Document ID: PHMSA-2008-0291-0048
Agency: phmsa
Document Type: Rule
Title: Pipeline Safety: Updates to Pipeline and Liquefied Natural Gas Reporting Requirements
Posted Date: 2010-11-26T05:00Z

[Federal Register Volume 75, Number 227 (Friday, November 26, 2010)]
[Rules and Regulations]
[Pages 72878-72908]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2010-29087]

[[Page 72877]]

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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  

[[Page 72878]]

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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 roger.little@dot.gov.

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

[[Page 72879]]

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.

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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,

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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

[[Page 72882]]

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.
---------------------------------------------------------------------------

    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,

[[Page 72883]]

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

[[Page 72884]]

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

[[Page 72885]]

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

[[Page 72886]]

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.

[[Page 72887]]

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

[[Page 72888]]

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

[[Page 72889]]

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

[[Page 72890]]

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

[[Page 72891]]

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

[[Page 72892]]

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.

[[Page 72893]]

(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

[[Page 72894]]

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

[[Page 72895]]

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 
result that appears to overstate the number of pipeline miles actually 
assessed. Adding miles does, however, provide a better indicator of the 
number of miles by assessment method. Again, PHMSA recognizes that the 
totals need to be used with caution. Still, it will be appropriate to 
use them for some purposes, while miles inspected using individual 
tools (also collected in this part) or total HCA miles (collected in 
Part B) will be more appropriate for other uses.
    PHMSA agrees that it could be more useful to collect data on the 
number of repairs in each assessment cycle. The effectiveness of IM 
regulations would be demonstrated by a reduced number in subsequent 
reassessments. PHMSA considers, however, that it would be more 
difficult to collect and use this data. New HCAs on pipelines 
previously assessed make it unclear how to differentiate between 
baseline and reassessment, for example. Given that operators now 
collect data per integrity assessment method trends in this data over 
time will better reflect the relative effectiveness of IM.
    PHMSA has been careful to use terms with meanings commonly 
understood within the pipeline industry. The terms ``leak,'' 
``failure,'' and ``incident'' are defined in the instructions 
consistent with ASME/ANSI B31.8S and with current regulations. PHMSA 
recognizes that these terms are used in other situations and will try 
to ensure consistent use on other forms. Use of the term ``scheduled'' 
to identify some IM anomalies is also consistent with the regulations 
and is not redundant with ``one-year conditions.'' Section 192.933(c) 
requires that operators schedule some anomalies for remediation 
consistent with the scheduling provisions of ASME/ANSI B31.8S, while 
Sec.  192.933(d)(2) identifies some specific anomalies as ``one-year 
conditions.'' PHMSA has revised the section references on the form 
(which both previously referred only to Sec.  192.933) to make this 
distinction more clear.
    PHMSA acknowledges that question 5 in Part F inaccurately referred 
to ILI inspections. This question is intended to address assessments by 
other techniques. PHMSA has corrected this error, which eliminates the 
duplication NiSource noted.
    We addressed above in the section on ``Creating a National Registry 
of Pipeline and LNG Operators'' comments about reporting IM data by 
individual OPID vs. under a common program.
Part G--Miles of HCA Baseline Assessments Completed
    INGAA suggested that this section be broken into separate sub-
sections for each reassessment. Atmos and TPA reported that they did 
not see how reporting assessments by vintage was useful. Spectra noted 
that HCA miles complicate the treatment of vintage given that an 
assessment by ILI often inspects more than just HCA mileage. A new HCA 
within a piggable segment, for example, may undergo a baseline 
assessment at the same time that other HCAs within the segment are 
being reassessed.

Response

    At this time, PHMSA agrees that collecting data on assessment 
vintage (i.e., first, second, etc.) is not necessary. PHMSA may revisit 
the need for this information as part of future activities. PHMSA has 
revised this part to collect data on the number of baseline miles 
completed and the number of reassessment miles (regardless of vintage). 
PHMSA expects that there will be a reduction in the number of anomalies 
identified in reassessments vs. initial baseline assessments, and needs 
this data to validate that expectation.

[[Page 72896]]

Part H--Miles of Pipe by Nominal Pipe Size
    INGAA noted that the proposed form does not allow reporting of odd 
pipe sizes. The form provides for reporting of even pipe sizes 
specified in modern standards, but INGAA noted that intermediate sizes 
may exist in older systems, particularly for grandfathered pipe. INGAA 
also noted that the largest pipe size included in the form is 36-inch 
diameter and pointed out that larger pipe is being used/planned for 
some gas transmission pipelines.

Response

    PHMSA acknowledges that odd pipe sizes may exist in some pipeline 
systems, including small diameter pipe (e.g., 5-inch diameter) and pipe 
installed in older pipeline systems before pipe sizing was 
standardized. PHMSA has modified the form and instructions to 
accommodate reporting of odd pipe sizes and to include sizes larger 
than 36-inch diameter.
Part J--Miles of Transmission Pipe by Specified Minimum Yield Strength
    AGA, NWN, SWGas, and Paiute commented that reporting pipeline 
mileage by specified minimum yield strength (SMYS) would be unduly 
burdensome because records are incomplete, grandfathered pipe may not 
fit into standard categories, and information technology (IT) changes 
would be needed to track mileage by SMYS. These commenters see no 
safety benefit in doing so. Atmos and TPA would also delete this 
section although they recognized there could be some benefit in 
reporting for pipelines operating under special permits or at 80% SMYS 
where special regulatory attention may be needed. They suggested that 
targeted reporting for these pipelines should be established rather 
than imposing an unjustified burden on all pipeline operators. TPA 
claimed that some operators of gathering pipelines treat all of their 
lines as Type A rather than determining the percentage of SMYS at which 
they operate and that it would be unreasonable to require operators to 
make this determination solely for this reporting.
    NiSource noted that no allowance is made for pipelines operating at 
an unknown percentage of SMYS even though the regulations allow 
operations without this determination. For example, Sec.  192.739 
provides for determining a pressure limit for pipeline operating at an 
unknown percentage of SMYS. NiSource also noted that plastic and iron 
pipe are excluded, even though some transmission pipe is constructed of 
these materials. NiSource also claimed that the information collected 
via Part J largely duplicates information from Part K, miles of pipe by 
class location.
    INGAA suggested that we eliminate blacked-out cells (implying that 
no pipeline should exist in that category) and noted that there is no 
offshore transmission pipeline that exceeds 72 percent SMYS.

Response

    PHMSA considers this data to be important. The thresholds dividing 
the various categories in the table reflect regulatory requirements 
(e.g., change in design factors) and PHMSA needs to have an 
understanding of the inventory of pipe to which these requirements 
apply. PHMSA notes that INGAA, which represents transmission pipeline 
operators who would tend to have pipeline across the range of allowable 
percentages of SMYS, did not object to reporting this data. Rather, AGA 
and some of its member companies expressed concerns. These companies 
generally operate distribution pipeline systems. While many of their 
systems include some transmission pipeline, the amount is relatively 
less and most tend to operate in the lower percentage SMYS categories. 
Thus, the burden for completing this section will be less for these 
companies.
    While the regulations establish design thresholds consistent with 
those in this part, existing pipelines do not always fit into these 
neat categories. Pipe that was installed prior to the time pipeline 
safety regulations were initially established (i.e., pre-1970) may 
operate at maximum allowable operating pressures (MAOP) based on 
historical operation prior to that date (so-called ``grandfathered 
pipe'') and this pressure is in some cases in excess of 72 percent 
SMYS. Some pipe operates under special permits that allow different 
MAOP. Some pipe operates at MAOP greater than originally designed due 
to changes in class location and the allowance for pressure increase 
that is inherent in Sec.  192.611. PHMSA is not persuaded by arguments 
that it is too hard for pipeline operators to acquire this data. 
Pipeline operators should acquire this data wherever possible because 
of its importance. Pipe operating at a higher percentage of SMYS has 
less safety margin. It is important that operators know where this pipe 
is and take this factor into account in the risk analyses required by 
IM regulations.
    For these reasons, PHMSA has retained this part. PHMSA has made 
changes in response to the other comments concerning this part. PHMSA 
has eliminated blacked out cells. As discussed above, grandfathering, 
special permits, and other circumstances could result in pipe operating 
at various combinations of MAOP and class location and PHMSA agrees it 
is more appropriate to allow for data collection in all categories. 
Operators with no pipe in individual categories will simply enter zero. 
The revised form allows for pipe that operates at an unknown percentage 
of SMYS and for pipelines other than steel. PHMSA has also deleted the 
row corresponding to offshore transmission pipeline with MAOP greater 
than 72 percent SMYS.
    The information collected in this part does not duplicate that in 
Part K. PHMSA agrees that the information in the two parts is related. 
Important information will be obtained through analyses that compare 
the information obtained in each of these parts. This will help PHMSA 
understand, for example, the amount of pipe that operates at MAOP 
higher than initial design due to the automatic-increase provisions in 
Sec.  192.611. It is necessary to collect the data in both parts to 
allow this kind of correlation to be made.
    Part J applies to transmission pipeline. Operators of gathering 
lines need not complete Part J.
Part K--Miles of Pipe by Class Location
    SWGas and Paiute commented that this section appears to replicate 
Part B insofar as it relates to miles in HCA. They claimed it could be 
confusing to report miles that are not in an HCA but which must be 
inspected anyway under the IM program.
    SWGas recommended that we exempt distribution pipeline operators 
that also report on transmission pipeline they operate. Many 
distribution operators treat all of their pipeline as Class 3 or 4 and 
do not perform analyses to determine accurately the class location of 
their transmission pipeline. SWGas opposed requiring such analyses 
solely to meet this reporting requirement.

