Federal Register / Vol. 72, No. 77 / Monday, April 23, 2007 / Rules and Regulations 20055 

(156.65 MHz) and channel 16 (156.8 

MHz). 

(d) Enforcement period. The security 

zone will be enforced from 3 p.m. until 

10 p.m. on May 11, 2007; from 9 a.m. 

to 11 p.m. on May 12, 2007; and from 

9 a.m. to 10 p.m. on May 13, 2007. 

(e) Effective period. This regulation is 

effective from 3 p.m. on May 11, 2007, 

to 10 p.m. on May 13, 2007. 

Dated: April 6, 2007. 

Patrick B. Trapp, 

Captain, U.S. Coast Guard, Captain of the 

Port, Hampton Roads. 

[FR Doc. E7–7669 Filed 4–20–07; 8:45 am] 

BILLING CODE 4910–15–P 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

49 CFR Part 192 

[Docket No. PHMSA–2005–22642] 

RIN 2137–AE09 

Pipeline Safety: Design and 

Construction Standards To Reduce 

Internal Corrosion in Gas 

Transmission Pipelines 

AGENCY: Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA), Department of 

Transportation. 

ACTION: Final rule. 

SUMMARY: This final rule requires 

operators to use design and construction 

features in new and replaced gas 

transmission pipelines to reduce the 

risk of internal corrosion. The design 

and construction features required by 

this rule will reduce the risk of internal 

corrosion and related pipeline failures 

by reducing the potential for 

accumulation of liquids and facilitating 

operation and maintenance practices 

that address internal corrosion. 

DATES: This final rule takes effect May 

23, 2007. 

FOR FURTHER INFORMATION CONTACT: 

Barbara Betsock by phone at (202) 366–

4361, by fax at (202) 366–4566, or by email at barbara.betsock@dot.gov. 

SUPPLEMENTARY INFORMATION: 

Background 

We initiated this rulemaking 

proceeding in response to a 2003 

recommendation of the National 

Transportation Safety Board (NTSB) and 

corresponding advice of the Technical 

Pipeline Safety Standards Committee 

(TPSSC). The NTSB recommendation 

arose out of its investigation of the 

August 19, 2000 gas transmission 

pipeline explosion near Carlsbad, New 

Mexico in which 12 people were killed. 

In its accident investigation report, 

PAR–03–01, issued February 11, 2003, 

the NTSB concluded that the immediate 

cause of the Carlsbad pipeline failure 

was severe internal corrosion. The 

NTSB recommended that PHMSA (1) 

require that new and replaced gas 

transmission pipelines be designed and 

constructed with features to mitigate 

internal corrosion; (2) require operators 

to ensure that their internal corrosion 

control programs address water and 

other contaminants in the corrosion 

process; and (3) change its Federal 

inspection to ensure adequate 

assessments of pipeline operator safety 

programs. In 2004 and 2005, the NTSB 

closed as acceptable PHMSA actions to 

respond to the second and third 

recommendations. This rulemaking 

proceeding responds to the first 

recommendation. 

On December 15, 2005, PHMSA 

published a notice of proposed 

rulemaking (NPRM) in the Federal 

Register (70 FR 74262) proposing to 

require operators to use design and 

construction features to reduce the risk 

of internal corrosion in transmission 

pipelines. As we explained in the 

NPRM, the proposed rule was intended 

to prevent the risk of internal corrosion 

by applying knowledge and experience 

about the causes and prevention of 

corrosion to design of pipelines. The 

incorporation of design features to 

address internal corrosion improves the 

ability of the operator to prevent 

internal corrosion and facilitates 

maintenance activities to control 

internal corrosion. 

The basic requirements of this final 

rule are similar to those proposed in the 

NPRM. New and replaced gas 

transmission pipelines must be 

configured to reduce the risk that 

liquids will collect in the line; have 

effective liquid removal features; and 

allow use of corrosion monitoring 

devices in locations with significant 

potential for internal corrosion. When 

an operator changes the configuration of 

a pipeline, the operator must consider 

and address the impact the changes will 

have on the risk of internal corrosion in 

an existing downstream pipeline. This 

final rule does not supersede or negate 

the requirement to address internal 

corrosion during operation and 

maintenance activities. Designing and 

building a pipeline in accordance with 

the final rule will not prevent internal 

corrosion unless the operator also 

follows a well-planned maintenance 

program. For example, incorporating 

equipment to measure gas quality will 

not prevent internal corrosion unless it 

is used and the operator acts on the 

results. 

Advisory Committee Consideration 

PHMSA briefed the TPSSC in June 

2005 and considered the Committee’s 

advice in developing the NPRM. 

