[Federal Register Volume 76, Number 229 (Tuesday, November 29, 2011)]
[Proposed Rules]
[Pages 73570-73581]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-29852]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191, 192, 195 and 198

[Docket No. PHMSA-2010-0026]
RIN 2137-AE59


Pipeline Safety: Miscellaneous Changes to Pipeline Safety 
Regulations

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), 
Department of Transportation (DOT).

ACTION: Notice of proposed rulemaking.

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SUMMARY: PHMSA is proposing to make miscellaneous changes to the 
pipeline safety regulations. The proposed changes would correct errors, 
address inconsistencies, and respond to rulemaking petitions. The 
requirements in several subject matter areas would be affected, 
including the performance of post-construction inspections; leak 
surveys of Type B onshore gas gathering lines; the requirements for 
qualifying plastic pipe joiners; the regulation of ethanol; the 
transportation of pipe; the filing of offshore pipeline condition 
reports; the calculation of pressure reductions for hazardous liquid 
pipeline anomalies; and the odorization of gas transmission lateral 
lines.
    The proposed changes are addressed on an individual basis and, 
where appropriate, would be made applicable to the safety standards for 
both gas and hazardous liquid pipelines. Editorial changes are also 
included.

DATES: Submit comments by February 3, 2012.

ADDRESSES: Comments should reference Docket No. PHMSA-2010-0026 and may 
be submitted in the following ways:
     E-Gov Web site: http://www.regulations.gov. This Web site 
allows the public to enter comments on any Federal Register notice 
issued by any agency. Follow the instructions for submitting comments.
     Fax: 1-(202) 493-2251.
     Mail: Docket Management System: U.S. Department of 
Transportation, Docket Operations, M-30, Room W12-140, 1200 New Jersey 
Avenue SE., Washington, DC 20590-0001.
     Hand Delivery: DOT Docket Management System, West Building 
Ground Floor, Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 
20590-0001 between 9 a.m. and 5 p.m., Monday through Friday, except 
Federal holidays.
    Instructions: If you submit your comments by mail, please submit 
two copies. To receive confirmation that PHMSA received your comments, 
include a self-addressed stamped postcard.

    Note: Comments are posted without changes or edits to http://www.regulations.gov, including any personal information provided. 
There is a privacy statement published on http://www.regulations.gov.

    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), or visit http://dms.dot.gov.

FOR FURTHER INFORMATION CONTACT: John A. Gale, Director of Standards 
and Rulemaking by telephone at (202) 366-4046 or by Email at 
john.gale@dot.gov.

SUPPLEMENTARY INFORMATION: 

Background

    PHMSA is proposing to make miscellaneous changes to the pipeline 
safety regulations. The proposed changes would be relatively minor, 
would impose minimal (if any) burden, and would clarify the existing 
regulations. The following issues are addressed below:

    [cir] Responsibility to Conduct Construction Inspections
    [cir] Leak Surveys for Type B Gathering Lines
    [cir] Qualifying Plastic Pipe Joiners
    [cir] Mill Hydrostatic Tests for Pipe to Operate at Alternative 
MAOP
    [cir] Regulating the Transportation of Ethanol by Pipeline
    [cir] Limitation of Indirect Costs in State Grants
    [cir] Transportation of Pipe
    [cir] Threading Copper Pipe
    [cir] Offshore Pipeline Condition Reports
    [cir] Calculating Pressure Reductions for Hazardous Liquid 
Pipeline Integrity Anomalies
    [cir] Testing Components other than Pipe Installed in Low-
Pressure Gas Pipelines
    [cir] Alternative MAOP Notifications
    [cir] National Pipeline Mapping System
    [cir] Welders vs. Welding Operators
    [cir] Components Fabricated by Welding
    [cir] Odorization of Gas
    [cir] Editorial Amendments

Responsibility To Conduct Construction Inspections--NAPSR-CR-1-02

    Section 192.305 states that each gas transmission line or main must 
be inspected to ensure that it is constructed in accordance with the 
requirements of 49 CFR part 192. These inspections are important 
because transmission pipelines and mains are generally buried after 
construction. Subsequent examinations often involve a difficult 
excavation process.
    The National Association of Pipeline Safety Representatives (NAPSR) 
\1\ has suggested that the current regulation should be changed to 
require a greater degree of independence. Specifically, NAPSR believes 
that contractors who install a transmission line or main should be 
prohibited from inspecting their own work for compliance purposes.
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    \1\ NAPSR 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.
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    PHMSA agrees with NAPSR. Section 192.305 does not prohibit a 
contractor who installs a transmission line or main from inspecting 
their own work; that lack of independence raises public safety 
concerns. PHMSA believes the same concerns apply to non-contractor 
pipeline personnel as well. Accordingly, PHMSA is proposing to revise 
Sec.  192.305 to specify that a transmission pipeline or main cannot be 
inspected by someone who participated in its construction.
    Section 195.204 imposes a similar construction inspection 
requirement for hazardous liquid pipelines. PHMSA has proposed to make 
the same rule change applicable to Sec.  195.204.

Leak Surveys for Type B Gathering Lines

    In March 2006 (71 FR 13289), PHMSA established a new method for 
determining whether a gas pipeline is an ``onshore gathering line.'' 
PHMSA also imposed new safety standards for ``regulated onshore 
gathering lines,'' which divided regulated onshore gathering lines into 
two risk-based categories.
    Type A gathering lines are metallic lines with a MAOP of 20% or 
more of specified minimum yield strength (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

[[Page 73571]]

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% 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 49 CFR 192.619, and comply with the requirements for 
maintaining and installing line markers that apply to transmission 
lines.
    NAPSR notes that the current regulations do not require leak 
surveys of Type B gathering lines. NAPSR states that gas leaks are the 
primary hazard from low-stress pipelines, including Type B gathering 
lines, and that leak detection is a necessary risk-management measure. 
NAPSR further notes that 49 CFR 192.706 requires leak surveys of 
transmission lines at intervals not exceeding 15 months, but at least 
once each calendar year, and more frequently in densely populated 
areas. NAPSR believes that operators of Type B gathering lines should 
be subject to the same requirements.
    NAPSR notes that operators had to perform leak surveys of non-rural 
gas gathering lines prior to the March 2006 final rule. NAPSR also 
states that 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. NAPSR believes that 
leak detection surveys should be required to ensure the safety of these 
lines.
    PHMSA agrees. Leak surveys are an effective means of ensuring the 
integrity of low-stress pipelines. Accordingly, this proposed rule 
would require operators of Type B gathering lines to perform leak 
surveys in accordance with Sec.  192.706.

