Part 1.
RAILROAD COMMISSION OF TEXAS
Chapter 3.
OIL AND GAS DIVISION
The Railroad Commission of Texas (Commission) proposes amendments
to §§3.12, 3.13, and 3.30, relating to Directional Survey Company
Report; Casing, Cementing, Drilling, and Completion Requirements; and Memorandum
of Understanding between the Railroad Commission of Texas (RRC) and the Texas
Natural Resource Conservation Commission (TNRCC); the repeal of §§3.65,
3.66, 3.67, and 3.69, relating to Pipeline Permits Required; Pipeline Tariffs;
Obtaining Pipeline Connections; and Definitions; new §§3.70 and
3.71, relating to Pipeline Permits Required; and Pipeline Tariffs; the repeal
of §3.72, relating to Manifest To Accompany Each Transport of Liquid
Hydrocarbons by Vehicle; new §3.72, relating to Obtaining Pipeline Connections;
the repeal of §§3.75, and 3.77, relating to Discharges to Waters
of the State; and Brine Mining Injection Wells; and new §§3.79,
3.81 and 3.85, relating to Definitions; Brine Mining Injection Wells; and
Manifest to Accompany Each Transport of Liquid Hydrocarbons by Vehicle; and
amendments to §§3.93, 3.99, and 3.100, relating to Water Quality
Certification Definitions; Cathodic Protection Wells; and Seismic Holes and
Core Holes.
The Commission proposes these repeals, new sections, and amendments to
update references to rule numbers or titles, update agencies' names, and repeal
and renumber some rules so that the Texas Administrative Code section number
matches the commonly- used Statewide Rule number. All of the proposed changes
are non- substantive and are made for clarification and accuracy. The proposed
amendment to §3.12 adds overnight mail as a delivery option. The proposed
amendments to §3.100 and the change in wording in new §3.79 (current §3.69)
update the references to the Commission's coal and uranium mining regulations.
Sections 3.99(i) and 3.100(b) are proposed to be deleted because they refer
to a rule which has been repealed.
The Commission also proposes the review of these rules pursuant to Texas
Government Code, §2001.039, in a separate document filed simultaneously
with the
Texas Register
. In addition to the
repeals, new sections, and amendments in this proposal, the proposed review
also includes §§3.6, 3.16, 3.20, 3.23, 3.27, 3.31, 3.34, 3.41, 3.54,
3.55, 3.62, 3.80, and 3.102, relating to Application for Multiple Completion;
Log and Completion or Plugging Report; Notification of Fires Breaks, Leaks,
and Blowouts; Vacuum Pumps; Gas To Be Measured and Surface Commingling of
Gas; Gas Reservoirs and Gas Well Allowable; Gas To Be Produced and Purchased
Ratably; Application for New Oil or Gas Field Designation and/or Allowable;
Gas Reports Required; Reports on Gas Wells Commingling Liquid Hydrocarbons
before Metering; Cycling Plant Control and Reports; Commission Forms, Applications
and Filing Requirements; and Tax Reduction for Incremental Production.
Leslie Savage, Oil and Gas Division planner, has determined that for each
year of the first five years the repeals, new sections, and amendments as
proposed will be in effect, there will be no fiscal implications for state
or local governments.
There will be no cost of compliance for individuals, small businesses,
or micro-businesses.
Ms. Savage has determined that for each year of the first five years that
the repeals, new sections, and amendments will be in effect, there will be
a public benefit in that the Commission's rules will be clearer and more accurate.
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 shall refer to Oil and Gas Docket No. 20- 0235283.
The Commission encourages all interested persons to submit comments no later
than the deadline. The Commission cannot guarantee that comments submitted
after the deadline will be considered. For further information, call Ms. Savage
(512) 463-7308. The status of Commission rulemakings in progress is available
at www.rrc.state.tx.us/rules/proposed.html.
16 TAC §§3.12, 3.13, 3.30, 3.70 - 3.72, 3.79, 3.81, 3.85, 3.93, 3.99, 3.100
The Commission proposes the new sections, and amendments pursuant
to Texas Natural Resources Code, §§81.051 and 81.052, which provide
the Commission with jurisdiction over all persons owning or engaged in drilling
or operating oil or gas wells and persons owning or operating pipelines in
Texas and the authority to adopt all necessary rules for governing and regulating
persons and their operations under Commission jurisdiction and pursuant to
Texas Natural Resources Code §§85.042, 85.202, 86.041 and 86.042
which require the Commission to adopt rules to control waste of oil and gas.
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, 85.024, 85.202, 86.041, and 86.042.
Cross-reference to statute: Texas Natural Resources Code, §§81.051
and 81.052 and §§85.042, 85.202, 86.041 and 86.042.
Issued in Austin, Texas, on June 10, 2003.
§3.12.Directional Survey Company Report.
(a)
(No change.)
(b)
Each directional survey, with its accompanying certification
and a certified plat on which the bottom hole location is oriented both to
the surface location and to the lease lines (or unit lines in case of pooling)
shall be mailed by registered
,
[
§3.13.Casing, Cementing, Drilling, and Completion Requirements.
(a)
General.
(1)
(No change.)
(2)
Definitions. The following words and terms, when used in
this chapter, shall have the following meanings, unless the context clearly
indicates otherwise.
(A)-(B)
(No change.)
(C)
Protection depth--Depth to which usable-quality water must
be protected, as determined by the Texas
Commission on Environmental
Quality (TCEQ) or its successor agencies
[
(D)
(No change.)
(b)
Onshore and inland waters.
(1)
(No change.)
(2)
Surface casing.
(A)
Amount required.
(i)
An operator shall set and cement sufficient surface casing
to protect all usable-quality water strata, as defined by the
TCEQ
[
(ii)
(No change.)
(B)-(G)
(No change.)
(3)-(5)
(No change.)
(c)
(No change.)
§3.30.Memorandum of Understanding between the Railroad Commission of Texas (RRC) and the Texas Commission on Environmental Quality (TCEQ) [
(a)
(No change.)
(b)
General agency jurisdictions.
(1)
Texas
Commission on Environmental Quality (TCEQ) (the
successor agency to the Texas
Natural Resource Conservation Commission
(TNRCC)
)
.
References in this section to TCEQ shall mean TCEQ
or any successor agencies.
(A)
The
TCEQ
[
(B)
Under Texas Health and Safety Code, §361.003(34),
solid waste under the jurisdiction of the
TCEQ
[
(C)-(D)
(No change.)
(E)
After delegation of RCRA authority to the Railroad Commission
of Texas (RRC), the definition of solid waste (which defines
TCEQ's
[
(2)
Railroad Commission of Texas (RRC).
(A)
(No change.)
(B)
Notwithstanding subparagraph (A) of this paragraph, hazardous
wastes generated at natural gas or natural gas liquids processing plants or
reservoir pressure maintenance or repressurizing plants are subject to the
jurisdiction of the
TCEQ
[
(c)
Definition of hazardous waste.
(1)
Under the Texas Health and Safety Code, §361.003(12),
a "hazardous waste" subject to the jurisdiction of the
TCEQ
[
(2)-(3)
(No change.)
(d)
Jurisdiction over specific disposal activities.
(1)
Discharges under Texas Water Code, Chapter 26. Under the
Texas Water Code, Chapter 26, the
TCEQ
[
(2)
Disposal wells under Texas Water Code, Chapter 27. Jurisdiction
over wastes disposed by injection is divided between the RRC and the
TCEQ
[
(3)
Disposal of naturally occurring radioactive material (NORM).
(The term "disposal" does not include receipt, possession, use, processing,
transfer, transport, storage, or commercial distribution of radioactive materials,
including NORM. These activities are under the jurisdiction of the Texas Department
of Health per Texas Health and Safety Code, §401.011(a).)
(A)
(No change.)
(B)
Under Texas Health and Safety Code, §401.412, the
TCEQ
[
(e)
Jurisdiction over waste from specific oil and gas activities.
(1)-(2)
(No change.)
(3)
Storage of oil.
(A)
Tank bottoms, stormwater runoff, and other wastes from
the storage of crude oil (whether foreign or domestic) before it enters the
refinery are under the jurisdiction of the RRC. In addition, waste resulting
from storage of crude oil at refineries is subject to the jurisdiction of
the
TCEQ
[
(B)
Wastes generated from storage tanks which are part of the
refinery and wastes resulting from the wholesale and retail marketing of refined
products are subject to the jurisdiction of the
TCEQ
[
(4)-(5)
(No change.)
(6)
Transportation of crude oil or natural gas.
(A)
(No change.)
(B)
The
TCEQ
[
(C)
The
TCEQ
[
(7)
Reclamation plants.
(A)
The RRC has jurisdiction over wastes from reclamation plants
that process wastes from activities associated with the exploration, development,
or production of oil, gas, or geothermal resources, such as lease tank bottoms.
Waste management activities of reclamation plants for other wastes are subject
to the jurisdiction of the
TCEQ
[
(B)
(No change.)
(8)
Refining of oil.
(A)
The management of wastes resulting from oil refining operations,
including spent caustics, spent catalysts, still bottoms or tars, and API
separator sludges, is subject to the jurisdiction of the
TCEQ
[
(B)
(No change.)
(9)
Natural gas or natural gas liquids processing plants (including
gas fractionation facilities) and pressure maintenance or repressurizing plants.
Wastes resulting from activities associated with these facilities include
produced water, cooling tower water, sulfur bead, sulfides, spent caustics,
sweetening agents, spent catalyst, waste hydrocarbons (including used oil),
asbestos insulation, wastes contaminated with PCBs (including transformers,
capacitors, ballasts, and soils), treating and cleaning chemicals, filters,
trash, domestic sewage, and dehydration materials. These wastes are subject
to the jurisdiction of the RRC under Texas Natural Resources Code, §91.101.
Disposal of waste from activities associated with natural gas or natural gas
liquids processing plants (including gas fractionation facilities), and pressure
maintenance or repressurizing plants by injection is subject to the jurisdiction
of the RRC under Texas Water Code, Chapter 27. Notwithstanding any contrary
provision of this paragraph, until delegation of authority under RCRA to the
RRC, the
TCEQ
[
(10)
Manufacturing processes.
(A)
Wastes that result from the use of natural gas, natural
gas liquids, or products refined from crude oil in any manufacturing process,
such as the production of petrochemicals or plastics, or from the manufacture
of carbon black, are industrial wastes subject to the jurisdiction of the
TCEQ
[
(B)
(No change.)
(11)
Commercial service company facilities and training facilities.
(A)
The
TCEQ
[
(B)
The
TCEQ
[
(C)-(E)
(No change.)
(12)
(No change.)
(f)
Interagency activities.
(1)
Recycling and pollution prevention.
(A)
The
TCEQ
[
(B)
The
TCEQ
[
(2)
Treatment of wastes under RRC jurisdiction at facilities
registered by
TCEQ's
[
(A)
Soils contaminated with constituents that are physically
and chemically similar to those normally found in soils at leaking underground
petroleum storage tanks from generators under the jurisdiction of the RRC
are eligible for treatment at
TCEQ
[
(B)
Generators under RRC jurisdiction should also be aware
that
TCEQ
[
(C)
The RRC must specifically authorize management of contaminated
soils under its jurisdiction at facilities registered by the PST Division
of the
TCEQ
[
(D)
All waste materials, including those that have been treated,
that are subject to the jurisdiction of the RRC and are managed at facilities
registered by the PST Division of the
TCEQ
[
(E)
TCEQ
[
(3)
Disposal of wastes under RRC jurisdiction at facilities
permitted by the
TCEQ
[
(A)
As provided in this paragraph, waste materials subject
to the jurisdiction of the RRC may be managed at solid waste facilities under
the jurisdiction of the
TCEQ
[
(B)
A facility under the jurisdiction of the
TCEQ
[
(C)
In all other instances, individual written concurrences
from the
TCEQ
[
(D)
Notwithstanding subparagraphs (A)-(C) of this paragraph,
waste sludge subject to the jurisdiction of the RRC, other than domestic septage
that is not mixed with other waste materials, may not be applied to the land
at a facility permitted by the
TCEQ
[
(E)
Additional guidance regarding requirements for, and restrictions
on, management of particular types of wastes regulated by the RRC at facilities
registered or permitted by the
TCEQ
[
(F)
TCEQ
[
(i)-(iii)
(No change.)
(G)
If a facility requests or requires a
TCEQ
[
(H)
Wastes that are under the jurisdiction of the RRC need
not be reported to the
TCEQ's
[
(4)
Management of nonhazardous wastes under
TCEQ
[
(A)
Once alternatives for recycling and source reduction have
been explored, and with prior authorization from the RRC, the following nonhazardous
wastes subject to the jurisdiction of the
TCEQ
[
(B)
(No change.)
(C)
Once alternatives for recycling and source reduction have
been explored, and subject to the RRC's individual authorization, the following
wastes under the jurisdiction of the
TCEQ
[
(D)
In a public health, public safety, or environmental emergency,
the RRC and the
TCEQ
[
(E)
Pursuant to Texas Water Code, §27.0511(g),
TCEQ
[
(F)
(No change.)
(5)
Drilling in landfills. The
TCEQ
[
(6)
Coordination of enforcement actions and cooperative sharing
of enforcement information.
(A)
In the event that a generator or transporter disposes,
without proper authorization, of wastes regulated by the
TCEQ
[
(B)
The
TCEQ
[
(g)
(No change.)
(h)
Disputes. The staff of the RRC and the
TCEQ
[
(i)
(No change.)
§3.70.Pipeline Permits Required.
(a)
No pipeline or gathering system, whether a common carrier
or not, shall be used to transport oil, gas, or geothermal resources from
any tract of land within this state without a permit from the commission.
Application for the permit shall be made upon the required form, and the permit
will be granted if the commission is satisfied from such application and the
evidence in support thereof, and its own investigation, that the proposed
line is, or will be, so laid, equipped, and managed, as to reduce to a minimum
the possibility of waste, and will be operated in accordance with the conservation
laws and conservation rules and regulations of the commission.
(b)
The permit, if granted, shall be revocable at any time
after hearing held after 10 days' notice, if the commission finds that the
line is so unsafe, or so improperly equipped, or so managed, as likely to
result in waste. If the commission finds the line is in such condition as
to cause waste, five days' written notice shall be given to the operating
company to correct the condition before notice of hearing for revocation of
the permit is given. A permit may also be revoked after 10 days' notice and
hearing, if the commission finds that the operator of the line, in its operation
thereof, is willfully violating or contributing to the violation of the laws
of Texas regulating the production, transportation, processing, refining,
treating, and/or marketing of crude oil or geothermal resources, or any of
the laws of the state to conserve the oil, gas, or geothermal resources, or
any rule or regulation of the commission enacted under such laws.
§3.71.Pipeline Tariffs.
Every person owning, operating, or managing any pipeline, or any part
of any pipeline, for the gathering, receiving, loading, transporting, storing,
or delivering of crude petroleum as a common carrier shall be subject to and
governed by the following provisions. Common carriers specified in this section
shall be referred to as "pipelines," and the owners or shippers of crude petroleum
by pipelines shall be referred to as "shippers."
(1)
All marketable oil to be received for transportation. By
the term "marketable oil" is meant any crude petroleum adapted for refining
or fuel purposes, properly settled and containing not more than 2.0% of basic
sediment, water, or other impurities above a point six inches below the pipeline
connection with the tank. Pipelines shall receive for transportation all such
"marketable oil" tendered; but no pipeline shall be required to receive for
shipment from any one person an amount exceeding 3,000 barrels of petroleum
in any one day; and, if the oil tendered for transportation differs materially
in character from that usually produced in the field and being transported
therefrom by the pipeline, then it shall be transported under such terms as
the shipper and the owner of the pipeline may agree or the commission may
require.
(2)
Basic sediment, how determined--temperature. In determining
the amount of sediment, water, or other impurities, a pipeline is authorized
to make a test of the oil offered for transportation from an average sample
from each such tank, by the use of centrifugal machine, or by the use of any
other appliance agreed upon by the pipeline and the shipper. The same method
of ascertaining the amount of the sediment, water, or other impurities shall
be used in the delivery as in the receipt of oil. A pipeline shall not be
required to receive for transportation, nor shall consignee be required to
accept as a delivery, any oil of a higher temperature than 90 degrees Fahrenheit,
except that during the summer oil shall be received at any atmospheric temperature,
and may be delivered at like temperature. Consignee shall have the same right
to test the oil upon delivery at destination that the pipeline has to test
before receiving from the shipper.
(3)
"Barrel" defined. For the purpose of these sections, a
"barrel" of crude petroleum is declared to be 42 gallons of 231 cubic inches
per gallon at 60 degrees Fahrenheit.
(4)
Oil involved in litigation, etc.--indemnity against loss.
When any oil offered for transportation is involved in litigation, or the
ownership is in dispute, or when the oil appears to be encumbered by lien
or charge of any kind, the pipeline may require of shippers an indemnity bond
to protect it against all loss.
(5)
Storage. Each pipeline shall provide, without additional
charge, sufficient storage, such as is incident and necessary to the transportation
of oil, including storage at destination or so near thereto as to be available
for prompt delivery to destination point, for five days from the date of order
of delivery at destination.
(6)
Identity of oil, maintenance of oil. A pipeline may deliver
to consignee either the identical oil received for transportation, subject
to such consequences of mixing with other oil as are incident to the usual
pipeline transportation, or it may make delivery from its common stock at
destination; provided, if this last be done, the delivery shall be of substantially
like kind and market value.
(7)
Minimum quantity to be received. A pipeline shall not be
required to receive less than one tank car-load of oil when oil is offered
for loading into tank cars at destination of the pipeline. When oil is offered
for transportation for other than tank car delivery, a pipeline shall not
be required to receive less than 500 barrels.
(8)
Gathering charges. Tariffs to be filed by a pipeline shall
specify separately the charges for gathering of the oil, for transportation,
and for delivery.
(9)
Measuring, testing, and deductions (reference Special Order
Number 20-63,098 effective June 18, 1973).
(A)
Except as provided in subparagraph (B) of this paragraph,
all crude oil tendered to a pipeline shall be gauged and tested by a representative
of the pipeline prior to its receipt by the pipeline. The shipper may be present
or represented at the gauging or testing. Quantities shall be computed from
correctly compiled tank tables showing 100% of the full capacity of the tanks.
(B)
As an alternative to the method of measurement provided
in subparagraph (A) of this paragraph, crude oil and condensate may be measured
and tested, before transfer of custody to the initial transporter, by:
(i)
lease automatic custody transfer (LACT) equipment, provided
such equipment is installed and operated in accordance with the latest revision
of American Petroleum Institute (API) Manual of Petroleum Measurement Standards,
Chapter 6.1, or;
(ii)
any device or method, approved by the commission or its
delegate, which yields accurate measurements of crude oil or condensate.
(C)
Adjustments to the quantities determined by the methods
described in subparagraphs (A) or (B) of this paragraph shall be made for
temperature from the nearest whole number degree to the basis of 60 degrees
Fahrenheit and to the nearest 5/10 API degree gravity in accordance with the
volume correction Tables 5A and 6A contained in API Standard 2540, American
Society for Testing Materials 01250, Institute of Petroleum 200, first edition,
August 1980. A pipeline may deduct the basic sediment, water, and other impurities
as shown by the centrifugal or other test agreed upon by the shipper and pipeline;
and 1.0% for evaporation and loss during transportation. The net balance shall
be the quantity deliverable by the pipeline. In allowing the deductions, it
is not the intention of the commission to affect any tax or royalty obligations
imposed by the laws of Texas on any producer or shipper of crude oil.
(D)
A transfer of custody of crude between transporters is
subject to measurement as agreed upon by the transporters.
(10)
Delivery and demurrage. Each pipeline shall transport
oil with reasonable diligence, considering the quality of the oil, the distance
of transportation, and other material elements, but at any time after receipt
of a consignment of oil, upon 24 hours' notice to the consignee, may offer
oil for delivery from its common stock at the point of destination, conformable
to paragraph (6) of this section, at a rate not exceeding 10,000 barrels per
day of 24 hours. Computation of time of storage (as provided for in paragraph
(5) of this section) shall begin at the expiration of such notice. At the
expiration of the time allowed in paragraph (5) of this section for storage
at destination, a pipeline may assess a demurrage charge on oil offered for
delivery and remaining undelivered, at a rate for the first 10 days of $.001
per barrel; and thereafter at a rate of $.0075 per barrel, for each day of
24 hours or fractional part thereof.
(11)
Unpaid charges, lien for and sale to cover. A pipeline
shall have a lien on all oil to cover charges for transportation, including
demurrage, and it may withhold delivery of oil until the charges are paid.
If the charges shall remain unpaid for more than five days after notice of
readiness to deliver, the pipeline may sell the oil at public auction at the
general office of the pipeline on any day not a legal holiday. The date for
the sale shall be not less than 48 hours after publication of notice in a
daily newspaper of general circulation published in the city where the general
office of the pipeline is located. The notice shall give the time and place
of the sale, and the quantity of the oil to be sold. From the proceeds of
the sale, the pipeline may deduct all charges lawfully accruing, including
demurrage, and all expenses of the sale. The net balance shall be paid to
the person lawfully entitled thereto.
(12)
Notice of claim. Notice of claims for loss, damage, or
delay in connection with the shipment of oil must be made in writing to the
pipeline within 91 days after the damage, loss, or delay occurred. If the
claim is for failure to make delivery, the claim must be made within 91 days
after a reasonable time for delivery has elapsed.
(13)
Telephone-telegraph line--shipper to use. If a pipeline
maintains a private telegraph or telephone line, a shipper may use it without
extra charge, for messages incident to shipments. However, a pipeline shall
not be held liable for failure to deliver any messages away from its office
or for delay in transmission or for interruption of service.
(14)
Contracts of transportation. When a consignment of oil
is accepted, the pipeline shall give the shipper a run ticket, and shall give
the shipper a statement that shows the amount of oil received for transportation,
the points of origin and destination, corrections made for temperature, deductions
made for impurities, and the rate for such transportation.
(15)
Shipper's tanks, etc.--inspection. When a shipment of
oil has been offered for transportation the pipeline shall have the right
to go upon the premises where the oil is produced or stored, and have access
to any and all tanks or storage receptacles for the purpose of making any
examination, inspection, or test authorized by this section.
(16)
Offers in excess of facilities. If oil is offered to any
pipeline for transportation in excess of the amount that can be immediately
transported, the transportation furnished by the pipeline shall be apportioned
among all shippers in proportion to the amounts offered by each; but no offer
for transportation shall be considered beyond the amount which the person
requesting the shipment then has ready for shipment by the pipeline. The pipeline
shall be considered as a shipper of oil produced or purchased by itself and
held for shipment through its line, and its oil shall be entitled to participate
in such apportionate.
(17)
Interchange of tonnage. Pipelines shall provide the necessary
connections and facilities for the exchange of tonnage at every locality reached
by two or more pipelines, when the commission finds that a necessity exists
for connection, and under such regulations as said commission may determine
in each case.
(18)
Receipt and delivery--necessary facilities for. Each pipeline
shall install and maintain facilities for the receipt and delivery of marketable
crude petroleum of shippers at any point on its line if the commission finds
that a necessity exists therefor, and under regulations by the commission.
(19)
Reports of loss from fires, lightning, and leakage.
(A)
Each pipeline shall immediately notify the commission district
office, electronically or by telephone, of each fire that occurs at any oil
tank owned or controlled by the pipeline, or of any tank struck by lightning.
Each pipeline shall in like manner report each break or leak in any of its
tanks or pipelines from which more than five barrels escape. Each pipeline
shall file the required information with the commission in accordance with
the appropriate commission form within 30 days from the date of the spill
or leak.
(B)
No risk of fire, storm, flood, or act of God, and no risk
resulting from riots, insurrection, rebellion, war, or act of the public enemy,
or from quarantine or authority of law or any order, requisition or necessity
of the government of the United States in time of war, shall be borne by a
pipeline, nor shall any liability accrue to it from any damage thereby occasioned.
If loss of any crude oil from any such causes occurs after the oil has been
received for transportation, and before it has been delivered to the consignee,
the shipper shall bear a loss in such proportion as the amount of his shipment
is to all of the oil held in transportation by the pipeline at the time of
such loss, and the shipper shall be entitled to have delivered only such portion
of his shipment as may remain after a deduction of his due proportion of such
loss, but in such event the shipper shall be required to pay charges only
on the quantity of oil delivered. This section shall not apply if the loss
occurs because of negligence of the pipeline.
