Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules 36861 

1The Department of Transportation first proposed 

class location regulations on March 24, 1970 (35 FR 

5012). The proposal was part of a series of NPRMs 

published in response to the Natural Gas Pipeline 

Safety Act of 1968 (Pub. L. 90–481). The NPRMs 

were directed at developing a comprehensive 

system of Federal safety standards for gas pipeline 

facilities and for the transportation of gas through 

such pipelines. The class location rulemaking was 

finalized on August 19, 1970, as part of a 

consolidated rulemaking establishing the first 

minimum Federal safety standards for the 

transportation of natural gas by pipelines (35 FR 

13248). 

2 35 FR 13248. 

Subpart C—Technical Standards 

Brief Description: Part 101 prescribes 

the manner in which portions of the 

radio spectrum may be made available 

for private operational, common carrier, 

24 GHz Service, Local Multipoint 

Distribution Service, and fixed, 

microwave operations that require 

transmitting facilities on land or in 

specified offshore coastal areas within 

the continental shelf. Subpart C sets 

forth technical standards for 

applications and licenses in the Fixed 

Microwave Services. 

Need: The revised rules provide the 

interference protection criteria for fixed 

stations subject to part 101 and requires 

that transmitters used in the private 

operational fixed and common carrier 

fixed point-to-point microwave and 

point-to-multipoint services under this 

part must be a type that has been 

verified for compliance. The need for 

these rules is ongoing. 

Legal Basis: 47 U.S.C. 154, and 303. 

Section Number and Titles: 

101.105(a)(5) and (6) Interference 

protection criteria. 

101.139(h) and (i) Authorization of 

transmitters. 

[FR Doc. 2018–16282 Filed 7–30–18; 8:45 am] 

BILLING CODE 6712–01–P 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

49 CFR Part 192 

[Docket ID: PHMSA–2017–0151] 

RIN 2137–AF29 

Pipeline Safety: Class Location 

Change Requirements 

AGENCY: Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA), DOT. 

ACTION: Advance notice of proposed 

rulemaking (ANPRM). 

SUMMARY: PHMSA is seeking public 

comment on its existing class location 

requirements for natural gas 

transmission pipelines as they pertain to 

actions operators are required to take 

following class location changes due to 

population growth near the pipeline. 

Operators have suggested that 

performing integrity management 

measures on pipelines where class 

locations have changed due to 

population increases would be an 

equally safe but less costly alternative to 

the current requirements of either 

reducing pressure, pressure testing, or 

replacing pipe. This request for public 

comment continues a line of discussion 

from a Notice of Inquiry published in 

2013 and a report to Congress in 2016 

regarding whether expanding integrity 

management requirements would 

mitigate the need for class location 

requirements. 

DATES: Persons interested in submitting 

written comments on this ANPRM must 

do so by October 1, 2018. 

ADDRESSES: You may submit comments 

identified by the Docket: PHMSA–2017– 

0151 by any of the following methods: 

E-Gov website: https://

www.regulations.gov. This site allows 

the public to enter comments on any 

Federal Register notice issued by any 

agency. Follow the online instructions 

for submitting comments. 

Fax: 1–202–493–2251. 

Mail: Hand Delivery: U.S. DOT Docket 

Management System, West Building 

Ground Floor, Room W12–140, 1200 

New Jersey Avenue SE, Washington, DC 

20590–0001 between 9:00 a.m. and 5:00 

p.m., Monday through Friday, except 

Federal holidays. 

Instructions: Identify the Docket ID at 

the beginning of your comments. If you 

submit your comments by mail, submit 

two copies. If you wish to receive 

confirmation that PHMSA has received 

your comments, include a selfaddressed stamped postcard. Internet 

users may submit comments at https:// 

www.regulations.gov/. 

Note: Comments are posted without 

changes or edits to https://

www.regulations.gov, including any 

personal information provided. There is 

a privacy statement published on 

https://www.regulations.gov. 

FOR FURTHER INFORMATION CONTACT: 

Technical questions: Steve Nanney, 

Project Manager, by telephone at 713– 

272–2855 or by email at steve.nanney@

dot.gov. 

General information: Robert Jagger, 

Technical Writer, by telephone at 202– 

366–4361 or by email at robert.jagger@

dot.gov. 

SUPPLEMENTARY INFORMATION: 

Outline of This Document 

I. Class Location History and Purpose 

A. Class Location Determinations 

B. Class Location—‘‘Cluster Rule’’ 

Adjustments 

II. Changes in Class Location Due to 

Population Growth 

III. Class Location Change Special Permits 

A. Special Permit Conditions 

IV. Pipeline Safety, Regulatory Certainty, and 

Job Creation Act of 2011—Section 5 

A. 2013 Notice of Inquiry: Class Location 

Requirements 

B. 2014 Pipeline Advisory Committee 

Meeting, Class Location Workshop, and 

Subsequent Comments 

C. 2016 Class Location Report 

V. INGAA Submission on Regulatory 

Reform—Proposal To Perform IM 

Measures In-Lieu of Pipe Replacement 

When Class Locations Change 

VI. Questions for Consideration 

VII. Regulatory Notices 

Background 

I. Class Location History and Purpose 

The class location concept pre-dates 

Federal regulation of gas transmission 

pipelines 1 and was an early method of 

differentiating areas and risks along 

natural gas pipelines based on the 

potential consequences of a 

hypothetical pipeline failure. Class 

location designations were previously 

included in the American Standards 

Association B31.8–1968 version of the 

‘‘Gas Transmission and Distribution 

Pipeline Systems’’ standard, which 

eventually became the American 

Society of Mechanical Engineers 

(ASME) International Standard, ASME 

B31.8 ‘‘Gas Transmission and 

Distribution Pipeline Systems.’’ The 

class location definitions incorporated 

into title 49, Code of Federal 

Regulations (CFR) § 192.5 were initially 

derived from the designations in this 

standard and were first codified on 

April 19, 1970.2 These definitions were 

like the original ASME B31.8 definitions 

for Class 1 through 3 locations but 

added an additional Class 4 definition 

and, with some modifications, still 

apply today. 

Gas transmission pipelines are 

divided into classes from 1 (rural areas) 

to 4 (densely populated, high-rise areas) 

that are based on the number of 

buildings or dwellings for human 

occupancy in the area. This concept is 

to provide safety to people from the 

effects of a high-pressure natural gas 

pipeline leak or rupture that could 

explode or catch on fire. PHMSA uses 

class locations in 49 CFR part 192 to 

implement a graded approach in many 

areas that provides more conservative 

safety margins and more stringent safety 

standards commensurate with the 

potential consequences based on 

population density near the pipeline. 

When crafting the natural gas 


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3For instance, the number of human dwellings 

near the pipeline or the type of dwelling (hospital, 

school, playground, nursing care facility, etc.). 

4This can include piping at compressor stations, 

metering stations, fabrications, and road or railroad 

crossings. 

5 Design factors for steel pipe are listed in 

§ 192.111. Class 1 locations have a 0.72 design 

factor, Class 2 locations have a 0.60 factor, Class 3 

locations have a 0.50 factor, and Class 4 locations 

have a 0.40 design factor. 

6SMYS is an indication of the minimum stress a 

pipe may experience that will cause plastic, or 

permanent, deformation of the steel pipe. 

7The seam type of a pipeline, per this formula, 

has a limiting effect on the MAOP of the pipeline. 

While it is typically ‘‘1.00’’ and does not affect the 

calculation, certain types of furnace butt-welded 

pipe or pipe not manufactured to certain industry 

standards will have factors of 0.60 or 0.80, which 

will necessitate a reduction in design pressure. 

8The temperature derating factor ranges from 

1.000 to 0.867 depending on the operating 

temperature of the pipeline. Pipelines designed to 

operate at 250 degrees Fahrenheit and lower have 

a factor of 1.000, which does not affect the design 

pressure calculation. Pipelines designed to operate 

at higher temperatures, including up to 450 degrees 

Fahrenheit, will have derating factors that will 

lower the design pressure of the pipeline. 

9 §§ 192.5, 192.8, 192.9, 192.65, 192.105, 192.111, 

192.123, 192.150, 192.175, 192.179, 192.243, 

192.327, 192.485, 192.503, 192.505, 192.609, 

192.611, 192.613, 192.619, 192.620, 192.625, 

192.705, 192.706, 192.707, 192.713, 192.903, 

192.933, and 192.935. 

10Per the regulations, a ‘‘building’’ is a structure 

intended for human occupancy, whether it is used 

as a residence, for business, or for another purpose. 

