L-2010-144, Extended Power Uprate License Amendment Request - Response to NRC Acceptance Review Questions

Extended Power Uprate License Amendment Request - Response to NRC Acceptance Review Questions

ML102080036
Person / Time
Site:	Saint Lucie
Issue date:	07/23/2010
From:	Richard Anderson Florida Power & Light Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
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L-2010-144
Download: ML102080036 (55)

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Florida Power & Light Company, 6501 S. Ocean Drive, Jensen Beach, FL 34957 July 23, 2010 L-2010-144 FPL 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Re: St. Lucie Unit 1 Docket No. 50-335 Extended Power Uprate License Amendment Request - Response to NRC Acceptance Review Questions On April 16, 2010, Florida Power and Light Company (FPL) submitted the St. Lucie Unit 1 Extended Power Uprate (EPU) License Amendment Request (LAR) via FPL letter L-2010-078. As a result of the NRC's acceptance review of the submittal, the NRC has requested additional information. This correspondence provides responses to the Reactor Systems Branch questions exclusive of those related to the spent fuel pool criticality analysis (Attachment 1), as well as a copy of the St. Lucie EPU Grid Stability Analysis (Attachment 2) and the System Impact Study (Attachment 3) for use by the Electrical Branch.

The no significant hazards analysis submitted with FPL letter L-2010-078 remains bounding.

Should you have any questions regarding the information provided in this transmittal, please contact Mr. James Connolly, St. Lucie Extended Power Uprate Licensing Manager, at 772-429-7852.

I declare under penalty of perjury that the foregoing is true and correct to the best of my knowledge.

Executed on ' \k" t

Very you cha dL. nderson Site ice Pr sident S . ucie ant Attachments cc: Mr. William Passetti, Florida Department of Health ILI4 an FPL Group company

L-2010-144 Attachment 1 Page 1 of 13 ST. LUCIE UNIT 1 EXTENDED POWER UPRATE RESPONSE TO REFERENCE 3 NRC REVISED REACTOR SYSTEMS BRANCH ACCEPTANCE REVIEW QUESTIONS (exclusive of questions related to the spent fuel pool)

NRC Question 1:

SRXB understands that fluence calculations are discussed in LR Section 2.1.2.

This section references WCAP-16083, which is the Westinghouse Licensing Topical Report that describes the FERRET methodology. The NRC staff now believes that sufficient information has been included in the LR for detailed review of the fluence calculations. Question I is withdrawn.

FPL Response to NRC Question 1:

As discussed in NRC question 1 above, question 1 was withdrawn and no response is required.

NRC Question 2:

SRXB understands that the licensee will respond to Item #2, below.

Provide a comparison of safety-related mitigatingsystems available for the feedwaterline break and the main steam line break.

FPL Response to NRC Question 2:

Subsequent to the transmittal of question 2, discussions were held with the NRC which resulted in the clarification, as FPL understand it, that FPL is to confirm that the same equipment is available for mitigating both the main steam line break (MSLB) event and the feedwater line break (FWLB) event. The following provides the response to question 2 as clarified.

The key system, subsequent to reactor trip, for mitigating the post-scram (MSLB event is the Safety Injection system, which injects boron into the RCS to arrest the post-scram return-to-power (See LR Section 2.8.5.1.2)., In the St. Lucie Unit 1 licensing basis, the FWLB event is defined as a cooldown event bounded by the MSLB event. The FWLB event is bounded by the MSLB event for the reasons described in Section 2.8.5.2.4.2 of the Licensing Report (i.e. the break size and the enthalpy of the break flow are both smaller for the FWLB event compared to the MSLB event). The same mitigating systems apply to both MSLB and FWLB.

L-2010-144 Attachment 1 Page 2 of 13 NRC Question 3:

Provide the analyses performed to demonstrate that reactorcoolant system pressure and pressurizerliquid inventory are acceptable during,the control rod withdrawal at power event, and that the trips credited in the accident evaluation continue to provide acceptable protection from this type of event at varying power levels under EPU conditions.

