L-PI-14-010, Response to Request for Additional Information (RAI) Regarding Response to Bulletin 2012-01, Design Vulnerability in Electric Power System.

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Response to Request for Additional Information (RAI) Regarding Response to Bulletin 2012-01, Design Vulnerability in Electric Power System.
ML14034A066
Person / Time
Site: Prairie Island  Xcel Energy icon.png
Issue date: 02/03/2014
From: Sharp S
Northern States Power Co, Xcel Energy
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
BL-12-001, L-PI-14-010
Download: ML14034A066 (7)
v • d • e


Text

Xcel Energy@

February 3, 2014 L-PI-14-01 0 10 CFR 50.54(f)

U S Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Units 1 and 2 Dockets 50-282 and 50-306 Renewed License Nos. DPR-42 and DPR-60 Response to Request For Additional Information (RAI) Regarding Response To Bulletin 2012-01, "Design Vulnerability In Electric Power System" Northern States Power Company, a Minnesota corporation, doing business as Xcel Energy (hereafter "NSPM"), submits the response to the RAI for Prairie Island Nuclear Generating Plant (PINGP) Units 1 and 2. The response to the Nuclear Regulatory Commission (NRC), as requested by letter dated December 20, 2013 (Agencywide Documents Access and Management System Accession No. ML13351A314), Request for Additional Information Regarding Respqn~e to Bulletin 2012-01, "Design Vulnerability in Electric Power System," is attached in the enclosure.

If there are any questions, or if additional information is needed, please contact Mr. Frank Sienczak, at 651-267-1740.

Summary of Commitments This letter contains no new commitments and no revisions to existing commitments.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on February 3, 2014 p~~

Scott M. Sharp Director, Site Operations, Prairie Island Nuclear Generating Plant Northern States Power Company - Minnesota 1717 Wakonade Drive East

  • Welch, Minnesota 55089-9642 Telephone: 651.388.1121

Document Control Desk Page2 Enclosure (1) cc: Administrator, Region Ill, USNRC Project Manager, PINGP, USNRC Resident Inspector, PINGP, USNRC Document Control Desk NSPM ENCLOSURE 1 Response to Request for Additional Information for Bulletin 2012-01 "Design Vulnerability in Electric Power System" for the Prairie Island Nuclear Generating Plant (PINGP)

Background Information

  • On January 30, 2012, Byron Station Unit 2 automatically scrammed from 100%

power on reactor coolant pump bus undervoltage. The cause was determined to be a loss of C-phase voltage to both unit system auxiliary transformers due to a failed insulator in the 345-kV switchyard resulting in a voltage imbalance on the Engineered Safety Feature buses prior to the Scram. After the unit scrammed, the engineered safety feature buses were subjected to the phase imbalance.

The phase imbalance was identified by the main control room operators, and the feed breakers were opened, resulting in an automatic start of the associated emergency diesels. This incident identified a design vulnerability in the Byron Station undervoltage and degraded voltage logic. The protection scheme was not designed to identify a loss of phase of either A or C phase from the offsite grid to the System Auxiliary Transformers.

  • On February 9, 2012, CAP 01324369 identified Prairie Island Nuclear Generating Plant has the same design vulnerability identified at the Byron Station Unit 2.

OPR 01324369 determined the condition to be Operable But Nonconforming.

Normal electrical alignment at Prairie Island has one safety bus powered from the RY source and one safety bus powered from the CT source. If one of these sources were to experience an open phase condition, the redundant train would not be impacted by the condition; therefore it can be concluded that the condition would not result in the loss of safety function.

Off-normal electrical alignments could place both safety buses on the same source. In this configuration, both safety buses could be impacted by an open phase condition.

1M, 2M, 2RX, 2RY, CT11, and CT12 Transformers are Delta-WYE configuration.

1GT, 2GT, 2RS, and CT1, Transformers are WYE-Delta configuration. 1R Transformer is a WYE-WYE with an unused Delta Tertiary configuration, and 10 Bank Transformer is a WYE-Delta with a Delta Tertiary feeding CT12. The voltage and current response differs for each transformer configuration. To determine the voltage and current response, "A Practical Guide for Detecting Single-Phasing on a Three-Phase Power System" by Basler Electric Company was reviewed.

