
a remotely controlled, quick-closing valve which shall
remain closed except during the operating period;
(3)
a fail-close valve; or
(4)
a check valve on filling connections.
(h)
ESD valves shall be single-purpose valves.
(i)
Valves and valve controls shall be designed to permit operation
under icing conditions, if such conditions are possible.
(j)
Powered controls shall be provided for emergency shutoff
valves that would require excessive time to manually operate during an emergency
or if the valve is eight inches or larger in size. A means for manual operation
shall also be provided.
§14.2419.Welding at Piping Installations.
Qualification and performance of welders shall comply with ANSI B31.3.
Oxygen-fuel gas welding is prohibited on piping for service temperatures below
-20 degrees Fahrenheit. Electric arc or inert gas-shielded welding are permissible.
§14.2422.Pipe Marking and Identification.
(a)
Markings on pipe shall be made with a material compatible
with the basic material or with a round-bottom, low-stress die. Materials
less than 1/4 inch in thickness shall not be die-stamped.
(b)
Marking materials that are corrosive to the pipe material
shall not be used.
(c)
Piping shall be identified by color-coding, painting, or
labeling so as to be readily readable.
§14.2425.Pipe Supports.
(a)
Pipe supports, including insulation systems used to support
pipe whose integrity is essential to facility safety, shall be resistant to
or protected from fire exposure, escaping cold liquid, or both, if such exposure
is possible.
(b)
Pipe supports for cold lines shall be designed to prevent
excessive heat transfer which can result in piping restraints caused by ice
formations or embrittlement of supporting steel. Design of supporting elements
shall conform with ANSI B31.3, 321.
§14.2428.Inspection and Testing of Piping.
(a)
Pressure tests shall be conducted in accordance with ANSI
B31.3, 337.
(b)
Pressure, test medium temperature, and ambient temperature
shall be recorded for the duration of each test and these records shall be
maintained for the life of the facility or until such time as a retest is
conducted.
§14.2431.Welded Pipe Tests.
(a)
Longitudinal or spiral welded pipe which will be subjected
to service temperatures below -20 degrees Fahrenheit shall have a design pressure
of less than 2/3 of the mill proof test pressure or subsequent shop or field
hydrostatic test pressure, except for pipe which has been subjected to 100%
radiographic or ultrasonic inspection of the longitudinal or spiral weld.
(b)
Circumferential butt-welds shall be fully examined by radiographic
or ultrasonic inspection. Piping with an operating pressure that produces
a hoop stress of less than 20% specified minimum yield stress need not be
nondestructively tested provided it has been visually inspected in accordance
with ANSI B31.3, 336.4.2.
(c)
Socket welds and fillet welds shall be fully examined by
liquid penetrant.
(d)
Fully penetrated groove welds for branch connections required
by ANSI B31.3, 327.4.4 shall be fully examined by inprocess examination in
accordance with ANSI B31.3, 336.4.7, and shall also be examined by liquid
penetrant after the final pass of the weld. If specified in the engineering
design or specifically authorized by the inspector, examination by radiographic
or ultrasonic techniques may be substituted for the examinations required
by this paragraph.
(e)
Nondestructive examination methods, limitations on defects,
qualifications of the authorized inspector, and personnel performing the examination
shall meet the requirements of ANSI B31.3, 336.
(f)
Test records and written procedures required when conducting
nondestructive examinations shall be maintained for the life of the piping
system or until such time as a reexamination is conducted.
(g)
Records and certifications pertaining to materials, components,
and heat treatment as required by ANSI B31.3, 336.5.1(c) and 336.5.3(d) shall
be maintained for the life of the system.
§14.2434.Purging of Piping Systems.
Piping systems shall be purged of air or gas in a safe manner. Blow-down
and purge connections shall be provided to facilitate purging of all process
and flammable gas piping. Such connections shall be installed to eliminate
all hazards to a safe operating condition.
§14.2437.Pressure and Relief Valves in Piping.
(a)
Pressure relieving safety devices shall be installed to
minimize damage to equipment and personnel. The means for adjusting relief
valve set pressure shall be sealed.
(b)
Thermal expansion relief valves shall be installed to prevent
overpressure in any section of cold liquid or cold vapor piping which can
be isolated by valves.
(c)
Thermal expansion relief valves shall be set to discharge
above the maximum pressure normally expected in the line but less than the
rated test pressure of the line they protect.
(d)
Discharge from the valves shall be directed to minimize
hazard to personnel or equipment and the discharge location shall be approved
by the Commission.
§14.2440.Corrosion Control.
(a)
Underground and submerged piping shall be protected and
maintained in accordance with the National Association of Corrosion Engineers
Standard RP-01-69M, Control of External Corrosion of Underground or Submerged
Metallic Piping Systems.
(b)
Austenitic stainless steels and aluminum alloys shall be
protected to minimize corrosion and pitting from corrosive atmospheric and
industrial substances during storage, construction, fabrication, testing,
and service.
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 February 26, 2003.
TRD-200301442
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§14.2501, 14.2504, 14.2507, 14.2510, 14.2513, 14.2516
The new rules are proposed under Texas Natural Resources Code, §116.012,
which authorizes the Commission to adopt rules and standards relating to liquefied
natural gas activities to protect the health, welfare, and safety of the general
public; and under Senate Bill 310, 77th Legislature (2001), as codified at
Texas Natural Resources Code, §§116.032, 116.033, 116.034, and 116.0346.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on February 25, 2003.
§14.2501.Liquid Level Gauging.
(a)
LNG containers shall be equipped with liquid level gauging
devices. Density variations shall be considered in the selection of the gauging
device. Consideration shall be given to a secondary or backup gauge. At least
one of these gauges shall be replaceable without taking the container out
of operations.
(b)
When the container filling rate is greater than 1.0% per
day, the container shall be provided with a high-liquid-level alarm which
shall be separate from the liquid level gauging device. The alarm shall be
set so that the operator will have sufficient time to stop the flow without
exceeding the maximum permissible filling height, and shall be located so
that it is visible and audible to personnel controlling the filling. A high-liquid-level
flow cutoff device, if used, shall not substitute for the alarm.
(c)
Containers with a capacity of 93,240 gallons or less which
are continuously attended during the filling operation may be equipped with
trycocks in lieu of the high-liquid-level alarm.
§14.2504.Pressure Gauges.
