62148 Federal Register / Vol. 73, No. 202 / Friday, October 17, 2008 / Rules and Regulations 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

49 CFR Part 192 

[Docket No. PHMSA–2005–23447] 

RIN 2137–AE25 

Pipeline Safety: Standards for 

Increasing the Maximum Allowable 

Operating Pressure for Gas 

Transmission Pipelines 

AGENCY: Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA), Department of Transportation 

(DOT). 

ACTION: Final rule. 

SUMMARY: PHMSA is amending the 

pipeline safety regulations to prescribe 

safety requirements for the operation of 

certain gas transmission pipelines at 

pressures based on higher operating 

stress levels. The result is an increase of 

maximum allowable operating pressure 

(MAOP) over that currently allowed in 

the regulations. Improvements in 

pipeline technology assessment 

methodology, maintenance practices, 

and management processes over the past 

twenty-five years have significantly 

reduced the risk of failure in pipelines 

and necessitate updating the standards 

that govern the MAOP. This rule will 

generate significant public benefits by 

reducing the number and consequences 

of potential incidents and boosting the 

potential capacity and efficiency of 

pipeline infrastructure, while promoting 

rigorous life-cycle maintenance and 

investment in improved pipe 

technology. 

DATES: Effective Date: This final rule 

takes effect November 17, 2008. 

Incorporation by Reference Date: The 

incorporation by reference of a certain 

publication listed in this rule is 

approved by the Director of the Federal 

Register as of November 17, 2008. 

FOR FURTHER INFORMATION CONTACT: 

Alan Mayberry by phone at (202) 366– 

5124, or by e-mail at 

alan.mayberry@dot.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

A. Purpose of the Rulemaking 

B. Background 

B.1. Current Regulations 

B.2. Evolution in Views on Pressure 

B.3. History of PHMSA Consideration 

B.4. Safety Conditions in Special Permits 

B.5. Codifying the Special Permit 

Standards 

B.6. How to Handle Special Permits and 

Requests for Special Permits 

B.7. Statutory Considerations 

C. Comments on the NPRM 

C.1. General Comments 

C.2. Comments on Specific Provisions in 

the Proposed Rule 

C.2.1. Section 192.7, Incorporation by 

Reference 

C.2.2. Design Requirements 

C.2.3. Construction Requirements 

C.2.4. Eligibility for and Implementing 

Alternative MAOP 

C.2.5. Operation and Maintenance 

Requirements 

C.3. Comments on Regulatory Analysis 

D. Consideration by the Technical Pipeline 

Safety Standards Committee 

E. The Final Rule 

E.1. In General 

E.2. Amendment to § 192.7—Incorporation 

by Reference 

E.3. New § 192.112—Additional Design 

Requirements 

E.4. New § 192.328—Additional 

Construction Requirements 

E.5. Amendment to § 192.611—Change in 

Class Location: Confirmation or Revision 

of Maximum Operating Pressure 

E.6. Amendment to § 192.619—Maximum 

Allowable Operating Pressure 

E.7. New § 192.620—Operation at an 

Alternative MAOP 

E.7.1. § 192.620(a)—Calculating the 

Alternative MAOP 

E.7.2. § 192.620(b)—Which Pipelines 

Qualify 

E.7.3. §§ 192.620(c)(1), (2), and (3)—How 

an Operator Selects Operation Under 

This Section 

E.7.4. § 192.620(c)(4)—Initial Strength 

Testing 

E.7.5. § 192.620(c)(5)—Operation and 

Maintenance 

E.7.6. § 192.620(c)(6)—New Construction 

and Maintenance Tasks 

E.7.7. § 192.620(c)(7)—Recordkeeping 

E.7.8. § 192.620(c)(8)—Class Upgrades 

E.8. § 192.620(d)—Additional Operation 

and Maintenance Requirements 

E.8.1. § 192.620(d)(1)—Threat Assessments 

E.8.2. § 192.620(d)(1)—Public Awareness 

E.8.3. § 192.620(d)(2)—Emergency 

Response 

E.8.4. § 192.620(d)(3)—Damage Prevention 

E.8.5. § 192.620(d)(4)—Internal Corrosion 

Control 

E.8.6. §§ 192.620(d)(5), (6), and (7)— 

External Corrosion Control 

E.8.7. §§ 192.620(d)(8) and (9)—Integrity 

Assessments 

E.8.8. § 192.620(d)(10)—Repair Criteria 

E.9. § 192.620(e)—Overpressure 

Protection—Proposed § 192.620(e) 

F. Regulatory Analyses and Notices 

F.1. Privacy Act Statement 

F.2. Executive Order 12866 and DOT 

Policies and Procedures 

F.3. Regulatory Flexibility Act 

F.4. Executive Order 13175 

F.5. Paperwork Reduction Act 

F.6. Unfunded Mandates Reform Act of 

1995 

F.7. National Environmental Policy Act 

F.8. Executive Order 13132 

F.9. Executive Order 13211 

A. Purpose of the Rulemaking 

PHMSA published a Notice of 

Proposed Rulemaking (NPRM) on March 

12, 2008 (73 FR 13167), to establish 

standards under which certain natural 

or other gas (gas) transmission pipelines 

would be allowed to operate at higher 

maximum allowable operating pressure 

(MAOP). The proposed changes were 

made possible by dramatic 

improvements in pipeline technology 

and risk controls over the past 25 years. 

The current standards for calculating 

MAOP on gas transmission pipelines 

were adopted in 1970, in the original 

pipeline safety regulations promulgated 

under Federal law. Almost all risk 

controls on gas transmission pipelines 

have been strengthened in the 

intervening years, beginning with the 

introduction of improved 

manufacturing, metallurgy, testing, and 

assessment tools and standards. Pipe 

manufactured and tested to modern 

standards is far less likely to contain 

defects that can grow to failure over 

time than pipe manufactured and 

installed a generation ago. Likewise, 

modern maintenance practices, if 

consistently followed, significantly 

reduce the risk that corrosion, or other 

defects affecting pipeline integrity, will 

develop in installed pipelines. Most 

recently, operators’ development and 

implementation of integrity 

management programs have increased 

understanding about the condition of 

pipelines and how to reduce pipeline 

risks. In view of these developments, 

PHMSA concludes that certain gas 

transmission pipelines can be safely and 

reliably operated at pressures above 

current Federal pipeline safety design 

limits. With appropriate conditions and 

controls, permitting operation at higher 

pressures will increase energy capacity 

and efficiency without diminishing 

system safety. 

Currently, PHMSA has granted 

special permits on a case-by-case basis 

to allow operation of particular pipeline 

segments at a higher MAOP than 

currently allowed under the existing 

design requirements. These special 

permits, that have been granted, have 

been limited to operation in Class 1, 2, 

and 3 locations and conditioned on 

demonstrated rigor in the pipeline’s 

design and construction and the 

operator’s performance of additional 

safety measures. Building on the record 

of success developed in the special 

permit proceedings, PHMSA is 

codifying the conditions and limitations 

of the special permits into standards of 

general applicability. 

B. Background 

B.1. Current Regulations 

The design factor specified in 

§ 192.105 restricts the MAOP of a steel 


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gas transmission pipeline based on 

stress levels and class location. For most 

steel pipelines, the MAOP is defined in 

§ 192.619 based on design pressure 

calculated using a formula, found at 

§ 192.111, which includes the design 

factor. The regulations establish four 

classifications based on population 

density, ranging from Class 1 

(undeveloped, rural land) through Class 

4 (densely populated urban areas). In 

sparsely populated Class 1 locations, the 

design factor specified in § 192.105 

restricts the stress level at which a 

pipeline can be operated to 72 percent 

of the specified minimum yield strength 

(SMYS) of the steel. The operating 

pressures in more populated Class 2 and 

Class 3 locations are limited to 60 and 

50 percent of SMYS, respectively. 

Paragraph (c) of § 192.619 provides an 

exception to this calculation of MAOP 

for pipelines built before the issuance of 

the Federal pipeline safety standards. A 

pipeline that is ‘‘grandfathered’’ under 

this section may be operated at a stress 

level exceeding 72 percent of SMYS if 

it was operated at that pressure for five 

years prior to July 1, 1970. 

Part 192 also prescribes safety 

standards for designing, constructing, 

operating, and maintaining steel 

pipelines used to transport gas. 

Although these standards have always 

included several requirements for initial 

and periodic testing and inspection, 

prior to 2003, part 192 contained no 

Federal requirements for internal 

inspection of existing pipelines. Internal 

inspection is performed using a tool 

known as an ‘‘instrumented pig’’ (or 

‘‘smart pig’’). Many pipelines 

constructed before the advent of this 

technology cannot accommodate an 

instrumented pig and, accordingly, 

cannot be inspected internally. 

Beginning in 1994, PHMSA required 

operators to design new pipelines so 

that they could accommodate 

instrumented pigs, paving the way for 

internal inspection (59 FR 17281; Apr. 

12, 1994). 

In December 2003, PHMSA adopted 

its gas transmission integrity 

management rule, requiring operators to 

develop and implement plans to extend 

additional protections, including 

internal inspection, to pipelines located 

in ‘‘high consequence areas’’ (HCAs) (68 

FR 69816). Integrity management 

programs, as required by subpart O of 

part 192, include threat assessments, 

both baseline and periodic internal 

inspection, pressure testing, or direct 

assessment (DA), and additional 

measures designed to prevent and 

mitigate pipeline failures and their 

consequences. AN HCA, as defined in 

§ 192.903, is a geographic territory in 

which, by virtue of its population 

density and proximity to a pipeline, a 

pipeline failure would pose a higher 

risk to people. In addition to class 

location, one of the criteria for 

identifying an HCA is a potential impact 

circle surrounding a pipeline. The 

calculation of the circle includes a 

factor for the MAOP, with the result that 

a higher MAOP results in a larger 

impact circle. 

B.2. Evolution in Views on Pressure 

Absent any defects, and with proper 

maintenance and management practices, 

steel pipe can last for many decades in 

gas service. However, the manufacture 

of the steel or rolling of the pipe can 

introduce flaws. In addition, during 

construction, improper backfilling can 

damage the pipe and pipe coating. Over 

time, damaged coating unchecked can 

allow corrosion to continue and cause 

leaks. Excavation-related damage can 

produce an immediate pipeline failure 

or leave a dent or coating damage that 

could grow to failure over time. 

The regulations on MAOP in part 192 

have their origin in engineering 

standards developed in the 1950s, when 

industry had relatively limited 

information about the material 

properties of pipe and limited ability to 

evaluate a pipeline’s integrity during its 

operating lifetime. Early pipeline codes 

allowed maximum operating pressures 

to be set at a fixed amount under the 

pressure of the initial strength test 

without regard to SMYS. Pipeline 

engineers developing consensus 

standards looked for ways to lengthen 

the time before defects initiated during 

manufacture, construction, or operation 

could grow to failure. Their solutions 

focused on tests done at the mill to 

evaluate the ability of the pipe to 

contain pressure during operation. They 

added an additional factor to the 

hydrostatic test pressure of the mill test. 

At the time during the 1950’s, the 

consensus standard, known as the B31.8 

Code, used this conservative margin of 

safety for gas pipe design. A 25 percent 

margin of safety translated into a design 

factor limiting stress level to 72 percent 

of SMYS in rural areas. Specifically, the 

MAOP of 72 percent of SMYS comes 

from dividing the typical maximum mill 

test pressure of 90 percent of SMYS by 

1.25. When issuing the first Federal 

pipeline safety regulations in 1970, 

regulators incorporated this design 

factor, as found in the 1968 edition of 

the B31.8 Code, into the requirements 

for determining the MAOP. 

Even as the Federal regulations were 

being developed, some technical 

support existed for operation at a higher 

stress level, provided initial strength 

testing resulted in operators removing 

defects. In 1968, the American Gas 

Association published Report No. 

L30050 entitled Study of Feasibility of 

Basing Natural Gas Pipeline Operating 

Pressure on Hydrostatic Test Pressure 

prepared by the Battelle Memorial 

Institute. The research study concluded 

that: 

• It is inherently safer to base the 

MAOP on the test pressure, which 

demonstrates the actual in-place yield 

strength of the pipeline, than to base it 

on SMYS alone. 

• High pressure hydrostatic testing is 

able to remove defects that may fail in 

service. 

• Hydrostatic testing to actual yield, 

as determined with a pressure-volume 

plot, does not damage a pipeline. 

The report specifically recommended 

setting the MAOP as a percentage of the 

field test pressure. In particular, it 

recommended setting the MAOP at 80 

percent of the test pressure when the 

minimum test pressure was 90 percent 

of SMYS or higher. Although the 

committee responsible for the B31.8 

Code received the report, the committee 

deferred consideration of its findings at 

that time because the Federal regulators 

had already begun the process to 

incorporate the 1968 edition of the 

B31.8 Code into the Federal pipeline 

safety standards. 

More than a decade later, the 

committee responsible for development 

of the B31.8 Code, now under the 

auspices of the American Society of 

Mechanical Engineers (ASME), revisited 

the question of the design factor it had 

deferred in the late 1960s. The 

committee determined pipelines could 

operate safely at stress levels up to 80 

percent of SMYS. ASME updated the 

design factors in a 1990 addendum to 

the 1989 edition of the B31.8 Code, and 

they remain in the current edition. 

Although part 192 incorporates parts of 

the B31.8 Code by reference, it does not 

incorporate the updated design factors. 

With the benefit of operating experience 

with pipelines, it seems clear that 

operating pressure plays a less critical 

role in pipeline integrity and failure 

consequence than other factors within 

the operator’s control. 

By any measure, new technologies 

and risk controls have had a far greater 

impact on pipeline safety and integrity. 

A great deal of progress has occurred in 

the manufacture of steel pipe and in its 

initial inspection and testing. 

Technological advances in metallurgy 

and pipe manufacture decrease the risk 

of incipient flaws occurring and going 

undetected during manufacture. The 

detailed standards now followed in steel 

and pipe manufacturing provide 


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engineers considerable information 

about their material properties. 

Toughness standards make new steel 

pipe more likely to resist fracture and to 

survive mechanical damage. Knowledge 

about the material properties allows 

engineers to predict how quickly flaws, 

whether inherent or introduced during 

construction or operation, will grow to 

failure under known operating 

conditions. 

Initial inspection and hydrostatic 

testing of pipelines allow operators to 

discover flaws that have occurred prior 

to operation, such as during 

transportation or construction. They 

also serve to validate the integrity of the 

pipeline before operation. Initial 

pressure testing causes longitudinal and 

some other flaws introduced during 

manufacture, transportation, or 

construction to grow to the point of 

failure. Initial pressure testing detects 

all but one type of manufacturing or 

construction defect that could cause 

failure in the near-term. The sole type 

of defect that pressure testing may not 

identify, a flaw in a girth weld, is 

detectable through pre-operational nondestructive testing, which is required in 

this rule. 

The most common defects initiated 

during operation are caused by 

mechanical damage or corrosion. 

Improvements in technology have 

resulted in internal inspection 

techniques that provide operators a 

significant amount of information about 

defects. Although there is significant 

variance in the capability of the tools 

used for internal inspections, each 

provides the operator information about 

flaws in the pipeline that an operator 

would not otherwise have. An operator 

can then examine these flaws to 

determine whether they are defects 

requiring repair. In addition, internal 

inspections with in-line inspection (ILI) 

devices, unlike pressure testing, are not 

destructive and can be done while the 

pipeline is in operation. Initial internal 

inspection establishes a baseline. 

Operators can use subsequent internal 

inspections at appropriate intervals to 

monitor for changes in flaws already 

discovered or to find new flaws 

requiring repair or monitoring. Internal 

inspections, and other improved lifecycle management practices, increase 

the likelihood operators will detect any 

flaws that remain in the pipe after initial 

inspection and testing, or that develop 

after construction, well before the flaws 

grow to failure. 

B.3. History of PHMSA Consideration 

Although the agency had never 

formally revisited its part 192 MAOP 

standards, prior to this rulemaking, 

developments in related arenas have 

increasingly set the stage for changes to 

those standards. Grandfathered 

pipelines have operated successfully at 

higher stress levels in the United States 

during more than 35 years of Federal 

safety regulation. Many of these 

grandfathered pipelines have operated 

at higher stress levels for more than 50 

years without a higher rate of failure. 

We have also been aware of pipelines 

outside the United States operating 

successfully at the higher stress levels 

permitted under the ASME standard. A 

technical study published in December 

2000 by R.J. Eiber, M. McLamb, and 

W.B. McGehee, Quantifying Pipeline 

Design at 72% SMYS as a Precursor to 

Increasing the Design Stress Level, GRI– 

00/0233, further raised interest in the 

issue. 

In connection with our issuance of the 

2003 gas transmission integrity 

management regulations, PHMSA 

announced a policy to grant ‘‘class 

location’’ waivers (now called special 

permits) to operators demonstrating an 

alternative integrity management 

program for the affected pipeline. A 

‘‘class location’’ waiver allows an 

operator to maintain current operating 

pressure on a pipeline following an 

increase in population that changes the 

class location. Absent a waiver, the 

operator would have to reduce pressure 

or replace the pipe with thicker walled 

pipe. PHMSA held a meeting on April 

14–15, 2004, to discuss the criteria for 

the waivers. In a notice seeking public 

involvement in the process (69 FR 

22116; Apr. 23, 2004), PHMSA 

announced: 

Waivers will only be granted when pipe 

condition and active integrity management 

provides a level of safety greater than or 

equal to a pipe replacement or pressure 

reduction. 

A second notice (69 FR 38948; June 

29, 2004) announced the criteria. The 

criteria included the use of high quality 

manufacturing and construction 

processes, effective coating, and a lack 

of systemic problems identified in 

internal inspections Although the class 

location special permits/waivers do not 

address increases in stress levels per se, 

the risk management approach 

developed in those cases takes account 

of operating pressure and addresses 

many of the same concerns. The same 

risk management approach, and many of 

the specific criteria applied in the class 

location waivers, guided PHMSA’s 

handling of the special permits 

discussed below and, ultimately, this 

rule. 

Beginning in 2005, operators began 

addressing the issue of stress level 

directly with requests that PHMSA 

allow operation at the MAOP levels that 

the ASME B31.8 Code would allow. 

With the increasing interest, PHMSA 

held a public meeting on March 21, 

2006, to discuss whether to allow 

increased MAOP consistent with the 

updated ASME standards. PHMSA also 

solicited technical papers on the issue. 

Papers filed in response, as well as the 

transcript of the public meeting, are in 

the docket for this rulemaking. Later in 

2006, PHMSA again sought public 

comment at a meeting of its advisory 

committee, the Technical Pipeline 

Safety Standards Committee (TPSSC). 

The transcript and briefing materials for 

the June 28, 2006, meeting are in the 

docket for the advisory committee, 

Docket ID PHMSA–RSPA–1998–4470– 

204, 220. This docket can be found at 

http://www.regulations.gov. Comments 

and papers written during the period 

these efforts were undertaken 

overwhelmingly supported examining 

increased MAOP as a way to increase 

energy efficiency and capacity while 

maintaining safety. 

B.4. Safety Conditions in Special 

Permits 

In 2005, operators began requesting 

waivers, now called special permits, to 

allow operation at the MAOP levels that 

the ASME B31.8 Code would allow. In 

some cases, operators filed these 

requests at the same time they were 

seeking approval from the Federal 

Energy Regulatory Commission (FERC) 

to build new gas transmission pipelines. 

In other cases, operators sought relief 

from current MAOP limits for existing 

pipelines that had been built to more 

rigorous design and construction 

standards. 

In developing an approach to the 

requests, PHMSA examined the 

operating history of lines already 

operated at higher stress levels. 

Canadian and British standards have 

allowed operation at the higher stress 

levels for some time. The Canadian 

pipeline authority, which has allowed 

higher stress levels since 1973, reports 

the following regarding pipelines 

operating at stress levels higher than 72 

percent of SMYS: 

• About 6,000 miles of pipelines on 

the Alberta system, ranging from six to 

42 inches in diameter, were installed or 

upgraded between the early 1970s and 

2005; 

• About 4,500 miles of pipelines on 

the Mainline system east of the AlbertaSaskatchewan border, ranging from 20 

to 42 inches in diameter, were installed 

or upgraded between the early 1970s 

and 2005; and, 


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• More than 600 miles in the 

Foothills Pipe Line system, ranging from 

36 to 40 inches in diameter, were 

installed between 1979 and 1998. 

In the United Kingdom, about 1,140 

miles of the Northern pipeline system 

have been uprated to operate at higher 

stress level in the past ten years. 

Accident rates for pipelines in these 

countries have not indicated a 

measurable increased risk from 

operation at these higher operating 

stress levels. 

In the United States, some 5,000 miles 

of gas transmission lines have MAOPs 

that were grandfathered under 

§ 192.619(c), when the Federal pipeline 

safety regulations were adopted in the 

early 1970s, continue to operate at stress 

levels higher than 72 percent of SMYS. 

After some accidents caused by 

corrosion on grandfathered pipelines, 

PHMSA considered whether to remove 

the exception in § 192.619(c). In 1992, 

PHMSA decided to continue to allow 

operation at the grandfathered pressures 

(57 FR 41119; Sept. 9, 1992). PHMSA 

based its decision on the operating 

history of two of the operators whose 

pipelines contained most of the mileage 

operated at the grandfathered pressures. 

PHMSA noted the incident rate on these 

pipelines, operated at stress levels above 

72 percent of SMYS, was between 10 

percent and 50 percent of the incident 

rate of pipelines operated at the lower 

pressure. Texas Eastern Gas Pipeline 

Company (now Spectra Energy), the 

operator of many of the grandfathered 

pipelines, attributed the lower incident 

rate to aggressive inspection and 

maintenance. This included initial 

hydrostatic testing to 100 percent of 

SMYS, internal inspection, visual 

examination of anomalies found during 

internal inspection, repair of defects, 

and selective pressure testing to validate 

the results of the internal inspection. 

Internal inspection was not in common 

use in the industry prior to the 1980s. 

PHMSA’s statistics show these pipelines 

continue to have an equivalent safety 

record when compared with pipelines 

operating according to the design factors 

in the pipeline safety regulations. 

PHMSA also considered technical 

studies and required companies seeking 

special permits to provide information 

about the pipelines’ design and 

construction and to specify the 

additional inspection and testing to be 

used. PHMSA also considered how to 

handle findings that could compromise 

the long-term serviceability of the pipe. 

PHMSA concluded that pipelines can 

operate safely and reliably at stress 

levels up to 80 percent of SMYS if the 

pipeline has well-established 

metallurgical properties and can be 

managed to protect it against known 

threats, such as corrosion and 

mechanical damage. 

Early and vigilant corrosion 

protection reduces the possibility of 

corrosion occurring. At the earliest 

stage, this includes care in applying a 

protective coating before transporting 

the pipe to the right-of-way. With the 

newer coating materials and careful 

application, coating provides 

considerable protection against external 

corrosion and facilitates the application 

of induced current, commonly called 

cathodic protection, to prevent 

corrosion from developing at any breaks 

that may occur in the coating. Regularly 

monitoring the level of protection and 

addressing any low readings will detect 

and correct conditions that can cause 

corrosion at an early stage. Vigilant 

corrosion protection includes close 

attention to operating conditions that 

lead to internal corrosion, such as poor 

gas quality. In addition, for new 

pipelines, operators’ compliance with a 

rule issued last year requiring greater 

attention to internal corrosion 

protection during design and 

construction (72 FR 20059; Apr. 23, 

2007) will prevent internal corrosion. 

Finally, corrosion protection includes 

internal inspection and other 

assessment techniques for early 

detection of both internal and external 

corrosion. 

One of the major causes of serious 

pipeline failure is mechanical damage 

caused by outside forces, such as an 

equipment strike during excavation 

activities. Burying the pipeline deeper, 

increased patrolling, and additional line 

marking help prevent the risk that 

excavation will cause mechanical 

damage. Further, enhanced pipe 

properties increase the pipe’s resistance 

to immediate puncture from a single 

equipment strike. Improved toughness 

increases the ability of the pipe to 

withstand mechanical damage from an 

outside force and may also limit any 

failure consequences to leaks rather 

than ruptures. This toughness usually 

allows time for the operator to detect the 

damage during internal inspection well 

before the pipe fails. 

To evaluate each request for a special 

permit, PHMSA established a docket 

and sought public comment on the 

request. We received several public 

comments, most in response to the first 

special permits considered. Many of the 

comments supported granting the 

special permits. Those who were not 

supportive may have underestimated 

the significance of the safety upgrades 

required for the special permits. A few 

commenters raised technical concerns. 

Among these were questions about the 

impact of rail crossings and blasting 

activities in the vicinity of the pipeline. 

The special permits did not change the 

current requirements where road 

crossings exist and added a requirement 

to monitor activities, such as blasting, 

that could impact earth movement. 

Some commenters expressed concern 

about the impact radius of the pipeline 

operating at a higher stress level. 

PHMSA included supplemental safety 

criteria to address the increased radius. 

The remainder of the comments 

addressed concerns, such as 

compensation or aesthetics, which were 

outside the scope of the special permits. 

PHMSA special permits do not address 

issues on siting, which are governed by 

the FERC. 

