Document ID: PHMSA-2007-27954-0194
Agency: phmsa
Document Type: Rule
Title: Pipeline Safety: Control Room Management/Human Factors
Posted Date: 2009-12-03T05:00Z

[Federal Register: December 3, 2009 (Volume 74, Number 231)]
[Rules and Regulations]               
[Page 63310-63330]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr03de09-7]                         

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 192 and 195

[Docket ID PHMSA-2007-27954; Amdt. Nos. 192-112 and 195-93]
RIN 2137-AE28

 
Pipeline Safety: Control Room Management/Human Factors

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA); 
DOT.

ACTION: Final rule.

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SUMMARY: PHMSA is amending the Federal pipeline safety regulations to 
address human factors and other aspects of control room management for 
pipelines where controllers use supervisory control and data 
acquisition (SCADA) systems. Under the final rule, affected pipeline 
operators must define the roles and responsibilities of controllers and 
provide controllers with the necessary information, training, and 
processes to fulfill these responsibilities. Operators must also 
implement methods to prevent controller fatigue. The final rule further 
requires operators to manage SCADA alarms, assure control room 
considerations are taken into account when changing pipeline equipment 
or configurations, and review reportable incidents or accidents to 
determine whether control room actions contributed to the event.
    Hazardous liquid and gas pipelines are often monitored in a control 
room by controllers using computer-based equipment, such as a SCADA 
system, that records and displays operational information about the 
pipeline system, such as pressures, flow rates, and valve positions. 
Some SCADA systems are used by controllers to operate pipeline 
equipment, while, in other cases, controllers may dispatch other 
personnel to operate equipment in the field. These monitoring and 
control actions, whether via SCADA system commands or direction to 
field personnel, are a principal means of managing pipeline operation.
    This rule improves opportunities to reduce risk through more 
effective control of pipelines. It further requires

[[Page 63311]]

the statutorily mandated human factors management. These regulations 
will enhance pipeline safety by coupling strengthened control room 
management with improved controller training and fatigue management.

DATES: Effective Date: The effective date of this final rule is 
February 1, 2010. Compliance Date: An operator must develop control 
room management procedures by August 1, 2011 and implement the 
procedures by February 1, 2012.
    Incorporation by Reference Date: The incorporation by reference of 
certain publications listed in this rule is approved by the Director of 
the Federal Register as of February 1, 2010.

FOR FURTHER INFORMATION CONTACT: For technical information contact: 
Byron Coy at (609) 989-2180 or by e-mail at Byron.Coy@dot.gov. For 
legal information contact: Benjamin Fred at (202) 366-4400 or by e-mail 
at Benjamin.Fred@dot.gov. All materials in the docket may be accessed 
electronically at http://www.regulations.gov. General information about 
PHMSA may be found at http://phmsa.dot.gov.

SUPPLEMENTARY INFORMATION:

I. Background

A. Pipelines

    Approximately two-thirds of our domestic energy supplies are 
transported by pipeline. There are roughly 170,000 miles of hazardous 
liquid pipelines, 295,000 miles of gas transmission pipelines, and 1.9 
million miles of gas distribution pipelines in the United States. 
Hazardous liquid pipelines carry crude oil to refineries and refined 
products to locations where these products are consumed or stored for 
later use. Hazardous liquid pipelines also transport highly volatile 
liquids (HVLs), other hazardous liquids such as anhydrous ammonia, and 
carbon dioxide. The regulations in 49 CFR part 195 apply to owners and 
operators of pipelines used in the transportation of hazardous liquids 
and carbon dioxide. Throughout this document, the term ``hazardous 
liquid'' refers to all products in pipelines regulated under part 195. 
In addition, the term ``operator'' refers to both owners and operators 
of pipeline facilities.
    Gas transmission pipelines typically carry natural gas over long 
distances from gas gathering, supply, or import facilities to 
localities where it is used to heat homes, generate electricity, and 
fuel industry. Gas distribution pipelines take natural gas from 
transmission pipelines and distribute it to residential, commercial, 
and industrial customers. The regulations in 49 CFR part 192 apply to 
operators of pipelines that transport natural gas, flammable gas, or 
gas which is toxic and corrosive. Throughout this document, the term 
``gas'' refers to all gases in pipelines regulated under part 192.

B. Control Rooms and Controllers

    Pipelines vary from small and simple to large and complex. 
Pipelines often span broad geographic areas. Gas distribution pipelines 
may cover entire metropolitan areas, literally street-by-street. Gas 
transmission and hazardous liquid pipelines may traverse hundreds or 
thousands of miles. Equipment exists throughout pipelines that must be 
operated to control the safe movement of commodity. This includes pumps 
and compressors to provide motive force and valves that control 
pressure or change position to direct the flow of commodity. In many 
cases, parameters measuring pipeline operations, such as pressure and 
flow, are monitored from remote, central locations referred to as 
control rooms. Pipeline equipment may also be operated remotely from 
control rooms. The employees who monitor pipeline parameters and direct 
certain actions from control rooms are known as controllers.
    Most pipelines are underground and operate without disturbing the 
environment or negatively impacting public safety. However, accidents 
do occur occasionally. Effective control is one key component of 
accident prevention.\1\ Controllers can help identify risks, prevent 
accidents, and minimize commodity loss if provided with the necessary 
tools and working environment. This rule will increase the likelihood 
that pipeline controllers have the necessary knowledge, skills, and 
abilities to help prevent accidents. The rule will also ensure that 
operators provide controllers with the necessary training, tools, 
procedures, management support, and environment where a controller's 
actions can be effective in helping to assure safe operation.
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    \1\ The pipeline safety regulations in 49 CFR parts 191, 192, 
and 193 refer to certain events on a gas pipeline system as 
``incidents'' while part 195 refers to similar failures on a 
hazardous liquid pipeline system as ``accidents.'' Throughout this 
document the terms ``accident'' and ``incident'' may be used 
interchangeably to mean an event or failure on a gas or hazardous 
liquid pipeline.
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    Most operators use computer-based SCADA systems, distributed 
control systems (DCS), or other less sophisticated systems to gather 
key information electronically from field locations.\2\ These systems 
are configured to present field data to the controllers, and may 
include additional historical, trending, reporting, and alarm 
management information. Controllers track routine operations 
continuously and watch for developing abnormal operating or emergency 
conditions. A controller may take direct action through the SCADA 
system to operate equipment or the controller may alert and defer 
action to others.
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    \2\ SCADA, DCS or other similar systems perform similar 
functions. Throughout this document, where the term SCADA is used, 
it should be interpreted to mean SCADA, DCS or other similar 
systems.
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    Control rooms and controllers are critical to the safe operation of 
pipelines. Control rooms often serve as the hub or command center for 
decisions such as adjusting commodity flow or facilitating an 
operator's initial response to an emergency. The control room is the 
central location where humans or computers receive data from field 
sensors. Commands from the control room may be transmitted back to 
remotely controlled equipment. Field personnel also receive significant 
information from the control room. In essence, the control room is the 
``brain'' of many pipeline systems.
    Errors made in control rooms can have significant effects on the 
controlled systems. A controller's errors can initiate or exacerbate an 
accident. A controller's improper action or lack of action can place 
undue stresses on a pipeline, which could result in a subsequent 
failure, the loss of service, or an increase in lost commodity and risk 
to people, property, the environment, and the fuel supply. On the other 
hand, proper controller responses to developing abnormal operating 
conditions or accidents can alleviate the consequences of some events, 
or prevent them altogether, regardless of the initial cause.

C. Knowledge and Information Are Required To Do the Job

    A controller must possess certain abilities, and attain the 
knowledge and skills necessary to complete the various tasks required 
for a specific pipeline system. To attain the necessary knowledge and 
skills, the controller is typically required to complete extensive on-
the-job training and is often closely observed by an experienced 
controller for a period of time. The controller must also review and 
understand appropriate procedures, including those associated with 
emergency response, and repeatedly practice the correct responses to a 
variety of abnormal operating conditions. Pipeline operators 
periodically evaluate a controller's skills and knowledge through the 
regulatory-

[[Page 63312]]

required operator qualification (OQ) process.
    Pipeline controllers must have adequate and up-to-date information 
about the conditions and operating status of the equipment they monitor 
and control if they are to succeed in maintaining pipeline safety. 
Incorrect, delayed, missing, or poorly displayed data may confuse a 
controller and lead to problems despite the extensive training, 
qualification, and abilities of the controller. SCADA systems perform 
the function of gathering this information and displaying it to the 
controller. Operators need to assure that SCADA systems perform this 
important function correctly, and that the information is displayed in 
a manner that facilitates controller understanding and recognition of 
abnormal operating conditions.

D. Control Room Management

    All of this must occur within an environment that facilitates 
appropriate and correct actions. Operators must prudently manage the 
factors affecting the controller. This includes relevant human factors, 
such as factors that can affect controller fatigue, and operator 
processes and procedures for managing the pipeline from the control 
room. PHMSA refers to the combination of all these factors as control 
room management. This rule requires that operators take specific 
actions to assure that pipeline control room management contributes to 
the safe operation of pipeline facilities.

E. NPRM

    On September 12, 2008, PHMSA published a notice of proposed 
rulemaking (NPRM) (73 FR 53076) proposing to require operators of 
hazardous liquid pipelines, gas pipelines, and liquefied natural gas 
(LNG) facilities to amend their existing written operations and 
maintenance procedures, OQ programs, and emergency plans to assure 
controllers and control room management practices and procedures are 
adequate to maintain pipeline safety and integrity. In summary, the 
NPRM proposed to revise the Federal pipeline safety regulations by:
    (1) Requiring operators to amend their Operations and Maintenance 
Manuals to address the human factors management plan required by the 
Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 
(PIPES Act (Pub. L. 109-468), Section 12).
    (2) Defining the terms alarm, controller, control room, and SCADA.
    (3) Requiring operators to define roles and responsibilities so 
that management and controllers have uniform expectations and 
understandings about response requirements before an abnormal operating 
condition or emergency arises.
    (4) Requiring operators to establish procedures to facilitate 
controllers receiving management input in a timely manner when 
required.
    (5) Requiring operators to assure that controllers receive the 
timely and necessary information they need to fulfill their 
responsibilities.
    (6) Requiring operators to conduct an initial point-to-point 
baseline verification for each SCADA system to validate and document 
that field equipment configurations agree with computer displays.
    (7) Requiring operators to record critical information during each 
shift.
    (8) Requiring operators to include in their written procedures a 
limit on the length of time a controller may work and a requirement to 
allow time for adequate rest between shifts.
    (9) Requiring two levels of alarm management review.
    (10) Requiring operators to establish thorough and frequent 
communication between controllers, management, and field personnel when 
planning and implementing changes to pipeline equipment and 
configuration.
    (11) Requiring operators to review all reportable accidents and 
incidents and certain other events on a routine basis to identify and 
correct deficiencies related to: Controller fatigue; field equipment; 
procedures; SCADA system configuration and performance; and training.
    (12) Requiring operators to include certain content in their 
controller training programs. The proposed rule included a minimum set 
of elements that would overlap and supplement existing OQ programs.
    (13) Requiring additional controller qualifications to measure or 
verify a controller's performance, including the prompt detection of, 
and appropriate response to, abnormal and emergency conditions likely 
to occur.
    (14) Mandating that a senior executive officer validate certain 
aspects of controller training, qualification, and compliance with the 
requirements of this rule.
    (15) Requiring operators to maintain records that demonstrate 
compliance with the regulation and to document any deviations from 
their control room management procedures.
    The intent of the NPRM was to ensure that pipeline controllers 
would have the necessary knowledge, skills, abilities, and 
qualifications to help prevent accidents. The proposal was also 
intended to assure that operators would provide controllers with 
accurate information and the training, tools, procedures, management 
support, and operating environment where a controller's actions can 
help prevent accidents and minimize commodity losses. The requirements 
proposed in the NPRM were based on a controller study conducted by 
PHMSA that had identified areas for enhancement, an NTSB SCADA safety 
study, and certain mandates in the PIPES Act.

F. PHMSA Controller Study

    As detailed in the NPRM, PHMSA had been studying and evaluating 
control room operations for many years and began developing control 
room inspection guidance in 1999. Congress subsequently enacted the 
Pipeline Safety Improvement Act of 2002 (PSIA) (Pub. L. 107-355), which 
required a pilot program be conducted to evaluate the need for pipeline 
controllers to be certified through tests and other requirements. In 
response to the PSIA, PHMSA conducted the Controller Certification 
(CCERT) project study and reported its findings to Congress within a 
report dated December 17, 2006, entitled ``Qualification of Pipeline 
Personnel.'' This project included a comprehensive review of existing 
controller training, qualification processes, procedures, and 
practices. This review also included identifying potential enhancements 
to controller qualifications and control room operations, such as 
validation and certification processes currently used in other 
industries to enhance public safety. Additional information on the 
CCERT study may be found in the NPRM.

G. NTSB SCADA Study

    The NTSB conducted a safety study on hazardous liquid pipeline 
SCADA systems during the same period PHMSA conducted its CCERT study. 
While the PHMSA project addressed a wider perspective of interest, the 
two studies include similar findings.\3\ The NTSB study identified 
areas for potential improvement, which resulted in five 
recommendations. Three are incorporated in this final rule. PHMSA is 
addressing the other two recommendations independent of this 
rulemaking.
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    \3\ See ``Supervisory Control and Data Acquisition (SCADA) 
Systems in Liquid Pipelines,'' Safety Study NTSB/SS-05-02, adopted 
November 29, 2005.
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    The impetus of the NTSB study was a number of hazardous liquid 
accidents investigated by the NTSB in which there was a delay between 
the initial

[[Page 63313]]

indications of a leak evident on the SCADA system and the controller's 
initiation of response efforts. The NTSB designed its SCADA study to 
examine how hazardous liquid pipeline companies use SCADA systems to 
monitor and record operating data and to evaluate the role of SCADA 
systems in leak detection. The study identified five areas for 
potential improvement:
     Display graphics.
     Alarm management.
     Controller training.
     Controller fatigue data collection.
     Leak detection systems.
    While the NTSB SCADA study specifically addressed hazardous liquid 
pipelines, the report included an appendix of all NTSB SCADA-related 
recommendations since 1976, which resulted from investigations of both 
hazardous liquid and gas pipeline accidents. Since 1976, the NTSB has 
issued approximately 30 recommendations to various entities related to 
SCADA systems involving both hazardous liquid and gas pipeline systems. 
PHMSA considers the NTSB recommendations in the most-recent SCADA 
safety study to be applicable for both gas and hazardous liquid 
pipelines. The recommendations being addressed through this rulemaking 
are as follows:
NTSB Recommendation P-05-1
    Operators of hazardous liquid pipelines should be required to 
follow the API Recommended Practice 1165 (API RP 1165) for the use of 
graphics on the SCADA screens.
NTSB Recommendation P-05-2
    PHMSA should require pipeline companies to have a policy for the 
review and audit of SCADA-based alarms.
NTSB Recommendation P-05-3
    Operators should be required to include simulator or non-
computerized simulations for training controllers in recognition of 
abnormal operating conditions, in particular leak events.

