12762 Federal Register / Vol. 80, No. 47 / Wednesday, March 11, 2015 / Rules and Regulations 

PART 1—INCOME TAXES 

■ Paragraph 1. The authority citation 

for part 1 continues to read in part as 

follows: 

Authority: 26 U.S.C. 7805 * * * 

■ Par. 2. Section 1.501(r)–0 is amended 

by revising the heading for the table of 

contents entry § 1.501(r)–7 to read as 

follows: 

§ 1.501(r)–0 Outlines of regulations. 

* * * * * 

§ 1.501(r)–7 Effective/applicability date. 

* * * * * 

■ Par. 3. Section 1.501(r)–1 is amended 

by revising the first sentence of 

paragraph (b)(23) and revising 

paragraph (b)(29)(ii)(B) to read as 

follows: 

§ 1.501(r)–1 Definitions. 

* * * * * 

(b) * * * 

(23) Partnership agreement means, for 

purposes of paragraph (b)(22)(ii)(B) of 

this section, all written agreements 

among the partners, or between one or 

more partners and the partnership, and 

concerning affairs of the partnership 

and responsibilities of the partners, 

whether or not embodied in a document 

referred to by the partners as the 

partnership agreement. * * * 

* * * * * 

(29) * * * 

(ii) * * * 

(B) Without paying a fee to the 

hospitality facility, hospital 

organization, or other entity maintaining 

the Web site; and 

* * * * * 

■ Par. 4. Section 1.501(r)–2 is amended 

by revising the second sentence of 

paragraph (c) to read as follows: 

§ 1.501(r)–2 Failures to satisfy section 

501(r). 

* * * * * 

(c) * * * For purposes of this 

paragraph (c), a ‘‘willful’’ failure 

includes a failure due to gross 

negligence, reckless disregard, or willful 

neglect, and an ‘‘egregious’’ failure 

includes only a very serious failure, 

taking into account the severity of the 

impact and the number of affected 

persons. * * * 

* * * * * 

■ Par. 5. Section 1.501(r)–3 is amended 

by revising the introductory text of 

paragraph (c)(2) to read as follows: 

§ 1.501(r)–3 Community health needs 

assessments. 

* * * * * 

(c) * * * 

(2) Description of how the hospital 

facility plans to address a significant 

health need. A hospital facility’s 

implementation strategy will have 

described a plan to address a significant 

health need identified through a CHNA 

for purposes of paragraph (c)(1)(i) of this 

section if the implementation strategy— 

* * * * * 

■ Par. 6. Section 1.501(r)–6 is amended 

by: 

■ 1. Revising paragraph (c)(4)(i)(A). 

■ 2. Revising the first sentence of 

paragraph (c)(4)(iii)(A). 

■ 3. Revising the second of paragraph 

(c)(4)(iv), Example 2. 

■ 4. Revising paragraph (c)(6)(i)(C)(1). 

The revisions read as follows: 

§ 1.501(r)–6 Billing and collection. 

* * * * * 

(c) * * * 

(4) * * * 

(i) * * * 

(A) Provides the individual with a 

written notice that indicates financial 

assistance is available for eligible 

individuals, that identifies the ECA(s) 

that the hospitality facility (or other 

authorized party) intends to initiate to 

obtain payment for the care, and that 

states a deadline after which such 

ECA(s) may be initiated that is no earlier 

than 30 days after the date that the 

written notice is provided. 

* * * * * 

(iii) * * * 

(A) Otherwise meets the requirements 

of paragraph (c)(4)(i) of this section but, 

instead of the notice described in 

paragraph (c)(4)(i)(A) of this section, 

provides the individual with a FAP 

application form and a written notice 

indicating that financial assistance is 

available for eligible individuals and 

stating the deadline, if any, after which 

the hospital facility will no longer 

accept and process a FAP application 

submitted (or, if applicable, completed) 

by the individual for the previously 

provided care at issue. * * * 

* * * * * 

(iv) * * * 

Example 2. * * * Y also makes numerous 

attempts to encourage G to apply for financial 

assistance, including by calling G to inform 

her about the financial assistance available to 

eligible patients under Y’s FAP and to offer 

assistance with the FAP application process. 

* * * 

* * * * * 

(6) * * * 

(i) * * * 

(C) * * * 

(1) If the individual is determined to 

be eligible for assistance other than free 

care, provides the individual with a 

billing statement that indicates the 

amount the individual owes for the care 

as a FAP-eligible individual and how 

that amount was determined and that 

states, or describes how the individual 

can get information regarding, the AGB 

for the care. 

* * * * * 

PART 53—FOUNDATION AND SIMILAR 

EXCISE TAXES 

■ Par. 8. The authority citation for part 

53 continues to read in part as follows: 

Authority: 26 U.S.C. 7805 * * * 

■ Par. 9. In § 53.4959–1(c), the 

paragraph heading is revised to read as 

follows: 

§ 53.4959–1 Taxes on failures by hospital 

organizations to meet section 501(r)(3). 

* * * * * 

(c) Effective/applicability date. * * * 

* * * * * 

Martin V. Franks, 

Chief, Publications and Regulations Branch, 

Legal Processing Division, Associate Chief 

Counsel, (Procedure and Administration). 

[FR Doc. 2015–05519 Filed 3–10–15; 8:45 am] 

BILLING CODE 4830–01–P 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

49 CFR Parts 191, 192, and 195 

[Docket No. PHMSA–2010–0026; Amdt. Nos. 

191–23; 192–120; 195–100] 

RIN 2137–AE59 

Pipeline Safety: Miscellaneous 

Changes to Pipeline Safety 

Regulations 

AGENCY: Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA), Department of Transportation 

(DOT). 

ACTION: Final rule. 

SUMMARY: PHMSA is amending the 

pipeline safety regulations to make 

miscellaneous changes that update and 

clarify certain regulatory requirements. 

These amendments address several 

subject matter areas including the 

performance of post-construction 

inspections, leak surveys of Type B 

onshore gas gathering lines, qualifying 

plastic pipe joiners, regulation of 

ethanol, transportation of pipe, filing of 

offshore pipeline condition reports, and 

calculation of pressure reductions for 

hazardous liquid pipeline anomalies. 

The changes are addressed on an 

individual basis and, where appropriate, 

made applicable to the safety standards 


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Federal Register / Vol. 80, No. 47 / Wednesday, March 11, 2015 / Rules and Regulations 12763 

1NAPSR is a non-profit organization of state 

pipeline safety personnel who serve to promote 

pipeline safety in the United States and its 

territories. Its membership includes the staff 

manager responsible for regulating pipeline safety 

from each state that is certified to do so or conducts 

inspections under an agreement with DOT in lieu 

of certification. 

for both gas and hazardous liquid 

pipelines. Editorial changes are also 

included. 

DATES: The effective date of these 

amendments is October 1, 2015. 

Immediate compliance with these 

amendments is authorized. The 

incorporation by reference of certain 

publications listed in the rule is 

approved by the Director of the Federal 

Register as of March 6, 2015. 

FOR FURTHER INFORMATION CONTACT: Kay 

McIver, Transportation Specialist, by 

telephone at 202–366–0113, or by 

electronic mail at kay.mciver@dot.gov. 

SUPPLEMENTARY INFORMATION: 

I. Background 

A. Notice of Proposed Rulemaking 

On November 29, 2011, PHMSA 

published a Notice of Proposed 

Rulemaking (NPRM) under the docket, 

PHMSA–2010–0026, (76 FR 73570), 

notifying the public of the proposed 

changes to 49 CFR parts 191, 192, and 

195. We allowed an initial 90-day 

comment period, but based on requests 

from several pipeline trade associations, 

the comment period was extended from 

February 3, 2012, to March 6, 2012, (77 

FR 5472). Most of the amendments 

proposed in the NPRM were intended to 

provide relief to industry by 

eliminating, revising, clarifying, or 

relaxing regulatory requirements. 

B. Advisory Committee Meetings 

On July 11 and 12, 2012, the 

Technical Pipeline Safety Standards 

Committee (commonly referred to as the 

Gas Pipeline Advisory Committee 

(GPAC)) and the Technical Hazardous 

Liquid Pipeline Safety Standards 

Committee (commonly referred to as the 

Liquid Pipeline Advisory Committee 

(LPAC)), met jointly at the Marriott 

Hotel at Metro Center in Washington, 

DC. The Pipeline Advisory Committees 

(PACs) are statutorily mandated 

advisory committees that advise 

PHMSA on proposed safety standards, 

risk assessments and safety policies for 

natural gas pipelines and hazardous 

liquid pipelines. The PACs 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). 

Each committee consists of 15 members, 

with membership divided among the 

Federal and state agencies, the regulated 

industry and the public. The PACs 

advise PHMSA on the technical 

feasibility, practicability and costeffectiveness of each proposed pipeline 

safety standard. During the meeting, the 

PACs considered the NPRM and 

discussed the various comments and 

edits proposed by the pipeline industry 

and the public regarding changes to the 

regulations. 

The PACs recommended PHMSA 

adopt the following proposals with 

minor or no changes to the regulatory 

text: 

• Leak Surveys for Type B Gathering 

Lines; 

• Qualifying Plastic Pipe Joiners; 

• Regulating the Transportation of 

Ethanol by Pipeline; 

• Transportation of Pipe; 

• Threading Copper Pipe; 

• Offshore Pipeline Condition 

Reports; 

• Alternative Maximum Allowable 

Operating Pressure (MAOP) 

Notifications; 

• National Pipeline Mapping System; 

• Welders vs. Welding Operators; 

• Components Fabricated by 

Welding; and 

• Editorial Amendments. 

The PACs recommended PHMSA 

adopt the following proposals with 

changes to the regulatory text: 

• Responsibility to Conduct 

Construction Inspections; 

• Mill Hydrostatic Tests for Pipe to 

Operate at Alternative MAOP; 

• Calculating Pressure Reductions for 

Hazardous Liquid Pipeline Integrity 

Anomalies; and 

• Testing Components other than 

Pipe Installed in Low-Pressure Gas 

Pipelines. 

The PACs recommended that PHMSA 

not adopt the proposed changes to: 

• Limitation of Indirect Costs in State 

Grants; and 

• Odorization of gas. 

This Final Rule adopts the 

recommendations of the PACs. 

Additional discussion of the 

amendments and associated comments 

of the PACs are provided below: 

II. Proposals Addressed in This Final 

Rule 

1. Responsibility to Conduct 

Construction Inspections. 

2. Leak Surveys for Type B Gathering 

Lines. 

3. Qualifying Plastic Pipe Joiners. 

4. Mill Hydrostatic Tests for Pipe to 

Operate at Alternative MAOP. 

5. Regulating the Transportation of 

Ethanol by Pipeline. 

6. Limitation of Indirect Costs in State 

Grants. 

7. Transportation of Pipe. 

8. Threading Copper Pipe. 

9. Offshore Pipeline Condition 

Reports. 

10. Calculating Pressure Reductions 

for Hazardous Liquid Pipeline Integrity 

Anomalies. 

11. Testing Components other than 

Pipe Installed in Low-Pressure Gas 

Pipelines. 

12. Alternative MAOP Notifications. 

13. National Pipeline Mapping 

System. 

14. Welders vs. Welding Operators. 

15. Components Fabricated by 

Welding. 

16. Odorization of Gas. 

17. Editorial Amendments. 

III. Commenters to the Rule. 

PHMSA received a total of 42 

comments on the NPRM, to include: 

• 15 from pipeline trade associations. 

• 17 from pipeline operators. 

• 3 from pipeline manufacturers. 

• 3 from states and municipalities. 

• 1 from a Federal source (the 

National Transportation Safety Board 

(NTSB)). 

• 3 from private organizations/

citizens. 

IV. Discussion of Public Comments on 

Individual Issues 

In this section, PHMSA discusses the 

changes proposed in the NPRM and the 

comments received in response to the 

NPRM. Based on an assessment of the 

proposed changes and the comments 

received, PHMSA identifies the 

proposals that are adopted in this Final 

Rule. 

(1) Responsibility to Conduct 

Construction Inspections § § 192.305 

and 195.204. 

Proposal: PHMSA proposed to revise 

§ 192.305 to specify that a transmission 

pipeline or main cannot be inspected by 

someone who participated in its 

construction. This proposal was based, 

in part, on a petition (Docket No. 

PHMSA–2010–0026) from the National 

Association of Pipeline Safety 

Representatives (NAPSR),1 that 

suggested that contractors who install a 

transmission line or main should be 

prohibited from inspecting their own 

work for compliance purposes. This 

petition was also based on the 

experiences of NAPSR members 

concerned with the poor quality of 

construction by unsupervised 

contractors. 

PHMSA agreed with NAPSR but 

recognized that the same concerns 

should apply to non-contractor pipeline 

personnel and to hazardous liquid lines. 

Accordingly, PHMSA proposed to revise 

§§ 192.305 and 195.204 to specify that a 

transmission pipeline main, or pipeline 


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system, cannot be inspected by someone 

who participated in its construction. 

Comments: This topic was the most 

controversial of all the proposed items. 

Comments included the following 

concerns and recommendations: 

• The proposed rule will result in 

significant cost impact to operators; 

• The proposal is overly burdensome 

economically and has the potential to 

compromise site safety due to additional 

personnel, congestion, inattention, 

carelessness and unnecessary overhead 

expenses; 

• The proposed amendment is clearly 

a significant regulatory action and is 

inappropriately included in a nonsignificant rulemaking and should be 

considered in a separate rulemaking; 

• The proposed language does not 

differentiate between an operator’s 

employee and a contractor’s employee; 

• PHMSA should clarify the meaning 

of ‘‘person participating in the 

construction’’ of a pipeline; 

• Inspection and new construction 

should be an Operator Qualification 

(OQ) task; 

• Prohibiting any ‘‘person’’ involved 

in the construction of a pipeline could 

be interpreted to prohibit any other 

municipal employee from performing 

inspection; and 

• PHMSA should re-define ‘‘a person 

who participated’’ in the construction of 

the pipeline. 

NAPSR commented that their 

resolution was intended to preclude 

operators from allowing contractor 

personnel to self-inspect their own work 

and was based on its members’ 

experience with poor quality of 

construction by unsupervised 

contractors. 

Members of the Association of Oil 

Pipelines (AOPL) said they do not agree 

with the statement that ‘‘the proposed 

rule does not impose any compliance, 

recordkeeping or other reporting 

requirement.’’ AOPL said the proposed 

change to § 192.305 will result in 

significant cost to the operators. In 

addition, AOPL asserted that the 

proposal is overly burdensome 

economically and has the potential to 

compromise site safety due to additional 

personnel, congestion, inattention, 

carelessness and unnecessary overhead 

expense. 

The American Gas Association (AGA) 

noted that PHMSA has failed to provide 

an analysis to support the significant 

expansion of the construction 

inspection revision to all entities and 

personnel encompassed in the § 192.3 

definition of ‘‘person.’’ Another 

commenter noted that PHMSA did not 

provide a basis for its conclusion on 

construction inspection and PHMSA’s 

proposed rule does not address the same 

concerns as NAPSR. The Interstate 

Natural Gas Association of America 

(INGAA) noted that instead of adopting 

the proposed amendment, which 

increases regulatory confusion and adds 

to the issues already surrounding 

construction, PHMSA should convene a 

public hearing or workshop to develop 

the fundamental regulatory changes 

needed to align PHMSA’s policy 

objectives with common pipeline 

configurations. 

Response: Consistent with the 

petition from NAPSR, PHMSA proposed 

to revise §§ 192.305 and 195.204 to 

prohibit individuals involved in the 

construction of a transmission line, 

main or pipeline system from inspecting 

his or her own work. These inspections 

are important because transmission 

pipelines and mains are generally 

buried after construction. Subsequent 

examinations often involve a difficult 

excavation process. PHMSA believes 

that allowing individuals to inspect 

their own work defeats, in part, the 

measure of safety garnered from such 

inspections. PHMSA was not intending 

to require third party inspections or 

attempting to prohibit any person from 

a company to inspect the work of 

another person from the same company. 

The PACs did not agree with the 

proposed language. There was 

considerable discussion on the use of 

alternative language proposed by 

INGAA and the original language from 

the NAPSR petition. 

