28770 Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations

(c) The authorized bandwidth for

emission type F3E transmitted by a FRS

unit is 12.5 kHz.

10. Newly redesignated § 95.633 is

amended by revising paragraph (b) to

read as follows:

§ 95.633 Unwanted radiation.

* * * * *

(b) The power of each unwanted

emission shall be less than TP as

specified in the applicable paragraph:

Transmitter Emission type Applicable

paragraphs

GMRS .................................................... A1D, A3E, F1D, G1D, F3E, G3E with filtering .................................................... (1), (3), (7)

A1D, A3E, F1D, G1D, F3E, G3E without filtering ............................................... (5), (6), (7)

H1D, J1D, R1D, H3E, J3E, R3E ......................................................................... (2), (4), (7)

FRS ....................................................... F3E with filtering .................................................................................................. (1), (3), (7)

Note: Filtering refers to the requirement in § 95.635(b) R/C:

27 MHz band ......................................... As specified in § 95.629(b) .................................................................................. (1), (3), (7)

72–76 MHz band ................................... As specified in § 95.629(b) .................................................................................. (1), (3), (7), (10), (11),

(12)

CB .......................................................... A1D, A3E ............................................................................................................. (1), (3), (8), (9)

H1D, J1D, R1D, H3E, J3E, R3E ......................................................................... (2), (4), (8), (9)

A1D, A3E type accepted before September 10, 1976 ........................................ (1), (3), (7)

H1D, J1D, R1D, H3E, J3E, R3E type accepted before September 10, 1986 .... (2), (4), (7)

* * * * *

11. Newly redesignated § 95.635 is

amended by revising paragraph (a) to

read as follows:

§ 95.635 Modulation standards.

(a) A GMRS transmitter that transmits

emission types F1D, G1D, or G3E must

not exceed a peak frequency deviation

of plus or minus 5 kHz. A GMRS

transmitter that transmits emission type

F3E must not exceed a peak frequency

deviation of plus or minus 5 kHz. A FRS

unit that transmits emission type F3E

must not exceed a peak frequency

deviation of plus or minus 2.5 kHz, and

the audio frequency response must not

exceed 3.125 kHz .

* * * * *

12. Newly redesignated § 95.637 is

amended by adding a new paragraph (d)

to read as follows:

§ 95.637 Maximum transmitter power.

* * * * *

(d) No FRS unit, under any condition

of modulation, shall exceed 0.500 W

effective radiated power (ERP).

13. Newly redesignated § 95.645 is

revised to read as follows:

§ 95.645 FRS unit and R/C transmitter

antennas.

The antenna of each FRS unit, and the

antenna of each R/C station transmitting

in the 72–76 MHz band, must be an

integral part of the transmitter. The

antenna must have no gain (as

compared to a half-wave dipole) and

must be vertically polarized.

14. Newly redesignated § 95.647 is

revised to read as follows:

§ 95.647 Power capability.

No CB or R/C station transmitter or

FRS unit shall incorporate provisions

for increasing its transmitter power to

any level in excess of the limit specified

in § 95.637.

15. Newly redesignated § 95.649 is

revised to read as follows:

§ 95.649 Crystal control required.

All transmitters used in the Personal

Radio Services must be crystal

controlled, except an R/C station that

transmits in the 26–27 MHz frequency

band, and a FRS unit.

16. Appendix 1 to Subpart E is

amended by adding the definition for

‘‘FRS’’, in alphabetical order, to read as

follows:

Appendix 1 To Subpart E-Glossary of Terms

* * * * *

FRS. Family Radio Service.

* * * * *

[FR Doc. 96–14140 Filed 6–5–96; 8:45 am]

BILLING CODE 6712–01–P

DEPARTMENT OF TRANSPORTATION

Research and Special Programs

Administration

49 CFR Part 192

[Docket PS–124; Amdt. 192–76]

RIN 2137–AC25

Regulatory Review; Gas Pipeline

Safety Standards

AGENCY: Research and Special Programs

Administration (RSPA), DOT.

ACTION: Final rule.

SUMMARY: This final rule changes

miscellaneous gas pipeline safety

regulations to provide clarity, eliminate

unnecessary or burdensome

requirements, and foster economic

growth. The changes result from a

comprehensive review of the regulations

RSPA has completed under President

Clinton’s Regulatory Reinvention

Initiative to reduce the burden of

government regulations. The changes

are intended to reduce the costs of

compliance without compromising

safety.

EFFECTIVE DATE: This final rule is

effective July 8, 1996. The incorporation

by reference of certain publications

listed in the regulations is approved by

the Director of the Federal Register as of

July 8, 1996.

FOR FURTHER INFORMATION CONTACT: A.

C. Garnett, (202) 366–2036, or L. M.

Furrow, (202) 366–4559, regarding the

subject matter of this amendment, or the

Dockets Unit, (202) 366–5046 regarding

copies of this amendment or other

material in the docket.

SUPPLEMENTARY INFORMATION:

Background

Early in 1992, RSPA began an

extensive review of the federal gas

pipeline safety regulations (49 CFR part

192) and invited the public to

participate (57 FR 4745, Feb. 7, 1992).

The review was to see what changes

were necessary to provide clarity,

eliminate unnecessary or overly

burdensome requirements, and foster

economic growth. As a result of the

review, RSPA published a Notice of

Proposed Rulemaking (NPRM),

proposing changes to 38 regulations in

part 192 (Notice 1; 57 FR 39572, Aug.

31, 1992).

Then the National Association of

Pipeline Safety Representatives

(NAPSR) reported on a separate but

related review of part 192. RSPA had

asked NAPSR to identify regulations in

part 192 that may not assure safety or
Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations 28771

that may be hard to enforce. Because the

NAPSR report concerned a few of the

regulations covered by the NPRM and

had similar goals, we published the

report and requested public comment

on its various recommended rule

changes (Notice 2; 58 FR 59431, Nov. 9,

1993). At the same time, we announced

that in developing final rules under the

NPRM, we would consider comments

on any NAPSR recommendations that

addressed the same issues as the NPRM.

The period for public comment on the

NAPSR recommendations was extended

90 days until April 11, 1994 (Notice 3;

58 FR 68382, Dec. 27, 1993).

Later on, President Clinton launched

the Regulatory Reinvention Initiative

(memorandum for Heads of

Departments and Agencies; March 4,

1995), which, among other things,

directed DOT and other Federal

agencies to review and revise existing

regulations to remove unnecessary or

burdensome requirements. Today’s

publication of this Final Rule is a major

step in carrying out that directive with

respect to DOT’s pipeline safety

regulations.

Advisory Committee

The Technical Pipeline Safety

Standards Committee (TPSSC),

consisting of 15 members, was

established by statute to consider the

feasibility, reasonableness, and

practicability of proposed pipeline

safety regulations. In developing the

final regulations, RSPA considered all

final TPSSC votes and comments on the

NPRM, including minority positions. A

more detailed consideration of the

TPSSC action is contained in the

following section-by-section discussion

of comments. A record of the TPSSC

deliberation is available in the docket.

Discussion of Comments

RSPA received comments on the

NPRM from 36 pipeline operators, 9

pipeline-related associations, 1 state

agency, and 8 other commenters. More

commenters submitted views on the

NAPSR recommendations: 58 pipeline

operators, 10 pipeline-related

associations, 4 state agencies, and 5

other commenters.

The following discussion on

development of the final rules explains

how we treated TPSSC positions,

comments on the NPRM, and comments

on NAPSR recommendations related to

NPRM proposals (§§ 192.3, 192.475,

192.485, and 192.607). We appreciate

the comments on NAPSR

recommendations that were not related

to NPRM proposals. They will help us

decide appropriate responses to those

recommendations in an action separate

from this rulemaking.

Small Gas Systems. The NPRM

invited comments on the idea of

whether RSPA should develop separate,

more appropriate safety standards for

small gas distribution systems. Such

systems include master meter systems

and petroleum gas systems serving

mobile home or apartment complexes.

Although TPSSC did not address this

matter, RSPA received comments from

two pipeline operators, one state

agency, and one mobile home

association. The state agency said that it

is not clear that separate regulations are

required. This commenter suggested

that a less complicated remedy might be

to excerpt those portions of the

regulations specifically applicable to

small operators (deleting, for example,

sections applicable to transmission

lines) and publish the result as a guide

or as instructional material.

Three commenters supported the

need for more appropriate standards for

small gas distribution systems. A mobile

home association endorsed the idea of

developing standards for small gas

distribution systems, such as mastermeter systems serving mobile home

parks, and publishing the standards as

a new part of title 49 of the Code of

Federal Regulations. The mobile home

association commented that if it were

not for the Guidance Manual for

Operators of Small Gas Systems

published by RSPA, the average mobile

home park operator would have

difficulty determining which

regulations in part 192 apply to mastermeter systems.

RSPA believes that each of the

suggestions has merit and will be useful

in developing future pipeline safety

agendas.

Section 192.1, Scope of Part

Section 192.1(b)(1) excepts from the

scope of part 192 certain gathering lines

on the outer continental shelf (OCS), but

does not except similar gathering lines

located in State offshore waters. Section

192.1(b)(1) reads as follows: ‘‘This part

does not apply to * * * (o)ffshore

gathering of gas upstream from the

outlet flange of each facility on the outer

continental shelf where hydrocarbons

are produced or where produced

hydrocarbons are first separated,

dehydrated, or otherwise processed,

whichever facility is farther

downstream.’’ Because RSPA treats OCS

and State offshore gathering alike under

part 192, we proposed to delete the

phrase ‘‘on the outer continental shelf’’

so the exception would cover offshore

gathering no matter where located. We

also proposed to replace ‘‘offshore

gathering of gas’’ with ‘‘offshore

pipelines,’’ recognizing that the

excepted pipelines may be either

production or gathering lines.

Twelve TPSSC members voted for the

proposal, two supported it but

recommended a change, one member

opposed it, and one abstained. The

recommended change was that

‘‘gathering of gas’’ should be retained in

§ 192.1(b)(1), since proposed § 192.9

refers to gathering under § 192.1.

We did not adopt the TPSSC

minority’s recommended change

because the excepted pipelines located

upstream from the referenced offshore

facilities may be either production lines

or gathering lines. Also, the term

‘‘offshore pipelines’’ was used in a

similar revision of 49 CFR 195.1(b)(5)

that we made to clarify the jurisdiction

of the hazardous liquid pipeline

regulations over offshore pipelines

(Docket PS–127; 59 FR 33388; June 28,

1994). As discussed below under the

§ 192.9 heading, § 192.9 has already

been revised to cross-reference § 192.1.

Since the cross- reference does not refer

specifically to gathering lines, deleting

the words ‘‘gathering of gas’’ from

§ 192.1(b)(1) should not hinder the

understanding of § 192.9.

RSPA received 14 comments on the

proposed rule change, nine from

operators, four from pipeline-related

associations, and one from a state

agency. None of these comments

opposed the proposal to change

§ 192.1(b)(1).

Section 192.3, Definitions

1. Petroleum Gas. A revised definition

of ‘‘petroleum gas’’ is discussed below

under the § 192.11 heading.

2. Secretary. The proposed revision of

the definition of ‘‘Secretary’’ is no

longer needed. Because the term

‘‘Secretary’’ is not used in part 192, the

definition of ‘‘Secretary’’ was removed

from § 192.3 in an earlier rulemaking

(59 FR 17281; April 12, 1994).

3. Transmission Line. A longstanding

RSPA interpretation holds that the

definition of ‘‘transmission line’’ in

§ 192.3 encompasses lines that link

gathering lines or transmission lines to

large volume customers, such as

factories or power plants. This

interpretation was founded on the

definition of ‘‘transmission line’’ in the

1968 edition of the American Society of

Mechanical Engineers [ASME] B31.8

Code. This code, which was the

cornerstone of part 192, defined

transmission to end at large volume

customers. RSPA proposed to codify the

interpretation by restating the definition

of ‘‘transmission line’’ under part 192 to
28772 Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations

include a ‘‘large volume customer’’ as

an end point of transmission.

Eleven TPSSC members voted for the

proposal, three supported it with a

recommended change, and one

abstained. The members who

recommended a change thought that

RSPA should define ‘‘large volume

customer.’’ As discussed further below,

the final definition includes an

explanation of this term.

Twenty-six entities commented on the

NPRM proposal, including 19 pipeline

operators, five pipeline-related

associations, one state agency, and one

industrial consumer. Of these

commenters, only eight expressed

unqualified support. Three commenters

completely opposed the proposal,

saying it was not needed or would

create confusion.

RSPA continues to believe that the

proposed change is needed. The present

definition does not reflect RSPA’s

interpretation that the term

‘‘transmission line’’ includes pipelines

that connect large volume customers to

gathering or transmission lines.

Nine commenters thought the

proposed definition would reclassify as

transmission those pipelines that

connect large volume customers to high

pressure distribution lines. RSPA did

not intend for the proposed change to

alter the classification of distribution

lines that supply large volume

customers. To avoid this unintended

outcome, the definition explicitly does

not include lines serving large volume

customers downstream from a

distribution center.

Four commenters said that the

volume of gas transported is not an

appropriate indicator of transmission.