 III. Qualifying Plastic Pipe Joiners

    Section 192.285 contains requirements for qualifying persons to 
make joints in plastic pipe. Under Sec.  192.285(c), ``[a] person must 
be re-qualified 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 Sec.  192.513.''
    NAPSR (2008-03-AC-1) has two concerns with the current 
requirements. First, NAPSR states that many operators are required to 
perform requalification on a less than 12-month period to ensure that 
joiners are not disqualified. According to NAPSR, this leads to a 
regressing requalification schedule (i.e., scheduling requalification 
for a period less than 12 months) and occasionally requires tests at 
times that are not advantageous from a cost and quality standpoint. 
NAPSR notes that most of the periodic requirements in 49 CFR part 192 
avoid this problem by providing flexibility in the performance 
interval, such as requiring actions annually not to exceed 15 months. 
NAPSR suggests that the same flexibility be applied to plastic pipe 
joiner qualification.
    NAPSR's second concern is with the number of unacceptable joints 
permitted under the current regulation. NAPSR notes that the 
installation of proper joints is important to ensuring the safety of 
plastic pipelines, and that allowing a joiner with a demonstrated 
inability to join pipe to continue to engage in that activity is 
inconsistent with pipeline safety. NAPSR suggests that the current 
requirement should be revised to require requalification of a joiner if 
any production joint is found unacceptable by the required testing.
    PHMSA agrees with NAPSR in both respects. Accordingly, the proposed 
rule would revise Sec.  192.285 to provide greater scheduling 
flexibility and require requalification of a joiner if any production 
joint is found unacceptable.

Mill Hydrostatic Tests for Pipe To Operate at Alternative MAOP

    Section 192.112 specifies additional design requirements for new or 
existing pipeline segments to qualify for the alternative MAOP 
permitted under 49 CFR 192.620. PHMSA is proposing to revise paragraph 
(e)(1) of Sec.  192.112 by eliminating the allowance for combining 
loading stresses imposed by pipe mill hydrostatic testing equipment for 
the required mill hydrostatic test.
    Mill hydrostatic testing is used to ensure that new pipe has 
adequate strength. Section 192.112 applies to pipe that will operate at 
the higher stresses allowed under the alternate MAOP. Therefore, it is 
important that adequate strength be assured. During the 2008 
construction season, PHMSA identified a number of cases where new pipe 
did not meet its specified strength requirements. 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 alternate 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.

Regulating the Transportation of Ethanol by Pipeline

    On August 10, 2007, (72 FR 45002; Docket number PHMSA-2007-28136) 
PHMSA published a policy statement and request for comment 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 in the future as a result of several 
Federal energy policy initiatives, and that the predominant modes for 
transporting such commodities (i.e., truck, rail, or barge) would 
expand over time to include greater use of pipelines. 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 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 Sec.  195.2 to include ethanol and biofuels in the definition of 
hazardous liquid. PHMSA invited comment on that proposal and other 
issues related to the transportation of biofuels by pipeline.
    Nine organizations submitted comments. Two trade associations 
concerned with hazardous liquid pipeline issues (American Petroleum 
Institute and Association of Oil Pipelines) submitted joint comments. 
Two associations dedicated to the use of bio-fuels (National Biodiesel 
Board and Renewable Fuels Association) submitted separate comments. Two 
standards developing organizations (American Society of Mechanical 
Engineers and National Fire Protection Association), one state pipeline 
safety regulator (Iowa Utilities Board), NAPSR, and one

[[Page 73572]]

biofuels producer (Imperium Renewables, Inc.) also submitted comments.
    All of the commenters agreed that the transportation of biofuels by 
pipeline is likely to increase in the future, and that pure ethanol 
should be classified as a hazardous liquid under the Pipeline Safety 
Laws (49 U.S.C. 60101 et seq.). However, several commenters stated that 
a similar classification was not warranted for pure biodiesel, which 
has chemical properties that are different from ethanol. Most of the 
comments on the transportation of biodiesel focused on biodiesel-
petroleum blends. As explained in the August 2007 policy statement, the 
transportation of biodiesel-petroleum blends is already subject to the 
Pipeline Safety Laws and Regulations, because petroleum and petroleum 
products are both defined as hazardous liquids.
    PHMSA is proposing to modify its definition of hazardous liquid to 
include ethanol. Such a change would make clear that the transportation 
of pure ethanol by pipeline is subject to the requirements of 49 CFR 
part 195. Operators are reminded that biodiesel-petroleum and ethanol-
petroleum blends are already subject to those regulations. Though PHMSA 
is not revising its August 10, 2007 policy statement, PHMSA is 
deferring a final decision on whether the definition of a hazardous 
liquid in 49 CFR 195.2 should be revised to include pure biodiesel. In 
its August 2007 policy statement, PHMSA also requested comment on 
whether research and development would be appropriate to support the 
transportation of biofuels by pipeline and for efforts to assure 
appropriate emergency response to pipeline accidents involving 
biofuels. PHMSA will consider comments in these areas in a separate 
proceeding.

Limitation of Indirect Costs in State Grants

    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% cap on indirect 
expenses allocated to the pipeline safety program grants.
    PHMSA believes that the amount of state pipeline safety grants 
which may be allocated to indirect expenses should be limited. Such a 
limitation ensures that grant funds are used principally for functions 
that serve directly to support implementing a pipeline safety oversight 
program. Accordingly, PHMSA proposes to incorporate the 20% limitation 
on indirect expenses into the regulations governing grants to state 
pipeline safety programs.

Transportation of Pipe

    Section 192.65 states that pipe having a diameter-to-wall-thickness 
ratio of 70 to 1, or more, must be transported in accordance with the 
American Petroleum Institute's (API) Recommended Practices 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.
    During its investigation of a July 2002 pipeline incident, the 
National Transportation Safety Board (NTSB) found that the growth of a 
fatigue crack, introduced to the pipe due to inadequate loading during 
transportation, was a causal factor in the pipe failure. NTSB 
recommended that PHMSA revise its regulations to require that the 
transportation of all pipe be subject to the referenced API standards.
    PHMSA agrees with NTSB's recommendation and proposes to delete the 
exclusion in Sec.  192.65(a)(2). The amount, if any, of pipe 
transported prior to November 12, 1970, which remains in operator 
stockpiles is likely to be very small. Therefore, this change will have 
minimal impact on pipeline operators.