(C)
Common carrier pipelines shall mail (return receipt requested)
or hand deliver to landowners (persons who have legal title to the property
in question) and residents (persons whose mailing address is the property
in question) of land upon which a spill or leak has occurred, all spill or
leak reports required by the commission for that particular spill or leak
within 30 days of filing the required reports with the commission. Registration
with the commission by landowners and residents for the purpose of receiving
spill or leak reports shall be required every five years, with renewal registration
starting January 1, 1999. If a landowner or resident is not registered with
the commission, the common carrier is not required to furnish such reports
to the resident or landowner.
(20)
Printing and posting. Each pipeline shall have paragraphs
(1)-(19) of this section printed on its tariff sheets, and shall post the
printed sections in a prominent place in its various offices for the inspection
of the shipping public. Each pipeline shall post and publish only such rules
and regulations as may be adopted by the commission as general rules or such
special rules as may be adopted for any particular field.
(21)
Immediately upon the publication of its tariffs, and each
subsequent amendment thereof, each pipeline is requested to file one copy
with the commission.
(22)
Records.
(A)
Each person operating crude oil gathering, transportation,
or storage facilities in the state must maintain daily records of the quantities
of all crude oil moved from each oil field in the state, and such records
shall also show separately for each field to whom delivery is made, and the
quantities so delivered.
(B)
The information contained in the records thus required
to be kept must be reported to the commission by the gatherers, transporters,
and handlers at such times and in such manner as may be required by the commission.
§3.72.Obtaining Pipeline Connections.
(a)
A common carrier pipeline transporting crude oil in Texas,
upon application for connection and offer of crude oil by a producer or persons
owning unconnected lease batteries, shall connect such lease batteries in
the following instances:
(1)
when such request is made for connection of lease batteries
in the general area served by a common carrier, which is an affiliate or subsidiary
of a common purchaser, as defined in the Texas Natural Resources Code, §111.081;
and
(2)
within individual fields, when any common carrier possesses
the only pipeline serving such field or common reservoir and request is made
for connection of an unconnected lease battery in the field, provided, that
for just cause a common carrier pipeline may apply for an exception. If proper
application has been made for such connection and the common carrier pipeline
refuses to connect the unconnected lease battery, a complaint for failure
to connect may be filed with the commission by the person seeking the connection.
The complaining person may allege discrimination or noncompliance with the
provisions of this subsection or the appropriate section(s) of the Texas Natural
Resources Code.
(b)
Whether the matter comes to the commission either as an
application for exception by the pipeline or on a complaint for failure to
connect, at least 10 days' notice shall be given to all interested parties,
after which the hearing shall be held. At the hearing, the commission may
require and consider, among other factors, evidence relating to ability of
the pipeline carrier to transport the quality of oil, the market or lack of
market for the proffered oil, and the period required to return the capital
investment for the connection. It is not its intention to limit, nor does
the commission herein limit, the consideration by it of any facts with respect
to a claim of violation of, or of any facts that may constitute a cause of
action for violation of, any of the provisions of Texas Natural Resources
Code, §§11.001-11.136, whether enumerated in this section or not.
§3.79.Definitions.
The following words and terms, when used in this chapter, shall have
the following meanings, unless the context clearly indicates otherwise.
(1)
Adjacent estuarine zones--This term embraces the area inland
from the coast line of Texas and is comprised of the bays, inlets, and estuaries
along the gulf coast.
(2)
By-product--Any element found in a geothermal formation
which when brought to the surface is not used in geothermal heat or pressure
inducing energy generation.
(3)
Casinghead gas--Any gas or vapor, or both, indigenous to
an oil stratum and produced from such stratum with oil.
(4)
Commission--The Railroad Commission of Texas.
(5)
Common reservoir--Any oil, gas, or geothermal resources
field or part thereof which comprises and includes any area which is underlaid,
or which from geological or other scientific data or experiments or from drilling
operations or other evidence appears to be underlaid by a common pool or accumulation
of oil, gas, or geothermal resources.
(6)
Cubic foot of gas or standard cubic foot of gas--The volume
of gas contained in one cubic foot of space at a standard pressure base and
at a standard temperature base. The standard pressure base shall be 14.65
pounds per square inch absolute, and the standard temperature base shall be
60 degrees Fahrenheit. Whenever the conditions of pressure and temperature
differ from the standard in this definition, conversion of the volume from
these conditions to the standard conditions shall be made in accordance with
the ideal gas laws, corrected for deviation.
(7)
District office--The commission-designated office for the
geographic area in which the property or act subject to regulation is located
or arises.
(8)
Dry gas--Any natural gas produced from a stratum that does
not produce crude petroleum oil.
(9)
Exploratory well--Any well drilled for the purpose of securing
geological or geophysical information to be used in the exploration or development
of oil, gas, geothermal, or other mineral resources, except coal and uranium,
and includes what is commonly referred to in the industry as "slim hole tests,"
"core hole tests," or "seismic holes." For regulations governing coal exploratory
wells, see Chapter 12 of this title (relating to Coal Mining Regulations),
and for regulations governing uranium exploratory wells, see Chapter 11, Subchapter
C of this title (relating to Surface Mining and Reclamation Division, Substantive
Rules--Uranium Mining).
(10)
Gas lift--Gas lift by the use of gas not in solution with
oil produced.
(11)
Gas well--Any well:
(A)
which produces natural gas not associated or blended with
crude petroleum oil at the time of production;
(B)
which produces more than 100,000 cubic feet of natural
gas to each barrel of crude petroleum oil from the same producing horizon;
or
(C)
which produces natural gas from a formation or producing
horizon productive of gas only encountered in a wellbore through which crude
petroleum oil also is produced through the inside of another string of casing
or tubing. A well which produces hydrocarbon liquids, a part of which is formed
by a condensation from a gas phase and a part of which is crude petroleum
oil, shall be classified as a gas well unless there is produced one barrel
or more of crude petroleum oil per 100,000 cubic feet of natural gas; and
that the term "crude petroleum oil" shall not be construed to mean any liquid
hydrocarbon mixture or portion thereof which is not in the liquid phase in
the reservoir, removed from the reservoir in such liquid phase, and obtained
at the surface as such.
(12)
Gatherer--Includes any pipeline, truck, motor vehicle,
boat, barge, or person authorized to gather or accept oil, gas, or geothermal
resources from lease production or lease storage.
(13)
Geothermal energy and associated resources--
(A)
All products of geothermal processes, embracing indigenous
steam, hot water and hot brines, and geopressured water;
(B)
Steam and other gases, hot water and hot brines resulting
from water, gas, or other fluids artificially introduced into geothermal formations;
(C)
Heat or other associated energy found in geothermal formations;
(D)
Any by-product derived from them.
(14)
Geothermal resource well--A well drilled within the established
limits of a designated geothermal field.
(A)
A geopressured geothermal well must be completed within
a geopressured aquifer.
(B)
A geopressured aquifer is a water-bearing zone with a pressure
gradient in excess of 0.5 pounds per square inch per foot and a temperature
gradient in excess of 1.6 degrees Fahrenheit per 100 feet of depth.
(15)
Marginal well--Any oil well which is incapable of producing
its maximum capacity of oil except by pumping, gas lift, or other means of
artificial lift, and which well so equipped is capable, under normal unrestricted
operating conditions, of producing such daily quantities of oil as herein
set out, as would be damaged, or result in a loss of production ultimately
recoverable, or cause the premature abandonment of same, if its maximum daily
production were artificially curtailed. The following described wells shall
be deemed "marginal wells" in this state.
(A)
Any oil well incapable of producing its maximum daily capacity
of oil except by pumping, gas lift, or other means of artificial lift, within
this state and having a maximum daily capacity for production of 10 barrels
or less, averaged over the preceding 10 consecutive days of stabilized production,
producing from a depth of 2,000 feet or less.
(B)
Any oil well incapable of producing its maximum daily capacity
of oil except by pumping, gas lift, or other means of artificial lift, within
this state and having a maximum daily capacity for production of 20 barrels
or less, averaged over the preceding 10 consecutive days of stabilized production,
producing from a horizon deeper than 2,000 feet and less in depth than 4,000
feet.
(C)
Any oil well incapable of producing its maximum daily capacity
of oil except by pumping, gas lift, or other means of artificial lift, within
this state and having a maximum daily capacity for production of 25 barrels
or less, averaged over the preceding 10 consecutive days of stabilized production,
producing from a horizon deeper than 4,000 feet and less in depth than 6,000
feet.
(D)
Any oil well incapable of producing its maximum daily capacity
of oil except by pumping, gas lift, or other means of artificial lift, within
this state and having a maximum daily capacity for production of 30 barrels
or less, averaged over the preceding 10 consecutive days of stabilized production,
producing from a horizon deeper than 6,000 feet and less in depth than 8,000
feet.
(E)
Any oil well incapable of producing its maximum daily capacity
of oil except by pumping, gas lift, or other means of artificial lift, within
this state and having a maximum daily capacity for production of 35 barrels
or less, averaged over the preceding 10 consecutive days of stabilized production,
producing from a horizon deeper than 8,000 feet. (Reference Order Number 20-59,200,
effective May 1, 1969.)
(16)
Natural gas or gas--These terms shall have the same meaning,
as used in the rules, regulations, or forms of the commission.
(17)
Natural gasoline--Gasoline manufactured from casinghead
gas or from any natural gas.
(18)
Oil well--Any well which produces one barrel or more crude
petroleum oil to each 100,000 cubic feet of natural gas.
(19)
Operator--A person, acting for himself or as an agent
for others and designated to the commission as the one who has the primary
responsibility for complying with its rules and regulations in any and all
acts subject to the jurisdiction of the commission.
(20)
Person--Any natural person, corporation, association,
partnership, receiver, trustee, guardian, executor, administrator, and a fiduciary
or representative of any kind.
(21)
Product--Includes refined crude oil, crude tops, topped
crude, processed crude petroleum, residue from crude petroleum, cracking stock,
uncracked fuel oil, fuel oil, treated crude oil, residuum, casinghead gasoline,
natural gas gasoline, gas oil, naphtha, distillate, gasoline, kerosene, benzine,
wash oil, waste oil, blended gasoline, lubricating oil, blends or mixtures
of petroleum, and/or any and all liquid products or by-products derived from
crude petroleum oil or gas, whether hereinabove enumerated or not.
(22)
Sour gas--Any natural gas containing more than 1 1/2 grains
of hydrogen sulphide per 100 cubic feet or more than 30 grains of total sulphur
per 100 cubic feet, or gas which in its natural state is found by the commission
to be unfit for use in generating light or fuel for domestic purposes.
(23)
Sweet gas--All natural gas except sour gas and casinghead
gas.
(24)
Texas offshore--This term embraces the area in the Gulf
of Mexico seaward of the coast line of Texas comprised of:
(A)
the three league area confirmed to the State of Texas by
the Submerged Land Act (43 United States Code §§1301-1315); and
(B)
the area seaward of such three league area owned by the
United States.
(25)
Transportation or to transport--The movement of any crude
petroleum oil or products of crude petroleum oil or the products of either
from any receptacle in which any such crude petroleum or products of crude
petroleum oil or the products of either has been stored to any other receptacle
by any means or method whatsoever, including the movement by any pipeline,
railway, truck, motor vehicle, barge, boat, or railway tank car. It is the
purpose of this definition to include the movement or transportation of crude
petroleum oil and products of crude petroleum oil and the products of either
by any means whatsoever from any receptacle containing the same to any other
receptacle anywhere within or from the State of Texas, regardless of whether
or not possession or control or ownership change.
(26)
Transporter or transporting agency--Includes any common
carrier by pipeline, railway, truck, motor vehicle, boat, or barge, and/or
any person transporting oil or a product by pipeline, railway, truck, motor
vehicle, boat, or barge.
§3.81.Brine Mining Injection Wells.
(a)
Definitions. The following words and terms, when used in
this section, shall have the following meanings, unless the context clearly
indicates otherwise.
(1)
Affected person--A person who, as a result of the activity
sought to be permitted, has suffered or may suffer actual injury or economic
damage other than as a member of the general public.
(2)
Brine mining facility or facility--The brine mining injection
well, and the pits, tanks, fresh water wells, pumps, and other structures
and equipment that are or will be used in conjunction with the brine mining
injection well.
(3)
Brine mining injection well--A well used to inject fluid
for the purpose of extracting brine by the solution of a subsurface salt formation.
The term "brine mining injection well" does not include a well used to inject
fluid for the purpose of leaching a cavern for the underground storage of
hydrocarbons or the disposal of waste, or a well used to inject fluid for
the purpose of extracting sulphur by the thermofluid mining process.
(4)
Commission--The Railroad Commission of Texas.
(5)
Director--The director of the Oil and Gas Division or a
staff delegate designated in writing by the director of the Oil and Gas Division
or the commission.
(6)
Existing brine mining injection well--A brine mining injection
well in which injection operations began prior to the effective date of this
section.
(7)
Fresh water--Water having bacteriological, physical, and
chemical properties that make it suitable and feasible for beneficial use
for any lawful purpose.
(8)
New brine mining injection well--A brine mining injection
well in which injection operations begin on or after the effective date of
this section.
(9)
Permit--A written authorization issued by the commission
under this section for the operation of a brine mining injection well.
(10)
Person--A natural person, corporation, organization, government
or governmental subdivision or agency, business trust, estate, trust partnership,
association, or any other legal entity.
(11)
Pollution--The alteration of the physical, chemical, or
biological quality of, or the contamination of, water that makes it harmful,
detrimental, or injurious to humans, animal life, vegetation or property or
to public health, safety, or welfare, or impairs the usefulness or the public
enjoyment of the water for any lawful or reasonable purpose.
(b)
Prohibitions.
(1)
Unauthorized injection. No person may operate a brine mining
injection well without obtaining a permit from the commission under this section.
No person may begin constructing a new brine mining injection well until the
commission has issued a permit to operate the well under this section and
a permit to drill, deepen, plug back, or reenter the well under §3.5
of this title (relating to Application to Drill, Deepen, or Plug Back) (Rule
5).
(2)
Fluid migration. No person may operate a brine mining injection
well in a manner that allow fluids to escape from the permitted injection
zone. If fluids are migrating from the permitted injection zone, the operator
shall immediately cease injection operations.
(3)
Falsifying documents and tampering with gauges. No person
may knowingly make any false statement, representation, or certification in
any application, report, record, or other document submitted or required to
be maintained under this section or under any permit issued pursuant to this
section, or falsify, tamper with, or knowingly render inaccurate any monitoring
device or method required to be maintained under this section or under any
permit issued pursuant to this section.
(c)
Standards for permit issuance. A permit may be issued only
if the commission determines that the operation of the brine mining injection
well will not result in the pollution of fresh water. All permits issued under
this section will contain the conditions required by subsections (f) and (g)
of this section, and all other conditions reasonably necessary to prevent
the pollution of fresh water.
(d)
Permit application.
(1)
Duty to apply. Any person who operates or proposes to operate
a brine mining injection well shall file a permit application with the commission
in Austin within the time provided in paragraph (2) of this subsection. The
applicant shall mail or deliver a copy of the application to the appropriate
district office on the same day the application is mailed or delivered to
the commission in Austin. A permit application will be considered filed with
the commission on the date it is received by the commission in Austin.
(2)
Time to apply.
(A)
Any person who proposes to operate a new brine mining injection
well shall file a permit application at least 180 days before the date on
which injection is to begin, unless a later date has been authorized by the
director.
(B)
Any person who is operating an existing brine injection
well shall file a permit application within 90 days of the effective date
of this section.
(C)
Any person who has obtained a permit under this section
and who wishes to continue to operate the brine mining injection well after
the permit expires shall file an application for new permit at least 180 days
before the existing permit expires, unless a later date has been authorized
by the director.
(3)
Who applies. When a brine mining facility is owned by one
person but is operated by another person, it is the operator's duty to file
an application for a permit.
(4)
Application requirements for all applicants. All applicants
shall submit the following information, using application forms supplied by
the commission:
(A)
name, mailing address, and location of the brine mining
facility for which the application is submitted;
(B)
the operator's name, mailing address, telephone number,
and status as federal, state, private, public, or other entity, and a statement
indicating whether the operator is the owner of the facility;
(C)
the proposed uses for the brine mined at the facility;
(D)
a listing of all permits or construction approvals for
the facility received or applied for under federal or state environmental
programs;
(E)
a topographic map, or other map if the topographic map
is unavailable, extending one mile beyond the property boundaries of the facility,
depicting the facility and those springs, other surface water bodies, drinking
water wells, and other wells listed in public records or otherwise known to
the applicant within 1/4 mile of the facility property boundary;
(F)
a plat showing the oil and gas operators of the tract on
which the facility is located and the tracts adjacent to the tract on which
the facility is located. On the plat or on a separate sheet attached to the
plat, the applicant shall list the names and addresses of the oil and gas
operators;
(G)
a plat showing the surface ownership of the tract on which
the facility is located and the tracts adjacent to the tract on which the
facility is located. On the plat or on a separate sheet attached to the plat,
the applicant shall list the names and addresses of the surface owners, as
determined from the current county tax rolls or other reliable sources, and
shall identify the source of the list. If the director determines that, after
diligent efforts, the applicant has been unable to ascertain the name and
address of one or more surface owners, the director may waive the requirements
of this subparagraph with respect to those surface owners;
(H)
a map with surveys marked showing the type, location, and
depth of all wells of public record within a 1/4 mile radius of the brine
mining injection well that penetrate the salt formation. The applicant shall
attach the following information to the map:
(i)
a tabulation of the wells showing the dates the wells were
drilled and the present status of the wells; and
(ii)
plugging records for plugged and abandoned wells and completion
records for other wells;
(I)
a letter from the Texas Commission on Environmental Quality
stating the depth to which fresh water strata should be protected;
(J)
a complete electric log of the brine mining injection well
or a nearby well. On the log, the applicant shall identify the geologic formations
between the land surface and the top of the salt formation and the depths
at which they occur;
(K)
a drawing of the surface and subsurface construction details
of the brine mining injection well;
(L)
the proposed maximum daily injection rate and maximum injection
pressure;
(M)
the proposed injection procedure;
(N)
the proposed mechanical integrity testing procedure;
(O)
the source of mining water to be used at the facility.
If the source is groundwater, the following information must be included:
(i)
the groundwater formation name;
(ii)
an depth of the groundwater formation; and
(iii)
an analysis of the groundwater;
(P)
the direction of the hydraulic gradient in the area; and
(Q)
the proposed groundwater monitoring plan, or an alternate
plan for assuring that fluids are not escaping from the permitted injection
zone.
(5)
Additional information. The applicant shall submit any
other information required on the application form supplied by the commission.
In addition to the information reported on the application form, the applicant
shall submit, at the director's request, any other information the commission
may reasonably require to assess the brine mining injection well and to determine
whether to issue a permit.
(e)
Signatories to applications and reports.
(1)
Applications. All applications shall be signed as follows:
(A)
for a corporation, by a responsible corporate officer.
A responsible corporate officer means a president, secretary, treasurer, or
vice-president of the corporation in charge of a principal business function,
or any other person who performs similar policy-making or decision-making
functions for the corporation; or
(B)
for a partnership or sole proprietorship, by a general
partner or the proprietor, respectively.
(2)
Reports. All reports required by permits and other information
requested by the commission shall be signed by a person described in paragraph
(1) of this subsection or by a duly authorized representative of that person.
A person is a duly authorized representative only if:
(A)
the authorization is made in writing by a person described
in paragraph (1) of this subsection;
(B)
the authorization specifies an individual or position having
responsibility for the overall operation of the regulated facility; and
(C)
the authorization is submitted to the commission before
or together with any report of information signed by the authorized representative.
(3)
Certification. Any person signing a document under paragraph
(1) or (2) of this subsection shall make the following certification: "I certify
under penalty of law that this document and all attachments were prepared
under my direction or supervision in accordance with a system designed to
assure that qualified personnel properly gathered and evaluated the information
submitted. Based on my inquiry of the person or persons who manage the system,
or who are directly responsible for gathering the information, the information
submitted is, to the best of my knowledge and belief, true, accurate, and
complete. I am aware that there are significant penalties for submitting false
information."
(f)
Conditions applicable to all permits. The conditions specified
in this subsection apply to all permits.
(1)
Duty to comply. The operator shall comply with all conditions
of the permit. Any permit noncompliance is grounds for enforcement action,
for permit termination, revocation and reissuance, or modification, or for
denial of a permit renewal application.
(2)
Duty to reapply. If the operator wishes to continue a permitted
activity after the expiration date of the permit, the operator shall apply
for and obtain a new permit.
(3)
Need to halt or reduce activity not a defense. It is not
a defense for an operator in an enforcement action that it would have been
necessary to halt or reduce the permitted activity in order to maintain compliance
with the conditions of the permit.
(4)
Duty to mitigate. The operator shall take all reasonable
steps to minimize and correct any adverse effect on the environment resulting
from noncompliance with the permit.
(5)
Proper operation and maintenance. The operator shall at
all times properly operate and maintain all facilities and systems of treatment
and control, and related appurtenances, that are installed or used by the
operator to achieve compliance with the conditions of the permit. Proper operation
and maintenance includes effective performance, adequate funding, adequate
operator staffing and training, and adequate laboratory and process controls,
including appropriate quality assurance procedures. This provision requires
the operation of back-up and auxiliary facilities or similar systems only
when necessary to achieve compliance with the conditions of the permit.
(6)
Permit actions. The permit may be modified, revoked and
reissued, or terminated for cause. The filing of a request by the operator
for a permit modification, revocation and reissuance, or termination, or a
notification of planned changes or anticipated noncompliance does not stay
any permit condition.
(7)
Property rights. The permit does not convey any property
rights of any sort, or any exclusive privilege.
(8)
Duty to provide information. The operator shall also furnish
to the commission, within a time specified by the commission, any information
that the commission may request to determine whether cause exists for modifying,
revoking and reissuing, or terminating the permit, or to determine compliance
with the permit. The operator shall also furnish to the commission, upon request,
copies of records required to be kept under the conditions of the permit.
(9)
Inspection and entry. The operator shall allow any member
or employee of the commission, on proper identification, to:
(A)
enter upon the premises where a regulated activity is conducted
or where records are kept under the conditions of the permit;
(B)
have access to and copy, during reasonable working hours,
any records required to be kept under the conditions of the permit;
(C)
inspect any facilities, equipment (including monitoring
and control equipment), practices, or operations regulated or required under
the permit; and
(D)
sample or monitor any substance or parameter for the purpose
of assuring compliance with the permit or as otherwise authorized by the Texas
Water Code, §27.071, or the Texas Natural Resources Code, §91.1012.
(10)
Monitoring and records.
(A)
Samples and measurements taken for the purpose of monitoring
must be representative of the monitored activity.
(B)
The operator shall retain records of all monitoring information,
including all calibration and maintenance records and all original chart recordings
for continuous monitoring instrumentation, copies of all reports required
by the permit, and records of all data used to complete the permit application,
for at least three years from the date of the sample, measurement, report,
or application. This period may be extended by request of the commission at
any time.
(C)
Records of monitoring information must include the date,
exact place, and time of the sampling or measurements; the individual(s) who
performed the sampling or measurements; the date(s) analyses were performed;
the individual(s) who performed the analyses; the analytical techniques or
methods used; and the results of the analyses.
(11)
Signatory requirements. All reports and other information
submitted to the commission shall be signed and certified in accordance with
subsection (e) of this section.
(12)
Reporting requirements.
(A)
The operator shall notify the commission as soon as possible
of any planned physical alteration or addition to the facility.
(B)
The operator shall give advance notice to the commission
of any planned changes in the facility that may result in noncompliance with
permit requirements.
(C)
Monitoring results shall be reported at the intervals specified
in the permit.
(D)
Reports of compliance or noncompliance with the requirements
contained in any compliance schedule of the permit shall be submitted no later
than 30 days after each scheduled date.
(E)
The operator shall report to the commission any noncompliance
that may endanger human health or the environment.
(i)
An oral report shall be made to the appropriate district
office immediately after the operator becomes aware of the noncompliance.
A written report shall be filed with the Austin office within five days of
the time the operator becomes aware of the noncompliance. The written report
must contain the following information:
(I)
a description of the noncompliance and its cause;
(II)
the period of noncompliance, including exact dates and
times, and, if the noncompliance has not been corrected, the anticipated time
it is expected to continue; and
(III)
steps taken or planned to reduce, eliminate, and prevent
recurrence of the noncompliance.
(ii)
Information that shall be reported under this subparagraph
includes the following:
(I)
any monitoring or any other information that indicates
that any contaminant may endanger fresh water; or
(II)
any noncompliance with a permit condition or malfunction
of the injection system that may cause fluid migration into or between fresh
water strata.