This group suggested that engineering

characteristics, such as high pressure,

stress level, or connection to a pressure

limiting station are more indicative of

transmission than the volume of gas

transported. However, the purpose of

the transmission proposal was not to

open discussion on whether volume is

an appropriate indicator of

transmission. The purpose was to

recognize that, by interpretation of the

present definition, volume already is an

established indicator of transmission,

and that the interpretation should be

codified. None of the commenters

challenged the correctness of the

interpretation. Moreover, before

publishing the proposed definition, we

referred to the 1992 edition of the ASME

B31.8 Code, a widely recognized code of

voluntary standards for gas piping.

Section 803.21 of the ASME B31.8 Code

(1992 edition) defined ‘‘transmission

line’’ as ‘‘pipe installed for the purpose

of transmitting gas from a source or

sources of supply to one or more

distribution centers or to one or more

large volume customers * * *’’

(emphasis added). And this definition is

the same in the current 1995 edition of

the code. Given our longstanding

interpretation and the ASME B31.8

Code definition, we find it reasonable to

add ‘‘large volume customer’’ to the

definition of transmission line as

proposed.

Three commenters wanted RSPA to

define ‘‘large volume customer.’’ We

agree that an explanation of ‘‘large

volume customer’’ would make the final

definition more precise. Thus, we added

a statement to the final definition to

explain that ‘‘large volume customer’’

includes factories, power plants, and

institutional users of gas.

We did not specify a minimum

volume of gas a pipeline must transport

to a customer to qualify as transmission.

Volumes vary, and setting an arbitrary

threshold might unfairly reclassify some

existing lines. However, since ‘‘large

volume customer’’ and ‘‘distribution

center’’ each mark the end of

transmission under the definition,

operators may use the volume of gas

supplied to distribution centers as a

guide to identifying large volume

customers.

The NAPSR report recommended

changing the part 192 definition of

‘‘transmission line’’ so that pipelines

beginning at gathering or transmission

lines and ending at ‘‘distribution

systems and other load centers’’ would

be classified as transmission lines.

Under this alternative wording, load

centers conceivably would include large

volume customers.

Most of the persons who commented

directly on this NAPSR

recommendation opposed it. A primary

objection was that the recommended

definition would needlessly reclassify

as transmission low stress pipelines

between communities or between

distribution systems and high pressure

transmission lines. In this regard, many

commenters felt transmission should be

limited to pipelines that operate at 20

percent or more of specified minimum

yield strength (SMYS) of pipe, one of

the characteristics under the present

definition. The lack of definition of the

term ‘‘load center’’ was another

frequently stated reason for opposing

the NAPSR recommendation.

Commenters argued that introducing

this term into the definition would lead

to more, not less, confusion. Also

several commenters thought the

definition of transmission line should

remain unchanged until RSPA

completes its project to redefine the

term ‘‘gathering line,’’ which appears in

the transmission line definition. After

considering these concerns, we agree

that the NAPSR recommendation would

not strengthen the present definition

and could cause reclassification of many

lines. Therefore, we did not adopt the

recommendation in the final definition.

Section 192.5, Class Locations

RSPA proposed to clarify § 192.5 to

minimize the possibility that a pipeline

is classified higher than required.

Inasmuch as part 192 regulations

become more stringent as pipeline

classification increases, any overclassification results in needless

expenditures.

Fourteen TPSSC members voted for

the proposal and one abstained. Eight

operators and one pipeline-related

association commented on the proposed

change. While these commenters

generally supported the need to clarify

§ 192.5, two operators suggested

alternative wording. Based on one

suggestion, RSPA has combined

proposed §§ 192.5 (c)(2) and (c)(3) into

final § 192.5(c)(2).

One focus of the NPRM was the

cluster exception in existing

§§ 192.5(f)(2) and (f)(3). This exception

provides that if a cluster of buildings

intended for human occupancy requires

a Class 2 or 3 location, the classification

ends 220 yards from the nearest

building in the cluster, rather than at the

end of the 1-mile class location unit that

would otherwise be the basis for

classification. In the NPRM (at 39573),

we stated that adding buildings outside

a cluster to those inside the cluster

would result in over-classification of the

class location unit. However, this

statement was incorrect. The history of

§ 192.5 (35 FR 13251, August 19, 1970)

shows that the cluster exception applies

only when all buildings in a 1-mile class

location unit are in a single cluster. If a

class location unit contains buildings

outside a cluster or more than one

cluster of buildings, all buildings in the

unit must be counted to determine the

classification of the unit. The final rule

clarifies this point.

The association that commented

thought we should define the term

‘‘cluster.’’ However, the term is used in

its ordinary dictionary sense, and, in

RSPA’s experience, has not been a

significant source of misunderstanding.

Section 192.7, Incorporation by

Reference

Section 192.7 describes the

incorporation by reference in part 192 of

documents or portions of documents

relevant to gas pipeline safety. RSPA

proposed to revise § 192.7(a) to clarify

that when a regulation in part 192
Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations 28773

references a document, the entire

document is not necessarily

incorporated by reference. Rather, only

those portions of the document that are

specifically referenced in the regulation

or are essential for compliance with the

regulation are incorporated by reference.

Such portions may or may not comprise

the whole document, depending on the

scope of the reference.

Fourteen TPSSC members voted for

the proposal and one abstained.

Commenters on the proposed change,

seven operators and one pipelinerelated association, all favored the

proposal. However, two of these

commenters wanted RSPA to change the

rule in a manner not proposed. They

advised changing § 192.7 to require

operators to follow the latest published

editions of documents, instead of

particular editions, which can become

obsolete before RSPA updates the

references. RSPA believes this

recommended action is inappropriate

because it would hand over an

established governmental function,

rulemaking, to the private organizations

who produce the referenced documents.

Each newly published edition would

automatically change a pipeline safety

rule and bypass the Federal rulemaking

process, which ensures fair treatment of

all affected parties.

Section 192.9, Gathering Lines

When the NPRM was published,

§ 192.9 required gathering lines to

comply with part 192 standards

applicable to transmission lines without

indicating that certain gathering lines

are excepted from part 192 by § 192.1.

To highlight this exception and provide

a clear understanding of which

gathering lines must meet transmission

line standards, we proposed to crossreference § 192.1 in § 192.9.

Thirteen TPSSC members voted for

the proposal and two abstained. RSPA

received seven comments on the

proposed change, six from operators and

one from a pipeline-related association.

Only one commenter opposed the

proposal, saying it did not see how the

change would clarify the present rule.

Then in 1994, in a separate, unrelated

action concerning the passage of pigs,

RSPA revised § 192.9 to include a crossreference to § 192.1 (59 FR 17281, April

12, 1994). Thus, § 192.9 has already

been changed consistent with the

proposal in this proceeding, and no

further action is necessary.

Section 192.11, Petroleum Gas Systems

(Including Changes to §§ 192.1 and

192.3)

RSPA proposed several changes to the

special rules in § 192.11 for petroleum

gas systems: First, we proposed to

require that peak shaving plants

supplying petroleum gas by pipeline to

a natural gas distribution system as well

as pipeline systems transporting only

petroleum gas or petroleum gas/air

mixtures comply with part 192

standards and the National Fire

Protection Association (NFPA)

Standards 58 and 59. Downstream from

the point where a peak shaving plant

injects petroleum gas into a natural gas

distribution system, only part 192

would apply. Next, we proposed that

the NFPA Standards prevail in the event

of a conflict between part 192 and NFPA

Standards 58 or 59. At the same time,

we said that a conflict does not exist

when NFPA Standards 58 and 59 are

silent or nonspecific on a subject (such

as for corrosion protection or leak

detection). In this case, the operator

would have to comply with any

applicable part 192 rule. Finally, we

proposed to add a definition of

‘‘petroleum gas’’ to § 192.3, and to

clarify under § 192.1(b)(4) which

petroleum gas systems are excepted

from part 192.

Ten TPSSC members voted for the

proposal, one member supported it with

a recommended change, three members

opposed it, and one abstained. Two

TPSSC members disagreed with the

proposal that NFPA standards should

prevail in the event of a conflict with

part 192. One TPSSC member voted yes,

but recommended that in the event of

conflict the most stringent requirement

should prevail.

We explained in the NPRM why we

believe the NFPA standards should have

priority in direct conflict situations. The

main reason is that in contrast to part

192, the NFPA Standards specifically

cover petroleum gas transportation.

Also, NFPA Standards 58 and 59 reflect

current petroleum gas technology and

safety practices. Given this special

attention to petroleum gas, we do not

think there is sufficient reason to

require operators to follow part 192

instead of the NFPA Standards in the

event of conflict, even if part 192 is

more stringent.

RSPA received eight comments in

favor and three comments in opposition

to the proposed changes to § 192.11.

Those commenters who opposed the

proposal were concerned that

compliance with NFPA Standards 58

and 59 would involve significant capital

expenditures. However, § 192.11 already

requires petroleum gas systems to meet

NFPA Standards 58 and 59. And, in

accordance with 49 U.S.C. § 60104(b),

none of the design, installation,

construction, initial testing, or initial

inspection requirements of NFPA

Standards 58 and 59 would apply under

part 192 to peak shaving plants now in

existence. So, retrofitting existing plants

would not be required. Although all

plants would have to comply with the

operation and maintenance

requirements of NFPA Standards 58 and

59, overall compliance costs should be

small because, as NFPA stated in its

petition, most, if not all, existing plants

already comply with NFPA Standards

58 and 59 to qualify for insurance

coverage. Thus, § 192.11 is revised as

proposed in the NPRM.

Proposed § 192.1(b)(4)(i) would

exclude from part 192 pipeline systems

that transport only petroleum gas or

petroleum gas/air mixtures to fewer

than 10 customers, if no portion of the

system is located in a public place. This

exclusion is in the present § 192.11(a),

but in proposing to relocate it to

§ 192.1(b)(4)(i), we omitted the

parenthetical phrase ‘‘(such as a

highway).’’ One commenter objected to

the omission, saying it would leave the

meaning of ‘‘public place’’ open to

interpretation. However, our experience

has been that the parenthetical phrase

has hindered more than helped the

understanding of public place. We have

consistently interpreted ‘‘public place’’

to mean a place which is generally open

to all persons in a community as

opposed to being restricted to specific

persons. We consider churches, schools,

and commercial property as well as any

publicly owned right-of-way or property

which is frequented by persons to be

public places. Although § 192.11(a)

refers to a highway as an example of a

public place, many operators have

incorrectly considered the example to

restrict, rather than define, the coverage

of petroleum gas systems with fewer

than 10 customers.

Proposed § 192.1(b)(4)(ii) would

clarify that part 192 does not apply to

single-tank, single-customer petroleum

gas systems located entirely on the

customer’s premises, but partially in a

public place. These systems exist, for

example, at churches or restaurants,

where the gas is used for heating or

cooking. The proposal was based on the

jurisdiction of part 192 over the

distribution of gas. As indicated by the

definition of ‘‘service line’’ (§ 192.3),

part 192 does not apply to gas

distribution beyond the point where

metered gas enters customer piping. For

single-tank, single-customer systems on

the customer’s premises, this point

normally occurs at the tank.

Three commenters protested that part

192 would still apply to singlecustomer, multi-tank systems on the

customer’s premises, regardless of tank

size. For example, the proposed rule
28774 Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations

would not exclude a two-tank system

partly in a public place, even if the total

quantity of stored gas is less than in a

large single-tank system. Because the

proposed exclusion did not rest on the

quantity of gas delivered to the

customer, we agree that the number of

tanks should not be a factor in the

exclusion of single-customer systems on

the customer’s premises. Therefore,

final § 192.1(b)(4)(ii) omits the term

‘‘single-tank.’’

The proposed definition of

‘‘petroleum gas’’ drew no objections

from either the TPSSC or commenters.

So the definition is adopted as

proposed.

Sections 192.14 and 192.553,

Conversion and Uprating

If a steel pipeline to be converted to

gas service under part 192 has not been

designed and constructed to meet part

192 standards, it must be converted

according to § 192.14 (§ 192.13(a)(2)).

Section 192.14(a)(4) requires that each

pipeline must be pressure tested under

subpart J of part 192 to substantiate the

maximum allowable operating pressure

(MAOP) permitted by subpart L of part

192. Under subpart L, to compute the

MAOP of a pipeline being converted, an

operator must determine the design

pressure of the weakest element of the

pipeline (§ 192.619(a)(1)).

Design pressure is also a factor under

§ 192.553, which establishes general

requirements for increasing any

pipeline’s MAOP (uprating). Under

§ 192.553(d), an increased maximum

allowable operating pressure may not

exceed the MAOP part 192 allows for a

new pipeline constructed of the same

materials in the same location. Thus, to

uprate a pipeline within this MAOP

limit, an operator must determine the

design pressure of the weakest element

of the pipeline (§ 192.619(a)(1)).

Because of the role of design pressure,

a steel pipeline may not be converted or

uprated when any of the pipe

characteristics needed to calculate

design pressure under § 192.105 is

unknown. Therefore, RSPA proposed to

amend §§ 192.14(a)(1) and 192.553(d) to

permit the conversion or uprating of

steel pipelines based on an approach

found in paragraph 845.214 and

Appendix N of the ASME B31.8 Code.