Threading Copper Pipe

    Section 192.279 specifies when copper pipe may be threaded and 
refers to Table C1 of American Society of Mechanical Engineers (ASME) 
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 49 CFR part 192 by reference. GPTC stated that the information in 
Table C1 was taken from a different ASME standard, ASME B36.10M, 
``Standard for Welded and Seamless Wrought Steel Pipe,'' and that this 
standard should be substituted as a more appropriate reference. PHMSA 
agrees with GPTC and is proposing to incorporate the suggested 
reference to ASME B36.10M in Sec.  192.279.

Offshore Pipeline Condition Reports

    In a December 1991 final rule (56 FR 637770-637771), PHMSA's 
predecessor agency, the Research and Special Programs Administration 
(RSPA), complied with a statutory mandate in Public Law 101-599 (Nov. 
16, 1990) by establishing new requirements for pipelines in the Gulf of 
Mexico (Gulf) and its inlets. Specifically, RSPA promulgated Sec. Sec.  
192.612(a) and 195.413(a), which required each operator to conduct an 
underwater inspection of all of those lines after October 3, 1989, and 
before November 16, 1992. RSPA also issued Sec. Sec.  191.27 and 
195.57, which required operators to submit a report to RSPA within 60 
days of completing those inspections.
    In an August 2004 final rule (69 FR 48400), RSPA amended Sec. Sec.  
192.612(a) and 195.413(a) to require each operator to prepare and 
follow written procedures for identifying any shallow-water pipelines 
in the Gulf and its inlets that could be exposed or present a hazard to 
navigation. RSPA also amended the other provisions in Sec. Sec.  
192.612 and 195.413 to require operators to conduct appropriate 
periodic inspections of those pipelines, and to take steps to promptly 
report, mark, and rebury any line found to be exposed or a hazard to 
navigation. RSPA did not repeal or modify the reporting requirements in 
Sec. Sec.  191.27 or 195.57.
    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 Public Law 102-508 (Oct. 24, 1992) (modifying 
statutory mandate for underwater inspection, reporting, and reburial of 
pipelines in the Gulf and its inlets). Rather, those regulations only 
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 a regime. Sections 
192.612(c) and 195.413(c) also require operators to file a written 
report with the National Response Center within 24 hours of discovering 
that a pipeline in those areas is exposed or a hazard to navigation. 
That reporting requirement is sufficient to meet PHMSA's current 
information collection needs.
    Accordingly, PHMSA is proposing to repeal Sec. Sec.  191.27 and 
195.57.

Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity 
Anomalies

    Section 195.452(h)(4)(i) specifies the actions that an operator of 
hazardous liquid pipelines 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. The particular focus of that pressure 
reduction formula

[[Page 73573]]

is corrosion. However, corrosion is only one of the threats that could 
cause an immediate repair condition under Sec.  195.452(h)(i).
    PHMSA sought to modify Sec.  195.452(h)(4)(i) in a July 17, 2007, 
final rule (72 FR 39017) 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. PHMSA is again revising Sec.  195.452(h)(4)(i) as part of 
this rule to make the same change as published in the July 17, 2007, 
final rule with corrected amendatory instructions.

Testing Components Other Than Pipe Installed in Low-Pressure Gas 
Pipelines

    Section 192.505 specifies strength test requirements for steel pipe 
to operate at a hoop stress of 30 percent or more of SMYS. Paragraph 
(d) of Sec.  192.505 provides an exception if a component other than 
pipe is the only item being replaced or added. It states that a post-
installation strength test is not required if the manufacturer 
certifies that the component was tested to at least the pressure 
required for the pipeline to which it is being added, manufactured 
under a quality control system that assures adequate strength, or 
carries a pressure rating established through applicable ASME/ANSI, MSS 
specifications or by unit strength calculations. A similar exception is 
not provided if a component other than pipe is the only item being 
replaced or added to steel pipeline systems that operate at less than 
30 percent of SMYS (Sec. Sec.  192.507 and 192.509), service lines 
(Sec.  192.511), or plastic pipelines (CFR 192.513).
    In a letter dated March 25, 2010, GPTC petitioned PHMSA to create 
such an exception by repealing paragraph (d) of Sec.  192.505 and 
adding that provision to Sec.  192.503, which imposes general 
requirements applicable to testing all gas pipelines. GPTC argued that 
the primary purpose of a post-installation strength test is to prove 
the integrity of the entire pipeline system. GPTC further noted that 
the most important parts of a single-component replacement to be 
checked 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 Sec.  192.503. These joints are also 
required to be leak tested at operating pressure, a requirement that 
would not be changed by GPTC's petition.
    If a component other than pipe is the only item being replaced or 
added to a low-stress steel line, a service line, or a plastic pipeline 
and the manufacturer of the component provides the certification 
required under Sec.  192.505(d), PHMSA agrees that a strength test 
after installation is not necessary to ensure public safety. Such 
testing must necessarily be performed prior to installation and not as 
part of a test of the overall pipeline system. PHMSA proposes to grant 
the GPTC petition as part of this rulemaking by deleting paragraph (d) 
of Sec.  192.505 and adding that provision as a new paragraph (e) to 
Sec.  192.503.

Alternative MAOP Notifications

    Section 192.620(c)(1) requires an operator to notify PHMSA, and in 
some instances the appropriate State authority, upon electing to 
establish a higher alternative MAOP. Such notification must be provided 
at least 180 days prior to commencing operations at the alternative 
MAOP. The 180-day allowance provides PHMSA and state regulators with 
sufficient time to conduct any needed inspections, including checks of 
the manufacturing process, visits to the pipeline construction sites, 
analysis of operating history of existing pipelines, and review of test 
records, plans, and procedures.
    Operators are expected to provide PHMSA's regional offices with 
notice of planned alternative MAOP design and operations as early as 
practical, and prior to the start of pipe manufacturing and/or 
construction activities. Such notification avoids unnecessary delays in 
PHMSA's review of applicable procedures, specifications, manufacturing 
of pipe and external coating, field construction activities, operations 
& maintenance plans, and all other required documentation.
    Consistent with that practice, PHMSA is proposing to revise Sec.  
192.620 to require that operators notify PHMSA field offices 180 days 
prior to pipe manufacturing and/or construction activities. PHMSA is 
also proposing to revise Sec.  192.620(c)(8) to correct a typographical 
error related to the reference to Sec.  192.611(a).