For the purposes of this rulemaking, a ‘‘building’’ 

may be interchangeably referred to as a ‘‘home,’’ a 

‘‘house,’’ or a ‘‘dwelling.’’ 11Under § 192.5, Class 1 locations also include 

offshore areas, and Class 3 locations contain areas 

where the pipeline lies within 100 yards of a 

building or a small, well-defined outside area 

(including playgrounds, recreation areas, and 

outdoor theaters) that is occupied by 20 or more 

persons at least 5 days a week for 10 weeks in any 

12-month period. The days and weeks need not be 

consecutive. 

regulations, DOT’s Office of Pipeline 

Safety (OPS) determined that these more 

stringent standards were necessary 

because a greater number of people in 

proximity to the pipeline substantially 

increases the probabilities of personal 

injury and property damage in the event 

of an accident. At the same time, the 

external stresses, the potential for 

damage from third-parties, and other 

factors that contribute to accidents 

increase along with the population; 

consequently, additional protective 

measures are often needed in areas with 

greater concentrations of population. 

The most basic and earliest use of the 

class location concept focused on the 

design (safety) margin for the pipeline. 

As pipelines are designed based, in part, 

on the population along their pipeline 

route and therefore the class location of 

the area, it is important to decrease pipe 

stresses in areas where there is the 

potential for higher consequences or 

where higher pipe stresses could affect 

the safe operation of a pipeline in largerpopulated areas. Pipeline design factors 

are derating factors that ensure 

pipelines are operated below 100 

percent of the maximum pipe yield 

strength. From an engineering 

standpoint, they were developed based 

on risk to the public 3 and for piping 

that may face additional operational 

stresses.4 Pipeline design factors vary, 

ranging from 0.72 in a Class 1 location 

to 0.40 in a Class 4 location. They are 

used in the pipeline design formula 

(§ 192.105) to determine the design 

pressure for steel pipe, and are generally 

reflected in the maximum allowable 

operating pressure (MAOP) based upon 

a percentage of the specified minimum 

yield strength (SMYS) at which the 

pipeline can be operated.5 6 Design 

factors are used along with pipe 

characteristics in engineering 

calculations (Barlow’s Formula) to 

calculate the design pressure and MAOP 

of a steel pipeline. More specifically, the 

formula at § 192.105 is P = (2St/D) × F 

× E × T, where P is the design pressure, 

S is the pipe’s yield strength, t is the 

wall thickness of the pipe, D is the 

diameter of the pipe, F is the design 

factor per the class location, E is the 

longitudinal joint factor,7 and T is the 

temperature derating factor.8 The 

formula in § 192.105 can be used to 

calculate the MAOP of a 1000 psig 

pipeline with the same operating 

parameters (diameter, wall thickness, 

yield strength, seam type, and 

temperature) but in different class 

locations (and therefore different design 

factors), and the MAOP of that pipeline 

in the different class locations would be 

as follows: 

• No class location—design factor = 1.0 

(none); MAOP = 1000 psig 

• Class 1—design factor = 0.72; MAOP 

= 720 psig 

• Class 2—design factor = 0.60; MAOP 

= 600 psig 

• Class 3—design factor = 0.50; MAOP 

= 500 psig 

• Class 4—design factor = 0.40; MAOP 

= 400 psig 

As therefore evidenced, pipelines at 

higher class locations will have lower 

operating pressures and maximum 

allowable operating pressures due to 

more stringent design factors to protect 

people near the pipeline. 

As natural gas pipeline standards and 

regulations evolved, the class location 

concept was incorporated into many 

other regulatory requirements, including 

test pressures, mainline block valve 

spacing, pipeline design and 

construction, and operations and 

maintenance (O&M) requirements, to 

provide additional safety to populated 

areas. In total, class location concepts 

affect 12 of 16 subparts of part 192 and 

a total of 28 individual sections.9

A. Class Location Determinations 

Pipeline class locations for onshore 

gas pipelines are determined as 

specified in § 192.5(a) by using a 

‘‘sliding mile.’’ The ‘‘sliding mile’’ is a 

unit that is 1 mile in length, extends 220 

yards on either side of the centerline of 

a pipeline, and moves along the 

pipeline. The number of buildings 10

within this sliding mile at any point 

during the mile’s movement determines 

the class location for the entire mile of 

pipeline contained within the sliding 

mile. Class locations are not determined 

at any given point of a pipeline by 

counting the number of dwellings in 

static mile-long pipeline segments 

stacked end-to-end. 

When higher dwelling concentrations 

are encountered during the continuous 

sliding of this mile-long unit, the class 

location of the pipeline rises 

commensurately. As it pertains to 

structure counts, a Class 1 location is a 

class location unit along a continuous 

mile containing 10 or fewer buildings 

intended for human occupancy, a Class 

2 location is a class location unit along 

a continuous mile containing 11 to 45 

buildings intended for human 

occupancy, and a Class 3 location is a 

class location unit along a continuous 

mile containing 46 or more buildings 

intended for human occupancy.11 Class 

4 locations exist where buildings with 

four or more stories above ground are 

prevalent. Whenever there is a change 

in class location that will cause an 

apparent overlapping of class locations, 

the higher-numbered class location 

applies. 

B. Class Location—‘‘Cluster Rule’’ 

Adjustments 

After proposing the initial natural gas 

safety regulations in 1970, OPS received 

several comments stating that the 

proposed class location definitions 

could create 2-mile stretches of higher 

class locations for the sole protection of 

small clusters of buildings at crossroads 

or road crossings. Because part 192 

regulations become more stringent as 

class locations increase from Class 1 to 

4 locations, pipelines in higher class 

location areas such as these can result 

in increased expenditures to the 

pipeline operator in areas where there is 

no population. When finalizing the class 

location definitions as a part of 

establishing part 192 on August 19, 

1970 (35 FR 13248), OPS added a new 

paragraph to allow operators to adjust 

the boundaries of Class 2, 3, and 4 


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12See § 192.5(c)(1) & (2). 

13For example, if all buildings for human 

occupancy in a sliding mile containing enough 

buildings to require a Class 3 location were 

clustered in the middle of that sliding mile, the 

Class 3 area would end 220 yards from the nearest 

building (on either side of the cluster through 

which the pipeline passes) rather than at the end 

of the 1-mile class location unit that would 

otherwise be the basis for classification. Thus, if the 

cluster were 200 yards in length, the total length of 

the Class 3 area would be 640 yards (220 + 200 + 

220). 

14PHMSA Interpretation #PI–14–0017, available 

at https://www.phmsa.dot.gov/sites/phmsa.dot.gov/ 

files/legacy/interpretations/Interpretation%20Files/ 

Pipeline/2015/Air_Products_PI_14_0017_10_01_

2014_Part_192.5.pdf. 

15See § 192.611 as appropriate to one-class 

changes (e.g., Class 1 to 2 or Class 2 to 3 or Class 

3 to 4). As an example, for a Class 1 to Class 2 

location change, the pipeline segment would 

require a pressure test to 1.25 times the MAOP for 

8 hours. Following a successful pressure test, the 

pipeline segment would not need to be replaced 

with new pipe, but the existing design factor of 0.72 

for a Class 1 location would be acceptable for a 

Class 2 location. 

16See § 192.611. Specifically, if the applicable 

segment has been hydrostatically tested for a period 

of longer than 8 hours, the MAOP 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% of 

Continued 

locations. Under this provision, 

operators can choose to end Class 4 

location boundaries 220 yards from the 

furthest edges of a group of 4-story 

buildings, and operators can choose to 

end Class 2 and 3 boundaries up to 220 

yards upstream and downstream from 

the furthest edges of a group or 

‘‘cluster’’ of buildings.12 ‘‘Clustering,’’ 

therefore, is a means of reducing the 

length of a Class 2, 3, or 4 location in 

a sliding mile unit that requires a Class 

2, 3, or 4 location; in other words, it 

allows operators to cluster or reduce the 

amount of pipe that is subject to the 

requirements of a higher class 

location.13

It is important to note that while 

clustering allows for the adjustment of 

the length of class locations in certain 

areas, it does not change the length of 

class location units themselves nor the 

method by which class location units 

are determined. Further, clustering does 

not exclude ‘‘buildings for human 

occupancy’’ in a class location unit/ 

sliding mile, so all buildings within a 

specified class location unit must be 

protected by the maximum class 

location level that was determined for 

the entire class location unit. This 

concept becomes especially important 

when other buildings for human 

occupancy are built within a class 

location unit/sliding mile where a 

cluster exists and an operator has 

adjusted the class location length to 

exclude certain lengths of pipe outside 

of the cluster area. 

For instance, assume there is a class 

location unit/sliding mile containing 47 

homes close to one another. The class 

location unit would be a Class 3 

location per the definition provided at 

§ 192.5(b). An operator can consider 

these homes a ‘‘cluster’’ and 

appropriately apply the adjustment at 

§ 192.5(c) so that the boundaries of the 

Class 3 location are 220 yards upstream 

and downstream from the furthest edges 

of the clustered homes (buildings for 

human occupancy). Therefore, while the 

entirety of the pipeline is in a Class 3 

class location unit, the only pipe subject 

to Class 3 requirements is the length of 

the cluster plus 220 yards on both sides 

of the cluster. The remaining pipe in the 

class location unit/sliding mile, the pipe 

that is outside of this clustered area, 

could therefore be operated at Class 1 

requirements rather than at the 

otherwise-required Class 3 

requirements. 

