ML070310282
| ML070310282 | |
| Person / Time | |
|---|---|
| Site: | Millstone, Kewaunee, Surry, North Anna  |
| Issue date: | 01/30/2007 |
| From: | Grecheck E S Dominion Energy Kewaunee, Dominion Nuclear Connecticut, Dominion Resources Services, Virginia Electric & Power Co (VEPCO) |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 06-1070, GL-06-002 | |
| Download: ML070310282 (21) | |
Text
Dominion Resources 5(100 Lhminion Boult Services, Inc.
xud, Glcn Allrn, Vh 110(,0 January 30, 2007 U .S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Serial No.: 06- 1 070 NL&OS/ETS:
RO Docket Nos.:
50-305 50-336/423 50-338/339 50-280128 1 License Nos.: DPR-43 DPR-65 N PF-49 N PF-4/7 DPR-32/37 DOMINION ENERGY KEWAUNEE INC. (DEK) - DOMINION NUCLEAR~NNECTICUT.
INC. (DNC) - VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION) - KIEWAUNEE POWER STATION - MILLSTONE POWER STATION UNITS 2 AND 3 - NORTH ANNA POWER STATION UNITS 1 AND 2 - SlJRRY POWER STATION UNITS 1 AND 2 - OIN PLANT RISK AND THE OPERABILITY OF OFFSITE POWER - 01n February 1, 2006, the NRC issued Generic Letter 2006-02 to determine if compliance was being maintained with NRC regulatory requirements governing electric power for nuclear power plants and associated personnel training.
In an April 3, 2006 letter (Serial No. 06-1 03), DEK, DNC, and Dominion provided the requested information for Kewaunee, Millstone, North Anna and Surry Power Stations. In a December 5, 2006 letter the NRC Staff requested additional information to resolve the issues identified in thle generic letter. The attachments to this letter provide DEK's, DNC's and Dominion's response to the request to the specific questions asked of each station.
If you have any questions or require additional information, please contact Mr. Thomas Stiaub at (804) 273-2763.
Very truly yours, .-J Eugene S. Grecheck Vice President - Nuclear Support Services Dominion Energy Kewaunee, Inc. Dominion Nuclear Connecticut, I nc. Virginia Electric and Power Company Serial No. 06-1 070 Docket Nos. 50-305;SO-336/423,50-3381339;SO-2801281 Page 2 of 4 Attachments
- 3. Dominion - North Anna and Surry RAI Response Commitments made by this letter: None cc:: U. S. Nuclear Regulatory Commission Region 1 Regional Administrator 475 Allendale Road King of Prussia, PA 19406-1 41 5 U. S. Nuclear Regulatory Commission Region II Regional Administrator Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW Suite 23T85 Atlanta, Georgia 30303 U. S. Nuclear Regulatory Commission Region Ill Regional Administrator 2443 Warrenville Road Suite 210 Lisle, Illinois 60532-4352 Mr. R. F. Kuntz (Attachment 1 only)
Project Manager Kewaunee U. S. Nuclear Regulatory Commission, Mail Stop 7 DIA One White Flint North 1 1 555 Rockville Pike Rockville, MD 20852-2738 Mr. V. Nerses (Attachment 2 only) NRC Senior Project Manager Millstone Units 2 and 3 U. S. Nuclear Regulatory Commission, Mail Stop 8 B1 One White Flint North 1 1 555 Rockville Pike Rockville, MD 20852-2738 Serial No. 06-1 070 Docket Nos. 50-305;50-336142330-338133950-2801281 Page 3 of 4 Mr. S. P. Lingam (Attachment 3 only) NRC Project Manager North Anna and Surry U. S. Nuclear Regulatory Commission, Mail Stop 8 G9A One White Flint North 1 1 555 Rockville Pike Rockville, MD 20852-2738 Mr. S. C. Burton (Attachment 1 only) NRC Senior Resident lnspector Kewaunee Power Station Mr. S. M. Schneider (Attachment 2 only) NRC Senior Resident lnspector Millstone Power Station Mr. J. T. Reece (Attachments 3 only) NRC Senior Resident lnspector North Anna Power Station Mr. N. P. Garrett (Attachment 3 only) NRC Senior Resident lnspector Surry Power Station Serial No. 06-1070 Docket Nos. 50-305;50-336/423,50-338133950-2801281 Page 4 of 4 COMMONWEALTH OF VIRGINIA ) ) COUNTY OF HENRICO ) Tk~e foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Eugene S. Grecheck who is Vice President - Nuclear Support Services for Dominion Energy Kewaunee, Inc., Dominion Nuclear Connecticut, Inc. and Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of these Companies, and that the statements in the document are true to the best of his knowledge and belief.
