ML14153A562

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Response to Request for Additional Information Regarding Enhancements to Diesel Generator License Amendment Request
ML14153A562
Person / Time
Site: Calvert Cliffs  Constellation icon.png
Issue date: 05/30/2014
From: George Gellrich
Exelon Generation Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML14153A562 (44)
v • d • e


Text

A ExeLon Generation George Gellrich Site Vice President Calvert Cliffs Nuclear Power Plant 1650 Calvert Cliffs Parkway Lusby. MD 20657 410 495 5200 Office 717 497 3463 Mobile www.exeloncorp.com george.gellrich@exeloncorp.com May 30, 2014 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 Renewed Facility Operating License Nos. DPR-53 and DPR-69 NRC Docket Nos. 50-317 and 50-318

Subject:

Response to Request for Additional Information Regarding Enhancements to Diesel Generator License Amendment Request

References:

1. Letter from Mr. G. H. Gellrich (CCNPP) to Document Control Desk (NRC),

dated October 16, 2012, License Amendment Request re: Enhancements to Diesel Generator Surveillance Requirements

2. Letter from Ms. N. S. Morgan (NRC) to Mr. G. H. Gellrich (CCNPP), dated April 15, 2014, Request for Additional Information Regarding Enhancements to Diesel Generator Surveillance Requirements License Amendment (TAC No. ME9832 and ME9833)

In Reference 1, Calvert Cliffs Nuclear Power Plant, LLC submitted a license amendment request to revise Surveillance Requirements 3.8.1.8, 3.8.1.11, and 3.8.2.1, and add Surveillance Requirement 3.8.1.17 to Technical Specification 3.8.1, "AC Sources-Operating." In Reference 2, the Nuclear Regulatory Commission requested additional information to support their review of Reference (1). Attachment (1) and Enclosures provide the responses to the Nuclear Regulatory Commission's request for additional information contained in Reference 2.

These responses do not change the No Significant Hazards Determination provided in Reference 1. No regulatory commitments are contained in this letter.

Document Control Desk May 30, 2014 Page 2 Should you have questions regarding this matter, please contact Mr. Douglas E. Lauver, Director-Licensing, at (410) 495-5219.

I declare under penalty of perjury that the foregoing is true and correct. Executed on May 30, 2014.

Respectfully, George H. Gellrich Site Vice President Exelon Generation Company, LLC GHG/PSF/bjd

Attachment:

(1) Response to Request for Additional Information Regarding Enhancements to Diesel Generator License Amendment Request

Enclosures:

1 Marked Up Technical Specification and Technical Specification Bases Pages 2 OCP-N-10, Division of Responsibilities For NERC Standard NUC-001 3 OCP-N-2, Notifications Requirements cc: CCNPP Project Manager, NRC CCNPP Resident Inspector, NRC Region 1 Administrator, NRC S. Gray, DNR

ATTACHMENT (1)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING ENHANCEMENTS TO DIESEL GENERATOR LICENSE AMENDMENT REQUEST Calvert Cliffs Nuclear Power Plant May 30, 2014

ATTACHMENT (1)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING ENHANCEMENTS TO DIESEL GENERATOR LICENSE AMENDMENT REQUEST

RAI 1

The response to RAI #2 stated that over the last five years, two failures were identified where the sequencers did not perform according to the design requirements. The Calvert Cliffs Updated Final Safety Analyses Report Section 8.4 states that each of the four emergency diesel generators (EDG) has a loss of coolant incident (LOCI) sequencer and a shutdown sequencer.

The LOCI sequencer provides the timing for loading the EDG following a safety bus undervoltage in combination with a safety injection actuation signal (SIAS). The shutdown sequencer provides the timing for loading the EDG following a safety bus undervoltage without SIAS. Please confirm that each of the two sequencer circuits was tested on a 31-day frequency in accordance with guidance provided in Generic Letter 96-01 "Testing of safety related Logic Circuits."

CCNPP Response 1:

The LOCI sequencers are tested every 31 days as required by Technical Specification Surveillance Requirement (SR) 3.8.1.8. However, the shutdown sequencer was not tested periodically until mid-2012. As noted in Nuclear Regulatory Commission (NRC) Inspection Report 05000317/2012003 and 05000318/2012003, Calvert Cliffs received a green non-cited violation for this lack of testing. We began testing the shutdown sequencer every six months as a compensatory action and submitted this license amendment request to make the Technical Specification surveillance more specific concerning the sequencer test.

RAI 2

RAI #5 related to performing the 2-hour test after the 22-hour test as part of Surveillance Requirement (SR) 3.8.11, in its response, the licensee stated that a higher test load at the end of an endurance run can more closely model the bus loading that could be experienced during an event. The response to RAI #4 tabulates the loading on the EDGs during large break loss of coolant accident (LBLOCA) and also during a LOOP event. The NRC staff notes that the highest loading on EDGs 1A and 2B for LBLOCA and LOOP events occurs within 10-75 minutes and for EDGs 1B and 2A after 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> during shutdown cooling. The intent of this SR is to partly demonstrate the capability of the EDG to supply safe shutdown loads during the initial conditions of a design basis event, when the pumps may be operating under run-out conditions and the EDG has to operate in overload range, and during extended steady state conditions for mitigating the consequences of a design basis accident.

In view of the above observations:

a) Explain how performing the 2-hour overload test at the end of a 22-hour operation more closely models the bus loading that could be experienced during the worst case loading conditions.

b) Confirm that the tabulated loading is considered with the EDG operating at the highest allowable frequency as verified by the Technical Specification, such as SR 3.8.1.9 and the limiting bus voltage.

CCNPP Response 2:

Calvert Cliffs agrees to perform testing as shown in the Improved Standard Technical Specifications. The revised marked-up page is attached.

1

ATTACHMENT (1)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING ENHANCEMENTS TO DIESEL GENERATOR LICENSE AMENDMENT REQUEST

RAI 3

The response to RAI #3 provides an explanation as to why Calvert Cliffs does not want to test the power factor (PF)capability of the EDGs. The response indicates that the reasonsinclude:

1. Depending on the 4 kV bus voltage at the time of the test, the DG voltage regulator range may not be sufficient to achieve the requiredpower factor.
2. With the 13.8 kV voltage regulatorin manual, the 4 kV bus and associated electrical distribution system can be adversely affected by changes in grid voltages.
3. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance test is performed when the unit is operating. The associated 4 kV bus remains operable during the test and the impact to the stability of the operable 4 kV bus is increasedwhen the voltage regulatoris in the manual mode.

The NRC staff considers PF testing an important parameter to validate the capability of the exciter and the generatorsystems to generate reactive power and carry the required current (accident condition) for an extended duration. The NRC staff recognizes that in some cases, the grid voltage conditions may not permit EDG operation at the required PF for the total 24-hour period.

Please confirm the following:

a) Prior to EDG testing, Calvert Cliffs personnel verify grid conditions to ensure that there are no planned outages or grid contingenciesthat can result in degraded grid conditions.

b) Grid operators provide adequate warning of contingency analyses that indicate that the post trip bus voltage for both units may not be adequate for plant shutdown.

c) During light load stable conditions, the transmission system in the vicinity of the plant maintains a stable voltage.

d) EDG testing is not performed during peak grid loading conditions.

e) The PF testing can be performed with the 13.8kV voltage regulatorin manual mode for a few hours (i.e. less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) and can be relatively risk insignificant or very minor increase in risk with appropriateprecautionarymeasures.

