releases of greenhouse gases (GHG) to the atmosphere, thus avoiding
additional contributions to global climate change. PHMSA estimated net
GHG emissions abatement over 15 years of 69,000 to 122,000 metric tons
of methane and 14,000 to 22,000 metric tons of carbon dioxide, based on
the estimated number of incidents averted and emissions from pressure
tests and ILI upgrades.
    J.2. Are alternative minimum test pressures (other than those
specified in subpart J) appropriate, and why?
    1. INGAA, supported by a number of pipeline operators, argued that
there is no evidence suggesting that subpart J test pressures are
inadequate. INGAA added that there are circumstances in which
additional tests to 1.25 times MAOP may be appropriate to verify
fitness for service. This is consistent with ASME/ANSI B31.8S and
addressed in its Fitness for Service protocol.
    2. Texas Pipeline Association, Texas Oil & Gas Association, and
Atmos argued that a pressure test at the time of construction is
adequate. The associations further added that operating practices since
part 192 became effective can also verify fitness for service, if
primary test records are not available, particularly if MAOP is
reduced.
    3. AGA, GPTC, and a number of pipeline operators commented that any
test to pressures greater than MAOP has some value. AGA noted that even
tests to 1.1 times MAOP would identify the most severe defects that
have the potential to adversely affect pipeline integrity.
    4. MidAmerican suggested that a fitness for service evaluation
should be allowed if there are service interruption issues and for pre-
1970 pipelines. MidAmerican would allow testing for existing pipelines,
to 1.1 or 1.25 times MAOP or to mill test pressures if they are less
than would be required by subpart J.
    5. An anonymous commenter argued that alternative minimum test
pressures are not appropriate, since they provide no more information
than successful operation at normal operating pressures.
    6. Accufacts suggested that pipelines tested to lower pressures and
that have been subject to aggressive operating cycles be considered for
high-pressure testing. Accufacts would also require test pressures be
recorded both in psig and percent SMYS.
Response to Question J.2 Comments
    PHMSA appreciates the information provided by the commenters.
Following publication of the ANPRM, the NTSB issued its report on the
San Bruno incident that included a recommendation for this issue (P-11-
15). The NTSB recommended that PHMSA amend its regulations so that
manufacturing- and construction-related defects can only be considered
``stable'' if a gas pipeline has been subjected to a post-construction
hydrostatic pressure test of at least 1.25 times the MAOP. This NPRM
proposes to revise the integrity management requirement in
192.917(e)(3) to allow the presumption of stable manufacturing and
construction defects only if the pipe has been pressure tested to at
least 1.25 times MAOP. In addition, PHMSA proposes to revise pressure
test safety factors in Sec.  192.619(a)(2)(ii) to correspond to at
least 1.25 MAOP for newly installed pipelines.
    J.3. Can ILI be used to find seam integrity issues? If so, what ILI
technology should be used and what inspection and acceptance criteria
should be applied?
    1. INGAA and numerous pipeline operators noted that ILI tools can
examine seam issues but the technology to identify and evaluate seam
anomalies is still evolving. INGAA added that there are significant
burdens associated

with requiring pressure testing as an alternative.
    2. AGA reported that its discussions with ILI vendors have
identified that ILI can detect seam issues but detection is dependent
on many conditions and is not guaranteed.
    3. Texas Pipeline Association and Texas Oil & Gas Association
argued that ILI conducted using a multi-purpose tool can provide a seam
assessment equivalent to pressure testing for detection of seam
integrity issues, depending on anomaly characteristics and the ILI
method used.
    4. Northern Natural Gas commented that ILI can be used to detect
seam anomalies. Analysis of anomalies is based on the log-secant method
with consideration of toughness to determine the predicted failure
pressure ratio. The response criteria can then be based on the failure
pressure versus maximum allowable operating pressure, similar to wall
loss. Northern noted that this is consistent with ASME/ANSI B31.8 and
B31.8S.
    5. Accufacts commented that ILI cannot, at present, reliably detect
all seam anomalies.
Response to Question J.3 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
proposes requirements in the rulemaking to address the use of ILI for
seam integrity issues. This includes incorporating industry standard
NACE SP0102-2010 into the regulations to provide better guidance for
conducting integrity assessments with in-line inspection. In addition,
for pipe segments subject to MAOP verification in new Sec.  192.624,
specific guidance is provided for analyzing crack stability when using
engineering critical assessment in conjunction with inline inspection
to address seam or other cracking issues.
    J.4. Are other technologies available that can consistently be used
to reliably find and remediate seam integrity issues?
    1. INGAA and numerous pipeline operators noted that magnetic
particle inspection is now being used by many operators when pipe with
disbanded coating is exposed.
    2. GPTC, Northern Natural Gas, and MidAmerican reported that there
are other methods that are useful under some circumstances, such as x-
ray or other forms of radiography and guided wave ultrasound.
    3. Texas Pipeline Association, Texas Oil & Gas Association, and
Atmos noted that radiography, ultrasonic testing (UT), and shear wave
UT are now being tested.
    4. AGA, supported by a number of its pipeline operator members,
noted that operators must have the flexibility to select appropriate
tools without prior PHMSA approval. AGA argued that technology is
advancing rapidly and that PHMSA stifles advancement by requiring prior
approval of new inspection tools. AGA argued that some requirements
being imposed on the use of other technologies are effectively
regulations imposed without formal rulemaking, citing limitations
imposed on the use of guided wave ultrasound as an example.
    5. Atmos recommended that PHMSA modify its regulations to allow
operators to use appropriate methods to evaluate seam integrity without
requiring approval as ``other technology.''
    6. Accufacts opined that pressure testing and cyclic monitoring and
analysis are the only useful technologies currently available.
Response to Question J.4 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
proposes requirements in the rulemaking to address the use of best
available technology, including use of electromagnetic acoustic
transducers (EMAT) or ultrasonic testing (UT) tools to assess seam
integrity issues. In addition, proposed requirements include performing
fracture mechanics modeling for failure stress pressure and cyclic
fatigue crack growth analysis to assess crack or crack-like defects.
These requirements would apply to any segment that required
verification of MAOP.
    J.5. Should additional pressure test requirements be applied to all
pipelines, or only pipelines in HCAs, or only pipelines in Class 2, 3,
or 4 location areas?
    1. INGAA and several pipeline operators argued that existing
requirements are adequate and any verification beyond those
requirements should rely on INGAA's Fitness for Service protocol. INGAA
argued that its protocol is consistent with Section 23 of the Pipeline
Safety, Regulatory Certainty, and Job Creation Act of 2011.
    2. MidAmerican suggested any new requirements should focus on pipe
with manufacturing and construction defects and should prioritize
pipelines in Class 3 and 4 areas and HCAs. MidAmerican sees little
benefit in testing other pipelines.
    3. An anonymous commenter recommended additional unspecified
requirements be applied to pipelines in Class 3 and 4 areas and HCAs.
    4. The California Public Utilities Commission would apply pressure
testing requirements to HCAs that are determined by the method
described in paragraph 1 in the definition of HCA in Sec.  192.903, as
a minimum.
    5. The Iowa Utilities Board and the Iowa Association of Municipal
Utilities argued that class location is not a reasonable basis for
determining where to apply pressure testing requirements, given that
class location has no relationship to risk. These commenters noted that
small-diameter, low-pressure lines could be Class 3, even with no
structures intended for human occupancy within a potential impact
radius.
    6. The Commissioners of Wyoming County Pennsylvania would apply
requirements to all transmission and gathering pipelines, including
those in Class 1 locations.
    7. Thomas Lael noted that all pipelines have been tested once,
after construction.
Response to Question J.5 Comments
    PHMSA appreciates the information provided by the commenters. This
NPRM proposes requirements for verification of MAOP in new Sec.
192.624 for onshore, steel, gas transmission pipelines that are located
in an HCA or MCA and meet any of the conditions in Sec.  192.624(a)(1)
through (a)(3). Use of the MCA location criteria would apply to pipe
segments where dwellings, occupied sites, or interstate highways,
freeways, and expressways, and other principal 4-lane arterial roadways
are located within the potential impact radius, but would not
necessarily include all class 3 or 4 locations. Verification of MAOP
includes establishing and documenting MAOP using one or more of the
methods in 192.624(c)(1) through (c)(6). In addition, this NPRM
proposes requirements for verification of pipeline material in new
Sec.  192.607 for existing onshore, steel, gas transmission pipelines
that are located in an HCA or class 3 or class 4 locations.
    J.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements pursuant to commenter's suggestions.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.

     The potential environmental impacts of modifying the
existing regulatory requirements.
    No comments were received in response to this question.

K. Establishing Requirements Applicable to Underground Gas Storage

    Underground storage facilities are comprised of wells and
associated separation, compression, and metering facilities to inject
and withdraw natural gas at high pressures from depleted hydrocarbon
reservoirs and salt caverns. Pipelines that transport gas within a
storage field are defined in Sec.  192.3 as transmission pipelines and
are regulated by PHMSA, while underground storage facilities including
surface and subsurface well casing, tubing, and valves are not
currently regulated under part 192. In the ANPRM, PHMSA provided a
brief history of a 1992 accident that occurred in Brenham, Texas an
involving underground storage facility. This incident involved an
uncontrolled release of highly volatile liquids from a salt dome
storage cavern that resulted in 3 fatalities, 21 people treated for
injuries at area hospitals, and damages in excess of $9 million.
Following the incident, the National Transportation Safety Board (NTSB)
conducted an investigation that resulted in a recommendation for the
Research and Special Programs Administration, the precursor to PHMSA,
to initiate a rulemaking proceeding. Following a period of study, RSPA
terminated that rulemaking. RSPA described this action in an Advisory
Bulletin published in the Federal Register on July 10, 1997 (ADB-97-04,
62 FR 37118).
    Since publication of the 1997 Advisory Bulletin, significant
incidents have continued to occur involving underground gas storage
facilities. The most significant incident occurred in 2001 near
Hutchinson, Kansas. An uncontrolled release from an underground gas
storage facility resulted in an explosion and fire, in which two people
were killed. Many residents were evacuated from their homes and were
not able to return for four months.
    The Kansas Corporation Commission initiated enforcement action
against the operator of the Hutchinson storage field as a result of
safety violations associated with the accident. As part of this
enforcement proceeding, it was concluded that the storage field was an
interstate gas pipeline facility. Federal statutes provide that ``[a]
State authority may not adopt or continue in force safety standards for
interstate pipeline facilities or interstate pipeline transportation''
(49 U.S.C. 60104). There were, and remain, no federal safety standards
against which enforcement could be taken. Therefore, the enforcement
proceeding was terminated.
    The ANPRM listed questions for consideration and comment. The
following are general comments received related to this topic as well
as comments related to the specific questions:
General Comments for Topic K
    1. AGA, supported by a number of pipeline operators, suggested that
any proceeding addressing gas storage be conducted under a docket
separate from any pipeline requirements, arguing that the relevant
engineering and regulatory concepts are vastly different.
    2. The Kansas Department of Health and Environment (KDHE) noted
that the ANPRM misstated the agency that took enforcement action in the
case of the Kansas gas storage incident previously discussed. That
action was taken by KDHE, and not the Kansas Corporation Commission, as
stated.
    3. Kansas Corporation Commission recommended that PHMSA work with
the states to have Congress amend the Pipeline Safety Act to allow the
states to regulate interstate and intrastate gas storage wellbores. KCC
noted that current federal regulations undermine the ability of states
to regulate gas storage facilities, as in the 2001 accident where
Kansas attempted to take enforcement as a result of a serious incident
but was precluded from doing so by pre-emption of federal regulations.
    4. The Interstate Oil & Gas Compact Commission argued that states
should be mandated to regulate gas storage wellbores, whether
interstate or intrastate.
    5. The Texas Pipeline Association and Texas Oil & Gas Association
opposed new requirements, arguing that there has been no demonstration
of undue risk or insufficiency of current regulations.
    Comments submitted for questions in Topic K.
    K.1. Should PHMSA develop Federal standards governing the safety of
underground gas storage facilities? If so, should they be voluntary? If
so, what portions of the facilities should be addressed in these
standards?
    1. INGAA suggested that PHMSA develop high-level, performance-based
guidelines that acknowledge and reflect existing applicable state rules
to address regional and geologic variations in underground storage
activity. Development of guidelines should follow PHMSA's current
practice of stakeholder involvement leading to development of a
consensus standard and its subsequent adoption into regulations. INGAA
reported that it is committed to developing a standard under the
auspices of the American Petroleum Institute (API), with work beginning
in 2012. INGAA cautioned that it is important to understand, and
clearly state, the scope of ``gas storage,'' which it contends begins
at and includes the wing valve at the wellhead, the wellhead
components, the well bore, and the ``underground container'' (i.e., the
geologic formation). INGAA stated that PHMSA should recognize the
limits and requirements imposed on gas storage by FERC, arguing that no
new regulations are needed in these areas. A number of pipeline
operators supported INGAA's comments, and have submitted separate
comments addressing one or more of these points.
    2. AGA suggested that PHMSA adopt federal performance standards, in
conjunction with API. AGA argued that one-size-fits-all requirements
are not appropriate in this area, since they would fail to recognize
variations in wells and the geologic diversity of storage caverns and
structures. AGA argued that no new requirements are needed governing
maximum operating parameters and environmental conditions, since these
are addressed adequately by existing federal and state certification
and compliance programs related to gas storage facilities. AGA
recommended that any new standards should be mandatory, but also
recognize regional variations by state due to geologic and geographical
diversity among storage fields. A number of pipeline operators
supported AGA's comments.
    3. INGAA, the Kansas Corporation Commission, and the Interstate Oil
& Gas Compact Commission recommended that compliance with any new
standards be mandatory, but that regulatory authority should be
delegated to the states since PHMSA lacks relevant technical expertise.
A number of pipeline operators supported this comment.
    4. The Kansas Corporation Commission and the Interstate Oil & Gas
Compact Commission recommended that any new standards cover all
portions of a storage facility and that PHMSA enter into a memorandum
of understanding with FERC regarding gas containment.
    5. Southern Star Central Gas Pipeline agreed that the development
of requirements for operation of gas storage facilities is appropriate
but explicitly disagreed with Kansas Corporation Commission's
suggestion that development be delegated to states.

