L-2011-021, St. Lucie, Unit 2 - License Amendment Request for Extended Power Uprate, Attachment 5, Appendix C, Grid Stability Analysis and System Impact Study for St. Lucie Plant with Proposed EPU

St. Lucie, Unit 2 - License Amendment Request for Extended Power Uprate, Attachment 5, Appendix C, Grid Stability Analysis and System Impact Study for St. Lucie Plant with Proposed EPU

ML110730303
Person / Time
Site:	Saint Lucie
Issue date:	02/25/2011
From:	Florida Power & Light Co
To:	Office of Nuclear Reactor Regulation
References
L-2011-021
Download: ML110730303 (42)

Text

Grid Stability Analysis for St. Lucie Plant with Proposed EPU In accordance with section 2.3.2 of NRC document RS-001, a grid stability study was performed for the St. Lucie Nuclear Power Pl ant (St. Lucie) with the proposed extended power uprate (EPU). The St. Lucie study focu sed on whether the loss of the nuclear unit, the largest operating generating facility on the grid, or the most critical transmission line will result in the loss-of-offsite power (LOOP) to the plant following implementation of the proposed EPU. The NRC's acceptance criteria for offsite power systems are based on GDC-17. Specific review criteria are contained in SRP sections 8.1 and 8.2, and Appendix A to SRP section 8.2, and Branch Technical Positions (BTPs) PSB-1 and ICSB-11. The information in this report is intended to upda te section 8.2.2 analysis section of the St.

Lucie FSAR.

Analysis Procedure Contingencies were selected to conform to USNRC Standard Review Plan 8.2-III. 1.f.

Several cases were analyzed for each of the single event outage types specified in the SRP. The most up-to-date transmission model representing projected 2012 summer peak load conditions was used. Additional non-firm transfers were modeled in the 2012 summer peak load case to bring the total Florida import le vel up to the transfer limit of 3600 MW. This represents the most conservative scenario.

The PTI dynamic simulation software (PSS/E rev.30) was used to simulate the outage events. The simulation results were analyzed for any sign of instability, protective relay action or load shedding. The figures accompanying the simulation results show the St.

Lucie plant and transmission system response to the contingency events modeled. Each figure is divided into four parts which show voltage magnitude, machine angle, bus frequency, and line flows.

Power flow analysis of the post transient condition for each case was done using the PTI load flow program (PSS/E rev.30) This analysis was used to assess whether the event

causes any voltage or line loading violations. The power flow results are summarized in Table 1.

Conclusions The results of this study indicate that the thermal, voltage, and stability performance is not degraded by implementation of the EPU. The transmission system and St. Lucie response is stable for all of the contingency events simulated. None of the outage events m odeled cause transmission voltages or line loadings to exceed ratings.

1 Dynamic Stability Results Loss of the largest source

Case 1 - The largest power source within the Florida interconnected power system is the St. Lucie #2 generator, which is modeled with a gross output of 1072 MW. The sudden trip of St. Lucie #2 is modeled in case 1. A St. Lucie #2 auxiliary load of 49 MW

and 33 MVAR is left connected to the St. Lucie 230 kV bus.

System response is stable. The frequenc y briefly dips to 59.91 Hz and settles at 59.99 hertz. This response is consistent with obs erved response of the grid. The decline in machine angles is due to the slight decline in overall grid frequency. Machine angles are calculated relative to a fixed 60 hertz source with this simulation software. No transmission overloads, generator reactive overloads or voltage problems are caused by this outage.

Case 2 - St. Lucie #1 is assumed to be off line with its capacity replaced by increased generation at the Martin, Manatee a nd Sanford power plants. The sudden trip of St. Lucie #2 is modeled in case 2. A total St. Lucie auxiliary load of 98 MW and 65

MVAR is left connected to the St. Lucie 230 kV bus.

System response is stable. The St. Lucie 230 kV bus voltage drops from 104.2% (of 230 kV) to 102.9%. The frequency briefly dips to 59.94 Hz and settles at 59.99 hertz. This response is consistent with observed response of the grid. No transmission overloads, generator reactive overloads or voltage problems are caused by this outage.

Loss of the most critical transmission circuit

Case 3 - The St. Lucie-Midway 230 kV #3 is faulted and tripped in case 3. A three phase fault at the St. Lucie end of this circuit is disconnected after a total fault duration of 0.067 seconds (normal fault clearing time). The same system response would occur for an outage of either the #1 or #2 circuits as the three St. Lucie-Midway 230 kV circuits have nearly identical impedances.

System response is stable. The #1 circuit loading increases to 968 MVA and the #2 circuit

loading increases to 959 MVA. These loadings are well within their 1111 MVA ratings.

No transmission overloads, generator reactive overloads or voltage problems are caused by

this outage.

Case 4 - The Midway 500/230 kV autotransformer is faulted and tripped in case 4.

A three phase fault on the 230 kV side is di sconnected after a total fault duration of 0.067 seconds (normal fault clearing time). The Midway 500/230 transformer could be regarded as the most critical transmission circuit affecting the St. Lucie plant.

2 System response is stable. No transmission overloads, generator reactive overloads or voltage problems are caused by this outage.

Case 5 - The Duval - Thalmann 500 kV circuit is faulted and tripped in case 5. A three phase fault is modeled on the Duval side. The fault is disconnected after a total fault duration of 0.05 seconds (normal fault clearing time). The Duval-Thalmann 500 kV circuit could be regarded as the most critical transmission circuit affecting the Florida transmission system as this contingency frequently sets the Georgia to Florida transfer limit.

System response is stable. No transmission overloads, generator reactive overloads or voltage problems are caused by this outage.

Loss of the largest load Case 6 - The Andytown-Nobhill 230 kV circuit is faulted and tripped in case 6. This disconnects five distribution stations with a total load of 231 MW. This is the largest amount of load served from one transmission circuit during 2012 summer peak load conditions.

System response is stable. The rise in machin e angles is due to the slight increase in overall grid frequency. No transmission overloa ds, generator reactive overloads or voltage problems are caused by this outage.