However, what would happen if new 

buildings were built within that sliding 

mile but away from that single cluster? 

If, per the example above, there is a 

cluster of 47 homes at one end of a class 

location unit/sliding mile, and 3 homes 

are built at the other end of the class 

location unit, the operator must count 

and treat those 3 homes as a second 

cluster, with the length of the cluster 

plus 220 yards on both sides of the 

cluster subject to Class 3 requirements. 

The pipeline between these two clusters 

would still be in a Class 3 location per 

its class location unit, as there would be 

50 homes within the sliding mile, but 

the pipeline between the clusters could 

be operated under Class 1 location 

requirements. If the 220-yard extensions 

of any two or more clusters intercept or 

overlap, the separate clusters must be 

considered a single cluster for purposes 

of applying the adjustment. 

An operator must use the clustering 

method consistently to ensure that all 

buildings for human occupancy within 

a class location unit are covered by the 

appropriately determined class location 

requirements. Any new buildings for 

human occupancy built in a class 

location unit where clustering has been 

used must also be clustered, whether 

they form a new, independent cluster or 

are added to the existing cluster. Note 

that even a single house could form the 

basis of a second cluster under this 

requirement, as all buildings within a 

specified class location unit must be 

protected by the maximum class 

location level that was determined for 

the entire class location unit. 

PHMSA’s interpretation to Air 

Products and Chemicals, Inc., issued on 

March 11, 2015,14 explains and 

diagrams this concept further. 

II. Changes in Class Location Due to 

Population Growth 

Class locations can change as the 

population living or working near a 

pipeline grows and, as outlined earlier, 

are specifically determined based on the 

density of dwellings within the 440- 

yard-wide (quarter-mile-wide) sliding 

mile down the pipeline centerline. Class 

locations are used to determine a 

pipeline’s design factor, which is a 

component of the design formula 

equation at § 192.105 and ultimately 

factors into the pressure at which the 

pipeline is operated. As population 

around a pipeline increases and the 

pipeline’s class location increases, the 

numeric value of the design factor 

decreases, which translates, via the 

formula at § 192.105, into a lower 

MAOP for the pipeline. To illustrate 

this, a Class 4 location containing a 

prevalence of 4-or-more-story buildings 

has a safety factor of 0.4, whereas a 

Class 2 location containing 11 to 45 

dwellings has a safety factor of 0.6. If a 

Class 2 location is very quickly 

developed to a point where there is a 

prevalence of 4-or-more story buildings, 

the corresponding difference in safety 

factor when the class location changes, 

from a 0.6 to a 0.4, equates to a 33% 

reduction in MAOP per the design 

formula equation. 

A change in class location requires 

operators to confirm safety factors and 

to recalculate the MAOP of a pipeline. 

If the MAOP per the newly determined 

class location is not commensurate with 

the present class location, current 

regulations require that pipeline 

operators (1) reduce the pipe’s MAOP to 

reduce stress levels in the pipe; (2) 

replace the existing pipe with pipe that 

has thicker walls or higher yield 

strength to yield a lower operating stress 

at the same MAOP; or (3) pressure test 

at a higher test pressure if the pipeline 

segment has not previously been tested 

at the higher pressure and for a 

minimum of 8 hours.15 Depending on 

the pipeline’s test pressure and whether 

it meets the requirements in §§ 192.609 

and 192.611 (‘‘Change in class location: 

Required study,’’ and ‘‘Change in class 

location: Confirmation or revision of 

maximum allowable operating 

pressure,’’ respectively), an operator can 

base the pipeline’s MAOP on a certain 

safety factor times the test pressure for 

the new class location as long as the 

corresponding hoop stress of the 

pipeline does not exceed certain 

percentages of the specified minimum 

yield strength (SMYS) of the pipe.16


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36864 Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules 

SMYS of the pipe in Class 2 locations, 60% of 

SMYS in Class 3 locations, or 50% of SMYS in 

Class 4 locations. 

17See Section IV of this document. In the context 

of this rulemaking, PHMSA has been considering 

issues related to class location requirements since 

publishing an ANPRM on the gas transmission 

regulations in 2011. Following that, PHMSA 

published a notice of inquiry soliciting comments 

on expanding gas IM program requirements and 

mitigating class location requirements (78 FR 

46560; August 1, 2013) and held a public meeting 

on the notice of inquiry topics on April 16, 2014 

(both actions under Docket Number PHMSA–2013– 

0161). PHMSA also received comments on the 

issues discussed in this rulemaking in the docket 

titled ‘‘Transportation Infrastructure: Notice of 

Review of Policy, Guidance, and Regulations 

Affecting Transportation Infrastructure Projects’’ 

which was noticed in the Federal Register on June 

8, 2017 (82 FR 26734; Docket Number OST–2017– 

0057). 

18Operators did not outline the type of integrity 

assessments that would be appropriate from their 

perspective nor the factors that should be 

considered to determine whether a pipeline 

segment is fit for service (such as pipe, pipe seam, 

or coating conditions; O&M history; material 

properties; pipe depth of cover; non-destructive 

testing of girth welds; type pipe coatings used and 

if they shield cathodic protection; seam type; failure 

or leak history; and pressure testing or acceptance 

criteria and any re-evaluation intervals). 

19Special permit conditions are implemented to 

mitigate the causes of gas transmission incidents 

and are based on the type of threats pertinent to the 

pipeline. The conditions are generally more heavily 

weighted on identifying: Material, coating and 

cathodic protection issues, pipe wall loss, pipe and 

weld cracking, depth of pipe cover, third party 

damage prevention, marking of the pipeline and 

pipeline right-of-way patrols, pressure tests and 

documentation, data integration of integrity issues, 

and reassessment intervals. 

20Examples of PHMSA’s class location special 

permit conditions can be found at: https://

primis.phmsa.dot.gov/classloc/docs/SpecialPermit_

ExampleClassLocSP_Conditions_090112_

draft1.pdf, and more information about PHMSA’s 

special permit process for class location changes 

can be found at: https://primis.phmsa.dot.gov/ 

classloc/documents.htm 

21Cathodic protection is a technique used to 

control the corrosion of a metal surface by making 

it the cathode of an electrochemical cell. This can 

be achieved with a special coating on the external 

surface of the pipeline along with an electrical 

system and anodes buried in the ground or with a 

‘‘sacrificial’’ or galvanic metal acting as an anode. 

In these systems, the anode will corrode before the 

protected metal will. 

22Federal Register (69 FR 38948, June 29, 2004). 

Additional guidance is provided online at: http:// 

primis.phmsa.dot.gov/classloc/index.htm. Public 

notices were published in Federal Register: 69 FR 

22115 and 69 FR 38948, dated April 23, 2004 and 

June 29, 2004: Docket No. RSPA–2004–17401— 

Pipeline Safety: Development of Class Location 

Change Waiver (Special Permit). 

This is often referred to as a ‘‘one-class 

bump,’’ as an operator can use this 

method when class locations change 

from a Class 1 to 2, a Class 2 to a 3, or 

a Class 3 to a 4. 

The §§ 192.5 and 192.611 

requirements to change-out pipe, repressure test, or de-rate pipe to a lower 

MAOP when population growth occurs 

and requires a class location change are 

the most significant reasons that 

operators request that class locations be 

revised or eliminated. Throughout the 

process of considering class location 

changes,17 comments PHMSA received 

from the trade associations state that 

reducing a pipeline’s operating pressure 

below that at which the pipeline 

historically operated may unacceptably 

restrict deliveries to natural gas 

customers. These same commenters 

suggest that pressure testing pipelines 

may be practicable in select cases, but 

the test pressure required for higher 

class locations may exceed what a 

pipeline is designed to accommodate. 

Operators also contend that they should 

not have to change out pipe when a 

class location change occurs if the 

operator can prove that the pipe 

segment is fit for service through 

integrity assessments.18

III. Class Location Change Special 

Permits 

As population growth occurs around 

pipelines that were formerly in rural 

areas, some operators have applied for 

special permits to prevent the need for 

pipe replacement or pressure reduction 

when the class location changes. A 

special permit is an order issued under 

§ 190.341 that waives or modifies 

compliance with regulatory 

requirements if the pipeline operator 

requesting it demonstrates a need and 

PHMSA determines that granting the 

special permit would be consistent with 

pipeline safety. PHMSA performs 

extensive technical analysis on special 

permit applications and typically grants 

special permits on the condition that 

operators will perform alternative 

measures to provide an equal or greater 

level of public safety. PHMSA publishes 

a notice and request for comment in the 

Federal Register for each special permit 

application received and tracks issued, 

denied, and expired special permits on 

its website. 