Southern Star indicated that it would not object to the delegation of
inspection and enforcement to federal standards. Southern Star noted
that a federal court has held only federal regulations can be enforced
against its storage facilities. The company also argued that no new
requirements are needed for storage reservoirs given existing FERC
regulations.
    6. GPTC, Nicor, Ameren Illinois, and Atmos argued that existing
regulations are sufficient and that no new standards are needed. GPTC
and Nicor added that if PHMSA elects to develop new requirements, they
should be limited to facilities ``affecting interstate or foreign
commerce.'' Atmos added that geology and circumstances vary
considerably among gas storage facilities and states have the requisite
expertise to regulate storage safety.
    7. Texas Pipeline Association and Texas Oil & Gas Association
argued that PHMSA lacks the expertise to regulate wellbores and
therefore should not attempt to develop gas storage regulations.
    8. FERC, NAPSR, Interstate Oil & Gas Compact Commission, Iowa
Utilities Board, Kansas Corporation Commission, and Railroad Commission
of Texas recommended that PHMSA seek statutory authority to confer
jurisdiction over all gas storage facilities to the states. The
commenters argued that states have expertise on local geology and
storage fields and could therefore regulate in a fashion similar to
that of production facilities. The commenters referred to PHMSA's
Advisory Bulletin ADB 97-04 as a further basis for this recommendation.
FERC further suggested that PHMSA delegate inspection and enforcement
activities to states if statutory changes are not forthcoming.
    9. The Alaska Department of Natural Resources recommended that
PHMSA develop standards in consultation with the states.
    10. The NTSB encouraged the development of gas storage regulations,
noting that this was the subject of its recommendation P-93-9, which it
closed as ``unacceptable action,'' after a rulemaking proceeding to
regulate underground gas storage was terminated in 1997.
    11. A private citizen suggested that there should be some level of
regulation, as gas storage is currently insufficiently regulated.
    12. NAPSR commented that, in many states, the agency familiar with
gas storage issues is not responsible for regulation of pipeline
safety. As a result, NAPSR stated that certification of additional
state agencies may be required.
    13. An anonymous commenter suggested that PHMSA should develop
requirements applicable to piping within gas storage facilities. The
commenter argued that caverns, well heads, casing, tubing, fresh water,
and brine pumping are generally regulated by states.
    14. ITT Exelis Geospatial Systems suggested that PHMSA consider
requirements for leak detection, noting that their LIDAR system could
serve this purpose.
    K.2. What current standards exist governing safety of these
facilities? What standards are presently used for conducting casing,
tubing, isolation packer, and wellbore communication and wellhead
equipment integrity tests for down-hole inspection intervals? What are
the repair and abandonment standards for casings, tubing, and wellhead
equipment when communication is found or integrity is compromised?
    1. AGA, INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas
Association and numerous pipeline operators noted that FERC, EPA, and
the states regulate various aspects of gas storage. Commenters reported
that state regulations generally provide standards for wells and that
EPA regulations provide standards for caverns. AGA described the
aspects regulated by FERC, EPA, and the states and suggested provisions
of each which might be considered for new PHMSA regulations. For
example, it was recommended that a federal guideline be established to
require a storage operator notification-review-and-approval process for
third party wells encroaching on storage containers, which is a
requirement some states currently have in place. Commenters reported
that repaired wells must meet state standards for new wells and state
requirements for abandonment vary. AGA indicated that interstate
storage operators use state requirements as guidance in the absence of
federal regulations.
    2. The Kansas Department of Health and Environment, the Kansas
Corporation Commission, the Railroad Commission of Texas, the
Interstate Oil & Gas Compact Association, Ameren Illinois, and Atmos
reported that states generally regulate gas storage. For example, in
Texas, Statewide Rule 16 applies and KDHE submitted a copy of its gas
storage regulations.
    3. Texas Pipeline Association and Texas Oil & Gas Association noted
that Texas requirements for gas storage are more similar to provisions
that would govern production drilling and operations rather than
pipeline operations.
    K.3. What standards are used to monitor external and internal
corrosion?
    1. AGA, INGAA, and numerous pipeline operators noted that varying
approaches are used and argued that prescriptive standards would be
inappropriate given that no one tool is applicable to all wells and
well casings are not available for direct examination.
    2. The Railroad Commission of Texas reported that its regulations
require integrity testing every five years or after a well work over.
Texas regulations also require periodic casing inspections and a
pipeline integrity program.
    3. Northern Natural Gas reported that it uses the same measures to
monitor corrosion in its gas storage facilities as it does for its
pipelines.
    K.4. What standards are used for welding, pressure testing, and
design safety factors of casing and tubing including cementing and
casing and casing cement integrity tests?
    1. INGAA, AGA, the Texas Pipeline Association, the Texas Oil & Gas
Association and numerous pipeline operators noted that state
requirements reflect unique situations, welding is seldom used,
pressure capacity is demonstrated by historical record, and casing
requirements are customized for local geologic conditions. Welding,
when used, is generally performed to procedures compliant with ASTM
B31.8, part 192, and inspection is conducted to API-1104 criteria.
    2. The Railroad Commission of Texas reported that Texas regulations
are flexible to allow for site-specific decisions.
    K.5. Should wellhead valves have emergency shutdowns both primary
and secondary? Should there be integrity and O&M intervals for key
safety and CP systems?
    1. INGAA, AGA, and several pipeline operators reported that storage
in salt domes generally requires emergency shutdown systems; these
systems are generally not required for storage in depleted gas fields
or aquifers but may be required depending on local site conditions. The
commenters indicated that testing intervals are set in accordance with
operator procedures and CP testing is based on an operator's local
experience.
    2. The Railroad Commission of Texas, the Texas Pipeline
Association, and the Texas Oil & Gas Association reported that Texas'
regulations require emergency shutdown systems and annual drills.
    3. The Kansas Department of Health and Environment suggested that
at least

the primary well should have an emergency shutdown system. KDHE stated
that O&M intervals should be established for key safety systems and
attached a copy of the relevant Kansas regulations to its comments.
    4. Northern Natural Gas suggested that emergency shutoffs should
only be required when the well is within 330 feet of a structure
intended for human occupancy. Northern stated that intervals should be
established for O&M activities and CP systems.
    5. GPTC and Nicor expressed their opinion that no new regulations
are needed in this area; decisions on emergency shutdown should be made
based on local circumstances.
    K.6. What standards are used for emergency shutdowns, emergency
shutdown stations, gas monitors, local emergency response
communications, public communications, and O&M Procedures?
    1. AGA, GPTC, and several pipeline operators reported that
operators generally follow DOT regulations, where applicable, and
industry good practices.
    2. The NTSB commented that gas storage facility information should
be made available to emergency responders, per its recommendation P-11-
8.
    3. The Railroad Commission of Texas, the Texas Pipeline
Association, the Texas Oil & Gas Association, and Atmos reported that
states establish standards in these areas through their regulations.
    4. The Kansas Department of Health and Environment reported that
these standards are specified in its regulations, and submitted a copy
of its regulations as an attachment to its comments.
    K.7. Does the current lack of Federal standards and preemption
provisions in Federal law preclude effective regulation of underground
storage facilities by States?
    1. INGAA, supported by several of its member companies, noted that
jurisdiction over gas storage facilities in interstate pipeline systems
is federal.
    2. AGA and several of its pipeline operator members suggested that
federal standards could assure a degree of consistency, and uniform
standards would promote integrity and safety. AGA opined that
implementation of federal standards could be delegated to the states.
    3. GPTC and Nicor opined that federal regulations are not needed;
as states are not now precluded from regulating gas storage and many do
so.
    4. The Texas Pipeline Association, the Texas Oil & Gas Association,
Atmos, Ameren Illinois, and Northern Natural Gas opined that effective
state regulation is not now precluded. The commenters stated that state
regulation in combination with applicable FERC and DOT requirements has
been demonstrated to assure safety successfully.
    5. The Kansas Department of Health and Environment and the Kansas
Corporation Commission noted that state regulation of the safety of
interstate gas storage facilities is currently precluded. When Kansas
attempted to enforce its requirements following an accident at an
interstate storage facility, it was prevented from doing so by a
federal court on the basis of federal preemption. The agencies noted
that lack of action by PHMSA or FERC on interstate gas storage facility
safety precludes states from taking any action and leaves these
facilities essentially unregulated.
    K.8. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.
     The potential environmental impacts of modifying the
existing regulatory requirements.
    No comments were received in response to this question.
Response to All Topic K Comments
    Since the publication of the ANPRM and the close of its comment
period, Southern California Gas Company's (SoCal Gas) Aliso Canyon
Natural Gas Storage Facility Well SS25 failed, causing a sustained and
uncontrolled natural gas leak near Los Angeles, California. The
failure, possibly from the downhole well casing, resulted in the
relocation of more than 4,400 families according to the Aliso Canyon
Incident Command briefing report issued on February 1, 2016. On January
6, 2016, California Governor Jerry Brown issued a proclamation
declaring the Aliso Canyon incident a state emergency. On February 5,
2016, PHMSA issued an advisory bulletin in the Federal Register (81 FR
6334) to remind all owners and operators of underground storage
facilities used for the storage of natural gas to consider the overall
integrity of the facilities to ensure the safety of the public and
operating personnel and to protect the environment. The advisory
bulletin specifically reminded these operators to review their
operations and identify the potential of facility leaks and failures,
review the operation of their shut-off and isolation systems, and
maintain updated emergency plans. In addition, PHMSA used the advisory
bulletin to advocate the review of a previous advisory bulletin (97-04)
dated July 10, 1997 and the voluntary implementation of American
Petroleum Institute (API) 1170 ``Design and Operation of Solution-mined
Salt Caverns Used for Natural Gas Storage, First Edition, July 2015,''
API RP 1171 ``Functional Integrity of Natural Gas Storage in Depleted
Hydrocarbon Reservoirs and Aquifer Reservoirs, First Edition, September
2015,'' and Interstate Oil and Gas Compact Commission (IOGCC) standards
entitled ``Natural Gas Storage in Salt Caverns--A Guide for State
Regulators'' (IOGCC Guide), as applicable. PHMSA will consider
proposing a separate rulemaking to address the safety of underground
natural gas storage facilities. Proposing a separate rulemaking that
specifically focuses on improving the safety of underground natural gas
storage facilities will allow PHMSA to fully consider the impacts of
incidents that have occurred since the close of the initial comment
period. It will also allow the Agency to consider voluntary consensus
standards that were developed after the close of the comment period for
this ANPRM, and to solicit feedback from additional stakeholders and
members of the public to inform the development of potential
regulations.