Under the proposal, when design

pressure is unknown, operators would

have to pressure test the pipeline under

Appendix N until pipe yield occurs.

The first pressure that produces pipe

yield, reduced by 20 percent and the

appropriate factor under

§ 192.619(a)(2)(ii), would be used

instead of design pressure to calculate

MAOP.

Twelve TPSSC members voted for the

proposed revision of § 192.14, one

member supported it with a

recommended change, one member

opposed it but suggested changes, and

one member abstained. Eleven members

voted for the proposal regarding

§ 192.553, two supported it with a

recommended change, one opposed it,

and one abstained. The recommended

changes were to make yield testing

mandatory instead of permissive, and to

allow yield testing that is based on other

than the ‘‘first pressure’’ that produces

yield, since Appendix N does not use

that term. The reasons against the

proposal were that yield testing

appeared to be mandatory, and use of

the Appendix N method should be

discretionary.

RSPA has adopted the recommended

change regarding mandatory yield

testing. Although, in the proposed rules,

yield testing may have appeared

permissive, RSPA clearly intended such

testing to be the only alternative when

design pressure is unknown. Therefore,

in the final rule, if factors in the design

formula are unknown, a pipeline to be

converted or uprated would have to be

pressure tested under Appendix N to

determine pipe yield, except as

discussed below for low-stress pipe.

The TPSSC member’s

recommendation to delete ‘‘first

pressure’’ from the proposed rule was

not adopted. Although Appendix N

does not refer to the first pressure that

produces yield, paragraph 845.214(a)(2)

of the ASME B31.8 Code, which applies

to the establishment of MAOP when

design pressure is unknown, provides

that only the first test to yield can be

used to determine MAOP. The proposed

rules were consistent with this B31.8

standard, which precludes the use of

higher yield pressures that can result

from successive testing.

RSPA did not adopt the TPSSC

member’s comment that use of the

Appendix N method should be

discretionary. When MAOP is

determined without knowing the

pipeline’s design pressure, conformity

to a standardized practice (Section N5.0

of Appendix N) assures additional

safety to offset the lack of knowledge

about design pressure.

RSPA received comments on the

proposed rules from 11 operators and

three pipeline-related associations. Four

operators and one pipeline-related

association recommended removal of

the proposed requirement to use the

‘‘first pressure’’ that produces yield. Our

position on this subject is given above

in response to a similar comment by a

TPSSC member.

One operator and one pipeline-related

association suggested locating the

proposed amendments in § 192.105

instead of §§ 192.14 and 192.553. RSPA

did not adopt this suggestion because

§ 192.105 affects the design of new

pipelines, a subject the proposed rules

did not address.

One operator and two pipeline-related

associations argued that pressure testing

to yield is unnecessary to qualify lowstress distribution lines (generally lines

123⁄4 inches or less in nominal outside

diameter operating at pressures less

than 200 psig) for conversion or

uprating. Part 192 recognizes that lowstress pipelines present a much lower

risk to public safety than high-stress

lines, all other factors being equal. For

example, certain welding standards in

subpart E are less stringent for pipelines

to be operated below 20 percent of

SMYS. Because of the lower risk, the

final rule provides that pipelines 123⁄4

inches or less in nominal outside

diameter to be operated at a pressure

less than 200 psig may be converted or

uprated without testing to yield. The

MAOP of such pipelines may be

determined under § 192.619(a)(1) by

using 200 psig as design pressure.

An operator argued that pressure

testing to yield should be discretionary,

because sufficient safety would be

provided by the proposed pressure

reduction factors regardless of the level

of test pressure. The commenter was

also concerned that pressure testing to

yield for an extended time could cause

the growth of defects that later cause

failure during operation. Two hours was

suggested as the optimum hold time for

yield testing, based on ongoing studies.

RSPA did not adopt these comments.

Pressure testing to yield exposes more

material and construction defects than

does testing to a lower pressure. With

fewer defects remaining after testing to

yield, greater long-term protection

against failures due to the growth of

unexposed defects results. RSPA

intended this extra protection,

combined with the proposed pressure

reduction factors, to offset the absence

of design pressure as a limit on MAOP.

Pressure testing to yield appears to be

reasonable since many operators already

strength test their pipelines at or above

yield for safety and efficiency reasons.

Also, none of the other commenters or

TPSSC members objected to pressure

testing to yield, except as discussed

above for low-stress lines. As to the

optimum hold period for yield testing,

because the matter is still being studied

by industry and is not addressed by the

procedure for yield testing under

Appendix N, it is too soon to consider
Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations 28775

establishing a special hold period for

yield testing under part 192.

The final rules have been drafted to

improve clarity, to show their relation to

design pressure and MAOP under

§ 192.619, and to include the changes

discussed above. The proposed

amendments to §§ 192.14(a)(1) and

192.553(d) are revised and published as

an amendment to § 192.619(a)(1),

because this section deals specifically

with design pressure and MAOP. Final

§ 192.619(a)(1), set forth below, provides

that when design pressure is unknown

for steel pipelines being converted or

uprated, a reduced value of first yield

hydrostatic test pressure, instead of

design pressure, is used to compute

MAOP. As discussed below, final

§ 192.619(a)(1) does not include the

reduction factors proposed for butt and

lap welded pipe under § 192.14(a)(1)(ii).

If the pipeline to be converted is 123⁄4

inches or less in nominal outside

diameter, 200 psig, instead of design

pressure, may be used if the line is not

yield tested. Section 192.553(d) is also

revised to refer to amended

§ 192.619(a)(1). Also, because the 1992

edition of the ASME B31.8 Code is now

out-of-print, the 1995 edition is

referenced in § 192.619(a)(1) as shown

by the revisions to Appendix A of part

192 (see below).

Section 192.107, Yield Strength (S) for

Steel Pipe

For pipe made according to a

specification not listed in part 192 or

whose specification or tensile properties

are unknown, § 192.107(b)(1) provides

that yield strength may be established

by tensile testing in accordance with

section II–D of appendix B to part 192.

When yield strength is determined by

such tensile testing, paragraph (b)(1)

requires that the yield strength used in

the design formula of § 192.105 be the

lower of either 80 percent of the average

yield strength determined by tensile

testing or the lowest yield strength

determined by tensile testing, but not

over 52,000 psi. RSPA proposed to

remove this 52,000 psi upper limit on

yield strength, because higher strength

pipe has become available since this

limitation was adopted, and tensile

testing is a generally accepted method of

determining material properties.

Twelve TPSSC members voted for the

proposal, one member supported it with

a recommended change and two

abstained. The member recommending

the change felt that the proposal would

be better justified if we knew the

proportion of higher strength pipe that

lacks tensile documentation and why

this information is unknown. RSPA

believes this information is not essential

in deciding whether to adopt the

proposal because the proposed

amendment has limited application. We

expect operators would use the

proposed amendment to qualify stock

pipe they have stored for maintenance

and emergencies and to qualify used

pipe being reclaimed. In either case, the

amount of pipe that would be qualified

under proposed § 192.107(b)(1)(ii)

should be very small compared with all

pipe being qualified for use in gas

pipeline systems.

RSPA received six comments on the

proposed amendment. The comments

came from five operators and one

pipeline-related association, and all

supported the proposal. In addition, one

operator recommended that RSPA

further amend § 192.107 to permit the

use of recognized statistical methods to

determine yield strength from tensile

tests. RSPA did not adopt this comment

because this concept was not addressed

in the NPRM and would require further

public comment and study.

Accordingly, § 192.107 is amended as

proposed in the NPRM.

Section 192.121, Design of Plastic Pipe

RSPA proposed to add the following

formula to § 192.121, which would

allow use of the Standard Dimension

Ratio (SDR) in determining design

pressure for plastic pipe:

P

S

SDR = −

2

1

0 32

( ) .

SDR is a commonly used plastic pipe

characteristic in the gas pipeline

industry.

Thirteen TPSSC members voted for

the proposal and two abstained. RSPA

received eight responses from the

public, all in favor of the proposed rule.

Therefore, the final rule is issued as

proposed in the NPRM, except that the

proposed definition is reworded to

conform to standard usage. The final

definition agrees with the SDR

definition given in the voluntary

standard referenced in part 192 for the

manufacture of thermoplastic pipe:

American Society for Testing and

Materials (ASTM) Designation D 2513,

‘‘Standard Specification for

Thermoplastic Gas Pressure Pipe,

Tubing, and Fittings’’ (1990c edition).

Section 192.123, Design Limitations for

Plastic Pipe

Under § 192.123, plastic pipe may not

be used where pipe operating

temperatures are below ¥20°F. RSPA

proposed to lower this limit to ¥40°F

in light of improvements in pipe

technology. Additionally, RSPA

proposed to clarify § 192.123(b)(2),

which sets the maximum operating

temperature for thermoplastic pipe and

reinforced thermosetting plastic pipe.

Thirteen TPSSC members voted for

the proposal and two abstained. RSPA

received nine comments on the

proposed rule changes: six from

operators, one from a pipeline-related

association, and two from

manufacturers. The operators and the

association supported the proposal or

did not object to it. However, the

manufacturers opposed the proposal

stating that many components other

than pipe that are made for use in gas

pipeline systems do not have a low

temperature rating of ¥40°F, although

they perform satisfactorily at ¥20°F.

One of these commenters argued that

unsafe operation could occur if pipeline

designers assumed that all components,

such as repair and connection devices,

fittings, valves, meters, and regulators,

may be used at ¥40°F.

RSPA shares the manufacturers’

concern. Therefore, the final rule allows

the use of plastic pipe at temperatures

between ¥20°F and ¥40°F only if all

pipe and pipeline components whose

operating temperature will be below

¥20°F have a manufacturer’s

temperature rating consistent with that

operating temperature.

Section 192.179, Transmission Line

Valves

Gas transmission lines must have

sectionalizing block valves spaced

according to population density under

§ 192.179(a). RSPA proposed to revise

this rule to allow the RSPA

Administrator to approve alternative

spacing where the operator

demonstrates an equivalent level of

pipeline safety.

Thirteen TPSSC members voted for

the proposal, one against, and one

abstained.

RSPA received comments from 12

operators, two pipeline-related

associations, and a state agency.

Thirteen commenters gave their full or

qualified approval, but one association

and the state agency argued against the

proposal. Those commenters expressing

qualified support generally felt that the

proposal offered some benefit to

pipeline operators. However, they urged

that operators be permitted to determine

spacing based on criteria similar to

those for hazardous liquid pipelines in

49 CFR 195.260(c).

RSPA did not adopt the comment that

transmission line valve spacing should

be governed by criteria similar to those

in 49 CFR 195.260(c). While those

criteria may be appropriate for

hazardous liquid pipelines, we have no

indication they are suitable for gas
28776 Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations

transmission lines. In fact, the widely

accepted voluntary standard for valve

spacing, paragraph 846.11 of the ASME

B31.8 Code, differs little from existing

§ 192.179.

As for the comments opposing the

proposal, RSPA has considered the state

agency’s concern that the proposed rule

would infringe on the authority of state

agencies to grant waivers from § 192.179

for intrastate transmission lines. (See 49

U.S.C 60118(d)). However, this concern

has been addressed by a procedural rule

(49 CFR 190.9) that RSPA adopted to

handle petitions for finding or approval

under the federal pipeline safety

regulations. Under this rule, which

would apply to petitions for alternative

spacing under § 192.179, operators of

intrastate pipelines subject to the safety

regulatory jurisdiction of a certified

state agency must submit their petitions

to that agency for review and

recommendation before final action by

the Administrator.

RSPA does not agree with the

pipeline-related association’s suggestion

that since the underlying rule is not

justified, the proposed amendment is

not needed. The basis for existing

§ 192.179 was the 1968 edition of the

ASME B31.8 Code. As noted above, the

current edition of that code continues to

specify valve spacing similar to

§ 192.179.

Section 192.203, Instrument, Control,

and Sampling Pipe and Components

Under § 192.203(b)(2), each takeoff

line must have a shutoff valve as near

as practicable to the point of takeoff.

RSPA proposed an exception for takeoff

lines on pressure regulators when the

lines can be isolated by other valves

from their source of pressure.

Eleven TPSSC members voted for the

proposal, one voted against it, two

members supported it with a

recommended change, and one

abstained. The two members

recommended that we also except

instrument control lines that are capable

of being isolated from their source of

pressure.

Although the industry’s use of

isolatable regulators gave rise to the

proposed rule change, isolation of a

takeoff line from its pressure sources

applies to any takeoff line capable of

such isolation, not just takeoff lines on

regulators. Therefore, the final rule

excepts any takeoff line capable of being

isolated from its sources of pressure.

Thus, the term ‘‘takeoff line’’ includes

instrument control lines that are

designed as takeoff lines.

RSPA received 13 public comments,

all in favor of changing the regulation.

One of these commenters offered a

rewording intended to broaden the

regulation to include control lines at

both measuring and regulating stations.

As explained above, such control lines

will be covered by the exception when

they are takeoff lines capable of

isolation from their sources of pressure.