Response

    PHMSA agrees that reporting HCA miles in the IM program in this 
part duplicates Part B and has eliminated this section of Part K.
    This part does not require that operators perform Class location 
studies if they do not do so for other purposes. Operators of 
distribution pipeline that treat all of their pipeline as Class 3 or 4 
should report the mileage that they consider to be in each Class.

[[Page 72897]]

Part L1--Leaks Eliminated/Repaired During Year and Failures/Incidents 
in HCA
    Atmos, NWN, and TPA requested clarification as to whether leaks 
repaired in IM assessments and reported in Part F are also to be 
reported in this part.
    Nicor and NWN suggested reorganizing the columns for failure, leak, 
and incident data in order of severity to provide clarity and help 
assure consistent reporting. AGA noted that the failure category was 
omitted for gathering pipelines.
    NAPSR suggested adding a column for unregulated gathering lines, as 
they consider that data should be collected for all gathering lines.

Response

    Operators are to report all leaks both in HCAs and outside HCAs. 
Failures and incidents are to be reported for HCAs. This is an existing 
performance measure required by Sec.  192.945 (through reference to 
ASME/ANSI B31.8S) that has been reported on semi-annual performance 
measure reports.
    PHMSA agrees that reordering the columns in order of relative 
severity could improve clarity and has made that change.
    While PHMSA agrees with NAPSR that it would be beneficial to have 
data for unregulated gathering lines, such lines are by definition 
unregulated. PHMSA cannot impose a reporting requirement on these 
pipelines without a regulatory change. Such changes are beyond the 
scope of this rulemaking.
Part N--Certifying Signature
    Atmos and TPA suggested that a separate signature block be used to 
certify IM information because the proposed form implies certification 
of the entire form, which is not required. INGAA noted that the 
references to the parts of the form containing IM information, and for 
which certification is required, were incorrect.

Response

    PHMSA has revised the form to make it clearer that executive 
certification applies only to IM information. PHMSA will also clarify 
this in the on-line electronic reporting system.
Instructions
    Atmos and TPA commented that the instructions need to reflect 
electronic reporting and address the requirements for seeking alternate 
reporting methods.
    TPA suggested that the instructions define interstate pipelines as 
those to subject to FERC jurisdiction ``under the Natural Gas Act'' 
rather than simply ``subject to FERC jurisdiction,'' noting that some 
intrastate pipelines are subject to limited FERC jurisdiction.
    NAPSR suggested defining synthetic gas. NAPSR also suggested 
clarifying the instructions on counting repaired leaks. For example, if 
a section of pipe with leaks is replaced, does PHMSA consider that one 
repair or must the number of leaks within the section be reported?
    SWGas and Paiute contended that the definition of operator in the 
instructions is inconsistent with the definition in the regulations in 
that it introduces the term ``substantial control.''
    INGAA suggested that the instructions for Part F, Question 4 should 
refer to ``meeting repair criteria'' rather than ``exceeding.'' INGAA 
also suggested that the instructions for Part G should mirror those for 
Part F.
    SWGas and Paiute suggested that the instructions for Part J clarify 
reporting for pipe that is classified as transmission under the 
functional aspects of the regulatory definition even though it operates 
at less than 20% SMYS.

Response

    PHMSA has revised the instructions to address requirements for 
applying for alternate methods (i.e., non-electronic) of data 
submission and to use the statutory definition of interstate pipeline 
from 49 USC 60101. PHMSA has included a definition of synthetic gas 
that is consistent with the definition in the instructions for the new 
incident report form. PHMSA has also reviewed and revised all 
definitions to be consistent with regulations.
    Counting leaks has always been problematic. As NAPSR pointed out, 
when a section of pipe is replaced due to leakage, an operator could 
count the repair as one repair or as the number of leaks in the 
replaced section. When replaced pipe is retired in place, it may not be 
possible to count the number of leaks. Operators have previously been 
required to report the number of leaks repaired as part of their annual 
reports. Operators should report the number of leaks repaired based on 
the best data they have available. For sections replaced, but retired 
in place, operators should consider leak survey information to 
determine, to the extent practical, the number of leaks in the replaced 
section.
    PHMSA has made editorial changes concerning repair of anomalies 
``meeting'' repair criteria. INGAA's suggestion that the instructions 
for Part G mirror those for Part F was predicated on its recommended 
expansion of Part G so that the parts would be similar in content. As 
discussed above, this change is not necessary because we have 
simplified Part G to reflect only baseline and reassessment miles, 
regardless of vintage.
    PHMSA does not understand the basis for confusion over whether Part 
J should apply to transmission pipelines operating at less than 20 
percent SMYS. The proposed part explicitly included a section in the 
form for pipeline operating at less than or equal to 20 percent SMYS. 
Nevertheless, PHMSA has clarified in the instructions that Part J 
applies to all transmission pipeline.

Comments on the Annual Report for Hazardous Liquid Pipelines

General Comments
    API and AOPL commented that mileage should be reported to the 
nearest mile rather than to three decimal places citing a lack of need 
or justification for the proposed level of precision. API and AOPL also 
commented that reporting by state should be limited to infrastructure 
data (e.g., miles by state) and that by-state reporting of IM data 
should be required for intrastate pipelines only because interstate 
hazardous liquid pipelines are operated as systems and operators do not 
keep or track data by state. They noted that reporting all data by 
state would be a significant increase in burden with no corresponding 
increase in safety.

Response

    PHMSA agrees that reporting of mileage to three decimal places is 
unnecessary yet notes that for those pipelines less than one mile in 
length 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.
    PHMSA also agrees that reporting all IM data by state is 
unnecessary. PHMSA has revised the form and instructions to require 
that IM data be reported once for all interstate pipelines under an 
OPID. We will continue to require data for intrastate pipelines to be 
reported by state.
Part A--Operator Information
    API and AOPL submitted a number of comments on this part. They 
recommended that PHMSA--
     Make explicit the implication in the first box of question 
5 that lines that cannot affect an HCA need not be in an IM program.
     Clarify question 5 regarding how information for companies 
under a common IM program is to be collected. Specifically, they 
contended that

[[Page 72898]]

operators of pipelines that are under a common program should not be 
required to be report data that will be reported for the OPID under 
which the common program is managed.
     Delete question 7, which asks operators to list the states 
in which their inter- and intrastate pipelines are located, since this 
duplicates information collected elsewhere on the form.
     Combine the first two sub-blocks of Question 8, Part 3 
because mergers and acquisitions can be confused.
     Revise question 4 to add space for state and zip code.

Response

    PHMSA has revised Question 5 but has not accepted all of the 
suggestions. While in most cases pipelines that cannot affect an HCA 
are not in an IM program, that is not universally true. Some pipelines 
that cannot affect HCAs are covered by an IM program as a result of 
special requirements imposed by compliance orders or as conditions of a 
special permit, for example. PHMSA expects IM data for these pipelines 
to be reported as part of the annual report. IM data is to be reported 
by individual OPID and not as part of a common program, as discussed 
above. PHMSA has revised question 5 and the instructions to make this 
clear. 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), need not be completed.
    PHMSA has revised question 6. Although we received no comments on 
this question, review of the form to address other comments revealed 
that PHMSA had omitted biofuels/ethanol as a commodity type. On August 
10, 2007, PHMSA published in the Federal Register (72 FR 45002) a 
determination that transport of unblended biofuels by pipeline is under 
its jurisdiction and has previously revised the accident report form 
(PHMSA F 7000-1) to include this commodity type. Operators would select 
this commodity type in question 6 for pipelines that predominantly 
carry unblended biofuels. Transportation of biofuels blended with 
refined petroleum products would be reported as Petroleum Products/
Refined Products. PHMSA is aware of only a limited number of miles of 
U.S. pipelines in Florida and Texas that currently transport unblended 
biofuels, but notes that some operators have expressed an interest in 
constructing such pipelines.
    PHMSA has retained question 7. There is little burden associated 
with answering these questions given that operators are aware of the 
states in which their pipelines are located. Answering this question in 
Part A helps position the operator to complete the remainder of the 
form. The answer also provides an opportunity for PHMSA to cross-check 
that necessary data is, indeed, reported for all appropriate states as 
part of its ongoing efforts to assure data quality.
    PHMSA has revised question 8 in response to the API and AOPL 
comment and to comments made with regard to a similar question on the 
gas transmission and gathering pipeline annual report form. PHMSA has 
combined the blocks operators would use to report changes due to 
mergers and acquisitions 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 on this form for calendar year 2010 
because the data will be reported for the first time during that year). 
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.
    There has been some confusion regarding the intent of question 8. 
In particular, comments submitted with respect to the gas transmission 
and gathering pipeline annual report form suggested that the question 
was unnecessary because virtually all operators would experience one of 
the listed changes during any given year. In response, PHMSA notes 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 reported data changes for a given operator from year-to-
year and to help prioritize its inspection activities. In addition, by 
eliminating the requirement 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 have to complete the bulk of the form (except for the reporting of 
calendar year 2010 data). PHMSA has made editorial changes to the form 
to emphasize this.
    PHMSA has also changed the form to allow state and zip code 
information to be entered for the operator headquarters' address.
Part C--Volume Transported in Barrel-Miles
    API and AOPL recommended allowing reporting for more than one 
commodity, adding columns for crude oil, refined products, HVL, and 
CO2. They maintained that these changes would return to the 
intent of the current form.