Although the St. Lucie Unit I licensing basis indicates that the variable high-power trip will provide acceptable protection from this type of event, previous experience with power uprate requests has demonstrated that the uncontrolled control rod withdrawal at power event presents a challenge to both the departure from nucleate boiling ratio limits and the reactorcoolant pressure boundary pressure limits. In particular,the transient has been shown to progress, when initiated from lower power levels, in such a mannerthat the pressure boundary integrity is challenged,either by overpressurizationor by liquid level increases in the pressurizer.In some cases, plants that previously credited high-power trips have been required to credit additional,power dependent reactortrips as well as high pressurizerpressuretrips.

FPL Response to NRC Question 3:

Subsequent to the transmittal of question 3, discussions were held with the NRC which resulted in the clarification, as FPL understands it, that FPL is to provide the basis to demonstrate that control element assembly (CEA) withdrawal events at lower power levels do not present a challenge to the reactor coolant pressure boundary or pressurizer overfill. The following provides the response to question 3 as clarified.

The reactor coolant system (RCS) overpressure for the CEA withdrawal at power event is bounded by the loss of external load (LOEL) event as described in the last paragraph of LR Section 2.8.5.4.2.2.2 (i.e. the secondary system is not isolated until after reactor trip for the CEA withdrawal at power event, but is isolated immediately for the LOEL event). This same paragraph also states that CEA Withdrawal events initiated from part power are bounded by the hot full power (HFP) event. This is due to the function of the variable high power trip (VHPT) which will produce a reactor trip at a power level about 10% above the initial power level. Since the pressurizer level and pressurizer pressure are directly related, and this event is not limiting with respect to the pressurizer pressure, there will be no challenge to pressurizer overfill for this event.

The variable high power trip function available for CE-NSSS plants, like St. Lucie Unit 1, makes this event non-limiting for part power cases unlike W-NSSS plants, where the'high power trip is not reset to a lower value at part powers. The high power trip setpoint for St. Lucie Unit 1, as defined in the Technical Specifications (TS Table 2.2-1, Item 2) is a fixed value above the initial operating power level and is not a function of rate of power increase, which is the case for some W-NSSS plants with high flux rate trip. The reactivity insertion rate, and the corresponding rate of power increase, thus does not affect the power level at which the reactor will trip for St. Lucie Unit 1.

L-2010-144 Attachment 1 Page 3 of 13 Thus, CEA withdrawal events initiated from part power will produce a smaller challenge to RCS overpressurization than the HFP event for St. Lucie Unit 1.

NRC Question 4:

Clarify whether the pressurizerfills with liquid water during the inadvertent opening of the pressurizerPORV event. Also, describe (1) what terminates this transient and (2) what considerationis given to the long-term consequences of this event.

FPL Response to NRC Question 4:

Clarify whether the pressurizerfills with liquid water during the inadvertentopening of the pressurizerPORV event:

An Inadvertent Opening of Pressurizer Pressure Relief Valve, or RCS Depressurization, event is defined as an accidental opening of the pressurizer power operated relief valves (PORV) due to a mechanical failure, a spurious actuation signal, or unanticipated operator action. The event results in a rapid depressurization of the RCS and a challenge to the departure from nucleate boiling (DNB) specified acceptable fuel design limit (SAFDL). The core is protected from reaching the DNB SAFDL by the thermal margin/low pressure (TM/LP) reactor protection system (RPS) trip.

For the DNB portion of the event, the pressurizer does not fill with liquid water during this event as shown in the figure below as analyzed using the S-RELAP5 code of the NRC-approved methodology, EMF-2310(P)(A) Revision 1, SRP Chapter 15 Non-LOCA Methodology for Pressurized Water Reactors, Framatome ANP, Inc.

Describe (1) what terminates this transient and (2) what considerationis given to the long-term consequences of this event:

The early part of the transient is terminated by the reactor trip as described above.

In the longer term, this event will be terminated with operator action by i) closing the affected PORV block valve and ii) controlling the pressurizer level by throttling the HPSI flow as necessary, following the plant procedures.