CCNPP Response 3:

3a - Calvert Cliffs has procedures in place to manage risks. Included in Calvert Cliffs' risk management is awareness of grid conditions. Examples are given below. These actions apply when the diesel generator (DG) is tested. Also, the grid operator is contacted prior to paralleling diesel generators, so the grid operator is aware of impending DG paralleling.

CNG-OP-4.01-1000, Integrated Risk Management procedure:

Step 4.17.M:

Mitigates nuclear risk by evaluating the next day's grid demand and ensuring proper permissions are granted, contingencies are in place, and Risk Activities are evaluated for implementation during high grid stress conditions.

2

ATTACHMENT (1)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING ENHANCEMENTS TO DIESEL GENERATOR LICENSE AMENDMENT REQUEST Step 5.6.C

1. Once the Work Week manager (WWM) has determined that a high or emergency grid demand exists, the following day's schedule shall be re-evaluated.
a. The WWM shall recommend to the Operations Shift Manager whether work should be rescheduled. Consideration of rescheduling work must be weighed against the safety benefit of completing work.
c. Operations and the WWM should independently set all configuration flags/environmental variables which are required to accurately reflect the status of the plant -and any external factors which may impact risk (for example, grid instability, severe weather, declared Maximum Emergency Generation (MEG) or High LMP).

Additionally, per CNG-MN-4.01-1006, Online Schedule Management, Step 5.5.D. PJM Monitoring, the Work Week Managers use http://www.pjm.com/ to monitor for high Location Based Marginal Pricing (LMP). If additional system constraints or risks are projected by CCG, Generation Dispatch should communicate emerging grid system concerns that may not be represented in the day-ahead LMP directly to the affected stations (such as unexpected weather, forced outages, or high risk work occurring at other stations within the CGG fleet).

Finally, PJM declared Maximum Emergency Generation Alert or higher will be used to evaluate grid demand condition. Since the PJM declarations are made directly to the Control Room, the Shift Manager is responsible for communicating this information to the WWMs.

The Equipment Out Of Service (EOOS) Monitor is used to determine the plant risk. Included in this system are inputs for grid condition. The Maintenance Rule Risk Assessment Guidelines (MRRAG) provides direction for inputting information in the EOOS. Included in the MRRAG is direction for major grid disturbances. The integrated risk management process provides direction to determine if a combination of individual activities causes a yellow PRA risk, and then evaluate reasonable schedule changes to attempt to prevent a yellow PRA risk.

Therefore, Calvert Cliffs monitors grid conditions for impact on plant operations, including DG testing, and reschedules work based on risk. If the risk assessment for plant conditions, including grid conditions, indicates a yellow condition, then rescheduling of activities is evaluated.

3b - Grid operators provide adequate warning to Calvert Cliffs for grid conditions. See attached files for the Nuclear Operating Committee Administrative Procedure OCP-N-10, Division of Responsibilities for NERC Standard NUC-001 and OCP-N-2, Notifications Requirements.

The purpose of OCP-N-2 is to provide the guidelines for the interface between Calvert Cliffs and Baltimore Gas and Electric Company (BGE) to provide direction for ensuring that notification requirements are properly completed in accordance with the ISA and INPO's SOER 99-01.

Included in the scope of OCP-N-2 is the establishment of communications and information transfer protocol. These include, but are not limited to the following:

  • Notification of work requirements in or around the other company's facility
  • Notification of emergency conditions
  • Notification of system restoration capability

" Notification of deficiencies 3

ATTACHMENT (1)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING ENHANCEMENTS TO DIESEL GENERATOR LICENSE AMENDMENT REQUEST Also included in the notification requirements process is notification of an emergency condition requiring immediate action to preserve public safety, to limit or prevent damage to equipment or to expedite restoration of service. In accordance with the BGE operations manuals, BGE provides prompt verbal notification to the Calvert Cliffs control room of any local (BGE) emergency that causes Calvert Cliffs to increase/decreases generation, or will cause a loss of offsite power availability to Calvert Cliffs.

See also PJM Manual 3, Transmission Operations, particularly Section 3.4, for PJM system operation (PJM.com).

3c - The grid operators maintain a stable voltage in the vicinity of Calvert Cliffs even during light load conditions. In addition, Calvert Cliffs has voltage regulators which further control the voltage at the 4 kV level.

The grid associated with Calvert Cliffs is operated in accordance with North American Electric Reliability Corporation (NERC) Standard VAR-002-2b, Generator Operation for Maintaining Network Voltage Schedules (see web page www.NERC.com). The purpose of this guidance is to ensure generators provide reactive and voltage control necessary to ensure voltage levels, reactive flows, and reactive resources are maintained within applicable Facility Ratings to protect equipment and the reliable operation of the Interconnection.

3d - Emergency Diesel Generator testing can be performed during peak grid conditions. As indicated above, the EOOS Monitor is used to determine the plant risk. If the risk is determined to be acceptable, EDG testing may be performed even during peak grid conditions.

Grid conditions are monitored and considered for plant evolutions, including DG testing as described above.

3e - Calvert Cliffs rarely places the 13.8 kV voltage regulators in manual with the associated Unit in Mode 1. Placing the 13.8 kV voltage regulator in manual is required when performing some electrical switching, which is rarely performed.

Calvert Cliffs does not currently place the 13.8 kV voltage regulator in manual to perform any DG testing with the associated Unit at power. Due to the potential consequences (see Response to RAI 4), Calvert Cliffs does not consider it acceptable to place the 13.8 kV voltage regulators in manual when the associated Unit is in Mode 1 for DG testing due to degraded grid voltage concerns and the impact to the safety-related 4 kV bus operability.

RAI 4

On page 3 of Attachment I of its October 16, 2012, letter, the licensee stated that placing the voltage regulators in the manual mode of operation puts equipment at a greaterrisk for being impacted by degraded grid voltage during the surveillance test, and that the probability for this increases for the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test period. Please provide corroborating data to support these statements.

CCNPP Response 4:

With the 13.8 kV voltage regulators in manual, the electrical equipment associated with that voltage regulator are subjected to voltage changes on the grid (degraded voltage scenario).

4

ATTACHMENT (1)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING ENHANCEMENTS TO DIESEL GENERATOR LICENSE AMENDMENT REQUEST The safety-related 4 kV busses are not protected from grid voltage changes which could initiate UV logic, separating safety-related busses from the grid and starting the EDGs. The non-safety-related busses are not protected from grid voltage changes and equipment reliability (effects of increased current, effects of decreased voltage) could be affected resulting in plant trips.

With the 13.8 kV voltage regulators in manual, there is some risk that grid voltage changes could impact both safety-related and non-safety-related equipment. Since these occurrences are not controlled, the longer the plant is in this condition, the higher the probability the event could occur.

The purpose of Calvert Cliffs calculation CA01206, Safety Related 4 kV Undervoltage Protection, is to determine the undervoltage protective relay settings for the steady state undervoltage element (SUR), transient undervoltage element (TUR) and loss of voltage element (LOV) for the safety-related buses.

Included in CA01 206, the SUR undervoltage level of protection is designed to monitor the 4 kV bus voltages during steady-state voltage conditions, while the TUR level monitors for transient voltage dips at the 4 kV safety buses. The LOV level of undervoltage protection is set to detect a total loss of bus voltage.