National Pipeline Mapping System

    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 PHMSA-regulated breakout 
tanks.
    The NPMS project began in 1998 and data submission became mandatory 
as a result of the Pipeline Safety Improvement Act of 2002. Operators 
are currently required to make a submission to the NPMS once every 12 
months, or to notify NPMS staff if there were no changes during that 
time. An NPMS submission consists of geospatial data, attribute data 
and metadata, public contact information, and a transmittal letter. 
These requirements and acceptable formats are explained in full in the 
NPMS Operator Standards Manual (http://www.npms.phmsa.dot.gov/Documents/Operator_Standards.pdf).
    PHMSA is seeking to improve its ability to compare Annual Report 
statistics with NPMS data. This will aid PHMSA in accurately portraying 
our nation's pipeline transportation network, allocating its resources, 
achieving the goal of becoming a data-driven organization, and 
conducting operator compliance efforts. The ability to accurately 
identify and track operators' physical assets is beneficial to PHMSA, 
pipeline operators, and all stakeholders who utilize such data, and 
ultimately helps promote pipeline safety.
    Section 60132 of the Pipeline Safety Laws requires pipeline 
operators to make a submission to the NPMS once every 12 months, or to 
notify the NPMS if there were no changes from the previous submission. 
To ensure that all operators are complying with this requirement, PHMSA 
proposes to add an NPMS submission requirement to the Code of Federal 
Regulations.
    In an Advisory Bulletin issued on July 31, 2008, PHMSA requested 
that operators submit their NPMS data concurrently with hazardous 
liquid and gas transmission annual report submissions. Annual reports 
are due on March 15 each year for gas transmission operators and on 
June 15 for LNG plant operators. Annual reports represent assets as of 
December 31 of the previous year. In an advisory bulletin issued on May 
17, 2011, PHMSA temporarily extended those timelines for the 2010 
calendar year for the owners and operators of gas transmission and 
gathering lines, hazardous liquid lines, and LNG facilities to account 
for recent revisions to the agency's reporting forms.
    Toward these ends, PHMSA proposes to:
    1. Require operators to follow the submission rules and dates set 
forth in the July 31, 2008, Advisory Bulletin. Gas transmission 
operators and LNG plant operators will make their NPMS submissions on 
or before March 15, representing assets as of December 31 of the 
previous year. Hazardous liquid operators will make their NPMS

[[Page 73574]]

submissions on or before June 15, representing assets as of December 
31, of the previous year. To expedite processing, PHMSA urges operators 
to submit their NPMS data as early in the year as possible. A 
rulemaking published on November 26, 2010, requires operators to use 
the same Operator ID number (OPID) for the same asset for all PHMSA 
reporting requirements. Therefore, an OPID used in an annual report 
submission must match the same asset described in an NPMS submission.
    2. Codify the statutory requirement for submission of NPMS data in 
49 CFR parts 192, 193, and 195. An NPMS submission consists of 
geospatial data, attribute data and metadata, public contact 
information, and a transmittal letter.
    For information about acceptable submission formats and the 
components of each element, refer to the latest edition of the NPMS 
Operator Standards Manual. Incomplete submissions, or submissions in 
unacceptable formats, will be deemed noncompliant with this regulation.

Welders vs. Welding Operators

    The use of mechanized and automatic welding has become more common 
in pipeline construction, and the operators of such equipment must be 
qualified to ensure their work meets pipeline safety standards. The 
requirements for welders and welding operations are prescribed in 
subpart D, Construction, of 49 CFR parts 192 and 195. Welding operators 
of mechanized and automatic welding equipment have never been 
specifically addressed in those regulations.
    The ASME Boiler and Pressure Vessel Code (BPVC) Section IX defines 
a welder as ``[o]ne who performs manual or semi-automatic welding.'' 
and a welding operator as ``[o]ne who operates machine or automatic 
welding equipment.'' Moreover, both the ASME BPVC Section IX and API 
1104 have specific processes for the qualification of welding operators 
and automatic welding equipment. PHMSA's expectations of qualified 
personnel are consistent with the requirements in these two standards.
    PHMSA is proposing to add a reference to these requirements in the 
applicable sections of subpart D in 49 CFR parts 192 and 195 to clarify 
the qualification standards for welding operators. This change will not 
affect the current industry practice; rather, it addresses the 
distinction between welders and welding operators and the specific 
qualification requirements under the current standards incorporated by 
reference in 49 CFR parts 192 and 195. Those standards are designed to 
ensure that qualified personnel are used for welding processes whether 
they are performed by welders or welding operators.

Components Fabricated by Welding

    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, and tested in accordance with the requirements of 
ASME BPVC Section VIII, as required by Sec.  192.153 and Sec.  
192.165(b)(3), and the additional test requirements of Sec.  
192.505(b).
    However, 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 of 
the ASME BPVC than the edition which is currently incorporated by 
reference. This revision created a difference in pressure testing 
requirements of the ASME BPVC from the test requirements of Sec.  
192.505(b), which requires a test factor of 1.5 times MAOP for meter 
and compressor stations, as well as any other Class 3 location. PHMSA 
has not reduced the testing requirements of these vessels and they must 
be tested to at least the pressure required for the pipeline to which 
they are being added.
    Because the standard ASME pressure vessel test in ASME BPVC Section 
VIII 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 special ordered with a test pressure of 1.5 times MAOP 
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 MAOP, it cannot be used in a compressor or meter station, or 
other Class 3 location. The failure to meet this requirement can 
potentially lead to exceeding the design parameters of the vessel 
during subsequent testing of the pipeline system.
    A clarification is being added to Sec.  192.153 as a new paragraph 
(e) 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. All ASME pressure vessels 
subject to Sec.  192.153 and Sec.  192.165(b)(3) must be designed and 
tested at a pressure that is 1.5 times MAOP, in lieu of the standard 
ASME BPVC Section VIII test pressure of 1.3 times MAOP. Additionally, 
Sec.  192.165(b)(3) is being revised to refer the reader to this 
requirement.
    This is not a change to the pressure testing requirements, as the 
requirements found in part 192 have not changed. This clarification is 
made to ensure a clear understanding of PHMSA's pressure testing 
requirements for certain ASME BPVC vessels in compressor and meter 
stations, and other Class 3 locations.

Odorization of Gas Transmission Lateral Lines

    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.''
    Section 192.625 does not specify a clear method for calculating the 
length of a lateral line, and that has led to inconsistency in applying 
the odorization requirement. To address that concern, PHMSA proposes to 
amend Sec.  192.625(b)(3) to state that the length of a lateral line 
for purposes of calculating whether at least 50 percent is in a Class 1 
or Class 2 location is measured between the distribution center and the 
first upstream connection to the transmission line.