PHMSA presented the NPRM and 

regulatory evaluation to the TPSSC for 

formal consideration at their meeting on 

June 28, 2006. At that meeting, members 

expressed concern that the proposed 

documentation requirements were 

burdensome. TPSSC members asked for 

information about whether PHMSA 

intended to require detailed 

documentation of every action taken 

during design and construction; what 

alternatives commenters suggested; and 

how the NTSB reached its 

recommendation. PHMSA provided 

additional information in the form of a 

concept paper on the documentation 

needed for compliance, an expanded 

summary of comments, and excerpts 

from the NTSB report on the Carlsbad 

incident. PHMSA briefed the TPSSC at 

a meeting on August 26, 2006 and 

outlined changes we intended to make 

in response to comments. A few 

members expressed individual concerns 

about particular issues. These concerns 

are addressed in the remainder of this 

preamble. The TPSSC voted 

unanimously to support the NPRM as 

technically feasible, reasonable, costeffective and practicable, provided the 

final rule included the changes PHMSA 

outlined at the meeting. In addition, the 

TPSSC advised PHMSA to hold 

discussions in an open forum on 

enforcement criteria, including protocol 

development and recordkeeping. The 

final rule is consistent with the 

discussion at the TPSSC meeting. In 

accordance with the TPSSC’s advice, 

PHMSA intends to convene an open 

forum soon after the final rule is issued. 

Comments on the NPRM 

PHMSA received public comments on 

the NPRM from 18 commenters, 13 of 

them operators of gas transmission 

pipelines. The Gas Piping Technology 

Committee, Interstate Natural Gas 

Association of America, American Gas 

Association, the Texas Pipeline 

Association, and the Iowa Utilities 

Board also commented. Commenters 

agreed with the basic concept of the 

proposal—addressing internal corrosion 

risks during design and construction. 

Most commenters viewed the 

documentation requirements of the 

proposed rule as burdensome. Some 

expressed confusion about what an 

operator would have to do to comply. 

As an example, some questioned 


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20056 Federal Register / Vol. 72, No. 77 / Monday, April 23, 2007 / Rules and Regulations 

1From NTSB report PAR 03–01: 

The Safety Board concludes that, as a likely result 

of the partial clogging of the drip upstream of the 

rupture location, some liquids bypassed the drip, 

continued through the pipeline, and accumulated 

and caused corrosion at the eventual rupture site 

where pipe bending had created a low point in the 

pipeline. 

Periodic use of cleaning pigs can remove water 

and other liquid and solid contaminants from a 

pipeline. One of the considerations for the design 

and construction of a cleaning pig system is to make 

provisions for effective collection and removal of 

the accumulated materials from the pipeline after 

pigging [* * *] 

[* * *] The Safety Board therefore concludes that 

if the accident section of pipeline 1103 had been 

able to accommodate cleaning pigs, and if cleaning 

pigs had been used regularly with the resulting 

liquids and solids thoroughly removed from the 

pipeline after each pig run, the internal corrosion 

that developed in this section of pipe would likely 

have been less severe. 

whether the proposed rule would 

require an operator to conduct an 

engineering analysis to justify variations 

in elevation due to following the 

contours of the land. PHMSA has 

revised the rule text to clarify the final 

rule and refine the documentation 

requirements to ensure compliance 

without excessive burden. We discuss 

the major comments and how we are 

addressing them more specifically in the 

following paragraphs. 

Redundancy 

Some commenters contend existing 

regulations in 49 CFR part 192 make 

this rulemaking redundant and 

unnecessary. These commenters point 

to regulations requiring operators to 

design new pipeline to allow the use of 

instrumented internal inspection 

devices (§ 192.150); to check for internal 

corrosion when pipe is removed 

(§ 192.475); to maintain continuing 

surveillance (§ 192.613); and to develop 

integrity management programs 

addressing internal corrosion (subpart 

O). However, none of the regulations 

cited by commenters squarely addresses 

the goals of this rulemaking and the 

NTSB recommendation. 

The purpose of § 192.150 is to allow 

internal inspection to address a variety 

of pipeline risks. Section 192.150 

incidentally aids internal corrosion 

control because a pipeline designed to 

allow internal inspection can also 

accommodate cleaning pigs. Cleaning 

pigs remove liquids and contaminants 

from a pipeline as part of corrosion 

control. In its report on the 2000 

Carlsbad incident, the NTSB recognized 

the value of cleaning pigs and their 

limitations in addressing the internal 

corrosion issues in the Carlsbad 

incident.1 The NTSB recommended 

additional regulation to require design 

features focused on internal corrosion. 

In addition, unlike this final rule, 

§ 192.150 does not apply to gathering 

lines. 

The regulations requiring an operator 

to check line pipe removed from a 

pipeline for signs of internal corrosion 

(§ 192.475) and to maintain continuing 

surveillance (§ 192.613) are not design 

requirements. These regulations are 

among those operation and maintenance 

regulations requiring operators to 

monitor their pipelines and collect and 

analyze information about safety risks. 

But these practices usually only enable 

operators to detect signs of corrosion. 

