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									Balancing Authority/Transmission Operator
    Reliability Readiness Audit Report


        Lafayette Utilities System
         (City of Lafayette, LA)




               June 19–22, 2006

            Lafayette, Louisiana




         North American Electric Reliability Council
NERC 2006 Reliability Readiness Audit Report
Lafayette Utilities System

                                                         Table of Contents
Introduction and Audit Process....................................................................................................... 1
Audit Team ..................................................................................................................................... 1
Organization Profile........................................................................................................................ 2
Executive Summary ........................................................................................................................ 2
Positive Observations...................................................................................................................... 2
Recommendations........................................................................................................................... 2
Discussion ....................................................................................................................................... 4
1. Agreements ............................................................................................................................... 4
2. Operator Authority.................................................................................................................... 4
3. Delegation of Authority ............................................................................................................ 4
4. Staff Certification...................................................................................................................... 5
5. Training..................................................................................................................................... 5
6. Operating Policies and Operating Procedures .......................................................................... 6
7. Planning .................................................................................................................................... 7
8. Outage Coordination and Communication ............................................................................... 8
9. Plans for the Loss of Control Facilities..................................................................................... 9
10. Tools ......................................................................................................................................... 9
11. Load Shedding Plans............................................................................................................... 10
12. Real-Time Monitoring ............................................................................................................ 11
    a. System Visibility............................................................................................................... 11
    b. Alarms............................................................................................................................... 11
    c. Frequency.......................................................................................................................... 12
    d. Voltage/Reactive Reserve................................................................................................. 12
    e. Critical Facilities............................................................................................................... 13
    f. Transmission System Congestion ..................................................................................... 13
    g. Load Generation Balance.................................................................................................. 13
    h. Contingency Reserves....................................................................................................... 14
    i. Special Protection Systems ............................................................................................... 15
13. System Restoration ................................................................................................................. 15
14. Capacity and Energy Emergency Plan.................................................................................... 16
15. Equipment Maintenance and Testing...................................................................................... 16
16. Vegetation and Rights of Way Management .......................................................................... 17
17. Nuclear Power Plant Requirements ........................................................................................ 17
APPENDIX 1: Critical Energy Infrastructure ............................................................................. 18
APPENDIX 2: Audit Participants................................................................................................ 19
APPENDIX 3: Documents Reviewed ......................................................................................... 20




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NERC 2006 Reliability Readiness Audit Report
Lafayette Utilities System

Introduction and Audit Process
The North American Electric Reliability Council (NERC) Reliability Readiness Audit and
Improvement Program is one of the commitments of NERC and the industry following the
blackout of August 14, 2003, to strengthen the reliability of the North American bulk power
system. The program conducts independent audits of balancing authorities, transmission
operators, reliability coordinators, and other key entities that support the reliable operation of the
bulk power system to assess their preparedness to meet their assigned reliability responsibilities.
The audits identify strengths and areas for improvement in an effort to promote excellence in
operations among these organizations. The document NERC Readiness Audit Procedure
describes and defines the process used for reliability readiness audits. This document and other
documents related to the program are available at http://www.nerc.com/~rap/.

The reliability readiness audit teams, each led by a NERC staff member and a regional co-leader,
include industry volunteers with considerable expertise selected to provide representation from
other interconnections, other regions, and neighboring operating entities. The teams also
typically include representatives from the Federal Energy Regulatory Commission (FERC) staff.

The public version of the reliability readiness audit report contains the majority of the audit
team’s findings. Any discussion of findings pertaining to critical energy infrastructure will be
contained in Appendix 1, a confidential appendix to the report that is sent privately to the
organization audited and is not included in the public version of the report.

The audit team for the Lafayette Utilities System (City of Lafayette, LA) (LAFA) met on-site
with LAFA representatives on June 19–22, 2006. This report reflects the views and
recommendations of the audit team regarding the readiness of the LAFA to meet its
responsibilities as a balancing authority/transmission operator.

Audit Team
Jacqueline Power*      NERC
Ron Ciesiel*           Southwest Power Pool (SPP)
Darryl Boggess         Western Farmer’s Electric Cooperative (WFEC)
Pawel Krupa            Seattle City Light (SCL)
Howard Rulf            Wisconsin Energy

*Team co-leader




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NERC 2006 Reliability Readiness Audit Report
Lafayette Utilities System

Organization Profile
The Lafayette Utilities System (LAFA), originally established as a utility service for the city of
Lafayette, is publicly owned and operated by the Lafayette Consolidated Government. LAFA
provides electric energy, water, wastewater, and internet services to more than 110,000 residents
of the city of Lafayette, a geographical area of approximately 48 square miles. The system
operators located at the field operations complex monitor and control the electric, water,
wastewater, and telecommunication systems.

LAFA is a vertically integrated energy service provider, covering a geographical area mainly
around the city of Lafayette. LAFA interconnects with Entergy at two 138 kV tie points and
with CLECO Corporation (CLEC) via one 230 kV, two 138 kV, and one 69 kV tie points.
LAFA owns 39 miles of transmission lines and 200 miles of distribution lines that service 56,000
electrical customers. LAFA’s peak load was 438 MW, which occurred on August 24, 2005.
LAFA owns three steam turbine units with a total plant capacity of 297 MW and four gas
combustion turbine units with a combined capacity of 208 MW. Also, LAFA has 50 percent
ownership of a steam turbine generating plant outside its service area, with an entitlement of 250
MW.