Editorial Amendments

    In this NPRM, PHMSA is also proposing to make the following 
editorial amendments to the pipeline safety regulations:
    (1) In Sec.  195.571, to revise the reference to NACE Standard on 
Cathodic Protection as Incorporated by Reference in Sec.  195.3.
    (2) In Sec.  195.3B(9), to amend ANSI/API Recommended Practice 651 
to show the correct source and reference material as Sec. Sec.  195.565 
and 195.573(d).
    (3) In Sec.  195.2, to amend the definition of ``Alarm'' to correct 
an error in the codification of the new control room management 
regulations (74 FR 63310).
    (4) In Sec. Sec.  192.925(b) and (b)(2), to replace ``indirect 
examination'' with ``indirect inspection'' to maintain consistency with 
Sec.  192.925(a) and the applicable NACE standard.
    (5) In Sec.  195.428(c), to replace ``Sec.  5.1.2'' with ``Sec.  
7.1.2'' to correctly reference the overfill protection requirements for 
aboveground breakout tanks in the 2010 edition of API Standard 2510, 
which is now incorporated by reference (see Sec.  195.3).

[[Page 73575]]

Regulatory Analyses and Notices

Executive Order 12866, Executive Order 13563, and DOT Regulatory 
Policies and Procedures

    This proposed rule is not a 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 proposed 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.'' In 
this notice, PHMSA is proposing to amend miscellaneous provisions to 
clarify and eliminate unduly burdensome requirements. PHMSA is also 
responding to requests from industry and State pipeline safety 
representatives to revise its regulations. PHMSA anticipates the 
proposals contained in this rule will have economic benefits to the 
regulated community by increasing the clarity of its regulations and 
reducing compliance costs.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA 
must consider whether rulemaking actions would have a significant 
economic impact on a substantial number of small entities. PHMSA is 
proposing to make miscellaneous changes to the pipeline safety 
regulations.

Description of the Reasons That Action by PHMSA Is Being Considered

    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; (7) the calculation of pressure reductions for hazardous 
pipeline anomalies; and (8) the odorization of gas transmission lateral 
lines. PHMSA wishes to address these issues.

Succinct Statement of the Objectives of, and Legal Basis for, the 
Proposed 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 this authority to the PHMSA Administrator. 49 CFR 1.53(a). 
The proposed rule would effect changes in the regulations consistent 
with the protection of persons and property, while changing unduly 
burdensome or nonsensical requirements.

Description of Small Entities to Which the Proposed Rule Will Apply

    In general, the proposed 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 
qualifying 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 concerns may qualify as a small business 
concern.

Description of the Projected Reporting, Recordkeeping, and Other 
Compliance Requirements of the Proposed 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 proposed rule does not directly impose any reporting or 
recordkeeping requirement. But the rule does create an obligation to 
perform leak surveys of Type B gathering lines. This sort of survey is 
currently required of transmission lines. This requirement is expected 
to apply only to small business entities, and not small governmental 
entities, because small jurisdictions typically operate distribution or 
transmission systems, to which the requirement will not apply. 
Professional inspectors will be needed to comply with this requirement, 
but the time required for compliance will vary greatly with each 
system.
    The remainder of the proposed rule does not impose any compliance, 
recordkeeping, or reporting requirement; it does, however, affect the 
timing and substance of the reports that must be created and maintained 
under existing regulations. The rule proposes that operators notify 
PHMSA field offices 180 days prior to pipe manufacturing or 
construction activities. Currently existing 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 notice of alternative design as early as practical, and 
prior to pipe manufacturing or construction activities, the proposed 
rule does not impose any additional reporting requirement.
    Additionally, the proposed rule changes the reporting requirement 
for submissions to the National Pipeline Mapping System (NPMS). 
Submissions to the NPMS are mandatory as a result of the Pipeline 
Safety Improvement Act of 2002. At present, NPMS submissions are due 
every 12 months; the proposed rule would require establish due dates 
for NPMS submissions that coincide with the due dates for annual 
reports.

Identification, to the Extent Practicable, of all Relevant Federal 
Rules That May Duplicate, Overlap, or Conflict With the Proposed Rule

    PHMSA is unaware of any duplicative, overlapping, or conflicting 
federal rules. As noted below, PHMSA seeks comments and information 
about any such rules.

Description of Any Significant Alternatives to the Proposed Rule That 
Accomplish the Stated Objectives of Applicable Statutes and That 
Minimize Any Significant Economic Impact of the Proposed 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 proposed 
rule are specifically designed to eliminate confusion and potentially 
lower costs for regulated entities. For example, the proposed addition 
of 49 CFR 192.153(e) is designed to prevent regulated entities from 
purchasing pressure vessels that do not comply with Sec.  192.505(b), 
but that do comply with ASME Boiler and Pressure Vessel Code Section 
VII, as required by Sec.  192.165(b)(3). PHMSA seeks comments about 
lower-cost alternatives which would meet the stated objectives.
    Questions for Comment to Assist Regulatory Flexibility analysis:
    1. Please provide any data concerning the number of small entities 
which may be affected.
    2. Please provide comment on any or all of the provisions in the 
proposed rule with regard to (a) the impact of the provisions, if any, 
and (b) any alternatives PHMSA should consider, paying specific 
attention to the effect of the rule on small entities.

[[Page 73576]]

    3. Please describe ways in which the rule could be modified to 
reduce any costs or burdens for small entities.
    4. Please identify all relevant Federal, state, local, or industry 
rules or policies that may duplicate, overlap, or conflict with the 
proposed rule and have not already been incorporated by reference.

Executive Order 13175

    PHMSA has analyzed this proposed rule according to the principles 
and criteria in Executive Order 13175, ``Consultation and Coordination 
with Indian Tribal Governments.'' Because this proposed 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 proposed rule imposes no new requirements for recordkeeping 
and reporting.

Unfunded Mandates Reform Act of 1995

    This proposed 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 proposed rule.

