Transmission & Substation Outage and Clearance

♦^Transmission & Substation Outage and Clearance Coordination Procedures

circuit breaker operating at a voltage of 60kV and higher occurs. A "ForcedOutage Check List" form is included in this document. In the event of anunplanned generation outage, the Customer or his designated representativewill advise CNP's RTO System Controller as soon as possible. In emergencysituations, switching may be performed by a qualified person, authorized by theCustomer, based upon switching instructions provided by the RTO SystemController. An "Emergency Switching Check List" form is included in thisdocument. The RTO System Controller can be contacted at 281-894-0491, orat the RTO HOTLINE 281-894-1625.

3.2.6 ERCOT Approvals - The RTO System Scheduler will coordinate a review andnotify the Customer whether or not the outage can be scheduled for the desiredday. Transmission line outages and the energization of new equipment requirethe approval of ERCOT. The Customer will notify the RTO System Scheduleras soon as possible if an outage is canceled prior to • the outage date. TheCustomer will immediately notify the RTO System Controller if an outage iscanceled on the day of the outage. CNP will endeavor to notify the Customer assoon as possible when it is deemed necessary to cancel an outage.

3.2.7 Customer Substation Evacuations - During emergencies requiring evacuationof a customer's facility, the customer shall contact RTO prior to the evacuationand provide information regarding the operational status of their substation andassociated support facilities (i.e. substation station service power, battery &battery charger, ability for CenterPoint Energy to access substation, etc).Customer substations are an integral part of the interconnected transmissionsystem and disabling them has an impact on the electrical grid.

3.3 Transmission Accounts Division

3.3.1 CNP's Transmission Accounts division is responsible for coordinating theCustomer's service needs within CNP. Transmission Accounts representativeswill endeavor to inform Customer's of long range planned switching and projectswhich may affect the Customer's facility

3.3.2 The Customer will notify the Transmission Accounts representative as specifiedin Section 9 when equipment additions or removals are planned or when highvoltage equipment 60kV and higher or associated equipment requiresmodification or replacement. The Customer will contact a TransmissionAccounts representative to request current CNP specifications and applicablebills of material for substation equipment additions and replacement.

3.3.3 Transmission Accounts representatives may be contacted for any questionsconcerning the operation of the Customer's substation. The TransmissionAccounts representatives are listed on Page 1 of this document.

Revised: April 24, 2008 Page 850

•--cmarflo'r+t,

Transmission & Substation Outage and Clearance Coordination Procedures

3.4 Substation and Equipment Identification

3.4.1 CNP assigns a Substation name (Substation ID) of six characters or less, toidentify the Customer's substation facility. The Substation ID is also referred toas the six character mnemonic name in which some characters may be blank.CNP will mount signs with the Substation ID on a substation control house doorand on a substation entrance gate at the Customer's facility.

3.4.2 The Customer's high voltage circuit breakers switches, transformers, andcertain low side equipment will be identified with CNP's assigned numbers.CNP will develop a substation basic one-line diagram that includes theseassigned numbers. CNP or the Customer will mark these numbers on thesubstation equipment. CNP may stencil identification numbers on substationequipment and mount signs, labels, drawings, telephone numbers, andinstructions on the Customer's facilities.

3.4.3 The Customer will use CNP's assigned Substation name, or Substation ID, andequipment identification numbers in discussions with the RTO SystemController and the RTO System Scheduler.

3.5 Telephone Lines and Data Communication

3.5.1 The Customer will maintain a telephone in the substation control houseconnected to an outside telephone line independent from the Customer'stelephone system.

3.5.2 The Customer will maintain data acquisition equipment to provide real-timedata to RTO when it has been installed at electric generating facilities.

3.5.3 CNP will maintain a communication circuit for real time data if CNP SupervisoryControl and Data Acquisition. (SCADA) equipment is installed at the Customer'sfacility.

3.6 Alarm Response

3.6.1 CNP will respond to alarms for communication equipment installed to protectCNP transmission circuits.

3.6.2 The Customer should report substation alarms to the RTO System Controllerand respond to alarms pertaining to their equipment. A "Loss of DC" alarmshould be immediately reported to the RTO System Controller and investigatedby the customer.



Transmission Control I Real Time OperationsOutage Scheduling, Metering & Forced Outage Requirements

Per ERCOT and CenterPoint Energy outage reporting requirements, plannedoutages on circuit breakers, transmission lines and autotransformers rated 60kVand higher must be requested through the ERCOT Outage Coordinators by theCenterPoint Energy Real Time Operations System Scheduler.

Also per ERCOT Protocols, planned outages on ERCOT Polled Settlement (EPS)meters and/or the equipment to which they are connected require a 5 dayminimum notice. A 10 calendar-day minimum notice is required for anymodifications to approved EPS equipment.

Table 1. Planned OutagesEquipment Being Minimum Advance Notice Contact

Requested69kV & 138kV lines, single No later than 1200 hours Short Term Coordinatorload transformers, on the Wednesday of the atindividual breakers and bus week before the Planned 713-207-2196outages of no more than Outage is to take place.one day in duration.All transmission line 35 Calendar Days notice Mid Term Coordinatoroutages and equipment atoutages, including busses, 713-207-1619of up to four contiguousdays duration (daily orcontinuous outages).Any transmission line 90 Calendar Days notice Long Term Coordinatoroutages and/or equipment atoutages, including busses, 713-207-2462of 5 days or longer duration(daily or continuous)

For additional Long Term Outage Coordination, contact the CenterPoint EnergySystem Coordinator at 713-207-2462.

Forced Outages

Forced outages due to equipment emergencies will be handled by CenterPointEnergy - Real Time Operations and ERCOT System Operations on a case-by-casebasis by the Customer contacting the Real Time Operations Security Desk at 713-207-2203.

Per ERCOT requirements, forced outage on EPS meters with no back-up or checkmeters must be corrected within 12 hours. Forced outages on EPS meters withback-up or check meters must be corrected within 5 days.


a^Transmission & Substation Outage and Clearance Coordination Procedures

4 Switching, Clearances, Grounding

4.1 Billable Costs

4.1.1 Grounding and switching requested by Customer to be performed during otherthan normal working hours is billable to the Customer.

4.1.2 Grounding and switching charges will be waived under the following conditions:

4.1.2.1 The party requesting switching and/or grounding activities by CenterPointEnergy is a transmission voltage service Customer who is interconnected toCenterPoint Energy's transmission system through a customer ownedsubstation; and

4.1.2.2. The requested activities are to allow the Customer to performmaintenance activities or equipment upgrades on its transmission voltagefacilities within the Customer's substation; and

4.1.2.3. The switching and grounding field activities are requested to occur on anormal CenterPoint Energy work day, with outages commencing no earlier than0800, and outages concluding no later than 1600.

4.1.3 Outages extending beyond the timeframes identified in Section 4.1.2.3 on aforced basis may result in billing for associated switching and groundingactivities, as determined on a case-by-case basis.

4.1.4 Outages with switching and/or grounding activities requested for more than twoconsecutive days may be subject to charges for each additional consecutiveday, even if the outages occur within the timeframes identified in Section4.1.2.3, unless early/intermittent outage restoration is required by ERCOT or for

CNP system requirements.

4.1._ Questions regarding charges should be directed to the Transmission Accountsrepresentative.

4.2 Switching

4.2.1 CNP will provide all necessary switching at the remote end of a CNPtransmission line for outages at a Customer substation which require switchingof CNP transmission lines. CNP will provide switching instructions for the highvoltage devices in the Customer substation that is directly interconnected withCNP's transmission system. Switching instructions are not provided for remotefacilities interconnected to the customer substation that is directlyinterconnected with CNP's transmission system. A "Switching Order" form anda "Transmission Switching Check List" form are included in this document.


cbw~Transmission & Substation Outage and Clearance Coordination Procedures

4.2.2 The Customer will follow switching instructions, provided by the RTO SystemController, prior to initiating any switching to remove equipment from service orreturn equipment to service in the Customer's facilities. The Customer willimplement specific procedures for the switching of its facilities. Theseprocedures will include a visual check that all phases have fully opened orclosed. A device bearing a Hold Tag will not be operated under anycircumstances.

4.3 Clearances

4.3.1 A clearance is required for applicable work on high voltage apparatusconnected to CNP transmission lines when switching at the remote end of aCNP transmission line is necessary. Clearances are also issued when theCustomer and CNP will be working on apparatus within the same isolated areaat the Customer's facilities. Each party will be issued an individual clearance.

4.3.2 The Customer will request a clearance from the RTO System Controller whenrequired. Personnel authorized by CNP will either "trip and hold" or "check fortrip and hold" on necessary devices before a clearance will be issued.

4.3.3 A clearance cannot be released by anyone other than the person to whom itwas issued unless uncontrollable circumstances make that impossible. In thissituation, the person's supervisor may, after informing each member of thecrew that such action is being taken, contact the RTO System Controller torelease the clearance. For field personnel shift changes, the person assumingthe leadership of the work will be issued a new clearance and the person towhom the clearance was originally issued will then release the clearance.

4.4 Grounding

4.4.1 CNP issues clearances indicating that high voltage devices have been opened,locked, and tagged to prevent the devices from operating. The Customer willverify that the apparatus is de-energized before protective - grounding isattached or work on high voltage facilities begins.

4.4.2 The Customer is responsible for assuring that protective grounds are installedon all de-energized electrical apparatus before applicable work is performed onit. When more than one party (e.g., the Customer and CNP) will be working onapparatus within the same isolated area at the Customer's facilities, each partywill install their own individual grounds before applicable work is performed.

4.4.3 Work may be performed on the control circuits and mechanisms of a devicewithout grounding the apparatus - if such work can be performed without risk ofcontact with primary voltages. Grounds may be temporarily removed if requiredby testing procedures.

4.4.4 Before a grounding device is attached to any conductor, that conductor will firstbe tested to confirm that it is de-energized. Grounds will be placed such thatthe operation of a switching device cannot remove their protection.


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4.4.5 The clamps and conductors of grounding devices will be designed for theavailable fault current. Grounding devices must be inspected for brokenstrands and loose connections. The surface of the ground clamps must beclean of corrosion and oxides.