L. Management of Change

    The ANPRM requested comments regarding the addition of requirements
for the management of change to provide a greater degree of control
over this element of pipeline risk, particularly following changes to
physical configuration or operational practices. Operation of a
pipeline over an extended period without effective management of
change, such as changes to pipeline systems (e.g., pipeline equipment,
computer equipment or software used to monitor and control the
pipeline) or to practices used to construct, operate, and maintain
those systems, can result in safety issues. Changes can introduce
unintended consequences if the change is not well thought out or is
implemented in a manner not consistent with its design or planning.
Similarly, changes in procedures require people to perform new or
different actions, and failure to train them properly and in a timely

manner can result in unexpected consequences. The result can be a
situation in which risk or the likelihood of an accident is increased.
A recently completed but poorly-designed modification to the pipeline
system was a factor contributing to the Olympic Pipeline accident in
Bellingham, Washington. The following are general comments received
related to this topic as well as comments related to the specific
questions:
General Comments for Topic L
    1. INGAA and several of its pipeline operator members disagreed
with the implication in the ANPRM that change management is not now
addressed in regulations. They pointed out that Sec.  192.911(k) and
ASME/ANSI B31.8S (incorporated by reference) already address this
subject. INGAA reported that its members are committed to clarifying
and expanding the use of a formal ``management of change'' process, and
to facilitating its consistent application as a key management system.
INGAA expressed its belief that the full adoption of ASME/ANSI B31.8S
will facilitate the widespread application of these principles.
Dominion East Ohio Gas also noted that part 192 already contains a
management of change process. In addition, Chevron noted that
management of change programs are generally specific to the
organizational, operational, and ownership structures of the company,
and part 192 already addresses this subject.
    2. A private citizen opined that management of change is
necessarily an integral part of quality management systems and another
private citizen supported management of change requirements, noting
that accidents often result from changes to systems. The Alaska
Department of Natural Resources also supported PHMSA's goal of
establishing management of change requirements or guidelines.
Response to General Comments for Topic L
    PHMSA appreciates the information provided by the commenters. PHMSA
agrees management of change is currently addressed in Sec.  192.911(k).
However, because of its importance, and consistent with INGAA members'
commitment to expanding use of formal MOC processes, PHMSA believes it
is prudent to provide greater emphasis on MOC directly within the rule
text.
    Therefore, PHMSA proposes to clarify integrity management
requirements for management of change by explicitly including aspects
of an effective management of change process into the rule text to
emphasize the current requirements. In addition, PHMSA also proposes to
add a new subsection 192.13(d) that would apply to onshore gas
transmission pipelines, and require that an evaluation must be
performed to evaluate and mitigate, as necessary, the risk to the
public and environment as an integral part of managing pipeline design,
construction, operation, maintenance and integrity, including
management of change. The new paragraph would also articulate the
general requirements for a management of change process, consistent
with Section 192.911(k).
    Comments submitted for questions in Topic L.
    L.1. Are there standards used by the pipeline industry to guide
management processes including management of change? Do standards
governing the management of change process include requirements for IM
procedures, O&M manuals, facility drawings, emergency response plans
and procedures, and documents required to be maintained for the life of
the pipeline?
    1. AGA, supported by several of its members, and several
transmission pipeline operators questioned why this question was in the
ANPRM, noting that management of change requirements are already
promulgated in Sec.  192.911(k). GPTC added that Sec.  192.909 also
addresses this subject.
    2. INGAA reported that Section 11 of ASME/ANSI B31.8S is the
industry standard in this area, and all of the considerations in this
question are included in operators' management of change processes.
Several pipeline operators supported this comment.
    3. Atmos reported that it is not aware of any standards used by the
industry to guide management of change processes. Atmos does not have a
formal management of change process, except in its integrity management
program, but expressed its conclusion that existing practices within
the company contribute to its ability to manage change.
    4. Texas Pipeline Association (TPA) reported that its members do
not have formal management of change processes but comply with
regulations that address proxy requirements (e.g., Sec.  192.911). TPA
expressed its belief that part 192, taken as a whole, includes
management of change requirements to which its members adhere. Texas
Oil & Gas Association supported TPA's comments.
    5. California Public Utilities Commission reported that it is
unaware of any pipeline industry standards in this area.
    6. An anonymous commenter opined that most operators do not have
management of change processes.
    7. The NTSB recommended that PHMSA require operators of natural gas
transmission and distribution pipelines and hazardous liquid pipelines
to ensure that their control room operators immediately notify the
relevant 911 emergency call centers of possible ruptures
(Recommendation P-11-9).
    8. TransCanada reported that it is committed to clarifying and
expanding the use of a formal ``management of change'' process.
TransCanada expressed its conclusion that the full adoption of ASME/
ANSI B31.8S will facilitate the widespread application of management of
change principles.
Response to Question L.1 Comments
    PHMSA appreciates the information provided by the commenters, which
did not identify any standards beyond ASME/ANSI B31.8S, which is
already invoked by part 192, and used by the pipeline industry to guide
management processes including management of change. See response to
the general comments for Topic L, above.
    L.2. Are standards used in other industries (e.g., Occupational
Safety and Health Administration standards at 29 CFR 1910.119)
appropriate for use in the pipeline industry?
    1. INGAA reported that Section 11 of ASME/ANSI B31.8S is based on
OSHA's Process Safety Management (PSM) standards. INGAA noted that OSHA
worked with industry in developing PSM standards that would identify
potential threats and assure that mitigative actions were taken.
Several pipeline operators supported INGAA's comments.
    2. AGA and GPTC expressed their belief that there is no benefit in
comparing standards with other industries, reiterating that Sec. Sec.
192.909 and 192.911 and ASME/ANSI B31.8S already include management of
change. Several pipeline operators supported AGA's comments.
    3. The Texas Pipeline Association and the Texas Oil & Gas
Association reported that their members are aware of standards used in
other industries but do not believe they are appropriate or applicable
to the pipeline industry.
    4. The Iowa Association of Municipal Utilities expressed its
conclusion that OSHA standards are complicated and would be unduly
costly for small municipal utilities.
    5. Accufacts noted that transportation pipelines are specifically
excluded from OSHA regulation; however, this does not prevent PHMSA
from incorporating elements of 29 CFR 1910.119 into the

federal pipeline safety regulations in order to mandate a more prudent
pipeline safety culture.
    6. Atmos reported that it has no experience with standards used in
other industries but noted that OSHA standards appear to be directed
toward situations where processes interact such that a change in one
process affects a second or third process.
    7. Ameren Illinois suggested that standards from other industries
would need to be studied to determine if they are applicable to the
pipeline industry.
    8. An anonymous commenter suggested that the OSHA standards are a
good model for pipelines, as they are well written and thought out.
Response to Question L.2 Comments
    PHMSA appreciates the information provided by the commenters. See
response to the general comments for Topic L, above.
    L.3. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.
     The potential environmental impacts of modifying the
existing regulatory requirements.
    No comments were received in response to this question.

M. Quality Management Systems (QMS)

    The ANPRM requested comments on whether and how to impose
requirements related to quality management systems. Quality management
includes the activities and processes that an organization uses to
achieve quality. These include formulating policy, setting objectives,
planning, quality control, quality assurance, performance monitoring,
and quality improvement.
    Achieving quality is critical to gas transmission pipeline design,
construction, and operations. PHMSA recognizes that pipeline operators
strive to achieve quality, but our experience has shown varying degrees
of success in accomplishing this objective among pipeline operators.
PHMSA believes that an ordered and structured approach to quality
management can help pipeline operators achieve a more consistent state
of quality and thus improve pipeline safety.
    PHMSA's pipeline safety regulations do not currently address
process management issues such as quality management systems. Section
192.328 requires a quality assurance plan for the construction of
pipelines intended to operate at an alternative MAOP, but there is no
similar requirement applicable to other pipelines. Quality assurance is
generally considered to be an element of quality management. Important
elements of quality management systems are their design and application
to control (1) the equipment and materials used in new construction
(e.g., quality verification of materials used in construction and
replacement, post-installation quality verification), and (2) the
contractor work product used to construct, operate, and maintain the
pipeline system (e.g., contractor qualifications, verification of the
quality of contractor work products).
    The ANPRM then listed questions for consideration and comment. The
following are general comments received related to this topic as well
as comments related to the specific questions:
General Comments for Topic M
    1. MidAmerican suggested that PHMSA work with the committees for
ASME/ANSI B31.8 and B31.8S to address these topics more fully, if PHMSA
believes more is needed. MidAmerican opined that a general rule
addressing quality management systems would divert resources and
adversely affect safety, if applied to this already heavily-regulated
industry.
    2. The Alaska Department of Natural Resources supported quality
management systems and suggested that pipeline operators should apply
such standards to their contractors.
    3. A private citizen supported quality management systems, noting
that this is an area that would be difficult to regulate but might be
an element in incentive programs.
    Comments submitted for questions in Topic M.
    M.1. What standards and practices are used within the pipeline
industry to assure quality? Do gas transmission pipeline operators have
formal QMS?
    1. INGAA opined that achieving consistent quality materials,
construction and management is an appropriate focus for the INGAA
Foundation, which has sponsored and will continue to sponsor workshops
on this subject. INGAA reported that the Foundation plans to publish
five relevant White Papers in 2012 and its Integrity Management--
Continuous Improvement team is currently working on guidelines. INGAA
also noted that there are elements of a quality management system in
ASME/ANSI B31.8S, already incorporated by reference, including quality
assurance/quality control, management of change, communication and
performance measurement, Standards, specifications, and procedures
governing pipe and appurtenances form part of a pipeline quality
management system. INGAA cited ISO (9001:2008/29001:2010) and API (Spec
Q1) quality management standards as references that are available for
operator use. INGAA further noted that API published Spec Q2 in
December 2011. Several pipeline operators supported INGAA's comments.
    2. AGA, GPTC, Nicor, Atmos, the Texas Pipeline Association, and the
Texas Oil & Gas Association suggested that part 192, taken as a whole,
is essentially a quality management system. AGA provided a summary
listing of part 192 requirements that assure quality. A number of
additional pipeline operators supported AGA's comments.
    3. Ameren Illinois reported that it has a quality assurance program
for pipeline construction that includes building alliances with
excavators and other elements.
    4. Paiute and Southwest Gas reported that their practices beyond
compliance with part 192 requirements include operator qualification
(OQ) for construction, an internal quality assurance group, root cause
analysis of events, and quality control verification of OQ.
    5. MidAmerican reported that it has no formal quality management
system but applies standards to assure quality processes. In
particular, ASME/ANSI B31.8 and B31.8S and ANSI/ISO/ASQ Q9004-2000 were
used to guide its company quality programs. MidAmerican also has a
contractor oversight program.
    6. An anonymous commenter opined that most operators have a quality
management system, often incorporated into their SCADA system, to
satisfy customers or end user requirements. The commenter suggested
that some of these systems have only recently been modified to address
internal corrosion mechanisms, often identified as part of operators'
integrity management programs.
    M.2. Should PHMSA establish requirements for QMS? If so, why? If
so, should these requirements apply to all gas transmission pipelines
and to the complete life cycle of a pipeline system?