National Environmental Policy Act

    The National Environmental Policy Act (42 U.S.C. 4321-4375) 
requires that Federal agencies analyze proposed 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 proposed action, (2) alternatives to the proposed action, 
(3) probable environmental impacts of the proposed action and 
alternatives, and (4) the agencies and persons consulted during the 
consideration process. 40 CFR 1508.9(b).
1. Purpose and Need
    PHMSA is proposing to make non-substantive amendments and editorial 
changes to the pipeline safety regulations. That includes modifying the 
requirements for the performance of post-construction inspections; the 
conduct of leak surveys of Type B onshore gas gathering lines; the 
requirements for qualifying plastic pipe joiners; the regulation of 
ethanol; the transportation of pipe; the filing of offshore pipeline 
condition reports; the calculation of pressure reductions for hazardous 
liquid pipeline anomalies; and the odorization of gas transmission 
lateral lines.
2. Alternatives
    In developing the proposed rule, PHMSA considered two alternatives:
    (1) No action or
    (2) Propose revisions to the pipeline safety regulations to 
incorporate the amendments previously and minor editorial changes.
    Alternative 1: PHMSA has an obligation to ensure the safe and 
effective transportation of hazardous liquids and gases by pipeline. 
The changes proposed in this NPRM serve that purpose by clarifying the 
pipeline safety 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 is proposing to make certain amendments, 
corrections and editorial changes to the pipeline safety regulations. 
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 proposed in this NPRM serve 
that purpose by clarifying the pipeline safety regulations and 
eliminating unduly burdensome requirements.
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 proposed rule 
includes the 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 proposed 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 damage and 
environmental damage to injuries or, on rare occasions, fatalities.
    The proposed amendments are not substantive in nature and would 
have little or no impact on the human environment. Thus it is possible 
that, on a national scale, the cumulative environmental damage from 
pipelines is reduced, or at a minimum unchanged.
    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 were 
consulted in the development of this proposed rulemaking.
5. Decision About the Degree of Environmental Impact
    PHMSA has preliminarily determined that the selected alternative 
would not have a significant impact on the human environment and 
welcomes comment on any of these conclusions.

Executive Order 13132

    PHMSA has analyzed this proposed rule according to Executive Order 
13132 (``Federalism''). The proposed 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 proposed 
rule does not impose substantial direct compliance costs on state and 
local governments. This proposed rule does

[[Page 73577]]

not preempt state law for intrastate pipelines. Therefore, the 
consultation and funding requirements of Executive Order 13132 do not 
apply.

Executive Order 13211

    This proposed 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. Further, the Office of Information and Regulatory Affairs 
has not designated this proposed rule as a significant energy action.

List of Subjects

49 CFR Part 191

    Pipeline safety, Reporting, and recordkeeping requirements.

49 CFR Part192

    Pipeline safety, Fire prevention, Security measures.

49 CFR Part 195

    Ammonia, Carbon dioxide, Incorporation by reference, Petroleum, 
Pipeline safety, Reporting and recordkeeping requirements.

49 CFR Part 198

    Grant programs, Formula, Pipeline safety.

    In consideration of the foregoing, PHMSA is proposing to amend 49 
CFR Chapter I as follows:

PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; 
ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION 
REPORTS

    1. The authority citation for Part 191 continues to read as 
follows:

    Authority:  49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 
60118, and 60124, and 49 CFR 1.53.

    2. In Sec.  191.7, paragraph (a) is revised and paragraph (e) is 
added to read as follows:


Sec.  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://opsweb.phmsa.dot.gov unless an alternative 
reporting method is authorized in accordance with paragraph (d) of this 
section.
* * * * *
    (e) Exceptions. An operator must provide the National Pipeline 
Mapping System data to the address identified in the NPMS Operator 
Standards manual available at www.npms.phmsa.dot.gov or by contacting 
the PHMSA Geospatial Information Systems Manager at (202) 366-4595.


Sec.  191.27   [Removed]

    3. Section 191.27 is removed.
    4. Section 191.29 is added to read as follows:


Sec.  191.29  National Pipeline Mapping System.

    (a) (1) 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:
    (i) 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.
    (ii) The name and address for the operator.
    (iii) The name and contact information of a pipeline company 
employee who will serve as a contact for questions from the general 
public about the operator's NPMS data, which is displayed on a public 
Web site.
    (2) This information must be submitted each year, not later than 
March 15, representing assets as of December 31 of the previous year. 
If no changes have occurred since the previous year's submission, 
comply with the guidance provided in the NPMS Operator Standards manual 
available at www.npms.phmsa.dot.gov or contact the PHMSA Geospatial 
Information Systems Manager at (202) 366-4595.
    (b) [Reserved]

PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: 
MINIMUM FEDERAL SAFETY STANDARDS

    5. The authority citation for part 192 continues to read as 
follows:

    Authority:  49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 
60113, 60116, 60118, and 60137; and 49 CFR 1.53.

    6. In Sec.  192.3, definitions for ``Welder'' and ``Welding 
Operator'' are added in appropriate alphabetical order to read as 
follows:


Sec.  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.
    7. In Sec.  192.7 paragraph (c)(2) amend the Table of referenced 
material by redesignating items D.(6) through D.(9) as D.(7) and D.(10) 
and adding a new D.(6) to read as follows:


Sec.  192.7  What documents are incorporated by reference partly or 
wholly in this part?

* * * * *
    (c) * * *
    (2) * * *
    Source and name of referenced material 49 CFR reference

------------------------------------------------------------------------
   Source and name of referenced material         49 CFR  reference
------------------------------------------------------------------------
 
                                * * * * *
D. * * *...................................
(6) ASME/ANSI B36.10M, ``Standard for        Sec.   192.279
 Welded and Seamless Wrought Steel Pipe''.
 
                                * * * * *
------------------------------------------------------------------------

    8. In Sec.  192.9, paragraph (d)(7) is added to read as follows:


Sec.  192.9  What requirements apply to gathering lines?

* * * * *
    (d) * * *
    (7) Conduct leakage surveys in accordance with Sec.  192.706 using 
leak detection equipment and fix hazardous leaks that are discovered in 
accordance with Sec.  192.703(c).
* * * * *
    9. In Sec.  192.65, paragraph (a) is revised to read as follows.


Sec.  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 use pipe having an outer 
diameter to wall thickness of 70 to 1, or more, that is transported by 
railroad unless the transportation is performed in accordance with API 
RP 5LI.
* * * * *
    10. In the Table in Sec.  192.112, paragraph (e) is revised to read 
as follows:


Sec.  192.112  Additional design requirements for steel pipe using 
alternative maximum allowable operating pressure.