L-2010-144 Attachment 1 Page,4 of 13 100 90 80 70

-2" 60 50

, 40 30-20 10 0

10 20 30 40 50 Time (s)

Pressurizer Level vs. Time NRC Question 5:

Please provide information to demonstrate that the assumed break geometry used as input to the boric acid precipitationanalysis provides a limiting loop pressure drop at EPU conditions.Include comparative studies regardingthe pressure drop characteristicsof other, less limiting break geometries (e.g., double-ended break vs. a slot break).

The licensing report states that the selection of the height of the mixing volume was justified with supporting calculations accounting for the loop pressuredrop between the core and the break. This is consistent with Item 2 of the clarification letter sent to J. A. Gresham, Westinghouse, regardingthe withdrawal of NRC approval of CENPD-254-P,which states that the mixing volume is a variable quantity that increases with time, and that the analysis to determined boric acid concentration needs to account for the variation in the mixing region while considering the pressure drop in the loop. The loop pressuredrop is dependent on the assumed break geometry. If a double-ended break on the cold leg were assumed, the loop pressuredrop characteristicswould be different than if a slot break on the top of the cold leg were assumed.

FPL Response to NRC Question 5:

As documented in LR Section 2.8.5.6.3.5.1, the St. Lucie Unit 1 boric acid precipitation analysis used the CENPD-254-P-A post-LOCA boric acid precipitation analysis methodology as modified by the approach used in the Waterford 3 EPU boric acid precipitation analysis and as approved by the NRC for that purpose. The methodology used for St. Lucie Unit 1 EPU is consistent with all four of the NRC restrictions on the

L-2010-144 Attachment 1 Page 5 of 13 application of the CENPD-254-P-A methodology that were documented in the clarification letter from D. S. Collins, NRC, to J. A. Gresham (Westinghouse) dated November 23, 2005. In particular, the Westinghouse response presented below further demonstrates conformance with Item 2 in the clarification letter, which requires determining the variation in the mixing region to be used for boric acid precipitation analyses while considering the pressure drop in the loop.

(A) GeneralAssumptions Discussed in the Licensing Report The boric acid precipitation analysis is based on an assumed break geometry that is integral to the analysis methodology. The assumed break geometry is a double-ended break in the cold leg. Detailed information regarding the break geometry assumed when determining the creditable height of the mixing volume used in the boric acid precipitation analysis is discussed in LR Section 2.8.5.6.3.5.2, under the heading "General Assumptions used in the CENPD-254-P-A Methodology," Items #1, #4, and

1. 10.

• In Item #1, the limiting break scenario, which is bounding for all break sizes and locations, is the large cold leg break. Specifically, this break is located in the reactor coolant pump discharge section of the cold leg at the point of injection.

• Also in Item #1, all of the injection to the broken cold leg is assumed to spill out the break to the containment. Therefore, there will be the same amount of spillage assumed in the boric acid precipitation analysis regardless of break size or break type (i.e., slot or guillotine).

• In Item #4, the break geometry in the cold leg is further described with the bottom elevation of the cold leg break consistent with the bottom of the cold leg.

• In Item #10, the potential of loop seal refilling for slot break geometry and its impact on the loop pressure drop is eliminated, as they do not have a significant impact compared to the core and downcomer hydrostatic pressure drops, which dominate the pressure balance analysis in the inner vessel. St. Lucie Unit 1 is designed with a loop seal elevation that is above the elevation of the top of the active core.

(B) Technical JustificationRegarding the Limiting Break Definition To further clarify the information contained in the LR Items listed above, the assumed break geometry is confirmed to be limiting for the boric acid precipitation analysis using the following technical justification:

Maximum Spillage - For the cold leg break configuration, ECCS injection to the broken cold leg is assumed to spill to the containment. Of the remaining injection flow to the intact cold legs, only the amount needed to maintain the reactor vessel downcomer level to the elevation of the bottom of the cold leg is credited in the boric acid precipitation calculation and the remainder is assumed to spill to the containment. By comparison, there is no spillage upstream of the core if the break is located in the hot leg and the fully developed safety injection flow to the cold legs provides hydrostatically driven flushing flow through the reactor vessel.