SUR Setting Philosophy The SUR undervoltage relay will be set to ensure the terminal voltage of all safety-related loads will not drop below their minimum operating voltage of 90% of nominal voltage during steady-state conditions such that permanently connected class 1E load will not be damaged. This relay will have an external time delay set to allow the 13.8 kV voltage regulators to change tap position and correct voltage deviations, override motor starts, and to allow the EDG voltage regulator to stabilize.

If the voltage regulator is in manual, the setting philosophy for the SUR undervoltage relay is compromised.

For these reasons, Calvert Cliffs does not consider placing the 13.8 kV voltage regulator in manual with the associated Unit in Mode 1 to be an acceptable risk for EDG testing.

5

ENCLOSURE I MARKED UP TECHNICAL SPECIFICATION AND TECHNICAL SPECIFICATION BASES PAGES Calvert Cliffs Nuclear Power Plant May 30, 2014

Insert I Verify each DG operates for > 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s:

a. For > 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded to > 4200 kW for DG 1A, and > 3150 kW and < 3300 kW for DGs 1B, 2A, and 2B, and
b. For the remaining hours of the test loaded to > 3600 kW for DG 1A, and > 2700 kW and

< 3000 kW for DGs 1B, 2A and 2B.

Insert 2 Reference 12 requires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, > 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of which is at a load equivalent to 105-110% of the continuous service rating and the remainder of the time at a load equivalent to 90-100% of the continuous service rating. For the Nos. 1B, 2A, and 2B DGs the SR reflects these loading ranges. For the No. 1A DG, since the post accident loading is significantly less than the continuous service rating, the post accident loading (<4000 kW) is used instead of the continuous service rating. Actual testing is performed at a load higher than the post accident loading.

The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelubricating and warmup, discussed in SR 3.8.1.3 and for gradual loading, discussed in SR 3.8.1.4 are applicable to this SR.

The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

In addition, the post-accident load for No. 1A DG is significantly lower than the continuous rating of No. 1A DG. To ensure No. 1A DG performance is not degraded, routine monitoring of engine parameters should be performed during the performance of this SR for No. 1A DG (Reference 9).

The 24 month frequency is consistent with the recommendations of Reference 12, takes into consideration unit conditions required to perform the Surveillance; and is intended to be consistent with expected fuel cycle lengths.

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8,1.11 ------------------- NOTE --------------------

Momentary transients outside the load and power factor limits do not invalidate this test.

W4-t0-efffsitecr, the.urveillAncP 4ed-

-eeftditions do not permit-,-the-powear liitacso lmt r isnotequrdt.b e-Under-- th-------- i---n--th---po-er------r 24 months v~s-,---and operatesfring

.. , mr-es-h~

le4ed toŽ40 fe Gs--IC 8A , n SR 3.8.1.12 Verify each DG rejects a load Ž 500 hp 24 months without tripping.

CALVERT CLIFFS - UNIT 1 3.8.1-14 Amendment No. 302 CALVERT CLIFFS - UNIT 2 Amendment No. 279

AC Sources-Operating B 3.8.1 BASES regarding ESF equipment time delays are not violated. The UFSAR provides a summary of the automatic loading of ESF buses. q,.V The Frequn consstent withu SR 3.8.1.9 r,-eWCqdi-,

-,Ar\S Q'-_(D -e rc4 I See SR 3.8.1.3.

SR 3.8.1.10 Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads. The 24 month Frequency of the Surveillance is based on engineering judgment, taking into consideration the unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.8.1.11 T-h+s--SR--p ev-+ý

-- ý-&<a-t-i on-t-h.

a load s t ha reit-ed accidenqt loads for a*.-l-easL 60-f'-i-utes ore pr 24 ,,.h. Ona-t-e greater

a. than-ea-le,*at'ed--aL "rt od "l clal d..mon.trate the_

al 4 1 f t s to perfurM Lnthir-sdrLy fu,,tion. In orde--to--ensui-e tha the is tsted under load condit-ion6 s t-h-a-t--a-r as cl!e o eign eondition~aspnss -i-b-le-r-t--t-ei-ng m~ust be performe-d uing-a DG-4-oad-g-eatertha&n er-eq-u-a--te-o calculated accident load a-Rd---i.ng a power factor _<.8.

Th e T is chosen to be rce4r-es-e-ta-i-ve-Q-f--t-he--

ac-desrgTr bdSas inductiihradiny ildt the-D could-expe-rremT'e. In -addition_1, thepot accid'entlodfro.A S is signi'ficantly loerthan~thcotiuous rating of No i-G-oe-'--r"" i-- e--pe-r--f-er CALVERT CLIFFS - UNITS 1 & 2 B 3.8. 1-28 Revision 26

AC Sources-Operating B 3.8.1 BASES

-dir*g-the-perfohanef this SR frNA-~

(Referenee-9}.

This SR is modified by a Note which states that momentary transients due to changing bus loads do not invalidate this test. Similarly, momentary power factor transients above SR 3.8.1.12 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This SR demonstrates the DG load response characteristics. This SR is accomplished by tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power.

Consistent with References 10, 3, and 4, the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower.

The 24 month Frequency is consistent with the Reference 2, Chapter 8.

SR 3.8.1.13 This SR demonstrates that DG non-critical protective functions are bypassed on a required actuation signal. This SR is accomplished by verifying the bypass contact changes to the correct state which prevents actuation of the non-critical function. The non-critical protective functions are consistent with References 3 and 4, and Institute-of Electrical and Electronic Engineers (IEEE)-387 and are listed in Reference 2, Chapter 8. Verifying the non-critical trips are bypassed will ensure DG operation during a required actuation. The non-critical trips are bypassed during DBAs and provide an alarm on an abnormal engine CALVERT CLIFFS - UNITS 1 & 2 B 3.8. 1-29 Revision 26

ENCLOSURE 2 OCP-N-10, Division of Responsibilities For NERC Standard NUC-001 Calvert Cliffs Nuclear Power Plant May 30, 2014

Nuclear Operating Committee Administrative Procedure DIVISION OF RESPONSIBILITIES FOR NERC STANDARD NUC-001 OCP-N-10 Revision 2 Effective Date: March 15, 2013 Writer: Bob Stark, Larry Williams Original signed by Horace G. Beasley Original Signed by Richard Clarke Horace G. Beasley Richard Clarke Operating Committee Representative Operating Committee Representative Calvert Cliffs Nuclear Power Plant, LLC Baltimore Gas and Electric Company

OCP-N- 10 Division of Responsibilities for NUC-O0 1 Revision 2 Page 2 of 17 RECORD OF REVISIONS AND CHANGES Revision Change Summary of Revision or Changes 0 Initial Issue.

1 I Changes made to update agreement:

Added short circuit studies to agreement. Corrected grammar mistake page 15.