Case 7 - The Nobhill station is isolated by tripping the Andytown-Nobhill and Conservation-Nobhill 230 kV circuits. This disconnects six distribution stations with a total load of 372 MW. This is the largest am ount of load that can be interrupted by the outage of a single transmission system element.

System response is stable. No transmission overloads, generator reactive overloads or voltage problems are caused by this outage.

3 4 Table 1 - Power Flow Analysis

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GENERATION INTERCONNECTION SERVICE And NETWORK RESOURCE INTERCONNECTION SERVICE

SYSTEM IMPACT STUDY FPL EXTENDED POWER UPRATE PROJECTS ST. LUCIE 1 & 2

Q114 & Q115 REVISED 9/17/2010 Revision Date Original study document November 24, 2008 Incorporated results of St. Lucie switchyard string bus study September 17, 2010 1

Summary: In accordance with the Standard Large Generator Interconnection Procedures Florida Power & Light Company ("FPL") has completed a Generation Interconnection Service ("GIS") System Impact Study ("SIS") regarding the increased power output of the St. Lucie 1 extended power uprate project ("SL1EPUP") & St. Lucie 2 extended power uprate project ("SL2EPUP") associated with FPL's GIS queue requests No.114 & No.115 respectively, to the FPL Transmission System and an attendant request for Network Resource Interconnection Service

("NRIS"). GIS queue reque st 114 is for an increase in the cap acity of the existi ng St. Lucie unit 1 from 905 MW gross to a maximum potential cold winter output of 1052 MW gross. GIS queue request 115 is for an increase in the capacity of the existing St. Lucie unit 2 from 905 MW gross to a maximum potential cold winter output of 1072 MW gross.

As delineated in the SIS Agreement, the purpose of the SIS was to provide:

Identification of any circuit breaker short circuit capability limits exceeded as a result of SL1EPUP and SL2EPUP; Identification of any thermal overload or voltage limit violations resulting from SL1EPUP and SL2EPUP; and Identification of any instability or inadequately damped res ponse to system disturbances resulting from the interconnection; and A description and non-binding estimated cost of facilities required to integrate SL1EPUP and SL2EPUP to the FPL Transmission System and to address the identified short circuit, instability and power flow issues that the request to increase the power output of the proposed SL1EPUP and SL2EPUP may create on the FPL Transmission System.

The performance of the SIS consisted of a:

Reactive Power Capability Analysis; Short Circuit Analysis; Analysis of NRIS request for SL1EPUP and SL2EPUP; Dynamic Stability Analysis; Southern/Florida Transmission Interface Assessment; and Transmission Project's Facilities Cost Estimate consisting of:

-Substation Facilities Cost Estimate;

-Protection and Control Facilities Cost Estimate; and

-Transmission Facilities Cost Estimate.

In summary the results of the SIS are as follows:

Reactive Power Capability Analysis

The reactive capability of the units was analyzed. The analysis recognized that the units' current reactive capability is grandfathered as acceptable, and that the SL1EPU P and SL2EPUP projects' incremental increase in MW output to the FPL transmission system must meet the requirements of the Standard Large Generato r Interconnection Procedures in FPL's OATT. In order to determine whether the incremental increase in MW output of each unit meets the requirements, a 2

comparison was made between the existing units' reactive capabilities, and the uprated units' reactive capabilities. Each unit is recognized as meeting the requirements provided that the uprated unit does not increase a current MVar deficiency in reactiv e capability. Any improvement in a current MVar deficiency as a result of the uprates is credited to the existing deficiency and not considered to be the uprated portion exceeding the requirement. The reactive capability following the uprates must be maintained at the new design capability specified in the data submittal. Based upon these criter ia the analysis results were that:

The SL1EPUP uprate meets the reactive capability requirements. The SL2EPUP uprate meets the reactive capability requirements.

Short Circuit Analysis Fault current levels did not exceed the rating of any circuit breakers as a result of the SL1EPUP and SL2EPUP GIS request.

These results are predicated on upgrades to the FPL system attributed to preceding GIS requests being in place prior to the incr ease in power output of the SL1EPUP and SL2EPUP. Withdrawal of one or more of these preceding GIS requests may result in SL1EPUP and/or SL2EPUP being responsible for such breaker upgrades and/or substation reconfigurations. FPL will advise SL1EPUP and SL2EPUP of any changes associated with preceding GIS requests that may require a re-study of the GIS request for the SL1EPUP and SL2EPUP.

Please refer to Appendix I for detailed results.

Provision of NRIS for SL1EPUP

Based on the current status of FPL's GIS queue and transmission servi ce requests the following are the results of this part of the evaluation: The integration of SL1EPUP as an FPL network resource does not require upgrading of the existing facilities or construction of new facilities.

Provision of NRIS for SL2EPUP Based on the current status of FPL's GIS queue and transmission servi ce requests the following are the results of this part of the evaluation: The integration of SL2EPUP as an FPL networ k resource requires an increase in the thermal rating of the existing St. Lucie-Midway #1, St. Lucie-Midway #2, and St. Lucie-Midway #3 230 kV lines. Transmission line conductor ampacity of 3050A (185F/85C) for the

2X1691AAAC and 3395A (239F/115C) for the 3400ACSR is limited to 2790 A due to clearances. Therefore, the three St. Lucie-Midway line ratings will be increased from 2380A to 2790A.

Please refer to Appendix II for detailed results.

3 4 Dynamic Stability Analysis The existing BFBU total clearing time at Midw ay 230kV substation of 9.9 cycles is adequate. The existing BFBU total clearing time at St. Lucie 230kV substation of 8.8 cycles is adequate. Stabilizers are required for St. Lucie #1 and #2 units to improve oscillations damping. Results of the dynamic simulati ons indicate acceptable performance for the most extreme NERC Category D event at Midway substation. The most severe fault at Midway substation is on the Midway 500/230kV auto with delayed clearing for breaker failure. Similar to the existing performance without the upgrades, the St. Lucie #1 and #2 units lose synchronism and trip after the fault is cleared however the transmission system remains stable, which is acceptable performance for the NERC Category D extreme event. It is recommended that all future breaker replacements at Midway 230kV substation use Independent Pole Operated breakers to improve system performance for extreme events.

Please refer to Appendix III for detailed results.