Following the discussion, the PACs 

agreed on the revised language for gas 

and hazardous liquid pipelines. After 

reviewing the PACs’ recommendations 

and evaluating public comments, 

PHMSA has adopted language that more 

clearly identifies the types of 

individuals who should be excluded 

from the required inspections, (i.e., the 

individual who performed the 

construction task that requires 

inspection). 

In regard to the comments that dealt 

with costs and the significance of the 

rule, PHMSA believes that the 

commenters overstated the impact of the 

proposal. 

(2) Leak Surveys for Type B Gathering 

Lines § 192.9. 

Proposal: In the NPRM, PHMSA 

proposed that operators of Type B 

gathering lines must perform leak 

surveys in accordance with § 192.706 

and fix any leaks discovered. 

Operators of Type B gathering lines 

currently must ensure that any new or 

substantially changed Type B line 

complies with the design, installation, 

construction, and initial testing and 

inspection requirements for 

transmission lines and, if of metallic 

construction, comply with the corrosion 

control requirements for transmission 

lines. Operators must also include Type 

B gathering lines in their damage 

prevention and public education 

programs, establish the MAOP of those 

lines under § 192.619, and comply with 

the requirements for maintaining and 

installing line markers that apply to 

transmission lines. 

Comments: The Texas Pipeline 

Association (TPA) suggested that if 

PHMSA decided to move forward with 

the proposal to survey Type B lines, 

then several topics would need to be 

addressed to assure the reasonableness 

of the proposed regulation. TPA 

suggested that: 

• PHMSA share any supporting 

information provided by NAPSR to 

show that leaks are the primary hazard 

for Type B gathering pipelines; 

• Section 21 of the Pipeline Safety, 

Regulatory Certainty, and Job Creation 

Act of 2011 requires the Secretary of 

Transportation to review the existing 

Federal and state regulations for 

gathering pipelines to determine their 

sufficiency to ensure the safety of such 

lines. As such, PHMSA should not 

move forward with additional 

regulatory requirements for Type B 

gathering lines since Congress has 

mandated a review of the sufficiency of 

existing regulations; 

• The docket contains no supporting 

evidence to show that the proposed 

amendment is based on facts and not 

speculation; 

• Excavation damage may pose a 

greater risk than leaks in Type B 

gathering lines; 

• PHMSA should develop estimates 

of the cost of compliance for affected 

operators; 

• The economic impact may exceed 

the threshold for a non-significant 

regulatory action; and 

• If PHMSA implements the change, 

it must provide at least one year 

adequate time for affected operators to 

purchase leak detection equipment, 

establish leak survey routes, develop 

recordkeeping systems for these surveys 

and hire additional personnel following 

adoption of the new leak survey 

equipment. 

The Iowa Utilities Board (IUB) 

commented that the proposed 

amendment appears responsive to 

NAPSR Resolution 2006–3, which 

called for the reinstatement of leak 

surveys that were not included when 

requirements for Type B gathering lines 

were adopted in Amendment 192–102. 

The IUB further noted that the proposed 

amendment includes a second part that 


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Federal Register / Vol. 80, No. 47 / Wednesday, March 11, 2015 / Rules and Regulations 12765 

was not in the NAPSR resolution. The 

language of the second part reads: ‘‘and 

fix hazardous leaks that are discovered 

in accordance with § 192.703(c).’’ ‘‘Fix’’ 

is hardly usual regulatory language and 

has no specified definition or usage 

history in Part 192. The IUB and 

MichCon DTE Energy suggested that 

PHMSA use alternate language that 

removes a nonstandard term and an 

unnecessarily complicated rule 

reference by simply saying ‘‘and 

promptly repair hazardous leaks that are 

discovered.’’ 

The Northeast Gas Association 

suggested that PHMSA revise its 

proposal to require operators of Type B 

regulated gathering lines to apply leak 

survey methods in accordance with 

§ 192.723 which provides the leak 

survey requirements for low-stress 

pipelines with a MAOP of less than 20 

percent specified minimum yield 

strength (SMYS). 

Response: As for the comment that 

PHMSA should wait until its 

congressionally mandated review of 

existing regulations for gas and 

hazardous liquid gathering lines is 

complete, the study required by Section 

21 of the Pipeline Safety, Regulatory 

Certainty, and Job Creation Act requires 

PHMSA to study and report to Congress 

on: 

(A) The sufficiency of existing Federal 

and state laws and regulations to ensure 

the safety of gas and hazardous liquid 

gathering lines; 

(B) The economic impacts, technical 

practicability and challenges of 

applying existing Federal regulations to 

gathering lines that are not currently 

subject to Federal regulation when 

compared to the public safety benefits; 

and 

(C) Subject to a risk-based assessment, 

the need to modify or revoke existing 

exemptions from Federal regulation for 

gas and hazardous liquid gathering 

lines. 

The need to include leakage surveys 

as a compliance activity was identified 

between the publications of the 

Supplemental Notice of Proposed Rule 

Making (SNPRM) titled: ‘‘Pipeline 

Safety: Gas Gathering Line Definition: 

Alternative Definition for Onshore Lines 

and Proposed Safety Standards,’’ 

published October 3, 2005; 70 FR 57536 

[Docket No. RSPA–1998–4868; Notice 

5], and the Final Rule of the same title 

published March 15, 2006; 71 FR 13289 

[Docket No. PHMSA–1998–4868]. The 

inclusion of leakage surveys as a 

compliance action was not included in 

the Final Rule because it was beyond 

the scope of the SNPRM and the agency 

did not want to further delay the 

rulemaking. During its annual meeting 

in September 2006, NAPSR also passed 

a resolution [NAPSR Resolution 2006–3] 

requesting the regulatory change to 

Type B lines. 

As for the comment that Type B leaks 

due to excavation damage may pose a 

greater risk, the annual Type B report 

data for calendar year 2011 indicated 

that there were 289 leaks eliminated or 

repaired by operators of onshore Type B 

gathering lines, with the leading cause 

of leaks being external. Excavation 

damage is and has been recognized as a 

high risk for Type B gathering lines. 

This point was elaborated on in the Gas 

Gathering Line Definition in the SNPRM 

(October 3, 2005; 70 FR 57536) and 

Final Rule (March 15, 2006; 71 FR 

13289), and served as the basis for the 

compliance activities for Type B lines 

(damage prevention programs, 

placement of line markers, and public 

awareness programs). This amendment 

will add one more recognized risk 

control activity required on Type B 

gathering lines. 

Regarding the comment that PHMSA 

should estimate the costs of compliance, 

PHMSA performed a cost analysis by 

averaging the daily rate of two leak 

survey service providers. The average 

cost of surveying two miles of pipeline 

per day equaled $600. The estimated 

that approximately 3,650 miles of Type 

B gathering lines will be required to be 

inspected annually at an average cost of 

$300 per mile for an upper bound 

annual cost of approximately $1.1 

million. 

However, leak surveys, while not 

currently required for Type B gathering 

lines, are a widespread industry practice 

because they serve a business purpose 

in helping to detect leaks, thereby 

reducing lost gas and liability exposure. 

Although operators do not submit data 

on the extent of these surveys, PHMSA 

believes that approximately half of all 

Type B gathering line mileage that 

would otherwise be affected by this 

proposal is already being inspected. 

This is based on the fact that this is a 

widespread industry practice and until 

2006, this was an existing regulatory 

requirement. Therefore, a more realistic 

estimate of the actual incremental cost 

is approximately 50% of the upper 

bound of $1.1 million, or $0.55 million 

per year. 

The Northeast Gas Association, in a 

comment on PHMSA’s published 

NPRM, noted there were operational 

similarities between Type B gathering 

lines and gas distribution lines that 

operate at similar, lower pressures, and 

requested PHMSA apply leak survey 

standards to Type B gathering lines that 

were more in line with leak survey 

standards for distribution lines, rather 

than leak survey standards for 

transmission lines. 

Title 49 CFR 192.706 requires 

transmission line leak surveys at 

intervals not exceeding 15 months, but 

at least once each calendar year, and 

more frequently in densely populated 

areas. NAPSR believes that Type B 

gathering lines should be subject to the 

same requirements, as Type B gathering 

lines can carry gas that is corrosive, and 

gas leaks are a significant hazard on 

those low-stress pipelines. Therefore, 

requiring leak surveys on Type B 

gathering lines is an appropriate and 

necessary risk-management measure. 

NAPSR also noted in their comments 

that some Type B gathering lines are 

located under broad paved areas, where 

electrical surveys that detect pipe 

damage may be difficult to perform, and 

leaking gas can migrate under the 

pavement and accumulate in 

surrounding structures. NAPSR 

recommends that leak detection surveys 

should be required to ensure the safety 

of these lines. 

As it stands, distribution lines in 

business districts must be surveyed each 

calendar year, with the remainder of 

distribution lines subject to leak survey 

at frequencies driven by local 

conditions but at an interval that does 

not exceed 5 years. Distribution lines, 

per the regulations, are required to be 

odorized which provides members of 

the public with a warning system for the 

period between surveys. The gas in 

gathering lines is un-odorized, so the 

public does not have any advance 

warning of line leaks outside of those 

leak surveys. Leak surveys would serve 

as the warning bell. 

Regarding the concerns raised by 

commenters about the cost of this 

proposal, under the current regulations, 

Type B gathering lines are treated the 

same as transmission lines for design, 

installation, construction, and initial 

testing and inspection. If the line in 

question is composed of metal, the line 

must also comply with the same 

corrosion control requirements as 

transmission lines. Similar to 

transmission lines, Type B gathering 

lines must be included in damage 

prevention and public education 

programs, have established MAOPs 

under § 192.619, and comply with the 

requirements for installing and 

maintaining line markers. 

Because Type B gathering lines are 

regulated with many of the same 

requirements as transmission lines, it 

would follow that Type B gathering 

lines and transmission lines have a 

similar risk profile. Therefore, because 

transmission lines are subject to annual 

leak surveys, Type B gathering lines 


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12766 Federal Register / Vol. 80, No. 47 / Wednesday, March 11, 2015 / Rules and Regulations 

should be subject to the same 

requirement for safety reasons. 

While leak surveys are not currently 

required for Type B gathering lines, they 

are a widespread industry practice that 

help operators detect leaks early and 

avoid loss of lives, gas and liability 

exposure. When this voluntary practice 

becomes a regulation it will provide a 

standard and consistent level of safety 

to the American public and ensure the 

integrity of these lines. 

Taking this into consideration, as well 

as the GPAC’s recommendation and the 

evaluation of public comments, PHMSA 

has adopted § 192.9(d)(7) as proposed 

with the minor modification of 

substituting the word ‘‘fix’’ with 

‘‘repair.’’ 

(3) Qualifying Plastic Pipe Joiners 

§ 192.285(c) 

Proposal: Section 192.285 contains 

requirements for qualifying persons to 

make joints in plastic pipe. Under 

§ 192.285(c), ‘‘[a] person must be requalified under an applicable 

procedure, if during any 12-month 

period that person: (1) Does not make 

any joints under that procedure; or (2) 

has three joints or three percent of the 

joints made, whichever is greater under 

that procedure that are found 

unacceptable by testing under 

§ 192.513.’’ In its petition to amend the 

regulations (2008–03–AC–1), NAPSR 

noted that the current rule, with its 12- 

month time period, requires detailed 

records of each individual joiner’s 

activities and sets the stage for 

requalification date ‘‘creep,’’ where a 

joiner must requalify at an earlier date 

every year. NAPSR commented that the 

existing regulatory language sets a very 

low standard for joiner requalification 

and noted that the large number of 

operators requesting similar waivers 

demonstrates that a requalification 

system like the one proposed in its 

resolution is acceptable and preferred 

by pipeline operators. 

In the NPRM, based on the NAPSR 

petition, PHMSA proposed to revise 

§ 192.285 to provide greater scheduling 

flexibility and require requalification of 

a joiner if any production joint is found 

unacceptable. 

Comments: Center Point Energy (CPE) 

noted that it is overly excessive to 

disqualify and retrain a joiner if one 

joint is found unacceptable during a 12- 

month period CPE suggested that 

PHMSA leave § 192.285(c)(2) as written 

and that quality assurance/quality 

checks of potentially unacceptable 

joints be accomplished through 

§ 192.513 testing. CPE also queried 

whether PHMSA has data from a study 

to show that an individual who makes 

one unacceptable joint will make more. 

City Utilities of Springfield, Missouri, 

suggested that we amend the language 

to clarify that requalification is 

necessary only if the joint failure is due 

to operator error. 

Nicor Gas (Nicor), while supporting 

the proposal to add a three-month grace 

period in the requalification interval, 

does not support the proposed revision 

that would require requalification of the 

joiner if one joint is found unacceptable 

by the required pressure testing. Nicor 

commented that the proposal is 

unnecessarily restrictive and not 

validated or supported by 

documentation from NAPSR. Nicor 

noted that there are field conditions 

and/or circumstances beyond the 

joiner’s control (rain, snow, blowing 

dirt, trench cave-ins, equipment 

malfunctions and material flaws) that 

would affect the joining process without 

reflecting a lack of skill or proper 

training. All these incidents may lead to 

an unacceptable joint. 

TPA also disagrees with the proposal 

to impose a zero-failure tolerance 

standard for plastic pipe joiners and 

commented that perfection in the 

performance of any task in any industry 

100 percent of the time is rarely, if ever, 

achieved. TPA commented on the 

contrast of the regulations in plastic 

joining versus welding of steel pipelines 

and noted that the existing regulations 

for welders do not impose a zerotolerance standard, even though most 

steel pipelines operate at higher 

pressures than plastic pipelines, and 

would pose a higher safety risk to the 

public. The zero tolerance proposal for 

plastic pipe joiners also fails to consider 

that all plastic pipe is required to be 

pressure tested before going into service 

and that this testing provides an 

additional layer of safety assurance that 

plastic pipe joints are safe before 

pipeline operation begins. 

AGA suggested that PHMSA analyze 

data on fusion failures, present the 

information to the public and then 

determine how best to address the issue. 

AGA further commented that the 

amendment to prohibit the entire crew 

from further fusion after one joint 

failure until requalification occurs 

seems unnecessarily severe, is 

unsupported by statistical evidence and 

has the potential to create unexpected 

adverse consequences. 

Response: PHMSA reviewed the 

comments received on the topic 

including those that raised concerns of, 

and requested clarification on, the 

changes surrounding requalification if 

one joint is found unacceptable. 

PHMSA understands some of the 

concerns may have been related to the 

language used in the preamble and 

additional clarification may be needed 

regarding PHMSA’s intent. PHMSA 

does not believe the proposed 

requirements are as onerous as some of 

the commenters indicated, nor would 

there necessarily be a zero tolerance 

policy in effect as a result of the 

proposed changes. PHMSA agrees there 

could be a number of factors including 

some beyond the joiners control such as 

weather, equipment malfunctions and 

material flaws, which could result in an 

unacceptable joint. However, PHMSA 

expects some evaluation would be done 

following any unacceptable joint, and in 

some cases evaluation may be necessary 

on a case-by-case basis. If an 

unacceptable joint is a result of a 

factor(s) clearly beyond the joiner’s 

control, PHMSA does not expect those 

conditions to affect the requalification 

of the joiner. Likewise, if an individual 

fusing a joint realizes that it is a bad 

joint, cuts it out, and fuses another 

(acceptable) joint immediately 

following, PHMSA does not expect that 

the joiner would have to requalify. On 

the other hand, if an unacceptable joint 

is related to issues that are within the 

joiner’s control, that joiner would need 

to be re-qualified. While PHMSA has 

presented some general expectations, 

ultimate determination of the adequacy 

of an acceptable joint, whether or not 

the joiner would need to be requalify, 

and what may constitute an adequate 

qualifying joining test would be up to 

which ever entity inspects the joint. In 

most cases, particularly for intrastate 

systems, it would be up to the 

individual state. 

In response to the comments 

regarding the burden of this provision, 

PHMSA notes that the changes may 

help reduce some of the current burden 

associated with the paperwork, tracking 

and record-keeping requirements that 

were associated with ‘‘three joints or 

three percent of the joints made, 

whichever is greater’’ in the current 

regulatory language. Regarding the 

comments inquiring about data or other 

studies surrounding joints, PHMSA is 

not aware of any studies showing that 

an individual who makes one 

unacceptable joint will make more. On 

the other hand, PHMSA is not aware of 

any data or studies that can guarantee 

that an individual who makes one 

unacceptable joint won’t make another 

unacceptable joint. The potential safety 

issues surrounding an unacceptable 

joint those are not addressed through 

proper evaluation and requalification 

seem to outweigh any benefit with 

continuing the qualification 

requirements as they currently exist in 


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the regulations. Many of these and other 

aspects were discussed with the GPAC, 

the transcripts of which are available in 

the docket. 