Page 1 of 5 Document Control Desk NSPM For Delta-WYE: If a phase of the Plant incoming power were to open, an unbalanced voltage condition would occur. The voltage would not be 0 (zero).

The exact voltage would require a study to analyze Prairie Island's configuration.

The voltages on all three phases would not be normal.

For WYE-Delta: If a phase of the Plant incoming power were to open, the lost phase is re-created, and the voltages on all three phases would be normal.

However, 8 phase cannot carry current, which causes A and C phases to carry more current. 8 phase current would be 0 (zero), and A and C phases would be greater than normal.

All of the transformers that are directly upstream of Prairie Island 4kV buses (1M, 2M, 1R, 2RX, 2RY, CT11, and CT12) are Delta-WYE fed by WYE-Delta transformers. If the open phase were to occur in the switchyard (upstream of these transformers), these transformers would see normal voltages and 0 (zero) current.

Transformers 1M, 2M, 1R, 2RX, 2RY, CT11, and CT12 have all three phase currents monitored. These indications are available in the Control Room via current meters. 1M current is monitored by meters 41193~01, 02, and 03. 2M current is monitored by meters 41728-01, 02, 03. 1RX current is monitored by meters 41192-01, 02, and 03. 1RY current is monitored by meters 41920-02, 03 and 04. 2RX current is monitored by meters 41729-10, 11, and 12. 2RY current is monitored by meters 41901-02, 03 and 04. CT12 current is monitored by meters 41908-02, 03, and 04. CT11 current is monitored by meters 41900-02, 03 and 04. There is no audible or visual alarm to alert the operator to an open phase condition. Values displayed by ERGS would not provide the operator with indication that a phase has opened.

A review of the current basis for the degraded voltage scheme does not indicate that it was designed to detect and separate the safety bus from a source that has experienced an open phase condition. Based on the design, if an open phase were to occur on the 8 phase, both potential transformers would lose power, and the voltage restoration function of the load sequencer would occur. However, if an open phase were to occur on the A or C phase, automatic load sequencing would not occur until the bus feeder breaker is manually opened.

  • OPR 01324369 implemented compensatory measures and a defense in depth strategy. While both ESF 4.16kV buses for either unit are placed on the same station auxiliary transformer, a designated operator will be required to monitor G panel indications and the Sequencer Channel Alert Alarms to identify a single loss of phase which would result in both ESF buses not being able to perform their ESF functions. (See below and CAP 01324369 for more detail.)

Page 2 of 5 Document Control Desk NSPM Response 1 - Summary of All Interim Corrective Actions Lessons learned from the events at Byron station were reviewed and various interim corrective actions evaluated for safety and efficiency at the Prairie Island Nuclear Generating Plant. Based on the plant's offsite power configuration, electrical design details, and on lessons learned, the actions listed below were taken to ensure plant operators can promptly diagnose and respond to open phase conditions (OPC). These changes were implemented to provide compensatory actions until the non-conforming condition can be corrected.

  • PINGP operating procedures were reviewed and revised to ensure operators can diagnose and respond to an OPC when both safety-related trains of power are on the same offsite source.
  • Alarm response procedures were revised to provide compensatory action if a sequencer voltage alarm is received.
  • As a compensatory measure and defense in depth strategy, a designated Operator will be required during times when both safeguards buses for PINGP Unit 1 or Unit 2 are placed on the same transformer.

PINGP operating procedures were reviewed and revised to ensure operators can diagnose and respond to an OPC when both safety-related trains of power are on the same offsite source.

  • Procedure C20.3, "ELECTRICAL POWER SYSTEM SECURITY ANALYSIS,"

had Precautions 3.1 & 3.2 added as follows:

o 3.1 When placing both trains of Safeguards 4.16KV Buses on the same Station Auxiliary Transformer, a loss of Singe Phase Power results in a loss of 4KV Safety Function. Time in this configuration MUST be minimized.

o 3.2 IF both trains of Safeguards 4.16KV Buses are powered from the same Station Auxiliary Transformer (i.e., sequencer repowered a bus from the same source), THEN enter TS 3.8.1 Condition A for a path to the grid inoperable for Modes 1, 2, 3, and 4. (Ref PCR 01330456).