2 2 Added version I of the NPIRs

OCP-N- 10 Division of Responsibilities for NUC-00 1 Revision 2 Page 3 of 17 TABLE OF CONTENTS SECTION TITLE PAGE Contents 1.0 Introduction ............................................................................................................. 5 1.1 P urpo se ......................................................................................................................... 5 1.2 Scope/Applicability ................................................................................................. 5 2.0 References ........................................................................................................... 5 2.1 Developmental References ..................................................................................... 5 2.2 Performance References .......................................................................................... 6 3.0 Definitions ............................................................................................................ 6 4.0 Division of Responsibilities for NUC-001 ............................................................. 8 4.1 CCNPP and BGE Responsibilities ......................................................................... 8 4.2 Technical Requirements and Analysis .................................................................... 9 4.3 Operations and Maintenance Coordination ........................................................... 12 4.4 Communications and Training .............................................................................. 14

OCP-N- 10 Division of Responsibilities for NUC-001 Revision 2 Page 4 of 17 Attachments A CCNPP NPIRs ............................................................................................................ 17 LIST OF EFFECTIVE PAGES Page No. Change No. Page No. Change No. Page No. Change No.

1 1 8 0 15 1 2 1 9 0 16 0 3 0 10 0 17 2 4 1 11 0 5 0 12 1 6 0 13 0 7 0 14 0

OCP-N- 10 Division of Responsibilities for NUC-00 1 Revision 2 Page 5 of 17

1.0 INTRODUCTION

1.1 Purpose The purpose of this procedure is to provide the responsibilities and required work interfacing activities between Calvert Cliffs Nuclear Power Plant, LLC (CCNPP) and Baltimore Gas and Electric Company (BGE) for the purposes of meeting the subset of Calvert Cliffs Nuclear Plant Interface Requirements (NPIRs) and NERC Standard NUC-001 requirements applicable as a result of Baltimore Gas and Electric Company's ownership of transmission lines 5051 and 5052, a portion of 5072, and Calvert Cliffs 500 kV Switchyard.

Transmission lines 5051 and 5052 are 500 kV transmission lines connected from BGE's Waugh Chapel Substation to BGE's Calvert Cliffs 500kV Switchyard.

1.2 Scope/ Applicability A. The NUC-001 standard requires coordination between Calvert Cliffs Nuclear Plant LLC (CCNPP) and Baltimore Gas and Electric (BGE) for the purpose of ensuring the nuclear plant's safe operation and shut down.

B. This standard requires that CCNPP develop Nuclear Plant Interface Requirements (NPIRs), provide BGE written copies of the proposed NPIRs and have in effect agreements that include the mutually agreed upon NPIRs documenting how CCNPP and BGE implement the NPIRs.

C. This procedure outlines the responsibilities of BGE and CCNPP in implementing the NPIRs.

D. This procedure is applicable to CCNPP and BGE.

2.0 REFERENCES

2.1 Developmental References A. NERC Standard NUC-00 I - Nuclear Plant Interface Coordination

OCP-N- 10 Division of Responsibilities for NUC-001 Revision 2 Page 6 of 17 B. CCNPP Final Safety Analysis Report (FSAR)

C. Specifications for Interconnection Service Agreement Between PJM Interconnection, LLC and Calvert Cliffs Nuclear Power Plant, Inc and Baltimore Gas and Electric Company, Effective: January 17, 2006 (ISA)

D. IOCFR50.65 - Nuclear Maintenance Rule 2.2 Performance References A. Nuclear Operating Committee Administrative Procedure OCP-N-2 (Notification Requirements)

B. Nuclear Operating Committee Administrative Procedure OCP-N-3 (Planning and Scheduling)

C. Nuclear Operating Committee Administrative Procedure OCP-N-8 (Issue Resolution)

D. Nuclear Operating Committee Administrative Procedure OCP-N-9 (Division of Responsibilities for PRC-005 and CIP-002)

E. Constellation Nuclear Generation Fleet Administrative Procedure CNG-MN-4.01-2000 (On-Line Scheduling)

F. Specifications for Interconnection Service Agreement Between PJM Interconnection, LLC and Calvert Cliffs Nuclear Power Plant, Inc and Baltimore Gas and Electric Company, Effective: January 17, 2006 (ISA) 3.0 DEFINITIONS All definitions for the OCPs are referenced in the ISA or contained herein.

A. NERC North American Electric Reliability Corporation B. NPIRs Nuclear Plant Interface Requirements

OCP-N- 10 Division of Responsibilities for NUC-001 Revision 2 Page 7 of 17 C. NUC-001 NERC reliability standard for Nuclear Plant Interface Coordination D. BGE Baltimore Gas and Electric, Transmission Owner, Load-Serving Entity and Distribution Provider E. CCNPP Calvert Cliffs Nuclear Power Plant LLC, Generator Owner and Generator Operator F. OCPs Nuclear Operating Committee Administrative Procedures G. PJM The Regional Transmission Operator (RTO) that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia.

PJM is registered as follows:

TP: Transmission Planner TOP: Transmission Operator BA: Balancing Authority RC: Reliability Coordinator TSP: Transmission Service Provider (for the BGE Transmission Zone)

PA/PC: Planning Authority/Coordinator H. NRC United States Nuclear Regulatory Commission

1. NRC Maintenance Rule NRC rules and regulations governing maintenance of certain facilities in accordance with 10 C.F.R. § 50.65, as they may be amended.

J. Point of Interconnection Physical point of interconnection where capacity, energy, and ancillary services are transferred between CCNPP and the BGE System. The Points of Interconnection are specified in the ISA.

K. LCO Limiting Condition for Operation as specified by CCNPP Technical Specifications.

L. PEPCO Potomac Electric Power Company, Transmission Owner

OCP-N- 10 Division of Responsibilities for NUC-001 Revision 2 Page 8 of 17 M. SMECO Southern Maryland Electric Cooperative, Inc., Distribution Provider

[Basis: NUC-00, requirements R9.1.1, R9.1.2]

4.0 DIVISION OF RESPONSIBILITIES FOR NUC-001 4.1 CCNPP and BGE Responsibilities A. CCNPP shall provide the proposed NPIRs in writing to BGE and shall verify receipt. This document shall serve as the agreement between BGE and CCNPP on the implementation of the NPIRs.

[Basis: NUC-00 1, requirements R I and R2, R9.1.2]

B. At the direction of PJM, BGE shall perform operations of the electric system to meet the agreed upon NPIRs, and inform CCNPP when the ability to assess the operation of the electric system affecting NPIRs is lost. I

[Basis: NUC-001, requirements R3, R4, R4.1, R4.2, R4.3, R9.1.2]

C. CCNPP shall operate per the existing interconnection agreements with BGE and shall implement the NPIRs developed in accordance with NERC standard NUC-001

[Basis: NUC-001, requirements R5, R9.1.2]

D. BGE and CCNPP shall coordinate outages and maintenance activities which affect the NPIRs per OCP-N-3 (Planning and Scheduling).

[Basis: NUC-001, requirements R6, R9.1.2]

E. CCNPP shall inform BGE of actual or proposed changes to nuclear plant design, configuration, operations, limits, protection systems, or capabilities that may impact the ability of the electric system to meet the NPIRs per OCP-N-2 (Notification Requirements).

[Basis: NUC-001, requirements R7, R9.1.2]

F. BGE shall inform CCNPP of actual or proposed changes to electric system design, configuration, operations, limits, protection systems, or PJM shall incorporate the NPIRs supplied by CCNPP into their planning analyses of the electric system and shall communicate the results of these analyses to the CCNPP. PJM shall incorporate the NPIRs into their operating analyses of the electric system.

OCP-N- 10 Division of Responsibilities for NUC-00 1 Revision 2 Page 9 of 17 capabilities for BGE owned equipment that may impact the ability of the electric system to meet the NPIRs per OCP-N-2 (Notification Requirements).