4.4.6 Grounding devices for transmission voltage conductors must be installed andremoved with the use of applicable live line tools. Grounding devices mustalways be securely connected at the ground end before connection is made tothe conductor. Grounds must always be removed by first detaching theconnection at the conductor and, then, detaching the connection at the groundend. When grounding to a steel structure, the ground must not be applied to aflat surface unless an appropriate flat surface clamp is used.

4.4.7 CNP does not ground Customer-owned substation equipment except for-workbeing performed by CNP.


sTransmission & Substation Outage and Clearance Coordination Procedures

4.5 Switching 345kV Facilities Equipped with Ferroresonance Protection

4.5.1 Ferroresonance protection is installed whenever a wound potential transformer(PT) is connected to 345kV and the possibility of a ferroresonance conditionoccurring exists. If applicable, the Customer will implement specific proceduresfor switching 345kV equipment that has ferroresonance protection installed.Procedures will include the following.

q Place the sync handle in position for the last breaker that will be opened

q Monitor the potential lights on all three phases before and after the last breaker isopened

q If one or more of the lights do not dim immediately but gets brighter

q Immediately close the last breaker opened to reenergize the bus

q Investigate the ferroresonance protection

q If all three lights dim immediately

q Reset the targets ("flags") on the ferroresonance protection relays

q If relay targets did not operate

q Investigate the ferroresonance protection circuit



4.6 Terminology for Switching Orders

Time - Military time, or 24 hour clock, based on prevailing Central Time.

Check Ring for Close - Verify by visual inspection that all devices in the ring are in theclosed position.

Block Transformers - Place automatic control of the load tap changer to the manualposition.

Unblock Transformers - Place automatic control of the load tap changer to theautomatic position.

Remove / Roll Loads - Remove all loads connected to a power transformer. This maybe done by tripping applicable low side breakers or by rolling load to an adjacenttransformer and tripping applicable low side breakers.

Trip - Initiate and complete an opening operation on a device.

Close - Initiate and complete a closing operation on a device.

Hold Tag - A tag placed on a device to indicate it shall not be operated. The tag willindicate the party who placed the tag.

Trip and Hold - Trip device, physically or mechanically (e.g., affix padlock) disabledevice from closing, and place a Hold Tag on the device.

Check for Trip and Hold - Verify by visual inspection that a device is in the trip positionand place a Hold Tag on the device.

Secure Against Operation (SAO) - Physically, mechanically, and/or electrically disable adevice (e.g., a motor operated disconnect switch) to prevent it from operating.

Secondary Potential Fuse (SPF) - Remove and tag fuses on the secondary side of

potential devices to prevent the possibility of back energizing isolated equipment.


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4.7 Switching Order

SWITCHING

ORDER #

SUBSTATION ISSUED RELEASED

EQUIPMENT DISP. DISP.

OUT RESTORE TIME TIME

DISP DISP. DATE DATE

TIME TIME ISSUED TO

DATE DATE NUMBER OF MEN AND GROUNDS

EXEC. BY EXEC. BY ON

TIME TIME

INSTRUCTIONS

SWITCHING PROCEDURES DISCUSSEDWITH ALL MEMBERS OF CREW: Y N

CREW INITIALS

Real Time Operations Division's Outage and Clearance Coordination Procedure

#


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4.8 TRANSMISSION SWITCHING CHECK LIST

The following basic procedures are for the day of the switching after the outage hasbeen scheduled with and authorized by the RTO System Scheduler (713-207-2196). This applies to the customer substation that is directly interconnected withCNP's transmission system.

I- Call the RTO System Controller at 281-894-0491 and request a Switching Orderi Provide name, company affiliation, and telephone numberI Provide Substation IDI Describe reason for requestI Fill out Switching Order

Record the Switching Order numberI_ Record start time provided by the RTO System ControllerL. Record the RTO System Controller's nameI Record the instructions to take equipment OUTI Repeat the instructions

I Execute the Switching Order placing Hold Tags where appropriatei Call the RTO System Controller when the instructions have been completed

! Report the actual completion timeI.' Record the completion time provided by the RTO System Controller on Switching OrderI. Request a Clearance if necessary

t _ Provide the number of personnel in the crewL Provide the number of and location of grounds

L Verify apparatus is de-energized with a hot line indicator[_ Install protective grounds when requiredt._ Perform workI._ Remove protective grounds if installedI._ Call the RTO System Controller to request to RESTORE equipment

[_ Report whether more than one Hold Tag is on any deviceL Provide Clearance number if applicable

F- Provide the number of personnel in the crew clear of the apparatus1 -1 Provide the number of grounds removed

Provide the Switching Order numberI Fill out Switching Order

F. Record start time provided by the RTO System ControllerRecord the RTO System Controller's name

, Discuss performing Switching Order instructions in reverse order[ Alert all personnel to move to a safe distance from apparatus being energizedI_ Execute the Switching Order removing Hold Tags where appropriateI Call the RTO System Controller when restoration has been completed

r Report the actual completion timeI Record the completion time provided by the RTO System Controller on Switching Order


^Real Time Operations Division's Outage and Clearance Coordination Procedure

5 Outage Scheduling Check List

5.1 Outage Scheduling Check List

5.1.1 The following basic procedures are for scheduling transmission equipmentoutages. This, applies to the customer's substation that is directly interconnectedwith CNP's transmission system. Please refer to the "Outage Scheduling,Metering and Forced Outage Requirements" outlined in Section 3 of thisprocedure.

q Call the RTO System Scheduler at 713-207-2196

q Record the RTO System Scheduler's name:

q Provide the following information

q Your name, company affiliation, and telephone number

q Substation ID:

q Equipment to be de-energized:

q Date of desired outage:

q Time of desired outage:

q Expected duration of desired outage:

q Specify whether a clearance will be requested on the day of the outage

q Specify whether any isolated, high voltage devices will be operated during the outage

q Specify if maintenance of instrument transformers connected to CNP meters is planned

q Specify if CNP grounding of CNP lines or equipment is required

q Specify the number of grounds:

q Specify the preferred locations of grounds:

q Provide the name, phone number, and pager number of the person to contact

BY: DATE:


^^ .Real Time Operations Division's Outage and Clearance Coordination Procedure

6 Unplanned Outages

6.1 Unplanned Outages

6.1.1 ERCOT Protocols require that CNP notify ERCOT of all unplanned transmissionoutages.

6.1.2 The Customer will contact the RTO System Controller as soon as possiblewhenever any unplanned tripping of any high voltage (60kV and higher) circuitbreaker occurs. CNP crews will be dispatched when high voltage circuit breakersremain open in the customer substation that is directly interconnected with CNP'stransmission system. CNP crews will reset relay targets except in emergencysituations. A "Forced Outage Check List" form is included in this document.

6.1.3 CNP crews are not dispatched when high voltage circuit breakers remain open ina remote, non-CNP, substation connected to a Customer's substation but notdirectly interconnected with the CNP system. In such a case, the Customer willdiscuss and evaluate the event with the RTO System Controller. The Customerwill notify the RTO System Controller prior to any switching.

6.1.4 In the event of an unplanned generation outage, the Customer or his designatedrepresentative will advise CNP's RTO System Controller as soon as possible.

6.2 Unplanned Outages of 345kV Facilities Equipped with Ferroresonance Protection

6.2.1 Ferroresonance protection is installed whenever a wound potential transformer(PT) is connected to a 345kV and the possibility of a ferroresonance conditionoccurring exists. If applicable, the Customer will implement specific proceduresfor unplanned tripping of 345kV equipment that has ferroresonance protectioninstalled. Procedures will include the following.

r- Visually inspect the potential transformer lights on all three phasesI_ If one or more of the lights are bright and not dim

I.__ Open all the breaker disconnect switches to isolate the potential transformersL Disconnect/Remove the PT(s) from service on the phases with the bright lights

t. If one or more of the lights are dark and not dimr Open all the breaker disconnect switches along the affected busI Disconnect/Remove the PTs from service on the phases with the dark lights

t If remote monitoring of potential transformer voltages indicated a ferroresonance condition occurredI Open all the breaker disconnect switches to isolate the potential transformersI Disconnect/Remove the PT(s) from service on the phases that indicated ferroresonance

I If all three lights are dimL Reset the targets on the ferroresonance protection relays

I If relay targets do not indicate proper actionI Investigate the ferroresonance protection circuit


o^ °Real Time Operations Division's Outage and Clearance Coordination Procedure

6.3 Emergency Switching

6.3.1 In emergency situations, switching may be performed prior to a CNP crew arrivingat a Customer's incoming substation. A qualified person, authorized by theCustomer, may operate breakers and switches based upon switching instructionsprovided by the RTO System Controller. Prior to switching, all relay trip targetswill be reset after the Customer has recorded them and reported them to the RTOSystem Controller. All personnel will move to a safe distance from apparatusbeing energized prior to switching. An "Emergency Switching Check List" form isincluded in this document.

6.3.2 UNPLANNED OUTAGE CHECK LIST

6.3.3 The following basic procedures are for whenever any unplanned tripping of anytransmission service voltage breaker occurs.

Call the RTO System Controller Hot Line at 281-894-1625Provide the following information to the RTO System Controller

I Your name, company affiliation, and telephone numberI Substation IDF- Nature of the problemC= Time of outagef Status of all breakers and switches (i.e., open, closed, tagged)[- Cause of the event if knownC: Fault location and faulted equipment if known[ Fires and their proximity to energized equipment[:.. Plant and substation entry constraints (e.g., chemical releases)

F Record the RTO System Controller's nameF Investigate and provide the following information to the RTO System Controller

f- Cause of the event if found during investigationI Fault location and faulted equipment if found during investigation[ Number of trip operations for each breaker (i.e., change in breaker veeder reading)F Relay trip targets - Do not reset targets

I Discuss outage with CNP crewsI_. CNP crews record and reset relay trip targetsf- CNP crews record breaker veeder readingsI Resolve outage and complete any necessary corrective actionL Call the RTO System Controller at 281-894-0491 to request to RESTORE equipment

I_ Record the instructions to RESTORE equipment- Repeat the instructions

I Execute the instructionsI__ Call the RTO System Controller when instructions have been completed

BY: DATE:


^^Real Time Operations Division's Outage and Clearance Coordination Procedure

6.4 EMERGENCY SWITCHING CHECK LIST

6.4.1 The following basic procedures are for emergency situations. Contact the RTOSystem Controller at one of the following telephone numbers.