LNG containers shall be equipped with a pressure gauge connected to
the container at the point above the maximum intended liquid level.
§14.2507.Vacuum Gauges.
Vacuum-jacketed containers shall be equipped with instruments or connections
for checking the absolute pressure in the annular space.
§14.2510.Emergency Failsafe.
Facilities shall be designed so that if power or instrument air fails,
the system will go into a failsafe condition that will be maintained until
the operator can take appropriate action to either reactivate or secure the
system.
§14.2513.Electrical Equipment.
(a)
Electrical equipment and wiring shall be installed in accordance
with the applicable sections of NEC.
(b)
Fixed electrical equipment and wiring installed within
the areas specified in Table 1 of subsection (h) of this section shall comply
with the requirements specified.
(c)
Seals, barriers, or other means used to comply with this
section shall be designed to prevent the passage of flammable fluids through
the conduit, stranded conductors, and cables. Such means may include but not
be limited to:
(1)
a physical interruption of the conduit run and of the stranded
conductors through the use of an adequately vented junction box containing
terminal strip or busbar connections;
(2)
an exposed section of MI cable using suitable fittings;
or
(3)
an exposed section of single conductor which is incapable
of transmitting gases or vapors.
(d)
A primary seal shall be provided between the flammable
fluid system and the electrical conduit wiring system. If the failure of the
primary seal would allow the passage of flammable fluids to another portion
of the conduit or wiring system, an additional seal shall be provided to prevent
the passage of the flammable fluid beyond the additional device or means.
(e)
Unless specifically designed and approved for the purpose,
the seals specified in this section are not intended to replace the conduit
seals required in NEC.
(f)
Where primary seals are installed, drains, vents, or other
devices shall be provided for monitoring purposes to detect flammable fluids
and leaking.
(g)
Primary seals shall be designed to withstand the service
conditions to which they may be exposed. Additional seals or barriers and
interconnecting enclosures shall meet the pressure and temperature requirements
of the condition to which they could be exposed in the event of failure of
the primary seal, unless other approved means are provided to accomplish this
purpose.
(h)
The classified areas described in Table 1 of this section
shall not extend beyond an unpierced wall, roof, or solid vaportight partition.
§14.2516.Electrical Grounding and Bonding.
(a)
Electrical grounding and bonding shall be provided as recommended
by NFPA 77, Static Electricity, Sections 5.4 and 6.1.3, and as required by
the NEC.
(b)
Static protection is not required when container vehicles
are loaded or unloaded by conductive or nonconductive hose, flexible metallic
tubing, or pipe connections through or from tight top or bottom outlets where
both halves of metallic couplings are in contact.
(c)
If stray currents may be present or if impressed currents
are used on loading and unloading systems such as for cathodic protection,
protective measures to prevent ignition shall be taken in accordance with
API RP 2003, Protection Against Ignitions Arising Out of Static, Lightning
and Stray Currents.
(d)
Grounding shall be provided for tanks supported on nonconductive
foundations. Metal storage containers and tanks do not require lightning protection.
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 February 26, 2003.
TRD-200301443
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§14.2601, 14.2604, 14.2607, 14.2610, 14.2613, 14.2616, 14.2619, 14.2622, 14.2625, 14.2628, 14.2631, 14.2634, 14.2637, 14.2640, 14.2643
The new rules are proposed under Texas Natural Resources Code, §116.012,
which authorizes the Commission to adopt rules and standards relating to liquefied
natural gas activities to protect the health, welfare, and safety of the general
public; and under Senate Bill 310, 77th Legislature (2001), as codified at
Texas Natural Resources Code, §§116.032, 116.033, 116.034, and 116.0346.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on February 25, 2003.
§14.2601.Applicability.
This subchapter applies to the design, installation, inspection, and
testing of LNG fuel supply systems for vehicle engines and other engines installed
on a vehicle.
§14.2604.System Component Qualification.
(a)
Components in the engine compartment normally in contact
with LNG shall be suitable for service over a range of temperatures of -260
degrees Fahrenheit to +250 degrees Fahrenheit. Other components not normally
in contact with LNG shall be suitable for service over a range of -40 degrees
Fahrenheit to +250 degrees Fahrenheit.
(b)
Components outside the engine compartment normally in contact
with LNG shall be suitable for service over a range of temperatures from -260
degrees Fahrenheit to +180 degrees Fahrenheit. Other components not normally
in contact with LNG shall be suitable for service over a range from -40 degrees
Fahrenheit to +180 degrees Fahrenheit.
(c)
Fuel-carrying components (excluding service valves, tubing,
and fittings) shall be labeled or stamped with the following:
(1)
the manufacturer's name or symbol;
(2)
the model designation;
(3)
the maximum allowable maximum allowable working pressure;
(4)
the design temperature range;
(5)
direction of flow of fuel when necessary for correct installation;
and
(6)
capacity or electrical rating as applicable.
§14.2607.Vehicle Fuel Containers.
(a)
Containers shall be designed, tested, and marked or stamped
in accordance with DOT Specification 4L or ASME Code, "Rules for the Construction
of Pressure Vessels," Section VIII, Division 1, applicable on the date of
manufacture.
(b)
The owner of a container shall be responsible for its suitability
for continued service.
(c)
Repair or alteration of containers shall comply with the
Code under which that container was fabricated. Licensees making repairs or
alterations shall file LNG Form 2008 with the Commission.
(d)
Containers shall be equipped with a dip tube or other device
so that the maximum filling volume of the container complies with §14.2107
of this title (relating to Stationary LNG Storage Containers).
(e)
Containers shall be constructed so that the unrelieved
pressure inside the container shall not exceed the maximum allowable working
pressure of the container within a 72-hour period at an ambient temperature
of 70 degrees Fahrenheit after the container has been filled with LNG stabilized
at the maximum allowable working pressure and temperature equilibrium has
been established.
(f)
Connections for pressure relief valves shall be located
and installed to communicate directly with the vapor space.
(g)
Containers shall have permanent identification markings,
decals, or stencils to identify:
(1)
the total volumetric capacity of the container in gallons;
(2)
the words, "FOR LNG ONLY," in capital letters at least
one inch high in a location that is visible after installation; and
(3)
all inlets and outlets, except relief valves and gauging
devices, designating whether they communicate with vapor or liquid space.