Section 192.227, Qualification of

Welders, and § 192.229, Limitations on

Welders

Welders qualified to weld on pipe to

be operated at any hoop stress

(§ 192.227(a)) must requalify every 6

months (§ 192.229(c)). However,

welders qualified to weld only on pipe

to be operated at low hoop stress (less

than 20 percent of SMYS) need only

requalify once a year (§ 192.227(b)), and

the requalification requirements are less

comprehensive than those for other

welders.

RSPA proposed to revise §§ 192.227

and 192.229 to allow welders initially

qualified for any hoop stress level, but

who weld only on pipe to be operated

at low hoop stress, to requalify under

the low-stress requirements. Such

welders would then not be permitted to

weld on pipe to be operated at 20

percent or more of SMYS unless they

again qualify under § 192.227(a).

Twelve TPSSC members voted for and

one against the proposed revision of

§ 192.227, and two abstained. The

TPSSC members’ vote on § 192.229 was

the same as on § 192.227. Eight pipeline

operators and two pipeline-related

associations also agreed with the

proposal.

A commenter suggested that the final

rule make clear that either existing

§ 192.229(c) or § 192.227(b) can be used

to requalify welders to weld on pipe to

be operated at less than 20 percent of

SMYS. RSPA adopted the substance of

this comment by adding a sentence

concerning low stress requalification to

the final § 192.229(c).

The commenter who opposed the

proposal claimed that qualification

under §§ 192.227(a) and (b) is

inadequate. However, RSPA finds no

justification for this claim. Section

192.227 became effective in February

1970. Our accident data in the

intervening 26 years have not indicated

that field welding of steel materials in

pipelines presents a significant safety

problem.

In the final rules, proposed

§ 192.227(c) is redesignated as

§ 192.229(d). Thus, all requalification

requirements appear in one section.

Section 192.241, Inspection and Test of

Welds

Section 192.241 requires inspection

and test of welds on steel materials in

pipelines, except welds made during the

manufacture of pipe and pipeline

components. Under existing

§ 192.241(c) and appendix A to part 192,

the acceptability of a weld that is

nondestructively tested or visually

inspected is determined according to

the standards in section 6 of API

Standard 1104 (17th edition).

The Appendix of API Standard 1104,

which is based on fracture mechanics

principles, provides more detailed

acceptance standards for weld flaws

than the criteria in section 6 of API

Standard 1104. RSPA proposed to

amend § 192.241(c) to permit use of the

Appendix as an alternative acceptance

standard for girth weld flaws, except

welds unacceptable because of a crack.

Eleven TPSSC members voted for the

proposal, three members supported it

with a recommended change and one

abstained. The three members suggested

that the word ‘‘flaw’’ be changed to

‘‘defect’’.

In existing § 192.241, neither the word

‘‘flaw’’ nor ‘‘defect’’ is used. The rule is

written in terms of weld acceptability.

Therefore, in response to the comments

of the TPSSC members, the final rule is

written without using either ‘‘flaw’’ or

‘‘defect.’’

Eleven pipeline operators and three

pipeline-related associations agreed

with the proposed change. Only one

commenter was opposed to allowing use

of the Appendix of API Standard 1104.

This commenter was concerned that

industry inspection personnel may not

be qualified to apply the complicated

engineering criteria found in the

Appendix. On the contrary, personnel

who would use the Appendix must be

able to apply it correctly. Under

§§ 192.243(b) and (c), operators must

ensure that nondestructive testing is

performed in accordance with written

procedures by persons who have been

properly trained and qualified.

The final rule indicates that use of the

Appendix is restricted to girth welds to

which the Appendix applies. For

example, as Section A.1 of the

Appendix provides, welds used to

connect fittings and valves are not

covered. Also, the Appendix applies

only to girth welds between pipe of

equal nominal wall thickness.

Section 192.243, Nondestructive Testing

For pipelines subject to

nondestructive testing under part 192,

§ 192.243(d)(4) requires such testing for

all field butt welds at pipeline tie-ins.

RSPA proposed to amend

§ 192.243(d)(4) to add the phrase

‘‘including tie-ins of replacement

sections.’’ This change was meant to

clarify that tie-ins occur in pipeline
Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations 28777

replacement, as well as in new

construction.

Fourteen TPSSC members voted for

the proposal and one abstained.

Comments were received from five

pipeline operators and one pipelinerelated association, and all favored the

proposed rule change. Section 192.243

is amended as proposed in the NPRM.

Section 192.281, Plastic Pipe

This rule establishes standards

governing the joining of plastic pipe.

RSPA proposed to revise § 192.281(c),

which applies to heat-fusion joints, to

cover electrofusion, a method of heatfusion joining. The proposal was that

electrofusion joints must be made with

equipment and techniques expressly

prescribed by the fittings manufacturer.

Thirteen TPSSC members voted for

the proposal, one member supported it

with a recommended change, and one

abstained. The recommended change

was that ‘‘or the equivalent’’ be added

so that operators could use equipment

and techniques equivalent to that

prescribed by fittings manufacturers.

RSPA received 15 comments on the

proposed change to § 192.281(c). Eleven

commenters fully or partially agreed

with the proposed rule, while four

commenters objected. A commenter

who partially agreed recommended that

electrofusion be specifically addressed

in § 192.285. However, RSPA finds that

step unnecessary because electrofusion

is a type of heat fusion, and heat fusion

is covered by § 192.285(b)(2).

The objections focused on RSPA’s

proposal that operators must use

‘‘equipment and techniques expressly

prescribed by the fittings

manufacturer.’’ One commenter said

that electrofusion equipment is

expensive and that most electrofusion

fittings can be installed only by using

the fittings manufacturer’s equipment.

As a result, most operators have only a

single source of electrofusion fittings.

However, the commenter stated that

electrofusion equipment under

development will allow the installation

of several different brands of

electrofusion fittings, and that those

additional sources would encourage

competitive pricing. Other operators

argued they should not be denied the

use of procedures and equipment not

expressly prescribed by the fittings

manufacturer, as long as the procedures

are qualified for use under § 192.283.

Since the proposal was intended to

relax the current regulatory

requirement, RSPA accepts the

recommendations that operators should

have latitude in choosing equipment

and techniques for use in electrofusion

joining. We have adopted a slight

revision of the wording proposed by

three pipeline operators and one

pipeline-related association. This

wording meets the ‘‘or the equivalent’’

recommendation made by the TPSSC

member. Additionally, this wording

responds to the commenter’s concern

that the proposed wording would deter

competitive pricing. The adopted

wording requires that the joints be

joined using equipment and techniques

of the fittings manufacturer or

equipment and techniques shown, by

testing to certain criteria of ASTM

Designation F1055, ‘‘Standard

Specification for Electrofusion Type

Polyethylene Fittings for Outside

Diameter Controlled Polyethylene Pipe

and Tubing,’’ to be at least equivalent to

those of the fittings manufacturer. The

ASTM criteria are those adopted under

the next heading for qualifying

electrofusion joining procedures.

Section 192.283, Plastic Pipe: Qualifying

Joining Procedures

Section 192.283 prescribes criteria for

qualifying procedures used to join

plastic pipe. RSPA proposed to amend

this section by adding more appropriate

criteria for procedures used to join

polyethylene plastic pipe by

electrofusion. The proposed criteria are

contained in certain sections of ASTM

Designation F1055 (1987 edition).

Fourteen TPSSC members voted for

the proposal and one member abstained.

RSPA received eight comments on the

proposal: seven from pipeline operators

and one from a pipeline-related

association. Seven commenters

supported the proposal. But one

opposed it, saying that the proposal

should be withdrawn or rewritten to

accept any procedure that demonstrates

a suitable quality of joint. We believe,

however, that allowing operators to

judge the quality of an electrofusion

joint without applying a recognized

safety standard would be unacceptable.

Because of the failure risk of plastic

pipe joints, the present rule requires

heat fusion joining methods to be

qualified under generally recognized

voluntary standards, ASTM D2513 and

ASTM D2517. In the absence of safety

data to the contrary, as a heat fusion

method, electrofusion procedures

should likewise be qualified under an

appropriate recognized standard.

Accordingly, proposed § 192.283(a)(iii)

is adopted as final. However, the

proposed reference to the 1987 edition

of ASTM Designation F1055 is updated

to the 1995 edition, as shown by the

revisions to Appendix A of part 192 (see

below). And the referenced title of

paragraph 9.4 is corrected to read ‘‘Joint

Integrity Tests.’’

Sections 192.317(a), Protection From

Hazards

This section requires that gas

transmission lines and mains be

protected from washouts, floods,

unstable soil, landslides, or other

hazards that may cause the pipeline to

move or sustain abnormal loads.

Additionally, offshore pipelines must be

protected from damage by mud slides,

water currents, hurricanes, ship

anchors, and fishing operations. RSPA

recognized that in areas susceptible to

these hazards, such as offshore

pipelines in areas where hurricanes

usually pass, complete protection

against the hazards may not be feasible.

We, therefore, proposed to change the

regulation to require that in

construction of transmission lines and

mains, operators ‘‘take all practicable

steps to protect’’ the pipeline against the

cited hazards.

Eleven TPSSC members voted for the

proposal, one member supported it with

a recommended change, two members

were opposed and one member

abstained. The two members who

opposed it said that ‘‘all practicable

steps to protect’’ would be difficult to

interpret.

Comments were received from seven

pipeline operators and two pipelinerelated associations. All commenters

gave their full or qualified approval.

RSPA has issued the final rule as

proposed in the NPRM. The ‘‘all

practicable steps to protect’’ wording

was left in the rule to allow operators

flexibility in compliance; any tightening

of this performance wording would

diminish that flexibility. RSPA will

interpret or apply the rule in light of

customary pipeline design and

construction practices in the industry.

§§ 192.319(c) and 192.327(e), Offshore

Pipe in the Gulf of Mexico and Its Inlets

Under § 192.612, operators had to

inspect gas pipelines in the Gulf of

Mexico and its inlets in waters up to 15

feet deep. If the pipelines were found

exposed or to be a hazard to navigation

(i.e., buried less than 12 inches below

the seabed), the operator had to bury

them to a depth of 36 inches in soil or

18 inches in rock.

The part 192 review disclosed that

§§ 192.319(c) and 192.327(e), which

govern the installation of pipe offshore,

are incompatible with the objectives of

§ 192.612. In water between 12 and 200

feet deep, § 192.319(c) permits pipe to

be installed at or above the natural

bottom. And in water less than 12 feet

deep, in certain circumstances

§ 192.327(e) permits pipe to be buried

less than 36 inches in soil or 18 inches
28778 Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations

in rock. RSPA proposed to amend

§§ 192.319(c) and 192.327(e) to require

that when pipe is installed offshore in

the Gulf of Mexico and its inlets, the

pipe must be installed consistent with

the burial standards of § 192.612.

Thirteen TPSSC members voted for

the proposal, one member supported it

with a recommended change, and one

abstained. One member supported the

proposal but recommended rewording

and rearrangement for clarity, and that

§ 192.319(c) be moved to § 192.327.

Seven operators and four pipelinerelated associations supported the

proposed changes to §§ 192.319(c) and

192.327(e). However, five commenters

recommended wording changes and

rearrangement for clarity, and five

commenters suggested that § 192.319(c)

be moved to § 192.327. In light of the

recommendations, RSPA has clarified

the final rule text, as set forth below.

One pipeline-related association

opposed the proposal. It maintained that

pipe installed in water between 12 and

15 feet deep with less than 12 inches of

cover (now acceptable under

§ 192.319(c) but not § 192.612) might

not be an actual hazard to navigation.

But the proposal concerned the

inconsistency of § 192.612 with other

pipeline safety rules, a problem that can

be resolved without reopening the

question of what is a ‘‘hazard to

navigation’’ in the Gulf of Mexico and

its inlets. A ‘‘hazard to navigation’’ is

defined in § 192.3 to mean ‘‘a pipeline

where the top of the pipe is less than 12

inches below the seabed in water less

than 15 feet deep, as measured from the

mean low water.’’ This definition was

adopted in the proceeding on § 192.612

(Docket No. PS–120). Any remaining

controversy over the definition may be

raised by submitting a petition for

rulemaking under 49 CFR part 106.

Section 192.321, Installation of Plastic

Pipe; and § 192.375, Service Lines:

Plastic

Section 192.321(a) requires that

plastic pipe be installed below ground

level. RSPA proposed to allow the

temporary use of uncased (i.e., not

encased) plastic pipe above ground level

under certain conditions. The proposed

conditions limited the use to (1) 30

days; (2) locations where the pipe is

unlikely to be damaged (or is protected

from damage) by external forces; (3)

pipe that is resistant to the exposure to

ultraviolet light and temperature

extremes; and (4) pipe that has not been

previously used above ground level.

Nine TPSSC members voted for the

proposal, one against, three members

supported it with a recommended

change, and two abstained. The

recommended changes were similar to

those made by the commenters as

discussed below.

RSPA received 18 comments on this

proposal. Each commenter agreed

partially with the proposed rule. Some

commenters said the current rule should

be amended to permit the permanent

use of plastic above ground when the

pipe is encased in steel conduit.