[Basis: NUC-00 1, requirements R8, R9.1.2]

G. BGE and CCNPP shall review the NPIRs and this procedure every three (3) years. Any disputes concerning the NPIRs shall be resolved by the Operating Committee per the ISA Appendix 2 Subpart E Section 70 and OCP-N-8 (Issue Resolution).

[Basis: NUC-001, requirements 9.1.3 & 9.1.4, R9.1.2]

4.2 Technical Requirements and Analysis A. Identification of parameters, limits, configurations, and operating scenarios included in the NPIRs

1. Parameters - Offsite power is supplied to the Calvert Cliffs 500 kV Switchyard from the transmission network by three 500 kV transmission lines: 5051 and 5052 (BGE-Waugh Chapel) and 5072 (PEPCO-Chalk Point).

Normally two 500 kV to 13.8kV transformers, powered from independent Calvert Cliffs 500 kV Switchyard busses (Black bus and Red bus) as off-site power sources, power site service loads.

A third 69 kV to 13.8 kV offsite power source that may be manually connected to CCNPP is available from SMECO. It can be manually connected to supply the Engineered Safeguard loads (accident loads on one unit plus shutdown loads on the other unit) in the event of the loss of the normal 500 kV supply with both units shut down.

These lines are considered "offsite power sources" and are needed to supply the "offsite power circuits" required by the Calvert Cliffs Nuclear Power Plant Operating License (i.e., Technical Specifications Limiting Conditions for Operation (LCO) 3.8.1 and 3.8.2).

Requirement Offsite Power Sources required to comply with CCNPP Licensing requirements: If the reactor coolant system temperature of either unit is greater than 200'F, then two of the four lines supplying offsite power (line 5051, 5052, 5072, or SMECO) must be operable and available to power two 13.8 kV busses (Nos. 11 and 21). If the reactor coolant system temperature of both units is at or below 200'F, then one of the four offsite sources (line 5051, 5052,

OCP-N- 10 Division of Responsibilities for NUC-00 1 Revision 2 Page 10 of 17 5072, or SMECO) must be operable and available to power two 13.8 kV busses (Nos. 11 and 21). BGE should assume that at least one of the Calvert Cliffs units is above 200'F at all times, unless otherwise notified by CCNPP.

[Basis: NUC-001, requirement R9.2. 1]

2. Calvert Cliffs 500 kV Switchyard Operating Voltage and Frequency Requirements 11 Calvert Cliff Voltage Limits Plant Service Pre-Contingency Post-Contingency Transformers (P-13000-2 & P-13000-2)

Both xfmrs in service 500kV - 550kV 475kV - 550kV Only one xfmr in service 520kV - 550kV 510kV - 550kV Note: See maximum post-trip voltage drop below for loss of a CCNPP unit.

Maximum post-trip voltage drop (post contingency for a single CCNPP unit): Voltage drop of 5% of the pre-trip bus voltage with either one or both P-13000 transformers in service. The 5% post contingency voltage drop limit is to be applied at the Calvert Cliffs 500 kV Switchyard for a contingency trip of CCNPP Unit 1 or Unit 2.

The Unit I and Unit 2 CCNPP Main generators will trip on an under-frequency relay protection setting/time delay of 57.5 Hz/309 cycles (includes breaker operating time).

[Basis: NUC-001, requirement R9.2. I]

3. Configurations - The Calvert Cliffs 500 kV Switchyard is arranged in a breaker-and-one-half configuration and has two bays consisting of three breakers each and one bay of two breakers with two main busses (Black and Red) and connection to each generator main power transformer, the two 500 kV to 13.8 kV plant service transformers, and three 500 kV transmission lines (5051, 5052 and 5072) to the 500 kV network.

[Basis: NUC-001, requirement R9.2.1]

4. Operating Scenarios - If the reactor coolant system temperature of either unit is greater than 2007F, then two of the four lines supplying offsite power (line 5051, 5052, 5072, or SMECO) must be operable and available to power two 13.8 kV busses (Nos. 11 and 21). If the reactor coolant system temperature of both units is at or below 2007F, then one of the four lines supplying offsite

OCP-N- 10 Division of Responsibilities for NUC-00 I Revision 2 Page 11 of 17 power (line 5051, 5052, 5072, or SMECO) must be operable and available to power two 13.8 kV busses (Nos. 11 and 21).

[Basis: NUC-001, requirement R9.2.1]

5. Specifications for Interconnection Service Agreement Between PJM Interconnection, LLC and Calvert Cliffs Nuclear Power Plant, Inc and Baltimore Gas and Electric Company (ISA) Schedule G-2 Section 6.2 (NRC Requirements and Commitments) shall be used for supplying specific data not provided within this procedure.

[Basis: N UC-001, requirement R9.2.1 ]

B. Identification of facilities, components, and configuration restrictions essential for meeting the NPIRs.

I. Offsite power is supplied to the Calvert Cliffs 500 kV Switchyard from the transmission network by three 500 kV transmission lines:

5051 and 5052 (Waugh Chapel) and 5072 (Chalk Point). Two physically independent circuits from the Calvert Cliffs 500 kV Switchyard are required to supply power from the Calvert Cliffs 500 kV Switchyard to two 13 kV busses and then to the two 4.16 kV Engineered Safeguard busses on each unit.

Another offsite power source, a 69 kV to 13.8 kV source, that may be manually connected to either 13 kV bus is available from SMECO. It can be manually connected to supply the Engineered Safeguard loads (accident loads on one unit plus shutdown loads on the other unit) in the event of the loss of both of the connected offsite power sources.

See item 4.2.A.4, above, for configuration requirements.[Basis:

NUC-001, requirement R9.2.2]

C. Types of planning and operational analyses performed specifically to support the NPIRs, including the frequency of studies and types of Contingencies and scenarios required.

A state estimator and real time contingency analysis program shall be used to monitor the Calvert Cliffs 500 kV Switchyard voltage limits. Both BGE and PJM possess state estimator equipment. Both BGE and CCNPP shall comply with section 2.4 of the current revision of PJM manual M39. Single contingencies analyzed must include the trip of a CCNPP Unit and the trip of transmission facilities impacting the Calvert Cliffs 500 kV Switchyard voltage limits. PJM shall communicate to BGE all Calvert Cliffs 500 kV Switchyard contingency voltage limit violations within 15 minutes.

OCP-N- 10 Division of Responsibilities for NUC-00 1 Revision 2 Page 12 of 17 The communication shall include the cause of the contingency violation. PJM shall immediately communicate to BGE all Calvert Cliffs 500 kV Switchyard actual voltage limit violations. BGE shall immediately communicate to CCNPP all notifications received from PJM.

If PJM loses its state estimator or contingency analysis capability, BGE's state estimator and contingency analysis systems will provide backup capability. Under these conditions, BGE shall immediately notify CCNPP of actual voltage security analysis limit violations and notify CCNPP within 15 minutes of contingency voltage security analysis violations. If both PJM and BGE lose state estimator or real time contingency analysis capability, BGE shall immediately notify CCNPP. PJM and/or BGE shall support CCNPP and provide an assessment when requested and as system conditions permit, 2 of the current grid condition based on available tools at the time.