H. PIPES Act of 2006

    The PIPES Act introduced additional requirements for PHMSA with 
respect to control room management and human factors. Section 12 of the 
PIPES Act (codified at 49 U.S.C. 60137) requires PHMSA to issue 
regulations requiring each operator of a gas or hazardous liquid 
pipeline to develop, implement, and submit a human factors management 
plan designed to reduce risks associated with human factors, including 
fatigue, in each control room for the pipeline. The plan must include, 
among other things, a maximum limit on the hours of service for 
controllers working in a control room. PHMSA, or a state authorized to 
exercise safety oversight, is required to review and approve operators' 
human factors plans, and operators are required to notify PHMSA (or the 
appropriate state) of any deviations from the plan. Section 19 of the 
PIPES Act requires PHMSA to issue standards to implement the three 
recommendations of the NTSB SCADA safety study described above. This 
final rule fulfills requirements in sections 12 and 19 of the PIPES 
Act.

II. Summary of Public Comments

    PHMSA received a total of 144 comments on the NPRM, including 
comments from trade associations, municipal operators, local 
distribution companies (LDC), NTSB, LNG facilities, gas transmission 
pipeline operators, other gas distribution pipeline operators, 
hazardous liquid pipeline operators, state regulators, and private 
citizens. In addition, PHMSA participated in two trade association 
meetings during the public comment period: (1) On October 14-15, 2008, 
at the American Petroleum Institute (API) and Association of Oil 
Pipelines (AOPL) forum for control room management in Houston, Texas; 
and (2) on October 30, 2008, at the American Gas Association (AGA) 
control room management workshop in Ashburn, Virginia. Summaries of 
PHMSA's interactions at these meetings are available in the docket. 
Subsequent to the public comment period, on February 12, 2009, PHMSA 
staff met with NTSB staff in Washington, DC to discuss NTSB's comments 
on fatigue mitigation. A summary of this meeting is also in the docket.
    The national pipeline trade associations, consisting of the AGA, 
the American Public Gas Association (APGA), the API, the AOPL, and the 
Interstate Natural Gas Association of America (INGAA), submitted a 
joint comment on October 8, 2008, shortly after the NPRM was issued, 
suggesting the agency withdraw the proposed rule. The associations 
contended that the proposed rule was overly-broad, unduly burdensome, 
and exceeded what the associations saw as the intent of Congress. They 
proposed that PHMSA issue an amended proposed rule with a clear scope 
and revised definitions that would reflect congressional intent and 
input from previous public meetings, and that would incorporate 
available consensus standards to a greater degree.
    The trade associations submitted a second letter on November 12, 
2008, reaffirming their previous suggestion that the proposed rule be 
reissued. The second joint letter provided alternative rule language to 
support the associations' suggested re-issuance of the proposed rule. 
The letter also suggested that PHMSA provide its pipeline safety 
advisory committees the opportunity to vote on their suggested 
alternative language at a joint committee meeting scheduled for 
December 2008.
    AGA, APGA, INGAA, and API/AOPL also individually submitted comments 
on the proposed rule. Other associations that submitted comments were: 
The National Association of Pipeline Safety Representatives (NAPSR), 
Northeast Gas Association (NGA), Texas Energy Coalition (TEC), Texas 
Oil and Gas Association (TXOGA), and Texas Pipeline Association (TPA). 
NGA supported AGA's comments and TEC, TXOGA, and TPA supported the 
joint trade associations' comments and the associated alternative 
regulatory language. APGA stated that the rule as written would have a 
disproportionately greater impact on small utilities with no offsetting 
benefits based on its survey that found, on average, 22 percent of 
small public gas system employees would be classified as controllers 
subject to this rule. APGA noted that the agency's Regulatory Impact 
Analysis (RIA) did not address adequately the impact on small entities.
    NAPSR is an organization of state agency pipeline safety managers 
responsible for the administration of their state's pipeline safety 
programs. NAPSR expressed concerns about jurisdictional authority in 
situations where a pipeline crosses State boundaries while under the 
control of a control room, or where a pipeline connects to a dispatch 
center or communications center in another State. NAPSR proposed 
adopting the definitions of control room and controller in API 
Recommended Practice 1168 (API RP 1168) to resolve the issue of 
jurisdictional authority.
    Comments from individual pipeline operators generally echoed the 
comments of the joint trade associations and the individual trade 
associations. Their comments mainly addressed the scope of the proposed 
rule. Many of these commenters were concerned with the proposed 
definitions of ``controller'' and ``control room,'' contending that 
these definitions would have the effect of making the proposed rule's 
scope unreasonably broad. Another area of significant concern was the 
proposed requirement to conduct a 100 percent baseline data point 
verification of SCADA systems. Pipeline operators generally commented 
that this proposed requirement would entail significant cost for very 
limited benefit. The

[[Page 63314]]

pipeline operators all supported the alternative regulatory language 
submitted by the joint trade associations or their own trade 
association.

III. Advisory Committees Meeting

    On December 11, 2008, the Technical Pipeline Safety Standards 
Committee (TPSSC) and the Technical Hazardous Liquid Pipeline Safety 
Standards Committee (THLPSSC) met jointly for their bi-annual public 
meeting in Arlington, Virginia.\4\ This meeting included consideration 
of the proposed control room management rule. As described above, the 
joint trade associations had submitted comments suggesting that the 
proposal be withdrawn and that the rule be significantly revised before 
being reissued. The associations submitted proposed alternative rule 
language as a basis for revision and had asked that the advisory 
committees be afforded the opportunity to consider their revised 
language if PHMSA did not withdraw the proposed rule.
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    \4\ The TPSSC and THLPSSC are statutorily-mandated advisory 
committees that advise PHMSA on proposed safety standards, risk 
assessments, and safety policies for natural gas pipelines and for 
hazardous liquid pipelines. Both committees were established under 
the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C. App. 1) 
and the pipeline safety law (49 U.S.C. Chap. 601). Each committee 
consists of 15 members--with membership evenly divided among the 
Federal and State government, the regulated industry, and the 
public. The committees advise PHMSA on technical feasibility, 
practicability, and cost-effectiveness of each proposed pipeline 
safety standard.
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    Based on the comments filed by the joint trade associations, those 
received during the public meetings described above, and the general 
trend of other comments, PHMSA presented the Advisory Committees with 
three variations of the regulatory language being considered by the 
Agency. These included the language proposed in the NPRM, the 
alternative language proposed by the joint trade associations, and a 
third option that reflected the trade associations' proposed language 
with modifications to reflect critical NPRM language and other comments 
that had been received. PHMSA provided these variations of the 
regulatory language to facilitate the Advisory Committee members' 
discussion of the rule and to provide a process by which the members 
could recommend a certain course of action by PHMSA with regard to the 
rule. Although PHMSA had not selected any particular course of action 
at that time, PHMSA expressed its view that the third option might be 
the most viable alternative.
    The TPSSC discussed exempting gas distribution from all 
requirements of this rulemaking action. After substantial discussion, 
the TPSSC voted against recommending that PHMSA exclude distribution 
from the rule, but voted in favor of recommending that PHMSA limit the 
requirements placed on certain small distribution operators to fatigue 
management and associated recordkeeping issues.
    The Advisory Committees provided additional substantive and 
editorial comments to the proposed definitions, the scope of part 192, 
general requirements, requirements concerning SCADA systems, 
verification, backup control, fatigue mitigation, alarm management, 
change management, operating experience, and training requirements. 
Also, members of the public were afforded an opportunity to comment 
during the meeting, and several participants from the public provided 
their viewpoints for the record. After further discussion among the 
members, the TPSSC voted twelve to one, and the THLPSSC voted 
unanimously in favor. Also, both Advisory Committees provided a 
recommendation for PHMSA to make the changes noted during discussion. A 
transcript of the Advisory Committees meeting is posted in the docket 
(PHMSA-2007-27954-0184.2).
    The Advisory Committees recommended the following changes to the 
rule language proposed in the NPRM:
     Changing the definitions of controller and control room to 
limit the scope of the rule. The revised definitions would exclude 
field personnel who operate equipment and operator personnel who use 
SCADA information but who have no operational responsibility to respond 
to SCADA indications.
     Adding a scope statement to explicitly limit the 
application of the rule to controllers using SCADA systems.
     Excluding gas distribution pipelines serving less than 
250,000 customers or gas transmission pipelines without compressor 
stations from many of the requirements.
     Reducing specificity in the elements operators would be 
required to define as controllers' roles and responsibilities.
     Limiting applicability of SCADA display guidance in API RP 
1165 to SCADA systems that would be installed or undergo certain 
changes after the rule became effective.
     Requiring point-to-point verification of SCADA only when 
new field equipment is installed or when changes are made to field 
equipment or displays that could affect pipeline safety.
     Eliminating requirements to implement additional measures 
to monitor for fatigue when only a single controller is on duty.
     Reducing the scope and frequency of required alarm 
reviews.
     Eliminating the proposed requirement that operators review 
for lessons learned pipeline events that did not require reporting as 
incidents and focusing required reviews of incidents on those events 
where there is reason to believe that control room actions contributed 
to the event.
     Deferring to existing requirements for operator 
qualification rather than imposing an additional qualification 
requirement for controllers.
     Eliminating the proposed requirement that a senior officer 
of each pipeline company submit certification that the requirements of 
the rule have been implemented.
    Our changes to the final rule in response to the comments and 
advisory committees' recommendations are discussed below in section V.

IV. Summary of Final Rule

    This final rule imposes requirements for control room management 
for all gas and hazardous liquid pipelines subject to parts 192 and 195 
respectively that use SCADA systems and have at least one controller 
and control room. The scope of the rule is narrower in several respects 
than was proposed in the NPRM. First, for the reasons set forth below, 
LNG facilities are not covered by the rule, and no new requirements are 
adopted for part 193. In addition, changes to the proposed definition 
of a controller focus the new requirements on persons who work in 
control rooms and use SCADA systems to control their pipelines. The 
scope of the final rule has also been revised for gas pipeline 
operators such that each control room whose operations are limited to 
either or both of distribution with fewer than 250,000 customers or gas 
transmission without compressor stations must follow procedures with 
appropriate documentation that implement only the requirements for 
fatigue management, validation, and compliance and deviations. 
Pipelines meeting these criteria are generally smaller and simpler. 
They pose less complexity, obviating the need for the other 
requirements in this rule.
    This rule requires pipeline operators to have and follow written 
control room management procedures. The operators must define the roles 
and responsibilities of controllers in normal, abnormal, and emergency 
operating

[[Page 63315]]