PHMSA expects to issue seven special 

permits, and possibly more, in response 

to these requests. In each case, PHMSA 

has provided oversight to confirm the 

line pipe is, or will be (for pipe yet to 

be constructed), as free of inherent flaws 

as possible, that construction and 

operation do not introduce flaws, and 

that any flaws are detected before they 

can fail. PHMSA accomplishes this by 

imposing a series of conditions on the 

grant of special permits. The conditions 

imposed as part of the special permits 

are designed to address the potential 

additional risk involved in operating the 

pipeline at a higher stress level. A 

proposed pipeline must be built to 

rigorous design and construction 

standards, and the operator requesting a 

special permit for an existing pipeline 

must demonstrate that the pipeline was 

built to rigorous design and 

construction standards. These 

additional design and construction 

standards focused on producing a high 

quality pipeline that is free from 

inherent defects that could grow more 

rapidly under operation at a higher 

stress level and is more resistant to 

expected operational risks. In addition, 

PHMSA requires the operator of a 

pipeline receiving a special permit to 

comply with operation and maintenance 

(O&M) requirements that exceed current 

pipeline safety regulations. These 

additional O&M and integrity 

management requirements focused on 

the potential for corrosion and 

mechanical damage and on detecting 

defects before the defects can grow to 

failure. 

B.5. Codifying the Special Permit 

Standards 

This rule puts in place a process for 

managing the life-cycle of a pipeline 

operating at a higher stress level based 

on our experience with the special 

permits. Integrity management focuses 

on managing and extending the service 


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life of the pipeline. Life-cycle 

management goes beyond the operations 

and maintenance practices, including 

integrity management, to address steel 

production, pipeline manufacture, 

pipeline design, and installation. 

Industry experience with integrity 

management demonstrates the value of 

life-cycle management. Through 

baseline assessments in integrity 

management programs, gas transmission 

operators identified and repaired 2,883 

defects in the first three years of the 

program (2004, 2005, and 2006). More 

than 2,000 of these were discovered in 

the first two years as operators assessed 

their highest risk, generally older, 

pipelines. In a September 2006 report, 

GAO–09–946, the Government 

Accountability Office noted this data as 

an early indication of improvement in 

pipeline safety. In order to qualify for 

operation at higher stress levels under 

this rule, pipelines will be designed and 

constructed under more rigorous 

standards. Baseline assessment of these 

lines will likely uncover few defects, 

but removing those few defects will 

result in safer pipelines. In addition, the 

results of the baseline assessment will 

aid in evaluating anomalies discovered 

during future assessments. 

This rule, based on the terms and 

conditions of the special permits 

allowing operation at higher stress 

levels, imposes similar terms and 

conditions and limitations on operators 

seeking to apply the new rule. The 

terms and conditions, which include 

meeting design standards that go 

beyond current regulation, address the 

safety concerns related to operating the 

pipeline at a higher stress level. PHMSA 

will step up inspection and oversight of 

pipeline design and construction, in 

addition to review and inspection of 

enhanced life-cycle management 

requirements for these pipelines. 

With special permits, PHMSA 

individually examined the design, 

construction, and O&M plans for a 

particular pipeline before allowing 

operation at a higher pressure than 

currently authorized. In each case, 

PHMSA conditioned approval on 

compliance with a series of rigorous 

design, construction, O&M, and 

management standards, including 

enhanced damage prevention practices. 

PHMSA’s experience with these 

requests for special permits led to the 

conclusion that a rule of general 

applicability is appropriate. With a rule 

of general applicability, the conditions 

for approval are established for all 

without need to craft the conditions 

based on individual evaluation. Thus, 

this rule sets rigorous safety standards. 

In place of individual examination, the 

rule requires senior executive 

certification of an operator’s adherence 

to the more rigorous safety standards. 

An operator seeking to operate at a 

higher pressure than allowed by current 

regulation must certify that a pipeline is 

built according to rigorous design and 

construction standards and must agree 

to operate under stringent O&M 

standards. After PHMSA or state 

pipeline safety authority (when the 

pipeline is located in a state where 

PHMSA has an interstate agent 

agreement, or an intrastate pipeline is 

regulated by that state) receives an 

operator’s certification indicating its 

intention to operate at a higher 

operating stress level, PHMSA or the 

state would then follow up with the 

operator to verify compliance. As with 

the special permits, this rule would 

allow an operator to qualify both new 

and existing segments of pipeline for 

operation at the higher MAOP, provided 

the operator meets the conditions for the 

pipeline segment. 

Several types of pipeline segments 

will not qualify under this rule. These 

include the following: 

• Pipeline segments in densely 

populated Class 4 locations. In addition 

to the increased consequences of failure 

in a Class 4 location, the level of activity 

in such a location increases the risk of 

excavation damage. 

• Pipeline segments of grandfathered 

pipeline already operating at a higher 

stress level but not constructed in 

accordance with modern standards. 

Although grandfathered pipeline has 

been operated successfully at the higher 

stress level, PHMSA or the state would 

examine any further increases 

individually through the special permit 

process. 

• Bare or ineffectively coated pipe. 

This pipe lacks the coating needed to 

prevent corrosion and to make cathodic 

protection effective. 

• Pipelines with wrinkle bends. 

Section 192.315(a) currently prohibits 

wrinkle bends in pipeline operating at 

hoop stress exceeding 30 percent of 

SMYS. 

• Pipelines experiencing failures 

indicative of a systemic problem, such 

as seam flaws, during initial hydrostatic 

testing. Such pipe is more likely to have 

inherent defects that can grow to failure 

more rapidly at higher stress levels. 

• Pipe manufactured by certain 

processes, such as low frequency 

electric welding process. 

• Pipeline segments which cannot 

accommodate internal inspection 

devices. 

We are establishing slightly different 

requirements for segments that have 

already been operating and those which 

are to be newly built. Some variation is 

necessary or appropriate for an existing 

pipeline. For example, the requirement 

for cathodically protecting pipeline 

within 12 months of construction is an 

existing requirement for all pipelines. A 

requirement for the operator of an 

existing pipeline segment to prove that 

the segment was in fact cathodically 

protected within 12 months of 

construction provides greater 

confidence in the condition of the 

existing segment. Allowing proof of five 

percent fewer nondestructive tests done 

on an existing segment at the time of 

construction recognizes the possibility 

that some welds may not be tested when 

100 percent nondestructive testing is 

not required. The overriding principle 

in the variation is to allow qualification 

of a quality pipeline with minimal 

distinction. Based on our review of 

requests for special permits on existing 

pipelines, PHMSA does not believe the 

more rigorous standards we are 

requiring are too high for existing 

segments of modern design and 

construction. Setting the qualification 

standards lower for existing pipeline 

segments could encourage operators to 

construct a pipeline at the lower 

standards and seek to raise the operating 

pressure at some future date. 

PHMSA acknowledges this rule may 

not cover all conditions encountered by 

a pipeline operator. Further, operators 

may have innovative alternative 

methods to the guidelines contained in 

this rule. To that end, operators may 

apply to PHMSA or state pipeline safety 

authority (when the pipeline is located 

in a state where PHMSA has an 

interstate agent agreement, or an 

intrastate pipeline is regulated by that 

state) for a special permit requesting to 

implement the alternative methods. 

B.6. How To Handle Special Permits 

and Requests for Special Permits 

A number of pipeline operators have 

submitted requests for special permits 

seeking relief from the current design 

requirements to allow operation at 

higher stress levels. For the most part, 

this rule addresses the relief requested. 

PHMSA has already granted many of 

these under terms and conditions that 

may vary slightly from those in this 

final rule. In some cases, the relief 

granted is specific to the relief requested 

by the operator and extends beyond the 

scope of this rulemaking. PHMSA has 

continued review of pending special 

permit applications while working on 

this rulemaking, in recognition that a 

final rule may not be issued by the time 

an operator intended to operate its 

pipeline at a higher operating stress 

level. With the publication of this final 


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rule, this case-by-case approach to 

approving operation under a special 

permit at higher operating stress levels 

is no longer needed. 

PHMSA will terminate its review of 

any pending applications for special 

permits associated with operation at 

higher operating stress levels once this 

final rule is issued. Operators of those 

pipelines must comply with this final 

rule in order to operate their pipelines 

at a higher alternative MAOP. PHMSA 

will examine special permits that have 

already been granted, as appropriate, to 

determine if any modifications are 

needed in light of safety decisions made 

in preparing this rule. 

B.7. Statutory Considerations 

Under 49 U.S.C. 60102(a), PHMSA 

has broad authority to issue safety 

standards for the design, construction, 

O&M of gas transmission pipelines. 

Under 49 U.S.C. 60104(b), PHMSA may 

not require an operator to modify or 

replace existing pipelines to meet a new 

design or construction standard. 

Although this rule includes design and 

construction standards, these standards 

simply add more rigorous, nonmandatory requirements. This rule does 

not require an operator to modify or 

replace existing pipelines or to design 

and construct new pipeline in 

accordance with these non-mandatory 

standards. If, however, a new or existing 

pipeline meets these more rigorous 

standards, the rule allows an operator to 

elect to calculate the MAOP for the 

pipeline based on a higher stress level. 

This would allow operation at an 

increased pressure over that otherwise 

allowed for pipeline built since the 

Federal regulations were issued in the 

1970s. To operate at the higher pressure, 

the operator would have to comply with 

more rigorous O&M, and management 

requirements. 

Under 49 U.S.C. 60102(b), a gas 

pipeline safety standard must be 

practicable and designed to meet the 

need for gas pipeline safety and for 

protection of the environment. PHMSA 

must consider several factors in issuing 

a safety standard. These factors include 

the relevant available pipeline safety 

and environmental information, the 

appropriateness of the standard for the 

type of pipeline, the reasonableness of 

the standard, and reasonably 

identifiable or estimated costs and 

benefits. PHMSA has considered these 

factors in developing this rule and 

provides its analysis in the preamble. 

PHMSA must also consider any 

comments received from the public and 

any comments and recommendations of 

the TPSSC. These are discussed below. 

C. Comments on the NPRM 

PHMSA received comments from 19 

organizations in response to the NPRM. 

These included eleven pipeline 

operators, four trade associations and 

related organizations, three steel/pipe 

manufacturers, and one state pipeline 

safety regulatory agency. 

C.1. General Comments 

API 5L, 44th Edition 

Many commenters noted that pipe 

material/design requirements in 

American Pipeline Institute (API) 

Standard 5L (API 5L) have been 

significantly revised in the 44th edition, 

which they stated would be in effect by 

the time a final rule is issued. These 

commenters generally suggested that 

PHMSA should defer to, or incorporate, 

requirements from the 44th edition 

where applicable rather than 

establishing different technical 

requirements in regulation. 

Response 

API 5L, 43rd edition, is currently 

incorporated by reference into the Code 

of Federal Regulations (CFR). PHMSA 

has begun a technical review of the 44th 

edition to determine whether and to 

what extent it is appropriate to update 

this reference or if exceptions need be 

taken when so incorporating the 

standard. PHMSA cannot reference 

requirements in the 44th edition until 

this review is completed and the 

regulations have been revised to 

incorporate the new edition. Where 

differences in the 44th edition would 

affect requirements in this rule, 

appropriate changes will be made when 

that edition is incorporated. 

Effect on Special Permits 

All commenters who addressed the 

question suggested that requirements in 

a final rule should not apply 

retroactively to pipelines operating at 

alternative MAOP based on special 

permits issued after detailed review by 

PHMSA. One pipeline operator 

provided a legal analysis maintaining 

that such retroactive application would 

be contrary to PHMSA’s statutory 

authority. These organizations also 

commented that PHMSA should 

continue review of special permit 

applications until the final rule is 

issued, noting that in many cases 

operation at the proposed higher MAOP 

is necessary to meet contractual 

commitments operators have made in 

anticipation of a special permit being 

granted and to meet national energy 

needs. 

Response 

As noted above, PHMSA continued 

reviewing special permit applications 

throughout this rulemaking proceeding, 

generally applying the same criteria 

adopted in this rule. Having now 

published the final rule, we consider it 

unnecessary to complete review of 

pending special permit applications on 

the subject. Accordingly, PHMSA 

intends to terminate these proceedings, 

with appropriate notice to the 

individual applicants. 

In contrast, this regulatory action has 

no effect on the status of special permits 

or waivers currently in effect. As we 

explained recently in Docket No. 

PHMSA–2007–0033, Pipeline Safety: 

Administrative Procedures, Address 

Updates, and Technical Amendments, 

(FR Volume 73, No. 61, 16562, 

published March 28, 2008), PHMSA 

reserves the right to revoke or modify a 

special permit or waiver based on an 

operator’s failure to comply with the 

conditions of the special permit/waiver 

or on a showing of material error, 

misrepresentation, or changed 

circumstances. Although an operator 

may elect to surrender its special permit 

at any time, nothing in this rule requires 

the operator to do so or otherwise 

triggers reopening of a special permit/ 

waiver currently in effect. The existing 

MAOP special permits were issued 

based upon a PHMSA review of the 

operator’s engineering, construction, 

O&M procedures and operating history. 

While some of the pipeline segments 

may not meet all of the requirements 

specified in this final rule, the 

operational history and O&M practices 

provide an equivalent level of safety as 

provided in this final rule. Furthermore, 

whether a pipeline is operating at higher 

MAOP under this rule or a special 

permit/waiver, PHMSA will monitor 

and enforce compliance with the 

applicable conditions and safety 

controls. 

Structure 

One state pipeline safety regulatory 

agency expressed concern about the 

complexity and inconsistency being 

added to the regulations as a result of 

the structure of the proposed rule. The 

state agency noted that the proposal 

would add many pages to part 192 that 

would apply to only a limited number 

of gas transmission operators. The 

agency suggested that it would be more 

effective, and cause less confusion, if 

requirements for pipelines operating at 

an alternative MAOP were presented in 

a separate subpart, applicable only to 

those pipelines. 


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1Clock Spring is a commercially available 

composite sleeve used for pipeline repairs. 

Response 

PHMSA has not previously used a 

separate subpart to include varied 

requirements applicable to specific 

types of pipelines. Instead, subparts 

have been used for individual topics, 

such as Corrosion Control or Integrity 

Management. PHMSA considers it more 

appropriate to incorporate requirements 

applicable to each subpart as the 

requirements in this rule implicate 

several subparts. PHMSA also notes that 

no other commenters indicated that the 

structure of the proposed rule was 

confusing. PHMSA has retained the 

structure of the proposal in this final 

rule. PHMSA intends to post this notice 

of final rulemaking on its web site, 

which will provide a reference for 

pipeline operators that includes all of 

the requirements associated with 

alternative MAOP in one document. 

C.2. Comments on Specific Provisions in 

the Proposed Rule 

C.2.1. Section 192.7, Incorporation by 

Reference 

Interstate Natural Gas Association of 

America (INGAA) and three pipeline 

operators supported incorporation of 

American Society of Testing and 

Materials (ASTM) standard ASTM A– 

578/A578M–96 into the regulations. 

These commenters generally noted that 

this action is consistent with reliance on 

consensus standards, which they 

support. American Gas Association 

(AGA) and the Gas Piping Technology 

Committee (GPTC) took the contrary 

position and opposed incorporation of 

the ASTM standard. GPTC commented 

that the standard is used by one mill 

and that other mills use other standards 

(including International Standards 

Organization (ISO) standards). GPTC 

also noted that there are a number of 

equivalent standards and that PHMSA 

should not select one for incorporation. 

AGA added that incorporating the 

standard could have unintended 

consequences of making the rule too 

prescriptive and precluding the use of 

equivalent standards. 

Response 

The final rule incorporates ASTM 

A578/A578M–96 into the regulations. 

Incorporation by reference makes the 

provisions of the standard apply, when 

it is referenced in a regulation, in the 

same manner as if they were written in 

the CFR. Referencing consensus 

standards wherever possible is the 

policy of the Federal government. 

This standard is referenced in the 

regulation for assuring plate/coil quality 

control (QC). That reference requires 

that ultrasonic (UT) testing be 

conducted in accordance with the 

standard, API 5L paragraph 7.8.10, or 

equivalent. The pipe must also be 

manufactured in accordance with API 

5L which is already referenced in 

§ 192.7. PHMSA considers that the 

allowance for use of an equivalent 

standard renders moot the concerns 

expressed by AGA and GPTC. 

C.2.2. Design Requirements 

Section 192.112(a), General Standards 

for the Steel Pipe 

Carbon equivalent: INGAA, five 

pipeline operators and two pipe 

manufacturers all noted that the 

proposed limit in paragraph (a)(1) on 

carbon equivalent (CE) (0.23 percent 

Pcm) is inconsistent with the 44th 

edition of API 5L. INGAA and one 

operator suggested deleting the limit 

from the proposed rule. Two operators 

noted that the NPRM described no 

analysis or data showing the need for a 

different limit. Several commenters 

indicated that high-strength pipe (grades 

X–80 and above) is difficult to achieve 

with the stated limit. One operator 

suggested that weldability is the key 

issue and that allowance for a higher CE 

is particularly important for highstrength and strain-based pipe. A steel 

manufacturer objected to sole reliance 

on the Pcm formula for determining the 

CE value. 

Response 

PHMSA agrees that the limit in API 

5L is acceptable. PHMSA has changed 

the limit for CE to 0.25 Pcm (Ito-Bessyo 

formula for CE), which is consistent 

with API 5L. PHMSA does not agree 

that no limit should be included in the 

CFR. PHMSA considers that a limit is 

necessary to assure the quality of steel 

used for pipelines to operate at an 

alternative MAOP. Weldability tests are 

not timely for determining the 

acceptability of steel, as they cannot be 

performed until pipe is manufactured. 

Recent experience with several new 

pipelines using X–80 steel has indicated 

that such high strength steel can meet 

the CE limit. PHMSA does not currently 

have experience with steels of grades 

higher than X–80 and will need to 

understand what is important for such 

pipe grades as they are used. 

PHMSA acknowledges that there are 

other methods for calculating the CE 

value of steel. The Pcm formula 

included in the proposed rule is a 

method used by several mills. PHMSA 

has revised the final rule to include use 

of an alternate International Institute of 

Welding (IIW) CE formula, used by 

other mills for determining CE. 

Diameter to thickness ratio: INGAA 

and three pipeline operators suggested 

deleting the limit in proposed paragraph 

(a)(3) on the ratio of pipe diameter to 

thickness (D/t). They maintained that 

this limit may be inappropriate for highgrade pipe and that the concerns that 

might underlie such a limit are 

adequately addressed by the proposed 

rule and common construction practices 

and quality assurance (QA). One 

operator noted that ovality and denting 

issues are addressed by the proposed 

construction requirements of § 192.328, 

that QA is required by proposed 

§ 192.620(d)(9), and that the baseline 

geometry ILI and the provisions of the 

ASME Code would also address the 

underlying concerns. 

Response 

PHMSA has retained the proposed 

limit. PHMSA adopted this limit (i.e., D/ 

t ≤ 100) based upon presentations made 

by industry experts at the public 

meeting on ‘‘Reconsideration of 

Maximum Allowable Operating 

Pressure in Natural Gas Pipelines’’ held 

on March 21, 2006 in Reston, VA. 

Higher D/t ratios can lead to excessive 

denting during transportation, 

construction bending, pipe stringing on 

the right-of-way, backfilling, and 

hydrostatic testing. 

Section 192.112(b), Fracture Control 

Several commenters noted that some 

requirements included in the proposed 

rule are being eliminated or 

significantly revised in the 44th edition 

of API 5L. The steel/pipe manufacturers 

suggested referencing the new standard 

to, among other things, avoid 

unnecessarily limiting approaches to 

deriving arrest toughness and treating 

all sizes and types of pipe (e.g., 

seamless) the same for purposes of the 

drop weight test. 

INGAA and three pipeline operators 

suggested a change to allow a crack 

arrest design other than mechanical 

arrestors if crack propagation cannot be 

made self-limiting. (One operator noted 

that Clock Spring 1 is marketed as a 

crack arrestor). They suggested that a 

rule should allow an option for 

engineering analysis, including an 

analysis of consequences. One operator 

noted that this option could be 

particularly important for high-pressure, 

large-diameter pipelines. Two operators 

generally supported the proposed 

approach for fracture control if selfarrest is attainable. They noted that it is 

critical that operators have a plan and 

consider the potential underVerDate Aug<31>2005 19:47 Oct 16, 2008 Jkt 217001 PO 00000 Frm 00008 Fmt 4701 Sfmt 4700 E:\FR\FM\17OCR3.SGM 17OCR3

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conservativeness of Charpy toughness 

equations for high grade pipe (X–70 and 

above). 

Response 

PHMSA has not yet incorporated the 

44th edition of API 5L into the 

regulations. PHMSA is conducting a 

technical review of this edition to 

determine if it is acceptable for 

incorporation. If, after that review, 

PHMSA determines that the standard is 

acceptable, PHMSA will propose to 

incorporate the 44th edition and change 

other affected rules as appropriate. 

The final rule requires an overall 

fracture control plan to resist crack 

initiation and propagation and to arrest 

a fracture within eight pipe joints with 

a 99 percent occurrence probability and 

within five pipe joints with a 90 percent 

occurrence probability. Research has 

shown that an effective fracture plan 

should include acceptable Charpy 

impact and drop weight tear tests, 

which are required in this final rule. 

PHMSA considers composite sleeves 

to be suitable mechanical crack 

arrestors. Operators could use 

composite sleeves for this purpose, 

install periodic joints of thicker-walled 

pipe, or use other design features to 

provide crack arrest if it is not possible 

to achieve the toughness properties 

specified in the rule and also assure 

self-limiting arrest. PHMSA has revised 

the language in this final rule to allow 

additional design features and to make 

mechanical crack arrestors an example 

of such features rather than the only 

method allowed. 

Section 192.112(c), Plate/Coil Quality 

Control 

One pipeline operator and two pipe 

manufacturers suggested expanding the 

mill control inspection program to a full 

internal quality management program 

and including caster and plate/coil/pipe 

mills. 

INGAA, three pipeline operators and 

two pipe manufacturers commented that 

the specificity of requirements 

applicable to mill inspection should be 

reduced. These commenters agreed that 

a macro etch test is appropriate but 

suggested that the details of how this 

test is applied should be left to 

decisions of the mill and the pipe 

purchaser. They suggested that API 5L 

provides a foundation for those 

decisions and the specific requirements 

in the proposed rule add unnecessary 

cost impact. One pipe manufacturer 

noted that the Mannesmann scale is 

very subjective, while a second 

separately commented that reference to 

the Mannesmann scale should be 

deleted because it is proprietary and 

thus inappropriate for inclusion in a 

regulation. One operator requested that 

the mill inspection requirements, 

including those for macro etch and UT 

examination, be explicitly limited to 

new pipelines, noting that it is unlikely 

these tests were performed for any 

existing pipelines and that they have 

minimal relevance for existing pipelines 

that would be subject to the proposed 

rule. 

INGAA and four pipeline operators 

suggested that an alternative to the UT 

testing specified should be allowed for 

identifying laminations. They suggested 

that a full-body UT inspection, for 

example, should be acceptable. 

One operator and two manufacturers 

commented that it is inappropriate to 

use the proposed macro etch test and 

acceptance criteria as a heat/slab 

rejection criteria. These commenters 

noted that no consensus standard 

references this test. The operator 

maintained that the test does not 

accomplish what PHMSA suggested in 

the preamble of the NPRM, that it is a 

lagging rather than a leading test and its 

use as an acceptance test without a 

retest allowance could result in 

rejection of up to 2,000 tons of steel or 

more. The operator suggested that this 

should be a mill control test rather than 

an acceptance test with specifics, 

including retest allowance, to be 

negotiated between the mill and pipe 

purchaser. 

One operator and one manufacturer 

noted that ASTM A578 is a plate UT 

inspection standard. They commented 

that specifying this standard for coil/ 

pipe is beyond its scope. They also 

commented that we gave no basis for 

proposing that 50 percent of surface and 

90 percent of joints be examined. They 

noted that pipe seam welds and pipe 

ends are inspected radiographically or 

by UT and that additional UT is more 

appropriately a purchaser-specified 

requirement. Another operator also 

suggested that the 50 percent surface 

coverage requirement be deleted in 

favor of reference to ASTM A578/ 

A578M. 

Two manufacturers suggested that the 

rule allow UT on plate/coil or pipe 

body, noting that most United States 

mills lack equipment to perform ASTM 

A578 testing. Another manufacturer 

suggested that a combination of 

electromagnetic inspection (EMI) and 

UT inspection is superior and would 

produce the most dramatic impact. This 

combination, according to this 

manufacturer, is also applicable to 

seamless and electric resistance welded 

(ERW) pipe. 

One manufacturer recommended that 

the inspection program of proposed 

section 192.112(c)(2)(ii) be limited to 

submerged arc welded (SAW) pipe, and 

that the acceptance criteria for UT 

testing be referenced to ASTM A578 or 

equivalent. This commenter noted that 

laminations are not a significant issue 

for modern pipe. 

Response 

PHMSA agrees that an ‘‘internal 

quality management program’’ is more 

descriptive than a ‘‘mill control 

inspection program’’ and that such a 

program should be required at all mills 

associated with the manufacture of steel 

and pipe. The final rule has been 

revised accordingly. 