Since 2004, PHMSA has approved 

over 15 class location special permits 

based on operators adopting additional 

conditions, including certain operating 

safety criteria and periodic integrity 

evaluations.19 20 Generally, the 

additional conditions PHMSA requires 

are designed to identify and mitigate 

integrity issues that could threaten the 

pipeline segment and cause failure, 

especially given the fact that the 

majority of class location special 

permits it receives and reviews are for 

older pipelines that may have 

manufacturing, construction, or ongoing 

maintenance issues, such as seam or 

pipe body cracking, poor external 

coating, insufficient soil cover, lack of 

material records, dents, or repairs not 

made to class location design safety 

factors. 

Typically, PHMSA requires operators 

to incorporate the affected segments into 

the company’s O&M procedures and 

integrity management plan, perform 

additional assessments for threats to the 

pipeline segments identified during an 

operator’s risk assessment, perform 

additional cathodic protection 21 and 

corrosion control measures, and repair 

any discovered anomalies to a specified 

schedule. Therefore, the additional 

monitoring and maintenance 

requirements PHMSA prescribes 

through this process help to ensure the 

integrity of the pipe and protection of 

the population living near the pipeline 

segment at a comparable margin of 

safety and environmental protection 

throughout the life of the pipe compared 

to the regulations as written. The class 

location change special permits that 

PHMSA has granted have allowed 

operators to continue operating the 

pipeline segments identified under the 

special permits at the current MAOP 

based on the previous class locations. 

PHMSA notes that it developed its class 

location special permit process by 

adapting Integrity Management (IM) 

concepts and published the typical 

considerations for class location change 

special permit requests in the Federal 

Register in 2004.22 Based on its 

experiences when renewing some of the 

earliest class location change special 

permits, PHMSA has extended the 

expiration date of its class location 

change special permits from 5 years to 

10 years. This extension should provide 

additional regulatory certainty to 

operators that apply for these permits. 

Further, throughout the renewal process 

of existing special permits, PHMSA has 

not significantly changed the original 

conditions imposed on individual 

operators. While PHMSA can make 

modifications to its special permit 

conditions when it is in the interest of 

safety and the public to do so, PHMSA 

has determined that the present special 

permit conditions and process are 

consistent with public safety. 

A. Special Permit Conditions 

In the special permit conditions and 

criteria PHMSA published in the 

Federal Register on June 29, 2004, 

PHMSA outlines several ‘‘threshold 

conditions’’ pipelines must meet to be 

considered for a special permit when 

class locations change. For instance, 

PHMSA does not consider any pipeline 

segments for a special permit where the 

class location those segments are in 

changes to a Class 4 location. Typically, 

PHMSA receives special permit requests 


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23Federal Register (78 FR 46560, August 1, 2013). 

24Regarding these questions, PHMSA received 30 

comment letters, available at www.regulations.gov 

at docket PHMSA–2013–0161. 

for pipeline segments where the class 

location is changing from Class 1 to 

Class 3. PHMSA also does not consider 

for class location change special permits 

any segments that have bare pipe or 

wrinkle bends. Other manufacturingand construction-related items PHMSA 

considers include whether the 

applicable segments have certain seam 

types that may be more prone to defects 

and failures, whether the pipe has 

certain coating types that provide an 

adequate level of cathodic protection, 

and the design strength of the pipe. 

There are also operation and 

maintenance factors that PHMSA 

considers when evaluating pipeline 

segments for class location change 

special permit feasibility. For example, 

PHMSA doesn’t consider for a Class 1 

to Class 3 location change special 

permit any pipe segments that operate 

above 72 percent SMYS. Operators also 

need to produce a hydrostatic test 

record showing the segment was tested 

to 1.25 times the MAOP. Also, operators 

are required to have pipe material 

records to document the pipelines 

diameter, wall thickness, strength, seam 

type and coating type. For operators 

who do not have these records, PHMSA 

requires they make these records per the 

special permit conditions. PHMSA often 

requires operators to operate each 

applicable segment at or below its 

existing MAOP as well. 

As part of the special permit 

conditions, operators are required by 

PHMSA to incorporate the applicable 

pipeline segments into their IM program 

and inspect them on a regular basis 

according to the operator’s procedures. 

As an extension of this requirement, 

operators must perform in-line 

inspections on the applicable segments, 

and the segments must not have any 

significant anomalies that would 

indicate any systemic problems. 

Additionally, PHMSA’s published 

special permit criteria defines a ‘‘waiver 

inspection area,’’ also known as a 

‘‘special permit inspection area,’’ as up 

to 25 miles of pipe on either side of the 

applicable segment. Operators must 

incorporate these areas into their IM 

programs as well and inspect and repair 

them per the operator’s IM program 

procedures. Some of the factors PHMSA 

uses when deciding the length of special 

permit inspection areas are based on 

factors including what class location the 

surrounding pipe is in and whether 

class location ‘‘clustering’’ has been 

used. For both the special permit 

segments and the special permit 

inspection areas, PHMSA also typically 

requires operators to perform 

assessments and surveys to identify 

pipe that may be susceptible to certain 

issues, especially seam or cracking 

issues in the pipe seam or pipe body, 

based on the coating type, vintage, or 

manufacturing of the pipe. Pipelines in 

the special permit segments or in the 

special permit inspection areas that 

have had a leak or failure history are 

also taken into consideration when 

PHMSA develops an individual special 

permit’s conditions so as to prevent 

similar issues in the future. Further, 

PHMSA looks at the enforcement 

history of an operator applying for a 

special permit as a benchmark for how 

the operator has followed the Federal 

Pipeline Safety Regulations when 

developing the conditions following a 

special permit request. 

In class location change special 

permit requests, PHMSA also ensures 

that integrity threats to pipelines in 

special permit segments and special 

permit inspection areas are addressed in 

operator operations and management 

plans, including a systematic, ongoing 

program to review and remediate 

pipeline safety concerns. Some of the 

typical integrity and safety threats 

PHMSA would expect operators to 

address include pipe coating quality, 

cathodic protection effectiveness, stress 

corrosion and seam cracking, and any 

long-term pipeline system flow 

reversals. To this end, PHMSA often 

requires coating condition surveys, the 

remediation of coating, and cathodic 

protection systems for pipelines where 

the operator has requested a class 

location change special permit. Any 

data gathered on the special permit area 

and special permit inspection area 

would have to be incorporated into the 

operator’s greater IM program. 

PHMSA incorporates these conditions 

into class location change special permit 

requests to ensure that operators meet or 

exceed the threshold requirements with 

equivalent safety to the provisions in 

the Federal Pipeline Safety Regulations 

that are being waived and ensure that 

granting the special permit will not be 

inconsistent with safety. 

IV. Pipeline Safety, Regulatory 

Certainty, and Job Creation Act of 

2011—Section 5 

On January 3, 2012, the Pipeline 

Safety, Regulatory Certainty, and Job 

Creation Act of 2011 (Pub. L. 112–90) 

was enacted. Among the many 

provisions of the Act, Section 5 required 

PHMSA to evaluate whether IM system 

requirements, or elements thereof, 

should be expanded beyond highconsequence areas (HCA) and, with 

respect to gas transmission pipeline 

facilities, whether applying IM program 

requirements, or elements thereof, to 

additional areas would mitigate the 

need for class location requirements. 

PHMSA was required to report the 

findings of this evaluation to Congress 

and was authorized to issue regulations 

pursuant to the findings of the report 

following a prescribed review period. 

A. 2013 Notice of Inquiry: Class 

Location Requirements 

In August 2013, through a Notice of 

Inquiry, PHMSA solicited comments on 

whether expanding IM requirements 

would mitigate the need for class 

locations in line with the Section 5 

mandate of the 2011 Pipeline Safety 

Act.23 Several topics were discussed, 

including whether class locations 

should be eliminated and a single 

design factor used, whether design 

factors should be increased for higher 

class locations, and whether pipelines 

without complete material records 

should be allowed to use a single design 

factor if class locations were to be 

eliminated.24

There was broad consensus among 

PHMSA’s stakeholders that eliminating 

class locations entirely would not lead 

to improvement to pipeline safety. 

Further, commenters noted that 

establishing a single design factor in 

lieu of class location designations might 

be too complicated to implement. Many 

commenters noted that any changes in 

class location requirements would 

impact not only the classifications of 

many pipelines but would also possibly 

create several unintended consequences 

within part 192, as the class location 

requirements are referenced or built 

upon throughout the natural gas 

regulations. 

Several industry trade groups had 

suggestions for changing the class 

location regulations, and these 

suggestions were developed further 

through subsequent discussions at 

advisory committee meetings and at 

public workshops. The Interstate 

Natural Gas Association of America 

(INGAA) noted that IM should be 

extended beyond HCAs with the caveat 

that PHMSA should examine the effects 

of such a change on other areas of the 

pipeline safety regulations. Along with 

this, it suggested that PHMSA revise 

certain operations and maintenance 

requirements that may no longer be 

necessary given technological advances 

and IM activities. 


