[Federal Register Volume 75, Number 227 (Friday, November 26, 2010)]
[Rules and Regulations]
[Pages 72878-72908]
[FR Doc No: 2010-29087]

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Part II

Department of Transportation

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 Pipeline and Hazardous Materials Safety Administration

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49 CFR Parts 191, 192, 193 et al.

 Pipeline Safety: Updates to Pipeline and Liquefied Natural Gas
Reporting Requirements; Final Rule

Federal Register / Vol. 75 , No. 227 / Friday, November 26, 2010 /
Rules and Regulations

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR 191, 192, 193 and 195

[Docket No. PHMSA-2008-0291; Amdt. Nos. 191-21; 192-115; 193-23; and
195-95]
RIN 2137-AE33

Pipeline Safety: Updates to Pipeline and Liquefied Natural Gas
Reporting Requirements

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

ACTION: Final rule.

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SUMMARY: This final rule revises the Pipeline Safety Regulations to
improve the reliability and utility of data collections from operators
of natural gas pipelines, hazardous liquid pipelines, and liquefied
natural gas (LNG) facilities. These revisions will enhance PHMSA's
ability to understand, measure, and assess the performance of
individual operators and industry as a whole; integrate pipeline safety
data to allow a more thorough, rigorous, and comprehensive
understanding and assessment of risk; and expand and simplify existing
electronic reporting by operators. These revisions will improve both
the data and the analyses PHMSA and others rely on to make critical,
safety-related decisions, and will facilitate both PHMSA's and states'
allocation of pipeline safety program inspection and other resources
based on a more accurate accounting of risk.

DATES: This final rule is effective January 1, 2011.

FOR FURTHER INFORMATION CONTACT: Roger Little by telephone at 202-366-
4569 or by electronic mail at<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

I. Background

    On July 2, 2009, (74 FR 31675) PHMSA published a Notice of Proposed
Rulemaking proposing to revise the Pipeline Safety Regulations (49 CFR
Parts 190-199) to improve the reliability and utility of data
collections from operators of natural gas pipelines, hazardous liquid
pipelines, and LNG facilities. Specifically, PHMSA proposed the
following amendments to the regulations:
    1. Modify 49 CFR 191.1 to reflect the changes made to the
definition of gas gathering lines in Part 192.
    2. Change the definition of an ``incident'' in 49 CFR 191.3 to
require an operator to report an explosion or fire not intentionally
set by the operator and to establish a volumetric basis for reporting
unexpected or unintentional gas loss.
    3. Require operators to report and file data electronically
whenever possible.
    4. Require operators of LNG facilities to submit incident and
annual reports.
    5. Create and require participation in a National Registry of
Pipeline and LNG Operators.
    6. Require operators to use a standard form in electronically
submitting Safety-Related Condition Reports and Offshore Pipeline
Condition Reports.
    7. Merge the natural gas transmission IM Semi-Annual Performance
Measures Report with the annual reports. Revise the leak cause
categories listed in the annual report to include those nine categories
listed in ASME B31.8S. Expand information on the natural gas
transmission annual report to add information for miles of gathering
lines by Type A and Type B gathering, class location information by
specified minimum yield strength (SMYS), volume of commodity
transported, and type of commodity transported.
    8. Modify hazardous liquid operator telephonic notification of
accidents to require operators to have and use a procedure to calculate
and report a reasonable initial estimate of released product and to
provide an additional telephonic report to the NRC if significant new
information becomes available during the emergency response phase.
    9. Require operators of hazardous liquid pipelines to submit
pipeline information by state on the annual report for hazardous liquid
pipelines.
    10. Remove obsolete provisions that would conflict with the
proposal to require electronic submission of all reports.
    11. Update Office of Management and Budget (OMB) control numbers
assigned to information collections.
    The statutory authority under 49 U.S.C. 60101 et seq. authorizes
this final rule; these Federal Pipeline Safety Laws grant broad
authority to PHMSA to regulate pipeline safety. The proposed data
collection and filing requirement revisions are wholly consistent with
Section 15 of the PIPES Act of 2006 (Pub. L. 109-468, December 26,
2006), which requires PHMSA to review and modify the incident reporting
criteria as appropriate to ensure that the data accurately reflects
trends over time.
    For natural gas pipeline operators, specific reporting requirements
in 49 CFR Part 191 are found at:
     Sec.  191.5 Telephonic notice of certain incidents.
     Sec.  191.7 Addresses for written reports.
     Sec.  191.9 Natural gas distribution incident report.
     Sec.  191.11 Natural gas distribution annual report.
     Sec.  191.15 Natural gas transmission and gathering
incident report.
     Sec.  191.17 Natural gas transmission and gathering annual
report.
     Sec.  191.23 Reporting safety-related conditions.
     Sec.  191.25 Filing safety-related condition reports.
     Sec.  191.27 Filing offshore pipeline condition reports.
    The requirement for reporting leaks and spills of LNG in accordance
with Part 191 is found at Sec.  193.2011. Part 191 has excluded LNG
from many of the reporting requirements.
    For hazardous liquid pipeline operators specific reporting
requirements in 49 CFR Part 195 are found at:
     Sec.  195.48 Scope.
     Sec.  195.49 Annual report.
     Sec.  195.50 Reporting accidents.
     Sec.  195.52 Telephonic notice of certain accidents.
     Sec.  195.54 Accident reports.
     Sec.  195.55 Reporting safety-related conditions.
     Sec.  195.56 Filing safety-related condition reports.
     Sec.  195.57 Filing offshore pipeline condition reports.
     Sec.  195.58 Address for written reports.
    As the Nation's repository for pipeline data, PHMSA's data is used
not only by PHMSA, but by state pipeline safety programs, congressional
committees, metropolitan planners, civic associations and other local
community groups, pipeline research organizations, industry safety
experts, industry watch groups, the media, the public, industry trade
association, industry consultants, and members of the pipeline and
energy industries. A significant amount of critical safety information
is cultivated from PHMSA's data through statistical analysis and
information retrieval. One of the agency's most valued assets is the
data it collects, maintains, and analyzes pertaining to the industry.
PHMSA is responsible for maintaining the most comprehensive collection
of accident/incident data for intrastate and interstate pipelines in
the country. PHMSA is subject to continual interest and scrutiny by
numerous and varied stakeholders for the reliability, utility, and
applicability of information and statistics pertaining to pipelines and
LNG facilities, including the collection, tracking, and retrieval of
historical data. PHMSA, therefore, must periodically

modify its information and data collections and associated processes to
address changes in industry business practices, changes in PHMSA's
regulations, and changes in PHMSA's own data analysis strategies and
objectives.
    This rule also responds to various Government Accountability Office
(GAO) and National Transportation Safety Board (NTSB) recommendations.
In GAO's report titled: ``Natural Gas Pipeline Safety: IM Benefits
Public Safety, but Consistency of Performance Measure Should Be
Improved,'' (GAO-06-946, September, 2006), GAO stated that the current
gas incident reporting requirements do not adjust for the changing cost
of gas released in incidents. GAO recommended that PHMSA ``revise the
definition of a reportable incident to consider changes in the price of
natural gas.'' In the same report, GAO also recommended PHMSA revise
reporting of performance measures for the IM programs to measure the
impact of the program. GAO recommended that PHMSA improve the measures
related to incidents, leaks, and failures to compare performance over
time and make the measures more consistent with other pipeline safety
measures.
    The NTSB recommended that PHMSA modify 49 CFR 195.52 of the
hazardous liquid pipeline regulations to require pipeline operators to
have a procedure to calculate and provide a reasonable initial estimate
of released product in their telephonic reports to the NRC (NTSB Safety
Recommendation P-07-07). NTSB also recommended that the hazardous
liquid regulations require pipeline operators to provide an additional
telephonic report to the NRC if significant new information becomes
available during the emergency response (NTSB Safety Recommendation P-
07-08). This rule includes provisions addressing these recommendations.
    Section 15 of the PIPES Act of 2006 (Pub. L. 109-468, December 26,
2006) requires PHMSA to review and modify the incident reporting
criteria to ensure that the data accurately reflects trends over time.
One of the goals of this rulemaking is to comply with the requirements
of this mandate.
    In 2009, PHMSA revised the incident/accident report forms for gas
transmission, gas distribution and hazardous liquid pipelines (August
17, 2009; 74 FR 41496). The use of these new forms were required
beginning on January 1, 2010. The revisions to these forms were
intended to make the information collected more useful to all those
concerned with pipeline safety and to provide additional, and in some
instances, more detailed data for use in the development and
enforcement of its risk-based regulatory program.

II. Analysis of Public Comments

    PHMSA received comments from 37 organizations including:
     Eight associations representing pipeline operators (trade
associations).
     Fourteen gas distribution pipeline operators, many of
which also operate small amounts of transmission pipeline as part of
their pipeline systems.
     Five gas transmission pipeline operators.
     Two LNG facility operators.
     One operator of both gas transmission and hazardous liquid
pipelines.
     The National Association of State Pipeline Safety
Representatives.
     Two state pipeline regulatory authorities.
     Two pipeline service vendors.
     One standards developing organization.
     One citizens group.
    Most commenters supported PHMSA's proposal to improve its data
collection, although many expressed concerns over specific aspects of
the proposal. This section addresses general comments regarding PHMSA's
approach. We address comments related to specific changes proposed in
the NPRM and on related proposed reporting forms individually, below:

General Comments

Stability and Consistency
    A number of comments addressed stability and consistency in
reporting and data collection. Southwest Gas Corporation (SWGas),
Paiute Pipeline Company (Paiute), and TransCanada noted that PHMSA was
revising incident report forms not affected by the changes proposed in
this NPRM concurrently but in a separate docket. These commenters
suggested that the dockets be combined or that PHMSA delay changes to
the incident report forms until this proceeding was concluded. SWGas
and Paiute also suggested that all data-collection changes should be
considered in light of their potential impact on other PHMSA regulatory
initiatives, such as control room management and IM for distribution
pipelines. SWGas and Paiute also suggested that cause categories (e.g.,
for leaks, incidents) should be consistent across all reports and that
PHMSA should convene working groups to agree on categories and the
minimal set of data needed. They contended that PHMSA's proposal would
involve collection of more data than it will ever use. Piedmont Natural
Gas Company (Piedmont) also requested that causes be made consistent
between transmission and distribution, noting that it is burdensome to
track causes differently for each pipeline type. Distrigas of
Massachusetts LLC (DOMAC) suggested that PHMSA and the Federal Energy
Regulatory Commission (FERC) meet to reconcile inconsistencies in
reporting for facilities over which both agencies exercise
jurisdiction, noting that such a meeting was contemplated in the 1993
Memorandum of Understanding between the agencies but has never
occurred. National Grid requested that PHMSA make reporting changes
once and minimize subsequent changes because change is very costly to
implement and requires an operator to modify its management systems for
collecting data.

Response

    PHMSA recognizes that changes in reporting requirements necessitate
a change in an operator's procedures and practices and that these
changes should be infrequent. PHMSA also must change its data
management systems when different data is reported. Yet, good data is
necessary for PHMSA to understand the state of pipeline safety and to
identify areas where additional regulatory attention may be needed.
PHMSA is updating all of its data collection/management and reporting
requirements so that it has the data that it needs to advance as a
data-driven organization. PHMSA acknowledges that the changes made in
this final rule, and to the incident/accident forms, will require the
reporting of more data. PHMSA is making every effort to assure that the
outcome of this rulemaking will minimize the need for any future
changes. PHMSA is coordinating all of the activities related to data
collection and does not believe that it is necessary to combine
dockets. PHMSA is trying to establish consistent use of cause
categories across all types of reporting and is considering its data
collection needs, and the effect of its data gathering requirements, in
light of its other regulatory initiatives.
    PHMSA does not consider that a meeting with FERC to reconcile any
differences in reporting is necessary at this time. While FERC and
PHMSA share jurisdiction over some LNG facilities, there are many LNG
facilities subject to PHMSA's regulations over which FERC exercises no
jurisdiction.

Implementation

    The AGA, Northeast Gas Association (NEGas), Oklahoma Independent
Petroleum Association (OKIPA) and five pipeline operators requested
that PHMSA allow time for data collection processes, databases, and
software to be modified before new forms are implemented. Some
suggested allowing one year after the effective date of the final rule.
OKIPA requested 18 months. SWGas and Paiute suggested that one full
calendar year of data collection should be allowed before new forms are
used. TransCanada suggested PHMSA conduct a 90-day trial and begin use
of new forms at the beginning of the calendar year following the end of
the trial, with no retroactive reporting. They asserted that this kind
of approach is needed to make sure the system works and that
retroactive reporting would be unnecessarily redundant and confusing.