However, since the proposal concerned

only temporary usage, this comment

was not adopted in the final rule.

Many commenters argued that the 30-

day period would be too brief. They

suggested a longer period, such as 60 or

90 days, in view of the time it may take

to complete a permanent installation.

They cited the time associated with

planning, obtaining governmental

permits, acquiring easements, engaging

contractors, competing work demands,

and other unforeseen events. Several

commenters suggested that no specific

time limit be defined and that

performance language be used.

Commenters also maintained that the

proposed prohibition against the

subsequent reuse of plastic pipe above

ground level is not justified, since

commercially available plastic pipe can

be exposed to ultraviolet light for at

least 2 years with no degradation of its

properties. These commenters argued

that the rule should permit reuse of

plastic pipe provided such use does not

exceed the pipe manufacturer’s

exposure limits.

RSPA agrees that in most cases 30

days may not be enough time for

operators to take full advantage of a

temporary aboveground plastic pipe

installation. In a recent waiver of

§ 192.321(a), we allowed the applicant

to install plastic pipe above ground for

a time that does not exceed the

manufacturer’s recommended maximum

period of exposure (60 FR 55752; Nov.

2, 1995). Although commenters

indicated that extending the limit to 2

years might not adversely affect pipeline

safety, we are not certain 2 years would

be safe for all plastic materials. Some

pipe manufacturers may recommend

less exposure time. Therefore, we have

chosen the manufacturer’s

recommended maximum period of

exposure but not longer than 2 years as

the limit on the temporary use of plastic

pipe above ground. If a manufacturer

has no recommended maximum

exposure period, then the limit would

be 2 years. RSPA does not believe a

performance standard would provide a

suitable time limit, because the safe

service life of plastic pipe exposed

above ground is too uncertain.

RSPA agrees that the final rule should

not unduly hinder the use of plastic

pipe. Thus, the proposed ban on reusing

plastic pipe above ground level does not

appear justified. The final rule permits

cumulative aboveground use for the

manufacturer’s recommended maximum

period of exposure but not longer than

2 years, provided the operator can

demonstrate the cumulative time of

aboveground use. In monitoring

compliance, RSPA will consider

credible evidence that demonstrates

cumulative time of use, such as business

records, work orders, or affidavits

related to the pipe concerned.

RSPA recognized that the changes to

§ 192.321 affected only plastic mains

and transmission lines. However, the

need for these changes applies as well

to plastic service lines. As with

transmission lines and mains, in some

situations operators may be able to save

material and construction costs of

service lines located outside buildings

by temporarily installing the lines above

ground. Thus, § 192.375(a), which

requires that plastic service lines

outside buildings be installed below

ground, is revised to allow temporary

aboveground installations in accordance

with § 192.321(g).

Section 192.455, External Corrosion

Control: Buried or Submerged Pipelines

Installed After July 31, 1971

Under § 192.455(a)(2), a pipeline must

have a cathodic protection system

designed to protect the pipeline in its

entirety. RSPA proposed to remove the

phrase ‘‘in its entirety’’ because it is

unnecessary to convey the meaning of

the rule, and some operators have

incorrectly assumed that pipeline

casings also must be protected.

In addition, § 192.455(f)(1) exempts

from corrosion control requirements

certain metal fittings in plastic pipelines

if the fitting is protected against

corrosion by alloyage. RSPA recognized

that the word ‘‘alloyage’’ is not in

common usage and proposed its

replacement with ‘‘alloy composition’’

to improve understanding.

Twelve TPSSC members voted for the

proposal, two members supported it

with a recommended change and one

abstained. The two members

recommended that in proposed

paragraph (f)(1), the term ‘‘corrosion

resistance’’ be replaced by ‘‘corrosion

control,’’ which is the term used in the

existing rule and throughout subpart I.

RSPA has made this replacement in the

final rule.

Comments were received from six

pipeline operators and one pipelinerelated association. Six commenters

gave their full approval and the seventh

was noncommittal. Therefore, except for

the previously discussed wording
Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations 28779

changes, § 192.455 is adopted as

proposed in the NPRM.

Section 192.475, Internal Corrosion

Control: General.

Section 192.475(c) limits the

hydrogen sulfide content of natural gas

stored in pipe-type or bottle-type

holders to 0.1 grain per 100 standard

cubic feet of gas. An operator proposed

that this rule be relaxed to allow a

concentration of 0.25 grain per 100

standard cubic feet of gas. Because the

0.25 limit is within customary industry

contract limits and is still lower than

maximum allowable safe limits set by

other government agencies, RSPA

proposed to increase the allowable

hydrogen sulfide limit in gas to be

stored in pipe-type and bottle-type

holders to 0.25 grain per 100 standard

cubic feet of gas. This action would

lower the cost of processing natural gas

that contains small quantities of

hydrogen sulfide.

Thirteen TPSSC members voted for

the proposal, one against, and one

member abstained.

Seven commenters supported the

proposed change. No commenters

opposed the change. One state agency

suggested that hydrogen sulfide levels

be expressed in parts per million in

addition to grains per 100 standard

cubic feet of gas. The NAPSR report also

made this recommendation, and all

comments on the subject were

supportive. RSPA agrees the allowable

level should be stated in parts per

million and has included this

designation in the final rule.

Section 192.485, Remedial Measures:

Transmission Lines

RSPA’s review of § 192.485, which

prescribes remedial measures for

corroded transmission lines, disclosed

that many operators need guidance on

how to determine the remaining

strength of corroded pipe. RSPA

proposed to provide this guidance by

referencing ASME B31G Manual for

Determining the Remaining Strength of

Corroded Pipelines in a new

§ 192.485(c).

Fourteen TPSSC members voted for

the proposal and one member abstained.

Comments relevant to proposed

§ 192.485(c) were received from 10

pipeline operators and two pipelinerelated associations. Six commenters

gave their full or partial support.

Another six said the proposal was

unnecessarily restrictive because it did

not allow the use of other proven

industry-developed methods for

determining the remaining strength of

corroded pipelines.

The most noteworthy method

mentioned was the method in the

American Gas Association (AGA) report

for Project PR 3–805, ‘‘A Modified

Criterion for Evaluating the Remaining

Strength of Corroded Pipe,’’ (December

22, 1989; AGA catalog No. L51609).

Project PR 3–805 was undertaken to

devise a criterion that, while still

assuring adequate pipeline integrity,

would eliminate, as much as possible,

the excess conservatism embodied in

the ASME B31G Manual. For a complex

analysis, the modified criterion can be

applied by using a computer program

called RSTRENG, which is furnished

with the report. The modified criterion

can also be applied with a long-hand

equation, or if a simplified analysis is

preferred, with tables or curves.

Evaluating the strength of corroded

pipe by procedures in ASME B31G or

the associated AGA report is subject to

the limitations specified in the

procedures. For example, the

procedures are not appropriate for

determining the ability of pipe to

withstand stresses other than stress from

internal pressure. Thus, if corroded pipe

is under significant secondary stress

(e.g., bending stress), an additional

method must be used to determine the

pipe’s remaining strength.

The NAPSR report recommended

amending § 192.483 to require the use of

appropriate guides, such as those

published by ASME and the Gas Piping

Technology Committee, whenever the

remaining strength of corroded

pipelines must be determined. The

majority of commenters who addressed

this NAPSR recommendation opposed

mandatory use of the guides. They said

operators should retain the flexibility to

decide when calculations under the

guides are necessary. Even those

commenters who supported the

recommendation thought the rule

should permit the use of other valid

methods.

After considering the comments on

proposed § 192.485(c) and the NAPSR

recommendation, we believe the NAPSR

recommendation would be unduly

restrictive. Operators are now free to use

any valid method to determine the

remaining strength of corroded pipe,

and we see no compelling reason to

restrain this flexibility. The NPRM

simply proposed to reference guidance

documents that are generally available

for operators to use at their discretion.

Moreover, the proposal was written in a

permissive sense to assist, but not

restrict, operator decision-making. So

we have amended the regulation

essentially as proposed, but referenced

both ASME B31G and the AGA report,

with RSTRENG, to expand the

information provided.

Section 192.491, Corrosion Control

Records

Under § 192.491(a), operators must

maintain records or maps showing the

location of cathodically protected

piping, cathodic protection facilities,

other than unrecorded anodes installed

before August 1, 1971, and neighboring

structures bonded to the cathodic

protection system. RSPA proposed to

amend this requirement to relieve

operators of the burden of making

precise field measurements and

preparing and maintaining records or

maps showing the specific location of

millions of individual anodes.

The TPSSC members voted

unanimously for the proposal.

Comments on proposed § 192.491(a)

were received from six pipeline

operators, two pipeline-related

associations, and one state agency. Eight

commenters expressed their full or

partial support with one commenter

opposed. RSPA has accepted the

recommendation of two operators that

in the second sentence of proposed

paragraph (a), the phrase ‘‘Records and

maps * * *’’ should, for consistency

with the rest of this section, be changed

to ‘‘Records or maps * * *.’’

Section 192.491(b)(2) requires that

operators retain records of corrosion

control tests, surveys, and inspections

for ‘‘as long as the pipeline remains in

service.’’ RSPA proposed to reduce this

retention period to at least 5 years for

many records, because 5 years was

thought to be adequate for compliance

investigations and analysis of possible

corrosion problems.

The proposal did not, however,

extend to records under §§ 192.465 (a)

and (e) and 192.475(b). These records

relate to tests and inspections to

determine the adequacy of, or need for,

external and internal protection on

existing lines. RSPA felt strongly that

these records should continue to be kept

for the service life of the pipeline,

because they provide a valuable

database for use in assessing corrosion

problems.

The TPSSC unanimously supported

the proposal.

Three pipeline-related associations,

10 operators, and one state agency

commented on the proposal. Four of

these commenters agreed with the

proposal as written; the rest qualified

their support by recommending

changes.

Five commenters, including two

pipeline-related associations and a state

agency, were not persuaded of the

importance of keeping records of
28780 Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations

corrosion monitoring under § 192.465

for the life of the pipe. Most of these

commenters declared that 5 years would

be adequate, but did not explain why a

longer period is excessive. Lacking any

convincing documentation to the

contrary, RSPA believes the current rule

should stay in effect. In our experience,

a history of corrosion monitoring sheds

light on the possible causes of a

pipeline’s condition. Such history has

proven to be a valuable resource in

deciding the extent and kind of

remedial action needed when corrosion

problems emerge on a pipeline.

Regarding the proposed 5-year

retention time for records other than

those required by §§ 192.465 (a) and (e)

and 192.475(b), two commenters said

the minimum time should be 3 years to

coincide with the longest interval

between inspections. Two others

suggested that instead of a set time, we

adopt a performance standard for record

retention, basing it on the time needed

to observe trends, inquire into

compliance, or collect superseding data.

All these comments provide a

reasonable basis for record retention.

However, our main concern is that

operators keep records for a period that

is compatible with the occurrence of

routine compliance investigations.

Therefore, for simplicity and

uniformity, we have decided to adopt

the proposed 5-year minimum retention

time.

The state agency that commented

objected to the 5-year proposal on

grounds that it would sacrifice

information about why external or

atmospheric corrosion control was not

installed on pipelines under §§ 192.455,

192.457, and 192.479. RSPA believes

the loss of this information after 5 years

would not be significant, because the

pipelines involved are covered by

requirements for periodic inspections or

tests for corrosion under §§ 192.465 and

192.481.

Section 192.553, General Requirements

(See previous discussion under

§ 192.14).

Section 192.607, Determination of Class

Location and Maximum Allowable

Operating Pressure

Because § 192.607 has no continuing

effect and the deadlines for compliance

have expired, RSPA proposed to remove

§ 192.607 from part 192.

Fourteen TPSSC members voted for

the proposal and one member abstained.

Five operators, one pipeline-related

association, and one state agency

commented on the proposed removal of

§ 192.607. Four operators and the

association favored the idea. One

operator and the state agency disagreed

with removal, believing the rule is

needed to tie a pipeline’s maximum

allowable operating pressure (MAOP) to

its class location. Similarly, the NAPSR

report recommended that we only

remove the past compliance deadlines

from § 192.607, leaving the rest of the

rule in place to regulate the relation of

class location to stress level on highstress pipelines.

Section 192.607 was a transitional

requirement. Its purpose was to

establish plans under which operators

initially determined class locations and

confirmed or revised the MAOPs of

their high-stress pipelines

commensurate with their class

locations. Section 192.607 provides that

the plans had to be executed in

accordance with § 192.611. This latter

section together with § 192.609 are

sufficient to require that operators have

up-to-date class location determinations

for high-stress pipelines, and maintain

the MAOPs of those lines commensurate

with their class locations.

Accordingly, § 192.607 is removed

from part 192.

Section 192.611, Change in Class

Location

Section 192.611 requires confirmation

or revision of a pipeline’s MAOP within

18 months after a change in class

location. RSPA proposed to reorganize

§ 192.611 to clarify the requirement that

the MAOP resulting from confirmation

or revision may not exceed the

pipeline’s previous MAOP. This

requirement is currently set forth in

§ 192.611(a)(3)(ii), suggesting that it

applies only to confirmations or

revisions under paragraph (a)(3), which

is not the intent.