* * * * *

[[Page 73578]]



------------------------------------------------------------------------
                                  The pipeline segment must meet these
To address this design issue:           additional requirements:
------------------------------------------------------------------------
 
                              * * * * * * *
(e) Mill hydrostatic test....  (1) All pipe to be used in a new pipeline
                                segment must be hydrostatically tested
                                at the mill at a test pressure
                                corresponding to a hoop stress of 95
                                percent SMYS for 10 seconds.
                               (2) Pipe in operation prior to December
                                22, 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
                                November 17, 2008, but before [INSERT
                                DATE OF FINAL RULE], 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 API Specification 5L, Appendix K
                                (incorporated by reference, see Sec.
                                192.7).
 
                              * * * * * * *
------------------------------------------------------------------------

    11. In Sec.  192.153, a new paragraph (e) is added to read as 
follows:


Sec.  192.153  Components fabricated by welding.

* * * * *
    (e) A component having a design pressures established in accordance 
with paragraph (a) or paragraph (b) of this section and subject to the 
strength testing requirements of Sec.  192.505(b) must be tested to at 
least 1.5 times the maximum allowable operating pressure.
    12. In Sec.  192.165, paragraph (b)(3) is revised to read as 
follows:


Sec.  192.165  Compressor stations: Liquid removal.

* * * * *
    (b) * * *
    (3) Be manufactured in accordance with section VIII of the ASME 
Boiler and Pressure Vessel Code (incorporated by reference, see Sec.  
192.7) and the additional requirements of Sec.  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 Sec.  192.225, paragraph (a) is revised to read as follows:


Sec.  192.225  Welding procedures.

    (a) Welding must be performed by a qualified welder or welding 
operator in accordance with welding procedures qualified in accordance 
with API 1104 (incorporated by reference, see Sec.  192.7) or section 
IX of the ASME Boiler and Pressure Vessel Code ``Welding and Brazing 
Qualifications'' (incorporated by reference, see Sec.  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:


Sec.  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, 12, or 13 of API 1104 (incorporated by reference, see Sec.  192.7) 
or section IX of the ASME Boiler and Pressure Vessel Code (incorporated 
by reference, see Sec.  192.7). However, a welder or welding operator 
qualified under an earlier edition than the edition listed in Sec.  
192.7 of this part may weld but may not re-qualify under that earlier 
edition.
    (b) A welder or welding operator 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 or welding operator 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:


Sec.  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 has engaged in welding with that process.
    (c) A welder or welding operator qualified under Sec.  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 section 6 or section 9 of API 
Standard 1104 (incorporated by reference, see Sec.  192.7). 
Alternatively, a welder or welding operator 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 7\1/2\ months. A welder or welding 
operator qualified under an earlier edition of a standard than the 
edition listed in Sec.  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 re-qualifies under paragraph (d)(1) or (d)(2) of this 
section.
    (d) A welder or welding operator qualified under Sec.  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 
Sec.  192.227(b); or
    (2) Within the preceding 7\1/2\ 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) Two sample welds tested and found acceptable in accordance 
with the test in section III of Appendix C of this part or a welder or 
welding operator who works only on service lines 2 inches (51 
millimeters) or smaller in diameter.
    16. In Sec.  192.241, paragraph (c) is revised to read as follows:


Sec.  192.241  Inspection and test of welds.

* * * * *
    (c) The acceptability of a weld that is nondestructively tested or 
visually

[[Page 73579]]

inspected is determined according to the standards in Section 9 or 
Appendix A of API Standard 1104, as applicable (incorporated by 
reference, see Sec.  192.7).
    17. In Sec.  192.243, paragraph (e) is revised to read as follows:


Sec.  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's or 
welding operator's work for each day must be nondestructively tested, 
when nondestructive testing is required under Sec.  192.241(b).
* * * * *
    18. Section 192.279 is revised to read as follows:


Sec.  192.279  Copper Pipe.

    Copper pipe may not be threaded except that copper pipe used for 
joining screw fittings or valves may be threaded 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 (incorporated by reference, see Sec.  
192.7).
    19. In Sec.  192.285, paragraph (c) is revised to read as follows:


Sec.  192.285  Plastic pipe: Qualifying persons to make joints.

* * * * *
    (c) A person must be re-qualified under an applicable procedure if:
    (1) During any calendar year (not exceeding 15 months) that person 
does not make any joints under that procedure; or
    (2) Any production joint is found unacceptable by testing under 
Sec.  192.513.
* * * * *
    20. Section 192.305 is revised to read as follows:


Sec.  192.305  Inspection: General.

    Each transmission line and main must be inspected to ensure that it 
is constructed in accordance with this subpart. An inspection may not 
be performed by a person who participated in the construction of that 
transmission line or main.
    21. In Section 192.503, add new paragraph (e) to read as follows:


Sec.  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 all of the 
below requirements and the operator maintains these certifications for 
the in service life of the component:
    (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, MSS specifications, or by unit strength 
calculations as described in Sec.  192.143.


Sec.  192.505  [Amended]

    22. In Section 192.505, paragraph (d) is removed and paragraph (e) 
is re-designated as paragraph (d).
    23. In Sec.  192.620, paragraph (c)(1) and the first sentence of 
paragraph (c)(8) are revised to read as follows:


Sec.  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 maximum allowable operating pressure. For 
new pipelines, notify the PHMSA pipeline safety regional office 180 
days prior to start of pipe manufacturing and/or construction 
activities. An operator must also notify a State pipeline safety 
authority when the pipeline is located in a state where PHMSA has an 
interstate agent agreement or an intrastate pipeline is regulated by 
that state.
* * * * *
    (8) A Class 1 and Class 2 location can be upgraded one class due to 
class changes per Sec.  192.611(a). * * *
* * * * *
    24. In Sec.  192.625, paragraph (b)(3) is revised to read as 
follows:


Sec.  192.625  Odorization of Gas.

* * * * *
    (b) * * *
    (3) In the case of a lateral line which transports gas to a 
distribution center, at least 50 percent of the length of that line is 
in a Class 1 or Class 2 location as measured between the distribution 
center and the first upstream connection to the transmission line;
* * * * *
    25. In Sec.  192.925, the introductory text of paragraph (b) and 
the introductory text of (b)(2) are revised to read as follows:


Sec.  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 
Sec.  192.7), section 6.4, and in NACE SP0502-2008 (incorporated by 
reference, see Sec.  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 
(Sec.  192.917(b)) to evaluate the covered segment for the threat of 
third party damage and to address the threat as required by Sec.  
192.917(e)(1).
* * * * *
    (2) Indirect inspection. In addition to the requirements in ASME/
ANSI B31.8S section 6.4 and NACE SP0502-2008, section 4, the plan's 
procedures for indirect inspection of the ECDA regions must include--
* * * * *

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

    26. The authority citation for Part 195 continues to read as 
follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60116, 
60118, and 60137; and 49 CFR 1.53.