Response

    PHMSA had revised this part of the form to reflect the requirement 
that operators must file separate annual reports for each pipeline 
carrying a different commodity type. PHMSA recognizes that the operator 
files only one annual report for each pipeline system based on the 
commodity predominantly carried. PHMSA has restored the option to 
report volume for all commodities, as suggested by API and AOPL, thus 
eliminating the possibility of double reporting mileage of batched 
systems.
Part D--Miles of Pipe by Corrosion Protection and
Part H--Miles of Pipe by Nominal Pipe Size
    API and AOPL suggested that we revise the titles of these parts to 
explicitly apply to steel pipe.

Response

    Corrosion prevention, the subject of Part D, only applies to steel 
pipe and PHMSA has revised the title of this part accordingly. Part H 
applies to all pipe. PHMSA recognizes that most pipe in hazardous 
liquid pipeline systems is steel, nevertheless, there is some non-steel 
pipe in some systems. PHMSA has not revised the title of Part H and 
expects operators to report this data for all pipe materials.
Part F--Integrity Inspections Conducted and Actions Taken Based on 
Inspection
    API and AOPL suggested a number of changes for this part:
     Refer to ``could affect an HCA'' vs. ``HCA affecting.'' 
The former is defined in the regulations while the latter is not.

[[Page 72899]]

     Refer to ``anomalies repaired'' vs. ``conditions 
repaired'' for consistency with the Plastic Pipe Data Committee 
reporting. They would have the instructions refer to API RP 1163 for a 
definition of ``anomaly.''
     Clarify that repairs are to be reported for the year in 
which the repair is made rather than the year in which an assessment 
was conducted.
     Add actions (e.g., repairs) for ruptures that occur during 
pressure tests.
     Add an option to question 1 for a combination ILI tool, 
since use of combination tools is becoming more prevalent.
     Clarify that the state identifier is required only for 
intrastate pipelines.

Response

    PHMSA agrees it is better to use terms defined in the regulations, 
and has revised the form to use ``could affect an HCA'' rather than 
``HCA affecting.''
    The regulations refer to repairs that must be made following IM 
assessments as ``conditions'' (i.e., immediate repair conditions, 60-
day conditions, 180-day conditions). PHMSA has retained use of this 
term for those elements of questions in Part F that refer to repairs 
made that are required by the rule. PHMSA has revised the form to use 
the term ``anomaly'' for those elements that refer to repairs made as a 
result of an operator's criteria, which may be different than those in 
the rule. PHMSA has not adopted the suggestion to refer to API RP 1163 
for the definition of anomaly. API RP 1163 is not currently 
incorporated by reference into the Code of Federal Regulations. 
Further, PHMSA considers it more important to understand anomalies that 
operators determine require repair. Operators may use the definition in 
API RP 1163 or they may use a different definition. Data concerning the 
number of repairs made as a result of operator-defined repair criteria 
should be reported in terms of the number of repairs actually made, 
regardless of a formal definition of the term ``anomaly.''
    PHMSA has clarified that data to be reported for pressure test 
ruptures should reflect the number of repairs made. PHMSA has also 
revised the header for Part F to clarify that the state identifier is 
only applicable to intrastate pipeline systems.
    PHMSA has not modified the list of tool types to include a 
combination tool. PHMSA recognizes that combination tools are becoming 
more common. When using such a tool, an operator is inspecting its 
pipeline using each of the tools included in the combination, and the 
number of miles inspected should be reported for each of those tool 
types. Reporting the data once for a ``combination'' tool would confuse 
the data concerning the prevalence of different ILI inspection methods.
Part G--Miles of Baseline Assessments and Reassessments Completed (HCA-
Affecting Segment Miles Only)
    API and AOPL would delete this part because the baseline period is 
over for all pipelines and collecting assessments by vintage would add 
confusion while adding no useful information. They further commented 
that PHMSA should clarify that the state identifier is only required 
for intrastate pipelines, if PHMSA retains this part.

Response

    PHMSA has not deleted this part. Contrary to API's and AOPL's 
assertion, the baseline period is not over for all pipelines. The 
baseline period is still running for rural low-stress pipelines 
recently made subject to Part 195, for example. New baseline 
assessments can also be expected as a result of new HCAs and new 
pipelines. PHMSA has revised this part to require data for baseline 
assessments and reassessments and has eliminated the need to report 
mileage by the vintage of reassessment (e.g., first, second). PHMSA 
agrees that this could be confusing, particularly when new HCAs develop 
near pipelines already assessed. PHMSA expects that data will show a 
significant drop in the number of conditions requiring repair as a 
result of reassessments compared to baseline assessments but does not 
expect the same trend between reassessments.
    PHMSA has clarified that the state identifier is only required for 
intrastate pipeline systems.
Part J--Miles of Pipe by Specified Minimum Yield Strength
    API and AOPL would limit this part to a report of pipe above or 
below 20% SMYS because the additional categories are of limited use.

Response

    PHMSA has retained the proposed breakdown for this part. There are 
few categories in addition to the two suggested by API-AOPL (i.e., 
above and below 20 percent SMYS). The limited additional data required 
addresses non-steel pipe. Pipeline operators should acquire this data 
wherever possible. This data is important to pipeline operators so that 
they know where this pipe is and take it into account in the risk 
analyses required by IM regulations.
    PHMSA has also modified this part to include rural low-stress 
pipelines not generally subject to the safety requirements of Part 195. 
Section 195.48, added by rulemaking on June 3, 2008 (73 FR 31634), 
imposed the reporting requirements of Subpart B, including the 
requirement to submit annual reports, on operators of these pipelines. 
These reporting requirements were necessary so that PHMSA could collect 
data for the second phase of its rulemaking addressing rural low-stress 
pipelines. The data must be segregated so that it can be used for this 
purpose. The changes to Part J accommodate reporting by these new 
reporting operators and PHMSA's data needs.
Part K--Miles of Regulated Gathering Lines
    API and AOPL would clarify that the first row in this part requires 
reporting of pipelines less than ``or equal to'' 20% SMYS. They would 
also delete the row for non-steel pipe operating at greater than 125 
psi, since non-steel pipe is not allowed in hazardous liquid pipeline 
systems.

Response

    PHMSA agrees that the first row should be ``less than or equal to'' 
20% SMYS to be consistent with the definition of regulated gathering 
lines and has revised the form accordingly. PHMSA has not deleted 
reference to non-steel pipeline operating above 125 psi. The 
regulations acknowledge that some pipe of this type may exist within 
gathering pipeline systems (see 195.11(a)(3)(ii)).
Part L--HCA-Affecting Segment Miles of Pipe by Type of HCA
    API and AOPL recommended revising this part to report the total 
onshore and offshore HCA miles and not miles by HCA type. API and AOPL 
contended that operators do not keep data on mileage by HCA type given 
that all types are treated the same within an IM program.

Response

    PHMSA considers that the mileage of pipeline that could affect HCAs 
of various types is important to its ability to analyze risks. PHMSA 
also considers that this data should have value for operators 
performing risk analyses required by IM requirements. PHMSA has 
retained this part as proposed.
Part M--Breakout Tanks
    API and AOPL requested that we revise this part to allow operators 
to alternatively report information on breakout tanks to either to the 
NPMS or on the annual report.

[[Page 72900]]

Response

    We considered the past practice of allowing the option of filing 
breakout tank information via either the annual report or via the NPMS 
and determined that this option causes potential ambiguities in the 
data. Accordingly, we are eliminating the option to file this 
information via NPMS.
Instructions
    API and AOPL noted that the instructions need to address electronic 
filing and the process for applying for alternate reporting methods. 
API and AOPL also suggested that the instructions refer to Appendix A 
of Part 195 for examples of inter- and intra-state pipelines and that 
the definitions in the instructions be made consistent with those used 
for accident report forms.
    The instructions for Part G instruct reporting parties to compare 
the total completed and scheduled assessment mileage to the mileage 
reported in Part B, to identify any discrepancies, and to submit 
corrections via a supplemental report, as needed. API and AOPL 
contended that this could be interpreted to require correction of data 
reported in prior years based on current-year data. API and AOPL 
requested that PHMSA clarify its intent because this could misrepresent 
the IM data collected for prior years.