situations. The final rule does not enumerate specific responsibilities 
that must be defined, as did the proposed rule. Instead, the final rule 
leaves the scope of controller responsibilities to be defined by each 
pipeline operator taking into consideration the characteristics of its 
pipeline and its methods of safely managing pipeline operation.
    Pipeline operators will be required by this final rule to assure 
that new SCADA displays and displays for SCADA systems that are 
expanded or replaced meet the provisions of the consensus standard 
governing such displays, API RP 1165. Displays for gas pipelines are 
required to meet only some provisions of the standard. The proposed 
rule would not have limited applicability of this requirement to new or 
modified SCADA systems. Operators will be required to validate the 
accuracy of SCADA displays whenever field equipment is added or moved 
and when other changes that may affect pipeline safety are made to 
field equipment or SCADA displays. The proposed rule would have 
required that all operators perform a 100 percent verification of 
existing SCADA systems within a few years. This provision was not 
included in the final rule. Pipeline operators will also be required to 
test any backup SCADA systems and to test and verify a means to 
manually operate the pipeline (in the event of a SCADA failure) at 
least annually.
    Pipeline operators must also establish a means of recording shift 
changes and other situations in which responsibility for pipeline 
operations is handed over from one controller to another. Such changes 
in responsibility may occur at scheduled shift changes or within a 
shift, when a controller is relieved for breaks and other reasons. 
Handovers can also occur between control rooms, for example where only 
one of multiple control rooms is used during night shifts. Pipeline 
operators will need to define procedures for shift changes and other 
circumstances in which responsibility for pipeline operation is 
transferred from one controller to another. The procedures must include 
the content of information to be exchanged during the turnover.
    Pipeline operators must implement measures to prevent fatigue that 
could influence a controller's ability to perform as needed. Operators 
will need to schedule their shifts in a manner that allows each 
controller enough off-duty time to achieve eight hours of continuous 
sleep. Operators must train controllers and their supervisors to 
recognize the effects of fatigue and in fatigue mitigation strategies. 
Finally, each operator's procedures must establish a maximum limit on 
the number of hours that a controller can work. PHMSA recognizes there 
may be infrequent emergencies during which an operator may find the 
need to deviate from the maximum limit it has established to ensure 
adequate coverage in the control room for emergency response. 
Accordingly, the regulation provides that an operator's procedures may 
provide for the deviation from the maximum limit in the case of an 
emergency. Such a deviation would only be permitted if necessary for 
the safe operation of the pipeline facility. PHMSA or the head of the 
appropriate State agency, as the case may be, may review the 
reasonableness of any deviation from an operator's maximum limit on 
hours of service when considering whether to take enforcement action.
    All pipeline operators are subject to the fatigue management 
requirement, even those whose operations do not involve multiple 
shifts. Controller fatigue can affect even single-shift pipeline 
operations and the PIPES Act requires that all pipeline operators have 
a plan that addresses fatigue. PHMSA expects that small operators, many 
of which operate only a single shift, will be able to meet these 
requirements with little effort. Shift schedule rotation is not an 
issue for these operators and written instructional material (e.g., 
pamphlets) that can be reviewed during scheduled training may be 
sufficient to address the education and training requirements for such 
small operators.
    SCADA alarms are a key tool for managing pipeline operations, but 
excessive numbers of alarms can overwhelm controllers. This final rule 
will require pipeline operators to develop written alarm management 
plans. These plans must include monthly reviews of data points that 
have been taken off scan or have had forced or manual values for 
extended periods. Operators will also need to verify correct alarm set-
points, eliminate erroneous alarms, and review their alarm management 
plans at least annually. Proposed requirements for weekly reviews of 
issues related to alarm management and specified elements to include in 
annual reviews were not incorporated in the final rule. Some elements 
that would have been included in those weekly reviews, particularly 
``nuisance alarms,'' have been generalized to points that have had 
alarms inhibited (which would likely result if nuisance alarms occur) 
or which have generated false alarms, both of which are now required to 
be included in monthly reviews. Operators will also be required to 
monitor the content and volume of activity being directed to their 
controllers (including alarms and actions directed to controllers from 
sources other than the SCADA system) at least annually.
    Pipeline operators will be required to consider the effects of 
future changes to the pipeline on control room operations. They must 
involve controllers, controller representatives, or their management in 
planning prior to implementing significant hydraulic or configuration 
changes that could affect control room operations. This participation 
must be accomplished with enough time prior to the implementation to 
allow adequate training, procedure development and review by the 
affected controllers. Operators must also assure good communications 
when field personnel are implementing physical changes to pipeline 
equipment or configuration. Proposed requirements to track SCADA 
maintenance, coordinate SCADA changes in advance, and consider effects 
on control rooms in merger and acquisition plans have not been 
incorporated.
    Mergers and acquisitions are events that can introduce changes of 
importance to controllers. Acquired assets are often added to existing 
SCADA systems, or divested assets are removed. Other changes in 
operating practices may occur as a result of management changes 
associated with a merger. The proposed rule would have required that 
merger, acquisition, and divestiture plans be developed and used to 
establish and conduct controller training and qualification prior to 
the implementation of any changes to the controller's responsibilities. 
A unique section regarding merger, acquisition, and divestiture plans 
for the control room has not been included in the final rule, because 
these types of plans frequently include many elements that do not 
affect control rooms and controllers. Nevertheless, PHMSA considers 
that operators should take into account potential implications on 
control rooms during such events. Other requirements of this rule 
address many of the important factors affecting control room operations 
and controllers in a merger, acquisition, or divestiture. For example, 
operators will be required to consider additional alarms added to a 
controller station to determine whether they could create a ``flood'' 
that would potentially overwhelm the controller. PHMSA expects that 
operators would also consider alarm descriptors and prioritization if 
changes are made to a controller console. Changes to SCADA systems to 
incorporate new (or delete old) assets would trigger requirements

[[Page 63316]]

for display point validation and display design (i.e., required 
elements of API RP 1165). PHMSA thus considers that important changes 
associated with mergers, acquisitions, and divestitures are still 
addressed within this rule even though the proposed explicit 
requirement to address them in plans for these events has not been 
included.
    Pipeline operators will be required to review their operating 
experience to identify lessons that might improve control room 
management. Specifically, operators will be required to review any 
reportable event and determine if control room actions contributed to 
the event. This is more focused than the proposed requirement that 
operators review all reported incidents. Operators must identify, from 
these reviews, aspects of the event that may reflect on controller 
fatigue, field equipment, operation of any relief device, procedures, 
SCADA system configuration, and SCADA system performance. Operators 
must include lessons learned in controller training programs. The 
proposed rule requirement for operators to review ``near misses'' or 
events that did not meet criteria for reporting was not adopted in this 
rulemaking action, but such reviews are certainly encouraged.
    Pipeline operators will be required to have formal training 
programs including computer-based or non-computer (e.g., tabletop) 
simulations to train controllers to recognize and deal with abnormal 
events. The training must also provide controllers with a working 
knowledge of the pipeline system, particularly as it may affect the 
progression of abnormal events, and their communication 
responsibilities under the operator's emergency response plans. 
Proposed requirements that training include site-specific failure modes 
of equipment and site visits to a representative sample of field 
installations similar to those for which a controller is responsible 
were not adopted.
    Operators must, upon request of pipeline safety regulators, submit 
their completed control room management programs to the regulator for 
review. This replaces the proposed requirement that executives of 
pipeline operating companies submit to regulators annually a signed 
validation that: Controller training has been reviewed, only qualified 
controllers have been allowed to operate the pipeline, and the company 
continues to seek ways to improve control room operations. A request to 
review the plan will usually be in the course of a regulatory 
inspection where the adequacy of control room management plans and 
training will be reviewed, as will the operator's compliance with each 
of the above-referenced requirements.
    The proposed requirements related to a qualification program for 
controllers were not adopted. Controllers are still subject to existing 
requirements for operator qualification, which address similar 
subjects.

V. Response to the Comments

    The responses to comments in this section reflect PHMSA's 
consideration of the Advisory Committees' recommendations as well as 
the individual comments in the docket. A review of all submitted 
comments shows that the comments submitted by trade associations (API, 
AOPL, INGAA, AGA, and APGA), jointly and individually, address the 
comments of almost all pipeline operators. Some comments were on the 
preamble to the proposed rule. These comments will not be responded to 
unless they are relevant to this rulemaking action. Comments that were 
beyond the scope of this rulemaking action are not being addressed.

A. Liquefied Natural Gas (LNG) Facilities

    The joint trade associations; the Iowa Utilities Board; 11 LNG 
facility and gas pipeline operators; AGA; APGA; and one individual 
opposed addition of requirements into 49 CFR part 193 addressing LNG 
facilities.
    AGA and the LNG facility operators stated that the LNG facilities 
should not be included in the final rule because: (1) It was not the 
intent of Congress or the NTSB to include LNG in this regulation; (2) 
Congress expressly limited the CCERT study in the Pipeline Safety Act 
of 2002 to three pipeline facilities; (3) LNG facilities were not to be 
included in the pilot study; (4) LNG facilities are operated as plant 
sites with local control rooms; (5) Almost all of the text in the 
proposed amendments to 49 CFR part 193 is copied verbatim from the 
language for gas and hazardous liquid pipelines, but many of the 
requirements that are logical for pipelines make no sense in operating 
LNG plants; (6) The agency's own Regulatory Impact Analysis (RIA) study 
of the proposed rule clearly demonstrates no benefit that would offset 
the cost of including LNG facilities in the NPRM; (7) LNG facilities 
are regulated by 49 CFR part 193 and NFPA 59A, as incorporated by 
reference; and (8) The very detailed proposed control room rule creates 
confusion when added to the existing regulations. AGA and the joint 
trade associations suggested that PHMSA should initiate a separate 
rulemaking action focused on issues relevant to LNG facilities if it 
concludes that control room management requirements are needed for 
these facilities.
    Agency response--PHMSA agrees that the PIPES Act requirement 
regarding control room management does not explicitly refer to LNG 
facilities, nor are such facilities referenced in the PSIA legislation 
with regard to the controller certification pilot study. Similarly, 
NTSB did not address LNG facilities in its SCADA safety study and 
related recommendations. At the same time, neither Congress nor NTSB 
explicitly stated that control room management requirements should not 
be included for LNG facilities. Given the broad authority of PHMSA to 
regulate pipeline safety, including the safety of LNG facilities, the 
silence of the PIPES Act and the NTSB safety study with respect to LNG 
is not, by itself, a compelling reason why these facilities should be 
excluded from this rulemaking. However, through further review and 
consideration of the comments, PHMSA has determined that LNG should not 
be included in this rulemaking action at this time.
    After considering the comments and re-evaluating the basis for 
applying the same requirements to part 193 for LNG facilities, PHMSA is 
persuaded that there are several reasons why we should not have used 
the same requirements. LNG facilities are different from pipelines. As 
pointed out by commenters, LNG facilities exist on a single site, 
rather than dispersed over hundreds or thousands of miles, and LNG 
controllers thus have different knowledge of and working 
responsibilities for facility equipment. LNG controllers can, and do, 
walk to ``field'' equipment within minutes to monitor its condition or 
take local operating actions, whereas pipeline controllers may 
``interact'' with field equipment only via their SCADA systems. Because 
they operate equipment locally, LNG controllers have better operational 
knowledge of the equipment in their facilities, including its possible 
failure modes, than do most pipeline controllers. All of these 
differences diminish the value in improved safety that would result 
from implementing the proposed requirements at LNG facilities.
    In addition, the regulations in part 193 do not parallel precisely 
those in the other parts. For example, part 193 includes specific 
requirements applicable to control centers \5\ (49 CFR 193.2441) that 
were not in parts 192 or

[[Page 63317]]

195 prior to this rulemaking. This could create some degree of overlap, 
and potential confusion, if the requirements included in this final 
rule for Parts 192 and 195 were also incorporated into part 193. PHMSA 
thus has not included requirements for part 193 in this final rule.
---------------------------------------------------------------------------

    \5\ Control centers is the term used in part 193 to refer to 
what are called control rooms in this document.
---------------------------------------------------------------------------

B. Scope of the Rule and Related Definitions

    AGA stated that the proposed definitions of controller and control 
room had the effect of unreasonably expanding the scope of all rule 
sections. AGA stated that the proposed rule would regulate local, 
remote or field control rooms, panels and devices, but noted that 
local, remote or field control rooms are usually hardwired instead of 
operated via long-distance communications through SCADA. Because a 
controller or a technician can address problems and concerns with a few 
minutes' walk in these facilities, AGA contended local control rooms do 
not need the complicated procedures placed in this proposed rule.
    Other commenters agreed that the proposed definitions of 
``controller'' and ``control room'' were unreasonably broad and that 
they led to a scope that was broader than necessary. The Iowa Utilities 
Board (Iowa) stated that by defining a controller as someone who 
monitors ``or'' controls, instead of monitors ``and'' controls, the 
scope of the rule would unreasonably expand to include any facility 
with a pressure gauge, and any person who checks the pressure gauge. 
The joint trade associations' alternative regulatory language included 
revisions to definitions. Their alternate definitions for 
``controller'' and ``control room'' are based on API RP 1168. API and 
AOPL also stated that the NPRM definitions for ``controller'' and 
``control room'' are too broad. They recommended the agency adopt the 
API RP 1168 definitions for ``controller'' and ``control room'' as 
proposed in the joint trade associations' alternate language. Iowa 
agreed that the definition of controller and control room should be 
based on the definitions in API RP 1168. Iowa also suggested that the 
agency adopt the alternative regulatory language proposed by the trade 
associations. NAPSR proposed adopting the API RP 1168 control room and 
controller definitions to resolve the issue of jurisdictional authority 
for pipelines crossing state lines. The Missouri Public Service 
Commission (PSC) stated that it supports and concurs with the comments 
submitted by NAPSR. PSC also believes that the definitions of ``control 
room'' and ``controller'' noted in the NAPSR comments should be adopted 
in the rulemaking. All individual gas and hazardous liquids pipeline 
operators expressed similar concerns with the proposed rule definitions 
of ``controller'' and ``control room.''
    INGAA stated that the proposed regulations far exceed what Congress 
intended regarding the range of subjects covered, the range of 
facilities covered and the range of employees covered.
    The joint trade associations stated that the proposed rule had no 
scope statement to provide guidance regarding the application of the 
proposed rule. API and AOPL stated that the scope of the NPRM exceeds 
the intent of Congress. Individual pipeline operators echoed the 
comments of the joint trade associations and the individual trade 
associations. Many of the comment submitters are, like AGA, concerned 
with broad definitions of ``controller'' and ``control room.'' Also, 
some individuals commented that the scope of the proposed rule is too 
broad.
    APGA stated that the proposed rule should be re-written to be 
limited to true pipeline controllers and made reasonable for those 
operators. APGA noted that many small gas distribution pipeline 
operators, including many of its members, do not have control rooms and 
controllers in the same sense as do larger pipeline operators.
    Agency response--PHMSA agrees that the proposed definitions of 
``controller'' and ``control room'' had a rather pervasive effect on 
the scope of the requirements in the rule. In particular, PHMSA agrees 
with the Iowa Utilities Board that the proposed language could have 
been read to include personnel who monitor a pressure gauge (or other 
instrument) but have no authority or responsibility for pipeline 
operation. This result was unintended. PHMSA did not intend these 
requirements to apply to persons who may use SCADA information for non-
operational reasons, but rather to persons with operational duties and 
responsibilities that involve use of SCADA and who thus can directly 
effect on pipeline safety. PHMSA has made changes in the definitions in 
the final rule to clarify this intent.
    The inclusion of field control rooms and local control panels, 
however, was intended. The proposed rule was intended to apply to these 
control operations, in situations in which the person performing local 
control actions could not actually see the effect of those actions, 
based on the premise that the cognitive issues related to use of local 
computer-based controls were similar to those associated with use of 
SCADA in remote control rooms. PHMSA is persuaded by its review of the 
public comments that while cognitive issues may be similar, the 
potential effect on safety that could result from use of local 
computer-based controls are much less. As a result, PHMSA has modified 
the final rule to remove explicit requirements that local control 
panels be included in the actions required by this rule. Local control 
panels and field control rooms will only be included if they meet the 
definitions included in this rule, i.e., if they can have an effect on 
pipeline safety similar to that of a non-local control room.
    By revising the definition of control room in response to the 
comments, the agency has also limited the scope to control rooms with 
SCADA systems. In addition, the wording in the proposed definition is 
changed from ``monitoring or controlling'' to ``monitoring and 
controlling.'' It should be noted that a control room whose SCADA 
system is used only to monitor incoming data is still included in the 
requirements of the rule if the controllers otherwise act to 
``control'' the pipeline. Some control rooms have only monitoring 
capability in their SCADA system, but they achieve control through 
controllers responding to incoming data by other means such as by 
contacting field personnel and directing them to take action when 
necessary. If controllers prompt others to action (or perform those 
control action themselves) they are considered to ``control'' the 
pipeline. Therefore, the change from ``or'' to ``and'' does not exclude 
monitor-only control rooms from the scope of this rulemaking action. 
The change from ``or'' to ``and'' principally excludes individuals who 
may access and monitor SCADA system data for non-controller, incidental 
reasons, such as maintenance planning, equipment efficiency, or 
business logistics purposes. These persons cannot directly affect 
pipeline safety, because they are unable to use the SCADA system to 
take any controller actions.
    With respect to the definition of controller, the agency similarly 
narrowed the scope to eliminate persons who only use SCADA data 
incidentally and thus cannot directly affect pipeline safety. The 
definition now includes only those persons who monitor SCADA data from 
a control room and have ``operational authority and accountability for 
the remote operational functions of the pipeline facility as defined by 
the pipeline operator.'' As in the case of ``control room,'' the 
definition of ``controller'' has been modified from ``monitor or 
control'' to ``monitor and control.'' If a