The actions recommended by the NTSB 

and addressed in this final rule reduce 

the risk that internal corrosion will even 

initiate by designing and constructing 

pipelines to reduce that risk in the first 

place. Requiring operators to design 

their systems to reduce the risk of 

internal corrosion neither duplicates nor 

obviates the need to detect and monitor 

internal corrosion. 

Some commenters said the proposed 

rule did not take into account the 

internal corrosion management plans 

required by the integrity management 

regulations (subpart O). In fact, we 

believe that the final rule will 

complement the existing requirements 

under subpart O. Subpart O applies only 

to pipelines in high consequence areas 

(HCAs). In those areas, it supplements 

the safety protection provided by the 

minimum standards. This final rule sets 

a minimum standard for design and 

construction applicable to all onshore 

pipelines, regardless of location. For 

pipeline in an HCA, compliance with 

the new standard will facilitate 

addressing the risk of internal corrosion 

under an integrity management 

program. For example, § 192.927(c)(4) 

requires an operator to continually 

monitor covered segments where 

internal corrosion has been identified. A 

segment constructed in accordance with 

this final rule will have liquid removal 

features and allow the use of 

appropriate monitoring devices. 

Exceptions Based on What the Operator 

Expects To Occur During Operations 

Many commenters requested an 

exception to the design and 

construction requirements if the 

operator believes liquids will not pose 

a problem in the line. Commenters 

suggested several variations. Some 

commenters suggested that we establish 

an exception applicable if the operator 

confirms liquids will not present an 

uncontrolled threat (presumably 

because of planned corrosion control 

activities). Others suggested requiring 

design and construction features only 

where corrosive gas is transported. 

Others pointed to areas without a 

history of internal corrosion and 

suggested that the rule should not apply 

to pipelines installed in these areas. 

PHMSA does not agree with the 

suggestions of these commenters and, 

accordingly, is not establishing 

exceptions to design and construction 

requirements based on expected 

operations. An operator needs to 

include internal corrosion control 

measures in operation and maintenance 

programs. Relying on these operation 

and maintenance programs alone to 

control internal corrosion misses the 

safety and economic benefit from good 

design. Building features to reduce the 

risk of corrosion into new pipelines 

costs little and provides additional and 

fuller protection against internal 

corrosion. Even where operators do not 

expect to have liquids enter the 

pipeline, one commenter noted that an 

operator cannot rule out upset 

conditions which can result in the 

introduction of liquids. These can occur 

when there is an operational error; 

tertiary recovery introduces liquids; gas 

comes from a new or different area of 

the same field; gas from a different 

operator joins the gas stream; equipment 

fails; or other causes. The increased risk 

of internal corrosion such a situation 

causes, albeit possibly small, justifies 

the minimal incremental cost of 

incorporating the measures required in 

the final rule. However, in the interest 

of cost effectiveness, PHMSA agrees 

with the need to provide operators 

flexibility to select design and 

construction options fitting the relative 

risks that there will be liquids in the 

pipeline in the future. 

Exceptions for Particular Types of 

Facilities 

A few commenters requested that 

PHMSA carve out exceptions to the 

final rule for particular types of pipeline 

facilities. We address these comments in 

the following paragraphs, by reference 

to the particular pipeline facilities in 

issue. 

Offshore pipelines. The Interstate 

Natural Gas Association of America and 

one large gas transmission operator 

requested that PHMSA carve out an 

exception for offshore lines. Among the 

reasons given were the lower risk to 

public safety in the offshore 

environment and the impossibility of 

engineering out the effects of dips and 

low spots offshore. PHMSA agrees that 

offshore lines should be excepted from 

the final rule. 

Although there have been serious gas 

incidents offshore, these have been 

caused by outside force damage 

sufficient to rupture the pipeline, such 

as an anchor dragging or vessel 


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Federal Register / Vol. 72, No. 77 / Monday, April 23, 2007 / Rules and Regulations 20057 

2The only fire was almost instantaneously 

extinguished by the water. 

3Based on data reported for incidents occurring 

between 2000 and 2005. 

grounding. This sort of damage includes 

sources of ignition from vessels passing 

overhead. In contrast, a corrosion leak 

in an offshore gas pipeline poses less 

risk to people. Unless corrosion is 

widespread, a corrosion failure is likely 

to leak rather than rupture and is not 

likely to pose a threat to people. It is 

highly unlikely that a vessel would pass 

over the underwater pipeline at the 

moment of rupture and provide both a 

source of ignition triggering a fire and 

people to be killed or injured. Between 

2000 and 2005, there were more than 

twice as many internal corrosion 

incidents offshore as onshore, but less 

damage, even though damage includes 

the cost of lost gas and repair to the 

underwater pipeline. There have been 

no injuries or fatalities.2

Finally, as noted by the commenters, 

there are more limited design and 

construction options available for 

offshore pipelines. Pipelines commonly 

follow the contours of the seabed with 

its natural low points. Installing and 

operating liquid removal equipment is 

not possible at low points in deep water. 