    1. INGAA, supported by a number of its pipeline operator members,
asserted that no new requirements are appropriate at this time. INGAA
noted that much work is ongoing in this area and it may be appropriate
to adopt some standards (e.g., API Q1 or Q2) in the future.
    2. AGA, GPTC, the Texas Pipeline Association, the Texas Oil & Gas
Association, Oleksa and Associates, and numerous pipeline operators
expressed an opinion that new quality assurance requirements are not
needed. These commenters view part 192 as quality assurance
requirements and argue that a new programmatic requirement would not be
beneficial.
    3. TransCanada opined that quality management systems need to be
adopted throughout the entire industry and embraced by operators and
contractors alike, arguing that this would provide a more consistent
level of quality throughout the industry. TransCanada opined that the
INGAA Foundation is the appropriate venue in which to develop
guidelines.
    4. Northern Natural Gas opined that the existing process, which
includes PHMSA/State inspections, is adequate.
    5. A private citizen commented that quality management systems
should be required to improve pipeline safety, including documentation,
investigations, validation, audits/inspections, change management,
training, and quality/management oversight.
    6. An anonymous commenter opined that no new requirements are
needed, arguing that most operators have such systems.
    M.3. Do gas transmission pipeline operators require their
construction contractors to maintain and use formal QMS? Are contractor
personnel that construct new or replacement pipelines and related
facilities already required to read and understand the specifications
and to participate in skills training prior to performing the work?
    1. INGAA reported that most of its members apply quality management
principles, including requiring contractors conform to specified
requirements, though the approach varies from operator to operator.
INGAA acknowledged, however, that ``[t]here is room to establish a more
structured approach to QMS for operators and construction contractors''
to assure more consistency. A number of pipeline operators supported
INGAA's comments.
    2. AGA reported that transmission operators have the means to
assure contractor work quality and that most LDC operators impose
operator qualification (OQ) and other specific requirements on their
construction contractors.
    3. The Texas Pipeline Association and the Texas Oil & Gas
Association encouraged PHMSA not to adopt requirements for operators to
train construction personnel. The associations expressed concerns over
potential liability and their preference for a performance-based
standard.
    4. Ameren Illinois, Atmos, and MidAmerican reported that they apply
operator qualification (OQ) requirements on their contractors.
    5. Northern Natural Gas, Paiute, and Southwest Gas reported that
they do not require contractors to have formal QMS but do require
conformance to various standards.
    6. Oleksa and Associates reported its experience that operators
require construction contractors to meet the same standards as their
employees.
    7. GPTC, Nicor, and an anonymous commenter suggested that
compliance with construction regulations contribute to QMS through
requirements for specifications and inspections.
    8. NAPSR, the Texas Pipeline Association, and the Texas Oil & Gas
Association suggested that operator qualification (OQ) requirements be
applied to construction, since this would apply formal QMS to the full
range of construction and operation.
    M.4. Are there any standards that exist that PHMSA could adopt or
from which PHMSA could adapt concepts for QMS?
    1. INGAA and a number of pipeline operators suggested that several
standards could be used as general references, including ISO 9001:2008
(Quality Management Systems), ISO 29001:2010 (Oil and Gas) and API Spec
Q1 (Oil and Gas). INGAA opined that compliance with these standards
should not be required, and added that additional standards, white
papers, and guidance are under development.
    2. The AGA, GPTC, Nicor, and Ameren Illinois opposed new
requirements in this area. AGA opined that part 192 is already
``saturated'' with this type of requirement. A number of additional
pipeline operators supported AGA's comments.
    3. The NTSB recommended improvement to PHMSA's drug and alcohol
requirements, citing their recommendations P-11-12 & 13.
    4. A private citizen suggested that, by extrapolating from the
practices of a pipeline operator with a good safety record. The
commenter stated that useful references include the Baldrige
Performance Excellence Program and Quality Management Standard ISO
9000.
    M.5. What has been the impact on cost and safety in other
industries in which requirements for a QMS have been mandated?
    1. INGAA reported that quality management systems have been
demonstrated to reduce risk and opined that the keys to a successful
QMS are simplicity, empowerment, accountability and ease of
implementation. A number of pipeline operators supported INGAA's
comments.
    M.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.
     The potential environmental impacts of modifying the
existing regulatory requirements.
    No comments were received in response to this question.
Response to All Topic M Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
does not propose additional rulemaking for this topic at this time.
PHMSA will review the comments received on the ANPRM and will consider
them in future rulemaking.

N. Exemption of Facilities Installed Prior to the Regulations

    The ANPRM requested comments regarding proposed changes to part 192
regulations that would eliminate provisions that exempt pipelines from
pressure test requirements to establish MAOP. Federal pipeline safety
regulations were first established with the initial publication of part
192 on August 19, 1970 (35 FR 13248). Gas transmission pipelines had
existed for many years prior to this, some dating to as early as 1920.
Many of these older pipelines had operated safely for years at
pressures higher than would have been allowed under the new
regulations. It was concluded that a required reduction in the
operating pressure of these pipelines would not have resulted in a
material increase in safety. Therefore, a provision was included in the
regulations (Sec.  192.619(c)) that allowed pipelines to

operate at the highest actual operating pressure to which they were
subjected during the 5 years prior to July 1, 1970. The safe operation
of these pipelines at these pressures was deemed to be evidence that
operation could safely continue.
    Many gas transmission pipelines continue to operate in the United
States under an MAOP established in accordance with Sec.  192.619(c).
Some of these pipelines operate at stress levels higher than 72 percent
specified minimum yield strength (SMYS), the highest level generally
allowed for more modern gas transmission pipelines. Some pipelines
operate at greater than 80 percent SMYS, the alternate MAOP allowed for
some pipelines by regulations adopted October 17, 2008 (72 FR 62148).
Under these regulations, operators who seek to operate their pipelines
at up to 80 percent SMYS (in Class 1 locations) voluntarily accept
significant additional requirements applicable to design, construction,
and operation of their pipeline that are intended to assure quality and
safety at these higher operating stresses. Pipelines that operate under
an MAOP established in accordance with Sec.  192.619(c) are subject to
none of these additional requirements.
    Part 192 also includes several provisions other than establishment
of MAOP for which an accommodation was made in the initial part 192.
These provisions allowed pipeline operators to use steel pipe that had
been manufactured before 1970 and did not meet all requirements
applicable to pipe manufactured after part 192 became effective
(192.55); valves, fittings and components that did not contain all the
markings required (192.63); and pipe which had not been transported
under the standard included in the new part 192 (192.65, subject to
additional testing requirements).
    The ANPRM then listed questions for consideration and comment. The
following are general comments received related to this topic as well
as comments related to the specific questions:
General Comments for Topic N
    1. INGAA and a number of pipeline operators opined that age alone
is not an appropriate criterion for determining a pipeline's fitness
for service. Old pipe that is well maintained operates safely and unfit
pipe should be replaced regardless of age. INGAA suggested that fitness
for service of pipe in HCAs should be evaluated using available
records, if adequate, or through new testing. INGAA attached a white
paper to its comments that described its Fitness for Service protocol.
INGAA also cautioned that any requirement to reconfirm MAOP should be
subject to a rigorous cost-benefit analysis, as hydrostatic testing is
very expensive and could require outages of up to several weeks.
    2. A private citizen suggested phasing out sub-standard or systems
that pre-date regulatory requirements where public safety is concerned,
implying that this has been done in other areas (citing elimination of
radium dial watches and leaking underground storage tanks as examples).
    3. A private citizen suggested that legacy facilities should be
subject to a timetable to come into full compliance with current
regulations, arguing that this would improve safety and knowledge of
older facilities.
Response to General Comments for Topic N
    PHMSA appreciates the information provided by the commenters. NTSB
recommended that regulatory exemptions be repealed. In addition,
section 23 of the Act addressed gas transmission pipelines without
records sufficient to validate MAOP. In response to these concerns,
this NPRM proposes requirements for verification of maximum allowable
operating pressure (MAOP) in new Sec.  192.624 for onshore, steel, gas
transmission pipelines that are located in an HCA or MCA and meet any
of the conditions in Sec.  192.624(a)(1) through (a)(3). Verification
of MAOP includes establishing and documenting MAOP if the pipeline MAOP
was established in accordance with Sec.  192.619(c), the grandfather
clause. In addition, this NPRM proposes requirements for verification
of pipeline material in accordance with new Sec.  192.607 for existing
onshore, steel, gas transmission pipelines that are located in an HCA
or class 3 or class 4 locations.
Comments Submitted for Questions in Topic N
    N.1. Should PHMSA repeal provisions in part 192 that allow use of
materials manufactured prior to 1970 and that do not otherwise meet all
requirements in part 192?
    1. INGAA, supported by several pipeline operators, suggested age,
alone, should not be a criterion for determining fitness for service,
noting some pre-regulation materials (e.g., seamless pipe) are as good
as today's.
    2. AGA, GPTC, and numerous pipeline operators noted it is illogical
to storehouse pre-1970 materials for installation now. AGA indicated
that it thus did not understand the purpose of the ANPRM question.
    3. Iowa Utilities Board, NAPSR, Texas Pipeline Association, Texas
Oil & Gas Association, Accufacts, Alaska Department of Natural
Resources, Atmos, Commissioners of Wyoming County Pennsylvania,
Professional Engineers in California Government, and an anonymous
commenter encouraged repeal of this allowance. Some of these commenters
would allow a specified time period for operators to come into
compliance.
    4. Thomas Lael and MidAmerican recommended operators be allowed to
continue use of materials that have already been placed into service,
arguing that they have been demonstrated safe through integrity
management.
    5. Ameren Illinois and Northern Natural Gas opposed repeal of this
provision.
Response to Question N.1 Comments
    PHMSA appreciates the information provided by the commenters. As
stated above, this NPRM proposes requirements for verification of MAOP
in new Sec.  192.624 for onshore, steel, gas transmission pipelines
that are located in an HCA or MCA and meet any of the conditions in
Sec.  192.624(a)(1) through (a)(3). In addition, this NPRM proposes
requirements for verification of pipeline material in accordance with
new Sec.  192.607 for existing onshore, steel, gas transmission
pipelines that are located in an HCA or class 3 or class 4 locations.
    N.2. Should PHMSA repeal the MAOP exemption for pre-1970 pipelines?
Should pre-1970 pipelines that operate above 72% SMYS be allowed to
continue to be operated at these levels without increased safety
evaluations such as periodic pressure tests, in-line inspections,
coating examination, CP surveys, and expanded requirements on
interference currents and depth of cover maintenance?
    1. INGAA and a number of pipeline operators opposed repeal of this
exemption. INGAA suggested its Fitness for Service protocol be used to
assure continued safety of old pipe.
    2. AGA, GPTC, Texas Pipeline Association, Texas Oil & Gas
Association and numerous pipeline operators commented that the wording
of this question creates a false impression. There is no exemption for
MAOP. Rather, the regulations establish requirements for determining
MAOP and the only ``exemption'' is to a post-construction hydrostatic
test, since the pipeline was in service at the time the regulations
became effective.
    3. AGA, supported by several of its pipeline operator members,
contended the appropriate method for verifying