  • Procedures 1C20.5, "Unit 1 - 4.16KV System" and 2C20.5, "Unit 2 - 4.16KV System", modified sections 5.15, 5.16, 5.17 & 5.18 to allow placing both buses on the same station auxiliary transformer in modes 1 thru 6 if a designated operator is stationed at the G Panel to recognize the casualty and provide defense in depth upon receipt of Bus 15, 16, 25, and 26 Sequencer Channel Alert alarm. Additionally, OPR 1324369-01 was added as a reference to section 7.1.

o For 1C20.5, Precaution 3.2 "When placing both trains of Safeguards 4.16KV Buses on the same Station Auxiliary Transformer, a loss of Single Phase Power results in a loss of 4KV Safety Function."

o For 2C20.5, Precaution 3.3 "When placing both trains of Safeguards 4.16KV Buses on the same Station Auxiliary Transformer, a loss of Single Phase Power results in a loss of 4KV Safety Function."

Page 3 of 5 Document Control Desk NSPM PINGP alarm response procedures were revised to provide compensatory action if a sequencer under voltage alarms PCR 01332478 & PCR 01332482

  • C47024 and C47524 Alarm Response Procedures were revised so that if a 4.16KV Safeguards Bus Load Sequencer Channel Alert alarms the response includes checking currents on the associated bus and putting the existing source breaker to open and placing switch in pullout position if the currents are not normal and balanced. (Ref. PCR 01332478 & PCR 01332482)

As a compensatory measure and defense in depth strategy, a designated PINGP Operator will be required during times when both safeguards buses are placed on the same SAT,

  • As a compensatory measure and defense in depth strategy, a designated Operator will be required during times when both safeguards buses are placed on the same SAT, (exception: when TS 3.9.5 applies). The designated operator will be at the appropriate G Panel to trip the bus' source breaker as directed by the applicable ARP. The considerations below provide assurance the designated Operator will perform their actions in an expeditious manner, minimizing the time the safeguards equipment are subject to the abnormal voltages and currents.

(Ref OPR 1324369-01) o An Operator, in addition to the Duty Crew, will be stationed to perform these actions.

o The operator will be directed to monitor for a single open phase using G Panel indications and the BUS (15, 16, 25, or 26) Sequencer Channel Alert alarm.

o The action that is required to be taken will be performed in the Control Room. Therefore, there are no concerns with respect to the environment in which this action would be taken. In the event of a LOOP/LOCA would occur the Control Room would be at normal temperature.

o Since the Operator will be stationed at the G Panel within the Control Room, ingress/egress will not be an issue as this is a low dose-low temperature area during the time when their actions would be required for applicable accidents.

o A designated Operator will be assigned to this activity. The Operator will receive a pre-job briefing of the activity and will remain at the G Panel area at all times. The individual will not be assigned other activities within the Control Room. The Control Room Supervisor must ensure that activities within area surrounding the G Panel do not interfere with the designated Operator's response.

o This is an analyzed condition that will result in entry into existing plant procedures that will be able to place the plant in a safe condition with no additional requirements.

Page 4 of 5 Document Control Desk NSPM o Procedure changes have been put in place to accomplish the Operator's actions [which are]: upon receipt of the BUS (15, 16, 25, or 26) Sequencer Channel Alert alarm open the bus source breaker and place in pullout, as necessary.

Response 2 - Status and Schedule for Completion of Plant Design Changes

  • Status o All holders of operating licenses and combined licenses for nuclear power reactors are investigating options being researched by several vendors (PSC2000, EPRI, Schweitzer, etc.) to detect OPC faults. There is currently no generic, off-the-shelf technology that has been proven to detect all the required open phase fault conditions for all plant and transformer designs.

o All holders of operating licenses and combined licenses for nuclear power reactors are fully engaged in the development of the NEI OPC Guidance Document, as well as development of enhancements to software tools being used to analyze OPC faults.

o With the goal of ensuring accurate detection without compromising nuclear safety or increasing plant risk, this new OPC technology is being thoroughly evaluated, will be tested, and will be fully analyzed before installation.

o Vulnerability studies of the OPC faults have been started for Prairie Island Nuclear Generating Plant.