Some new pipelines are being installed 

in water more than one mile deep, 

complicating the under water pipeline 

design process. Control of liquids in the 

gas stream is already a critical factor in 

deep water pipeline construction and 

operation. 

Moreover, adopting this exception 

will not leave offshore pipelines 

unprotected or allow an operator to 

ignore the risk of internal corrosion. 

Existing regulations in subparts I and L 

require operators of offshore pipelines 

to address internal corrosion during 

operation and maintenance. 

Gathering lines. The only regulated 

gas gathering lines are those in 

populated areas, where the risk of injury 

or property damage in the event of 

failure is greatest. By their very nature, 

gathering lines regularly transport gas 

containing liquids—a combination 

known to cause corrosion over time. 

Approximately a third of onshore 

incidents caused by internal corrosion 

involve gathering lines.3 None of the 

commenters challenged these basic 

facts. PHMSA does not except gathering 

lines from this final rule. 

At least one commenter suggested that 

gathering lines were not within the 

scope of the NPRM in this rulemaking. 

That is not the case. When PHMSA 

issued the NPRM in December 2005, gas 

gathering lines in non-rural areas were 

subject to the same regulations 

applicable to transmission pipelines (49 

CFR 192.9 (2005)). The only exceptions 

were the requirement that new pipelines 

accommodate internal inspection 

devices (§ 192.150) and integrity 

management regulations (subpart O). 

PHMSA published a Supplemental 

Notice of Proposed Rulemaking 

(SNPRM) proposing changes to 

regulation of gathering lines on October 

3, 2005 (70 FR 57536). The SNPRM on 

gathering lines proposed to continue to 

subject gathering lines to most 

regulations applicable to transmission 

pipelines, including both corrosion 

control and design and construction 

requirements. The final rule on 

gathering lines continued to subject 

gathering lines to corrosion control and 

design and construction requirements 

such as this final rule (71 FR 13289; 

March 15, 2006). 

Compressor stations. PHMSA is not 

persuaded that the final rule should 

except compressor stations. The 

commenter suggesting an exception did 

not offer a reason, and we cannot 

discern one. Compressors do not operate 

well when liquids are present in the gas 

flow. Actions to remove liquid before it 

enters the compressor may result in 

liquid accumulation in the compressor 

station piping. About forty percent of 

the damage caused by internal corrosion 

onshore incidents between 2000 and 

2005 was due to incidents at compressor 

stations. People work in compressor 

stations. They also live near compressor 

stations, particularly in suburban 

locations in which there has been 

significant development since the 

transmission pipelines were 

constructed. 

Placement Within 49 CFR Part 192 

Several commenters suggest subpart 

I—Requirements for Corrosion 

Control—is the wrong place for a rule 

addressing internal corrosion control in 

design and construction. Commenters 

cite two reasons for their position. First, 

the regulations in subpart I primarily 

address operation and maintenance 

requirements. These requirements apply 

to pipelines existing when the 

regulations are issued. Design and 

construction requirements, such as 

those in the final rule, apply only to 

new and replaced pipelines. The 

commenters suggest PHMSA place these 

requirements applicable only to new 

and replaced pipelines in one of the 

subparts of 49 CFR part 192 which 

contain no requirements applicable to 

existing pipelines. Second, some 

commenters suggest that operators 

designing and constructing pipelines 

might overlook design and construction 

requirements placed in subpart I. 

Commenters who addressed the issue 

were not uniform in their suggestions 

for alternate placement within Part 192. 

They suggest placement in subpart C—

Pipe Design, subpart D—Design of 

Pipeline Components, or subpart G—

General Construction Requirements for 

Transmission Lines and Mains. 

Some regulations in subpart I already 

include design and construction 

requirements, such as requirements for 

pipe coating. PHMSA believes 

consolidating corrosion control 

requirements strengthens the planning 

aspects of this regulation. To address 

commenters’ concerns, PHMSA has 

reworded the final rule to be consistent 

with other design and construction 

requirements in the regulations. We 

have also added an applicability date to 

the final rule clearly indicating the nonretroactive effect of the design and 

construction requirements. Finally, the 

final rule cross references subpart I in 

subpart D to alert those designing 

pipelines of the need to consult 

corrosion control requirements. 

Recordkeeping 

Many commenters and the TPSSC 

expressed concern about the 

recordkeeping provision proposed in 

the NPRM, contending it would be 

costly, difficult to adhere to, and 

burdensome. PHMSA agrees. Operators 

normally maintain as-built drawings 

and other construction records. These 

records may already contain adequate 

explanation of variances. If not, some 

additional explanation will be 

necessary. We have modified the final 

rule to require maintenance of records 

demonstrating compliance. 