Southern/Florida Transmission Interface Assessment

The principal finding of this analysis is that the SL1EPUP and SL2EPUP projects will not

adversely affect the current Southern to Florida import capability of 3600 MW in the 2012 timeframe. In addition, the 4100 MW transfer case also indicates acceptable performance for the outage of the St. Lucie #2 unit. Based on this analysis it appears that the Southern/Florida transmission interface in the 2012 time frame will be more robust and thus able to accommodate a larger generator outage within the FRCC Region. Based on past studies for previously queued Transmission Service Requests (TSRs), the most severe contingency affecting the SO/FL interface at the increased transfer level of 4100 MW is the outage of the Duval-Thalmann 500 kV tie line as opposed the near term studies at a 3600 MW SO/FL transfer level that shows the most severe outage being the loss of an 800 - 900 MW class generating unit outage in Florida. Please refer to Appendix IV for detailed results.

Transmission Project's Facilities Cost Estimate

The total non-binding, good faith estimate to upgrade the existing FPL Transmission System to accommodate the uprates excluding the GSU improvements, is

$11.5 Million. The estimates for Unit #1 are escalated to 2011 dollars and the estimates for Unit #2 are escalated to 2012 dollars.

Please refer to Appendix V for detailed scope of work.

APPENDIX I SHORT CIRCUIT ANALYSIS 5

I. SHORT CIRCUIT ANALYSIS FOR SL1EPUP-Q114 PURPOSE: Determine the impact on breaker interrupting ca pability at FPL's substations due to the SL1EPUP-Q114 as specified in the fo llowing configuration (See Figure A).

Figure A - SL1EPUP - Q114

• 889/905 MW*1032/1052 MW* Summer/Winter gross continuous MW capability In-service Date11-24-2011Uprate-Q114 METHODOLOGY: The analysis was performed using PSS/E application for automatic sequence fault calculation for three phase and phase to ground fa ults. Fault calculations were performed with a line outage condition (each line outaged individually), where applicable, on all buses in FPL's area. The breaker duty fault current was determined by taki ng the larger of the two, three phase or single phase fault currents.

The breaker duty fault current was then compared to the breaker interrupting capability in order to determine if any breaker(s) needed to be upgraded. In circumstances where the study case fault current levels exceeded the mid-breaker rating an additional analysis was performed in order to determine the breaker duty for such mid-breakers.

6 ASSUMPTIONS:

Base Case Given the SL1EPUP in-service date of June 2011, the 2011-year Summer Case (based on the most recent available FRCC Transmission Working Group case) was used as the Base Case.

This Base Case represents late summer 2011 a nd reflects changes in lo ad, generation capacity, and transmission capacity that have been planne d through such period in time. In addition, the Base Case was modified to reflect preceding GIS requests, and the attendant incremental facilities necessary for such preceding GIS requests that may potentially have a material impact on the results of this analysis.

Study Case The Study Case was derived from the aforementioned Base Case while also modeling SL1EPUP. SL1EPUP is modeled as one generating unit with a gross summer capacity of 1032MW, 1200 MVA connected to St. Lucie 230 kV switchyard. See Figure A.

FINDINGS In the Study Case the breaker duty did not exce eded the rating of any existing circuit breakers as a result of the SL1EPUP GIS request. The following table below shows the impact of SL1EPUP on fault current levels at Mi dway and St. Lucie 230 kV substations:

STATION kV Rating kA STUDY kA kA prior to SL1EPUP Midway 230 63 57.3 57.1 St. Lucie 230 63 45.0 44.6 II. SHORT CIRCUIT ANALYSIS FOR SL2EPUP-Q115 PURPOSE: Determine the impact on breaker interrupting ca pability at FPL's substations due to the SL2EPUP-Q115 as specified in the fo llowing configuration (See Figure B).

7 Figure B - SL2EPUP - Q115

• 1052/1072 MW*1032/1052 MW* Summer/Winter gross continuous MW capability In-service Date11-24-2011Uprate-Q114 In-service Date6-24-2012Uprate-Q115 METHODOLOGY: The analysis was made using PSS/E application for automatic sequence fault calculation for three phase and phase to ground faults. Fault calculations were performed with a line outage condition (each line outaged individually), where applicable, on all buses in FPL's area. The breaker duty fault current was determined by taking the larger of the two, three phase or single phase fault currents.

The breaker duty fault current was then compared to the breaker interrupting capability in order to determine if any breaker(s) needed to be upgraded. In circumstances where the study case fault current levels exceeded the mid-breaker rating an additional analysis was performed in order to determine the breaker duty for such mid-breakers.

ASSUMPTIONS:

Base Case Given the SL2EPUP in-service date of Dec. 2012, the 2013-year Summer Case (based on the most recent available FRCC Transmission Working Group case) was used as the Base Case.

This Base Case represents late summer 2013 a nd reflects changes in lo ad, generation capacity, 8 and transmission capacity that have been planned through such period in time. In addition, the Base Case was modified to reflect preceding GIS requests, including SLIEPUP, and the attendant incremental facilities necessary for such preceding GIS requests that may potentially have a material impact on the results of this analysis.

Study Case

• The Study Case was derived from the aforementioned Base Case while also modeling SL2EPUP. SL2EPUP is modeled as one generating unit with a gross summer capacity of 1052MW, 1200 MVA connected to St. Lucie 230 kV switchyard.

See Figure B. FINDINGS

• In the Study Case the breaker duty did not exceeded the rating of any existing circuit breakers as a result of the SL2EPUP GIS request..

The following table below shows the impact of SL2EPUP on fault current levels at Midway and St. Lucie 230 kV substations:

Rating Study kA prior STATION kV kA kA to SL2EPUP Midway 230 63 58.6 58.4 St. Lucie 230 63 46.8 46.2 9 10

APPENDIX II NRIS ASSESSMENT

SL1EPUP NRIS Assessment:

PURPOSE Determine the transmission system additions/mod ifications for the proposed SL1EPUP to be integrated as an FPL's Network Resource.

SUMMARY

This project consists of one generating unit with a maximum potential cold winter continuous capability of 1052 MW and a November 2011 in-service date. See Figure C below.