Executive Summary
The audit team found no significant operational problems and concluded that the LAFA
balancing authority/transmission operator has adequate facilities, processes, plans, procedures,
tools, and trained personnel to perform its balancing authority/transmission operator reliability
functions, with one notable exception in the area of training. The audit team identified several
positive observations. It also offers 24 recommendations that, if implemented, will greatly
enhance LAFA reliability readiness. The findings are listed in order of importance.

Positive Observations
The audit team noted the following positive observations during the reliability readiness audit
process:
1. LAFA requires all its system operators to carry a memory stick that contains emergency
   procedures, energy management system (EMS) vendor procedures, and normal and
   emergency contact numbers (Section 9).
2. LAFA has developed a very good dynamic load shedding tool and display (Section 11).
3. LAFA’s vegetation management program shows emphasis on transmission assets by
   performance of continuous trimming activities (Section 16).

Recommendations
The audit team recommends that LAFA take the following actions to address issues discovered
during the audit process:
1. Evaluate operations staffing levels to address the following items:
      a. Shift coverage requirements (Section 4)
      b. Dedicated training time for real-time operations staff (Section 5)
      c. Training development for LAFA-specific training requirements, including, but not
          limited to, the following training: (Section 5)


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NERC 2006 Reliability Readiness Audit Report
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                  i. System restoration
                 ii. Backup control center
                iii. Energy management system
        d. Development of a document control process
2. Develop, implement, and maintain a formalized training program for initial and continuing
    training, including an effort to (Section 5):
        a. Identify personnel responsible for training
        b. Identify training time for each certified operations personnel
3. Expand, formalize, and maintain documentation for completion of the on-the-job training
    checklist, specifying skills and knowledge items necessary for trainees to achieve
    competencies and proficiency (Section 5).
4. Develop and document an evaluation process for verification of a trainee’s ability to perform
    work independently (Section 5).
5. Develop a formal tracking methodology and documentation containing a summary of each
    individual system operator’s completed training hours and courses (Section 5).
6. Develop documentation of training topics and objectives that are delivered to the real-time
    operations staff during bimonthly shift meetings (Section 5).
7. Develop, implement, and maintain a formalized document control methodology. Include, at
    a minimum, the following items: (Section 6)
        a. Revision dates, review history, and approval signature
        b. A review cycle for all procedures and policies
8. Develop a long-range protective relay maintenance plan and schedule for existing generation
    units (Section 15).
9. Revise the existing Loss of Primary Control Center procedures to address manual area
    control error (ACE) calculation, documentation of energy schedules, and notification
    requirements (Section 9).
10. Complete the development of the backup control center, per the existing projected scheduled
    date of July 31, 2006 (Section 9).
11. Develop summary overview and geographical displays in the EMS for the LAFA footprint
    and consider expanding LAFA’s system wid-area view (Section 12.a).
12. Develop a generator reactive testing program and schedule, per Southwest Power Pool (SPP)
    Criteria 12.1.6 (Section 12.d).
13. Determine a synchronization process and incorporate synchronization instructions into
    LAFA’s system restoration plan (Section 13).
14. Document system restoration training and performance of system restoration simulation once
    every three years (Section 13).
15. Perform an evaluation of the combustion turbines for use as SPP blackstart units (Section
    13).
16. Provide copies of the capacity and energy emergency plan and system restoration plan to
    neighboring entities (Sections 13 and 14).
17. Revise section five of the capacity and energy emergency plan to change the review policy
    from a three-year cycle to an annual review (Section 14).
18. Require relay personnel communicate to the system operator when real-time relay
    maintenance activities are being performed (Section 15).
19.–24. See discussion in Appendix 1.



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NERC 2006 Reliability Readiness Audit Report
Lafayette Utilities System

Discussion
The reliability readiness audit team examined the following key areas during the audit. The
detailed discussion that follows provides the foundation for the recommendations, positive
observations, and potential examples of excellence that the team identified. The report uses the
generic term “system operator” to refer to all on-shift operating personnel responsible for
executing the functions necessary to operate reliably and maintain the reliable operation of the
bulk power system. This term will be used for the discussions unless additional specificity is
required, such as the balancing system operator, or transmission system operator.

1. Agreements
The balancing authority must have agreements that establish its authority as a balancing
authority. The balancing authority/transmission operator must have agreements that establish
the reliability coordinator for its footprint.

LAFA has the necessary facility connection agreements. These agreements are with CLEC,
Entergy, and Southwestern Electric Power Company (SWEPCO). LAFA has an agreement with
CLEC for providing regulation service for its service area, which is based on predetermined
ACE set points. LAFA has a signed empowerment agreement with SPP, designating SPP as the
reliability coordinator; the agreement specifies the roles and responsibilities of each entity.

2. Operator Authority
The balancing authority/transmission operator is responsible for establishing and authorizing
the system operator position that will have the on-shift responsibility for the safe and reliable
operation of its portion of the bulk power system in cooperation with neighboring operating
entities and the reliability coordinator.