PHMSA considers that a macro etch 

test or other equivalent method is 

needed to identify inclusions that may 

cause centerline segregation during the 

continuous casting process. The 

acceptance criteria must be agreed to 

between the purchaser and the mill. 

PHMSA has added an alternative to the 

requirement for a macro etch test 

consisting of an operator QA monitoring 

plan that includes audits conducted by 

the operator (or an agent operating 

under its authority) of: (a) Steelmaking 

and casting facilities; (b) QC plans and 

manufacturing procedure specifications 

(MPS); (c) equipment maintenance and 

records of conformance; (d) applicable 

casting superheat and speeds; and (e) 

centerline segregation monitoring 

records to ensure mitigation of 

centerline segregation during the 

continuous casting process. 

PHMSA agrees that alternate methods 

to test the pipe body for laminations, 

cracks, and inclusions should be 

acceptable and has revised the rule to 

allow methods per API 5L Section 

7.8.10 or ASTM A578-Level B, or other 

equivalent methods. PHMSA 

understands that it is unlikely that 

many existing pipelines were 

manufactured using processes that 

included the specified examinations but 

does not consider that sufficient reason 

for excluding existing pipelines from 

the requirements. 

The requirement for 50 percent of 

surface and 95 percent of lengths of pipe 

to be UT tested was set to ensure 

adequate QC standards. PHMSA agrees 

that the specified QC requirements also 

must be practical. In the final rule, we 

have reduced the requirement for 50 

percent of surface coverage to 35 

percent because we recognize that it 

may be difficult to achieve 50 percent 

coverage for pipe manufactured with 

helical seams. 

PHMSA has not deleted reference to 

the Mannesmann scale, which is widely 

used by steel manufacturers. In 


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addition, the regulation allows for use of 

equivalent measures. 

PHMSA does not agree that the 

inspection program of proposed 

192.112(c)(2)(ii) should be limited to 

SAW pipe. PHMSA considers this 

requirement to be an overall quality 

management tool and not just for 

laminations. Additionally, PHMSA 

notes that at least one recently 

constructed pipeline has had problems 

with laminations. 

Section 192.112(d), Seam Quality 

Control 

INGAA, four pipeline operators, and 

two pipe manufacturers all 

recommended additional reliance on the 

procedures of API 5L 44th edition. The 

manufacturers would have referenced 

API 5L for toughness requirements and 

made them applicable to weld and heat 

affected zone in SAW pipe only. They 

noted that the proposed requirement is 

inappropriate for ERW pipe, that the 

specified toughness is higher than that 

called for in API 5L and is not 

necessary. The manufacturers believe 

that fracture arrest capabilities are not 

needed in weld metal, since staggered 

seams in pipeline construction result in 

arrest occurring in the pipe body. 

INGAA and three pipeline operators 

would have eliminated reference to 

specific hardness testing or a maximum 

hardness level, arguing that API 5L 

contains sufficient guidance. They 

further noted that the specified hardness 

of 280 Vickers (Hv10) is only for sour 

gas. One manufacturer would have 

relaxed the hardness requirement to 300 

Hv10 and allowed for equivalent test 

methods (per ASTM E140). Another 

would have specified a maximum 

hardness ‘‘appropriate for the pipeline 

design’’ vs. specifying a limit. The first 

manufacturer noted that API 5L does 

not specify hardness limits except for 

sour gas service or offshore pipelines 

and that the technical justification for 

these limits on other pipe is not 

obvious. The manufacturers maintained 

that limiting hardness may not allow 

attaining the best weld properties and 

that 280 Hv10 is likely not attainable for 

pipe grades X–80 and above. 

Two pipe manufacturers requested 

that the rule be clarified to indicate that 

the seam QC requirements apply only to 

longitudinal or helical seams. They 

noted that pipe mill jointer welds 

require radiography per API 1104 and 

that significant capital expense would 

be required for pipe mills to UT test 

jointer and skelp end welds after cold 

expansion and hydrostatic testing. 

Response 

PHMSA has not yet incorporated the 

44th edition of API 5L into the 

regulations. PHMSA is conducting a 

technical review of this edition to 

determine if it is acceptable for 

incorporation. If, after review, PHMSA 

determines that the standard is 

acceptable, PHMSA will propose to 

incorporate the 44th edition and 

propose changes to other affected 

regulations as appropriate. 

PHMSA has deleted the proposed 

limit on toughness. This limit was not 

included in the conditions applied to 

special permits issued for alternative 

MAOP operation. Pipe procured to 

modern standards generally meets the 

proposed limit, and other requirements 

in this rule, provide for crack arrest. 

Thus, PHMSA concluded that a 

toughness limit was not needed. 

PHMSA does not agree that it is not 

necessary to specify a hardness limit. 

All recent pipelines for which special 

permits have been issued to operate at 

alternative MAOP have met the 

proposed hardness limit without 

apparent difficulty. This includes X–80 

pipe. The requirement helps assure that 

only high-quality steel is used for 

pipelines to be operated at alternative 

MAOP. Hardness must be limited to 

assure welds are not susceptible to 

cracking. The proposed limit has been 

retained in the final rule. 

PHMSA intends the proposed seam 

inspection requirements to apply to 

pipe seam welds and not to jointer or 

skelp welds. The title of this 

subparagraph is ‘‘Seam quality control,’’ 

and its requirements all refer to ‘‘seam 

welds’’ or ‘‘seams.’’ PHMSA does not 

consider that additional changes are 

needed to clarify the applicability of 

these requirements. 

Section 192.112(e), Mill Hydrostatic 

Test 

Most commenters objected to the 

proposed requirement that mill 

hydrostatic tests be held for 20 seconds. 

They noted that mills typically follow 

API 5L, which specifies a hydrostatic 

test of 10 seconds and that changing this 

standard could reduce mill 

productivity. One operator also noted 

that a more rigorous qualification test is 

already specified elsewhere in the 

proposed regulation. 

One manufacturer would have limited 

the required maximum test pressure to 

3,000 psi if there are physical 

limitations in mill test equipment that 

preclude obtaining higher pressures. 

The manufacturer stated that most mills 

cannot achieve test pressures above 

3,000 psi, which is the maximum 

specified in API 5L and that upgrades to 

equipment would cost from $0.5 to $4 

million per tester. 

Response 

PHMSA agrees that a 20-second mill 

hydrostatic test is not needed and has 

revised the final rule to reduce the 

required hold time to 10 seconds. While 

a longer mill hydrostatic test may allow 

the discovery of more pipe defects, the 

benefit is marginal. The pipeline will 

later be subject to a much longer 

hydrostatic test prior to being placed in 

service according to 192.505(c). 

Moreover, in the case of Class 1 and 2 

locations, the pipe will be tested at a 

higher stress level than the mill 

hydrostatic test according to 

192.620(a)(2). 

PHMSA does not consider it 

appropriate to limit the maximum test 

pressure to reflect the reported mill 

limitations. In practice, the need for 

tests above 3,000 psi should be rare. 

Test pressures that high would only be 

required for pipeline in a Class 3 

location operating at a very high MAOP. 

Section 192.112(f), Coating 

INGAA, GPTC, and eight pipeline 

operators all objected to the proposed 

requirements that would have limited 

operation at an alternative MAOP to 

pipe coated with fusion bonded epoxy 

(FBE). The commenters noted that 

specifying any single coating type 

would stifle innovation. They suggested 

that a performance-based requirement 

would be more appropriate. The 

important performance characteristics 

they identified include non-disbonding 

and non-cracking. Two operators would 

add non-shielding, and GPTC suggested 

specifying that coating must meet or 

exceed the protection of FBE. 

GPTC and one operator requested 

clarification that girth welds can be 

coated with other than FBE. GPTC also 

requested clarification that the proposed 

requirement in subparagraph 2 that 

coatings used for trenchless installation 

must resist abrasion and other damage 

applies to the coatings described under 

subparagraph 1. 

Response 

PHMSA agrees that specifying a 

particular coating could stifle 

innovation and we have revised the 

final rule to require non-shielding 

coatings. Eliminating reference to FBE 

coating in this section obviates the need 

for additional changes to note that girth 

welds can be coated with other than 

FBE. 

PHMSA has made a minor change in 

response to GPTC’s request for 

clarification. Subparagraph 192.112(f)(2) 


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now requires that coatings used for 

trenchless installation must resist 

abrasions and other installation damage 

‘‘in addition to being non-shielding.’’ 

Section 192.112(g), Flanges and Fittings 

INGAA and three pipeline operators 

generally supported the proposed 

requirements for certification records 

and a pre-heat procedure for welding of 

components with CE greater than 0.42 

percent, but maintained that existing 

standards and operator supplemental 

requirements are adequate to assure the 

integrity of flanges and fittings. The 

operators cited specific standards to 

which fittings and flanges should be 

purchased. Another operator noted that 

the proposed requirements go beyond 

API and ASTM standards, and 

suggested that the new requirements 

should be part of an industry standard. 

This operator also suggested that 

PHMSA establish a minimum size 

below which certifications would not be 

required. 

GPTC requested clarification as to 

what certification is required and what 

requirements/specifications are to be 

certified. 

Response 

PHMSA has concluded that no 

changes are needed to the standards 

proposed for flanges and fittings. It is 

likely that flanges and fittings procured 

to current standards will meet the rule’s 

requirements. PHMSA will review the 

degree of compliance during inspections 

of pipelines being constructed or 

upgraded for operation at an alternative 

MAOP. PHMSA does not agree that the 

proposed requirements go beyond API 

and ASTM standards. Fittings, flanges 

and valves manufactured to API, ASTM, 

and/or ASME/ANSI standards should 

not be operated above the maximum 

operating pressure limits of those 

industry standards for the product 

rating. This rule change is not intended 

to increase maximum operating pressure 

limits or designated pressure or 

temperature rating of referenced code 

standards. 

In the final rule, PHMSA has clarified 

that certification must address 

chemistry, strength and wall thickness. 

Section 192.112(h), Compressor Stations 

Commenters expressed concern about 

the proposed requirement to limit 

compressor station discharge 

temperatures to 120 degrees Fahrenheit 

(49 degrees Celsius) unless testing 

shows the coating can withstand higher 

temperatures in long-term operations. 

INGAA and four pipeline operators 

would allow ‘‘research’’ in addition to 

testing to permit operation above 120 

degrees Fahrenheit. INGAA submitted a 

white paper titled ‘‘A Review of the 

Performance of Fusion-Bonded Epoxy 

Coatings on Pipelines at Operating 

Temperatures Above 120 °F’’, dated 

May 16, 2008, describing research it 

believes is relevant. The commenters 

stated that more testing is not needed, 

because FBE coating has been shown 

effective by research and experience in 

service. They maintained that 

disbonding may occur but is irrelevant 

because FBE coating is conductive and 

cathodic protection is still effective. 

One pipeline operator would have 

allowed operation at a higher 

compressor station discharge 

temperature if justified by test or data 

held by the manufacturer, coating 

applicator, or operator. The operator 

maintained that modern coating can 

withstand higher temperatures, and that 

maintaining 120 degrees Fahrenheit 

may be impractical on hot days (during 

which peak loads often occur) in 

southern locations. Another operator 

suggested allowing operators to rely on 

FBE manufacturers’ specifications as the 

‘‘testing’’ adequate to allow operation 

above 120 degrees Fahrenheit, limiting 

operation to 90 percent of the 

manufacturer’s continuous operating 

temperature. Another operator 

suggested allowing a long-term coating 

integrity monitoring program as an 

alternative to designing compressor 

stations to limit discharge temperature 

to 120 degrees Fahrenheit. 

A state pipeline safety regulatory 

agency suggested that alternative 

approaches be allowed. The agency 

suggested that operators could install 

heavier walled pipe and operate at 

conventional MAOP for the distance 

required to assure that pipe wall 

temperatures would be below 120 

degrees Fahrenheit. This commenter 

stated its belief that this would be a 

simpler and cheaper solution to the 

concern over compressor station outlet 

temperature and that its use should not 

be precluded. 

Response 

PHMSA is not persuaded by the 

arguments put forth by commenters, and 

in the INGAA white paper titled ‘‘A 

Review of the Performance of FusionBonded Epoxy Coatings on Pipelines at 

Operating Temperatures Above 120 °F’’, 

dated May 16, 2008, that operation 

above 120 degrees Fahrenheit is simply 

acceptable. In fact, the INGAA white 

paper confirms that disbonding and 

possibly cracking of FBE coating is more 

likely to occur at operating temperatures 

above 120 degrees Fahrenheit. PHMSA 

disagrees that disbonding is irrelevant 

because disbonded FBE remains 

conductive and an operating cathodic 

protection system will protect the 

pipeline from corrosion. 

External corrosion is one of the most 

significant threats affecting steel 

pipelines. PHMSA regulations require 

two levels of protection against this 

threat: Coating and cathodic protection. 

These requirements are intended to 

provide redundant protection. If coating 

fails, cathodic protection continues to 

protect the pipe. If cathodic protection 

fails, the coating is still present. PHMSA 

agrees that it is important that 

disbonded coating remain conductive to 

assure continued protection by cathodic 

protection. This is why the rule has 

been revised to require ‘‘non-shielding’’ 

coating. At the same time, PHMSA does 

not consider it acceptable to ignore 

known circumstances in which one of 

the protections against corrosion is 

likely to fail simply because the other 

exists. If PHMSA believed only one 

level of protection were needed, the 

regulations would require either coating 

or cathodic protection. INGAA’s white 

paper confirms that there is a significant 

likelihood that one of the levels of 

protection against corrosion (i.e., 

coating) will fail if operated above 120 

degrees Fahrenheit. For pipelines to be 

operated at an alternative MAOP, where 

the margin for corrosion is smaller than 

for pipelines conforming to the existing 

regulations, PHMSA will not accept this 

higher likelihood of failure of the 

coating system. 

Nevertheless, PHMSA recognizes that 

improvements in coating systems may 

allow operation above 120 degrees 

Fahrenheit without significantly higher 

likelihood of disbonding. Thus, the rule 

allows operation above this temperature 

if research, testing, and field monitoring 

tests demonstrate that the coating type 

being used will withstand long-term 

operation at the higher temperature. The 

operator must assemble and maintain 

the data supporting higher-temperature 

operation. Research, testing and field 

monitoring must be for coating by the 

same manufacturer and must be specific 

to the brand of coating (if the 

manufacturer makes more than one 

brand), application temperature, or 

operating temperature rated coating. 

PHMSA agrees that a long-term 

coating integrity monitoring program 

can also assure that coating remains 

effective at higher operating 

temperatures, but the effectiveness of 

such a program depends on how it is 

structured and implemented. PHMSA 

would expect, for example, that a 

monitoring program being used as a 

basis for operating at temperatures 

above 120 degrees Fahrenheit would 

include periodic examinations to assure 


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coating integrity (e.g., direct current 

voltage gradient). PHMSA has modified 

the final rule to allow a long-term 

coating integrity monitoring program to 

be used as a basis for allowing pipe 

temperatures in excess of 120 degrees 

Fahrenheit, but operators must submit 

their programs to the PHMSA pipeline 

safety regional office in which the 

pipeline is located for review before 

pipeline segments may be operated at 

alternative MAOP at these higher 

temperatures. PHMSA’s review will 

help assure that the monitoring 

programs are comprehensive enough to 

assure long-term coating integrity, to 

identify instances in which coating 

integrity becomes degraded, and to 

address those problems. An operator 

must also notify a state pipeline safety 

authority when the pipeline is located 

in a state where PHMSA has an 

interstate agent agreement, or an 

intrastate pipeline is regulated by that 

state. 

Where compressor station 

compression ratios raise the temperature 

of the flowing gas to above 120 degrees 

Fahrenheit, operators should consider 

installing gas coolers at compressor 

stations. This practice has been 

successfully used in the industry to cool 

the gas stream to not damage the pipe 

external coating. 

PHMSA agrees that the alternative of 

heavier walled pipe operated at 

conventional MAOP for the distance 

required to assure that pipe wall 

temperatures do not exceed 120 degrees 

Fahrenheit suggested by the state 

regulator is also an acceptable method 

of addressing the concern of hightemperature operation. PHMSA has 

made minor changes to the rule to make 

it clear that this option is not precluded. 

C.2.3. Construction Requirements 

Section 192.328(a), Quality Assurance 

(QA) 

Four pipeline operators supported the 

QA requirements of proposed 

§ 192.328(a). A state pipeline safety 

regulator noted that subparagraph 2(ii) 

duplicated requirements in proposed 

§ 192.620(c)(5) and questioned why both 

sub-rules were needed. 

Response 

PHMSA’s experience in regulating 

pipelines operating at higher MAOPs 

under special permits has indicated that 

control of quality is subject to frequent 

problems. As a result, PHMSA considers 

that an explicit requirement for a QA 

plan during construction is needed. The 

requirements of proposed 

§ 192.620(c)(5) also addressed quality 

concerns, but they relate principally to 

personnel qualification. As described 

below, this proposed paragraph has 

been revised in the final rule to more 

explicitly address the qualification of 

personnel performing construction 

tasks. 

Section 192.328(b), Girth Welds 

INGAA and four pipeline operators 

suggested moving the requirement for 

testing of girth welds on existing 

pipelines from § 192.328 to § 192.620. 

They believe that the requirement is 

inappropriately located in a 

construction section that is not 

otherwise applicable to existing pipe. 

Response 

PHMSA agrees and has moved this 

requirement in the final rule to 

§ 192.620(b) as one of the criteria for 

determining when an existing pipeline 

can be operated at alternative MAOP. 

Section 192.328(c), Depth of Cover 

Three pipeline operators supported 

the proposed depth of cover 

requirements, although one would 

clarify that they apply to new 

construction. Another operator 

suggested that allowance be made for 

less depth of cover if alternative means 

of protection are used (e.g., concrete 

slabs) that offer equivalent protection. 

Response 

PHMSA agrees that alternative 

protection is acceptable and has revised 

its proposed rule accordingly in this 

final rule. To satisfy the rule, alternative 

protection must provide equivalent 

protection and the operator must 

demonstrate this equivalence. Simply 

providing barriers without 

demonstrating that they provide 

equivalent protection is not sufficient. 

PHMSA did not intend this 

requirement to apply to new 

construction only and thus, has not 

changed the requirement in the final 

rule. PHMSA considers that a pipeline 

to be operated at alternative MAOP, 

including existing pipelines, must have 

superior protection from outside force 

damage. PHMSA recognizes that 

existing pipelines constructed in 

compliance with § 192.327 may have 

less cover than required in this rule. 

Operators of those pipelines desiring to 

implement alternative MAOP must 

provide equivalent protection for those 

segments not meeting the depth of cover 

requirements. 

Section 192.328(d), Initial Strength 

Testing 

A number of commenters objected to 

the proposed requirement that any 

failure indicative of a fault in material 

disqualifies a pipeline segment from 

operation at an alternative MAOP. The 

commenters suggested that a root cause 

analysis be permitted, consistent with 

previously-issued special permits, to 

determine if the fault indicates a 

systemic issue. Disqualification is only 

appropriate, according to the 

commenters, if a systemic issue exists, 

and failures can result from isolated 

causes. One operator would also clarify 

that these requirements apply to base 

pipe material rather than flanges, 

gaskets, etc. Another suggested that 

multiple test failures can actually be 

beneficial, because they prompt 

additional failure analyses that better 

assure the integrity of the non-failed 

pipe. 

Response 

PHMSA agrees that a single failure 

can reflect an isolated cause and should 

not disqualify an entire segment from 

operation at an alternative MAOP if it 

can be demonstrated that the failure is 

not indicative of a problem that could 

affect the rest of the pipeline segment. 

PHMSA has revised the final rule to 

allow a root cause analysis of any 

failures as a way of justifying 

qualification of a pipeline segment. Root 

cause analysis must demonstrate that 

failures in alternative MAOP pipeline 

segments are not systemic. Operators are 

required to notify PHMSA of the results 

of their evaluations, which will allow us 

to validate their conclusions. 

Section 192.328(e), Cathodic Protection 

INGAA and seven pipeline operators 

suggested that this paragraph be deleted, 

since it duplicates requirements in 

§ 192.455. One of the operators further 

commented that whether cathodic 

protection was operational within 12 

months becomes irrelevant once the line 

is assessed and its condition is known. 

Response 

PHMSA recognizes that § 192.455 

requires that cathodic protection be 

operational within 12 months of placing 

a pipeline in service but does not 

consider the requirement in this rule 

duplicative. Operators who complied 

with § 192.455 will, of course, meet this 

criterion for operation at alternative 

MAOP. Those who did not install 

cathodic protection within 12 months of 

initial operation will not, whether or not 

§ 192.455 was effective at the time. 

PHMSA considers it critical that 

cathodic protection be provided as 

quickly as possible after construction, 

because there are some forms of 

corrosion that can result in high 

corrosion rates (e.g., microbiological 

corrosion and corrosion from current 


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faults) producing significant loss of pipe 

wall in a short period of time. Operation 

at alternative MAOP is thus not allowed 

for those pipelines for which cathodic 

protection was not provided within 12 

months of initial operation. 

PHMSA has moved this requirement 

from § 192.328, a section addressing 

construction requirements, to 

§ 192.620(d)(8), a section addressing 

operations and maintenance 

requirements. PHMSA believes that this 

change will help emphasize that this is 

not simply a re-statement of the 

requirement in § 192.455. 

Section 192.328(f), Interference Currents 

Three pipeline operators supported 

the proposed requirements in this 

subparagraph (one with the 

understanding that § 192.473 will 

govern for an existing Class 1 pipeline). 

Taking a contrary position, another 

operator urges PHMSA to delete this 

paragraph because the requirement is 

already addressed in the regulations and 

it is difficult to address all interference 

issues during construction without 

active cathodic protection (cathodic 

protection is not required to be in 

service until 12 months after 

construction). 

Response 

It is important to address the potential 

for interference currents as early as 

possible. Some pipelines have 

experienced significant wall loss in the 

first months of operation due to the 

effect of interference currents. While it 

may be true that all interference 

currents cannot be identified before 

cathodic protection is in operation, 

many can be anticipated and remediated 

during construction. These include the 

effects of electric transmission lines or 

electrified trains sharing or paralleling a 

right of way, or other ground beds in 

proximity to the pipeline’s route. 

Operators need to address, during 

construction, interference currents that 

can be anticipated. Review of cathodic 

protection effectiveness once it is in 

operation may identify additional 

issues, and operators need to deal 

effectively with these. It is not 

necessary, however, and potentially 

deleterious to pipeline integrity to delay 

all actions addressing interference 

currents until this time. The provisions 

proposed in the NPRM remain 

unchanged in the final rule. 

C.2.4. Eligibility for and Implementing 

Alternative MAOP 

Section 192.620(a), Calculating an 

Alternative MAOP 

Most commenters from the pipeline 

industry objected that the proposed 

requirements for calculating an 

alternative MAOP did not recognize that 

class locations may change once a 

pipeline is in service. They noted that 

§ 192.611 recognizes this for 

conventional MAOP pipelines, and 

allows operation following a class 

change at a higher MAOP than would be 

required for new pipe in that class 

provided that testing was performed at 

a sufficiently high pressure. The 

commenters sought similar treatment for 

alternative MAOPs in this paragraph 

and conforming changes to the language 

in § 192.611 concerning class location 

changes. These commenters also noted 

that the proposed rule does not 

explicitly address compressor stations, 

meter stations, etc. 

Two pipeline operators would reduce 

the test factor for Class 2 locations from 

1.5 to 1.25. They contended that this 

would allow testing of Class 1 and 2 

pipelines to be done together, thereby 

minimizing environmental disruption 

that would be associated with separately 

testing Class 2 to a higher factor. They 

noted that testing of both classes 

together would not be possible with a 

specified test factor of 1.5 for Class 2, 

since this would overstress the Class 1 

pipe (i.e., exceed 100 percent SMYS). 

One operator suggested allowing a test 

factor of 1.25 for existing pipelines and 

requiring 1.5 only for lines installed 

after the effective date of this rule. They 

contended that specifying 1.5 as a 

design factor for Class 2 results in the 

alternative MAOP for Class 2 pipe 

segments being less than currently 

allowed for existing pipelines. 

Two operators suggested that PHMSA 

amend the proposed rule to explicitly 

state that the design factors will increase 

for facilities (stations, crossings, 

fabricated assemblies, etc.) upgraded in 

accordance with the rule. One suggested 

stating that an increase of approximately 

11 percent is allowed. The other 

suggested specific design factors of 0.56 

for station pipe, 0.67 for fabricated 

assemblies and uncased road/railroad 

crossings in Class 1 areas, and 0.56 for 

such assemblies/crossings in Class 2 

locations. 

The state pipeline safety regulatory 

agency commented that the rule should 

contain only one provision regarding 

the test pressure used in determining 

the MAOP. This commenter noted 

proposed § 192.620(a)(2)(ii) limits 

MAOP to 1.5 times the test pressure in 

Class 2 and 3 locations and that 

proposed § 192.620(c)(3) allows 1.25 

times test pressure in all classes. The 

commenter contends that a reference in 

the latter requirement to the former 

creates a confusing circularity. 