72 Acknowledged before me this ,-$0 = day of 2007 w My Commission Expires: ( (SISAL)
ATTACHMENT 1 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION GENERIC LETTER 2006-02 GRID RELIABILITY AND THE IMPACT ON PLANT RISK AND THE OPERABILITY OF OFFSITE POWER (SERIAL NO. 06-1 070) DOMINON ENERGY KEWAUNEE KEWAUNEE POWER STATION DOCKET NO.
50-305 Serial No.
06-1 070 Docket No. 50-305 Attachment 1 KEWAUNEE RESPONSE REQUEST FOR ADDITIONAL INFORMATION RELATED TO GL 2006-02 Kewaunee was requested to respond to Questions 3 and 5 DEK Response:
RAI Topic 3 Verification of RTCA Predicted Post-Trip Voltage RAI Questions Your response to question 2(g) indicates that you have not verified by procedure the voltaaes predicted by the online grid analysis tool (software program) with actual real plant trip voltage values. It is important that the programs used for predicting post-trip voltage be verified to be reasonably accurate and conservative.
What is the ranae of accuracv for your GO's contingency analysis program? - Whv are you confident that the post-trip voltages calculated by the GO's contingency analysis program (that you are using to determine operability of the offsite power system) are reasonably accurate and conservative?
The Kewaunee Power Stations (KPS) grid operator (GO) is the American Transmission Company (ATC). The ATC does not determine the range of accuracy for its contingency analysis program. The predicted post-trip voltages are reported only by exception when the calculated values exceed predefined limits. Dominion Energy Kewaunee's (DEK) confidence in ATCs post trip voltage calculations comes from ATCs experience with many scheduled and forced outages across ATC's system (including at Kewaunee).
ATC has stated that of the many scheduled and forced outages there were no instances where the post-trip voltages violated pre-defined limits which were not already identified by the contingency analysis program.
Page 1 of 3 Serial No. 06-1070 Docket No. 50-305 Attachment 1 5 Seasonal Variation in Grid Stress (Reliability and Loss- of-Offsite-Power (LOOP) Probability)
-- - RA! Questions What is your standard of acceptance?
Certain regions during certain times of the year (seasonal variations) experience hiaher arid stress as is indicated in Electric Power Research Institute (EPRI) Report 101 1759, Table 4-7, Grid LOOP Adjustment Factor, and NRC NUREGICR-6890.
Do vou adiust the base LOOP frequency in your probabilistic risk assessment (PRA) and Maintenance Rule evaluations for various seasons? If you do not consider seasonal variations in base LOOP frequency in your PRA and Maintenance Rule evaluations, explain whv it is acceptable not to do so. Response DEK relies on the TSO (MISO) and the GO (ATC) to operate a state estimator and a RTCA program to evaluate the nuclear power plant contingency voltages. The state estimator and RTCA programs are utilized by MIS0 and ATC as tools for evaluating and maintaining the reliability of the transmission system. MIS0 and ATC utilize these tools as a means to satisfy their responsibilities as a North American Electric Reliability Council (NERC) Reliability Coordinator as delineated in NERC Standards IRO-002 and TOP- 006. The NERC Standards provide the standards with which the TSO (MISO) and GO (ATC) must comply.
The seasonal LOOP frequency is dominated by known and well- understood effects, including grid instability, severe weather and switchyard maintenance (which is performed more frequently in the spring and fall, when refueling outages are scheduled).
Rather than utilize a coarse seasonal penalty on the LOOP frequency in (a)(4) analyses, DEK increases the LOOP point estimate in the PRA model when these effects are present.
For example, grid stability is monitored by the plant operations staff, the system grid operator and the regional grid operator.