F1 Call the RTO System Controller Hot Line at 281-894-1625F^ Provide the following information to the RTO System Controller

F1 Your name, company affiliation, and telephone numberF1 Substation IDF] Nature of the problemr1 Time of outagen Status of all breakers and switches ( i.e., open, closed, tagged)F1 Cause of the event if knownF1 Fault location and faulted equipment if knownF1 Fires and their proximity to energized equipmentrl Plant and substation entry constraints (e.g., chemical releases)n Relay trip targets

C7 Record the RTO System Controller's namen Record the instructions to RESTORE equipment0 Reset relay trip targetsn Execute the instructionsF7 Call the RTO System Controller at 281-894-0491 when instructions have been completed

BY:

6.5 Other Emergency Conditions

DATE:

6.5.1 Customer substations are an integral part of the interconnected transmissionsystem and disabling them has an impact on the electrical grid. In certainemergency situations, Customer's may evacuate or shut down their facility. Insuch cases, the Customer shall endeavor to keep the portion of their substationthat is directly connected to the transmission grid in service, unless specificallydirected otherwise by ERCOT or CNP's RTO System Controller or otherresponsible personnel.


O;nmtPbiw.S-V Real Time Operations Division's Outage and Clearance Coordination Procedure

7 Generation Operation

7.1 Applicability

7.1.1 This section applies only if the Customer operates electric generating facilities andparticipates in the wholesale transmission market. The Customer will follow theERCOT Operating Guides and ERCOT Protocols or other regulatory requirementsthat apply to their facilities

7.2 Unit Operation

7.2.1 Where CNP owns the interconnecting substation and there is not an in-line breakerto synchronize a generating unit, the Customer will have control of CNP's substationbreakers that are functioning as generator breakers. CNP will have operationalcontrol of the disconnect switches associated with these breakers.

7.2.2 The Customer will have generation control personnel on duty at the generating unitsite at all times that the generating units are on-line.

7.2.3 The Customer or Customer's representative will notify the RTO System Controller,phone number 281-894-0491, immediately before a unit is synchronized andconnected to CNP's transmission system. The Customer will report forced unitoutages.

7.2.4 The Customer will operate units to support the transmission system voltage byregulating reactive power output up to levels demonstrated in the ERCOT tests asrequired in the ERCOT Protocols. The Customer will maintain the ERCOT specifiedvoltage level unless otherwise directed by the RTO System Dispatcher or ERCOT.If the ERCOT specifies a maximum voltage in addition to the recommended level,the Customer will maintain the maximum voltage only during light system loadconditions. If the ERCOT does not specify a voltage level, the Customer willprovide reactive support based on instructions provided by ERCOT or the RTOSystem Dispatcher.

7.2.5 The Customer's voltage regulators, speed governors and power system stabilizers,if required by ERCOT, will be in service whenever generating units are on-line. TheCustomer will immediately notify the ERCOT Real Time Desk whenever a voltageregulator, speed governor or power system stabilizer is taken out of service orplaced back in service. The Customer will maintain settings as close as practical tofive percent speed regulation.

7.2.6 The Customer will maintain generating units on-line during system under-frequencyconditions except that units may be tripped manually at 58.3 Hertz, byinstantaneous relaying at 58.3 Hertz, or by 0.5 second time delay relaying at 58.4Hertz.



8 Protective Relay Settings

8.1 Settings for Relays Installed for the Protection and Automatic Reclosing of CNPTransmission Lines

8.1.1 CNP will calculate and implement all settings for customer owned relays installedfor the protection and automatic reclosing of CNP transmission lines and forcustomer owned relays installed to prevent back-energizing CNP's system fromgeneration installed on the low side of Customer power transformers. On a case-by-case basis, CNP may issue settings for other Customer owned relays. Therelay settings implemented by CNP for the Customer's owned relays will beprovided to the Customer upon request.

8.2 Applicable Relay Settings

8.2.1 The Customer will provide CNP with the settings of Customer owned relays thattrip or close any Customer owned high voltage (60kV and higher) circuit breakers.The Customer will provide to the Transmission Accounts representative anyproposed settings changes for such relays for CNP's review.


r.OW~Real Time Operations Division's Outage and Clearance Coordination Procedure

9 Equipment Additions, Replacement, Upgrades and Removal

9.1 Notify CNP of Equipment Changes

9.1.1 The Customer must notify the Transmission Accounts representative withsufficient notice to meet the timeline and data reporting requirements in Table 2below when equipment additions or removals are planned or when high voltageequipment or associated equipment requires modification or replacement.

9.1.2 The Customer will provide equipment and installation per applicable CNPspecifications and bill of materials. The Customer will provide necessary details(e.g., drawings, specifications, and manufacturer type and catalog number) forCNP's review. All CNP comments must be incorporated or resolved before anyequipment or materials are procured or any work is begun.

9.1.3 ERCOT Protocols require that all changes to equipment rated at 60 kV and above

be communicated by CNP to ERCOT prior to the in-service date as specified inTable 2 below.

9.1.4 ERCOT shall only approve energization requests when the transmission elementis satisfactorily modeled in the ERCOT Network Operations Model.

9.2 Modification, Repair, and Replacement of Customer Equipment

9.2.1 CNP will notify the Customer of problems in their facilities of which CNP becomesaware. The Customer will provide any needed equipment modifications, repairs,or replacement within an appropriate time frame. The Customer will replaceequipment that CNP demonstrates is no longer maintainable. On a case-by-casebasis, the Customer and CNP will develop the responsibilities for the modification,repair, and replacement of this equipment.

9.2.2 Industry experience may dictate that certain equipment be modified, repaired, orreplaced due to manufacturing defects or unacceptable failure rates andconsequences. The Customer will, within an appropriate time frame, modify,repair, or replace equipment based on manufacturer issued product serviceadvisories or CNP issued advisories.

Customer Substation Equipment Additions,Relocations, Upgrades and/or Removals


e- s_ _„^,._^_ ,Real Time Operations Division's Outage and Clearance Coordination Procedure

When installing, relocating or upgrading transmission system equipment, Customers must contacttheir appropriate CenterPoint Energy Transmission Accounts representative with sufficient notice tomeet the timelines and data requirements shown below. ERCOT Nodal Protocols section 3.10.1requires that all changes to transmission equipment energized at 60 kV and above be communicatedby CNP to ERCOT using the Network Operations Model Change Request (NOMCR) process assummarized below:

Table 2

Target Physical Equipment

In-Service Month

Deadline to Submit necessary informationto Transmission Accounts - by no laterthan:

Month of January June 1 (the prior year)

Month of February July 1 (the prior year)

Month of March August 1 (the prior year)

Month of April September 1 (the prior year)

Month of May October 1

Months of June-July - August (Summer Model) January 1

Month of September February 1

Month of October March 1

Month of November April 1

Month of December May 1

(1) CNP will require the following information to meet the deadlines shown above. The NOMCR datarequirements include, but are not limited to (per Nodal Protocol 3.3.2.1):

• Completed project expected in-service date

• equipment ratings

• device nomenclature will be provided by CNP

• Engineering drawings showing the final configuration.

• Construction sequence with expected energization dates for each piece of equipment.

• Identification of SCADA data points

• Additional data as may be determined by ERCOT

(2) Known outage requests must be submitted by Real Time Operations with the NOMCR's for each

expected energization date.

(3) ERCOT shall only approve energization requests when the Transmission Element is satisfactorilymodeled in the ERCOT Network Operations Model.


6^Real Time Operations Division's Outage and Clearance Coordination Procedure

10 Equipment Maintenance

10.1 CNP Maintenance

10.1.1 CNP will perform periodic testing of certain Customer equipment if the equipment isinstalled for the protection of CNP transmission lines. This includes power linecarrier tuning and testing of wave traps, tuners, and carrier sets and calibration andtesting of relays and fiber optic communication equipment. CNP will performperiodic calibration and testing of SCADA (Supervisory Control and DataAcquisition) transducers that provide real time data to CNP. CNP may designateadditional Customer equipment for maintenance by CNP. CNP will label equipmentmaintained by CNP.

10.1.2CNP will endeavor to coordinate CNP maintenance with the Customer'smaintenance outages.

10.1.3 CNP transmission line outages are required for CNP to perform testing of applicableCustomer wave traps.

10.1.4 Outages of approximately ten hours duration for certain Customer facilities arerequired for CNP's periodic maintenance of any CNP high voltage meteringinstrument transformers. Transformer outages are required for metering instrumenttransformers installed on the high side of transformers. A total separation fromCNP's system may be required for certain substation configurations.

10.2 Customer Maintenance

10.2.1 The Customer will perform periodic inspections and preventive maintenance on allstructures and equipment owned by the Customer except for equipment designatedby CNP for maintenance by CNP such as SCADA equipment and transmission lineprotective relaying equipment. The Customer will not perform preventivemaintenance on the equipment maintained by CNP. The Customer will maintainequipment logs and test reports, which will be provided to CNP upon request.

10.2.2 Depending upon ownership, equipment maintained by the Customer may includethe following: line surge arresters, potential and current transformers not owned byCNP, coupling capacitors, coupling capacitor potential devices, switches (includingauxiliary contacts and motors if installed), breakers (bushings, mechanism, tanks),transformers (bushings, surge arresters, main tank, load tap changer, alarms),relays not tested by CNP, and DC Battery system equipment.

10.2.3 The Customer will notify the RTO System Scheduler at least ten (10) working daysin advance before performing maintenance on potential or current transformersconnected to CNP meters.