Response 

PHMSA agrees that the proposed 

regulation could be more restrictive 

than existing requirements in § 192.611 

in the event of a class change. As noted 

in the comments, the existing regulation 

allows operation at a higher MAOP 

following a class change (i.e., higher 

than would be required for a new 

pipeline installed in that class location) 

provided that testing has been 

conducted at a sufficiently high 

pressure to demonstrate adequate safety. 

PHMSA has revised the final rule to be 

more consistent with § 192.611 in 

allowing operation at a higher pressure 

following a class change. 

PHMSA has reduced the required test 

pressure for existing pipelines (i.e., 

pipelines installed prior to the effective 

date of the rule) in Class 2 locations to 

1.25 times MAOP. This is consistent 

with § 192.611(a)(1). However, if Class 2 

pipeline is tested at 1.25 times MAOP, 

then operation at an increased 

alternative MAOP following a class 

change is not allowed. Such testing does 

not provide sufficient assurance of 

safety margin for the higher population 

Class 3 areas. Operators who desire to 

operate at higher pressures following a 

change from Class 2 to Class 3 must test 

their pipe at 1.5 times alternative 

MAOP. 

PHMSA has included alternate design 

factors for existing facilities and 

fabricated assemblies to be operated at 

alternative MAOP. PHMSA does not 

agree that design factors for facilities 

and fabricated assemblies are needed for 

new installations (i.e., those constructed 

after the effective date of this final rule). 

PHMSA expects design factors for new 

facilities (stations, crossings, fabricated 

assemblies, etc.) to be in accordance 

with § 192.111(b), (c), and (d). 

Section 192.620(b), When may an 

alternative MAOP be used? 

Proposed paragraph b(6) limited 

eligibility for an alternative MAOP for 

pipeline segments that have previously 

been operated to those that have not 

experienced any failure during normal 

operations indicative of a fault in 

material. A number of commenters 

objected to this limitation, which is 

similar to the limitation in proposed 

§ 192.328(d) described above. Here, 

again, the commenters indicated that 

root cause analysis should be allowed 

and operation at an alternative MAOP 


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should be proscribed only if the 

evaluation reveals a systemic issue. 

GPTC requested that paragraph b(3) 

be clarified. That paragraph requires 

that segments to be operated at 

alternative MAOP must have remote 

monitoring and control provided by a 

supervisory control and data acquisition 

system. GPTC requested that PHMSA 

clarify the degree of ‘‘control’’ that is 

required and questioned whether 

remote control of flow and pressure are 

required or if remote control of valves 

is all that was intended. 

One pipeline operator requested that 

either this paragraph or existing 

§ 192.611 be revised to clarify the 

applicability of the current 72/60/50 

percent SMYS limitation on hoop stress. 

The operator believes it is unclear when 

and if the § 192.611 limitations on hoop 

stress apply if an alternative MAOP is 

used. 

Response 

PHMSA agrees that exclusion from 

operation at an alternative MAOP is 

appropriate only if a failure during mill 

hydrostatic testing, construction 

hydrostatic testing, or operation is 

indicative of a systematic issue. PHMSA 

has revised the final rule here (in this 

paragraph and in § 192.328(d) above) to 

allow root cause analysis with operators 

required to notify PHMSA of the results. 

Control requires that operators 

monitor pressures and flows as well as 

compressor start-up and shut-down. 

Valves must also be able to be remotely 

closed. The final rule has been modified 

to make these requirements clear. 

PHMSA has revised § 192.611 to 

include hoop stress limits applicable to 

pipeline operating at alternative MAOP. 

Section 192.620(c), What must an 

operator do to use an alternative MAOP? 

INGAA and four pipeline operators 

suggested that an engineering analysis 

should be allowed for existing pipe that 

was not tested to 125 percent of the 

alternative MAOP. They noted that 

some existing pipe may have been 

tested to higher pressures but not quite 

to 125 percent, and that this pipe should 

not be automatically excluded. They 

noted that experience shows that the 

vast majority of existing pipe is tested 

successfully without systemic problems, 

and that the allowance for 95 percent vs. 

100 percent of girth weld examinations 

in proposed § 192.328(b)(2) establishes a 

precedent for allowing existing pipe that 

can not fully meet new pipe criteria to 

operate at an alternative MAOP. 

One pipeline operator suggested that 

the rule either state that pressure test 

must be at 125 percent of alternative 

MAOP for Classes 1, 2, and 3 or be 

revised to refer to the factors in 

§ 192.620(a)(2)(ii). They contended the 

proposed language was unclear as to 

whether 125 percent is sufficient in all 

class locations. 

A state pipeline safety regulatory 

agency again suggested that the rule 

should contain only one provision 

regarding test pressure (see discussion 

under § 192.620(a) above). 

Several commenters addressed 

training and qualification requirements 

in proposed § 192.620(c)(5). The state 

agency noted that they duplicated 

proposed § 192.328(a)(2)(ii) and 

essentially applied operator 

qualification (OQ) requirements 

(subpart N) to construction personnel. 

The state agency suggested it would be 

simpler and less confusing if it were 

done in subpart N. One pipeline 

operator also suggested deleting 

paragraph c(5) and referring to subpart 

N. This operator noted that the 

proposed rule used undefined and 

vague language—terms such as QC and 

integrity verification (which could be 

confused with assessments under 

subpart O). The operator further noted 

that subpart N requires OQ and that the 

meaning of its requirements is well 

known. 

GPTC requested clarification that the 

requirements are only applicable to 

segments that operate at an alternative 

MAOP and as to the meaning of the 

term ‘‘integrity verification method.’’ 

Response 

PHMSA does not agree that an 

engineering analysis provides an 

adequate basis to justify operation at 

alternative MAOP. Operators who desire 

to use an alternative MAOP for existing 

pipelines that were not tested to 

sufficient pressures should re-test their 

pipelines. 

PHMSA has revised the final rule to 

refer to paragraph (a) for test pressures 

rather than duplicating them. PHMSA 

agrees that this change could help avoid 

confusion. 

PHMSA agrees that applying the 

known requirements of subpart N, 

related to the qualification of personnel 

performing work on the pipeline, would 

likely cause less confusion than 

specifying the alternative, but similar, 

requirements included in the proposed 

rule. Pipeline operators are familiar 

with subpart N, and their training 

programs under that subpart have been 

subjected to audits by PHMSA or states, 

as appropriate. By its terms, though, 

subpart N does not apply to 

construction tasks, since they are not 

‘‘an operations or maintenance task’’— 

one part of the four-part test in 

§ 192.801(b). PHMSA has revised this 

final rule to provide that ‘‘construction’’ 

tasks associated with implementing 

alternative MAOP be treated as covered 

tasks notwithstanding the definition in 

§ 192.801(b). For those tasks, then, the 

requirements of subpart N will apply. 

This change obviates the concerns 

expressed by GPTC and the state 

agency. (PHMSA disagrees with the 

state comment, however, that the 

requirement as proposed duplicated 

§ 192.328(a)(2)(ii), as the latter 

requirement applied only to girth weld 

coating and not to all constructionrelated tasks.) 

C.2.5. Operation and Maintenance 

Requirements 

Section 192.620(d), Additional O & M 

Requirements 

Two pipeline operators and one state 

pipeline regulatory agency suggested 

that covered pipelines should be held to 

the same requirements as pipelines in 

HCA under subpart O. They believe that 

this would make most of § 192.620(d) 

unnecessary and would increase 

flexibility for operators. 

The state regulator noted that it would 

avoid confusion that might be created 

for covered pipelines that would be 

subject to both sets of requirements. One 

operator commented that no technical 

basis is provided for the proposed 

requirements, while subpart O is based 

on science and research. 

Response 

PHMSA disagrees with these 

comments and has not changed the final 

rule because some provisions are more 

restrictive than subpart O. 

Section 192.620(d)(1), Identifying 

Threats 

INGAA and three pipeline operators 

suggested eliminating the requirement 

for a threat matrix and the implied need 

for additional preventive and mitigative 

measures. They noted that operation at 

incrementally higher pressures does not 

inherently increase risk or introduce 

new threats and that the proposed rule 

already includes requirements sufficient 

to address the incremental change. 

Response 

PHMSA does not agree that the rule 

necessarily addresses all threats to a 

pipeline. The rule addresses many 

known threats; however, other threats 

may exist or develop that may affect the 

pipeline’s integrity. It is up to the 

operator to identify and evaluate 

possible pipeline threats and therefore 

PHMSA retained the requirement to 

identify and evaluate threats consistent 

with § 192.917. The term ‘‘assess’’ was 

changed to ‘‘evaluate’’ to avoid 


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confusion with a similar term used in 

integrity management. 

Section 192.620(d)(2), Notifying the 

Public 

INGAA and five pipeline operators 

would eliminate the requirements in 

this proposed section. They contended 

they are unnecessary as they duplicate 

requirements in existing § 192.616 for 

public education. They further 

contended that a dedicated notification, 

specific to operation at a higher 

pressure, is not needed. One operator 

would delete subparagraph (d)(2)(ii) and 

replace it with a one-time notification 

before operation under an alternative 

MAOP begins. This operator believes 

that the proposed requirement for a 

continuing information program is 

excessive, but that a one-time 

notification could be appropriate. 

Response 

Because of the higher consequences of 

operating a pipeline at a higher 

alternative MAOP (and thus a greater 

impact radius), PHMSA believes that 

additional public information is 

necessary to inform any stakeholders 

living along the right-of-way of this 

increase. Where the alternative MAOP 

pipeline is in an HCA already identified 

per Subpart O, then no additional 

notification is necessary beyond what is 

already required. 

Section 192.620(d)(3), Responding to an 

Emergency in High Consequence Areas 

Most industry commenters suggested 

deleting the requirement that operators 

be able to remotely open mainline 

valves. They maintained this 

requirement is unnecessary as an 

emergency response measure and is 

contrary to the operating practice of 

many gas transmission pipeline 

operators. Some also opposed a 

requirement for remote pressure 

monitoring, indicating that it would be 

costly to provide and would add no 

value. AGA commented that the 

language relating to remote control of 

valves was too prescriptive and could 

have the unintended consequence of 

requiring operators to make their safety 

procedures less stringent (presumably 

by allowing remote opening of valves). 

GPTC and two pipeline operators 

questioned the requirement for remote 

valve operation if personnel response 

time to the valves exceeds one hour. 

They argued that the one-hour criterion 

is arbitrary and not justified by research. 

One operator suggested that it is also 

counter to experience. These 

commenters also noted that it is unclear 

how the response time is to be applied, 

from the time of notification of an event, 

from the time a responder is requested 

to go to the valve location, or from some 

other triggering event. GPTC suggested 

that PHMSA consider a requirement 

based on mileage, similar to § 192.179. 

One operator indicated that the need for 

remote control should be based on risk 

analysis rather than an arbitrary 

specified response time. 

Response 

PHMSA agrees that the proposed 

requirement that operators be able to 

remotely open mainline valves is not 

needed for emergency response. 

PHMSA agrees that it is more 

conservative to require local action to 

open valves that may have been closed 

in response to an emergency. PHMSA 

has modified the final rule to eliminate 

the requirement that operators be able to 

remotely open valves. PHMSA 

considers it important to be able to 

monitor pressure in order to know that 

valve closure has been effective. 

PHMSA has retained this requirement. 

PHMSA considers a one-hour 

response time appropriate and 

reasonable. It provides time to respond 

to events while limiting the 

consequences of an extended 

conflagration. In the final rule, PHMSA 

has clarified that the one-hour period 

begins from the time an event requiring 

valve closure is identified in the control 

room and is to be determined using 

normal driving conditions and speed 

limits. 

Section 192.620(d)(4), Protecting the 

Right-of-way 

All commenters except the state 

pipeline safety regulatory agency and 

the steel/pipe manufacturers addressed 

this section. All contended that the 

requirement to patrol the right-of-way 

26 times per year was excessive and that 

experience indicates that more frequent 

patrolling does not prevent pipeline 

events. They maintained that the 

proposed frequency has no apparent 

basis other than that it is the patrolling 

frequency required for hazardous liquid 

pipelines and that application of a 

hazardous liquid pipeline frequency to 

gas transmission lines is inappropriate. 

One operator noted that its experience 

with monthly patrols has demonstrated 

that there is very little excavation 

activity during winter and the summer 

growing season, making patrols then of 

little value. The commenters’ proposals 

for alternate patrolling intervals varied, 

with some suggesting intervals that 

would vary based on the class location. 

INGAA suggested patrolling every 41⁄2

months and after known events. 

INGAA and one pipeline operator 

suggested deleting the requirement for a 

soil monitoring plan, because it would 

be costly and only duplicates other 

existing requirements. 

INGAA and six pipeline operators 

suggested deleting the requirement to 

maintain depth of cover. In its place, 

they would require restoring depth of 

cover or providing appropriate 

preventive and mitigation measures 

only where damage may occur due to 

loss of cover. They noted that 

maintaining the original depth of cover 

is impractical and unnecessary. Normal 

erosion and other events can reduce 

depth of cover, but that reduction does 

not necessarily lead to an increased risk 

of damage. Action may be needed in 

limited circumstances and providing 

other protection in those circumstances 

may be more effective and less costly 

than restoring the original depth of 

cover. One operator suggested that a 

monitoring/maintaining depth of cover 

requirement should be driven by events 

or risk analysis and that discussion in 

the preamble of the NPRM implied such 

an approach. This operator suggested 

allowing engineered solutions in 

addition to restoring depth of cover. 

INGAA and four pipeline operators 

would delete or relax the requirement 

for line-of-sight pipeline markers. 

INGAA noted that discussion at the 

March 2007 public meeting indicated 

that such markers add no value. One 

operator suggested that it would be 

more effective to emphasize one-call 

damage prevention in the preamble of 

the final rule. Another operator noted 

that installation of such markers is 

‘‘non-trivial,’’ and that there is no data 

or analysis supporting the need for 

them. Yet another operator commented 

that the intent of the requirement is 

unclear and suggested that 

circumstances other than agricultural 

areas and large bodies of water 

(exclusions included in the proposed 

rule) would also make it difficult to 

install line-of-sight markers (e.g., steep 

terrain, swamps). 

INGAA and five pipeline operators 

objected to what they characterized as 

an ‘‘open ended’’ requirement to 

implement national consensus 

standards for damage prevention. These 

commenters suggested that the 

requirements focus on the damage 

prevention best practices identified by 

the Common Ground Alliance (CGA) 

and require that operators implement 

the CGA best practices that apply to 

their situation. One operator suggested 

that operators be allowed to evaluate 

and choose among CGA practices. 

Another operator also supported a right 

to choose, indicating that the CGA guide 

includes no expectation that operators 

will adopt all best practices. 


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INGAA and five pipeline operators 

objected to the proposed requirement 

for a right-of-way management plan, 

because it duplicates existing 

requirements for damage prevention. 

Response 

PHMSA has revised the required 

patrol frequency to once per month, at 

intervals not to exceed 45 days. The 

decision to reduce the patrolling 

frequency from 26 patrols per year was 

based on further analysis of the value 

added by the cost of additional 

patrolling, PHMSA’s greater experience 

with administering special permits, and 

comments from industry and public 

advocates supporting risk-based 

requirements rather than a one-size-fitsall approach. PHMSA believes that the 

right of way management plan required 

by § 192.620(d)(4)(vi), coupled with the 

patrolling requirement, will provide 

appropriate safety coverage through 

requiring an operator to develop and 

implement an array of actions based on 

the risk of third-party damage to the 

pipeline. These preventative actions 

may well include additional patrolling 

above what is required by this rule in 

areas that are more heavily-populated or 

that possess greater chances for thirdparty activities in the vicinity of a 

pipeline. 

PHMSA has retained the requirement 

for a soil monitoring program. Gas 

transmission pipelines are often located 

in areas that can exhibit unstable soils, 

such as clay, hills, and mountainous 

areas. It is important to assure that 

stresses caused by soil movement do not 

damage pipelines in these areas with 

reduced design safety factors. PHMSA 

recognizes that operators may already 

address these issues in their damage 

prevention plans or other operating and 

maintenance procedures. If so, an 

additional plan is not required. 

Operators must be able to demonstrate, 

during regulatory audits, that soil 

monitoring is addressed within their 

procedures. 

PHMSA has retained the requirement 

for line-of-sight pipeline markers. 

Outside damage is the most significant 

threat to gas transmission pipelines, 

resulting in the greatest number of 

accidents. These accidents occur despite 

current requirements for pipeline 

markers. Those requirements in 

§ 192.707 already require that markers 

be maintained ‘‘as close as practical’’ in 

the areas required to be covered. 

PHMSA continues to believe that it is 

important to provide line-of-sight 

markers for pipelines operating at 

alternative MAOP in order to reduce the 

frequency of outside damage. PHMSA 

supports one-call programs, and 

regularly takes actions to encourage and 

foster their use. Still, damage incidents 

occur. It is important to reinforce the 

need for using a one-call program by 

providing visual evidence that a 

pipeline is located in an area subject to 

potential excavation. 

At the same time, PHMSA recognizes 

that installation of line-of-sight markers 

is not feasible in all locations. The rule 

does not require installation of line-ofsight markings in agricultural areas or 

large water crossings such as lakes and 

swamps where line-of-sight markers are 

not practicable. The marking of 

pipelines is also subject to FERC orders 

or environmental permits and local 

laws/regulations. The rule does not 

require installation where these other 

authorities prohibit markers. 

PHMSA also retained the requirement 

for a right-of-way management plan 

since PHMSA data indicates recurring 

similarities in pipeline accidents on 

construction sites where better 

management of the right-of-way could 

have prevented the accidents. This 

provision is not redundant with existing 

damage prevention program 

requirements, but requires operators to 

take further steps to integrate activities 

under those programs to provide for 

better protection of the right-of-way. 

Section 192.620(d)(5), Controlling 

Internal Corrosion 

INGAA, GPTC, four pipeline 

operators and the state pipeline safety 

regulatory agency would require a 

program to monitor gas quality and to 

remediate internal corrosion as needed 

but would delete all the specific 

requirements in this section. One 

operator suggested that a program 

complying with Subpart I is all that is 

needed. The state regulatory agency 

noted that the NPRM provided no 

rationale for more stringent or 

prescriptive requirements than those 

recently published as § 192.476. 

Two pipeline operators objected to 

the requirement for filter separators, 

contending that these devices are not 

effective for dealing with upsets 

involving free water and can provide a 

false sense of security. One suggested 

that other actions could be required to 

assure gas quality. Two other operators 

suggested that properly designed gas 

separators would be as effective as filter 

separators. 

One operator objected to requirements 

for cleaning pigs, inhibitors, and 

sampling of accumulated liquids. 

Another opposed the requirement for 

inhibitors. These operators noted that 

these actions are not needed if gas 

monitoring confirms no deleterious 

constituents. They maintained that the 

requirements are unnecessary and can 

potentially result in unintended 

consequences and risks. 

AGA contended that operators should 

be allowed to determine appropriate 

methods for monitoring gas quality and 

that these methods need not always 

require testing by individual operators. 

AGA believes this is especially true if 

tariffs and operating experience 

demonstrate the absence of 

contaminants. One pipeline operator 

asked that PHMSA clarify that the 

required chromatographs are for 

analysis of corrosive constituents and 

need not provide complete analysis for 

heating value or other purposes. 

Two pipeline operators suggested that 

PHMSA define deleterious gas stream 

constituents of concern. Two pipeline 

operators suggested that the limits on 

gas constituents should be deleted or 

revised based on research and testing. 

They believe that the proposed limits 

are not technically justified. One further 

noted that deleterious effects may result 

from contaminants acting ‘‘in concert.’’ 

One pipeline operator would revise 

the requirement for review of an 

operator’s internal corrosion monitoring 

and mitigation program to annual 

review because there is no technical 

justification for quarterly reviews. 

Another operator suggested that the gas 

quality requirements be deleted, as they 

may conflict with tariffs and result in 

duplicate enforcement. This operator 

also suggested that sampling intervals 

be established by reference to section 

§ 192.477 and agreed that a requirement 

for quarterly review of internal 

corrosion monitoring programs is 

excessive. 

Response 

PHMSA concludes that the proposed 

requirements do not duplicate or 

conflict with those in the recently 

published § 192.476. The latter 

requirements deal principally with 

design considerations related to internal 

corrosion, while those included here 

address monitoring to determine 

whether conditions conducive to such 

corrosion occur. Similarly, § 192.477 

only requires monitoring if corrosive gas 

is present. The requirements included 

here specify contaminants to be 

monitored and limits to be achieved. 

Since § § 192.476 and 192.477 represent 

the requirements in subpart I related to 

internal corrosion, PHMSA does not 

agree that a program complying with 

subpart I alone is sufficient. 

PHMSA has revised the requirement 

for use of cleaning pigs, inhibitors, and 

collection of accumulated liquids to 

apply only in those situations in which 

corrosive gas is determined to be 


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present. For the particular case of 

hydrogen sulfide, PHMSA has specified 

a limit (0.5 grain per hundred cubic feet, 

8 parts per million (ppm)) above which 

this requirement applies. 

PHMSA has retained the requirements 

for gas monitoring. It is important to 

monitor the gas stream to assure that 

internal corrosion will not occur or will 

be identified if corrosion does occur. 

Continuous monitoring is the most 

effective way of doing this. PHMSA 

agrees that monitoring equipment 

required by this rule is for the purpose 

of analyzing corrosive gas constituents 

and need not provide estimates of 

heating value or other characteristics. 

Operators can rely on others (e.g., those 

supplying gas to them) to perform 

monitoring, but they must assure that 

such monitoring covers all gas streams 

and meets the requirements of this rule, 

including the need for continuous 

monitoring. PHMSA has also retained 

the requirement to review the internal 

corrosion monitoring program quarterly. 

Such reviews are needed to help assure 

that upset conditions that could 

potentially cause internal corrosion are 

identified and addressed promptly. 

Annual reviews are insufficient to do 

this. 

PHMSA has revised the limit for 

hydrogen sulfide to 1.0 grain per 

hundred cubic feet, or 16 ppm. (PHMSA 

has also presented this limit in both 

forms of measurement, as suggested by 

one commenter). This limit is more 

consistent with typical tariff limits. At 

the same time, the final rule requires 

that additional mitigative actions, 

including use of cleaning pigs and 

inhibitors be required when the 

hydrogen sulfide content exceeds 0.5 

grain per hundred cubic feet, as this 

concentration increases the likelihood 

of internal corrosion. 

The final rule clarifies that deleterious 

gas stream constituents also include 

entrained or suspended solids 

(regardless of size) that are detrimental 

to the pipeline or pipeline facilities. 

Section 192.620(d)(6), Controlling 

Interferences That Can Impact External 

Corrosion 

Two pipeline operators requested that 

we clarify that interference surveys are 

only required where interference is 

likely, are to be developed using 

operator judgment, and can be 

performed using voltage measurements 

versus ‘‘current.’’ 

Response 

PHMSA has clarified the final rule to 

require that surveys be performed in 

areas where interference is suspected. 

Operators should consider the 

proximity of potential sources of 

interference, including electrical 

transmission lines, other cathodic 

protection systems, foreign pipelines, 

and electrified railways in deciding 

where surveys are needed. Operators 

must conduct surveys capable of 

detecting the effect of interfering 

currents, but these surveys need not 

measure ‘‘current’’ directly. 

Section 192.620(d)(7), Confirming 

External Corrosion Control Through 

Indirect Assessment 

INGAA and four pipeline operators 

requested that this section be revised to 

require close interval survey (CIS) alone 

versus one of CIS, direct current voltage 

gradient (DCVG), or alternating current 

voltage gradient (ACVG). One of these 

operators requested clarification that 

indirect examination is not necessary if 

additional measures are taken to assure 

the integrity of the pipeline. Yet another 

operator suggested that this section be 

revised to allow other methods of 

indirect assessment, noting that C– 

SCAN (which is a current measurement 

technique) is one possibility that 

appears to be precluded by the proposed 

language. All of these commenters plus 

three additional pipeline operators 

requested that the timeframe for 

conducting these examinations be 

relaxed from six months to one year. 

They noted that six months may often 

be impractical because of limitations 

associated with seasonal weather. 

One pipeline operator would delete 

the proposed requirement for a coating 

survey of existing pipelines, 

maintaining that this examination is not 

needed, since the results of ILI and CIS 

show that the combination of coating 

and cathodic protection is working to 

protect against corrosion. This operator 

would move the requirement for 

indirect survey and coating damage 

remediation to § 192.328 to make it clear 

that this is a construction requirement 

applicable to new pipelines only. 

Another operator also commented that 

requirements to remediate construction 

damaged coating should be limited to 

new pipe only. This operator further 

requested deleting the proposed 

requirement to repair all voltage drops 

classified as moderate or severe by 

National Association of Corrosion 

Engineers (NACE), since it is 

unnecessary and impractical to repair 

every voltage drop. Another operator 

commented that operators should be 

allowed to develop specific repair 

criteria based on their experience. 

INGAA and four pipeline operators 

would relax the proposed requirement 

to remediate construction coating 

damage to require either remediation or 

appropriate cathodic protection. They 

suggested that the proposed requirement 

conflicts with the NACE standard 

referenced in this section (NACE RP– 

0502–2002) and that coating 

remediation is not needed as cathodic 

protection provides adequate protection 

for areas affected by coating holidays. 