[[Page 63318]]

SCADA system is designed and used in a control room only for monitoring 
purposes, and the individual contacts other personnel to initiate 
corrective actions after monitoring the SCADA system, that person is 
considered a controller.
    PHMSA considers that these changes to the definitions of ``control 
room'' and ``controller'' limit the scope of the proposed rule to those 
persons and operating centers that can directly affect pipeline safety. 
Most importantly, they eliminate the unintended apparent inclusion of 
certain employees who use SCADA data only incidentally. PHMSA considers 
that the revised definitions still encompass the majority of employees 
and control centers that were intended as the focus of this rulemaking. 
The changes in definitions address most, but not all comments 
concerning scope.
    PHMSA has revised the final rule to include a statement of scope to 
clarify that it applies to each operator of a pipeline facility with a 
controller working in a control room who monitors and controls all or 
part of a pipeline facility through a SCADA system. PHMSA has also 
revised the rule to exclude operators of some smaller gas pipeline 
systems from many of the rule's provisions. Specifically, gas 
distribution operators with less than 250,000 services and gas 
transmission operators without compressor stations are required only to 
comply with the provisions related to fatigue mitigation, validation, 
and compliance and deviation. These small and simple pipelines require 
far less controller action, obviating the need for the other 
provisions. There are often few or no actions that controllers of small 
distribution systems can take remotely. These systems operate at low 
pressures, providing significant time to identify and respond to 
unusual situations before any safety problem could result. Similarly, 
there are few actions that a controller of a transmission pipeline that 
does not include compressor stations can take to adversely affect 
safety. Most such pipelines are short. They often are the gas supply 
for local distribution companies, and are operated as an integral part 
of their distribution pipelines. They meet the definition of 
transmission pipelines because they operate above 20 percent SMYS or 
serve one of the functions included in the definition in section 192.3, 
but they represent a much smaller potential for safety issues. It 
should be noted, however, that this limited exclusion applies only if 
the operations from a gas operator's control room are limited to such 
smaller operations. The full requirements of the rule apply to 
operators of such pipelines if the operator also operates other 
pipelines outside of this limited exclusion from the same control room. 
For example, there may be large gas transmission operators who also 
operate small distribution pipelines or large LDCs that also have or 
operate transmission without compressors. In such cases, all the 
provisions of this rule apply to all of the operator's pipeline 
operations from a common control room.

C. Other Definitions

    The joint trade associations proposed changes to the definition of 
SCADA systems. The proposed rule would have defined these as ``a 
computer-based system that gathers field data, provides a structured 
view of pipeline system or facility operations, and may provide a means 
to control pipeline operations.'' This definition would have 
encompassed computer-based control systems in the field. The trade 
associations proposed that this definition be limited to systems used 
by controllers in the control room. This change is related to the 
concern over scope and the definition of ``controller'' and ``control 
room'' described above. The joint trade associations would also focus 
the definition of ``alarm'' on safety-related parameters, omitting 
reference to indications that operational parameters not related to 
safety are outside expected conditions.
    INGAA stated that the definition of ``alarm'' is not required or 
even contemplated by Congress for gas transmission pipelines and, 
therefore, should be deleted. On the definition of SCADA system, INGAA 
recommended that the agency adopt the definition provided by the joint 
trade associations.
    Agency response--Alarm management is a significant factor in 
control room management and is thus included in this rule. Excessive 
numbers of alarms or alarms that are inaccurate or not prioritized can 
overwhelm a controller, resulting in a failure to take appropriate 
action. Assuring appropriate management of control room alarms requires 
that the alarms of concern be defined. At the same time, PHMSA 
understands the industry's concern that SCADA systems are used to alarm 
many parameters that do not affect safety and that response to these 
parameters is outside what should be PHMSA's concern. Accordingly, 
PHMSA has revised the definition in the final rule to reflect that 
alarms of concern are those providing either or both audible and 
visible indications to controllers that equipment or processes are 
outside operator-defined, safety-related parameters. However, the final 
rule will require that operators monitor the content and volume of 
activity being directed to each controller.
    The final rule defines SCADA systems as a computer-based system or 
systems used by a controller in a control room that collects and 
displays information about a pipeline facility and may have the ability 
to send commands back to the pipeline. This excludes local computer-
based control stations for the reasons described above. Also as 
discussed above, control may be exercised by a controller notifying 
other personnel to take action. Control may also be accomplished 
through SCADA commands. The key factor is that the system provides 
information that allows control to occur, and systems that cannot send 
commands to operate pipeline equipment may thus still be SCADA systems 
under this definition.

D. Regulatory Analysis

    The joint trade associations stated that the preamble statement 
vastly underestimates the cost of the proposed regulations. They stated 
that the proposed rule would cost more than $100 million annually and 
that the preliminary regulatory analyses should have concluded that 
this was an economically significant rule under section 3(f)(1) of 
Executive Order 12866 (58 FR 51735; October 4, 1993) and DOT's 
regulatory policies and procedures (44 FR 11034; February 26, 1979). 
Also, they stated that the proposed rule has a significant regulatory 
impact within the meaning of 5 U.S.C. 601 et seq. They contended the 
proposed rule is contrary to the Unfunded Mandates Reform Act of 1995 
because a large portion of gas distribution systems are owned and 
operated by municipalities and local governments. In addition, the 
associations maintained that the proposed rule would impose substantial 
costs to state and local governments contrary to Executive Order 13132.
    AGA stated that its review of the proposed rule shows obvious 
errors in the analysis. AGA stated that it obtained rough estimates 
from some of its LDC members that show the proposed rule to be not cost 
beneficial on a national basis, and that it will exceed the $100 
million in annual costs threshold of a significant rule. AGA stated 
that a comparison of implementation costs between the proposed rule and 
that of the alternative regulatory language proposed by the joint trade 
associations shows the costs of the alternative regulatory language are 
approximately

[[Page 63319]]

14 to 15 percent of the costs of the proposed rule.
    INGAA stated that the benefits of the proposed rule for the gas 
transmission companies are unworthy of a rulemaking compared to the 
expected annual costs for the next 10 years of nearly $140,000,000.\6\ 
INGAA contends a handful of anecdotal data from an appendix to an 
unrelated study, some answers to hypothetical questions about 
theoretical possibilities and a series of assumptions with no 
foundation in the record do not constitute a legally defensible 
foundation for imposing detailed and costly regulations on the gas 
transmission pipeline industry.
---------------------------------------------------------------------------

    \6\ INGAA provided estimated implementation costs for selected 
requirements of the proposed rule at initial cost of $262,986,000 
and annually at $139,798,000.
---------------------------------------------------------------------------

    API and AOPL stated that they asked their members to comment on the 
number of employees that would be covered under the definition of 
``controller'' provided in the proposed rule; the aggregated cost 
estimate for training and qualifying these additional employees; and 
the estimated cost of point-to-point verification today and the 
projected estimate under the proposed rule. They stated that the cost 
estimates vary from operator to operator, but what each operator had in 
common was a tremendous increase in the number of additional employees 
that would need to be trained and qualified at an exorbitant cost. They 
stated that estimates on the increased number of employees under the 
proposed rule range from four times as many employees to train and 
qualify to more than ten times the current number of ``traditional 
controllers.'' The initial training and qualification costs ranged from 
$1.2 million to more than $5 million per operator with operators 
calculating these costs in a number of ways. The annual re-
qualification costs would average $500,000 per operator. The point-to-
point verification cost estimates averaged $500,000 per operator. They 
stated that one of their members included lost revenue from having to 
shut down the pump station, breakout storage tank areas, terminal 
deliveries and other hard assets in order to complete the point-to-
point test. Also, they stated that the RIA did not have estimates for 
Alarm management and Qualification. They stated that a company 
estimated that it would cost $52,000 per year to review SCADA 
operations at least once a week as proposed, and evaluating a 
controller's physical abilities and implementing methods to address 
gradual degradation would cost $60,000 initially for 400 controllers 
and $8,000 annually thereafter.
    Agency response--PHMSA has revised the regulatory analysis based on 
the revised scope of the rule, relevant comments received, and 
industry-submitted cost estimates. The scope of the rule is narrowed to 
exclude some gas LDCs and some gas transmission operators from most 
requirements in this rulemaking action. In addition, many of the 
individual requirements have been narrowed.
    PHMSA concludes that the widely varying estimates of cost between 
our RIA and industry estimates resulted largely from confusion 
concerning the definition of a controller. As discussed above, the 
definition in the proposed rule had the unintended effect of appearing 
to encompass pipeline operator employees who use SCADA data but have no 
operational responsibilities for the pipeline. This significantly 
increased the number of employees that would have been subject to the 
requirements affecting controllers (e.g., fatigue mitigation, training 
and qualification). PHMSA agrees that applying these requirements to a 
much larger number of personnel would incur costs significantly higher 
than estimated in the RIA. The revised definition in the final rule 
focuses the requirements on controllers working in control rooms with 
operational responsibility--and the revised RIA uses a more-realistic 
estimate of the numbers of these personnel that will be affected.
    Changes made in the final rule also significantly reduced the cost 
of elements not depending on the number of controllers affected. A 
major cost element was the proposed requirement for a one-time, 100 
percent verification of SCADA systems. Commenters pointed out that this 
requirement would have involved significant costs for very little 
benefit. It is unlikely that such a ``baseline'' verification would 
have identified significant problems that could affect safety. This is 
because SCADA systems are already installed and in use by operators, so 
readings have already been verified and problems of any significance 
would likely have surfaced in the normal course of using a SCADA system 
over time. Thus, PHMSA agrees that the significant effort that would be 
required for a 100 percent baseline verification is unlikely to result 
in commensurate safety benefit, and so the final rule eliminates that 
requirement. It requires, instead, that SCADA displays be verified when 
field equipment monitored by SCADA is moved or when other changes that 
affect pipeline safety are made to field equipment or displays. These 
kinds of changes can introduce errors that would affect subsequent 
SCADA operations. For this reason, SCADA information is typically 
verified when making these types of changes, to assure that the changes 
have been implemented properly and that all equipment is functioning as 
intended once work is completed. As a result, this re-focused SCADA 
verification requirement imposes much lower additional costs. It 
essentially has the effect of requiring that all pipeline operators 
take the same actions that a conscientious operator would take even if 
no requirement existed.
    The scope of required alarm verifications is also significantly 
reduced in this final rule. Commenters suggested that they would need 
to hire additional staff solely to perform the weekly and monthly 
reviews that would have been required by the proposed rule. PHMSA is 
persuaded that the alarm conditions are unlikely to change so much on a 
weekly basis, absent some significant ``event,'' that a thorough review 
would be needed on such a frequency. Response to an event would 
typically include the effect that the event may have had on alarms. The 
final rule has reduced these requirements to a monthly review of more-
limited scope and an annual review of the alarm management plan, 
significantly reducing expected costs.
    The revised RIA considers the changes in scope of the final rule 
and concludes that the rule is cost-beneficial.

E. Roles and Responsibilities

    AGA stated that Congress intended for pipeline operators, not the 
agency, to write their control room management plans due to the 
diversity of control rooms. AGA stated that PHMSA should not dictate to 
an operator what responsibilities and tasks should be written into an 
operator's plan, which AGA considered was the effect of the specific 
elements included in the proposed rule.
    API and AOPL supported the language in Paragraphs (b)(1)-(3) of the 
proposed rule (decision making during normal operations, role during 
abnormal events, and emergency role) and recommended deletion of 
paragraphs (b)(4) and (b)(5) (responsibility to coordinate with other 
operators having pipelines in common corridors and shift change). API 
and AOPL stated that operators currently maintain Emergency Response 
plans that address multi-pipeline corridors and appropriate 
notification and response procedures. They stated that these roles and 
responsibilities for controllers and other

[[Page 63320]]

field personnel are clearly defined in the notification and response 
procedures. They believed that PHMSA might find API RP 1168 useful in 
developing control room management programs related to roles and 
responsibilities.
    INGAA stated that this section should be deleted in its entirety 
because it runs counter to congressional direction and PHMSA's 
authority under Section 12 of the PIPES Act.
    Agency response--PHMSA agrees that it is appropriate for operators 
to define roles and responsibilities for controllers, because of the 
many varied circumstances of different pipelines, their control rooms, 
and their operating practices. The proposed rule would have required 
that operators define these roles and responsibilities, and this has 
been retained in the final rule. The proposed rule went on to list 
certain roles and responsibilities that operators were to include in 
their definition. These have been deleted. PHMSA will verify during 
inspections that operators have appropriately defined the roles and 
responsibilities for their controllers.
    PHMSA acknowledges API/AOPL's support of the proposed elements 
addressing normal operations, abnormal operations, and emergencies. 
These elements have been retained in the final 192.631(b) and 
195.446(b) (Note: For editorial purposes PHMSA has moved the 
requirements proposed as Sec.  195.454 to Sec.  195.446). PHMSA also 
acknowledges the concerns expressed by AGA and gas pipeline operators 
that these elements tend to dictate the content (in part) of the roles 
and responsibilities the operator must define; however, PHMSA considers 
it essential that an operator's defined roles and responsibilities 
address normal, abnormal, and emergency operating conditions. The final 
rule does not include specific responsibilities for each of these 
conditions, but does require that the operator's definition consider 
them all.
    PHMSA disagrees that it is not necessary to address shift change. 
Experience has shown the importance of controlling the transfer of 
information between controllers. Incidents, accidents, and other 
problems have occurred because of inadequate shift change. PHMSA has 
deleted the specific alternative mechanisms for recording a shift 
change that were included in the proposed rule (a system log-in feature 
or recording in shift records), but the final rule still requires that 
operators establish a method of recording controller shift changes. 
Operators are also required to define the information that controllers 
must discuss or exchange during shift changes and other instances in 
which another controller assumes responsibility.