10.3 Monthly Inspections

10.3.1 The Customer will perform monthly inspections to include the following asapplicable.

F^ Visual inspection of outdoor equipment including inside control cabinetsn Verify oil levelsF1, Verify transformer nitrogen blanket pressuren Verify transformer fan operationP, Verify breaker compressor or hydraulic pump operationn Drain condensate from breaker mechanism air tanksF1 Verify operation of control house heating and air conditioning

10.4 Quarterly, Semi-annual Testing and Inspection

10.4.1 CNP recommends Total Combustible Gas (TCG) testing once every three monthson transformers equipped with a nitrogen blanket.

10.4.2 Infrared thermography of high voltage equipment is recommended once every sixmonths.

10.5 DC Battery System

10.5.1 The Customer will perform periodic DC battery system equipment inspections andmaintenance to include the following as applicable.

C7 Every Month5 Visually inspect batteries (corroded connections, leaks, cracked cases)q Visually inspect chargers7 Verify and correct water levelsi I Record and verify float voltageF^ Record and verify ground reference voltage

,-t Every Six MonthsF-i Clean battery surfacesF^ Check charger ventilationq Record and verify cell voltages7 Perform cell impedance testing7 Measure connection resistance-1 Record and verify specific gravity reading on a single pilot cell7 Verify float and equalize voltage settings71 Verify proper operation of chargers and alarms--1 Verify proper operation of high voltage shutdown circuits


caMaPndnta^Real Time Operations Division's Outage and Clearance Coordination Procedure

10.6 Functional Testing

10.6.1 The Customer and/or CNP will perform functional trip testing following substationadditions or modifications. Each high voltage breaker will be tripped and closedfrom the breaker control switch at least once every year. This breaker tripping, aswell as functional trip testing, may be coordinated with the switching required formaintenance outages. The Customer will notify the RTO System Scheduler, byNoon Wednesday of the week prior to the planned maintenance before performingfunctional testing and allow CNP to witness the testing.

10.6.2 High voltage circuit breakers equipped with dual trip coils that use a commonactuating shaft (e.g., Allis Chalmers, Westinghouse) require special functionaltesting. The Customer will perform a test on each breaker by applying trip voltagesimultaneously to both trip coils. If the breaker does not immediately trip, thevoltage must be quickly removed to avoid damaging the coils. After verifying thewiring, the Customer will appropriately label the control wiring. The Customer'smaintenance procedures will include tagging and properly reconnecting trip coilwiring. The Customer will perform this test whenever a trip coil is replaced orbreaker control wiring is modified.

10.7 Special Inspection and Testing

10.7.1 Industry experience may dictate that certain equipment requires special inspectionand testing due to manufacturing defects or unacceptable failure rates andconsequences. The Customer will perform special inspection and testing based onmanufacturer issued product service advisories and CNP issued advisories.


aM►x~Real Time Operations Division's Outage and Clearance Coordination Procedure

11 Plant Design Considerations

11.1 Emergency Systems

11.1.1 Continuous electric service from utility power systems cannot be guaranteed evenfor facilities that are connected to a large number of transmission lines. Thepossibility exists that a total power outage or separation from the utility system mayoccur. It is important to consider this when plant emergency systems are designed.

11.2 Automatic Reclosing

11.2.1 CNP utilizes automatic reclosing of high voltage circuit breakers followingunplanned tripping of CNP transmission lines. CNP endeavors to intentionally delaythe initial reclose attempt by at least one second. The Customer is responsible forthe separation of necessary motors or other equipment within one second of thetripping.

11.3 System Voltage

11.3.1 Electric service from a utility power system cannot be guaranteed againstfluctuations. A common fluctuation is a voltage sag that occurs during the time of afault. The large majority of faults on a utility transmission system are single line-to-ground faults. With automatic reclosing of circuit breakers, several voltage sagscan occur within a one-minute period. Most voltage sags from faults ontransmission systems have a very short duration of less than ten cycles with high-speed fault clearing. Another common fluctuation is a transient voltage oscillationthat occurs each time a capacitor bank is energized. Equipment, such as motorcontractors, adjustable speed drives, programmable logic controllers, and highintensity discharge lamps, can be sensitive to these short duration voltage sag andtransient voltage oscillation.

11.3.2 It is important to consider voltage sag "ride-through" for equipment applied to criticalprocesses where nuisance tripping can cause a whole process to shut down. Plantpower systems and equipment control systems can be designed or modified to ride-through the most common voltage sags and transient voltage oscillations on utilitypower systems. CNP will provide additional information upon request.

11.4 Electrical Protection Coordination Studies

11.4.1 Customers typically perform plant electrical protection coordination studies fromtime to time. The Customer may contact a Transmission Accounts representative torequest the available CNP system fault current and system impedance at theCustomer's facility.

11.5 Substation Design Specifications

11.5.1 The Customer can contact a Transmission Accounts representative to requestcurrent CNP specifications and applicable bills of material for new substations andsubstation equipment additions and replacement.


Exhibit "G"Telemetry Specification

TECO Final SGIA 20090210 (2) 172

SPECIFICATION

FOR

REMOTE TELEMETRY OF A CUSTOMER FACILITY

terAvAotEnergy

SUBSTATION OPERATIONS DEPARTMENTP.O. BOX 1700 HOUSTON, TEXAS 77251

REFERENCE DRA1NlNGS: Latest Revisions ofCenterPoint Energy, CNP Drawing No.BSC-007-400-02 SH.1 & 2

REFERENCE SPECIFICATIONS: Latest Revisions ofCenterPoint Energy, CNP Specification No. 007-400-01, SCADA RTUCenterPoint Energy, HL&P Specification No. 007-267-01, Transducer

REFERENCE DOCUMENTS: Latest Revisions ofCenterPoint Energy, Engineering Bulletin No. 19, CNP NAMING CONVENTIONCenterPoint Energy, SCADA ALARMS

' CenterPoint Energy ^HOUSTON, TEXAS

APPRnvFn 12l30/03 M.W. Fumish

5 2/30/04 REVISED FOR EPS METERING COMM WM WM 4WF SHEET I OF 10 SHEETS

NO DATE ITEMS REVISED BY CH APP Wt] 4UU U'L

CONTENTS

ITEM NO. TITLE PAGE NO.

1.0 SCOPE 3

2.0 GENERAL 3

3.0 SCADA SYSTEM 3

4-0 DESIGN, LAYOUT, AND PHYSICAL CRTERIA 5

5-0 COMMUNICATION LINE 6

6-0 CALIBRATION AND MAINTENANCE 6

7.0 CURRENT AND POTENTIAL TRANSFORMERS 6

8.0 DRAWING APPROVAL 7

LIST OF ABBREVIATIONS USED IN FIGURES 8

FIGURE 1- Breaker Control and Status Wiring 9

FIGURE 1- SCADA Cabinet Detail 10

Page 2 of 10

74

1. SCOPE

I.I. This specification defines the requirements for the engineering, installation, calibration, and maintenance of remote

telemetry at customer owned facilities connected to the CenterPoint Energy (CNP) transmission system.

2. GENERAL

2.1. Remote telemetry in Customer-owned facilities is required for (1) All new Independent Power Producers on the

transmission system (2 ) all new transmission substations, (3) existing transmission substations which are undertaking

significant rearrangement or expansion of their existing electrical facilities, or (4) existing transmission substations which

CNP or ERCOT considers critical to system reliability.

2.2. All equipment and work covered by this specification shall be designed, constructed, and tested in accordance with the

latest revisions or editions in effect at the time of fabrication; of the applicable codes, standards, specifications,

regulations, tests, and procedures of all federal, state and local laws, and including (but not limited to) the following:

2.2.1. American National Standards Institute (ANSI)

2.2.2. National Electrical Manufacturers Association (NEMA)

2.2,3. Occupational Safety and Health Administration (OSHA)

22.4. Federal Communications Commission (FCC)

2.3. In the event of conflicting requirements, the order of precedence shall be the applicable federal, state, and local laws and

regulations, this specification, and other referenced CNP specifications.

2.4. CNP will specify the Supervisory Control And Data Acquisition (SCADA) Remote Terminal Unit (RTU). The Customer

must provide interface equipment consisting of items such as transducers, status and alarm contacts, cabling, terminal

blocks, conduit, and communication equipment. All equipment shall be fiunished and installed by the. Customer unless

otherwise noted in this specification or agreed to by separate agreements.

2.5. Equipment specified may be substituted with written approval from the CNP Substation Systems Engineering Division.

2.6. All SCADA equipment shall be readily accessible to CNP personnel.

3. SCADA SYSTEM

3.1. The SCADA RTU is composed of three subsystems : ( 1) analog, (2) status, and (3) control.

3.2. Analog Subsystem: The analog subsystem consists of various customer-supplied transducers which send a *1.5 mA signalto the SCADA RTU or an Intelligent Electronic Device (IED) such as a Electronic meter that can communicate variousdata via DNP3 or Modbus. CNP will determine the transducer electrical requirements. The Customer shall provide anelectrical relay and metering one-line diagram of the existing or proposed Customer-owned substation.

3.2.1. Single phase (AO) watt monitoring and single phase (A0) var monitoring are required for each power flow into or

out of the substation busses. These include (1) CNP transmission line power flows and (2) loads or auxiliaries

connected to the substation busses. See table 1 for acceptable transducer models.

3.2.2. Single phase(AO) bus voltage monitoring is required for each substation transmission bus equipped with a Potential

Transformer (PT). See Table I for an acceptable voltage transducer models.

Page 3 of 1075

3.2.3. IPP Customers shall provide Net Watt and Var monitoring of all generators. A phase, B phase, C phase, and three

phase values shall be supplied to the SCADA RTU. All other power flows can will be three phase values.

3.2.4. Substation Systems Engineering will determine the voltage monitoring requirements for single tap Customer-owned

substations.

3.2.5. Meter test switches are required for each transducer's current and voltage connection. Single phase test switches are

specified in Table 1.

TABLE 1

ACCEPTABLE ANALOG TRANSDUCERS AND TEST SWITCHES

Company Model No. Quantity Description

Scientific Columbus XL342K5A4 and

XLV342KSA4

One per IPP power flow Three phase Watt

Transducer

Scientific Columbus XL5C5A4 and

XLV5C5A4

One per power flow Single phase Watt and

Var Transducer

Scientific Columbus VT110A4 One per substation bus Voltage Transducer

Durham 1060 One per each transducer Three Phase Test Switch

Durham 1022 One per each transducer Single Phase Test Switch

3.3. Status Subsystem: The status subsystem of the SCADA RTU shall consist of the following.

3.3.1. Status of transmission voltage breakers or other devices directly affecting the CNP electrical system as determined by

CNP shall be required. Status shall be derived from either an isolated auxiliary "a" contact in the breaker or

monitoring primary trip coil of the breaker. Refer to Fig.1 for Breaker Status Connections.