Another operator noted that the NACE 

defect classification guidelines are 

qualitative and that interpretation 

differences could result in differing 

repair expectations. 

INGAA and two pipeline operators 

recommended relaxing the requirement 

to integrate indirect assessment results 

with ILI from six months to one year. 

They believe that more rapid integration 

is not needed and that the value of 

quicker integration is not explained in 

the NPRM. Another operator suggested 

there is an inconsistency in that 

paragraph (ii) requires action based on 

the results of one assessment while 

paragraph (iii) requires that the results 

of two assessments be integrated. 

INGAA and three pipeline operators 

would delete the periodic assessment 

requirements of proposed paragraph 

(iv). They would move the requirements 

for location of CIS test points in 

proposed subparagraph (B) to § 192.328, 

as they contended these are more 

appropriate as construction 

requirements. These commenters would 

further revise the CIS location 

requirements to state that a CIS test 

station must be within one mile of each 

HCA, versus within each HCA. They 

contended that it is not practical to 

require a test station within each HCA, 

noting that the length of the pipeline in 

some HCAs may be very short. Another 

operator would combine subparagraphs 

(A) and (B). 

Response 

CIS is a technique to locate areas of 

poor cathodic protection and is 

considered a macro tool. Micro tools, 

such as DCVG or ACVG, must be used 

to locate small but critical coating 

holidays. C–SCAN, which is a current 

measurement technique, is considered a 

macro tool and will only find large 

coating holidays. Small coating holidays 

can be just as critical as large ones, 

especially in areas where cathodic 

protection potentials can be depressed. 

PHMSA considers it important to 

monitor coating condition. The 

comments suggesting that macro tools 

be allowed appear to be based on the 

premise that small coating holidays are 

not important as long as cathodic 

protection continues to protect the 

pipeline. As discussed above, PHMSA 

does not agree with this presumption, 

and here, again, does not agree that 


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either coating or cathodic protection is 

required; both are needed. PHMSA 

recognizes that if one accepts the 

presumption that assuring coating 

integrity is not important on pipelines 

subject to cathodic protection, then 

prompt resolution of coating issues is 

not important either. Since PHMSA 

does not accept the premise, PHMSA 

has not relaxed the proposed timeframes 

for conducting surveys or integrating 

results. 

In particular, PHMSA does not agree 

that a one year interval should be 

allowed to assess coating adequacy. 

Experience has demonstrated that 

significant corrosion can occur during 

very short intervals. PHMSA notes that 

the proposed requirement potentially 

extends the period between the 

beginning of pipeline operation and 

coating assessment to 18 months—12 

months after operation in which 

cathodic protection must be made 

operational (§ 192.455(a)(2)) plus the six 

months allowed here. PHMSA considers 

this to be the maximum period that 

should be allowed before determining 

coating adequacy. Proper planning and 

scheduling should allow operators to 

accommodate weather and other 

scheduling concerns. Operators can 

delay the start of operation at an 

alternative MAOP if they cannot 

schedule coating surveys within six 

months. 

PHMSA’s conclusion that coating 

integrity is important, regardless of the 

presence of cathodic protection, means 

that determining coating adequacy is 

important for existing pipelines as well 

as new construction. As such, it is not 

appropriate to move this requirement to 

a section applicable to new construction 

only. Further, it is not acceptable to rely 

on ILI or other assessment methods to 

identify corrosion after it has occurred. 

The purpose here is to prevent 

corrosion. ILI or other assessments are a 

second level of defense, detecting 

corrosion after it occurs, but PHMSA 

does not consider them to obviate the 

need for actions to prevent the problem 

from occurring in the first place. CIS is 

a verified method of determining if all 

of a segment is protected by appropriate 

cathodic protection potentials. The use 

of CIS will allow an operator to find any 

‘‘hot spots’’ along the pipeline that 

could cause active corrosion. The CIS 

will find any depressed locations 

whereas a test station survey may miss 

such locations unless they are in close 

proximity to the test station. 

With respect to proximity to a test 

station, PHMSA agrees that there could 

be situations in which it may not be 

practical to locate a test station within 

an HCA. This could occur, for example, 

when the HCA is determined by an 

identified site near the outer radius of 

the potential impact circle, in which 

case the length of pipeline in the HCA 

could be very short (on the order of 

several feet). Still, PHMSA does not 

agree that this limitation should be 

addressed by requiring that a test station 

be within one mile of an HCA. PHMSA 

has revised the final rule to require that 

a test station be located within an HCA 

if practicable and has retained the 

proposed requirement that test stations 

be located at half-mile intervals on 

pipelines to be operated at alternative 

MAOP. 

Section 192.620(d)(8), Controlling 

External Corrosion Through Cathodic 

Protection 

INGAA, GPTC and eight pipeline 

operators considered the requirement to 

address inadequate cathodic protection 

readings in six months to be excessive. 

They also noted that seasonal and land 

use issues make responding within one 

year much more reasonable, and 

suggested the proposed rule be changed 

accordingly. GPTC and one operator 

noted that the proposed change is 

inconsistent with an existing PHMSA 

interpretation, which states that 

remediation of inadequate cathodic 

protection readings is required before 

the next scheduled monitoring. The 

operator noted that this is typically one 

year (not to exceed 15 months), 

supporting the proposed change to a 

one-year response in this rule. 

INGAA and three pipeline operators 

objected to the proposed requirement to 

conduct CISs after remediating cathodic 

protection problems to evaluate 

effectiveness. They noted that a CIS is 

not needed to confirm resolution of 

many problems (e.g., loss of power, cut 

cable, short). They agreed that operators 

should confirm that remedial action was 

appropriate and effective, but contended 

that a requirement to perform a CIS after 

any remedial action is unjustified and 

excessive. 

Response 

As discussed above, experience has 

shown that significant corrosion damage 

can occur over brief periods. Pipelines 

operating at an alternative MAOP have 

less margin for corrosion than do 

pipelines operating at MAOP 

determined in accordance with 

§ 192.111. Cathodic protection is an 

important protection against corrosion 

damage, as recognized by those 

commenting on this rule. PHMSA does 

not agree that it is acceptable to wait 

one year to resolve known cathodic 

protection problems. At the same time, 

PHMSA recognizes that there may be 

situations in which remediation in six 

months is not practical. PHMSA has 

revised the final rule to require 

operators to notify the PHMSA Regional 

Office where a pipeline is located (and 

states where appropriate) if inadequate 

cathodic protection readings are not 

addressed within six months, providing 

the reason for the delay and a 

justification that the delay is not 

detrimental to pipeline safety. This will 

allow regulators to review the 

circumstances of each situation in 

which resolution takes longer than six 

months and to make a judgment of 

adequacy based on the particular 

circumstances. 

PHMSA agrees that it is not necessary 

to perform a complete CIS again to 

verify that any remedial action has 

addressed an identified problem. 

Commenters are correct in noting that 

problems such as a cut cable or short 

can result in inadequate cathodic 

protection readings and that correction 

of these problems can be verified 

without a new CIS. PHMSA has revised 

the final rule to require that operators 

verify that corrective action is adequate, 

leaving the means to do so up to the 

operator’s discretion and judgment. 

Section 192.620(d)(9), Conducting a 

Baseline Assessment of Integrity 

Proposed § 192.620(d)(9)(iii) would 

require that headers, mainline valve bypasses, compressor station piping, meter 

station piping, or other short portions 

that cannot accommodate ILI tools be 

assessed using DA. INGAA and four 

pipeline operators objected to this 

requirement as unjustified and 

inconsistent with previous special 

permits. They suggested a change that 

would also allow pressure testing or 

development and implementation of a 

corrosion control plan. They further 

noted that these segments may be 

designed to § 192.111, may not operate 

at an alternative MAOP, and thus may 

not be subject to this section. 

One operator also noted that there 

may be portions of a pipeline facility 

that will not be operated at an 

alternative MAOP. The operator 

requested clarification that the proposed 

requirements apply only to segments 

that are intended to operate at an 

alternative MAOP. This commenter also 

suggested an exclusion for small pipe 

and equipment to be consistent with a 

frequently asked question (FAQ) #84 on 

the gas transmission integrity 

management Web site (http:// 

primis.phmsa.dot.gov/gasimp/). (The 

FAQ addresses whether small-diameter 

piping, e.g., within a compressor 

station, must be considered to be part of 

an HCA. It states that potential impact 


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radii should be calculated, and a 

determination made as to whether an 

HCA exists, based on the diameter of 

individual pipeline segments.) 

The same operator would also allow 

the baseline assessment for an existing 

pipeline segment to be conducted before 

operation at an alternative MAOP begins 

but within the assessment interval 

specified in subpart O rather than the 

proposed two years. The operator 

contended that there is no scientific 

basis to require assessments every two 

years, particularly if a pipeline segment 

is being managed under subpart O. 

Response 

PHMSA agrees that assessment of 

small-diameter station piping can be 

performed using pressure testing and 

has revised the final rule accordingly. 

PHMSA does not agree that it is 

acceptable for such a non-piggable 

pipeline to be under an unspecified 

corrosion control plan rather than to be 

subject to assessment. 

PHMSA agrees that FAQ #84 

addresses the same pipe, but does not 

agree that it is a precedent for 

determining whether a small-diameter 

pipeline requires assessment. An FAQ is 

advisory in nature and this FAQ 

provides guidance in the context of 

integrity management, on whether this 

pipeline should itself be determined to 

be an HCA. For this rule, additional 

assessment requirements are being 

applied to a pipeline operating at an 

alternative MAOP, regardless of whether 

it is in an HCA. PHMSA has revised this 

paragraph to clarify that it applies only 

to a pipeline operating at an alternative 

MAOP. Small-diameter pipe within a 

station that does not operate at 

alternative MAOP would not be affected 

by these requirements. PHMSA agrees 

that small-diameter pipe, headers, meter 

stations, compressor stations, river 

crossings, road crossings and any other 

pipeline facility can be designed and 

constructed in accordance with 

§ 192.111 criteria and then would not be 

subject to alternative MAOP integrity 

assessment criteria such as ILI and DA. 

PHMSA does not agree that it is 

acceptable to rely on assessments that 

may have been performed within the 

time intervals allowed by subpart O. 

Under subpart O, it may have been 

nearly ten years (in some limited cases 

15 years) since a complete assessment 

was performed. PHMSA considers that 

more current information is needed 

before deciding that it is acceptable to 

operate a pipeline at an alternative 

MAOP. PHMSA considers the two-year 

period reasonable for operators to 

schedule and perform assessments that 

will result in more current information 

when the operating stresses on the 

pipeline are increased. 

Section 192.620(d)(11), Making Repairs 

INGAA and three pipeline operators 

noted that the repair requirements in the 

proposed rule are inconsistent with 

subpart O and, they believe, overly 

conservative and burdensome. INGAA 

contended that the proposed 

requirements will be unachievable in 

many cases. Another operator 

commented that the repair criteria 

proposed for Class 2 and 3 areas are 

extremely conservative and 

unnecessary. 

Two pipeline operators suggested that 

this section be replaced with a reference 

to subpart O, since they believe the 

repair requirements of that subpart and 

ASME/ANSI B31.8S (referenced in 

subpart O) are appropriate for pipelines 

operating at 80 percent SMYS. 

Two pipeline operators noted that the 

dent repair criteria in subparagraph 

(i)(A) are those for new pipelines 

following construction and before 

commissioning and suggested that these 

are inappropriate for existing pipelines. 

One of these operators contended that 

the repair criteria for existing pipelines 

should be as in subpart O, § 192.933(d). 

The other noted that there is experience 

demonstrating that plain dents of much 

greater than two percent of pipe 

diameter in depth are not a threat to 

pipeline integrity. 

Three pipeline operators proposed 

alternative repair criteria. They would 

require immediate repair of defects for 

which the failure pressure is 1.1 times 

the revised alternative MAOP. They 

would require repairs within one year 

for defects for which the failure pressure 

is 1.25 times the MAOP. They 

contended that these criteria are 

consistent with those in subpart O and 

ASME/ANSI B31.8S and are 

appropriate. They believe that the 

criteria in the proposed rule represent 

an inappropriate shortening of the time 

allowed to address identified defects. 

Proposed subparagraph (i)(A) would 

require that an operator ‘‘use the most 

conservative calculation for determining 

remaining strength’’ of a pipeline 

segment containing an identified 

anomaly. INGAA and four pipeline 

operators contended that this 

requirement could be interpreted to 

require that multiple calculations be 

performed, using all available tools/ 

models, to determine which is most 

conservative. They believe this is 

inappropriate and that operators should 

use the most appropriate calculational 

tool. 

Response 

PHMSA recognizes that the repair 

criteria in this rule are more stringent 

than those in subpart O. PHMSA 

considers this appropriate. A pipeline 

that will operate under alternative 

MAOP is subject to more stress and has 

less wall thickness margin to failure 

than most pipelines operating under 

subpart O (with the exception of some 

grandfathered lines). Most pipelines that 

will be subject to this rule will be new 

pipelines. PHMSA’s repair criteria use 

safety factors similar to those for the 

design of a new pipeline based upon 

class location design factors, and are 

intended to maintain overall safety 

margins at corrosion anomalies based 

upon all operating and environmental 

factors. The net effect of the QA and 

O&M requirements in this rule for 

construction and operation of those 

pipelines covered by the rule will likely 

result in the need for few repairs, even 

with these stricter criteria. PHMSA 

considers these factors of safety a key 

element in assuring public safety on 

higher MAOP pipelines. 

Similarly, PHMSA disagrees that 

failure pressures of 1.1 and 1.25 times 

MAOP are appropriate for immediate 

and one-year (respectively) repairs for 

all class locations. Class 2 and Class 3 

locations require more stringent safety 

factors for anomaly evaluation and 

remediation due to the higher 

consequences to public safety that may 

be caused by a leak or rupture of the 

pipeline. As discussed extensively 

throughout this response to comments, 

pipelines to be operated at alternative 

MAOP will operate at higher pressures 

with less margin to failure than most 

pipelines. Use of repair criteria different 

from and requiring repairs quicker than 

in subpart O is appropriate. 

With respect to dents, the repair 

criteria of § 192.309(b) apply only for 

dents found during construction 

baseline assessments (i.e., for new 

pipelines). PHMSA notes that this 

section already requires repair of two 

percent dents for pipelines over 123⁄4

inches in diameter. The criteria for 

repairing dents on existing pipelines 

and subsequent assessments on new 

pipelines and existing pipelines are in 

§ 192.933(d). 

PHMSA acknowledges that an 

operator cannot know which method for 

calculating remaining strength is most 

conservative without applying each 

method. Questions have been raised 

concerning the applicability of some 

current methods for calculating the 

remaining strength of high-strength 

pipelines and greater depth corrosion 

anomalies in all field operating 


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conditions. PHMSA is planning to 

sponsor a public meeting to review 

these questions and help determine the 

adequacy of existing calculational 

methods for the kind of high-strength 

pipe that will operate at alternative 

MAOP. PHMSA will propose changes to 

this rule at a later date, if appropriate. 

C.3. Comments on Regulatory Analysis 

One pipeline operator submitted two 

comments relating directly to the 

regulatory analysis supporting the 

proposed rule. 

First, the operator contends that the 

expected reduction in expenditure for 

compressors for new pipelines should 

not be claimed as a benefit. The operator 

contended that reductions may be 

realized for existing pipelines that 

operate at an alternative MAOP but not 

for new pipelines. 

Second, the operator contended that 

PHMSA should not state that new 

design factors will result in increased 

capacity for new pipelines and noted 

that new pipelines will be designed for 

the required capacity. The effect of the 

proposed rule will be to reduce costs by 

allowing the use of thinner-walled pipe. 

Response 

PHMSA understands that the 

operator’s statement that new pipelines 

will be designed for the required 

capacity is at the heart of both of these 

comments. The operator essentially 

contended that new pipelines that will 

be so designed will see no increased 

capacity or change in costs as a result 

of this rule. PHMSA does not agree. 

New pipelines designed with alternative 

MAOPs should mean less cost to the 

customer/public, and thus a benefit to 

society, due to less capital costs for the 

same natural gas through-put/flow 

volumes. Existing pipelines will be able 

to carry up to an additional 11 percent 

natural gas flow volumes based upon 

the overall design of the pipeline and 

compressor stations with this alternative 

MAOP. 

In the absence of this rule (or of 

obtaining a special permit to operate at 

alternative MAOP) new pipelines would 

need to be designed for less capacity or 

at increased cost (due to the need to use 

thicker-walled pipe). Thus, there is a 

societal benefit to this rule in that it will 

allow more gas to be transported at a 

higher standard of safety for a given 

dollar investment. The companies 

designing and constructing new 

pipelines under this rule will also 

realize a benefit, since in the absence of 

this rule (or a special permit addressing 

the same issues) they would either have 

to carry less gas or incur additional 

costs. PHMSA has revised the 

discussion in the regulatory analysis to 

help make this point more clearly. 

D. Consideration by the Technical 

Pipeline Safety Standards Committee 

(TPSSC) 

The TPSSC met on June 10, 2008, and 

considered the proposed rule. During 

this discussion, PHMSA provided its 

preliminary views of changes that might 

be made in response to comments 

submitted in response to the proposed 

rule. 

PHMSA informed the TPSSC that 

some changes would be made in rule 

structure, moving some requirements to 

other sections for better applicability 

(e.g., requirements applicable to existing 

pipelines would be moved from the 

section of the rule in which 

construction requirements are located). 

PHMSA informed the TPSSC it has 

not adopted the suggestion by the state 

pipeline safety regulatory agency that 

submitted comments supported by its 

director (a member of the committee) to 

place the rule in a separate subpart, as 

that is counter to the general structure 

of part 192. 

TPSSC members expressed concern, 

as did many commenters, about reliance 

on individual standards or tests. In the 

final rule, PHMSA has allowed use of 

equivalent methods (e.g., for the macro 

etch test, hardness limits, type of crack 

arrestors). 

PHMSA informed the TPSSC that the 

vast majority of commenters objected to 

the proposed requirement for mill 

hydrostatic inspection tests of longer 

duration and that, as a result, that 

change would not be included in the 

final rule. PHMSA also noted that most 

industry commenters noted that the 

proposed rule did not make allowances 

for changes in class location after a 

pipeline is in service, as do the existing 

regulations. 

The anomaly repair requirements 

were of concern to industry, who 

asserted the requirements were overly 

conservative. PHMSA informed the 

TPSSC that this issue is complicated by 

questions recently raised concerning the 

applicability of remaining strength 

calculational methods to high-stress 

pipelines and that resolving those 

questions before completing this rule 

would delay issuance of the rule. 

PHMSA stated that it would conduct a 

public meeting later this year to address 

the global issue of appropriate 

calculational methods and repair 

criteria. Changes to this or other 

regulations requiring pipeline repair 

may be appropriate following that 

workshop. 

Treatment of existing and pending 

applications for special permits was a 

significant concern for several members 

of the TPSSC. PHMSA noted that the 

standards in the final rule are very 

similar to those applied in recent 

special permits. PHMSA reported its 

intention to continue to review pending 

special permit applications while this 

rulemaking proceeded. Upon issuance 

of the final rule, PHMSA expects 

operators desiring to use alternative 

MAOP to comply with the rule. PHMSA 

will examine special permits that have 

already been granted, as appropriate, to 

determine if any modifications are 

needed in light of the outcome of this 

rulemaking. 

Subsequent to discussion, the TPSSC 

voted unanimously to find the proposed 

rule and supporting regulatory 

evaluations technically feasible, 

reasonable, practicable, and cost 

effective, subject to incorporation of the 

changes discussed by PHMSA during 

this meeting. A transcript of the meeting 

is available in the docket. 

E. The Final Rule 

Revisions described in this section are 

changes to the corresponding section in 

the proposed rule. 

E.1. In General 

The rule adds a new section 

(§ 192.620) to Subpart L—Operations. 

This new section explains what an 

operator would have to do to operate at 

a higher MAOP than currently allowed 

by the design requirements. Among the 

conditions set forth in new § 192.620 is 

the requirement that the pipeline be 

designed and constructed to more 

rigorous standards. These additional 

design and construction standards are 

set forth in two additional new sections 

(§§ 192.112 and 192.328) located in 

Subpart C—Pipe Design and Subpart 

G—General Construction Requirements 

for Transmission Lines and Mains, 

respectively. In addition, the rule makes 

necessary conforming changes to 

existing sections on incorporation by 

reference (§ 192.7), change in class 

location (§ 192.611), and maximum 

allowable operating pressure 

(§ 192.619). 

E.2. Amendment to § 192.7— 

Incorporation by Reference 

The rule adds ASTM Designation: A 

578/A578M—96 (Re-approved 2001) 

‘‘Standard Specification for StraightBeam Ultrasonic Examination of Plain 

and Clad Steel Plates for Special 

Applications’’ to the documents 

incorporated by reference under § 192.7. 

This specification prescribes standards 

for ultrasonic testing of steel plates. It is 

referenced in new § 192.112. 


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The rule also revises the description 

of item (B)(1) in the table of 

§ 192.7(c)(2), API 5L ‘‘Specification for 

Line Pipe,’’ (43rd edition and errata), 

2004, to indicate that it is referenced in 

new § 192.112 in addition to the 

locations at which it was referenced 

previously. 

E.3. New § 192.112—Additional Design 

Requirements 

The rule adds a new section to 

Subpart C—Pipe Design in 49 CFR Part 

192. The new section, § 192.112, 

prescribes additional design standards 

required for the steel pipeline to be 

qualified for operation at an alternative 

MAOP based on higher stress levels. 

These include requirements for rigorous 

steel chemistry and manufacturing 

practices and standards. Pipelines 

designed under these standards contain 

pipe with toughness properties to resist 

damage from outside forces and to 

control fracture initiation and growth. 

The considerable attention paid to the 

quality of seams, coatings, and fittings 

will prevent flaws leading to pipeline 

failure. Unlike other design standards, 

§ 192.112 applies to a new or existing 

pipeline only to the extent that an 

operator elects to operate at a higher 

alternative MAOP than allowed in 

current regulations. 

Paragraph (a) sets high manufacturing 

standards for the steel plate or coil used 

for the pipe. The pipe would be 

manufactured in accordance with Level 

2 of API 5L, with the ratio between 

diameter and wall thickness limited to 

prevent the occurrence of denting and 

ovality during construction or 

operation. Improved construction and 

inspection practices addressed 

elsewhere in this rule also help prevent 

denting and ovality. 

Paragraph (a) has been revised in 

response to comments to add an 

alternative method (and applicable 

limit) for determining equivalent carbon 

content. In addition, the proposed limit 

on equivalent carbon content of 0.23 

(Pcm formula) has been raised to 0.25. 

Several comments suggested deleting 

the limit on the ratio of pipe D/t, but 

this limit has been retained, as 

discussed above. 

Paragraph (b) addresses fracture 

control of the metal. First PHMSA 

expects the metal would be tough; that 

is, deform plastically before fracturing. 

Second, the pipe would have to pass 

several tests designed to reduce the risk 

that fractures would initiate. Third, to 

the extent it would be physically 

impossible for particular pipe to meet 

toughness standards under certain 

conditions, crack arrestors would have 

to be added to stop a fracture within a 

specified length. 

Paragraph (b) has been revised to 

allow alternate means of crack arrest. 

This can include the ‘‘mechanical’’ 

means included in the proposed rule 

but can also include other design 

features such as use of composite 

sleeves, spacing, increases in wall 

thickness at appropriate distances, etc. 

This paragraph has also been revised to 

clarify the factors that must be 

considered by an operator in evaluating 

resistance to fracture initiation and to 

make clear that this evaluation is 

intended to address the full range of 

relevant parameters to which the pipe 

will be exposed over its operating 

lifetime. If unexpected situations or a 

change in operating conditions result in 

a change in these parameters during 

operation, such that they are outside the 

bounds of those analyzed, operators will 

be required to review and update their 

evaluation and implement remedial 

measures to assure continued resistance 

to fracture initiation. 

Paragraph (c) provides tests to verify 

that there are no deleterious 

imperfections in the plate or coil. The 

macro etch test will identify flaws such 

as segregation that impact the plate or 

coil quality. Surface and interior flaws 

such as laminations and cracking will 

show up in UT testing. 

This paragraph has been revised, in 

response to comments, to change ‘‘mill 

inspection program’’ to an internal 

quality management program designed 

to eliminate or detect defects or 

inclusions that can affect pipe quality 

and to require that such a program be 

implemented at all mills involved in the 

process of casting the steel, rolling it 

into plate, coil or skelp, and the process 

of manufacturing the steel into line 

pipe. The revised paragraph also 

includes an alternative to the macro 

etch test and reference to an additional 

standard for UT testing the plate, coil, 

skelp or manufactured line pipe. 

(Equivalent standards are also still 

allowed.) 

In addition to the quality of the steel, 

the integrity of a pipe depends on the 

integrity of the seams. Paragraph (d) 

provides for a QA program to assure 

tensile strength and toughness of the 

seams so that they resist breaking under 

regular operations. Hardness and UT 

tests after mill hydrostatic tests would 

ensure that the seams did not have 

defects or imperfections that were 

exposed by the stresses of the 

hydrostatic test pressure. 

Paragraph (e) requires a mill pressure 

test for new pipe at a higher hoop stress 

than required by current regulations. 