The LAFA system operators have the responsibility and authority under normal and emergency
conditions to initiate any action, including manual load shedding, required to preserve or restore
the security of the interconnection and the integrity of bulk power system. This authority is
documented in the job description for the system operators and in LAFA’s emergency operations
procedures. This authority is reinforced by a letter signed by several senior-level employees,
including the director of utilities, the electric operations manager, the engineering and power
supply manager, and the energy control system supervisor. This letter is posted in the control
room.

3. Delegation of Authority
Any functions that have been delegated must be clearly documented. The documentation must
recognize that the balancing authority/transmission operator that is delegating the function
continues to be responsible for that function.

LAFA has not delegated any of its functions to another entity.




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NERC 2006 Reliability Readiness Audit Report
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4. Staff Certification
Balancing system operators and transmission system operators must be NERC-certified
operators. The balancing authority/transmission operator must have sufficient NERC-certified
operator staff for continuous coverage of the system operator positions.

The LAFA control center is staffed with five NERC-certified system operators. Four system
operators work 12-hour rotational shifts, and the fifth system operator works normal business
hours, when not covering shift vacation and sick time. All five of the system operators are
certified to the balancing, interchange, and transmission level. The audit team made a
recommendation for LAFA’s management to evaluate its operations staffing levels to address its
shift coverage requirements. The audit team determined evaluation of its staffing would
determine areas of deficiency and improve other areas identified by the audit team that LAFA
needs to address. These areas are detailed in the appropriate section.

5. Training
The system operators must be adequately and effectively trained to perform their roles and
responsibilities. The balancing authority/transmission operator must have documents that
outline the training plans for the system operators. The balancing authority/transmission
operator must have training records and individual staff training records available for review.

LAFA is a small utility with limited resources, and its training program lacks structure. The
audit team made numerous recommendations associated with LAFA’s training for its system
operations staff in an effort to help LAFA focus its resources to address training inadequacies
and prepare for certification and continuing education requirements. The audit team
recommends LAFA develop, implement, and maintain a formalized training program for its
initial and continuing training and include identification of personnel responsible for initial and
continuing training.

Initial training consists of on-the-job training by a certified system operator, in the role of
mentor, for the new trainee. LAFA has determined that a hands-on approach to training best
serves its needs. Therefore, while serving as an apprentice system operator, the candidate will sit
alongside the certified on-duty operator learning the various duties, procedures, and industry
jargon. As the candidate becomes more proficient in electric system operations, focus shifts
from observation to actual performance of duties. During this time, the trainee will be enrolled
into a NERC-approved training program for certification. Once the apprentice has earned NERC
certification, he is put into the operator rotation. An informal checklist is used to guide the
trainee on subjects to complete. LAFA will be addressing hiring trainees in the near future and
presently does not have an objective-based and documented initial training plan or program. The
audit team recommends LAFA expand, formalize, and maintain the documentation verifying the
completion of an on-the-job training checklist, specifying skills and knowledge items necessary
for trainees to achieve competencies and proficiency. LAFA’s evaluation of a trainee’s ability to
work independently relies on completion of the on-the-job checklist and approval from the
manager of system operations. The audit team recommends LAFA develop and document an
evaluation process for verification of a trainee’s ability to perform work independently.




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NERC 2006 Reliability Readiness Audit Report
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LAFA contracts the services of a NERC-approved training company to provide the necessary
training for its five system operators. Each system operator is scheduled for training with an
outside entity in order to complete the required number of NERC continuing education hours. At
present, the majority of continuing training consists of online training performed during the time
the system operators are performing real-time operations. The system operators interviewed
indicated there were too many distractions during shift time to concentrate on training, and they
felt that more dedicated training time would be preferable. The audit team recommends LAFA’s
management evaluate its operations staffing levels to address dedicated training time for real-
time operations staff.

LAFA conducts bimonthly meetings with its real-time system operators and, during these
meetings, conducts internal training on changes in procedures and operational issues. The audit
team encourages LAFA to add more structure to these training topics and recommends LAFA
develop documentation of training topics and objectives delivered during its bimonthly shift
meetings.

Documentation associated with LAFA’s initial and continuing training is minimal, with a lack of
adequate detail on completed training. The audit team recommends LAFA develop a formal
tracking methodology and documentation containing a summary of each individual system
operator’s completed training hours and courses.

6. Operating Policies and Operating Procedures
The balancing authority/transmission operator must have an established procedure to ensure
that system operators and operations staff are aware of any changes to NERC, regional, and/or
local policies or procedures prior to taking over control of a shift position.

The balancing authority/transmission operator must have shift change procedures for updating
incoming shift personnel on the current status of the system.

LAFA uses e-mail notification to keep its operating staff informed of new or changed operating
policies and procedures. The system operators interviewed indicated this process works, as
LAFA’s system is small and changes to its operating policies or procedures occur infrequently.
LAFA also uses its bimonthly operations meetings to convey information to its real-time
operators. Hard copies of all operating procedures are located in the electric system control
room.

Development of new procedures is the responsibility of LAFA’s engineering and electric
operations division. The engineering division will coordinate any procedures with the affected
neighbor prior to, or during, the draft portion of development. The supervisor of operations is
responsible for reviewing and revising existing procedures. Changes are discussed with the real-
time operators via e-mail or the bimonthly meeting.