Fourteen TPSSC members voted for

the proposal and one member abstained.

Five operators and one pipelinerelated association commented on the

proposal; each agreed with the proposal.

Section 192.611 is, therefore, adopted as

proposed in the NPRM.

Section 192.614, Damage Prevention

Program

To decrease excavation damage to

pipelines, § 192.614(b)(2) requires

operators to notify excavators and the

public about the need to locate buried

pipelines before excavating. The NPRM

proposed to amend the rule to clarify

that in contrast to the actual notification

required for excavators, only general

notification is required for the public.

General notice can be given through

newspapers, radio, television, or other

means of mass communication, as

appropriate for the public in the vicinity

of the pipeline.

Fourteen TPSSC members voted for

the proposal and one member abstained.

Six pipeline operators and two

pipeline-related organizations

commented. Seven commenters gave

their full or qualified approval and one

commenter opposed the proposal. The

qualified and negative comments were

that the rule should inform operators of

the acceptable means of notification. We

do not feel it is necessary for the rule

to do so, however, because the available

means of giving general public notice

are well known. The amendment to

paragraph (b)(2) is adopted as proposed.

Section 192.619, Maximum Allowable

Operating Pressure: Steel or Plastic

Pipelines

Section 192.619(a) prescribes six

pressure limits for use in determining

the MAOP of steel and plastic pipelines,

the lowest of which establishes the

MAOP. Paragraph (a)(4) limits the

MAOP of furnace butt welded pipe to 60

percent of the mill test pressure.

Paragraph (a)(5) limits the MAOP of

other steel pipe to 85 percent of the

highest test pressure to which the pipe

has been subjected, whether by mill test

or by the post installation test.

RSPA proposed to repeal paragraphs

(a)(4) and (a)(5), primarily because mill

tests are not an adequate MAOP

consideration. However, to assure

consideration of longitudinal joint

efficiency, RSPA also proposed, in

paragraph (a)(2)(iii), that the class

location pressure limit under existing

paragraph (a)(2)(ii) be reduced for

furnace butt welded pipe and lap

welded pipe.

Eleven TPSSC members voted for the

proposal, one member supported it with

a recommended change, two members

opposed it, and one abstained. A

member recommended that RSPA not

adopt proposed paragraph (a)(2)(iii)

because design pressure (under

paragraph (a)(1)) adequately covers

longitudinal joint concerns.

RSPA concurs with this view as

explained below in response to public

comment.

Thirteen operators, four pipelinerelated associations, and one state

agency commented on the proposed

amendment. Two operators, one

pipeline-related association, and one

state agency commented that proposed

paragraph (a)(2)(iii) could require

operators to reduce the operating

pressure of some pipelines or test them

to higher pressures than they previously

were tested, possibly damaging the

pipelines. In addition, some

commenters stated that proposed

paragraph (a)(2)(iii) would duplicate use

of longitudinal joint factors.
Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations 28781

Upon further consideration of our

joint efficiency concern, RSPA concurs

with these comments. Further, RSPA

has no data showing that pipelines

covered by proposed paragraph

(a)(2)(iii) pose a risk that warrants

pressure reduction or retesting.

Therefore, although the final rule

repeals paragraphs (a)(4) and (a)(5) as

proposed, proposed paragraph (a)(2)(iii)

is not adopted.

Section 192.625, Odorization of Gas

Section 192.619(f) requires operators

to conduct periodic samplings of gas to

assure the proper concentration of

odorant. Based on a suggestion by the

Oregon Public Utility Commission, the

NPRM proposed to allow operators of

master meter systems to comply with

this sampling requirement by (1)

receiving written verification from their

gas supplier that odorant meets the

required concentration, and (2)

conducting periodic sniff tests at system

extremities to confirm that the gas

contains odorant.

Thirteen TPSSC members voted for

the proposal, one against, and one

member abstained.

Comments were received from eight

pipeline operators, two pipeline-related

associations, a mobile home association,

and a consultant. One commenter

favored the proposal and 11

commenters opposed it. Commenters

opposing the proposal argued that (1)

gas from a transmission line may be

unodorized; (2) gas suppliers may be

unwilling to provide written verification

of odorization levels because of

potential legal liability and the

increased burden of providing the

written verifications; (3) the frequencies

of sniff tests and written verifications

are unclear; and (4) the proposal would

relax odorant monitoring requirements

on gas systems which, in general, have

a relatively high leakage rate.

The purpose of the proposal was to

ease the sampling requirement for

operators of master meter systems, who

largely do not have the training or

resources to adequately carry out the

requirement. The alternative of getting

written verifications and conducting

sniff tests should be much less

burdensome than purchasing,

maintaining, and using an odorometer

or contracting for odorant testing.

We do not feel this potential

advantage is outweighed by any of the

negative considerations the commenters

raised. First of all, most master meter

system operators purchase odorized gas

from local distribution companies.

Although some operators may receive

unodorized gas from transmission lines

and have to odorize the gas themselves,

this situation does not warrant rejecting

the proposed alternative. Those

operators who receive unodorized gas

simply would not be able to take

advantage of the alternative. Similarly,

operators could not take advantage of

the alternative if their gas suppliers are

unwilling to provide requested

verifications of odorant level. But again

this difficulty is no reason to deny the

alternative to other operators. Regarding

the frequency of verifications and sniff

tests, the proposal called for an initial

written verification from the gas

supplier and periodic sniff tests

thereafter. As with periodic sampling,

the frequency of sniff tests would

depend on the performance history of

odorization in the system: the longer the

period of satisfactory odorization, the

longer the period between tests to assure

proper odorant levels. Testing details

would be specified in the operator’s

operations and maintenance manual

under § 192.605 and reviewed for

adequacy by government inspectors.

Finally, the charge that master meter

systems have a high leakage rate was

unsupported. In a 1984 report, ‘‘Exercise

of Jurisdiction Over Master Meter Gas

Operators,’’ RSPA concluded that

master meter systems probably have a

small leakage rate in comparison to the

leakage rate of utility distribution

systems. And more recent safety data

continue to substantiate that conclusion.

Therefore, after weighing the comments

and favorable TPSSC vote, we have

decided to amend § 192.625(f) as

proposed.

Section 192.705, Transmission Lines:

Patrolling

Operators of transmission lines must

patrol their rights-of-way for indications

of certain adverse conditions. Because

of repeated questions about whether

patrols may be done from the air, RSPA

proposed to change § 192.705 to include

aerial patrols as an optional method of

compliance.

Fourteen TPSSC members voted for

the proposal and one abstained.

Six operators and one pipeline-related

association commented on the proposal.

All but two of these commenters agreed

with the proposal. One commenter that

disagreed said a list of methods of

compliance might be considered

exclusive, thus disallowing other

appropriate methods. The other

commenter that disagreed thought the

rule change unnecessary.

RSPA believes the phrase ‘‘or other

appropriate means of traversing the

right-of-way’’ in the proposed and final

rule eliminates any chance the list of

compliance methods might be

considered exclusive. Also, the need for

the rule change is based on RSPA’s

experience in explaining the meaning of

‘‘patrol’’ under § 192.705. The change to

§ 192.705 is, therefore, adopted as

proposed.

Section 192.709, Transmission Lines:

Record Keeping

Section 192.709 requires operators to

keep various records about transmission

lines for as long as the line remains in

service. RSPA proposed a shorter

retention span that would not affect the

usefulness of records in determining an

operator’s level of compliance effort or

in constructing the history of an

accident or safety problem. RSPA

proposed a minimum 5-year retention

period for records of patrols, surveys,

inspections, and tests, and a 1-year

retention period for records of repairs

on facilities other than pipe. We also

proposed to clarify the information to be

recorded.

Ten TPSSC members voted for the

proposal, three members supported it

with a recommended change, one

member opposed it, and one abstained.

The recommended changes were that 5

years should be changed to 3–5 years or

to 10 years, and that leaks and

linebreaks should also be recorded as

the current § 192.709 provides. The

‘‘No’’ vote was predicated on an alleged

need to keep records of repairs on

valves, compressors, and other nonpipe components for 3–5 years.

As with final § 192.491(c), RSPA’s

main concern about non-pipe records is

that operators keep records for a

minimum period that is compatible

with the occurrence of routine

compliance investigations. The

suggested 3–5 years would not be long

enough, and 10 years would be

excessive. Therefore, we have adopted

the proposed 5-year minimum period.

Repair records, as currently required,

already provide information about leaks

and linebreaks. Thus, requirements to

keep the records of leaks and linebreaks

were omitted from the proposed rule as

unnecessary in view of this existing

requirement.

As for the ‘‘No’’ vote, RSPA has

adopted this minority TPSSC position

as explained below in response to a

comment by a state agency.

Eight operators, two pipeline-related

associations, and one state agency

commented on the proposed changes to

§ 192.709. Five of the operators

supported the proposal without

suggesting any modification.

Two other operators suggested 3 years

as an alternative to the proposed 5-year

minimum. But, as explained above, 3

years is insufficient for compliance

monitoring purposes.
28782 Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations

One operator thought the words ‘‘for

the useful life of the pipe’’ under

proposed § 192.709(a) could be

misinterpreted. This commenter

suggested that instead we adopt the

words used in § 192.491(c): ‘‘for as long

as the pipeline remains in service.’’ We

agree that for consistency the two

sections should use similar wording to

describe similar record retention

requirements. This comment was,

therefore, adopted in the final rule.

One pipeline-related association

recommended that § 192.709 be like 49

CFR 195.404(c), which applies to

hazardous liquid pipelines. We did not

adopt this comment because

§ 195.404(c) specifies a 2-year retention

period for records of inspections and

tests, a time we now find to be

insufficient for purposes of compliance

investigations. Otherwise the two

sections are parallel. The other

association reiterated its previous

comment, which we opposed as

discussed above, that record retention

requirements should be performance

based.

The state agency that commented

objected to the proposed 1-year

retention time for non-pipe repairs,

saying it was inconsistent with the

proposal to keep for at least 5 years

records of inspections that may show

the need for repair. This commenter

reasoned that an inspector might not

find any record showing the needed

repair was made. RSPA agrees that the

two requirements should be congruent.

Therefore, the final rule requires that

records of non-pipe repairs made as a

result of a required patrol, survey,

inspection, or test be kept for the same

time required for records of such patrol,

survey, inspection, or test.

Section 192.721, Distribution Systems:

Patrolling

This section governs the frequency at

which operators must patrol mains in

distribution systems. The regulation is

written in performance terms, except

that mains located where anticipated

movement or loading could cause

leakage must be patrolled at intervals

not exceeding 41⁄2 months, but at least

four times a year. RSPA proposed a

more moderate patrol frequency of twice

a year for such mains in Class 1 or 2

locations, in recognition of the lower

risk in these less densely populated

locations.

Twelve TPSSC members voted for the

proposal, one against, one member

supported it with a proposed change,

and one abstained. The member against

the proposal said that separating

requirements on the basis of class

locations is not always workable for

distribution systems. Our response to

this minority view is given below

following similar comments by

operators.

Four operators and two pipelinerelated associations commented on the

proposal. Three of the operators and one

association supported the proposal, but

the other operator and association

thought class location should not be

used as a basis for patrol frequency in

distribution systems. One commenter

suggested ‘‘rural areas’’ as an alternative

to Class 1 and 2 locations.

RSPA agrees that the class location

concept is not easy to apply in all

distribution systems. Therefore, in the

final rule, we have used the term

‘‘business district’’ to represent areas of

higher risk and ‘‘outside business

districts’’ to represent areas of lower

risk. A similar classification method is

already in place under § 192.723 for

leakage surveys in distribution systems.

The new patrol requirement matches

that method. The term ‘‘rural area’’ was

not adopted because it lacks precedent

in part 192.

Rulemaking Notices and Analyses

Paperwork Reduction Act

This Final Rule revises information

collection requirements in part 192 that

are subject to review by the Office of

Management and Budget (OMB) under

the Paperwork Reduction Act of 1995

(Pub. L. 104–13). The following revised

regulations reduce the existing

paperwork burden by 28,326 hours:

• §§ 192.491 (a) and (b), ‘‘Corrosion

Control Records,’’ reduces the

paperwork burden by 22,486 hours by

reducing the number of records, the

precision of the measurements, and the

amount of time the records must be

kept.

• § 192.709, ‘‘Transmission Lines;

Record keeping,’’ reduces the

paperwork burden by 5,840 hours by

reducing the amount of time the records

must be kept.

Persons are not required to respond to

a collection of information unless it

displays a currently valid OMB control

number. OMB has approved the revised

information collection requirements of

part 192 through May 31, 1999 (OMB

No. 2137–0049).

Executive Order 12866 and DOT

Regulatory Policies and Procedures

OMB considers this final rule to be a

significant regulatory action under

section 3(f) of Executive Order 12866.

Therefore, OMB has reviewed the final

rule. Also, DOT considers the final rule

to be significant under its regulatory

policies and procedures (44 FR 11034,

February 26, 1979).

A final regulatory evaluation has been

prepared and is available in the Docket.