F. Providing Adequate Information

    AGA disagrees with periodic point-to-point verification 
requirements except to show that the SCADA system displays accurately 
depict field configuration when any modification affecting safety is 
made to field equipment or applicable software, and when new field 
equipment is installed.
    INGAA stated that ``Adequate'' would seem to include those points 
that affect pipeline safety, and not each of the points that collect 
information about the pipeline which are completely unrelated to 
safety. INGAA estimates the safety-related points to be significantly 
outnumbered by the non-safety-related points.
    API and AOPL stated that their members' experience shows that re-
verification offers few safety benefits in return for the large 
investment in SCADA system and field resources that would be required. 
They suggested the emphasis of the regulation should be on management 
of change, rather than re-verification.
    The proposed requirement to implement API RP 1165 for SCADA 
displays also caused concern. Pipeline operators objected to the 
requirement to apply the standard to existing displays, noting that 
controllers have been trained and have experience in using existing 
systems and that any benefit from implementing the standard would 
likely be small. Other operators objected to the incorporation of the 
standard or suggested that alternatives be allowed. AGA and several 
operators suggested that operators be required to implement the 
``general'' requirements of the standard.
    INGAA commented that the ``critical'' information required to be 
exchanged during shift changes required more definition. Some pipeline 
operators objected to the proposed requirement to provide an overlap 
between shifts to allow for shift change. API and AOPL suggested that 
PHMSA consider adopting API RP 1168 to govern shift change 
requirements.
    Agency response--PHMSA has eliminated from the final rule the 
proposed requirement to perform 100 percent baseline verification of 
SCADA systems. PHMSA has also eliminated the proposed requirement that 
operators plan for systematic re-verification. As discussed above (see 
paragraph D of this section), PHMSA concluded that a baseline 
verification was unlikely to identify safety-related problems that had 
not already been recognized through normal operations. Similarly, new 
problems are likely to be identified as part of normal work before a 
re-verification would find them. As a result, the significant effort 
that would be required to implement these two requirements would result 
in little foreseen safety benefit. The final rule requires that 
operators verify SCADA when changes are made that can affect the 
information displayed by SCADA. SCADA problems are most likely to be 
introduced when making changes and verification that the SCADA system 
functions as intended are a means of identifying such problems.
    With respect to API RP 1165, PHMSA agrees that applying the 
standard to existing displays is likely to lead to little safety 
benefit for the cost incurred, since controllers have already been 
trained and are experienced in using existing displays in their current 
operations. In addition, changes made to existing displays would 
require retraining of controllers and could introduce confusion 
unnecessarily. When displays are changed, however, retraining will be 
needed because of the change and the reasons for not disrupting 
controllers' use of displays with which they are familiar no longer 
apply. PHMSA has limited the requirement to apply the standard to 
displays that are added, expanded or replaced after the date by which 
the control room management procedures required by this rule must be 
implemented. For gas pipelines, the final rule requires that only 
certain sections of the standard be implemented. The cited sections 
address the aspects that are most important to assuring that displays 
are configured to be most useful to controllers for managing safe 
pipeline operations, including human factors engineering. PHMSA is not 
aware of equivalent standards that would accomplish the same purpose, 
and has not provided for an alternative. Flexibility is available in 
that operators need not implement a provision of API RP 1165 if they 
demonstrate that the provision is not practical for the SCADA system 
used.
    PHMSA has eliminated the requirement to provide for overlap of 
shifts to facilitate shift turnover. Overlaps will likely be needed to 
accommodate the need to transfer information to an oncoming controller. 
The transfer of information is required, obviating the need to specify 
an overlap requirement in the regulation. The final rule for gas 
pipeline operators requires that operators establish procedures for 
when a different controller assumes responsibility, including the 
content of information that must be exchanged, but

[[Page 63321]]

has deleted the requirement that ``critical'' information must be 
included. It will be up to operators to define the information that is 
important to impart to oncoming controllers. API RP 1168 provides 
guidance that can assist in this definition. This standard is 
incorporated by reference for this purpose for hazardous liquid 
pipeline operators. PHMSA will verify during inspections that operators 
have included in their definitions the information needed by their 
controllers to assure pipeline safety.

G. Fatigue Mitigation

    The National Transportation Safety Board (NTSB) stated that it does 
not believe the proposed rule satisfactorily addresses mitigation of 
controller fatigue. NTSB stated that the proposed rule should require 
operators of pipeline facilities to incorporate fatigue research, 
circadian rhythms, and sleep and rest requirements when establishing a 
maximum limit on controller shift length, maximum limit on controller 
hours of service, and schedule rotations. Also, NTSB stated that it 
would like PHMSA to provide additional information about the agency's 
criteria for evaluating operators' plans and to explain how the agency 
intends to monitor the effectiveness of implementing those plans on 
fatigue mitigation.
    Some individuals suggested that the proposed rule does not go far 
enough. Some suggested a need for a uniform maximum hours of work limit 
to be established in the regulations. These individuals stated that the 
rule needs to set standards to decrease the likelihood of controller 
fatigue rather than passing that duty on to operators. They stated that 
the proposed rule does not set standards regarding fixed versus 
rotating shifts and does not set standards for the length of each 
rotation. One individual suggested setting shifts at ten hours with two 
hours overlap between beginning and end of shifts and with a three 
consecutive day break. Some suggested using part-time workers to 
overlap 12 hour shifts. One stated that the agency should redraft the 
vague provisions found in the shift change and fatigue sections and 
should provide more specific examples for the pipeline operators to 
adequately comply with the rule. One individual stated that for the 
proposed rule to increase vigilance and mitigate fatigue, the agency 
must address boredom and monotony. One suggested that the agency should 
consider methods that specifically address mental fatigue and an 
adrenaline response training program for all pipeline workers.
    Other citizens supported the proposed rule on fatigue mitigation. 
One stated that fatigue management should be implemented on an intra-
company basis based on the individual needs of the controllers rather 
than on an industry-wide scale. Others commended the agency for not 
prescribing a maximum hours of work limit. Some supported the need for 
testing of physical and visual abilities for controllers. One 
individual suggested a requirement for controllers to check if they are 
physically fit to perform the tasks assigned. One individual suggested 
implementing a requirement that workers make observational entries 
every quarter hour to ensure that they remain engaged in their duties 
and maintain continual mental vigilance throughout a shift.
    AGA objected to requiring that operators implement additional 
measures to monitor for fatigue when a single controller is on duty. 
AGA stated that the gas distribution industry's safety record has 
demonstrated that a single controller can safely operate a pipeline.
    API and AOPL suggested that PHMSA modify paragraph (d) of the 
proposed rule to reflect that despite reasonable fatigue mitigation 
measures the operator may not be able to ``prevent'' fatigue from 
occurring. Also, they encouraged PHMSA to consider adopting the 
language in Section 6 of API RP 1168 on Fatigue Management.
    INGAA stated that the joint trade associations' substitute rule 
addresses fatigue. INGAA stated that it urges adoption of these 
provisions along with the rest of the substitute rule.
    Agency response--Fatigue can be an important factor affecting 
controller performance. NTSB has recommended that PHMSA establish 
requirements in this area, and the PIPES Act requires that operator 
human factors plans include a maximum hours of service limit. Fatigue 
is something that affects all people at some time and many individual 
comment submitters have suggested ways in dealing with this issue. 
Nonetheless, PHMSA agrees that it is difficult to establish and enforce 
regulations that ``prevent'' fatigue. In this final rule, PHMSA 
requires that operators implement methods to reduce the risks 
associated with fatigue.
    Pipeline operators will be required to comply with a maximum hours 
of service limit. This rule does not establish such a limit, but rather 
requires that each operator establish a reasonable limit for itself. 
This will allow consideration of factors that may be unique to the 
operation of particular pipelines. Experience has also shown that 
deviations from normal scheduling (e.g., requiring a controller to work 
a double shift due to unexpected absence) can result in excessive 
fatigue; establishing a limit will have the effect of reducing the 
occurrence of these deviations.
    At the same time, PHMSA recognizes there may be infrequent 
emergencies during which an operator may find the need to deviate from 
the maximum limit it has established to ensure adequate coverage in the 
control room for emergency response. Accordingly, the regulation 
provides that an operator's procedures may provide for the deviation 
from the maximum limit in the case of an emergency. Such a deviation 
would only be permitted if necessary for the safe operation of the 
pipeline facility. PHMSA or the head of the appropriate State agency, 
as the case may be, may review the reasonableness of any deviation from 
an operator's maximum limit on hours of service when considering 
whether to take enforcement action.
    PHMSA has not included an explicit requirement that operators 
incorporate fatigue research and circadian rhythms when establishing 
their limits. Operators will be expected to have a scientific basis for 
the limit they select. PHMSA expects that operators will consider 
circadian effects, need for rest, and other factors highlighted by 
relevant research, but PHMSA sees no benefit in including general 
references to these factors in this rule. PHMSA has included in this 
final rule a requirement that shift lengths and schedule rotations 
provide controllers sufficient off-duty time to achieve eight hours of 
continuous sleep. This addresses NTSB's concerns that sleep and rest 
needs to be accommodated. PHMSA has already issued an advisory bulletin 
providing guidance to pipeline operators on ways to manage fatigue,\7\ 
and may issue additional guidance if new research, operational 
experience, or other factors indicate a need to do so.
---------------------------------------------------------------------------

    \7\ ADB-05-06, August 11, 2005 (70 FR 46917).
---------------------------------------------------------------------------

    PHMSA has not yet developed criteria for reviewing operator-
developed hours of service limits and human factors management 
procedures, but plans to develop inspection criteria.
    PHMSA has not included in this final rule a requirement to provide 
additional measures to address fatigue in situations where a single 
controller is on duty. Operators will need to address single-controller 
situations in their fatigue management plans, but no particular 
additional measures are required to monitor fatigue of a single 
controller at this time.

[[Page 63322]]

H. Alarm Management

    AGA stated that the proposed rule for alarm management is overly 
prescriptive. AGA requested that language be written at a high level to 
account for the diversity of control room systems used by different 
operators.
    API and AOPL stated that they believe the alarm management 
requirement of the proposed rule is too prescriptive and will not 
result in an application of ``best practices'' as currently written. 
API and AOPL suggested that PHMSA require each operator to maintain an 
alarm management plan based on currently accepted industry practices. 
They stated that the plan should be based on a company's risk 
assessment related to alarm management and include regular audits and 
reviews of the alarm system performance to identify areas for training 
and improvement. They also stated that a company should assess risks 
associated with alarming and modify its program as needed on a less 
frequent basis.
    INGAA stated that this section should be deleted in its entirety 
because it runs counter to congressional direction as expressed in 
Section 12 of the PIPES Act and because it will not increase pipeline 
safety. INGAA urged the agency to adopt the joint trade associations' 
substitute rule for alarm management. INGAA also contended that the 
requirement would be very costly to implement.
    Agency response--The alarm management provisions included in the 
NPRM were prescriptive and required frequent reviews. In addition, some 
of the required review elements would have been difficult to identify. 
For example, weekly reviews would have been required to include events 
that should have resulted in alarms but did not. Such events could be 
identified using SCADA data (even though they did not produce alarms) 
but would have required detailed review to do so. PHMSA is persuaded by 
the comments that the proposed provisions would have been burdensome 
and might not necessarily have addressed factors important for alarm 
management in particular pipeline control rooms. Instead, PHMSA has 
adopted the suggestions to require that each operator have an alarm 
management plan. Operators will develop those plans in recognition of 
issues that have proven important to their operations.
    The final rule continues to require that alarm management plans 
include some critical elements. Foremost among these is a monthly 
review of points impacting safety that are not providing current data 
to controllers or points that may be triggering erroneous alarms. 
Operators respond to problems that occur in SCADA systems (and which 
can result in inaccurate information being displayed) by taking the 
points ``off scan,'' which means operators manually ``force'' certain 
information to be displayed. Controllers are generally made aware that 
the affected data is not timely and accurate, but the forced values (or 
no values at all) help prevent confusion. Operators return the data 
points to normal operation once the problems with the SCADA system have 
been identified and corrected. Generally, SCADA systems involve many 
data points (often thousands) and controllers are able to manage 
pipeline operations and respond to abnormal events even though some 
data is not current. Still, PHMSA considers it important that SCADA 
problems be addressed promptly, so that controllers have the most 
accurate and timely information with which to diagnose and respond to 
pipeline events. The monthly review is intended to assure that the need 
to address SCADA problems promptly is not lost in the crush of other 
activities.
    The final rule will also require that operators monitor the content 
and volume of activity being directed to each controller. This 
requirement is intended to identify so-called alarm ``floods,'' which 
can involve many alarms (often not relating to pipeline safety) 
occurring simultaneously or in a short period. Such floods can 
overwhelm the capability of a controller to recognize problems and 
events that may underlie the alarms, and thus delay prompt response. 
PHMSA accepts the point made by commenters that the agency should not 
be regulating use of SCADA alarms for purposes not related directly to 
pipeline safety, but still considers that it is important to assure 
that controllers' ability to respond appropriately to safety-related 
alarms is not compromised. The requirement to monitor for volume and 
content of activity is intended to do this. Operators who identify 
situations in which controllers are receiving more information or 
required to perform more activities than they can process and address 
will be expected to take appropriate corrective action in a timely 
fashion.
    It is also critical that operators verify correct alarm set points 
and descriptions, review their alarm management plans regularly, but at 
least annually, and address deficiencies identified in their reviews. 
Accordingly, these elements are also included in the final rule.

