Pipeline Safety: Updates to Pipeline and Liquefied Natural Gas Reporting Requirements, 72878-72908 [2010-29087]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[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]



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Part II





Department of Transportation





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 Pipeline and Hazardous Materials Safety Administration



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49 CFR Parts 191, 192, 193 et al.



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

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

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR 191, 192, 193 and 195

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


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

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

ACTION: Final rule.

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

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

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

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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

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

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

49 CFR 191.3

Proposal

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

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

Comments

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

[[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