[Federal Register Volume 81, Number 38 (Friday, February 26, 2016)]
[Notices]
[Page 9927]
[FR Doc No: 2016-04209]

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DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

Seventeenth Meeting: RTCA Special Committee (227) Standards of
Navigation Performance

AGENCY: Federal Aviation Administration (FAA), U.S. Department of
Transportation (DOT).

ACTION: Notice of Seventeenth RTCA Special Committee 227 Meeting.

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SUMMARY: The FAA is issuing this notice to advise the public of the
Seventeenth RTCA Special Committee 227 meeting.

DATES: The meeting will be held March 15-17, 2016 from 9:00 a.m.-4:30
p.m.

ADDRESSES: The meeting will be held at RTCA Inc. Conference Room, 1150
18th, NW., Suite 910, Washington, DC, Tel:<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: The RTCA Secretariat, 1150 18th Street
NW., Suite 910, Washington, DC 20036, or by telephone at (202) 833-
9339, fax at<PHONE_NUMBER>, or Web site at http://www.rtca.org or
Jennifer Iversen, Program Director, RTCA, Inc<EMAIL_ADDRESS>
(202) 330-0662.

SUPPLEMENTARY INFORMATION: Pursuant to section 10(a)(2) of the Federal
Advisory Committee Act (Pub. L. 92-463, 5 U.S.C., App.), notice is
hereby given for a meeting of RTCA Special Committee 227. The agenda
will include the following:

Tuesday, March 15, 2016

1. Plenary (9:00 a.m.-10:00 a.m.)
    a. Welcome and Administrative Remarks
    b. Introduction
    c. Review of Minutes from Meeting 16
    d. Agenda Overview
    i. Schedule
    ii. New Business
    e. Adjourn Plenary
2. Working Group 3 Work Session, (10:15 a.m.-4:30 p.m.)
    a. New Issues and/or proposed MOPS changes
    b. Review and discussion of MOPS issues and change proposals

Wednesday-Thursday, March 16-17, 2016

1. Working Group 3 Work Session (Wednesday, 9:00 a.m.-Thursday, 10:30
a.m.)
2. Closing Plenary (Thursday, 10:45 a.m.-12:00 p.m.)
    a. Working Group 2 Progress Report/Summary
    b. Other Business
    c. Date of Next Meeting
    d. Adjourn

    Attendance is open to the interested public but limited to space
availability. With the approval of the chairman, members of the public
may present oral statements at the meeting. Plenary information will be
provided upon request. Persons who wish to present statements or obtain
information should contact the person listed in the FOR FURTHER
INFORMATION CONTACT section. Members of the public may present a
written statement to the committee at any time.

    Issued in Washington, DC, on February 23, 2016.
Latasha Robinson,
Management & Program Analyst, NextGen, Enterprise Support Services
Division, Federal Aviation Administration.
[FR Doc. 2016-04209 Filed 2-25-16; 8:45 am]
 BILLING CODE 4910-13-P


[Federal Register Volume 76, Number 229 (Tuesday, November 29, 2011)]
[Proposed Rules]
[Pages 73570-73581]
[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<PHONE_NUMBER> or by Email at
<EMAIL_ADDRESS>
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

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

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<PHONE_NUMBER>71), 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
4<IP_ADDRESS>(b) of ASME/ANSI B31.4. 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 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

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).

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.

    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

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<PHONE_NUMBER>.

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<PHONE_NUMBER>.
    (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<PHONE_NUMBER>.
    (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.

* * * * *

------------------------------------------------------------------------
                                  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

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:

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<PHONE_NUMBER>.
    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<PHONE_NUMBER>.
    (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<PHONE_NUMBER>.
    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:

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


State of california

air resources board

Manufacturer’s Advisory Correspondence (MAC) 2010-XX

sUBJECT:	Optional Test Procedure For Certifying Model-Year 2016 And
Later Vehicles Under The Cool Cars Alternate Performance Compliance
Option

aPPLICABILITY:	2016 model year (MY) and later vehicles < 10,000 GVWR
produced by manufacturers who have chosen to have some or all of their
product line comply with the Cool Cars regulation by demonstrating
equivalent solar control using the alternate performance option.

rEFERENCES:

1.	Section 95603 of Title 17, California Code of Regulations (CCR),
“Cool Car Standards and Test Procedures – 2012 and Subsequent
Model-Year Passenger Cars, Light-Duty Trucks, and Medium-Duty
Vehicles”

The following sections and topics will be presented in this MAC.