    27. In Sec.  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:


Sec.  195.2  Definitions.

* * * * *
    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 Sec.  195.3(c), paragraph entry B (9) is revised to read:

[[Page 73580]]

Sec.  195.3  Incorporation by reference.

* * * * *
    (c) * * *

------------------------------------------------------------------------
 
------------------------------------------------------------------------
B. * * *..........................
(9) ANSI/API Recommended Practice   Sec.  Sec.   195.565, 195.573(d).
 651, ``Cathodic Protection of
 Aboveground Petroleum Storage
 Tanks'' (3rd edition, January
 2007).
------------------------------------------------------------------------

* * * * *


Sec.  195.57  [Removed]

    29. Section 195.57 is removed.
    30. In Sec.  195.58, paragraph (a) is revised and a new paragraph 
(e) is added to read as follows:


Sec.  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 the Pipeline and Hazardous Materials Safety 
Administration at http://opsweb.phmsa.dot.gov unless an alternative 
reporting method is authorized in accordance with paragraph (d) of this 
section.
* * * * *
    (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:


Sec.  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 Geospatial Information Systems Manager at (202) 366-4595.
    (2) The name and address for the operator.
    (3) The name and contact information of a pipeline company employee 
who will serve as a contact for questions from the general public about 
the operator's NPMS data, which is displayed on a public Web site.
    (b) This information must be submitted each year, not later than 
June 15, representing assets as of December 31 of the previous year. If 
no changes have occurred since the previous year's submission, see the 
information provided in the NPMS Operator Standards manual available at 
www.npms.phmsa.dot.gov or by contacting the PHMSA Geospatial 
Information Systems Manager at (202) 366-4595.
    32. Section 195.204 is revised to read as follows:


Sec.  195.204  Inspection--general.

    Inspection must be provided to ensure the installation of pipe or 
pipeline systems in accordance with the requirements of this subpart. 
No person may be used to perform inspections unless that person has 
been trained and is qualified in the phase of construction to be 
inspected. An inspection may not be performed by a person who 
participated in the installation of the pipe or pipeline systems.
    33. In Sec.  195.214, paragraph (a) is revised to read as follows:


Sec.  195.214  Welding Procedures.

    (a) Welding must be performed by a qualified welder or welding 
operator in accordance with welding procedures qualified in accordance 
with API 1104 (incorporated by reference, see Sec.  192.7) or section 
IX of the ASME Boiler and Pressure Vessel Code ``Welding and Brazing 
Qualifications'' (incorporated by reference, see Sec.  192.7) to 
produce welds meeting 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).
* * * * *
    34. In Sec.  195.222 the heading, paragraph (a), the introductory 
text of (b), and paragraph (b)(2) are revised to read as follows:


Sec.  195.222  Welding: Qualification of welders and welding operators.

    (a) Each welder or welding operator must be qualified in accordance 
with sections 6, 12, or 13 of API 1104 (incorporated by reference, see 
Sec.  195.3) or section IX of the ASME Boiler and Pressure Vessel Code, 
(incorporated by reference, see Sec.  195.3) except that a welder or 
welding operator qualified under an earlier edition than an edition 
listed in Sec.  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 welded tested and found acceptable under section 9 or 
Appendix A of API 1104 (incorporated by reference, see Sec.  195.3).
    35. In Sec.  195.228, paragraph (b) is revised to read as follows:


Sec.  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 1104 (incorporated by 
reference, see Sec.  195.3).
    36. In Sec.  195.234, paragraph (d) is revised to read as follows:


Sec.  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.
* * * * *
    37. In Sec.  195.307 paragraphs (c) and (d) are revised to read as 
follows:


Sec.  195.307  Pressure testing aboveground breakout tanks.

* * * * *
    (c) For aboveground breakout tanks built to API Standard 650 
(incorporated by reference, see Sec.  195.3) and first placed in 
service after October 2, 2000, testing must be in accordance with 
Section 5.3.5 of API Standard 650 (incorporated by reference, see Sec.  
195.3).
    (d) For aboveground atmospheric pressure breakout tanks constructed 
of carbon and low alloy steel, welded or riveted, and non-refrigerated 
and tanks built to API Standard 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 Sec.  195.3).
* * * * *
    38. In Sec.  195.428, paragraph (c) is revised to read as follows:

[[Page 73581]]

Sec.  195.428  Overpressure safety devices and overfill protection 
systems.

* * * * *
    (c) Aboveground breakout tanks that are constructed or 
significantly altered according to API Standard 2510 after October 2, 
2000, must have an overfill protection system installed according to 
section 7.1.2 of API Standard 2510. 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 Recommended 
Practice 2350 (incorporated by reference, see Sec.  195.3). However, an 
operator need not comply with any part of API Recommended Practice 2350 
for a particular breakout tank if the operator describes in the manual 
required by Sec.  195.402 why compliance with that part is not 
necessary for safety of the tank.
* * * * *
    39. In Sec.  195.452, paragraph (h)(4)(i) introductory text is 
revised to read as follows:


Sec.  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'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 in paragraph (h)(4)(i)(B) of this 
section, if applicable, or when the formulas in paragraph (h)(4)(i)(B) 
of this section are not applicable by using a pressure reduction 
determination in accordance with Sec.  195.106 and the appropriate 
remaining pipe wall thickness, or if all of these are unknown a minimum 
20 percent or greater operating pressure reduction must be implemented 
until the anomaly is repaired. 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. An operator must treat the following 
conditions as immediate repair conditions:
* * * * *
    40. Section 195.571 is revised to read as follows:


Sec.  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 in paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 
and 6.3 of NACE Standard RP 0169 (incorporated by reference, see Sec.  
195.3).

PART 198--REGULATIONS FOR GRANTS TO AID STATE PIPELINE SAFETY 
PROGRAMS

    41. The authority citation for Part 198 continues to read as 
follows:

    Authority:  49 U.S.C. 60105, 60106, 60114, and 49 CFR 1.53.

    42. In Sec.  198.13, a new paragraph (g) is added to read as 
follows:


Sec.  198.13  Grant allocation formula.

* * * * *
    (g) Indirect cost rate reimbursement is limited to a maximum of 20% 
of Direct Costs of the Pipeline Safety Program.

    Issued in Washington, DC, on November 19, 2011.
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. 2011-29852 Filed 11-28-11; 8:45 am]
BILLING CODE 4910-60-P