  • Schedule o The Prairie Island Nuclear Generating Plant have committed to the generic schedule provided in the Industry OPC Initiative.

o It is our intention to meet the milestones of this schedule; however, deviations may be required to accommodate outage schedules, software and hardware availability, manufacturer's delivery capabilities, licensing delays, etc.

o Any deviation from the Industry OPC Initiative schedule will be documented through the deviation/exemption process addressed in the NEI OPC Guidance Document.

Page 5 of 5

Text

Xcel Energy@

February 3, 2014 L-PI-14-01 0 10 CFR 50.54(f)

U S Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Units 1 and 2 Dockets 50-282 and 50-306 Renewed License Nos. DPR-42 and DPR-60 Response to Request For Additional Information (RAI) Regarding Response To Bulletin 2012-01, "Design Vulnerability In Electric Power System" Northern States Power Company, a Minnesota corporation, doing business as Xcel Energy (hereafter "NSPM"), submits the response to the RAI for Prairie Island Nuclear Generating Plant (PINGP) Units 1 and 2. The response to the Nuclear Regulatory Commission (NRC), as requested by letter dated December 20, 2013 (Agencywide Documents Access and Management System Accession No. ML13351A314), Request for Additional Information Regarding Respqn~e to Bulletin 2012-01, "Design Vulnerability in Electric Power System," is attached in the enclosure.

If there are any questions, or if additional information is needed, please contact Mr. Frank Sienczak, at 651-267-1740.

Summary of Commitments This letter contains no new commitments and no revisions to existing commitments.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on February 3, 2014 p~~

Scott M. Sharp Director, Site Operations, Prairie Island Nuclear Generating Plant Northern States Power Company - Minnesota 1717 Wakonade Drive East

  • Welch, Minnesota 55089-9642 Telephone: 651.388.1121

Document Control Desk Page2 Enclosure (1) cc: Administrator, Region Ill, USNRC Project Manager, PINGP, USNRC Resident Inspector, PINGP, USNRC Document Control Desk NSPM ENCLOSURE 1 Response to Request for Additional Information for Bulletin 2012-01 "Design Vulnerability in Electric Power System" for the Prairie Island Nuclear Generating Plant (PINGP)

Background Information

  • On January 30, 2012, Byron Station Unit 2 automatically scrammed from 100%

power on reactor coolant pump bus undervoltage. The cause was determined to be a loss of C-phase voltage to both unit system auxiliary transformers due to a failed insulator in the 345-kV switchyard resulting in a voltage imbalance on the Engineered Safety Feature buses prior to the Scram. After the unit scrammed, the engineered safety feature buses were subjected to the phase imbalance.

The phase imbalance was identified by the main control room operators, and the feed breakers were opened, resulting in an automatic start of the associated emergency diesels. This incident identified a design vulnerability in the Byron Station undervoltage and degraded voltage logic. The protection scheme was not designed to identify a loss of phase of either A or C phase from the offsite grid to the System Auxiliary Transformers.

  • On February 9, 2012, CAP 01324369 identified Prairie Island Nuclear Generating Plant has the same design vulnerability identified at the Byron Station Unit 2.

OPR 01324369 determined the condition to be Operable But Nonconforming.

Normal electrical alignment at Prairie Island has one safety bus powered from the RY source and one safety bus powered from the CT source. If one of these sources were to experience an open phase condition, the redundant train would not be impacted by the condition; therefore it can be concluded that the condition would not result in the loss of safety function.

Off-normal electrical alignments could place both safety buses on the same source. In this configuration, both safety buses could be impacted by an open phase condition.

1M, 2M, 2RX, 2RY, CT11, and CT12 Transformers are Delta-WYE configuration.

1GT, 2GT, 2RS, and CT1, Transformers are WYE-Delta configuration. 1R Transformer is a WYE-WYE with an unused Delta Tertiary configuration, and 10 Bank Transformer is a WYE-Delta with a Delta Tertiary feeding CT12. The voltage and current response differs for each transformer configuration. To determine the voltage and current response, "A Practical Guide for Detecting Single-Phasing on a Three-Phase Power System" by Basler Electric Company was reviewed.

Page 1 of 5 Document Control Desk NSPM For Delta-WYE: If a phase of the Plant incoming power were to open, an unbalanced voltage condition would occur. The voltage would not be 0 (zero).

The exact voltage would require a study to analyze Prairie Island's configuration.

The voltages on all three phases would not be normal.