(h)
Container appurtenances shall be fabricated of materials
suitable for LNG service. Pressure containing metal parts of appurtenances,
except fusible elements, shall have a minimum melting point of +1,500 degrees
Fahrenheit. Container appurtenances shall have a rated maximum allowable working
pressure not less than the maximum allowable working pressure of the container.
(i)
Containers shall be equipped with the pressure relief devices
and pressure control valves required by the code or regulations under which
the containers were designed. The pressure relief devices and pressure control
valves shall communicate directly with the vapor space of the container, and
shall be designed to minimize the possibility of tampering. Externally set
or adjusted valves shall be provided with a means of sealing the adjustment.
(j)
Valves shall be readily accessible and operable without
the use of tools. A shutoff valve shall be installed directly on the container
vapor outlet with no intervening fitting other than pressure relief devices
and shall be marked with the words, "VAPOR SHUTOFF VALVE." Another shutoff
valve shall be installed directly on the container liquid outlet and shall
be marked with the words, "LIQUID SHUTOFF VALVE." The markings shall be in
capital letters. Decals or stencils are acceptable. Normally closed automatic
shutoff valves that are held open by electric current or manually operated
shutoff valves may be used.
§14.2610.Installation of Vehicle Fuel Containers.
(a)
Vehicle fuel containers shall comply with the following
specifications:
(1)
Fuel containers on vehicles other than school buses, mass
transit, or other vehicles used in public transportation may be located within,
below, or above the driver or passenger compartments, provided all connections
to the containers are external to or sealed and vented from those compartments.
The motor fuel containers installed on a special transit vehicle may be installed
in the passenger compartment, provided all connections to the containers are
external to or sealed and vented from those compartments.
(2)
Fuel supply components and containers shall be mounted
in a location to minimize damage from collision. No part of a container or
its appurtenances shall protrude beyond any part of the vehicle at the point
of installation.
(3)
Fuel systems shall be installed with as much road or ground
clearance as practicable, but not less than the minimum road or ground clearance
of the vehicle when loaded to its gross vehicle weight rating. The minimum
distance shall be measured from the lowest part of the fuel system.
(4)
No portion of a fuel supply container or container appurtenance
shall be located ahead of the front axle or behind the rear bumper mounting
face of a vehicle. Fuel container valves shall be protected from physical
damage using the vehicle structure, valve protectors, or a suitable metal
shield.
(5)
Fuel supply containers located less than eight inches from
the exhaust system shall be shielded from direct heat.
(6)
Mountings shall minimize fretting corrosion between the
fuel container and the mounting system by means of rubber insulators or other
suitable means.
(7)
Fuel containers shall not be installed where they would
adversely affect the driving characteristics of the vehicle.
(8)
Fuel containers on school buses or mass transit vehicles
shall be installed on the underside of the vehicle, except as specified in
subsection (c) of this section. Fuel containers on special transit vehicles
shall be installed in a location which will not interfere with vehicle operation.
(9)
Fuel containers, appurtenances, and connections may be
enclosed in a shroud-type structure, provided it is securely attached to the
container and liquid-tight. The shroud access doors shall be secured in place
by fasteners such as wing nuts or spring-loaded latches and shall not require
the use of tools for removal. The use of locks on shroud access doors is prohibited.
(b)
Fuel supply containers shall be connected or mounted to
comply with the following specifications:
(1)
Fuel supply container connections shall be external to
or sealed and vented from the driver and passenger compartments or any space
containing radio transmitters or other spark-producing equipment.
(2)
Container brackets shall be secured to the vehicle body,
bed, or frame with bolts, lock washers and nuts, or self-locking nuts of a
size and strength capable of withstanding a static force in any direction
of eight times the weight of a full container for vehicles with gross vehicle
weights of 19,500 pounds or less, and four times the weight of a full container
for vehicles with gross vehicle weights of 19,501 pounds or more. Mounting
brackets shall be marked with the manufacturer's name or logo. If self-locking
nuts are installed, they shall not be reused once they are removed. Container
mounting brackets shall prevent the container from jarring loose, slipping
or rotating.
(3)
Fuel supply containers shall be secured in the mounting
brackets by bolts, lock washers, and nuts, or self-locking nuts of a size
and strength capable of withstanding a static force applied in any direction
eight times the weight of the full container for vehicles with gross vehicle
weights of 19,500 pounds or less, and four times the weight of a full container
for vehicles with gross vehicle weights of 19,501 pounds or more. If self-locking
nuts are installed, the nuts shall not be reused once they are removed.
(4)
The weight of the fuel container shall not be supported
by the outlet, service valves, manifolds, or other fuel connections.
(5)
Containers shall be secured to a school bus, mass transit,
or special transit vehicle frame excluding the floor by container fastenings
or mounting brackets described in subsection (b) of this section. The fastenings
or brackets shall be secured to the frame, backing plates, or other supporting
structure without compromising the strength of that structure.
(c)
Roof-mounted containers are allowed if the vehicle was
originally designed and manufactured to have roof-mounted containers or if
the original manufacturer approves the design of the structure mounting. Vehicles
shall not be modified to have roof-mounted containers.
(d)
Container markings shall be readable after a container
is permanently installed on a vehicle. A portable lamp or mirror may be used
to read markings.
(e)
Where an LNG container is substituted for the fuel container
installed by the original manufacturer of the vehicle, whether or not that
fuel container was for LNG, the LNG container shall either fit within the
space in which the original fuel container was installed or comply with subsection
(a) of this section.
(f)
If necessary, a plumbing chamber door shall be provided
in the sidewall of the school bus, mass transit, or special transit vehicle
to allow for easy access for filling or securing the service valve in the
event of an emergency. The plumbing chamber door shall be hinged and latched,
but not locked.
§14.2613.Engine Fuel Delivery Equipment.
(a)
Vaporizers shall completely vaporize the LNG and heat the
vapor to the appropriate temperature prior to the vapor entering the pressure
regulator when the vaporizer is subjected to the maximum fuel flow rate. Vaporizers
shall be permanently marked at a readily visible point with the maximum allowable
working pressure of the fuel-containing portion of the vaporizer. Engine exhaust
gases may be used as a direct source of heat to vaporize the fuel if the materials
of construction of those parts of the vaporizer in contact with the exhaust
gases are resistant to corrosion from those gases.