Figure C - SL1EPUP - Q114

• 889/905 MW*1032/1052 MW* Summer/Winter gross continuous MW capability In-service Date11-24-2011Uprate-Q114 The integration of SL1EPUP as a Network Res ource does not require upgrading of the existing facilities or construction of new facilities.

METHODOLOGY:

The study was performed by conducting a single contingency power flow analysis. All systems elements 69kV or higher in the FRCC region were simulated for NERC Category A and B contingency scenarios. Overloads greater than 100% of a facility rating that is materially aggravated (more than 3%) when compared to th e reference case or overloads that were not existing in the reference case, for the same contingency, are attributed to SL1EPUP. Similarly, 11 low voltages, less than 0.95 p.u., that were materi ally lower (more than 2%) when compared to the reference case, for the same con tingency, are attributed to SL1EPUP.

In addition, multiple contingencies were simulated for NERC Category C scenarios. The study was performed by conducting a multiple contingency power flow analysis. All systems elements 100kV or higher in the FPL East region were simulated for NERC Category C2, C3 and C5 contingency scenarios. Following the FRCC me thodology of analyzing ove rloads greater than 130% for Category C3 and greater than 100% for Category C2 and C5 of a facility rating that is materially aggravated (more than 3%) when comp ared to the reference case or overloads that were not existing in the reference case, for the same contingency, are attributed to SL1EPUP or SL2EPUP. Similarly, low voltages, less than 0.90 p.u., that were materially lower (more than 2%) when compared to the reference case, for the same contingency, are attributed to SL1EPUP or SL2EPUP.

The latest available peak case for the winter of 2011 from the 2008 FRCC databank (FY08 Rev3) with firm long-term contractual obligations was used to create a base case for the power flow analysis. This case was updated to include the most up-to-date information on the FPL system (e.g., planned new transmission facilities and upgrades, committed new generation, confirmed transmission service obligations, etc.). The update d base case was then modified to incorporate relevant preceding GIS requests and transmission service requests.

The Study Case was derived from the aforementioned Base Case while also modeling SL1EPUP. SL1EPUP is modeled as one steam generating unit with a maximum potential cold winter gross capacity of 1052MW.

FINDINGS: The results of the contingency power flow analysis show that there were no overloads of facilities that resulted from SL1EPUP. Al so, no existing overloads in the cases were materially aggravated (more than 3%) due to the SL1EPUP. Similarly, there were no low voltages observed that were materially lower (lower than 2%) due to the SL1EPUP.

Note that these results are based on the current FPL GIS and transmission service queue which includes requests preceding the SL1EPUP GIS request. To the extent that one or more of these

requests are modified or withdraw n, the results presented in this analysis may no longer apply to this request and may change materially. FPL will advise SL1EPUP of any changes associated with preceding GIS requests that may require a re-study of the GIS request for the SL1EPUP.

CONCLUSION Based on the current status of FPL's GIS queue and transmission servi ce requests the following are the results of this part of the evaluation:

The integration of SL1EPUP as a Network Resource does not require upgrading of the existing facilities or construction of new facilities.

12 SL2EPUP NRIS Assessment:

PURPOSE Determine the transmission system additions/modifications to integrate SL2EPUP as an FPL Network Resource.

SUMMARY

This project consists of one generating unit with a maximum potential cold winter gross continuous capability of 1072 MW and a June 2012 in-service date. See Figure C below.

Figure C - SL2EPUP - Q115

• 1052/1072 MW*1032/1052 MW* Summer/Winter gross continuous MW capability In-service Date11-24-2011Uprate-Q114 In-service Date6-24-2012Uprate-Q115 The integration of SL2EPUP as an FPL network resource requires an increase in the thermal rating of the existing St. Lucie-Midway #1, St. Lucie-Midway #2, and St. Lucie-Midway #3 230 kV lines. Transmission line conductor ampacity of 3050A (185F/85C) for the 2X1691AAAC and 3395A (239F/115C) for the 3400ACSR is limited to 2790 A due to clearances. Therefore, the three St. Lucie-Midway line ratings will be increased from 2380A to 2790A.

13 METHODOLOGY:

The study was performed by conducting a single contingency power flow analysis. All systems elements 69kV or higher in the FRCC region were simulated for NERC Category A and B contingency scenarios. Overloads greater than 100% of a facility rating that is materially aggravated (more than 3%) when compared to th e reference case or overloads that were not existing in the reference case, for the same contingency, are attributed to SL2EPUP. Similarly, low voltages, less than 0.95 p.u., that were materi ally lower (more than 2%) when compared to the reference case, for the same con tingency, are attributed to SL2EPUP.

In addition, multiple contingencies were simulated for NERC Category C scenarios. The study was performed by conducting a multiple contingency power flow analysis. All systems elements 100kV or higher in the FPL East region were simulated for NERC Category C2, C3 and C5 contingency scenarios. Following the FRCC me thodology of analyzing ove rloads greater than 130% for Category C3 and greater than 100% for Category C2 and C5 of a facility rating that is materially aggravated (more than 3%) when comp ared to the reference case or overloads that were not existing in the reference case, for the same contingency, are attributed to SL1EPUP or SL2EPUP. Similarly, low voltages, less than 0.90 p.u., that were materially lower (more than 2%) when compared to the reference case, for the same contingency, are attributed to SL1EPUP or SL2EPUP.

The latest available peak cases for the summer and winter of 2012 from the 2008 FRCC databank (FY08 Rev 3) with firm long-term contractual obligations were used to create base cases for the power flow analysis. These cases were updated to include the most up-to-date information on the FPL system (e.g., planned new transmission facilities and upgrades, committed new generation, confirmed transmission service oblig ations, etc.). The updated base cases were then modified to incorporate relevant preceding GIS requests and transmission service requests. The Study Cases were derived from the aforementioned Base Cases while also modeling SL2EPUP. SL2EPUP is modeled as one steam generating unit with a maximum potential cold winter/summer gross capacity of 1072/1052MW.