MAOP of older pipelines is for PHMSA to follow Section 23 of the
Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.
AGA opposed eliminating Sec.  192.619(c) for determining MAOP of older
pipelines, arguing that it would cripple the nation's gas pipeline
capacity. A number of additional pipeline operators joined AGA in
opposing any new requirement to pressure test all older pipelines,
arguing costs would be excessive and there would be significant
potential to interrupt gas services. AGA included a white paper with
its comments outlining its suggested approach to MAOP verification.
    4. Accufacts, Texas Pipeline Association, and Texas Oil & Gas
Association opposed requiring all pre-1970 pipelines to reduce MAOP, if
necessary, to a pressure that would impose stresses no greater than 72
percent SMYS. Accufacts noted this pipe is still safe at its current
operating pressure if it is managed properly, but suggested a possible
focus on interactive threats that might make seam welds unstable.
    5. Ameren Illinois opposed modifying MAOP requirements for pre-1970
pipelines.
    6. NAPSR, the NTSB, and Professional Engineers in California
Government supported repeal of exemptions applying to MAOP of pre-1970
pipelines. NAPSR added PHMSA should not allow any pipeline to operate
at pressures above that which would impose stresses greater than 72
percent SMYS.
    7. MidAmerican suggested use of a performance-based approach, which
might include a fitness for service determination for pipe in Class 2,
3, or 4 areas or HCA.
    8. Commissioners of Wyoming County Pennsylvania would support
repeal of MAOP exemptions because pipeline infrastructure is aging and
they see additional safety measures needed.
Response to Question N.2 Comments
    PHMSA appreciates the information provided by the commenters. As
stated above, this NPRM proposes requirements for verification of MAOP
in new Sec.  192.624 for onshore, steel, gas transmission pipelines
that are located in an HCA or MCA and meet any of the conditions in
Sec.  192.624(a)(1) through (a)(3). Verification of MAOP includes
establishing and documenting MAOP if the pipeline segment: (1) Has
experienced a reportable in-service incident, as defined in Sec.
191.3, since its most recent successful subpart J pressure test, due to
an original manufacturing-related defect, a construction-,
installation-, or fabrication-related defect, or a cracking-related
defect, including, but not limited to, seam cracking, girth weld
cracking, selective seam weld corrosion, hard spot, or stress corrosion
cracking and the pipeline segment is located in one of the following
locations: (i) A high consequence area as defined in Sec.  192.903;
(ii) a class 3 or class 4 location; or (iii) a moderate consequence
area as defined in Sec.  192.3 if the pipe segment can accommodate
inspection by means of instrumented inline inspection tools (i.e.,
``smart pigs''); (2) Pressure test records necessary to establish
maximum allowable operating pressure per subpart J for the pipeline
segment, including, but not limited to, records required by Sec.
192.517(a), are not reliable, traceable, verifiable, and complete and
the pipeline segment is located in one of the following locations: (i)
A high consequence area as defined in Sec.  192.903; or (ii) a class 3
or class 4 location; or (3) the pipeline segment maximum allowable
operating pressure was established in accordance with Sec.  192.619(c)
of this subpart before [effective date of rule] and is located in one
of the following areas:
    (i) A high consequence area as defined in Sec.  192.903; (ii) a
class 3 or class 4 location; or (iii) a moderate consequence area as
defined in Sec.  192.3 if the pipe segment can accommodate inspection
by means of instrumented inline inspection tools (i.e., ``smart
pigs'').
    N.3. Should PHMSA take any other actions with respect to exempt
pipelines? Should pipelines that have not been pressure tested in
accordance with subpart J be required to be pressure tested in
accordance with present regulations?
    1. AGA and a number of pipeline operators opposed any requirement
to pressure test all pipelines that have not been tested in accordance
with subpart J, arguing Congress considered and rejected this approach
in developing the Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011. The commenters argue such a requirement would
cripple the pipeline industry and support the alternative requirements
included in the Act.
    2. MidAmerican suggests a focus on pipe in Class 3 or 4 areas or
HCAs. The company suggests no new requirements are needed if records
are complete for pipe in these areas or it has been tested to 1.25
times MAOP. Otherwise, MidAmerican would subject such pipelines to a
fitness for service determination.
    3. The NTSB would require all pre-1970 pipelines to be pressure
tested, including a spike test, citing their recommendation P-11-14.
    4. Texas Pipeline Association and Texas Oil & Gas Association
opposed a requirement to test all pipelines not previously subject to
subpart J tests, arguing testing per the construction codes in effect
when the pipelines were constructed and safe operating experience since
then is adequate assurance of suitability.
    5. Ameren Illinois reported the State of Illinois imposed pressure
testing requirements before federal pipeline safety regulations were
adopted in 1970.
    6. Iowa Utilities Board and Iowa Association of Municipal Utilities
recommended any new pressure test requirement be limited to pipeline
segments in HCA and which operate at pressures where a rupture could
occur (generally greater than 30 percent SMYS). These commenters argued
the serious impacts of service interruptions pressure testing would be
necessary for testing have not been appreciated and the cost for such
testing of other pipelines would be unjustified absent any specific
demonstration of risk.
    7. Commissioners of Wyoming County Pennsylvania and Professional
Engineers in California Government (PECG) would require pressure
testing for pipelines not previously tested to subpart J requirements,
since this would assure public safety. PECG would also require testing
if adequate records of prior tests do not exist, noting California has
experienced two failures to date of pipeline not adequately tested.
PECG would also require all testing, modification, and replacement be
observed by a certified inspector loyal to public safety interests.
    8. An anonymous commenter would require subpart J testing but would
allow schedule flexibility.
Response to Question N.3 Comments
    PHMSA appreciates the information provided by the commenters. This
NPRM proposes requirements for verification of MAOP in new Sec.
192.624 for onshore, steel, gas transmission pipelines that are located
in an HCA or MCA and meet any of the conditions in Sec.  192.624(a)(1)
through (a)(3). Verification of MAOP includes establishing and
documenting MAOP using one or more of the methods in 192.624(c)(1)
through (c)(6). In addition, this NPRM proposes requirements for
verification of pipeline material in new Sec.  192.607 for existing
onshore, steel, gas transmission pipelines that are located in an HCA
or class 3 or class 4 locations.
    N.4. If a pipeline has pipe with a vintage history of systemic
integrity issues in areas such as longitudinal

weld seams or steel quality, and has not been pressure tested at or
above 1.1 times MAOP or class location test criteria (Sec. Sec.
192.505, 192.619 and 192.620), should this pipeline be required to be
pressure tested in accordance with present regulations?
    1. AGA and several pipeline operators opposed requiring hydrostatic
tests for systemic issues, arguing it could potentially affect all
pipelines. AGA noted Congress had considered and rejected this approach
in developing the Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011. AGA supports the requirements in Section 23 of
the Act. AGA further argued hold times in subpart J are excessive since
defects that fail will likely do so in the first 30 minutes and urged
PHMSA not to require any special testing for pipelines operating at
less than 30 percent SMYS since they are likely to fail by leakage
rather than rupture.
    2. GPTC and Nicor opposed a blanket requirement for hydrostatic
testing. They would test only in event of a demonstrated safety issue
and only if a risk evaluation indicates testing is appropriate. For
distribution operators, these commenters would treat any safety issues
in distribution integrity management programs.
    3. Atmos would not require pressure testing for systemic issues,
arguing these are addressed adequately by subpart O.
    4. Accufacts would require testing, focusing first on pipe in HCAs,
at pressures greater than 1.1 times MAOP. Accufacts understands some
operators are arguing for a 1.1 x MAOP test pressure and considers that
to be insufficient.
    5. MidAmerican would allow a risk-based alternative approach for
problem pipe.
    6. Texas Pipeline Association and Texas Oil & Gas Association would
require assessments appropriate to a specific threat rather than a
blanket requirement for pressure testing.
    7. An anonymous commenter supported pressure testing for pipe
subject to systemic issues.
Response to Question N.4 Comments
    PHMSA appreciates the information provided by the commenters. This
NPRM proposes requirements for verification of MAOP in new Sec.
192.624 for onshore, steel, gas transmission pipelines that are located
in an HCA or MCA and meet any of the conditions in Sec.  192.624(a)(1)
through (a)(3).
    N.5. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.
     The potential environmental impacts of modifying the
existing regulatory requirements.
    No comments were received in response to this question.

O. Modifying the Regulation of Gas Gathering Lines

    The ANPRM requested comments regarding modifying the regulations
relative to gas gathering lines. In March 2006, PHMSA issued new safety
requirements for ``regulated onshore gathering lines.'' \38\ Those
requirements established a new method for determining if a pipeline is
an onshore gathering line, divided regulated onshore gas gathering
lines into two risk-based categories (Type A and Type B), and subjected
such lines to certain safety standards.
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    \38\ 71 FR 13289 (March 15, 2006).
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    The 2006 rule defined onshore gas gathering lines based on the
provisions in American Petroleum Institute Recommended Practice 80,
``Guidelines for the Definition of Onshore Gas Gathering Lines,'' (API
RP 80), a consensus industry standard incorporated by reference.
Additional regulatory requirements for determining the beginning and
endpoints of gathering, modifying the application of API RP 80, were
also imposed to improve clarity and consistency in their application.
    In practice, however, the use of API RP 80, even as modified by the
additional regulations, is difficult for operators to apply
consistently to complex gathering system configurations. Enforcement of
the current requirements has been hampered by the conflicting and
ambiguous language of API RP 80, a complex standard that can produce
multiple classifications for the same pipeline system, which can lead
to the potential misapplication of the incidental gathering line
designation under that standard. In addition, recent developments in
the field of gas exploration and production, such as shale gas,
indicate that the existing framework for regulating gas gathering lines
may need to be expanded. Gathering lines are being constructed to
transport ``shale'' gas that range from 4 to 36 inches in diameter with
MAOPs up to 1480 psig, far exceeding the historical operating
parameters (pressure and diameter). The risks considered during the
development of the 2006 rule did not foresee gathering lines of these
diameters and pressures.
    Currently, according to 2011 annual reports submitted by pipeline
operators, PHMSA only regulates about 8845 miles of Type A gathering
lines, 5178 miles of Type B gathering lines, and about 6258 miles of
offshore gathering lines, for a total of approximately 20,281 miles of
regulated gas gathering pipelines. Gas gathering lines are currently
not regulated if they are in Class 1 locations. Current estimates also
indicate that there are approximately 132,500 miles of Type A gas
gathering lines located in Class 1 areas (of which approximately 61,000
miles are estimated to be 8-inch diameter or greater), and
approximately 106,000 miles of Type B gas gathering lines located in
Class 1 areas. Also, there are approximately 2,300 miles of Type B gas
gathering lines located in Class 2 areas, some of which may not be
regulated in accordance with Sec.  192.8(b)(2).
    The ANPRM then listed questions for consideration and comment. The
following are general comments received related to this topic as well
as comments related to the specific questions:
General Comments for Topic O
    1. Gas Processors Association (GPA) recommended PHMSA complete the
study required by Section 21 of the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 before proposing any
substantive regulations regarding gathering lines. The Association sees
this as an essential pre-requisite and indicated it would establish a
working group to work with PHMSA on the study. Following the study, GPA
would then have PHMSA begin any rulemaking process with another ANPRM,
focused on the issues to be addressed in changing regulation of
gathering lines. Independent Petroleum Association of America, American
Petroleum Institute, Oklahoma Independent Petroleum Association, and
Chevron agreed any change to gathering line regulations before the
required report to Congress would be inconsistent with the Act.
    2. Independent Petroleum Association of America, American Petroleum
Institute, Oklahoma Independent Petroleum Association, and Chevron
argued no change in the gathering line regulatory regime is justified.
IPAA and API argued gathering lines can be regulated based only on
actual, vs.

speculative, risk, and that any change without such demonstrated risk
would be arbitrary, capricious, and contrary to law.
    3. Atmos would require new gathering lines operating above 20
percent SMYS to meet requirements in Sec.  192.9(c), and those below 20
percent SMYS Sec.  192.9(d). These paragraphs are, respectively,
requirements applicable to Type A and Type B gathering lines. The
``type'' of a gathering line is established in accordance with
requirements in Sec.  192.8, and is based on the pipe material and MAOP
of the line. Atmos argued, however, that class location changes over
time and determining applicable requirements for new gathering lines
based on stress levels would provide for public safety without the
problems or confusion that could result from subsequent class location
changes.
    4. Texas Pipeline Association and Texas Oil & Gas Association
suggested PHMSA treat gathering lines under a separate docket and
collect data under the current regulatory regime before making any
changes. The associations suggested a delay in rulemaking of 3 to 5
years to accumulate data from recently-promulgated changes in reporting
requirements. The associations argued changes made without gathering
and reviewing that data could be found unnecessary and would divert
resources from higher risk needs. Atmos agreed any rulemaking
concerning gathering lines should be conducted under a separate docket
due to the complexity of the issues involved.
    5. Dominion East Ohio Gas argued it is too soon for wholesale
changes to the new federal regulations applicable to gas gathering
lines. The company suggested one proposed change would be to consider
``Incidental Gathering'' as defined in API RP 80.
    6. NAPSR and Commissioners of Wyoming County Pennsylvania suggested
PHMSA assert regulatory authority beginning at the wellhead or first
metering point. They argued the regulatory gap that results from
excluding production facilities from regulation produces risks,
especially in areas where high-pressure wells are being drilled in
urban areas. NAPSR further stated that PHMSA should consider short
sections of pipeline downstream of processing, compression, and similar
equipment to be a continuation of gathering. The functional name of a
segment of pipeline is not important, i.e., production, gathering,
transmission. All pipelines should be treated the same in terms of
safety from the well head to the city gate.
    7. Commissioners of Wyoming County Pennsylvania recommended PHMSA
regulate gathering lines in Class 1 areas. The Commissioners noted many
new gathering lines, some operating at high pressures, are being
constructed in Class 1 areas of the Marcellus Shale Region, and
regulation of these lines is necessary to ensure public safety. The
Commissioners noted Pennsylvania law gives the state's public utilities
commission authority to regulate pipelines but requires that they be no
more stringent than federal regulations.
    8. The League of Women Voters of Pennsylvania would regulate
gathering lines in the same manner as transmission and would further
require that gas in pipelines of both types be odorized.
    9. Pipeline Safety Trust would have PHMSA assure gathering lines
are displayed on the National Pipeline Mapping System.
Response to General Comments for Topic O
    PHMSA appreciates the information provided by the commenters. The
commenters are correct that the Act required several actions related to
gas gathering lines including a requirement that a study to be
conducted prior to issuing new rules. We would note, however, that
PHMSA is only proceeding with the issuance of an NPRM proposing
expanded requirements and needed clarity with regard to issues that had
been identified prior to enactment of the Act. The study has been
completed and submitted to Congress and placed on the docket. PHMSA
invites public comment on the study, which will inform the final rule.
In addition, recent developments in the field of gas exploration and
production, such as shale gas, indicate that the existing framework for
regulating gas gathering lines may need to be expanded. Gathering lines
are being constructed to transport ``shale'' gas that range from 4 to
36 inches in diameter with MAOPs up to 1,480 psig, far exceeding the
historical operating parameters of such lines.
    Currently, according to 2011 annual reports submitted by pipeline
operators, PHMSA only regulates about 8845 miles of Type A gathering
lines, 5,178 miles of Type B gathering lines, and about 6,258 miles of
offshore gathering lines, for a total of approximately 20,281 miles of
regulated gas gathering pipelines. Gas gathering lines are currently
not regulated if they are in Class 1 locations. Current estimates also
indicate that there are approximately 132,500 miles of Type A gas
gathering lines located in Class 1 areas, and approximately 106,000
miles of Type B gas gathering lines located in Class 1 areas. Also,
there are approximately 2,300 miles of Type B gas gathering lines
located in Class 2 areas, some of which may not be regulated in
accordance with Sec.  192.8(b)(2).
    Moreover, enforcement of the current requirements has been hampered
by the conflicting and ambiguous language of API RP 80, a complex
standard that can produce multiple classifications for the same
pipeline system because numerous factors are involved, including the
locations of treatment facilities, processing plants, and compressors,
the relative spacing of production fields, and the commingling of gas.
This can lead to the potential misapplication of the incidental
gathering line designation under that standard.
    In this NPRM, PHMSA proposes to extend existing requirements for
Type B gathering lines to Type A gathering lines in Class 1 locations,
if the nominal diameter is 8'' or greater.
    Comments submitted for questions in Topic O.
    O.1. Should PHMSA amend 49 CFR part 191 to require the submission
of annual, incident, and safety-related conditions reports by the
operators of all gathering lines?
    1. AGA, GPTC, Texas Pipeline Association, Texas Oil & Gas
Association, and several pipeline operators opposed requiring annual
reports for unregulated gas gathering pipelines, arguing such a
requirement would be unduly burdensome with no safety benefit. These
commenters agreed incident reports for unregulated gathering lines
could be useful as a means to determine the effectiveness of safety
practices on these pipelines.
    2. Gas Producers Association opposed expanding reporting
requirements to Class 1 gathering pipelines. The Association noted
gathering lines in other class locations are currently subject to
reporting requirements and suggested there were other means for PHMSA
to collect data on Class 1 lines without requiring burdensome
reporting. In the specific case of safety-related condition reports,
the Association argued requiring reporting is clearly premature,
because the purpose of these reports is to highlight problems in which
PHMSA may elect to become involved and PHMSA presently does not
regulate these pipelines.
    3. Texas Pipeline Association and Texas Oil & Gas Association would
support requiring incidents to be reported for all gathering pipelines
as a first step in collecting data to determine whether other changes
are needed.