 Response

    PHMSA recognizes that it will take time for operators to revise
their internal data management and collection systems and processes to
report newly-required information. At the same time, excessive delay
only postpones PHMSA's ability to use new data to understand better the
state of pipeline safety. PHMSA does not consider that any of the
information required in the revised forms is new. Pipeline operators
already collect this information. Changes to internal processes may,
indeed, make it easier to organize and report this data, but PHMSA does
not believe that any retroactive data gathering will be required to
complete the new annual report forms. The industry has been aware for
some time that changes of this nature were in development. As discussed
above, PHMSA needs better data to judge the effectiveness of its
regulatory activities and to make informed decisions about future
activities. Further postponement will only delay PHMSA's ability to use
better data. Operators will therefore be required to use the new annual
report forms in 2011 to report data for 2010. The information required
to complete the new LNG incident report form is related to the
occurrence of an incident and is collected during investigation of the
event, not over time. Thus, the rule requires that the new form be used
as soon as it is approved. However, in order to develop its on-line
systems, PHMSA is delaying the submission of the 2010 annual reports
for gas transmission, LNG and hazardous liquids. For the reporting year
2010, the gas transmission annual report and the LNG annual report will
not be required to be submitted until June 15th and the hazardous
liquid annual report will not be required to be submitted until August
15, 2011. In addition, we are delaying the implementation of the OPID
registry requirements until January 1, 2012.
Additional Comment Opportunity
    The Gas Piping Technology Committee (GPTC) and the Pipeline Safety
Trust (PST) suggested that PHMSA allow a second opportunity for public
comment. They noted that many changes were proposed in the NPRM and
that many issues remain to be unresolved. They also noted there are
significant changes to the related reporting forms.

Response

    PHMSA believes adequate time has been given for comment and that an
additional comment period is not needed. PHMSA considers that the
issues have been well vetted through discussions with industry data
groups, the comments discussed in this notice, and discussion at the
December 2009 public meeting of the Technical Pipeline Safety Standards
Committee and the Technical Hazardous Liquid Pipeline Safety Standards
Committee.
    As discussed below, PHMSA is withdrawing the proposed new safety-
related condition report form.
Organization of Regulatory Reporting Requirements
    AGA, GPTC, DOMAC, and seven pipeline operators suggested that
reporting requirements for gas pipelines and LNG facilities should be
integrated into 49 CFR Parts 192 and 193 respectively. At present,
reporting requirements for gas pipelines and LNG facilities are
consolidated in Part 191 while the technical safety requirements
applicable to these facilities are in Parts 192 and 193. For hazardous
liquid pipelines, reporting and technical requirements are both in Part
195. Commenters suggested that relocation of the gas/LNG reporting
requirements would improve clarity. DOMAC suggested it would be clearer
for LNG facility operators given that the definitions in Part 193 are
more specific to LNG--definitions in Part 191 are focused more on gas
pipelines and can create confusion for LNG operators. SWGas and Paiute
similarly commented that they consider LNG facilities to have unique
characteristics that do not fit a pipeline-based reporting scheme. The
other commenters also suggested that future changes would be
facilitated and questioned why there is a different approach in the
regulations for gas/LNG than for hazardous liquid pipelines.

Response

    PHMSA did not propose any changes in how the pipeline safety
reporting requirements should be organized. Thus, changes to
incorporate Part 191 reporting requirements into Parts 192 and 193 are
beyond the scope of this rulemaking. PHMSA will consider if it should
undertake a future rulemaking to make these changes.
Risk-Based Regulation
    Some commenters questioned whether the proposed changes reflect a
risk-based approach. Technology and Management Systems, Inc. (TMS)
noted that risk-based regulation would require consideration of both
probability and consequences and standards that establish criteria on a
risk basis. TMS also suggested that PHMSA should collect time and total
volume of product flow between incidents, asserting that this data is
needed for a true consideration of risk. DOMAC also suggested that
throughput data be collected from all sectors on annual reports to
provide a context for analysis of safety over time.

Response

    PHMSA recognizes that a determination of risk involves
consideration of both probability and consequence. Many of PHMSA's
recent regulatory changes, particularly our IM initiatives, have been
directed at managing risk, and these initiatives involve consideration
of both the probability of an adverse event occurring and its potential
consequences. PHMSA also recognizes that true ``risk-based'' regulation
would involve standards expressed in terms of numerical thresholds
related to risk. PHMSA does not consider such an approach practical for
regulation of pipeline safety at this time.
    PHMSA does not agree that collecting information on time and volume
of product flow between incidents would serve PHMSA's needs or provide
a better analysis of risk. Similarly, additional data concerning
product throughput is not needed. Overall information on product
movement is available from data PHMSA and the Energy Information
Administration collect on annual reports, and this information can be
used to understand the context in which pipeline incidents occur.
Definitions and Terminology
    Some commenters requested that PHMSA add definitions for terms not
now formally defined in the regulations. PST suggested adding
definitions to Part 191 for gas pipeline facility/facilities,

LNG plant, production facility, distribution pipeline system, gathering
pipelines, and transmission pipelines, noting that these terms are used
in the part but not now defined. DOMAC requested that the regulations
refer to an ``LNG facility'' rather than an ``LNG plant or facility,''
because the regulations only define the term facility. El Paso Pipeline
Group (El Paso) suggested that terms be defined as needed, particularly
the term ``explosion.'' SWGas and Paiute recommended clarifying use of
the term ``significant,'' noting that the regulatory analysis
supporting the NPRM used this term to describe events using the same
criteria as those defining accidents in Sec.  195.50. El Paso suggested
that the references to ``subchapter'' in proposed Sec.  192.945 be
revised to refer to ``part'' as found elsewhere in the regulations.

Response

    In the NPRM, PHMSA did not propose to add the definitions suggested
by PST to Part 191. PHMSA cannot now add definitions in the final rule
without having allowed an opportunity for public comment. PHMSA notes
that many of the terms are defined in Parts 192 and 193 and are thus
commonly understood within the pipeline industry. PHMSA does not
consider the lack of these definitions in Part 191 to be a cause of
confusion. PHMSA will consider if future rulemaking is needed to define
additional terms in Part 191.
    PHMSA does not consider that all terms used in the pipeline safety
regulations must be defined explicitly. Terms require definition when
they have particular meanings within the regulations. Terms that are
used that reflect their commonly understood meaning need not be defined
explicitly. As such, PHMSA does not think it is necessary to define
``LNG plant'' or to refer only to an ``LNG facility'' because that term
is defined in Part 193. The use of ``plant'' to describe an industrial
facility is common within the English language and does not need an
explicit definition.
    PHMSA also does not find it necessary to define the term
``explosion.'' Although there are accepted technical definitions for
this term, many involve factors, such as consideration of the magnitude
of the resulting pressure wave that would require data not normally
available for a pipeline event. At the same time, PHMSA considers that
the difference between ``ignites'' (or burns) and ``explodes'' is
commonly understood, and that reliance on this common understanding
results in less confusion than would result from trying to apply a
formal definition.
    With respect to the term ``significant,'' that term was used in the
regulatory analysis to differentiate events that require reporting as
accidents from events of lesser importance. It was not intended to
reflect any more-important subset of reported incidents/accidents.
Regulatory evaluations are prepared to explain the basis and benefits
of proposed regulatory changes to all stakeholders, including those not
directly involved in the regulated industry. It is thus necessary to
reflect that not all adverse events that occur at a pipeline facility
are reported as incidents, only those that are significant.
    Proposed Sec.  192.945 included two references to other sections of
the pipeline safety regulations, one of which is in another Part (Part
191). Therefore, we must use ``of this subchapter'' for that reference.
The other reference to Sec.  192.7 should be referred to as ``of this
part.'' PHMSA has revised this section accordingly.
Miscellaneous
    PST opposes the use of the National Pipeline Mapping System (NPMS)
to collect data if information will not be available to the public via
that system.
    El Paso and Spectra Energy Transmission LLC (Spectra) requested
that PHMSA encourage all stakeholders to make use of the reported data.
They noted that they currently answer many telephone calls from PHMSA
and state pipeline safety regulatory personnel seeking information that
this proposed rule would require be reported.
    OKIPA requested that PHMSA provide examples of significant
information that would require a supplemental incident report under
Sec.  191.15(c).

Response

    PHMSA does not intend to use NPMS to gather data proposed for the
annual reports. As we noted, PHMSA is redesigning its own information
management systems. These changes will make information more readily
available to PHMSA and state regulatory personnel. PHMSA will encourage
its staff to obtain information from the PHMSA systems rather than
telephoning operators.
    Section 191.15(c) does not require a supplemental report for
``significant'' information, and thus no examples are necessary to
illustrate significance. This paragraph requires a supplemental
incident report when additional information becomes known after an
initial incident report is submitted. This could include information
necessary to complete a section of the incident report form that was
left blank in the initial submission because the information was not
yet known. It could also include additional information that the
operator concludes is important to understanding the incident and which
the operator would report in the narrative section of the form.

III. Discussion of Public Comments on Individual Issues

(1) Modifying the Scope of Part 191 To Reflect the Change to the
Definition of Gas Gathering Lines

49 CFR 191.1

Proposal

    In the NPRM, PHMSA proposed to revise the scope of Part 191 to
address an inadvertent omission in the March 15, 2006, final rule that
redefined the definition of gas gathering pipelines in Part 192. Part
of that rulemaking effort revised Sec.  192.1 to reflect the change in
the scope of Part 192. A corresponding change was not made to the scope
of Part 191, which specifies requirements for reporting incidents and
other events and for submission of annual reports by operators of
pipelines subject to Part 192. Because of this omission, there was
confusion whether operators of gathering lines that became regulated
only with the 2006 rule were required to submit reports. Further,
operators of gathering lines have been reporting the number of miles of
gas gathering lines by the old definition and not by the new definition
in Part 192.

Comments

    The Texas Oil and Gas Association (TXOGA) and Atmos Energy
Corporation (Atmos) suggested clarifying Sec.  191.15, requiring
submission of incident reports, and Sec.  191.17, requiring annual
reports, to indicate that they apply only to regulated gathering lines.
    The National Association of Pipeline Safety Representatives,
supported by the Iowa Utilities Board (IUB), suggested PHMSA require
operators of all gathering lines to report incidents, regardless of
whether they are regulated under Part 192. The commenters noted that
data on incidents that occur on non-regulated lines is necessary to
determine whether additional regulation is needed.

Response

    PHMSA has not changed the proposed regulatory language. Section
191.1(b)(4)(ii), as revised in this final rule, clearly states that
Part 191 does not apply to gathering lines that are not regulated
gathering lines as determined in accordance with Sec.  192.8. Thus,
none

of the provisions in Part 191, including Sec. Sec.  191.15 and 191.17,
applies to non-regulated gathering lines. The clarification TXOGA and
Atmos requested is not needed.
    PHMSA agrees that data for incidents that occur on non-regulated
gathering lines could be useful in determining whether these pipelines
should be brought under the reporting regulations. However, PHMSA did
not propose such a change. PHMSA would have to undertake a new
rulemaking to bring unregulated gathering lines under Part 191 incident
reporting requirements.

(2) Changing the Definition of an ``Incident'' for Gas Pipelines

49 CFR 191.3

Proposal

    In the NPRM, PHMSA proposed to change the definition of an incident
in 49 CFR 191.3 to establish a new reporting category: An explosion or
fire not intentionally set by the operator. This proposed change would
make the definition consistent with the accident reporting criteria for
hazardous liquid pipelines in Part 195.
    The NPRM also proposed to establish a volumetric basis of 3,000 Mcf
(the abbreviation ``Mcf'' means thousand cubic feet) for reporting
unintentional gas loss. This proposal responded to a GAO
recommendation. In a report titled: ``Natural Gas Pipeline Safety:
Integrity Management Benefits Public Safety, but Consistency of
Performance Measure Should Be Improved,'' (GAO-06-946, September,
2006), GAO stated that the current gas incident reporting requirements
do not adjust for the changing cost of gas released in incidents. GAO
recommended that PHMSA ``revise the definition of a reportable incident
to consider changes in the price of natural gas.''
    In November 2005, the Interstate Natural Gas Association of America
(INGAA) submitted a petition for rulemaking recommending PHMSA adopt a
volume basis instead of the cost of gas lost. INGAA recommended 20
million standard cubic feet as a reporting threshold. INGAA based this
volume on the $50,000 reporting threshold and the 1985 \1\ cost of gas
at $2.50 per Mcf.
---------------------------------------------------------------------------

    \1\ The criterion for reporting property damage exceeding
$50,000 was established in 1984 and began widespread use in 1985.
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    The proposed change responded to both the GAO recommendation and
the INGAA petition. It would remove the cost of gas lost from
consideration in determining whether an event constitutes an incident
under the existing criterion of $50,000 damage. This would correct the
problem GAO identified in that the volatility of gas prices would no
longer be an issue in determining whether a particular event met the
definition of an incident. The new criterion would separately capture
events in which a large quantity of gas is lost regardless of the value
of resulting property damage.
    The proposal also changed the language preceding the criteria to
make clear that an incident was an event that resulted in one of the
listed consequences. Previously, the regulations referred only to
events that ``involve[d]'' one of the consequences and it was not clear
that events of interest were those in which the gas pipeline failure
resulted in the listed consequences.