3.3.2. Indication of low voltage and battery charger failure is required for the 130 VDC battery system(s). For new

installations, a charger that has low voltage, high voltage, loss of AC input, and loss of charger output indications

shall be provided. A single alarm shall be generated by connecting in parallel the normally open contacts for these

indications. For existing installations a charging system monitor ( F Squared Industries, Model CSM2-130, EVA)

shall be installed by the customer to provide the Alarm.

3.3.3. SCADA Close Inhibit (SCI) indication is required of breakers controlled by SCADA whenever a lockout relay can

inhibit breaker closure by SCADA. A dry, normally open, contact from that relay shall be supplied for SCI

indication. Indication contacts from all lockout relays shall be wired in parallel for a single indication in the SCADA

cabinet, see figure 1.

3.4. Control Subsystem: The control subsystem of the SCADA RTU shall consist of the following:

3.4.1. All 69KV, 138KV, or 345KV circuit breakers that directly affect the CNP transmission system as determined by

CNP require remote control by CNP. Should CNP require the control of any additional breakers, these items will be

indicated by CNP on an Electrical One-Line diagram.

Page 4 of 1076

3.4.2. Dual remote control (control of a breaker by both the Customer's and CNP's control center) is not permitted.

3.4.3. Circuit breaker control shall be through the control subsystem of the SCADA RTU. Figure 1 illustrates how SCADA

control will interface with a typical breaker control scheme.

3.4.4. Carrier control shall be installed for all CNP lines that are equipped with carrier relaying. A contact from the SCADA

RTU shall be installed in the carrier squelch circuit. See figure 2 for typical carrier control circuit.

4. DESIGN, LAYOUT , AND PHYSICAL CRITERIA

4.1. SCADA Set Designation: The type of SCADA RTU installed by CNP will depend on the number of breakers control led.

4.1.1. A free-standing cabinet will require a maximum area of dimensions 36" wide by 36" deep and 90" tall. Each cabinet

may have front and rear access. Clearance of 40" in front of both doors shall be reserved for maintenance access.

Substations with more than ten breaker control points will require two cabinets.

4.1.2. A Wall mounted cabinet will require a maximum area of dimensions 36" wide by 36" deep and 90" tall. Each cabinet

will have front access. Clearance of 40" in front of the door(s) shall be reserved for maintenance access. Substations

with more than ten breaker control points will require two cabinets.

4.2. Connections by the Customer: The Customer shall install all interconnections between the SCADA RTU and the

substation control house.

4.2.1. The Customer shall provide a 120 VAC fifteen (15) amp dedicated AC power circuit, protected by a fifteen (15) amp

circuit breaker, to the SCADA RTU Cabinet.

4.2.2. The Customer shall provide a 130 VDC fifteen ( 15) amp dedicated DC power circuit, protected by a fifteen amp

circuit breaker, to the SCADA RTU Cabinet. .

4.2.3. All cable shields shall be grounded at a location other than the SCADA RTU Cabinet. Cable shields shall be

grounded at one end only.

4.3. Cabling: The Customer shall size and install all conduit or cable troughs in accordance with ANSI/NFPA 70 (National

Electrical Code).

4.3.1. Polyethylene Polyvinylchloride (PEPVC) insulated shielded 2/C #16 cable with stranded copper conductors shall be

used for terminations for all transducer outputs.

4.3.2. Breaker controls shall use seven conductor (#12) PEPVC insulated cable with stranded copper conductors for

terminations. The color code shall conform to Figure 1.

4.3.3. Two conductor (#10 or larger) PEPVC insulated cable with stranded copper conductors shall be used for terminations

of the AC and DC power circuit.

4.3.4. Status and alarms shall be terminated with two conductor (#16) PEPVC insulated cable with stranded copper

conductors.

4.3.5. The Customer shall install the necessary conduit or cable trough between the SCADA RTU and the relay panels.

4.4. Every breaker with 130 VDC SCADA control circuits shall have breaker coil surge suppression. A one hundred (100) ohm,

eleven (11) watt resistor (Ohmite style 995-10A) and a zener diode (Motorola type IN3051A) shall be used for this

suppression. The series combination of the zener diode and the resistor shall be parallel to each breaker trip and breaker

close coil. Durham slider-link terminal blocks shall be installed in the breakers for terminating the resistors and zener

diodes. CNP will verify breaker coil surge suppression. See figure 1.

Page 5 of 1077

5. COMMUNICATION LINE

5.1. CNP will order and pay for the communication line(s) from the telephone company. The Customer shall supply the name

and telephone number of a representative for purposes of co-ordinating the installation of these line(s). The

communication line(s) will be in CNP's name.

5.1.1. The Customer shall provide one dedicated.25-pair cable for communications circuits between the SCADA RTU

Cabinet and an appropriate telephone company demarcation point. The cable shall have the following specifications:

5.1.1.1. Grease filled

5.1.1.2. Shielded, twisted pair cable

5.1.1.3. 22 - 24 AWG solid copper

5.1.1.4. ANSUICEA S-85-625-1996 (Formerly RUS / REA Specification PE-38)

5.1.1.5. gas tube lightning protection

5.1.2. The Customer shall provide a conduit between the communication circuit and the SCADA RTU Cabinet. The conduit

shall be sized for the communications cable.

5.2. CNP, at its option, may use SCADA Radio (952/928 M]Elz FM) for the SCADA communication circuit. The requirements

of the radio, antenna, and associated equipment will be determined by CNP. The Customer shall provide a location for this

equipment.

5.3. The Customer shall provide a full business (IFB) phone line inside the relay control house. This phone shall have a cord

extendable to the SCADA RTU cabinet. This phone is an outside phone line independent from Customer phone system.

5.4. The telephone communication circuit(s) will not fail in the event of power failure. Line conditioners or toopback devices

shall fail with the communications line connected.

6. CALIBRATION AND MAINTENANCE

6.1. After all equipment necessary for remote telemetry has been installed, CNP personnel will calibrate and verify operation of

all equipment installed per this specification.

6.2. The RTU and transducers installed per this specification will be maintained by CNP unless otherwise noted in the

Customer operational agreement. Maintenance will include accuracy checks, recalibration and replacement/repair of

equipment when needed. -

6.3. CNP personnel shall be allowed access at a mutually agreeable time to those locations containing equipment to be

calibrated and maintained by CNP. Access shall be granted for initial calibration, periodic maintenance, and unexpected

maintenance.

6.4. A lock box with a CNP Co. lock shall be installed by the door to give CNP personnel access to the control house.

7. CURRENT TRANSFORMERS AND POTENTIAL TRANSFORMERS

7.1. The current transformers (CTs) and potential transformers (PTs) necessary for transducers and meter circuits itemized in

this specification shall be provided according to CNP specification 007-231-14. If a particular application is not covered

by this specification, then CNP will designate the necessary PT(s) and CT(s) on the substation one-line diagram that the

Customer submits for comment and approval.

7.2. For some substation layouts a potential rollover circuit shall be needed. If a potential rollover circuit is needed, it will be

designated by CNP on the one-line diagram that the Customer submits for comment and approval.

Page 6 of 1078

8. DRAWING APPROVAL

8.1. The Customer shall provide three ( 3) folded copies of all drawings showing equipment connections and structural details

of all equipment associated with SCADA installation for comment and approval by CNP Substation System Engineering.

Preliminary drawings shall be submitted sixteen (16) weeks in advance of equipment purchase so that timely changes can

be implemented. The minimun turn around time for comment and/or approval of preliminary drawings by CNP System

Engineering is four weeks. All drawings returned unapproved to the Customer shall be re-submitted for approval before

ordering equipment or starting construction. Transmission Customers shall submit the drawings to the CNP Industrial and

Large Commercial Accaount (ILCA) Representative.

8.2. Drawings required by this specification include:

1. Substation one-line relay and metering diagrams illustrating the overall telemetry scheme,

2. Relay control room layout(s) and floor plan(s),

3. Conduit and cable lists and layout

4. RTU manufacturers prints and customer connections

5. AC Schematics for all power and control circuits,

6. AC Relaying Schematics (Electrical Three-Line),

7. Relay panel layouts,

8. Bill of material for items required by this specification,

9. Battery charger alarm relay(s) schematics,

10. AC & DC Distribution Panels,

11. Communication cable and conduit routing through Customer facility,

12. Customer Facility Plot Layout,

Page 7 of 10

79

LIST OF ABBREVIATIONS AND SYMBOLS USED IN FIGURE 1

aN4, AN 14 = TYPICAL WIRE NAMES IN CNP CARRIER RELAYING SCHEMES

ATCR = AUTOMATIC CARRIER REMOVAL

C = CLOSE

C = BREAKER CLOSE COTL

CS = CONTROL SWITCH

CVE = SYNCRO-VERIFIER RELAY

ICR = INDICATION CONTROL RELAY

N 11, N21 = TYPICAL WIRE NAMES IN CNP RECLOSE REMOVAL SCHEMES

NO = NORMALLY OPEN

RC = AUTOMATIC RECLOSING RELAY

RR = RECLOSE REMOVAL LATCHING RELAY

T = TRIP

TC = BREAKER TRIP COIL

X, Y = AUXILIARY COILS OF RC RELAY

SSS = SLIDER-LINK TERMINAL

R = RESISTOR

DDD = ZENER DIODE

AMS = AUTOMATIC / MANUAL THROWOVER SWITCH

Page 8 of 1080

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Exhibit "H"Attached Drawings

TECO Final SGIA 20090210 (2) 183

PAGES CONTAINING CRITICAL ENERGY

INFRASTRUCTURE INFORMATION (CEII) REDACTED

FOR PUBLIC FILING.