The audit team reviewed LAFA’s internal procedures and policies and its copies of regional and
NERC policies. The audit team noted some documents were not the latest revision, and there is
a lack consistency in both the procedure structure and review cycle. The audit team recommends
LAFA develop, implement, and maintain a formalized document-control methodology. At a


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NERC 2006 Reliability Readiness Audit Report
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minimum, the methodology should include revision dates, review history, and an approval
signature for each of its procedures. Further, LAFA should develop a review cycle for all its
procedures and policies. As discussed previously, the audit team made a recommendation that
an evaluation of LAFA’s operations staffing level be performed. This is necessary to adequately
address the need for LAFA to develop several programs and processes, including its
documentation-control methodology.

At shift turnover, system operators coming off shift review the operations logbook items with
incoming operators. The logs contain entries describing out-of-normal equipment and line
configuration. Operator logs are kept for historical information. Checklists are available for
activities to be performed on-shift.

7. Planning
The balancing authority/transmission operator and its supporting planning organizations must
have a process for day-ahead planning, and for longer-term planning, such as week-ahead,
seasonal, and year-ahead, for the operation and outage scheduling of transmission facilities and
generation and reactive resources.

The balancing authority/transmission operator and its supporting planning organizations must
have agreements with its reliability coordinator to ensure that day-ahead and longer-term plans
for the operation and outage scheduling of transmission facilities, and generation and reactive
resources, will not jeopardize the reliability of the bulk power system.

LAFA is a member of the Acadiana Load Pocket Study Group and participates along with
neighboring entities, Entergy and CLEC in performing studies on the area transmission system.
The “Acadiana Load” pocket is considered the geographical area of south central Louisiana.
The purpose of the study group is to analyze transmission needs and determine solutions for
short- and long-term transmission congestion issues.

LAFA’s engineering staff performs a yearly transmission contingency study and evaluates its
system loading for a five-year horizon. Each year a study is performed to analyze the upcoming
peak season for n-1 contingencies. LAFA uses the power system simulator for engineering
(PSS/E) tool to perform studies on its system.

SPP, LAFA’s reliability coordinator, develops long-range and seasonal study models through the
yearly model-building process. LAFA supports this effort by verifying the models’ data
accuracy for LAFA’s generator and transmission equipment. LAFA also submits its load
projections for use in future models at that time.

SPP also performs real-time and next-day studies and determines the import and export
capabilities for the LAFA system. Facility ratings are coordinated through the model building
process with SPP.

LAFA’s engineering department determines the week- and month-ahead resource adequacy
using a load forecasting software. The process estimates short-range generation requirements
and determines if requested maintenance outages can be allowed.


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NERC 2006 Reliability Readiness Audit Report
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LAFA uses two principle parameters to determine operating security limits for system voltages
and transmission line flows. The system is considered outside of operating security limits when
either voltage is outside a range of +/- 5.0 percent from nominal voltage or transmission facility
flows exceed transmission line ratings. Transmission facility ratings are determined for normal
and emergency conditions on a seasonal basis.

System operators monitor all LAFA’s transmission facility voltages, based on line-rating criteria.
Facilities are alarmed for notification of facility overloads and voltages that are out of tolerance.
All security limit violations are communicated and coordinated with the affected neighbor and
SPP to remediate violations.

8. Outage Coordination and Communication
Planned outages of transmission facilities and generating units must be coordinated with the
reliability coordinator to ensure that conflicting outages do not jeopardize the reliability of the
bulk power system.

Information relative to forced outages of transmission facilities and generating units that may
jeopardize the reliability of the bulk power system must be shared with affected balancing
authorities, transmission operators, and the reliability coordinator as expeditiously as possible.

LAFA’s transmission planning engineers and transmission system operators are responsible for
the planning of transmission-system switching operations that are necessary to accommodate
maintenance, construction, or other operational needs. The planning engineer develops a
detailed, sequential procedure that specifies device numbers, locations, and the operation to be
performed at each device. This switching plan is reviewed and approved by the planning
engineer, the system operator, and the operations foreman.

Prior to the execution of the switching operations, the system operator will review the detailed
procedures with the field foreman responsible for performing the switching operations. The
system operator also provides the field foreman with a copy of the switching order. When the
switching procedures are implemented, the system operator will direct the step-by-step operation
in communication via radio with the field personnel responsible for performing the operations.

Following the completion of all the elements of the switching order, both the system operator
and the field foreman will sign off that the work is done. The field foreman will transmit the
field copy of the completed and signed switching order to the system operator, and both copies
will be maintained by the ECS division for a period of five years.

Switching operations on the 138 kV and 69 kV systems involving neighboring entities are
coordinated and communicated with the affected neighbors via phone conversations prior to and
during the switching activities. Contact information for LAFA’s neighbors is located at the
system operator’s console. Any switching performed on the 138 kV and 230 kV transmission
systems are scheduled electronically in SPP’s OPS1, a Web-based transmission-outage
scheduling tool. The OPS1 scheduling tool is a separate application from the SPP reserve



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NERC 2006 Reliability Readiness Audit Report
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sharing system. SPP holds weekly telephone conference calls with entities within its region to
discuss upcoming transmission outages.