The mill test is used to discover flaws 

introduced in manufacturing. Because 

the pipeline will be operated at a higher 

stress level, the more rigorous mill test 

is needed to match (or exceed) the level 

of safety provided for pipelines operated 

at less than 72 percent of SMYS. 

Paragraph (e) has been revised to 

eliminate the proposed extension of the 

duration of mill pressure tests. 

Paragraph (f) sets rigorous standards 

for factory coating designed to protect 

the pipeline from external corrosion. A 

QA program must address all aspects of 

the application of coating that will 

protect the pipeline. This would include 

applying a coating resistant to damage 

during transportation and installation of 

the pipe and examining the coated 

pipeline to determine whether the 

applied coating is uniform and without 

defects. Thin spots or voids/holidays in 

the coating make it more likely for 

corrosion to occur and more difficult to 

protect the pipeline cathodically. 

Paragraph (g) requires that factorymade fittings, induction bends, and 

flanges be certified as to their 

serviceability and quality. In addition 

the CE of these fittings and flanges 

would need to be documented, so that 

welding procedures could require preheat temperature to eliminate welding 

defects. 

Paragraph (g) has been revised to 

clarify that the serviceability 

certification must address properties 

such as chemistry, minimum yield 

strength, and minimum wall thickness 

to meet design conditions. PHMSA 

expects that valves, flanges and fittings 

should be rated based upon the required 

specification rating class for the 

alternative MAOP and the operator to 

have documented mill reports with 

chemistry, minimum yield strength, and 

minimum wall thickness. Where 

specialty bends such as hot bends are 

used for pipeline segments operating 

per the alternative MAOP, PHMSA 

expects the operator to address 

properties such as chemistry, minimum 

yield strength, minimum wall thickness 

and other properties that the hot 

bending process could alter. 

Paragraph (h) requires compressor 

design to limit the temperature of 

downstream pipe operating at an 

alternative MAOP to a specified 

maximum. Higher temperature can 

damage pipe coating. An exception to 

the specified maximum is allowed if 

testing of the coating shows it can 

withstand a higher temperature. The 

testing duration, qualification 

procedures and results must be of 

sufficient length and rigor to detect 

coating integrity issues for the type 

coating, operating and environmental 

conditions on the pipeline. Operators 


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may also rely on a long-term coating 

integrity monitoring program to justify 

operation at higher temperatures, 

provided the program is submitted to 

and reviewed by PHMSA. 

Paragraph (h) has been revised to 

clarify the allowed exception. Testing 

must address coating adhesion and 

condition as well as cathodic 

disbondment. Operators are required to 

submit their test results, including the 

acceptance criteria they applied to 

assure themselves that these 

characteristics are adequate, to the 

appropriate PHMSA regional office(s) 

and applicable state regulatory 

authorities at least 60 days prior to 

operating at elevated temperature. (State 

notification applies when the pipeline is 

located in a state where PHMSA has an 

interstate agent agreement, or an 

intrastate pipeline is regulated by that 

state.) 

A subtle, but important, change has 

also been made in the language in this 

paragraph. As proposed, the discharge 

temperature of compressor stations 

would have been limited to the 

specified temperature. As revised, the 

temperature of the nearest downstream 

pipeline segment to operate at 

alternative MAOP must be limited. For 

situations in which the pipeline 

segment at the discharge of a 

compressor station operates at 

alternative MAOP, there is no practical 

difference. The revised language, 

however, allows pipeline operators to 

implement an alternative approach in 

which they would use pipe operating at 

conventional MAOP from the discharge 

of a compressor station downstream to 

the point at which pipe temperature 

will drop to the specified limit. This 

may provide an alternative for situations 

in which it may be difficult to limit the 

compressor station discharge to the 

specified limit (e.g., southern locations 

on hot summer days). Gas coolers may 

be installed at compressor stations on 

pipelines operating per the alternative 

MAOP that need to operate above 120 

degrees Fahrenheit. Gas cooling at 

compressor stations is a long standing 

method for most operators to reduce gas 

pipeline temperatures. 

E.4. New § 192.328—Additional 

Construction Requirements 

The rule also adds a new section to 

Subpart G—General Construction 

Requirements for Transmission Lines 

and Mains. The new section, § 192.328, 

prescribes additional construction 

requirements, including rigorous QC 

and inspections, as conditions for 

operation of the steel pipeline at higher 

stress levels. Unlike other construction 

standards, § 192.328 would apply to a 

new or existing pipeline only to the 

extent that an operator elects to operate 

at a higher alternative MAOP than 

allowed in current regulations. 

Paragraph (a) requires a QA plan for 

construction. QA, also called QC, is 

common in modern pipeline 

construction. Activities such as 

lowering the pipe into the ditch and 

backfilling, if done poorly, can damage 

the pipe and coating. Other construction 

activities such as nondestructive 

examination of girth welds, if done 

poorly, will result in flaws remaining in 

the pipeline or failures during 

hydrostatic testing or while in gas 

service. Using a QA plan helps to verify 

that the basic tasks done during 

construction of a pipeline are done 

correctly. 

Field application of coating is one of 

these basic tasks to be covered in a QA 

plan. During the course of analyzing 

requests for special permits, PHMSA 

discovered field coatings at one 

construction site which were applied at 

lower temperature than needed for good 

adhesion to the pipe. Because coating is 

so critical to corrosion protection, 

paragraph (a) requires quality assurance 

plans to contain specific performance 

measures for field coating. Field coating 

must meet substantially the same 

standards as coating applied at the mill 

and the individuals applying the coating 

must be appropriately trained and 

qualified. 

Installation of the pipe into the ditch 

and backfilling of the pipe are critical 

operations. PHMSA has found that 

construction and inspection lapses 

during the backfilling of the pipe have 

resulted in pipe denting and coating 

damage. Sometimes during backfilling 

of the pipe there are design 

requirements for the installation of other 

engineered items such as concrete 

weights at creek and water saturated soil 

areas. The proper installation of these 

types of engineered items is critical to 

ensure that the pipe and coating are not 

damaged and the item is installed as 

required in the specifications. PHMSA 

has found operator lapses in this critical 

QC aspect of pipeline construction. 

Paragraph (b) requires non-destructive 

testing of all girth welds. Although past 

industry practice sometimes has been to 

non-destructively test only a sample of 

girth welds, no alternative exists for 

verifying the integrity of the remaining 

welds. The initial pressure testing once 

construction is complete does not 

normally detect flaws in girth welds 

unless the girth weld is cracked, has 

severe lack of penetration or is under 

undue tension stresses, which would be 

indicative of systemic problems on the 

pipeline. PHMSA believes that most 

modern pipeline construction projects 

include non-destructive testing of all 

girth welds. However, because the 

regulations do not require testing of all 

girth welds, an operator’s records for 

pipelines already in operation may not 

be complete on 100 percent of girth 

welds. To account for this, proposed 

paragraph (b) would have required 

testing records for only 95 percent of 

girth welds on existing segments. This 

requirement has been retained, but 

proposed paragraph (b) has been moved 

to new § 192.620, as it applies to 

existing pipelines. This section 

addresses pipeline construction. 

Paragraph (c) requires deeper burial of 

segments operated at higher stress level. 

A greater depth of cover decreases the 

risk of damage to the pipeline from 

excavation, including farming 

operations. 

Paragraph (d) addresses the results of 

the initial strength test and the 

assurance these results provide that the 

material in the pipeline is free of preoperational flaws which can grow to 

failure over time. Since the initial 

strength test is a destructive test, it only 

detects flaws that would fail at the test 

pressure. This could leave in place 

smaller flaws. To prevent this from 

occurring, the proposed paragraph 

would have disqualified any segment 

which experienced a failure during the 

initial strength test indicative of flaws in 

the material. Most commenters objected 

to this provision as too restrictive. They 

noted that failures can be isolated and 

that it was unreasonable to preclude an 

entire pipeline segment from operation 

at alternative MAOP because of a single 

failure. This paragraph has been revised 

to allow conduct of a root cause 

examination of a failure, including 

metallurgic examination of the failed 

pipe, as a way of justifying qualification 

of the pipeline segment. If that 

examination determines that the cause 

of the failure is not systemic, then the 

pipeline segment would not be 

disqualified from alternative MAOP 

operation. Operators must report the 

results of their root cause evaluation to 

regulators (PHMSA Regional Office or 

applicable state regulatory authorities). 

Review of these analyses by pipeline 

safety regulators will provide oversight 

for operator conclusions regarding the 

non-systemic nature of a failure. 

Proposed paragraph (e) addressed 

cathodic protection on an existing 

segment. This paragraph has been 

moved to new § 192.620. 

Paragraph (e) (proposed as paragraph 

(f)) addresses electrical interference for 

new segments. During construction, 

sources of electrical interference which 

can impair future cathodic protection or 


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damage the pipe prior to placing 

cathodic protection in service need to be 

identified. Addressing interference at 

this time supports better corrosion 

control. Operators will need to 

coordinate with electric transmission 

line operators prior to pipeline 

construction to identify locations of 

grounding structures and power line 

currents and voltages and their effect on 

the pipe. The additional O&M 

requirements of new § 192.620(d)(6) 

require operators electing to operate 

existing pipelines at higher stress levels 

to address electrical interference prior to 

raising the MAOP. 

E.5. Amendment to § 192.611—Change 

in Class Location: Confirmation or 

Revision of Maximum Allowable 

Operating Pressure 

The proposed rule did not include a 

provision to amend this section. 

Commenters pointed out that this 

section addresses changes in class 

location (e.g., increase in population 

density near the pipeline) during 

operation. The existing requirements 

allow continued operation at pressures 

higher than would be required for new 

pipe installed in the new class location, 

provided pressure testing has been 

performed at appropriate pressures. The 

commenters noted that without 

addressing operation at alternative 

MAOP in this section, the regulations 

would effectively rescind the 

authorization provided by this rule to 

operate at higher pressure whenever 

there was a change in class location. 

PHMSA agrees that this result was not 

intended. This section has been revised 

to include provisions for pipelines 

operating at alternative MAOP 

substantially the same as those already 

provided for existing pipelines. 

Operation at higher alternative 

pressures can continue after a class 

location change, again provided that the 

pipeline has been tested at appropriate 

pressures and is not an alternative 

MAOP operating in a Class 3 location 

that is upgraded to a Class 4 location. 

The limits on hoop stress included in 

this section have been revised to reflect 

the higher hoop stress that will be 

experienced by a pipeline at alternative 

MAOP. 

E.6. Amendment to § 192.619— 

Maximum Allowable Operating Pressure 

The final rule amends existing 

§ 192.619 by adding a new paragraph (d) 

providing an additional means to 

determine the alternative MAOP for 

certain steel pipelines. In addition, the 

rule makes conforming changes to 

existing paragraph (a) of the section. 

E.7. New § 192.620—Operation at an 

Alternative MAOP 

The final rule adds a new section, 

§ 192.620, to subpart L of part 192, to 

specify what actions an operator must 

take in order to elect an alternative 

MAOP based on higher operating stress 

levels. The rule applies to both new and 

existing pipelines. 

E.7.1. § 192.620(a)—Calculating the 

Alternative MAOP 

Paragraph (a) describes how to 

calculate the alternative MAOP based 

on the higher operating stress levels. 

Qualifying segments of pipeline would 

use higher design factors to calculate the 

alternative MAOP. For a segment 

currently in operation this would result 

in an increase in MAOP. No changes 

were proposed in the design factors 

used for segments within compressor or 

meter stations or segments underlying 

certain crossings. PHMSA expects new 

pipelines operating per the alternative 

MAOP to have road/railroad crossings, 

fabrications, headers, mainline valve 

assemblies, separators, meter stations 

and compressor stations designed and 

operated per existing design factors in 

§ 192.111. 

Paragraph (a) has been revised to 

include new design factors for 

compressor/meter stations or segments 

underlying certain crossings. These 

factors apply to facilities in existence 

prior to the effective date of this rule. 

Commenters pointed out that 

compressor stations for existing 

pipelines have been designed and that 

failure to allow alternative design 

factors for them could effectively 

preclude operation at alternative MAOP 

for the existing pipelines of which they 

are a part. PHMSA agrees this was not 

our intent. The additional risk 

associated with use of slightly higher 

design factors for these facilities is 

marginal. At the same time, there is 

little additional cost associated with 

designing stations/crossings/ 

fabrications/headers for future pipelines 

to serve at the desired MAOP using 

existing design factors in § 192.111(b), 

(c), and (d). The rule includes no 

alternative design factors for these 

facilities in future pipelines, and 

operators must use the existing 

requirements. 

E.7.2. § 192.620(b)—Which Pipeline 

Qualifies 

Paragraph (b) describes which 

segments of new or existing pipeline are 

qualified for operation at the alternative 

MAOP. The alternative MAOP is 

allowed only in Class 1, 2, and 3 

locations. Only steel pipelines meeting 

the rigorous design and construction 

requirements of §§ 192.112 and 192.328 

and monitored by supervisory data 

control and acquisition systems qualify. 

Mechanical couplings in lieu of welding 

are not allowed. Although the special 

permits did not expressly mention 

mechanical couplings, PHMSA would 

not have granted a special permit if the 

pipeline involved had mechanical 

couplings. 

As proposed, paragraph (b) would 

have excluded from consideration any 

existing pipeline that had experienced a 

failure indicative of materials concerns. 

This provision has been revised to allow 

root cause analysis to determine if the 

failure is indicative of a systemic 

problem and to preclude use of an 

alternative MAOP only if a failure is 

determined to be systematic in nature. 

Results of the analysis must be reported 

to regulators (PHMSA Regional Office or 

applicable state regulatory authorities). 

This is essentially the same change 

made for new pipelines in new 

§ 192.328(d), as described above. 

Paragraph (b) has also been revised to 

include the requirement that 95 percent 

of girth welds must have been examined 

for existing pipelines to operate at 

alternative MAOP. This requirement 

was moved from proposed § 192.328(e), 

as discussed above. 

E.7.3. §§ 192.620(c)(1), (2), and (3)— 

How an Operator Selects Operation 

Under This Section 

Paragraph (c)(1) requires an operator 

to notify PHMSA, and applicable state 

pipeline safety regulators, when it elects 

to establish an alternative MAOP under 

this section. This notification must be 

provided at least 180 days prior to 

commencing operations at the 

alternative MAOP established under 

this section. This will provide PHMSA 

and states sufficient time for appropriate 

inspection which may include checks of 

the manufacturing process, visits to the 

pipeline construction sites, analysis of 

operating history of existing pipelines, 

and review of test records, plans, and 

procedures. 

Paragraph (c)(3) requires an operator 

to further notify PHMSA when it has 

completed the actions necessary to 

support operation at an alternative 

MAOP, by submitting a certification by 

a senior executive that the pipeline 

meets the requirements for operation at 

alternative MAOP. The certification is 

required by paragraph (c)(2). A senior 

executive must certify that the pipeline 

meets the additional design and 

construction regulations of this rule. A 

senior executive must also certify that 

the operator has changed its O&M 

procedures to include the more rigorous 


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additional O&M requirements. In 

addition, a senior executive must certify 

that the operator has reviewed its 

damage prevention program in light of 

best practices, such as CGA best 

practices or some equivalent best 

practices, and made any needed changes 

to it to ensure that the program meets or 

exceeds those standards or practices. 

The certification must be submitted at 

least 30 days prior to operation at an 

alternative MAOP. 

E.7.4. § 192.620(c)(4)—Initial Strength 

Testing 

Paragraph (c)(4) addresses initial 

strength testing requirements. In order 

to establish the MAOP under this 

section, an operator must perform the 

initial strength testing of a new segment 

at a pressure at least as great as 125 

percent of the MAOP in Class 1 

locations and 150 percent in Class 2 and 

3 locations. Since an existing pipeline 

was previously operated at a lower 

MAOP, it may have been initially tested 

at a pressure less than these levels. If so, 

paragraph (c) allows the operator to 

elect to conduct a new strength test in 

order to raise the MAOP. 

E.7.5. § 192.620(c)(5)—Operation and 

Maintenance 

Paragraph (c)(5) requires an operator 

to comply with the additional operating 

and maintenance requirements of 

§ 192.620(d). An operator must comply 

with these additional requirements if 

the operator elects to calculate the 

alternative MAOP for a segment under 

§ 192.620(a) and notifies PHMSA of that 

election. 

E.7.6. § 192.620(c)(6)—New 

Construction and Maintenance Tasks 

Paragraph (c)(6) addresses the need 

for competent performance of both new 

construction, and future maintenance 

activities, to ensure the integrity of the 

segment. PHMSA now requires 

operators to ensure that individuals who 

perform pipeline O&M activities are 

qualified. Paragraph (c)(6) requires 

operators seeking to operate at the 

allowable higher operating stress levels 

to treat construction tasks as if they 

were covered by subpart N, 

‘‘Qualification of Pipeline Personnel.’’ 

Subpart N (commonly known as OQ) 

specifies training and qualification 

requirements applicable to tasks that 

meet a four-part test in § 192.801(b). 

Operations and maintenance tasks on 

the pipeline meet this test, and it is the 

requirements in subpart N that will 

govern training and qualification of 

personnel performing these tasks on a 

pipeline to be operated at an alternative 

MAOP. Construction tasks typically do 

not meet the four-part test and are not 

covered under subpart N. As proposed, 

paragraph (c)(6) (then designated (c)(5)) 

would have required operators to take 

other actions to assure qualification of 

personnel performing construction tasks 

on a pipeline intended to operate at 

alternative MAOP. Commenters noted 

that the proposed requirements were 

vague and subject to interpretation and 

suggested that PHMSA, instead, rely on 

the known requirements of subpart N. 

This paragraph has been modified, in 

response to these comments, to require 

that the requirements of subpart N be 

applied to construction tasks for a 

pipeline intended to operate at 

alternative MAOP regardless of the fourpart test in § 192.801(b). 

E.7.7. § 192.620(c)(7)—Recordkeeping 

Paragraph (c)(7) specifies 

recordkeeping requirements for 

operators electing to establish the 

MAOP under this section. Existing 

regulations, such as §§ 192.13, 

192.517(a), and 192.709, already require 

operators to maintain records applicable 

to this section. New § 192.620 is in 

subpart L. Because the additional 

requirements in this section address 

requirements found in other subparts of 

part 192, the recordkeeping 

requirements could cause confusion. 

For example, § 192.620(d)(9) requires a 

baseline assessment for integrity for a 

segment operated at the higher stress 

level regardless of its potential impact 

on an HCA. Section 192.947, in subpart 

O, requires operators to maintain 

records of baseline assessments for the 

useful life of the pipeline. Section 

192.709 requires an operator to retain 

records for an inspection done under 

subpart L for a more limited time. 

Accordingly, this paragraph clarifies the 

need to maintain all records 

demonstrating compliance with all 

alternative MAOP requirements for the 

useful life of the pipeline. 

E.7.8 § 192.620(c)(8)—Class Upgrades 

Paragraph (c)(8) allows pipelines in 

Class 1 and 2 to be upgraded one class 

when class changes occur per § 192.611. 

This paragraph precludes operation of 

pipeline in Class 4 at alternative MAOP. 

E.8. § 192.620(d)—Additional Operation 

and Maintenance Requirements 

Paragraph (d) sets forth ten operating 

and maintenance requirements that 

supplement the existing requirements in 

part 192. Currently § 192.605 requires 

an operator to develop O&M procedures 

to implement the requirements of 

subparts L and M. Since § 192.620(d) is 

in subpart L, an operator must develop 

and follow the O&M procedures 

developed under this section. These 

include requirements for an operator to 

evaluate and address the issues 

associated with operating at higher 

pressures. Through its public education 

program, an operator would inform the 

public of any risks attributable to higher 

pressure operations. The additional 

operating and maintenance 

requirements address the two main risks 

the pipelines face, excavation damage 

and corrosion, through a combination of 

traditional practices and integrity 

management. Traditional practices 

include cathodic protection, control of 

gas quality, and maintenance of burial 

depth. Integrity management includes 

internal inspection on a periodic basis 

to identify and repair flaws before they 

can fail. The additional O&M and 

management requirements are discussed 

in more detail below. 

E.8.1. § 192.620(d)(1)—Threat 

Assessments 

Paragraph (d)(1) requires an operator 

to identify and evaluate threats to the 

pipeline consistent with the similar 

procedures done under integrity 

management to address the risks of 

operating at an increased stress level. 

E.8.2. § 192.620(d)(2)—Public 

Awareness 

Paragraph (d)(2) requires an operator 

to include any people potentially 

impacted by operation at a higher stress 

level within the outreach effort in its 

public education program required 

under existing § 192.616. In order to 

identify this population, an operator 

would use a broad area measured from 

the centerline of the pipe plus, in HCAs, 

the potential impact circle recalculated 

to reflect operation at a higher operating 

stress level. This is intended to get 

necessary information for safety to the 

people potentially impacted by a failure. 

E.8.3. § 192.620(d)(3)—Emergency 

Response 

Paragraph (d)(3) addresses the 

additional needs for responding to 

emergencies for operation at higher 

operating stress levels. Consistent with 

the conditions imposed in the special 

permits, and past experience with 

response issues, the paragraph requires 

methods such as remote control valves 

to provide more rapid shut-down in the 

event of an emergency. 

E.8.4. § 192.620(d)(4)—Damage 

Prevention 

Paragraph (d)(4) addresses one of the 

major risks of failure faced by a 

pipeline, damage from outside force 

such as damage occurring during 

excavation in the right-of-way. Although 


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the improved toughness of pipe reduces 

the risk of damage, it does not prevent 

it and additional measures are 

appropriate for pipelines operating at 

higher operating stress levels. This 

paragraph adds several new or more 

specific measures to existing 

requirements designed to prevent 

damage to pipelines from outside force. 

The first more specific measure, in 

paragraph (d)(4)(i), addresses patrolling, 

required for all transmission pipelines 

by § 192.705. More frequent patrols of 

the right-of-way prevent damage by 

giving the operator more accurate and 

timely information about potential 

sources of ground disturbance and other 

outside force damage. These include 

both naturally occurring conditions, 

such as wash outs, and human activity, 

such as construction in the vicinity of 

the pipeline. The requirement is for 

patrols to be made monthly, at intervals 

not to exceed 45 days. The patrolling 

requirement along with other right-ofway requirements including line-ofsight markers, use of national consensus 

standards, and the right-of-way 

management plan comprise a multifaceted approach to protecting the 

pipeline. 

Other more specific or new measures 

to address damage prevention include 

developing and implementing a plan to 

monitor and address ground movement, 

a requirement of paragraph (d)(4)(ii). 

Ground movement such as earthquakes, 

landslides, soil erosion, and nearby 

demolition or tunneling can damage 

pipelines. Since pipelines near the 

surface are more likely to be damaged 

by surface activities, paragraph 

(d)(4)(iii) requires an operator to 

maintain the depth of cover over a 

pipeline or provide alternative 

protection. Line-of-sight markers alert 

excavators, emergency responders, and 

the general public of the presence and 

general location of pipelines. Paragraph 

(d)(4)(iv) requires these markers both to 

improve damage prevention and to 

enhance public awareness. 

Damage prevention programs are 

improving because of the work being 

done by the CGA, a national, non-profit 

educational organization dedicated to 

preventing damage to pipelines and 

other underground utilities. The CGA 

has compiled best practices applicable 

to all parties relevant to preventing 

damage to underground utilities and 

actively promotes their use. Paragraph 

(d)(5)(v) requires operators electing to 

operate at higher stress levels to 

evaluate their damage prevention 

programs in light of industry best 

practices, such as those developed by 

CGA. An operator must identify the 

practices applicable to its circumstances 

and make appropriate changes to its 

damage prevention program. This 

approach is consistent with annual 

reviews of O&M programs under 

§ 192.605. An operator must include in 

the certification required under 

§ 192.620(c)(1) that the review and 

upgrade have occurred. 

Paragraph (d)(4) also requires the 

preparation of a right-of-way 

management plan. In the past several 

years, PHMSA has seen recurring 

similarities in pipeline accidents on 

construction sites. In each case, better 

management of the pipeline right-ofway could have prevented the 

accidents. Better management includes 

closer attention to the qualifications of 

individuals critical to damage 

prevention, better marking practices, 

and closer oversight of the excavation. 

In 2006, PHMSA issued two advisory 

bulletins to alert operators of the need 

to pay closer attention to these 

important damage prevention issues. 

The first advisory bulletin described 

three accidents in which either operator 

personnel or contractors damaged gas 

transmission pipelines during 

excavation in the rights-of-way (ADB– 

06–01; 71 FR 2613; Jan.17, 2006). This 

bulletin advised operators to pay closer 

attention to integrating OQ regulations 

into excavation activities and providing 

that excavation is included as a covered 

task under OQ programs required by 

subpart N. The second advisory bulletin 

pointed to an additional excavation 

accident where the excavator struck an 

inadequately marked gas transmission 

pipeline (ADB–06–003; 71 FR 67703; 

Nov. 22, 2006). This advisory bulletin 

advised pipeline operators to pay closer 

attention to locating and marking 

pipelines before excavation activities 

begin and pointed to several good 

practices as well as the best practices 

described by the CGA. This paragraph 

requires an operator electing to operate 

at a higher stress level to develop a plan 

to manage the protection of their rightof-way from excavation activities. Each 

operator already has a damage 

prevention program, under § 192.614, 

and a program to ensure qualification of 

pipeline personnel, under subpart N. 