H.\CACAS\TA1Customers\Forrns, Policies, Procedures, Specifications\SGIA\CEII Redacted Insertion Page.docx 84

Exhibit "I"Specification for Customer 138 kV Substation Design

TECO Final SGIA 20090210 (2) 1 85

5-8-2006 Addendum toSpec. No. 007-231-14 Rev. 14 7-22-2005

SPECIFICATION FORCUSTOMER 138 kV SUBSTATION DESIGN

CENTERPOINT ENERGYSUBSTATION OPERATION DEPARTMENT

P.O. BOX 1700 HOUSTON, TEXAS 77251

Date Original Version Revision Comments

5-8-06 a. Table of Contents (TOC) a. Added missing TOC items 4 a. Updated Table of Contents

b. REFERENCE DRAWINGS not & 8 b. Reference drawings

included in this document b. Added drawings to end of this includeddocument

86

SPECIFICATIONFOR

CUSTOMER138 kV SUBSTATION

DESIGN

CENTERPOINT ENERGYSUBSTATION OPERATIONS DEPARTMENT

P.O. BOX 1700 HOUSTON, TEXAS 77251

REFERENCE DRAWINGS: Latest revision ofCenterPoint Energy 004-241-01, Customer-Owned Substation Line Termination StandardCenterPoint Energy 171-190-06, 138 kV Standard, Instrument Transformer StandardCenterPoint Energy 581-500-01, 138 kV Potential Transformer Schematic and Wiring Diagram

REFERENCE DOCUMENT: Latest revision ofOperation of a Customer Owned Substation on CenterPoint Energy's Transmission System

REFERENCE SPECIFICATIONS: Latest revision ofCenterPoint Energy 007-231-78, Specification for Cogenerator Connected to CenterPoint Energy Trans.

SystemCenterPoint Energy 007-400-02, Specification for Remote Telemetry of a Customer-Owned Facility

REFERENCE STANDARDS: Latest revision ofAASHTOACI 318AISC, "Manual of Steel Construction"ASCE 10ANSI C12.1ANSI C37.32ANSI C37.06IEEE C37.04IEEE C37.40IEEE C37.60

IEEE C57.12.00IEEE C57.13IEEE C2 (NESC)IEEE Std. 80IEEE Std. 519IEEE Std. 837IEEE Std. 1119IEEE Std. 998IEEE Std. 142NEMA CC 1

CENTERPOINT ENERGYHOUSTON, TEXAS

WRITTEN 4/9/74 E. C. ReidCHECKED 4/l0/74 L. G. Pond

APPROVED 7/17/74 C. S. Kayser

14 7-22-2005 Change to 4000A and other updates Var Var DRS SHEET I OF 26

NO DATE ITEMS REVISED BY CH APP SPECIFICATION NO. 007 231 14

87

CenterPoint Energy SPECIFICATION FOR CUSTOMER 138 KV SUBSTATION DESIGN

TABLE OF CONTENTS

ITEM TITLE PAGE

1. SCOPE ................................................................................................. ..........................................................3

2. GENERAL ........................................................................................... .......................................................... 3

3. CENTERPOINT ENERGY SYSTEM CHARACTERISTICS ....... ..........................................................4

4. ELECTRICAL DESIGN CRITERIA ............................................... ..........................................................4

5. STRUCTURAL AND MECHANICAL DESIGN CRITERIA ........ ..........................................................6

6. SITE CRITERIA ................................................................................. ..........................................................8

7. HIGH VOLTAGE EQUIPMENT ..................................................... ..........................................................9

8. CONTROL HOUSE ............................................................................ ........................................................12

9. METERING EQUIPMENT .............................................................. .........................................................12

10. FUSING ............................................................................................... .........................................................15

11. PROTECTIVE RELAYING ............................................................. .........................................................16

12. UNDER-FREQUENCY LOAD SHEDDING .................................. .........................................................18

13. REMOTE TELEMETRY .................................................................. .........................................................19

14. GENERATION .................................................................................. .........................................................19

15. DRAWING COMPLIANCE REVIEW & COMMENTS .............. .........................................................20

16. EQUIPMENT INSTALLATION ...................................................... .........................................................21

17. REQUIRED TESTS AND INSPECTIONS ..................................... .........................................................22

18. RECOMMENDED TESTS AND INSPECTIONS ......................... ..........................................................24

REFERENCE DRAWINGS ......................................................................................... ..........................................................26

Rev Date Items Revised Specification No. Page File

14 7-22-2005 4000A and other updates 007-231-14 2 CNP_007-231-14revI4_7-22-2005 Addendum 5-8-2006.doc

88


1. SCOPE

I.I. This specification covers design criteria for 138 kV customer-owned substations connected to theCenterPoint Energy Houston Electric, LLC (CenterPoint Energy) transmission system.

2. GENERAL

2.1. Any customer that is approved by CenterPoint Energy to receive service from the CenterPoint Energy138 kV transmission system is required to provide a substation capable of accepting that service fromCenterPoint Energy. The customer's substation becomes an integral part of the CenterPoint Energytransmission system network and therefore has a significant impact on overall system reliability.Consequently, the customer is obligated not only to meet present CenterPoint Energy specifications,but also to modify the substation in the future as the CenterPoint Energy transmission system continuesto evolve. When deemed necessary by CenterPoint Energy, changes may be needed to conform toindustry standards, transmission system characteristics, and CenterPoint Energy practices or to takeadvantage of technological advances which will maintain the present reliability of the substation.

2.2. All equipment shall be in accordance with designated standards of this specification, the AmericanNational Standards Institute (ANSI), the Institute of Electrical and Electronic Engineers (IEEE), theAmerican Society of Civil Engineers (ASCE), the American Institute of Steel Construction (AISC),

National Electrical Manufacturing Association, (NEMA) and the American Concrete Institute (ACI).In the event of conflicting requirements, the order of precedence shall be this specification, ANSI,IEEE, ASCE, AISC, NEMA and ACI Standards. All electrical clearances shall comply with the latestversion of the National Electric Safety Code (NESC).

2.3. This specification is not intended to be totally comprehensive. To ensure the efficient coordinationbetween CenterPoint Energy and the customer during the design and construction of the customer'ssubstation, CenterPoint Energy requires that engineering documents be submitted to CenterPointEnergy for review before certain equipment is ordered or construction begins. All items requiring

CenterPoint Energy review are listed in Article 15.0 of this specification and shall be submitted inwriting to the designated Project Coordinator, or designated representative.

2.4. Any deviations from this specification or CenterPoint Energy reviewed project drawings shall requirewritten acceptance by the responsible CenterPoint Energy Project Coordinator.

2.5. All labor and equipment shall be furnished by the customer unless otherwise noted in this specification.

2.6. Unless otherwise stated in this specification:

2.6.1. CenterPoint Energy will provide only functional reviews of complete and final drawings and

schematics,

2.6.2. CenterPoint Energy will not verify or correct customer's point-to-point wiring, and

2.6.3. CenterPoint Energy will require specific tests which are to be conducted by the customer toverify the proper operation and coordination of the substation's protection and control

equipment.

2.7. CenterPoint Energy reserves the right to refuse to energize any service which fails to meet this

specification.


14 7-22-2005 4000A and other updates 007-231-14 3 CNP_007-231-14rev14_7-22-2005Addendum 5-8-2006.doc

89


2.8. The customer will coordinate the operation of their high voltage facilities with CenterPoint Energy'sReal Time Operations Division per CenterPoint Energy's "Transmission & Substation Outage andClearance Coordination Procedures" document.

2.9. It is the customer's responsibility to comply with the applicable laws, ordinances, codes, rules, andregulations established by the appropriate government entities.

2.10. Because the customer's substation becomes an integral part of the CenterPoint Energy transmissionsystem network CenterPoint Energy requires access to the substation 7 days-a-week, 24 hours-a-day,365 days-a-year. Access to the substation by CenterPoint Energy personnel should be considered whendetermining the location and plant operating procedures.

3. CENTERPOINT ENERGY SYSTEM CHARACTERISTICS

3.1. CenterPoint Energy's phase rotation is designated C-B-A counterclockwise and the customer shall

phase his equipment accordingly. Connection of the customer's HI -H2-H3 power transformer leads toCenterPoint Energy's C-B-A, B-A-C or A-C-B, respectively, is recommended.

3.2. The steady-state nominal system voltage is 138 kV +/- 5%, wye effectively grounded. Transient

conditions exceeding this range may be encountered. See Sub-articles 3.4, 4.6 and 7.1.4 for additional

relevant information.

3.3. Frequency, which ERCOT is responsible for maintaining, is nominally 60 Hz. Refer to ERCOT

(www.ercot.com) Operating Guides and Protocols for information regarding frequency regulation.

3.4. The customer's equipment "voltage dip ride through" design criteria, that CenterPoint Energy suggeststhe customer utilize when designing and selecting plant equipment is illustrated in figure 3.1.

V=50%

TV = 100%

VV VV VVI -V VV12 cycles.^ -

"V" represents the phase-to-neutral voltage at the customer's "load side" of a delta-wye transformer for a phase-to-ground fault at the "high side" of the transformer.

Figure 3.1

3.5. Multiple shot, staggered, relay supervised, automatic reclosing is utilized on the CenterPoint Energytransmission system. The first automatic reclosing attempt on CenterPoint Energy transmission linewill occur a minimum of one second after the fault has cleared. The number of automatic reclosingattempts varies, but the total duration of the automatic reclosing sequence is typically one minute. Thecustomer shall accordingly coordinate operation and protection of electric motors, computers and otherplant equipment.

4. ELECTRICAL DESIGN CRITERIA

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4.1. The minimum acceptable electrical design characteristics are listed below:

Bus, Switch and Insulator Impulse Level 650 kV BIL in a non-contaminated area750 kV BIL or 650 kV BIL with extra creep in acontaminated area

Note: CenterPoint Energy shall make determination of contaminated or non-contaminated area.

Transformer Winding Impulse Level

Bus and Switch Insulator Leakage Distance

Apparatus Bushing Leakage Distance(circuit breakers, bushings, transformerbushings, etc.)