RSPA estimates the changes to existing

rules will result in savings of

$33,000,000 a year, without associated

costs and with no adverse effect on

safety. As discussed above, these

savings come from the use of new

technology, greater flexibility in

constructing, maintaining, and

operating pipelines, improved clarity,

and the elimination of burdensome

requirements.

Regulatory Flexibility Act.

RSPA criteria for small companies or

entities are those with less than

$1,000,000 in revenues and are

independently owned and operated.

Few of the companies subject to this

rulemaking meet these criteria.

Accordingly, based on the facts

available concerning the impact of this

final rule, I certify under Section 605 of

the Regulatory Flexibility Act that this

final rule will not have a significant

economic impact on a substantial

number of small entities.

E. O. 12612

The final rule would not have

substantial direct effects on states, on

the relationship between the Federal

Government and the states, or on the

distribution of power and

responsibilities among the various

levels of Government. Therefore, in

accordance with Executive Order 12612

(52 FR 41685; October 30,1987), RSPA

has determined that the final rule does

not have sufficient federalism

implications to warrant preparation of a

Federalism Assessment.

List of Subjects in 49 CFR Part 192

Incorporation by reference, Natural

gas, Pipeline safety, Reporting and

recordkeeping requirements.

In consideration of the foregoing,

RSPA amends 49 CFR part 192 as

follows:

PART 192—[AMENDED]

1. The authority citation for part 192

continues to read as follows:

Authority: 49 U.S.C. 5103, 60102, 60104,

60108, 60109, 60110, 60113, and 60118; 49

CFR 1.53.

2. In § 192.1, paragraph (b)(1) is

revised and paragraph (b)(4) is added to

read as follows:

§ 192.1 Scope of part.

* * * * *

(b) This part does not apply to:

(1) Offshore pipelines upstream from

the outlet flange of each facility where

hydrocarbons are produced or where
Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations 28783

produced hydrocarbons are first

separated, dehydrated, or otherwise

processed, whichever facility is farther

downstream;

* * * * *

(4) Any pipeline system that

transports only petroleum gas or

petroleum gas/air mixtures to—

(i) Fewer than 10 customers, if no

portion of the system is located in a

public place; or

(ii) A single customer, if the system is

located entirely on the customer’s

premises (no matter if a portion of the

system is located in a public place).

3. In § 192.3, a definition of

‘‘Petroleum gas’’ is added and the

definition of ‘‘Transmission line’’ is

revised to read as follows:

§ 192.3 Definitions.

* * * * *

Petroleum gas means propane,

propylene, butane, (normal butane or

isobutanes), and butylene (including

isomers), or mixtures composed

predominantly of these gases, having a

vapor pressure not exceeding 1434 kPa

(208 psig) at 38°C (100°F).

* * * * *

Transmission line means a pipeline,

other than a gathering line, that:

(a) Transports gas from a gathering

line or storage facility to a distribution

center, storage facility, or large volume

customer that is not downstream from a

distribution center;

(b) Operates at a hoop stress of 20

percent or more of SMYS; or

(c) Transports gas within a storage

field. A large volume customer may

receive similar volumes of gas as a

distribution center, and includes

factories, power plants, and institutional

users of gas.

* * * * *

4. Section 192.5 is revised to read as

follows:

§ 192.5 Class locations.

(a) This section classifies pipeline

locations for purposes of this part. The

following criteria apply to

classifications under this section.

(1) A ‘‘class location unit’’ is an

onshore area that extends 220 yards on

either side of the centerline of any

continuous 1- mile length of pipeline.

(2) Each separate dwelling unit in a

multiple dwelling unit building is

counted as a separate building intended

for human occupancy.

(b) Except as provided in paragraph

(c) of this section, pipeline locations are

classified as follows:

(1) A Class 1 location is:

(i) An offshore area; or

(ii) Any class location unit that has 10

or fewer buildings intended for human

occupancy.

(2) A Class 2 location is any class

location unit that has more than 10 but

fewer than 46 buildings intended for

human occupancy.

(3) A Class 3 location is:

(i) Any class location unit that has 46

or more buildings intended for human

occupancy; or

(ii) An area where the pipeline lies

within 100 yards of either a building or

a small, well-defined outside area (such

as a playground, recreation area,

outdoor theater, or other place of public

assembly) that is occupied by 20 or

more persons on at least 5 days a week

for 10 weeks in any 12-month period.

(The days and weeks need not be

consecutive.)

(4) A Class 4 location is any class

location unit where buildings with four

or more stories above ground are

prevalent.

(c) The length of Class locations 2, 3,

and 4 may be adjusted as follows:

(1) A Class 4 location ends 220 yards

from the nearest building with four or

more stories above ground.

(2) When all buildings intended for

human occupancy within a Class 2 or 3

location are in a single cluster, the class

location ends 220 yards from the nearest

building in the cluster.

5. Section 192.7(a) is revised to read

as follows:

§ 192.7 Incorporation by reference.

(a) Any documents or portions thereof

incorporated by reference in this part

are included in this part as though set

out in full. When only a portion of a

document is referenced, the remainder

is not incorporated in this part.

* * * * *

6. Section 192.11 is revised to read as

follows:

§ 192.11 Petroleum gas systems.

(a) Each plant that supplies petroleum

gas by pipeline to a natural gas

distribution system must meet the

requirements of this part and ANSI/

NFPA 58 and 59.

(b) Each pipeline system subject to

this part that transports only petroleum

gas or petroleum gas/air mixtures must

meet the requirements of this part and

of ANSI/NFPA 58 and 59.

(c) In the event of a conflict between

this part and ANSI/NFPA 58 and 59,

ANSI/NFPA 58 and 59 prevail.

7. Section 192.107(b)(1)(ii) is revised

to read as follows:

§ 192.107 Yield strength (S) for steel pipe.

* * * * *

(b) * * *

(1) * * *

(ii) The lowest yield strength

determined by the tensile tests.

* * * * *

8. Section 192.121 is revised to read

as follows:

§ 192.121 Design of plastic pipe.

Subject to the limitations of § 192.123,

the design pressure for plastic pipe is

determined in accordance with either of

the following formulas:

P S

t

D t

P

S

SDR

= −

= −

2 0 32

2

1

0 32

( ) .

( ) .

Where:

P=Design pressure, gauge, kPa (psig).

S=For thermoplastic pipe, the long-term

hydrostatic strength determined in

accordance with the listed

specification at a temperature equal

to 23°C (73°F), 38°C (100°F), 49°C

(120°F), or 60°C (140°F); for

reinforced thermosetting plastic

pipe, 75,842 kPa (11,000 psi).

t=Specified wall thickness, mm (in).

D=Specified outside diameter, mm (in).

SDR=Standard dimension ratio, the

ratio of the average specified

outside diameter to the minimum

specified wall thickness,

corresponding to a value from a

common numbering system that

was derived from the American

National Standards Institute

preferred number series 10.

9. Section 192.123(b) is revised to

read as follows:

§ 192.123 Design limitations for plastic

pipe.

* * * * *

(b) * * *

(1) Below ¥29°C (¥20°F), or ¥40°C

(¥40°F) if all pipe and pipeline

components whose operating

temperature will be below ¥29°C

(¥20°F) have a temperature rating by

the manufacturer consistent with that

operating temperature; or

(2) Above the following applicable

temperatures:

(i) For thermoplastic pipe, the

temperature at which the long-term

hydrostatic strength used in the design

formula under § 192.121 is determined.

However, if the pipe was manufactured

before May 18, 1978 and its long-term

hydrostatic strength was determined at

23°C (73°F), it may be used at

temperatures up to 38°C (100°F).

(ii) For reinforced thermosetting

plastic pipe, 66°C (150°F).

* * * * *
28784 Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations

10. The introductory text of

§ 192.179(a) is revised to read as

follows:

§ 192.179 Transmission line valves.

(a) Each transmission line, other than

offshore segments, must have

sectionalizing block valves spaced as

follows, unless in a particular case the

Administrator finds that alternative

spacing would provide an equivalent

level of safety:

* * * * *

11. Section 192.203(b)(2) is revised to

read as follows:

§ 192.203 Instrument, control, and

sampling pipe and components.

* * * * *

(b) * * *

(2) Except for takeoff lines that can be

isolated from sources of pressure by

other valving, a shutoff valve must be

installed in each takeoff line as near as

practicable to the point of takeoff.

Blowdown valves must be installed

where necessary.

* * * * *

12. Section 192.227(b) is revised to

read as follows:

§ 192.227 Qualification of welders.

* * * * *

(b) A welder may qualify to perform

welding on pipe to be operated at a

pressure that produces a hoop stress of

less than 20 percent of SMYS by

performing an acceptable test weld, for

the process to be used, under the test set

forth in section I of Appendix C of this

part. Each welder who is to make a

welded service line connection to a

main must first perform an acceptable

test weld under section II of Appendix

C of this part as a requirement of the

qualifying test.

13. In § 192.229, paragraph (c) is

revised and paragraph (d) is added to

read as follows:

§ 192.229 Limitations on welders.

* * * * *

(c) A welder qualified under

§ 192.227(a)—

(1) May not weld on pipe to be

operated at a pressure that produces a

hoop stress of 20 percent or more of

SMYS unless within the preceding 6

calendar months the welder has had one

weld tested and found acceptable under

section 3 or 6 of API Standard 1104,

except that a welder qualified under an

earlier edition previously listed in

Appendix A of this part may weld but

may not requalify under that earlier

edition; and

(2) May not weld on pipe to be

operated at a pressure that produces a

hoop stress of less than 20 percent of

SMYS unless the welder is tested in

accordance with paragraph (c)(1) of this

section or requalifies under paragraph

(d)(1) or (d)(2) of this section.

(d) A welder qualified under

§ 192.227(b) may not weld unless—

(1) Within the preceding 15 calendar

months, but at least once each calendar

year, the welder has requalified under

§ 192.227(b); or

(2) Within the preceding 71⁄2 calendar

months, but at least twice each calendar

year, the welder has had—

(i) A production weld cut out, tested,

and found acceptable in accordance

with the qualifying test; or

(ii) For welders who work only on

service lines 2 inches or smaller in

diameter, two sample welds tested and

found acceptable in accordance with the

test in section III of Appendix C of this

part.

14. Section 192.241(c) is revised to

read as follows:

§ 192.241 Inspection and test of welds.

* * * * *

(c) The acceptability of a weld that is

nondestructively tested or visually

inspected is determined according to

the standards in section 6 of API

Standard 1104. However, if a girth weld

is unacceptable under those standards

for a reason other than a crack, and if

the Appendix to API Standard 1104

applies to the weld, the acceptability of

the weld may be further determined

under that Appendix.

15. Section 192.243(d)(4) is revised to

read as follows:

§ 192.243 Nondestructive testing.

* * * * *

(d) * * *

(4) At pipeline tie-ins, including tieins of replacement sections, 100

percent.

* * * * *

16. In § 192.281, paragraph (c)(3) is

redesignated as paragraph (c)(4) and

paragraph (c)(3) is added to read as

follows:

§ 192.281 Plastic pipe.

* * * * *

(c) * * *

(3) An electrofusion joint must be

joined utilizing the equipment and

techniques of the fittings manufacturer

or equipment and techniques shown, by

testing joints to the requirements of

§ 192.283(a)(1)(iii), to be at least

equivalent to those of the fittings

manufacturer.

* * * * *

17. In § 192.283, the word ‘‘or’’ is

removed from the end of paragraph

(a)(1)(i), paragraph (a)(1)(ii) is revised,

and paragraph (a)(1)(iii) is added to read

as follows:

§ 192.283 Plastic pipe; qualifying joining

procedures.

(a) * * *

(1) * * *

(ii) In the case of thermosetting plastic

pipe, paragraph 8.5 (Minimum

Hydrostatic Burst Pressure) or paragraph

8.9 (Sustained Static Pressure Test) of

ASTM D2517; or

(iii) In the case of electrofusion

fittings for polyethylene pipe and

tubing, paragraph 9.1 (Minimum

Hydraulic Burst Pressure Test),

paragraph 9.2 (Sustained Pressure Test),

paragraph 9.3 (Tensile Strength Test), or

paragraph 9.4 (Joint Integrity Tests) of

ASTM Designation F1055.

* * * * *

18. Section 192.317(a) is revised to

read as follows:

§ 192.317 Protection from hazards.

(a) The operator must take all

practicable steps to protect each

transmission line or main from

washouts, floods, unstable soil,

landslides, or other hazards that may

cause the pipeline to move or to sustain

abnormal loads. In addition, the

operator must take all practicable steps

to protect offshore pipelines from

damage by mud slides, water currents,

hurricanes, ship anchors, and fishing

operations.

* * * * *

19. Section 192.319(c) is revised to

read as follows:

§ 192.319 Installation of pipe in a ditch.

* * * * *

(c) All offshore pipe in water at least

12 feet deep but not more than 200 feet

deep, as measured from the mean low

tide, except pipe in the Gulf of Mexico

and its inlets under 15 feet of water,

must be installed so that the top of the

pipe is below the natural bottom unless

the pipe is supported by stanchions,

held in place by anchors or heavy

concrete coating, or protected by an

equivalent means. Pipe in the Gulf of

Mexico and its inlets under 15 feet of

water must be installed so that the top

of the pipe is 36 inches below the

seabed for normal excavation or 18

inches for rock excavation.