9. Plans for the Loss of Control Facilities
The balancing authority/transmission operator must have a workable plan to continue to
perform the balancing authority/transmission operator functions that are required to maintain a
reliable bulk power system following the sudden catastrophic loss of its primary control facility,
or the partial or full failure of its computer facilities or monitoring tools at the primary control
facility.

At the time of the reliability readiness audit, LAFA was in the process of constructing a backup
control center. The construction of the backup control center is part of the overall EMS
replacement project. The backup control center site is located above the 100-year flood plan,
and the building will be designed to withstand 120-mph winds. Scheduled completion for the
backup control center is set for July 31, 2006. The completed backup control center will be
configured to be independent of the primary EMS and will contain all the EMS displays the
LAFA system operators use at the primary control center. LAFA has recently developed
procedures for several scenarios associated with loss of the primary control center, including the
loss of voice and data communication facilities and full or partial loss of its EMS system. The
audit team reviewed these procedures and noted instruction on communication with its neighbors
and acquiring and documenting operational information was not included. The audit
recommends LAFA revise its Loss of Primary Control Center procedures to address manual
ACE calculation, documentation of energy schedules, and notification to SPP and its neighbors.

The LAFA system operators have not received training nor performed drills associated with the
new procedures. The audit team identified the need for LAFA to develop system operator
training for the loss of its primary control center as well as for the loss of its EMS and data
communication. LAFA’s management indicated drills on loss of its primary control center are
planned to be performed on a yearly basis, once the backup control center is completed. Also,
the audit team encourages and recommends LAFA to complete the construction of its backup
control center per the existing scheduled date of July 31, 2006.

LAFA requires all its system operators to carry a memory stick containing emergency
procedures, EMS vendor procedures, normal and emergency contact numbers, and spreadsheets
to conduct business at an alternate site. Field personnel will be dispatched to interties to monitor
flows, voltage, etc. Communications would be over telephone and, if conditions warrant,
satellite phones. The system operator is responsible to verify and download procedures on a
regular basis to ensure the memory stick contains the latest revision of the information. The
memory stick will be used to access information while operating from the backup control center.
The audit team noted the use of the memory stick to access policies and procedures as a positive
observation.

10. Tools
The balancing authority/transmission operator must have adequate analysis tools to perform the
balancing authority/transmission operator functions. Such tools include state estimation,


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NERC 2006 Reliability Readiness Audit Report
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precontingency and postcontingency analyses capabilities (thermal, stability, and voltage),
mapboard (static, dynamic, hardwired, or projected), eTagging program, weather service,
interchange scheduling system, outage scheduling system, trending tools, and a voice recording
system.

SPP provides real-time contingency analysis for the LAFA footprint. LAFA does not have a
state estimator or real-time contingency analysis program. Its engineering division uses PSS/E to
perform studies on the LAFA system. The EMS/SCADA has a weather interface where weather
data is downloaded on an hourly basis for the system operators to use in load forecasting. The
system operator uses the OATI tagging and scheduling software for interchange functions.
There is a separate “reserve sharing system” (RSS) terminal that is connected to SPP and used
for reserve sharing and electronic communication. The LAFA system operators submit daily
load reports, daily generation status, daily transmission status, and next-day load forecasts to the
RSS. In emergency conditions, e.g., a generation or transmission outage, the operators log the
data on the OPS1 Web site. The system operators have two displays which are used as an
electronic mapboard.

LAFA converted its EMS system in 2005. The system operators indicated they liked the new
EMS system. LAFA hired additional system engineers to work closely with system operators to
provide assistance and on-the-job EMS training during real-time operations. LAFA is
developing new EMS applications that should help system operators in day-to-day operations of
the LAFA system.

11. Load Shedding Plans
The balancing authority/transmission operator must establish plans for automatic load shedding
for underfrequency or undervoltage conditions, coordinate load shedding plans with other
interconnected entities, implement load shedding in steps to minimize further uncontrolled
events, and have plans for operator-controlled manual load shedding to mitigate violations of
system operating limits (SOL) or interconnection reliability operating limits (IROL).

LAFA system operators have an automatic underfrequency load shedding scheme capability, and
LAFA has developed a very good dynamic load shedding tool and display. Selected 13.8 kV
distribution feeders are grouped into blocks of approximately 35 MW of load, representing
approximately 10 percent of LAFA’s load. All feeders are given a circuit priority ranking from 1
to 6, with 6 representing the lowest priority. Groups of feeders are configured on the SCADA
display according to their priority ranking. Blocks of load are set to activate on frequency levels
of 59.3 Hz to 58.7 Hz. System operators can enter load shedding requirements and then arm the
system. The system will adjust the feeders per block required to be shed. A system operator has
the ability to shed one feeder or a block of feeders by going to the load shed display, selecting
the appropriate feeder or group, and arming the system to execute. Eight blocks of 20 MW are
available to the system operators for manual load shedding. Overlap between automatic and
manual load shedding is approximately 25 percent. This system allows for rotating blackout
blocks of load. The audit team noted the load shedding tool as a positive observation.




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NERC 2006 Reliability Readiness Audit Report
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12. Real-Time Monitoring
    a. System Visibility
        The balancing authority/transmission operator must monitor operating data and status
        in real time for its area and adjacent areas as necessary to maintain situational
        awareness of its system.