Phase to Ground Clearance

550 kV BIL

132 in. creep (equivalent to 750 kV BIL or extracreep 650 kV BIL)

92 in. creep (equivalent to 650 kV BIL)

52 in. (Metal to Metal)

Phase to Phase Bus Spacing 63 in. (Metal to Metal)(including vertical spacing at crossoverpoint of high and low bus)

Phase to Phase Bushing Spacing (138 kV) 84 in. (Center Line to Center Line)

Phase to Phase Horizontal Spacing 144 in. (Center Line to Center Line, regardless of

at Incoming Line Dead End Structure the line angle)

4.2. "Full loop" (ring bus or breaker-and-a-half) or "loop tap" are standard substation configurationsallowed by CenterPoint Energy.

4.3. For "full loop" substations, "loop tap" substations or substations arranged for future "loop" service, thecontinuous current rating of all equipment in the substation "loop" and incoming transmission linepositions (transmission line disconnect switches, line traps, etc.) shall be 4,000 A minimum, unlessotherwise specified by CenterPoint Energy. For substations with four or more 138 kV transmissionlines, the continuous current rating of equipment in the substation may be required to be greater than4,000 A. The 138 kV substation shall be designed for a short circuit cur-rent of 63 kA rms symmetrical,

with X/R ratio of 15.

4.4. A key interlock system is not permitted on 138 kV equipment.

4.5. The customer's connected load and equipment shall be designed and operated to adhere to therecommended harmonic limits of IEEE Std. 519.

4.6. The CenterPoint Energy flicker limit criteria for 138 kV customers is as follows:

4.6.1. The operation of customer's equipment (starting of motors, furnaces, etc.) shall not produce avoltage dip greater than 2.0% at the customer's high side bus with one transmission linesegment directly associated with the electrical supply to the customer substation out-of-service.

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4.6.2. If the starting of the customer's equipment produces a voltage dip greater than 1.5% at thecustomer's high side bus with all transmission line segments in-service, the customer shallcontact CenterPoint Energy for further evaluation.

4.7. The substation ground mat shall be designed for a short circuit current of 63 kA rms symmetrical. withX/R ratio of 15 and duration of 0.25 seconds ^ and comply with IEEE Std. 80 and IEEE C2 (NESC).

Ground mat connections shall comply with IEEE Std. 837.

4.8. The substation direct lightning stroke shielding design shall comply with IEEE Std. 998.

5. STRUCTURAL AND MECHANICAL DESIGN CRITERIA

5.1. The customer shall provide a complete structural and foundation design package for the dead-endstructures (supporting the CenterPoint Energy transmission lines connected to the customer's 138 kVsubstation) and the instrument transformer stands in accordance with Article 15.0. The design packageshall be signed and sealed by a registered professional engineer and shall include designreferences/codes, computer analysis, member design, connection design, foundation design, structuraland foundation drawings, and all other information that documents the design of the structure(s).

5.2. Design shall be based upon loadings realistically combined to cause the most unfavorable effect uponthe structure or component. Refer also to Sub-Article 5.4 and 5.5.5.

5.3. Structures shall meet the Strength Requirements of IEEE C2 (NESC), Section 26, for grade B

construction.

5.4. The minimum acceptable structural design loading criteria shall be the more severe of the following

two cases:

5.4.1. Case 1- Combined Ice and Wind Loading: Reference specification IEEE C2 (NESC); minimumallowable strength factors per Section 26, Table 261-1A or Table 261-1B; loading requirementsper Section 25, Rule 250.B and Table 250-1; and loading components to be applied to thestructure shall be according to Fig.5.1.

Transverse

^

WindLongitudinal

Direction St

Isi

St

Tt Tt TtSi

TI Ti TIWind and Ice loads are specified in Section 25 of ANSI/IEEE C2

Static Wire Conductor WireSI = 6.00 kips/wire longitudinally TI = 10.0 kips/phase longitudinallySt= 3.00 kips/wire transversely Tt = 5.00 kips/phase transverselySv = 0.50 kips/wire vertically Tv = 1.50 kips/phase vertically

CASE 1 - Combined Ice and Wind Loading - Overhead View.Static wire and conductor wire loading component (Overload capacity factors not included.)

Figure 5.1

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5.4.2. Case 2 - Extreme Wind Loading: Reference specification; IEEE C2 (NESC) Section 25, Rule250.C; minimum allowable strength factors per IEEE C2 (NESC), Section 26, Rule 260.C; andmagnitude and direction of static wire and conductor wire loading components to be applied tothe structure shall be according to Fig.5.2.

o Transverse

WindLongitudinal

Direction St --► St

ht t--Tt TtSl Si

Ti Ti Ti

For Case 2 the following shall apply:Basic Wind speed determined from wind map in, Exposure category C,Importance factor 1.0, Design wind pressure equation and coefficientsper IEEE C2 (NESC) Rule 250.C in latest version.

Static Wire Conductor WireSI = 6.00 kips/wire longitudinally TI = 15.0 kips/phase longitudinally

St= 3.00 kips/wire transversely Tt = 7.50 kips/phase transversely

Sv = 0.50 kips/wire vertically Tv = 1.50 kips/phase vertically

CASE 2 - Extreme Wind Loading - Overhead View.Static wire and conductor wire loading component: (Overload capacity factors not included.)

Refer to Sub-Article 8.1.2.4.1' Figure 5.2

5.5. DEAD-END STRUCTURES

5.5.1. In the absence of specifically defined criteria by CenterPoint Energy, the following designcriteria shall be used as default design values for dead-end structures.

5.5.1.1. The conductor height at attachment shall be 35 feet above the finished substation grade.

5.5.2. Customer shall design all attachment points to ensure that sufficient electrical clearance ismaintained to the customer's structure ground and equipment. CenterPoint Energy will extendthe load carrying conductor to the first item of customer's equipment or bus and will furnish,own and maintain all necessary fittings for terminating the line conductors including the towerfittings, suspension insulators, dead-end clamps and line conductor terminal fittings withNEMA standard four-hole flat pads (0.5625 in. diameter holes, 1.75 in. centers) for attachmentto the first item of equipment or bus in the customer's substation. CenterPoint Energy will alsofurnish stirrup clamps or other similar devices (such as a bar on the NEMA pad for ACSSconductors) on the line conductors as required for connection of surge arresters and potentialtransformers.

5.5.3. Customers shall provide pull-off plates (0.625 in. minimum thickness) for terminating the lineconductors and which have a 0.8125 in. diameter chamfered hole at the center of a 1.50 in.radius rounding of the end of the plate. In addition, the customer shall provide pull-off plates(0.375 in. minimum thickness) for terminating the static wires and which have a 0.8125 in.diameter chamfered hole on a 1.50 in. radius rounding of the end of the plate. All pull-off

plates must satisfy Equation 4.6-1 and 4.6-2 in ASCE 10. Details for division of ownershipshall be in accordance with CenterPoint Energy Drawing 004-241-01.


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5.5.4. The height of the dead-end structure's conductor attachment shall be in accordance with theNational Electric Safety Code (IEEE C2) or 35 ft whichever is greater, unless otherwisespecified by CenterPoint Energy. The static wire height at attachment shall be at a sufficientelevation and position to provide a shield angle to the outside conductors of 30° and 45°between two adjacent static wires (see IEEE Std.142).

5.5.5. The installation of fiber optic cable may be required for transmission protective relaying and/orcontrol purposes. The fiber optic cable installations will normally be installed underground.However, should an overhead installation be required, additional loadings will be imposed onthe customer's dead end structure. Additional design information concerning the fiber opticcable will be supplied by CenterPoint Energy when fiber optic cable is to be used. Typically theconnection for the fiber optic cable is at least 8 ft from the nearest conductor.

5.6. INSTRUMENT TRANSFORMER STANDS

When high side metering is utilized, the customer shall provide stands for mounting CenterPointEnergy furnished instrument transformers and design and build foundations to support the stands.The design shall be in accordance with Sub-Articles 5.1 - 5.4 of this specification. The necessarydesign parameters are indicated on CenterPoint Energy Drawing 171-190-06.

6. SITE CRITERIA

6.1. Site preparation and plot plan drawings shall be submitted to CenterPoint Energy for comment.Facilities that must be shown on this drawing include dimensions of the substation site, accessroadways, space between the substation and access roadways, walks, culverts and ditches. Refer to

Article 15.0


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6.2. The customer shall stake the location of the dead-end structures according to Figure 6.1.

Staking Requirements for Typical Customer SubstationFigure 6.1

6.3. An all weather access roadbed shall be provided to the substation capable of supporting heavyconstruction vehicles. The areas in substations that need to support heavy vehicular traffic shouldconform to AASHTO H20 loading.

6.4. Access for CenterPoint Energy to attach line conductors to the dead-end structures shall be provided by

either:

6.4.1. A 25 ft wide, level, and unobstructed access outside the substation site from a main road to theCenterPoint Energy right-of-way and in front of the dead-end structures with fencing amaximum of 20 ft from the attachment point of the dead-ends and a 13 ft (minimum) wide gatefor access into the substation.

6.4.2. A 25 ft wide access inside the substation from the substation access gate (20 ft wide minimum)

to the front of the dead-ends with fencing a minimum of 25 ft from the attachment point.

6.5. Access and space shall be provided for installation and future replacement of high voltage equipmentincluding metering instrument transformers.

7. HIGH VOLTAGE EOUIPMENT

7.1. POWER TRANSFORMERS

7.1.1. Power transformers shall conform to IEEE C57.12.00. In addition, sudden pressure and low oillevel should be connected for alarming and tripping.

7.1.2. Power transformers shall have a minimum of two 600:5 A multi-ratio current transformers(CT's) per 138 kV bushing. Each CT shall have IEEE C57.13 accuracy C400 or better. Where


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W RACKS AT THESE LOCATIONS


applications require additional CT's and/or different ratios, CenterPoint Energy shall provideratios to support equipment purchase schedule. The secondary resistance of power transformerbushing CT's shall not exceed 0.0025 S2 per turn. CT secondary rated continuous current shallbe 10 A minimum. Rating Factor (R.F.) shall equal 2.0.