Observation of grid instability by any of these parties, as measured Page 2 of 3 Serial No. 06-1 070 Docket No. 50-305 Attachment 1 D-,,,,,, ntqJu1 IS= bv wedetermined setpoints, will procedurally initiate an update of the (a)(4) analysis.
Similarly, the LOOP frequency is also increased when the severe weather procedures are entered, or when switchyard maintenance is underway.
The DEK approach is the more accurate and preferable approach to modeling LOOP frequency variations.
A seasonal penalty could mask actual effects and de-sensitize the plant staff to increases in risk. This method goes above and beyond the regulatory requirement in NUMARC 93-01. Page 3 of 3 ATTACHMENT 2 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION GENERIC LETTER 2006-02 GRID RELIABILITY AND THE IMPACT ON PLANT RISK AND THE OPERABILITY OF OFFSITE POWER (SERIAL NO. 06-1 070) DOMINION NUCLEAR CONNECTICUT, INC. MILLSTONE POWER STATION UNITS 2 AND 3 DOCKET NOS. 50-3361423 Serial No. 06-1 070 Docket Nos. 50-3361423 Attachment 2 MILLSTONE RESPONSE REQUEST FOR ADDITIONAL INFORMATION RELATED TO GL 2006-02 Millstone was requested to respond to Questions 5 and 6 DNC Response:
RAI Topic 5 Seasonal Variation in Grid Stress (Reliability and Loss- of-Offsite-Power (LOOP) Probability)
RAI Questions Certain regions during certain times of the year (seasonal variations) experience hiaher grid stress as is indicated in Electric Power Research Institute (EPRI) Report 101 1759, Table 4-7, Grid LOOP Adjustment Factor, and NRC NUREGICR-6890.
Do vou adiust the base LOOP frequency in your probabilistic risk assessment (PRA) and Maintenance Rule evaluations for various seasons? If you do not consider seasonal variations in base LOOP frequency in your PRA and Maintenance Rule evaluations, ex~lain whv it is acceptable not to do so. Response Suggestions The seasonal LOOP frequency is dominated by known and well- understood effects, including grid instability, severe weather and switchyard maintenance (which is performed more frequently in the spring and fall, when refueling outages are scheduled).
Rather than utilize a coarse seasonal penalty on the LOOP frequency in (a)(4) analyses, Dominion Nuclear Connecticut, INC. (DNC) increases the LOOP point estimate in the PRA model when these effects are present. For example, grid stability is monitored by the plant operations staff, the system grid operator and the regional grid operator.
Observation of grid instability by any of these parties, as measured bv predetermined set~oints, will procedurally initiate an update of the (a)(4) analysis.
Page 1 of 2 6 Interface With Transmission System Operator During Extended Plant Maintenance 6a How do vou interface with your GO when on-going maintenance at the nuclear power plant, that has been previously coordinated with your GO for a definite time frame, gets extended past that planned time frame? Serial No. 06-1 070 Docket Nos. 50-3361423 Attachment 2 Similarly, the LOOP frequency is also increased when the severe weather procedures are entered, or when switchyard maintenance is underway.
The DNC approach is the more accurate and preferable approach to modeling LOOP frequency variations. A seasonal penalty could mask actual effects and de-sensitize the plant staff to increases in risk. This method goes above and beyond the regulatory requirement in NUMARC 93-01 . Millstone station has a procedure in place to coordinate maintenance with the grid operator.
The procedure details how maintenance activities are reviewed and approved in advance by both parties, along with direction on actions to take when changes to previously coordinated maintenance is extended past the planned time frame. The procedure details when written and verbal communications are utilized.