Comments

Causality
    INGAA, the Texas Pipeline Association (TPA), TransCanada, and
NiSource Gas Transmission and Storage (NiSource) supported the change
to make it clear that events only become incidents if the listed
consequences resulted from a release of gas from a pipeline. DOMAC and
National Grid disagreed, noting that conclusions of causality could
imply legal liability, and expressing a preference for the former
structure of reporting events that ``involve'' stated consequences to
avoid pre-judging liability.
Explosion or Fire Not Intentionally Set by the Operator
    AGA, the American Public Gas Association (APGA), GPTC, NAPSR, IUB,
and many pipeline operators objected to the addition of this criterion.
Many of these comments reflected confusion about fires that did not
result from the gas pipeline failure. Commenters noted, for example,
that over 400,000 structure fires occur each year in the U.S. In many
of those fires, a gas meter is damaged and gas subsequently becomes
involved in the pre-existing fire. These commenters maintained that
PHMSA has no jurisdiction over fires that begin from non-pipeline
causes and that reporting these events as pipeline incidents would
significantly misrepresent pipeline safety and would distort current
incident trends. They also asserted that other agencies (e.g., Federal
Emergency Management Agency) already collect fire data.
    GPTC and several operators commented that a brief ``fire'' is an
expected operational event during many activities associated with
operation and maintenance of gas distribution pipelines. DOMAC claimed,
for example, that the proposed criterion would require reporting of a
lightning strike that ignites a gas relief vent that is designed to
close and snuff out the resulting fire with no safety consequences.
APGA argued that this criterion could significantly increase the number
of ``incidents'' and that PHMSA had not considered the significant
burden that could result due to existing requirements to test personnel
involved in an incident for drugs and alcohol. Some commenters also
objected that analyses referred to in the NPRM in support of this
proposed new criterion were not included in the docket for public
examination. Several pipeline operators suggested that the new
criterion was not needed since the remaining criteria would provide a
complete picture of consequential events.
    INGAA, El Paso, and Spectra took a contrary position and suggested
that the proposed new criterion apply to events resulting from
intentional and unintentional releases of gas.
    IUB suggested that we should not exclude fires intentionally set by
an operator because hazardous liquid pipeline operators sometimes
intentionally set fires to consume released product that cannot
otherwise be recovered.
    AGA commented that nearby fires should be deleted as a primary
cause of a gas pipeline incident because these are outside PHMSA
jurisdiction.
Volume Measure for Released Gas
    AGA, NAPSR, IUB, and several pipeline operators questioned the
practicality of the proposed criterion. AGA and several pipeline
operators noted the difficulty in calculating the amount of a release
within two hours, by which time a telephonic report of an incident is
expected. They contended that factors necessary for this analysis are
not readily obvious. IUB, Atmos, and Michigan Consolidated Gas
(MichCon) questioned the applicability of this criterion to
distribution pipeline incidents. They noted that property damage is the
predominant component of costs for distribution incidents, and that the
concern expressed by INGAA and others that increases in the cost of gas
(and resulting increase in the calculated cost of gas lost) strongly
influence the determination of whether an event constitutes an incident
generally is not applicable to distribution pipeline events. They also
noted that it is sometimes difficult to calculate the amount of gas
lost in distribution events. SWGas and Paiute,

distribution and transmission pipeline operators respectively, agreed,
stating that the volume of gas lost was usually ancillary to other
reporting criteria. Baltimore Gas & Electric (BG&E) suggested
eliminating or qualifying this criterion to apply only to unintended
releases. BG&E contended that release of gas is a routine part of doing
business and classifying such events as incidents could distort safety
trends.
    Most commenters questioned the size of the proposed criterion. Many
noted that it was incorrectly stated in the proposed rule language as
3,000 million cubic feet, although the preamble discussion described
the proposed amount as 3,000 Mcf. The industry trade associations and
many operators argued that the proposed magnitude of the criterion is
too small and that 3,000 Mcf is inconsistent with a criterion of
$50,000 in property damage. INGAA suggested that the release criterion
should be 20,000 Mcf. Other commenters suggested different values,
varying between 10,000 and 20,000 Mcf. Northern Natural Gas (Northern)
and Spectra (gas transmission pipeline operators) suggested that it
would be appropriate to establish different criteria for gas
transmission and distribution pipelines.
    INGAA and several pipeline operators requested clarification
concerning how the proposed criterion was to be applied. El Paso and
Spectra contended that intentional releases, including from
appurtenances designed to release gas (e.g., relief valves) should not
require reporting because these are not consequential incidents. These
operators also suggested that the criterion not be applied to small
leaks that might release large quantities of gas over an extended
period. Similarly, NiSource commented that the criterion should only
apply to immediate releases resulting from an event and should exclude
subsequent blowdowns which have no significant effect on public safety.
INGAA, El Paso, and TransCanada also suggested that the criterion be
limited to gas lost at the incident location because gas lost at
controlled locations (such as would be used for blowdowns) does not
pose the same risk.
    The industry trade associations and several operators also
requested that PHMSA make clear that the introduction of this new
criterion means that the cost of gas lost will no longer be used in
determining whether an event constitutes an incident because of $50,000
in property damage costs. PST also requested clarification in this
area. IUB suggested that PHMSA should provide guidance on how the
amount of gas lost is to be calculated.
Property Damage Criterion
    AGA and a number of pipeline operators commented that the existing
criterion of $50,000 property damage is too low and should be raised.
The commenters noted that this criterion was established in 1984 and
has not been adjusted since; inflation has made events reportable that
would not have been reportable in 1984. Commenters suggested that the
criterion should be increased to $100,000, that it should be revised
periodically or indexed for inflation, or that various categories of
costs should be excluded from consideration. Contrary to this general
trend, SWGas and Paiute suggested that all costs, including third-party
damages and costs to relight customers, should be included, since these
are costs directly related to the event.
Miscellaneous
    PHMSA received several comments related to the definition of a gas
pipeline incident that did not fit into the categories discussed above.
MidAmerican, a gas distribution pipeline operator, suggested not to
change the definition because the proposed changes would add events of
little or no safety significance and divert resources from safety. The
Missouri Public Service Commission (MOPSC) suggested revising the
existing criterion related to injuries to include medical care at an
emergency room or other facility in addition to inpatient
hospitalization. MOPSC contended that changes in the practice of
medicine have resulted in many injuries that formerly required
inpatient hospitalization now being treated at such facilities. INGAA,
NAPSR, Northern, Atmos, and TransCanada commented that incidents should
be limited to unintentional releases of gas). MOPSC suggested that the
definition not be limited to releases ``from a pipeline,'' given that
consequential events can result from releases at other locations (e.g.,
fuel lines). AGA and BG&E noted that it is impractical to make incident
criteria the same for hazardous liquids and natural gas because there
are fundamental differences between hazardous liquid and gas pipelines,
particularly gas distribution pipelines.

Response

Causality
    PHMSA is sensitive to the potential legal issue raised by DOMAC and
National Grid. PHMSA understands that an initial conclusion that a
pipeline event ``resulted in'' certain consequences may differ from a
legal finding that the pipeline event caused those consequences,
resulting in liability. Still, PHMSA concludes that it is important to
consider causality in reporting incidents.
    PHMSA's mission is to protect public health and safety and the
environment from risks associated with transporting hazardous materials
by pipeline. PHMSA's concern in requiring the reporting of incidents is
that it understands fully the extent to which problems on regulated
pipelines result in adverse impacts on safety and the environment.
Accordingly, PHMSA's analyses of its incident data always assume a
degree of causality between the pipeline failure and the reported
consequences. It is therefore important that this data be collected so
that it is limited to those events in which a pipeline failure resulted
in adverse consequences, rather than instances in which the event
happened to occur concurrently with circumstances that meet one of the
criteria defining an incident (i.e., death, injury, or property damage
exceeding the reporting threshold). PHMSA is thus persuaded that the
incident definition in Sec.  191.3 should require a conclusion of a
degree of causality (which does not imply legal liability).
    Causality has been treated in the Sec.  195.50 requirement for
accident reports for hazardous liquid pipelines for many years.
Hazardous liquid operators have not complained to PHMSA that this
treatment has adversely affected them in any liability proceedings.
PHMSA has accepted the suggestion to conform the treatment of incidents
in Part 191 to that of accidents in Part 195; therefore, this final
rule defines a gas pipeline incident as ``a release of gas from a
pipeline, or of LNG, liquefied petroleum gas, refrigerant gas, or gas
from an LNG facility, and that results in one or more of the following
consequences:''.
Explosion or Fire Not Intentionally Set by the Operator
    PHMSA has not included in this final rule the proposed new
criterion concerning fires or explosions not intentionally set by the
operator. PHMSA is persuaded by the comments that it did not adequately
consider the effect of this new criterion and the resulting burden. In
addition, as discussed above, PHMSA has revised the definition of an
incident in Sec.  191.3 to include an implied causal relationship
between a pipeline failure and one of the listed consequential