I. 	Background and Discussion

II. 	Alternate Performance Option Test Procedure Overview

	A. 	Assembly and Requirements of Test Stand

	B. 	Vehicle and Cabin Equipment

	C. 	Preconditioning

	D. 	Test

III.  	Certification Requirements

	A. 	Cool Cars Group Determination

	B.	Data Vehicle Selection

	C. 	Testing Requirements

	D.	Durability Requirements

	E.	Records Retention

	F.	Carry-Over and Carry-Across

i.	Background and Discussion:

Subarticle 9, sections 95600, 95601, 95602, 95603, 95604, and 95605,
under title 17 of the California Code of Regulations established the
Cool Cars regulation.  The regulation aims to reduce the solar heat gain
of vehicles parked in the sun by requiring manufacturers to equip new
vehicles with solar control glazing.  Specifically, beginning in model
year 2012, manufacturers must use solar control windshields that meet a
50 % total solar transmittance (Tts) standard, side and back windows
that meet a 60 Tts standard, and rooflights that meet a 30 Tts standard.
 Beginning with model year 2016, further control of solar heat gain is
required; reductions in solar heat gain can be achieved either through
solar control of all glazing at 40 Tts (rooflight at 30 Tts), or through
a performance-based option where a combination of solar control
technologies may be used as long as they result in equivalent solar
performance to the glazing alone.  In addition to solar control glazing,
several approaches to reducing solar heat gain have been identified,
including solar reflective paints, passive or active ventilation
systems, solar reflective or thermoregulating materials, and vehicle
insulation.  These and other technologies may be used to meet a
performance-based option.  The purpose of this Manufacturer’s Advisory
Correspondence (MAC) is to provide manufacturers with guidance in
complying with the Tier 2 alternate performance option, should this
option be chosen in lieu of glazing meeting the standard.

The test protocol presented in this MAC is approved for 2016 MY and
beyond.  However, the ARB may revise this guidance in the future if
additional data become available that warrant reassessment of the test
procedures and certification guidelines identified herein.

ii.	Alternate Performance Option Test Procedure Overview

The Cool Cars performance option test procedure includes the testing of
a vehicle in two configurations, one of which is installed with the
solar control glazing meeting the Tier 2 standards, and the other is
installed with a package of alternate solar control technologies.
Through the test procedure outlined in this MAC, manufacturers must show
that the package of alternate solar control technologies results in a
reduction in air temperature within the vehicle that is equal to or
greater than that achieved with the solar control glazing.  The
following procedures should be followed in the preparation and testing
of vehicle:

A. 	Assembly and requirements of the test stand

The goal of a thermal soak test facility is to simulate the impact of an
ambient heat load on the heat transmittance properties of technologies
installed on vehicles in lieu of solar control glazing meeting the Tier
2 Cool Cars requirements. The environmental facility control elements
that are discussed are ambient air temperature and humidity, minimum
test cell size, solar heating, and vehicle frontal air flow.

Ambient Temperature.  (a) Ambient temperature during the test shall be
maintained at 23 °C ± 2 °C (during the heating phase the temperature
is allowed to rise to 35 °C)

	(b) Air temperature shall be recorded continuously at a minimum of 30
second intervals. Records of cell air temperatures and values of average
test temperatures are maintained by the manufacturer for all
certification related programs.

Humidity.  (a) Ambient humidity is controlled, within the test cell,
during all phases of the test sequence to an average of 100 ± grains of
water/pound of dry air.

	(b) Humidity is recorded continuously at a minimum of 30 second
intervals. Records of cell humidity and values of average test humidity
are maintained by the manufacturer for all certification related
programs.

Minimum Test Cell Size.  The recommended test cell size shall conform to
the recommendations in the EPA Solar Loading Procedure – SC03 Federal
Code of Register part 86.161–00 Air conditioning environmental test
facility ambient requirement.

Solar heating.  Vehicle heating shall be obtained through the use of
lamps with solar irradiance according to EPA Solar Loading Procedure –
SC03 Federal Code of Register Section 40 part 86.161–00 Air
conditioning environmental test facility ambient requirement.