(F)
The operator shall report any noncompliance not reported
under subparagraphs (C), (D), and (E) of this paragraph at the time monitoring
reports are submitted. The report must contain the information listed in subparagraph
(E) of this paragraph.
(G)
If the operator becomes aware that it failed to submit
any relevant facts or submitted incorrect information in a permit application
or a report to the commission, the operator shall promptly submit the relevant
facts or correct information.
(13)
Transfers. The permit is not transferable to any person
except by modification, or revocation and reissuance, to change the name of
the operator and incorporate other necessary requirements.
(14)
Completion report. Injection operations may not begin
in any new brine mining injection well until the operator has submitted a
completion report to the director, and the director has reviewed the completion
report and found the well in compliance with the conditions of the permit.
(15)
Workovers. The operator shall notify the appropriate district
office at least 48 hours before performing any workover or corrective maintenance
operations that involve the removal of the tubing or well stimulation.
(16)
Mechanical integrity.
(A)
No person may perform injection operations in a brine mining
injection well that lacks mechanical integrity. A well has mechanical integrity
if:
(i)
there is not significant leak in the casing; and
(ii)
there is no significant fluid movement into fresh water
strata through vertical channels adjacent to the wellbore.
(B)
For any existing brine mining injection well, mechanical
integrity must be demonstrated annually. For any new brine mining injection
well, mechanical integrity must be demonstrated before injection operations
begin and annually thereafter. In addition, for all brine mining injections
wells, mechanical integrity must be demonstrated after any workover that involves
the removal of the tubing.
(C)
To demonstrate the absence of a significant leak in the
casing, the operator shall conduct a fluid pressure test in accordance with
the following procedures:
(i)
the operator shall submit a written test procedure to the
commission in Austin at least 15 days before the test;
(ii)
the operator shall notify the district office orally at
least 48 hours before the test;
(iii)
the operator shall perform the test using the test procedure
submitted prior to the testing unless otherwise instructed by the commission;
and
(iv)
the operator shall file a complete record of the test
with the commission in Austin within 30 days after the test.
(D)
In lieu of an annual fluid pressure test, the operator
may monitor the pressure of a hydrocarbon pad or blanket contained in the
annulus space of the well, provided the operator has obtained written approval
from the director prior to using this method.
(E)
One of the following methods shall be used to demonstrate
the absence of significant fluid movement into fresh water strata through
vertical channels adjacent to the wellbore:
(i)
the results of a temperature or noise log; or
(ii)
where the nature of the casing precludes the use of the
logging techniques prescribed in clause (i) of this subparagraph, cementing
records demonstrating the presence of adequate cement to prevent such movement.
(F)
The director may allow the use of a method of demonstrating
mechanical integrity other than one listed in subparagraphs (C), (D), and
(E) of this paragraph with the approval of the administrator of the Environmental
Protection Agency obtained pursuant to 40 Code of Federal Regulations §146.8(d).
(G)
Mechanical integrity must be demonstrated to the satisfaction
of the director. In conducting and evaluating the results of a mechanical
integrity test, the operator and the director will apply procedures and standards
generally accepted in the industry. In reporting the results of a mechanical
integrity test, the operator must include a description of the method and
procedures used. In evaluating the results, the director will review monitoring
and other test data submitted since the previous mechanical integrity test.
(17)
Notice of conversion or abandonment. The operator shall
notify the commission at such times as the permit requires before conversion
or abandonment of the well.
(18)
Plugging. Within one year after cessation of brine mining
injection operations, the operator shall plug the well in accordance with §3.14(a)
and (c)(h) of this title (relating to Plugging) (Rule 14(a) and (c)-(h)).
For good cause, the director may grant a reasonable extension of time in which
to plug the well if the operator submits a proposal that describes actions
or procedures to ensure that the well will not endanger fresh water during
the period of the extension.
(g)
Other permit conditions. In addition to the conditions
required in all permits, the commission will establish conditions, as required
on a case-by-case basis, to provide for and assure compliance with the requirements
specified in this subsection.
(1)
Duration. Permits will be effective for a term up to the
operating life of the facility. The commission will review each permit issued
pursuant to this section at least once every five years to determine whether
cause exists for modification, revocation and reissuance, or termination of
the permit.
(2)
Operating requirements. Permits will prescribe operating
requirements, which will at a minimum specify that:
(A)
except during well stimulation, injection pressure at the
wellhead may not exceed a maximum calculated to assure that the injection
pressure does not initiate new fractures or propagate existing fractures in
the injection zone; and
(B)
in no case may the injection pressure initiate fractures
in the confining zone or cause the escape of injection or formation fluids
from the injection zone.
(3)
Monitoring requirements. Permits will specify the following
monitoring requirements:
(A)
requirements concerning the proper use, maintenance, and
installation, when appropriate, of monitoring equipment or methods;
(B)
requirements concerning the type, intervals, and frequency
of monitoring sufficient to yield data representative of the monitored activity,
including continuous monitoring when appropriate; and
(C)
requirements to report monitoring results with a frequency
dependent on the nature and effect of the monitored activity, but in no case
less than quarterly.
(4)
Construction requirements. Permits will specify construction
requirements to assure that the injection operations will not endanger fresh
water. Changes in construction requirements during construction may be approved
by the director as minor modifications of the permit. No such changes may
be physically incorporated into the construction of the well prior to approval
of the modifications by the director.
(A)
An existing brine mining injection well shall achieve compliance
with the construction requirements according to a compliance schedule established
as soon as possible and in no case later than one year after the effective
date of the permit. The permit will require the operator to submit a written
compliance report within 30 days after compliance has been achieved.
(B)
A new brine mining injection well must be cased and cemented
in accordance with §3.13 of this title (relating to Casing, Cementing,
Drilling, and Completion Requirements), (Rule 13), provided, however, that
the operator shall set and cement surface casing in accordance with the letter
obtained from the Texas Commission on Environmental Quality pursuant to subsection
(d)(4)(I) of this section regardless of the total depth of the well. No alternative
program for setting less surface casing will be authorized.
(C)
Appropriate logs and other tests must be conducted during
the drilling and construction of a new brine mining injection well. A descriptive
report interpreting the results of such logs and tests must be prepared by
a knowledgeable log analyst and submitted to the director. The logs and tests
appropriate to each well will be determined based on the depth, construction,
and other characteristics of the well, the availability of similar data in
the area, and the need for additional information that may arise from time
to time as the construction of the well progresses.
(5)
Financial responsibility. It shall be a permit condition
that the operator maintain financial responsibility and resources to plug
and abandon the brine mining injection well. The operator shall show evidence
of such financial responsibility to the commission by submitting a surety
bond or letter of credit in a form prescribed by the commission. Such bond
or letter of credit shall be maintained until the well is plugged in accordance
with subsection (f)(18) of this section.
(6)
Corrective action. For all known wells that penetrate the
injection zone within a 1/4 mile radius of the brine mining injection well
and are improperly completed, plugged, or abandoned, the commission will consider
requiring corrective action to prevent movement of fluid into fresh water
strata.
(A)
In determining the need for corrective action, the commission
will consider the following factors: nature and volume of injected fluid;
nature of native fluids; potentially affected population; geology; hydrology;
history of the injection operation; completion and plugging records; abandonment
procedures in effect at the time a well was abandoned; and hydraulic connections
with fresh water.
(B)
For an existing brine mining injection well requiring corrective
action, any permit issued will include a compliance schedule leading to compliance
with corrective action requirements. The compliance schedule will require
compliance as soon as possible and in no case later than one year after the
effective date of the permit. The permit will require the operator to submit
a written compliance report within 30 days after all required corrective action
has been taken.
(C)
For a new brine mining injection well, the operator may
not begin injection operations until all required corrective action has been
taken.
(h)
Modification, revocation and reissuance, and termination
of permits. A permit may be modified, revoked and reissued, or terminated
by the commission either upon the written request of any interested person,
including the operator, or upon the commission's initiative, but only for
the reasons and under the conditions specified in this subsection. Except
for minor modifications made under paragraph (2) of this subsection, the commission
will follow the applicable procedures in subsection (i) of this section. In
the case of a modification, the commission may request additional information
or an updated application. In the case of a revocation and reissuance, the
commission will require a new application. If a permit is modified, only the
conditions subject to modification are reopened. The term of a permit may
not be extended by modification. If a permit is revoked and reissued, the
entire permit is reopened and subject to revision, and the permit is reissued
for a new term.
(1)
Modification, or revocation and reissuance. The following
are causes for modification, or revocation and reissuance:
(A)
material and substantial alterations or additions to the
facility occurred after permit issuance and justify permit conditions that
are different or absent in the existing permit;
(B)
the commission receives new information;
(C)
the standards or regulations on which the permit was based
have been changed by promulgation of amended standards or regulations or by
judicial decision after the permit was issued;
(D)
the commission determines good cause exists for modifying
a compliance schedule, such as a act of God, strike, flood, materials shortage,
or other event over which the operator has little or no control and for which
there is no reasonably available remedy;
(E)
cause exists for terminating a permit under paragraph (3)
of this subsection, and the commission determines that modification, or revocation
and reissuance, is appropriate; or
(F)
a transfer of the permit is proposed.
(2)
Minor modifications. With the operator's consent, the director
may make minor modifications to a permit administratively, without following
the procedures of subsection (i) of this section. Minor modifications may
only:
(A)
correct clerical or typographical errors, or clarify any
description or provision in the permit, provided that the description or provision
is not changed substantively;
(B)
require more frequent monitoring or reporting;
(C)
change construction requirements provided that any changes
shall comply with the requirements of subsection (g)(4) of this section; or
(D)
allow a transfer of the permit where the director determines
that no change in the permit is necessary other than a change in the name
of the operator, provided that a written agreement between the current operator
and the new operator containing a specific data for the transfer of permit
responsibility, coverage, and liability has been submitted to the commission.
(3)
Termination. The following are causes for terminating a
permit during its term, or for denying a permit renewal application:
(A)
the operator fails to comply with any condition of the
permit or this section;
(B)
the operator fails to disclose fully all relevant facts
in the permit application or during the permit issuance process, or misrepresents
any relevant fact at any time;
(C)
a material change of conditions occurs in the operation
or completion of the well, or there are material changes in the information
originally furnished;
(D)
the commission determines that the permitted injection
endangers human health or the environment, or that pollution of fresh water
is occurring or is likely to occur as a result of the permitted injection;
or
(E)
fluids are escaping from the permitted injection zone.
(i)
Permitting procedures.
(1)
Review of applications. Upon receipt of an application
for a permit, the director will review the application for completeness. Within
30 days after receipt of the application, the director will notify the applicant
in writing whether the application is complete or deficient. A notice of deficiency
will state the additional information necessary to complete the application,
and a date for submitting this information. The application will be deemed
withdrawn if the necessary information is not received by the specified date,
unless the director has extended this date upon request of the applicant.
Upon timely receipt of the necessary information, the director will notify
the applicant that the application is complete. The director will not begin
processing a permit until the application is complete.
(2)
Permit denial. If the director administratively denies
a permit application, a notice of administrative denial will be mailed to
the applicant. The applicant will have a right to a hearing on request. If
the applicant requests a hearing, the notice of administrative denial will
be subject to the same procedures as a draft permit prepared under paragraph
(3) of this subsection.
(3)
Draft permits.
(A)
A draft permit will be prepared when the director tentatively
decides:
(i)
to issue a permit;
(ii)
to modify, or revoke and reissue, a permit; or
(iii)
to terminate a permit, in which case the director will
prepare a notice of intent to terminate, which is a type of draft permit.
(B)
A draft permit will contain all proposed permit conditions.
(4)
Fact sheets. The director will prepare a fact sheet to
accompany every draft permit that the director finds is the subject of widespread
public interest or raises important issues. The fact sheet will briefly set
forth the principal facts and the significant factual, legal, methodological,
and policy questions considered in preparing the draft permit. The fact sheet
will include information satisfying the requirements of 40 Code of Federal
Regulations §124.8(b).
(5)
Notice.
(A)
The commission will give notice when a draft permit is
prepared under paragraph (3) of this subsection, and when a hearing is scheduled
under paragraph (7) of this subsection.
(B)
Notice will be given by the methods specified in this subparagraph.
(i)
A copy of the notice will be mailed to the following persons:
(I)
any agency that the commission knows has issued or is required
to issue a permit for the same facility under any federal or state environmental
program;
(II)
the United States Environmental Protection Agency;
(III)
persons on a mailing list developed according to 40 Code
of Federal Regulations §124.10(c)(1)(viii);
(IV)
any unit of local government having jurisdiction over
the area where the facility is or is proposed to be located, and each state
agency having any authority under state law with respect to the construction
or operation of the facility;
(V)
the operator; and
(VI)
any oil and gas operators or surface owners required to
be listed in the application under subsection (d)(4)(F) and (G) of this section.
If, pursuant to subsection (d)(4)(G), the director waived the requirement
to list certain surface owners in the application, the applicant shall notify
such persons by publishing the notice. The notice shall be published by the
applicant once each week for two consecutive weeks in a newspaper of general
circulation for the county where the facility is located. The applicant shall
file proof of publication with the commission in Austin.
(ii)
The notice shall be published by the applicant at least
once in a newspaper of general circulation for the county where the facility
is located. The applicant shall file proof of publication with the commission
in Austin.
(C)
Notices will include information satisfying the requirements
of 40 Code of Federal Regulations §124.10(d) and the Administrative Procedure
and Texas Register Act.
(D)
A copy of any draft permit, fact sheet, and application
will be mailed to the persons notified under subparagraph (B)(i)(I) and (II)
of this paragraph, and to any other person upon request. The applicant will
be mailed a copy of any draft permit and fact sheet.
(E)
The Texas Commission on Environmental Quality, the Texas
Water Development Board, the Texas Department of Health, the Texas Parks and
Wildlife Department, the United States Fish and Wildlife Service, other state
and federal agencies with jurisdiction over fish, shellfish, and wildlife
resources, the Advisory Council on Historic Preservation, state historic preservation
officers, and other appropriate government authorities will be given opportunity
to receive copies of notices, applications, draft permits, and fact sheets.
(6)
Comments and requests for hearing. Notice of a draft permit
will allow at least 30 days for public comment. During the public comment
period, any interested person may submit written comments on the draft permit
and may request a hearing if one has not already been scheduled.
(7)
Hearings on draft permits.
(A)
A hearing will be held:
(i)
when the director finds, on the basis of requests, a significant
degree of public interest in a draft permit;
(ii)
when an applicant or an affected person requests a hearing
on a draft permit; or
(iii)
when an operator requests a hearing on a draft permit
prepared when the director tentatively decides to modify, revoke and reissue,
or terminate a permit.
(B)
The commission may hold a hearing at its discretion, for
instance, when a hearing might clarify one or more issues involved in the
permit decision.
(C)
Notice of a hearing will be given at least 30 days before
the hearing. The public comment period under paragraph (6) of this subsection
will automatically be extended to the close of any hearing under this paragraph.
(8)
Administrative approval. After the close of the public
comment period, the director may issue, modify, revoke and reissue, or terminate
a permit administratively if no hearing is required under paragraph (7) of
this subsection.
(9)
Response to comments. When a final permit is issued, the
commission will respond in writing to comments received during the public
comment period. The response will be made available to the public and will:
(A)
specify which provisions, if any, of the draft permit have
been changed in the final permit, and the reasons for the changes; and
(B)
briefly describe and respond to all significant comments
on the draft permit raised during the public comment period, or during any
hearing on the draft permit.
(j)
Commission review of administrative actions. Administrative
actions performed by the director or commission staff pursuant to this section
are subject to review by the commissioners.
(k)
Federal regulations. All references to the Code of Federal
Regulations in this section are references to the 1987 edition of the Code.
The following federal regulations are adopted by reference and can be obtained
at the William B. Travis Building, 1701 North Congress Avenue, Austin, Texas
78711: 40 Code of Federal Regulations §§124.8(b), 124.10(c)(1)(viii),
124.10(d), and 146.8(d). Where the word "director" is used in the adopted
federal regulations, it should be interpreted to mean "commission."
(l)
Effective date. This section becomes effective upon approval
of the commission's Class III Underground Injection Control (UIC) Program
for brine mining injection wells by the United States Environmental Protection
Agency under the Safe Drinking Act, §1422 (42 United States Code §300h-1).
§3.85.Manifest To Accompany Each Transport of Liquid Hydrocarbons by Vehicle.
(a)
The following words and terms, when used in this section,
shall have the following meanings, unless the context clearly indicates otherwise.
(1)
Cargo manifest--One or more documents that together contain
the information required by subsection (c) of this section. That part of a
manifest which contains information unique to the particular transport being
described (such as date and time of removal) must be part of a book, tablet,
or series, wherein the documents are sequentially numbered.
(2)
Commission--The Railroad Commission of Texas.
(3)
Facility--Any place used to store, process, refine, reclaim,
dispose of, or treat liquid hydrocarbons.
(4)
Lease--A well producing oil, gas, or oil and gas, and any
group of contiguous wells producing oil, gas, or oil and gas of any number
operated as a producing unit.
(5)
Liquid hydrocarbons--Unrefined oil or condensate, and refined
oil or condensate to be blended with unrefined liquid hydrocarbons.
(6)
Oil tanker vehicle--A motor vehicle licensed for highway
use on a public highway or used on a public highway:
(A)
that is equipped with, carrying, pulling, or otherwise
transporting an assembly, compartment, tank, or other container that is used
for transporting, hauling, or delivering liquids; and
(B)
that is being used to transport liquid hydrocarbons on
a public highway.
(7)
Public highway--A way or place of whatever nature open
to the use of the public as a matter of right for the purpose of vehicular
travel, even if the way or place is temporarily closed for the purpose of
construction, maintenance, or repair.
(8)
Transporter--Each gatherer, storer, or other handler of
liquid hydrocarbons who moves or transports those liquid hydrocarbons by truck
or other motor vehicle, provided however, that the provisions of this rule
do not apply to:
(A)
common carriers as defined in the Natural Resources Code,
Chapter 111; or
(B)
the movement of salt water, brine, sludge, drilling mud,
or other liquid or semiliquid material if the commission has authorized the
entity to move such material and such material contains less than 7.0% liquid
hydrocarbon, by volume, or if not authorized by the commission, the movement
is not for hire and the material moved does not contain more than 7.0% liquid
hydrocarbons by volume.
(b)
A cargo manifest must be carried in each oil tanker vehicle
transporting liquid hydrocarbons on a public highway in this state and must
be presented on request for inspection as provided by subsection (f) of this
section.
(c)
For each load of liquid hydrocarbons loaded onto and transported
by an oil tanker vehicle, the cargo manifest must include:
(1)
an identification of the lease or facility from which the
liquid hydrocarbons were removed, which must include:
(A)
the lease or facility name; and
(B)
the name of the operator of the lease or facility;
(2)
the total quantity of liquid hydrocarbons removed from
the lease or facility and loaded onto the oil tanker vehicle; provided that
for purposes of indicating quantity on the copy of the manifest left with
the lease operator, top and bottom gauges will suffice. On the other copies,
an estimate in barrels must be included;
(3)
the date and hour when the liquid hydrocarbons were removed
from the lease or facility and loaded onto the oil tanker vehicle;
(4)
the identity of the transporter which must include;
(A)
the company or individual transporter's name and address;
(B)
the oil tanker vehicle driver's name; and
(C)
a unique number for the oil tanker vehicle that for a truck
tractor and semitrailer type oil tanker vehicle must include unique vehicle
numbers for both truck tractor and semitrailer; and
(5)
the intended point of destination for the liquid hydrocarbons,
including the name of the receiving facility.
(d)
Copy of manifest to be left at the lease.
(1)
A copy of the cargo manifest must be left at the lease
or facility from which the liquid hydrocarbons were removed or delivered to
the lease or facility operator, his agent, or his representative.
(2)
The requirements of this section may be met by leaving
a separate document at the lease or facility from which the liquid hydrocarbons
were removed or by delivering to the lease or facility operator a separate
document that includes information required under subsection (c)(1)-(3) and
(4)(A) and (B) this section.
(3)
If more than one load of liquid hydrocarbons is removed
from a single tank or other container of liquid hydrocarbons within a period
of 24 consecutive hours, subsection (c)(2) and (3) of this section may be
met for purposes of this section by a separate document that includes:
(A)
the total quantity of liquid hydrocarbons removed;
(B)
the date and hour the first load was removed; and
(C)
the date and hour the last load was removed.
(4)
If the operator of a facility requires that a transporter
leave at the facility or deliver to the operator a document other than the
transporter's cargo manifest, a transporter may meet the requirements of this
section by leaving those specified documents at an agreed location or delivering
the document to the operator.
(e)
After the delivery of all liquid hydrocarbons in an oil
tanker vehicle is completed, the cargo manifest must be maintained in the
records of the transporter for a period of not less than two years from the
date the liquid hydrocarbons are removed from the oil tanker vehicle.
(f)
Upon request from a commission agent or other law enforcement
official the transporter must produce the cargo manifest for inspection immediately,
whether it is on an oil tanker vehicle or in the records of the transporter.
Copies of cargo manifests must be filed with the commission, upon request
from the commission.
(g)
Companies or individuals who do not have organization reports
(Form P-5) on file with the Railroad Commission, as required by Rule 1 (§3.1
of this title (relating to Organization Name To Be Filed and Records To Be
Kept)), may not issue cargo manifests.
(h)
Every truck or other vehicle covered by this section shall
bear on both sides thereof the name of the company or individual responsible
for such transportation, the number of the vehicle, and the number of the
certificate or permit authorizing the service. In the case of vehicles not
for hire, this number shall be the company's organizational report (P-5) number.
The identifying signs shall be printed in letters not less than two inches
in height, in sharp color contrast to the background, and shall be plainly
legible for a distance of at least 50 feet.
§3.93.Water Quality Certification Definitions.
(a)-(c)
(No change.)
(d)
Notice of Request for Certification.
(1)
(No change.)
(2)
Notice by Applicant. If a joint notice is not used as provided
in paragraph (1) of this subsection, the applicant must mail notice of the
request for certification on or before the date the request for certification
is filed with the commission. Such notice shall include the information required
in paragraph (3) of this subsection. The applicant shall provide notice by
first class mail to:
(A)-(C)
(No change.)
(D)
the Texas
Commission on Environmental Quality (TCEQ)
or its successor agencies
[
(E)-(H)
(No change.)
(3)-(4)
(No change.)
(e)-(h)
(No change.)
§3.99.Cathodic Protection Wells.
(a)
Definitions. The following words and terms, when used in
this section, shall have the following meanings, unless the context clearly
indicates otherwise.
(1)-(2)
(No change.)
(3)
Protection depth--Depth or depths at which usable quality
water must be protected or isolated, as determined by the Texas
Commission
on Environmental Quality (TCEQ) or its successor agencies
[
(4)
(No change.)
(b)
(No change.)
(c)
Determination of protection depth. Before drilling any
cathodic protection well, an operator shall obtain a letter from the
TCEQ
[
(d)-(f)
(No change.)
(g)
Reporting. Within 30 days of completion of the last well
in a project area, the operator shall submit a letter to the commission stating
that each cathodic protection well in the project area has been completed
in accordance with subsection (e) of this section. The letter must include
the completion date for each well, the name and address of the operator, and
the drilling permit and API numbers of the well, if applicable. A plat of
the project area identifying cathodic protection well locations, counties,
survey lines, scale, and northerly direction must be attached. In addition,
a letter from the
TCEQ
[
(h)
(No change.)
[
§3.100.Seismic Holes and Core Holes.
(a)
Definitions. The following words and terms, when used in
this section, shall have the following meanings, unless the context clearly
indicates otherwise.
(1)
(No change.)
(2)
Core hole--Any hole drilled for the purpose of securing
geological information to be used in the exploration or development of oil,
gas, geothermal, or other mineral resources, except coal or uranium. For regulations
governing coal exploratory wells, see
Chapter 12
[
(3)
(No change.)
(4)
Protection depth--Depth or depths at which usable quality
water must be protected or isolated, as determined by the Texas
Commission
on Environmental Quality (TCEQ) or its successor agencies
[
(5)-(6)
(No change.)
[
(b)
[
(c)
[
(d)
[
(1)
Holes that do not penetrate any protection depth. A seismic
hole or core hole that does not penetrate any protection depth does not require
a drilling permit.
(2)
Holes that penetrate any protection depth. A seismic hole
or core hole that penetrates any protection depth requires a drilling permit
to satisfy the requirements for exploratory wells described in §3.5(g)
of this title (relating to Application To Drill, Deepen, Reenter, or Plug
Back) (Statewide Rule 5).