events. PHMSA concludes that these changes will eliminate the perceived
need to report the vast majority of events in which a fire existed
before the gas pipeline failure (so-called ``fire first'' events).
    At the same time, PHMSA does not agree that no ``fire first''
events should be considered. PHMSA considers the argument that it lacks
jurisdiction over fires not resulting from pipeline failures to be
irrelevant. PHMSA also lacks jurisdiction over excavation near
pipelines or over severe weather events (e.g., hurricanes), both of
which often result in pipeline incidents. PHMSA has a responsibility to
assure that the pipeline facilities over which it has jurisdiction are
adequately protected from events, including excavation, hurricanes, and
nearby fires, that could cause safety-significant problems in those
facilities regardless of whether it has jurisdiction over the events
themselves. PHMSA collects incident data, in large part, to assure that
this protection is adequate or to identify instances in which
additional regulation is required to assure adequate protection.
    As part of a separate proceeding involving changes to incident/
accident reporting forms, PHMSA has revised the form's instructions to
clarify that secondary ignition events--those events where the fire
exists first and subsequently results in damage to pipeline
facilities--need only be reported if the damage to pipeline facilities
exceeds $50,000 (one of the incident-defining criteria in this rule).
This provision was included in incident reporting instructions prior to
a form change in 2004. A NAPSR resolution, included as an attachment to
its comments filed in this docket, sought restitution of this provision
as its proposed solution to the problem posed by ``fire first'' events.
PHMSA agrees. The changes in this final rule and to the reporting
instructions should eliminate the need to report the vast majority of
structure fires, since few structures are associated with pipeline
facilities that could result in $50,000 damage (the value of a typical
residential meter set is a few hundred dollars). The changes will
result in reporting of significant pipeline failures caused by nearby
fires (e.g., forest fires), which are appropriate for PHMSA's
consideration in the same manner as other events that cause pipeline
incidents.
Volume Measure for Released Gas
    PHMSA concludes that many of the comments regarding this criterion
resulted from the relatively low volume proposed. This led to concerns
about the need to report routine releases associated with operational
events, such as leaks and blowdowns. PHMSA analyzed incident reporting
from 2004 through 2009 to assess the impacts that a 3,000 Mcf vs. a
10,000 Mcf volumetric reporting threshold would have on incident
reporting frequency. Both gas transmission and gas distribution
incident reporting during that timeframe included the cost of gas lost,
facilitating the comparison. The comparison indicates that at 10,000
Mcf, we would lose about 20 incident reports per year across both gas
transmission and gas distribution incident reporting. Because the
annual frequency is very low (about 135 gas transmission and about 150
gas distribution incidents annually), PHMSA believes that lowering the
numbers further would adversely impact our ability to effectively
conduct safety analysis and trending. Our analysis shows that at the
3,000 Mcf threshold, we estimate we would lose six incident reports per
year. INGAA had suggested a threshold of 20,000 Mcf, an amount that
corresponds to the amount of gas that would have cost $50,000 when the
property damage threshold was revised in 1984. PHMSA agrees that
relating the volume threshold to the property damage threshold is
appropriate, but does not agree that this should be done on the basis
of 1984 costs. Incidents are reported based on current costs. Absent
this rule change, an event that resulted in loss of approximately
10,000 Mcf would be reportable as a loss of $50,000 of gas (considering
current costs). However, as PHMSA concludes from a comparison of 10,000
Mcf to 3,000 Mcf as stated above, the impact of lowering the already
low frequency of reporting further would impact safety trending
capability, therefore, we have chosen to maintain the proposed 3,000
Mcf threshold for the volume release criterion. This final rule
requires reporting of releases that meet or exceed ``3 million cubic
feet'' (i.e., 3,000 Mcf). PHMSA recognizes that initial calculations
are approximate, but does not consider this a reason not to report
events that have consequence.
    PHMSA recognizes that the amount of gas lost in distribution
incidents is usually less than that for transmission pipelines. This
means that there will likely be fewer events that are defined as
incidents on distribution pipelines due to the volume of gas released
if the same criterion is used for both types of pipelines.
Nevertheless, PHMSA considers use of a common criterion appropriate.
Distribution events more often become ``incidents'' due to the amount
of property damage that occurs or as a result of death or injury. This
reflects real differences between transmission and distribution
pipelines. Using a different volume release criterion for distribution
pipelines to force the number of reported incidents to be similar to
that of transmission pipelines would distort analytical results and
obscure these real differences.
    PHMSA agrees that intentional, controlled releases are not events
with significant safety consequences. PHMSA has revised the final rule
to clarify that reporting under the volume threshold is only required
for ``unintended'' releases that exceed the specified amount. Yet,
PHMSA does not agree that other criteria should be limited to
unintentional releases. PHMSA considers that an intentional release
that results in death, inpatient hospitalization, or $50,000 in
property damage would be an event with significant safety consequences
and should be reported as an incident.
    The intent of this new criterion is to separate lost gas from other
property damage costs to preclude the volatility of gas prices from
affecting which events are defined as incidents. PHMSA has revised the
final rule to make clear that the cost of gas lost is not to be
included in the calculation of property damages for comparison with the
$50,000 criterion.
Property Damage Criterion
    The NPRM did not include any change to the existing $50,000
property damage criterion. As such, changes to this criterion would be
outside the scope of this rulemaking. However, PHMSA does believe that
because the annual frequency of both gas distribution and gas
transmission incident reporting is extremely low as noted above, a
reevaluation of that threshold is appropriate and PHMSA may take that
under consideration in the future.
Miscellaneous
    PHMSA does not agree that the changes in the definition of a gas
pipeline incident add events of little safety significance. As
discussed above, these events are significant. PHMSA has made
clarifications to eliminate reporting of non-consequential events
(e.g., intentional blowdowns and most ``fire first'' events). PHMSA
does not consider that these changes will result in any inappropriate
redirection of resources.
    Similarly, PHMSA did not propose any change to the existing
criterion for injury; therefore, MOPSC's suggested

changes to this criterion would be outside the scope of this
proceeding. PHMSA notes, however, that inpatient hospitalization is an
objective criterion. Other treatment can vary based on local practices.
In some areas, people with minor injuries may still be taken to
emergency rooms as a precautionary measure, but those patients would
not be admitted unless their injuries were serious. PHMSA considers the
existing criterion appropriate.
    PHMSA has discussed above its reasons for requiring reporting of
events resulting from intentional releases of gas, excluding events
that result solely in loss of gas, as incidents. Pipelines and pipeline
facilities are PHMSA's focus of regulatory concern; therefore, PHMSA
has not accepted MOPSC's suggestion to expand the scope of incidents
beyond releases from these facilities.
    PHMSA agrees that the criteria defining an incident for hazardous
liquid and gas pipelines should recognize differences between those
pipelines and the commodities they carry. As discussed above, PHMSA has
decided not to include a criterion in the definition of a gas pipeline
incident related to a fire not intentionally set by the operator or an
explosion. Such a criterion has long been part of the definition of an
accident for a hazardous liquid pipeline.

(3) Requiring Electronic Reporting and Filing of Reports

49 CFR 191.7 and 195.58

Proposal

    In the NPRM, PHMSA proposed to require operators of a regulated
pipeline or facility to submit all reports to PHMSA electronically.
This proposal was intended to improve the processing of submitted
reports and reduce paperwork burdens.

Comments

    Most commenters supported electronic reporting, while APGA
suggested retaining an option for paper filing for very small
distribution operators that may lack internet access. GPTC noted that
the proposed requirement to apply for non-electronic submission 60 days
in advance of a report being due was inconsistent with the requirement
to submit incident reports in 30 days. OKIPA requested that PHMSA
describe the criteria it will use to review applications for non-
electronic reporting and to assure consistency among states. PST
objected to allowing an option for non-electronic reporting, noting
that internet access is now widely available.
    Many commenters addressed the process by which electronic reports
will be made. The American Petroleum Institute (API) and the American
Association of Oil Pipelines (AOPL) argued that electronic reporting
should be more than completing a form on the computer; it should
include internal checks to prevent incorrect entries, assure data
consistency, etc. API and AOPL also suggested that a narrative
description should continue to be part of incident reports. API, AOPL,
AGA, GPTC, and several pipeline operators suggested that the on-line
system allow for saving interim work and printing a completed form
before submission. API, AOPL and Atmos proposed that the system allow
for electronic submission of a completed template to save time and
reduce potential for errors. Pipeline operators recommended that the
on-line system allow users to print a blank form, provide electronic
confirmation of submission, and provide clear guidance for updating/
modifying/superseding reports in the event of new information. National
Grid commented that controls should be established to allow submissions
only by a company's designated representative. APGA, GPTC, and Northern
Illinois Gas Company (Nicor) maintained that reports should not be
considered late-filed if the on-line system is not available on the
date on which a report submission is required.
    Northern suggested that the on-line system should also allow a
report to be rescinded electronically, which would be consistent with
requiring electronic submissions and would be less burdensome. Piedmont
advised that PHMSA should staff sufficiently to handle data correction
requests based on their experience that it is difficult to correct data
once submitted.
    APGA, GPTC, and NiSource suggested revising the regulations to
allow electronic submittal of reports that must be made immediately to
the NRC, noting that the NRC system now provides for this alternate
method.
    API, AOPL, TPA, TXOGA, and Atmos commented that separate reports
should not be required for interstate agents and states; instead
current technology allows reports to be forwarded to the appropriate
agency based on the location of assets involved.

Response

    PHMSA agrees that a paper-filing option must be provided, although
PHMSA expects that the need for alternate submission will be rare. At
the same time, PHMSA is persuaded that its proposed option to apply for
non-electronic filing was unduly burdensome. A requirement to request
non-electronic reporting 60 days in advance is, as commenters noted,
inconsistent with a requirement to report incidents in 30 days. In
addition, requiring a request for non-electronic filing separately for
each report unnecessarily adds burden for operators and PHMSA because
the same few operators are likely to apply for approval repeatedly.
PHMSA has revised the final rule to eliminate the requirement to
request an alternate reporting method 60 days in advance of each
required submission. The final rule provides that operators may apply
for use of alternate submission methods and that approvals of such
requests may be indefinite or until a date specified by PHMSA,
eliminating the need to apply separately for each required submission.
PHMSA will review the description of the undue burden that would be
imposed by a requirement to file electronically but does not find it
necessary or appropriate to define specific criteria for acceptance or
denial at this time. The requirement for electronic submission, and for
alternate methods, applies to submissions made to PHMSA; therefore, the
question of consistency among states is not at issue here.
    PHMSA's electronic reporting system includes the options commenters
requested. This system is already being used for recently revised
incident/accident report forms. The system includes internal checks for
data consistency and incorrect entries (e.g., entering text in a
numeric field). It allows saving of work in progress and printing of
completed or blank forms. Where forms are printed before submission,
the word ``DRAFT'' appears as a diagonal watermark to avoid later
confusion as to whether a filed copy represents information that was
actually submitted. The incident reports provide for a narrative
description. Confirmation of submission is provided by an electronic
date stamp visible to both the submitting operator and PHMSA.
    PHMSA has not allowed for submission of a completed template in
lieu of entering the information on-line. On-line data entry provides
for data quality checks that would not be possible with uploaded files.
These controls are important to help reduce the need for data
correction, and are expected to help address the difficulties with data
correction raised by Piedmont.
    Submissions are made using user identification and passwords that
are provided to a company's designated person. PHMSA does not consider
it necessary to modify further its on-line

system to allow submission only by designated company representatives.
Operators should control dissemination of their ID/password as they
would for any password-protected computer system.
    PHMSA has not adopted Northern's suggestion to allow reports to be
rescinded electronically. Although this may be easier, rescissions need
to be made through PHMSA's staff for data quality reasons.
    PHMSA has eliminated requirements to file duplicate copies of
reports with states with the exception of safety-related condition
reports. PHMSA is required by statute (49 U.S.C. 60102(h)) to provide
for concurrent notice of safety related conditions to appropriate State
authorities.
    As suggested by commenters, PHMSA has revised Sec. Sec.  191.5 and
195.52 to allow operators the option of submitting on-line reports of
certain incidents to the NRC (NRC). The NRC now allows for electronic
reporting of incidents; therefore, including this option in PHMSA's
regulations imposes no new burden on the regulated industry.

(4) Requiring LNG Operators To Submit Incident and Annual Reports

49 CFR 191.9, 191.15, 191.17 and 193.2011

Proposal

    In the NPRM, PHMSA proposed to amend Sec. Sec.  191.9, 191.15,
191.17, and 193.2011 to require LNG facility operators to submit annual
and incident reports consistent with the current reporting requirements
for gas and hazardous liquid pipeline operators. LNG facility operators
had previously been exempted from these requirements.

Comments

    SWGas and Paiute contended that submission of incident reports for
LNG facilities is not needed because incidents at these facilities are
very rare. BG&E and MidAmerican also maintained that annual reports are
unnecessary because these facilities are static and the reported
information will not change from year to year. SWGas and Paiute claimed
that the need for annual reports to justify user fees is specious given
that fees are currently determined by tank volume. These operators also
contended that it was not possible to estimate the burden for
completing the annual report forms since changes in which emergency
shutdowns are to be reported could have a major impact on what needs to
be reported. DOMAC also commented that information reported on incident
reports (e.g., emergency shutdowns) should not be repeated on annual
reports. DOMAC maintained that PHMSA has not made a good case for the
need for reporting by LNG facility operators and those problems in
other sectors should not be the basis for requiring reporting by LNG
operators. DOMAC suggested that PHMSA should convene an LNG data team
to design forms to be used to report LNG incidents because the
reporting proposal and related forms demonstrate a lack of knowledge of
LNG facilities. DOMAC further suggested that facility data should be
automatically populated on incident report forms from information
available in the Pipeline and LNG Operators' Registry. SWGas and Paiute
suggested that PHMSA should partner with FERC or states to get LNG
information to eliminate duplicate reporting. These operators also
claimed that a form is not needed for safety-related condition reports
because such reports at LNG facilities are rare.
    Other commenters raised concerns related to how the definition of
an incident in Sec.  191.3 apply to LNG facilities. A principal concern
of these commenters was the proposed requirement that all emergency
shutdowns be reported as incidents, except those resulting from
maintenance. AGA, INGAA, NEGas, Northern, Northwest Natural Gas (NWN),
BG&E, National Grid, and MidAmerican would all limit reporting to
actual emergencies, noting that not all emergency shutdowns are safety-
significant events. MidAmerican suggested that requiring such reports
would discourage operators from installing aggressive emergency
shutdown systems. DOMAC claimed that the exclusion for maintenance is
unnecessary because the preamble of the 1984 rulemaking that required
telephonic reporting of emergency shutdowns stated that only actual
emergencies needed to be reported. DOMAC also maintained that the
concept of a leak in piping and equipment is not applicable to an LNG
facility. BG&E would similarly eliminate rollover events as not safety-
significant. SWGas and Paiute would delete from the definition of an
incident any reference to refrigerant gas because this is not gas in
transportation and not subject to PHMSA's jurisdiction. Piedmont asked
for clarification as to whether the volume release or explosion/fire
criteria apply to LNG facilities.
    SWGas and Paiute noted that use of some terms differs between
pipelines and LNG facilities and that terms used for LNG need to be
accurately defined.
    NiSource Distribution Companies (NISource Distribution) suggested
that because LNG is a ``chemical of interest'' for terrorist
protection, PHMSA and the Department of Homeland Security should
discuss what information is to be collected and made public.