This management program requires the 

operator to integrate activities under 

those programs to provide better 

protection for the right-of-way of the 

pipeline operated at the higher stress 

level. 

E.8.5. § 192.620(d)(5)—Internal 

Corrosion Control 

Paragraph (d)(5) adds specificity to 

the requirements for internal corrosion 

control now in pipeline safety standards 

for pipelines operated at higher stress 

levels. These internal corrosion control 

programs must include use of gas 

separators or filter separators and gas 

quality monitoring equipment. 

Operators are required to use cleaning 

pigs and inhibitors when corrosive gas 

is present. (Use of cleaning pigs and 

inhibitors is required when the level of 

one corrosive contaminant, hydrogen 

sulfide (H2S), is between 0.5 and 1.0 

grain per hundred cubic feet). Most 

operators who have applied for special 

permits to operate their pipeline at 

alternative MAOP limit H2S to 0.5 grain. 

The higher levels allowed in this rule 

are within typical FERC tariffs, but may 

present an increased likelihood of 

internal corrosion. Maximum levels of 

contaminants that could promote 

corrosion must be reviewed quarterly, 

and operators must adjust their 

programs as needed to monitor and 

mitigate any deleterious gas stream 

constituents. PHMSA believes the levels 

are fully consistent with the 

requirements in FERC tariffs designed to 

prevent internal corrosion. 

E.8.6. §§ 192.620(d)(6), (7), and (8)— 

External Corrosion Control 

Since external corrosion is one of the 

greatest risks to the integrity of 

pipelines operating at higher stress 

levels, the special permits and this rule 

contain several measures to prevent it 

from occurring. These include use of 

effective external coating, addressing 

interference, early installation of 

cathodic protection, confirming the 

adequacy of coating and cathodic 

protection and diligent monitoring of 

cathodic protection levels. The 

requirements concerning quality of the 

coating and installation of cathodic 

protection for new pipelines are 

addressed in sections on design and 

construction, as discussed above. The 

remaining external corrosion provisions 

are addressed here. 

Interference from overhead power 

lines, railroad signaling, stray currents, 

or other sources can interfere with the 

cathodic protection system and, if not 

properly mitigated, even accelerate the 

rate of external corrosion. Paragraph 

(d)(6) requires an operator to identify 

and address interference early before 

damage to the pipeline can occur. 

Paragraph (d)(7) requires an operator 

to confirm both the effectiveness of the 

coating and the adequacy of the 

cathodic protection system soon after 

deciding on operation at higher 

operating stress levels/alternative 

MAOP. This is accomplished through 

indirect assessments, such as a CIS for 

cathodic protection and DCVG or ACVG 

for coating condition. After completion 

of the baseline internal inspection 


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required by § 192.620(d)(9), an operator 

is required to integrate the results of that 

inspection with the indirect 

assessments. An operator must take 

remedial action to correct any 

inadequacies. In HCAs, an operator 

must periodically repeat indirect 

assessment to confirm that the cathodic 

protection system remains as functional 

as when first installed. 

Paragraph (d)(8) requires more 

rigorous attention to ensure adequate 

levels of cathodic protection. 

Regulations now require an operator 

discovering a low reading, meaning a 

reduced level of protection, to act 

promptly to correct the deficiency. This 

section puts an outer limit of six months 

on the time for completion of the 

remedial action and restoration of an 

adequate level of cathodic protection. In 

addition, the operator must confirm that 

its actions have been effective in 

restoring cathodic protection. 

E.8.7. §§ 192.620(d)(9) and (10)— 

Integrity Assessments 

Among the most important ways of 

ensuring integrity during pipeline 

operations are the assessments done 

under the integrity management 

program requirements in subpart O. 

Paragraphs (d)(9) and (d)(10) require 

operators electing to operate at higher 

stress levels to perform both baseline 

and periodic assessments of the entire 

pipeline segment operating at the higher 

stress level, regardless of whether the 

pipeline segment is located in an HCA. 

The operator must use both a geometry 

tool and a high resolution magnetic flux 

tool for the entire pipeline segment. In 

very limited circumstances in which 

internal inspection is not possible 

because internal inspection tools cannot 

be accommodated, such as a short 

crossover segment connecting two 

pipelines in a right-of-way, an operator 

would substitute pressure testing or DA. 

The operator must then integrate the 

information provided by these 

assessments with testing done under 

previously described paragraphs. This 

analysis would form the basis for 

mitigating measures, and for prompt 

repairs under paragraph (d)(11). 

E.8.8. § 192.620(d)(11)—Repair Criteria 

The repair criteria under paragraph 

(d)(11) for anomalies in a pipeline 

segment operating at a higher stress 

level are slightly more conservative than 

for other pipelines, including pipelines 

covered by an integrity management 

program. With the tougher pipe, better 

coating, construction quality inspection 

program, coating surveys after 

installation and backfill, and careful 

attention to damage prevention and 

corrosion protection, a pipeline 

operated at higher operating stress 

levels should experience few anomalies 

needing evaluation. 

E.9. § 192.620(e)—Overpressure 

Protection 

The alternative MAOP is higher than 

the upper limit of the required 

overpressure protection under existing 

regulations. Paragraph (e) increases the 

overpressure protection limit to 104 

percent of the MAOP, which is 83.2 

percent of SMYS for a pipeline segment 

operating at the alternative MAOP in a 

Class 1 location. 

F. Regulatory Analyses and Notices 

F.1. Privacy Act Statement 

Anyone may search the electronic 

form of all comments received for any 

of our dockets. You may review DOT’s 

complete Privacy Act Statement in the 

Federal Register published on April 11, 

2000 (65 FR 19477). 

F.2. Executive Order 12866 and DOT 

Policies and Procedures 

Due to magnitude of expected 

benefits, the DOT considers this 

rulemaking to be a significant regulatory 

action under section 3(f)(1) of Executive 

Order 12866 (58 FR 51735; Oct. 4, 

1993). Therefore, DOT submitted it to 

the Office of Management and Budget 

for review. This rulemaking is also 

significant under DOT regulatory 

policies and procedures (44 FR 11034; 

Feb. 26, 1979). 

PHMSA prepared a Regulatory 

Evaluation of the final rule. A copy is 

in Docket ID PHMSA–2005–23447. 

PHMSA estimates that the rule will 

result in gas transmission pipeline 

operators uprating 3,500 miles of 

existing pipelines to an alternative 

MAOP. Additionally PHMSA estimates 

that, in the future, the rule will result in 

an annual additional 700 miles of new 

pipelines each year whose operators 

elect to use an alternative MAOP. 

PHMSA expects the benefits of the 

rule to be substantial and in excess of 

$100 million per year. This expectation 

is based on quantified benefits in excess 

of $100 million per year (see below), 

coupled with un-quantified benefits 

associated with the rule that industry 

and PHMSA technical staff have 

identified. The expected benefits of the 

rule that cannot be readily quantified 

include: 

• Reductions in incident 

consequences. 

• Increases in pipeline capacity. 

• Increases in the amount of natural 

gas filling the line, commonly called 

line pack. 

• Reductions in adverse 

environmental impacts. 

The rule’s requirements, such as 

monthly right-of-way patrolling, 

additional internal inspections, and 

anomaly repair, are expected to prevent 

incidents that would have occurred in 

the absence of the rule, and to help 

mitigate the consequences of the 

incidents that do occur. In the case of 

new pipelines, the ability to use an 

alternative MAOP will make it possible 

to transport more product per dollar of 

pipeline cost than would be possible 

without this new rule. Quantifying the 

value of this increased capacity is 

difficult, and no estimate has been 

developed for this analysis. For existing 

pipelines, operation at a higher MAOP 

increases the amount of gas that can be 

transported. PHMSA expects the value 

of increased capacity due to use of 

alternative MAOP by gas pipelines to be 

significant. In areas where production is 

already well-established, there is an 

even greater potential for increased 

pipeline capacity. For example, one 

recipient of a special permit estimated 

a daily increase of at least 62 million 

standard cubic feet of gas. 

Similarly, increases in line pack will 

produce increased benefits which are 

difficult to quantify. Line pack is 

increased due to gas compressibility at 

higher operating pressures which results 

in increased gas volumes in the 

pipeline. The reduced amount of 

exterior storage capacity needed 

resulting from increased line pack may 

result in capital or O&M savings for the 

pipelines or their customers. Greater 

line pack in a pipeline increases the 

ability of the operator to continue gas 

delivery during short outages such as 

maintenance and during peak flow 

periods. These benefits are not readily 

quantifiable. 

The quantified benefits consist of: 

• Fuel cost savings. 

• Capital expenditure savings on pipe 

for new pipelines. 

Of these, pipeline fuel cost savings is 

the most important contributor to the 

estimated benefits. Although these 

quantified benefits do not capture the 

full benefits of the rule, they exceed 

$100 million per year. 

As a consequence of the rule, PHMSA 

estimates that pipeline operators will 

realize annually recurring benefits due 

to fuel cost savings of $49 million that 

will begin in the initial year after the 

rule goes into effect. Additionally, 

PHMSA estimates that each year 

pipeline operators will realize one-time 

benefits for savings in capital 

expenditures of $54.6 million (since 700 

miles of new pipeline operating at an 

alternative MAOP are added each year, 


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the one-time benefits resulting from this 

added mileage will be the same each 

year.) The benefits of the rule over 20 

years are expected to be as presented in 

the following table: 

TABLE D.2.–1—SUMMARY AND TOTAL FOR THE ESTIMATED BENEFITS OF THE RULE

[Millons of dollars per year] 

Benefit Estimate for year 1 Estimate of new benefits occurring 

in each subsequent year 

Reduced incident consequences ............................................................ Not quantified ................................ Not quantified. 

Fuel cost savings .................................................................................... $49.0 .............................................. $49.0 

Reduced capital expenditures ................................................................. $54.6 .............................................. $54.6 

Increased pipeline capacity ..................................................................... Not quantified ................................ Not quantified. 

Increased line pack ................................................................................. Not quantified ................................ Not quantified. 

Reduced adverse environmental impacts ............................................... Not quantified ................................ Not quantified. 

Other expected benefits .......................................................................... Not quantified ................................ Not quantified. 

Total ................................................................................................. $103.6 ............................................ $103.6 

The present value of the benefits 

evaluated over 20 years at a three 

percent discount rate is $1,541 million, 

while the present value of the benefits 

over 20 years at a seven percent 

discount rate is $1,098 million. For both 

discount rates, the annualized benefits 

would be $103.6 million. 

PHMSA expects the costs attributable 

to the rule are most likely to be incurred 

by operators for: 

• Performing baseline internal 

inspections. 

• Performing additional internal 

inspections. 

• Performing anomaly repairs. 

• Installing remotely controlled 

valves on either side of HCAs. 

• Preparing threat assessments. 

• Patrolling pipeline rights-of-way. 

• Preparing the paperwork notifying 

PHMSA of the decision to use an 

alternative MAOP. 

Overall, the costs of the rule over 20 

years are expected to be as presented in 

the following table: 

TABLE D.2.–2— SUMMARY AND TOTALS FOR THE ESTIMATED COSTS OF THE RULE

Cost item 

Cost by year after implementation 

[thousands of dollars] 

1st 2nd—10th 11th 12th—20th 

Baseline internal inspections.$29,119 ............................. None .................................. None .................................. None 

Additional internal inspections.None .................................. None .................................. $17,471 ............................. $2,912 each year. 

Anomaly repairs ................ $1,015 ............................... None .................................. $1,218 ............................... $203 each year. 

Remotely controlled valves $3,528 ............................... $588 each year ................. $588 .................................. $588 each year. 

Threat Assessments .......... $180 .................................. $30 each year ................... $30 .................................... $30 each year. 

Patrolling ............................ $4,620 ............................... $5,390 to $11,550 ............. $12,320 ............................. $15,090 to $19,250. 

Notifying PHMSA ............... Nominal ............................. Nominal ............................. Nominal ............................. Nominal. 

Total ........................... $38,462 ............................. $618 each year plus patrolling costs.$31,627 ............................. $3,733 each year plus patrolling costs. 

The present value of the costs 

evaluated over 20 years at a three 

percent discount rate are approximately 

$239 million, while the present value of 

the costs over 20 years at a seven 

percent discount rate are approximately 

$165 million. The annualized costs at 

the three percent discount rate are 

approximately $16 million, while the 

annualized costs at the seven percent 

discount rate are approximately $15 

million. 

Since the present value of the 

quantified benefits ($1,541 million at 

three percent and $1,098 million at 

seven percent) exceeds the present 

value of the costs ($328 million at three 

percent and $164 million at seven 

percent), the rule is expected to have net 

benefits. 

F.3. 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. 

The final rule affects operators of gas 

pipelines. Based on annual reports 

submitted by operators, there are 

approximately 1,450 gas transmission 

and gathering systems and an equivalent 

number of distribution systems 

potentially affected by this rule. The 

size distribution of these operators is 

unknown and must be estimated. 

The affected gas transmission systems 

all belong to NAICS 486210, Pipeline 

Transportation of Natural Gas. In 

accordance with the size standards 

published by the Small Business 

Administration, a business with $6.5 

million or less in annual revenue is 

considered a small business in this 

NAICS. 

Based on August 2006 information 

from Dunn & Bradstreet on firms in 

NAICS 486210, PHMSA estimates that 

33 percent of the gas transmission and 

gathering systems have $6.5 million or 

less in revenue. Thus, PHMSA estimates 

that 479 of the gas transmission and 

gathering systems affected by the rule 

will have $6.5 million or less in annual 

revenue. PHMSA does not expect that 


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any local gas distribution companies or 

gathering systems will be taking 

advantage of the potential to use an 

alternative MAOP. 

The rule mandates no action by gas 

transmission pipeline operators. Rather, 

it provides those operators with the 

option of using an alternative MAOP in 

certain circumstances, when certain 

conditions can be met. Consequently, it 

imposes no economic burden on the 

affected gas pipeline operators, large or 

small. Based on these facts, I certify that 

this rule will not have a substantial 

economic impact on a substantial 

number of small entities. 

F.4. Executive Order 13175 

PHMSA has analyzed this rulemaking 

according to Executive Order 13175, 

‘‘Consultation and Coordination with 

Indian Tribal Governments.’’ Because 

the rule does 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. 

F.5. Paperwork Reduction Act 

This rule adds notification paperwork 

requirements and record retention on 

pipeline operators voluntarily choosing 

an alternative MAOP for their pipelines. 

Based on analysis of the regulation, 

there will be an estimated nine total 

annual burden hours attributable to the 

notification and recordkeeping 

requirements in the first year. In 

following years, the annual burden is 

expected to decrease to one and one-half 

hours. The associated cost of these 

annual burden hours is $720 in year 

one, and $120 thereafter. No other 

burden hours and associated costs are 

expected. The Paperwork Reduction Act 

analysis in the docket has a more 

detailed explanation. 

F.6. Unfunded Mandates Reform Act of 

1995 

This rule does not impose unfunded 

mandates under the Unfunded 

Mandates Reform Act of 1995. It does 

not result in costs of $132 million or 

more in any one year 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. 

F.7. National Environmental Policy Act 

PHMSA has analyzed the rulemaking 

for purposes of the National 

Environmental Policy Act (42 U.S.C. 

4321 et seq.). The rulemaking will 

require limited physical change or other 

work that would disturb pipeline rightsof-way. In addition, the rule codifies the 

terms of special permits PHMSA has 

granted. Although PHMSA sought 

public comment on environmental 

impacts with respect to most requests 

for special permits to allow operation at 

pressures based on higher stress levels, 

no commenters addressed 

environmental impacts. Further, 

PHMSA did not receive any comment 

on the environmental assessment it had 

prepared in conjunction with the 

proposed rule. PHMSA has determined 

the rulemaking is unlikely to 

significantly affect the quality of the 

human environment. An environmental 

assessment document is available for 

review in the docket. 

F.8. Executive Order 13132 

PHMSA has analyzed the rulemaking 

according to Executive Order 13132 (64 

FR 43255, Aug. 10, 1999) and concluded 

that no additional consultation with 

States, local governments or their 

representatives is mandated beyond the 

rulemaking process. The 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 rule does not 

impose substantial direct compliance 

costs on State or local governments. 

Further, no consultation is needed to 

discuss the preemptive effect of the 

proposed rule. The pipeline safety law, 

specifically 49 U.S.C. 60104(c), 

prohibits State safety regulation of 

interstate pipelines. Under the pipeline 

safety law, States have the ability to 

augment pipeline safety requirements 

for intrastate pipelines PHMSA 

regulates, but may not approve safety 

requirements less stringent than those 

required by Federal law. And a State 

may regulate an intrastate pipeline 

facility PHMSA does not regulate. In 

addition, 49 U.S.C. 60120(c) provides 

that the Federal pipeline safety law 

‘‘does not affect the tort liability of any 

person.’’ It is these statutory provisions, 

not the rule, that govern preemption of 

State law. Therefore, the consultation 

and funding requirements of Executive 

Order 13132 do not apply. 

F.9. Executive Order 13211 

This rulemaking is likely to increase 

the efficiency of gas transmission 

pipelines. A gas transmission pipeline 

operating at an increased MAOP will 

result in increased capacity, fuel 

savings, and flexibility in addressing 

supply demands. This is a positive 

rather than an adverse effect on the 

supply, distribution, and use of energy. 

Thus this rulemaking is not a 

‘‘significant energy action’’ under 

Executive Order 13211. Further, the 

Administrator of the Office of 

Information and Regulatory Affairs has 

not identified this rule as a significant 

energy action. 

List of Subjects in 49 CFR Part 192 

Design pressure, Incorporation by 

reference, Maximum allowable 

operating pressure, and 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. In § 192.7, in paragraph (c)(2) 

amend the table of referenced material 

by revising item (B)(1), redesignating 

items (C)(6) through (C)(13) as (C)(7) 

through (C)(14), and adding a new item 

(C)(6) to read as follows: 

§ 192.7 What documents are incorporated 

by reference partly or wholly in this part? 

* * * * * 

(c) * * * 

(2) * * * 


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Source and name of referenced material 49 CFR reference 

B. * * * ............................................................................................................................................................... * * * 

(1) API Specification 5L ‘‘Specification for Line Pipe,’’ (43rd edition and errata), 2004 ................................... §§ 192.55(e); 192.112; 192.113; 

Item I of Appendix B. 

* * * * * * * 

C. * * * ..............................................................................................................................................................

(6) ASTM Designation: A 578/A578M–96 (Re-approved 2001) ‘‘Standard Specification for Straight-Beam 

Ultrasonic Examination of Plain and Clad Steel Plates for Special Applications’’.

§§ 192.112(c)(2)(iii). 

* * * * * * * 

■ 3. Add § 192.112 to subpart C to read 

as follows: 

§ 192.112 Additional design requirements 

for steel pipe using alternative maximum 

allowable operating pressure. 

For a new or existing pipeline 

segment to be eligible for operation at 

the alternative maximum allowable 

operating pressure (MAOP) calculated 

under § 192.620, a segment must meet 

the following additional design 

requirements. Records for alternative 

MAOP must be maintained, for the 

useful life of the pipeline, 

demonstrating compliance with these 

requirements: 

To address this design issue: The pipeline segment must meet these additional requirements: 

(a) General standards for the steel 

pipe.

(1) The plate, skelp, or coil used for the pipe must be micro-alloyed, fine grain, fully killed, continuously 

cast steel with calcium treatment. 

(2) The carbon equivalents of the steel used for pipe must not exceed 0.25 percent by weight, as calculated by the Ito-Bessyo formula (Pcm formula) or 0.43 percent by weight, as calculated by the International Institute of Welding (IIW) formula. 

(3) The ratio of the specified outside diameter of the pipe to the specified wall thickness must be less than 

100. The wall thickness or other mitigative measures must prevent denting and ovality anomalies during 

construction, strength testing and anticipated operational stresses. 

(4) The pipe must be manufactured using API Specification 5L, product specification level 2 (incorporated 

by reference, see § 192.7) for maximum operating pressures and minimum and maximum operating temperatures and other requirements under this section. 

(b) Fracture control ......................... (1) The toughness properties for pipe must address the potential for initiation, propagation and arrest of 

fractures in accordance with: 

(i) API Specification 5L (incorporated by reference, see § 192.7); or 

(ii) American Society of Mechanical Engineers (ASME) B31.8 (incorporated by reference, see § 192.7); and 

(iii) Any correction factors needed to address pipe grades, pressures, temperatures, or gas compositions 

not expressly addressed in API Specification 5L, product specification level 2 or ASME B31.8 (incorporated by reference, see § 192.7). 

(2) Fracture control must: 

(i) Ensure resistance to fracture initiation while addressing the full range of operating temperatures, pressures, gas compositions, pipe grade and operating stress levels, including maximum pressures and minimum temperatures for shut-in conditions, that the pipeline is expected to experience. If these parameters change during operation of the pipeline such that they are outside the bounds of what was considered in the design evaluation, the evaluation must be reviewed and updated to assure continued resistance to fracture initiation over the operating life of the pipeline; 

(ii) Address adjustments to toughness of pipe for each grade used and the decompression behavior of the 

gas at operating parameters; 

(iii) Ensure at least 99 percent probability of fracture arrest within eight pipe lengths with a probability of 

not less than 90 percent within five pipe lengths; and 

(iv) Include fracture toughness testing that is equivalent to that described in supplementary requirements 

SR5A, SR5B, and SR6 of API Specification 5L (incorporated by reference, see § 192.7) and ensures 

ductile fracture and arrest with the following exceptions: 

(A) The results of the Charpy impact test prescribed in SR5A must indicate at least 80 percent minimum 

shear area for any single test on each heat of steel; and 

(B) The results of the drop weight test prescribed in SR6 must indicate 80 percent average shear area with 

a minimum single test result of 60 percent shear area for any steel test samples. The test results must 

ensure a ductile fracture and arrest. 

(3) If it is not physically possible to achieve the pipeline toughness properties of paragraphs (b)(1) and (2) 

of this section, additional design features, such as mechanical or composite crack arrestors and/or heavier walled pipe of proper design and spacing, must be used to ensure fracture arrest as described in 

paragraph (b)(2)(iii) of this section. 

(c) Plate/coil quality control ............. (1) There must be an internal quality management program at all mills involved in producing steel, plate, 

coil, skelp, and/or rolling pipe to be operated at alternative MAOP. These programs must be structured 

to eliminate or detect defects and inclusions affecting pipe quality. 

(2) A mill inspection program or internal quality management program must include (i) and either (ii) or (iii): 

(i) An ultrasonic test of the ends and at least 35 percent of the surface of the plate/coil or pipe to identify 

imperfections that impair serviceability such as laminations, cracks, and inclusions. At least 95 percent of 

the lengths of pipe manufactured must be tested. For all pipelines designed after [the effective date of 

the final rule], the test must be done in accordance with ASTM A578/A578M Level B, or API 5L Paragraph 7.8.10 (incorporated by reference, see § 192.7) or equivalent method, and either 


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To address this design issue: The pipeline segment must meet these additional requirements: 

(ii) A macro etch test or other equivalent method to identify inclusions that may form centerline segregation 

during the continuous casting process. Use of sulfur prints is not an equivalent method. The test must 

be carried out on the first or second slab of each sequence graded with an acceptance criteria of one or 

two on the Mannesmann scale or equivalent; or 

(iii) A quality assurance monitoring program implemented by the operator that includes audits of: (a) all 

steelmaking and casting facilities, (b) quality control plans and manufacturing procedure specifications, 

(c) equipment maintenance and records of conformance, (d) applicable casting superheat and speeds, 

and (e) centerline segregation monitoring records to ensure mitigation of centerline segregation during 

the continuous casting process. 

(d) Seam quality control .................. (1) There must be a quality assurance program for pipe seam welds to assure tensile strength provided in 

API Specification 5L (incorporated by reference, see § 192.7) for appropriate grades. 

(2) There must be a hardness test, using Vickers (Hv10) hardness test method or equivalent test method, 

to assure a maximum hardness of 280 Vickers of the following: 

(i) A cross section of the weld seam of one pipe from each heat plus one pipe from each welding line per 

day; and 

(ii) For each sample cross section, a minimum of 13 readings (three for each heat affected zone, three in 

the weld metal, and two in each section of pipe base metal). 

(3) All of the seams must be ultrasonically tested after cold expansion and mill hydrostatic testing. 

(e) Mill hydrostatic test .................... (1) All pipe to be used in a new pipeline segment must be hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. The test pressure may include 

a combination of internal test pressure and the allowance for end loading stresses imposed by the pipe 

mill hydrostatic testing equipment as allowed by API Specification 5L, Appendix K (incorporated by reference, see § 192.7). 

(2) Pipe in operation prior to November 17, 2008, must have been hydrostatically tested at the mill at a 

test pressure corresponding to a hoop stress of 90 percent SMYS for 10 seconds. 

(f) Coating ....................................... (1) The pipe must be protected against external corrosion by a non-shielding coating. 

(2) Coating on pipe used for trenchless installation must be non-shielding and resist abrasions and other 

damage possible during installation. 