    4. Atmos would support limited reporting for Class 1 gathering
lines, to include incidents and total mileage.
    5. NAPSR, Alaska Department of Natural Resources, Pipeline Safety
Trust, and Commissioners of Wyoming County Pennsylvania would require
operators of Class 1 gathering pipelines to submit reports, because
these pipelines can affect public safety and should be held
accountable.
Response to Question O.1 Comments
    PHMSA appreciates the information provided by the commenters. The
comments provide varied support for requiring submission of annual,
incident, and safety-related conditions reports by the operators of all
gathering lines. PHMSA believes these reports would provide valuable
information, combined with the results of the congressionally required
study, to support evaluation of the effectiveness of safety practices
on these pipelines and determination of any needed additional
requirements beyond those proposed in this NPRM. Accordingly, PHMSA
proposes to delete the exemption for reporting requirements for
operators of unregulated onshore gas gathering lines.
    O.2. Should PHMSA amend 49 CFR part 192 to include a new definition
for the term ``gathering line''?
    1. AGA and several pipeline operators opposed a change to the
definition of gathering lines, noting API RP-80, with restrictions as
specified in current regulations, is a good working definition.
    2. Independent Petroleum Association of America, American Petroleum
Institute, Oklahoma Independent Petroleum Association, Atmos, and
Chevron argued that API RP 80, as currently specified, is the
appropriate means for defining gathering lines. They argued it is based
on a pipeline's function rather than its location and changes could
infringe on production facilities, regulation of which is precluded by
statute.
    3. Gas Processors Association opposed changing the definition of
gathering line or extending regulation to lines in Class 1 areas. The
Association noted excluding Class 1 lines from regulation is risk-based
and expressed its interest in continuing the risk-based approach to
regulation represented by the 2006 rule.
    4. NAPSR, GPTC, Accufacts, Thomas Lael, and Nicor supported
simplifying the definition of gathering lines. These commenters noted
that API RP-80 is confusing. One commenter referred to its application
as a ``nightmare.'' The definition in Texas regulations was suggested
as one possible model.
    5. Oklahoma Independent Petroleum Association strongly opposed
changes to the definitions of gathering line or production facilities.
    6. Texas Pipeline Association and Texas Oil & Gas Association would
not change the definition of gathering lines at this time, arguing data
gathering, a necessary first step, is not yet complete.
    7. The State of Washington Citizens Advisory Committee and a
private citizen urged changes to the definitions of gathering,
transmission, and distribution pipelines, arguing that the current
definitions are confusing and employ circular logic.
    8. Pipeline Safety Trust would revise the definition of gathering
in a manner that does not allow operators to choose whether their
pipeline is gathering or not on the basis of where they decide to
install equipment. PST noted there is significant overlap among
pipeline types in size, operating pressure, and attendant risks.
    9. Alaska Department of Natural Resources and Commissioners of
Wyoming County Pennsylvania urged a revision to the definition of
gathering lines, in light of shale gas development which, the
commenters contended, produces risks approximately equivalent to those
from transmission pipelines.
Response to Question O.2 Comments
    PHMSA appreciates the information provided by the commenters.
Industry commenters opposed a change to the definition of gathering
lines, whereas NAPSR and other commenters supported revision of the
definition of gathering lines and classified API RP-80 as confusing. As
discussed above, PHMSA believes revision of the definition of gathering
lines is needed and also proposes a new definition for onshore
production facility/operation. In addition, see response to question
O.3 comments.
    O.3. Are there any difficulties in applying the definitions
contained in RP 80? If so, please explain.
    1. Independent Petroleum Association of America, American Petroleum
Institute, Oklahoma Independent Petroleum Association, and Chevron were
emphatic in declaring there are no difficulties in applying API RP-80.
IPAA and API noted that significant difficulties among gathering lines
made RP-80 difficult to develop.
    2. AGA and a number of pipeline operators reported RP-80 is clear
and there are no difficulties with its application.
    3. Gas Processors Association would retain the RP-80 definition, at
least until the study required by the Act is completed. GPA
acknowledged that application of RP-80 has been difficult, but stated
that it has been difficult to craft a simpler definition.
    4. Texas Pipeline Association and Texas Oil & Gas Association
reported application of RP-80 has been challenging. The associations
opined this has resulted from complexities in gathering pipeline
systems and confusion caused by PHMSA guidance and interpretations.
    5. Accufacts, NAPSR, GPTC, and Nicor commented RP-80 is too
complex, not understandable to the public, and subject to misuse by
operators.
Response to Question O.3 Comments
    PHMSA appreciates the information provided by the commenters.
Industry commenters stated there are no difficulties in applying the
definitions contained in API RP 80, whereas Accufacts, NAPSR and other
commenters contend that API RP 80 is too complex, not understandable,
and subject to misuse. PHMSA enforcement of the current requirements
has been hampered by the conflicting and ambiguous language of API RP
80, which is complex and can produce multiple classifications for the
same pipeline system. In the 2006 rulemaking which incorporated by
reference the API RP 80, PHMSA expressed reservations concerning the
ability to effectively and consistently apply the document as written,
echoing NAPSR's comments at the time. Additionally, in 2006, PHMSA
imposed limiting regulatory language in part 192 in an attempt to
curtail the potential for misapplication of the language contained in
RP-80. These limitations and their intended application were discussed
in great detail in the Supplemental Notice of Proposed Rulemaking
[Docket No. RSPA-1998-4868; Notice 5]. Because of the ambiguous
language and terminology in the RP-80, e.g. separators are defined for
both production and gathering almost verbatim, experience has shown
that facilities are being classified as production much further
downstream than was ever intended. The application of ``incidental
gathering'' as used in API RP-80 has not been applied as intended in
some cases. Several recent interpretations letters have been issued by
PHMSA on this topic including an expressed intent to clarify the issue
in future rulemaking. Therefore, PHMSA believes revision of the
definition of gathering lines is needed and proposes

deleting the use of API RP 80 as the basis for determining regulated
gathering lines and would establish the new definition for onshore
production facility/operation and a revised definition for gathering
line as the basis for determining the beginning and endpoints of each
gathering line.
    O.4. Should PHMSA consider establishing a new, risk-based regime of
safety requirements for large-diameter, high-pressure gas gathering
lines in rural locations? If so, what requirements should be imposed?
    1. Commissioners of Wyoming County Pennsylvania and 24 private
citizens encouraged PHMSA to regulate gathering lines in Class 1
locations. The commenters noted many such pipelines will exist in shale
gas areas, many of them large-diameter and operating at high pressures,
and contended these pipelines currently are being ignored by federal
and state regulators. They noted the pipeline that ruptured causing the
San Bruno accident was operated at a pressure considerably lower than
some gathering lines in shale gas areas.
    2. AGA, GPTC, and a number of pipeline operators argued no new
requirements are needed and the effectiveness of the 2006 changes to
regulation needs to be reviewed first, in accordance with the Act.
    3. Gas Processors Association, Texas Pipeline Association, and
Texas Oil & Gas Association contended PHMSA must gather additional data
on Class 1 gathering lines before deciding whether to regulate them,
arguing that only a detailed study can determine whether new
regulations are appropriate.
    4. Oklahoma Independent Petroleum Association cautioned any
regulatory change needs to be supported by science and a comprehensive
cost-benefit analysis.
    5. Independent Petroleum Association of America, American Petroleum
Institute, Oklahoma Independent Petroleum Association, and Chevron
argued any change in the regulatory regime for gathering lines is
unjustified. The commenters contended such lines only operate at high
pressures when new, that pressure decreases as wells deplete, and that
the record shows these lines are safe.
    6. A private citizen who operates an outdoor gear supply business
in a shale gas region argued reduced use of recreational areas, caused
by concerns over nearby pipelines, will adversely impact his and
similar businesses.
    7. Alaska Department of Natural Resources would establish risk-
based safety requirements for gathering pipelines.
    8. NAPSR would establish new, prescriptive requirements for large-
diameter, high-pressure gathering lines.
    9. Pipeline Safety Trust argued the composition of gas carried in
many gathering lines leads to increased risk of corrosion and
additional corrosion and testing requirements should thus be
considered.
    10. A private citizen, arguing for regulation of Class 1 gathering
lines, noted experience has shown Class 1 locations change to Class 2
or 3 locations while the pipeline remains unchanged and, the commenter
contended, unsafe.
    11. Pipeline Safety Trust, Accufacts, and NAPSR would regulate
gathering lines the same as transmission pipelines. PST would include
integrity management requirements for lines operating at greater than
20 percent SMYS. NAPSR would impose IM if greater than 30 percent SMYS.
    12. ITT Exelis Geospatial Systems contended that safety criteria
applicable to a pipeline should be based on the specifications of the
line.
Response to Question O.4 Comments
    PHMSA appreciates the information provided by the commenters. The
comments provide varied opinions for establishing new, risk-based
safety requirements for gas gathering lines in rural locations. Several
comments recommended PHMSA gather additional data on gathering lines
before deciding to issue revised regulations. PHMSA believes rulemaking
should proceed now to address the identified issues with regulation of
gathering lines. Therefore, PHMSA proposes to extend existing
requirements for Type B gathering lines to Type A gathering lines in
Class 1 locations, if the nominal diameter is 8'' or greater. Integrity
management requirements would not be applied to gathering lines at this
time.
    O.5. Should PHMSA consider short sections of pipeline downstream of
processing, compression, and similar equipment to be a continuation of
gathering? If so, what are the appropriate risk factors that should be
considered in defining the scope of that limitation (e.g., doesn't
leave the operator's property, not longer than 1000 feet, crosses no
public rights of way)?
    1. The AGA, the GPTC, and a number of pipeline operators suggested
that the piping mentioned in O.5 be considered as gathering. The
commenters contended that this is clearly ``incidental gathering'' in
API RP-80, particularly if below 20 percent SMYS, and that some
agencies are presently treating this pipeline inappropriately as
transmission pipeline.
    2. Oleksa and Associates contended that the types of pipeline
described in the question are ``incidental gathering.'' Oleksa argued
that the length of these pipeline sections should not be the
determining factor in their definition but, rather, risk elements and
public safety impact should be afforded more importance.
    3. The Gas Processors Association, the Texas Pipeline Association,
and the Texas Oil & Gas Association would continue to treat these types
of pipelines as gathering. They argued that this reflects the practical
realities in the field regarding the ability to locate gathering-
related equipment. GPA urged PHMSA to retain the concept of incidental
gathering in any future change to the regulations, arguing this would
continue a consistent regulatory approach to gathering pipelines.
    4. The Independent Petroleum Association of America, the American
Petroleum Institute, the Oklahoma Independent Petroleum Association,
and Chevron contended that the safety record in the Barnett Shale area
demonstrates further regulation of downstream pipelines and compression
is not needed.
    5. Commissioners of Wyoming County Pennsylvania would treat
gathering lines as transmission lines, arguing that this would preclude
the need to answer any of these questions.
    6. The Delaware Solid Waste Authority (DSWA) argued for the
continued treatment of the listed pipeline sections as part of
gathering for landfill gas operations. DSWA noted that landfills may
use intermediate compression to improve collection efficiency and may
have pipe at pressure leading to flares etc.
    7. Waste Management contended that piping that is an active part of
a landfill gas collection and control system should be exempt from
regulation as this piping is generally on landfill property and poses
no risk to the public.
    8. The National Solid Waste Management Association and Waste
Management supported PHMSA's interpretation that pipelines operating at
vacuum, such as landfill systems up to the compressor/blower should be
unregulated.
Response to Question O.5 Comments
    PHMSA appreciates the information provided by the commenters. See
PHMSA's response to Question O.3, above.
    O.6. Should PHMSA consider adopting specific requirements for
pipelines associated with landfill gas