Response

    PHMSA is not persuaded that relative rarity of incidents at LNG
facilities means that reports of these events are not needed. Such
reports may be submitted rarely, but they will provide valuable data
concerning safety-significant events and conditions that may occur. The
existence of a reporting requirement or a related form will impose no
burden on LNG operators that do not experience incidents. PHMSA agrees
with DOMAC that it is not necessary to collect information on annual
reports that are obtained via incident reports. PHMSA has omitted
reports of emergency shutdowns from the annual report form, as these
will be reported as incidents. (As discussed below, PHMSA is
withdrawing the proposed safety-related condition report form at this
time).
    PHMSA recognizes that major changes occur infrequently at
individual permanently-located LNG facilities. At the same time, some
LNG facilities are temporary or mobile, and there has been
unprecedented expansion in the number of LNG facilities. It is no
longer practical for PHMSA to manage its oversight of LNG facilities
based on recalled knowledge. Data is needed, and annual reports are the
vehicle by which this data will be collected and kept current. PHMSA
has designed its form and will design its on-line reporting to allow
the operator of an individual LNG facility to indicate that data
reported in the previous year has not changed, in which case the
operator will not need to repeat the information. This will minimize
the reporting burden for operators of facilities that do not experience
changes.
    PHMSA does not agree with DOMAC that the forms proposed for LNG
reporting represent little knowledge of LNG facilities and systems. The
proposed forms were based, in large part, on forms that have been used
for reporting LNG events in the State of Texas for many years. PHMSA
believes these forms are suitable for use, but PHMSA recognizes that
these forms, as for any form, could likely be improved. PHMSA will
consider DOMAC's proposal to convene an LNG data team to review the
forms as a subsequent effort but does not consider it necessary to take
this step before implementing a reporting requirement for LNG
facilities.

PHMSA notes that problems in other sectors have not formed the basis
for requiring reporting of LNG incidents. PHMSA has focused on LNG in
this effort. The criteria defining significant consequences apply
equally to LNG and to pipelines. An event that causes a death, serious
injury, or significant property damage is significant whether it occurs
on a pipeline or at an LNG facility. LNG emergency shutdowns have long
existed as an incident-defining criterion. The change here is that
PHMSA is now requiring written reports for LNG incidents that
previously required only telephonic reports to NRC. This is part of
PHMSA's increased data focus. PHMSA intends to base future actions on
its analysis of data concerning actual safety performance. Additional
data concerning LNG incidents, even if rare, is important to support
this goal.
    PHMSA has revised the definition of an incident in Sec.  191.3 to
clarify that actuation of an emergency shutdown system at an LNG
facility that results from causes other than an actual emergency does
not constitute an incident. This will eliminate the need to submit
incident reports for shutdowns that result from maintenance,
inadvertent actuations and signals, and any other emergency shutdown
that does not result from an actual emergency. PHMSA has also deleted
rollovers as an incident criterion. PHMSA agrees that these changes
will focus reporting on events with safety significance. PHMSA doubts,
however, that LNG operators would not install systems that aggressively
protect their facility investment solely because of a requirement to
report safety system actuations.
    PHMSA has not deleted reference to a release of refrigerant gas.
PHMSA acknowledges that this is not gas in transportation, but the
facility in which it is used is regulated. Release of refrigerant gas
could represent a failure within that facility. If that failure results
in consequences significant enough to trigger one of the incident
reporting criteria, then that event needs to be reported. The volume
release criterion applies to LNG facilities, as modified, to include
only unintentional gas loss. In response to comments, we have
eliminated the proposed fire or explosion criterion.
    PHMSA agrees with DOMAC that it would reduce operator burden, and
likely improve data consistency/quality, if information in the Operator
Identification (OPID) Registry was automatically populated into
incident forms based on the entered OPID. At present however, the data
that PHMSA has concerning OPIDs is not of sufficient quality to do so.
This will change as operators validate the information (discussed
below). PHMSA will consider a change to its on-line reporting system,
once validation is completed, to implement the suggested change.
    In response to comments about consistency in definitions of terms,
PHMSA has made every effort to make the definitions in forms and
instructions for LNG reporting accurate and consistent.
    PHMSA regularly consults with the Department of Homeland Security
regarding security concerns about data made available to the public.
PHMSA will include LNG data in these discussions.

(5) Creating a National Registry of Pipeline and LNG Operators

49 CFR 191.22 and 195.64

Proposal

    In the NPRM, PHMSA proposed to require all pipeline operators and
LNG plant or LNG facility operators obtain an OPID from PHMSA. This
proposal also would require operators to use this OPID for all
submissions (NPMS, annual report, accident, incident, safety-related
condition etc.) to PHMSA. PHMSA also proposed that an operator notify
PHMSA at least 60 days in advance of certain profile or other changes
to its facilities which could impact public safety. Such changes would
have included any of the following activities for an existing or new
pipeline, pipeline segment, pipeline facility, LNG plant, or LNG
facility:
     A change in the operating entity responsible for operating
an existing pipeline, pipeline segment, or facility.
     A change in the operating entity responsible for managing
or administering a safety program (such as an IM or Corrosion
Prevention Program) covering an existing pipeline, pipeline segment, or
facility.
     The acquisition or divestiture of 50 or more miles of an
existing regulated pipeline or pipeline segment.
     Any rehabilitation, replacement, modification, upgrade,
uprate, or update costing $5 million or more.
     The construction of ten or more miles of a new hazardous
liquid or gas transmission pipeline facility, or other construction
project costing $5 million or more.
     The construction of a new LNG plant or LNG facility, or
the sale or purchase of an existing LNG plant or LNG facility.
    A National Registry of Pipeline and LNG Operators will serve as the
storehouse for the reporting requirements for a regulated operator.
Essential to the effectiveness of PHMSA's oversight is the ability to
monitor and assess the performance of the regulated community--
examining both discrete performance as well as historical trending over
time. The single greatest challenge to PHMSA's ability to track
performance, over time is the dynamic nature of the regulated community
itself. Due to conversions of service, new construction, abandonments,
or changes in operatorship that occur during divestitures,
acquisitions, or contractual turnovers, operators' asset profiles often
change year-to-year, rendering historical trending inaccurate.
Currently, PHMSA does not receive any alerts, information, or
notification of these types of changes and we lack any mechanism to
track or capture these changes when they occur. As a result, PHMSA's
ability to accurately portray and assess the performance of individual
operators is severely compromised, with the situation deteriorating
over time as operating and asset changes accumulate and compound.
    Additionally, there is an increased burden to industry and to PHMSA
in tracking and maintaining potentially numerous OPID's for the same
company. Some companies accumulate a large number of OPID's, often
inadvertently, as the company reports across a variety of lines of
business (e.g., operators may use separate OPID's for reporting their
user fee mileage, safety-related conditions, NPMS submissions,
incidents, and annual infrastructure and IM data.) The proposed
National Registry of Pipeline and LNG Operators will facilitate the use
of one OPID across a company's reporting requirements for a given set
of pipeline segments or facilities thereby reducing the burden on both
PHMSA and industry for tracking these multiple, duplicative OPIDs.

Comments

    Many comments concerning the proposed OPID Registry addressed the
proposal to require 60-days advance notice of certain events that can
change the nature of the operator. INGAA, API, AOPL, and many operators
commented that many of the events for which notification was proposed
are business transactions that must remain confidential until they
occur. Sometimes, this is dictated by requirements of the Securities
and Exchange Commission or other agencies. Commenters also noted that
even non-confidential changes may be delayed or modified before

implementation, causing schedules to be delayed. INGAA and Piedmont
suggested that annual reporting of changes should be sufficient and
that per-event notification should not be required. They also suggested
that PHMSA should obtain information currently reported to FERC, which
duplicates some of the information proposed for the Registry. AGA,
Atmos, and BG&E recommended deleting the proposed notification
requirements because we had not articulated the need for the
information. API and AOPL also asked that PHMSA explain the need for
notifications. TPA suggested deleting certain notification elements.
AGA, NiSource Distribution, and NWN noted that the information is
already reported annually to NPMS or on other forms. SWGas sought an
exemption for distribution pipeline operators from the notification
requirements, contending that PHMSA has no authority to regulate the
costs involved and that a relationship to safety is not obvious.
    Commenters also expressed concern about the extent of information
that would be required in notifications. Since the proposed
notification form was not placed in the docket, AGA, Atmos, and BG&E
claimed that they cannot estimate the burden notification would entail.
API and AOPL suggested that PHMSA should identify the information to be
included in notifications and provide an additional opportunity to
comment. NiSource suggested that a form be developed for this purpose.
SWGas and Paiute noted it was unclear how operators are to make
required notifications. Atmos and TPA suggested that the proposed
notification requirements should be delayed while PHMSA seeks
additional comments.
    Other comments in this area addressed concerns with specific
elements of the proposed notification requirements:
     API and AOPL suggested that notification should be
required for acquisition of a pipeline system rather than a pipeline
facility because this is more consistent with the definitions in Sec.
195.2.
     El Paso, SWGas, and Paiute suggested that additional
guidance was needed concerning how to treat multi-year construction
events for notification purposes. NiSource suggested that clarification
was needed on how to address the costs for multi-year projects and
further suggested that reporting for this criterion be moved to the
annual report.
     AGA, API, AOPL, and numerous pipeline operators expressed
concerns about the proposed notification requirement for
rehabilitation, replacement, modification, upgrade, uprate, or update
or construction of a new pipeline facility costing $5 million or more.
They suggested deleting the dollar criterion completely, given that it
is not indexed for inflation and would be likely to capture smaller
projects in future years. They would rely solely on notification of
construction of some threshold of miles of pipeline. El Paso and
Spectra suggested increasing the threshold from $5 million to $10
million, noting that the cost of materials, contractors, and gas loss
makes a $5 million project a relatively minor activity. National Grid
would index the dollar amounts for inflation and limit their
applicability to single projects vs. programs with multiple projects.
     Other commenters expressed concerns with the proposed
notification requirement for rehabilitation, replacement, modification,
upgrade, uprate, or update. API and AOPL would eliminate the proposed
requirement noting that these changes are intended to improve safety,
notification does not add to safety, and the results of these projects
would appear in subsequent annual reports. Atmos suggested that the
provision exclude changes that must be made in an emergency, since 60-
day advance reporting would be impractical in such circumstances. Mid-
American would delete this criterion completely, claiming it would
delay emergency repairs. TransCanada suggested collecting this
information via annual report after the events had occurred. NAPSR, on
the other hand, supported reporting under this criterion, noting that
the information is needed to address public concerns and inquiries.
     Some commenters questioned the mileage threshold for
notification of pipeline construction projects. API, AOPL, Atmos, and
TXOGA would increase the threshold from ten miles to 50 miles, noting
that this is consistent with the proposed requirement for notifying of
acquisition of an existing pipeline and that smaller construction
projects would show up in annual reports. IUB suggested that the
threshold be lowered to five miles because information about even small
construction projects is necessary to plan safety inspections. Spectra
supported 60-day prior notification for construction of more than ten
miles of pipeline or a new LNG plant.
     INGAA pointed to a discrepancy between the preamble and
the regulatory text on notification of changes in the entity
responsible for major pipeline safety programs. INGAA suggested that
notification should not be required. PST, on the other hand, suggested
that the discrepancy was an omission from the regulatory language and
that PHMSA add this notification criterion.
     Atmos and TPA suggested modifying the criterion for
pipeline acquisition to refer to pipelines/facilities subject to Parts
192 and 193 rather than ``regulated by PHMSA.'' They noted that the
proposed language could lead to confusion for pipelines states
regulate.
     IUB requested that the Registry capture contact
information following acquisitions or mergers because this information
has sometimes been difficult to determine. BG&E would limit
notifications to maintaining current contact information. El Paso and
Spectra suggested that a means to update contact information
electronically would be less burdensome than current practice of
requiring a letter to do so.
     API and AOPL suggested defining ``operating entity'' in
the phrase ``[a] change in the operating entity responsible for an
existing pipeline, pipeline segment, or pipeline facility, or LNG
facility.''
     National Grid requested that PHMSA work with states toward
single reporting per state per operator.
    Another major area of comments was the perception that PHMSA was
requiring operators to re-apply for their existing OPIDs. API and AOPL
commented that operators should not have to re-enter information when
re-applying, but rather record only changes in ownership. El Paso,
OKIPA, and Piedmont objected to requiring operators to re-apply when
PHMSA has not justified such a requirement. OKIPA commented further
that operators should not be required to re-populate information based
on a new OPID. Atmos and TPA commented that PHMSA should establish
reasonable deadlines for operators to complete re-application and for
PHMSA to establish a process to keep the information current. DOMAC
suggested that it would be helpful to have more information on the
content of information required when applying for an OPID.

