Pipeline Safety: Control Room Management/Human Factors, 63310-63330 [E9-28469]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[Federal Register Volume 74, Number 231 (Thursday, December 3, 2009)]
[Rules and Regulations]
[Pages 63310-63330]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-28469]


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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 https://www.regulations.gov. General information about 
PHMSA may be found at https://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