(e)
[
(1)
Holes that do not penetrate any protection depth. A seismic
hole or core hole that does not penetrate any protection depth must be plugged
in accordance with subparagraph (A) or (B) of this paragraph. Seismic holes
must be plugged after the hole is loaded with explosives. Core holes must
be plugged immediately after completion of coring the hole.
(A)
The operator shall adequately plug the hole by filling
it from total depth to a depth of no more than 16 feet below the surface with
drill cuttings and/or bentonite. Immediately above the drill cuttings and/or
bentonite, the operator shall place a bentonite plug no less than 10 feet
in length. A plastic cap imprinted with the name of the operator shall be
set above the bentonite plug no less than three feet below the surface. The
remainder of the hole shall be filled with drill cuttings or native soil.
All precautions should be taken to prevent bentonite from bridging over.
(B)
Alternative plugging procedures and materials may be utilized
when the operator has demonstrated to the commission's satisfaction that the
alternatives will protect usable quality water.
(2)
Holes that penetrate any protection depth. A seismic hole
or core hole that penetrates any protection depth must be plugged in accordance
with the requirements of §3.14 of this title (relating to Plugging)
(Statewide Rule 14) and a plastic cap imprinted with the name of the operator
shall be set in the hole no less than three feet below the surface.
(f)
[
(g)
[
(1)
Holes that do not penetrate any protection depth. Within
30 days of plugging the last hole in the project area, the operator shall
submit a letter to the commission stating that each seismic hole or core hole
in the project area has been plugged in accordance with subsection
(e)(1)
[
(2)
Holes that penetrate any protection depth. For any seismic
or core hole that penetrates any protection depth, a plugging record shall
be filed in accordance with §3.14 of this title (relating to Plugging)
(Statewide Rule 14).
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 June 11, 2003.
TRD-200303494
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: July 27, 2003
For further information, please call: (512) 475-1295
16 TAC §§3.65 - 3.67, 3.69, 3.72, 3.75, 3.77
(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 Commission proposes the repeals, new sections,
and amendments pursuant to Texas Natural Resources Code, §§81.051
and 81.052, which provide the Commission with jurisdiction over all persons
owning or engaged in drilling or operating oil or gas wells and persons owning
or operating pipelines in Texas and the authority to adopt all necessary rules
for governing and regulating persons and their operations under Commission
jurisdiction and pursuant to Texas Natural Resources Code §§85.042,
85.202, 86.041 and 86.042 which require the Commission to adopt rules to control
waste of oil and gas.
Statutory authority: Texas Natural Resources Code, §§81.051,
81.052, 85.024, 85.202, 86.041, and 86.042.
Cross-reference to statute: Texas Natural Resources Code, §§81.051
and 81.052 and §§85.042, 85.202, 86.041 and 86.042.
Issued in Austin, Texas, on June 10, 2003.
§3.65.Pipeline Permits Required.
§3.66.Pipeline Tariffs.
§3.67.Obtaining Pipeline Connections.
§3.69.Definitions.
§3.72.Manifest To Accompany Each Transport of Liquid Hydrocarbons by Vehicle.
§3.75.Discharges to Waters of the State.
§3.77.Brine Mining Injection Wells.
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 June 11, 2003.
TRD-200303495
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: July 27, 2003
For further information, please call: (512) 475-1295
Subchapter A. GENERAL REQUIREMENTS
16 TAC §§9.2, 9.9, 9.51 - 9.54
The Railroad Commission of Texas (Commission) proposes amendments
to §§9.2, 9.9, and 9.51 - 9.54, relating to Definitions; Requirements
for Certificate Renewal; General Requirements for Training and Continuing
Education; Training and Continuing Education Courses; Continuing Education
Credit for Previous Courses; and Commission-Approved Outside Instructors.
The main purpose of this rulemaking is to update the rules to reflect new
courses that have been added to the Commission's training and continuing education
curriculum, to add new categories of certificate holders who will be required
to complete training and continuing education, and to increase the annual
examination renewal fee in §9.9 from $25 to $35.
In §9.2, the Commission proposes to add new definitions for "AFT materials,"
"applicant" and "certificate holder"; to revise the definition of "CETP" to
reflect the recent transfer of ownership of that program from the National
Propane Gas Association to the Propane Education and Research Council; to
revise the definition of "outside instructor" to clarify that classes taught
by approved outside instructors may be presented for Railroad Commission training
credit as well as for continuing education credit; to clarify the definition
of "training"; and to renumber the remaining definitions. The three new definitions
are proposed for clarification and do not substantively change current Commission
policies or procedures.
Section 9.9(c) includes the proposed increase in the annual certificate
renewal fee from $25 to $35. This fee is the primary source of funding for
the training and continuing education program for the approximately 10,000
LP-gas certificate holders. Other proposed new language in §9.9(c) expressly
states that governmental employees do not have to pay this fee and, in subsection
(c)(1), clarifies the dates of the two-year period during which an individual
whose certification has lapsed may pay a late-filing fee instead of complying
with the requirements for a new certificate. Other clarifying language is
proposed in subsection (d) regarding lapsed certifications.
Throughout §§9.51 - 9.54, some nonsubstantive changes have been
proposed, mainly with regard to the use of the word "course." The Commission
will use the word "course" to refer to each individual course of instruction
included in the Commission's curriculum. The Commission will use the word
"class" to refer to a particular session held at a specific time and place.
The Commission proposes substantive amendments in §9.51(b) regarding
failure to comply with a training or continuing education requirement by an
assigned deadline and the payment of late-filing fees. In subsection (b)(1),
the Commission proposes to extend training and continuing education requirements
to Category D, F, G, J, and K applicants and certificate holders. Categories
D, F, G, J, and K are being added to the currently covered Category E and
Category I to increase public safety by training approximately 400 additional
individuals whose jobs require them to handle propane in Texas. The Commission
has increased the number and types of courses offered in its training and
continuing education program to accommodate certificate holders in these additional
categories.
In §9.51(d), the Commission proposes new language to clarify that
an individual who is required to pay a fee for a class may not receive credit
for the class until the fee is paid in full.
In §9.51(e), the Commission proposes to update class schedules on
its web site monthly, rather than twice a year, to ensure that current schedule
information is available timely.
In §9.51(f)(1), the Commission proposes to delete the requirement
that registration forms be filed with the AFRED training section at least
seven calendar days prior to a class. The Commission would rather have the
classes be well attended, instead of having vacancies in a class because an
individual was late in getting the registration form to the Commission. Also
in subsection (f)(1), the Commission has added to the required registration
information the registrant's level and category of certification, to ensure
that applicants and certified individuals register for the proper course.
In subsection (f)(2)(A), Categories F and G are proposed to be added to Category
I, currently in the rule, in the references to the 16-hour required course
of instruction. New language is also proposed with regard to eight-hour and
80-hour classes. New subparagraph (B) clarifies that the class fee does not
include the rules examination fee or the license fee. Also, a new sentence
is proposed in subparagraph (C) to state that current certificate holders
who have paid the annual renewal fee and who want to add a new certification
other than a Category E, F, G, or I shall not be required to pay the $75 class
fee. In subsection (f)(2)(B), the Commission has deleted the reference to
courses P115, P116, and P117. These courses are no longer offered.
In §9.51(f)(2), the Commission proposes to add a new subparagraph
(E). The new subparagraph will allow individuals or governmental subdivisions
to request that the Commission conduct a non-credit course and authorize the
Commission to do so if an instructor is available to teach the requested course
and enough students have registered. The new language also establishes the
fees for such courses.
In subsection (f)(3), the Commission has added language to clarify its
current practices when registering individuals for classes. The proposed language
clarifies that priority for registering in eight-hour classes will be given
to individuals whose renewal deadline is the soonest, and priority for registering
in 16-hour and 80-hour classes is based on the date the course fee is paid.
Other proposed new language allows the AFRED training section to reschedule
individuals who were registered for a class that was cancelled.
Other changes proposed in §9.51 are nonsubstantive and involve changes
in wording, organization, or punctuation for clarity.
In §9.52(a), the Commission has added the same categories added in §9.51(b)(1).
Proposed new wording specifically states that Category E applicants shall
attend the 80-hour course; Categories F, G, and I applicants shall attend
the 16-hour course; and all other applicants shall attend an eight-hour course.
The corresponding new categories are also added to subsection (a)(1), with
one exception: New subsection (a)(1)(K) includes appliance service and installation
employee-level applicants. This group was already included in the rules, but
was not listed in subsection (a)(1), and is added now for clarification. Another
clarification is proposed in subsection (a)(3), which adds a reference to
AFT requirements, and in subsection (a)(4), where the cross-reference to §9.17
is corrected from subsection (e) to subsection (g).
Current §9.52(b) specifies how the Commission phased in the continuing
education requirements for certificate holders when this rule was first adopted
in February 2001 and amended in May 2001 by assigning renewal dates randomly
over the following four years. This random assignment was necessary in order
for the Commission's training staff to train the approximately 10,000 certificate
holders in existence at that time. Now that this initial random assignment
has taken place, the language in subsection (b)(1) proposed to be deleted
is no longer necessary. New language is proposed in subsection (b) to clarify
how the four-year continuing education deadline will be determined. Proposed
language is also added to subsection (b)(1)(A) to add the same new categories
that were added in subsection (a)(1) of this rule.
In a substantive amendment, the Commission proposes new §9.52(b)(1)(B)
to specify May 31, 2005, as the deadline for current Category D, F, G, J,
and K certificate holders who have only one certification as of the effective
date of these amendments to complete their continuing education requirement.
Current Category D, F, G, J, and K certificate holders who hold more than
one certification as of the effective date of these amendments shall complete
their continuing education requirement by their current assigned continuing
education deadline. In paragraph (3), a new sentence is proposed to clearly
state that governmental employees are not required to pay the annual certificate
renewal fee.
New §9.52(c) is proposed to clarify that the Commission's Train-the-Trainer
classes do not count for training or continuing education credit. This wording
clarifies that Category D or E certificate holders who are approved outside
instructors must comply with all course requirements for each of those activities
and may not receive "double credit" for one course.
Section 9.52(f) deals with advanced field training (AFT). The Commission
has proposed some clarifying amendments and deleted the requirements that
completed AFT certification paperwork be submitted to the Commission. The
Commission proposes to require the AFT to be properly completed within 30
calendar days of attending a class. All of the qualification tasks must be
completed, including the AFT qualification checklist. The Commission proposes
that completed AFT materials, including the certification page, shall be retained
and readily available for inspection by an authorized person at a licensee's
business location in Texas. In paragraph (1), proposed new wording states
that the responsibility for certifying AFT shall not be delegated to an unauthorized
individual. New paragraph (2) is proposed to illustrate different scenarios
related to the retention of AFT materials and to clarify who is responsible
for keeping the AFT materials. Additionally, the proposed text will clarify
that all the performance tasks in the AFT certificate must be completed. In
paragraph (3), renumbered from (2), Categories F and G are added to Category
I with respect to required completion of the 16-hour management course.
Existing subsection (f) regarding computer-based continuing education courses
is proposed to be repealed. The Commission wishes to avoid the cost of updating
its current computer-based courses in light of the recent decline in usage.
However, as specified in §9.53(2), the Commission proposes to continue
to award credit for computer-based courses through September 1, 2003.
The Commission proposes some substantive changes in §9.52(g) to divide
into four tables the current single table that lists each course offered and
specifies which certificate holders may complete that course for training
or continuing education credit. The proposed four-table format is more specific
and better organized. With the addition of Categories D, F, G, J, and K to
the training and continuing education program, the information in the tables
has been expanded to include those categories. In particular, the changes
are as follows:
1. Dates have been added following the title of each table. As the tables
are revised in future rulemakings, the date will be changed to a "Revision"
date.
2. The Commission has added the following new courses indicated on Tables
1 and 2: 2.2/2.4, Inspecting, Requalifying, Filling and Transporting DOT Cylinders;
and Evacuating, Transporting, Maintaining and Refitting ASME Tanks; 3.1, Residential
Propane System Layout and Design; 3.2, Residential Propane System Installation;
3.7, Electrical Troubleshooting and Repairing Residential Gas Appliances;
3.11, Residential Propane System Inspection; and 6.1, Regulatory Compliance.
3. The first table, entitled "LP-Gas Management-Level Training and Continuing
Education Courses," includes Categories D, E, F, G, I, J, and K management-level
courses, course numbers, hours, and titles, and indicates whether AFT is included.
An "x" in the row for a particular course indicates the course is approved
for the corresponding license category. For example, a Category D management-level
applicant or certificate holder who will be required to attend training or
continuing education may take course 1.1, 3.1, 3.2, 3.5, 3.7, 3.11, or the
80-hour course.
4. Table 2, entitled "LP-Gas Employee-Level Training and Continuing Education
Courses," lists employee-level courses. As compared to the current table in §9.52,
in the segment of the table entitled "Railroad Commission Training and Continuing
Education Courses Available After September 1, 1997," some courses have been
eliminated and some courses have been added. The following courses will no
longer be offered: P109A, Appliance Installation; P113A, Appliance Service
Persons Overview; P115, GAS Check (3 days); P116, GAS Check (2 days); P117,
GAS Check (self-study); P120, Bulk Plant Management; P121, Propane Distribution
Systems; and P122, Residential Systems Safety Inspection--Appliances and Exterior.
These courses do not appear on any of the new tables.
5. In Table 3, entitled "Courses Which Count Towards Continuing Education
Credit For Management-Level Certificate Holders," and Table 4, entitled "Courses
Which Count Towards Continuing Education Credit For Employee-Level Applicants
or Certificate Holders," the Propane Education and Research Council's (PERC)
GAS Check course (formerly offered by the National Propane Gas Association
(NPGA)) has been added. The two tables are divided to show which courses apply
to management-level certificate holders and which courses apply to employee-level
certificate holders.
Section 9.53 covers continuing education credit for previous courses. This
section was originally adopted to allow certificate holders who had taken
Commission courses prior to the establishment of the training and continuing
education program to receive credit for those courses in certain instances.
Only nonsubstantive changes are proposed in this rule, namely a clarification
of the random assignment of initial due dates as previously discussed in the
corresponding amendment to §9.52(b). In paragraph (2), a date of September
1, 2003, is added to indicate the date on which credit will no longer be given
for completing the Commission's current computer-based courses.
Section 9.54 covers the requirements for Commission-approved outside instructors.
In subsection (a)(1), the Commission proposes to add that outside instructors
may also offer training classes for specified management-level and employee-level
applicants, as well as continuing education for current certificate holders.
Proposed new subparagraphs (A) and (B) add that Category D certificate holders
may also become outside instructors and clarify what courses may be offered
by a Category D or Category E outside instructor. Subsection (b) also includes
some nonsubstantive new language regarding the outside instructor application
process for Category D.
In subsection (h), the Commission has proposed a new Train-the-Trainer
refresher course that outside instructors must attend prior to their next
renewal deadline. The new refresher course replaces the previous requirement
that an outside instructor must teach at least one course each year to maintain
certification as an outside instructor and will help ensure that outside instructors
know current rules and requirements. As with the proposed language in §9.52(c),
new language in §9.54(j)(1) states that the Train-the-Trainer class will
not count towards a Category D or E applicant's or certificate holder's training
or continuing education requirement.
Dan Kelly, Director, Alternative Fuels Research and Education Division,
has determined that, for each year of the first five years that the amendments
are proposed to be in effect, there will be no fiscal implications for state
or local governments. The effect on the Commission of the addition of the
Category D, F, G, J, and K certificate holders will be minimal. There are
about 400 Category D certificate holders, and only a few certificate holders
each for Categories F, G, J, and K. By spreading the due date for these 400
or so individuals over the period between the effective date of these amendments
and May 31, 2005, the Commission can handle the additional registrations within
current budget and staffing limitations.
One effect on the Commission concerns the new $250 and $500 charges proposed
in §9.51(f)(2)(E). The Commission regularly receives requests for classes
on LP-gas laws and practices from entities such as recreational vehicle companies
who have employees that are not currently required to attend an LP-gas training
or continuing education class. The Commission views these classes as important
in ensuring safety and makes every effort to comply with such requests. However,
the Commission can no longer provide these classes at no cost to the requesting
entities. Therefore, the Commission has proposed a charge of $250 for a class
that staff can provide during one day without an overnight stay, and a charge
of $500 for a class that requires an overnight stay. These charges will enable
the Commission to recover its costs and continue to provide this training.
These courses are not part of the training and continuing education program
required by §§9.51 - 9.54, and no training or continuing education
credit will be awarded for completing these courses. The proposed fees will
allow these non-credit classes to be self-sustaining, instead of being funded
by the individuals that pay the annual certificate renewal fee. A political
subdivision such as a fire department is not required to pay this fee.
The proposed $250 and $500 fees are based on the following average expenses
involved in conducting these non-credit classes:
Figure: 16 TAC Chapter 9--Preamble
Mr. Kelly has also determined that, for each year of the first five years
the amendments are proposed to be in effect, the public benefit anticipated
as a result of enforcing the amendments will be improved LP-gas safety through
better trained LP-gas industry managers and employees, and clarification of
requirements.
There is an anticipated economic cost to individuals, small businesses,
or micro-businesses required to comply with the proposed amendments which
add Categories D, F, G, J, and K management-level and employee-level certificate
holders to the training and continuing education program. The costs for training
(which applies only to applicants for new management-level or employee-level
certificates) will be the cost for the courses as specified in §9.51(f)(2),
and will depend on which course the applicant chooses to take and whether
any travel is involved for the applicant to attend the course. The costs for
continuing education (which applies to current certificate holders) will involve
only travel costs, because the continuing education classes are offered at
no charge to individuals who have paid their annual examination renewal fee.
The annual examination renewal fee is proposed to be increased from $25
to $35 in §9.9(c). The Commission finds that this increase is necessary
to allow the Commission to continue to deliver the approximately 2,600 contact
hours of training and continuing education per year needed to sustain the
requirements of §§9.51 - 9.54 and to comply with the legislative
directive that the Commission's LP-gas safety programs be financially self-sustaining.
Railroad Commission Rider 7 of the 2004-2005 General Appropriations Act
appropriates LP-gas examination renewal fee receipts to the Commission for
the purpose of providing training to licensees and certificate holders. About
10,000 LP-gas certified individuals renew their examinations each year; accordingly,
the proposed $10 increase will provide an estimated additional $100,000 annually
for training purposes. This increase will replace 74 percent of the $135,718
of General Revenue the Commission devoted to the LP-gas training and continuing
education program during fiscal year 2003. The remaining $35,718 of General
Revenue will be made up by cost-saving measures, funding from other non-General
Revenue sources, or by a combination of the two.
The proposed changes in the rules will not result in any additions to the
AFRED training database because no new records need to recorded and reported.
New courses will be added to the course tables, and additional examination
categories will be incorporated in the table. The effort required to make
these changes is small and is part of the regular database maintenance.
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 Thomas Petru at (512) 463-6930. The status of Commission
rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
The Commission simultaneously proposes the review and readoption of §§9.2,
9.9, and 9.51 - 9.54 in accordance with Texas Government Code, §2001.039.
The notice of proposed review will be filed with the
Texas Register
concurrently with this proposal.
The amendments are proposed under the Texas Natural Resources
Code, §113.051, which authorizes the Commission to adopt rules relating
to any and all aspects or phases of the LP-gas industry that will protect
or tend to protect the health, welfare, and safety of the general public.
Statutory authority: Texas Natural Resources Code, §113.051
Cross-reference to statute: Texas Natural Resources Code, §113.051
Issued in Austin, Texas on June 10, 2003.
§9.2.Definitions.
In addition to the definitions in any adopted NFPA pamphlets, the following
words and terms, when used in this chapter, shall have the following meanings,
unless the context clearly indicates otherwise.
(1)
Advanced field training (AFT)--The final portion of the
training or continuing education requirements in which an individual shall
successfully perform the specified LP-gas activities in order to demonstrate
proficiency in those activities.
(2)
AFRED--The Commission's Alternative Fuels Research and
Education Division.
(3)
AFT materials--The portion of a Commission
training module manual consisting of the four sections of the Railroad Commission's
LP-Gas Employee Qualifying Field Activities, including General Instructions,
the Task Information, the Operator Qualification Checklist, and the Railroad
Commission Record and Employer Record.
(4)
[
(5)
Applicant--An individual:
(A)
who is applying for a new certificate; or
(B)
whose certification has lapsed for a period of less than
two years and who is applying to restore certification by paying any applicable
fees and by completing any applicable training or continuing education requirements.
(6)
[
(7)
[
(8)
[
(9)
Certificate holder--An individual:
(A)
who has passed the required management-level qualification
examination, satisfactorily completed any applicable training or continuing
education requirements, and paid the applicable fee; or
(B)
who has passed the required employee-level qualification
examination, paid the applicable fees, and complied with the training or continuing
education requirements in §9.52 of this title (relating to Training and
Continuing Education Courses); or
(C)
who has passed the required management-level qualification
examination or employee-level qualification examination, has paid the applicable
fee, and is required to comply with a training or continuing education requirement.
(10)
[
(11)
[
(12)
[
(13)
[
(14)
[
(15)
[
(16)
[
(17)
[
(18)
[
(19)
[
(20)
[
(21)
[
(22)
[
(23)
[
(24)
[
(25)
[
(26)
[
(27)
[
(28)
[
(29)
[
(30)
[
(31)
[
(32)
[
(33)
[
(34)
[
(35)
[
(36)
[
(37)
[
(38)
[
(39)
[
(40)
[
(41)
[
(42)
[
(43)
[
(44)
[
(45)
[
(46)
[
(47)
[
(48)
[
(49)
[
(50)
[
§9.9.Requirements for Certificate Renewal.
(a)
Active status. In order to maintain active status, certificate
holders shall comply with the applicable continuing education requirements
in this section.
(b)
Certificate renewal date. 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.
(c)
Certificate holders shall pay the
$35
[
(1)
Failure to pay the annual renewal fee by the deadline shall
result in a lapsed certification. To renew a lapsed certification, the individual
shall pay the
$35
[
(2)
Upon receipt of the annual renewal fee and any late-filing
penalty, the Commission shall verify that the individual's certification has
not been suspended, revoked, or expired for more than two years. After verification,
the Commission shall renew the certification and the individual may continue
or resume LP-gas activities authorized by that certification.
(d)
Continuing education. Certificate holders shall successfully
complete the continuing education requirements as specified in §§9.51
- 9.53 of this title (relating to General Requirements for Training and Continuing
Education; Training and Continuing Education Courses; and Continuing Education
Credit for Previous Courses).
(1)
Failure to comply with the continuing
education requirements by the assigned deadline shall result in a lapsed certification.
(2)
If a certification lapses as specified
in paragraph (1) of this subsection, the individual shall pay the $20 late
fee.
§9.51.General Requirements for Training and Continuing Education.
(a)
Effective March 1, 2001, individuals shall comply with
the training and continuing education requirements in this chapter.
(b)
Applicants for new licenses or new certificates, as set
forth in §9.7 and §9.8 of this title (relating to Application for
License and License Renewal Requirements, and Application for a New Certificate,
respectively) and persons holding existing licenses or certificates shall
comply with the training or continuing education requirements in this chapter.
Any individual who fails to comply with the training or continuing education
requirements by the assigned deadline may regain certification by paying the
course fee and satisfactorily completing an authorized training or continuing
education course within two years of the deadline. In addition to paying the
course fee, the person shall pay any fee or late penalties to the LP-Gas Safety
Section.
(1)
The training requirements apply only to applicants for
Category
D, E, F, G, I, J, or K
[
(2)
The continuing education requirements apply to:
(A)
all management-level certificate holders and employee-level
certificate holders as specified in
the tables in
[
(B)
any ultimate consumer who has purchased, leased, or obtained
other rights in any LP-gas bobtail, including any employee of such ultimate
consumer if that employee drives or in any way operates the equipment on an
LP-gas bobtail.
(3)
The training and continuing education requirements do not
apply to:
(A)
an ultimate consumer driving or fueling a motor vehicle
powered by LP-gas;
(B)
an individual who fuels motor vehicles as an employee of
an ultimate consumer;
(C)
an employee of a state agency, county, municipality, school
district, or other governmental subdivision;
(D)
an individual with a general installers and repairman exemption;
or
(E)
anyone certified only as a transport driver.
(4)
Any employee of an ultimate consumer or a state agency,
county, municipality, school district, or other governmental subdivision who
is not required to complete the training or continuing education shall be
properly supervised and trained by the employer in the maintenance and storage
of LP-gas and vehicles fueled by LP-gas, and in the operation of equipment
during the filling and dispensing of LP-gas.