(b)
Pressure regulator inlets and chambers shall have a maximum
allowable working pressure of at least the maximum allowable working pressure
of the container.
(c)
Pressure gauges shall be designed for the pressure and
temperature conditions to which they may be subjected with a burst pressure
safety factor of at least four. Dials shall be graduated to read at least
1.2 times the pressure at which a pressure relief device is set to function.
Gauges shall have an opening not to exceed 0.055 inches (Number 54 drill size)
at the inlet connection.
(d)
Pipe, tubing, and fittings between the vehicular fuel container
and the pressure regulator shall be designed to withstand a pressure of at
least two times the maximum allowable working pressure of the container.
(1)
Gaskets and packing material shall be suitable for the
intended service.
(2)
Pipe shall be stainless steel, brass, or copper, and shall
comply with the following:
(A)
stainless steel pipe: ANSI B36.19, Specification for Stainless
Steel Pipe (ASTM A 312);
(B)
brass pipe: ANSI H27.1, Specification for Seamless Red
Brass Pipe, Standard Size (ASTM B 43);
(C)
copper pipe: ANSI H26.1, Specification for Seamless Copper
Pipe, Standard Sizes (ASTM B 42).
(3)
Tubing shall be stainless steel, brass, or copper, and
shall comply with the following:
(A)
stainless steel tubing: ANSI B31.3, Specification for Seamless
and Welded Austenitic Steel Tubing for General Service (ASTM A 269);
(B)
copper tubing: Type K or L, ANSI H23.1, Specification for
Seamless Copper Water Tube (ASTM B 88);
(C)
copper tubing: ANSI H23.5, Specification for Seamless Copper
Tube for Air Conditioning and Refrigeration Field Service (ASTM B 280); or
(D)
brass tubing: ANSI H36.1, Specification for Seamless Brass
Tube (ASTM B 135).
(4)
Pipe and tube fittings shall be stainless steel, brass,
or copper. Pipe joints shall be threaded, welded, or brazed. Tubing joints
shall be flared, welded, brazed, or made with tube fittings.
§14.2616.Installation of Venting Systems and Monitoring Sensors.
(a)
Pressure relief devices and pressure carrying components
installed within a closed compartment shall be vented to the outside of the
vehicle in a suitable location.
(b)
Vents shall not exit into a wheel well.
(c)
Vents shall not restrict the operation of a fuel container
pressure relief device or pressure relief device channel. Vent lines shall
be located and secured to permit the required relief discharge capacity and
to minimize the possibility of physical damage.
(d)
Vent lines shall be equipped with a means to minimize the
possibility of water or other foreign material from entering the relief device
or vent line. Such means shall remain in place except when the relief device
operates and shall permit the relief device to operate at the required capacity.
(e)
Escaping gas shall not impinge on fuel supply containers
and shall not be directed into wheel wells, at individuals or other vehicles
in traffic, at the engine air intake, or in a manner that would create a hazard.
(f)
Safety relief valve discharge shall be directed or vented
so that any gas released will not directly impinge upon containers, any part
of the vehicle, adjacent individuals or vehicles, or the inside of the passenger
or luggage compartment.
(g)
At least two monitoring sensors shall be installed on all
LNG-fueled vehicles to detect hazardous levels of LNG. Sensors shall activate
at not more than 20% of the lower flammable limit of LNG. If the level exceeds
one-fifth of the LFL, the sensor shall either shut the system down or activate
an audible and visual alarm. The number of sensors to be installed shall comply
with the area of coverage for each sensor and the size of the vehicle. The
sensors shall be installed and maintained in accordance with the manufacturer's
instructions.
§14.2619.Installation of Piping.
(a)
Piping that carries fuel shall be fabricated to minimize
vibration and shall be shielded or installed in a protected location to prevent
damage from unsecured objects.
(b)
Fuel lines shall be mounted, braced, and supported to minimize
vibration and protected against damage, corrosion, or breaking due to strain
or wear. Fuel lines shall be supported at least every 21 to 27 inches.
(c)
Fuel lines passing through a panel shall be protected against
abrasion by grommets or similar devices such as fittings, which shall snugly
fit both the supply lines and the holes in the panel.
(d)
Fuel lines shall have a minimum clearance of eight inches
from the engine exhaust system or shall be shielded against direct heat.
(e)
Piping or tubing shall pass through the floor of a vehicle
directly beneath or adjacent to the container. If a branch line is required,
the tee connection shall be in the main fuel line under the floor and outside
the vehicle.
(f)
Hydrostatic relief valves shall be installed in each section
of piping or tubing in which LNG can be isolated between shutoff valves to
relieve to a safe atmosphere the pressure which could develop from the trapped
fuel. The pressure relief valve shall have a pressure not greater than the
maximum allowable working pressure of the line it protects.
(g)
Joint compound or tape acceptable for use with LNG shall
be applied to all male pipe threads prior to assembly.
(h)
Piping and fittings shall be clean and free from cutting
or threading burrs and scaling. The ends of all piping shall be reamed.
(i)
Bends in piping or tubing are prohibited if the bend weakens
the pipe or tubing. Bends shall be made by bending tools designated for this
purpose.
(j)
Joints or connections shall be located only in an accessible
location.
(k)
Fuel connections between a tractor and trailer or other
vehicle units are prohibited.
§14.2622.Installation of Valves.
(a)
Valves, valve packings, gaskets, and seats shall be suitable
for the intended service and shall comply with the following:
(1)
Shutoff valves shall have a maximum allowable working pressure
of at least the maximum allowable working pressure of the container. Leakage
shall not occur at less than 1 1/2 times the maximum allowable working pressure
of the valve.
(2)
Valve parts, except gaskets, packing, and seats that come
in contact with the fuel shall be stainless steel, brass, or copper.
(b)
Valves shall be securely mounted and shielded or installed
in a protected location to minimize damage from vibration and unsecured objects.
(c)
In vehicles whose engines do not incorporate an automatic
shutoff in the engine fuel system, a positive shutoff valve shall be installed
in the fuel supply line at the inlet to the pressure regulator. The shutoff
valve shall automatically close and prevent the flow of fuel to the engine
when the ignition switch is off or in the accessory position, or when the
engine is not running and the ignition switch is on.
(d)
When multiple fuel systems are installed on the vehicle,
automatic valves shall be provided as necessary to shut off the fuel not being
used.