Response

    PHMSA has revised the instructions to address the requirements to 
apply for non-electronic filing and to refer to Appendix A to Part 195 
for further information on determining inter- and intrastate pipeline 
systems.
    PHMSA has also clarified the instructions for Part G to explain 
that supplemental reports should not be submitted for prior years based 
on current-year data. Errors in prior year reporting that may be 
identified as a result of collecting and reviewing data for a new 
annual report should be addressed by submitting a supplemental report 
for the appropriate year.

Comments on the Safety-Related Condition Form

General Comment
    NiSource suggested revising the form to allow for supplemental 
reports to address resolution of a condition or correction of 
previously-reported information.
Part C--Condition Information
    Atmos and TPA noted that reporting the location of a condition by 
street address is not always appropriate and that other means of 
reporting conditions in rural areas should be provided. IUB agreed, 
noting that determining location by government land survey system 
(e.g., township, section, range) is often most practical in the 
Midwest. Spectra commented that a single-point location is often 
inadequate to define the location of a condition that extends over some 
portion of a pipeline and suggested defining the location as the center 
of the condition or allowing for designation of endpoints.
Part D--Description of Condition
    Atmos noted that a space is needed to report the percent blend for 
biofuels, as specified in the instructions. NAPSR suggested that 
CO2 transported as a gas be added as a commodity transported 
in light of forthcoming carbon sequestration projects.
Instructions
    Atmos commented that the instructions need to address electronic 
reporting and the requirements to apply for alternate reporting 
methods. Atmos and TPA also noted that the proposed instructions do not 
correlate to the proposed form, sections are in different order, and 
the instructions contain references that do not match the form. NAPSR 
requested that the instructions define synthetic gas.

Response

    After considering these comments and evaluating its own information 
needs, PHMSA has decided to withdraw the proposed safety-related 
condition report and associated changes to Sec. Sec.  191.25 and 
195.56. 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.

Comments on LNG Annual Report Form

General Comments
    AGA, NiSource, INGAA, and Southern LNG (SLNG) commented that much 
of the data that would be reported on this form duplicates data 
currently submitted semi-annually to FERC, to the U.S. Coast Guard 
(USCG), or to PHMSA as a result of incidents. MidAmerican noted that 
terminology is inconsistent between this form and the LNG incident 
report form. MidAmerican also cautioned that ``incidents'' should not 
be referred to as ``events.'' BG&E contended that this information is 
unnecessary given that LNG facilities are static and do not expand or 
change over time as do pipelines.
Part B--System Description
    MidAmerican questioned the relationship of information across a 
given row of this part. They noted that plants can be installed on 
different dates, in different states, and can have significantly 
different storage capacities. MidAmerican also noted that this part of 
the proposed form included an apparent formatting error in that lines 
denoting rows in the table do not extend across all columns.
Part C--Releases in Past Year From Incidents and Safety-Related 
Conditions
    BG&E contended that PHMSA should not collect this information on 
annual reports because some of it relates to economic issues (e.g., 
insulation performance), rather than to safety issues. BG&E recommended 
that information related to incidents should be collected via the 
incident report form rather than annually. MidAmerican suggested we 
reformat this part because it is difficult to follow for operators 
trying to categorize releases by cause.
Part D--Other Events
    AGA, NEGas and NWN recommended deleting this part. These commenters 
noted that other events are, by definition, not incidents. At most they 
are ``near miss'' events of limited relationship to safety and about 
which it will be difficult to collect consistent data. MidAmerican, 
NWN, and DOMAC cautioned that events reported on incident reports 
should not be reported again on this form, contending that summaries 
prepared for a different form at a different time are almost certain to 
result in confusion and apparent inconsistencies. MidAmerican, SWGas, 
and Paiute noted that this part is vague and needs clarification; they 
commented that several of the listed events appear to be subsets of 
emergency shutdown. NiSource and DOMAC recommended deleting rollovers 
and security breaches because these are not safety-significant events. 
MidAmerican maintained that both terms require better definition, 
noting that LNG is in constant rollover in tanks due to thermal 
gradients and suggesting that false activations of security systems/
detectors should not be included as security breaches.
Instructions
    TPA noted that the instructions need to address electronic filing 
and the requirements to apply for alternate reporting methods.

Response

    Many LNG facilities under PHMSA jurisdiction do not fall under the

[[Page 72901]]

jurisdiction of either FERC or USCG and do not report to those 
agencies. PHMSA thus cannot rely on data reported to those agencies for 
a complete understanding of the LNG facilities for which it is 
responsible. PHMSA understands that LNG facilities experience less 
year-to-year change than do pipeline facilities and that it would be an 
unnecessary burden for LNG facility operators to report the same data 
on consecutive year's forms. PHMSA has revised the LNG annual report 
form so that operators may report there has been no change from the 
data reported in the prior year. In that event, operators need not 
complete the remainder of the form.
    PHMSA agrees that there was a formatting error in Part B of the 
form that was posted in the docket for comment. Lines denoting rows 
within this part should have extended across all columns, but did not. 
PHMSA has revised the format of Part B to improve clarity. PHMSA 
considers that this change also resolves the apparent confusion about 
reporting of dates, locations, capacities, etc., as these now clearly 
relate to individual facilities.
    PHMSA has also revised the final form to change the formatting of 
Parts C and D. As proposed, these parts were in parallel columns, which 
appear to have caused confusion. In the revised form, these parts each 
extend across the entire form, which improves clarity. PHMSA does not 
agree that events to be reported in Part C (e.g., insulation 
performance) are solely economic issues with no safety significance. 
Events to be reported in Part C are releases of gas or LNG that result 
from these causes. Releases may have safety significance and are 
appropriately of interest to PHMSA.
    PHMSA agrees that events that have been reported as incidents 
should not be reported again on the annual report, and has revised Part 
D to eliminate categories that duplicate reportable incidents. PHMSA 
does not agree, however, that Part D should be deleted because none of 
the events is of safety significance. The remaining events do not reach 
the threshold of reporting as incidents or safety-related conditions, 
but do represent safety issues. They include, for example, situations 
that would have been reported as safety-related conditions had they not 
been corrected before the report of such a condition was required. (The 
safety significance of the conditions is the same as safety-related 
conditions. The only difference is time to repair). It is important to 
trend these safety events. Though individually of less significance, 
trends in their occurrence could reveal safety problems requiring 
additional regulatory attention. PHMSA has retained ``rollover'' as an 
event to be reported in Part D. PHMSA disagrees that LNG is in constant 
rollover. PHMSA agrees that blending and mixing routinely occur within 
LNG tanks, but this does not constitute rollover. Rollover is a term 
commonly understood within the LNG industry to refer to an event in 
which significant stratification has occurred within a tank and, as a 
result, significant quantities of liquefied gas suddenly relocate due 
to differences in density. Rollovers have resulted in damage to storage 
facilities and are safety significant events for LNG carriers and their 
unloading operations at import terminals. PHMSA recognizes that 
improved designs have significantly reduced the frequency of rollover 
occurrence, but considers events that do occur to be significant and to 
require reporting. PHMSA has also retained security breaches as an 
element to be reported in Part D. PHMSA does not consider it necessary 
to explicitly exclude false activations of security systems given that 
element to be reported is an actual breach rather than any activation 
of a security alarm system.
    PHMSA has revised the instructions to reflect the requirements to 
apply for an alternate (i.e., non-electronic) reporting method.

Comments on the LNG Incident Report Form

Terminology
    AGA, NWN, and NEGas noted that some terms used are not applicable 
to LNG operations but seem, rather, to be associated with pipelines 
(e.g., rupture of previously damaged pipe).

Response

    PHMSA has revised the form and instructions to more accurately 
refer to LNG facilities and assure that requested elements are relevant 
to LNG.
Part B--System Description
    DOMAC recommended that the on-line reporting system automatically 
populate this information with the operator having an opportunity to 
override or change as needed, and that information being collected for 
the OPID Registry should make this practical. BG&E commented that 
operational information is of limited relevance for incidents and 
suggested deleting this part.

Response

    PHMSA is not deleting this part. PHMSA agrees that information in 
the OPID Registry and reported on annual reports should allow this part 
to be automatically populated when operators complete an incident 
report form electronically. We will configure the on-line system to do 
so. At the same time, some information may change and not yet have been 
reported to the Registry or NPMS. For example, the status of a facility 
may change. A mobile facility's location may be different than 
originally reported. For OPIDs with multiple LNG facilities, the 
electronic system will be unable to identify the particular facility 
involved in the incident and will populate data for all facilities. The 
electronic system will thus afford operators the opportunity to change 
information that is automatically populated, including deleting 
information for facilities not involved in the incident. This practice 
will minimize the burden for completing this information, which could 
prove useful in understanding and following up on incidents.
Part C--Consequences
    DOMAC suggested revising the form to accommodate the possible 
situation that no evacuation was necessary and that the area was not 
unsafe, in which case there would be no elapsed time to make the area 
safe.