Page 2 of 2 ATTACHMENT 3 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION GENERIC LETTER 2006-02 GRID RELIABILITY AND THE IMPACT ON PLANT RISK AND THE OPERABILITY OF OFFSITE POWER (SERIAL NO. 06-1 070) VIRGINIA ELECTRIC AND POWER COMPANY NORTH ANNA AND SURRY POWER STATIONS DOCKET NOS. 50-3381339 AND 50-2801281 Serial No. 06-1 070 Docket Nos. 50-3381339 and 2801281 Attachment 3 NORTH ANNA AND SURRY RESPONSE REQUEST FOR ADDITIONAL INFORMATION RELATED TO GL 2006-02 North Anna was requested to respond to Questions 1, 3, 4, and 5. Surry was requested to respond to Questions 1, 4, and 5. Dominion Response:
RAI Topic 1 Switchyard Minimum Voltage RAI Questions In response to question 1 (g) you did not identify specific minimum switchyard voltage limits (kV) that you supplied to the local transmission entity. Please, provide the following information: What is the specific minimum acceptable switchvard voltaqe included in your protocol agreement with your grid operator (GO) and what was the basis for this value? North Anna The specified minimum acceptable post unit trip offsite switchyard voltage is 505kV. This value is included in both System Operations and Station Operations procedures.
The Degraded Voltage relays for North Anna monitor the 4160-volt emergency buses and have a nominal setting of 90 percent of 4160-volts with a nominal time delay of 56-seconds with no accident and 7.5-seconds with an accident. The voltage profile calculation demonstrates that the Degraded Voltage relays will not actuate at the post unit trip offsite switchyard voltage of 505kV. The minimum post unit trip voltage has been specified based on load flow analyses performed by the Electric Transmission department.
The voltage profile calculation has not utilized voltages below the minimum values provided by Electric Transmission. Operation with the minimum acceptable post unit trip offsite switchyard voltage below 505kV may provide acceptable voltage but is considered an unanalyzed condition.
Page 1 of 9 Serial No. 06-1 070 Docket Nos. 50-3381339 and 2801281 Attachment 3 RAI To~ic I RAI Questions your technical specification degraded voltage relay setpoints?
Surry The specified minimum acceptable post unit trip offsite switchyard voltages are 505kV (500kV yard) and 220kV (220kV yard). These values are included in both System Operations and Station Operations procedures. The Degraded Voltage relays for Surry monitor the 4160-volt emergency buses and have a nominal setting of 92.6 percent of 4160-volts with a nominal time delay of 60-seconds with no accident and 7-seconds with an accident. The voltage profile calculation demonstrates that the Degraded Voltage relays will not actuate at the post unit trip offsite switchyard voltages of 505kV and 220kV. The minimum post unit trip voltages have been specified based on load flow analyses performed by the Electric Transmission department.
The voltage profile calculation has not utilized voltages below the minimum values provided by Electric Transmission.
Operation with the minimum acceptable post unit trip offsite switchyard voltages below 505kV and 220kV may provide acceptable voltage but is considered an unanalyzed condition.
3 Verification of RTCA Predicted Post-Trip Voltage (North Anna only) The voltage profilecalculations demonstrate that the~egraded Voltage relays will not actuate at the post unit trip offsite Your response to question 2(g) indicates that you have not verified by procedure the voltaaes predicted by the online grid analysis tool (software program) with actual real plant trip voltage values.
It switchyard voltage of 505kV for North Anna and 505kV and 220kV for Surry. Page 2 of 9 Serial No. 06-1 070 Docket Nos.
50-3381339 and 2801281 Attachment 3 RAI To~ic RAI Questions is important that the programs used for predicting post-trip voltage be verified to be reasonably accurate and conservative.
What is the ranae of accuracv for your GO's contingency analysis program? !A& are you confident that the post-trip voltages calculated by the GO's contingency analysis program (that you are using to determine operability of the offsite power system) are reasonably accurate and conservative?
There is no established numerical range of accuracy for the transmission system operator's (PJM) contingency analysis program. However, state estimation and real time contingency analysis have been used for many years by PJM to aid in evaluating and maintaining transmission system reliability and are proven tools for analyzing transmission system contingencies.
Descri~tion of State Estimation and Relation to Real Time Continaencv Analvsis (RTCA) State estimation is an advanced application that is used to ensure that power system analysis that relies on complete power system models can be performed even when incomplete or conflicting data is received from the sensing devices in the field. Basically, the state estimator (SE) compares actual field data to an expected value based on the power system model resident in the application.
If the actual data is unavailable or out of its expected range, the SE will calculate a value and substitute it into the power system model, creating a SE solution, so that other applications (e.g., RTCA) can provide reasonable results. The relevance of the SE to the post-contingency voltage calculation discussion is that the SE results are used as the input to the real time contingency analysis (RTCA).