(e)
Fueling systems shall be equipped with a backflow check
valve which will prevent the return of gas from the container to the filling
connection.
(f)
Valves shall be installed so that their weight is not placed
on or supported by the attached lines.
§14.2625.Installation of Pressure Gauges.
(a)
Pressure gauges located within driver or passenger compartments
shall be installed so that no gas will flow through the gauge in the event
of failure. Installed gauges shall be readily visible by the driver.
(b)
Pressure gauges installed outside driver or passenger compartments
shall be equipped with a limiting orifice, a shatter-proof dial lens, and
a body relief.
(c)
Gauges shall be securely mounted, shielded, and installed
in a protected location to prevent damage from vibration and unsecured objects.
§14.2628.Installation of Pressure Regulators.
(a)
Automatic pressure reducing regulators shall be installed
to reduce the fuel container pressure to a level consistent with the maximum
allowable working pressure required by the engine fuel system, if the primary
relief valve setting to the fuel container exceeds the maximum allowable engine
inlet fuel pressure, and automatic pressure reducing regulator.
(b)
Means shall be provided to prevent regulator malfunctions
due to low temperatures.
(c)
Regulators shall be installed so that their weight is not
placed on or supported by the attached gas lines.
§14.2631.Wiring.
(a)
Wiring shall be installed, supported, and secured in a
manner to prevent damage due to vibration, shock, strains, wear, or corrosion.
(b)
Wiring shall be sized and fuse-protected with the size
and fuse rating adequate for the current draw.
§14.2634.Vehicle Fueling Connection.
(a)
Vehicle fueling connections shall provide for the reliable
and secure connection of the fuel system containers to a source of LNG.
(b)
Fueling connections shall be designed for the pressure
expected under normal conditions and corrosive conditions which might occur.
(c)
Fueling connections shall prevent escape of gas when the
connector is not properly engaged or becomes separated.
(d)
Refueling receptacles on engine fuel systems shall be firmly
supported and shall:
(1)
receive the fueling connector and accommodate the maximum
allowable working pressure of the vehicle fuel system;
(2)
incorporate a means to prevent the entry of dust, water,
and other foreign material. If the means used is capable of sealing system
pressure, it shall be capable of being depressurized before removal; and
(3)
have a different fueling connection for each pressure base
vehicle fuel system.
§14.2637.Signs and Labeling.
(a)
Signs or labels shall be readily visible before and during
transfer operations, shall be weather-resistant, and shall be located as specified
in Table 1 of this section.
(b)
Vehicles shall be identified with a weather-resistant diamond-shaped
label located on an exterior vertical or near vertical surface on the lower
right rear of the vehicle (excluding the bumper) inboard of any other markings.
The label shall be at least 4 3/4 inches by 3 1/4 inches. The marking shall
consist of a border and the capital letters, "LNG"; the letters shall be at
least one inch tall, and be silver or white reflective luminous material on
a blue or black background.
(c)
Upon completion of a vehicle conversion, the licensee making
the conversion shall affix to the vehicle an identification tag or decal in
a location that is easily readable. The tag or decal shall contain letters
that indicate the licensee's name, current license number, and the year and
month the conversion was made.
§14.2640.System Testing.
(a)
The complete LNG engine fuel system shall be leak tested.
(b)
After installation, the piping and connections that are
subject to container pressure shall be checked with a non-ammonia soap solution
or a leak detector instrument after the equipment is connected and pressurized
to its 90% of the maximum allowable working pressure of the container.
(c)
If the completed LNG engine fuel system is leak tested
with natural gas, the testing shall be done under adequately ventilated conditions.
(d)
If an LNG container is involved in an accident or fire
causing damage to the container, the container shall be replaced or removed
and returned to a currently licensed Category 15, 20, or 50 licensee to be
inspected and retested in accordance with the original manufacturer's specifications.
The licensee who performs any repair, modification, or testing of a container
shall file LNG Form 2008 with the Commission before the container is returned
to service.
(e)
If a vehicle is involved in an accident or fire causing
damage to any part of the LNG engine fuel system, the system shall be replaced
or repaired as provided in these regulations and retested before it is returned
to service.
§14.2643.Maintenance and Repair.
(a)
The owner or user or both shall maintain containers, container
appurtenances, piping systems, venting systems, and other components in a
safe condition.
(b)
Repair or alteration of pressure relief devices and fuel
lines is prohibited. Damaged pressure relief devices and fuel lines shall
be replaced.
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 February 26, 2003.
TRD-200301444
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
16 TAC §§14.2701, 14.2704, 14.2705, 14.2707, 14.2710, 14.2713, 14.2716, 14.2719, 14.2722, 14.2725, 14.2728, 14.2731, 14.2734, 14.2737, 14.2740, 14.2746, 14.2749
The new rules are proposed under Texas Natural Resources Code, §116.012,
which authorizes the Commission to adopt rules and standards relating to liquefied
natural gas activities to protect the health, welfare, and safety of the general
public; and under Senate Bill 310, 77th Legislature (2001), as codified at
Texas Natural Resources Code, §§116.032, 116.033, 116.034, and 116.0346.
Cross-reference to statute: Texas Natural Resources Code, Chapter 116.
Issued in Austin, Texas, on February 25, 2003.
§14.2701.DOT Requirements.
(a)
This subchapter applies to transport containers used in
the transportation and distribution of LNG.
(b)
LNG transports shall comply with the requirements of DOT
specification MC-338 and the applicable parts of Title 49, Code of Federal
Regulations, Parts 171 - 180.
§14.2704.Registration and Transfer of LNG Transports.
(a)
A person who operates an LNG transport as defined in this
chapter, regardless of who owns the transport, shall register the transport
with the Commission in the name or names under which the operator conducts
business in Texas prior to the transport being used in LNG service in Texas.
(1)
To register a unit previously unregistered in Texas, the
operator of the unit shall:
(A)
pay to the Commission the $270 registration fee for each
transport truck, semi-trailer, or other motor vehicle equipped with an LNG
cargo tank; and
(B)
file a properly completed LNG Form 2007.
(2)
To register a unit which was previously registered in Texas
but for which the registration has expired, the operator of the unit shall:
(A)
pay to the Commission the $270 registration fee;
(B)
file a properly completed LNG Form 2007;
(C)
file a copy of the latest test results if an expired unit
has not been used in the transportation of LNG for over one year.