Air Flow.  (a) The minimum air flow nozzle discharge area must be equal
or exceed the vehicle frontal inlet area. Optimum discharge area is 18
square feet (4.25 x 4.25), however, other sizes can be used.

		(b) Air flow volumes shall be equal to 2.0 ± 0.25 m/s throughout the
duration of the test.

B. 	Vehicle and Cabin Equipment

Test vehicles from each Cool Cars group shall be chosen according to the
certification guidelines detailed in Section III.   For each test
vehicle, the test procedure shall be conducted twice: once with the test
vehicle equipped with 40 Tts glazing on the
windshield/sidelights/backlights and 30 Tts on the rooflight (if
applicable), and once with the test vehicle equipped with the
manufacturer-designed solar control package.  The same test vehicle
shall be used for both tests.  When equipped with the Tier 2 solar
control glazing, any means may be used to reach the specified level of
solar control, including temporary films.  If metallic reflective
glazing is used to comply with the 40 Tts standard, deletion windows may
be used to improve the operation of electronic devices; deletion windows
may be used on each piece of glazing (windshield, sidelights, and
backlight) and be up to 10% of the glazing area for that piece as
defined in the regulation.

For each test, the test vehicle shall be instrumented as follows:

Temperature sensor accuracy shall be better than or equal to ± 0.25
°C.

The temperature measurement shall be an arithmetic mean of eight
measurements: interior breath level air and foot level air in the front
row (left and right seating positions) and back row (left and right
seating positions).  If there is no back row, only four measurements
from the front row shall be averaged.

Temperature sensors shall be equipped with radiation shields to prevent
direct heating from lamps and/or potential cooling from ventilation
systems.

Front seats shall be placed in the rearmost and lowest position,
seatback angle 90°, headrest down – Figure 1.

Breath-air thermocouple locations shall be at the seat centerline, 660
mm from the seat bottom and 250 mm forward.  If there is only one front
row seat use only one sensor.  If there is only one bench type seat use
the centerline of the left and right front head rests to orient
temperature sensor placement.

Foot-air thermocouple locations shall be at [tbd…FORD has proposal].

Data shall be collected at one second intervals.

Figure 1.  Seat Position and Temperature sensor location

C. 	Preconditioning

≥ 4 hours with windows open, lamps off.  Prior to starting test, close
vehicle windows.  Soak location and test cell location can be in
different locations as long as the vehicle cabin air temperature is
maintained within 23°C ± 2 °C during transport.

D. 	Test

The test vehicle shall be tested according to the procedure below.

Start recording temperature readings.  Temperature readings shall be
taken and logged at one second intervals.

Record temperatures for minimum of 15 minutes with solar lamps off.

If any temperature reading is outside of the 23°C ± 2 °C the vehicle
must be preconditioned again.

Turn solar lamps on, set to 850 W m-2; energy intensity is determined
according to 40 CFR 86.161–00 as an average of the two points measured
at the centerline of the test vehicle at the base of the windshield and
the centerline of the vehicle at the base of the rear window (truck and
van location defined as bottom of vertical window or where an optional
window would be located).

Heat vehicle for 150 minutes while continuing to record temperatures.

Turn lamps off.

Record temperatures for minimum of 15 minutes after lamps are off.

Report average temperature of the eight sensors during final 30 minutes.
while lamps were on.

III. CERTIFICATION REQUIRMENTS

A. 	Cool Cars Group Determination

Manufacturers shall divide their product line into cool cars groups
based on the following criteria that must include but not be limited to:

1. The vehicles covered by a certification application shall be divided
into cool car groups of vehicles which are expected to have similar
thermal responses to a solar load based on vehicle geometry, glazing
area, interior volume, and solar technology package.  Manufacturers
shall use the following guidelines for grouping vehicles:

Vehicle Group	Description

Two-seaters	Cars designed to seat only two adults

Sedan	Cars designed to seat 2+ adults, including hatchbacks

Wagon/Crossover	Utility vehicle built on a car chassis designed to seat
4+ adults

SUV	Utility vehicle built on a light truck chassis designed to seat 5+
adults

Minivan

	Pick-up Trucks

	Van/MDPV	< 10,000 pounds

B. 	Data Vehicle Selection

Within each cool car group the manufacturer shall select the vehicle
which is expected to be worst-case for interior heating due to solar
load.  The manufacturer shall use good engineering judgment in making
selections of vehicles under this section.