(c)
Individual credit. Successful completion of any required
training or continuing education
class
shall be credited to and
accrue to the individual.
(d)
No partial credit. Individuals attending
classes
[
(e)
Schedules. Dates and locations of
available
[
(f)
Registering for a
class
[
(1)
To register for a scheduled training or continuing education
class
[
(2)
Costs for
classes
[
(A)
Each registration for a training class
shall require the payment of the applicable nonrefundable class fee as follows:
(i)
$75 for an initial eight-hour class;
(ii)
$150 for the initial 16-hour Category F, G, and I class;
and
(iii)
$750 for the initial 80-hour Category E class.
(B)
The Category E, F, G, and I class fees
do not include the management-level rules examination or license fee described
in §9.6 and §9.10 of this title (relating to Licenses and Fees,
and Rules Examination, respectively).
(C)
Current certificate holders who have paid
the annual renewal fee and who want to add a new certification other than
Category E, F, G, or I shall not be required to pay the $75 class fee.
[(A)
Requests for training courses shall include
the appropriate nonrefundable course fee of $75 for an eight-hour course,
$150 for the 16-hour Category I training course, and $750 for the 80-hour
Category E seminar. The Category E and I seminar fees do not include the fee
to take the management-level rules examination which is described in §9.10
of this title (relating to Rules Examination).]
(D)
[
(E)
Requests for classes where no training
or continuing education class credit is given shall be submitted in writing
to the AFRED training section. The AFRED training section may conduct the
requested classes at its discretion. The fee for a non-credit class is $250
if no overnight expenses are incurred by the AFRED training section, or $500
if overnight expenses are incurred. A political subdivision is not required
to pay the non-credit class fee.
(F)
[
(3)
The Commission shall schedule individuals to attend
classes
[
(A)
Priority for attending the 16-hour Category
F, G, and I class, and the 80-hour Category E class is based on when the class
fee is paid.
(B)
Priority for attending classes other than
the 16-hour Category F, G, and I class, and the 80-hour Category E class shall
be given to applicants or certificate holders who must comply with training
or continuing education requirements by the next May 31 deadline.
(C)
If any
class
[
(4)
If a previously registered individual is unable to attend
the
class
[
(5)
Applicants who take
classes
[
(g)
Retention of records. Individual
applicants or certificate
holders
[
§9.52.Training and Continuing Education Courses.
(a)
Training. Applicants for a new
certification
[
(1)
The following management- or employee-level applicants
shall complete the training requirements:
(A)
Category D management-level;
(B)
[
(C)
Category F management-level;
(D)
Category G management-level;
(E)
[
(F)
Category J management-level;
(G)
Category K management-level;
(H)
[
(I)
[
(J)
[
(K)
Appliance service and installation employee-level;
and
(L)
[
(2)
Training requirements for an applicant for license shall
be fulfilled by all prospective company representatives and operations supervisors
[
(3)
Individuals who pass an employee-level rules examination
between March 1 and May 31 of any year shall have until May 31 of the next
year to complete any required training [
(4)
Applicants for company representative or operations supervisor
who do not comply with the conditional qualification in
§9.17(g)
[
(b)
Continuing education. A certificate holder shall complete
at least eight hours of continuing education every four years.
Upon fulfillment
of this requirement, the certificate holder's next continuing education deadline
shall be four years after the May 31 following the date of the most recent
class the certificate holder has completed, unless the class was completed
on May 31, in which case the deadline shall be four years from that date.
A certificate holder's continuing education deadline shall not be extended
if an examination for a current category and level of certification is retaken
and passed; a continuing education deadline shall be extended only after a
certificate holder successfully completes an applicable continuing education
class. An individual who completes a continuing education class after the
assigned deadline shall have four years from the original deadline to complete
the next class.
[
(1)
[
(A)
Certificate holders with one of the following certificates
shall complete the continuing education classroom instruction and any required
AFT for that
class
[
(i)
Category D management-level;
(ii)
[
(iii)
Category F management-level;
(iv)
Category G management-level;
(v)
[
(vi)
Category J management-level;
(vii)
Category K management-level;
(viii)
[
(ix)
[
(x)
[
(xi)
Appliance service and installation employee-level;
and
(xii)
[
(B)
Certificate holders who hold only a Category
D, F, G, J, or K certificate as of the effective date of this section shall
complete their initial continuing education requirement by May 31, 2005. Certificate
holders who hold a Category D, F, G, J, or K certificate and who have more
than one certification as of the effective date of this section shall complete
their continuing education requirement by the continuing education deadline
assigned for the initial certificate.
(C)
[
(2)
Certificate holders who attend a
class
[
(3)
Individuals who have not paid the annual certificate renewal
fee, including general installers and repairman exemption holders or members
of the general public, shall not attend
training or
continuing
education
classes
[
(4)
Any certificate holder who has timely paid the annual certificate
renewal fee but is not otherwise required to attend a
Commission continuing
education class
[
(c)
Train-the-Trainer classes. The Train-the-Trainer
classes shall not count as credit towards the training or continuing education
requirements.
(d)
[
(e)
[
(f)
[
(1)
The responsibility of certifying AFT activities shall
not be delegated to an unauthorized individual.
AFT
qualification
tasks
shall be
witnessed by an authorized individual, verified
[
(A)
For licensees with only one company representative, that
company representative shall self-certify the AFT.
(B)
For licensees with more than one company representative,
one company representative may certify the AFT of another company representative,
but shall not self-certify.
(C)
Company representatives shall certify operations supervisors'
AFT.
(D)
The company representative or an operations supervisor
authorized by the licensee and in current good standing with the Commission
shall certify the employees' AFT.
(E)
If authorized, a
[
(2)
Other AFT situations shall be handled
as follows:
(A)
For a certified individual employed by a licensee, the
licensee shall retain the most recently completed AFT material for each applicable
category of the individual's certification in the individual's employment
records.
(B)
For an individual who ceases employment with a licensee,
the licensee shall retain the latest required AFT material for at least two
years from the date the individual is no longer employed by the licensee.
The two-year period shall be based on the renewal period for the examination
renewal fee penalty. The licensee shall provide a copy of the AFT material
to the individual.
(C)
For an individual who begins employment with a different
licensee, the new licensee shall obtain a copy of the individual's AFT material
from the individual and shall place the copy in the individual's employment
records.
(D)
An individual who is never employed by a licensee shall
retain the most recently completed AFT material for each applicable category
of the individual's certification in a safe location for at least two years
from the date the class that required the AFT was attended.
(E)
For an individual who is employed by a licensee when a
class requiring AFT is attended, but who prior to the AFT's being certified
becomes employed by a new licensee, the new licensee shall certify the individual's
AFT.
(F)
For an individual who is employed by a licensee when a
class requiring AFT is attended, but who prior to the AFT's being certified
ceases employment with the licensee and wishes to continue performing LP-gas
activities, the individual shall contact a company representative or operations
supervisor of another applicable licensee or an approved Commission outside
instructor to complete the AFT and maintain the LP-gas certification.
(3)
[
(4)
[
[(f)
Computer-based continuing education courses.]
[(1)
To receive credit for a computer-based continuing education
course as shown in Table 1 of this section, the individual shall have successfully
completed all sections and exercises of the course.]
[(2)
The company representative or operations supervisor shall
comply with AFRED's written computer-based course agreement.]
[(3)
The individual shall ensure that all hardware and software
shall be returned to the AFRED training section within the time period established
by the AFRED training section. AFRED shall inspect the computer upon its return.
If AFRED determines that changes or modifications have been made (including,
for example, files or information downloaded from the Internet), the individual
shall not receive credit for the computer-based course and the Commission
shall not issue a certificate. If the computer requires any work to return
the computer to its original condition, the individual shall reimburse the
Commission for the repair costs.]
(g)
Available courses.
Training and continuing education
courses and other information are shown in
Tables 1 through 4
[
§9.53.Continuing Education Credit for Previous Courses.
An individual who is a current and valid certificate holder as of March
1, 2001, may receive credit toward the first continuing education requirement
to be completed by the due date
[
(1)
Commission classroom
classes
[
(2)
Commission computer-based courses. An individual who completed
a Commission computer-based course
between
[
(3)
CETP
classes
[
(A)
Basic Principles and Practices;
(B)
Propane Delivery;
(C)
Plant Operations;
(D)
Distribution Systems Operations;
(E)
Transfer Systems Operations;
(F)
Appliance Installation;
(G)
Appliance Service; or
(H)
Large Industrial/Commercial.
§9.54.Commission-Approved Outside Instructors.
(a)
General.
(1)
The Commission may approve and award
training or
continuing
education credit
for the management-level and employee-level applicants
and certificate holders specified in this section
[
(A)
Authorized Category D outside instructors
may offer only the applicable training and continuing education classes to
Category D or K management-level applicants or certificate holders and to
service and installation and appliance service and installation employee-level
applicants or certificate holders.
(B)
Authorized Category E outside instructors
may offer only the applicable training and continuing education classes to
Category D or K management-level applicants and to portable cylinder filling,
motor/mobile fuel dispenser, delivery truck, service and installation, and
appliance service and installation applicants and employee-level certificate
holders.
(2)
LP-gas companies may offer courses to their own personnel
and to other companies' personnel provided that the LP-gas company and the
outside instructor comply with the requirements of this section.
(3)
All curriculum and course materials submitted for Commission
review by an outside instructor applicant shall be printed or typewritten,
organized, and easily readable, and shall remain confidential within the limits
of Tex. Gov't Code, Chapter 552 (Public Information Act).
(4)
Copies of the Commission's curricula and materials are
available from the Commission at a reasonable cost.
(b)
Application process. Outside instructor applicants shall
submit the following to the Commission:
(1)
a non-refundable $300 registration fee for each outside
instructor;
(2)
a copy of the applicant's Category
D or
E current
certification card
or, in the case of Category D only, a copy of the
master or journeyman plumber/class A or B exemption card issued by the LP-Gas
Safety Section
;
(3)
for each course the outside instructor applicant intends
to teach:
(A)
the curriculum for and a description of the course;
(B)
the course materials and related supporting information
or a statement that the instructor will use the Commission's course materials;
(C)
a statement specifying whether the outside instructor seeks
approval to certify any AFT described in §9.52 of this title (relating
to training and continuing education courses);
(4)
proof that the outside instructor applicant has experience,
during at least three of the four years prior to the date of filing the application,
in both:
(A)
conducting LP-gas training or continuing education courses
and
(B)
performing or supervising LP-gas activities; and
(5)
any other information required by this section.
(c)
Curriculum standards. The curriculum for each course that
an outside instructor applicant intends to teach shall include, where applicable,
information that is at least the equivalent of the Commission's course or
courses on the same topic or topics, and shall include all applicable current
LP-gas regulations for Texas. Courses not offered by the Commission may be
approved if the courses are equal or greater in overall quality to other approved
courses.
(d)
Commission review. The Commission shall review the application
for approval as an outside instructor and, within 14 business days of the
filing of the application, shall notify the applicant in writing that the
application is approved, denied, or incomplete. If an application is incomplete,
the Commission's notice of deficiency shall identify the necessary additional
information, including any deficiencies in course materials. The outside instructor
applicant shall file the necessary additional information within 30 calendar
days of the date of the Commission's notice of deficiency. The outside instructor
applicant's failure to file the necessary additional information within the
prescribed time period may result in the dismissal of the outside instructor's
application and the necessity of the outside instructor applicant again paying
the non-refundable $300 registration fee for each subsequent filing of an
application.
(e)
Additional requirements for approval. Outside instructor
applicants whose applications are approved in writing by the Commission shall
attend the Commission's Train-the-Trainer Course, the fee for which is included
in the $300 registration fee. The Train-the-Trainer Course shall include classroom
instruction and the subject-matter examinations for each course for which
the applicant seeks approval to conduct. An outside instructor applicant shall
pass the subject-matter examination for each course with a score of at least
85 percent and shall attend the subject-matter courses for which the applicant
seeks approval to conduct.
(f)
Notification of approval. Within 10 business days of the
outside instructor applicant's completion of the requirements of this section,
the Commission shall notify the applicant in writing that the applicant is
approved as an outside instructor and the outside instructor may then begin
offering the courses for which the Commission approved the outside instructor.
(g)
Term of approval. Commission approval of an outside instructor
remains valid for three years unless the Commission revokes the approval pursuant
to subsection (l) of this section.
(h)
Renewal of approval. To continue offering Commission-approved
LP-gas
classes
[
(i)
Revision of course materials. An outside instructor who
[
(j)
Continuing requirements. Outside instructors shall:
(1)
maintain their Category
D or
E certificate
or Category D exemption card
in continuous good standing.
The Train-the-Trainer
class shall not count as credit towards any training or continuing education
requirements.
Any interruption of the required Category
D or
E
certification
or Category D exemption card
may result in the Commission
revoking the outside instructor's approval;
(2)
adhere to professional standards of conduct in
class
[
(3)
report to the Commission within three business days of
the conclusion of a
class
[
(k)
Disclaimer. Outside instructors are responsible for every
aspect of the
classes
[
(l)
Complaints.
(1)
Complaints regarding outside instructors shall be made
to the Commission in writing by electronic mail (e-mail), facsimile transmission
(fax), or U. S. Postal Service; shall include the printed name, address, telephone
number, and, if filed by fax or U.S. Postal Service, the signature of the
person complaining; shall state the outside instructor's name, the date, location,
and title of the course; and shall set forth the facts that the complainant
alleges demonstrate that the outside instructor:
(A)
failed to meet or maintain Commission requirements for
outside instructor approval;
(B)
failed to deliver a course as approved, including failure
to follow the approved curriculum, to use the approved course materials, or
to deliver the requisite numbers of hours of instruction; or
(C)
engaged in other conduct, including the use of language,
that created an atmosphere not conducive to learning. Such conduct includes
but is not limited to demeaning, derogating, or stereotyping women or men,
disabled persons, members of any political, religious, racial, or ethnic group,
or a particular individual, organization, or product.
(2)
Upon receipt of a complaint and at its discretion, the
Commission may gather any additional information necessary or appropriate
to making a full and complete analysis of the complaint. The Commission shall
deliver a written copy of the analysis and any findings by certified mail
to the outside instructor who is the subject of the complaint. The outside
instructor may file a written response within 20 calendar days from the date
the findings are postmarked.
(3)
If the Commission determines that an outside instructor
has engaged in conduct prohibited by this section, the Commission may prepare
a report that states the facts on which the determination is based and the
recommendation as to the action the Commission intends to take. The Commission
may issue a written warning to the outside instructor; decline to approve
or renew the outside instructor's approval; or revoke the outside instructor's
approval.
(4)
The Commission shall mail a copy of the report and recommendation
to the outside instructor by certified mail and shall include a statement
that the outside instructor has a right to a hearing on the determination
contained in the report.
(5)
Within 20 calendar days after the date the notice is postmarked,
the outside instructor shall file a written response either accepting the
determination and recommended action or requesting a hearing on the determination.
(6)
If the outside instructor accepts the determination, he
or she shall notify the Commission in writing of the acceptance, and the Commission
shall take the action indicated in the report.
(7)
If an outside instructor requests a hearing or fails to
respond timely to the notice given under paragraph (5) of this subsection,
the director shall refer the matter to the Office of General Counsel for the
setting of a hearing. The Office of General Counsel shall assign an examiner
to conduct a hearing, which shall be conducted under the Commission's General
Rules of Practice and Procedure, Chapter 1 of this title (relating to Practice
and Procedure).
(8)
Following
the
hearing, the Commission may enter
an order finding that the outside instructor has violated Commission rules
or that no violation has occurred; and may make any other finding based on
the evidence in the record.
(9)
If the outside instructor does not comply with the order
of the Commission, and if the enforcement of the Commission's order is not
stayed, then the Office of General Counsel may refer the matter to the attorney
general for enforcement of the Commission's order.
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 June 10, 2003.
TRD-200303486
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: July 27, 2003
For further information, please call: (512) 475-1295
The Railroad Commission of Texas proposes amendments to §§9.101,
9.114, 9.131, 9.135-9.137, 9.140-9.143, 9.206, 9.301, 9.307, 9.311, 9.312,
and 9.401-9.403 of this title relating to Filings Required for Stationary
LP-Gas Installations; Odorizing and Reports; 200 PSIG Working Pressure Stationary
Vessels; Unsafe or Unapproved Containers, Cylinders, or Piping; Filling of
DOT Containers; Inspection of Cylinders at Each Filling; Uniform Protection
Standards; Uniform Safety Requirements; LP-Gas Container Storage and Installation
Requirements; Bulkhead, Internal Valve, and ESV Protection for Stationary
LP-Gas Installations with Individual or Aggregate Water Capacities of 4,001
Gallons or More; Vehicle Identification Labels; Adoption by Reference of NFPA
54; Identification of Converted Appliances; Special Exceptions for Agricultural
and Industrial Structures Regarding Appliance Connectors and Piping Support;
Certification Requirements for Joining Methods; Adoption by Reference of NFPA
58; Clarification of Certain Terms Used in NFPA 58; and Sections in NFPA 58
Not Adopted by Reference, and Adopted with Changes, Additional Requirements,
or Corrections. The Commission proposes these amendments in order to adopt
by reference the 2001 edition of National Fire Protection Association (NFPA)
Texas Natural Resources Code, §113.011, provides that the Commission
shall administer and enforce the laws of Texas and the rules and standards
of the Commission relating to liquefied petroleum gas (LP-gas). Texas Natural
Resources Code, §113.051, provides that the Commission shall promulgate
and adopt rules or standards or both relating to any and all aspects or phases
of the liquefied petroleum gas industry that will protect or tend to protect
the health, welfare, and safety of the general public. Texas Natural Resources
Code, §113.052, provides that the Commission may adopt by reference,
in whole or in part, the published codes of the National Fire Protection Association
to be met in the design, construction, fabrication, assembly, installation,
use, and maintenance of containers, tanks, appliances, systems, and equipment
for the transportation, storage, delivery, use, and consumption of LP-gas
or any one or more of these purposes.
Recently, it has become more difficult for LP-gas businesses doing business
in Texas to conduct business regionally and/or nationally due to differences
in state rules and regulations. Differing state requirements increase costs
associated with operating an LP-gas business with operations in Texas and
one or more additional states. Current national standards, which have been
adopted by the Commission, impose safety standards and specifications on LP-gas
businesses that insure a high degree of safety to the public health, safety,
and welfare. Therefore, the Commission finds that it is in the public interest
to adopt by reference national safety standards in order to increase public
safety and remove regulatory burdens that increase the cost of operating an
LP-gas business. In 2001, the Commission adopted the 1998 edition of NFPA
58. The Commission either adopted alternative or additional language for or
did not adopt certain sections of the 1998 edition of NFPA 58, which are indicated
in the table in §9.403(a). Because the 2001 edition of NFPA 58 has been
adopted in whole or in part by most other states in the United States, the
Texas LP-gas industry would benefit from adopting the update to the 2001 edition
of NFPA 58, because Texas companies would be held to the same standards when
doing business in other states; therefore, LP-gas companies wishing to expand
their businesses to other states would have find it easier to do so.
As a result of adopting the 2001 edition of NFPA 58, the Commission proposes
some amendments to Commission rules in order that the rules remain consistent
with the 2001 edition of NFPA 58. Also, as the Commission did when adopting
the 1998 edition, there are some sections in the 2001 edition of NFPA 58 for
which the Commission proposes to adopt alternative or additional language,
or language which the Commission does not adopt; these sections are indicated
in the table in §9.403(a). The table also shows sections in NFPA 58 which
were published with typographical or other errors that were corrected by NFPA
in errata documents published at a later date.
The Commission included Chapter 9 in the adoption of the 1998 edition of
NFPA 58 and will likewise adopt Chapter 9 in the update to the 2001 edition,
even though at this time there are no installations in Texas covered by this
chapter.
As with the adoption of the 1998 edition of NFPA 58, the Commission does
not adopt Chapter 10 regarding marine shipping and receiving, because the
Commission's §9.1 states that the LP-gas safety rules do not apply to
these types of installations or activities.
Also, the Commission does not adopt language in NFPA 58 and other related
pamphlets referring to the practice of engineering (such as "sound engineering
practices" or "good engineering practices," for example) and has attempted
to maintain this distinction in the update to the 2001 edition of NFPA 58.
Proposed Non-substantive Amendments
NFPA changed its numbering scheme between the 1998 and the 2001 editions
of NFPA 58 from a number using a dash and periods to a number using all periods.
For example, in §9.101(c)(2), the reference to NFPA 58 §3-2.2.3
is now §3.2.2.3. There are many instances throughout these rules where
this non-substantive change has been proposed. In particular, the Commission
rules which have amendments proposed solely to change the NFPA section numbers
include §9.101, 9.114, 9.131, 9.135, 9.136, 9.137, 9.140, 9.141, 9.142,
9.206, 9.307, 9.311, and 9.312.
Clarifying and Substantive Amendments
The Commission proposes both substantive and non-substantive amendments
to §9.143. The proposed amendments in §9.143(a) reflect the rule
numbering scheme of the 2001 edition of NFPA 58, correct some NFPA 58 section
numbers, and add new language to exempt the filling of a container solely
through a 1-3/4 inch double back check filler valve, directly installed in
the container, from the requirements of §9.143; the wording for this
exemption is also proposed in subsection (b). The reason for this exemption
is that no bulkhead and ESV protection is required if containers are filled
through a standard filler valve with double back check capabilities. These
valves are designed to shear at an engineered point without loss of product
in the event of a pull-away accident. The Commission finds that requiring
bulkheads and ESVs on these small filler valves would be overly burdensome.
Proposed amendments to §9.143(d)(7)(E)(iii) and (e) are non- substantive
and reflect the rule numbering scheme of the 2001 edition of NFPA 58. The
proposed amendment to subsection (g) changes the requirements for stainless
steel flexible connectors from 24 inches in length or less to 36 inches in
length or less. The 2001 edition of NFPA 58, §1.7.26, defines the term
"flexible connector" as not exceeding 36 inches, and §3.2.17 mandates
that flexible connectors and hose used as flexible connectors shall not exceed
36 inches in length. The proposed amendment to increase the maximum length
to 36 inches is made in order to make Commission rules consistent with the
2001 edition of NFPA 58. The change in this requirement will not decrease
safety and, in certain circumstances, may increase safety. Limiting a flexible
connector's length to 24 inches may, in effect, make that connector rigid
due to the physical limitations of the space in which it is installed. In
circumstances where the connector needs a minimum amount of flexibility and
the 24- inch maximum length reduces needed flexibility, safety may be compromised.
For this reason, the Commission proposes this amendment to be consistent with
the requirements of the 2001 edition of NFPA 58.
Proposed new §9.401(a) adopts by reference the 2001 edition of NFPA
58, effective September 1, 2003, in order to update the 1998 edition currently
adopted by the Commission. Proposed amendments to §9.401(b) are non-substantive
and reflect the rule numbering scheme of the 2001 edition and update the edition
dates of other NFPA standards and codes cited by the 2001 edition of NFPA
58.
Proposed amendments in §9.402(a) are non-substantive, reflect the
numbering scheme of the 2001 edition, and delete the term "engineering" which
is no longer defined in the 2001 edition. The Commission, however, retains
the language in subsection (b) which clarifies the Commission's policy on
the practice of engineering.
Proposed amendments in §9.403(a) include a non-substantive amendment
to reflect NFPA's publication of a November 19, 2001, errata sheet. The errata
sheet, prepared by NFPA, shows corrections such as typographical and other
errors that were printed in the 2001 edition of NFPA 58. These errors are
shown with their corrected wording on the applicable rows in the Table. In
addition, the Commission proposes a new Table 1 in §9.403 to replace
the previous table showing the NFPA 58 sections not adopted, adopted with
changes, or in addition to existing Commission rules.
In new table §9.403(a), the Commission specifies which provisions
of the 2001 edition of NFPA 58 it is adopting with changes, additional requirements,
not adopting, and which have errata published by NFPA and corresponding corrections.
NFPA 58 Sections Adopted with Additional Requirements
The rows in the table in §9.403 which indicate "additional requirements"
refer to other Commission rules that accompany the NFPA 58 section. There
are three types of proposed changes within this category. The first group
includes changes solely in the numbering scheme for the NFPA 58 section; for
example, former NFPA 58 §1-3 is now §1.3. These sections, which
have no proposed changes other than the NFPA 58 section numbering scheme,
are §§1.3, 2.2.1.4, 2.2.2.2, 2.2.6.1, 2.3.2.3, 2.4.4, 2.4.4.3, 2.4.6,
3.2.2.2, 3.2.2.3, 3.4.2.4, 3.9.3.8, 4.2.3.8, 4.4.3.1, 5.2.1.1, 5.4.2.1, and
Appendix A.