Response

    PHMSA acknowledges that many of the changes for which we proposed
to be notified are business transactions that need to be kept
confidential and for which advance notification is impractical.
However, not all of the proposed notification criteria are in this
category. New construction by an existing operator, including planned

modifications, upgrades, rehabilitation and uprates, are not business
transactions requiring such confidentiality. PHMSA has modified the
proposed notification requirement to require notification of this type
of activity 60 days in advance. We will require notification of
business transactions that typically require confidentiality within 60
days after the event has occurred.
    PHMSA requires advance knowledge of planned construction activities
so that it can plan safety inspections and align appropriate inspection
resources to conduct these inspections. For pipeline construction in
particular, it is important to inspect construction activities while
they are underway, given that the pipeline is often buried before being
placed in service and it is not then practical to inspect the quality
of construction. NAPSR's comments support this need, noting that states
exercising safety jurisdiction also require advance notice for
inspection planning.
    PHMSA needs to know of changes in operator name, ownership, and
responsibility for operations to adequately track ongoing safety
performance, and to accurately portray safety performance over time,
including the identification of emerging safety trends. Sale of an
existing pipeline, or the complete acquisition or merger of a company
may involve the wholesale adoption of standing operating and safety
practices and programs. These programs may continue without change, or
they may be integrated into the programs of a new owner. Additionally,
sale of an existing pipeline may involve a complete replacement of
staff. Personnel responsible for day-to-day operation of the pipeline
often remain, becoming employees of the new owner. PHMSA must know when
changes in responsibility occur, and the parties involved, to
accurately evaluate and trend safety performance data through and
following periods of change. Some information regarding ownership is
currently reported via NPMS, but NPMS does not include all of the
information PHMSA needs. Similarly, although there is duplication in
some reporting elements with reports required by FERC, many pipeline
and LNG facility operators are not subject to FERC reporting
requirements making it impractical for PHMSA to rely on FERC
information to serve its operational needs.
    Whether ownership change is involved or not, sometimes there is a
change in the primary responsibility for managing or administering one
or more PHMSA-required safety programs. This situation arises when
existing pipelines or LNG Facilities covered by a single OPID are part
of a common PHMSA-required pipeline safety program or LNG safety
program which also involves other assets covered by other OPIDs. (These
common safety programs are sometimes referred to as ``umbrella'' safety
programs.) For PHMSA to adequately evaluate these programs and
accurately document compliance and safety performance over time, it
must be clear, and PHMSA must have a current record of which OPIDs
(and, by extension, which corresponding pipelines and/or facilities)
are included under each PHMSA-required safety program, know when these
OPIDs officially came under these programs, and, if and when these
OPIDs are ever removed from these programs. Additionally, this type of
notification serves to facilitate PHMSA's resource planning and
preparations for the conduct of its inspections of these safety
programs. These ``common safety program'' relationships involving
multiple OPIDs entail a relatively small number of pipeline operators,
something on the order of 10-15% of the total number of operators. And
they also tend to be the larger operators with multi-state and multi-
system operations which, in turn, represent approximately 70-80% of the
total infrastructure mileage. As a result, PHMSA's ability to
accurately track and monitor a large majority of the nation's most
extensive pipeline infrastructure will be accomplished through this
notification requirement affecting relatively few operators. And this
capability to understand the make-up of these common safety programs
over time and through operating and/or ownership changes is the
cornerstone of a more data-driven PHMSA organization.
    PHMSA and the states need to know of planned construction
activities, mergers, acquisitions and other changes in safety
responsibility for distribution pipelines as well as transmission
pipelines. PHMSA is not proposing to regulate costs associated with
distribution pipelines or any other type of pipeline, rather, PHMSA is
using the costs of modifications that do not involve construction
measurable in miles as a trigger for identifying projects PHMSA
regulates and for which prior inspection planning is needed. PHMSA has
thus not exempted distribution pipelines from the notification
requirements.
    Although the NPRM did not propose that operators must re-apply for
OPIDs, PHMSA recognizes that the NPRM was not clear in this regard due
to the number and nature of comments on this topic. PHMSA has modified
this final rule to make it clear that operators to which OPIDs have
been assigned prior to the effective date of the final rule must
validate the information associated with those OPIDs, and not initiate
an entire new application or reapplication process. This validation
must occur within six months of the effective date of the final rule.
Operators must access the information currently in PHMSA's records
concerning their OPIDs (using an on-line, internet-based system) to
make changes where appropriate, or to indicate that the information is
correct. This will help PHMSA assure that the information in its
National Registry of Pipeline and LNG Operators is a current and
accurate baseline. The information that operators must validate must be
consistent with the information required when applying for a new OPID.
This information will be on the OPID Assignment Request form (referred
to in the NPRM as the OPID Questionnaire).
    PHMSA has made changes to some of the criteria for notification,
but has not adopted all the changes commenters suggested:
     PHMSA does not agree with API and AOPL that notifications
for acquisitions should refer to pipeline systems. Pipeline facility,
as defined in both Sec. Sec.  192.3 and 195.2, is a broader term that
better represents the nature of changes in which PHMSA is interested.
     PHMSA does not agree that additional guidance is needed
concerning multi-year projects. The NPRM would not have required annual
notification but notification prior to initiation of a project meeting
a reporting threshold (dollars or miles) regardless of how many years
over which the project was to be accomplished. The final rule retains
the structure of the proposal in this regard.
     PHMSA understands the concerns commenters expressed about
using a dollar threshold to identify certain projects requiring
notification, but sees no practical alternative. As described above,
PHMSA (and states) require prior notification of projects for which in-
progress safety inspection is appropriate. A mileage threshold could
identify appropriate pipeline construction projects, but some
significant construction projects do not involve miles of pipe (e.g.,
construction of a new pump or compressor station). PHMSA has increased
the dollar threshold from $5 million to $10 million and has limited its
applicability to projects not involving line section pipe. PHMSA has
not indexed this threshold for inflation but considers that the
increase in size and limitation in scope

obviates the concerns that smaller projects will be unnecessarily
reported.
     PHMSA has also modified the reporting criterion for
rehabilitation, replacement, modification, upgrade, uprate or other
update to exclude changes that must be made on an emergency basis from
the requirement for 60-day prior reporting. The final rule requires
that operators notify PHMSA of emergency projects as soon as
practicable.
     PHMSA has retained the 10-mile threshold for notification
of projects involving construction of line section pipe. PHMSA
recognizes that this is not consistent with the requirement to notify
of acquisition of 50 miles of pipeline, but the needs addressed by each
criterion are different. Acquisitions usually involve sizeable pipeline
facilities; therefore, 50 miles is a reasonable criterion, and the
information is needed to support accurate trending of safety data.
PHMSA and states need information concerning pipeline construction to
plan safety inspections, and a 10-mile construction project is large
enough that safety inspections would be needed. PHMSA agrees with IUB
that knowledge of even smaller construction projects (e.g., IUB's
suggested 5-mile criterion) would be useful in many cases, but
considers 10 miles appropriate for this notification requirement.
     PHMSA has included a requirement to notify it of changes
in the entity responsible for major pipeline safety programs. The
failure to include this criterion in the proposed regulatory language
was an oversight. As noted by PST, it was discussed in the NPRM
preamble.
     PHMSA agrees with Atmos and TPA that reference to
facilities regulated by PHMSA could cause confusion when facilities
under state regulation are involved. PHMSA has modified the reference
to facilities subject to Part 192, and has made a similar change to the
Registry requirements for hazardous liquid pipelines in Sec.  195.58.
     PHMSA understands the importance of updating company
contact information and of reducing the burden for doing so. At the
same time, PHMSA considers that a change in personnel, which could
affect ``contact information,'' is too fine a level of detail to
require notification. Therefore, PHMSA has not adopted this requirement
into the regulations. PHMSA will consider modifying the National
Operator Registry to make it available for operators to report
voluntarily changes in contact information.
     PHMSA has replaced the term ``operating entity'' so that
the criterion in Sec.  191.22 now refers to, ``[a] A change in the
entity (e.g., company, municipality) responsible for an existing
pipeline, pipeline segment, pipeline facility, or LNG facility.'' This
should alleviate any confusion introduced by the use of a new term.
     PHMSA will make available to state pipeline safety
regulators information that it receives through the National Operator
Registry. States, however, have their own information needs,
requirements, and administrative procedures, and PHMSA cannot force
states to use common reporting instruments.
    PHMSA considers it reasonable that operators want to know the
burden associated with obtaining an OPID and notification of changes.
The NPRM referred to an OPID Questionnaire (now called the OPID
Assignment Request form) which was not made available for public
comment. PHMSA is adopting a form for submitting on-line notifications
to the National Registry of Pipeline and LNG Operators. Therefore,
PHMSA will publish a separate notice in the Federal Register providing
the public an opportunity to comment on the proposed forms.

(6) Requiring Electronic Safety-Related Condition and Offshore Pipeline
Condition Reports

49 CFR 191.25, 191.27, 195.56, 195.57 and 195.58

Proposal

    In the NPRM, PHMSA proposed to require an operator of a natural gas
or hazardous liquid pipeline, or of an LNG plant or LNG facility to use
a new standardized form instead of the free-form Safety-Related
Condition reporting now used. For offshore pipeline conditions, PHMSA
requires an operator to report certain information within 60 days after
completion of the inspection of all its underwater pipelines subject to
Sec. Sec.  192.612(a) or 195.413(a). PHMSA proposed also to obtain this
information on a standardized form, filed electronically with PHMSA.

Comments

    Many commenters objected to a change from the current requirement
for when a safety-related condition must be reported. Operators must
report safety-related conditions ``within five working days (not
including Saturday, Sunday, or Federal Holidays) after the day a
representative of the operator first determines that the condition
exists, but not later than 10 working days after the day a
representative of the operator discovers the condition.'' \2\ The
proposed language in the NPRM revised this to read ``* * * determines
or discovers * * *'' which commenters believed eliminated the current
distinction between five days after determination and ten days after
discovery of a condition.
---------------------------------------------------------------------------

    \2\ Sec. Sec.  191.25 and 195.56.
---------------------------------------------------------------------------

    SWGas and Paiute claimed that because safety-related conditions at
LNG facilities are rare, a reporting form is not needed. These
operators also asked that PHMSA describe how safety-related conditions
relate to the categories of leak, failure, and incident a lack of
common understanding affects the quality and consistency of reporting.
    With respect to offshore pipeline condition reports, Spectra
recommended not requiring reports for inspections that find no exposed
pipe. INGAA joined with Spectra in suggesting PHMSA require a report 60
days after identifying exposed pipe that poses a hazard to navigation.
El Paso and TransCanada similarly suggested treating these inspections
like incidents or IM inspections for reporting purposes (reporting
after an event or annually), as different criteria/timing for risk-
based inspections makes comparing data difficult.

Response

    After considering these comments and reevaluating our information
needs, PHMSA has decided to withdraw the proposed safety-related
condition report and associated changes to Sec. Sec.  191.25 and 195.56
at this time. PHMSA will continue to evaluate its needs and may, again,
propose changes to requirements for submitting safety-related condition
reports and the information to be included in such reports. The
proposed change to the timing for submission of safety-related
condition reports was an error. PHMSA has withdrawn the proposed
changes to these sections.
    Safety-related conditions are not similar to leaks, failures, and
incidents and do not fit into a hierarchy with these terms. Leaks,
failures, and incidents are instances in which a problem has occurred.
Safety-related conditions are conditions which make it more likely that
a failure will occur, and, therefore, require additional attention from
the operator and the safety regulator.
    The comments concerning underwater pipeline condition reports
highlighted an inconsistency in the current regulations that PHMSA had
not considered adequately. The requirements in Sec. Sec.  191.27 and
195.57 require reports 60 days after completion

of the inspection of all pipelines subject to Sec. Sec.  192.612(a) and
195.413(a) respectively, but the referenced sections do not require an
inspection of all pipelines at a specified period of time. Rather,
inspections are required to be done on appropriate periodic intervals,
which may vary for different pipelines for an individual operator.
Therefore, there might be no time where inspection of ``all'' pipelines
subject to the inspection requirements is completed, triggering the
reporting requirements of Sec. Sec.  191.27 and 195.57. Further,
Sec. Sec.  192.612(c) and 195.413(c) require prompt notification if an
underwater pipeline is found to be exposed. PHMSA is withdrawing the
changes proposed in the NPRM to Sec. Sec.  191.27 and 195.57. PHMSA is
also withdrawing the proposed forms related to these requirements.
PHMSA will consider the appropriate manner in which to address this
inconsistency and consider the comments received in this proceeding as
part of any future rulemaking.