(3)
To transfer a unit, the new owner of the transport shall:
(A)
pay the $100 transfer fee for each unit; and
(B)
file a properly completed LNG Form 2007.
(b)
The Commission may also request an operator registering
or transferring any unit to file a copy of the Manufacturer's Data Report
of a copy of the DOT certification issued by the manufacturer and/or subframer
who prepared the unit for road use, or any other documentation to show the
container complies with MC-338.
(c)
When all registration or transfer requirements have been
met, the Commission shall issue LNG Form 2004 or letter of authority which
shall be properly affixed as instructed on the decal or letter or maintained
on the bobtail or transport trailer. LNG Form 2004 or letter of authority
shall authorize the licensee or ultimate consumer to whom it has been issued
and no other person to operate such unit in the transportation of LNG and
to fill the transport containers.
(1)
A person shall not operate an LNG transport unit or introduce
LNG into a transport container in Texas unless the LNG Form 2004 or letter
of authority has been properly affixed as instructed on the decal or the letter
or maintained on the bobtail or transport trailer or unless its operation
has been specifically approved by the Commission.
(2)
LNG Form 2004 or letter of authority shall not be transferable
by the person to whom it has been issued, but shall be registered by any subsequent
licensee or ultimate consumer prior to the unit being placed into LNG service.
(3)
This section shall not apply to:
(A)
a container manufacturer/fabricator from introducing a
reasonable amount of LNG into a newly constructed container in order to properly
test the vessel, piping system, and appurtenances prior to the initial sale
of the container. The LNG shall be removed from the transport container prior
to the transport leaving the manufacturer's or fabricator's premises; or
(B)
a person introducing a maximum of 150 gallons into a newly
constructed transport container when such container will provide the motor
fuel to the chassis engine for the purpose of allowing the unit to reach its
destination.
(4)
The Commission shall not issue an LNG Form 2004 or letter
or authority if the Commission or a Category 15 or 50 licensee determines
that the transport is unsafe for LNG service.
§14.2705.Decals or Letter of Authority and Fees.
If an LNG Form 2004 decal or letter or authority on a unit currently
registered with the Commission is destroyed, lost, or damaged, the operator
of that vehicle shall obtain a replacement decal or letter of authority by
filing LNG Form 2018B and a $50 replacement fee with the Commission.
§14.2707.Testing Requirements.
(a)
Transport container units required to be registered with
the Commission shall be tested at least once every five years by a Category
15, 20, or 50 licensee.
(1)
Documentation of the required testing shall be filed by
the Category 15, 20, or 50 licensee.
(2)
The results of any test required under this section shall
clearly indicate whether the transport container unit is safe for LNG service.
The Category 15, 20, or 50 licensee shall mail LNG Form 2008 to the Commission
within 30 calendar days of the due date of any tests required under this section.
(3)
If evidence of any unsafe condition is discovered as a
result of any tests performed under this section, the transport container
unit shall be immediately removed from LNG service and shall not be returned
to LNG service until the Commission notifies the licensee in writing that
the transport container unit may be returned to LNG service.
(b)
Containers shall be tested in accordance with 49 CFR §338.
(c)
Containers shall be inspected for corroded areas, dents,
or other conditions (including leakage under test pressure) which could render
the container unsafe for LNG service.
§14.2710.Markings.
(a)
LNG transports and container delivery units in LNG service
shall be marked with the name of the licensee or the ultimate consumer operating
the unit. The name shall be in letters at least two inches in height and in
sharp color contrast to the background. The Commission will determine whether
the marking is sufficient to properly identify the operator.
(b)
Other markings shall comply with other DOT marking requirements.
(c)
If a transport unit is loaned or leased for a period of
time not to exceed 30 days, the unit may have painted or permanently affixed
thereon, in lieu of the name of the licensee operating the transport unit,
the name of the owner of the transport unit in letters at least two inches
in height.
§14.2713.Pressure Gauge.
Transport containers shall be equipped with a pressure gauge for LNG
service which shall be maintained in good operating condition at all times.
An isolation valve shall be installed between the container and the pressure
gauge.
§14.2716.Supports.
Transport containers shall be supported as required by DOT Regulations,
49 CFR §178.337-13.
§14.2719.Electrical Equipment and Lighting.
LNG transports and container delivery units shall not be equipped with
an artificial light other than electrical. Lighting circuits shall have suitable
overcurrent protection (fuses or automatic circuit breakers). Wiring shall
have sufficient current capacity and mechanical strength, and shall be secured,
insulated, and protected against physical damage.
§14.2722.Liquid Level Gauging Devices.
Truck and trailer containers shall be equipped with a liquid level
gauging device of approved design, such as a fixed tube device. Fixed tube
devices shall be arranged so that the maximum liquid level to which the container
may be filled is set at the maximum permitted for the container based on an
initial liquid temperature not to exceed 40 degrees Fahrenheit. An isolation
valve shall be installed between the container and the liquid level gauging
device.
§14.2725.Exhaust System.
No part of the exhaust system on any LNG transport or container delivery
unit shall be located less than six inches unless shielded from any piping,
pump, and/or compressor. The exhaust system discharge shall not impinge on
the containers, piping, or related appurtenances.
§14.2728.Extinguishers Required.
(a)
Transport power units shall be equipped with at least one
fire extinguisher having a UL rating of 10 B:C or more, and shall be labeled
or marked with that rating.
(b)
Fire extinguishers shall be fully charged, in good mechanical
condition, and accessible for use. Fire extinguishers shall be mounted with
a mounting bracket which will allow visual determination of being fully charged.
§14.2731.Manifests.
Manifests or bills or lading shall be covered by permanent shipping
papers authorized by the DOT.
§14.2734.Transfer of LNG on Public Highways, Streets, or Alleys.
Transferring LNG on public highways, streets, or alleys is prohibited
except in an emergency or where the containers are on machinery being used
for the construction or maintenance of such public highways, streets, or alleys.
§14.2737.Parking of LNG Transports and Container Delivery Units, and Use of Chock Blocks.
(a)
LNG transport or container delivery units shall not be
parked on any public street, highway, or alley, except in an emergency, or
when in connection with normal duties, meals, or rest stops. Such units shall
not be parked in a congested area and shall be parked a minimum distance of
50 feet from any building, except buildings devoted exclusively to LNG operations.