At the request of CCNPP, BGE shall perform periodic analysis of expected CCNPP switchyard post Unit trip voltages and/or provide BGE short circuit current data at points of interconnection, when requested, for use in CCNPP distribution short circuit current studies. The BGE studies are typically performed on an annual frequency, but could be needed on a more frequent basis. The results of these studies shall be provided to CCNPP by BGE.

[Basis: NUC-001, requirement 9.2.31 4.3 Operations and maintenance coordination A. Designation of ownership of electrical facilities at the interface between the electric system and the nuclear plant and responsibilities for operational control coordination and maintenance of these facilities.

1. Ownership of electrical facilities between CCNPP and BGE:

Points where 500kV conductors from the BG&E switchyard connect to CCNPP's:

1. U-22000-21, 22 (GSU) Disconnect Switch
2. U-25000-11, 12 (GSU) Disconnect Switch
3. Removable link at the high side of P-13000-1 Plant service transformer 2 PJM shall provide to CCNPP the types of planning and operational analyses performed specifically to support the NPIRs, including the frequency of studies and types of Contingencies and scenarios required.

OCP-N- 10 Division of Responsibilities for NUC-001 Revision 2 Page 13 of 17

4. Removable link at the high side of P-13000-2 Plant service transformer CCNPP owns and maintains all equipment at the points of interconnection into and including the power plant. BGE owns and maintains all equipment from the points of interconnection into and including the switchyard. Refer to the ISA Schedules B &

C.

[Basis: NUC-001, requirement 9.3.1]

B. Identification of any maintenance requirements for equipment not owned or controlled by the Nuclear Plant Generator Operator that are necessary to meet the NPIRs.

1. CCNPP and BGE shall perform Preventative and Predictive Maintenance in the Calvert Cliffs 500 kV Switchyard in accordance with a mutually agreed upon Preventative Maintenance strategy.

Preventative Maintenance tasks (PMs) will be approved by CCNPP and BGE. No changes shall be made to PMs for components in the Calvert Cliffs 500 kV Switchyard without the prior review and approval of the Calvert Cliffs System Engineering Unit.

[Basis: NUC-001, requirement 9.3.2]

C. Coordination of testing, calibration and maintenance of on-site and off-site power supply systems and related components.

1. Coordination of testing, calibration and maintenance for Calvert Cliffs 500 kV Switchyard is covered in Nuclear Operating Committee Administrative Procedure OCP-N-3 (Planning and Scheduling). CCNPP plant work is covered in Constellation Nuclear Generation Fleet Administrative Procedure CNG-MN-4.01-2000 (On-Line Scheduling).

[Basis: NUC-001, requirement 9.3.3]

D. Provisions to address mitigating actions needed to avoid violating NPIRs and to address periods when the responsible Transmission Entity loses the ability to assess the capability of the electric system to meet the NPIRs. These provisions shall include responsibility to notify the Nuclear Plant Generator Operator within a specified time frame.

1. If CCNPP is notified that PJM and BGE have lost their real time contingency analysis capability, the CCNPP Shift Manager or CCNPP Control Room Supervisor shall request PJM and BGE to provide an assessment of the current condition of the grid. This assessment will provide a basis for

OCP-N- 10 Division of Responsibilities for NUC-001 Revision 2 Page 14 of 17 the reliability and operability of the offsite power sources, including whether the current grid condition is bounded by the grid studies previously performed for CCNPP.

[Basis: NUC-001, requirements 9.3.4]

E. Provision for considering, within the restoration process, the requirements and urgency of a nuclear plant that has lost all off-site and on-site AC power.

1. PJM Manual 36: Offsite power should be restored as soon as possible to nuclear units, both units that had been operating and those that were already offline prior to the system disturbance, without regard to using these units for restoring customer load.

PJM shall direct restoration of offsite power to Nuclear Facilities. PJM through BGE shall keep CCNPP apprised of the anticipated restoration time for offsite power.

[Basis: NUC-001, requirement 9.3.5]

F. Coordination of physical and cyber security protection of the Bulk Electric System at the nuclear plant interface to ensure each asset is covered under at least one entity's plan.

1. Physical security at CCNPP and Calvert Cliffs 500 kV Switchyard is covered by the Nuclear Safety & Security Department at CCNPP. All cyber assets associated with ajoint use protection system must be jointly evaluated by BGE and CCNPP to determine if the cyber assets are essential to the operation of any Critical Asset according to CIP-002.

Likewise, for all BGE-owned cyber assets on CCNPP property and all CCNPP-owned cyber assets on BGE property, the cyber assets must be jointly evaluated to determine if the cyber assets are essential to the operation of any Critical Asset according to CIP-002. The entity that owns the equipment in question is responsible for facilitating, leading, and documenting the joint evaluation such that both entities are able to demonstrate compliance with the CIP-002 standard. This is covered in OCP-N-9 (Division of Responsibilities for PRC-005 and CIP-002).

[Basis: NUC-001, requirement 9.3.6]

G. Coordination of the NPIRs with transmission system Special Protection Systems and underfrequency and undervoltage load shedding programs.

OCP-N- 10 Division of Responsibilities for NUC-00 1 Revision 2 Page 15 of 17

1. BGE will not trip 5051 or 5052 with underfrequency or undervoltage load shedding programs or Special Protection Systems without CCNPP consent. CCNPP does not employ Special Protection Systems.

[Basis: NUC-001, requirement 9.3.7]

4.4 Communications and training A. Provisions for communications between the Nuclear Plant Generator Operator and Transmission Entities, including communications protocols, notification time requirements and definitions of terms.

1. Communications between BGE and CCNPP including notification protocols and responsibilities of each entity shall be in accordance with Nuclear Operating Committee Administrative Procedure OCP-N-2 (Notification Requirements) unless specifically addressed in this procedure.

[Basis: NUC-001, requirement 9.4.11]

B. Provisions for coordination during an off-normal or emergency event affecting the NPIRs, including the need to provide timely information explaining the event, an estimate of when the system will be returned to a normal state, and the actual time the system is returned to normal.

1. During an emergency or off-normal event that affects the NPIRs, BGE and CCNPP shall coordinate and communicate the status of each other's system. When requested by CCNPP, BGE shall provide timely information explaining the event, an estimate of when the system will be returned to a normal state, and the actual time the system is returned to normal. When requested by BGE, CCNPP shall provide timely information explaining the event, an estimate of when the system will be returned to a normal state, and the actual time the system is returned to normal. These communications are specified in Nuclear Operating Committee Administrative Procedure OCP-N-2 (Notification Requirements).

[Basis: NUC-001, requirement 9.4.2]

C. Provisions for coordinating investigations of causes of unplanned events affecting the NPIRs and developing solutions to minimize future risk of such events.

OCP-N- 10 Division of Responsibilities for NUC-00 1 Revision 2 Page 16 of 17

1. BGE and CCNPP coordinate investigations of causes of unplanned events affecting the NPIRs and develop solutions to minimize future risk of such events in accordance with the ISA Schedule G-2 Section 3.0.

[Basis: NUJC-001, requirement 9.4.3]

D. Provisions for supplying information necessary to report to government agencies, as related to NPIRs.

1. BGE and CCNPP shall coordinate the supply of information necessary to report to government agencies, as related to NPIRs in accordance with the ISA Appendix 2 Subpart E Section 69 and Schedule G-2 Section 6.0.