Following some discussion, the GPAC 

unanimously supported PHMSA’s 

proposal that was based on the NAPSR 

petition. The PACs, industry and the 

public indicated that the original 

language in the regulations required 

numerous letters of interpretation and 

caused problems in the application of 

the regulations. The proposed language 

is also in keeping with some state 

waivers granted by PHMSA. 

Accordingly, the Final Rule revises 

§ 192.285 to provide greater scheduling 

flexibility and require requalification of 

a joiner if any production joint is found 

unacceptable. 

(4) Mill Hydrostatic Tests for Pipe To 

Operate at Alternative Maximum 

Allowable Operation Pressure § 192.112 

Proposal: Section 192.112 applies to 

pipe that will operate at the higher 

stresses allowed under the alternative 

MAOP permitted under § 192.620 and 

specifies additional design 

requirements. In the NPRM, PHMSA 

proposed to revise § 192.112(e) by 

eliminating the allowance for combining 

loading stresses imposed by pipe mill 

hydrostatic testing equipment for the 

mill test. Eliminating the allowance to 

combine equipment loading stresses 

will have the effect of increasing the 

internal test pressure for mill 

hydrostatic tests for new pipe to be 

operated at an alternative MAOP. This 

design requirement, combined with 

pipe mill dimensional checks for 

expansion, will help assure that all new 

pipes to be operated at an alternative 

MAOP receive an adequate mill test and 

have adequate strength. 

Comments: Evraz, a steel and pipe 

manufacturer, noted that eliminating the 

allowance for combining loading 

stresses imposed by pipe mill 

hydrostatic testing equipment could put 

mills that use testing processes that 

apply high end loadings at a 

competitive disadvantage to mills that 

do not. The amount of end loading 

applied depends on the testing process 

and equipment used. Mills that apply 

higher end loadings will produce 

combined stresses in excess of 100 

percent SMYS if required to achieve 95 

percent of SMYS based on gauge 

pressure alone. Evraz noted that the 

more effective way of addressing the 

potential of low strength line pipe 

would be to fully institute the changes 

in the 3rd addendum of the 44th edition 

of the American Petroleum Institute’s 

(API), API Specification 5L, 

‘‘Specification for Line Pipe,’’ (API Spec 

5L). TransCanada Corporation suggested 

that PHMSA consult with pipe 

manufacturers regarding the potential 

impacts of consideration of end loading 

in the calculations of mill hydrostatic 

tests before adopting changes to the 

procedure. TransCanada maintained 

that the increased safety factor was 

already added in the 2008 Final Rule 

titled: ‘‘Pipeline Safety: Standards for 

Increasing the Maximum Allowable 

Operating Pressure for Gas 

Transmission Pipelines’’ (73 FR 62148). 

Response: Pipe mill hydrostatic 

testing is a factory proof test used to 

ensure that new pipe has no structural 

or manufacturing flaws and adequate 

strength. Section 192.112 applies to 

pipe that will operate at the higher 

stresses allowed under the alternative 

MAOP rule. The mill test pressure of a 

minimum of 95 percent SMYS is being 

required to ensure that lower strength 

pipe is not used for alternative MAOP 

pipelines. The alternative MAOP rule 

allows pipelines to operate at stresses of 

up to 80 percent of SMYS, where other 

pipelines can only operate up to 72 

percent SMYS. Pipelines that do not 

operate in accordance with the 

alternative MAOP must be mill tested as 

defined in the appropriate pipe 

manufacturing standard and the current 

edition of API Spec 5L incorporated by 

reference in § 192.7 (b)(7). The 45th 

edition of API Spec 5L was incorporated 

by reference on January 5, 2015 (80 FR 

168). API Spec 5L offers a lower 

requirement than that of a mill test of 95 

percent SMYS in § 192.112(e)(1) for 

non-alternative MAOP pipelines. 

During the 2008 through 2010 

construction seasons, PHMSA identified 

a number of cases where new pipe did 

not meet regulatory specified strength 

requirements. Pipe that is 15 percent 

below the mandated SMYS was found 

on several new pipeline construction 

projects. On May 21, 2009, PHMSA 

issued an advisory bulletin (ADB–09– 

01) Docket No. PHMSA–2009–0148— 

‘‘Pipeline Safety: Potential Low and 

Variable Yield and Tensile Strength and 

Chemical Composition Properties in 

High Strength Line Pipe’’), alerting 

pipeline operators of issues found with 

low strength pipe. Eliminating the mill 

test allowance to combine equipment 

loading stresses will have the effect of 

increasing the internal test pressure for 

mill hydrostatic tests for new pipe to be 

operated at an alternative MAOP. When 

combined with pipe mill dimensional 

checks for expansion, that change will 

help assure that all new pipes for this 

service receive an adequate mill test and 

have adequate strength. This mill 

hydrostatic test criteria change will help 

to eliminate low strength pipe in 

alternative MAOP pipelines. 

During 2009 to 2010, INGAA 

conducted two studies/white papers 

titled, ‘‘Guidelines for Evaluation and 

Mitigation of Expanded Pipes’’ dated 

June 9, 2010, and ‘‘Identification of Pipe 

with Low and Variable Mechanical 

Properties in High Strength, Low Alloy 

Steels’’ dated September, 2009 (Docket 

No. PHMSA–2010–0026). The INGAA 

studies confirm that if the mill 

hydrostatic pressure test produced a 

stress of 95 percent or more of SMYS, 

and diameter dimensions were taken at 

intervals along the length of each joint 

in addition to the required end 

dimension measurements, expansion of 

the pipe beyond the set tolerances in the 

pipe specification did not occur. If 

unacceptable expansion has occurred, 

those pipe joints can be identified and 

eliminated. 

Since steel and pipe production are 

worldwide manufacturing processes, it 

is very difficult to determine that a 

standard quality assurance process has 

been fully implemented. Mill 

hydrostatic tests are the final quality 

assurance process in the pipe 

manufacturing chain. They are 

conducted by the pipe manufacturer 

and have the full quality assurance 

review of the pipe manufacturer and 

pipe purchaser/pipeline operator. This 

new requirement is based upon an 

INGAA sponsored industry review of 

pipe making practices. If pipe is not 

tested to a higher pressure in the mill 

then the low strength pipe will create 

operational concerns in the field. The 

adoption of this amendment should 

expose low strength pipe in operation. 

Thus, PHMSA has adopted § 192.112(e) 

as proposed. 

(5) Regulating the Transportation of 

Ethanol by Pipeline § 195.2 

Proposal: In the NPRM, PHMSA 

proposed to modify its definition of 

‘‘hazardous liquid’’ to include ethanol. 

This action was based in part on a 

policy statement published in the 

Federal Register on August 10, 2007; 72 

FR 45002 (Docket Number: PHMSA– 

2007–28136) on the transportation of 

ethanol, ethanol blends, and other 

biofuels by pipeline. PHMSA noted in 

the policy statement that the demand for 

biofuels was projected to increase as a 

result of several Federal energy policy 

initiatives, which would result in 

greater use of pipelines for transporting 

biofuels. PHMSA also stated that 

ethanol and other biofuels are 

substances that ‘‘may pose an 

unreasonable risk to life or property’’ 

within the meaning of 49 U.S.C. 

60101(a)(4)(B), and accordingly, these 


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materials constitute ‘‘hazardous liquids 

for purposes of the pipeline safety laws 

and regulations.’’ PHMSA went on to 

say that the agency was considering a 

possible modification to § 195.2 to 

include ethanol and biofuels in the 

definition of hazardous liquid. PHMSA 

invited comments on that proposal and 

on other issues related to the 

transportation of biofuels by pipeline. 

Comments: Thomas Lael Services, 

L.P., suggested that the term ‘‘ethanol’’ 

and ‘‘bio-diesel petroleum’’ should be 

added to the definition of ‘‘hazardous 

liquid.’’ AOPL added that rather than 

having another Federal agency or a 

number of state agencies attempt to 

regulate the safety of pipeline 

transportation of ethanol, that denatured 

ethanol be defined as a ‘‘hazardous 

liquid’’ under § 195.2, so that ethanol 

transported via pipeline is regulated 

consistently with other energy liquids 

by PHMSA under 49 CFR part 195. 

Response: After evaluating the 

comments on the proposal, PHMSA has 

adopted the amendment to add the term 

‘‘ethanol’’ to the definition of 

‘‘hazardous liquids’’ in § 195.2. In this 

Final Rule PHMSA will not adopt the 

commenter’s suggestion that we add 

‘‘bio-diesel petroleum’’ to the definition 

because this request is outside of the 

scope of this rulemaking. However, 

PHMSA may address this issue in a 

future rulemaking. 

(6) Limitation of Indirect Costs in State 

Grants § 198.13 

Proposal: PHMSA reimburses the 

states for a portion of the costs accrued 

in administering their pipeline safety 

programs and Congress appropriates the 

funds used to make these 

reimbursements on a regular basis. The 

Pipeline Inspection, Protection, 

Enforcement and Safety Act of 2006 

(PIPES Act) removed a provision that 

imposed a 20 percent cap on indirect 

expenses allocated to the pipeline safety 

program grants. In the NPRM, PHMSA 

proposed to incorporate the 20 percent 

limitation on indirect expenses into the 

regulations governing grants to state 

pipeline safety programs. 

Comments: PHMSA received several 

comments opposed to this proposal. IUB 

and NAPSR objected to the proposal to 

limit the indirect cost rate that can be 

recovered through a state’s pipeline 

safety grant to 20 percent. They both 

stated that the limit is arbitrary and 

capricious and may prevent the 

recovery of legitimate costs of state 

participation in the Federal/state 

pipeline safety program. IUB said the 20 

percent limit is not mandated by law or 

by any referenced Federal grant guide 

material or requirement. IUB also noted 

that there was no clear rationale as to 

why PHMSA should impose a 

requirement by rule that Congress found 

unnecessary and removed from law 

when the PIPES Act was passed in 2006. 

IUB and NAPSR noted that different 

states have different methods of 

allocating costs within their budget and 

no basis was presented for punishing 

states that distribute a larger portion of 

their costs as indirect costs. NAPSR is 

concerned that states could artificially 

inflate indirect costs to receive a larger 

grant payment. 

PACs’ members pointed out that the 

way in which states do their budgeting 

and accounting varies and some states 

do have indirect costs that exceed the 20 

percent limit. However, because of the 

20 percent required cost share, states do 

not present their costs that are above 

that threshold. Some state 

representatives noted that their indirect 

cost submissions are required to be 

approved first at the Federal level and 

are highly scrutinized to ensure no 

padding is done. In addition to that, to 

ensure compliance, PHMSA performs 

frequent audits of the state programs. 

Response: PHMSA has decided not to 

adopt the proposal into regulation. 

However, PHMSA will maintain the 20 

percent indirect cost cap through 

language in our payment agreements 

with states. As part of its state program, 

PHMSA has payment agreements with 

each state. These agreements are 

binding and cap indirect costs at 20 

percent. 

(7) Transportation of Pipe § 192.65 

Proposal: Section 192.65 states that if 

pipe is to be transported by railroad, it 

will be operated at a hoop stress of 20 

percent or more of SMYS, and has a 

diameter-to-wall-thickness ratio of 70 to 

one or more; the pipe must be 

transported in accordance with API RP 

5L1. An exception is provided for 

certain pipe transported before 

November 12, 1970. That exception 

allows operators to use pipe stockpiled 

prior to the effective date of the original 

pipeline safety regulations, the 

transportation of which cannot be 

verified under API standards. 

Based on an NTSB investigation and 

recommendation resulting from an 

Enbridge pipeline incident that took 

place on July 4, 2002, near Cohasset, 

Minnesota, PHMSA proposed to revise 

the regulation to require that the rail 

transportation of all pipe be subject to 

the referenced API standards. 

Comments: We received several 

comments, including one from the 

NTSB in support of the proposal. The 

Committee on Pipe and Tube Imports 

(CPTI) Ad Hoc Large Diameter Line Pipe 

Producers Group agreed that the 

proposal would not have an adverse 

impact on operations or the ability to 

manufacture products. El Paso Pipeline 

Group (EPPG) commented that if 

PHMSA promulgates this amendment, it 

should specify that the use restriction 

does not apply to any pipe already 

installed, or to any pipe transported 

after § 192.65 initially took effect. EPPG 

commented that the proposed wording 

may result in misinterpretation and 

unintended consequences, such as 

assuming that ‘‘use’’ applies to pipe 

currently installed rather than to pipe in 

stock, and that shipping records must be 

provided for all pipe exceeding the 

specified diameter-to-wall thickness 

ratio. EPPG proposed this rewording of 

the regulatory language: 

(a) Railroad. In a pipeline to be operated 

at a hoop stress of 20 percent or more of 

SMYS, an operator may not install pipe 

shipped by rail prior to November 12, 1970, 

unless the operator can show that the 

transportation was performed in a manner 

that meets the requirements of API RP 5L1. 

NAPSR agrees that any remaining 

stock of such pipe is likely to be 

minimal. 

Response: Surveys conducted by 

INGAA failed to find any vintage pipe 

covered by § 192.65(a)(2). Therefore, 

PHMSA has no reason to continue the 

exemption and is removing this 

exemption from the regulation and 

adopting the amendment with one 

minor change. PHMSA is replacing the 

phrase ‘‘operator may not use pipe’’ 

with the phrase ‘‘operator may not 

install pipe’’ to clearly indicate that this 

amendment does not apply to pipe 

already installed. 

(8) Threading Copper Pipe: § 192.279 

Proposal: Section 192.279 specifies 

when copper pipe may be threaded and 

refers to Table C1 of American Society 

of Mechanical Engineers (ASME) 

Standard ASME/ANSI B16.5. In a letter 

dated June 11, 2009, the Gas Piping 

Technology Committee (GPTC) advised 

PHMSA that Table C1 was deleted in 

the most recent version of the ASME/

ANSI B16.5, which is incorporated into 

Part 192 by reference. The GPTC stated 

that the information in Table C1 was 

taken from a different standard and that 

ASME/ANSI B36.10M, ‘‘Standard for 

Welded and Seamless Wrought Steel 

Pipe,’’ should be substituted as a more 

appropriate reference. PHMSA proposed 

to use ‘‘threaded copper pipe if the wall 

thickness is equivalent to the 

comparable size of Schedule 40 or 

heavier wall pipe as listed in Table 1 of 

ASME B36.10M, Standard for Welded 

and Seamless Wrought Steel Pipe.’’ 


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Comments: We received no public or 

PAC comments on this proposal. 

Response: PHMSA is unable to 

incorporate ASME/ANSI B36.10M, 

‘‘Standard for Welded and Seamless 

Wrought Steel Pipe’’ due to the 

standards availability requirement 

described in Section 24 of the ‘‘Pipeline 

Safety, Regulatory Certainty, and Job 

Creation Act of 2011’’ (Pub. L. 112–90, 

January 3, 2012). Section 24 added a 

new public availability requirement for 

documents incorporated by reference 

after January 3, 2013. The law stated 

that beginning 1 year after the date of 

enactment of this subsection, the 

Secretary may not issue guidance or a 

regulation pursuant to this chapter that 

incorporates by reference any 

documents or portions thereof unless 

the documents or portions thereof are 

made available to the public, free of 

charge, on an Internet Web site. 

This section was further amended on 

August 9, 2013. The current law 

continues to prohibit the Secretary from 

issuing a regulation that incorporates by 

reference any document unless that 

document is available to the public, free 

of charge, but removes the Internet Web 

site requirements (Pub. L. 113–30, 

August 9, 2013). PHMSA will address 

this proposal in a future rulemaking 

action. 

(9) Offshore Pipeline Condition Reports 

§§ 191.27 and 195.57 

Proposal: In the NPRM, PHMSA 

proposed to remove §§ 191.27 and 

195.57. Sections 191.27 and 195.57 

require operators to submit a report to 

PHMSA within 60 days of completing 

the underwater inspections of pipelines 

in the Gulf of Mexico required by 

§§ 192.612(a), and 195.413(a). 

Sections 192.612(a) and 195.413(a) no 

longer require operators to perform an 

underwater inspection of all pipelines 

in the Gulf and its inlets. (See also Pub. 