(b)
LNG transports shall carry at least two chock blocks designed
to effectively prevent the movement of the transport. These blocks shall be
used any time the transport is parked and during the transfer of fuel regardless
of the level of the surrounding terrain.
§14.2740.Uniform Protection Standards.
(a)
LNG transport units and container delivery units, including
appurtenances, shall be maintained in a safe operating condition at all times.
(b)
Any transport unit or container delivery unit discovered
to be in an unsafe condition while being operated on a public roadway may
be continued in operation only to the nearest place where repairs can safely
be made. Such operation shall be conducted only if it is less hazardous to
the public than to permit the transport unit or container delivery unit to
remain on the public roadway.
§14.2746.Delivery of Inspection Report to Licensee.
The transport driver of any transport unit receiving an inspection
report from the Commission shall deliver that report to the licensee in whose
name the transport unit is registered.
§14.2749.Issuance of LNG Form 2004 Decal.
(a)
An LNG Form 2004 decal or letter of authority shall not
be issued to any transport that has not been tested as required by §14.2707
of this title (relating to Testing Requirements) at least once in the preceding
five years. An LNG Form 2004 decal or letter of authority shall not be issued
to any transport that has been determined to be unsafe for LNG service by
the Commission or a Category 15, 20, or 50 licensee in accordance with §14.2707
of this title (relating to Testing Requirements).
(b)
An LNG Form 2004 decal or letter of authority, when issued
by the Commission and properly affixed as instructed by the decal or letter,
or maintained on the bobtail or transport trailer, shall authorize the person
to whom it has been issued to operate such unit in the transportation of LNG
and to fill the transport containers.
(c)
No person or ultimate consumer shall operate an LNG transport
or introduce LNG into such unit in this state unless an LNG Form 2004 decal
or letter of authority authorizing its operation has been affixed in accordance
with placement instructions on the decal or letter, or maintained in readable
condition, or unless such operation has been specifically approved by the
Commission.
(d)
The LNG Form 2004 decal or letter of authority is not transferable
by the person to whom it has been issued, but shall be registered by any subsequent
person or ultimate consumer prior to the vehicle being placed into LNG service.
(e)
This subsection shall not prevent a container manufacturer/fabricator
from introducing a reasonable amount of LNG into a newly constructed container
in order to properly test the vessel, piping system, and appurtenances prior
to the initial sale of the container. The LNG shall be removed from the transport
container prior to the unit leaving the container manufacturer/fabricator's
premises.
(f)
A maximum of 150 gallons of LNG may be introduced into
a newly constructed transport container when such container will provide the
motor fuel to the chassis engine for the purpose of providing sufficient fuel
to allow the unit to reach its destination.
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 February 26, 2003.
TRD-200301445
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: April 13, 2003
For further information, please call: (512) 475-1295
Subchapter A. GENERAL APPLICABILITY AND REQUIREMENTS
(B)
Bay well--Any well under the
jurisdiction of the Commission for which the surface location is either:]
(i)
located in or on a lake, river, stream, canal,
estuary, bayou or other inland navigable waters of the state; or,]
(ii)
located on state lands seaward of the mean
high tide line of the Gulf of Mexico in water of a depth at mean high tide
of not more than 100 feet that is sheltered from the direct action of the
open seas of the Gulf of Mexico.]
(F)
] Individual well bond--A bond
or letter of credit issued:
(G)
Land well--Any well subject
to Commission jurisdiction for which the surface location is not in or on
inland or coastal waters.]
(H)
Offshore well--Any well subject
to Commission jurisdiction for which the surface location is on state lands
in or on the Gulf of Mexico, that is not a bay well.]
(I)
] Operator designation form--A
certificate of transportation authority and compliance or an application to
drill, deepen, recomplete, plug back, or reenter which has been completed,
signed and filed with the Commission.
(J)
] Productive horizon--Any stratum
known to contain oil, gas, or geothermal resources in producible quantities
in the vicinity of an unplugged well.
surface
] notice
on the landowner
--To hand deliver a written notice identifying the well
or wells
to be plugged and the projected date the well
or wells
will
be plugged to the
surface owner
[
intended recipient
]
at least three days prior to the day of plugging or to mail the notice by
first class mail, postage pre-paid, to the last known address of the
surface owner
[
intended recipient
] at least seven days prior
to the day of plugging.
Natural Resource Conservation
] Commission
on Environmental
Quality or its successor agencies
to contain usable quality water.
office
]. The operator shall not initiate approved plugging operations
before the date set out in the notification for the beginning of plugging
operations unless authorized by the district director
or the director's
delegate
. The operator shall notify the district office at least four
hours before commencing plugging operations and proceed with the work as approved.
The district director
or the director's delegate
may grant exceptions
to the requirements of this paragraph concerning the timing of notices when
a workover or drilling rig is already at work on location, ready to commence
plugging operations. Operations shall not be suspended prior to plugging the
well unless the hole is cased and casing is cemented in place in compliance
with Commission rules.
The Commission's approval of a notice of intent
to plug and abandon a well shall not relieve an operator of the requirement
to comply with subsection (b)(2) of this section, nor does such approval constitute
an extension of time to comply with subsection (b)(2) of this section.
(4)
The landowner and the operator
may file an application to condition an abandoned well located on the landowner's
tract for usable quality water production operations, provided the landowner
assumes responsibility for plugging the well and obligates himself, his heirs,
successors, and assignees as a condition to the Commission's approval of such
application to complete the plugging operations. The application shall be
made on the form prescribed by the Commission. In all cases, the operator
responsible for plugging the well shall place all cement plugs required by
this rule up to the base of the usable quality water strata.]
surface
]
notice on the
landowner
[
surface owner
] of the well
site tract, or the resident if the owner is absent, before the scheduled date
for beginning the plugging operations. A representative of the
landowner
[
surface owner
] may be present to witness the plugging of
the well. Plugging shall not be delayed because of the lack of actual notice
to the
landowner
[
surface owner
] or resident if the
operator has served [
surface
] notice as required by this paragraph.