Category B Results:

The results of the contingency power flow analys is show the following overl oads as a result of SL2EPUP:

2012 Summer Case No Overloads as a result of SL2EPUP

2012 Winter Case Contingency Violation Overload (%) Rating (MVA @ 230kV) Comments Loading w/ upgrade (%) St. Lucie-Midway #2 230 kV St. Lucie-Midway #1 230 kV 101.1 948 Need to upgrade 80.2 St. Lucie-Midway #1 230 kV St. Lucie-Midway #2 230 kV 100.7 948 Need to upgrade 79.9 Slight differences in system impedances caused the St. Lucie-Midway #3 circuit to be loaded slightly below its thermal rating under contingency; however the line is recommended to be upgraded with the #1 and #2 circuits.

14 There were no low voltages observed that were materially lower (lower than 2%) due to the SL2EPUP.

Note that these results are based on the current FPL GIS and transmission service queue which includes requests preceding the SL2EPUP GIS request. To the extent that one or more of these

requests are modified or withdraw n, the results presented in this analysis may no longer apply to this request and may change materially. FPL will advise SL2EPUP of any changes associated with preceding GIS requests that may require a re-study of the GIS request for the SL2EPUP.

Category C Results:

The results of the multiple contingency power flow analysis show that there were no Category C2 or C5 overloads of facilities that resulted from SL1EPUP or SL2EPUP. Also, no existing overloads in the cases were materially aggravated (more than 3%) due to the SL1EPUP or SL2EPUP. Similarly, there were no low voltages observed that were materially lower (lower than 2%) due to the SL1EPUP or SL2EPUP. Below ar e the results of the Category C3 contingency power flow analysis which indicate the following overloads as a result of SL1EPUP and

SL2EPUP: Category C3 Results:

Table 1 - Thermal Overload s for 2011 Winter Case N-2 Contingency Violation Overload (%) Rating (MVA @230kV) % Loading prior to SL1EPUP % Loading w/upgrade to 2790A Comments D:MIDWAY -ST LUCIE1 +MIDWAY -ST LUCIE2 MIDWAY - ST LUCIE 230 3 184.6 948 170.1 157.4 reduce generation at St. Lucie

& increase generation in the Southeast D:MIDWAY -ST LUCIE1 +MIDWAY -ST LUCIE3 MIDWAY - ST LUCIE 230 2 184.6 948 170.1 157.4 reduce generation at St. Lucie

& increase generation in the Southeast D:MIDWAY -ST LUCIE2 +MIDWAY -ST LUCIE2 MIDWAY - ST LUCIE

230 1 184.5 948 170.1 157.3 reduce generation at St. Lucie

& increase generation in the

Southeast Table 2 - Thermal Overloads for 2012 Summer Case N-2 Contingency Violation Overload (%) Rating (MVA @230kV) % Loading prior to SL2EPUP % Loading w/upgrade to 2790A Comments D:MIDWAY -ST LUCIE1 +MIDWAY -ST LUCIE2 MIDWAY - ST LUCIE

230 3 198.7 948 182.1 169.5 reduce generation at St. Lucie

& increase generation in the Southeast D:MIDWAY -ST LUCIE1 +MIDWAY -ST LUCIE3 MIDWAY - ST LUCIE

230 2 198.6 948 182.1 169.5 reduce generation at St. Lucie

& increase generation in the Southeast D:MIDWAY -ST LUCIE2 +MIDWAY -ST LUCIE2 MIDWAY - ST LUCIE

230 1 198.6 948 182.0 169.5 reduce generation at St. Lucie

& increase generation in the

Southeast D:EMERSON -

NIGHTHAW1 +HARTMAN -F PIERCE1 HARTMAN - LAWNWOOD 69 1 136.9 92 133.1 - Needs to be addressed by transmission owner D:HARTMAN -F PIERCE1 +MIDWAY -NIGHTHAW1 HARTMAN - LAWNWOOD 69 1 140.9 92 137.1 - Needs to be addressed by transmission owner D:MIDWAY -NIGHTHAW1 +F PIERCE-INDRIO 1 HARTMAN - LAWNWOOD 69 1 133.3 92 129.6 - Needs to be addressed by transmission owner 15 Category C3 contingencies allow for system adjustments to be performed after the first contingency in order to prepare for the sec ond contingency. For the loss of one St. Lucie-Midway circuit, either an emergency rating for each circuit to be capab le of carrying the two units at full output for a sufficient time that an operator could execute a mitigation plan prior to

the line rating being exceeded, or a pre- contingency system adjustment (lowering out put of the generating units) after the first contingency will be required in order to maintain compliance with NERC Reliability Standards FAC-010, and TPL-003. This will necessarily require a revision to the Transmission and Substations Power Supply department's "St. Lucie-Midway Transmission

Capacity and Plant Notification" procedure.

The revised procedure will be reviewed by Power Supply Operations and coordinated with St.Lucie Plant management, as required under the POWER SYSTEMS AND ST LUCIE PLANT TRANSMISSION SWITCHYARD INTERFACE AGREEMENT.

CONCLUSION Based on the current status of FPL's GIS queue and transmission servi ce requests the following are the results of this part of the evaluation:

The provision of NRIS for SL2EPUP requires an increase in the thermal rating of the existing St. Lucie-Midway #1, St. Lucie-Midway #2, and St. Lucie-Midway #3 230 kV lines. Transmission line conductor ampacity of 3050A (185F/85C) for the 2X1691AAAC and 3395A (239F/115C) for the 3400ACSR is limited to 2790 A due to clearances. Therefore, the three St. Lucie-Midway line ratings will be increased from 2380A to 2790A.

The revised rating of the lines and increased output of the St. Lucie units will require modification of Transmission and Substations Power Supply department's "St. Lucie-Midway Transmission Capacity and Plant Notification" procedure (See Attachment 1 below). The requirement to revise the procedure will be reviewed by Power Supply Operations and

coordinated with St.Lucie Plant management, as required under the POWER SYSTEMS AND ST LUCIE PLANT TRANSMISSION SWITCHYARD INTERFACE AGREEMENT.