I. Operating Experience

    AGA requested that the proposed requirements related to review of 
operating experience be deleted in their entirety, because AGA 
contended that they are duplicative of other sections in 49 CFR parts 
191 and 192. AGA, INGAA, and others also objected to the proposed 
requirement that operators establish a threshold for near-miss events 
(i.e., events of some significance but which do not meet criteria for 
reporting to regulators as an incident) and include them in periodic 
reviews. The comments noted that this concept is impractical and would 
be difficult to enforce, that it effectively elevates these ``near-
miss'' events to equality with incidents requiring reporting, and that 
it would add significant additional burden for very little benefit.
    INGAA stated that this section should be deleted in its entirety 
because it runs counter to congressional direction as expressed in 
Section 12 of the PIPES Act and because it will not increase pipeline 
safety.
    API and AOPL suggested deleting requirements associated with the 
need to review accuracy, timeliness and portrayal of field information 
on SCADA displays and review of events that do not meet the threshold 
for reporting as accidents.
    One individual commented that having controllers review non-
reportable events, along with other activities that this rule is 
imposing on controllers, would require an excessive amount of valuable 
time.
    Agency response--PHMSA does not agree that the proposed review 
requirements duplicate existing requirements. The requirements in this 
rule will build on existing requirements to identify and report 
incidents that meet certain criteria. PHMSA recognizes that those 
regulations require that operators review events to identify 
information that must be reported. The requirements in this rule are 
focused on identifying the effect of operational events on controllers, 
controller workload, and the ability of controllers to manage pipeline 
operations safely. PHMSA expects that these additional considerations 
will be included in the reviews of incidents currently conducted. 
Adding these considerations to existing reviews should result in 
minimal additional burden, but will help improve safe pipeline 
operations. The final rule will require that operators consider, in 
their reviews of reportable events, deficiencies relating to controller 
fatigue, field equipment, the operation of any relief device, SCADA 
system configuration, and SCADA

[[Page 63323]]

performance. Operators will be required to incorporate lessons learned 
from these reviews into controller training programs.
    PHMSA is persuaded that the requirement to conduct similar reviews 
for events that do not meet reporting criteria (i.e., near-miss events) 
is not necessary at this time. These events are not subject to reviews 
related to the need to submit information concerning the event, because 
operators are not required to report them. Accordingly, the entire 
review effort would be additional, rather than control-room 
considerations being a minimal addition of effort to an already-
required review. Furthermore, these events have less safety 
significance than those that must be reported. The proposed provision 
to review near-miss events for control room lessons has thus not been 
included in the final rule, but PHMSA encourages operators to use near-
miss information to advance pipeline safety.

J. Change Management

    AGA requested that change management be removed from the proposed 
rule. AGA stated that the concept is best left to individuals familiar 
with an operator's entire operations and maintenance manual. AGA 
further stated that the person managing operations and maintenance 
should address the changes that can impact the job of a controller or 
any pipeline function. AGA stated that since most changes to a pipeline 
system have nothing to do with controllers, the change management 
concept should not be introduced into pipeline safety through a control 
room management rule.
    API and AOPL recommended that PHMSA consider replacing the proposed 
language concerning change management with the language contained in 
Section 7 of API RP 1168. They stated that the proposed language is too 
prescriptive, would cause delays in implementation, and result in 
additional costs with no real benefit to justify these additional 
procedures.
    INGAA stated that this section should be deleted in its entirety 
because it runs counter to congressional direction as expressed in 
Section 12 of the PIPES Act, and because it will not increase pipeline 
safety.
    Agency response--Not all pipeline changes affect controllers or 
control room operations. Some do, however, and it is important that 
controllers recognize that such changes are occurring, have sufficient 
training before they occur, and understand how they will affect the 
response of the pipeline to operational events. PHMSA has thus retained 
requirements for change management in the final rule.
    At the same time, PHMSA agrees that the proposed requirements were 
too prescriptive and that pipeline operators should have flexibility in 
integrating change management into their organizational structure and 
business operations. The final rule requires that gas pipeline 
operators establish communications between control room 
representatives, management, and field personnel when planning and 
implementing physical changes to pipeline equipment or configurations. 
Operators must seek control room or control room management 
participation prior to implementing significant pipeline hydraulic or 
configuration changes. Field personnel will also be required to notify 
the controller when emergency conditions exist or when making field 
changes that affect control room operations. These requirements will 
assure that changes that could affect the ability of controllers to 
monitor the pipeline and assure safe operation are identified early so 
that training programs and procedures can be modified, if needed, and 
controllers can be made aware of changes that could affect their 
activities.
    Operators of hazardous liquid pipelines will be required to 
implement change management provisions in Section 7 of API RP 1168. 
These are similar to the requirements for gas pipeline operators 
discussed above. PHMSA recognizes that Section 7 of API RP 1168, and 
other recommended practices incorporated by reference, commonly use the 
word ``should'' to denote a recommendation or that which is advised but 
not required. For example, paragraph 7.1 of API RP 1168 states that 
``[p]ipeline control room personnel should be included in the project 
or change design and planning process.'' Where a standard incorporated 
by reference utilizes words of recommendation, such as ``should,'' an 
operator is expected to follow such provisions unless the operator has 
documented the technical basis for not implementing the recommendation. 
This has been PHMSA's position with regard to compliance with standards 
incorporated by reference that utilize words of recommendation. See, 
e.g., 64 FR 15926, Apr. 2, 1999. In the above-referenced example, an 
operator would be expected to include control room personnel in the 
project or change design and planning process unless the operator can 
show the technical basis for why this could not occur.

K. Training and Qualification

    A citizen suggested the use of videos instead of site visits for 
controllers. One individual suggested the use of a standardized 
examination for certification of controllers based on each pipeline's 
configuration, and a requirement for operators to consider the 
educational background of the individuals applying for a controller 
position. Another individual suggested controller feedback on training.
    AGA requested that the Training section be deleted because 49 CFR 
part 192, subpart N provides operator qualification rules for all 
pipeline employees performing covered tasks.
    INGAA stated that this section should be deleted in its entirety 
because it exceeds congressional direction and PHMSA's authority under 
Section 12 of the PIPES Act and because it will not increase pipeline 
safety.
    API and AOPL stated that under the proposed rule's overly broad 
definitions of ``controller'' and ``control room,'' operators would 
have to expend considerable resources to meet the proposed 
requirements. They suggested deleting some sections from the proposed 
rule.
    One individual agreed with an industry practice of a three year re-
qualification period rather than annual re-qualification as proposed by 
PHMSA.
    Agency response--Training is an important element of this rule. In 
many ways, training needs for controllers are different from those for 
other pipeline employees. Existing operator qualification requirements 
(subpart N of part 192 and subpart G of part 195) address training and 
qualification for specific tasks meeting certain criteria (called 
``covered tasks''). Controllers require training that goes beyond 
specific tasks. They must be able to recognize abnormal and emergency 
events from the indications and alarms that these events will produce 
through SCADA. NTSB has recognized that controllers need this training 
and has recommended that PHMSA establish requirements for controller 
training that include simulator or non-computerized (e.g., tabletop 
exercises) training to recognize abnormal operating conditions, in 
particular leak events. The PIPES Act mandates that PHMSA implement 
standards in response to this NTSB recommendation. Accordingly, PHMSA 
has included such training requirements in this final rule.
    PHMSA has revised the final rule to eliminate some of the specific 
elements that the proposed rule would have required to be included in 
this training. In particular, PHMSA has eliminated

[[Page 63324]]

the requirements that controller training include site visits to a 
representative sample of pipeline facilities similar to those for which 
the controller is responsible and that controllers receive hydraulic 
training sufficient to attain a thorough knowledge of the pipeline 
system. PHMSA agrees that these proposed requirements would have 
entailed benefit that was difficult to quantify. A site visit, for 
example, might impart some knowledge concerning what is required to 
operate equipment at the site but would be unlikely to result in 
lasting detailed knowledge about equipment operation and the potential 
effects of equipment failures. Instead, the final rule requires that 
controller training be sufficient to obtain a working knowledge of the 
pipeline system, especially during the development of abnormal 
conditions. Controller training must also include use of simulators or 
non-computerized simulations for training in identification of abnormal 
operating conditions. These requirements will assure that controllers 
receive the training recommended by NTSB, and required by the PIPES 
Act, while allowing operators flexibility to design training programs 
that fit their operations.

L. Executive Validation

    AGA requested that the senior executive validation requirements be 
removed from the rule. AGA commented that since the executive cannot 
approve the plan on the agency's behalf, it is not logical for the 
executive to independently approve the plan just to have the agency 
subsequently approve or reject the plan.
    API and AOPL stated that they would like to work with PHMSA to more 
clearly define operator accountability. They stated that the paragraph, 
as currently worded with ``senior executive officer,'' is 
inappropriate. They stated that the definition of ``senior executive 
officer'' differs among operators, and API and AOPL would like to 
better understand what the term means to PHMSA. They stated that many 
of their members also commented that verifying that ergonomic and 
fatigue factors continue to be addressed or that controllers are 
involved in finding ways to improve safety is more appropriate for a 
lower level of management than what would constitute a ``senior 
executive officer.'' Even if it were appropriate for executive signoff, 
they said they believe the current language of the proposed amendments 
is too narrow and specific.
    INGAA stated that requirements for executive validation should be 
deleted in their entirety. INGAA said this section is inconsistent with 
congressional direction and will not increase pipeline safety. INGAA 
stated that it understands the value of the proposed requirement to 
validate that the requirements of this rule have been implemented, 
since it could engender increased confidence and oversight of the 
respective control rooms and associated processes.
    INGAA stated that it sees no demonstrable safety benefit discussed 
in the proposed rule and there are no tangible benefits to be gained by 
promulgating this section.
    One individual stated that the senior executive officer validation 
should be required every three years.
    Agency response--The purpose of this proposed provision was to 
assure management attention to control room issues. A senior executive 
would have been required to certify annually that the operator had 
reviewed controller training and qualification programs and found them 
adequate, that only qualified controllers had been allowed to operate 
the pipeline, that the requirements of this rule had been complied 
with, that the operator continued to address fatigue and ergonomic 
issues, and that controllers were involved in continuing efforts to 
sustain and improve safety. This was not intended to substitute for 
approval of a plan by the regulator, but rather to assure that a plan 
submitted to the regulator had obtained appropriate management approval 
within the operator's organization.
    PHMSA agrees with commenters that it is likely that specific 
actions included within the proposed verification would be performed by 
lower-level managers and staff. The extent of actions that might have 
been required (or implied) was unclear in some cases. For example, 
ergonomic issues are not otherwise addressed in the proposed rule, but 
only in the proposed requirement that a senior officer certify that 
they were continuing to be addressed. PHMSA has, therefore, decided not 
to include the proposed requirement for periodic management 
certification in this rulemaking action.
    PHMSA has included in this final rule a requirement that operators, 
upon request, must submit their completed control room management plans 
to PHMSA or, in the case of an intrastate pipeline facility regulated 
by the state, to the appropriate state agency. PHMSA expects that 
regulators (state or PHMSA) will generally review plans, and compliance 
with the requirements of this final rule, through the regular 
inspection process.

M. Qualification of Pipeline Personnel

    INGAA stated that it supported the development of 49 CFR part 192, 
subpart N, when it was initially promulgated, and still believes it to 
be valid, including as it applies to controllers. Also, INGAA stated 
that it supports the use of the national consensus-based standard ASME 
B31Q, which addresses controller issues as well. INGAA stated that it 
does not see the need for a qualification section in this proposed 
rule, and notes the PIPES Act does not contemplate this section, 
either.
    API and AOPL stated that they believe PHMSA would create confusion 
by keeping this particular paragraph in the final rule. They recommend 
that PHMSA delete proposed paragraph (i) and consider incorporating the 
requirements into the current subpart G--Qualification of Pipeline 
Personnel. They stated that if ``qualification'' refers to any other 
purpose than ``OQ'', then PHMSA needs to clarify that requirement. API 
and AOPL stated that they support the concept in paragraph (i)(2) of 
the proposed rule concerning evaluating a controller's physical 
abilities; however, they recommended that it be deleted because it 
creates confusion among operators until further research can be 
performed to develop standardized thresholds for the various physical 
attributes. Also, they stated their concern that compliance with the 
requirements in this paragraph could result in violation of the 
Americans with Disabilities Act.
    AGA expressed concern that PHMSA is essentially rewriting the 
Operator Qualification rule. AGA stated that the two paragraphs for 
controller training and qualification are almost as long as 49 CFR part 
192, subpart N, which provides operator qualification rules for all 
pipeline covered employees.
    Agency response--PHMSA is persuaded by the comments to eliminate 
from this final rule specific requirements for periodic qualification 
of controllers, deferring to the existing operator qualification 
regulations in that regard. PHMSA recognizes, however, that certain 
changes to operators' controller qualification criteria will result 
from implementing the new requirements in this final rule and that 
operators will incorporate those changes, as necessary, into their 
qualification programs.