The second group includes NFPA 58 sections which were reorganized as well
as renumbered; for example, §1-6 in the 1998 edition of NFPA 58 is now §1.7.11
in the 2001 edition. No other changes are proposed. These sections include §1.7.11
(formerly §1-6), §3.2.2.8 (formerly §3-2.2.9), §3.2.4.2
(formerly §3-2.4.1(c), §3.2.4.4 (formerly §3-2.4.1(f), §3.2.9.1
(formerly §3-2.4.8(a); and §3.2.9.2(d) (formerly §3-2.4.9(d).
The third group includes the renumbering and some reorganization of the
NFPA 58 sections, but also includes some other proposed changes.
In §1.5, the Commission proposes the same changes as in the 1998 edition,
with the additional clarification of the specific Commission rules that are
applicable, whereas the exception adopted for the 1998 edition of the provision
pointed out the applicable rule chapter and subchapter.
The Commission proposes an additional requirement for §2.6.2.1 in
the 2001 edition, whereas in the 1998 edition the Commission adopted §2-6.2.1
with changes. The Commission is not adopting the prior change to §2.6.2.1
which required that an appliance be used according to the manufacturer's instructions.
The prior exception is not needed because the Commission's rule 9.307 applies
and it is not necessary to state that requirement as an exception to the NFPA
provision. The Commission does not have control over the content of appliance
instructions written by the manufacturer; such a requirement can, in effect,
promulgate nonuniform and differing requirements for the same type of appliance
made by different manufacturers; and NFPA 54, which the Commission has adopted,
contains provisions addressing LP-gas appliances.
The Commission proposes an exception to §3.2.17 as an additional requirement
instead of changing the provision as was done for §3-2.10.10 of the 1998
edition. The exception to the 1998 edition version required operators to comply
with §9.143, which they would have to do despite the exception to this
particular NFPA provision. Therefore, the Commission proposes to show §9.143
as an additional requirement rather than amending the text of the NFPA provision.
The Commission proposes the same type of change for §3.9.3.10 and §3.11.4.3(c).
The exception to §3-9.3.10 in the 1998 edition added language telling
operators to see Commission rule §9.140. Operators are already required
to comply with §9.140; therefore, the Commission proposes to show §9.140
as an additional requirement rather than amending the text of the NFPA provision.
The same change is proposed for §3-11.4.3(c)(3).
Sections in NFPA 58 Not Adopted
There are three groups of NFPA 58 sections which the Commission does not
adopt. The first group includes sections in the 1998 edition which were not
adopted and are not proposed to be adopted now; the only change is the numbering
scheme. These sections are §§1.4.1, 1.4.2, 2.2.6.3, 2.2.6.5, 3.2.3.1(c),
3.4.8.3, 3.11.5, 4.2.1.2, 5.3.1, 5.4.2.2, and Chapter 10.
The second group includes NFPA 58 sections which were reorganized as well
as renumbered; for example, §1-6 is the 1998 edition is now §1.7.40
in the 2001 edition. The sections which have these types of changes are §1.7.40
(formerly §1- 6), §§3.2.19.1, 3.2.19.2, 3.2.19.3, and 3.2.19.6
(which were formerly all part of §3-2.10.11), and §8.1.3 (formerly §8.1.4).
The third group includes the renumbering and some reorganization of the
NFPA 58 sections, but also includes some other proposed changes.
The requirements of §2-3.3.2 in the 1998 edition are substantively
the same as the requirements of §2.3.3.2 in the 2001 edition. However,
the text of §2.3.3.2 in the 2001 edition has been rewritten and is structurally
different from §2-3.3.2 of the 1998 edition. As a result, the Commission
has adopted with changes §2.3.3.2(a)-(b)(2), which in effect is no change
from the Commission's adoption with changes of §2-3.3.2 of the 1998 edition.
By not adopting §2.3.3.2(b)(3)-(4) of the 2001 edition, the requirements
of this provision are substantively the same as the Commission's adoption
with changes of §2-3.3.2 in the 1998 edition.
The Commission is not adopting §3.3.3.6 of the 2001 edition because
these requirements are covered by the exceptions to §2.3.3.2 of the 2001
edition. Section 3-3.3.7 in the 1998 edition was renumbered §3.3.3.6
in the 2001 edition. The requirements of Texas' exceptions to §3-3.3.7
in the 1998 edition are found in §2.3.3.2 of the 2001 edition.
The Commission is not adopting §5.4.3 of the 2001 edition because
the text of this provision mandates an exception under certain conditions.
The Commission has existing rule provisions for granting exceptions to its
rules.
Sections in NFPA 58 Adopted with Changes
There are four groups of NFPA 58 sections which the Commission adopts with
changes. The first group is sections which are adopted with the same changes
in the 2001 edition as in the 1998 edition; the only difference is the numbering
scheme. These are §§2.2.6.4, 3.2.2.1, 3.4.9.2, 3.4.2.1, 3.4.2.7,
6.3.6, 8.2.8.1, and 8.2.10.
The second group includes NFPA 58 sections which were reorganized as well
as renumbered. These sections are §3.2.5 (formerly §3-2.4.1(a), §§3.2.18.1,
3.2.18.2, and 3.2.18.3 (formerly all part of §3-2.11), §3.8.2.8(e)
(formerly §3- 8.2.7(d), and §3.4.4.1 (formerly §3-4.4).
The third group includes NFPA 58 sections which were proposed with changes
to the 1998 edition to address forthcoming changes in the 2001 edition. Now
that these changes are part of the 2001 edition, the exceptions are no longer
needed. These sections include §2-3.7(a), §3-2.2.7, §3-2.4.2(c), §3-2.4.3(a), §3-2.4.7(d), §3.2.9.3(d), §3.2.16.14
(formerly §3- 2.10.8(j), §§3.2.15.9 and 3.2.15.10 (formerly §3-2.10.9), §§3.2.11
through 3.2.15, §3.2.25.1(a) (formerly §3- 2.16.1.(a), §3.4.4.2
(formerly §3-4.4.(b), §3.4.5.1, §3.10.2.2 (formerly §3-10.2.3), §4.2.2.3, §5.4.1,
and §8.2.3 (formerly §8-2.3.1).
The fourth group includes NFPA 58 sections which were adopted with changes
to the 1998 edition and which are proposed to be adopted with some different
changes to the 2001 edition.
The Commission proposes to adopt §2.2.1.5 of the 2001 edition as written,
thus removing the exception made to §2- 2.1.5 in the 1998 edition. The
Commission has determined that it will increase public safety to require requalification
of cylinders which may be installed adjacent to buildings without a distance
separation.
The Commission proposes to retain the same changes to §2.3.1.5 as
were made to §2-3.1.5 in the 1998 edition in regards to the size requirements
of cylinders. The Commission does not propose any changes with regard to the
dates that were made in the 1998 edition of §2-3.1.5 because those dates
have passed.
The Commission proposes a change to §2.3.3.2(a)(5) in order to make
the provision consistent with the size of cylinder over which the Commission
has jurisdiction under Texas Natural Resources Code, Chapter 113.
The Commission proposes a change to §3.2.12.1 similar to that made
to §3-2.7.1 in the 1998 edition. In the 2001 edition of this provision,
the Commission is changing the date on which single-stage regulators shall
not be installed in fixed piping systems to February 1, 2001, which is consistent
with the effective date of the adoption of the 1998 edition of NFPA 58.
The Commission proposes a change to §3.2.24 in the 2001 edition in
order to remove a reference to engineering practice. This change is consistent
with the exception to the 1998 edition, §3-2.15.
The Commission proposes a change to §3.7.2.2 by removing "commercial"
from the exception for fixed electrical equipment at installations of LP-gas
systems. The justification for this change is that the Texas definition of
"commercial" includes industrial applications and differs from the NFPA definition
of "commercial," which excludes industrial applications and is based on tank
size rather than operational activity.
The Commission proposes changes to §§3.11.3, 3.11.3.1, and 3.11.3.3
in order to make these provisions consistent with the Commission's proposed
adopted version of §2.3.3.2. The provisions of §§3.11.3, 3.11.3.1,
and 3.11.3.3 are substantively the same as §3-11.3 of the 1998 edition
and therefore is not a substantive change to §3-11.3 of the 1998 edition
as adopted by the Commission with exceptions.
The Commission proposes changes to §4.4.3.2 in order to make this
provision consistent with the requirements of Commission rule §9.136.
The exceptions to §§6-2.4 and 6-3.7 in the 1998 edition are not
proposed to be retained in the 2001 edition because the language in the 2001
edition is consistent with all fire extinguisher requirements in NFPA 58 and
the exceptions create a third standard in addition to Department of Transportation
federal requirements.
The exception to §6-3.3.4 in the 1998 edition is not proposed to be
retained in the 2001 edition because the implementation date in the Texas
exception has passed and no exception is needed.
The Commission proposes changes to §6.5.2.1 in order to allow the
exceptions as provided by the 2001 edition. The Commission did not adopt any
of the exceptions in §6-5.2.1 in 1998 edition. However, the Commission
has determined that it is less dangerous to public safety to transport a container
with product for evacuation under controlled conditions than to attempt to
evacuate a container within a residential or commercial environment.
The Commission proposes changes to §8.2.3(1) in order to allow the
use of overfill prevention devices under certain limited circumstances. This
is a change from the Commission's adopted exception to §8-2.3(k) of the
1998 edition which did not allow the sole use of overfill prevention devices.
The Commission proposes changes to §8.2.6.6 which are substantively
the same as the changes made to §8-2.6.6 in the 1998 edition. The change
to §8.2.6.6 in the 2001 edition will additionally allow original vehicle
manufacturers to design and manufacture container mounting brackets.
The Commission does not propose a change to the definition of "bulk plant"
in the 2001 edition as was done in §1-6 of the 1998 edition. The definition
of "bulk plant" has been changed in the 2001 update to remove a gallon requirement.
Therefore, the 2001 edition's definition of "bulk plant" is consistent with
current Commission rules and no exception is needed.
The Commission's exceptions to §§2-2.3.2, 2-2.3.3, and 2- 2.3.6
of the 1998 edition removed certain dates. In the 2001 edition version of
these rules, the Commission proposes to retain these dates because these dates
refer to ASME design change dates, not rule implementation dates, and therefore
no exceptions are needed.
The exception to §2-3.2.5 in the 1998 edition is not proposed to be
retained in the 2001 edition because the February 1, 2002, date has passed
and all cylinders up to February 1, 1988, have already been required to have
had their relief valves replaced.
The Commission's exceptions to §§2-3.4.2, 2-3.4.2(a) and 2-3.4.2(c)
of the 1998 edition removed certain dates. In the 2001 edition, the Commission
proposes to retain these dates because they refer to ASME design change dates,
not rule implementation dates, and therefore no exceptions are needed.
The exception to §3-2.4.8(h)(3) in the 1998 edition is not proposed
to be retained in the 2001 edition, renumbered §3.2.9.1(f)(3), because
the Texas Commission on Environmental Quality (formerly the Texas Natural
Resource Conservation Commission) does not have rules addressing these items
and therefore no exception is needed.
The exception to §8-2.3.1(l) in the 1998 edition is not being retained
in the 2001 edition provision §8.2.3(j) because the design date has passed
and no exception is needed.
The exception to §8-3.7 in the 1998 edition is not being retained
in the 2001 edition provision §8.3.7 because the implementation date
has passed and no exception is needed.
Richard Gilbert, LP-gas safety specialist, Gas Services Division, LP-Gas
Safety, has determined that for each year of the first five years the proposed
amendments to §§9.101, 9.114, 9.131, 9.135-9.137, 9.140-9.143, 9.206,
9.301, 9.307, 9.311, 9.312, and 9.401-9.403 are in effect there will be fiscal
implications for state government as a result of enforcing or administering
the amendments. The Commission will be required to purchase 20 copies of the
2001 edition of NFPA 58; these cost $36.75 per pamphlet, and will thus have
a fiscal impact of at least $735, which the Commission will handle within
existing budget authority. There will be no fiscal implications to the Commission
with regard to the proposed amendments to §§9.101, 9.114, 9.131,
9.135-9.137, 9.140-9.143, 9.206, 9.301, 9.307, 9.311, 9.312, and 9.401-9.403.
There are no fiscal implications for local governments.
Mr. Gilbert has also determined that the public benefit anticipated as
a result of the amendments will be increased public health, safety and welfare,
and decreased regulatory costs associated with compliance with the 1998 version
of NFPA 58. The Commission finds that allowing the LP-gas industry to conduct
business pursuant to national uniform safety standards achieves a reasonable
balance between the public interest in having LP-gas, an environmentally-beneficial
fuel, widely and continuously available and at lower costs, and the public
interest in having LP-gas industry participants comply with comprehensive
safety standards.
There will be some financial impact on LP-gas licensees required to comply
with §9.7 of this title (relating to Application for License and License
Renewal Requirements) which requires licensees to maintain a current version
of the LP-Gas Safety Rules and to provide at least one copy to each company
representative and operations supervisor. Because NFPA 58 is adopted by reference,
it is part of the LP-Gas Safety Rules and licensees will be required to purchase
a copy of the 2001 edition of NFPA 58; the cost currently is $36.75 per copy.
A licensee is also required to purchase copies of the referenced NFPA 58 pamphlets
if the licensee performs the activities covered by those pamphlets. The current
cost, per book, of these publications is as follows:
NFPA 10 - $31.00;
NFPA 15 - $31.00;
NFPA 30 - $33.08;
NFPA 37 - $27.75;
NFPA 50B - $23.50;
NFPA 51 - $23.50;
NFPA 51B - $23.50;
NFPA 54 - $36.75;
NFPA 59 - $27.75;
NFPA 61 - $27.75;
NFPA 70 - $59.50;
NFPA 82 - $23.50;
NFPA 86 - $31.00;
NFPA 96 - $27.75;
NFPA 101 - $59.50;
NFPA 302 - $31.00;
NFPA 501A - $23.50;
NFPA 505 - $23.50; and
NFPA 1192 - $27.75.
A licensee purchasing one copy of all pamphlets would spend $592.58.
Pursuant to Texas Government Code, §2006.002(c), the Commission cannot
determine the cost of compliance for individual, small business, or micro-business
LP-gas businesses, because under the proposed amendments, operating an LP-gas
business is voluntary, not mandatory. The Commission assumes that there are
LP-gas businesses 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 LP-gas
business. In addition, the costs for any particular LP-gas business will vary
based on that business' 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). Further, pursuant to Texas Government
Code, §2006.002, the Commission finds that, considering that the purpose
of Texas Natural Resources Code, Chapter 113, is to ensure the safe use of
LP-gas, it is not feasible to reduce any adverse effect the proposed amendments
could have on individuals, small businesses, or micro-businesses based on
the size of the business.
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. Due to these amendments
being a routine update of existing rules, the Commission will accept comments
for 30 days after publication in the
Texas Register
and should refer to LP-Gas Docket No. 1735. 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. Gilbert at (512) 463-6935.
The status of Commission rulemakings in progress is available at www.rrc.state.tx.us/rules/proposed.html.
Subchapter B. STATIONARY INSTALLATIONS AND CONTAINER REQUIREMENTS
16 TAC §§9.101, 9.114, 9.131, 9.135 - 9.137, 9.140 - 9.143
The amendments are proposed under the Texas Natural Resources
Code, §113.051, which authorizes the Commission to adopt rules relating
to any and all aspects or phases of the LP-gas industry that will protect
or tend to protect the health, welfare, and safety of the general public,
and §113.052, which authorizes the Commission to adopt by reference,
in whole or in part the published codes of the National Fire Protection Association
as standards to be met in the design, construction, fabrication, assembly,
installation, use, and maintenance of containers, tanks, appliances, systems,
and equipment for the transportation, storage, delivery, use, and consumption
of LP-gas or any one or more of these purposes.
Statutory authority: Texas Natural Resources Code, §§113.051
and 113.052.
Cross-reference to statute: Texas Natural Resources Code, Chapter 113.
Issued in Austin, Texas on June 10, 2003.
§9.101.Filings Required for Stationary LP-Gas Installations.
(a)-(b)
(No change.)
(c)
Aggregate water capacity of 10,000 gallons or more.
(1)
(No change.)
(2)
In addition to NFPA 58,
§3.2.3.3
[
(A)-(B)
(No change.)
(3)-(5)
(No change.)
(d)-(g)
(No change.)
§9.114.Odorizing and Reports.
(a)
Odorization shall comply with NFPA 58,
§1.3
[
(b)-(d)
(No change.)
§9.131.200 PSIG Working Pressure Stationary Vessels.
In addition to NFPA 58,
§2.2.2.2
[
§9.135.Unsafe or Unapproved Containers, Cylinders, or Piping.
In addition to NFPA 58,
§2.2.1.4
[
§9.136.Filling of DOT Containers.
(a)
(No change.)
(b)
Containers designed to be used on forklifts or industrial
trucks shall be filled as specified in NFPA 58,
§8.3
[
§9.137.Inspection of Cylinders at Each Filling.
In addition to NFPA 58,
§2.2.1.5
[
§9.140.Uniform Protection Standards.
(a)
(No change.)
(b)
In addition to NFPA 58,
§§3.3.6.1, 3.4.2.4,
3.9.3.6, 4.2.3.8, 5.2.1.1, and 5.4.2.1
[
(1)-(7)
(No change.)
(c)
(No change.)
(d)
In addition to NFPA 58,
§§3.2.4.2, 3.2.9.1(a)-(d),
3.2.9.2(d), 3.3.6.1, 3.9.3.8, 5.4.2.1
[
(1)-(6)
(No change.)
(e)-(g)
(No change.)
(h)
In addition to NFPA 58,
§5.4.2.2
[
(1)-(5)
(No change.)
§9.141.Uniform Safety Requirements.
(a)
In addition to NFPA 58,
§3.2.4.1(f)
[
(1)-(2)
(No change.)
(b)
In addition to NFPA 58,
§3.9.4.2
[
(c)-(d)
(No change.)
(e)
In addition to NFPA 58,
§2.2.6.1
[
(f)
In addition to NFPA 58,
§3.2.2.8
[
(g)-(i)
(No change.)
§9.142.LP-Gas Container Storage and Installation Requirements.
Except as noted in this section, LP-gas containers shall be stored
or installed in accordance with the distance requirements in NFPA 58,
§3.2.2
[
(1)
An LP-gas liquid dispensing installation other than a retail
operated DOT portable container filling/service station installation is not
required to have a pump, provided that the storage containers are located
one and one half times the required distances specified in NFPA 58,
§3.2.2
[
(2)
(No change.)
§9.143.Bulkhead, Internal Valve, and ESV Protection for Stationary LP-Gas Installations with Individual or Aggregate Water Capacities of 4,001 Gallons or More.
(a)
Instead of NFPA 58,
§3.2.10.11
[
(b)
Within two years of February 1, 2001, or by February 1,
2003, at the latest, stationary LP-gas installations in existence as of February
1, 2001, with individual or aggregate water capacities of 4,001 gallons or
more, including licensee and nonlicensee locations, or railroad tank car transfer
systems to fill trucks with no stationary storage involved, which do not have
a bulkhead and/or backflow check valves where the flow is in one direction
into the container and ESVs installed shall install vertical bulkheads and
pneumatic ESVs.
The filling of a container solely through a 1 3/4 inch
double back check filler valve, directly installed in the container, is exempt
from the requirements of this section.
(1)-(5)
(No change.)
(c)
(No change.)
(d)
Bulkheads, whether horizontal or vertical, shall comply
with the following requirements:
(1)-(6)
(No change.)
(7)
Bulkheads shall be constructed by welding using the following
materials or materials with equal or greater strength, as shown in the diagram.
Figure: 16 TAC §9.143(d)(7) (No change.)
(A)-(D)
(No change.)
(E)
Either a schedule 40 pipe sleeve or a 3,000-pound coupling
shall be welded between the top crossmember and the kick plate;
(i)-(ii)
(No change.)
(iii)
Elbows or other fittings shall comply with NFPA 58,
§2.4.4
[
(8)-(9)
(No change.)
(e)
In addition to NFPA 58,
§2.3.3.2
[
(f)
(No change.)
(g)
By February 1, 2003, rubber flexible connectors which are
3/4-inch or larger in size installed in liquid or vapor piping at an existing
liquid transfer operation shall be replaced with a stainless steel flexible
connector. Stainless steel flexible connectors shall be
36
[
(h)
(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 June 10, 2003.
TRD-200303479
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: July 27, 2003
For further information, please call: (512) 475-1295
16 TAC §9.206
The amendments are proposed under the Texas Natural Resources
Code, §113.051, which authorizes the Commission to adopt rules relating
to any and all aspects or phases of the LP-gas industry that will protect
or tend to protect the health, welfare, and safety of the general public,
and §113.052, which authorizes the Commission to adopt by reference,
in whole or in part the published codes of the National Fire Protection Association
as standards to be met in the design, construction, fabrication, assembly,
installation, use, and maintenance of containers, tanks, appliances, systems,
and equipment for the transportation, storage, delivery, use, and consumption
of LP-gas or any one or more of these purposes.
Statutory authority: Texas Natural Resources Code, §§113.051
and 113.052.
Cross-reference to statute: Texas Natural Resources Code, Chapter 113.
Issued in Austin, Texas on June 10, 2003.
§9.206.Vehicle Identification Labels.
(a)
LP-gas shall not be introduced into any vehicle powered
by LP-gas and designed for regular use on public roadways unless the vehicle
is properly identified by a weather-resistant diamond-shaped label described
in NFPA 58,
§8.2.10
[
(b)-(c)
(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 June 10, 2003.
TRD-200303480
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: July 27, 2003
For further information, please call: (512) 475-1295
16 TAC §§9.301, 9.307, 9.311, 9.312
The amendments are proposed under the Texas Natural Resources
Code, §113.051, which authorizes the Commission to adopt rules relating
to any and all aspects or phases of the LP-gas industry that will protect
or tend to protect the health, welfare, and safety of the general public,
and §113.052, which authorizes the Commission to adopt by reference,
in whole or in part the published codes of the National Fire Protection Association
as standards to be met in the design, construction, fabrication, assembly,
installation, use, and maintenance of containers, tanks, appliances, systems,
and equipment for the transportation, storage, delivery, use, and consumption
of LP-gas or any one or more of these purposes.
Statutory authority: Texas Natural Resources Code, §§113.051
and 113.052.
Cross-reference to statute: Texas Natural Resources Code, Chapter 113.
Issued in Austin, Texas on June 10, 2003.
§9.301.Adoption by Reference of NFPA 54.
(a)
(No change.)
(b)
The Commission also adopts by reference all other NFPA
publications or portions of those publications referenced in NFPA 54 which
apply to LP-gas activities only. The adopted pamphlets referenced in NFPA
54 are:
(1)-(4)
(No change.)
(5)
NFPA 58,
Liquefied Petroleum Gas
Code
,
2001
[
(6)-(14)
(No change.)
§9.307.Identification of Converted Appliances.
(a)
In addition to the requirements of NFPA 54, §5.1.3,
and NFPA 58,
§2.6.2.1
[
(1)-(4)
(No change.)
(b)
(No change.)
§9.311.Special Exceptions for Agricultural and Industrial Structures Regarding Appliance Connectors and Piping Support.
(a)
In addition to the requirements of NFPA 54, §5.5.2
regarding gas hose connectors, agricultural structures, such as greenhouses
or broiler houses, or industrial structures not inhabited by humans may have
appliance connectors more than six feet in length provided that:
(1)
the hose used shall be marked as acceptable for LP-gas
service;
(2)
the hose shall comply with NFPA 58, §§
2.4.6.1
[
(3)-(4)
(No change.)
(b)-(c)
(No change.)
§9.312.Certification Requirements for Joining Methods.
(a)
In addition to the requirements in NFPA 54, §2.6.9,
and NFPA 58,
§2.4.4.3
[
(b)-(c)
(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 June 10, 2003.
TRD-200303481
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: July 27, 2003
For further information, please call: (512) 475-1295
16 TAC §§9.401 - 9.403
The amendments are proposed under the Texas Natural Resources
Code, §113.051, which authorizes the Commission to adopt rules relating
to any and all aspects or phases of the LP-gas industry that will protect
or tend to protect the health, welfare, and safety of the general public,
and §113.052, which authorizes the Commission to adopt by reference,
in whole or in part the published codes of the National Fire Protection Association
as standards to be met in the design, construction, fabrication, assembly,
installation, use, and maintenance of containers, tanks, appliances, systems,
and equipment for the transportation, storage, delivery, use, and consumption
of LP-gas or any one or more of these purposes.