16 TO: No! ... ' 2 , 2 t UNB y and Attachment 1 ATIOH' DA arch 26. J992 co TO: L LucIe Plant or any chan 10 !be swus of tneUUC:lO

• tor die condldoo.s l1.sled. (011 , ..,'P 6.5 '-Of .IO'P Of 1 unlt lh 1 or crl or unit. 17 1I Cho plaru should be placed In 18

APPENDIX III DYNAMIC STABILITY ANALYSIS

SUMMARY

A dynamic stability analysis was performed fo r the SL1EPUP and SL2EPUP (GIS # 114 & 115) as seen in figure A below. The study was performed for the maximum potential cold winter capability of 1052 MW gross for SL1EPUP and 1072 MW gross for SL2EPUP.

Figure A

• 1052/1072 MW*1032/1052 MW* Summer/Winter gross continuous MW capability In-service Date11-24-2011Uprate In-service Date6-24-2012Uprate

ASSUMPTIONS

Dynamic simulations were performed using the la test available 2012 summer peak base case at a peak load and off peak (50% of peak) load levels with existing commitments of all the companies in Florida. The study cases assumed the connection of the relevant GIS requests

preceding the SL1EPUP AND SL2EPUP (and attendant incremental facilities for each such GIS request) in the base case that may have an impact on the SL1EPUP AND SL2EPUP stability.

In the study cases SL1EPUP AND SL2EPUP units (GIS #114 & 115), with the maximum potential cold winter capability of 1052 MW gross and 1072 MW gross respectively were 19 modeled at the St. Lucie site. Auxiliary loads of 49.14 MW, 33.7 MVAR and 49.48 MW, 32.8 MVAR were modeled at the SL1EPU P AND SL2EPUP units respectively.

Study case assumptions were selected to identify system performance under stressed but likely scenarios. Conditions more likely to occur at summer peak load and off peak load (approximately 50% of summer peak) were considered.

Normally cleared faults and dela yed clearing faults due to breaker failure were simulated at the following locations:

1.St. Lucie 230kV substation (See figure A above) 2.Midway 230kV substation (See figure B below)

Figure B

Simulations of the faults in (1) and (2) above were intended to determine the acceptable clearing time at each substation based on breaker failure. Simulations of these faults were sufficient for the determination of the impact of the SL1EPUP AND SL2EPUP on the system stability. Disturbances electrically remote from the SL1EPUP AND SL2EPUP plant were not considered relevant as they may relate to this request. Midway and St. Lucie 230kV substations have redundant line, transformer and bus protection therefore simula tion of relay failure is not required.

20 RESULTS:

Midway 230kV Substation The existing BFBU total clearing time at Midw ay 230kV substation of 9.9 cycles is adequate. Results of the dynamic simulati ons indicate acceptable performance for the most extreme NERC Category D event at Midway substation. The most severe fault at Midway substation is on the Midway 500/230kV auto with delayed cl earing for breaker failure (See Ref. Table 1 case C11). Similar to the existing performance without the up grades, the St. Lucie #1 and #2 units lose synchronism and trip after the fault is cleared however the transmission system remains stable, which is acceptable performance for the NERC Category D extreme event. It is recommended that all future breaker replacements at Midway 230kV substation use Independent Pole Operated breakers to improve system performance for extreme events. See Ref. Table 1 cases C11 & C11_ipo.

St. Lucie 230kV Substation The existing BFBU total clearing time at St. Lucie 230kV substation of 8.8 cycles is adequate.

Stabilizers are required for SL1EPUP AND SL2EPUP units to improve oscillations damping. See Ref. Table 1 cases C11_ncl and C1_ncl_pss.

Table 1 2012 Summer Loading with SL1EPUP AND SL2EPUP Run ID Description Peak Load Off Peak Load C11_ncl 3-pha fault at Midway 500/230kV Auto TX, At 3 cy open Auto TX &

clear fault. System Stable Loadshed 0 MW

System Stable Loadshed 0 MW

St. Lucie units have poorly damped oscillations, need

to add PSS.

C11_ncl_pss 3-pha fault at Midway 500/230kV Auto TX, At 3 cy open Auto TX &

clear fault.

PSS on at SL1 & SL2 System Stable Loadshed 0 MW

System Stable Loadshed 0 MW

St. Lucie units well damped with PSS.

C11 3-pha fault at Midway 500/230kV

Auto TX, BRK 77 fails, At 3 cy open

Auto TX, At 9.9 cy open S 230kV &

138kV bus breakers at Midway &

clear fault. System stable following loss of synchronism by

unstable St. Lucie #1 and

1. 2 units. Loadshed 845 MW System stable following loss of synchronism by

unstable St. Lucie #1 and

1. 2 units. Loadshed 1347 MW C11_ipo 3-pha fault at Midway 500/230kV Auto TX, BRK 77 fails, At 3 cy open

Auto TX and convert fault to SLG, System Stable Loadshed 0 MW

System Stable Loadshed 0 MW

21 Run ID Description Peak Load Off Peak Load At 9.9 cy open S 230kV & 138kV bus breakers at Midway & clear fault. Changed breakers to Independent Pole Operated breakers at Midway.

C11_slg SLG fault at Midway 500/230kV Auto TX, BRK 77 fails, At 3 cy open Auto

TX, At 9.9 cy open S 230kV &

138kV bus breakers at Midway &

clear fault. System Stable Loadshed 0 MW

System Stable Loadshed 0 MW

C12 3-pha fault at Midway N 230kV Bus, BRK 15 fails, At 3 cy open all N

230kv & 138kV bus breakers tripping

Midway 230/138kV N Auto TX, At

9.9 cy open BRK 41 tripping St.

Lucie-Midway#1 230kV line & clear fault. System stable following loss of synchronism by

unstable St. Lucie #1 and

1. 2 units.

Loadshed 1503 MW System stable following loss of synchronism by

unstable St. Lucie #1 and

1. 2 units. . Out of Step scheme at Ft. White splits Ft. White substation.

Loadshed 1894 MW C13 3-pha fault at Midway S 230kV Bus, BRK 65 fails, At 3 cy open all S

230kv & 138kV bus breakers tripping

Midway 230/138kV S Auto TX, At

9.9 cy open BRK 212 tripping St.

Midway-Ranch 230kV line & clear fault. System Stable Loadshed 0 MW

System stable following loss of synchronism by

unstable St. Lucie #1 and

1. 2 units. Out of Step scheme at Ft. White splits Ft. White substation.