Changes Affecting Downstream Pipeline 

Few commenters discussed the 

proposal to require an operator to 

address the effect changes to an existing 

pipeline would have on the risk of 

internal corrosion in the downstream 

portions of the pipeline. The Texas 

Pipeline Association noted that the 

proposal matched what prudent 

operators already do and that the 

proposed standard was appropriate. 

Another commenter noted the proposed 

language might be too restrictive 

because it would require an operator to 

use equipment to address the effects. 

One member of the TPSSC noted that 

the proposal would apply to any change 

to the pipeline and suggested clarifying 

the regulation to apply only to changes 

affecting configuration. We have made 

changes to the final rule to limit 

applicability to changes that have the 

potential for affecting downstream risk. 

The final rule allows operator flexibility 

in addressing the risks. 


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20058 Federal Register / Vol. 72, No. 77 / Monday, April 23, 2007 / Rules and Regulations 

4Section 192.150 requires an operator to design 

most new and replaced transmission pipeline to 

allow the use of instrumented internal inspection 

devices. The exceptions to § 192.150 include certain 

lower risk gathering lines and lines too small in 

diameter to accommodate instrumented internal 

inspection devices. Although neither § 192.150 nor 

this final rule expressly requires designing to allow 

the use of cleaning pigs, it is much easier to 

accommodate cleaning pigs than instrumented 

internal inspection devices. 

5NTSB Report PAR 03–01, pages 41–42. 

Changes Due To Uprating 

Existing pipeline safety regulations 

(§ 192.555 and § 192.557) allow an 

operator to increase maximum 

allowable operating pressure of a gas 

pipeline through a process called 

uprating. Uprating results in operation 

at an increased hoop stress. A pipeline 

operating at a hoop stress of 20 percent 

or more of the specified minimum yield 

strength is considered a transmission 

pipeline by definition regardless of its 

function (§ 192.3). Thus, uprating a 

distribution line may result in its 

classification as a transmission line. A 

member of the TPSSC asked whether 

such a change would result in the line 

being considered a new transmission 

line subject to the design and 

construction requirements of this final 

rule. The answer is no. The uprated line 

is not newly constructed. However, to 

the extent an operator makes 

replacements in the line in connection 

with uprating to meet the requirements 

of § 192.555(b)(2) or § 192.557(b)(3), the 

replacements must be designed and 

constructed in accordance with this 

final rule. In addition, the operator 

would have to consider the effect of the 

replacement on internal corrosion risk 

to the downstream portion of the 

pipeline. 

Terminology 

The proposed rule allows an operator 

to deviate from specific aspects of 

design and construction if the operator 

can demonstrate that compliance is 

‘‘impracticable’’ or ‘‘unnecessary.’’

Some commenters said that the terms 

are too subjective and will result in 

disputes over the appropriateness of an 

operator’s actions. They suggest 

clarification through examples. We do 

not agree that further clarification is 

required at this time. The terms 

‘‘impracticable’’ and ‘‘unnecessary’’ are 

used elsewhere in regulation. As long as 

an operator makes a reasonable effort to 

address internal corrosion in design and 

construction, the potential for 

disagreement is slight. At the request of 

the TPSSC, PHMSA intends to conduct 

a public workshop on implementation 

of this regulation. Part of the workshop 

could be devoted to developing 

examples of situations in which 

regulators and industry agree that 

compliance with the final rule would be 

presumptively impracticable or 

unnecessary. 

The Final Rule 

The final rule adds a new subsection 

to § 192.143 in Subpart D—Design of 

Pipeline Components. The new 

subsection cross-references the design 

and installation requirements 

specifically addressing corrosion control 

in Subpart I—Requirements for 

Corrosion Control. 

The final rule also adds a new section 

to subpart I. The new section, § 192.476, 

requires an operator to address internal 

corrosion risk when designing and 

constructing a new gas transmission line 

or when replacing line pipe or 

components in a transmission line. 

Paragraph (a) addresses design and 

construction. It imposes a general 

performance requirement—that the 

design and construction of new and 

replaced pipelines include features to 

reduce the risk of internal corrosion. 

More specifically, the rule identifies 

three categories of corrosion control 

features that an operator must provide 

for unless doing so is impracticable or 

unnecessary: (1) Configuration to reduce 

the risk that liquids will collect in the 

line (paragraph (a)(1)); (2) effective 

liquid removal features (paragraph 

(a)(2)); and (3) ability to use corrosion 

monitoring devices in locations with 

significant potential for internal 

corrosion (paragraph (a)(3)). 