L. 102–508 (Oct. 24, 1992) (modifying 

the statutory mandate for underwater 

inspection, reporting and reburial of 

pipelines in the Gulf and its inlets). 

Rather, those regulations call for 

periodic, risk-based inspections of 

shallow-water pipelines. The filing of a 

written report within 60 days of 

completing all of those inspections is 

not consistent with such an action. 

Additionally, sections 192.612(c) and 

195.413(c) require operators to file their 

electronic/telephonic reports with the 

National Response Center within 24 

hours of discovering that a pipeline in 

those areas is exposed or a hazard to 

navigation, which is sufficient to meet 

PHMSA’s current information collection 

needs. 

Comments: PHMSA received no 

public comments on this proposal. 

Response: PHMSA has adopted the 

proposal to repeal §§ 191.27 and 195.57. 

(10) Calculating Pressure Reductions for 

Hazardous Liquid Pipeline Integrity 

Anomalies § 195.452(h)(4)(i) 

Proposal: Section 195.452(h)(4)(i) 

specifies the actions that an operator of 

a hazardous liquid pipeline must take 

after discovering an immediate repair 

condition. One of those actions is a 

temporary reduction in operating 

pressure as determined under the 

formula provided in section 451.6.2.2 

(b) of ASME/ANSI B31.4, ‘‘Pipeline 

Transportation Systems for Liquid 

Hydrocarbons and Other Liquids.’’ The 

particular focus of that pressure 

reduction formula is corrosion. 

However, corrosion is only one of the 

threats that could cause an immediate 

repair condition under 

§ 195.452(h)(4)(i). 

In a July 17, 2007, Final Rule (72 FR 

39017), PHMSA sought to modify 

§ 195.452(h)(4)(i) to provide for 

alternative methods of calculating a 

pressure reduction for immediate repair 

conditions caused by threats other than 

corrosion. The Office of the Federal 

Register was unable to incorporate that 

change due to inaccurate amendatory 

instructions. In the NPRM, PHMSA 

again proposed to revise 

§ 195.452(h)(4)(i) to make the same 

change as published in the July 17, 

2007, Final Rule, with corrected 

amendatory instructions. 

Comments: In response to our 

proposal, the TransCanada Corporation 

commented that it acknowledges the 

limitations of the current language in 

§ 195.452(h)(4)(i) and believes a revision 

to the language in this section is 

appropriate. However, since 

§ 195.452(h)(4)(i)(B) provides for the 

calculation of the remaining strength 

using methods that include, ‘‘but are not 

limited to,’’ ASME/ANSI B31G, 

‘‘Manual for Determining the Remaining 

Strength of Corroded Pipelines,’’ 

(ASME/ANSI B31G) or AGA Pipeline 

Research Committee, Project PR–3–805, 

‘‘A Modified Criterion for Evaluating the 

Remaining Strength of Corroded Pipe,’’ 

(PR–3–805 (RSTRING)), they do not 

believe a reference to the design 

requirements of § 195.106 is necessary. 

TransCanada commented that the ability 

to use alternative methods for 

calculating a pressure reduction would 

be incorporated with only a reference to 

§ 195.452(h)(4)(i)(B). They suggested the 

following language in lieu of what 

PHMSA has proposed: 

§ 195.452(h)(4)(i): ‘‘Immediate repair 

conditions. An operator’s evaluation and 

remediation schedule must provide for 

immediate repair conditions. To maintain 

safety an operator must provide for 

immediate repair conditions. To maintain 

safety an operator must temporarily reduce 

the operating pressure or shut down the 

pipeline until the operator completes the 

repair of these conditions. An operator must 

calculate the temporary reduction in 

operating pressure using the criteria in 

paragraph (h)(4)(i)(B) of this section. If no 

suitable remaining strength calculation 

method can be identified, a minimum 20 

percent or greater operating pressure 

reduction must be implemented until the 

anomaly is repaired. An operator must treat 

the following conditions as immediate repair 

conditions.’’ 

The AOPL commented that the 

proposed language requiring the 

calculation of pressure reductions for 

detected anomalies should be modified 

to appropriately reference suitable 

calculation methods. 

API noted that § 195.452(h)(4)(i)(B) 

already allows the use of PR–3–805 

(RSTRENG), modified PR–3–805 

(RSTRENG), or a suitable alternative 

remaining strength calculation method 

to be used, and therefore already fully 

covers the calculation of a temporary 

reduction in operating pressure. The 

API suggests that the following sentence 

in the proposed section is redundant: ‘‘If 

the formula is not applicable to the type 

of anomaly or would produce a higher 

operating pressure, an operator must use 

an alternative acceptable method to 

calculate a reduced operating pressure.’’ 

The LPAC suggested the following 

language: 

§ 195.452(h)(4)(i): ‘‘Immediate repair 

conditions. An operator’s evaluation and 

remediation schedule must provide for 

immediate repair conditions. To maintain 

safety, an operator must temporarily reduce 

the operating pressure or shut down the 

pipeline until the operator completes the 

repair of these conditions. An operator must 

calculate the temporary reduction in 

operating pressure using the formulas 

referenced in paragraph (h)(4)(i)(B) of this 

section. If no suitable remaining strength 

calculation method can be identified, a 

minimum 20 percent or greater operating 

pressure reduction, based on actual operating 

pressure for two months prior to the date of 

inspection, must be implemented until the 

anomaly is repaired. An operator must treat 

the following conditions as immediate repair 

conditions: [. . .]’’ 

Response: PHMSA believes both 

commenters were trying to make similar 

changes. In the Final Rule, PHMSA is 

adopting LPAC’s suggested language as 

it best clarifies that an operator must 

calculate remaining strength or reduce 

operating pressure until a repair can be 

completed. 


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12770 Federal Register / Vol. 80, No. 47 / Wednesday, March 11, 2015 / Rules and Regulations 

(11) Testing Components Other Than 

Pipe Installed in Low-Pressure Gas 

Pipelines § § 192.503 and 192.505 

Proposal: In the NPRM, PHMSA 

proposed to amend §§ 192.503 and 

192.505 to exempt certain components 

from the strength test requirement in 

Subpart J of Part 192. This proposal was 

based on a petition from the GPTC in a 

letter dated March 25, 2010. The GPTC 

argued that the primary purpose of a 

post-installation strength test is to prove 

the integrity of the entire pipeline 

system. The GPTC further noted that the 

most important parts to check of a 

single-component replacement are the 

joints that connect the component to the 

pipeline, and that these joints are 

currently exempted from testing for all 

gas pipelines by paragraph (d) of 

§ 192.503. 

Comments: PHMSA received many 

comments in support of this proposal. 

We also received some comments asking 

that we expand the list and sources of 

standards that can be used to establish 

pressure ratings. One commenter asked 

that we review all referenced standards 

and provide exemptions for all 

standards that establish pressure ratings. 

Response: PHMSA is adopting the 

amendment as proposed. The request to 

expand the list and sources of standards 

that can be used to establish pressure 

ratings is out of the scope of this 

rulemaking, as is the request to review 

all referenced standards. Therefore, 

those requests have not been adopted 

but may be considered in future 

rulemaking actions. 

(12) Alternative MAOP Notifications 

§ 192.620(c)(1) 

Proposal: Section 192.620(c)(1) 

currently requires a pipeline operator to 

notify each PHMSA pipeline safety 

regional office where the pipeline is in 

service of its election to use an 

alternative MAOP pressure with respect 

to a segment at least 180 days before 

operating at the alternative 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 where an intrastate 

pipeline is regulated by that state. 

PHMSA proposed to require that for 

new pipelines, an operator would notify 

the PHMSA pipeline safety regional 

office of planned alternative MAOP 

design and operations 180 days prior to 

start of pipe manufacturing or 

construction activities. An operator 

would also notify state pipeline safety 

authorities when the pipeline is located 

in a state where PHMSA has an 

interstate agent agreement or where an 

intrastate pipeline is regulated by that 

state. 

PHMSA also proposed to revise 

§ 192.620(c)(8) to correct a 

typographical error related to the 

reference to § 192.611(a). 

The proposal to require 180 day 

notice for new pipelines was to allow 

sufficient time for PHMSA to conduct 

any needed material manufacturing and 

construction inspections, including 

checks of new pipe rolling and coating 

processes, visit the new pipeline field 

sites during construction, analyze 

operating history of existing pipelines, 

and review test records, plans, and 

procedures. 

Comments: INGAA suggested that the 

proposal should apply only 

prospectively, that the regulation should 

include an alternative notice period 

measured from the placement of the 

pipe purchasing order to the start of 

pipe manufacturing and that the 

language needs clarification with regard 

to new pipe. In its comments to the 

NPRM, INGAA noted that for new 

pipeline projects the application and 

permitting process can extend over 

months or years before approval to 

construct is granted. Once this approval 

is obtained, pipe orders are placed and 

production dates are established. The 

interval from the time the pipe is 

ordered until the start of production is 

sometimes less than 180 days making it 

impractical to provide the required 

notice as the proposed rule is currently 

worded. To address this INGAA 

recommends that the wording be 

changed to 180 days or 10 business days 

before the operator places a purchasing 

order for the pipe or the pipe starts 

being manufactured. 

Panhandle Energy (Panhandle) 

recommended that the wording 

addressing new pipelines be changed to: 

‘‘For new pipelines, notify the PHMSA 

pipeline safety regional office 180 days 

prior to the start of pipe manufacturing 

and/or construction activities, if 

practicable, but no more than 10 

business days after the operator places 

an order for the pipe or executes the 

pipeline construction contract.’’ 

TPA commented that if the operator 

wishes to utilize the existing pipe stock 

that satisfies the MAOP regulation 

requirement, the 180 day notice to the 

manufacturer would be impossible, and 

that the language should be revised to 

remove ‘‘and/or’’ to provide clear, 

unambiguous standards. 

Response: PHMSA evaluated the 

comments and believes the proposed 

180 days notification is too restrictive. 

Notification to PHMSA of new 

alternative MAOP pipeline project 

activities at least 60 days prior to start 

of pipe manufacturing or construction 

activities should not delay operator 

project activities. PHMSA needs this 

time to schedule personnel for safety 

inspections at both the pipe and coating 

mills and at the construction site prior 

to the start of pipe construction 

activities. PHMSA will require a 60 day 

notice by the operator prior to the start 

of pipe manufacturing or construction 

activities of new alternative MAOP 

pipelines. 

(13) National Pipeline Mapping System 

§§ 191.29, 195.61 

Proposal: The National Pipeline 

Mapping System (NPMS) is a geospatial 

dataset that contains information about 

PHMSA-regulated gas transmission 

pipelines, hazardous liquid pipelines, 

and hazardous liquid low-stress 

gathering lines. The NPMS also contains 

data layers for all liquefied natural gas 

plants and a partial dataset of PHMSAregulated breakout tanks. 

In the NPRM, PHMSA proposed to 

codify the statutory requirement for the 

submission of the NPMS data into Parts 

191 and 195. An NPMS submission 

consists of geospatial data, attribute data 

and metadata, public contact 

information, and a transmittal letter. 

PHMSA also proposed to require 

operators to follow the submission 

guidelines and dates set forth in the July 

31, 2008, advisory bulletin (73 FR 

44800: Pipeline Safety; National 

Pipeline Mapping System). Gas 

transmission operators and liquefied 

natural gas (LNG) plant operators would 

make their NPMS submissions on or 

before March 15, representing their 

assets as of December 31 of the previous 

year. Hazardous liquid operators would 

make their NPMS submissions on or 

before June 15, representing their assets 

as of December 31 of the previous year. 

Comments: Oleska commented that, 

though they agree that the requirements 

should be added to Part 191, requiring 

operators to report to both NPMS and 

PHMSA is unduly burdensome and is 

not necessary. The TPA asked that 

PHMSA revise the language to clarify 

that this proposal only covers hazardous 

liquid trunklines and regulated rural 

hazardous liquid gathering pipelines as 

defined in the NPMS Operator 

Standards. TPA and Oleska noted that 

the operator ID for each operator is the 

same as it is for PHMSA, and that 

PHMSA should have the ability to get 

whatever information it needs directly 

from the NPMS without operators 

having to submit two sets of data. TPA 

and Oleska suggested that it would be 

better for PHMSA to get its data from 

the NPMS, because two sets of data 

increase the chance of discrepancies, 


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especially if changes are made between 

annual submissions. 

Response: In response to TPA’s and 

Oleksa’s concern about submitting the 

data twice, operators will continue to 

make only one NPMS submission 

following the guidelines in the NPMS 

Operator Standards Manual on the 

NPMS Web site 

(www.npms.phmsa.dot.gov). This Final 

Rule imposes no additional submission 

requirements. In response to the 

concern about the NPMS’s and 

PHMSA’s capability to process all the 

gas, LNG plant operator and liquid 

operator submissions received on or 

before March 15 and June 15, 

respectively, PHMSA encourages 

operators to make their submissions 

early beginning on January 1 of each 

year. In the Final Rule, PHMSA is 

adopting the amendment to the NPMS 

as proposed. 

(14) Welders vs. Welding Operators 

§§ 192.225, 192.227, 192.229, 195.214, 

195.222 

Proposal: The welding provisions in 

Subpart E of Part 192 and Subpart D of 

Part 195 allow qualification of welders 

in accordance with API Standard 1104, 

‘‘Welding of the ASME Pipelines and 

Related Facilities,’’ (API Std 1104), 

section 6 or ASME Boiler and Pressure 

Vessel Code., section IX: ‘‘Qualification 

Standard for Welding and Brazing 

Procedures, Welders, Brazers, and 

Welding and Brazing Operators,’’ 

(ASME BPVC, section IX). In the NPRM, 

PHMSA proposed to add references to 

additional qualification standards in 

API Std 1104, such as sections 12 and 

13 for welders and welding operators of 

mechanized and automated welding 

equipment. The addition of these 

qualification references was intended to 

follow current industry practice. These 

standards have specific processes to 

ensure that qualified personnel are used 

for welding processes whether they are 

performed by welders or welding 

operators. 

Comments: EPPG commented that the 

proposed language appears to not allow 

for the qualification of a welding 

operator whose welds are regularly 

being assessed per the criteria in API 

Std 1104, Appendix A, which is 

regarded as being equivalent to section 

9. EPPG suggested a revision of the 

proposed language of § 192.227(a) to 

read: ‘‘under section 6, or section 9 or 

Appendix A, as applicable of API Std 

1104 (incorporated by reference, see 

§ 192.7).’’ [Proposed deletion indicated 

by strikeout; proposed addition in bold]. 

INGAA recommended that while 

PHMSA is amending the welding 

regulations, PHMSA should take the 

opportunity to formally incorporate by 

reference Appendix B to API Std 1104 

for in-service (also known as ‘‘live line’’) 

welding. Oleska suggested that the 

language of the proposed revision 

would be clearer if we changed ‘‘pipe 

and components’’ to read ‘‘pipe or 

components.’’ 

Panhandle commented that the 

proposed language for § 192.229(c)(1) 

contains an oversight related to this 

equivalence. The section says, in part: 

A welder or welding operator 

qualified under § 192.227(a)— 

(1) May not weld on pipe to be 

operated at a pressure that produces a 

hoop stress of 20 percent or more of 

SMYS unless within the preceding six 

calendar months the welder or welding 

operator has had one weld tested and 

found acceptable under section 6 or 

section 9 of API Std 1104 (incorporated 

by reference, see § 192.7). 

According to Panhandle, sections 6 

and 9 of API Std 1104 relate to 

workmanship criteria only. The 

proposed language would appear to 

exclude qualification of a welding 

operator whose welds are regularly 

being assessed per the criteria in API 

Std 1104, Appendix A which is 

regarded as being equivalent to ASME 

BPVC, section IX. It is reasonable to 

allow qualification for a welding 

operator whose work has been 

acceptable under the Appendix A 

criteria. Panhandle therefore suggested 

that PHMSA modify the proposed 

language in the notice to read: 

A welder or welding operator qualified 

under § 192.227(a) may not weld on pipe to 

be operated at a pressure that produces a 

hoop stress of 20 percent or more of SMYS 

unless within the preceding 6 calendar 

months the welder or welding operator has 

had one weld tested and found acceptable 

under section 6, section 9 or Appendix A of 

API Std 1104, as applicable (incorporated by 

reference, see § 192.7). 