Statutory authority: Texas Natural Resources Code, §§113.051
and 113.052.
Cross-reference to statute: Texas Natural Resources Code, Chapter 113.
Issued in Austin, Texas on June 10, 2003.
§9.401.Adoption by Reference of NFPA 58.
(a)
Except as modified in this subchapter, the Commission adopts
by specific reference the provisions established by the National Fire Protection
Association (NFPA) in its
2001
[
(b)
The Commission also adopts by reference all other NFPA
publications or portions of those publications referenced in NFPA 58,
§13.1.1
[
(1)-(2)
(No change.)
(3)
NFPA 30,
Flammable and Combustible
Liquids Code
,
2000
[
(4)-(8)
(No change.)
(9)
NFPA 59,
Utility LP-Gas Plant
Code
, 1999 edition
[
(10)-(15)
(No change.)
(16)
NFPA 220,
Standard on Types of Building Construction
, 1999 edition;
(17)
NFPA 251,
Standard Methods of Tests of Fire Endurance of Building Construction and Materials
, 1999 edition;
(18)
[
(19)
[
(20)
[
(21)
[
§9.402.Clarification of Certain Terms Used in NFPA 58.
(a)
Authority having jurisdiction. As pertains to LP-gas activities
in Texas, the phrase "authority having jurisdiction" defined in NFPA 58,
§1.7
[
(b)
(No change.)
§9.403.Sections in NFPA 58 Not Adopted by Reference, and Adopted with Changes, Additional Requirements, or Corrections.
(a)
Table 1 of this section lists certain NFPA 58 sections
which the Commission does not adopt because the Commission's corresponding
rules are more pertinent to LP-gas activities in Texas, or which the Commission
adopts with changed language or additional requirements in order to address
the Commission's existing rules, or with corrections listed in the Errata
dated
November 19, 2001
[
(b)
(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 June 10, 2003.
TRD-200303482
Mary Ross McDonald
Deputy General Counsel
Railroad Commission of Texas
Earliest possible date of adoption: July 27, 2003
For further information, please call: (512) 475-1295
Chapter 22.
PRACTICE AND PROCEDURE
Subchapter J. SUMMARY PROCEEDINGS
or
] certified
,
or overnight
mail direct to the commission in Austin by the surveying
company making the survey.
Department of Water Resources
], which may include zones that contain brackish or saltwater if such
zones are correlative and/or hydrologically connected to zones that contain
usable-quality water.
Texas Department of Water Resources
]. Before drilling any well in any
field or area in which no field rules are in effect or in which surface casing
requirements are not specified in the applicable field rules, an operator
shall obtain a letter from the
TCEQ
[
Texas Department of Water
Resources
] stating the protection depth. In no case, however, is surface
casing to be set deeper than 200 feet below the specified depth without prior
approval from the commission.
Natural Resource Conservation Commission (TNRCC) ].
TNRCC
] has jurisdiction
over solid waste under Chapter 361 of the Texas Health and Safety Code, §§361.001-361.754.
The
TCEQ's
[
TNRCC's
] jurisdiction encompasses both hazardous
and nonhazardous, industrial and municipal, solid wastes.
TNRCC
]
is defined to include "garbage, rubbish, refuse, sludge from a waste treatment
plant, water supply treatment plant, or air pollution control facility, and
other discarded material, including solid, liquid, semisolid, or contained
gaseous material resulting from industrial, municipal, commercial, mining,
and agricultural operations and from community and institutional activities."
TNRCC's
] jurisdiction) will not include hazardous wastes generated at
natural gas or natural gas liquids processing plants, or reservoir pressure
maintenance or repressurizing plants. The term natural gas or natural gas
liquids processing plant refers to a plant the primary function of which is
the extraction of natural gas liquids from field gas or fractionation of natural
gas liquids. The term does not include a separately located natural gas treating
plant for which the primary function is the removal of carbon dioxide, hydrogen
sulfide, or other impurities from the natural gas stream. A separator, dehydration
unit, heater treater, sweetening unit, compressor, or similar equipment is
considered a part of a natural gas or natural gas liquids processing plant
only if it is located at a plant the primary function of which is the extraction
of natural gas liquids from field gas or fractionation of natural gas liquids.
Further, a pressure maintenance or repressurizing plant is a plant for processing
natural gas for reinjection (for reservoir pressure maintenance or repressurization)
in a natural gas recycling project. A compressor station along a natural gas
pipeline system or a pump station along a crude oil pipeline system is not
a pressure maintenance or repressurizing plant.
TNRCC
] until the RRC is authorized
by EPA to administer RCRA. When the RRC is authorized by EPA to administer
RCRA, jurisdiction over such hazardous wastes will transfer from the
TCEQ
[
TNRCC
] to the RRC.
TNRCC
] is defined as "solid waste identified or listed as a hazardous
waste by the administrator of the United States Environmental Protection Agency
under the federal Solid Waste Disposal Act, as amended by the Resource Conservation
and Recovery Act of 1976, as amended (42 U.S.C. §6901, et seq.)." Similarly,
under Texas Natural Resources Code, §91.601(1), "oil and gas hazardous
waste" subject to the jurisdiction of the RRC is defined as an "oil and gas
waste that is a hazardous waste as defined by the administrator of the United
States Environmental Protection Agency under the federal Solid Waste Disposal
Act, as amended by the Resource Conservation and Recovery Act of 1976 (42
U.S.C. §6901, et seq.)."
TNRCC
] has jurisdiction
over discharges of waste into or adjacent to water in the state, other than
discharges regulated by the RRC. The RRC regulates discharges of waste from
activities associated with the exploration, development, or production of
oil, gas, or geothermal resources, including transportation of crude oil and
natural gas by pipeline, and from solution brine mining activities (except
solution mining activities conducted for the purpose of creating caverns in
naturally-occurring salt formations for the storage of wastes regulated by
the
TCEQ
[
TNRCC
] ) under Texas Natural Resources Code,
Title 3, and Texas Water Code, Chapter 26. Discharges of waste regulated by
the RRC into water in the state shall not cause a violation of the water quality
standards. While water quality standards are established by the
TCEQ
[
TNRCC
] , the RRC has the responsibility for enforcing any
violations of such standards. Texas Water Code, Chapter 26, does not require
that discharges regulated by the RRC comply with regulations of the
TCEQ
[
TNRCC
] that are not water quality standards. Because
of the complexity of 30 Texas Administrative Code §307.6 (concerning
toxic materials), the staffs of the
TCEQ
[
TNRCC
] and
the RRC will consult from time to time regarding application and interpretation
of the Texas Surface Water Quality Standards.
TNRCC
] as set forth in Texas Water Code, Chapter 27
(the Injection Well Act). The RRC has jurisdiction under Texas Water Code,
Chapter 27, over injection wells used to dispose of oil and gas waste. Texas
Water Code, Chapter 27, defines "oil and gas waste" to mean "waste arising
out of or incidental to drilling for or producing of oil, gas, or geothermal
resources, waste arising out of or incidental to the underground storage of
hydrocarbons other than storage in artificial tanks or containers, or waste
arising out of or incidental to the operation of gasoline plants, natural
gas processing plants, or pressure maintenance or repressurizing plants. The
term includes but is not limited to salt water, brine, sludge, drilling mud,
and other liquid or semi-liquid waste material." The term "waste arising out
of or incidental to drilling for or producing of oil, gas, or geothermal resources"
includes waste associated with transportation of crude oil or natural gas
by pipeline pursuant to Texas Natural Resources Code, §91.101. The
TCEQ
[
TNRCC
] has jurisdiction over injection wells used to
dispose of other types of waste.
TNRCC
] has jurisdiction over the disposal of NORM which
is not oil and gas NORM waste.
TNRCC
]. Further, stormwater runoff from terminal
facilities where both refined products intended for use offsite and crude
oil are stored in aboveground tanks is under the jurisdiction of the
TCEQ
[
TNRCC
]. Stormwater runoff from a terminal facility
where crude oil is stored prior to refining and at which refined products
are stored solely for use at the facility is under the jurisdiction of the
RRC.
TNRCC
].
TNRCC
] has jurisdiction
over waste from transportation of refined products by pipeline.
TNRCC
] also has jurisdiction
over wastes associated with transportation of crude oil and natural gas, including
natural gas liquids, by railcar, tank truck, barge, or tanker.
TNRCC
].
TNRCC
]. The processing of light ends from the distillation and cracking
of crude oil or crude oil products is considered to be a refining operation.
The term "refining" does not include the processing of natural gas or natural
gas liquids.
TNRCC
] shall have jurisdiction over wastes
resulting from these activities that are not exempt from federal hazardous
waste regulation under RCRA and that are considered hazardous under applicable
federal rules.
TNRCC
]. The term "manufacturing process" does not include
the processing (including fractionation) of natural gas or natural gas liquids
at natural gas or natural gas liquids processing plants.
TNRCC
] has jurisdiction
over wastes generated at facilities, other than actual exploration, development,
or production sites (field sites), where oil and gas industry workers are
trained. In addition, the
TCEQ
[
TNRCC
] has jurisdiction
over wastes generated at facilities where materials, processes, and equipment
associated with oil and gas industry operations are researched, developed,
designed, and manufactured. However, wastes generated from tests of materials,
processes, and equipment at field sites are under the jurisdiction of the
RRC.
TNRCC
] also has jurisdiction
over waste generated at commercial service company facilities operated by
persons providing equipment, materials, or services (such as drilling and
work over rig rental and tank rental; equipment repair; drilling fluid supply;
and acidizing, fracturing, and cementing services) to the oil and gas industry.
These wastes include the following wastes when they are generated at commercial
service company facilities: empty sacks, containers, and drums; drum, tank,
and truck rinsate; sandblast media; painting wastes; spent solvents; spilled
chemicals; waste motor oil; and unused fracturing and acidizing fluids.
TNRCC
] and the RRC encourage
generators to eliminate pollution at the source and recycle whenever possible
to avoid disposal of solid wastes. Questions regarding source reduction and
recycling may be directed to the
TCEQ Small Business and Environmental
Assistance Division, telephone number (800) 447-2827
[
TNRCC Office
of Pollution Prevention and Recycling (OPPR)/Clean Texas 2000, telephone number
(800) 64-TEXAS
], or to the Waste Minimization Program at the RRC. The
TCEQ
[
TNRCC
] reserves the right to require generators to
explore source reduction and recycling alternatives prior to authorizing disposal
of any waste under the jurisdiction of the RRC at a facility regulated by
the
TCEQ
[
TNRCC
] ; similarly, the RRC reserves the right
to require generators to explore source reduction and recycling alternatives
prior to authorizing disposal of any waste under the jurisdiction of the
TCEQ
[
TNRCC
] at a facility regulated by the RRC.
TNRCC
] OPPR and the RRC
Waste Minimization Program will meet at least two times each year to maintain
a working relationship to enhance the efforts to share information and use
resources more efficiently. The
TCEQ
[
TNRCC
] OPPR will
make the proper
TCEQ
[
TNRCC
] personnel aware of the
services offered by the RRC Waste Minimization Program, share information
with the RRC Waste Minimization Program to maximize services to oil and gas
operators, and advise oil and gas operators of RRC Waste Minimization Program
services. The RRC Waste Minimization Program will make the proper RRC personnel
aware of the services offered by the
TCEQ
[
TNRCC
] OPPR,
share information with the
TCEQ
[
TNRCC
] OPPR to maximize
services to industrial operators, and advise industrial operators of the
TCEQ
[
TNRCC
] OPPR services.
TNRCC's
] Petroleum Storage Tank
Division.
TNRCC
] regulated
soil treatment facilities once alternatives for recycling and source reduction
have been explored. For the purpose of this provision, soils containing petroleum
substance(s) as defined in 30 Texas Administrative Code §334.481 (concerning
definitions) are considered to be similar, but drilling muds, acids, or other
chemicals used in oil and gas activities are not considered similar. Generators
under the jurisdiction of the RRC must meet the same requirements as generators
under the jurisdiction of the
TCEQ
[
TNRCC
] when sending
their petroleum contaminated soils to soil treatment facilities under
TCEQ
[
TNRCC
] jurisdiction. Those requirements are in 30 Texas
Administrative Code §334.496 (concerning shipping procedures applicable
to generators of petroleum-substance waste), except subsection (c) which is
not applicable, and 30 Texas Administrative Code §334.497 (concerning
recordkeeping and reporting procedures applicable to generators). RRC generators
with questions on these requirements should call the
TCEQ
[
TNRCC
] Petroleum Storage Tank (PST) Division, Responsible Party Investigations
Section, telephone number (512) 239-2200.
TNRCC
] regulated soil treatment facilities
are required by 30 Texas Administrative Code §334.499 (concerning shipping
requirements applicable to owners or operators of storage, treatment, or disposal
facilities) to maintain documentation on the soil sampling and analytical
methods, chain-of-custody, and all analytical results for the soil received
at the facility and transported off-site or reused on-site.
TNRCC
]. The RRC may grant such authorizations
by rule, or on an individual basis through permits or other written authorizations.
TNRCC
] will
remain subject to the jurisdiction of the RRC. Such materials will be subject
to RRC regulations regarding final reuse, recycling, or disposal.
TNRCC
] waste codes and registration
numbers are not required for management of wastes under the jurisdiction of
the RRC at facilities registered by the PST Division of the
TCEQ
[
TNRCC
].
TNRCC
].
TNRCC
] once alternatives
for recycling and source reduction have been explored. The RRC must specifically
authorize management of wastes under its jurisdiction at facilities regulated
by the
TCEQ
[
TNRCC
]. The RRC may grant such authorizations
by rule, or on an individual basis through permits or other written authorizations.
In addition, except as provided in subparagraph (B) of this paragraph, the
concurrence of the
TCEQ
[
TNRCC
] is required to manage
waste under the jurisdiction of the RRC at a facility regulated by the
TCEQ
[
TNRCC
]. The
TCEQ's
[
TNRCC's
]
concurrence may be subject to specified conditions.
TNRCC
] may accept, without further individual concurrence, waste under
the jurisdiction of the RRC if that facility is permitted or otherwise authorized
to accept that particular type of waste. The phrase "that type of waste" does
not specifically refer to waste under the jurisdiction of the RRC, but rather
to the waste's physical and chemical characteristics.
TNRCC
] shall be required to manage wastes
under the jurisdiction of the RRC at
TCEQ
[
TNRCC
] regulated
facilities. (This is required only if the
TCEQ
[
TNRCC
]
regulated facility receiving the waste does not have approval to accept the
waste included in its permit or other authorization provided by the
TCEQ
[
TNRCC
].) To obtain an individual concurrence, the waste
generator must provide to the
TCEQ
[
TNRCC
] sufficient
information to allow the concurrence determination to be made, including the
identity of the proposed waste management facility, the process generating
the waste, the quantity of waste, and the physical and chemical nature of
the waste involved (using process knowledge and/or laboratory analysis as
defined in 30 Texas Administrative Code, Chapter 335, Subchapter R (concerning
waste classification)). In obtaining
TCEQ
[
TNRCC
] approval,
generators may use their existing knowledge about the process or materials
entering it to characterize their wastes. Material Safety Data Sheets, manufacturer's
literature, and other documentation generated in conjunction with a particular
process may be used. Process knowledge must be documented and submitted with
the request for approval.
TNRCC
] for the
beneficial use of sewage sludge or water treatment sludge. Domestic septage
collected from portable toilets at facilities subject to RRC jurisdiction
that is not mixed with other waste materials may be managed at a facility
permitted by the
TCEQ
[
TNRCC
] for disposal, incineration,
or land application for beneficial use of such domestic septage waste without
specific authorization from the
TCEQ
[
TNRCC
].
TNRCC
] may be issued
in the future.
TNRCC
] waste codes and registration
numbers are not required for management of wastes under the jurisdiction of
the RRC at facilities under the jurisdiction of the
TCEQ
[
TNRCC
]. If a receiving facility nevertheless requests or requires a
TCEQ
[
TNRCC
] waste code for waste under the jurisdiction
of the RRC, a code consisting of the following may be provided:
TNRCC
] waste generator registration number for wastes under the jurisdiction
of the RRC, the registration number "XXXRC" may be provided.
TNRCC's
] Industrial and
Hazardous Waste Division.
TNRCC
] jurisdiction at facilities regulated by the RRC.
TNRCC
]
may be disposed of, other than by injection into a Class II well, at a facility
regulated by the RRC; bioremediated at a facility regulated by the RRC (prior
to reuse, recycling, or disposal); or reclaimed at a crude oil reclamation
facility regulated by the RRC: nonhazardous wastes that are chemically and
physically similar to oil and gas wastes, but excluding soils, media, debris,
sorbent pads, and other clean-up materials that are contaminated with refined
petroleum products.
TNRCC
] are
authorized without further
TCEQ
[
TNRCC
] approval to
be disposed of at a facility regulated by the RRC, bioremediated at a facility
regulated by the RRC, or reclaimed at a crude oil reclamation facility regulated
by the RRC: nonhazardous bottoms from tanks used only for crude oil storage;
unused and/or reconditioned drilling and completion/workover wastes from commercial
service company facilities; used and/or unused drilling and completion/workover
wastes generated at facilities where workers in the oil and gas exploration,
development, and production industry are trained; used and/or unused drilling
and completion/workover wastes generated at facilities where materials, processes,
and equipment associated with oil and gas exploration, development, and production
operations are researched, developed, designed, and manufactured; unless other
provisions are made in the underground injection well permit used and/or unused
drilling and completion wastes (but not workover wastes) generated in connection
with the drilling and completion of Class I, III, and V injection wells; wastes
(such as contaminated soils, media, debris, sorbent pads, and other cleanup
materials) associated with spills of crude oil and natural gas liquids if
such wastes are under the jurisdiction of the
TCEQ
[
TNRCC
]; and sludges from washout pits at commercial service company facilities.
TNRCC
] may consider allowing injection
of wastes under the jurisdiction of the
TCEQ
[
TNRCC
]
into Class II injection wells permitted by the RRC.
TNRCC
] concurrence is required for injection of
TCEQ
[
TNRCC
]-regulated waste in connection with a secondary or
tertiary recovery project.
TNRCC
] will notify the Environmental Services Section of the Oil and Gas
Division of the RRC and the landfill owner at the time a drilling application
is submitted if an operator proposes to drill a well through a landfill regulated
by the
TCEQ
[
TNRCC
]. The RRC and the
TCEQ
[
TNRCC
] will cooperate and coordinate with one another in advising the
appropriate parties of measures necessary to reduce the potential for the
landfill contents to cause groundwater contamination as a result of landfill
disturbance associated with drilling operations.
TNRCC
] at a facility permitted by the RRC, the
TCEQ
[
TNRCC
] is responsible for enforcement actions against the generator
or transporter, and the RRC is responsible for enforcement actions against
the disposal facility. In the event that a generator or transporter disposes,
without proper authorization, of wastes regulated by the RRC at a facility
permitted by the
TCEQ
[
TNRCC
] , the RRC is responsible
for enforcement actions against the generator or transporter, and the
TCEQ
[
TNRCC
] is responsible for enforcement actions against
the disposal facility.
TNRCC
] and the RRC agree
to cooperate with one another by sharing enforcement information. Employees
of either agency who discover, in the course of their official duties, information
that indicates a violation of a statute, regulation, order, or permit pertaining
to wastes under the jurisdiction of the other agency, are encouraged to notify
the other agency. In addition, to facilitate enforcement actions, each agency
is encouraged to share information in its possession with the other agency
if requested by the other agency to do so.
TNRCC
] shall meet as necessary to attempt to resolve any disputes regarding
interpretation of this MOU and disputes regarding definitions and terms of
art. If a staff-level meeting fails to resolve the dispute, the dispute will
be elevated to the senior management of both agencies for resolution.
Natural Resource Conservation Commission
];
Water
Commission
].
Texas Water Commission
] stating the protection depth
or depths.
Texas Water Commission
] stating
the protection depth or depths must be attached.
(i)
Superconducting super collider.
No provision of this section exempts any operator from compliance with §3.78
of this title (relating to Drilling Operations in the Vicinity of the Superconducting
Super Collider, Ellis County) (Statewide Rule 82).]
§11.221
] of this title (relating to
Coal Mining
[
State Program
] Regulations) [
(Statewide Rules 816.331-816.333)
], and for
regulations governing uranium exploratory wells, see
Chapter 11, Subchapter
C
[
§§11.136-11.139
] of this title (relating to
Surface Mining and Reclamation Division, Substantive Rules--Uranium Mining
[
Notice of Exploration Involving Hole Drilling, Permit, Reclamation
and Plugging Requirements, and Reporting
]).
Water
Commission
].
(b)
Superconducting super collider.
No provision of this section exempts any operator from compliance with §3.78
of this title (relating to Drilling Operations in the Vicinity of the Superconducting
Super Collider, Ellis County) (Statewide Rule 82).]
(c)
] Exemption. Any seismic hole
or core hole drilled to a depth of 20 feet or less is not subject to the requirements
of this section.
(d)
] Determination of protection
depth. Before drilling any seismic hole or core hole in a project area, an
operator shall obtain a letter from the
TCEQ
[
Texas Water
Commission
] stating the protection depth or depths in the project area.
(e)
] Drilling permits.
(f)
] Plugging.
(g)
] Physical requirements for
bentonite plugging materials. Bentonite materials used to plug seismic or
core holes shall be derived from naturally occurring, untreated, high swelling
sodium bentonite that is composed of at least 85% montmorillonite clay and
that meets the International Association of Geophysical Contractors (IAGC)
recommended geophysical industry standard dated January 24, 1992, for the
physical characteristics of bentonite used in seismic shot hole plugging.
(h)
] Reporting.
(f)(1)
] of this section. The letter must include the plugging
date for each hole and the name and address of the operator. A plat of the
project area identifying seismic or core hole locations, counties, survey
lines, scale, and northerly direction must be attached. A United States Geological
Survey map of the project area with hole locations marked will satisfy the
plat requirement. In addition, a letter from the
TCEQ
[
Texas
Water Commission
] stating the protection depth or depths must be attached.
Chapter 9.
LP-GAS SAFETY RULES
(3)
] Aggregate water capacity (AWC)--The
sum of all individual container capacities measured by weight or volume of
water which are placed at a single installation location.
(4)
] Assistant director--The assistant
director of the LP-Gas Safety Section who is the Commission's delegate responsible
for the enforcement of the LP-Gas Safety Rules and the Texas Natural Resources
Code.
(5)
] Breakaway--The accidental separation
of a hose from a cylinder, container, transfer equipment, or dispensing equipment,
which could occur on a cylinder, container, transfer equipment, or dispensing
equipment whether or not they are protected by a breakaway device.
(6)
] Categories of LPG activities--The
LP-gas license categories as specified in §9.6 of this title (relating
to Licenses and Fees).
(7)
] Certified--Authorized to perform
LP-gas work as set forth in the Texas Natural Resources Code. Employee certification
alone does not allow an individual to perform those activities which require
licensing.
(8)
] CETP--The
Propane Education
and Research Council's
[
National Propane Gas Association's
]
Certified Employee Training Program.
(9)
] Commercial installation--An
LP-gas installation located on premises other than a single family dwelling
used as a residence, including but not limited to a retail business establishment,
school, bulk storage facility, convalescent home, hospital, retail LP-gas
cylinder filling/exchange operation, service station, forklift refueling facility,
private motor/mobile fuel cylinder filling operation, a microwave tower, or
a public or private agricultural installation.
(10)
] Commission--The Railroad
Commission of Texas.
(11)
] Company representative--The
individual designated to the Commission by a license applicant or a licensee
as the principal individual in authority and, in the case of a licensee other
than a Category P licensee, actively supervising the conduct of the licensee's
LP-gas activities.
(12)
] Container delivery unit--A
vehicle used by an operator principally for transporting LP-gas in cylinders.
(13)
] Continuing education--Courses
required to be successfully completed at least every four years by certain
certificate holders.
(14)
] DOT--The United States Department
of Transportation.
(15)
] Employee--An individual who
renders or performs any services or labor for compensation, including individuals
hired on a part-time or temporary basis, on a full-time or permanent basis,
or, for purposes of this chapter, an owner-employee.
(16)
] Interim approval order--The
authority issued by the Railroad Commission of Texas following a public hearing
allowing construction of an LP-gas installation.
(17)
] Licensed--Authorized to perform
LP-gas activities through the issuance of a valid license.
(18)
] Licensee--A person which
has applied for and been granted an LP-gas license by the Commission.