N. Implementation

    The proposed rule would have established different deadlines for 
preparing and implementing control room management procedures,

[[Page 63325]]

depending on the type of pipeline or control room. Proposed time frames 
varied from 12 to 30 months after publication of the final rule. 
Industry comments generally found the proposed time frames 
inappropriate. The draft alternative rule language submitted by the 
joint trade associations included a requirement that procedures be 
written within 18 months following publication of the final rule and be 
implemented within 3 years of publication.
    Agency response--The elimination of local control stations from the 
final rule's scope, and its focus on control rooms using SCADA systems, 
makes it unnecessary to establish differing implementation schedules 
for control regimes of differing complexity. PHMSA agrees that the 
implementation time frames proposed by the joint trade associations 
would allow for a thorough process development phase before 
implementation, a familiarity with standards under development (such as 
International Society of Automation (ISA) 18.02 and API RP 1167), and 
an appropriate implementation time to promote consistency and 
understanding among operators. We have therefore, incorporated these 
time frames into the final rule.

VI. Regulatory Analyses and Notices

A. Statutory/Legal Authority for This Rulemaking

    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. This rulemaking also carries out the mandates of 
the PIPES Act of 2006--to address human factors and other aspects of 
control room management for pipelines where controllers use supervisory 
control and data acquisition (SCADA) systems (section 12) and to 
publish standards implementing certain NTSB recommendations (section 
19).

B. Executive Order 12866 and DOT Policies and Procedures

    This rulemaking action has been designated a significant regulatory 
action under Executive Order 12866 (58 FR 51735; Oct. 4, 1993). The 
rule is also a significant regulatory action under the U.S. Department 
of Transportation regulatory policies and procedures (44 FR 11034; Feb. 
26, 1979) because of the substantial congressional, industry, and 
public interest in control room operations and human factors management 
plans. Therefore, the Office of Management and Budget (OMB) has 
reviewed a copy of this rulemaking.
    The expected benefits of the rulemaking action are the reduction in 
pipeline incidents and accidents resulting from controller error and 
the associated societal costs that can be attributed to improved 
control room management and operations. The estimated benefits consist 
of two distinct measures: (1) The reduction in incidents and accidents 
due to errors attributed to control room personnel and (2) the 
reduction of societal costs related to those incidents and accidents 
that can be traced to factors related to control room operations 
management. Control room personnel errors can occur, for example, when 
a fatigued control room worker reads a pressure indicator incorrectly 
and increases pressure, leading to a pipeline rupture. Control room 
management errors occur when a procedure or process is not in place 
resulting in failure to detect an abnormal condition or a failure to 
respond to an incident or accident appropriately. For example, alarm 
systems may not be audited and an incident occurs that does not trigger 
an alarm. The remedial action (the rule) addresses both personnel error 
and operations management.
    This rulemaking action is not expected to adversely affect the 
economy or the environment. For those costs and benefits that can be 
quantified the present value of net benefits, discounted at 7 percent, 
are expected to be about $6 million over a ten-year period after all of 
the requirements are implemented. This rule is also not expected to 
have an annual effect of more than $100 million on the national 
economy; therefore, the rule is not considered an economically 
significant regulatory action within the meaning of Executive Order 
12866.
    A complete RIA, including an analysis of costs and benefits, is 
available in the docket.

C. Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA 
must consider whether its rulemaking actions would have a significant 
economic impact on a substantial number of small entities. There were 
some changes going from the NPRM to the final rule that considered the 
concerns of small businesses. First, in response to industry's comments 
and to reduce the burden on small firms, PHMSA redefined the criteria 
to better differentiate between large operations that would be subject 
to all the requirements and those smaller operations that would have 
more limited regulation. PHMSA clarified the type of operators that 
would be affected by refining the definitions of controller and control 
room to determine which operators would need to be subject to the 
requirements. Then, PHMSA separated the operators based on risk to 
determine which operators needed to comply with the requirements. This 
redefinition reduced the number of requirements for small entities. 
Most small firms are now only required to comply with certain 
requirements mandated by law, namely fatigue mitigation (including 
training), and recordkeeping for compliance purposes.
    Second, to better understand the distribution of systems based on 
size in the pipeline industry, PHMSA examined the operators' annual 
reports to further separate the firms by small, medium and large 
operations. The categories for this analysis were determined either by 
the number of pipeline miles, the number of customers served, or the 
complexity of the business. PHMSA has made every effort to limit the 
economic impact to small firms by taking steps to exempt gas 
distribution operators with fewer than 250,000 services from many of 
the requirements likely to have more than minimal cost impacts.
    Based on the submission of annual reports, PHMSA estimates that 
there are 220 hazardous liquid (HL) system operators with fewer than 50 
miles of pipeline that meet the definition of small entities. Also 
PHMSA estimated that 1,257 of 1,330 gas distribution systems and 475 of 
950 transmission systems (for a total of 1,732 gas systems) fit the 
definition of a small operator.
    The table below summarizes the expected compliance cost per small 
operator.

----------------------------------------------------------------------------------------------------------------
                    First-year costs                                      Annual recurring costs
----------------------------------------------------------------------------------------------------------------
            Low                          High                         Low                        High
----------------------------------------------------------------------------------------------------------------
           $6,000                               $9,000                      $2,300                      $2,800
----------------------------------------------------------------------------------------------------------------

[[Page 63326]]

    Although PHMSA does not have revenue data for the individual small 
pipeline operators, based on the most recent published operator revenue 
data, the estimated costs are significantly less than one percent of 
revenues for most firms and there is not likely to be a significant 
impact on a substantial small number of operators.\8\
---------------------------------------------------------------------------

    \8\ See: http://www.ibisworld.com/industry/
retail.aspx?indid=1179&chid=1; http://www.ibisworld.com/industry/
retail.aspx?indid=1184&chid=1; http://www.ibisworld.com/industry/
retail.aspx?indid=1181&chid=1; http://www.bts.gov/publications/
national_transportation_statistics/html/table_03_18.html.
---------------------------------------------------------------------------

    Therefore, based on this information showing that the economic 
impact of this rule on small entities will be minor, I certify under 
section 605 of the Regulatory Flexibility Act that these regulations 
will not have a significant impact on a substantial number of small 
entities. The final Regulatory Flexibility Analysis is available in the 
docket.

D. Executive Order 13175

    PHMSA has analyzed this rulemaking action according to Executive 
Order 13175, ``Consultation and Coordination with Indian Tribal 
Governments.'' Because this rulemaking action would 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.

E. Paperwork Reduction Act

    As required by the Paperwork Reduction Act of 1995 (44 U.S.C. 
3507(d)), DOT will submit all necessary documents to request the Office 
of Management and Budget (OMB) grant approval for a new information 
collection. A copy of the analysis document will also be entered in the 
docket. The RIA contains detailed information on how PHMSA arrived at 
the cost and time estimates noted below.
    This final rule contains information collection requirements that 
affect hazardous liquid and gas pipeline systems. The rule requires 
hazardous liquid and gas pipeline operators to keep records on the 
following sections: Control room management procedures; roles and 
responsibilities of pipeline controllers; information on SCADAs, 
fatigue mitigation; alarm management; change management; operating 
experience; training; compliance validation; and deviations. PHMSA 
estimates that it would take pipeline operators approximately 127,328 
hours per year to comply with the rule's recordkeeping and record 
retention requirements. PHMSA estimates that the total costs are 
approximately between $4.3 million and $5.9 million the first-year and 
approximately between $4.2 million and $5.8 million in successive 
years. The RIA has the details on the estimates used in this analysis.

F. Unfunded Mandates Reform Act of 1995

    This rulemaking action does not impose unfunded mandates under the 
Unfunded Mandates Reform Act of 1995. It does not result in costs of 
$141.3 million or more 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 this rulemaking action.

G. National Environmental Policy Act

    PHMSA has analyzed this rulemaking action for the purposes of the 
National Environmental Policy Act (42 U.S.C. 4321 et seq.). The agency 
has determined that implementation of this rule will not have any 
significant impact on the quality of the human environment. The 
environmental assessment is available for review in the docket.

H. Executive Order 13132

    PHMSA has analyzed this rulemaking action according to Executive 
Order 13132 (``Federalism''). The rulemaking action 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 
rulemaking action does not impose substantial direct compliance costs 
on State and local governments. Further, no consultation is needed to 
discuss the preemptive effect of the proposed rule. The pipeline safety 
laws, specifically 49 U.S.C. 60104(c), prohibits State safety 
regulation of interstate pipelines. Under the pipeline safety law, 
States have the ability to augment pipeline safety requirements for 
intrastate pipelines regulated by PHMSA, but may not approve safety 
requirements less stringent than those required by Federal law. A State 
may also regulate an intrastate pipeline facility PHMSA does not 
regulate. It is these statutory provisions, not the rule, that govern 
preemption of State law. Therefore, the consultation and funding 
requirements of Executive Order 13132 do not apply.

I. Executive Order 13211

    Transporting gas and hazardous liquids impacts the nation's 
available energy supply. However, this rulemaking action is not a 
``significant energy action'' under Executive Order 13211 and is not 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy. Further, the Administrator of the 
Office of Information and Regulatory Affairs has not identified this 
rulemaking action as a significant energy action.

J. Privacy Act Statement

    You may search the electronic form of comments received in response 
to any of our dockets by the name of the individual submitting the 
comment (or signing the comment if submitted for an association, 
business, labor union, etc.). You may review DOT's complete Privacy Act 
Statement in the Federal Register published on April 11, 2000 (65 FR 
19477).

List of Subjects

49 CFR Part 192

    Incorporation by reference, Gas, Natural gas, Pipeline safety, 
Reporting and recordkeeping requirements.

49 CFR Part 195

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

0
For the reasons set forth in the preamble, the Pipeline and Hazardous 
Materials Safety Administration is amending 49 CFR Chapter I as 
follows:

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

0
1. The authority citation for part 192 is revised to read as follows:

    Authority:  49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 
60113, 60116, 60118, and 60137; and 49 CFR 1.53.

0
2. In Sec.  192.3, definitions for ``alarm,'' ``control room,'' 
``controller,'' and ``Supervisory Control and Data Acquisition (SCADA) 
system'' are added in appropriate alphabetical order as follows:

Sec.  192.3  Definitions.

* * * * *
    Alarm means an audible or visible means of indicating to the 
controller that equipment or processes are outside operator-defined, 
safety-related parameters.
    Control room means an operations center staffed by personnel 
charged with the responsibility for remotely monitoring and controlling 
a pipeline facility.
    Controller means a qualified individual who remotely monitors and

[[Page 63327]]

controls the safety-related operations of a pipeline facility via a 
SCADA system from a control room, and who has operational authority and 
accountability for the remote operational functions of the pipeline 
facility.
* * * * *
    Supervisory Control and Data Acquisition (SCADA) system means a 
computer-based system or systems used by a controller in a control room 
that collects and displays information about a pipeline facility and 
may have the ability to send commands back to the pipeline facility.
* * * * *
0
3. Amend Sec.  192.7 as follows:
0
a. In paragraph (b) add ``202-366-4595'' after ``20590-001;''
0
b. In the table in paragraph (c)(2), item B.(7) is added to read as 
follows:

Sec.  192.7  What documents are incorporated by reference partly or 
wholly in this part?

* * * * *
    (c) * * *
    (2) * * *

------------------------------------------------------------------------
    Source and name of referenced
              material                         49 CFR reference
------------------------------------------------------------------------

                              * * * * * * *
B. * * *                              ..................................
(7) API Recommended Practice 1165     Sec.   192.631(c)(1).
 ``Recommended Practice for Pipeline
 SCADA Displays,'' (API RP 1165)
 First edition (January 2007).

                              * * * * * * *
------------------------------------------------------------------------

* * * * *

0
4. In Sec.  192.605, paragraph (b)(12) is added to read as follows:

Sec.  192.605  Procedural manual for operations, maintenance, and 
emergencies.

* * * * *
    (b) * * *
    (12) Implementing the applicable control room management procedures 
required by Sec.  192.631.
* * * * *
0
5. In Sec.  192.615, paragraph (a)(11) is added to read as follows:

Sec.  192.615  Emergency plans.

    (a) * * *
    (11) Actions required to be taken by a controller during an 
emergency in accordance with Sec.  192.631.
* * * * *
0
6. Section 192.631 is added to Subpart L to read as follows:

Sec.  192.631  Control room management.

    (a) General.
    (1) This section applies to each operator of a pipeline facility 
with a controller working in a control room who monitors and controls 
all or part of a pipeline facility through a SCADA system. Each 
operator must have and follow written control room management 
procedures that implement the requirements of this section, except that 
for each control room where an operator's activities are limited to 
either or both of:
    (i) Distribution with less than 250,000 services, or
    (ii) Transmission without a compressor station, the operator must 
have and follow written procedures that implement only paragraphs (d) 
(regarding fatigue), (i) (regarding compliance validation), and (j) 
(regarding compliance and deviations) of this section.
    (2) The procedures required by this section must be integrated, as 
appropriate, with operating and emergency procedures required by 
Sec. Sec.  192.605 and 192.615. An operator must develop the procedures 
no later than August 1, 2011 and implement the procedures no later than 
Febraury 1, 2012.
    (b) Roles and responsibilities. Each operator must define the roles 
and responsibilities of a controller during normal, abnormal, and 
emergency operating conditions. To provide for a controller's prompt 
and appropriate response to operating conditions, an operator must 
define each of the following:
    (1) A controller's authority and responsibility to make decisions 
and take actions during normal operations;
    (2) A controller's role when an abnormal operating condition is 
detected, even if the controller is not the first to detect the 
condition, including the controller's responsibility to take specific 
actions and to communicate with others;
    (3) A controller's role during an emergency, even if the controller 
is not the first to detect the emergency, including the controller's 
responsibility to take specific actions and to communicate with others; 
and
    (4) A method of recording controller shift-changes and any hand-
over of responsibility between controllers.
    (c) Provide adequate information. Each operator must provide its 
controllers with the information, tools, processes and procedures 
necessary for the controllers to carry out the roles and 
responsibilities the operator has defined by performing each of the 
following:
    (1) Implement sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 
(incorporated by reference, see Sec.  192.7) whenever a SCADA system is 
added, expanded or replaced, unless the operator demonstrates that 
certain provisions of sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 
1165 are not practical for the SCADA system used;
    (2) Conduct a point-to-point verification between SCADA displays 
and related field equipment when field equipment is added or moved and 
when other changes that affect pipeline safety are made to field 
equipment or SCADA displays;
    (3) Test and verify an internal communication plan to provide 
adequate means for manual operation of the pipeline safely, at least 
once each calendar year, but at intervals not to exceed 15 months;
    (4) Test any backup SCADA systems at least once each calendar year, 
but at intervals not to exceed 15 months; and
    (5) Establish and implement procedures for when a different 
controller assumes responsibility, including the content of information 
to be exchanged.
    (d) Fatigue mitigation. Each operator must implement the following 
methods to reduce the risk associated with controller fatigue that 
could inhibit a controller's ability to carry out the roles and 
responsibilities the operator has defined:
    (1) Establish shift lengths and schedule rotations that provide 
controllers off-duty time sufficient to achieve eight hours of 
continuous sleep;
    (2) Educate controllers and supervisors in fatigue mitigation 
strategies and how off-duty activities contribute to fatigue;
    (3) Train controllers and supervisors to recognize the effects of 
fatigue; and
    (4) Establish a maximum limit on controller hours-of-service, which 
may provide for an emergency deviation from the maximum limit if 
necessary for the safe operation of a pipeline facility.