        The system operators have all the displays necessary to adequately monitor the LAFA
        system, with the exception of a summary overview of the LAFA system. LAFA
        recently upgraded its EMS system, but the majority of the information is accessed at
        individual substation and tabular displays. The audit team thought the addition of a
        summary overview and a geographical display with MW, Mvar, Hz, etc. would be
        helpful to the system operators. The system overview should include expansion of
        visibility into LAFA’s neighboring systems. The audit team recommends LAFA
        develop summary overview and geographical displays in the EMS for the LAFA
        footprint and consider expanding LAFA’s system wide-area view.

        LAFA provides all tie-line data to its neighbors and sends ICCP data to SPP. The data
        includes transmission and generator breaker status, generator output, ACE, net tie
        deviation, frequency, interchange information, and flow information on LAFA’s 230
        kV, 138 kV, and 69 kV systems.

    b. Alarms
        The balancing authority/transmission operator must have effective and reliable
        alarming capability. This should be supported in the energy management system
        (EMS) and/or supervisory control and data acquisition (SCADA) system by alarm
        priority.

        LAFA’s EMS alarm system provides prioritization by color and category. There are
        eight categories, with category eight being the highest priority. In addition, alarms are
        categorized by whether the alarm has been acknowledged or not. Initially, alarm
        categorization and nomenclature was set by the vendor supplying the EMS system.
        The EMS staff and the system operators are in the process of evaluating and changing
        some of the alarms for better customization to the LAFA system. At present, the
        system operators indicated there were a lot of distribution nuisance alarms, and LAFA
        is investigating changing these alarms to a more precise alarm limit to reduce the
        number of alarms the system operators are receiving.

        The EMS has a process that monitors the health of all processes, ranging from alarm, to
        historical, to automatic generation control (AGC). If any of these processes fail, on-call
        information technology personnel are notified, and the process is restarted.




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    c. Frequency
        The balancing authority/transmission operator must monitor frequency, direct actions
        to resolve significant frequency errors, and correct real-time trends that indicate
        potentially developing problems. Frequency monitoring points should be of sufficient
        number and from several locations with sufficient area coverage to allow the balancing
        authority/transmission operator to effectively monitor the balancing
        authority/transmission operator footprint to determine possible islands.

        LAFA has two geographically separated frequency monitoring points. The primary is
        located at the control center site and the other one is located at a substation within the
        LAFA service area. The frequency points geographical arrangement allows the system
        operator the ability to identify separation and islanding of the LAFA compact service
        area. The two frequency points are input to the EMS system and have automatic
        failover capability. Frequency indication is displayed on a single screen under the
        AGC summary page.

    d. Voltage/Reactive Reserve
        The balancing authority/transmission operator must monitor voltage levels and take
        appropriate actions to support the bulk power system voltage if real-time trends
        indicate potentially developing problems. Voltage measuring points must be of
        sufficient number and from several locations and voltage levels to allow the balancing
        authority/transmission operator to effectively monitor the voltage profile of its
        footprint.

        LAFA’s voltage control philosophy is to focus on maintaining voltage at the
        distribution level as a way to keep the transmission system voltages within criteria.
        LAFA has automatically employed capacitors on its distribution system. Additional
        control of voltage is through the use of load tap changing transformers that regulate the
        69 kV transmission facilities. There are three load tap changers that are controlled by
        the system operator via the EMS. In addition, internal generation is under automatic
        voltage regulator control. Voltage limits on the 230 kV, 138 kV, and 69 kV
        transmission facilities are maintained between +/-5.0% of normal. The system
        operators interviewed appeared knowledgeable on reactive issues for the LAFA system.

        LAFA has two graphical voltage displays. Both displays contain numerical and
        graphical substation information. Load tap changer control and position are also
        included. Each substation’s telemetered voltage points are included in a tabular
        display.

        LAFA was unable to produce documentation reflecting reactive testing of its
        generators. The audit team recommends LAFA develop a generation testing program
        and schedule, per SPP criteria.




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    e. Critical Facilities
        Monitoring of facilities that are critical to the reliability of the bulk power system is a
        joint responsibility of the balancing authority, transmission operator, and the reliability
        coordinator.

        An established process must determine which facilities are critical to the reliability of
        the bulk power system. Real-time operating information (data and status) and
        operating limits for these critical facilities must be provided to the balancing authority,
        transmission operator, and the reliability coordinator.

        Critical facilities are identified by an engineering division study process. LAFA’s
        definition of a critical facility is one whose loss would create a situation where there
        would be no remedy for the next n-1 event. LAFA’s system is compact, and operation
        is contained within a small geographical area. System operators interviewed indicated
        they monitor all LAFA’s transmission facilities to ensure voltages and ratings are
        within criteria range. Facilities are alarmed for notification of frequency deviations,
        facility overloads, and voltages out of tolerance. The system operators coordinate and
        communicate security limit violations with Entergy, CLEC, and SPP to remediate such
        violations.

    f. Transmission System Congestion
        The transmission operator must monitor transmission flowgates and be prepared to
        take actions to alleviate congestion in conjunction with, and as directed by, its
        reliability coordinator.