There are many design features that 

an operator can incorporate to address 

the requirements of paragraph (a). These 

include the following: 

• An operator can minimize dead 

ends and low areas; 

• An operator can minimize aerial 

crossings, since these can result in 

variation of temperature; 

• An operator can design for 

turbulent flow, in which the velocity at 

a given point varies erratically in 

magnitude and direction, to decrease 

the chance of liquids separating from 

the flow and accumulating; 

• An operator can design a pipeline 

to minimize entry of water and 

corrosive gases at receipt locations; 

• When corrosive gas is expected, an 

operator can provide slam valves to 

isolate systems; 

• An operator can apply coatings to 

interior walls to inhibit internal 

corrosion; 

• An operator can identify critical 

low spots and instrument the pipeline 

to monitor relevant operating conditions 

(temperature, pressure, velocity, dew 

point); 

• An operator can evaluate seasonal 

nature of delivery and capacity patterns 

and design to avoid no-or low-flow 

conditions; 

• An operator can include equipment 

to evaluate gas characteristics; and 

• An operator can include equipment 

to allow sampling at key areas, such as 

pig traps, isolated sections with no flow, 

dead ends, and river and road crossings. 

Further, design should allow the use 

of cleaning pigs.4

Paragraph (b) provides exceptions to 

applicability. The design and 

construction requirements do not apply 

to pipeline installed or replacements 

made before the effective date of the 

regulation. They also do not apply to 

offshore pipelines. 

Paragraph (c) requires an operator to 

consider and address the impact of 

changes in the physical features of a 

pipeline on internal corrosion risks of 

an existing downstream pipeline. This 

will ensure that changes in 

configuration made after a pipeline 

begins operation do not inadvertently 

increase the risk of internal corrosion. 

An operator who finds an increased risk 

due to changes upstream might need to 

install liquid removal equipment. 

Alternatively, after analysis, an operator 

may decide operation and maintenance 

measures would adequately address the 

impact. In its investigation of the 

Carlsbad accident, the NTSB noted the 

impact of the addition of a pig receiver 

many years after original construction.5

This change in configuration allowed 

the liquids from pigging which were not 

caught in the receiver to flow 

downstream supposedly to be caught in 

the drip installed at the time of original 

construction to capture liquids before 

the low points near the river. The NTSB 

report notes that the pig receiver was 

added without also installing a separate 

storage leg or tank to collect the liquids 

from pigging. The NTSB also notes that 

partial clogging of the original drip, a 

maintenance issue, allowed liquids to 

bypass the drip and collect at the 

eventual rupture site. 

Paragraph (d) requires an operator to 

maintain records demonstrating 

compliance. Written procedures 

supported by as-built drawings and 

other construction records ordinarily 

will satisfy this requirement. However, 

these records must adequately show 

why an action described in paragraph 

(a)(1), (a)(2), or (a)(3) is impracticable or 

unnecessary. For example, an operator 

might have a written design allowing 

pipe to be laid following the contour of 

the land. To avoid accumulation of 

liquid in the low spots, the design 

procedure might call for incorporating 


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Federal Register / Vol. 72, No. 77 / Monday, April 23, 2007 / Rules and Regulations 20059 

design features to maintain gas velocity 

or to remove liquids. The actual 

construction records or as-built 

drawings would show what the operator 

actually did. Another example might be 

a construction record showing the use of 

a filter or separator at the gate station of 

a distribution pipeline. Regardless of the 

choices in recordkeeping an operator 

makes, the records must show 

circumstances justifying variance based 

on impracticability or lack of necessity. 

For example, if an operator does not 

provide features for effective liquid 

removal at low spots, the records must 

show why it is not necessary to do so. 

Regulatory Analyses and Notices 

Privacy Act Statement 

Anyone can search the electronic 

form of all comments received in 

response to any of our dockets by the 

name of the individual submitting the 

comment (or signing the comment, if 

submitted on behalf of an association, 

business, labor union, etc.). The 

Department of Transportation’s 

complete Privacy Act Statement is 

published in the Federal Register on 

April 11, 2000 (65 FR 19477), and on 

the Web at http://dms.dot.gov. 

Executive Order 12866 and DOT 

Policies and Procedures 

This final rule is not a significant 

regulatory action under section 3(f) of 

Executive Order 12866 (58 FR 51735) 

and, therefore, was not subject to review 

by the Office of Management and 

Budget. This final rule is not significant 

under the Regulatory Policies and 

Procedures of the Department of 

Transportation (44 FR 11034). 

Commenters pointed to discrepancies 

in the incident data used for the 

regulatory evaluation. Those 

discrepancies have been corrected in the 

regulatory evaluation for this final rule. 

One member of the TPSSC questioned 

whether the analysis included 

consideration of uncertainties. We have 

considered the comment and decided 

that our analysis adequately handles 

uncertainty in benefits and costs. 

Regulatory Flexibility Act 

Under the Regulatory Flexibility Act 

(5 U.S.C. 601 et seq.), PHMSA must 

consider whether rulemaking actions 

would have a significant economic 

impact on a substantial number of small 

entities. This final rule would affect 

operators of gas transmission pipelines 

and onshore gas gathering pipelines. 