The RTCA takes the SE solution and calculates post-contingency flows, voltages Page 3 of 9 RAI To~ic RAI Questions Serial No. 06-1070 Docket Nos. 50-3381339 and 2801281 Attachment 3 Response and voltage drops for each contingency in the contingency list (in PJM's case, the RTCA analyzes about 4,000 contingencies, approximately every 2 minutes).
However, without a valid SE solution, the RTCA is not possible.
On rare occasions, the SE is not able to provide a valid solution due to the magnitude of missing, conflicting, or inaccurate data. Normally, such events are caused by communications or equipment failure in the field. In these cases, PJM is required to notify the transmission owners (TOs) that PJM's capability to calculate the necessary nuclear plant post-contingency voltages is temporarily unavailable and that PJM will be deferring to the TO'S RTCA results. (Refer to PJM Manual M-01 Control Center, Section 2, pg 14.) If both PJM and the TO lose the capability to perform RTCA, the impacted nuclear power plants are notified.
At that point the NPP would enter the abnormal procedure on grid instabilities.
Advanced applications, like the SE and the RTCA, are critical to executing PJM's tasks as a Reliability Coordinator.
All Reliability Coordinators are required to have such tools to be in compliance with NERC Standard IRO-002, Reliability Coordination-Facilities.
Requirements addressing the accuracy and capability of field sensors and communications systems that feed the SE are covered in PJM Manual M-01, Control Center Requirements, and are necessary to be compliant with NERC Standard TOP-006, Monitoring System Conditions.
Issues related to SE accuracv Input Data Accuracy Continuous and accurate input data is critical to the proper Page 4 of 9 RAI Topic RAI Questions Serial No. 06-1 070 Docket Nos. 50-3381339 and 2801281 Attachment 3 Resoonse functioning of the SE. An accurate representation of the configuration of the grid components that actually exist in the field is essential. The data coming in from the sensors in the field must be accurately mapped to the correct elements in the SE model. Model Scope and Level of Detail The other key factor to ensuring accurate SE solutions is the scope and level of detail of the model.
The model must contain sufficient monitoring capability of its surrounding Reliability Coordinator areas to ensure that potential, actual operating limits are not violated.
Ste~s taken bv PJM to assure SE "accuracv" Given the issues stated above, PJM and its members take steps to ensure that the SE runs as accurately as possible, including the following: Overlapping coverage of PJM and member company state estimators In addition to PJM, the TOs have their own SEs running in parallel with the PJM SE. The respective models are different from a scope and level of detail standpoint, but the results obtained are generally close. If discrepancies between the two SEs are identified, PJM and the TO work together to correct the problem. During the interim period, the more conservative limit becomes the operational limit.
PJM works closely with the TOs and the generation owners to ensure the accuracy of the PJM data model.
PJM builds the updated model and verifies its accuracy in a test environment Page 5 of 9 Serial No.
06-1070 Docket Nos. 50-3381339 and 2801281 Attachment 3 RAI Topic RAI Questions before installing the updated model in the production system. Model updates are performed on a quarterly basis. 4 Identification of Applicable Single Contingencies Review of post-contingency parameters prior to switching Prior to switching transmission equipment out of service, the PJM operator is required to calculate the post-switching system parameters in the vicinity of the switching using RTCA. This step is taken to ensure that the switching will not result in a reliability problem. Once the switching has been done, the operator monitors the post-switching parameters, providing a near real time comparison to what RTCA predicted. Seldom does that comparison yield an unexpected result, attesting to the accuracy of the SE and RTCA solution.
Any case that does yield an unexpected result is investigated and understood.
Corrective actions are then taken, as appropriate.
In response to question 3(a) you did not identifv the loss of other critical transmission elements that may cause the offsite power system (OSP) to Dominion relies on the TSO (PJM) to operate a state estimator and a RTCA program to evaluate the nuclear power plant contingency voltages. The state estimator and RTCA program are utilized by the TSO (PJM) as tools for evaluating and maintaining the reliability of the transmission system.