Loadshed 1892 MW C14 3-pha fault at Midway on Midway-

Ralls 230kV line, Mid BRK 212 fails

At 3 cy open Midway-Ralls line at

Ralls, At 9.9 cy open Midway-Ranch line at Midway & clear fault at

Midway 230kV. At 10.9 cy open

Midway-Ranch at Ranch & clear fault

on line. System Stable Loadshed 0 MW

System stable following loss of synchronism by

unstable St. Lucie #1 and

1. 2 units. . Out of Step scheme at Ft. White splits Ft. White substation.

Loadshed 1896 MW C1 3-pha fault at St. Lucie on St. Lucie-

Midway #1 230kV line. BRK 192

fails, At 4 cy open St. Lucie-Midway

1. 1 at Midway. At 8.8 cy open E 230kV bus breakers at St. Lucie &

clear fault. System Stable Loadshed 0 MW

System Stable Loadshed 423 MW

C2 3-pha fault at St. Lucie E 230kV Bus, BRK 192 fails, at 8.8 cy open BRK

218 tripping St. Lucie-Midway#1 230kV line & clear fault. System Stable Loadshed 0 MW

System Stable Loadshed 423 MW

C3 3-pha fault at St. Lucie on St. Lucie-Midway #2 230kV line. BRK 43 fails, System Stable Loadshed 0 MW System Stable Loadshed 423 MW 22 Run ID Description Peak Load Off Peak Load At 4 cy open St. Lucie-Midway #2 at Midway. At 8.8 cy open BRK 40 &

clear fault.

C4 3-pha fault at St. Lucie on St. Lucie-Midway #3 230kV line. BRK 52 fails, At 4 cy open St. Lucie-Midway #3 at

Midway. At 8.8 cy open BRK 49 tripping St. Lucie Unit #2 & clear fault. System Stable Loadshed 0 MW

System Stable Loadshed 423 MW

C4a 3-pha fault at St. Lucie on St. Lucie-Midway #3 230kV line. BRK 55 fails, At 4 cy open St. Lucie-Midway #3 at

Midway. At 8.8 cy open BRK 52 &

clear fault. System Stable Loadshed 0 MW

System Stable Loadshed 423 MW

C5 3-pha fault at St. Lucie W 230kV Bus, BRK 43 fails, at 8.8 cy open BRK 40

tripping St. Lucie-Midway#2 230kV line & clear fault. System Stable Loadshed 0 MW System Stable Loadshed 423 MW C5a 3-pha fault at St. Lucie W 230kV Bus, BRK 55 fails, at 8.8 cy open BRK 52

tripping St. Lucie-Midway#3 230kV line & clear fault. System Stable Loadshed 0 MW

System Stable Loadshed 423 MW

NOTE: All simulations were performed with Power System stabilizers on at St. Lucie #1 and #2 units, except for C11_ncl.

23

APPENDIX IV SOUTHERN/FLORIDA TRANSMISSION INTERFACE ASSESSMENT

24 Based on current information, the largest unit in the Florida Reliability Coordinating Council (FRCC) region in the 2011-2012 timeframe will be the Progress Energy Florida Crystal River Nuclear Unit 3 which is currently planned to be uprated in 2011 to approximately 1070 MW gross output. The St.Lucie Unit #2 up rate is currently planned to increase the unit to 1072 MW maximum potential cold winter gross output.

The size of the single largest generator in Peninsular Florida is a factor because the transmission system must be capable of sustaining the loss of that generator without violating any Reliability Standards. This requirement may have a direct impact on the import capability from the Southeast Electric Re liability Council (SERC).

PURPOSE:

The purpose of this portion of the FPL SL1EPUP and SL2EPUP System Impact Study is to determine if the increase in capacity of the existing St. Lucie unit 1 and St. Lucie unit 2 could adversely impact the Southern to Florida transfer capability and the Southern/Florida Transmission Interface. The import capability into Peninsular Florida from SERC is in large part determined by the contingency of the instantaneous loss of the largest unit in the FRCC, and the attendant sudden in-rush of power from the eastern United Stat es interconnectio n reacting to replace such lost power source until additional generation is disp atched in the FRCC region. The St. Lucie #2 unit, the larger of the two units, will now be 1052 MW summer gross output. Simulation of the outage of the St. Lucie #2 unit will be tested for the current Southern to Florida TTC level of 3600 MW in the summer. In addition, due to previously qu eued TSRs, a Southern to Florida TTC level of 4100 MW will also be tested for the outage of the St. Lucie #2 unit.

ASSUMPTIONS: The transmission interface between the Southe astern Subregion of SERC and FRCC Regions ("SO/FL") is a multiple owner transmission interface that is governed by Reliability Coordination agreements and the Florida - Southern Transmission Interface Allocation Agreement Among Florida Power and Light Comp any, Florida Power Corporation, Jacksonville Electric Authority, and City of Tallahassee, and is currently limited to a total transfer capability ("TTC") of 3600 MW into the FRCC for summer conditions due to voltage security limitations associated with generating unit outage contingencies. FPL is currently performing studies for other interconnection and transmission service customers with higher queue priorities that have direct impacts on the SO/FL interface. At this time FPL has developed a series of transmission improvements that would increase the Southern to FRCC transfer capability from 3600 MW to 4100 MW in the 2012 timeframe, in order to accommodate these higher queued requests.

The 2012 summer peak load Joint Study case that was used for this year's Southern/Florida long term screening evaluations (performed for th e Southern/Florida Reliability Coordination Agreement Planning Committee) was used as a base case to create the study cases for this analysis. The 4100 MW Southern to Florida transfer case includes prev iously identified transmission system improvements to accommodate the increase from 3600 MW. The improvements to increase the Southern/Florida transmission interface from 3600 MW to 4100 MW includes installing a +500/-100 MVAR SV C and an additional 4 82 MVAR of capacitor banks at Duval 500 kV substation and a 110 MVAR capacitor bank at Tocoi 230 kV substation.