The district director
or the director's delegate
may grant exceptions
to the requirements of this paragraph concerning the timing of notices when
a workover or drilling rig is already at work on location ready to commence
plugging operations.
section
] and files with its application proof of either:
and
] the operator of any well for which a plugging extension is sought
under the terms of subparagraph (A) or (B) of this paragraph shall plug or
test such well to determine whether the well poses a potential threat of harm
to natural resources, including surface and subsurface water, oil and gas.
must
]
give the district office written notice specifying the date and approximate
time it intends to conduct the fluid level test at least 48 hours prior to
conducting the test; however, upon a showing of undue hardship, the district
director or the director's delegate
[
office
] may grant a
written waiver or reduction of the notice requirement for a specific well
test. The Commission or its delegate may require alternate methods of testing
if [
the Commission deems it
] necessary to ensure the well does
not pose a potential threat of harm to natural resources. Alternate methods
of testing may be approved by the Commission or its delegate by written application
and upon a showing that such a test will provide information sufficient to
determine that the well does not pose a threat to natural resources.
office
]. The district
director or the director's delegate
[
office
] shall be notified at least 48 hours before any
test other than a fluid level test is conducted. Mechanical integrity test
results shall be filed with the district office and fluid level test results
shall be filed with the Commission in Austin. Test results shall be filed
on a Commission-approved form, within 30 days of the completion of the test.
Upon request, the operator shall file the actual test data for any mechanical
integrity or fluid level test that it has conducted.
office
], provided that the operator gives the district office written notice
specifying the date and approximate time for the test at least 48 hours prior
to the time the test will be conducted, the production casing is tested to
a depth of at least 250 feet below the base of usable quality water strata,
or 100 feet below the top of cement behind the production casing, whichever
is deeper, and the minimum test pressure is greater than or equal to 250 psig
for a period of at least 30 minutes.
or
] gas
, or other formation fluid
is leaking
from the well, and:
assistant director of well
plugging
] or the
deputy
[
assistant
] director's
delegate, except when plugging is conducted in accordance with subparagraph
(B)(ii) of this paragraph or paragraph (6) of this subsection. Cementing companies,
service companies, or operators may apply for designation as approved cementers.
Approval will be granted on a showing by the applicant of the ability to mix
and pump cement
or other alternate materials as approved by the deputy
director of field operations or the director's delegate
in compliance
with this rule. An approved cementer is authorized to conduct plugging operations
in accordance with Commission rules in each Commission district.
assistant director of well plugging
] recommending
that the application to be designated as an approved cementer be approved
or denied. If the district director or the director's delegate does not recommend
approval, or the
deputy director of field operations
[
assistant
director of well plugging
] or the [
assistant
] director's
delegate denies the application, the applicant may request a hearing on its
application.
assistant director of well plugging
] for violations of Commission rules if:
will
] determine whether such a request warrants approval.
If the district director or the director's delegate refuses to administratively
approve this request, the operator may request a hearing on its request.
is necessary to
]
insure that the well does not pose a potential threat of harm to natural resources.
An operator shall request approval to use alternate fluid other than mud-laden
fluid by filing with the district director a written request providing all
pertinent information to support the use of the proposed alternate fluid.
The district director or the director's delegate shall determine whether such
a request warrants approval, and shall approve such a request only if the
proposed alternate fluid will insure that the well does not pose a potential
threat of harm to natural resources.
§3.94(e)
] of this title (relating
to Procedures for Identification and Control of Wellbores in Which Certain
Logging Tools Have Been Abandoned (Statewide Rule 35); and
Authorized
Disposal Methods
[
Disposal of Oil and Gas NORM Waste (Statewide
Rule 94)
], respectively). Pipe and unretrievable junk shall not be cemented
in the hole during plugging operations without prior approval by the district
director
or the director's delegate
.
surface
piping, and all subsurface
] piping [
that is less than three feet
beneath the ground surface,
] remove all loose junk and trash from the
location, and contour the location to discourage pooling of surface water
at or around the facility site. The operator shall close all pits in accordance
with the provisions of §3.8 of this title (relating to Water Protection
(Statewide Rule 8)). The district director
or the director's delegate
may grant a reasonable extension of time of not more than an additional
120 days for the removal of tanks, vessels and related piping.
be placed from
] 50 feet below the base of the deepest
usable quality water stratum [
to 50 feet above the top of the stratum
]. This plug shall be evidenced by tagging with tubing or drill pipe.
The plug
shall
[
must
] be respotted if it has not been
properly placed. In addition, a cement plug
shall
[
must
]
be set across the shoe of the surface casing. This plug
shall
[
must
] be a minimum of 100 feet in length and shall extend at least 50
feet above and below the shoe.
from
] 50 feet below
and 50 feet above
the base of the deepest usable quality water stratum
[
to 50 feet above the top of the stratum
].
Chapter 8.
PIPELINE SAFETY REGULATIONS
Chapter 8.
PIPELINE SAFETY REGULATIONS
Subchapter D. REQUIREMENTS FOR HAZARDOUS LIQUIDS PIPELINES ONLY
Chapter 8.
PIPELINE SAFETY REGULATIONS
Chapter 13.
REGULATIONS FOR COMPRESSED NATURAL GAS (CNG) AND LIQUEFIED NATURAL GAS (LNG)
Chapter 13.
REGULATIONS FOR COMPRESSED NATURAL GAS (CNG) AND LIQUEFIED NATURAL GAS (LNG)
Subchapter H. GENERAL RULES FOR ALL STATIONARY LNG INSTALLATIONS
Subchapter J. GENERAL RULES FOR LNG FUELING FACILITIES
Subchapter K. PIPING SYSTEMS AND COMPONENTS FOR ALL STATIONARY LNG INSTALLATIONS
Subchapter L. INSTRUMENTATION AND ELECTRICAL SERVICES
Subchapter M. ENGINE FUEL SYSTEMS
Subchapter N. LNG TRANSPORTS
Chapter 14.
REGULATIONS FOR LIQUEFIED NATURAL GAS (LNG)
Subchapter B. GENERAL RULES FOR ALL STATIONARY LNG INSTALLATIONS
Subchapter D. GENERAL RULES FOR LNG FUELING FACILITIES
Subchapter E. PIPING SYSTEMS AND COMPONENTS FOR ALL STATIONARY LNG INSTALLATIONS
Subchapter F. INSTRUMENTATION AND ELECTRICAL SERVICES
Subchapter G. ENGINE FUEL SYSTEMS
Subchapter H. LNG TRANSPORTS
Chapter 14.
REGULATIONS FOR LIQUEFIED NATURAL GAS (LNG)