(7) Merging the Gas Transmission IM Semi-Annual Performance Measures
Report with the Gas Transmission Operator Annual Reports

49 CFR 192.945 and 192.951

Proposal

    In the NPRM, PHMSA proposed to merge the gas transmission IM
Program semi-annual performance measure reports into an operator's
annual report. We also proposed changes to the annual report.
    The annual report has historically collected information on the
number of leaks from each of seven causes. The IM performance
requirements include the number of leaks, failures, and incidents from
each of nine causes. This difference was the basis for GAO's
recommendation in its report (GAO-06-946), ``Natural Gas Pipeline
Safety: Integrity Management Benefits Public Safety, but Consistency of
Performance Measure Should Be Improved'' that PHMSA make changes to
allow for optimal comparison of performance over time and make them
more consistent with other pipeline safety measures. PHMSA modified the
annual report to collect leak information for the same nine causes used
in collecting the IM performance measure.
    The gas transmission and gathering pipeline annual report is now
filed by state (i.e., an operator whose pipeline traverses multiple
states files one report for each such state). IM performance measures
have been reported semi-annually by program, i.e., one report covering
all pipelines within an IM program regardless of the state in which the
pipelines are located. The NPRM noted that one consequence of
integrating the IM performance measures into the annual report is that
these measures would now be required to be reported by state.

Comments

    AGA supported the changes to the annual report's cause categories
and generally supported integrating the IM performance measure report
with the annual report. AGA, joined by NWN, noted that this could cause
some difficulties for operators with IM programs that cover multiple
OPIDs, and who do not now separate IM results by individual OPID within
the common program. These operators suggested a means of referring to
data reported for the OPID under which a common IM program is managed
rather than requiring reporting for each individual OPID within the
program.
    While AGA agreed that IM performance measures should be reported
annually as part of the annual report, they disagreed that these
measures should be reported by state. They claimed that industry does
not now collect data on this basis and that the change will add
significant burden with no appreciable effect on safety.
    Geo Logic Environmental Services, LLC maintained that it would be
overly burdensome to integrate IM performance measures with the annual
report.

Response

    Operators must report IM data by OPID. PHMSA recognizes that some
operators manage common IM programs which include multiple OPIDs
representing different system assets. IM activities, however, are
conducted on individual pipeline segments (e.g., in the case of
assessments) or at individual locations along the pipeline (e.g., in
the case of repairs). Operators therefore have this data by OPID.
Analyzing data by individual OPID provides a better opportunity to
identify incipient problems. Operators with multiple OPIDs may have
accumulated them by acquiring other pipeline systems, and problems may
result from operation under the previous owner(s). Multiple OPIDs can
also represent different pipeline systems of differing vintage and
differing conditions. Prior treatment of pipelines by prior owners or
problems associated with aging or certain types of vintage materials
would be masked if IM information were reported at the common-program
level. The annual report form requires reporting of IM data by
individual OPID. At the same time, PHMSA needs to understand what OPIDs
are included in common programs so that it can plan IM inspections
appropriately and so that it can properly address any inspection
findings which result. This information will now be collected and
maintained as part of the National Registry of Pipeline and LNG
Operators.
    The issue of reporting IM information by state also affects
proposed changes to hazardous liquid pipeline annual reports and is
discussed below. The reporting burden is lessened, because reporting
will be required annually vs. semi-annually. PHMSA has included this
integration in this final rule.

(8) Modifying Hazardous Liquid Operator Telephonic Notification of
Accidents Reporting Requirement

49 CFR 195.52

Proposal

    In the NPRM, PHMSA proposed to require operators to have a
procedure to calculate and provide a reasonable initial estimate of
released product in telephonic reports to the NRC. PHMSA also proposed
to require operators to provide additional telephonic reports to the
NRC if significant new information becomes available during the
emergency response phase of a reported event. This proposal was based
in part on a recommendation from the NTSB that PHMSA modify 49 CFR
195.52 to require pipeline operators to have a procedure to calculate
and provide a reasonable initial estimate of released product in the
telephonic report to the NRC (NTSB Safety Recommendation P-07-07). NTSB
also recommended that the hazardous liquid regulations require pipeline
operators to provide an additional telephonic report to the NRC if
significant new information becomes available during the emergency
response (NTSB Safety Recommendation P-07-08).

Comments

    API, AOPL, TransCanada, and TPA noted that estimates made quickly
for immediate reports are subject to error. These commenters requested
that PHMSA include a provision holding an operator harmless for over-
or-under estimates in its initial reports. API, AOPL and TXOPA
recommended placing the requirement for a procedure to estimate release
volumes in Sec.  195.402, ``Procedural manual for operations,
maintenance, and emergencies'' rather than in the reporting
requirements of Sec.  195.52.
    TransCanada and TXOGA requested that PHMSA provide guidance on what
would constitute a significant change in information necessitating a
follow-up

report to NRC. API, AOPL, OKIPA, and TXOPA suggested revising the
regulatory text to limit the requirement for subsequent reports to
situations in which an operator has a reasonable basis for significant
revision of reported estimates. PST recommended requiring subsequent
reports to be submitted ``at the earliest practical moment'' as is now
required for initial reports.
    API and AOPL commented that there is no mechanism to amend or
rescind an NRC report and that one should be provided. TXOGA suggested
that original and subsequent reports be retained by PHMSA for
subsequent review and analysis.

Response

    PHMSA recognizes that estimates of release made quickly for
immediate reports are subject to error. Not all information can be
known immediately with accuracy. Calculations must be based on
assumptions, and those assumptions may not be correct. Still,
information is needed quickly to estimate the scope of a problem and
allow response by appropriate agencies/resources. This is why immediate
reports to NRC are required. Operators are expected to make their best
effort in making their initial estimates of release. Using a procedure
to make those estimates should help improve their accuracy by allowing
decisions concerning how estimates are to be calculated to be made
through deliberative pre-planning rather than in haste after a major
event. PHMSA has not modified this final rule to hold operators
harmless for incorrect estimates, but would exercise appropriate
discretion in any enforcement action that might result following an
event reported to NRC in which a good faith effort was made.
    Whether to place the requirement that operators have a procedure to
estimate releases in Sec. Sec.  195.402 or 195.52 is a matter of
preference. PHMSA can see how some might consider that this requirement
should be grouped with other requirements to have procedures. In the
NPRM, PHMSA chose to incorporate this requirement into the provision
requiring that reports be made to NRC, as recommended by NTSB. PHMSA
has retained that choice in this final rule.
    PHMSA does not agree that it is necessary to state in the
regulation that an additional report is required for new information
that provides a ``reasonable basis'' for modifying prior estimates. The
proposed rule already limited the requirement for subsequent reports to
instances in which ``significant'' new information becomes available.
The proposal did not require a supplemental report for ``any'' new
information. PHMSA considers that this qualifies the requirement
sufficiently to allow operators to use judgment in deciding whether new
information provides an appropriate basis for a supplemental report.
PHMSA previously published guidance concerning changes that would be
significant enough to justify a supplemental report to NRC. This
guidance may be found in Advisory Bulletin ADB-02-04, published in the
Federal Register on September 6, 2002 (67 FR 57060).
    Immediate reports are made to NRC, not to PHMSA. PHMSA has no
authority to change NRC processes, including establishing or changing
any mechanism to amend or rescind a report or governing which data will
be retained for subsequent analysis. Such changes are beyond the scope
of this proceeding. PHMSA understands that NRC's current practice is
not to remove reports from its database.

(9) Requiring Operators of Hazardous Liquid Pipelines to Report
Pipeline Information by State on the Annual Report for Hazardous Liquid
Pipelines

49 CFR 195.49

Proposal

    In the NPRM, PHMSA proposed to require operators of hazardous
liquid pipelines to submit certain infrastructure and IM data
separately for each state a pipeline traverses.

Comments

    API, AOPL, TXOPA, TPA, Spectra, and TransCanada objected to the
proposal to collect information by state. TransCanada would allow
collection of infrastructure data (e.g., miles of pipeline) on this
basis. These commenters noted that pipelines operate as systems and not
by state; therefore, operators have no business reason to collect data
on a by-state basis and do not currently do so. The commenters
contended that given that the elements to be reported cross state
lines, it would be unreasonably burdensome to require that the data be
collected on a by-state basis. API and AOPL contended that contrary to
the statement in the NPRM preamble which stated that the industry data
team generally supported collection of data by state, is inaccurate.
API and AOPL noted that in the 2004 rule that added the requirement for
the annual report PHMSA acknowledged in its response to comments that
mileage of hazardous liquid pipelines in each state is already
available in the NPMS and that it was examining additional enhancements
to NPMS that would allow collection of additional state-by-state
information without imposing additional burden on operators. API and
AOPL would limit collection of data by state to intrastate systems (for
which an annual report would generally address only one state). API and
AOPL claimed that the Regulatory Analysis supporting the NPRM was
neither reasonable nor reliable because it did not consider the
additional burden imposed by reporting information separately for each
state.
    OKIPA suggested that PHMSA obtain state based information from the
states exercising jurisdiction. PST supported obtaining additional
information on a by-state basis as this would increase PHMSA's ability
to oversee state pipeline regulatory activities.

Response

    This issue was discussed at some length during the Advisory
Committee meeting discussed below. At that meeting, PHMSA agreed that
it would be reasonable to roll up IM information nationally and to
limit by-state reporting in the annual report for gas transmission and
gathering pipelines and hazardous liquid pipelines, to infrastructure
information. The Committees supported that approach. PHMSA has modified
the proposed revision to the hazardous liquid pipeline annual report
form along these lines and has revised this final rule to require
reporting by state only for those parts of the form that indicate such
reporting is required. PHMSA acknowledges that some information is
available in NPMS by state, but all of the desired data is not. The
NPRM discussed the difficulties involved in changing NPMS and PHMSA's
uncertainty about each operator's ability to provide additional data
via that system. PHMSA concludes that obtaining this information
through NPMS is not practical at this time.
    It is not practical to obtain state information from the states, as
suggested by OKIPA. State reporting requirements vary. Additionally,
states only exercise jurisdiction over intrastate pipeline systems. The
only means to obtain consistent data for all pipelines is via a Federal
requirement.
    With respect to PST's suggestion that additional information by
state would help PHMSA oversee state pipeline safety regulatory
programs, PHMSA has the information it needs for this purpose. Some
information will be reported by state via the annual report, as
modified. PHMSA also obtains additional information directly from
states that it uses in its oversight of state programs.

(10) Removing/Revising Obsolete Provisions

49 CFR 191.19, 191.27, 195.57 and 195.62

Proposal

    In the NPRM, PHMSA proposed to remove or revise several provisions
in light of the proposal to require electronic submission of all
reports. These provisions were as follows:
     Remove Sec.  191.19, which advises operators they may
obtain, without charge, copies of paper report forms and reproduce the
forms.
     Remove Sec. Sec.  191.27(b) and 195.57(b), which require
mailing hard copies of Offshore Pipeline Condition reports.
     Revise Sec.  195.54 to remove the option to file an
accident report by facsimile.
     Remove Sec.  195.62, which requires operators to maintain
an adequate supply of forms that are a facsimile of DOT accident report
forms so that the operator may promptly report an accident.
    The NPRM also indicated that hard copies of forms would continue to
be available on PHMSA's Web site at http:[sol][sol]phmsa.dot.gov/
pipeline.
    PHMSA received no specific comments on these removals/revisions
and, therefore, we are adopting these removals/revisions as proposed.

(11) Updating OMB Control Numbers

49 CFR 191.21 and 195.63

Proposal

    In the NPRM, PHMSA proposed to update several sections to add new
OMB control numbers for the new forms (and information collection)
proposed in the NPRM.
    PHMSA received no public comments concerning these changes and have
adopted them as proposed.

IV. Comments on Forms

    In addition to comments concerning the proposed rule, PHMSA
received comments on the related forms.

Comments on the Annual Report for Gas Transmission and Gathering
Pipelines

Comments

    INGAA, API, AOPL, and TPA commented that reporting mileage to three
decimal places is more precise than is needed or justified. INGAA
suggested miles be reported to the nearest tenth. The other commenters
would report to the nearest mile.