The number of small entities operating 

gas transmission pipelines is not 

substantial and the cost of compliance 

with the final rule is small. Therefore, 

I certify, under 5 U.S.C. 605, that this 

rulemaking will not have a significant 

impact on a substantial number of small 

entities. 

Executive Order 13175 

PHMSA has analyzed this final rule 

according to Executive Order 13175, 

‘‘Consultation and Coordination with 

Indian Tribal Governments.’’ Because 

the final rule will not significantly or 

uniquely affect the communities of the 

Indian tribal governments nor impose 

substantial direct compliance costs, the 

funding and consultation requirements 

of Executive Order 13175 do not apply. 

Paperwork Reduction Act 

This final rule affects information 

collection that the Office of 

Management and Budget has approved 

under Control Number 2137–0049 

(recordkeeping under 49 CFR part 192). 

Operators of gas transmission pipelines 

must keep records to show the adequacy 

of corrosion control measures. In 

addition, they must keep construction 

records and make them available to 

individuals operating and maintaining 

the pipeline. The final rule may require 

some added effort to document 

decisions about internal corrosion made 

during design and construction. Because 

of existing recordkeeping needs and 

prudent business practice, PHMSA 

estimates the added burden hours will 

be nominal. 

Unfunded Mandates Reform Act of 1995 

This final rule does not impose 

unfunded mandates under the 

Unfunded Mandates Reform Act of 

1995. It does not result in costs of $100 

million or more to either State, local, or 

tribal governments, in the aggregate, or 

to the private sector, and is the least 

burdensome alternative that achieves 

the objective of the rulemaking. 

National Environmental Policy Act 

PHMSA has analyzed the final rule 

for purposes of the National 

Environmental Policy Act (42 U.S.C. 

4321 et seq.). Because the final rule 

requires limited physical change or 

other work that would disturb pipeline 

rights-of-way, PHMSA has determined 

the final rule is unlikely to affect the 

quality of the human environment 

significantly. An environmental 

assessment document is available for 

review in the docket. 

Executive Order 13132 

PHMSA has analyzed the final rule 

according to Executive Order 13132 

(‘‘Federalism’’). The final rule does not 

have a substantial direct effect on the 

States, the relationship between the 

national government and the States, or 

the distribution of power and 

responsibilities among the various 

levels of government. The final rule 

does not impose substantial direct 

compliance costs on State and local 

governments. Federal pipeline safety 

law prohibits State safety regulation of 

interstate pipelines. This regulation 

would not preempt state law for 

intrastate pipelines. Therefore, the 

consultation and funding requirements 

of Executive Order 13132 do not apply. 

Executive Order 13211 

Transporting gas impacts the nation’s 

available energy supply. However, this 

final rule is not a ‘‘significant energy 

action’’ under Executive Order 13211. It 

also is not a significant regulatory action 

under Executive Order 12866 and is not 

likely to have a significant adverse effect 

on the supply, distribution, or use of 

energy. Further, the Administrator of 

the Office of Information and Regulatory 

Affairs has not identified this final rule 

as a significant energy action. 

List of Subjects in 49 CFR Part 192 

Design and construction, Internal 

corrosion, Pipeline safety. 

■ For the reasons provided in the 

preamble, PHMSA amends 49 CFR part 

192 as follows: 

PART 192—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE: MINIMUM FEDERAL 

SAFETY STANDARDS 

■ 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; and 

49 CFR 1.53. 

■ 2. Amend § 192.143 by designating 

existing text as paragraph (a) and adding 

a new paragraph (b) to read as follows: 

§ 192.143 General requirements. 

* * * * * 

(b) The design and installation of 

pipeline components and facilities must 

meet applicable requirements for 

corrosion control found in subpart I of 

this part. 

■ 3. Add § 192.476 to read as follows: 

§ 192.476 Internal corrosion control: 

Design and construction of transmission 

line. 

(a) Design and construction. Except as 

provided in paragraph (b) of this 

section, each new transmission line and 

each replacement of line pipe, valve, 

fitting, or other line component in a 

transmission line must have features 

incorporated into its design and 

construction to reduce the risk of 


cprice-sewell on PRODPC74 with RULES
20060 Federal Register / Vol. 72, No. 77 / Monday, April 23, 2007 / Rules and Regulations 

internal corrosion. At a minimum, 

unless it is impracticable or unnecessary 

to do so, each new transmission line or 

replacement of line pipe, valve, fitting, 

or other line component in a 

transmission line must: 

(1) Be configured to reduce the risk 

that liquids will collect in the line; 

(2) Have effective liquid removal 

features whenever the configuration 

would allow liquids to collect; and 

(3) Allow use of devices for 

monitoring internal corrosion at 

locations with significant potential for 

internal corrosion. 

(b) Exceptions to applicability. The 

design and construction requirements of 

paragraph (a) of this section do not 

apply to the following: 

(1) Offshore pipeline; and 

(2) Pipeline installed or line pipe, 

valve, fitting or other line component 

replaced before May 23, 2007. 