Response

    PHMSA has revised the form to replace the question concerning 
elapsed time until the area was made safe to one asking for a timeline 
of the incident. This avoids the implication that the situation was 
``unsafe.'' PHMSA has retained reporting for evacuations. We have 
revised the instructions to require that operators complete this 
information based on their own knowledge or based on reports by police, 
fire or other emergency responder. If no evacuation was needed, 
operators enter zero. If an estimate is not possible, operators are 
requested to describe why in the narrative portion of the form. 
Evacuation information is collected in this same manner for pipeline 
incidents.
Part D--Origin of Gas Leak/Problem
    DOMAC suggested that ``gas leak'' be replaced with ``release,'' 
noting that a release may have been in liquid form. BG&E recommended 
deleting questions related to distributed control systems (DCS), since 
such systems are not required, the information is of limited value, and 
it will be burdensome to collect. DOMAC agreed that information 
concerning DCS systems would be of limited value, noting that such 
systems do not detect all hazards (e.g., fire).
    TPA commented that the list in question 1 of gases potentially 
involved

[[Page 72902]]

is unnecessary given that the form is intended for LNG facilities only.
    DOMAC suggested revising the title of question 2 in this part from 
``leak detection'' to ``hazard detection.'' DOMAC also suggested 
reorganizing the form to place this part before Part C; since an 
incident begins with a release it would be logical to begin data 
collection with the origin of the release rather than its consequences.

Response

    PHMSA does not agree that references to DCS should be deleted. 
PHMSA has revised this part to address ``computerized control 
systems,'' encompassing computer-based control systems that may be 
referred to by terms other than DCS. PHMSA recognizes that computerized 
control systems are not required to be installed in LNG facilities, but 
also notes that many facilities use such systems. It is important for 
PHMSA to understand how useful these systems are in identifying 
incidents. The information required for computerized control systems is 
very limited--whether one was in place and whether it initially 
detected the event--and thus not burdensome to report.
    PHMSA has retained the list of gases in question D1. The list 
simply asks whether the incident originated with natural gas, LNG or 
``other flammable gas.'' Other gases are used in liquefaction processes 
and could be the origin of events that escalate to incidents. The 
definition of an incident in Sec.  191.3 refers to events resulting in 
reportable consequences due to a release of ``refrigerant gas,'' which 
may include other flammable gases.
    PHMSA has not re-ordered the form to put Part D before Part C. 
While it is true that most incidents involve a release, the definition 
also includes emergency shutdowns and events that the operator 
considers significant even though they do not meet the other specified 
criteria. These other significant events may not involve a release 
(e.g., security breach). Part C reports consequences, which is why the 
event constituted an incident in the first place. PHMSA considers that 
the order of these sections is appropriate.
Part E--Suspected Causes
    DOMAC commented that this part appears to be taken from a pipeline 
context and does not fit the LNG environment.

Response

    We have revised this part to be more applicable to the LNG 
environment.
Instructions
    DOMAC noted that the instructions refer to Part 192 vs. Part 193 
and will require significant revision. TPA suggested that the 
instructions for Part D, question 2, refer to ``how was the release 
detected'' instead of ``where the leak/problem occurred.'' TPA also 
noted that the instructions need to address the requirements for 
reporting by methods other than electronic reporting.

Response

    PHMSA has revised the instructions to be consistent with the form 
as modified. The instructions include an explanation of how an operator 
must apply to use alternate reporting methods. PHMSA notes its strong 
preference for electronic reporting, which will be the required method 
for all reports addressed in this rule. Allowance is made for 
alternative methods when operators demonstrate that electronic 
reporting involves undue burden. PHMSA will review requests for use of 
alternate methods critically to assure that electronic reporting would 
be truly burdensome before approving an alternative.

Comments on Offshore Pipeline Condition Report Form

    API and AOPL noted that the form does not accommodate the 
likelihood that inspections will be completed with no exposed pipe 
identified.

Response

    As discussed above, PHMSA is withdrawing this proposed form.

V. Advisory Committee Recommendations

    The Technical Pipeline Safety Standards Committee (TPSSC) and the 
Technical Hazardous Liquid Pipeline Safety Standards Committee 
(THLPSSC) considered the July 2, 2009, NPRM to revise the reporting 
requirements in the pipeline safety regulations at a joint meeting on 
December 9, 2009. A transcript of this meeting is available in the 
docket.
    The TPSSC and THLPSSC have been established by statute to evaluate 
proposed pipeline safety regulations. Each committee has an authorized 
membership of 15 individuals with membership evenly divided between the 
government, industry, and the public. Each member of these committees 
is qualified to consider the technical feasibility, reasonableness, 
cost-effectiveness, and practicability of proposed pipeline safety 
regulations.
    Each committee voted to support the proposed rule, subject to 
comments made during committee discussion. The amendments adopted in 
this final rule are consistent with the recommendations of the 
committees except for the issue of the change in the definition of an 
incident and the volume of measure for release of gas. The committees 
recommended that PHMSA adopt a threshold of 10,000 Mcf and not the 
3,000 Mcf threshold proposed in the NPRM. For the reasons stated in 
Section 2, ``Changing the definition of an `Incident' for gas 
pipelines'' of the preamble, PHMSA has adopted a threshold of 3,000 
Mcf. Committee comments generally were consistent with written comments 
filed by other commenters discussed above.

VI. Section-by-Section Analysis

    1. Section 191.1--This Section is amended to include in the scope 
of Part 191 regulated rural gathering lines. Rural onshore regulated 
gathering lines were defined by a final rule published March 15, 2006 
(71 FR 13289), but that rule unintentionally failed to include these 
newly regulated lines in the reporting requirements of Part 191.
    2. Section 191.3--This Section is amended to revise the definition 
of an incident for gas pipelines and LNG facilities. As discussed 
elsewhere in this document, principal changes include the addition of a 
criterion defining as an incident an unintentional release of gas that 
results in estimated gas loss of 3 million cubic feet or more. The 
criterion defining an incident on the basis of $50,000 property damage 
is correspondingly revised to omit consideration of the cost of gas 
lost. This amendment also clarifies that the activation of an emergency 
shutdown system at an LNG facility for reasons other than an actual 
emergency does not constitute an incident.
    3. Sections 191.7 and 195.58--These Sections are amended to require 
that all required reports, except safety-related condition reports and 
offshore condition reports, be submitted electronically unless an 
operator has demonstrated that electronic reporting would pose an undue 
burden and hardship and has obtained PHMSA approval to report by other 
means.
    4. Section 191.9--This Section is amended to remove the exclusion 
for LNG facilities that are part of distribution pipeline systems. 
Submission of incident reports for these facilities will now be 
required.
    5. Section 191.11--This Section is amended to remove the exclusion 
for LNG facilities. Submission of annual reports for these facilities 
will now be required.
    6. Section 191.15--This Section is amended to add the requirement 
that

[[Page 72903]]

operators of LNG facilities submit written incident reports.
    7. Section 191.17--This Section is amended to add the requirement 
that operators of LNG facilities submit annual reports.
    8. Sections 191.19 and 195.62--These Sections described how to 
obtain copies of required forms. The Sections are being removed, 
because all reports for which forms have been approved will now be 
required to be made electronically. Copies of the forms on which the 
electronic reporting system is based will continue to be available on 
PHMSA's Web site.
    9. Sections 191.21 and 195.63--These Sections are amended to 
include new forms that are included under OMB Control Number 2137-0522 
for gas pipelines and to add new OMB control numbers for forms 
associated with hazardous liquid pipelines.
    10. Sections 191.22 and 195.64--These Sections are added to create 
a National Registry of Pipeline and LNG Operators. Operators will use 
the Registry to obtain and change an OPID. Operators who already have 
one or more OPIDs are required to validate the information in PHMSA's 
records currently associated with those OPIDs within six months. 
Operators are required to notify PHMSA, via the Registry, of certain 
changes that affect the facilities associated with an OPID. Operators 
are also required to use their assigned OPID for all reporting 
requirements and for submissions to the NPMS. Operators are also 
required to notify PHMSA of changes within safety programs managed in 
common across multiple OPIDs (e.g., where a company operates multiple 
pipelines) that affect the OPID the operator considers ``primary'' for 
that program (generally representing which operating entity is 
responsible for the program).
    PHMSA has previously obtained this information from operators 
informally, usually from an operator's compliance personnel, as this 
information is needed for inspection planning. PHMSA will also use this 
information to analyze safety program performance and to identify 
trends.
    11. Section 192.945--This Section is amended to reflect the 
integration of reporting of IM performance measures for gas 
transmission pipelines into the annual report. Semi-annual reporting of 
IM performance measures is no longer required.
    12. Section 192.951--This Section is amended to require that all 
reports required by Subpart O of Part 192 be submitted electronically 
in accordance with revised Sec.  191.7.
    13. Section 193.2011--This Section is amended to require that LNG 
facility operators submit annual reports and reports of incidents and 
safety-related conditions in accordance with the requirements of Part 
191.
    15. Section 195.48--This Section specifies the scope of hazardous 
liquid pipelines subject to the reporting requirements of Subpart B of 
Part 195. Exceptions from portions of the annual report for pipelines 
not otherwise subject to Part 195 have been revised and moved to Sec.  
195.49.
    15. Section 195.49--This Section is amended to require that some 
parts of the hazardous liquid pipeline annual report form (designated 
on the form) must be completed separately for each state a pipeline 
traverses.
    16. Section 195.52--This Section is amended to require that 
hazardous liquid pipeline operators have a written procedure for 
calculating an initial estimate of the amount of product released in an 
accident. The amended Section also requires that operators provide an 
additional telephonic report if significant new information becomes 
available during the emergency response phase.
    17. Section 195.54--This Section is revised to remove the option to 
submit a facsimile of the PHMSA form because all reports must now be 
submitted electronically.