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25The Pipeline Advisory Committees are 

statutorily mandated advisory committees that 

advise PHMSA on proposed safety standards, risk 

assessments, and safety policies for natural gas and 

hazardous liquid pipelines (49 U.S.C. 60115). These 

Committees were established under the Federal 

Advisory Committee Act (Pub. L. 92–463, 5 U.S.C. 

app. 1–16) and the Federal Pipeline Safety Statutes 

(49 U.S.C. chap. 601–603). Each committee consists 

of 15 members, with membership divided among 

Federal and State agency representatives, the 

regulated industry, and the public. 

26Meeting presentations are available online at: 

http://primis.phmsa.dot.gov/meetings/ 

MtgHome.mtg?mtg=95. 

27PHMSA notes that the special permit process 

is outlined in § 190.341 and is no different for the 

class location regulations than for any other 

pipeline safety regulation. Of the 18 special permits 

up for renewal from 2010–2017, 9 of them were for 

class location changes. When reviewing the class 

location change permits up for renewal, PHMSA 

found no safety reason to extensively modify any 

of the prior permits and made no major revisions 

to any of the previously imposed safety conditions. 

28The potential impact radius for the ruptured 

pipe segment involved in the San Bruno incident 

was calculated at 414 feet. However, the NTSB, in 

its accident report (NTSB/PAR–11/01), noted that 

the subsequent fire damage extended to a radius of 

about 600 feet from the blast center. 

29Those 18 categories were as follows: Baseline 

Engineering and Record Assessments—Girth Weld 

Assessment, Casing Assessment, Pipe Seam 

Assessment, Field Coating Assessment, Cathodic 

Protection, Interference Currents Control, Close 

Interval Survey, Stress Corrosion Cracking 

Assessments, In-line Inspection Assessments, Metal 

Loss Anomaly Management, Dent Anomaly 

Management, Hard Spots Anomaly Management. 

Ongoing Requirements—Integrity Management 

Program, Root Cause Analysis for Failure or Leak, 

Line Markers, Patrols, Damage Prevention Best 

Practices, Recordkeeping & Documentation. 

30See also: http://primis.phmsa.dot.gov/classloc/ 

index.htm. 

31https://www.regulations.gov/ 

document?D=PHMSA-2011-0023-0153. 

B. 2014 Pipeline Advisory Committee 

Meeting, Class Location Workshop, and 

Subsequent Comments 

On February 25, 2014, PHMSA hosted 

a joint meeting of the Gas and Liquid 

Pipeline Advisory Committees.25 At that 

meeting, PHMSA updated the 

committees on its activities regarding 

the Section 5 mandate of the 2011 

Pipeline Safety Act, and committee 

members and members of the public 

provided their comments. 

INGAA, reinforcing its comments on 

the 2013 Notice of Inquiry, noted that 

the original class location definitions in 

ASME B31.8 were intended to provide 

an increased margin of safety for 

locations of higher population density 

and stated that IM is a much better risk 

management tool than class locations. 

INGAA reiterated that it intends for its 

members to perform elements of IM on 

pipelines outside of HCAs. 

On April 16, 2014, PHMSA sponsored 

a Class Location Workshop to solicit 

comments on whether applying the gas 

pipeline IM program requirements 

beyond HCAs would mitigate the need 

for gas pipeline class location 

requirements. Presentations were made 

by representatives from PHMSA, the 

National Energy Board of Canada (NEB), 

National Association of Pipeline Safety 

Representatives (NAPSR), pipeline 

operators, industry groups, and public 

interest groups.26

During the workshop, INGAA 

representatives noted that the current 

class location regulations require 

changes that result in the replacement of 

‘‘good pipe,’’ and the special permit 

process for class location changes 

should be embedded in part 192. 

Representatives from the American Gas 

Association (AGA) noted that applying 

the current class location change 

requirements can cost more than $1 

million per change. AGA claimed the 

special permit process for class location 

changes is burdensome, the renewal 

process is increasingly complex, and the 

outcome is uncertain.27 Therefore, AGA 

suggested eliminating the special permit 

process for class location changes and 

incorporating specific requirements for 

special permits into part 192 as part of 

the base regulations. AGA 

recommended two approach methods, 

one based on IM and the other using the 

current class location approach. 

Public interest groups including 

Accufacts and the Pipeline Safety Trust 

(PST) pointed out how deeply the 

concept of class locations is embedded 

in part 192, while also noting that IM 

requirements and class locations 

overlap in densely populated areas to 

provide a redundant, but necessary, 

safety regime. The PST also suggested 

that, in time, the older class location 

method potentially could be replaced 

with an IM method for regulation. 

However, the PST noted that incidents 

and data suggest there is room for 

improvement in the IM regulations, as 

data shows higher incident rates in 

HCAs than in non-HCAs, and noted that 

pipe installed after 2010 has a higher 

incident rate than pipe installed a 

decade earlier. Similarly, Accufacts 

noted that the incident at San Bruno, 

CA, exposed weaknesses in the 

operator’s IM program and 

demonstrated that the consequences 

resulting from the incident spread far 

beyond the potential radius in which 

they were expected to occur.28

Therefore, Accufacts suggested that 

shifting the class location approach to 

solely an IM approach might decrease 

the protection of public safety. 

Following the Class Location 

Workshop, INGAA submitted additional 

comments to the docket stating that 

advancements in IM technology and 

processes have superseded the need for 

mandatory pipe replacement following a 

class location change. It noted that, in 

the past, it was logical to replace a 

pipeline when class locations changed 

because of the widespread belief that 

thicker pipe would take longer to 

corrode and would withstand greater 

external forces, such as damage from 

excavators, before failure. However, 

given current technology, improvements 

in pipe quality, and ongoing regulatory 

processes such as IM, operators can 

mitigate most threats without the need 

for pipe replacement. Therefore, INGAA 

offered an approach to class locations 

changes to not require pipe replacement 

for existing pipelines if pipe segments 

meet certain requirements that are in 

line with current IM requirements. 

Specifically, INGAA suggested that 

pipelines meeting a ‘‘fitness for service’’ 

standard in 18 categories of 

requirements could address potential 

safety concerns and preclude the need 

for pipe replacement.29 The 18 

categories are very similar to the special 

permit conditions that PHMSA uses for 

a Class 1 to 3 location special permit as 

noted in the 2004 Federal Register 

notice.30

C. 2016 Class Location Report 

The Pipeline Safety, Regulatory 

Certainty, and Job Creation Act of 2011 

required that PHMSA evaluate whether 

IM should be expanded beyond HCAs 

and whether such expansion would 

mitigate the need for class location 

requirements. In its report titled 

‘‘Evaluation of Expanding Pipeline 

Integrity Management Beyond HighConsequence Areas and Whether Such 

Expansion Would Mitigate the Need for 

Gas Pipeline Class Location 

Requirements,’’ 31 which was submitted 

to Congress in April 2016 concurrently 

with the publication of the NPRM titled 

‘‘Safety of Gas Transmission and 

Gathering Pipelines’’ (81 FR 20722), 

PHMSA noted that the application of IM 

program elements, such as assessment 

and remediation timeframes, beyond 

HCAs would not warrant the 

elimination of class locations. 

PHMSA notes that class locations 

affect all gas pipelines and are integral 

to determining MAOPs; design 

pressures; pipe wall thickness; valve 

spacing; HCAs, in certain cases; and 

O&M inspection, surveillance, and 

repair intervals. While IM measures are 

a critical step towards pipeline safety 

and are important to mitigate risk, the 

assessment and remediation of defects 

do not adequately compensate for these 

other aspects of class locations. Thus, as 

outlined in the report, PHMSA 

determined the existing class location 


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32 In its comments following the public workshop 

on Class Locations in 2014, INGAA noted that, after 

further analysis, it appears that applying the 

Potential Impact Radius (PIR) method to existing 

pipelines may be unworkable. 

33PHMSA has documented pipe material lowstrength issues through an advisory bulletin and the 

following website link: http://

primis.phmsa.dot.gov/lowstrength/index.htm. 

34 IM and operational procedures and practices 

were issues in the Pacific Gas & Electric (PG&E) San 

Bruno, CA, rupture in September 2010 and the 

Enbridge Marshall, MI, rupture in July 2010. 

35PHMSA issued Advisory Bulletins ADB–11–01 

and ADB–2012–10 to operators regarding IM 

meaningful metrics and assessments on January 10, 

2011, and December 5, 2012, respectively, which 

can be reviewed at: http://phmsa.dot.gov/pipeline/ 

regs/advisory-bulletin. 

36PHMSA issued Advisory Bulletin, ADB–12–06, 

concerning documentation of MAOP on May 7, 

2012, which can be reviewed at: http://

phmsa.dot.gov/pipeline/regs/advisory-bulletin. 

37Also note PHMSA’s Advisory Bulletin titled 

‘‘Deactivation of Threats,’’ issued March 16, 2017 

(82 FR 14106). 

38PHMSA requests further substantiation of this 

estimate. In extrapolating the national data, PHMSA 

estimates this number is the cost incurred for all 

pipe replacement projects on transmission lines, 

not just those projects triggered in response to class 

location changes. 