1. The worst-case test vehicle for a cool car group shall be the vehicle
with the greatest ratio of top-view glazing area to interior volume.
Top-view glazing area is defined as the total area of glazing determined
by viewing the vehicle from a plane parallel to the roof of the vehicle
rounded to the nearest 0.1 square feet.  Interior volume is the sum,
rounded to the nearest 0.1 cubic feet, of the front and rear seat volume
measured in accordance with the SAE standard “JXXXX” United States.
In the case of vehicles with a cargo area open to the passenger area
(e.g., hatchbacks, crossovers, SUVs) the cargo volume shall be included
in the vehicle volume.  In the event that two vehicles have identical
top-view/volume ratios, the vehicle with the largest total glazing area
shall be used.

2. The test vehicle shall be equipped with all equipment that would
affect solar loading that is standard on that model or is optional
equipment (e.g., rooflights) that is projected to be installed on > 33%
of vehicles produced.

3. The test vehicle shall be equipped with the worst-case interior and
exterior colors and materials offered on that model.  Worst-case colors
and materials are those with the highest solar absorbance.

C.	Data Vehicle Testing Requirements

1. Each test vehicle with alternative technology shall be used to
demonstrate equivalency to a test vehicle which is equipped with glazing
meeting the 2016MY standard with respect to interior temperature under
the specified conditions of the test procedure detailed in Section II.

2. Demonstration of equivalency shall be conducted to demonstrate that
the interior temperature of the test vehicle with the alternative
technology is equal to or less than the interior temperature of the test
vehicle with glazing meeting the 2016MY standards.

3.  Temperatures demonstrating equivalency must be the arithmetic mean
of the four breath air and four foot air temperatures recorded during
the final 30 minutes of the soak period.

D. 	Durability Requirements

1. Manufacturers must submit data to replicate the equivalent of 12
years durability (accelerated aging is acceptable with prior EO
approval).  For example, if on average based upon customer data a shade
on it expected to deploy 6 times/day, then the manufacturer must show
durability data for 12 years of shade deployment 6 times/day.

2. Manufacturer must calculate a deterioration factor for each solar
control management system.  The deterioration factor is the reduction of
a solar control system that may be expected during the useful life of
the system.  For example, an active ventilation fan may at the end of
its life not pull the same volume of air out of the cabin then when it
is new.  The deterioration factor in degrees Fahrenheit must be
subtracted from the temperature reduction seen by the Cool Cars data
vehicle installed with that technology.

E. 	Records Retention

1.  As specified in 17CCR § 9.95603, manufacturers must maintain
records of the direct solar reflectance, solar absorptance, and total
solar transmittance of the glazing utilized for each model vehicle for
ten (10) years after the end of that model-year.

2.  For those vehicles utilizing the alternate performance option,
manufacturers must maintain records of what technology(ies) was
utilized, if any, and data demonstrating the expected durability of the
alternate approach.

3.  For those vehicles utilizing the alternate performance option,
manufacturers must maintain records of the ambient cell conditions
(temperature and humidity) and vehicle interior temperatures measured
during the test.

4.  The records in (1), (2), and (3) must be provided within 30 days of
request by the California Air Resources Board.

5.  The records must include the following information:  model-year,
engine test group, model name, cool car group, direct solar reflectance,
solar absorptance, and total solar transmittance for each type (e.g.,
absorbing, reflecting, privacy) and position (e.g., windshield,
sidelight, rooflight(s), backlight) of glazing used.  The records must
also include necessary and appropriate details for alternate
approach(es) utilized.

F.  Carry-Over and Carry-Across

Certification of a cool car group may carry over model years unless the
vehicle selection is no longer representative. In determining if the
test vehicle is no longer representative, any of the following
conditions may apply:

1. A new model or model design within the cool car group has a top-view
glazing to interior volume ratio greater than the current test vehicle.

2. The solar management technology package changes in such a way as to
reduce the solar control of any piece of the technology package.

3. If the test vehicle did not have a rooflight and projected production
of vehicles with rooflights increases to above the 33% threshold.

 This is the threshold used for emissions certification regulations for
establishing vehicle mass.  See 40CFR §86.1832-01

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DRAFT Cool Cars MAC		03/04/2010

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