        One autotransformer on a 230 kV transmission line historically has been subject to
        overload conditions on the LAFA system. The Acadiana Load Pocket Study Group
        identified a need to build a new substation between Entergy and CLEC. Since this
        substation was constructed in 2005, there have been fewer transmission congestion
        issues. LAFA reported a recent increase in congestion in the Arcadian area, and the
        Acadiana Load Pocket Study Group is performing studies to identify solutions.

        The system operators monitor the flows and communicate with SPP to receive direction
        on relieving any system congestion. The system operators interviewed indicated they
        follow all directives given by the reliability coordinator (SPP), and the SPP response to
        the questionnaire supported the system operators’ statements. SPP uses the NERC
        transmission loading relief process for implementing transmission loading relief efforts.

    g. Load Generation Balance
        The balancing authority must monitor the balance of load, generation, and net
        scheduled interchange in its balancing area. The balancing authority must take actions
        to mitigate unacceptable load, generation, and net scheduled interchange imbalance.

        LAFA has a total generation capacity of 706 MW, which includes its 50 percent share
        of a jointly owned generation unit located outside its service area. All generating units


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        are capable of being placed on AGC; communication with the plant personnel is
        required for this.

        LAFA has invested in four recently commissioned combustion turbines, with a capacity
        of 50 MW each, to support its native load requirements. These are peaking units,
        capable of ramping from zero to full output within 15 minutes. LAFA has a contract
        for supplemental regulation service from its neighbor CLEC. LAFA calculates its ACE
        and dynamically sends the ACE data to CLEC’s EMS. CLEC supplies additional
        energy when LAFA’s ACE is between minus forty and plus five. At the time of the
        audit, CLEC’s regulating service was disabled in the EMS, and LAFA was providing
        its own regulation.

        LAFA provides its system operators with multiple tools and displays to monitor its area
        and balance load and generation. The audit team reviewed LAFA’s system operators’
        tools, including generation, economic dispatch, load, interchange, area control error,
        and AGC displays.

        The system operators are responsible for developing and verifying hourly interchange
        schedules. Hourly pre-schedules are verified the hour before they go into effect. After-
        the-fact checkouts take place before shift change everyday at 0530 and 1730. The
        system operators use OATI Webtrans for its interchange scheduling function.

        The system operators monitor the daily load profile. LAFA’s largest historical hourly
        load change is 30 MW, and LAFA reported it has more-than-adequate ramp rate with
        its combined generation units to meet load change requirements.

    h. Contingency Reserves
        The balancing authority must monitor the required reserves and the actual operating
        reserves in real time, and take action to restore acceptable reserve levels when reserve
        shortages are identified.

        All SPP control areas are members of the SPP reserve sharing group, and each
        contributes to the operating reserve pool based on a formula. The deficient entity
        inputs a request for additional reserves through the SPP RSS. LAFA’s operating
        reserves are calculated daily by SPP and sent via RSS and displayed on the OPS1 Web
        page for the next sequential day. SPP makes its calculations based on the largest unit
        on-line. On a typical day, LAFA’s operating reserves are between 2 MW and 5 MW, if
        LAFA has a generating unit on-line. The level of total operating reserves is displayed
        in the AGC overview display in EMS. Required contingency reserve is not displayed
        in EMS, and the system operators do not have alarm indication when actual reserves are
        below required level.

        SPP allows entities to ask for assistance beyond simple loss of generation. This
        assistance is classified by SPP as “other extreme conductions.” LAFA has used the
        other extreme condition request in conjunction with the request for Energy Emergency



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         Alerts to inform other SPP members that LAFA did not have any reserves left to
         participate in other SPP events.

     i. Special Protection Systems
         The balancing authority/transmission operator and the reliability coordinator must be
         aware of the operational condition of special protection systems that may have an effect
         on the operation of the bulk power system.

         LAFA does not have any special protection systems in its footprint.

13. System Restoration
The transmission operator must have a documented system-restoration plan that is consistent
with NERC Reliability Standard EOP-005-0 — System Restoration Plans. This restoration plan
must be provided to its reliability coordinator.

The transmission operator must be prepared to restore its transmission area following a partial
or total collapse of the system and coordinate system restoration with its neighboring
transmission operators and with the reliability coordinators.

LAFA’s system restoration procedure titled Emergency Restoration Plans contains sections for
determining system status, evaluating available generation, energizing its one blackstart unit, and
rebuilding the LAFA system. Included in the plan is contact information with names and
telephone numbers. SPP coordinates the synchronization with the neighboring entities, and
LAFA’s system operators are responsible for communicating the status of LAFA’s system to the
SPP and adjacent entities.

The emergency restoration plan was reviewed by the audit team. It contains basic instructions
for LAFA’s system operators to use during a system restoration event, but the procedure lacked
information necessary to make it a more complete plan for system restoration. The audit team
recommends LAFA determine the synchronization process with its neighboring entities and
incorporate synchronization instructions in LAFA’s system restoration plan. In addition, the
plan identifies use of LAFA’s one blackstart unit and four recently commissioned 50 MW
combustion turbines. The audit team recommends LAFA perform an evaluation of these units to
determine whether to include them as regional (SPP) blackstart units.