systems? If so, what regulations should be adopted and why? Should
PHMSA consider adding regulations to address the risks associated with
landfill gas that contains higher concentrations of hydrogen sulfide
and/or carbon dioxide?
    1. The AGA, the GPTC, and a number of pipeline operators contended
that RP-80 makes clear that these pipelines are production piping and
therefore regulation is prohibited. In addition, they argued that risk
doesn't justify regulating these lines; the situation is similar to
production and is already managed well. They also noted that landfill
systems are generally constructed with non-corrosive materials. The
commenters agreed that piping from landfills to transmission or
distribution pipelines is gathering and should be regulated.
    2. Oleksa and Associates contended that landfill pipelines are
distribution pipelines, if they carry gas to end use customers.
    3. The APGA argued that new requirements are appropriate, as
landfill gas is different from natural gas. The APGA contended that
application of current regulations often produces absurd results. APGA
would add new requirements applicable to systems with high
concentrations of hydrogen sulfide and allow systems with low
concentrations to use current requirements.
    4. The Delaware Solid Waste Authority argued that no new
requirements are needed, because these systems operate at low pressures
and existing requirements are sufficient.
    5. NAPSR encouraged that PHMSA establish jurisdiction over and
requirements for landfill gas systems, arguing that many operate as
distribution pipelines. NAPSR also recommended that PHMSA develop
requirements for odorizing landfill gas, since normal methods cannot be
used.
    6. The National Solid Waste Management Association and Waste
Management argued that landfill gas lines under the control of a
landfill operator or gas developer should remain unregulated because
they pose minimal risk. They also contended that lines delivering
landfill gas to distant users should also remain unregulated because
they are mostly buried, are generally constructed of plastic pipe, and
pose low risk due to low pressure, their dedicated nature, and lack of
interconnects.
    7. The National Solid Waste Management Association (NSWMA) noted
that these pipelines are already regulated by the EPA and the states
and argued that additional regulation would confer limited additional
benefits. NSWMA argued that no requirements are needed to address
internal corrosion, because these pipeline systems are generally
constructed of plastic pipe and corrosive gas constituents are limited
to prevent destruction of gas processing equipment. NSWMA suggested
that PHMSA work with the EPA to obtain data on the landfill experience
needed to support any future decision to regulate in this area.
    8. Oleksa and Associates and the Delaware Solid Waste Authority
would have PHMSA modify the regulations to clarify that pipe downstream
of intermediate compression is unregulated, even if at pressure. They
argued that the EPA has regulated such pipelines successfully and there
is no safety case for applying part 192. DSWA further notes that most
landfill pipeline is constructed of plastic pipe and not subject to
internal corrosion.
    9. Oleksa and Associates, the GPTC, Nicor, Waste Management, and
the Delaware Solid Waste Authority would exempt landfill gas systems
from requirements for odorization and odor sampling. They argued that
there is a strong odor inherent to landfill gas, the sampling of which
is not practical.
Response to Question O.6 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
is not proposing rulemaking to address landfill gas systems at this
time, but would note that a pipeline that transports landfill gas away
from the landfill facility to another destination is transporting gas.
PHMSA will consider comments on this aspect of Topic O in the future.
    O.7. Internal corrosion is an elevated threat to gathering systems
due to the composition of the gas transported. Should PHMSA enhance its
requirements for internal corrosion control for gathering pipelines?
Should this include required cleaning on a periodic basis?
    1. AGA, GPTC, and a number of pipeline operators commented that new
requirements are not needed. They argued existing part 192 requirements
are adequate for internal corrosion protection and unregulated
gathering lines are rural and pose little risk.
    2. AGA and a number of pipeline operators opposed a requirement for
periodic cleaning of gathering lines. They noted existing lines are not
configured to accommodate cleaning pigs and retrofitting them would be
a major cost with no safety benefit.
    3. Gas Producers Association noted internal corrosion is only one
of many threats, existing regulations are adequate, and thus no new
requirements are needed.
    4. Texas Pipeline Association and Texas Oil & Gas Association
opposed establishing internal corrosion requirements for gathering
pipelines. The associations noted risk from IC is not prevalent for
many gathering pipelines and suggested the need to collect data (e.g.,
incidents) to determine whether new requirements are needed.
    5. Accufacts would require, as a minimum, use of cleaning pigs and
analysis of removed materials.
    6. NAPSR, Alaska Department of Natural Resources, and Commissioners
of Wyoming County Pennsylvania would enhance internal corrosion
requirements and require periodic cleaning.
Response to Question O.7 Comments
    PHMSA appreciates the information provided by the commenters. The
majority of comments do not support enhancement of requirements for
internal corrosion control for gathering pipelines. PHMSA is not
proposing rulemaking specifically to address the need for additional
internal corrosion requirements for gathering lines at this time.
However, the proposed requirements in subpart I applicable to
transmission lines; except the requirements in Sec. Sec.  192.461(f),
192.465(f), 192.473(c) and 192.478, would be applicable to regulated
Type A onshore gathering lines.
    O.8. Should PHMSA apply its Gas Integrity Management Requirements
to onshore gas gathering lines? If so, to what extent should those
regulations be applied and why?
    1. The AGA and several pipeline operators suggested that PHMSA
consider applying some IM requirements to Type A gathering lines, since
these lines represent conditions and risks similar to transmission
pipelines. They consider IM inappropriate for Type B gathering lines,
since these lines pose low risk and operate at hoop stresses similar to
distribution pipelines.
    2. The Gas Producers Association, the Texas Pipeline Association,
the Texas Oil & Gas Association, and Atmos argued that it would be
inappropriate to apply integrity management requirements to gathering
pipelines. They noted that IM is a risk-based approach and that there
is no evidence that gathering pipelines pose a risk that justifies
application of IM.
    3. The GPTC and Nicor opined that extending some aspects of gas
transmission IM to non-rural, metallic

Type A gathering lines could provide enhanced protection to the public,
since the operation and risk of these pipelines is similar to
transmission pipelines. They cautioned, however, that the costs to
impose IM on gathering pipelines would be significant. They considered
IM inappropriate for Type B gathering lines since these lines are, by
definition, of lower pressure and lower risk.
    4. The Commissioners of Wyoming County Pennsylvania would apply IM
to all onshore gathering pipelines. They would also apply requirements
applicable to Class 2 transmission pipelines to Class 1 gathering
pipelines, arguing that Class 1 areas will grow and class location will
change.
    5. Accufacts and the Alaska Department of Natural Resources would
apply IM to gathering lines. Accufacts suggested an initial focus on
large-diameter, high-pressure lines, since these lines are subject to
failure by rupture.
Response to Question O.8 Comments
    PHMSA appreciates the information provided by the commenters. PHMSA
does not propose rulemaking to apply integrity management requirements
to gathering lines at this time.
    O.9. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
     The potential costs of modifying the existing regulatory
requirements.
     The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
     The potential impacts on small businesses of modifying the
existing regulatory requirements.
     The potential environmental impacts of modifying the
existing regulatory requirements.
    No comments were received in response to this question.

IV. Other Proposals

    Inspection of Pipelines Following Extreme Weather Events.
    Pipeline regulation prescribes requirements for the surveillance
and periodic patrolling of the pipeline to observe surface conditions
on and adjacent to the transmission line right-of-way for indications
of leaks, construction activity, and other factors affecting safety and
operation, including unusual operating and maintenance conditions. The
probable cause of the 2011 hazardous liquid pipeline accident resulting
in a crude oil spill into the Yellowstone River near Laurel, Montana,
is scouring at a river crossing due to flooding. This is a recent
example of extreme weather that resulted in a pipeline incident. PHMSA
has determined that additional regulations are needed to require, and
establish standards for, the inspection of the pipeline and right-of-
way for ``other factors affecting safety and operation'' following an
extreme weather event such as a hurricane or flood, landslide, an
earthquake, a natural disaster, or other similar event. The proposed
rule would add a new paragraph (c) to section 192.613 to require such
inspections, specify the timeframe in which such inspections should
commence, and specify the appropriate remedial actions that must be
taken to ensure safe pipeline operations. The new paragraph (c) would
apply to onshore pipelines and their rights-of-way.
    Notification for 7-Year Reassessment Interval Extension.
    Section 5 of the Act identifies a technical correction amending
Section 60109(c)(3)(B) of Title 49 of the United States Code to allow
the Secretary of Transportation to extend the 7-year reassessment
interval for an additional 6 months if the operator submits written
notice to the Secretary justifying the need for the extension. PHMSA
proposes to codify this statutory requirement.
    Reporting Exceedances of Maximum Allowable Operating Pressure.
    Section 23 of the Act requires operators to report each exceedance
of the maximum allowable operating pressure (MAOP) that exceeds the
margin (build-up) allowed for operation of pressure-limiting or control
devices. PHMSA proposes to codify this statutory requirement.
    Consideration of Seismicity.
    Section 29 of the Act states that in identifying and evaluating all
potential threats to each pipeline segment, an operator of a pipeline
facility must consider the seismicity of the area. PHMSA proposes to
codify this statutory requirement to explicitly reference seismicity
for data gathering and integration, threat identification, and
implementation of preventive and mitigative measures.
    Safety Features for In-line Inspection (ILI), Scraper, and Sphere
Facilities.
    PHMSA is proposing to add explicit requirements for safety features
on launchers and receivers associated with ILI, scraper and sphere
facilities.
    Consensus Standards for Pipeline Assessments.
    PHMSA is proposing to incorporate by reference consensus standards
for assessing the physical condition of in-service pipelines using in-
line inspection, internal corrosion direct assessment, and stress
corrosion cracking direct assessment.