(c) Change to existing transmission 

line. When an operator changes the 

configuration of a transmission line, the 

operator must evaluate the impact of the 

change on internal corrosion risk to the 

downstream portion of an existing 

onshore transmission line and provide 

for removal of liquids and monitoring of 

internal corrosion as appropriate. 

(d) Records. An operator must 

maintain records demonstrating 

compliance with this section. Provided 

the records show why incorporating 

design features addressing paragraph 

(a)(1), (a)(2), or (a)(3) of this section is 

impracticable or unnecessary, an 

operator may fulfill this requirement 

through written procedures supported 

by as-built drawings or other 

construction records. 

Issued in Washington, DC on April 16, 

2007. 

Thomas J. Barrett, 

Administrator. 

[FR Doc. E7–7701 Filed 4–20–07; 8:45 am] 

BILLING CODE 4910–60–P 

DEPARTMENT OF COMMERCE 

National Oceanic and Atmospheric 

Administration 

50 CFR Part 679 

[Docket No. 070213033–7033–01; I.D. 

041807B] 

Fisheries of the Exclusive Economic 

Zone Off Alaska; Yellowfin Sole by 

Vessels Using Trawl Gear in the Bering 

Sea and Aleutian Islands Management 

Area 

AGENCY: National Marine Fisheries 

Service (NMFS), National Oceanic and 

Atmospheric Administration (NOAA), 

Commerce. 

ACTION: Temporary rule; closure. 

SUMMARY: NMFS is closing directed 

fishing for yellowfin sole by vessels 

using trawl gear in the Bering Sea and 

Aleutian Islands management area 

(BSAI). This action is necessary to 

prevent exceeding the second seasonal 

allowance of the 2007 halibut bycatch 

allowance specified for the trawl 

yellowfin sole fishery category in the 

BSAI. 

DATES: Effective 1200 hrs, Alaska local 

time (A.l.t.), April 19, 2007, through 

1200 hrs, A.l.t., May 21, 2007. 

FOR FURTHER INFORMATION CONTACT: 

Jennifer Hogan, 907–586–7228. 

SUPPLEMENTARY INFORMATION: NMFS 

manages the groundfish fishery in the 

BSAI according to the Fishery 

Management Plan for Groundfish of the 

Bering Sea and Aleutian Islands 

Management Area (FMP) prepared by 

the North Pacific Fishery Management 

Council under authority of the 

Magnuson-Stevens Fishery 

Conservation and Management Act. 

Regulations governing fishing by U.S. 

vessels in accordance with the FMP 

appear at subpart H of 50 CFR part 600 

and 50 CFR part 679. 

The second seasonal allowance of the 

2007 halibut bycatch allowance 

specified for the trawl yellowfin sole 

fishery category in the BSAI is 195 

metric tons as established by the 2007 

and 2008 final harvest specifications for 

groundfish in the BSAI (72 FR 9451, 

March 2, 2007). 

In accordance with § 679.21(e)(7)(v), 

the Administrator, Alaska Region, 

NMFS, has determined that the second 

seasonal allowance of the 2007 halibut 

bycatch allowance specified for the 

trawl yellowfin sole fishery category in 

the BSAI has been caught. 

Consequently, NMFS is closing directed 

fishing for yellowfin sole by vessels 

using trawl gear in the BSAI. 

After the effective date of this closure 

the maximum retainable amounts at 

§ 679.20(e) and (f) apply at any time 

during a trip. 

Classification 

This action responds to the best 

available information recently obtained 

from the fishery. The Assistant 

Administrator for Fisheries, NOAA 

(AA), finds good cause to waive the 

requirement to provide prior notice and 

opportunity for public comment 

pursuant to the authority set forth at 5 

U.S.C. 553(b)(B) as such requirement is 

impracticable and contrary to the public 

interest. This requirement is 

impracticable and contrary to the public 

interest as it would prevent NMFS from 

responding to the most recent fisheries 

data in a timely fashion and would 

delay the closure of directed fishing for 

yellowfin sole by vessels using trawl 

gear in the BSAI. NMFS was unable to 

publish a notice providing time for 

public comment because the most 

recent, relevant data only became 

available as of April 17, 2007. 

The AA also finds good cause to 

waive the 30-day delay in the effective 

date of this action under 5 U.S.C. 

553(d)(3). This finding is based upon 

the reasons provided above for waiver of 

prior notice and opportunity for public 

comment. 

This action is required by § 679.21 

and is exempt from review under 

Executive Order 12866. 

Authority: 16 U.S.C. 1801 et seq. 

Dated: April 18, 2007. 

James P. Burgess 

Acting Director, Office of Sustainable 

Fisheries, National Marine Fisheries Service. 

[FR Doc. 07–1999 Filed 4–18–07; 1:07 pm] 

BILLING CODE 3510–22–S 


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