While conducting the interviews, the audit team learned that LAFA-specific system restoration
training has not been performed. The audit team recommends LAFA perform and document its
system restoration training. Also, simulation or testing of the system restoration plan has not
been performed; the audit team recommends LAFA perform and document simulation of its
system restoration plan at least once every three years. LAFA has not shared its restoration plan
with its adjacent neighbors, and the audit team recommends LAFA provide copies of its system
restoration plan to its adjacent neighbors.




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NERC 2006 Reliability Readiness Audit Report
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14. Capacity and Energy Emergency Plan
Each balancing authority must have a capacity and energy emergency plan that address the
following functions. (It should be noted that some of the items might not be applicable, as the
responsibilities for the item may not rest with the entity being reviewed.)

The system operator is responsible for advance resource planning, including day-ahead planning,
and determines whether the available energy resources are sufficient for meeting projected load
plus operating reserve requirements. If resources cannot meet demand, there are steps outlined
in LAFA’s Capacity and Energy Emergency Plan for the system operator to follow. These steps
are contained in “Advance Planning” section of the plan. If, after taking pre-emergency steps,
projected energy resources cannot meet demands, the system operator will declare an operating
emergency alert, and LAFA’s operating emergency team, made of up key management
personnel, will be activated. LAFA’s capacity and energy emergency plan includes actions to
curtail all nonessential energy use at company facilities, request voluntary customer load
reductions and energy conservation, implement a 5 percent voltage reduction, and schedule all
available emergency assistance from its neighbor, CLEC. Public appeals and fuel supply issues
are addressed in the plan. The plan contains a statement that gives its system operators the
authority to manually shed load.

The audit team reviewed LAFA’s Capacity and Energy Emergency Plan and determined it
contained all the necessary elements to address an emergency specific to the LAFA system. The
following statement is contained in the plan: “This Capacity and Energy Emergency Plan will be
reviewed and evaluated at least every three years from the initial approval date of these Policies
and Procedures.” The audit teams recommends LAFA revise section five of its capacity and
energy emergency plan and change the review policy from a three-year cycle to an annual
review. In addition, the audit team learned LAFA has not shared its capacity and energy
emergency plan with its neighbors. The audit team recommends LAFA provide copies of its
capacity and energy emergency plan to neighboring entities.

15. Equipment Maintenance and Testing
Transmission and generator owners must ensure that maintenance of transmission lines,
substation equipment, transmission protective systems, and generator relays is carried out
according to company, regional, and/or NERC requirements.

LAFA provided the audit team with maintenance and testing program documentation for its
transmission and substation relays. LAFA reported that it completed its 2005 schedule and has
not had any relay misoperations occur for the past 12 months. LAFA performs maintenance and
testing on its electromechanical relays every three years and on its microprocessor relays every
five years.

LAFA did not supply the audit team with a schedule or procedure for testing its generator(s)
relays, as LAFA does not have a maintenance schedule for its generating units. This was not a
concern in the past when LAFA was operating only one generating plant. However, LAFA
recently commissioned four additional generating units. LAFA indicated an awareness that it
should develop a coordinated maintenance schedule that would include all generating stations.



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NERC 2006 Reliability Readiness Audit Report
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The audit team recommends LAFA develop a long-range protective relay maintenance plan and
schedule for the existing generation units.

Relay crews contact the system operators to alert them work is starting on the specific relays.
This is a courtesy, informational-type communication, but it is not a requirement. The audit
team thinks performance of maintenance on the transmission system should always require
notification to the system operator. The audit team recommends LAFA require relay personnel
communicate to the system operator when real-time relay maintenance activities are being
performed.

16. Vegetation and Rights of Way Management
The transmission operator must have a documented vegetation-management program.

LAFA patrols all of its 230 kV transmission system along with its 69 kV lines once per year.
Vegetation management, including trimming activities, is performed annually on 100 percent of
its transmission system. LAFA’s vegetation and rights-of-way (ROW) management employs
mostly bush hogging, tree-trimming techniques, and herbicidal application. Tree trimming
includes maintaining a 25-foot buffer zone on each side of the line, and its 230 kV ROW corridor
is mowed at least once per year. LAFA presented the audit team with its vegetation management
documentation. The audit team thought LAFA’s continuous annual transmission vegetation
management program highlighted LAFA’s emphasis on its transmission assets and noted this
practice as a positive observation.


17. Nuclear Power Plant Requirements
Transmission operators must support nuclear power plants in meeting regulatory requirements
that allow the plant operators to maintain voltages within design limits and adequate off-site
power sources in both normal and abnormal operating conditions (n-1 and system restoration).

There are no nuclear power plants in the LAFA footprint.




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NERC 2006 Reliability Readiness Audit Report
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                       APPENDIX 1: Critical Energy Infrastructure

The following discussion is presented under private letter to the audited organization only and
will not be included within the public version of the report.




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NERC 2006 Reliability Readiness Audit Report
Lafayette Utilities System

                             APPENDIX 2: Audit Participants

The following discussion is presented under private letter to the audited organization only and
will not be included within the public version of the report.




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NERC 2006 Reliability Readiness Audit Report
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                           APPENDIX 3: Documents Reviewed

The following discussion is presented under private letter to the audited organization only and
will not be included within the public version of the report.




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