VII. Regulatory Analyses and Notices

    This final rule is published under the authority of the Federal 
Pipeline Safety Law (49 U.S.C. 60101 et seq.). Section 60102 authorizes 
the Secretary of Transportation to issue regulations governing design, 
installation, inspection, emergency plans and procedures, testing, 
construction, extension, operation, replacement, and maintenance of 
pipeline facilities. The amendments to the data collections 
requirements of the Pipeline Safety Regulations addressed in this 
rulemaking are issued under this authority and address NTSB and GAO 
recommendations. This rulemaking also carries out the mandates 
regarding incident reporting requirements under section 15 of the 
Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 
(Pub. L. No. 109-468, Dec. 29, 2006).

Executive Order 12866 and DOT Policies and Procedures

    This final rule is not a significant regulatory action under 
section 3(f) of Executive Order 12866 (58 FR 51735) and, therefore, was 
not reviewed by the OMB. This final rule is not significant under the 
Regulatory Policies and Procedures of the Department of Transportation 
(44 FR 11034).
    Overall, the costs of the final rule are approximately $1.6 million 
per year. The present value of this cost over ten years at a seven 
percent discount rate is approximately $11 million. Those costs cover 
changes to the 49 CFR to enhance general data and data management 
improvements for pipelines.
    The average of the present value of net benefits over ten years at 
a seven percent discount rate is approximately $73 million.
    The benefits of the final rule enhance PHMSA's ability to 
understand, measure, and assess the performance of individual operators 
and industry as a whole; integrate pipeline safety data in a way that 
will allow a more thorough, rigorous, and comprehensive understanding 
and assessment of risk; expand and simplify existing electronic 
reporting by operators; improve the data and analyses PHMSA relies on 
to make critical, safety-related decisions; and facilitate PHMSA's 
allocation of inspection and other resources based on a more accurate 
accounting of risk.
    A comparison of the benefits and costs of the rule results in 
positive net benefits. The present value of net benefits (the excess of 
benefits over costs) for the final rule is approximately $73 million 
using a seven percent discount rate. A copy of the regulatory 
evaluation is available for review in the docket.

Regulatory Flexibility Act

    The Regulatory Flexibility Act of 1980, as amended, requires 
Federal agencies to conduct a separate analysis of the economic impact 
of rules on small entities. The Regulatory Flexibility Act requires 
that Federal agencies take small entities' concerns into account when 
developing, writing, publicizing, promulgating, and enforcing 
regulations. The requirements imposed in this final rule will affect 
hazardous liquid, natural gas pipelines (distribution and 
transmission), and LNG facility operators.
    The Small Business Administration (SBA) size standards for 
hazardous liquid operators are companies with less than 1,500 
employees, including employees of parent corporations. The SBA size 
standards are $6.5 million in annual revenues for the natural gas 
transmission pipeline industry and 500 employees for the natural gas 
distribution industry. PHMSA has reviewed the data it collects from the 
hazardous liquid pipeline industry and has estimated there are 
approximately 220 small hazardous liquid pipeline operators, 475 
natural gas transmission

[[Page 72904]]

pipeline operators, and 54 LNG facility operators that may be 
considered small entities. The rule could result in a significant 
adverse economic impact on small entities if the estimated average 
annual costs attributed to the rule exceed one percent of their annual 
revenues. Since the average cost of the rule for each small pipeline 
operator affected by the rule is modest--estimated at $6,691 for each 
hazardous liquid pipeline operator, $461 for each natural gas 
transmission operator and $913 for each LNG facility operator--PHMSA 
concludes that there will not be a significant impact on a substantial 
number of small pipeline operators.

Executive Order 13175

    PHMSA has analyzed this final rule according to the principles and 
criteria in Executive Order 13175, ``Consultation and Coordination with 
Indian Tribal Governments.'' Because this final rule does not 
significantly or uniquely affect the communities of the Indian tribal 
governments or impose substantial direct compliance costs, the funding 
and consultation requirements of Executive Order 13175 do not apply.

Paperwork Reduction Act

    This final rule has resulted in revisions to several information 
collections that have either been approved by OMB, or have been 
submitted to OMB for approval. The following list contains the approved 
information collection and its approval information:

----------------------------------------------------------------------------------------------------------------
                                                                                                 Approved burden
                                      OMB Control No.   Info collection title   Expiration date       hours
----------------------------------------------------------------------------------------------------------------
1...................................       2137-0522   Incident and Annual          11/30/2011           53,627
                                                        Reports for Gas
                                                        Pipeline Operators.
----------------------------------------------------------------------------------------------------------------

    The following list contains the information collections that have 
been submitted to OMB for approval. When approval is received from OMB 
on these information collections, PHMSA will publish a notice 
announcing their approval in the Federal Register:

------------------------------------------------------------------------
                            OMB Control
                                No.            Info collection title
------------------------------------------------------------------------
1.......................       2137-0047  Transportation of Hazardous
                                           Liquids by Pipeline:
                                           Recordkeeping and Accident
                                           Reporting
2.......................       2137-0614  Pipeline Safety: New Reporting
                                           Requirements for Hazardous
                                           Liquid Pipeline Operators;
                                           Hazardous Liquid Annual
                                           Report.
------------------------------------------------------------------------

Unfunded Mandates Reform Act of 1995

    This final rule does not impose unfunded mandates under the 
Unfunded Mandates Reform Act of 1995. It would not result in costs of 
$100 million, adjusted for inflation, or more in any one year to either 
State, local, or tribal governments, in the aggregate, or to the 
private sector, and is the least burdensome alternative that achieves 
the objective of the final rule.

National Environmental Policy Act

    PHMSA analyzed the proposed rule in accordance with section 
102(2)(c) of the National Environmental Policy Act (42 U.S.C. 4332), 
the Council on Environmental Quality regulations (40 CFR 1500-1508), 
and DOT Order 5610.1C, and preliminarily determined the action would 
not significantly affect the quality of the human environment. We 
received no comment on this determination. Therefore, we conclude that 
this action will not significantly affect the quality of the human 
environment.

Executive Order 13132

    PHMSA has analyzed this final rule according to Executive Order 
13132 (``Federalism''). The final rule does not have a substantial 
direct effect on the States, the relationship between the national 
government and the States, or the distribution of power and 
responsibilities among the various levels of government. This final 
rule does not impose substantial direct compliance costs on State and 
local governments. This final rule does not preempt state law for 
intrastate pipelines. Therefore, the consultation and funding 
requirements of Executive Order 13132 do not apply.

Executive Order 13211

    This final rule is not a ``significant energy action'' under 
Executive Order 13211 (Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use). It is not 
likely to have a significant adverse effect on supply, distribution, or 
energy use. Further, the Office of Information and Regulatory Affairs 
has not designated this final rule as a significant energy action.

Privacy Act Statement

    Anyone may search the electronic form of all comments received for 
any of our dockets. You may review DOT's complete Privacy Act Statement 
in the Federal Register published on April 11, 2000 (70 FR 19477) or 
visit http://dms.dot.gov.

List of Subjects

49 CFR Part 191

    Pipeline Safety, Reporting and recordkeeping requirements.

49 CFR Part 192

    Pipeline safety, Fire prevention, Security measures.

49 CFR Part 193

    Pipeline safety, Fire prevention, Security measures, and Reporting 
and recordkeeping requirements.

49 CFR Part 195

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

0
In consideration of the foregoing, 49 CFR Chapter I is amended as 
follows:

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

0
1. The authority citation for Part 191 continues to read as follows:

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

0
2. In Sec.  191.1, paragraph (b)(4) is revised to read as follows:

Sec.  191.1  Scope.

* * * * *
    (b) * * *
    (4) Onshore gathering of gas--

[[Page 72905]]

    (i) Through a pipeline that operates at less than 0 psig (0 kPa);
    (ii) Through a pipeline that is not a regulated onshore gathering 
line (as determined in Sec.  192.8 of this subchapter); and
    (iii) Within inlets of the Gulf of Mexico, except for the 
requirements in Sec.  192.612.

0
3. In Sec.  191.3, the definition of ``Incident'' is revised to read as 
follows:

Sec.  191.3  Definitions.