Minimum Creditable Downcomer Head - The reactor vessel hydrostatic pressure balance calculation determines the mixing volume for the boric acid precipitation analysis. The methodology assumes that the hydrostatic head of coolant in the

L-2010-144 Attachment 1 Page 6 of 13 reactor vessel downcomer region extends to a height that is no greater than the elevation of the bottom of the cold leg, which is consistent with a guillotine or slot break located in the bottom of the reactor coolant pump discharge section of the cold leg. For conservatism, no accumulation of coolant in the downcomer above this elevation is assumed; therefore, other break configurations would be less limiting from a hydrostatic pressure head viewpoint.

• Higher Loop Pressure Drop - The reactor coolant loop pressure drop from the core to the break is higher for cold leg breaks than for hot leg breaks. The pressure losses through the steam generator, loop seal, and the assumed locked rotor of the reactor coolant pump add-significantly to the loop pressure drop compared to the hot leg or suction leg break locations. The slot break at the top of the cold leg would allow for the possibility of long-term liquid accumulating in the loop seal or loop seal refilling, which adds to the loop pressure drop.

However, the slot break at the top of the cold leg would also add to the height of the downcomer head. This item is discussed in greater detail in Section (D) below.

• Minimum Height of the Mixing Volume - The assumed break geometry of a large break in the bottom of the cold leg leads to a downcomer liquid height no greater than the bottom of the cold leg. Also, this break has an associated loop pressure drop that includes losses from the steam generator, loop seal, and locked rotor of the reactor coolant pump. Using these conditions, the hydrostatic pressure balance analysis results in the lowest mixing volume height in the inner vessel compared to other conditions with larger downcomer liquid heights or smaller loop pressure drops.

• Maximum Break Size - Maximizing the break size with the large break LOCA scenario is bounding for all break sizes .and locations for boric acid precipitation analyses. The large break LOCA transient results in a low reactor coolant system pressure, which yields a conservatively low boric acid solubility limit compared to a smaller break size scenario. Higher system pressure for the small break size transient results in lower core and upper plenum void fraction, thus increasing the mixing volume. Also, higher system pressure for the small break size transient leads to a higher core saturation temperature, thus increasing the safety injection subcooling for increased heat removal.

(C) Basis for Conservatism of St. Lucie Unit 1 EPU Analysis The items listed above explain how the assumed break configuration is conservative for the boric acid calculation, which is dependent on the core and upper plenum mixing volume. The mixing volume used in computing the boric acid concentration included the additional volume'of two-phase mixture above the core. However, this additional volume was limited to be no greater than the volume from the top of the core to the top elevation of the hot leg piping at the reactor vessel outlet nozzles. The selection of this height of the mixing volume used in .the boric acid precipitation analysis is justified as discussed in LR Section 2.8.5.6.3.5.2, under the heading "Analysis Assumptions Made Since the Waterford Approach," Item #2. The steps used to justify the height of the mixing volume included (1) conservatively calculating the loop pressure drop at several points in time for the assumed break configuration, then (2) confirming for all times that the hydrostatic head for the coolant in the downcomer remains greater than the hydrostatic head for the two-phase mixture in the core plus the core to break pressure drop. Section (D), below, discusses the results of a comparative study justifying the mixing volume as well as the analytical basis for the steps listed above.

L-2010-144 Attachment 1 Page 7 of 13, This analysis shows that the reactor vessel hydrostatic pressure balance including the impact of variations in loop pressure drop at EPU conditions does not result in a mixing volume height less than the top elevation of the hot leg. Furthermore, the calculations

.show that the actual mixing volume height using conservative assumptions is considerably higher than the elevation of the top of the hot leg. This conservatism in the actual mixing volume height compared to the value assumed in the analysis provides margin to cover other alternate break configurations with more limiting loop pressure drop but less limiting hydrostatic pressure parameters. Details of the hydrostatic pressure balance comparing the limiting break configuration to a slot break in the top of the cold leg are discussed in the following quantitative information in Section (D), below.