(3) A quality assurance inspection and testing program for the coating must cover the surface quality of the 

bare pipe, surface cleanliness and chlorides, blast cleaning, application temperature control, adhesion, 

cathodic disbondment, moisture permeation, bending, coating thickness, holiday detection, and repair. 

(g) Fittings and flanges ................... (1) There must be certification records of flanges, factory induction bends and factory weld ells. Certification must address material properties such as chemistry, minimum yield strength and minimum wall 

thickness to meet design conditions. 

(2) If the carbon equivalents of flanges, bends and ells are greater than 0.42 percent by weight, the qualified welding procedures must include a pre-heat procedure. 

(3) Valves, flanges and fittings must be rated based upon the required specification rating class for the alternative MAOP. 

(h) Compressor stations ................. (1) A compressor station must be designed to limit the temperature of the nearest downstream segment 

operating at alternative MAOP to a maximum of 120 degrees Fahrenheit (49 degrees Celsius) or the 

higher temperature allowed in paragraph (h)(2) of this section unless a long-term coating integrity monitoring program is implemented in accordance with paragraph (h)(3) of this section. 

(2) If research, testing and field monitoring tests demonstrate that the coating type being used will withstand a higher temperature in long-term operations, the compressor station may be designed to limit 

downstream piping to that higher temperature. Test results and acceptance criteria addressing coating 

adhesion, cathodic disbondment, and coating condition must be provided to each PHMSA pipeline safety 

regional office where the pipeline is in service at least 60 days prior to operating above 120 degrees 

Fahrenheit (49 degrees Celsius). An operator must also notify a State pipeline safety authority when the 

pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline 

is regulated by that State. 

(3) Pipeline segments operating at alternative MAOP may operate at temperatures above 120 degrees 

Fahrenheit (49 degrees Celsius) if the operator implements a long-term coating integrity monitoring program. The monitoring program must include examinations using direct current voltage gradient (DCVG), 

alternating current voltage gradient (ACVG), or an equivalent method of monitoring coating integrity. An 

operator must specify the periodicity at which these examinations occur and criteria for repairing identified indications. An operator must submit its long-term coating integrity monitoring program to each 

PHMSA pipeline safety regional office in which the pipeline is located for review before the pipeline segments may be operated at temperatures in excess of 120 degrees Fahrenheit (49 degrees Celsius). An 

operator must also notify a State pipeline safety authority when the pipeline is located in a State where 

PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State. 

■ 4. Add § 192.328 to subpart G to read 

as follows: 

§ 192.328 Additional construction 

requirements for steel pipe using 

alternative maximum allowable operating 

pressure. 

For a new or existing pipeline 

segment to be eligible for operation at 

the alternative maximum allowable 

operating pressure calculated under 

§ 192.620, a segment must meet the 

following additional construction 

requirements. Records must be 

maintained, for the useful life of the 

pipeline, demonstrating compliance 

with these requirements: 


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To address this construction issue: The pipeline segment must meet this additional construction requirement: 

(a) Quality assurance ...................... (1) The construction of the pipeline segment must be done under a quality assurance plan addressing pipe 

inspection, hauling and stringing, field bending, welding, non-destructive examination of girth welds, applying and testing field applied coating, lowering of the pipeline into the ditch, padding and backfilling, 

and hydrostatic testing. 

(2) The quality assurance plan for applying and testing field applied coating to girth welds must be: 

(i) Equivalent to that required under § 192.112(f)(3) for pipe; and 

(ii) Performed by an individual with the knowledge, skills, and ability to assure effective coating application. 

(b) Girth welds ................................ (1) All girth welds on a new pipeline segment must be non-destructively examined in accordance with 

§ 192.243(b) and (c). 

(c) Depth of cover ........................... (1) Notwithstanding any lesser depth of cover otherwise allowed in § 192.327, there must be at least 36 

inches (914 millimeters) of cover or equivalent means to protect the pipeline from outside force damage. 

(2) In areas where deep tilling or other activities could threaten the pipeline, the top of the pipeline must be 

installed at least one foot below the deepest expected penetration of the soil. 

(d) Initial strength testing ................ (1) The pipeline segment must not have experienced failures indicative of systemic material defects during 

strength testing, including initial hydrostatic testing. A root cause analysis, including metallurgical examination of the failed pipe, must be performed for any failure experienced to verify that it is not indicative 

of a systemic concern. The results of this root cause analysis must be reported to each PHMSA pipeline 

safety regional office where the pipe is in service at least 60 days prior to operating at the alternative 

MAOP. An operator must also notify a State pipeline safety authority when the pipeline is located in a 

State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that 

State. 

(e) Interference currents ................. (1) For a new pipeline segment, the construction must address the impacts of induced alternating current 

from parallel electric transmission lines and other known sources of potential interference with corrosion 

control. 

■ 5. Amend § 192.611 by revising 

paragraph (a)(1) and (a)(3)(i) and (ii) and 

adding new paragraph (a)(3)(iii) to read 

as follows: 

§ 192.611 Change in class location: 

Confirmation or revision of maximum 

allowable operating pressure. 

(a) * * * 

(1) If the segment involved has been 

previously tested in place for a period 

of not less than 8 hours: 

(i) The maximum allowable operating 

pressure is 0.8 times the test pressure in 

Class 2 locations, 0.667 times the test 

pressure in Class 3 locations, or 0.555 

times the test pressure in Class 4 

locations. The corresponding hoop 

stress may not exceed 72 percent of the 

SMYS of the pipe in Class 2 locations, 

60 percent of SMYS in Class 3 locations, 

or 50 percent of SMYS in Class 4 

locations. 

(ii) The alternative maximum 

allowable operating pressure is 0.8 

times the test pressure in Class 2 

locations and 0.667 times the test 

pressure in Class 3 locations. For 

pipelines operating at alternative 

maximum allowable pressure per 

§ 192.620, the corresponding hoop stress 

may not exceed 80 percent of the SMYS 

of the pipe in Class 2 locations and 67 

percent of SMYS in Class 3 locations. 

* * * * * 

(3) * * * 

(i) The maximum allowable operating 

pressure after the requalification test is 

0.8 times the test pressure for Class 2 

locations, 0.667 times the test pressure 

for Class 3 locations, and 0.555 times 

the test pressure for Class 4 locations. 

(ii) The corresponding hoop stress 

may not exceed 72 percent of the SMYS 

of the pipe in Class 2 locations, 60 

percent of SMYS in Class 3 locations, or 

50 percent of SMYS in Class 4 locations. 

(iii) For pipeline operating at an 

alternative maximum allowable 

operating pressure per § 192.620, the 

alternative maximum allowable 

operating pressure after the 

requalification test is 0.8 times the test 

pressure for Class 2 locations and 0.667 

times the test pressure for Class 3 

locations. The corresponding hoop 

stress may not exceed 80 percent of the 

SMYS of the pipe in Class 2 locations 

and 67 percent of SMYS in Class 3 

locations. 

* * * * * 

■ 6. Amend § 192.619 by revising 

paragraph (a) introductory text and by 

adding paragraph (d) to read as follows: 

§ 192.619 Maximum allowable operating 

pressure: Steel or plastic pipelines. 

(a) No person may operate a segment 

of steel or plastic pipeline at a pressure 

that exceeds a maximum allowable 

operating pressure determined under 

paragraph (c) or (d) of this section, or 

the lowest of the following: 

* * * * * 

(d) The operator of a pipeline segment 

of steel pipeline meeting the conditions 

prescribed in § 192.620(b) may elect to 

operate the segment at a maximum 

allowable operating pressure 

determined under § 192.620(a). 

■ 7. Add § 192.620 to subpart L to read 

as follows: 

§ 192.620 Alternative maximum allowable 

operating pressure for certain steel 

pipelines. 

(a) How does an operator calculate 

the alternative maximum allowable 

operating pressure? An operator 

calculates the alternative maximum 

allowable operating pressure by using 

different factors in the same formulas 

used for calculating maximum 

allowable operating pressure under 

§ 192.619(a) as follows: 

(1) In determining the alternative 

design pressure under § 192.105, use a 

design factor determined in accordance 

with § 192.111(b), (c), or (d) or, if none 

of these paragraphs apply, in 

accordance with the following table: 

Class location Alternative design factor (F) 

1 ............................................ 0.80 

2 ............................................ 0.67 

3 ............................................ 0.56 

(i) For facilities installed prior to 

November 17, 2008, for which 

§ 192.111(b), (c), or (d) apply, use the 

following design factors as alternatives 

for the factors specified in those 

paragraphs: § 192.111(b)—0.67 or less; 

192.111(c) and (d)—0.56 or less. 

(ii) [Reserved] 

(2) The alternative maximum 

allowable operating pressure is the 

lower of the following: 

(i) The design pressure of the weakest 

element in the pipeline segment, 

determined under subparts C and D of 

this part. 

(ii) The pressure obtained by dividing 

the pressure to which the pipeline 

segment was tested after construction by 


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a factor determined in the following 

table: 

Class location Alternative test 

factor 

1 ............................................ 1.25 

2 ............................................ 1 1.50 

3 ............................................ 1.50 

1For Class 2 alternative maximum allowable 

operating pressure segments installed prior to 

November 17, 2008, the alternative test factor 

is 1.25. 

(b) When may an operator use the 

alternative maximum allowable 

operating pressure calculated under 

paragraph (a) of this section? An 

operator may use an alternative 

maximum allowable operating pressure 

calculated under paragraph (a) of this 

section if the following conditions are 

met: 

(1) The pipeline segment is in a Class 

1, 2, or 3 location; 

(2) The pipeline segment is 

constructed of steel pipe meeting the 

additional design requirements in 

§ 192.112; 

(3) A supervisory control and data 

acquisition system provides remote 

monitoring and control of the pipeline 

segment. The control provided must 

include monitoring of pressures and 

flows, monitoring compressor start-ups 

and shut-downs, and remote closure of 

valves; 

(4) The pipeline segment meets the 

additional construction requirements 

described in § 192.328; 

(5) The pipeline segment does not 

contain any mechanical couplings used 

in place of girth welds; 

(6) If a pipeline segment has been 

previously operated, the segment has 

not experienced any failure during 

normal operations indicative of a 

systemic fault in material as determined 

by a root cause analysis, including 

metallurgical examination of the failed 

pipe. The results of this root cause 

analysis must be reported to each 

PHMSA pipeline safety regional office 

where the pipeline is in service at least 

60 days prior to operation at the 

alternative MAOP. An operator must 

also notify a State pipeline safety 

authority when the pipeline is located 

in a State where PHMSA has an 

interstate agent agreement, or an 

intrastate pipeline is regulated by that 

State; and 

(7) At least 95 percent of girth welds 

on a segment that was constructed prior 

to November 17, 2008, must have been 

non-destructively examined in 

accordance with § 192.243(b) and (c). 

(c) What is an operator electing to use 

the alternative maximum allowable 

operating pressure required to do? If an 

operator elects to use the alternative 

maximum allowable operating pressure 

calculated under paragraph (a) of this 

section for a pipeline segment, the 

operator must do each of the following: 

(1) Notify each PHMSA pipeline 

safety regional office where the pipeline 

is in service of its election with respect 

to a segment at least 180 days before 

operating at the alternative maximum 

allowable operating pressure. An 

operator must also notify a State 

pipeline safety authority when the 

pipeline is located in a State where 

PHMSA has an interstate agent 

agreement, or an intrastate pipeline is 

regulated by that State. 

(2) Certify, by signature of a senior 

executive officer of the company, as 

follows: 

(i) The pipeline segment meets the 

conditions described in paragraph (b) of 

this section; and 

(ii) The operating and maintenance 

procedures include the additional 

operating and maintenance 

requirements of paragraph (d) of this 

section; and 

(iii) The review and any needed 

program upgrade of the damage 

prevention program required by 

paragraph (d)(4)(v) of this section has 

been completed. 

(3) Send a copy of the certification 

required by paragraph (c)(2) of this 

section to each PHMSA pipeline safety 

regional office where the pipeline is in 

service 30 days prior to operating at the 

alternative MAOP. An operator must 

also send a copy to a State pipeline 

safety authority when the pipeline is 

located in a State where PHMSA has an 

interstate agent agreement, or an 

intrastate pipeline is regulated by that 

State. 

(4) For each pipeline segment, do one 

of the following: 

(i) Perform a strength test as described 

in § 192.505 at a test pressure calculated 

under paragraph (a) of this section or 

(ii) For a pipeline segment in 

existence prior to November 17, 2008, 

certify, under paragraph (c)(2) of this 

section, that the strength test performed 

under § 192.505 was conducted at a test 

pressure calculated under paragraph (a) 

of this section, or conduct a new 

strength test in accordance with 

paragraph (c)(4)(i) of this section. 

(5) Comply with the additional 

operation and maintenance 

requirements described in paragraph (d) 

of this section. 

(6) If the performance of a 

construction task associated with 

implementing alternative MAOP can 

affect the integrity of the pipeline 

segment, treat that task as a ‘‘covered 

task’’, notwithstanding the definition in 

§ 192.801(b) and implement the 

requirements of subpart N as 

appropriate. 

(7) Maintain, for the useful life of the 

pipeline, records demonstrating 

compliance with paragraphs (b), (c)(6), 

and (d) of this section. 

(8) A Class 1 and Class 2 pipeline 

location can be upgraded one class due 

to class changes per § 192.611(a)(3)(i). 

All class location changes from Class 1 

to Class 2 and from Class 2 to Class 3 

must have all anomalies evaluated and 

remediated per: The ‘‘original pipeline 

class grade’’ § 192.620(d)(11) anomaly 

repair requirements; and all anomalies 

with a wall loss equal to or greater than 

40 percent must be excavated and 

remediated. Pipelines in Class 4 may 

not operate at an alternative MAOP. 

(d) What additional operation and 

maintenance requirements apply to 

operation at the alternative maximum 

allowable operating pressure? In 

addition to compliance with other 

applicable safety standards in this part, 

if an operator establishes a maximum 

allowable operating pressure for a 

pipeline segment under paragraph (a) of 

this section, an operator must comply 

with the additional operation and 

maintenance requirements as follows: 

To address increased risk of a 

maximum allowable operating pressure based on higher stress levels 

in the following areas: 

Take the following additional step: 

(1) Identifying and evaluating 

threats.

Develop a threat matrix consistent with § 192.917 to do the following: 

(i) Identify and compare the increased risk of operating the pipeline at the increased stress level under this 

section with conventional operation; and 

(ii) Describe and implement procedures used to mitigate the risk. 

(2) Notifying the public .................... (i) Recalculate the potential impact circle as defined in § 192.903 to reflect use of the alternative maximum 

operating pressure calculated under paragraph (a) of this section and pipeline operating conditions; and 

(ii) In implementing the public education program required under § 192.616, perform the following: 


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To address increased risk of a 

maximum allowable operating pressure based on higher stress levels 

in the following areas: 

Take the following additional step: 

(A) Include persons occupying property within 220 yards of the centerline and within the potential impact 

circle within the targeted audience; and 

(B) Include information about the integrity management activities performed under this section within the 

message provided to the audience. 

(3) Responding to an emergency in 

an area defined as a high consequence area in § 192.903.

(i) Ensure that the identification of high consequence areas reflects the larger potential impact circle recalculated under paragraph (d)(1)(i) of this section. 

(ii) If personnel response time to mainline valves on either side of the high consequence area exceeds one 

hour (under normal driving conditions and speed limits) from the time the event is identified in the control 

room, provide remote valve control through a supervisory control and data acquisition (SCADA) system, 

other leak detection system, or an alternative method of control. 

(iii) Remote valve control must include the ability to close and monitor the valve position (open or closed), 

and monitor pressure upstream and downstream. 

(iv) A line break valve control system using differential pressure, rate of pressure drop or other widely-accepted method is an acceptable alternative to remote valve control. 

(4) Protecting the right-of-way ........ (i) Patrol the right-of-way at intervals not exceeding 45 days, but at least 12 times each calendar year, to 

inspect for excavation activities, ground movement, wash outs, leakage, or other activities or conditions 

affecting the safety operation of the pipeline. 

(ii) Develop and implement a plan to monitor for and mitigate occurrences of unstable soil and ground 

movement. 

(iii) If observed conditions indicate the possible loss of cover, perform a depth of cover study and replace 

cover as necessary to restore the depth of cover or apply alternative means to provide protection equivalent to the originally-required depth of cover. 

(iv) Use line-of-sight line markers satisfying the requirements of § 192.707(d) except in agricultural areas, 

large water crossings or swamp, steep terrain, or where prohibited by Federal Energy Regulatory Commission orders, permits, or local law. 

(v) Review the damage prevention program under § 192.614(a) in light of national consensus practices, to 

ensure the program provides adequate protection of the right-of-way. Identify the standards or practices 

considered in the review, and meet or exceed those standards or practices by incorporating appropriate 

changes into the program. 

(vi) Develop and implement a right-of-way management plan to protect the pipeline segment from damage 

due to excavation activities. 

(5) Controlling internal corrosion .... (i) Develop and implement a program to monitor for and mitigate the presence of, deleterious gas stream 

constituents. 

(ii) At points where gas with potentially deleterious contaminants enters the pipeline, use filter separators 

or separators and gas quality monitoring equipment. 

(iii) Use gas quality monitoring equipment that includes a moisture analyzer, chromatograph, and periodic 

hydrogen sulfide sampling. 

(iv) Use cleaning pigs and inhibitors, and sample accumulated liquids when corrosive gas is present. 

(v) Address deleterious gas stream constituents as follows: 

(A) Limit carbon dioxide to 3 percent by volume; 

(B) Allow no free water and otherwise limit water to seven pounds per million cubic feet of gas; and 

(C) Limit hydrogen sulfide to 1.0 grain per hundred cubic feet (16 ppm) of gas, where the hydrogen sulfide 

is greater than 0.5 grain per hundred cubic feet (8 ppm) of gas, implement a pigging and inhibitor injection program to address deleterious gas stream constituents, including follow-up sampling and quality 

testing of liquids at receipt points. 

(vi) Review the program at least quarterly based on the gas stream experience and implement adjustments 

to monitor for, and mitigate the presence of, deleterious gas stream constituents. 

(6) Controlling interference that can 

impact external corrosion.

(i) Prior to operating an existing pipeline segment at an alternate maximum allowable operating pressure 

calculated under this section, or within six months after placing a new pipeline segment in service at an 

alternate maximum allowable operating pressure calculated under this section, address any interference 

currents on the pipeline segment. 

(ii) To address interference currents, perform the following: 

(A) Conduct an interference survey to detect the presence and level of any electrical current that could impact external corrosion where interference is suspected; 

(B) Analyze the results of the survey; and 

(C) Take any remedial action needed within 6 months after completing the survey to protect the pipeline 

segment from deleterious current. 

(7) Confirming external corrosion 

control through indirect assessment.

(i) Within six months after placing the cathodic protection of a new pipeline segment in operation, or within 

six months after certifying a segment under § 192.620(c)(1) of an existing pipeline segment under this 

section, assess the adequacy of the cathodic protection through an indirect method such as close-interval survey, and the integrity of the coating using direct current voltage gradient (DCVG) or alternating 

current voltage gradient (ACVG). 

(ii) Remediate any construction damaged coating with a voltage drop classified as moderate or severe (IR 

drop greater than 35% for DCVG or 50 dBμv for ACVG) under section 4 of NACE RP–0502–2002 (incorporated by reference, see § 192.7). 

(iii) Within six months after completing the baseline internal inspection required under paragraph (8) of this 

section, integrate the results of the indirect assessment required under paragraph (6)(i) of this section 

with the results of the baseline internal inspection and take any needed remedial actions. 

(iv) For all pipeline segments in high consequence areas, perform periodic assessments as follows: 


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62180 Federal Register / Vol. 73, No. 202 / Friday, October 17, 2008 / Rules and Regulations 

To address increased risk of a 

maximum allowable operating pressure based on higher stress levels 

in the following areas: 

Take the following additional step: 

(A) Conduct periodic close interval surveys with current interrupted to confirm voltage drops in association 

with periodic assessments under subpart O of this part. 

(B) Locate pipe-to-soil test stations at half-mile intervals within each high consequence area ensuring at 

least one station is within each high consequence area, if practicable. 

(C) Integrate the results with those of the baseline and periodic assessments for integrity done under paragraphs (d)(8) and (d)(9) of this section. 

(8) Controlling external corrosion 

through cathodic protection.

(i) If an annual test station reading indicates cathodic protection below the level of protection required in 

subpart I of this part, complete remedial action within six months of the failed reading or notify each 

PHMSA pipeline safety regional office where the pipeline is in service demonstrating that the integrity of 

the pipeline is not compromised if the repair takes longer than 6 months. An operator must also notify a 

State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate 

agent agreement, or an intrastate pipeline is regulated by that State; and 

(ii) After remedial action to address a failed reading, confirm restoration of adequate corrosion control by a 

close interval survey on either side of the affected test station to the next test station. 

(iii) If the pipeline segment has been in operation, the cathodic protection system on the pipeline segment 

must have been operational within 12 months of the completion of construction. 

(9) Conducting a baseline assessment of integrity.(i) Except as provided in paragraph (d)(8)(iii) of this section, for a new pipeline segment operating at the 

new alternative maximum allowable operating pressure, perform a baseline internal inspection of the entire pipeline segment as follows: 

(A) Assess using a geometry tool after the initial hydrostatic test and backfill and within six months after 

placing the new pipeline segment in service; and 

(B) Assess using a high resolution magnetic flux tool within three years after placing the new pipeline segment in service at the alternative maximum allowable operating pressure. 

(ii) Except as provided in paragraph (d)(8)(iii) of this section, for an existing pipeline segment, perform a 

baseline internal assessment using a geometry tool and a high resolution magnetic flux tool before, but 

within two years prior to, raising pressure to the alternative maximum allowable operating pressure as allowed under this section. 

(iii) If headers, mainline valve by-passes, compressor station piping, meter station piping, or other short 

portion of a pipeline segment operating at alternative maximum allowable operating pressure cannot accommodate a geometry tool and a high resolution magnetic flux tool, use direct assessment (per 

§ 192.925, § 192.927 and/or § 192.929) or pressure testing (per subpart J of this part) to assess that portion. 

(10) Conducting periodic assessments of integrity.(i) Determine a frequency for subsequent periodic integrity assessments as if all the alternative maximum 

allowable operating pressure pipeline segments were covered by subpart O of this part and 

(ii) Conduct periodic internal inspections using a high resolution magnetic flux tool on the frequency determined under paragraph (d)(9)(i) of this section, or 

(iii) Use direct assessment (per § 192.925, § 192.927 and/or § 192.929) or pressure testing (per subpart J 

of this part) for periodic assessment of a portion of a segment to the extent permitted for a baseline assessment under paragraph (d)(8)(iii) of this section. 

(11) Making repairs ......................... (i) Perform the following when evaluating an anomaly: 

(A) Use the most conservative calculation for determining remaining strength or an alternative validated 

calculation based on pipe diameter, wall thickness, grade, operating pressure, operating stress level, 

and operating temperature: and 

(B) Take into account the tolerances of the tools used for the inspection. 

(ii) Repair a defect immediately if any of the following apply: 

(A) The defect is a dent discovered during the baseline assessment for integrity under paragraph (d)(8) of 

this section and the defect meets the criteria for immediate repair in § 192.309(b). 

(B) The defect meets the criteria for immediate repair in § 192.933(d). 

(C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under 

paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure. 

(D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under 

paragraph (a) of this section and the failure pressure is less than or equal to 1.4 times the alternative 

maximum allowable operating pressure. 

(iii) If paragraph (d)(10)(ii) of this section does not require immediate repair, repair a defect within one year 

if any of the following apply: 

(A) The defect meets the criteria for repair within one year in § 192.933(d). 

(B) The alternative maximum allowable operating pressure was based on a design factor of 0.80 under 

paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure. 

(C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under 

paragraph (a) of this section and the failure pressure is less than 1.50 times the alternative maximum allowable operating pressure. 

(D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under 

paragraph (a) of this section and the failure pressure is less than or equal to 1.80 times the alternative 

maximum allowable operating pressure. 

(iv) Evaluate any defect not required to be repaired under paragraph (d)(10)(ii) or (iii) of this section to determine its growth rate, set the maximum interval for repair or re-inspection, and repair or re-inspect 

within that interval. 


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Federal Register / Vol. 73, No. 202 / Friday, October 17, 2008 / Rules and Regulations 62181 

(e) Is there any change in overpressure 

protection associated with operating at 

the alternative maximum allowable 

operating pressure? Notwithstanding 

the required capacity of pressure 

relieving and limiting stations otherwise 

required by § 192.201, if an operator 

establishes a maximum allowable 

operating pressure for a pipeline 

segment in accordance with paragraph 

(a) of this section, an operator must: 

(1) Provide overpressure protection 

that limits mainline pressure to a 

maximum of 104 percent of the 

maximum allowable operating pressure; 

and 

(2) Develop and follow a procedure 

for establishing and maintaining 

accurate set points for the supervisory 

control and data acquisition system. 

Issued in Washington, DC, on October 2, 

2008. 

Carl T. Johnson, 

Administrator. 

[FR Doc. E8–23915 Filed 10–16–08; 8:45 am] 

BILLING CODE 4910–60–P 


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