* * * * *
    Incident means any of the following events:
    (1) An event that involves a release of gas from a pipeline, or of 
liquefied natural gas, liquefied petroleum gas, refrigerant gas, or gas 
from an LNG facility, and that results in one or more of the following 
consequences:
    (i) A death, or personal injury necessitating in-patient 
hospitalization;
    (ii) Estimated property damage of $50,000 or more, including loss 
to the operator and others, or both, but excluding cost of gas lost;
    (iii) Unintentional estimated gas loss of three million cubic feet 
or more;
    (2) An event that results in an emergency shutdown of an LNG 
facility. Activation of an emergency shutdown system for reasons other 
than an actual emergency does not constitute an incident.
    (3) An event that is significant in the judgment of the operator, 
even though it did not meet the criteria of paragraphs (1) or (2) of 
this definition.
* * * * *

0
4. In Sec.  191.5, the section heading and paragraph (b) introductory 
text are revised to read as follows:

Sec.  191.5  Immediate notice of certain incidents.

* * * * *
    (b) Each notice required by paragraph (a) of this section must be 
made to the National Response Center either by telephone to 800-424-
8802 (in Washington, DC, 202 267-2675) or electronically at http://www.nrc.uscg.mil and must include the following information:
* * * * *

0
5. Section 191.7 is revised to read as follows:

Sec.  191.7  Report submission requirements.

    (a) General. Except as provided in paragraph (b) of this section, 
an operator must submit each report required by this part 
electronically to the Pipeline and Hazardous Materials Safety 
Administration at http://opsweb.phmsa.dot.gov unless an alternative 
reporting method is authorized in accordance with paragraph (d) of this 
section.
    (b) Exceptions. An operator is not required to submit a safety-
related condition report (Sec.  191.25) or an offshore pipeline 
condition report (Sec.  191.27) electronically.
    (c) Safety-related conditions. An operator must submit concurrently 
to the applicable State agency a safety-related condition report 
required by Sec.  191.23 for intrastate pipeline transportation or when 
the State agency acts as an agent of the Secretary with respect to 
interstate transmission facilities.
    (d) Alternative Reporting Method. If electronic reporting imposes 
an undue burden and hardship, an operator may submit a written request 
for an alternative reporting method to the Information Resources 
Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, PHP-20, 1200 New Jersey Avenue, SE, Washington 
DC 20590. The request must describe the undue burden and hardship. 
PHMSA will review the request and may authorize, in writing, an 
alternative reporting method. An authorization will state the period 
for which it is valid, which may be indefinite. An operator must 
contact PHMSA at 202-366-8075, or electronically to 
informationresourcesmanager@dot.gov or make arrangements for submitting 
a report that is due after a request for alternative reporting is 
submitted but before an authorization or denial is received.

0
6. In Sec.  191.9, paragraph (c) is revised to read as follows:

Sec.  191.9  Distribution system: Incident report.

* * * * *
    (c) Master meter operators are not required to submit an incident 
report as required by this section.

0
7. Section 191.11 is revised to read as follows:

Sec.  191.11  Distribution system: Annual report.

    (a) General. Except as provided in paragraph (b) of this section, 
each operator of a distribution pipeline system must submit an annual 
report for that system on DOT Form PHMSA F 7100.1-1. This report must 
be submitted each year, not later than March 15, for the preceding 
calendar year.
    (b) Not required. The annual report requirement in this section 
does not apply to a master meter system or to a petroleum gas system 
that serves fewer than 100 customers from a single source.

0
8. Section 191.15 is revised to read as follows:

Sec.  191.15  Transmission systems; gathering systems; and liquefied 
natural gas facilities: Incident report.

    (a) Transmission or Gathering. Each operator of a transmission or a 
gathering pipeline system must submit DOT Form PHMSA F 7100.2 as soon 
as practicable but not more than 30 days after detection of an incident 
required to be reported under Sec.  191.5 of this part.
    (b) LNG. Each operator of a liquefied natural gas plant or facility 
must submit DOT Form PHMSA F 7100.3 as soon as practicable but not more 
than 30 days after detection of an incident required to be reported 
under Sec.  191.5 of this part.
    (c) Supplemental report. Where additional related information is 
obtained after a report is submitted under paragraph (a) or (b) of this 
section, the operator must make a supplemental report as soon as 
practicable with a clear reference by date to the original report.

0
9. Section 191.17 is revised to read as follows:

Sec.  191.17  Transmission systems; gathering systems; and liquefied 
natural gas facilities: Annual report.

    (a) Transmission or Gathering. Each operator of a transmission or a 
gathering pipeline system must submit an annual report for that system 
on DOT Form PHMSA 7100.2.1. This report must be submitted each year, 
not later than March 15, for the preceding calendar year, except that 
for the 2010 reporting year the report must be submitted by June 15, 
2011.
    (b) LNG. Each operator of a liquefied natural gas facility must 
submit an annual report for that system on DOT Form PHMSA 7100.3-1 This 
report must be submitted each year, not later than March 15, for the 
preceding calendar year, except that for the 2010 reporting year the 
report must be submitted by June 15, 2011.

Sec.  191.19  [Removed]

0
10. Section 191.19 is removed.

0
11. Section 191.21 is revised to read as follows:

Sec.  191.21  OMB control number assigned to information collection.

    This section displays the control number assigned by the Office of 
Management and Budget (OMB) to the information collection requirements 
in this part. The Paperwork Reduction Act requires agencies to display 
a current control number assigned by the Director

[[Page 72906]]

of OMB for each agency information collection requirement.

                      OMB Control Number 2137-0522
------------------------------------------------------------------------
 Section of 49 CFR Part 191 where
            identified                            Form No.
------------------------------------------------------------------------
191.5............................  Telephonic.
191.9............................  PHMSA 7100.1, PHMSA 7100.3.
191.11...........................  PHMSA 7100.1-1, PHMSA 7100.3-1.
191.15...........................  PHMSA 7100.2.
191.17...........................  PHMSA 7100.2-1.
191.22...........................  PHMSA 1000.1.
------------------------------------------------------------------------

0
12. Section 191.22 is added to read as follows:

Sec.  191.22  National Registry of Pipeline and LNG Operators.

    (a) OPID Request. Effective January 1, 2012, each operator of a gas 
pipeline, gas pipeline facility, LNG plant or LNG facility must obtain 
from PHMSA an Operator Identification Number (OPID). An OPID is 
assigned to an operator for the pipeline or pipeline system for which 
the operator has primary responsibility. To obtain on OPID, an operator 
must complete an OPID Assignment Request DOT Form PHMSA F 1000.1 
through the National Registry of Pipeline and LNG Operators in 
accordance with Sec.  191.7.
    (b) OPID validation. An operator who has already been assigned one 
or more OPID by January 1, 2011, must validate the information 
associated with each OPID through the National Registry of Pipeline and 
LNG Operators at http://opsweb.phmsa.dot.gov, and correct that 
information as necessary, no later than June 30, 2012.
    (c) Changes. Each operator of a gas pipeline, gas pipeline 
facility, LNG plant or LNG facility must notify PHMSA electronically 
through the National Registry of Pipeline and LNG Operators at http://opsweb.phmsa.dot.gov of certain events.
    (1) An operator must notify PHMSA of any of the following events 
not later than 60 days before the event occurs:
    (i) Construction or any planned rehabilitation, replacement, 
modification, upgrade, uprate, or update of a facility, other than a 
section of line pipe, that costs $10 million or more. If 60 day notice 
is not feasible because of an emergency, an operator must notify PHMSA 
as soon as practicable;
    (ii) Construction of 10 or more miles of a new pipeline; or
    (iii) Construction of a new LNG plant or LNG facility.
    (2) An operator must notify PHMSA of any of the following events 
not later than 60 days after the event occurs:
    (i) A change in the primary entity responsible (i.e., with an 
assigned OPID) for managing or administering a safety program required 
by this part covering pipeline facilities operated under multiple 
OPIDs.
    (ii) A change in the name of the operator;
    (iii) A change in the entity (e.g., company, municipality) 
responsible for an existing pipeline, pipeline segment, pipeline 
facility, or LNG facility;
    (iv) The acquisition or divestiture of 50 or more miles of a 
pipeline or pipeline system subject to Part 192 of this subchapter; or
    (v) The acquisition or divestiture of an existing LNG plant or LNG 
facility subject to Part 193 of this subchapter.
    (d) Reporting. An operator must use the OPID issued by PHMSA for 
all reporting requirements covered under this subchapter and for 
submissions to the National Pipeline Mapping System.

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

0
13. The authority citation for Part 192 continues to read as follows:

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

0
14. In Sec.  192.945, paragraph (a) is revised to read as follows:

Sec.  192.945  What methods must an operator use to measure program 
effectiveness?

    (a) General. An operator must include in its integrity management 
program methods to measure whether the program is effective in 
assessing and evaluating the integrity of each covered pipeline segment 
and in protecting the high consequence areas. These measures must 
include the four overall performance measures specified in ASME/ANSI 
B31.8S (incorporated by reference, see Sec.  192.7 of this part), 
section 9.4, and the specific measures for each identified threat 
specified in ASME/ANSI B31.8S, Appendix A. An operator must submit the 
four overall performance measures as part of the annual report required 
by Sec.  191.17 of this subchapter.