7.1.3. High side surge arresters shall be provided in accordance with Sub-Article 7.4.

7.1.4. The customer shall determine the need for, and if applicable, settings for a tap changer for de-energized operation and/or on-load tap changer. CenterPoint Energy recommends automatic

on-load tap changer.

7.2. CIRCUIT BREAKERS

7.2.1. Circuit breakers shall be of the three-pole, outdoor type, 138 kV nominal, in accordance withANSI C37.06 and IEEE C37.60, C37.04 and C37.40.

7.2.2. Continuous current rating of 138 kV circuit breakers shall be 4,000 A, with a three phasesymmetrical short circuit interrupting capability of 63 kA rms symmetrical. For substationswith four or more 138 kV transmission lines, circuit breakers may be required to have a highercontinuous rating. The rated interrupting time of the circuit breakers shall be three cycles orless. In some applications, the installation of TRV shaping capacitors may be required in orderto achieve the circuit breaker interrupting capability of 63 kA rms symmetrical for line faults.CenterPoint Energy shall determine the placement of TRV shaping capacitors, when required.

7.2.3. Each 138 kV circuit breaker shall be equipped with two 4,000:5 A multi-ratio CT's per 138 kVbushing. Each CT shall have an accuracy of C800 on the 3,000:5 A tap in accordance with

IEEE C57.13. The secondary resistance of circuit breaker bushing CT's shall not exceed0.0025 S2 per turn. CT secondary rated continuous current shall be 10 A minimum. RatingFactor (R.F.) shall equal 2.0.

7.2.4. Two trip coils shall be provided with independent 125 VDC control circuits. If both trip coils

operate a single armature, both coils shall be designed or marked in such a way as to preventtheir being connected in a manner that would result in the breaker not tripping in the event thatboth coils are energized simultaneously.

7.2.5. Trip and close DC currents shall not exceed 15 A per coil and shall not be less than 4 A per coil.

7.2.6. Trip circuits shall not be fused inside the circuit breaker control cabinet.

7.2.7. Surge suppression shall be provided on each trip and close coil. Reference CenterPoint EnergySpecification, 007-400-02.

7.2.8. The circuit breaker operating mechanism shall be both mechanically and electrically trip-free inany position. For oil circuit breakers, a latch check switch shall be provided.

7.2.9. Circuit breakers with air closing mechanisms shall have stored energy for 5 close-open

operations. Circuit breakers with spring closing mechanisms shall have the spring chargingmotor circuit connected to a 125 VDC battery source utilizing a DC supply cable dedicated for

this purpose. Voltage rollover from AC to DC shall not be installed for the spring charging

motor circuit for circuit breakers.

7.2.10. Gas circuit breakers shall have low gas pressure alarm and close inhibit contacts.

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7.2.11. Circuit breaker internal time delay circuitry for reclosing shall not be utilized. External time

delayed automatic reclosing, when utilized, shall be wired/connected directly to the circuitbreaker close circuit. External time delay for reclosing circuit is to be provided by other relays.

7.2.12. CenterPoint Energy recommends that the control circuitry of circuit breakers be equipped for

operation response monitoring.

7.3. AIR BREAK SWITCHES

7.3.1. Transmission line disconnect switches and all disconnect switches in the substation "loop" shallbe of the outdoor, three pole, gang operated type rated 138 kV nominal, 4,000 A continuous,164 kA peak withstand minimum, unless otherwise specified by CenterPoint Energy. For

substations with four or more 138 kV transmission lines, contact CenterPoint Energy for therequired rating of switches. The switch air gap BIL shall coordinate with the BIL rating of theswitch insulators.

7.3.2. Transmission line disconnect switches are required for "full loop" substations or "loop tap"

substations converted to "full loop".

7.3.3. "Loop tap" substations must be configured and designed with equipment to permit switching forthe scheduled outage of either transmission line section without interrupting service to thecustomer's load. An interrupting device attached to a disconnect switch in a "loop tap"substation for transmission line load breaking, loop switching or line dropping is not acceptable.

7.3.4. Two auxiliary "a" contacts shall be provided on the disconnect switch between transformers in athree circuit breaker, two transformer substation and the disconnect switch between lines in atwo circuit breaker substation.

7.4. SURGE ARRESTERS

7.4.1. All surge arresters shall be metal oxide varsistor type 108 kV class minimum, with a maximumcontinuous over voltage (MCOV) rating of 88 kV minimum. The minimum required energyabsorption capability is 7 kilojoules/ kV of MCOV rating. The minimum required pressure

relief capability is 63 kA rms symmetrical.

7.4.2. To allow for grading / leakage current monitoring, CenterPoint Energy recommends that surgearresters be mounted on plates using insulated spacers and associated hardware. The insulatedground conductor from the bottom flange of the arrester must be isolated from any other grounduntil it passes the point where a tong ammeter reading can be taken. The independent, insulatedground leads should be adequately marked to indicate A, B, and C phases.

7.5. COUPLING CAPACITORS AND LINE TUNERS

7.5.1. CenterPoint Energy shall specify vendor and vendor style number for the coupling capacitordevices and line tuners.

7.6. LINE TRAPS

7.6.1. CenterPoint Energy shall specify vendor and vendor style number for line trap devices.

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8. CONTROL HOUSE

8.1. The control house shall be a permanent, weatherproof structure constructed on a concrete foundationand scheduled for completion well in advance of the remainder of the substation to allow for adequatecheck out and testing. The ambient conditions inside the control house shall not exceed 32°C (90°F)and 85% relative humidity. Fluorescent lighting shall be provided.

8.2. TELEPHONE CIRCUITS:

8.2.1. A touch tone telephone, connected to a commercial, full business direct (IFB) line shall beinstalled in the control house as soon as practical upon completion of the house. The location ofthe telephone shall be such that the front of protective relay panels is visible from the telephone.Intercoms and intra-company telephones are not acceptable for this purpose.

8.2.2. A separate, dedicated telephone line shall be installed in the control house to be utilized forremotely interrogating metering for revenue billing purposes. An intra-company telephone line

with direct inward dialing is acceptable.

8.2.3. If CenterPoint Energy Supervisory Control and Data Acquisition (SCADA) equipment isinstalled, additional telephone circuits may be required. Refer to CenterPoint Energy

specification 007-400-02 for details.

8.3. Wall space for metering cabinets shall be provided in accordance with Sub-Article 9.1.3.1.

8.4. If line relaying with power line carrier and/or fiber optic communication is utilized, space for the powerline carrier transmitter/receiver sets and/or fiber optic fiber optic cable distribution box shall be

provided.

8.5. If CenterPoint Energy Supervisory Control and Data Acquisition (SCADA) equipment is installedspace for the SCADA set and intertie panel shall be provided in accordance with Sub-Article 13.1.

8.6. A separate 120 V AC, 20 A circuit shall be provided to each of the following: (a) the metering cabinet,

(b) the power line carrier transmitter/receiver sets location, and (c) the SCADA intertie panel cabinet, if

installed.

8.7. One single-phase, three wire, 240 V, 30 A outlet shall be located in the substation control house

(Crouse Hinds #AR 321 or equivalent) for relay testing equipment.

9. METERING EQUIPMENT

9.1. METERING

9.1.1. CenterPoint Energy's metering practices conform to ANSI C12.1. Any part of the metering

system that is installed by the customer or his agent shall also conform to ANSI C 12A l atminimum, unless otherwise directed by CenterPoint Energy.

9.1.2. The customer shall submit a one-line diagram of the proposed substation configuration toCenterPoint Energy in accordance with Article 15.0 of this specification. CenterPoint Energywill designate on the one-line diagram the location of all metering instrument transformers(including, without limitation, quantity, transformation ratios, voltage class - high side or low

side and ratings). The metering instrument transformers shall be connected to the transformerlow side or to the 138 kV substation bus by the customer as specified by CenterPoint Energy.


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9.1.3. Metering cabinets shall be located inside an environmentally controlled house.

9.1.3.1. Wall space 3.0 ft wide and 8.0 ft high measured from the floor with 4.0 ft front clearanceshall be provided for installation of each metering cabinet which will be furnished byCenterPoint Energy and installed by the customer. The number of metering cabinets will bedetermined by the metering scheme to be used.

9.1.3.2. Customers requesting metering pulses shall provide all conduit and wiring necessary toconnect to a junction box provided by CenterPoint Energy and mounted on the metering

installation.

9.1.3.3. The customer shall provide a conduit from the telephone board to the metering cabinet.

9.1.4. CenterPoint Energy personnel will make all meter connections. For metering equipment details,consult the CenterPoint Energy project representative.

9.1.5. When high side metering is used, a "full loop" customer shall provide two "a" contacts from thetie breaker and a single "a" contact for each side breaker. A two-breaker "loop tap" customershall provide two "a" contacts from the tie switch and a single "a" contact from each side

breaker. These contacts shall be routed from their associated relay panels to the meteringlocation for rollover of the metering potential to a second set of potential transformers

9.1.6. Where low side metering is used, the customer shall provide space for CenterPoint Energyspecified instrument transformers in their switchgear.

9.1.7. When lowside metering is utilized, 138 kV coupling capacitor potential devices shall beprovided and installed by the customer in accordance with Sub-Article 7.5, when specified by

CenterPoint Energy.

9.2. SWITCHGEAR MOUNTED METERING INSTRUMENT TRANSFORMERS

9.2.1. CenterPoint Energy shall specify all instrument transformers used for CenterPoint Energy

metering.

9.2.1.1. The switchgear manufacturer shall purchase and install the CenterPoint Energy specifiedinstrument transformers and the customer shall invoice CenterPoint Energy for the actualcost of the metering instrument transformers. -

9.2.1.2. Original certified test data shall be provided to CenterPoint Energy for each instrument

transformer supplied.

9.2.2. Metering current transformers (CT's) shall be located in the incoming main breaker cubicle.

The CT's shall be installed by the customer.

9.2.3. Metering potential transformers (PT's) shall be located in roll-out boxes. The PT's shall be

installed by the customer.

9.2.3.1. The secondary windings shall be used only for CenterPoint Energy metering.

9.2.3.2. PT's shall be equipped with I A, current limiting primary fuses.


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Transmission & Substation Outage and Clearance