Response: The Final Rule allows 

welds to be evaluated to API Std 1104, 

section 9 or Appendix A, and eliminates 

the requirement that the weld be first 

evaluated to section 9, before using 

Appendix A. Evaluating the welds first 

according to section 9 incurs 

unnecessary time and cost without any 

benefit. 

PHMSA re-evaluated its proposal to 

add additional references to 

qualification standards in API Std 1104. 

PHMSA finds that adding API Std 1104, 

section 13 (‘‘Automatic Welding 

Without Filler Metal Additions’’) is 

inconsistent with pipeline safety. API 

Std 1104, section 13 is not used on 

regulated pipelines and would be a 

major change in girth welding 

standards. Also, for practical purposes, 

there are no commercially used pipeline 

welding systems in the United States to 

which API Std 1104, section 13 can be 

applied. Not adopting API Std 1104, 

section 13, will prevent an operator 

from using a potentially less safe 

welding system without a PHMSA 

special permit review. 

INGAA suggested that PHMSA use 

the Final Rule as an opportunity to 

formally incorporate by reference 

Appendix B to API Std 1104 for inservice (‘‘live line’’) welding. Parts 192 

and 195 currently require that all 

welding procedures be qualified to API 

Std 1104, section 5 or ASME BPVC, 

section IX, and that all welders be 

qualified to API Std 1104, section 6 or 

ASME BPVC, section IX. API Std 1104, 

Appendix B is only applicable to inservice welds on live or ‘‘hot’’ pipelines, 

with pressurized product in the pipe. 

The qualification requirements of 

Appendix B are optimized for in-service 

welds, and differ greatly from API Std 

1104, sections 5 and 6 and ASME BPVC, 

section IX. Thus, adding API Std 1104, 

Appendix B to the Final Rule is a 

significant change that is outside the 

scope of this rule. We will consider this 

change for a future regulatory action. 

Based upon further review by PHMSA 

of Part 192, Appendix C, PHMSA 

decided that adding welding operators 

for Appendix C qualification in 

§ 192.227(b) would be inappropriate for 

the following reasons: 

(1) Qualification of welding operators 

can be, and is more appropriately 

performed to API Std 1104, section 12, 

instead of Appendix C; 

(2) Appendix C is primarily used for 

lower pressure, smaller diameter 

distribution lines, which are welded by 

welders, not welding operators; and 

(3) The language in Appendix C was 

written for qualification of welders, and 

may not be appropriate for qualification 

of welding operators. 

We agree with the comments that API 

1104, Appendix A should be included 

as a qualification reference. When we 

proposed to add the relevant references 

to welding qualification standards to be 

consistent with industry practice, we 

intended to include the Appendix A 

reference, a widely accepted standard. 

Appendix A is now cited in the final 

regulations applicable to welding and 

welding operators. 

(15) Components Fabricated by Welding 

§ 192.153 

Proposal: Pressure vessels can be 

found in meter stations, compressor 

stations and other pipeline facilities to 

facilitate the removal of liquids and 

other materials from the gas stream. 

These vessels are designed, fabricated 


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and tested in accordance with the 

requirements of ASME Boiler & Pressure 

Vessel Code, section VIII Rules for 

Construction of Pressure Vessels,’’ as 

required by § 192.153 and 

§ 192.165(b)(3), and the additional test 

requirements of § 192.505(b). 

In the NPRM, PHMSA proposed that 

because the standard ASME pressure 

vessel test in ASME BPVC, section VIII, 

division 1 is 1.3 times MAOP, an 

operator must specify the correct test 

pressure when placing an order for an 

ASME vessel to ensure it is designed 

and tested to the requirements of 49 

CFR part 192. Unless a vessel is 

specially ordered with a test pressure of 

1.5 times MAOP as prescribed by the 

purchaser, the vessel will be tested in 

accordance with the standard test factor 

of 1.3. If the vessel is not tested to 1.5 

times the MAOP, it cannot be used in 

a compressor or meter station, or other 

Class 3 or Class 4 locations. The failure 

to meet this requirement can potentially 

lead to exceeding the design parameters 

of the vessel during subsequent testing 

of the pipeline system. 

The pressure test requirements in 

ASME BPVC, section VIII were lowered 

from a test factor of 1.5 to 1.3 by an 

earlier edition. PHMSA proposed to add 

§ 192.153 to clearly specify the design 

and test requirements for pressure 

vessels in meter stations, compressor 

stations, and other locations that are 

tested to Class 3 requirements. Under 

the proposal, all ASME pressure vessels 

subject to § 192.153 and § 192.165(b)(3) 

would be designed and tested at a 

pressure that is 1.5 times the MAOP, in 

lieu of the standard ASME BPVC, 

section VIII test pressure of 1.3 times the 

MAOP. Additionally, PHMSA proposed 

to revise § 192.165(b)(3) reference to this 

requirement. 

Comments: Kern River, INGAA and 

Northern Natural Gas maintained that 

this proposal is not a simple 

clarification but a change from the 

previous understanding and practice of 

both PHMSA and the operators. If the 

proposed regulation is applied 

retroactively, this change will place 

many facilities constructed after the 

change in the pressure test requirements 

in ASME BPVC, section VIII, as well as 

many facilities uprated under special 

permits, in violation of ASME BPVC, 

sections I and II. INGAA noted that 

these sections of Part 192 and the ASME 

BPVC revision history make it clear that 

the proposed rule will require a number 

of operators to make substantial and 

costly changes. Northern Natural Gas 

commented that retesting and replacing 

of these in-service components would 

be unnecessary, very expensive, and 

take several years to complete. 

INGAA noted that station piping often 

includes fabricated sections that are 

assembled at the construction site. 

Many of these sections, such as 

compressor bottles, coolers and inlet 

scrubbers and separators are tested and 

certified by their manufacturers. 

Requiring a second test at the 

construction site as proposed would 

depart sharply from common practice, 

add costs that are not justified by a 

safety benefit and potentially invalidate 

the manufacturers’ compliance 

certificates. 

Kern River further commented that 

station piping is commonly tested in 

several segments and it is not common 

practice to include and retest ASME 

code vessels since they are certified by 

the manufacturers and retesting would 

require dewatering. INGAA advised 

PHMSA to adopt an alternate 

clarification that these components do 

not require testing beyond the ASME 

code. If PHMSA adopts the current 

recommendation, it should clarify that 

the amendment applies to components 

placed into service after the 

amendment’s effective date. 

Response: PHMSA has incorporated 

by reference ASME BPVC for pressure 

vessels. The revised ASME BPVC, 

section VII, division 1 has changed 

pressure testing standards from 1.5 

times MAOP to 1.3 times MAOP. This 

proposal is not a change to the current 

pressure testing requirements found in 

Part 192, but simply a clarification to 

ensure a clearer understanding of 

PHMSA’s pressure testing requirements 

for certain ASME BPVC vessels located 

in compressor stations, meter stations 

and other Class 3 or Class 4 locations. 

The pressure testing requirements for 

pipelines in the PSR (which by 

definition includes pressure vessels, 

meter stations, compressor stations and 

other facilities used to transport gas as 

defined in Part 192 and ASME/ANSI 

B31.8) in Class 3 and 4 areas, as well as 

those facilities located in Class 1 and 

Class 2 which are explicitly required by 

§ 192.505(b), requires a pressure test 

equal to a minimum of 1.5 times the 

MAOP. The testing requirements of 

§ 192.505(b) have not been revised and 

state that in a Class 1 or Class 2 location, 

each compressor station regulator 

station, and measuring station, must be 

tested to at least Class 3 location test 

requirements. This clarification of code 

requirements are to ensure that Industry 

does not incorrectly use the newer 

ASME BPVC standard for pressure 

testing even though that was never the 

requirement. This clarification will not 

lead to additional cost measures, and 

therefore, PHMSA is adopting this 

amendment as proposed. 

(16) Odorization of Gas Transmission 

Lateral Lines § 192.625 

Proposal: Section 192.625 contains 

requirements for operators to odorize 

combustible gas in a transmission line 

in Class 3 or Class 4 locations ‘‘so that 

at a concentration in air of one-fifth of 

the lower explosive limit, the gas is 

readily detectable by a person with a 

normal sense of smell.’’ Certain 

exceptions are recognized by regulation, 

including for a lateral line, ‘‘which 

transports gas to a distribution center, 

[if] at least 50 percent of the length of 

that line is in a Class 1 or Class 2 

location.’’ This section does not specify 

a clear method for calculating the length 

of a lateral line, and that has led to 

inconsistencies in applying the 

odorization requirement. In the NPRM, 

PHMSA proposed to amend 

§ 192.625(b)(3) to state that the length of 

a lateral line, for purposes of calculating 

whether at least 50 percent of the line 

is in a Class 1 or Class 2 location, be 

measured between the distribution 

center and the first upstream connection 

to the transmission line. 

Comments: Texas Oil and Gas 

Association commented, and API 

supported this comment, that PHMSA’s 

attempt to better define which natural 

gas transmission lateral pipelines are 

subject to the odorization requirement 

may create the unintended consequence 

of adversely impacting industrial 

facility (refinery) operations and 

product quality in addition to increasing 

emissions. TransCanada Corporation 

noted that the proposed amendment’s 

apparent distinction between lateral and 

transmission lines appears to lack logic, 

as it allows parts of a line originally 

considered to be a ‘‘lateral’’ line to 

change classification due to 

introduction of a branch. TransCanada 

further noted that the industry is not 

aware of, nor has PHMSA presented in 

the preamble, statistical evidence that 

this understanding of lateral has caused 

safety issues resulting from operators 

applying this definition to exempt 

certain lines from odorization with 

commensurate safety benefits. 

TransCanada submits that the definition 

of ‘‘lateral’’ most commonly used by the 

industry more than adequately serves 

the interest of public safety. It also 

noted that ‘‘laterals are not distinct 

classification of lines; rather, ‘laterals’ 

are described according to their function 

(e.g., transmission, distribution or 

gathering).’’ 

INGAA had similar comments and 

suggested that PHMSA convene a public 

hearing or workshop to develop the 

fundamental regulatory changes needed 

to align its policy objectives with 


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common pipeline configurations. The 

natural gas industry considers lateral 

lines to be any lines that branch off 

other lines. Section 192.625 does not 

specify a clear method to calculate the 

length of a lateral line, and that has led 

to inconsistency in applying the 

odorization requirement. Even with the 

proposed language, there is confusion 

on the calculation. There is no evidence, 

of record or otherwise, suggesting that 

the industry’s understanding of 

‘‘lateral’’ has caused any safety issues. 

The American Chemical Council 

(ACC) commented that the use of gas 

odorants at certain facilities could affect 

some chemical manufacturing processes 

and the quality of some chemicals. 

While there are well-established safety 

benefits of odorants in natural gas 

transmission that are fully consistent 

with the ACC member company 

interests in enhanced natural gas 

production and use, the ACC is 

concerned that the potential 

requirement to odorize lateral lines that 

carry natural gas may affect some 

industrial facilities. Further, the 

proposal could force chemical 

manufacturers to remove the odorant 

before processing, leading to a 

substantial potential increase in the 

effective cost of natural gas and in the 

cost of production. 

TPA commented that this change 

could also result in odorization 

equipment, including odorant storage 

tanks, being located in close proximity 

to populated areas, increasing the 

likelihood of false reports and odor 

complaints from nearby residents. 

According to TPA, some products 

manufactured with natural gas can be 

tainted by sulfur based odorant making 

the product worthless. 

Response: This controversial topic 

was discussed at length at the advisory 

committee meeting. GPAC members 

found it difficult to agree on how to 

calculate the 50 percent length of a 

lateral line between the distribution 

center and the first upstream connection 

to the transmission line. Committee 

members were also concerned with the 

costs and benefits of this proposal. 

GPAC voted unanimously for PHMSA 

not to adopt this proposal. Although 

PHMSA believes that proper odorization 

is important, this proposal requires 

further analysis. Therefore, PHMSA will 

re-evaluate the proposal and may 

consider the revision in a future 

rulemaking action. 

(17) Editorial Amendments 

A: Editorial Amendments Proposed in 

the NPRM 

In the NPRM, PHMSA proposed 

several editorial amendments to the 

regulations. 

(1) In § 195.571, we proposed to revise 

the reference to NACE SP0169 to specify 

compliance with one or more of the 

applicable criteria contained in 

paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 and 

6.3. 

(2) In § 195.2, we proposed to amend 

the definition of ‘‘Alarm’’ to correct an 

error in the codification of the new 

control room management regulations 

(74 FR 63310). 

(3) In §§ 192.925(b) and (b)(2), we 

proposed to replace ‘‘indirect 

examination’’ with ‘‘indirect 

inspection’’ to maintain consistency 

with § 192.925(a) and the applicable 

NACE standard. 

(4) In § 195.428(c), we proposed to 

replace ‘‘sections 5.1.2’’ with ‘‘section 

7.1.2’’ to correctly reference the overfill 

protection requirements for 

aboveground breakout tanks in the API 

Std 2510. 

(5) In section 192.3 we proposed to 

add the definition of ‘‘Welder’’ and 

‘‘Welding Operator. 

(6) In § 195.2, we proposed to revise 

the definitions of ‘‘alarm’’ and 

‘‘hazardous liquid.’’ 

None of these editorial amendments 

received any comment and, as such, we 

are adopting them all as proposed. 

B. Editorial Amendments Not Proposed 

in the NPRM 

Several administrative regulatory 

changes summarized in the following 

paragraphs are included in this Final 

Rule. 

Hazardous Liquid Construction 

Notifications 195.64 (c)(1)(i) 

PHMSA discovered an error in the 

hazardous liquid regulations covering 

operator notifications of planned 

construction, and gave notice of its 

intention to correct the regulatory 

language (see March 21, 2012; 77 FR 

16472, Advisory Bulletin ADB–2012– 

04). Section 195.64(c)(1)(iii) requires 

notification for construction of a new 

pipeline facility but does not specify a 

minimum dollar threshold for the 

construction project. Section 

195.64(c)(1)(i) also requires notification 

for construction of a new pipeline 

facility, but only for those projects with 

a cost of ten million dollars 

($10,000,000) or more. PHMSA does not 

wish to be notified about hazardous 

liquid pipeline facility construction 

with a cost of less than ten million 

dollars, so § 195.64(c)(1)(iii) is being 

deleted. 

Reporting and Notification Methods 

The NPRM proposed to remove the 

requirement to file offshore pipeline 

condition reports currently found in 

§§ 191.27 and 195.57. This Final Rule 

completes the removal and changes 

§§ 191.7 and 195.58 by removing the 

reference to offshore pipeline condition 

reports. 

Sections 191.25 and 195.56 include 

the method for submitting safety-related 

condition reports. Since the receipt and 

processing of these reports is extremely 

time sensitive, the regulations currently 

require submittal by facsimile and do 

not provide an option for electronically 

mailing the report to PHMSA. These 

amendments are non-substantive and 

allow operators easier reporting 

methods. In this Final Rule, these 

regulations are revised to allow 

submittal of reports by electronic mail. 

The remaining changes apply to the 

submittal methods for integrity 

management and operator qualification 

program notifications. Under changes 

made in this Final Rule, these 

notifications may now be submitted by 

either electronic mail or regular mail. 

For integrity management, changes are 

made in §§ 192.949 and 195.452. For 

operator qualification programs, 

changes are made in §§ 192.805 and 

195.505. 

Regulatory Analyses and Notices 

Executive Order 12866, Executive Order 

13563, and DOT Regulatory Policies and 

Procedures 

This Final Rule is a non-significant 

regulatory action under section 3(f) of 

Executive Order 12866 (58 FR 51735) 

and, therefore, was not reviewed by the 

Office of Management and Budget. This 

Final Rule is not significant under the 

Regulatory Policies and Procedures of 

the Department of Transportation (44 FR 

11034). 

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.’’ PHMSA amended 

miscellaneous provisions to clarify and 

eliminate unduly burdensome 

requirements. PHMSA also responded 

to requests from industry and state 

pipeline safety representatives to revise 

its regulations. PHMSA anticipates that 

a majority of the amendments contained 

in this Final Rule will have economic 

benefits to the regulated community by 


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increasing the clarity of its regulations 

and reducing compliance costs. 