Response

    PHMSA agrees that reporting of mileage to three decimal places is
unnecessary. At the same time, PHMSA notes that there are some
pipelines less than one mile in length and for which it would be
unclear whether zero or one should be reported if reporting were by
mile. PHMSA has revised the form to allow reporting to one decimal
place and has indicated that rounding to the nearest mile is allowed.
    The annual report describes the status of a pipeline at the end of
the reporting year and/or events that occurred during that year.
Gathering lines that become regulated during a year should be reported
as part of infrastructure on that year's annual report. Regulated
events (e.g., incidents) that occur during the year and following the
date on which the lines become regulated should also be reported.
Part A--Operator Information
    NAPSR would add CO2 to the list of commodities given that transport
of CO2 as a gas is likely to become more prevalent with forthcoming
carbon sequestration projects. SWGas and Paiute suggested defining
``assets,'' as used in Part A.
    INGAA and TPA recommended deleting the last boxes in question 8,
``does this report represent a change from last year's final reported
numbers for one or more of the following parts:'' They contended that
virtually all operators will experience one or more of these changes
and that the rare case where none of the boxes would be checked does
not warrant the inconvenience for others to respond. SWGas and Paiute
requested clarifying the scope of changes that would trigger a response
in question 8. NiSource commented that operators who experience no
changes should not have to complete the remainder of the form. NiSource
reads the form to indicate that operators with changes must complete
only those sections for which changes affect the reported data while
operators who do not experience any changes must complete the entire
form. TPA noted that spaces are needed for operator Headquarters' state
and zip code.

Response

    PHMSA recognizes that carbon sequestration projects are likely to
result in transport of carbon dioxide in gaseous form. At present,
however, PHMSA does not have jurisdiction to regulate transportation of
carbon dioxide as a gas. Legislative change would be required to
establish jurisdiction; therefore, PHMSA cannot accept NAPSR's
suggestion to add CO2 as a gas to the list of commodities
transported.
    PHMSA accepts that the term ``assets,'' could be confusing and has
replaced this term with ``pipelines'' and ``pipeline facilities,'' both
of which are defined in the regulations.
    PHMSA has revised Question 5 and the instructions to resolve
confusion concerning how to report IM data. IM data is to be reported
by individual OPID and not as part of a common program under one OPID,
as discussed above. The revised question simply asks whether the
pipelines and pipeline facilities under the OPID being reported are
under an IM program. If not, the form indicates which parts (i.e.,
those collecting IM-related data) the operator need not complete.
    PHMSA has revised question 8 in response to the comments on this
portion of the form and to comments made about a similar question on
the hazardous liquid pipeline annual report form. PHMSA has combined
the blocks operators would use to report changes due to mergers and
acquisitions, as suggested by API and AOPL, for the hazardous liquid
form because these two terms can be confused and there is no reason to
report the events separately. PHMSA has also revised question 8 to
indicate that operators who have experienced no changes need not
complete many sections of the form for which data would be identical to
that reported in the prior year. (Note that this is not applicable to
reporting for calendar year 2010 given that the data on this form will
be reported for the first time during that year). PHMSA concludes this
will reduce the reporting burden for operators who do not experience
changes to their pipeline systems. Operators who experience changes due
to any of the reasons listed in question 8 must complete the entire
form.
    PHMSA notes the confusion regarding the intent of question 8. In
particular, INGAA and TPA claimed the question was unnecessary because
virtually all operators would experience one of the listed changes
during any given year. PHMSA advises that simply experiencing such a
change does not lead to a ``yes'' answer to this question. Instead,
``yes'' indicates that the numbers reported on the prior year's form
have changed as a result of one of the listed events. PHMSA intends to
use the responses to this question to understand why data that was
reported changed for a given operator from year-to-year and to help
prioritize its inspection activities. In addition, eliminating the need
for operators who have not experienced changes that affect data
reported previously to report the same data again will improve data

quality by avoiding collection of inaccurate data due to data entry
errors. For example, operators who experience a modification to their
pipeline (one of the listed changes) but for whom that modification
results in no change to the numbers reported on the prior year's annual
report would answer ``no'' to question 8 and would not be required to
complete the bulk of the form (except for 2010). PHMSA has made
editorial changes to the form to emphasize this.
    PHMSA has made a number of other editorial corrections to the form,
including adding space for operator headquarters' state and zip code.
Part B--Transmission Pipeline HCA (High Consequence Area) Miles
    INGAA suggested deleting the number of offshore miles because there
are not enough miles of offshore transmission pipeline to make the data
pertinent.

Response

    PHMSA will require reporting of offshore HCA miles. Although there
may be few such miles, they do exist (e.g., an offshore platform that
includes a transmission line and is occupied by 20 or more persons).
Operators who have no offshore HCAs, which PHMSA recognizes will be
most operators, may enter zero in this field.
Part C--Volume Transported in Transmission Pipelines Only in Million
Standard Cubic Feet (mmscf)-Miles Per Year
    AGA contended that it would be unreasonably burdensome to report
volume transported. INGAA and Spectra maintained that because
transported gas does not necessarily traverse an entire pipeline
reporting volume-miles is impractical and PHMSA should use data already
collected by FERC. Atmos, TPA, SWGas, and Paiute commented that this
information does not appear relevant to pipeline safety and would be
difficult to collect, particularly for bi-directional pipelines. GPTC
and Nicor commented that this element is impractical for distribution
pipeline systems in which only a small portion of pipeline is defined
as transmission due to operating pressure. They noted that it is
impractical to determine how much gas flowed through these limited
portions of a pipeline system and questioned the safety need for the
information. NiSource and NWN also claimed that it is unclear why PHMSA
needs this information and that it may be proprietary or is already
available from FERC. TPA suggested that, if we retain this section, we
specify the reporting basis (e.g., standard temperature and pressure)
because some states (e.g., Texas) require reporting of volumes under
other pressure bases.

Response

    PHMSA recognizes that it is difficult to determine the amount of
gas transported, in mmscf-miles, for pipelines with multiple locations
at which gas can be collected and delivered. At the same time, an
indication of the total volume of gas transported will be useful data
for PHMSA's analysis of pipeline safety performance. Such information
can, for example, be used to normalize analyses of different events.
PHMSA has revised this part to require reporting of the total volume of
gas transported under the reporting OPID during the reporting year for
operators who do not operate their transmission lines as part of a
distribution pipeline system. PHMSA recognizes that this will not
accurately represent the volume carried in only portions of interstate
gas transmission systems, but PHMSA believes this strikes an
appropriate balance between the burden to calculate mmscf-miles and the
need for an overall measure of relative activity of different OPID
transmission volumes. PHMSA will use this information with care.
    PHMSA also recognizes that it would be particularly difficult for
operators of distribution pipeline systems in which only a portion of
the pipeline is classified as transmission to estimate the volume of
gas carried by their transmission pipelines. PHMSA has revised this
part to eliminate the need to report volume transported for operators
who operate transmission pipelines as part of a distribution pipeline
system. Volume information for these pipelines will be collected on the
distribution pipeline system annual report, which PHMSA is currently
revising.
    PHMSA notes that the proposed instructions for this part included a
definition of mmscf as million standard cubic feet and noted that
standard conditions are ``normally set at 60F and 14.7 psia.'' PHMSA
has deleted the word ``normally'' to make clearer that these are the
conditions at which volume is to be reported. PHMSA has also revised
the proposed instruction to reflect a pressure of 14.73 psia to be
consistent with how FERC describes standard conditions.
Part F--Integrity Inspections Conducted and Actions Taken Based on
Inspection
    INGAA commented that PHMSA should make clear that only testing
conducted as a result of IM requirements should be reported.
    AGA contended that PHMSA has not justified collecting more detailed
IM performance data. SWGas and Paiute claimed that PHMSA does not need
additional data to judge the adequacy of IM. National Grid does not
support reporting information beyond the number of immediate and
scheduled repairs in HCAs, because additional data would cause
confusion due to overlapping inspection techniques.
    Atmos and TPA commented that reporting the number of assessments by
tool type would overstate the mileage assessed compared with other
assessment types given that operators typically run multiple tools over
the same mileage as part of a complete assessment. AGA and NWN claimed
that collecting repair data by assessment technique would be burdensome
with no apparent safety benefit, and that information concerning
assessments conducted by method has no apparent safety value. INGAA,
GPTC, and NiSource recommended deleting questions concerning
inspections by tool type, contending that separate collection is
misleading, will lead to incorrect mileage totals, and is of marginal
value. INGAA also would limit miles inspected and actions taken for
hydrotests to HCA miles because that is the only area with consistent
repair criteria.
    Atmos and TPA also maintained that reporting the number of
conditions identified for repair by various assessment techniques,
particularly outside HCAs, will provide no useful information given
that there are no common criteria for when repairs are required. AGA
argued that repairs outside of HCA should not be reported because this
data serves no safety benefit and PHMSA has not justified collecting
this data. GPTC, NiSource, Nicor, NWN, Piedmont, and INGAA also
supported this position.
    AGA and NWN maintained it would be more useful to collect data on
anomalies identified by assessment cycle (e.g., baseline, first re-
assessment) rather than by tool.
    National Grid noted that because ``one year'' and ``scheduled''
conditions are the same under Sec.  192.933, both terms should not be
used. GPTC and Nicor would clarify that the number of anomalies within
HCAs (section 2c) should be the number repaired. AGA, GPTC, NWN, SWGas,
Paiute, NiSource, and Nicor suggested that consistent and more-detailed
definitions are needed for the terms leak, failure, incident, and
rupture if consistent reporting is to be achieved. They further
suggested PHMSA consider whether events of this type are to be reported
based only on IM

assessments or from all means by which they are identified. BG&E
suggested that PHMSA conform terms to their use elsewhere and
specifically use the terms ``immediate,'' ``scheduled,'' and
``monitored,'' as used in Subpart O of Part 192, to refer to anomalies
of concern under IM requirements.
    Sempra Energy Utilities (Sempra) recommended modifying this part to
allow an operator to reference another OPID for IM data. This would
accommodate situations in which IM activities are managed under a
common program for multiple OPIDs. NWN also noted that IM programs are
often run in common for multiple OPIDs making it difficult to break out
the data for individual OPIDs.
    GPTC noted that question 5b refers to in-line inspection (ILI) even
though the subject of question 5 is non-ILI techniques. NiSource would
delete Part F5, since it duplicates information collected elsewhere on
the form.

Response

    PHMSA does not understand completely why INGAA believes that only
testing conducted as a result of IM requirements should be included.
If, as INGAA suggested ``overtesting'' (i.e., testing of non-HCA miles
assessed as part of an IM inspection) were included, what would be
excluded for these segments? While the regulations establish maximum
reassessment intervals, they also require that operators base their
reassessment intervals on the identified threats, data from the last
assessment and data integration (Sec.  192.939). Assessments that are
conducted at shorter intervals than the maximums specified in the
regulations provide additional data that must be considered in data
integration and thus come under the provisions of IM regulations (see
the response to FAQ-70 on the gas integrity IM Web site, http://primis.phmsa.dot.gov/gasimp, for additional discussion). Therefore, all
testing on pipelines with HCAs must be reported.
    Assessments that are conducted on pipelines that do not contain any
HCAs are a different matter. Such pipelines are not covered by the IM
provisions of the regulations. Operators are not required to report
data for portions of these pipelines that they may assess for other
reasons. PHMSA will consider future regulatory changes to establish
requirements for reporting assessments and repair actions on pipeline
segments that do not include HCAs.
    Although PHMSA recognizes that there are no criteria in the
regulations for when anomalies outside of HCAs must be repaired, PHMSA
is aware that operators repair many anomalies outside of HCAs. PHMSA
considers it important to understand when such repairs are being made
and any trends (e.g., are the number of repairs increasing over time).
PHMSA recognizes that operators use different criteria for these
repairs and that the data must therefore be used with care. This does
not mean, however, that the data is not meaningful. Any data that is
indicative of the condition of U.S. pipelines has value in PHMSA's
analyses and decision making. PHMSA disagrees with INGAA's suggestion
that repairs performed as a result of hydrotests should only be
reported when they occur within HCA miles. Hydrotests identify defects,
by causing leakage or a rupture, which must be repaired and, therefore,
provide the most consistent ``criteria'' for repair of defects outside
HCAs of any assessment method.
    Similarly, collecting data by tool type and other assessment
methods will be useful in informing PHMSA decision making and in
improving PHMSA's understanding of the relative effectiveness and
extent of use of various assessment methods. PHMSA recognizes that
adding the miles assessed by different assessment methods provides a