[Basis: NUC-001, requirement 9.4.4]

E. Provisions for personnel training, as related to NPIRs.

1. BGE and CCNPP shall provide training to their personnel on the NPIRs. When necessary, joint training between BGE and CCNPP will be conducted.

[Basis: NUC-001, requirement 9.4.5]

OCP-N- 10 Division of Responsibilities for NUC-00I Revision 2 Page 17 of 17 Attachment A CCNPP NPIIRs

ENCLOSURE3 OCP-N-2, Notifications Requirements Calvert Cliffs Nuclear Power Plant May 30, 2014

Nuclear Operating Committee Administrative Procedure NOTIFICATION REQUIREMENTS OCP-N-2 Revision 4 This procedure is EXEMPT from IOCFR50.59 / IOCFR72.48 reviews.

Effective Date April 2, 2013 Writer: S. C. Collins Revised by T. J. Harrington / L. Williams Original Signed by Jerry G. Beasley Original Signed by Richard T. Clarke.

Jerry G. Beasley Richard T. Clarke Operating Committee Representative Operating Committee Representative Calvert Cliffs Nuclear Power Plant, Inc. Baltimore Gas and Electric Company CODE OF CONDUCT REMINDER - Under Federal and State rules governing relations, Baltimore Gas and Electric Company ("BGE") cannot disclose non-public information relating to either BGE's electric system or BGE's customers.

OCP-N-2 Notification Requirements Revision 4 Page 2 of 12 RECORD OF REVISIONS AND CHANGES Revision Change Summary of Revision or Changes 0 Initial Issue.

1 Reformatting Text; Revised organization names Added Section 2.1.B.5 regarding 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> notification for switchyard entry.

Added Section 2.1.N on planned switching notifications Added Section 2.2 on security notifications 2 Revised Section 2.1 to reference "High Risk" conditions as described by OCP-N-3. Added reference to outage scheduling guidelines in OCP-N-3.

Updated to reflect BGE Organization Changes 3 Updated references to Revised Interconnection Agreement 4 Added statement in 2.1 L to coordinate with OCP-N-10 Updated 2.1.B.4 to reflect scheduling windows and changed MN- I -I 14 reference to CNG-MN-4.01 -

1004.

OCP-N-2 Notification Requirements Revision 4 Page 3 of 12 TABLE OF CONTENTS SECTION TITLE PAGE

1.0 INTRODUCTION

5 1.1 Purpose 5 1.2 Scope/Applicability 5 2.0 NOTIFICATION REQUIREMENTS 6 2.1 Process 6 2.2 Security 12

OCP-N-2 Notification Requirements Revision 4 Page 4 of 12 LIST OF EFFECTIVE PAGES Page No. Rev. No. Change No. Page No. Rev. No. Change No.

1 3 0 8 3 0 2 3 0 9 3 0 3 3 0 10 4 0 4 3 0 11 3 0 5 3 0 12 3 0 6 3 0 7 4 0

OCP-N-2 Notification Requirements Revision 4 Page 5 of 12

1.0 INTRODUCTION

1.1 Purpose The purpose of this procedure is to provide the guidelines for the interface between the Calvert Cliffs Nuclear Power Plant, Inc. and the Baltimore Gas and Electric Company to provide direction for ensuring that notification requirements are properly completed in accordance with the ISA and INPO's SOER 99-01.

1.2 Scope/ Applicability A. This procedure supports implementation of ISA requiring the establishment of communications and information transfer protocol. These include, but are not limited to the following:

1. Notification of work requirements in or around the other company's facility
2. Actions necessary to address NRC Maintenance Rule requirements.
3. Notification of changes to service
4. Notification of emergency conditions
5. Notification of hazardous substance releases
6. Notification of control setting changes
7. Notification of system restoration capability
8. Notification of changes to power specifications
9. Notification of deficiencies B. The ISA or OCP-N-1 contains all reference information that applies to this procedure.
1. All definitions are found in the ISA or OCP-N-1.
2. All developmental and implementing reference procedures that apply to this OCP are contained in OCP-N-I.
3. All Basis references are specified in OCP-N-I.

OCP-N-2 Notification Requirements Revision 4 Page 6 of 12 2.0 NOTIFICATION REQUIREMENTS 2.1 Process A. All communications between BGE and CCNPP and work performed under these OCPs (including routine Inspections) shall comply with the rules and regulations of the Federal Energy Regulatory Commission (FERC) and the Maryland Public Service Commission (MPSC) regarding the provision of nondiscriminatory open access service. BGE is required to comply with the FERC Standards of Business Conduct established by Orders 889 and 2004. These requirements focus on the appropriate protection of market sensitive information.

B. Notification of planned maintenance; modification, inspections, additions or replacements required in or around the other company's facility or that limit the other company's ability to perform work at their facility. (BI - 53.1, 54.11, 55.3.2, 55.4)

1. Two-year preliminary schedules of routine work shall be transmitted to the other company by June 1 each year.

From time to time non-binding schedules reflecting changes shall be furnished. (BI - 55.3.1)

2. Written notification of a facility modification scheduled start date will be provided at least 180 days prior to the start date. Acceptance of the proposed date should be provided within 30 days. (BI - 53.1)
3. CCNPP will notify the TSO Outage Scheduling unit and the supervisor of Resource Management Substation and Transmission of planned work within six (6) weeks of the scheduled start date. TSO Outage Scheduling's role is to communicate the outages to the BGE maintenance organizations. This includes the following work:
  • Plant transformer work limiting the CC 500 kV Switchyard configuration BGE will provide notice of scheduled work at the CC 500 kV Switchyard in accordance with CNG MN-4.01-1004.

OCP-N-2 Notification Requirements Revision 4 Page 7 of 12 For work designated as High Risk, BGE will notify the CCNPP site sponsor of planned work at least sixteen (16) weeks prior to the scheduled start date for work designated as High Risk as described in OCP-N-3. This requirement does not pertain to routine inspections of the CC 500 kV Switchyard. See OCP-N-3 for outage scheduling guidelines.

5. Due to the security requirements imposed upon CCNPP by the Federal Office of Homeland Security, BGE shall notify CCNPP 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to entry into the switchyard. This will allow time for Security at CCNPP to arrange for the barriers in front of the entrance to be removed and for extra security personnel to be stationed at the switchyard entrance.

C. Notification of equipment testing requests (BI - 55.4)

1. BGE, pursuant to Good Utility Practice, may request that CCNPP perform testing, calibrations, verifications or validations of CCNPP's facility. The request should be submitted to the CCNPP General Supervisor- Electrical Maintenance.
2. CCNPP, pursuant to Good Utility Practice, may request that BGE perform testing, calibrations, verifications or validations of the BGE interconnection facilities. The request should be submitted to the TSO Outage Scheduling unit.

D. Notifications of actions necessary to implement NRC Maintenance Rule requirements. (BI - 3.0) 1I. When generated by CCNPP, the quarterly System Status Report and the CCNPP 500 kV System Report Card will be routed to the Director of Substations and Transmission in Integrated Field Services and a copy to the BGE Operating Committee Representative.

If the CCNPP 500 kV system requires an a(1) evaluation and corrective action plan per Maintenance Rule requirements, the corrective action plan will be presented to the BGE Operating Committee Representative for review prior to the CCNPP Plant Health Committee review.