PJM utilizes these tools as a means to satisfy their responsibilities as a North American Electric Reliability Council (NERC) Reliability Coordinator as delineated in NERC Standards IRO-002 and TOP-006. The NERC Standards provide the standard of acceptance with which the TSO (PJM) must comply. The RTCA monitors all critical transmission elements and OSP. With all transmission elements available, no single element loss results in a degraded OSP. All planned transmission element outages are studied in advance by both Dominion and PJM to ensure no problems will arise from any additional single Page 6 of 9 Serial No. 06-1 070 Docket Nos. 50-3381339 and 2801281 Attachment 3 RAI To~ic RAI Questions degrade, other than the loss of the nuclear unit. If it is possible for specific critical transmission elements (such as other generators, critical transmission line, transformers, capacitor banks, voltage regulators, etc.) to degrade the OSP such that inadequate post-trip voltage could result, have these elements been included in your N-1 contingency analysis?
When these elements are included in your GO'S contingency analysis model and failure of one of these transmission elements could result in actuation of your degraded voltage grid relay, is the offsite Dower declared inoperable?
Response contingency. Both plants are in very voltage-stable locations on the system. The Dominion TO would not knowingly permit transmission element outages that would place the transmission grid at a point where one additional loss/outage would potentially create problems with switchyard voltage at a nuclear plant.
All critical transmission elements (such as other generators, critical transmission lines, transformers, etc.) have been included in the N-1 contingency analysis.
As noted above, all planned transmission element outages are studied in advance by both Dominion and PJM to ensure no problems will arise from any additional single contingency.
Both plants are in very voltage-stable locations on the system. The Dominion TO would not knowingly permit transmission element outages that would place the transmission grid at a point where one additional loss/outage would potentially create problems with switchyard voltage at a nuclear plant. However, even if the loss of a transmission element (other than a NPP) could cause the actuation of the degraded voltage relays, offsite power would not automatically be declared inoperable. When notified of grid instabilities, a NPP will enter an Abnormal Procedure that will guide in evaluating the plant condition and the required actions to ensure safe plant operation.
Page 7 of 9 Serial No. 06-1070 Docket Nos.
50-3381339 and 2801281 Attachment 3 RAI Topic 5 Seasonal Variation in Grid Stress (Reliability and Loss- of-Offsite-Power (LOOP)
Probability)
RAI Questions What is your basis for not declaring the offsite power inoperable? Certain regions during certain times of the year (seasonal variations) experience hiaher arid stress as is indicated in Electric Power Research Institute (EPRI) Report 1 01 1759, Table 4-7, Grid LOOP Adiustment Factor, and NRC NUREGICR-6890. . Do you adiust the base LOOP frequencyin your probabilistic risk assessment (PRA) and Maintenance Rule evaluations for various seasons? If you do not consider seasonal variations in base LOOP frequency in your PRA and Maintenance Rule evaluations, explain why it is acceptable not to do so. Reseonse Predicted contingency voltages following loss of a transmission element (other than a NPP) are not used as the basis for offsite power operability determinations.
Postulated contingency voltages on the transmission system are not used as the basis for offsite power operability determination.
Such events are only postulated and have not actually occurred, therefore the offsite sources remain capable of supporting a safe shutdown and mitigating the affects of an accident. The seasonal LOOP frequency is dominated by known and well- understood effects, including grid instability, severe weather and switchyard maintenance (which is performed more frequently in the spring and fall, when refueling outages are scheduled).
Rather than utilize a coarse seasonal penalty on the LOOP frequency in (a)(4) analyses, Dominion increases the LOOP point estimate in the PRA model when these effects are present. Page 8 of 9 RAI Topic RAI Questions Serial No. 06-1 070 Docket Nos. 50-3381339 and 2801281 Attachment 3 For example, grid stability is monitored by the plant operations staff, the system grid operator and the regional grid operator.
Observation of grid instability by any of these parties, as measured bv redetermined set~oints, will procedurally initiate an update of the (a)(4) analysis.
Similarly, the LOOP frequency is also increased when the severe weather procedures are entered, or when switchyard maintenance is underway.
The Dominion approach is the more accurate and preferable approach to modeling seasonal LOOP frequency variations.
A seasonal penalty could mask actual effects and de-sensitize the plant staff to increases in risk. This method goes above and beyond the regulatory requirement in NUMARC 93-01. Page 9 of 9