39PHMSA notes that ILI and in-the-ditch 

evaluation technologies for crack identification are 

under development and could further be improved. 

requirements were appropriate for 

maintaining pipeline safety and should 

be retained. Therefore, any revisions to 

the class location requirements would 

have to be forward-looking (i.e., 

applying to pipelines constructed after a 

certain effective date) and would have 

to comport with the existing regulatory 

regime to provide commensurate safety 

if any changes are made to aspects of 

pipeline safety related to design and 

construction, which is where key safety 

benefits of class locations are realized.32

As a part of the continuing discussion 

on class location changes and 

subsequent pipe replacement, PHMSA 

summarized at the end of the Class 

Location Report the concerns operators 

expressed regarding the cost of 

replacing pipe in locations that change 

from a Class 1 to a Class 3 location or 

a Class 2 to a Class 4 location. As 

discussed throughout the document, 

operators submitted that the safe 

operation of pipelines constructed in 

Class 1 locations that later change to 

Class 3 locations can be achieved using 

current IM practices. 

However, over the past decade, 

PHMSA observed problems with pipe 

and fitting manufacturing quality, 

including low-strength material; 33

construction practices; welding; field 

coating practices; IM assessments and 

reassessment practices; 34 35 and record 

documentation practices.36 37 These 

issues give PHMSA pause in 

considering approaches allowing a twoclass bump (Class 1 to 3 or Class 2 to 

4) without requiring pipe replacement, 

especially for higher-pressure 

transmission pipelines. 

PHMSA stated in the conclusion of its 

Class Location Report that it would 

further evaluate the feasibility and the 

appropriateness of alternatives to 

address issues pertaining to pipe 

replacement requirements, continue to 

reach out to and consider input from all 

stakeholders, and consider future 

rulemaking if a cost-effective and safetyfocused approach to adjusting specific 

aspects of class location requirements 

could be developed to address the 

issues identified by industry. In doing 

so, PHMSA would evaluate alternatives 

in the context of other issues it is 

addressing related to new construction 

quality- and safety-management systems 

and will also consider inspection 

findings, IM assessment results, and 

lessons learned from past incidents. 

Therefore, PHMSA has initiated this 

rulemaking to gain further information 

on analyzing the current requirements 

resulting in pipe replacement and 

alternatives to that practice. 

V. INGAA Submission on Regulatory 

Reform—Proposal To Perform IM 

Measures in Lieu of Pipe Replacement 

When Class Locations Change 

On July 24, 2017, INGAA submitted 

comments to a DOT docket regarding 

regulatory review actions (Docket No. 

OST–2017–0057). In its submission, 

INGAA estimated that gas transmission 

pipeline operators incur annual costs of 

$200–$300 million 38 nationwide 

replacing pipe solely to satisfy the class 

location change regulations and 

requested PHMSA consider revising the 

current class location change 

regulations to include an alternative 

beyond pressure reduction, pressure 

testing, or pipe replacement. 

INGAA’s proposed alternate approach 

focuses on recurring IM assessments 

that would leverage advanced 

assessment technologies to determine 

whether the pipe condition warrants 

pipe replacement in areas where the 

class location has changed. INGAA 

states that such an approach would 

further promote IM processes and 

principles throughout the nation’s gas 

transmission pipeline network, improve 

economic efficiency by reducing 

regulatory burden, and help fulfill the 

purposes of Section 5 of the 2011 

Pipeline Safety Act. 

INGAA claims that the current 

alternatives to pipe replacement 

following a class location change do not 

reflect the substantial developments in 

IM processes, technologies, and 

regulations over the past 15-plus years. 

More specifically, in-line inspection 

(ILI) technologies, such as highresolution magnetic flux leakage tools, 

can precisely assess the presence of 

corrosion and other potential defects, 

allowing an operator to establish 

whether a pipeline segment requires 

remediation or replacement.39

INGAA further notes that PHMSA’s 

proposed rulemaking titled ‘‘Safety of 

Gas Transmission and Gathering 

Pipelines’’ aims to expand IM 

assessments to newly defined 

‘‘Moderate Consequence Areas’’ 

(proposed § 192.710), and such an 

expansion provides a framework for 

developing an alternative for managing 

class location changes. INGAA suggests 

that the costs saved from avoiding pipe 

replacement using such an alternative 

could mitigate, to some degree, part of 

the costs of the proposed rulemaking. 

Additionally, INGAA notes that the 

proposed rulemaking contains several 

new provisions that will require 

operators to better manage the integrity 

of their pipelines by implementing more 

preventative and mitigative measures to 

manage the threat of corrosion. INGAA 

states that the inclusion of such 

corrosion control measures as a part of 

a program for managing the integrity of 

pipeline segments, including ones that 

have experienced class location 

changes, would further justify the 

development of an IM-focused 

alternative to class location changes. 

Based on those statements, INGAA 

recommends PHMSA develop an 

alternative approach to § 192.611 that 

leverages the proposed § 192.710 for 

areas outside of HCAs and the IM 

requirements at § 192.921 to require 

recurring IM assessments and 

incorporation of those affected pipeline 

segments into IM programs. Further, 

INGAA suggests this approach require 

operators to reconfirm pipeline MAOP 

in a changed class location for any 

pipeline segment without traceable, 

verifiable, and complete records of a 

hydrostatic pressure test supporting the 

segment’s previous MAOP. 

PHMSA acknowledges that the class 

location change regulations predate the 

development of modern pipeline 

inspection technology such as ILI, 

above-ground surveys, and modern 

integrity management processes. In fact, 

it wasn’t until the mid-1990s that 

PHMSA, following models from other 

industries such as nuclear power, 

started to explore whether a risk-based 

approach to regulation could improve 

public and environmental safety. 

PHMSA finalized the IM regulations for 

gas transmission pipelines on December 


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40 68 FR 69778; Pipeline Safety: Pipeline Integrity 

Management in High Consequence Areas (Gas 

Transmission Pipelines). 

41PHMSA has met with operators constructing 

new pipelines on several occasions to discuss 

issues found during inspection. To reach out to all 

members of the pipeline industry, PHMSA hosted 

a public workshop in collaboration with our State 

partners, the Federal Energy Regulatory 

Commission (FERC) and Canada’s National Energy 

Board (NEB) in April 2009. The objective of the 

workshop was to inform the public, alert the 

industry, review lessons learned from inspections, 

and to improve new pipeline construction practices 

prior to the 2009 construction season. This website 

makes available information discussed at the 

workshop and provides a forum in which to share 

additional information about pipeline construction 

concerns. This workshop focused on transmission 

pipeline construction. http://primis.phmsa.dot.gov/ 

construction/index.htm. 

42Note that the potential impact radius (PIR) in 

Integrity Management (IM) does not give any 

criteria to establish the pipelines operating 

pressure, anomaly repair criteria, safety surveys for 

leaks, 3rd party encroachments, etc. When Class 

locations change (from additional dwellings for 

human occupancy) from one-level to a higher level 

there are cut-off levels that may require a different 

design factor, pressure test, or maintenance criteria. 

For pipe to be replaced the class location change 

would have to be from a Class 1 to 3 or Class 2 to 

4, which is a large increase in dwellings along the 

pipeline. 

15, 2003,40 in response to tragic 

incidents on pipelines in Bellingham, 

WA, in 1999 and near Carlsbad, NM, in 

2000, which killed 3 people and 12 

people, respectively. The IM regulations 

designated HCAs where operators 

would perform periodic assessments of 

the condition of their pipelines and 

make necessary repairs within specific 

timeframes if discovered anomalies met 

certain criteria. More specifically, the 

IM regulations outline the risk-based 

processes that pipeline operators must 

use to identify, prioritize, assess, 

evaluate, repair, and validate the 

integrity of gas transmission pipelines. 

For many years, the pipeline industry 

used internal steel brush devices 

(‘‘cleaning pigs’’) moved by product 

flow to clean the inside of their 

pipelines. This pigging concept was 

later adapted through the application of 

technology to measure and record 

irregularities in the pipe and welds that 

may represent corrosion, cracks, 

deformations, and other defects. Now 

operators use ILI technology (‘‘smart 

pigging or ILI’’) as a backbone of the 

modern IM program. ILI tools are 

inserted into pipelines at locations, such 

as near valves or compressor stations, 

that have special configurations of pipes 

and valves where the ILI tools can be 

loaded into launchers, the launchers can 

be closed and sealed, and the flow of the 

product the pipeline is carrying can be 

directed to launch the tool down the 

pipeline. A similar setup is located 

downstream where the tool is directed 

out of the main line into a receiver so 

that an operator can remove the tool and 

retrieve the recorded data for analysis 

and reporting. ILI tools come in several 

different varieties that have distinct 

advantages and disadvantages over 

other methods of pipeline assessment. 