For example, the changes related to 

NPMS and ethanol are simply a 

regulatory codification of current 

requirements. The elimination of the 

exception in § 192.65 related to the 

transportation of pipe should have 

minimal impact because the amount of 

pipe that would be eligible for the 

exception is very small. The elimination 

of the offshore pipeline condition report 

will eliminate a reporting requirement 

that is no longer necessary. 

Several provisions of the Final Rule 

are specifically designed to eliminate 

confusion and potentially lower costs 

for regulated entities. For example, the 

final addition of § 192.153(e) is designed 

to prevent regulated entities from 

purchasing pressure vessels that do not 

comply with § 192.505(b), but that do 

comply with ASME BPVC, section VII, 

as required by § 192.165(b)(3). The 

changes with respect to qualifying 

plastic pipe joiners will prevent requalification date ‘‘creep’’ and provide 

operators greater re-qualification 

flexibility and overall cost savings. 

Annual Compliance costs associated 

with this rulemaking are estimated to be 

$0.55 million, all of which are 

associated with requirement of leak 

Surveys for Type B gathering lines. 

PHMSA estimates approximately 3,650 

miles of Type B gathering lines will be 

required to be inspected annually. 

PHMSA estimates that the average cost 

of inspection is $300 per mile, bringing 

the upper bound limit of the total 

annual expenditure to approximately 

$1.1 million. A more realistic estimate 

of the actual incremental cost is 

approximately 50% of the upper bound 

of $.55 million. 

By performing leak surveys annually, 

operators are more likely to detect leaks 

early, thereby avoiding costlier future 

repairs and reducing the amount of gas 

lost. There are also practical, 

operational benefits to conducting leak 

surveys, in the form of greater 

knowledge of the state of the pipeline, 

including potential third-party 

encroachments, soil erosion, or 

intrusion by vegetation. 

The lead cause of these leaks is 

external corrosion. Leak surveys are 

particularly important for low pressure 

gas gathering lines because these lines 

tend to leak rather than rupture and 

because their gas is non-odorized, 

making leaks more difficult to detect. In 

addition to the direct operational 

benefits, annual leak surveys will also 

reduce the environmental harm caused 

by lost gas (i.e., the greenhouse gas 

potential of methane released into the 

atmosphere). Operator leak reporting 

also gives PHMSA valuable information 

that can be used in trending analysis for 

the determination of problem materials 

or poor operating practices. These 

important benefits cannot be readily 

quantified, but PHMSA believes that 

they are substantial. 

In addition, eliminating these leak 

helps to ensure that leaked gas does not 

collect and lead a catastrophic 

explosion or other incident. Although 

fortunately there have been no serious 

incidents involving Type B gathering 

lines in the past several years, increased 

leak surveys would reduce the potential 

of a future incident. At an incremental 

cost of $0.55 million per year, requiring 

annual leak surveys would be a costeffective safety intervention if it 

prevents even a single fatal incident 

over a 16 year period. 

A more thorough discussion of the 

subjects and the associated costs and 

benefits can be found in the Regulatory 

Impact Analysis, a copy of which has 

been placed in the Docket, PHMSA– 

2010–0026. 

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. 

Description of the reasons that action 

by PHMSA was taken. 

PHMSA, pipeline operators and 

others have identified certain errors, 

inconsistencies, and deficiencies in the 

pipeline safety regulations concerning 

the following subjects: (1) Performance 

of post-construction inspections; (2) 

leak surveys of Type B onshore gas 

gathering lines; (3) the requirements for 

qualifying plastic pipe joiners; (4) the 

transportation of ethanol by pipeline; (5) 

the transportation of pipe; (6) the filing 

of offshore pipeline condition reports 

and (7) the calculation of pressure 

reductions for hazardous pipeline 

anomalies. PHMSA is addressing these 

issues in this Final Rule. 

Succinct statement of the objectives 

of, and legal basis, for the Final Rule. 

Under the pipeline safety laws, 49 

U.S.C. 60101 et seq., the Secretary of 

Transportation must prescribe 

minimum safety standards for pipeline 

transportation and for pipeline facilities. 

The Secretary has delegated the 

authority of 49 CFR 1.53(a) to the 

PHMSA Administrator. The Final Rule 

would make changes in the regulations 

consistent with the protection of 

persons and property, while changing 

unduly burdensome or confusing 

requirements. 

Description of small entities to which 

the Final Rule will apply. 

In general, the Final Rule will apply 

to pipeline operators, some of which 

may qualify as a small business as 

defined in Section 601(3) of the 

Regulatory Flexibility Act. Some 

pipelines are operated by jurisdictions 

with a population of less than 50,000 

people, and thus qualify as small 

governmental jurisdictions. 

Some portions of the rule apply to 

manufacturers of pipeline components, 

as well as the contractors constructing 

or repairing a pipeline. Many of these 

may qualify as a small business entity. 

Description of the projected reporting, 

recordkeeping, and other compliance 

requirements of the Final Rule, 

including an estimate of the classes of 

small entities that will be subject to the 

rule, and the type of professional skills 

necessary for preparation of the report 

or record. 

The Final Rule does not directly 

impose any reporting or recordkeeping 

requirements. However, the rule creates 

an obligation to perform leak surveys of 

Type B gathering lines. This sort of 

survey is currently required of 

transmission lines. Professional 

technicians will be needed to comply 

with this requirement, and the time 

required for compliance will vary 

greatly with each system, depending on 

the system’s size. 

The remainder of the Final Rule does 

not impose any significant compliance, 

recordkeeping, or reporting 

requirements. However, it affects the 

timing and substance of one type of 

report that must be created and 

maintained under existing regulations. 

The Final Rule stipulates that operators 

notify PHMSA field offices 60 days 

prior to pipe manufacturing or 

construction activities on new 

alternative MAOP pipelines. The 

current regulations require operators to 

notify PHMSA 180 days in advance of 

operating a pipeline at a higher 

alternative MAOP. Because operators 

must currently provide PHMSA with a 

180 day notice prior to operating at the 

alternative MAOP the Final Rule does 

not impose any additional reporting 

requirements. 

Identification, to the extent 

practicable, of all relevant Federal rules 

that may duplicate, overlap, or conflict 

with the Final Rule. 

PHMSA is unaware of any 

duplicative, overlapping, or conflicting 

Federal rules. 

Description of any significant 

alternatives to the Final Rule that 

accomplish the stated objectives of 

applicable statutes and that minimize 

any significant economic impact of the 


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Final Rule on small entities, including 

alternatives considered. 

PHMSA is unaware of any 

alternatives which would produce 

smaller economic impacts on small 

entities while at the same time meeting 

the objectives of the relevant statutes. 

Several provisions of the Final Rule are 

specifically designed to eliminate 

confusion and potentially lower costs 

for regulated entities. For example, the 

addition of 49 CFR 192.153(e) is 

designed to prevent regulated entities 

from purchasing pressure vessels that 

do not comply with § 192.505(b), but 

that do comply with ASME BPVC 

section VII, as required by 

§ 192.165(b)(3). PHMSA believes that 

this Final Rule impacts a substantial 

number of small entities but that this 

impact will be negligible. The one 

requirement that may have a significant 

cost impact on small businesses is leak 

surveys for Type B gas gathering lines. 

PHMSA estimates that requiring leakage 

surveys on Type B gas gathering lines 

will necessitate an annual expenditure 

of approximately 0.55 million dollars. 

The costs are based on surveying two 

miles of pipeline per day at an 

approximate daily cost of $300 per mile 

and PHMSA’s estimation that 50 

percent of the mileage affected by this 

proposal already complies with the 

surveying. The daily costs are an 

average day rate provided by two 

providers of leak survey services. 

The Small Business Administration’s 

North American Industry Classification 

System Code for gas transmission 

pipeline operators defines a small 

business as those operators that have 

annual revenue of less than 25.5 million 

dollars. It is PHMSA’s opinion that very 

few gas gathering operators have 

revenues less than 25.5 million dollars 

per year. No other types of small 

entities, such as manufacturers, will see 

a significant cost impact. Therefore, this 

amendment will not affect a substantial 

number of small businesses. Based on 

the facts available about the expected 

impact of this rulemaking, I certify, 

under Section 605 of the Regulatory 

Flexibility Act (5 U.S.C. 605) that this 

Final Rule will not have a significant 

economic impact on a substantial 

number of small entities. 

Executive Order 13175 

PHMSA has analyzed this Final Rule 

according to the principles and criteria 

in Executive Order 13175, 

‘‘Consultation and Coordination with 

Indian Tribal Governments.’’ Because 

this Final Rule does not significantly or 

uniquely affect the communities of the 

Indian tribal governments or impose 

substantial direct compliance costs, the 

funding and consultation requirements 

of Executive Order 13175 do not apply. 

Paperwork Reduction Act 

This Final Rule imposes no new 

requirements for recordkeeping and 

reporting. 

Unfunded Mandates Reform Act of 1995 

This Final Rule does not impose 

unfunded mandates under the 

Unfunded Mandates Reform Act of 

1995. It would not result in costs of 

$100 million, adjusted for inflation, 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 Final Rule. 

National Environmental Policy Act 

The National Environmental Policy 

Act (42 U.S.C. 4321–4375) requires that 

Federal agencies analyze final actions to 

determine whether those actions will 

have a significant impact on the human 

environment. The Council on 

Environmental Quality regulations 

requires Federal agencies to conduct an 

environmental review considering (1) 

the need for the final action, (2) 

alternatives to the final action, (3) 

probable environmental impacts of the 

final action and alternatives, and (4) the 

agencies and persons consulted during 

the consideration process. 40 CFR 

1508.9(b). 

1. Purpose and Need 

PHMSA’s mission is to protect people 

and the environment from the risks of 

hazardous materials transportation. The 

purpose of this rulemaking change is to 

improve compliance, provide 

clarification, address conflicting 

language and promote improved 

pipeline integrity and safety. In addition 

the purpose is to address small gaps in 

the current regulations and mitigate 

some of the negative externalities that 

can result from industry market failures. 

The need for this action stems from 

statutory requirements described in the 

Pipeline Safety, Regulatory Certainty, 

and job Creation Act of 2011 (Public 

Law 112–90), safety recommendations 

from the NTSB, and petitions from 

industry groups. In addition, due to 

shortfalls and unenforceability of 

industry standards, there arises a need 

for government to set minimum safety 

levels in pipeline regulations. 

PHMSA is making amendments and 

editorial changes to the regulations that 

includes modifying the requirements 

for: the performance of postconstruction inspections, the 

conducting of leak surveys of Type B 

onshore gas gathering lines, qualifying 

plastic pipe joiners, the regulation of 

ethanol, the transportation of pipe, the 

filing of offshore pipeline condition 

reports, and the calculation of pressure 

reductions for hazardous liquid pipeline 

anomalies. 

2. Alternatives 

In developing the Final Rule, PHMSA 

considered three alternatives: 

(1) No action. 

(2) Adopting all proposed 

amendments. 

(3) Adopting all proposed 

amendments except for leak surveys for 

Type Gas gathering lines. 

Alternative 1 

PHMSA has an obligation to ensure 

the safe and effective transportation of 

hazardous liquids and gases by pipeline. 

The changes in this Final Rule serve 

that purpose by clarifying the 

regulations and eliminating unduly 

burdensome requirements. A failure to 

undertake these actions would allow for 

the continued imposition of 

unnecessary compliance costs without 

increasing public safety. Accordingly, 

PHMSA rejected the no action 

alternative. 

Alternative 2 

PHMSA’s Selected Action is a set of 

amendments and editorial changes to 

the Federal Pipeline Safety Regulations 

(49 CFR parts 191, 192, and 195). These 

revisions would eliminate 

inconsistencies and respond to several 

petitions for rulemaking and 

recommendations from our 

stakeholders, thereby facilitating the 

safe and effective transportation of 

hazardous liquids and gases by pipeline. 

The changes in this Final Rule will 

serve that purpose by clarifying certain 

regulatory requirements. 

Alternative 3 

As discussed above under alternative 

2, and in the published NPRM, PHMSA 

proposed to make certain amendments, 

corrections and editorial changes to the 

regulations. These revisions eliminate 

inconsistencies and respond to several 

petitions for rulemaking and 

recommendations from our 

stakeholders, thereby facilitating the 

safe and effective transportation of 

hazardous liquids and gases by pipeline. 

The proposal related to leak survey for 

Type B gas gathering lines. PHMSA 

established a new method for 

determining whether a gas pipeline is 

an ‘‘onshore gathering line’’ in 2006. 

PHMSA also imposed new safety 

standards for ‘‘regulated onshore 

gathering lines,’’ which divided 

regulated onshore gathering lines into 


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two risk-based categories. Type A 

gathering lines are metallic lines with a 

MAOP of 20 percent or more of SMYS, 

as well as nonmetallic lines with an 

MAOP of more than 125 psig, in a Class 

2, 3, or 4 location. These lines are 

subject to all of the requirements in Part 

192 that apply to transmission lines, 

except for the regulation that requires 

the accommodation of in-line inspection 

tools in the design and construction of 

certain new and replaced pipelines (49 

CFR 192.150) and the integrity 

management requirements of Part 192, 

Subpart O. Operators of Type A 

gathering lines are also permitted to use 

an alternative process for demonstrating 

compliance with the requirements of 

Part 192, Subpart N, Qualification of 

Pipeline Personnel. 

Type B gathering lines includes 

metallic lines with a MAOP of less than 

20 percent of SMYS, as well as 

nonmetallic lines with a MAOP of 125 

psig or less, in a Class 2 location (as 

determined under one of three formulas) 

or in a Class 3 or Class 4 location. These 

lines are subject to less stringent 

requirements than Type A gathering 

lines. Specifically, any new or 

substantially changed Type B line must 

comply with the design, installation, 

construction, and initial testing and 

inspection requirements for 

transmission lines and, if of metallic 

construction, the corrosion control 

requirements for transmission lines. 

Operators must also include Type B 

gathering lines in their damage 

prevention and public education 

programs, establish the MAOP of those 

lines under § 192.619, and comply with 

the requirements for maintaining and 

installing line markers that apply to 

transmission lines. It is important that 

dependable leak detection surveys are 

used to identify leakage so that 

appropriate repairs can be initiated to 

our nation’s pipeline system. Prompt 

repair can help reduce the consequences 

of incidents to the public, environment 

and property. Performing field leak 

surveys is a preventative and proactive 

safety measure. Operator leak reporting 

also gives PHMSA valuable information 

that can be used in trending analysis for 

the determination of problematic 

materials or poor operating practices. 

Over time, unchecked leakage can 

potentially impact safety in addition to 

the fact that gas leaks have the risk of 

accidental ignition causing a fire or 

explosion. 

Prior to the 2006 Final Rule, operators 

had to perform leak surveys of non-rural 

gas gathering lines. Also, some Type B 

gathering lines are located under broad 

paved areas where electrical surveys 

(another means of detecting pipe 

damage) may be difficult to perform and 

leaking gas could migrate under the 

pavement and accumulate in 

surrounding structures. PHMSA 

believes that leak surveys are an 

effective means of ensuring the integrity 

of low-stress pipelines. Accordingly, 

PHMSA rejected this alternative. 

3. Analysis of Environmental Impacts 

The Nation’s pipelines are located 

throughout the United States in a 

variety of diverse environments—from 

offshore locations, to highly populated 

urban sites, to unpopulated rural areas. 

The pipeline infrastructure is a network 

of over 2.5 million miles of pipeline that 

move millions of gallons of hazardous 

liquids and over 55 billion cubic feet of 

natural gas daily. The biggest source of 

energy is petroleum, including oil and 

natural gas. Together, these 

commodities supply 65 percent of the 

energy in the United States. 

The physical environment potentially 

affected by the Final Rule includes 

airspace, water resources (e.g., oceans, 

streams, lakes), cultural and historical 

resources (e.g., properties listed on the 

National Register of Historic Places), 

biological and ecological resources (e.g., 

coastal zones, wetlands, plant and 

animal species and their habitat, forests, 

grasslands, offshore marine ecosystems) 

and special ecological resources (e.g., 

threatened and endangered plant and 

animal species and their habitat, 

national and state parklands, biological 

reserves, wild and scenic rivers) that 

exist directly adjacent to and within the 

vicinity of pipelines. 