(D) Comparative Study for Less Limiting Break Geometry Conservatism in the reactor vessel hydrostatic pressure balance calculation is demonstrated by showing that the collapsed liquid height in the outlet plenum credited in the mixing volume is significantly less than the-elevation of the mixing volume actually available for all break sizes, break types, and break locations, at all times throughout the post-LOCA transient. The collapsed liquid height of available liquid in the outlet plenum, or the hydrostatic head of the outlet plenum, is calculated using Equation (5-1) below:

APop = APDc -APSTM - APCORE Eq. (5-1) where APop = hydrostatic head of the outlet plenum (psi)

APDC = hydrostatic head of the downcomer (psi)

APSTM = core-to-break steam flow pressure drop (psi)

APCORE = hydrostatic head of the core (psi)

The calculation of each of these pressure drops is discussed below. Additionally, each pressure drop is calculated at four different times (1, 4, 5, and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />) to ensure that the most limiting condition during the critical time period of the transient just prior to switchover to simultaneous hot and cold side injection is evaluated. This considers multiple times through the transient, as 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> corresponds to the latest time for switchover to simultaneous hot and cold side injection.

Hydrostatic Head of the Downcomer, APDC The height of the downcomer is defined from the bottom elevation of the active core to the bottom elevation of the RCP discharge legs. This distance is 15.72 feet for St. Lucie Unit 1.

The specific volume of saturated liquid at 14.7 psia is 0.016714 ft 3/lbm. Using this data, the downcomer hydrostatic pressure drop (APDOc) is equal to the height of liquid divided by the specific volume (and multiplied/divided by the appropriate conversion factors) as shown in Equation (5-2) below:

APDC = 15.72 ft / 0.01 6714 ft3/lbm / 144 in.2/ft2

• g/gc = 6.53 psi Eq. (5-2)

This results in a minimum, and thus conservative, value for the hydrostatic head of the downcomer, as discussed above in Section (B) under "Minimum Creditable Downcomer

L-2010-144 Attachment 1 Page 8 of 13 Head". This value is not time dependent, since it is constant throughout the post-LOCA transient.

Core-to-break steam flow pressure aroI:--PsTM The core-to-break steam flow pressure drop is calculated by Equation (5-3) below:

APSTM = K

• v /9266.112 * (W/A)2 Eq. (5-3) where K = K-factor (friction and geometric loss coefficients, dimensionless) v = specific volume of steam at 14.7 psia = 26.7952 ft3/Ibm A = area (ft2)

W = core boil off steam flow rate (Ibm/sec)

Units Conversion: 9266.112 = the product of 2*go (32.174 Ibm-ft/Ilbf-sec 2)*144 in. 2/ft2 . Its units are, therefore, Ibm-in. 2/Ilbf-sec2-ft.

(Note: In using this equation, the steam flow rates are converted to Ibm/sec.)

Steam Flow Rate (Core Boil Off)

The Decay Heat Fraction (DHF) at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> post-LOCA is determined using the BORON computer code decay heat model described in CENPD-254-P-A, reproduced as Equation (5-4) below. Using a time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, or 3600 seconds, the DHF is:

DECAY = 0.75*1 0 (0.75*logT- 0.

778

)/T Eq. (5-4) where DECAY = normalized decay heat fraction including 1.1 conservative multiplier T = time (seconds)

DECAY = 0.75*1 0 (0.75*1og(3600) - 077")/(3600) = 0.016143 Consistent with NRC imposed restrictions on the acceptability of the boric acid precipitation methodology, a 1.2 decay heat multiplier is applied as follows:

Decay Heat Fraction (including 1.2 decay heat multiplier) =

0.016143

• 1.2 / 1.1 = 0.01761 The core power level including power measurement uncertainty is 3030 MWt for EPU conditions for St. Lucie Unit 1.