(19)
] LP-Gas Safety Rules--The
rules adopted by the Railroad Commission in the Texas Administrative Code,
Title 16, Part 1, Chapter 9, including any NFPA or other documents adopted
by reference. The official text of the Commission's rules is that which is
on file with the Secretary of State's office and available at www.sos.state.tx.us
or through the Commission's web site at www.rrc.state.tx.us.
(20)
] LP-gas system--All piping,
fittings, valves, and equipment, excluding containers and appliances, that
connect one or more containers to one or more appliances that use or consume
LP-gas.
(21)
] Mass transit vehicle--Any
vehicle which is owned or operated by a political subdivision of a state,
city, or county, used primarily in the conveyance of the general public.
(22)
] Motor fuel container--An
LP-gas container mounted on a vehicle to store LP-gas as the fuel supply to
an engine used to propel the vehicle.
(23)
] Motor fuel system--An LP-gas
system, excluding the container, which supplies LP-gas to an engine used to
propel the vehicle.
(24)
] Noncorrosive--Corrosiveness
of gas which does not exceed the limitation for Classification 1 of the American
Society of Testing Material (ASTM) Copper Strip Classifications when tested
in accordance with ASTM D 1834-64, "Copper Strip Corrosion of Liquefied Petroleum
(LP) Gases."
(25)
] Nonspecification unit--An
LP-gas transport not constructed to DOT MC-330 or MC-331 specifications but
which complies with the exemption in 49 Code of Federal Regulations §173.315(k).
(See also "Specification unit" in this section.)
(26)
] Operations supervisor--The
individual who is certified by the Commission to actively supervise a licensee's
LP-gas operations.
(27)
] Outlet--A site operated by
an LP-gas licensee at which the business conducted materially duplicates the
operations for which the licensee is initially granted a license.
(28)
] Outside instructor--An individual
other than a Commission employee approved by the Commission to teach
certain
[
an
] LP-gas
training or
continuing education
courses
[
course
].
(29)
] Person--An individual, partnership,
firm, corporation, joint ventureship, association, or any other business entity,
a state agency or institution, county, municipality, school district, or other
governmental subdivision, or licensee, including the definition of "person"
as defined in the applicable sections of 49 CFR relating to cargo tank hazardous
material regulations.
(30)
] Portable cylinder--A receptacle
constructed to DOT specifications, designed to be moved readily, and used
for the storage of LP-gas for connection to an appliance or an LP-gas system.
The term does not include a cylinder designed for use on a forklift or similar
equipment.
(31)
] Property line--The boundary
which designates the point at which one real property interest ends and another
begins.
(32)
] Public transportation vehicle--A
vehicle for hire to transport persons, including but not limited to taxis,
buses (excluding school buses and mass transit or special transit vehicles),
or airport courtesy vehicles.
(33)
] Register (or registration)--The
procedure to inform the Commission of the use of an LP-gas transport or container
delivery unit in Texas.
(34)
] Repair to container--The
correction of damage or deterioration to an LP-gas container, the alteration
of the structure of such a container, or the welding on such container in
a manner which causes the temperature of the container to rise above 400 degrees
Fahrenheit.
(35)
] Rules examination--The Commission's
written examination that measures an examinee's working knowledge of Chapter
113 of the Texas Natural Resources Code and/or the current LP-Gas Safety Rules.
(36)
] School--A public or private
institution which has been accredited through the Texas Education Agency or
the Texas Private School Accreditation Commission.
(37)
] School bus--A vehicle that
is sold or used for purposes that include carrying students to and from school
or related events.
(38)
] Special transit vehicle--A
vehicle designed with limited passenger capacity which is used by a school
or mass transit authority for special transit purposes, such as transport
of mobility impaired persons.
(39)
] Specification unit--An LP-gas
transport constructed to DOT MC-330 or MC-331 specifications. (See also "Nonspecification
unit" in this section.)
(40)
] Subframing--The attachment
of supporting structural members to the pads of a container, excluding welding
directly to or on the container.
(41)
] Trainee--An individual who
has not yet taken and passed an employee-level rules examination.
(42)
] Training--Courses required
to be successfully completed as part of an individual's requirements to obtain
or maintain
certain [
new
] certificates.
(43)
] Transfer--The procedure to
inform the Commission of a change in operator of an LP-gas transport or container
delivery unit already registered with the Commission.
(44)
] Transfer system--All piping,
fittings, valves, and equipment utilized in dispensing LP-gas between containers.
(45)
] Transport--Any bobtail or
semitrailer equipped with one or more containers.
(46)
] Transport system--Any and
all piping, fittings, valves, and equipment on a transport, excluding the
container.
(47)
] Ultimate consumer--The individual
controlling LP-gas immediately prior to its ignition.
$25
] annual certificate 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.
An employee of a state agency, county, municipality,
school district, or other governmental subdivision is not required to pay
the annual certificate renewal fee.
$25
] annual renewal fee plus a $20
late-filing fee. Failure to do so shall result in the expiration of the certificate.
If an individual's certificate has been expired for more than two years
from May 31 of the year in which certification lapsed
, that individual
shall comply with the requirements for a new certificate.
E or I
] management-level
certificates and certain employee-level certificates.
Table 1
of
] §9.52 of this title (relating to Training and Continuing Education
Courses); and
courses
] shall receive credit only if they attend the entire
class,
properly complete any AFT, and pay any training or continuing education course
fees in full
[
course and complete any required AFT
]. The
Commission shall not award partial credit for partial attendance.
all
] Commission LP-gas training and continuing education
classes
can be obtained
[
courses/seminars shall be available
] in
the Austin offices of the Gas Services Division and AFRED, [
at certain
Commission district offices,
] and on the Commission's web site at www.rrc.state.tx.us
and shall be updated
monthly
[
February 1 and June 1 of each
year
]. Commission
classes
[
courses
] shall be conducted
in Austin and in other locations around the state. Individuals or companies
may request in writing that Commission
classes
[
courses
]
be taught in their area. The Commission shall schedule its
classes
[
courses
] and locations at its discretion.
course
].
course
], an individual shall complete the registration
form provided by AFRED and file the form with the AFRED training section [
at least seven calendar days
] prior to the
class
[
course
]. AFRED shall also accept
class
[
course
] registrations
via regular mail, electronic mail
(e-mail)
, or facsimile transmission
(fax)
; such requests shall include the applicant's full name, address,
phone number,
level (either manager or employee) and category of certification
(such as cylinder filling or service and installation), e-mail
[
electronic mail
] address, and the name
or number, location,
and
date of the requested
class
[
course
].
courses
].
(B)
] Continuing education
classes
[
courses, other than courses P115, P116, and P117,
]
shall be offered at no charge to certificate holders who have timely paid
the annual certificate renewal fee specified in §9.9 of this title (relating
to Requirements for Certificate Renewal).
(C)
] The Commission may charge reasonable
fees for materials for
classes
[
GAS Check or similar courses
] using third-party materials.
courses
] on a first-come, first-served basis
, except as follows:
[
.
]
course
]
has fewer than eight individuals registered within seven calendar days prior
to the
class
[
course
], the Commission may cancel the
class
[
course
] and shall
either
refund any
class
[
course
] registration fees
or shall reschedule
the registered individuals in another class agreed upon by the individuals
and the AFRED training section. The AFRED training section reserves the right
to determine class sizes for all classes
.
course
] at the time and place for which the
individual is registered due to illness or other unforeseen circumstances,
another individual from the same company may attend that same
class
[
course
] in his or her place.
courses
]
offered by an entity other than the Commission shall comply with the registration,
fee, and other requirements specified by that entity.
employees
] shall be responsible for promptly notifying
the AFRED training section
in writing
of any discrepancies or errors
in the training or continuing education records, and shall notify the LP-Gas
Safety Section
of any
[
for
] discrepancies or errors
in examination records
or certification cards
. In the event of
a discrepancy, the Commission's records
, including due dates,
shall
be deemed correct unless the individual has copies of applicable documents
which clarify the discrepancy.
license or certificate
] listed in this subsection, other than Category
E
, F, G,
or I management-level individuals and except as stated
in paragraph (4) of this subsection, shall attend at least eight hours of
training prior to their first certificate renewal deadline of May 31
of the appropriate
[
the following
] year. Applicants for Category
D, E, F, G, I, J, or K
[
E or I
] management-level
certification
shall attend the course or courses specified for the category.
Category E applicants shall attend the 80-hour class; Category F, G, and I
applicants shall attend the 16-hour class; and all other applicants shall
attend an eight-hour class.
(A)
] Category E management-level;
(B)
] Category I management-level;
(C)
] Delivery truck employee-level;
(D)
] DOT portable cylinder filler
employee-level;
(E)
] Service and Installation employee-level;
[
and
]
(F)
] Motor/mobile fuel dispensing
employee-level.
for the license applicant
].
and AFT
]. Individuals who
pass an employee-level rules examination at other times shall have until the
next May 31 to complete any required training [
and AFT
].
Completion of AFT shall be in accordance with subsection (f) of this section.
§9.17(e)
] of this title (relating to Designation and
Responsibilities of Company Representatives and Operations Supervisors) shall
comply with the training requirements in this section prior to the Commission
issuing a certificate.
Attendance at more than eight hours of continuing
education prior to a deadline shall not count toward the fulfillment of this
requirement for any subsequent four-year period and shall not extend the deadline.
]
As soon as practicable after the effective date of
this rule, the Commission shall randomly assign each certified individual
a continuing education deadline date. One-fourth of the certified individuals
shall be assigned a deadline date of May 31, 2002, and equal numbers of the
remaining certified individuals shall be assigned deadline dates of May 31,
2003, May 31, 2004, and May 31, 2005.
] Individuals
completing
[
who complete
] their continuing education requirements [
by the year
randomly assigned
] shall then have [
an additional
] four years
to complete the next eight-hour continuing education requirement
(unless
a new certification is added that requires training as specified in subparagraph
(B) of this paragraph)
.
course
]:
(i)
] Category E management-level;
(ii)
] Category I management-level;
(iii)
] Delivery truck employee-level;
(iv)
] DOT portable cylinder filler
employee-level;
(v)
] Service and Installation employee-level;
[
and
]
(vi)
] Motor/mobile fuel dispensing
employee-level.
(B)
] Certificate holders who are
certified to perform LP-gas activities covered by different certifications
shall complete the continuing education requirements for any one of the certifications
held in order to maintain active status. For each subsequent continuing education
requirement, such individuals shall
be responsible for attending
[
attend
] a different continuing education
class
[
course
] relevant to one of the other certifications held.
course
] offered by an outside instructor shall not be entitled to a
refund of the annual renewal fee or any other fees or penalties required by
the Commission.
courses
] free of charge, but may
request from the AFRED training section to attend
classes
[
courses
] at the charge specified in §9.51 of this title (relating
to General Requirements for Training and Continuing Education). Such requests
shall be in writing and handled at AFRED's discretion on an individual basis
and if space is available in the requested
class
[
course
].
Any employee of a state agency, county, municipality, school district, or
other governmental subdivision is not required to pay the fee.
continuing education course
] may voluntarily
attend a
class
[
continuing education course
], if space
is available, by registering with the AFRED training section as specified
in §9.51 of this title (relating to General Requirements for Training
and Continuing Education).
(c)
]
Class
[
course
] materials. Individuals who attend Commission-taught
classes
[
courses
] shall receive a copy of the
class
[
course
]
materials at no charge. Additional copies may be purchased from the Commission
at
the established price
[
a reasonable charge
].
(d)
] Certificates of completion.
The AFRED training section shall issue a certificate of completion to each
individual who completes a Commission-taught
class
[
course
]. Individuals shall retain the certificates as proof of completion
of the
class
[
course
].
(e)
] Advanced field training
(AFT)
. Some
classes
[
courses
] may include AFT
in addition to the [
course
] classroom hours, during which
class
[
course
] attendees shall perform LP-gas activities.
AFT shall be
properly
completed
within 30 calendar days of
attending the class. All qualification tasks included in the AFT shall be
completed. The AFT materials, including the qualification checklist and the
certification page, shall be readily available at the licensee's Texas business
location for review by an authorized Commission representative during normal
business hours.
[
and the individual responsible for certifying
the AFT shall return the AFT certification within a reasonable time following
the completion of the classroom hours and prior to the individual's certificate
renewal date in accordance with subsection (a)(3) of this section.
]
certified
] as being successfully completed
, and the
AFT form signed
as follows:
A
] Commission-approved
outside instructor may certify any AFT.
(2)
] Individuals who attend the
80-hour
Category E [
80-hour
] management-level
class
[
course
] or the
16-hour
Category
F, G, or
I [
16-hour
] management-level
class
[
course
] shall perform any required AFT activities during the
class
[
course
]. [
The Commission instructor shall certify the AFT.
]
(3)
] If AFT is required for a
class
[
course
], the AFT checklist outlining the specific
activities to be performed shall be included in the
class
[
course
] materials.
Table 1
] of this subsection. Items on the
tables
[
table
] marked with an "x" indicate courses that meet training or continuing
education requirements for management-level or employee-level certificate
holders in that category.
randomly
] assigned by the
Commission as described in §9.52(b) of this title (relating to Training
and Continuing Education Courses) if the individual completed one or more
of the following:
courses
].
An individual who attended a Commission
class
[
course
]
on or after September 1, 1997, shall receive credit as shown in the
tables
[
table
] in §9.52(g) of this title (relating to
Training and Continuing Education Courses) for a
class
[
course
] if it is directly related to the LP-gas activities authorized by that
individual's certificate.
on or after
]
September 1, 1997,
and September 1, 2003,
shall receive credit
as shown in the
tables
[
table
] in §9.52(g) for
up to two courses, for a total of eight hours, if the courses were applicable
to the individual's LP-gas activities. An individual who has received credit
for a computer-based course shall attend a classroom-based course the next
time that individual is required to attend a continuing education course.
courses
]. An individual
who has attended a CETP
class
[
course
] on or after September
1, 1997, shall receive credit as shown in the
tables
[
table
] in §9.52(g) if the
class
[
course
] applies
directly to the LP-gas activities authorized by the individual's certificate.
Individuals wishing to receive credit for a CETP
class
[
course
] shall submit to the AFRED training section, in writing, the individual's
name, address, phone number, [
valid
] Social Security number,
current LP-gas certification,
CETP
class
[
course
]
date, and a copy of the CETP certificate for an equivalent CETP
class
[
course
] as follows:
or new employees'
training credit for courses
] offered by an outside instructor provided
the outside instructor complies with the requirements of this section.
courses
], an outside instructor shall
renew his or her Commission approval every three years by paying a $150 renewal
fee to the Commission
and attending a Train-the-Trainer refresher class
prior to the outside instructor's next renewal deadline
. [
An outside
instructor who is renewing his or her approval shall not be required to attend
the Train-the-Trainer Course again, provided that the outside instructor has
conducted at least one Commission-approved LP-gas course within the 12 months
immediately prior to the month in which a renewal would become effective.
]
substantively
] revises any course materials previously approved
by the Commission shall submit the revisions in writing, along with a $100
review fee to the Commission, and shall not use the materials in a course
until the outside instructor has received written Commission approval. The
Commission shall review the revised course materials and, within 14 business
days, shall notify the outside instructor in writing that the revised course
materials are approved or not approved. If the revised course materials are
not approved, the Commission's notice shall identify the portion or portions
that are not approved and/or shall describe any deficiencies in the revised
course materials. The outside instructor shall file any necessary additional
information within 30 calendar days of the date of the Commission's notice
of disapproval. The outside instructor's failure to file the necessary additional
information within the prescribed time period may result in the dismissal
of the outside instructor's request for approval of revised course materials
and the necessity of again paying the $100 review fee for each subsequent
filing of revised course materials.
course
] presentations; and
course
] the names, social
security numbers, and any other information required by the Commission, of
the persons completing the
class
[
course
]. The report
shall be made by electronic mail (e-mail) in an electronic format provided
by the Commission. The outside instructor shall ensure that the Commission
receives the report by securing written acknowledgment of its receipt by the
Commission. This acknowledgement may be by return electronic mail (e-mail)
or by facsimile transmission (fax)
.
courses
] they teach, including
the location, schedule, date, time, duration, price, content, material, demeanor
and conduct of the outside instructor, and reporting of attendance information.
The Commission shall not monitor or supervise the actual
class
[
course
] presentations by outside instructors. The Commission is not
obligated to gather, maintain, or distribute information about outside instructors'
course offerings, other than the names, telephone numbers, and addresses of
approved outside instructors and the date on which an outside instructor's
approval would expire, absent renewal. The Commission may refuse to issue
or renew a certificate for an individual who presents for Commission credit
an unapproved
class
[
course
]; a
class
[
course
] taught by an unapproved outside instructor; or a
class
[
course
] taught using unapproved, incomplete, or incorrect
materials.
Chapter 9.
LP-GAS SAFETY RULES
§3-2.2.3
], prior to the installation of any individual LP-gas container,
the Commission shall determine whether the proposed installation constitutes
a danger to the public health, safety, and welfare.
§1-3
].
§2-2.2.2
] and
§2.3.2.3
[
§2-3.2.3
], 200 psig
working pressure stationary vessels in LP-gas service in Texas prior to September
1, 1981, may be continued in service for commercial propane provided that
they are fitted with pressure relief valves set for 250 psig normal start
to discharge and comply with other provisions of this chapter. For the purpose
of this section, "commercial propane" is defined as having a vapor pressure
not in excess of 210 psig at 100 degrees Fahrenheit. This section does not
apply to LP-gas motor fuel and mobile fuel containers.
§2-2.1.4
], a licensee or the licensee's employees shall not introduce LP-gas
into any container or cylinder if the licensee or employee has knowledge or
reason to believe that such container, cylinder, piping, or the system or
the appliance to which it is attached is unsafe or is not installed in accordance
with the statutes or the
LP-Gas Safety Rules
.
§8-3
].
§2-2.1.5
], before filling a DOT cylinder, the individual filling the cylinder
shall examine the cylinder. Where the cylinder is found to be dented or bulged,
where the metal is gouged, or where there is evidence of corrosion which substantially
reduces the integrity of the cylinder, such cylinder shall not be filled.
§§3-3.6, 3-4.2.4,
3-9.3.6, 4-2.3.8, 5-2.1.1, and 5-4.2.1
], fencing at LP-gas installations
shall comply with the following:
§3-2.4.1(c), §3-2.4.8(a),
(b), and (d), §3-2.4.9(d), §3-3.6, §3-9.3.8, and §5-4.2.1
], guardrails at LP-gas installations, except as noted in subsection
(a) of this section, shall comply with the following:
§5-4.2.2
], storage racks used to store nominal 20-pound DOT portable
or any size forklift containers shall be protected against vehicular damage
by:
§3-2.4.1(f)
], containers shall be painted as follows:
§3-9.4.2
], each LP-gas private or public motor/mobile or forklift
refueling installation which includes a liquid dispensing system shall incorporate
into that dispensing system a breakaway device. Any vapor return hose installed
at such installations shall also be equipped with a breakaway device. LP-gas
installations at which forklift cylinders are completely removed from the
forklift before being filled are not required to have a breakaway device.
§2-2.6.1
], all containers shall be numbered in accordance with
the requirements set forth in Table 1 of §9.140 of this title (relating
to Uniform Protection Standards).
§3-2.2.9
], no canopies or coverings are allowed over any LP-gas
container or over loading and unloading areas where LP-gas transport transfer
operations are performed. Non-combustible wind breaks and other weather protection
may be installed to provide employees and customers protection against the
elements of weather, but shall not be installed over any portion of an LP-gas
container.
§3-2.2
] and the entries for
§3.2.2.7
[
§3-2.2.7
] and
§5.4.1
[
§5-4.1
] as indicated in the table in §9.403 of this title (relating to
Sections in NFPA 58 Not Adopted by Reference, and Adopted with Changes, Additional
Requirements, or Corrections) and any other applicable requirements in NFPA
58 or the
LP-Gas Safety Rules
.
§3-2.2
], or a minimum distance of 15 feet
if the storage container is less than 125 gallons water capacity.
§3-2.10.11
], effective February 1, 2001, new stationary LP-gas installations with
individual or aggregate water capacities of 4,001 gallons or more, including
licensee and nonlicensee locations, shall install a vertical bulkhead and
pneumatically-operated internal valves and pneumatically-operated emergency
shutoff valves (ESVs), as required in this section and in the table in §9.403
of this title (relating to Sections in NFPA 58 Not Adopted by Reference, and
Adopted With Changes, Additional Requirements, or Corrections) for NFPA 58
, §§3.2.18.1, 3.3.3.6, and 3.11.3
[
sections 3-2.11, 3-3.3.7,
and 3-11.3
].
The filling of a container solely through a 1 3/4
inch double back check filler valve, directly installed in the container,
is exempt from the requirements of this section.
§2-4.4
] and shall direct the transfer hose
from vertical to prevent binding or kinking of the hose.
§2-3.3.2
] as amended in the table in §9.403 of this title
(relating to Sections in NFPA 58 Not Adopted by Reference, and Adopted with
Changes, Additional Requirements, or Corrections), ESVs and internal valves
shall have emergency remote controls conspicuously marked according to the
requirements of Table 1 of §9.140 of this title (relating to Uniform
Protection Standards). Effective February 1, 2001, for all new facilities,
where a bulkhead, internal valves, and ESVs are installed, at least one clearly
identified and easily accessible manually operated remote emergency shutoff
device shall be located between 20 and 100 feet from the ESV in the path of
egress from the ESV. Existing installations shall comply by August 1, 2001.
The use of swivel-type piping as specified in subsection (d)(8) of this section
shall not eliminate the requirement for an ESV. Swivel- type piping may be
installed between the bulkhead and the minimum 12-inch nipple, but shall not
eliminate the requirement for an ESV. The swivel-type piping shall be installed
and maintained according to the manufacturer's instructions.
24
] inches in length or less, and shall comply with all applicable
Subchapter C. VEHICLES AND VEHICLE DISPENSERS
§8-2.10
], as that section
is amended in Table 1 of §9.403 of this title (relating to Sections in
NFPA 58 Not Adopted by Reference, and Adopted With Changes, Additional Requirements,
or Corrections).
Subchapter D. ADOPTION BY REFERENCE OF NFPA 54 (NATIONAL FUEL GAS CODE)
1998
] edition;
§2-6.2.1
], upon completion
of the conversion and testing of LP-gas appliances, the licensee shall attach
to each such appliance a decal or tag of metal or other permanent material
indicating the following information:
2-4.6.1
] through
2.4.6.3
[
2-4.6.3
];
§2-4.4.1(c)(4)
], and
in addition to other LP-gas certification requirements, prior to performing
heat-fusion on polyethylene pipe or tubing, an individual shall be certified
by either the Commission or a person or certification school authorized by
the Commission. The certification shall confirm that the individual has a
working knowledge of heat-fusion methods and the ability to properly perform
the heat-fusion activity.
Subchapter E. ADOPTION BY REFERENCE OF NFPA 58 (LP-GAS CODE)
1998
] edition of the
February 1, 2001
]. Nothing in this section
or subchapter shall prevent the Commission, after notice, from adopting additional
requirements, whether more or less stringent, for individual situations to
protect the health, safety and welfare of the general public. Any documents
or parts of documents incorporated by reference into these rules shall be
a part of these rules as if set out in full.
§12-1.1
], which apply to LP-gas activities
only. The adopted pamphlets referenced in NFPA 58 are:
1996
] edition;
Standard for
the Storage and Handling of Liquefied Petroleum Gases at Utility Gas Plants
, 1998 edition
];
(16)
] NFPA 302,
Fire Protection Standard for Pleasure and Commercial Motor Craft
, 1998
edition;
(17)
] NFPA 501A,
Standard for Fire Safety Criteria for Manufactured Home Installations, Sites,
and Communities
,
2000
[
1999
] edition;
(18)
] NFPA 505,
Fire Safety Standard for Powered Industrial Trucks Including Type Designations,
Areas of Use, Conversions, Maintenance, and Operation
, 1999 edition;
(19)
] NFPA 1192,
Standard on Recreational Vehicles
, 1999 edition.
§1-6
], and referenced in other NFPA publications
shall be the Railroad Commission of Texas or any of its divisions or employees,
except with respect to the definitions of "approved," [
"engineering,"
] "labeled," and "listed" in NFPA 58,
§1.7
[
§1-6
].
June 1, 1998
], issued by NFPA
to correct typographical or other errors in the published NFPA 58 pamphlet.
According to NFPA, these errors may be corrected in future printings.
Part 2.
PUBLIC UTILITY COMMISSION OF TEXAS