Because the pipelines subject to the 

Final Rule contain hazardous materials, 

resources within the physically affected 

environment, as well as public health 

and safety, may be affected by gas 

pipeline incidents such as spills and 

leaks. Incidents on pipelines can result 

in fires and explosions, resulting in 

damage to the local environment. In 

addition, since pipelines often contain 

gas streams laden with condensates and 

natural gas liquids, failures also result 

in spills of these liquids, which can 

cause environmental harm. Depending 

on the size of a spill or gas leak and the 

nature of the impact zone, the 

environmental impacts could vary from 

property and environmental damage to 

injuries or, on rare occasions, fatalities. 

A majority of the amendments in this 

Final Rule are not substantive in nature 

and would have little or no impact on 

the human environment. It is likely that 

on a national scale, the cumulative 

environmental damage from pipelines is 

reduced, or at a minimum, unchanged. 

Requiring leakage surveys on Type B 

gathering lines will have positive 

environmental impacts. The 

Environmental Protection Agency (EPA) 

data indicate that methane contributed 

to nine percent of the reported 

greenhouse gas emissions in Calendar 

Year 2011 (www.epa.gov/methane/). 

Operators reported 289 leaks repaired 

on regulated Type B gathering lines in 

2011. It is expected that with formalized 

leak survey programs in place, 

emissions will be further reduced, in 

addition to enhanced safety from leak 

repairs. Although beneficial, this would 

not be a large-scale impact on the 

environment. 

For these reasons, PHMSA has 

concluded that neither of the 

alternatives discussed above would 

result in any significant impacts on the 

environment. 

4. Consultations 

Various industry associations and 

state regulatory agencies, such as the 

American Gas Association, the 

American Petroleum Associations and 

NAPSR, were consulted in the 

development of this rulemaking. 

5. Finding of No Significant Impact 

PHMSA has determined that the 

selected alternative would not have a 

significant impact on the human 

environment. 

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 

published in the Federal Register on 

April 11, 2000, (70 FR 19477). 

Executive Order 13132 

PHMSA has analyzed this Final Rule 

according to Executive Order 13132 

(‘‘Federalism’’). The Final Rule does not 

have a substantial direct effect on the 

states, the relationship between the 

national government and the states, or 

the distribution of power and 

responsibilities among the various 

levels of government. This Final Rule 

does not impose substantial direct 

compliance costs on state and local 

governments. This Final Rule does not 

preempt state law for intrastate 

pipelines. Therefore, the consultation 

and funding requirements of Executive 

Order 13132 do not apply. 

Executive Order 13211 

This Final Rule is not a ‘‘significant 

energy action’’ under Executive Order 

13211 (Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use). It is not likely to 

have a significant adverse effect on 

supply, distribution, or energy use. 


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Further, the Office of Information and 

Regulatory Affairs has not designated 

this Final Rule as a significant energy 

action. 

List of Subjects 

49 CFR Part 191 

Pipeline Safety, Reporting, and 

recordkeeping requirements. 

49 CFR Part 192 

Fire prevention, Incorporation by 

reference, Pipeline safety, Security 

measures 

49 CFR Part 195 

Ammonia, Carbon dioxide, 

Incorporation by reference, Petroleum, 

Pipeline safety, Reporting and 

recordkeeping requirements. 

In consideration of the foregoing, 49 

CFR Chapter I is amended as follows: 

PART 191—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE; ANNUAL REPORTS, 

INCIDENT REPORTS, AND SAFETYRELATED CONDITION REPORTS 

■ 1. The authority citation for Part 191 

is revised to read as follows: 

Authority: 49 U.S.C. 5121, 60102, 60103, 

60104, 60108, 60117, 60118, 60124, 60132, 

and 49 CFR 1.97. 

■ 2. In § 191.7 paragraphs (a) and (b) are 

revised and paragraph (e) is added to 

read as follows: 

§ 191.7 Report submission requirements. 

(a) General. Except as provided in 

paragraphs (b) and (e) of this section, an 

operator must submit each report 

required by this part electronically to 

the Pipeline and Hazardous Materials 

Safety Administration at http://

portal.phmsa.dot.gov/pipeline unless an 

alternative reporting method is 

authorized in accordance with 

paragraph (d) of this section. 

(b) Exceptions: An operator is not 

required to submit a safety-related 

condition report (§ 191.25) 

electronically. 

* * * * * 

(e) National Pipeline Mapping System 

(NPMS). An operator must provide the 

NPMS data to the address identified in 

the NPMS Operator Standards manual 

available at www.npms.phmsa.dot.gov 

or by contacting the PHMSA Geographic 

Information Systems Manager at (202) 

366–4595. 

■ 3. In § 191.25 paragraph (a) is revised 

to read as follows: 

§ 191.25 Filing safety-related condition 

reports. 

(a) Each report of a safety-related 

condition under § 191.23(a) must be 

filed (received by OPS within five 

working days, not including Saturday, 

Sunday, or Federal Holidays) after the 

day a representative of the operator first 

determines that the condition exists, but 

not later than 10 working days after the 

day a representative of the operator 

discovers the condition. Separate 

conditions may be described in a single 

report if they are closely related. Reports 

may be transmitted by electronic mail to 

InformationResourcesManager@dot.gov 

or by facsimile at (202) 366–7128. 

* * * * * 

§ 191.27 [Removed]. 

■ 4. Section 191.27 is removed. 

■ 5. Section 191.29 is added to read as 

follows: 

§ 191.29 National Pipeline Mapping 

System. 

(a) Each operator of a gas transmission 

pipeline or liquefied natural gas facility 

must provide the following geospatial 

data to PHMSA for that pipeline or 

facility: 

(1) Geospatial data, attributes, 

metadata and transmittal letter 

appropriate for use in the National 

Pipeline Mapping System. Acceptable 

formats and additional information are 

specified in the NPMS Operator 

Standards Manual available at 

www.npms.phmsa.dot.gov or by 

contacting the PHMSA Geographic 

Information Systems Manager at (202) 

366–4595. 

(2) The name of and address for the 

operator. 

(3) The name and contact information 

of a pipeline company employee, to be 

displayed on a public Web site, who 

will serve as a contact for questions 

from the general public about the 

operator’s NPMS data. 

(b) The information required in 

paragraph (a) of this section must be 

submitted each year, on or before March 

15, representing assets as of December 

31 of the previous year. If no changes 

have occurred since the previous year’s 

submission, the operator must comply 

with the guidance provided in the 

NPMS Operator Standards manual 

available at www.npms.phmsa.dot.gov 

or contact the PHMSA Geographic 

Information Systems Manager at (202) 

366–4595. 

PART 192—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE: MINIMUM FEDERAL 

SAFETY STANDARDS 

■ 6. The authority citation for Part 192 

is revised to read as follows: 

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

60108, 60109, 60110, 60113, 60116 and 

60118, 60137; and 49 CFR 1.97. 

■ 7. In § 192.3, definitions for ‘‘Welder’’ 

and ‘‘Welding operator’’ are added in 

alphabetical order to read as follows: 

§ 192.3 Definitions. 

* * * * * 

Welder means a person who performs 

manual or semi-automatic welding. 

Welding operator means a person who 

operates machine or automatic welding 

equipment. 

■ 8. In § 192.9, paragraph (d)(7) is added 

to read as follows: 

§ 192.9 What requirements apply to 

gathering lines? 

* * * * * 

(d) * * * 

(7) Conduct leakage surveys in 

accordance with § 192.706 using leak 

detection equipment and promptly 

repair hazardous leaks that are 

discovered in accordance with 

§ 192.703(c). 

* * * * * 

■ 9. In § 192.65, paragraph (a) is revised 

to read as follows: 

§ 192.65 Transportation of pipe. 

(a) Railroad. In a pipeline to be 

operated at a hoop stress of 20 percent 

or more of SMYS, an operator may not 

install pipe having an outer diameter to 

wall thickness of 70 to 1, or more, that 

is transported by railroad unless the 

transportation is performed by API RP 

5L1 (incorporated by reference, see 

§ 192.7). 

* * * * * 

■ 10. In the table in § 192.112, 

paragraph (e) is revised to read as 

follows: 

§ 192.112 Additional design requirements 

for steel pipe using alternative maximum 

allowable operating pressure. 

* * * * * 


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To address this 

design issue: The pipeline segment must meet these additional requirements: 

*******

(e) Mill hydrostatic test.(1) All pipe to be used in a new pipeline segment installed after October 1, 2015, must be hydrostatically tested at the mill at 

a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. 

(2) Pipe in operation prior to December 22, 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. 

(3) Pipe in operation on or after December 22, 2008, but before October 1, 2015, must have been 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 ‘‘ANSI/API Spec 5L’’ (incorporated by reference, see § 192.7). 

* * * * * * * 

■ 11. In § 192.153, a new paragraph (e) 

is added to read as follows: 

§ 192.153 Components fabricated by 

welding. 

* * * * * 

(e) A component having a design 

pressure established in accordance with 

paragraph (a) or paragraph (b) of this 

section and subject to the strength 

testing requirements of § 192.505(b) 

must be tested to at least 1.5 times the 

MAOP. 

■ 12. In § 192.165, paragraph (b)(3) is 

revised to read as follows: 

§ 192.165 Compressor stations: Liquid 

removal. 

* * * * * 

(b) * * * 

(3) Be manufactured in accordance 

with section VIII ASME Boiler and 

Pressure Vessel Code (BPVC) 

(incorporated by reference, see § 192.7) 

and the additional requirements of 

§ 192.153(e) except that liquid 

separators constructed of pipe and 

fittings without internal welding must 

be fabricated with a design factor of 0.4, 

or less. 

■ 13. In § 192.225, paragraph (a) is 

revised to read as follows: 

§ 192.225 Welding procedures. 

(a) Welding must be performed by a 

qualified welder or welding operator in 

accordance with welding procedures 

qualified under section 5, section 12, or 

Appendix A of API Std 1104 

(incorporated by reference, see § 192.7) 

or section IX ASME Boiler and Pressure 

Vessel Code (BPVC) (incorporated by 

reference, see § 192.7), to produce welds 

which meet the requirements of this 

subpart. The quality of the test welds 

used to qualify welding procedures 

must be determined by destructive 

testing in accordance with the 

referenced welding standard(s). 

* * * * * 

■ 14. Section 192.227 is revised to read 

as follows: 

§ 192.227 Qualification of welders and 

welding operators. 

(a) Except as provided in paragraph 

(b) of this section, each welder or 

welding operator must be qualified in 

accordance with section 6, section 12, or 

Appendix A of API Std 1104 

(incorporated by reference, see § 192.7), 

or section IX of ASME Boiler and 

Pressure Vessel Code (BPVC) 

(incorporated by reference, see § 192.7). 

However, a welder or welding operator 

qualified under an earlier edition than 

the edition listed in § 192.7 may weld 

but may not re-qualify under that earlier 

edition. 

(b) A welder may qualify to perform 

welding on pipe to be operated at a 

pressure that produces a hoop stress of 

less than 20 percent of SMYS by 

performing an acceptable test weld, for 

the process to be used, under the test set 

forth in section I of Appendix C of this 

part. Each welder who is to make a 

welded service line connection to a 

main must first perform an acceptable 

test weld under section II of Appendix 

C of this part as a requirement of the 

qualifying test. 

■ 15. Section 192.229 is revised to read 

as follows: 

§ 192.229 Limitations on welders and 

welding operators. 

(a) No welder or welding operator 

whose qualification is based on 

nondestructive testing may weld 

compressor station pipe and 

components. (b) A welder or welding operator may 

not weld with a particular welding 

process unless, within the preceding 6 

calendar months, the welder or welding 

operator was engaged in welding with 

that process. (c) A welder or welding operator 

qualified under § 192.227(a)— (1) May not weld on pipe to be 

operated at a pressure that produces a 

hoop stress of 20 percent or more of 

SMYS unless within the preceding 6 

calendar months the welder or welding 

operator has had one weld tested and 

found acceptable under either section 6, 

section 9, section 12 or Appendix A of 

API Std 1104 (incorporated by 

reference, see § 192.7). Alternatively, 

welders or welding operators may 

maintain an ongoing qualification status 

by performing welds tested and found 

acceptable under the above acceptance 

criteria at least twice each calendar year, 

but at intervals not exceeding 71⁄2

months. A welder or welding operator 

qualified under an earlier edition of a 

standard listed in § 192.7 of this part 

may weld, but may not re-qualify under 

that earlier edition; and, 

(2) May not weld on pipe to be 

operated at a pressure that produces a 

hoop stress of less than 20 percent of 

SMYS unless the welder or welding 

operator is tested in accordance with 

paragraph (c)(1) of this section or requalifies under paragraph (d)(1) or (d)(2) 

of this section. 

(d) A welder or welding operator 

qualified under § 192.227(b) may not 

weld unless— 

(1) Within the preceding 15 calendar 

months, but at least once each calendar 

year, the welder or welding operator has 

re-qualified under § 192.227(b); or (2) Within the preceding 71⁄2 calendar 

months, but at least twice each calendar 

year, the welder or welding operator has 

had— 

(i) A production weld cut out, tested, 

and found acceptable in accordance 

with the qualifying test; or (ii) For a welder who works only on 

service lines 2 inches (51 millimeters) or 

smaller in diameter, the welder has had 

two sample welds tested and found 

acceptable in accordance with the test 

in section III of Appendix C of this part. 

■ 16. In § 192.241, paragraph (c) is 

revised to read as follows: 

§ 192.241 Inspection and test of welds. 

* * * * * 

(c) The acceptability of a weld that is 

nondestructively tested or visually 

inspected is determined according to 

the standards in section 9 or Appendix 

A of API Std 1104 (incorporated by 


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reference, see § 192.7). Appendix A of 

API Std 1104 may not be used to accept 

cracks. 

■ 17. In § 192.243, paragraph (e) is 

revised to read as follows: 

§ 192.243 Nondestructive testing. 

* * * * * 

(e) Except for a welder or welding 

operator whose work is isolated from 

the principal welding activity, a sample 

of each welder or welding operator’s 

work for each day must be 

nondestructively tested, when 

nondestructive testing is required under 

§ 192.241(b). 

* * * * * 

■ 18. In § 192.285, paragraph (c) is 

revised to read as follows: 

§ 192.285 Plastic pipe: Qualifying persons 

to make joints. 

* * * * * 

(c) A person must be re-qualified 

under an applicable procedure once 

each calendar year at intervals not 

exceeding 15 months, or after any 

production joint is found unacceptable 

by testing under § 192.513. 

* * * * * 

■ 19. Section 192.305 is revised to read 

as follows: 

§ 192.305 Inspection: General. 

Each transmission line and main must 

be inspected to ensure that it is 

constructed in accordance with this 

subpart. An operator must not use 

operator personnel to perform a 

required inspection if the operator 

personnel performed the construction 

task requiring inspection. Nothing in 

this section prohibits the operator from 

inspecting construction tasks with 

operator personnel who are involved in 

other construction tasks. 

■ 20. In § 192.503, a new paragraph (e) 

is added to read as follows: 

§ 192.503 General requirements. 

* * * * * 

(e) If a component other than pipe is 

the only item being replaced or added 

to a pipeline, a strength test after 

installation is not required, if the 

manufacturer of the component certifies 

that: 

(1) The component was tested to at 

least the pressure required for the 

pipeline to which it is being added; 

(2) The component was manufactured 

under a quality control system that 

ensures that each item manufactured is 

at least equal in strength to a prototype 

and that the prototype was tested to at 

least the pressure required for the 

pipeline to which it is being added; or 

(3) The component carries a pressure 

rating established through applicable 

ASME/ANSI, Manufacturers 

Standardization Society of the Valve 

and Fittings Industry, Inc. (MSS) 

specifications, or by unit strength 

calculations as described in § 192.143. 

§ 192.505 [Amended] 

■ 21. In § 192.505, paragraph (d) is 

removed and paragraph (e) is 

redesignated as paragraph (d). 

■ 22. In § 192.620, paragraph (c)(1) and 

the first sentence of paragraph (c)(8) are 

revised to read as follows: 

§ 192.620 Alternative maximum operating 

pressure for certain steel pipelines. 

* * * * * 

(c) * * * 

(1) For pipelines already in service, 

notify the PHMSA pipeline safety 

regional office where the pipeline is in 

service of the intention to use the 

alternative pressure at least 180 days 

before operating at the alternative 

MAOP. For new pipelines, notify the 

PHMSA pipeline safety regional office 

of planned alternative MAOP design 

and operation at least 60 days prior to 

the earliest start date of either pipe 

manufacturing or construction 

activities. An operator must also notify 

the state pipeline safety authority when 

the pipeline is located in a state where 

PHMSA has an interstate agent 

agreement or where an intrastate 

pipeline is regulated by that state. 