Therefore, using the above data, the core boil-off rate (WBO) at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> post-LOCA is equal to the core power times the decay heat fraction divided by the heat of vaporization, as given in Equation (5-5) below:

WBO = 3030 MWt

• 948.04 Btu/sec-MWt

• 0.01761 /(1150.28 - 180.18) Btu/Ibm

=52.15 Ibm/sec Eq. (5-5)

This calculation is repeated at three additional times (4, 5, and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />) to cover the time frame of this comparative analysis for St. Lucie Unit 1 at EPU conditions. The following table summarizes the core boil-off for all four times.

L-2010-144 Attachment 1 Page 9 of 13 Time (hr) Time (sec) DHF DHF (w/1.2) WBO 1 3600 0.016143 0.017611 52.15 4 14400 0.011415 0.012453 36.87 5 18000 0.010796 0.011777 34.87 6 21600 0.010314 0.011252 :33:32 K-Factor The K-Factor quantifies the resistance from the core to the assumed break location, i.e.,

the cold leg. This resistance is composed of the losses due to both friction and geometry. The geometry resistance K-Factor, GK, is obtained directly from plant-specific pressure drop data, and with added conservatism is calculated to be 160'fdr St.

Lucie Unit 1. This geometric K-factor contains an additional 10% conservative margin for uncertainty in the geometric losses in the reactor vessel and 20% for geometric losses in the remainder of the reactor coolant system. The friction resistance, FK, was also obtained using plant-specific pressure drop data, and is calculated to be 37.534 for St. Lucie Unit 1. This friction factor contains the same additional conservative margins for uncertainty as used for the geometric losses, and in addition, it is rounded up to 60 for conservatism. Additionally, these K-Factors are for the entire RCS loop, including the friction and geometric losses in the core, which is more conservative than just including the resistances from the core outlet to the break.

Thus, the composite resistance factor is:

Total K-Factor = GK + FK = 160 + 60 = 220 The core-to-break steam flow pressure drop is calculated using Equation (5-3):

APSTM=K

• v /9266.112 * (W/A)2 2 2 APSTM - (220

• 26.7952 ft3/lbm) / 9266.112 * (52.15 Ibm/sec / 54.00 ft )

= 0.593 psi Again, the calculation of APSTM was repeated for all times mentioned above for EPU conditions for St. Lucie Unit 1. The following table summarizes APSTM for all four calculated times post-LOCA.

Time (hr) Time (sec) APSTM (psi) 1 3600 0.593 4 14400 0.297 5 18000 0.265 6 21600 0.242 As expected, the core-to-break loop pressure loss for these conditions is an order of magnitude less significant than the hydrostatic head of the downcomer.

Hydrostatic Head of the Core, APCORE The head of the collapsed liquid in the core is dependent upon the liquid volume, which in turn is dependent on the void fraction of the core, and thus is time dependent. For St.

L-2010-144 Attachment 1 Page 10 of 13 Lucie Unit 1 at EPU conditions, the liquid volume in the active core at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> post-LOCA is determined to be 160.43 ft3. This calculation was performed using the liquid mass calculated by the BORON computer code, which is part of the CENPD-254-P-A methodology, in combination with applying the CEFLASH-4AS phase separation model for dynamic void fraction modeling, which is part of the NRC-approved small break LOCA ECCS performance methodology in CENPD-137 Supplement 1-P and CENPD-133 Supplement 3-P. In addition, the core flow area is 54.00 ft 2, and the specific volume of saturated liquid at 14.7 psia is 0.016714 ft 3/lbm. Based on this data and using Equation (5-2), the core hydrostatic pressure drop, APCORE at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> post-LOCA is:

APCORE = (160.43 ft 3 / 54.00 ft2) /0.016714 ft3/lbm / 144 in.2/ft2

• g/gc = 1.23 psI The following table summarizes APCORE for all four times post-LOCA being evaluated, thus showing the variation due to the time dependent change in void volume calculated by the phase separation model and the CENPD-254-P computer code outputs.