[[Page 63328]]

    (e) Alarm management. Each operator using a SCADA system must have 
a written alarm management plan to provide for effective controller 
response to alarms. An operator's plan must include provisions to:
    (1) Review SCADA safety-related alarm operations using a process 
that ensures alarms are accurate and support safe pipeline operations;
    (2) Identify at least once each calendar month points affecting 
safety that have been taken off scan in the SCADA host, have had alarms 
inhibited, generated false alarms, or that have had forced or manual 
values for periods of time exceeding that required for associated 
maintenance or operating activities;
    (3) Verify the correct safety-related alarm set-point values and 
alarm descriptions at least once each calendar year, but at intervals 
not to exceed 15 months;
    (4) Review the alarm management plan required by this paragraph at 
least once each calendar year, but at intervals not exceeding 15 
months, to determine the effectiveness of the plan;
    (5) Monitor the content and volume of general activity being 
directed to and required of each controller at least once each calendar 
year, but at intervals not to exceed 15 months, that will assure 
controllers have sufficient time to analyze and react to incoming 
alarms; and
    (6) Address deficiencies identified through the implementation of 
paragraphs (e)(1) through (e)(5) of this section.
    (f) Change management. Each operator must assure that changes that 
could affect control room operations are coordinated with the control 
room personnel by performing each of the following:
    (1) Establish communications between control room representatives, 
operator's management, and associated field personnel when planning and 
implementing physical changes to pipeline equipment or configuration;
    (2) Require its field personnel to contact the control room when 
emergency conditions exist and when making field changes that affect 
control room operations; and
    (3) Seek control room or control room management participation in 
planning prior to implementation of significant pipeline hydraulic or 
configuration changes.
    (g) Operating experience. Each operator must assure that lessons 
learned from its operating experience are incorporated, as appropriate, 
into its control room management procedures by performing each of the 
following:
    (1) Review incidents that must be reported pursuant to 49 CFR part 
191 to determine if control room actions contributed to the event and, 
if so, correct, where necessary, deficiencies related to:
    (i) Controller fatigue;
    (ii) Field equipment;
    (iii) The operation of any relief device;
    (iv) Procedures;
    (v) SCADA system configuration; and
    (vi) SCADA system performance.
    (2) Include lessons learned from the operator's experience in the 
training program required by this section.
    (h) Training. Each operator must establish a controller training 
program and review the training program content to identify potential 
improvements at least once each calendar year, but at intervals not to 
exceed 15 months. An operator's program must provide for training each 
controller to carry out the roles and responsibilities defined by the 
operator. In addition, the training program must include the following 
elements:
    (1) Responding to abnormal operating conditions likely to occur 
simultaneously or in sequence;
    (2) Use of a computerized simulator or non-computerized (tabletop) 
method for training controllers to recognize abnormal operating 
conditions;
    (3) Training controllers on their responsibilities for 
communication under the operator's emergency response procedures;
    (4) Training that will provide a controller a working knowledge of 
the pipeline system, especially during the development of abnormal 
operating conditions; and
    (5) For pipeline operating setups that are periodically, but 
infrequently used, providing an opportunity for controllers to review 
relevant procedures in advance of their application.
    (i) Compliance validation. Upon request, operators must submit 
their procedures to PHMSA or, in the case of an intrastate pipeline 
facility regulated by a State, to the appropriate State agency.
    (j) Compliance and deviations. An operator must maintain for review 
during inspection:
    (1) Records that demonstrate compliance with the requirements of 
this section; and
    (2) Documentation to demonstrate that any deviation from the 
procedures required by this section was necessary for the safe 
operation of a pipeline facility.

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
7. The authority citation for part 195 is amended to read as follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60116, 
60118, and 60137; and 49 CFR 1.53.

0
8. In Sec.  195.2, definitions for ``alarm,'' ``control room,'' 
``controller,'' and ``Supervisory Control and Data Acquisition (SCADA) 
system'' are added in appropriate alphabetical order as follows:

Sec.  195.2  Definitions.

* * * * *
    Alarm means an audible or visible means of indicating to the 
controller that equipment or processes are outside operator-defined, 
safety-related parameters.
* * * * *
    Control room means an operations center staffed by personnel 
charged with the responsibility for remotely monitoring and controlling 
a pipeline facility.
    Controller means a qualified individual who remotely monitors and 
controls the safety-related operations of a pipeline facility via a 
SCADA system from a control room, and who has operational authority and 
accountability for the remote operational functions of the pipeline 
facility.
* * * * *
    Supervisory Control and Data Acquisition (SCADA) system means a 
computer-based system or systems used by a controller in a control room 
that collects and displays information about a pipeline facility and 
may have the ability to send commands back to the pipeline facility.
* * * * *
0
9. Amend 195.3 as follows:
0
a. In paragraph (b) add ``202-366-4595'' after ``20590-001'';
0
b. In the table in paragraph (c) items B.(18) and B.(19) are added to 
read as follows:

Sec.  195.3  Incorporation by reference.

* * * * *
    (c) * * *

[[Page 63329]]

------------------------------------------------------------------------
    Source and name of referenced
              material                         49 CFR reference
------------------------------------------------------------------------

                              * * * * * * *
B. * * *
(18) API Recommended Practice 1165    Sec.   195.446(c)(1).
 ``Recommended Practice for Pipeline
 SCADA Displays,'' (API RP 1165)
 First Edition (January 2007).
(19) API Recommended Practice 1168    Sec.   195.446(c)(5).
 ``Pipeline Control Room
 Management,'' (API RP 1168) First
 Edition (September 2008).

                              * * * * * * *
------------------------------------------------------------------------

0
10. In Sec.  195.402, paragraph (c)(15) and (e)(10) are added to read 
as follows:

Sec.  195.402  Procedural manual for operations, maintenance, and 
emergencies.

* * * * *
    (c) * * *
    (15) Implementing the applicable control room management procedures 
required by Sec.  195.446.
* * * * *
    (e) * * *
    (10) Actions required to be taken by a controller during an 
emergency, in accordance with Sec.  195.446.
* * * * *

0
11. Section 195.446 is added to read as follows:

Sec.  195.446  Control room management.

    (a) General. This section applies to each operator of a pipeline 
facility with a controller working in a control room who monitors and 
controls all or part of a pipeline facility through a SCADA system. 
Each operator must have and follow written control room management 
procedures that implement the requirements of this section. The 
procedures required by this section must be integrated, as appropriate, 
with the operator's written procedures required by Sec.  195.402. An 
operator must develop the procedures no later than August 1, 2011 and 
implement the procedures no later than February 1, 2012.
    (b) Roles and responsibilities. Each operator must define the roles 
and responsibilities of a controller during normal, abnormal, and 
emergency operating conditions. To provide for a controller's prompt 
and appropriate response to operating conditions, an operator must 
define each of the following:
    (1) A controller's authority and responsibility to make decisions 
and take actions during normal operations;
    (2) A controller's role when an abnormal operating condition is 
detected, even if the controller is not the first to detect the 
condition, including the controller's responsibility to take specific 
actions and to communicate with others;
    (3) A controller's role during an emergency, even if the controller 
is not the first to detect the emergency, including the controller's 
responsibility to take specific actions and to communicate with others; 
and
    (4) A method of recording controller shift-changes and any hand-
over of responsibility between controllers.
    (c) Provide adequate information. Each operator must provide its 
controllers with the information, tools, processes and procedures 
necessary for the controllers to carry out the roles and 
responsibilities the operator has defined by performing each of the 
following:
    (1) Implement API RP 1165 (incorporated by reference, see Sec.  
195.3) whenever a SCADA system is added, expanded or replaced, unless 
the operator demonstrates that certain provisions of API RP 1165 are 
not practical for the SCADA system used;
    (2) Conduct a point-to-point verification between SCADA displays 
and related field equipment when field equipment is added or moved and 
when other changes that affect pipeline safety are made to field 
equipment or SCADA displays;
    (3) Test and verify an internal communication plan to provide 
adequate means for manual operation of the pipeline safely, at least 
once each calendar year, but at intervals not to exceed 15 months;
    (4) Test any backup SCADA systems at least once each calendar year, 
but at intervals not to exceed 15 months; and
    (5) Implement section 5 of API RP 1168 (incorporated by reference, 
see Sec.  195.3) to establish procedures for when a different 
controller assumes responsibility, including the content of information 
to be exchanged.
    (d) Fatigue mitigation. Each operator must implement the following 
methods to reduce the risk associated with controller fatigue that 
could inhibit a controller's ability to carry out the roles and 
responsibilities the operator has defined:
    (1) Establish shift lengths and schedule rotations that provide 
controllers off-duty time sufficient to achieve eight hours of 
continuous sleep;
    (2) Educate controllers and supervisors in fatigue mitigation 
strategies and how off-duty activities contribute to fatigue;
    (3) Train controllers and supervisors to recognize the effects of 
fatigue; and
    (4) Establish a maximum limit on controller hours-of-service, which 
may provide for an emergency deviation from the maximum limit if 
necessary for the safe operation of a pipeline facility.
    (e) Alarm management. Each operator using a SCADA system must have 
a written alarm management plan to provide for effective controller 
response to alarms. An operator's plan must include provisions to:
    (1) Review SCADA safety-related alarm operations using a process 
that ensures alarms are accurate and support safe pipeline operations;
    (2) Identify at least once each calendar month points affecting 
safety that have been taken off scan in the SCADA host, have had alarms 
inhibited, generated false alarms, or that have had forced or manual 
values for periods of time exceeding that required for associated 
maintenance or operating activities;
    (3) Verify the correct safety-related alarm set-point values and 
alarm descriptions when associated field instruments are calibrated or 
changed and at least once each calendar year, but at intervals not to 
exceed 15 months;
    (4) Review the alarm management plan required by this paragraph at 
least once each calendar year, but at intervals not exceeding 15 
months, to determine the effectiveness of the plan;
    (5) Monitor the content and volume of general activity being 
directed to and required of each controller at least once each calendar 
year, but at intervals not exceeding 15 months, that will assure 
controllers have sufficient time to analyze and react to incoming 
alarms; and
    (6) Address deficiencies identified through the implementation of 
paragraphs (e)(1) through (e)(5) of this section.
    (f) Change management. Each operator must assure that changes that 
could affect control room operations are coordinated with the control 
room

[[Page 63330]]

personnel by performing each of the following:
    (1) Implement section 7 of API RP 1168 (incorporated by reference, 
see Sec.  195.3) for control room management change and require 
coordination between control room representatives, operator's 
management, and associated field personnel when planning and 
implementing physical changes to pipeline equipment or configuration; 
and
    (2) Require its field personnel to contact the control room when 
emergency conditions exist and when making field changes that affect 
control room operations.
    (g) Operating experience. Each operator must assure that lessons 
learned from its operating experience are incorporated, as appropriate, 
into its control room management procedures by performing each of the 
following:
    (1) Review accidents that must be reported pursuant to Sec.  195.50 
and 195.52 to determine if control room actions contributed to the 
event and, if so, correct, where necessary, deficiencies related to:
    (i) Controller fatigue;
    (ii) Field equipment;
    (iii) The operation of any relief device;
    (iv) Procedures;
    (v) SCADA system configuration; and
    (vi) SCADA system performance.
    (2) Include lessons learned from the operator's experience in the 
training program required by this section.
    (h) Training. Each operator must establish a controller training 
program and review the training program content to identify potential 
improvements at least once each calendar year, but at intervals not to 
exceed 15 months. An operator's program must provide for training each 
controller to carry out the roles and responsibilities defined by the 
operator. In addition, the training program must include the following 
elements:
    (1) Responding to abnormal operating conditions likely to occur 
simultaneously or in sequence;
    (2) Use of a computerized simulator or non-computerized (tabletop) 
method for training controllers to recognize abnormal operating 
conditions;
    (3) Training controllers on their responsibilities for 
communication under the operator's emergency response procedures;
    (4) Training that will provide a controller a working knowledge of 
the pipeline system, especially during the development of abnormal 
operating conditions; and
    (5) For pipeline operating setups that are periodically, but 
infrequently used, providing an opportunity for controllers to review 
relevant procedures in advance of their application.
    (i) Compliance validation. Upon request, operators must submit 
their procedures to PHMSA or, in the case of an intrastate pipeline 
facility regulated by a State, to the appropriate State agency.
    (j) Compliance and deviations. An operator must maintain for review 
during inspection:
    (1) Records that demonstrate compliance with the requirements of 
this section; and
    (2) Documentation to demonstrate that any deviation from the 
procedures required by this section was necessary for the safe 
operation of the pipeline facility.

    Issued in Washington, DC, on November 20, 2009 under authority 
delegated in 49 CFR part 1.
Cynthia L. Quarterman,
Administrator.
[FR Doc. E9-28469 Filed 12-2-09; 8:45 am]

BILLING CODE 4910-60-P