* * * * * 

(8) A Class 1 and Class 2 location can 

be upgraded one class due to class 

changes per § 192.611(a). * * * 

* * * * * 

■ 23. In § 192.805 paragraph (i) is 

revised to read as follows: 

§ 192.805 Qualification program. 

* * * * * 

(i) After December 16, 2004, notify the 

Administrator or a state agency 

participating under 49 U.S.C. Chapter 

601 if the operator significantly 

modifies the program after the 

administrator or state agency has 

verified that it complies with this 

section. Notifications to PHMSA may be 

submitted by electronic mail to 

InformationResourcesManager@dot.gov, 

or by mail to ATTN: Information 

Resources Manager DOT/PHMSA/OPS, 

East Building, 2nd Floor, E22–321, New 

Jersey Avenue SE., Washington, DC 

20590. 

■ 24. In § 192.925, the introductory text 

of paragraph (b) and the introductory 

text of paragraph (b)(2) are revised to 

read as follows: 

§ 192.925 What are the requirements for 

using External Corrosion Direct 

Assessment (ECDA)? 

* * * * * 

(b) General requirements. An operator 

that uses direct assessment to assess the 

threat of external corrosion must follow 

the requirements in this section, in 

ASME/ANSI B31.8S (incorporated by 

reference, see § 192.7), section 6.4, and 

in NACE SP0502 (incorporated by 

reference, see § 192.7). An operator must 

develop and implement a direct 

assessment plan that has procedures 

addressing pre-assessment, indirect 

inspection, direct examination, and post 

assessment. If the ECDA detects 

pipeline coating damage, the operator 

must also integrate the data from the 

ECDA with other information from the 

data integration (§ 192.917(b)) to 

evaluate the covered segment for the 

threat of third party damage and to 

address the threat as required by 

§ 192.917(e)(1). 

* * * * * 

(2) Indirect inspection. In addition to 

the requirements in ASME/ANSI 

B31.8S, section 6.4 and in NACE 

SP0502, section 4, the plan’s procedures 

for indirect inspection of the ECDA 

regions must include— 

* * * * * 

■ 25. Section 192.949 is revised to read 

as follows: 

§ 192.949 How does an operator notify 

PHMSA? 

An operator must provide any 

notification required by this subpart 

by— 

(a) Sending the notification by 

electronic mail to 

InformationResourcesManager@dot.gov; 

or 

(b) Sending the notification by mail to 

ATTN: Information Resources Manager, 

DOT/PHMSA/OPS, East Building, 2nd 

Floor, E22–321, 1200 New Jersey Ave. 

SE., Washington, DC 20590. 

PART 195—TRANSPORTATION OF 

HAZARDOUS LIQUIDS BY PIPELINE 

■ 26. The authority citation for Part 195 

is revised to read as follows: 

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

60108, 60109, 60116, 60118, 60132, 60137, 

and 49 CFR 1.97. 

■ 27. In § 195.2, the definitions of 

‘‘alarm’’ and ‘‘hazardous liquid’’ are 

revised and definitions for ‘‘welder’’ 

and ‘‘welder operator’’ are added in 

appropriate alphabetical order to read as 

follows: 

§ 195.2 Definitions. 

* * * * * 


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Alarm means an audible or visible 

means of indicating to the controller 

that equipment or processes are outside 

operator-defined, safety-related 

parameters. 

* * * * * 

Hazardous liquid means petroleum, 

petroleum products, anhydrous 

ammonia, or ethanol. 

* * * * * 

Welder means a person who performs 

manual or semi-automatic welding. 

Welding operator means a person who 

operates machine or automatic welding 

equipment. 

■ 28. In § 195.56 paragraph (a) is revised 

to read as follows: 

§ 195.56 Filing safety-related condition 

reports. 

(a) Each report of a safety-related 

condition under § 195.55(a) must be 

filed (received by OPS) within five 

working days (not including Saturday, 

Sunday, or Federal Holidays) after the 

day a representative of the operator first 

determines that the condition exists, but 

not later than 10 working days after the 

day a representative of the operator 

discovers the condition. Separate 

conditions may be described in a single 

report if they are closely related. Reports 

may be transmitted by electronic mail to 

InformationResourcesManager@dot.gov, 

or by facsimile at (202) 366–7128. 

* * * * * 

§ 195.57 [Removed] 

■ 29. Section 195.57 is removed. 

■ 30. In § 195.58, paragraphs (a) and (b) 

are revised and a new paragraph (e) is 

added to read as follows: 

§ 195.58 Report submission requirements. 

(a) General. Except as provided in 

paragraphs (b) and (e) of this section, an 

operator must submit each report 

required by this part electronically to 

PHMSA at http://opsweb.phmsa.dot.gov 

unless an alternative reporting method 

is authorized in accordance with 

paragraph (d) of this section. 

(b) Exceptions: An operator is not 

required to submit a safety-related 

condition report (§ 195.56) 

electronically. 

* * * * * 

(e) National Pipeline Mapping System 

(NPMS). An operator must provide 

NPMS data to the address identified in 

the NPMS Operator Standards Manual 

available at www.npms.phmsa.dot.gov 

or by contacting the PHMSA Geographic 

Information Systems Manager at (202) 

366–4595. 

■ 31. Section 195.61 is added to read as 

follows: 

§ 195.61 National Pipeline Mapping 

System. 

(a) Each operator of a hazardous 

liquid pipeline facility must provide the 

following geospatial data to PHMSA for 

that facility: 

(1) Geospatial data, attributes, 

metadata and transmittal letter 

appropriate for use in the National 

Pipeline Mapping System. Acceptable 

formats and additional information are 

specified in the NPMS Operator 

Standards manual available at 

www.npms.phmsa.dot.gov or by 

contacting the PHMSA Geographic 

Information Systems Manager at (202) 

366–4595. 

(2) The name of and address for the 

operator. 

(3) The name and contact information 

of a pipeline company employee, to be 

displayed on a public Web site, who 

will serve as a contact for questions 

from the general public about the 

operator’s NPMS data. 

(b) This information must be 

submitted each year, on or before June 

15, representing assets as of December 

31 of the previous year. If no changes 

have occurred since the previous year’s 

submission, the operator must refer to 

the information provided in the NPMS 

Operator Standards manual available at 

www.npms.phmsa.dot.gov or contact the 

PHMSA Geographic Information 

Systems Manager at (202) 366–4595. 

§ 195.64 [Removed] 

■ 32. In § 195.64, paragraph (c)(1)(iii) is 

removed. 

■ 33. Section 195.204 is revised to read 

as follows: 

§ 195.204 Inspection—general. 

Inspection must be provided to ensure 

that the installation of pipe or pipeline 

systems is in accordance with the 

requirements of this subpart. Any 

operator personnel used to perform the 

inspection must be trained and qualified 

in the phase of construction to be 

inspected. An operator must not use 

operator personnel to perform a 

required inspection if the operator 

personnel performed the construction 

task requiring inspection. Nothing in 

this section prohibits the operator from 

inspecting construction tasks with 

operator personnel who are involved in 

other construction tasks. 

■ 34. In § 195.214, paragraph (a) is 

revised to read as follows: 

§ 195.214 Welding procedures. 

(a) Welding must be performed by a 

qualified welder or welding operator in 

accordance with welding procedures 

qualified under section 5, section 12 or 

Appendix A of API Std 1104 

(incorporated by reference, see § 195.3), 

or section IX of ASME Boiler and 

Pressure Vessel Code (BPVC) 

(incorporated by reference, see § 195.3). 

The quality of the test welds used to 

qualify welding procedures must be 

determined by destructive testing. 

* * * * * 

■ 35. In § 195.222 the heading, 

paragraph (a), the introductory text of 

paragraph (b), and paragraph (b)(2) are 

revised to read as follows: 

§ 195.222 Welders and welding operators: 

Qualification of welders and welding 

operators. 

(a) Each welder or welding operator 

must be qualified in accordance with 

section 6, section 12 or Appendix A of 

API Std 1104 (incorporated by 

reference, see § 195.3), or section IX of 

ASME Boiler and Pressure Vessel Code 

(BPVC), (incorporated by reference, see 

§ 195.3), except that a welder or welding 

operator qualified under an earlier 

edition than an edition listed in § 195.3, 

may weld but may not re-qualify under 

that earlier edition. 

(b) No welder or welding operator 

may weld with a welding process 

unless, within the preceding 6 calendar 

months, the welder or welding operator 

has— 

* * * * * 

(2) Had one weld tested and found 

acceptable under section 9 or Appendix 

A of API Std 1104 (incorporated by 

reference, see § 195.3). 

■ 36. In § 195.228, paragraph (b) is 

revised to read as follows: 

§ 195.228 Welds and welding inspection: 

Standards of acceptability. 

* * * * * 

(b) The acceptability of a weld is 

determined according to the standards 

in section 9 or Appendix A of API Std 

1104 (incorporated by reference, see 

§ 195.3). Appendix A of API Std 1104 

may not be used to accept cracks. 

■ 37. In § 195.234, paragraph (d) is 

revised to read as follows: 

§ 195.234 Welds: Nondestructive testing. 

* * * * * 

(d) During construction, at least 10 

percent of the girth welds made by each 

welder and welding operator during 

each welding day must be 

nondestructively tested over the entire 

circumference of the weld. 

* * * * * 

■ 38. In § 195.307 paragraphs (c) and (d) 

are revised to read as follows: 


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§ 195.307 Pressure testing aboveground 

breakout tanks. 

* * * * * 

(c) For aboveground breakout tanks 

built to API Std 650 (incorporated by 

reference, see § 195.3) and first placed 

in service after October 2, 2000, testing 

must be in accordance with sections 

7.3.5 and 7.3.6 of API Standard 650 

(incorporated by reference, see § 195.3). 

(d) For aboveground atmospheric 

pressure breakout tanks constructed of 

carbon and low alloy steel, welded or 

riveted, and non-refrigerated tanks built 

to API Std 650 or its predecessor 

Standard 12 C that are returned to 

service after October 2, 2000, the 

necessity for the hydrostatic testing of 

repair, alteration, and reconstruction is 

covered in section 12.3 of API Standard 

653 (incorporated by reference, see 

§ 195.3). 

* * * * * 

■ 39. In § 195.428, paragraph (c) is 

revised to read as follows: 

§ 195.428 Overpressure safety devices and 

overfill protection systems. 

* * * * * 

(c) Aboveground breakout tanks that 

are constructed or significantly altered 

according to API Std 2510 (incorporated 

by reference, see § 195.3) after October 

2, 2000, must have an overfill protection 

system installed according to API Std 

2510, section 7.1.2. Other aboveground 

breakout tanks with 600 gallons (2271 

liters) or more of storage capacity that 

are constructed or significantly altered 

after October 2, 2000, must have an 

overfill protection system installed 

according to API RP 2350 (incorporated 

by reference, see § 195.3). However, an 

operator need not comply with any part 

of API RP 2350 for a particular breakout 

tank if the operator describes in the 

manual required by § 195.402 why 

compliance with that part is not 

necessary for safety of the tank. 

* * * * * 

■ 40. In § 195.452, paragraph (h)(4)(i) 

introductory text and paragraph (m) are 

revised to read as follows: 

§ 195.452 Pipeline integrity management in 

high consequence areas. 

* * * * * 

(h) * * * 

(4) * * * 

(i) Immediate repair conditions. An 

operator’s evaluation and remediation 

schedule must provide for immediate 

repair conditions. To maintain safety, an 

operator must temporarily reduce the 

operating pressure or shut down the 

pipeline until the operator completes 

the repair of these conditions. An 

operator must calculate the temporary 

reduction in operating pressure using 

the formulas referenced in paragraph 

(h)(4)(i)(B) of this section. If no suitable 

remaining strength calculation method 

can be identified, an operator must 

implement a minimum 20 percent or 

greater operating pressure reduction, 

based on actual operating pressure for 

two months prior to the date of 

inspection, until the anomaly is 

repaired. An operator must treat the 

following conditions as immediate 

repair conditions: 

* * * * * 

(m) How does an operator notify 

PHMSA? An operator must provide any 

notification required by this section by: 

(1) Sending the notification by 

electronic mail to 

InformationResourcesManager@dot.gov; 

or 

(2) Sending the notification by mail to 

ATTN: Information Resources Manager, 

DOT/PHMSA/OPS, East Building, 2nd 

Floor, E22–321, 1200 New Jersey Ave 

SE., Washington, DC 20590. 

■ 41. In § 195.505 paragraph (i) is 

revised to read as follows: 

§ 195.505 Qualification program. 

* * * * * 

(i) After December 16, 2004, notify the 

Administrator or a state agency 

participating under 49 U.S.C. Chapter 

601 if the operator significantly 

modifies the program after the 

administrator or state agency has 

verified that it complies with this 

section. Notifications to PHMSA may be 

submitted by electronic mail to 

InformationResourcesManager@dot.gov, 

or by mail to ATTN: Information 

Resources Manager DOT/PHMSA/OPS, 

East Building, 2nd Floor, E22–321, New 

Jersey Avenue SE., Washington, DC 

20590. 

■ 42. Section 195.571 is revised to read 

as follows: 

§ 195.571 What criteria must I use to 

determine the adequacy of cathodic 

protection? 

Cathodic protection required by this 

subpart must comply with one or more 

of the applicable criteria and other 

considerations for cathodic protection 

contained paragraphs 6.2.2, 6.2.3, 6.2.4, 

6.2.5 and 6.3 in NACE SP 0169 

(incorporated by reference, see § 195.3). 

Issued in Washington, DC, on February 26, 

2015, under authority delegated in 49 CFR 

1.97. 

Timothy P. Butters, 

Acting Administrator. 

[FR Doc. 2015–04440 Filed 3–10–15; 8:45 am] 

BILLING CODE 4910–60–P 

DEPARTMENT OF COMMERCE 

National Oceanic and Atmospheric 

Administration 

50 CFR Part 679 

[Docket No. 141021887–5172–02] 

RIN 0648–XD813 

Fisheries of the Exclusive Economic 

Zone Off Alaska; Reallocation of 

Pollock in the Bering Sea and Aleutian 

Islands 

AGENCY: National Marine Fisheries 

Service (NMFS), National Oceanic and 

Atmospheric Administration (NOAA), 

Commerce. 

ACTION: Temporary rule. 

SUMMARY: NMFS is reallocating the 

projected unused amounts of the 

Community Development Quota pollock 

directed fishing allowances from the 

Aleutian Islands subarea to the Bering 

Sea subarea. This action is necessary to 

provide opportunity for harvest of the 

2015 total allowable catch of pollock, 

consistent with the goals and objectives 

of the Fishery Management Plan for 

Groundfish of the Bering Sea and 

Aleutian Islands Management Area. 

DATES: Effective 1200 hrs, Alaska local 

time (A.l.t.), March 11, 2015 through 

2400 hrs, A.l.t., December 31, 2015. 

FOR FURTHER INFORMATION CONTACT: 

Steve Whitney, 907–586–7228. 

SUPPLEMENTARY INFORMATION: NMFS 

manages the groundfish fishery in the 

BSAI exclusive economic zone 

according to the Fishery Management 

Plan for Groundfish of the Bering Sea 

and Aleutian Islands Management Area 

(FMP) prepared by the North Pacific 

Fishery Management Council (Council) 

under authority of the MagnusonStevens Fishery Conservation and 

Management Act. Regulations governing 

fishing by U.S. vessels in accordance 

with the FMP appear at subpart H of 50 

CFR part 600 and 50 CFR part 679. 

In the Aleutian Islands subarea, the 

portion of the 2015 pollock total 

allowable catch (TAC) allocated to the 

Community Development Quota (CDQ) 

directed fishing allowance (DFA) is 

1,900 metric tons (mt) as established by 

the final 2015 and 2016 harvest 

specifications for groundfish in the 

BSAI (80 FR 11919, March 5, 2015). 

As of March 5, 2015, the 

Administrator, Alaska Region, NMFS, 

(Regional Administrator) has 

determined that 1,900 mt of pollock 

CDQ DFA in the Aleutian Islands 

subarea will not be harvested. 

Therefore, in accordance with 

§ 679.20(a)(5)(iii)(B)(4), NMFS 


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