Time (hr) Time (sec) APcoRE (psi) 1 3600 1.23 4 14400 1.51 5 18000 1.56 6 21600 1.60 Hydrostatic Head of the Outlet Plenum, APop The following hydrostatic pressure balance, given earlier as Equation (5-1), is used to calculate the hydrostatic head of the outlet plenum:

APop = APDC -APSTM - APCORE APDC, APSTM, and APCORE have been calculated above for four different times in the transient post-LOCA for EPU conditions of St. Lucie Unit 1. Once APop is calculated, the height of static head of the outlet plenum (that is, the collapsed liquid level above the top of the active core) can be calculated using Equation (5-6) as follows:

Hop, ft = APop, psi

• v, ft 3/Ibm

• 144 in. 2/ft 2

• g/gc Eq. (5-6)

Since this height was derived from the pressure drop, it represents the collapsed height of the liquid in the outlet plenum, which is conservative for justifying the impact of the break configuration on the mixing volume. If this value was converted to a froth height based on the void fraction of the outlet plenum and volume, the static mixture level would increase, providing more margin to the limit specified as the top elevation of the hot leg. (At 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, the area adjusted void fraction in the upper plenum is greater than 40%, which adds measurably to the two-phase-mixture height above the core.)

The following table summarizes the values for all pressure drops for each time, as well as the static head of the outlet plenum.

L-2010-144 Attachment 1 Page 11 of 13 Time (hr) Time (sec) APOC (psi) APSTM (psi) APCORE (psi) APop (psi) Hop (ft) 1 3600 6.53 0.593 1.23 4.707 11.33 4 14400 6.53 0.297 1.51 4.723 11.37 5 18000 6.53 0.265 1.56 4.705 11.32 6 21600 6.53 0.242 1.60 4.688 11.28 From this table, the lowest static head of the outlet plenum occurs at6 hours, when the pressure drop through the core is highest, and is 11.28 ft. For these comparative calculations examining the limiting conditions for the break configuration and the loop pressure drop, a lower height is more conservative, as discussed above in Section (B) under "Minimum Height of the Mixing Volume". Also, this time corresponds to the latest time considered before switchover to simultaneous hot and cold side injection, where boric acid concentration is the highest.

While this demonstrates that at a minimum there is 11.28 feet available for the mixing volume in the outlet plenum, the analysis only credits up to the top of the hot leg (or 7.60 feet). When converted to a pressure drop using Equation (5-6), the analysis-credited height to the top of the hot leg of 7.60 feet is equivalent to 3.158 psi. Therefore, for a double-ended guillotine break, at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> post-LOCA, there is 1.530 psi of margin in the hydrostatic balance. The following diagram visually depicts this hydrostatic balance at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for EPU conditions for St. Lucie Unit 1, including the available margin in the outlet plenum.

L-2010-144 Attachment 1 Page 12 of 13 Reactor Vessel Hydrostatic Pressure Balance For Boric Acid Precipitation Analysis (Regions Shown to Scale at 6 Hours Post-LOCA)

Reactor Vessel Reactor Inner Vessel.

Cold/Downflow Side Hot/Upflow Side MARGIN kydr,~tatic Head~of the in Static Head of the Downcomer 1Ou53ps*lenmi 6.53 psi 1t pi Static Head of the Outlet Plenum Credited (to the top of the hot leg) 3.158 psi

'Core toaBreak Stean: Fow Presur e q ýh!

1 242 pSir.z "Hydrostatic Head of the.

Core, 1:60 psi Bottom of Active Core As can be seen for this limiting break configuration, there is 1.530 psi of margin (more than 23% of the hydrostatic head of the downcomer) in the hydrostatic pressure balance between the hot and cold sides of the reactor vessel.

The above quantitative evaluation represents the limiting break in the bottom of the cold leg. If a slot break at the top of the cold leg were assumed, there could be an additional pressure drop due to the loop seals refilling as well as an additional pressure drop due to a higher level for the downcomer liquid, described as follows:

0 Loop seal refilling will increase the value of the core-to-break steam flow pressure drop, which will reduce the margin calculated above.