V. Section-by-Section Analysis

    Sec.  191.1 Scope.
    Section 191.1 prescribes requirements for the reporting of
incidents, safety-related conditions, and annual pipeline summary data
by operators of gas pipeline facilities. Currently, onshore gas
gathering pipelines are exempt from reporting, as specified in
paragraph (b)(4) of this section. In March 2012, the Government
Accountability Office (GAO) issued a report (GAO-12-388) that contained
a recommendation for DOT to collect data on federally unregulated
hazardous liquid and gas gathering pipelines. PHMSA has determined that
the statute requires the collection of additional information about
gathering lines and that these reports and the congressionally required
study support evaluation of the effectiveness of safety practices on
these pipelines. Furthermore, PHMSA has inquired into whether any
additional requirements are needed beyond those proposed in this NPRM.
Accordingly, the proposed rule would repeal the exemption for reporting
requirements for operators of unregulated onshore gas gathering lines
by deleting Sec.  191.1(b)(4), adding a new Sec.  191.1(c), and making
other conforming editorial amendments. In addition, Section 23 of the
Act requires PHMSA to promulgate rules that require operators to report
each exceedance of the maximum allowable operating pressure (MAOP) that
exceeds the margin (build-up) allowed for operation of pressure-
limiting or control devices. The proposed rule would amend 191.1 to
include MAOP exceedances within the scope of part 191.
    Sec.  191.23 Reporting safety-related conditions.
    Section 23 of the Act requires operators to report each exceedance
of the maximum allowable operating pressure (MAOP) that exceeds the
margin (build-up) allowed for operation of pressure-limiting or control
devices. On December 21, 2012, PHMSA published advisory bulletin ADB-
2012-11, which advised operators of their responsibility under Section
23 of the Act to report such exceedances. PHMSA proposes to revise
Sec.  191.23 to codify this requirement.
    Sec.  191.25 Filing safety-related condition reports.
    Section 23 of the Act requires operators to report each exceedance
of the maximum allowable operating pressure (MAOP) that exceeds the

margin (build-up) allowed for operation of pressure-limiting or control
devices. As described above, PHMSA proposes to revise Sec.  191.23 to
codify this requirement. Section 191.25 would also be revised to
provide consistent procedure, format, and structure for filing of such
reports by all operators.
    Sec.  192.3 Definitions.
    Section 192.3 provides definitions for various terms used
throughout part 192. In support of other regulations proposed in this
NPRM, PHMSA is proposing to amend the definitions of ``Electrical
survey,'' ``(Onshore) gathering line,'' and ``Transmission line,'' and
add new definitions for ``Close interval survey,'' ``Distribution
center, '' ``Dry gas or dry natural gas,'' ``Gas processing plant,''
``Gas treatment facility,'' ``Hard spot,'' ``In-line inspection
(ILI),'' ``In-line inspection tool or instrumented internal inspection
device,'' ``Legacy construction technique,'' ``Legacy pipe,''
``Moderate consequence area,'' ``Modern pipe,'' ``Occupied site,''
``Onshore production facility or onshore production operation,''
``Significant Seam Cracking,'' ``Significant Stress Corrosion
Cracking,'' and ``Wrinkle bend.'' These changes will define these terms
as used in the proposed changes to part 192. Many of the terms (such as
in-line inspection, dry gas, hard spot, etc.) clarify technical
definitions of terms used in part 192 or proposed in this rulemaking.
    The revised definition for ``(Onshore) gathering line,'' and the
new definitions for ``Gas processing plant,'' ``Gas treatment
facility,'' and ``Onshore production facility or onshore production
operation,'' are necessary because of ambiguous language and
terminology in the current definition of regulated gas gathering lines,
which invoke by reference API RP-80. The application of ``incidental
gathering'' as used in API RP-80 has not been applied as intended in
some cases. Several recent interpretation letters have been issued by
PHMSA on this topic including an expressed intent to clarify the issue
in future rulemaking. Therefore, PHMSA believes revision of the
definition of gathering lines is needed and proposes repealing the use
of API RP 80 as the basis for determining regulated gathering lines and
would establish the new definition for ``onshore production facility/
operation, gas treatment facility, and gas processing plant,'' and a
revised definition for ``(onshore) gathering line'' as the basis for
determining the beginning and endpoints of each gathering line.
    The revised definition for ``Electrical survey'' aligns with the
amended definition recommended in a petition dated March 26, 2012, from
the Gas Piping Technology Committee (GPTC).
    With regard to the new terms ``moderate consequence area'' or MCA,
and ``occupied site,'' the definitions are based on the same
methodology as ``high consequence area'' and ``identified site'' as
defined in Sec.  192.903. Moderate consequence areas will be used to
define the subset of non-HCA locations where integrity assessments are
required (Sec.  192.710), where material documentation verification is
required (Sec.  192.607), and where MAOP verification is required
(Sec. Sec.  192.619(e) and 192.624). The criteria for determining MCA
locations would use the same process and same definitions that are
currently used to identify HCAs, except that the threshold for
buildings intended for human occupancy and the threshold for persons
that occupy other defined sites located within the potential impact
radius would both be lowered from 20 to 5. This approach is proposed as
a means to minimize the effort needed on the part of operators to
identify the MCAs, since transmission operators must have already
performed the analysis in order to have identified the HCAs or to
verify that they have no HCAs. In response to NTSB recommendation P-14-
01, which was issued as a result of the Sissonville, West Virginia
incident, the MCA definition would also include locations where
interstate highways, freeways, and expressways, and other principal 4-
lane arterial roadways are located within the potential impact radius.
    With regard to the new terms ``legacy construction technique'' and
``legacy pipe,'' the definitions are used in proposed and Sec.  192.624
to identify pipe to which the proposed material verification and MAOP
verification requirements would apply. The definitions are based on
historical technical issues associated with past pipeline failures.
    Sec.  192.5 Class locations.
    Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that an important aspect of compliance with this
requirement is to assure that pipeline class location records are
complete and accurate. The proposed rule would add a new paragraph
Sec.  192.5(d) to require each operator of transmission pipelines to
make and retain for the life of the pipeline records documenting class
locations and demonstrating how an operator determined class locations
in accordance with this section.
    Sec.  192.7 What documents are incorporated by reference partly or
wholly in this part?
    Section 192.7 lists documents that are incorporated by reference in
part 192. PHMSA proposes conforming amendments to Sec.  192.7 in the
rule text to reflect other changes proposed in this NPRM.
    Sec.  192.8 How are onshore gathering lines and regulated onshore
gathering lines determined?
    Section 192.8 defines the upstream and downstream endpoints of gas
gathering pipelines. Recent developments in the field of gas
exploration and production, such as shale gas, indicate that the
existing framework for regulating gas gathering lines may no longer be
appropriate. Gathering lines are being constructed to transport
``shale'' gas that range from 4 to 36 inches in diameter with MAOPs of
up to 1480 psig, far exceeding the historical operating parameters of
such lines.
    Currently, according to the 2011 annual reports submitted by
pipeline operators, PHMSA only regulates about 8,845 miles of Type A
gathering lines, 5,178 miles of Type B gathering lines, and about 6,258
miles of offshore gathering lines, for a total of approximately 20,281
miles of regulated gas gathering pipelines. Gas gathering lines are
currently not regulated if they are in Class 1 locations. Current
estimates also indicate that there are approximately 132,500 miles of
Type A gas gathering lines located in Class 1 areas (of which
approximately 61,000 miles are estimated to be 8-inch diameter or
greater), and approximately 106,000 miles of Type B gas gathering lines
located in Class 1 areas. Also, there are approximately 2,300 miles of
Type B gas gathering lines located in Class 2 areas, some of which may
not be regulated in accordance with Sec.  192.8(b)(2).
    Moreover, enforcement of the current requirements has been hampered
by the conflicting and ambiguous language of API RP 80, a complex
standard that can produce multiple classifications for the same
pipeline system. PHMSA has also identified a regulatory gap that
permits the potential misapplication of the incidental gathering line
designation under that standard. Consequently, to address these issues
and gaps, the proposed rule would repeal the use of API RP 80 as the
basis for determining regulated gathering lines and would establish a
new definition for onshore production facility/operation and a

revised definition for gathering line as the basis for determining the
beginning and endpoints of each gathering line. The definition of
onshore production facility/operation includes initial preparation of
gas for transportation at the production facility, including
separation, lifting, stabilizing, and dehydration. Pipelines commonly
referred to as ``farm taps'' serving residential/commercial customers
or industrial customers are not classified as gathering, but would
continue to be classified as transmission or distribution as defined in
Sec.  192.3.
    Sec.  192.9 What requirements apply to gathering lines?
    Section 192.9 identifies those portions of part 192 that apply to
regulated gas gathering lines. For the same reasons discussed under
Sec.  192.8, above, the proposed rule would expand and clarify the
requirements that apply to gathering lines. PHMSA proposes to extend
existing regulatory requirements for Type B gathering lines to Type A
gathering lines in Class 1 locations, if the nominal diameter of the
line is 8'' or greater.
    In addition, on August 20, 2014, the GAO released a report (GAO
Report 14-667) to address the increased risk posed by new gathering
pipeline construction in shale development areas. GAO recommended that
a rulemaking be pursued for gathering pipeline safety that addresses
the risks of larger-diameter, higher-pressure gathering pipelines,
including subjecting such pipelines to emergency response planning
requirements that currently do not apply. Currently, Type A gathering
lines are subject to the emergency planning requirements in Sec.
192.615 and only include gathering lines in Class 2, 3, and 4 locations
that have a Maximum Allowable Operating Pressure (MAOP) with a hoop
stress of 20% or more for metallic pipe and MAOP of more than 125 psig
for non-metallic pipe. Further, gathering lines that are located in
Class 1 areas (e.g., rural areas) are not considered Type A gathering
lines even if they meet the pressure criteria specified in the
preceding sentence. PHMSA is proposing to create sub-divisions of Type
A gathering lines (Type A, Area 1 and Type A, Area 2). The new
designation ``Type A, Area 1 gathering lines'' would apply to currently
regulated Type A gathering lines. The new designation ``Type A, Area 2
gathering lines'' would apply to gathering lines with a diameter of 8-
inch or greater that meet all of the qualifying parameters for
currently regulated Type A gathering, but are located in Class 1
locations. PHMSA proposes to address the GAO recommendation by
requiring the newly proposed Type A, Area 2 regulated onshore gathering
lines, which include lines in Class 1 locations with a nominal diameter
of 8-inch or greater, to develop procedures, training, notifications,
and carry out emergency plans as described in Sec.  192.615, in
addition to a limited set of other specific requirements, including
corrosion protection and damage prevention.
    Sec.  192.13 General.
    Section 192.13 prescribes general requirements for gas pipelines.
PHMSA has determined that safety and environmental protection would be
improved by generally requiring operators to evaluate and mitigate
risks during all phases of the useful life of a pipeline as an integral
part of managing pipeline design, construction, operation, maintenance
and integrity, including management of change. This proposed rule would
add a new paragraph (d) to establish a general clause requiring onshore
gas transmission pipeline operators to evaluate and mitigate risks to
the public and environment as part of managing pipeline design,
construction, operation, maintenance, and integrity, including
management of change. The new paragraph would also invoke the
requirements for management of change as outlined in ASME/ANSI B31.8S,
section 11, and explicitly articulate the requirements for a management
of change process that are applicable to onshore gas transmission
pipelines.
    Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that an important aspect of compliance with this
requirement is to assure that records that demonstrate compliance with
part 192 are complete and accurate. The proposed rule would add a new
paragraph (e) that clearly articulates the requirements for records
preparation and retention and requires that records be reliable,
traceable, verifiable, and complete. Further, the proposed Appendix A
would provide specific requirements for records retention for
transmission pipelines.
    In addition, conforming amendments to paragraphs (a) and (b) list
the effective date of the proposed requirements for newly regulated
onshore gathering lines.
    Sec.  192.67 Records: Materials.
    Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipeline material
records are complete and accurate. The proposed rule would add a new
Sec.  192.67 to require each operator of transmission pipelines to make
and retain for the life of the pipeline the original steel pipe
manufacturing records that document tests, inspections, and attributes
required by the manufacturing specification in effect at the time the
pipe was manufactured.
    Sec.  192.127 Records: Pipe design.
    Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipe design records
are complete and accurate. The proposed rule would add a new Sec.
192.127 to require each operator of transmission pipelines to make and
retain for the life of the pipeline records documenting pipe design to
withstand anticipated external pressures and determination of design
pressure for steel pipe.
    Sec.  192.150 Passage of internal inspection devices.
    The current pipeline safety regulations in 49 CFR 192.150 require
that pipelines be designed and constructed to accommodate in-line
inspection devices. Part 192 is silent on technical standards or
guidelines for implementing requirements to assure pipelines are
designed and constructed for ILI assessments. At the time these rules
were promulgated, there was no consensus industry standard that
addressed design and construction requirements for ILI. NACE Standard
Practice, NACE SP0102-2010, ``In-line Inspection of Pipelines,'' has
since been published and provides guidance in this area in Section 7.
The incorporation of this standard into Sec.  192.150 will promote a
higher level of safety by establishing consistent standards for the
design and construction of line pipe to accommodate ILI devices.
    Sec.  192.205 Records: Pipeline components.
    Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.