25 FINDINGS: Currently, based upon assessments performed by FPL, the sudden outage of a unit size of approximately 1,200MW gross output or less should not adversely impact the FRCC's import capability from SERC in this time frame. The assessments performed by FPL indicate that the addition of approximately 4700MW of generation in Southeast Florida (Turkey Point and West County Energy Center Combined Cycle units) and planned system upgrades in Northeast Florida will make the Southern/Florida transmission interface more robust and able to accommodate the outage of a larger generating unit within the FRCC Region.

The principal finding of this analysis is that the SL1EPUP and SL2EPUP projects will not adversely affect the current Southern to Fl orida transfer capabilit ies of 3600 in the 2012 timeframe. In addition, the 4100 MW transfer case also indicates acceptable performance for the outage of the St. Lucie #2 unit. Based on past st udies for previously requested queued TSRs, the most severe contingency affecting the SO/FL interface at the increased transfer levels of 4100 MW is the outage of the Duval-Thalmann 500 kV tie line as opposed the near term studies at a 3600 MW SO/FL transfer level that shows the most severe outage being the loss of an 800 - 900 MW class generating unit outage in Florida.

26 27

APPENDIX V Transmission Projects Assessment

TRANSMISSION PROJECTS CONCEPTUAL SCOPE OF REQUIRED WORK FOR UPRATE OF ST. LUCIE UNIT #1 & UNIT #2 The results delineated below may be subject to change based on a more detailed investigation or should unforeseen circumstances be encountered during the performance of the Facilities Study.

1.SCOPE OF WORK (SUBSTATION)

This study addresses the scope of changes required to the FPL system for the uprates of St. Lucie Units 1 and 2 respectively. The interco nnection configuration is as shown in the Transmission Planning portion of this System Impact Study.

St. Lucie Switchyard The eighteen (18) 2500 amp, 230kV disconnect switches in generator bays #1 (8G34, 8G32, 8G31, 8G29, 8G27, 8G25), #2 (8 G37,8G24,8G39,8G41,8G4 2,8G44), and #3 (8G48,8G50,8G51,8G53,8G54,8G56) must be replaced with 3000A switches.

The switchyard pulloff structures have been evaluated. The field inspection has determined that improvements will not be required.

A field inspection has been conducted to determine if improvements or replacements are

required for the GSU dead end structures in the nuclear plant. The study has determined that the structures are sufficient without improvements.

This study has been amended to include the requirements to uprate one of the GSUs removed from Unit 2 to install coolers so that the uprated GSU can be used as the spare.

Midway 230kV Switchyard One (1) 2000 amp, 230kV breaker (8W95) in tie line bay #2 and eleven (11) 2000 amp, 230kV disconnect switches in tie line bays #4 (8G18, 8G14, 8G36, 8G40, 8G44, 8G48) and #5 (8G30, 8G28, 8G32, 8G54, 8G56) must be replaced with 3000A disconnect switches and a 230kV 63kA independent pole breaker. Additionally, the associated jumpers, bus work and equipment connections must be upgraded.

GSU Transformers (Excluded from total cost.) The Unit 1A and 1B coolers and low side bushings on 1A, will be replaced to uprate the GSU transformers to 635 MVA. Coolers will be installed on the St. Lucie Spare to uprate it to 635 MVA so that it can be used to replace Unit 2A.

A new 635 MVA GSU transformer purchase will be required for replacement of Unit 2B.

2.SCOPE OF WORK (PRO TECTION AND CONTROL)

This study evaluates the scope of changes required to the FPL transmission protection systems for the SL1EPUP and SL2EPUP unit uprate projects.

28 Relay Protection:

Midway - St. Lucie 230kV Line #1, #2, #3 There is no additional Protective Equipment required. The existing breaker failure protection is to be moved to a separate set of CTs as part of the breaker replacement of 8W95 at Midway. Protection and Control personnel will need to change the line protection CT ratio to 3000/5 on the #1 line at Midway. Protection and Control personnel will review and revise the line protection relay settings as needed.

Control & Reclosing:

There will be no change to the existing c ontrol and reclosing at St. Lucie or Midway Substations.

Metering & Data Acquisition:

No Changes.

3.SCOPE OF WORK (TRANSMISSION)

St. Lucie Switchyard Transmission/Substation Engineering performed field measurements of the string bus conductor sag and temperature during the 2009 St. Lucie Unit 2 outage. The data acquired in the field was entered into PLSCADD to model the stri ng busses. PLSCADD is a widely accepted computer program used in transmission line design. The model indicated that the string busses can oper ate at the proposed unit rating without modification.

St. Lucie - Midway 230kV Tie Lines Spacers will need to be installed between the existing bundled phase conductors on the Midway-St. Lucie #1, #2 and #3 230kV lines. The distance of these lines is approximately 11.8 miles each. Each of the three St. Lucie lines has a normal (continuous) rating of 2380A. Following the upgrade, each of the lines will have a normal (continuous) rating of 2790 amps. In addition, the overhead ground wires outside of Midway will need to be tied together and the grounding will require improvements due to fault current requirements.

4.SCOPE OF WORK (OPERATIONS)

There will be requirements for various 230kV bus clearances. Timing of these clearances will be dependent upon many factors including but not limited to the time of year, maintenance requirements, other prev iously granted clearances, weather, telecommunication traffic/contracts and system load conditions.

Clearances are reviewed on a daily basis and may be cancelled or delayed due to reliability considerations associated with the factors listed above. Such cancellations or delays associated with planned clearances will be considered unavoidable and may affect the scheduled completion of requirements associated with this project which in turn may delay the in-service date as well as impact the total cost of the project.

29 30 TOTAL UPRATE PROJECT COST The total non-binding, good faith estimate to upgrade the existing FPL Transmission System to accommodate the uprate, excluding the GSU improvements, is

$11.5 Million. This estimate includes the permitting, engineering and installation of all equipment and materials, labor and vehicle associated with the wo rk to be performed by FPL as described within this study report.

The estimates shown for Unit #1 are escalated to 2011 dollars and the estimates for Unit #2 are escalated to 2012 dollars. In addition, labor, material and equipment costs are subject to change depending upon market conditions and delivery schedules. Labor costs are based upon contractors performing the work under FPL supervision.

The estimated duration to engineer, permit, acquire material and construct the FPL scope of work described herein is 24 months from the date of authorization to proceed.