For WYE-Delta: If a phase of the Plant incoming power were to open, the lost phase is re-created, and the voltages on all three phases would be normal.

However, 8 phase cannot carry current, which causes A and C phases to carry more current. 8 phase current would be 0 (zero), and A and C phases would be greater than normal.

All of the transformers that are directly upstream of Prairie Island 4kV buses (1M, 2M, 1R, 2RX, 2RY, CT11, and CT12) are Delta-WYE fed by WYE-Delta transformers. If the open phase were to occur in the switchyard (upstream of these transformers), these transformers would see normal voltages and 0 (zero) current.

Transformers 1M, 2M, 1R, 2RX, 2RY, CT11, and CT12 have all three phase currents monitored. These indications are available in the Control Room via current meters. 1M current is monitored by meters 41193~01, 02, and 03. 2M current is monitored by meters 41728-01, 02, 03. 1RX current is monitored by meters 41192-01, 02, and 03. 1RY current is monitored by meters 41920-02, 03 and 04. 2RX current is monitored by meters 41729-10, 11, and 12. 2RY current is monitored by meters 41901-02, 03 and 04. CT12 current is monitored by meters 41908-02, 03, and 04. CT11 current is monitored by meters 41900-02, 03 and 04. There is no audible or visual alarm to alert the operator to an open phase condition. Values displayed by ERGS would not provide the operator with indication that a phase has opened.

A review of the current basis for the degraded voltage scheme does not indicate that it was designed to detect and separate the safety bus from a source that has experienced an open phase condition. Based on the design, if an open phase were to occur on the 8 phase, both potential transformers would lose power, and the voltage restoration function of the load sequencer would occur. However, if an open phase were to occur on the A or C phase, automatic load sequencing would not occur until the bus feeder breaker is manually opened.

  • OPR 01324369 implemented compensatory measures and a defense in depth strategy. While both ESF 4.16kV buses for either unit are placed on the same station auxiliary transformer, a designated operator will be required to monitor G panel indications and the Sequencer Channel Alert Alarms to identify a single loss of phase which would result in both ESF buses not being able to perform their ESF functions. (See below and CAP 01324369 for more detail.)

Page 2 of 5 Document Control Desk NSPM Response 1 - Summary of All Interim Corrective Actions Lessons learned from the events at Byron station were reviewed and various interim corrective actions evaluated for safety and efficiency at the Prairie Island Nuclear Generating Plant. Based on the plant's offsite power configuration, electrical design details, and on lessons learned, the actions listed below were taken to ensure plant operators can promptly diagnose and respond to open phase conditions (OPC). These changes were implemented to provide compensatory actions until the non-conforming condition can be corrected.

  • PINGP operating procedures were reviewed and revised to ensure operators can diagnose and respond to an OPC when both safety-related trains of power are on the same offsite source.
  • Alarm response procedures were revised to provide compensatory action if a sequencer voltage alarm is received.
  • As a compensatory measure and defense in depth strategy, a designated Operator will be required during times when both safeguards buses for PINGP Unit 1 or Unit 2 are placed on the same transformer.

PINGP operating procedures were reviewed and revised to ensure operators can diagnose and respond to an OPC when both safety-related trains of power are on the same offsite source.

  • Procedure C20.3, "ELECTRICAL POWER SYSTEM SECURITY ANALYSIS,"

had Precautions 3.1 & 3.2 added as follows:

o 3.1 When placing both trains of Safeguards 4.16KV Buses on the same Station Auxiliary Transformer, a loss of Singe Phase Power results in a loss of 4KV Safety Function. Time in this configuration MUST be minimized.

o 3.2 IF both trains of Safeguards 4.16KV Buses are powered from the same Station Auxiliary Transformer (i.e., sequencer repowered a bus from the same source), THEN enter TS 3.8.1 Condition A for a path to the grid inoperable for Modes 1, 2, 3, and 4. (Ref PCR 01330456).