0
15. Section 192.951 is revised to read as follows:
* * * * *

Sec.  192.951  Where does an operator file a report?

    An operator must file any report required by this subpart 
electronically to the Pipeline and Hazardous Materials Safety 
Administration in accordance with Sec.  191.7 of this subchapter.

PART 193--LIQUEFIED NATURAL GAS FACILITIES: FEDERAL SAFETY 
STANDARDS

0
16. The authority citation for Part 193 continues to read as follows:

    Authority: 49 U.S.C. 5103, 60102, 60103, 60104, 60108, 60109, 
60110, 60113, 60118, and 49 CFR 1.53.

0
17. Section 193.2011 is revised to read as follows:

Sec.  193.2011  Reporting.

    Incidents, safety-related conditions, and annual pipeline summary 
data for LNG plants or facilities must be reported in accordance with 
the requirements of Part 191 of this subchapter.

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
18. The authority citation for Part 195 continues to read as follows:

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

0
19. Section 195.48 is revised to read as follows:

Sec.  195.48  Scope.

    This subpart prescribes requirements for periodic reporting and for 
reporting of accidents and safety-related conditions. This subpart 
applies to all

[[Page 72907]]

pipelines subject to this part and, beginning January 5, 2009, applies 
to all rural low-stress hazardous liquid pipelines.

0
20. Section 195.49 is revised to read as follows:

Sec.  195.49  Annual report.

    Each operator must annually complete and submit DOT Form PHMSA F 
7000-1.1 for each type of hazardous liquid pipeline facility operated 
at the end of the previous year. An operator must submit the annual 
report by June 15 each year, except that for the 2010 reporting year 
the report must be submitted by August 15, 2011. A separate report is 
required for crude oil, HVL (including anhydrous ammonia), petroleum 
products, carbon dioxide pipelines, and fuel grade ethanol pipelines. 
For each state a pipeline traverses, an operator must separately 
complete those sections on the form requiring information to be 
reported for each state.

0
21. Section 195.52 is revised to read as follows:

Sec.  195.52  Immediate notice of certain accidents.

    (a) Notice requirements. At the earliest practicable moment 
following discovery of a release of the hazardous liquid or carbon 
dioxide transported resulting in an event described in Sec.  195.50, 
the operator of the system must give notice, in accordance with 
paragraph (b) of this section, of any failure that:
    (1) Caused a death or a personal injury requiring hospitalization;
    (2) Resulted in either a fire or explosion not intentionally set by 
the operator;
    (3) Caused estimated property damage, including cost of cleanup and 
recovery, value of lost product, and damage to the property of the 
operator or others, or both, exceeding $50,000;
    (4) Resulted in pollution of any stream, river, lake, reservoir, or 
other similar body of water that violated applicable water quality 
standards, caused a discoloration of the surface of the water or 
adjoining shoreline, or deposited a sludge or emulsion beneath the 
surface of the water or upon adjoining shorelines; or
    (5) In the judgment of the operator was significant even though it 
did not meet the criteria of any other paragraph of this section.
    (b) Information required. Each notice required by paragraph (a) of 
this section must be made to the National Response Center either by 
telephone to 800-424-8802 (in Washington, DC, 202-267-2675) or 
electronically at http://www.nrc.uscg.mil and must include the 
following information:
    (1) Name, address and identification number of the operator.
    (2) Name and telephone number of the reporter.
    (3) The location of the failure.
    (4) The time of the failure.
    (5) The fatalities and personal injuries, if any.
    (6) Initial estimate of amount of product released in accordance 
with paragraph (c) of this section.
    (7) All other significant facts known by the operator that are 
relevant to the cause of the failure or extent of the damages.
    (c) Calculation. A pipeline operator must have a written procedure 
to calculate and provide a reasonable initial estimate of the amount of 
released product.
    (d) New information. An operator must provide an additional 
telephonic report to the NRC if significant new information becomes 
available during the emergency response phase of a reported event at 
the earliest practicable moment after such additional information 
becomes known.

0
22. In Sec.  195.54, paragraph (a) is revised to read as follows:

Sec.  195.54  Accident reports.

    (a) Each operator that experiences an accident that is required to 
be reported under Sec.  195.50 must, as soon as practicable, but not 
later than 30 days after discovery of the accident, file an accident 
report on DOT Form 7000-1.
* * * * *

0
23. Section 195.58 is revised to read as follows:

Sec.  195.58  Report submission requirements.

    (a) General. Except as provided in paragraph (b) of this section, 
an operator must submit each report required by this part 
electronically to PHMSA at http://opsweb.phmsa.dot.gov unless an 
alternative reporting method is authorized in accordance with paragraph 
(d) of this section.
    (b) Exceptions. An operator is not required to submit a safety-
related condition report (Sec.  195.56) or an offshore pipeline 
condition report (Sec.  195.67) electronically.
    (c) Safety-related conditions. An operator must submit concurrently 
to the applicable State agency a safety-related condition report 
required by Sec.  195.55 for an intrastate pipeline or when the State 
agency acts as an agent of the Secretary with respect to interstate 
pipelines.
    (d) Alternate Reporting Method. If electronic reporting imposes an 
undue burden and hardship, the operator may submit a written request 
for an alternative reporting method to the Information Resources 
Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, PHP-20, 1200 New Jersey Avenue, SE., Washington 
DC 20590. The request must describe the undue burden and hardship. 
PHMSA will review the request and may authorize, in writing, an 
alternative reporting method. An authorization will state the period 
for which it is valid, which may be indefinite. An operator must 
contact PHMSA at 202-366-8075, or electronically to 
``informationresourcesmanager@dot.gov'' to make arrangements for 
submitting a report that is due after a request for alternative 
reporting is submitted but before an authorization or denial is 
received.

Sec.  195.62  [Removed]

0
24. Section 195.62 is removed.
0
25. Section 195.63 is revised to read as follows:
    Sec.  195.63 OMB control number assigned to information collection.
    The control numbers assigned by the Office of Management and Budget 
to the hazardous liquid pipeline information collection pursuant to the 
Paperwork Reduction Act are 2137-0047, 2137-0601, 2137-0604, 2137-0605, 
2137-0618, and 2137-0622.

0
26. Section 195.64 is added to read as follows:

Sec.  195.64  National Registry of Pipeline and LNG Operators.

    (a) OPID Request. Effective January 1, 2012, each operator of a 
hazardous liquid pipeline or pipeline facility must obtain from PHMSA 
an Operator Identification Number (OPID). An OPID is assigned to an 
operator for the pipeline or pipeline system for which the operator has 
primary responsibility. To obtain an OPID or a change to an OPID, an 
operator must complete an OPID Assignment Request DOT Form PHMSA F 
1000.1 through the National Registry of Pipeline and LNG Operators in 
accordance with Sec.  195.58.
    (b) OPID validation. An operator who has already been assigned one 
or more OPID by January 1, 2011 must validate the information 
associated with each such OPID through the National Registry of 
Pipeline and LNG Operators at http://opsweb.phmsa.dot.gov, and correct 
that information as necessary, no later than June 30, 2012.
    (c) Changes. Each operator must notify PHMSA electronically through 
the National Registry of Pipeline and LNG Operators at http://

[[Page 72908]]

opsweb.phmsa.dot.gov, of certain events.
    (1) An operator must notify PHMSA of any of the following events 
not later than 60 days before the event occurs:
    (i) Construction or any planned rehabilitation, replacement, 
modification, upgrade, uprate, or update of a facility, other than a 
section of line pipe, that costs $10 million or more. If 60 day notice 
is not feasible because of an emergency, an operator must notify PHMSA 
as soon as practicable;
    (ii) Construction of 10 or more miles of a new hazardous liquid 
pipeline; or
    (iii) Construction of a new pipeline facility.
    (2) An operator must notify PHMSA of any following event not later 
than 60 days after the event occurs:
    (i) A change in the primary entity responsible (i.e., with an 
assigned OPID) for managing or administering a safety program required 
by this part covering pipeline facilities operated under multiple 
OPIDs.
    (ii) A change in the name of the operator;
    (iii) A change in the entity (e.g., company, municipality) 
responsible for operating an existing pipeline, pipeline segment, or 
pipeline facility;
    (iv) The acquisition or divestiture of 50 or more miles of pipeline 
or pipeline system subject to this part; or
    (v) The acquisition or divestiture of an existing pipeline facility 
subject to this part.
    (d) Reporting. An operator must use the OPID issued by PHMSA for 
all reporting requirements covered under this subchapter and for 
submissions to the National Pipeline Mapping System.

    Issued in Washington, DC, on November 9, 2010, under the 
authority delegated in 49 CFR Part 1.
Cynthia L. Quarterman,
Administrator.
[FR Doc. 2010-29087 Filed 11-24-10; 8:45 am]
BILLING CODE 4910-60-P