For instance, while some ILI tools might 

be able to reliably determine whether a 

pipeline has internal corrosion, the 

same tool might not be able to 

determine whether the pipeline has any 

crack indications. In selecting the tools 

most suitable for inline inspections, 

pipeline operators must know the type 

of threats that are applicable to the 

pipeline segment. Threats that ILI tools 

can identify typically include existing 

pipe wall thickness, pipe wall changes, 

pipe wall loss, cracking, and dents. 

At the time the class location 

regulations were promulgated, it was 

logical to replace a pipeline when 

population growth resulted in a class 

location change in order to restore the 

safety margin appropriate for that 

location because the industry did not 

have the technology that is available 

today to learn the in situ material 

condition of the pipe. Further, since the 

existing pipe would not achieve a 

similar safety margin as replaced pipe, 

operators would need to use applicable 

inspection technology and pressure 

testing to ensure pipe has the correct 

wall thickness; strength; seam 

condition; toughness; no detrimental 

cracking or corrosion in the pipe body 

or seam; and a pipe coating that has not 

deteriorated or shields cathodic 

protection currents to allow corrosion or 

cracking issues such as girth weld 

cracking, stress corrosion cracking, or 

selective seam weld corrosion. 

Currently, operators are not required 

to inspect pipelines or otherwise 

perform IM on those portions of 

pipelines unless they are within high 

consequence areas (HCAs) or the 

operator otherwise voluntarily assesses 

them and performs remediation 

measures for threats to the pipeline. As 

such, while prudent operators may 

know the characteristics and conditions 

of their pipelines outside of HCAs and 

can be confident that they can manage 

class location change expectations 

through the performance of IM 

measures, some operators may not. 

PHMSA notes that while class 

locations and HCAs both provide 

additional protection to areas with high 

population concentrations, they were 

designed for different purposes. Unlike 

class locations, which provide blanket 

levels of safety throughout the nation’s 

pipeline network at all locations by 

driving MAOP and design, construction, 

testing, and O&M requirements, the 

purpose of the IM regulations is to 

provide a structure for operators to 

focus their resources on improving 

pipeline integrity in the areas where a 

failure would have the greatest impact 

on public safety. Whereas over time the 

safety margins that class locations 

provide can be reduced due to corrosion 

or other types of pipe degradation, IM 

requirements provide a continuing 

minimum safety margin for more 

densely populated areas because 

operators are required to inspect and 

repair those applicable pipelines at a 

minimum of every 7 years and more 

frequently based upon risk assessments 

of threats to the segment in the HCA. 

PHMSA acknowledges that applying 

modern IM assessments and processes 

could potentially be a comparable 

alternative to pipe change-outs. PHMSA 

notes that if operators perform integrity 

assessments on significant portions of 

non-HCA pipe mileage, PHMSA could 

further consider operators using such 

assessments to determine whether pipe 

in a changed class location is fit for 

service rather than having to replace it. 

PHMSA is concerned, however, that 

some issues that result in pipeline 

failures, including poor construction 

practices 41 and operational 

maintenance threats, are not always 

being properly assessed and mitigated 

by operators, whether due to lack of 

technology or other causes. Further, as 

the incident at San Bruno in 2010 

showed, operators may not have 

traceable, verifiable, and complete 

records of pipe properties, such as pipe 

material yield strength, pipe wall 

thickness, pipe seam type, pipe and 

seam toughness, and coating quality, 

that are critical and necessary for IM 

processes and pipeline safety in Class 3 

and 4 locations and HCAs where there 

are higher population densities. PHMSA 

also points out that there might be 

instances where a pipeline may be in 

‘‘good condition’’ from a visual 

standpoint, but it may not have the 

initial pipe manufacturing, pipe 

strength, construction quality, and O&M 

history requirements that add the extra 

level of safety required by the 

regulations for the higher population 

density area and the MAOP.42 Section 

192.611 already allows a ‘‘one-class 

location’’ bump for pipeline class 

locations that are in satisfactory 

physical condition and have the 

required pressure test. 

Because of these factors, PHMSA 

seeks comment on the potential safety 

consequences of altering the current 

class location methodology and moving 

to an IM-only method in certain areas. 


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Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules 36869 

43Sections involving class location requirements 

include §§ 192.5, 192.609, 192.611, 192.619 and 

192.620. 

44Section 192.933 has anomaly repair 

requirements based upon a predicted failure 

pressure being less than or equal to 1.1 times the 

MAOP. 

VI. Questions for Consideration 

PHMSA is requesting comments and 

information that will be used to 

determine if revisions should be made 

to the Federal Pipeline Safety 

Regulations regarding the current 

requirements operators must meet when 

class locations change. The list of 

questions below is not exhaustive and 

represents an effort to help in the 

formulation of comments. Any 

additional information that commenters 

determine would be beneficial to this 

discussion is also welcomed. 

Q1—When the population increases 

along a pipeline route that requires a 

class location change as defined at 

§ 192.5, should PHMSA allow pipe 

integrity upgrades from Class 1 to Class 

3 locations by methods other than pipe 

replacement or special permits? 43 Why 

or why not? 

1a.—Should part 192 continue to 

require pipe integrity upgrades when 

class locations change from Class 1 to 

Class 3 locations or Class 2 to 4 

locations? Why or why not? 

1b.—Should part 192 continue to 

require pipe integrity upgrades from 

Class 1 to Class 3 locations for the 

‘‘cluster rule’’ (see § 192.5(c)) when 10 

or fewer buildings intended for human 

occupancy have been constructed along 

the pipeline segment? Why or why not? 

1c.—Should part 192 continue to 

require pipe integrity upgrades for 

grandfathered pipe (e.g., pipe segments 

without a pressure test or with an 

inadequate pressure test, operating 

pressures above 72% SMYS, or 

inadequate or missing material records; 

see § 192.619(c))? Why or why not? 

Q2—Should PHMSA give operators 

the option of performing certain IM 

measures in lieu of the existing 

measures (pipe replacement, lower the 

operating pressure, or pressure test at a 

higher pressure; see § 192.611) when 

class locations change from Class 1 to 

Class 3 due to population growth within 

the sliding mile? Why or why not? 

2a.—If so, what, if any, additional 

integrity management and maintenance 

approaches or safety measures should 

be applied to offset the impact on safety 

these proposals might create? 

Q3—Should PHMSA give operators 

the option of performing certain IM 

measures in lieu of the existing 

measures (pipe replacement with a more 

conservative design safety factor or a 

combination of pressure test and lower 

MAOP) when class locations change 

due to additional structures being built 

outside of clustered areas within the 

sliding mile, if operators are using the 

cluster adjustment to class locations per 

§ 192.5(c)(2)? Why or why not? 

3a.—If so, what, if any, additional 

integrity management and maintenance 

approaches or safety measures should 

be applied to offset the impact on safety 

these proposals might create? 

3b.—At what intervals and in what 

timeframes should operators be required 

to assess these pipelines and perform 

remediation measures? 

Q4—If PHMSA allows operators to 

perform certain IM measures in lieu of 

pipe replacement when class locations 

change from Class 1 to Class 3, should 

some sort of ‘‘fitness for service’’ 

standard determine which pipelines are 

eligible? Why or why not? 

4a.—If so, what factors should make 

a pipeline eligible or ineligible? 

(i) Should grandfathered pipe (lacking 

records, including pressure test or 

material records) or pipe operating 

above 72% SMYS be eligible? Why or 

why not? 

(ii) Should pipe that has experienced 

an in-service failure, was manufactured 

with a material or seam welding process 

during a time or by a manufacturer 

where there are now known integrity 

issues or has lower toughness in the 

pipe and weld seam (Charpy impact 

value) be eligible? Should pipe with a 

failure or leak history be eligible? Why 

or why not? 

(iii) Should pipe that contains or is 

susceptible to cracking, including in the 

body, seam, or girth weld, or having 

disbonded coating or CP shielding 

coatings be eligible? Are there coating 

types that should disqualify pipe? 

Should some types of pipe, such as lapwelded, flash-welded, or low-frequency 

electric resistance welded pipe be 

ineligible? Should pipe where the seam 

type is unknown be ineligible? Why or 

why not? 

(iv) Should pipe with significant 

corrosion (wall loss) be eligible for 

certain IM measures, or should it be 

replaced? Why or why not? 

(v) Should anomalies be repaired 

similar to IM, allowed to grow to only 

a 10-percent safety factor 44

(§ 192.933(d)) before remediation in 

high population areas such as Class 2, 

3 and 4 locations, or should they have 

an increased safety factor for 

remediation should these class location 

factors be eliminated? Why or why not? 

(vi) Should pipe that has been 

damaged (dented) or has lost ground 

cover due to 3rd party activity 

(excavation or other) be eligible? Why or 

why not? 

(vii) Should pipe lacking cathodic 

protection due to disbonded coating be 

eligible? Why or why not? 

(viii) Should pipe with properties 

such as low frequency electric 

resistance weld (LF–ERW), lap welded, 

or other seam types that have a history 

of seam failure due to poor 

manufacturing properties or seam types 

that have a derating factor below 1.0 be 

eligible? Why or why not? 