  • Procedures 1C20.5, "Unit 1 - 4.16KV System" and 2C20.5, "Unit 2 - 4.16KV System", modified sections 5.15, 5.16, 5.17 & 5.18 to allow placing both buses on the same station auxiliary transformer in modes 1 thru 6 if a designated operator is stationed at the G Panel to recognize the casualty and provide defense in depth upon receipt of Bus 15, 16, 25, and 26 Sequencer Channel Alert alarm. Additionally, OPR 1324369-01 was added as a reference to section 7.1.

o For 1C20.5, Precaution 3.2 "When placing both trains of Safeguards 4.16KV Buses on the same Station Auxiliary Transformer, a loss of Single Phase Power results in a loss of 4KV Safety Function."

o For 2C20.5, Precaution 3.3 "When placing both trains of Safeguards 4.16KV Buses on the same Station Auxiliary Transformer, a loss of Single Phase Power results in a loss of 4KV Safety Function."

Page 3 of 5 Document Control Desk NSPM PINGP alarm response procedures were revised to provide compensatory action if a sequencer under voltage alarms PCR 01332478 & PCR 01332482

  • C47024 and C47524 Alarm Response Procedures were revised so that if a 4.16KV Safeguards Bus Load Sequencer Channel Alert alarms the response includes checking currents on the associated bus and putting the existing source breaker to open and placing switch in pullout position if the currents are not normal and balanced. (Ref. PCR 01332478 & PCR 01332482)

As a compensatory measure and defense in depth strategy, a designated PINGP Operator will be required during times when both safeguards buses are placed on the same SAT,

  • As a compensatory measure and defense in depth strategy, a designated Operator will be required during times when both safeguards buses are placed on the same SAT, (exception: when TS 3.9.5 applies). The designated operator will be at the appropriate G Panel to trip the bus' source breaker as directed by the applicable ARP. The considerations below provide assurance the designated Operator will perform their actions in an expeditious manner, minimizing the time the safeguards equipment are subject to the abnormal voltages and currents.

(Ref OPR 1324369-01) o An Operator, in addition to the Duty Crew, will be stationed to perform these actions.

o The operator will be directed to monitor for a single open phase using G Panel indications and the BUS (15, 16, 25, or 26) Sequencer Channel Alert alarm.

o The action that is required to be taken will be performed in the Control Room. Therefore, there are no concerns with respect to the environment in which this action would be taken. In the event of a LOOP/LOCA would occur the Control Room would be at normal temperature.

o Since the Operator will be stationed at the G Panel within the Control Room, ingress/egress will not be an issue as this is a low dose-low temperature area during the time when their actions would be required for applicable accidents.

o A designated Operator will be assigned to this activity. The Operator will receive a pre-job briefing of the activity and will remain at the G Panel area at all times. The individual will not be assigned other activities within the Control Room. The Control Room Supervisor must ensure that activities within area surrounding the G Panel do not interfere with the designated Operator's response.

o This is an analyzed condition that will result in entry into existing plant procedures that will be able to place the plant in a safe condition with no additional requirements.

Page 4 of 5 Document Control Desk NSPM o Procedure changes have been put in place to accomplish the Operator's actions [which are]: upon receipt of the BUS (15, 16, 25, or 26) Sequencer Channel Alert alarm open the bus source breaker and place in pullout, as necessary.

Response 2 - Status and Schedule for Completion of Plant Design Changes

  • Status o All holders of operating licenses and combined licenses for nuclear power reactors are investigating options being researched by several vendors (PSC2000, EPRI, Schweitzer, etc.) to detect OPC faults. There is currently no generic, off-the-shelf technology that has been proven to detect all the required open phase fault conditions for all plant and transformer designs.

o All holders of operating licenses and combined licenses for nuclear power reactors are fully engaged in the development of the NEI OPC Guidance Document, as well as development of enhancements to software tools being used to analyze OPC faults.

o With the goal of ensuring accurate detection without compromising nuclear safety or increasing plant risk, this new OPC technology is being thoroughly evaluated, will be tested, and will be fully analyzed before installation.

o Vulnerability studies of the OPC faults have been started for Prairie Island Nuclear Generating Plant.

  • Schedule o The Prairie Island Nuclear Generating Plant have committed to the generic schedule provided in the Industry OPC Initiative.

o It is our intention to meet the milestones of this schedule; however, deviations may be required to accommodate outage schedules, software and hardware availability, manufacturer's delivery capabilities, licensing delays, etc.

o Any deviation from the Industry OPC Initiative schedule will be documented through the deviation/exemption process addressed in the NEI OPC Guidance Document.

Page 5 of 5

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