OCP-N-2 Notification Requirements Revision 4 Page 8 of 12 E. Notification of changes to service including heating, ventilation, air conditioning lighting, AC and DC station service, paging, and other building services. (BI - 2.1.1)

1. If planned service changes will interrupt service, then notify the Operating Committee in writing no less than 30 days prior to the change.
2. The responsible operations and maintenance organizations will contact one another per sections 2.1 B or F of this procedure.

F. Notification of an emergency condition requiring immediate action to preserve public safety, to limit or prevent damage to equipment or to expedite restoration of service, such that notification through the PJM System Operator is not timely enough to prevent loss of offsite power availability to CCNPP or to preserve the integrity of the BGE system. (BI - 7.1, B2) For any condition that does not require immediate action, system conditions, status and direction will be communicated to CCNPP via PJM and Constellation Energy Commodities Group (CCG).

1. In accordance with the BGE operations manuals, BGE shall provide prompt verbal notification to the CCNPP control room of any local (BGE) emergency that causes CCNPP to increase/decreases generation, or will cause a loss of offsite power availability to CCNPP.
2. CCNPP shall provide prompt verbal notification to BGE of any condition, which might reasonably be expected to affect the transmission system or the interconnection facilities. The Control Room will make such notification as directed by operating procedures.
3. Emergency communications shall include at a minimum the following information:
  • Description of the emergency
  • The anticipated length of the outage or emergency (if known at the time)
  • The corrective action to be taken (if known at the time)

Written notification confirming the emergency communications shall be completed within 30 days of the verbal communication and sent to the General Supervisor Nuclear Power Operations and to the BGE Manager

OCP-N-2 Notification Requirements Revision 4 Page 9 of 12 Transmission System Operation. Event reporting and investigation may go beyond 30 days.

G. Notification of a release of a hazardous substance (BI - 50.27)

1. BGE shall notify the General Supervisor - Chemistry, CCNPP, as soon as possible of the release of a hazardous substance on CCNPP property.
2. CCNPP shall notify the Director Substations and Transmission, as soon as possible of the release of a hazardous substance on BGE property.

H. Notification of a change to a control setting.

1. CCNPP shall notify the Director System Protection and Automation in IFS and send a copy to the BGE Operating Committee Representative of any control setting changes affecting generator control (such as excitation, droop, and automatic generator controls).

I. Notification of CCNPP's capability to participate in system restoration and black start capability. (BI - 1.3BB)

1. The CCNPP and BGE Operating Committee Representatives shall periodically review CCNPP's ability to support system restoration. Black start capability does not apply to CCNPP.

J. Notification of changes to power production specifications.

1. CCNPP shall notify the System Operator, the BGE Manager of Transmission Systems Operations and the BGE Operating Committee Representative of changes in the ability of the plant to provide or absorb reactive power.

(B I - 54.7)

CCNPP shall notify the System Operator if a reactive load limit is reached, if there is any deviation from the assigned voltage schedule, or if any automatic voltage regulator is removed from or restored to service. (B1 - 54.7)

K. Notification of Operating Committee Membership (BI - 1.0)

1. BGE and CCNPP shall each appoint one representative and one alternate to the Operating Committee. The

OCP-N-2 Notification Requirements Revision 4 Page 10 of 12 organizations shall notify each other in writing. Any changes in membership shall be similarly documented.

L. Notification of deficiencies

1. Upon request, the company owning a Joint Use Facility shall provide to the other company copies of the written reports summarizing the results of inspections and describing any problems, deficiencies or other observed defects per OCP-N-7.
2. Upon discovery of a deficiency potentially requiring immediate corrective action, contact the other company through the appropriate facility control room prior to taking any action. (BI - 56.2)
3. If BGE observes any deficiency or defects that might adversely affect the BGE System or the Company Interconnection Facilities, they will notify the General Supervisor of CCNPP Electrical Maintenance. (BI -56.2)
4. If CCNPP observes any deficiency or defects that might adversely affect the generating facility, they will notify the BGE Manager of Transmission Systems Operations. (B 1 -

56.2)

5. At the direction of PJM, BGE shall perform operations of the electric system to meet the agreed upon NPIRs, and inform CCNPP when the ability to assess the operation of the electric system affecting NPIRs is lost.'

[Basis: NUC-001, requirements R3, R4, R4.1. R4.2, R4.3, R9.1.2]

M. Notification of an outage

1. Except in an emergency, CCNPP shall notify BGE not less than eight (8) hours prior to any anticipated outage other than planned maintenance. (BI - 55.3)
2. CCNPP agrees to give notice to BGE as soon as practicable in the event of emergencies or other unanticipated outages.

PJM shall incorporate the NPIRs supplied by CCNPP into their planning analyses of the electric system and shall communicate the results of these analyses to the CCNPP. PJM shall incorporate the NPIRs into their operating analyses of the electric system.

OCP-N-2 Notification Requirements Revision 4 Page 11 of 12

3. Except in an emergency, BGE shall notify CCNPP not less than eight (8) hours prior to any anticipated outage other than planned maintenance. BGE agrees to notify CCNPP in the event of emergencies or other unanticipated outages in accordance with appropriate PJM protocols.

N. Notification of planned switching I1. All switching required for the support of maintenance, outages, modifications, improvements, etc. shall be in accordance with OCP-N-4.

2. Coordination of switching requirements between both companies shall be in a timely manner and in accordance with the pre-planned schedule. Any deviations to the planned schedule, for example in exiting an outage, shall be verbally communicated between the BGE and CCNPP Control Rooms and shall follow the guidelines below:

" If the scheduled activity deviates from the schedule more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, then notification of the revised switching schedule shall be no less than five (5) days.

" If the scheduled activity deviates from the schedule more than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, then notification of the revised switching schedule shall be no less than two (2) days.

" If the scheduled activity deviates from the schedule more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, then notification of the revised switching schedule shall be no less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

  • Any deviation from the schedule less than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> will require notification of the revised switching schedule on an hourly basis within the final 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> window.

2.2 Security A. Office of Homeland Security (OHS)

1. The OHS has developed a Homeland Security Advisory System (HSAS) to provide a comprehensive and effective system to disseminate information regarding the risk of terrorist attacks to Federal, State, and local authorities and to the public. (B5)

OCP-N-2 Notification Requirements Revision 4 Page 12 of 12

2. The HSAS provides a consistent national framework for allowing government officials and citizens to communicate the nature and degree of terrorist threats.
a. Upon a declaration of an HSAS threat condition, the NRC will promptly notify affected licensees of the threat condition and of the appropriate protective measures.
b. Upon notification by the NRC, CCNPP shall notify BGE of any threats that may affect the security of the 500 switchyard and/or high lines.
c. Similarly, for any security threats to the 500 kV system that have the potential to threaten the loss of offsite power to CCNPP, BGE shall promptly notify CCNPP.
3. BGE access to CCNPP at the main gate does not require any specific notification regardless of alert levels as long as all occupants of the vehicle are badged appropriately.

However, during HSAS security threat levels of orange and red, access may be denied without sponsorship available.

a. Prior to entering the CCNPP property, BGE should contact the CCNPP Control Room to request escort by a sponsor from E&C Maintenance.
b. For access to the protected area, notification of the CCNPP Sponsor is required to ascertain any additional NRC requirements in gaining access to the facility.

B. Security Notifications All notifications from either company to the other regarding security related matters shall be considered confidential and treated as competition market sensitive. Reference OCP-N-1, section 4.2.B, for more detailed information on the confidentiality of communications.

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