20. In § 192.321, paragraph (a) is

revised and paragraph (g) is added to

read as follows:

§ 192.321 Installation of plastic pipe.

(a) Plastic pipe must be installed

below ground level unless otherwise

permitted by paragraph (g) of this

section.

* * * * *

(g) Uncased plastic pipe may be

temporarily installed above ground level

under the following conditions:
Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations 28785

(1) The operator must be able to

demonstrate that the cumulative

aboveground exposure of the pipe does

not exceed the manufacturer’s

recommended maximum period of

exposure or 2 years, whichever is less.

(2) The pipe either is located where

damage by external forces is unlikely or

is otherwise protected against such

damage.

(3) The pipe adequately resists

exposure to ultraviolet light and high

and low temperatures.

21. In § 192.327, the introductory text

of paragraph (a) is revised, paragraph (e)

is revised, and paragraphs (f) and (g) are

added to read as follows:

§ 192.327 Cover.

* * * * *

(a) Except as provided in paragraphs

(c), (e), (f), and (g) of this section, each

buried transmission line must be

installed with a minimum cover as

follows:

* * * * *

(e) Except as provided in paragraph

(c) of this section, all pipe installed in

a navigable river, stream, or harbor must

be installed with a minimum cover of 48

inches in soil or 24 inches in

consolidated rock between the top of the

pipe and the natural bottom.

(f) All pipe installed offshore, except

in the Gulf of Mexico and its inlets,

under water not more than 200 feet

deep, as measured from the mean low

tide, must be installed as follows:

(1) Except as provided in paragraph

(c) of this section, pipe under water less

than 12 feet deep, must be installed

with a minimum cover of 36 inches in

soil or 18 inches in consolidated rock

between the top of the pipe and the

natural bottom.

(2) Pipe under water at least 12 feet

deep must be installed so that the top

of the pipe is below the natural bottom,

unless the pipe is supported by

stanchions, held in place by anchors or

heavy concrete coating, or protected by

an equivalent means.

(g) All pipelines installed under water

in the Gulf of Mexico and its inlets, as

defined in § 192.3, must be installed in

accordance with § 192.612(b)(3).

22. Section 192.375(a) is revised to

read as follows:

§ 192.375 Service lines: Plastic.

(a) Each plastic service line outside a

building must be installed below ground

level, except that—

(1) It may be installed in accordance

with § 192.321(g); and

(2) It may terminate above ground

level and outside the building, if—

(i) The above ground level part of the

plastic service line is protected against

deterioration and external damage; and

(ii) The plastic service line is not used

to support external loads.

* * * * *

23. In § 192.455, paragraphs (a)(2) and

(f)(1) are revised to read as follows:

§ 192.455 External corrosion control:

Buried or submerged pipelines installed

after July 31, 1971.

(a) * * *

(2) It must have a cathodic protection

system designed to protect the pipeline

in accordance with this subpart,

installed and placed in operation within

1 year after completion of construction.

* * * * *

(f) * * *

(1) For the size fitting to be used, an

operator can show by test, investigation,

or experience in the area of application

that adequate corrosion control is

provided by the alloy composition; and

* * * * *

24. Section 192.475(c) is revised to

read as follows:

§ 192.475 Internal corrosion control:

General.

* * * * *

(c) Gas containing more than 0.25

grain of hydrogen sulfide per 100

standard cubic feet (4 parts per million)

may not be stored in pipe-type or bottletype holders.

25. Section 192.485(c) is added to

read as follows:

§ 192.485 Remedial measures:

Transmission lines.

* * * * *

(c) Under paragraphs (a) and (b) of

this section, the strength of pipe based

on actual remaining wall thickness may

be determined by the procedure in

ASME/ANSI B31G or the procedure in

AGA Pipeline Research Committee

Project PR 3–805 (with RSTRENG disk).

Both procedures apply to corroded

regions that do not penetrate the pipe

wall, subject to the limitations

prescribed in the procedures.

26. Section 192.491 is revised to read

as follows:

§ 192.491 Corrosion control records.

(a) Each operator shall maintain

records or maps to show the location of

cathodically protected piping, cathodic

protection facilities, galvanic anodes,

and neighboring structures bonded to

the cathodic protection system. Records

or maps showing a stated number of

anodes, installed in a stated manner or

spacing, need not show specific

distances to each buried anode.

(b) Each record or map required by

paragraph (a) of this section must be

retained for as long as the pipeline

remains in service.

(c) Each operator shall maintain a

record of each test, survey, or inspection

required by this subpart in sufficient

detail to demonstrate the adequacy of

corrosion control measures or that a

corrosive condition does not exist.

These records must be retained for at

least 5 years, except that records related

to §§ 192.465 (a) and (e) and 192.475(b)

must be retained for as long as the

pipeline remains in service.

27. Section 192.553(d) is revised to

read as follows:

§ 192.553 General requirements.

* * * * *

(d) Limitation on increase in

maximum allowable operating pressure.

Except as provided in § 192.555(c), a

new maximum allowable operating

pressure established under this subpart

may not exceed the maximum that

would be allowed under this part for a

new segment of pipeline constructed of

the same materials in the same location.

However, when uprating a steel

pipeline, if any variable necessary to

determine the design pressure under the

design formula (§ 192.105) is unknown,

the MAOP may be increased as

provided in § 192.619(a)(1).

§ 192.607 [Removed and reserved]

28. Section 192.607 is removed and

reserved.

§ 192.611 [Amended]

29. In § 192.611, paragraphs (b) and

(c) are redesignated as (c) and (d),

respectively; paragraph (a)(3)(ii) is

redesignated as paragraph (b), and

paragraph (a)(3)(iii) is redesignated as

paragraph (a)(3)(ii).

30. In § 192.614, the introductory text

of paragraph (b)(2) is revised to read as

follows:

§ 192.614 Damage prevention program.

* * * * *

(b) * * *

(2) Provide for general notification of

the public in the vicinity of the pipeline

and actual notification of the persons

identified in paragraph (b)(1) of the

following as often as needed to make

them aware of the damage prevention

program:

* * * * *

31. In § 192.619, paragraph (a)(1) is

revised to read as follows, paragraphs

(a)(4) and (a)(5) are removed, paragraph

(a)(6) is redesignated as paragraph (a)(4),

and paragraph (b) is amended by

removing ‘‘(a)(6)’’ and adding ‘‘(a)(4)’’ in

its place:

§ 192.619 Maximum allowable operating

pressure: Steel or plastic pipelines.

(a) * * *
28786 Federal Register / Vol. 61, No. 110 / Thursday, June 6, 1996 / Rules and Regulations

(1) The design pressure of the weakest

element in the segment, determined in

accordance with subparts C and D of

this part. However, for steel pipe in

pipelines being converted under

§ 192.14 or uprated under subpart K of

this part, if any variable necessary to

determine the design pressure under the

design formula (§ 192.105) is unknown,

one of the following pressures is to be

used as design pressure:

(i) Eighty percent of the first test

pressure that produces yield under

section N5.0 of Appendix N of ASME

B31.8, reduced by the appropriate factor

in paragraph (a)(2)(ii) of this section; or

(ii) If the pipe is 324 mm (123⁄4 in) or

less in outside diameter and is not

tested to yield under this paragraph,

1379 kPa (200 psig).

* * * * *

32. Section 192.625 (f) is revised to

read as follows:

§ 192.625 Odorization of gas.

* * * * *

(f) Each operator shall conduct

periodic sampling of combustible gases

to assure the proper concentration of

odorant in accordance with this section.

Operators of master meter systems may

comply with this requirement by—

(1) Receiving written verification from

their gas source that the gas has the

proper concentration of odorant; and

(2) Conducting periodic ‘‘sniff’’ tests

at the extremities of the system to

confirm that the gas contains odorant.

33. Section 192.705(c) is added to

read as follows:

§ 192.705 Transmission lines: Patrolling.

* * * * *

(c) Methods of patrolling include

walking, driving, flying or other

appropriate means of traversing the

right-of-way.

34. Section 192.709 is revised to read

as follows:

§ 192.709 Transmission lines: Record

keeping.

Each operator shall maintain the

following records for transmission lines

for the periods specified:

(a) The date, location, and description

of each repair made to pipe (including

pipe-to-pipe connections) must be

retained for as long as the pipe remains

in service.

(b) The date, location, and description

of each repair made to parts of the

pipeline system other than pipe must be

retained for at least 5 years. However,

repairs generated by patrols, surveys,

inspections, or tests required by

subparts L and M of this part must be

retained in accordance with paragraph

(c) of this section.

(c) A record of each patrol, survey,

inspection, and test required by

subparts L and M of this part must be

retained for at least 5 years or until the

next patrol, survey, inspection, or test is

completed, whichever is longer.

35. Section 192.721(b) is revised to

read as follows:

§ 192.721 Distribution systems: Patrolling.

* * * * *

(b) Mains in places or on structures

where anticipated physical movement

or external loading could cause failure

or leakage must be patrolled—

(1) In business districts, at intervals

not exceeding 41⁄2 months, but at least

four times each calendar year; and

(2) Outside business districts, at

intervals not exceeding 71⁄2 months, but

at least twice each calendar year.

36. In Appendix A, section I. is

amended by redesignating subsections

A. through F. as subsections B. through

G., respectively, and by adding a new

subsection A.; and section II. is

amended by redesignating subsections

A. through E. as subsections B. through

F., respectively, by adding a new

subsection A. and a new subsection 12.

to newly designated C., by redesignating

newly designated subsections D.3.

through D.5. as subsections D.5. through

D.7., respectively, and by adding new

subsections D.3. and D.4. as follows:

Appendix A—Incorporated by

Reference

I. * * *

A. American Gas Association (AGA), 1515

Wilson Boulevard, Arlington, VA 22209.

* * * * *

II. * * *

A. American Gas Association (AGA):

1. AGA Pipeline Research Committee,

Project PR–3–805, ‘‘A Modified Criterion for

Evaluating the Remaining Strength of

Corroded Pipe’’ (December 22, 1989).

* * * * *

C. * * *

12. ASTM Designation: F1055 ‘‘Standard

Specification for Electrofusion Type

Polyethylene Fittings for Outside Diameter

Controlled Polyethylene Pipe and Tubing’’

(F1055–95).

D. * * *

3. ASME/ANSI B31G ‘‘Manual for

Determining the Remaining Strength of

Corroded Pipelines’’ (1991).

4. ASME/ANSI B31.8 ‘‘Gas Transmission

and Distribution Piping Systems’’ (1995).

* * * * *

Issued in Washington, DC, on May 28,

1996.

D.K. Sharma,

Administrator.

[FR Doc. 96–13787 Filed 6–5–96; 8:45 am]

BILLING CODE 4910–60–P

DEPARTMENT OF COMMERCE

National Oceanic and Atmospheric

Administration

50 CFR Part 663

[Docket No. 960304057–6151–02; I.D.

020596A]

RIN 0648–AH84

Pacific Coast Groundfish Fishery;

Framework for Treaty Tribe Harvest of

Pacific Groundfish and 1996 Makah

Whiting Allocation

AGENCY: National Marine Fisheries

Service (NMFS), National Oceanic and

Atmospheric Administration (NOAA),

Commerce.

ACTION: Final rule.

SUMMARY: NMFS is establishing a

framework to implement the

Washington coastal treaty Indian tribes’

rights to harvest Pacific groundfish.

NMFS also announces the allocation of

15,000 metric tons (mt) of Pacific

whiting to the Makah Indian Tribe

(Makah) for 1996 only, under the

provisions of the regulatory framework.

EFFECTIVE DATE: May 31, 1996.

ADDRESSES: Copies of the

Environmental Assessment/Regulatory

Impact Review/Initial Regulatory

Flexibility Analysis (EA/RIR/IRFA) may

be obtained from the Director,

Northwest Region, NMFS, 7600 Sand

Point Way NE., BIN C15700, Seattle,

WA 98115.

FOR FURTHER INFORMATION CONTACT:

William L. Robinson at 206–526–6140.

SUPPLEMENTARY INFORMATION: NMFS is

issuing this rule under the authority of

the Pacific Coast Groundfish Fishery

Management Plan (FMP) and the

Magnuson Fishery Conservation and

Management Act (Magnuson Act). It

amends the FMP’s implementing

regulations to establish a clear

procedure to accommodate the

Washington coastal treaty Indian tribes’

rights to harvest Pacific groundfish. At

the same time, NMFS is modifying the

groundfish regulations to consolidate

regulations on treaty Indian fishing into

one section and to provide for the treaty

trawl harvest of midwater groundfish

species. Under the provisions of this

rule, NMFS announces the allocation of

15,000 mt of Pacific whiting to the

Makah for 1996. For purposes of this

rule, Washington coastal treaty Indian

tribes means the Hoh, Makah, and

Quileute Indian Tribes and the Quinault

Indian Nation.

This rule is implemented under

authority of section 305(d) of the

Magnuson Act, which gives NMFS,