4b.—Should PHMSA base any 

proposed requirements off its criteria 

used for considering class location 

change waivers (69 FR 38948; June 29, 

2004), including the age and 

manufacturing and construction 

processes of the pipe, and O&M history? 

Why or why not? 

4c.—In the 2004 Federal Register 

notice (69 FR 38948), PHMSA outlines 

certain requirements pipelines must 

meet to be eligible for waiver 

consideration, including no bare pipe or 

pipe with wrinkle bends, records of a 

hydrostatic test to at least 1.25 times 

MAOP, records of ILI runs with no 

significant anomalies that would 

indicate systemic problems, and 

agreement that up to 25 miles of pipe 

both upstream and downstream of the 

waiver location must be included in the 

operator’s IM program and periodically 

inspected using ILI technology. Further, 

the criteria provides no waivers for 

segments changing to Class 4 locations 

or for pipe changing to a Class 3 

location that is operating above 72% 

SMYS. Should PHMSA require 

operators and pipelines to meet the 

threshold conditions outlined earlier in 

this document (Section 3A; ‘‘Class 

Location Change Special Permits— 

Special Permit Conditions) or other 

thresholds to be eligible for a waiver 

when class locations change? Why or 

why not? 

Q5—As it is critical for operators to 

have traceable, verifiable, and complete 

(TVC) records to perform IM, should 

operators be required to have TVC 

records as a prerequisite for performing 

IM measures on segments instead of 

replacing pipe when class locations 

change? Why or why not? 

5a.—If so, what records should be 

necessary and why? Should records 

include pipe properties, including yield 

strength, seam type, and wall thickness; 

coating type; O&M history; leak and 

failure history; pressure test records; 

MAOP; class location; depth of cover; 

and ability to be in-line inspected? 

5b.—If operators do not have TVC 

records for affected segments and TVC 

records were a prerequisite for 

performing IM measures on pipeline 


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36870 Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules 

45See OMB Memorandum M–17–21, ‘‘Guidance 

Implementing Executive Order 13771, Titled 

‘Reducing Regulation and Controlling Regulatory 

Costs,’ ’’ (April 5, 2017). 

segments in lieu of replacing pipe, how 

should those records be obtained, and 

when should the deadline for obtaining 

those records be? 

Q6—Should PHMSA incorporate its 

special permit conditions regarding 

class location changes into the 

regulations, and would this 

incorporation satisfy the need for 

alternative approaches? Why or why 

not? (Examples of typical PHMSA class 

location special permit conditions can 

be found at https://

primis.phmsa.dot.gov/classloc/ 

documents.htm.) 

6a.—What, if any, special permit 

conditions could be incorporated into 

the regulations to provide regulatory 

certainty and public safety in these high 

population density areas (Class 2, 3, and 

4)? 

Q7—For all new and replaced 

pipelines, to what extent are operators 

consulting growth and development 

plans to avoid potentially costly pipe 

change-outs in the future? 

Q8—What is the amount of pipeline 

mileage per year being replaced due to 

class location changes for pipelines: (1) 

Greater than 24 inches in diameter, (2) 

16–24 inches in diameter, and (3) less 

than 16 inches in diameter? 

8a.—Of this mileage, how much is 

being replaced due to class locations 

changing when additional structures for 

human occupancy are built near 

clustered areas, if operators are using 

the cluster adjustment to class locations 

per § 192.5(c)(2)? 

8b.—At how many distinct locations 

are pipe replacements occurring due to 

class location changes and that involve 

pipe with these diameters? 

8c.—What is the average amount of 

pipe (in miles) being replaced and cost 

of replacement at the locations 

described in question 8b. and for these 

diameter ranges due to class location 

changes? 

Q9—Should any additional pipeline 

safety equipment, preventative and 

mitigative measures, or prescribed 

standard pipeline predicted failure 

pressures more conservative than in the 

IM regulations be required if operators 

do not replace pipe when class locations 

change due to population growth and 

perform IM measures instead? Why or 

why not? 

9a.—Should operators be required to 

install rupture-mitigation valves or 

equivalent technology? Why or why 

not? 

9b.—Should operators be required to 

install SCADA systems for impacted 

pipeline segments? Why or why not? 

Q10—Should there be any maximum 

diameter, pressure, or potential impact 

radius (PIR) limits that should disallow 

operators from using IM principles in 

lieu of the existing requirements when 

class locations change? For instance, 

PHMSA has seen construction projects 

where operators are putting in 42-inchdiameter pipe designed to operate at up 

to 3,000 psig. The PIR for that pipeline 

would be over 1,587 feet, which would 

mean the total blast diameter would be 

more than 3,174 feet. 

VII. Regulatory Notices 

A. Executive Order 12866, Executive 

Order 13563, Executive Order 13771, 

and DOT Regulatory Policies and 

Procedures 

Executive Orders 12866 and 13563 

require agencies to regulate in the ‘‘most 

cost-effective manner,’’ to make a 

‘‘reasoned determination that the 

benefits of the intended regulation 

justify its costs,’’ and to develop 

regulations that ‘‘impose the least 

burden on society.’’ Executive Order 

13771 (‘‘Reducing Regulation and 

Controlling Regulatory Costs’’), issued 

January 30, 2017, provides that ‘‘it is 

essential to manage the costs associated 

with the governmental imposition of 

private expenditures required to comply 

with Federal regulations.’’ One way to 

manage the costs of rulemakings is to 

propose new regulations that are 

deregulatory in nature, i.e. regulations 

that reduce the cost of regulatory 

compliance. PHMSA seeks information 

on whether this rulemaking could result 

in a deregulatory action under E.O. 

13771, meaning that a potential final 

rule could have ‘‘total costs less than 

zero.’’ 45 We therefore request 

comments, including specific data if 

possible, concerning the costs and 

benefits of revising the pipeline safety 

regulations to accommodate any of the 

changes suggested in the advance 

notice. 

B. Executive Order 13132: Federalism 

Executive Order 13132 requires 

agencies to assure meaningful and 

timely input by State and local officials 

in the development of regulatory 

policies that may have a substantial, 

direct effect on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government. PHMSA is 

inviting comments on the effect a 

possible rulemaking adopting any of the 

amendments discussed in this 

document may have on the relationship 

between national government and the 

States. 

C. Regulatory Flexibility Act 

Under the Regulatory Flexibility Act 

of 1980 (5 U.S.C. 601 et seq.), PHMSA 

must consider whether a proposed rule 

would have a significant impact on a 

substantial number of small entities. 

‘‘Small entities’’ include small 

businesses, not-for-profit organizations 

that are independently owned and 

operated and are not dominant in their 

fields, and governmental jurisdictions 

with populations under 50,000. If your 

business or organization is a small 

entity and if adoption of any of the 

amendments discussed in this ANPRM 

could have a significant economic 

impact on your operations, please 

submit a comment to explain how and 

to what extent your business or 

organization could be affected and 

whether there are alternative 

approaches to the regulations the agency 

should consider that would minimize 

any significant negative impact on small 

business while still meeting the 

agency’s statutory objectives. 

D. National Environmental Policy Act 

The National Environmental Policy 

Act of 1969 requires Federal agencies to 

consider the consequences of Federal 

actions and that they prepare a detailed 

statement analyzing them if the action 

significantly affects the quality of the 

human environment. Interested parties 

are invited to address the potential 

environmental impacts of this ANPRM, 

including comments about compliance 

measures that would provide greater 

benefit to the human environment or 

any alternative actions the agency could 

take that would provide beneficial 

impacts. 

E. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

Executive Order 13175 requires 

agencies to assure meaningful and 

timely input from Indian Tribal 

Government representatives in the 

development of rules that ‘‘significantly 

or uniquely affect’’ Indian communities 

and that impose ‘‘substantial and direct 

compliance costs’’ on such 

communities. We invite Indian Tribal 

governments to provide comments on 

any aspect of this ANPRM that may 

affect Indian communities. 

F. Paperwork Reduction Act 

Under 5 CFR part 1320, PHMSA 

analyzes any paperwork burdens if any 

information collection will be required 

by a rulemaking. We invite comment on 

the need for any collection of 


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Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules 36871 

information and paperwork burdens 

related to this ANPRM. 

G. Privacy Act Statement 

Anyone can search the electronic 

form of comments received in response 

to any of our dockets by the name of the 

individual submitting the comment (or 

signing the comment, if submitted on 

behalf of an association, business, labor 

union, etc.). DOT’s complete Privacy 

Act Statement was published in the 

Federal Register on April 11, 2000 (65 

FR 19477). 

Issued in Washington, DC, on July 25, 

2018, under authority delegated in 49 CFR 

1.97. 

Alan K. Mayberry, 

Associate Administrator for Pipeline Safety. 

[FR Doc. 2018–16376 Filed 7–30–18; 8:45 am] 

BILLING CODE 4910–60–P 


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