However, with the slot break at the top of the cold leg, water in the cold leg can be credited, which is not currently done as discussed in Section (B) under "Minimum Height of the Mixing Volume". Crediting water in the cold leg will increase the hydrostatic head of the downcomer and increase the margin calculated above.

To demonstrate that a slot break at the top of the cold leg is not limiting, the pressure drop due to clearing the loop seals is calculated, and shown to be covered by the margin

L-2010-144 Attachment 1 Page 13 of 13 in the static head of the outlet plenum for the limiting double-ended break in the bottom of the cold leg.

Using the geometric information tabulated in Table 2.8.5.6.3-10 in LR Section 2.8.5.6.3.5.2, the height of the loop seal (from top of cross-over leg to bottom of discharge leg) is 3.5 ft for St. Lucie Unit 1. The static head associated with the height of liquid in the cold leg above the loop seal inlet to the reactor coolant pump is offset by the added static head for the downcomer from this liquid. Using Equation (5-2) given above to calculate the hydrostatic head of the downcomer, the pressure drop, ignoring the head of steam in the downflow side of the loop seal, associated with clearing the liquid in the upflow side of the loop seal is calculated as follows:

APDC ='3.5 ft/ 0.016714 ft3/Ibm / 144 in. 2/ft2

• g/gc = 1.454 psi Because this pressure drop is less than the available margin of 1.530 psi, there is sufficient margin in the pressure balance for the break in the bottom of the cold leg to include clearing the loop seals for a slot break at the top of the cold leg.

Other potential break locations are even less limiting and do not need to be evaluated.

For example, if the break was in the loop seal, the above calculation of the pressure drop due to loop seal refilling is not required, as discussed in Section (B) under "Higher Loop Pressure Drop". Comparatively, the double ended break in the cold leg is still bounding. If the break was in the hot leg, all safety injection would go directly to the core (i.e., none would spill out of the break), as discussed in Section (B) under "Maximum Spillage". Therefore, based on the above evaluations, the double-ended break in the cold leg is confirmed to be the limiting break geometry for the boric acid precipitation analysis.

(E) Conclusion This evaluation demonstrates that with regard to pressure drop characteristics, the limiting configuration of a large break in the bottom of the cold leg for EPU conditions for St. Lucie Unit 1 contains sufficient conservatism to bound other break geometries such as a slot break in the top of the cold leg. This evaluation further demonstrates that the methodology used for St. Lucie Unit 1 EPU boric acid precipitation analysis is consistent with the NRC restrictions on the use of the CENPD-254-P-A for determining the variation in the mixing region used for boric acid precipitation analyses while considering the pressure drop in the loop (documented by NRC in the clarification letter from D. S.

Collins, NRC, dated November 23, 2005). The results of the evaluation and the technical justification in support of the conservative basis for the St. Lucie Unit 1 EPU boric acid precipitation analysis, justify that the methodology is bounding for all break configurations and is consistent with all NRC limitations and conditions for CENPD-254-P-A.

L-2010-144 Attachment 2 Page 1 of 11 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 Plant (St. Lucie) with the proposed extended power uprate (EPU). The St. Lucie study focused 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-I and ICSB-11. The information in this report is intended to update 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-IIl. 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 level 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 modeled cause transmission voltages or line loadings to exceed ratings.

I

L-2010-144 Attachment 2 Page 2 of 11 Dynamic Stability Results Loss of the largest source Case I - 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 frequency briefly dips to 59.91 Hz and settles at 59.99 hertz. This response is consistent with observed 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 and 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 disconnected 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

L-2010-144 Attachment 2 Page 3 of 11 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 machine angles is due to the slight increase in overall grid frequency. No transmission overloads, 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 amount 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

L-2010-144 Attachment 2 Page 4 of 11 Table I - Power Flow Analysis St. Lucie 230 Grid voltage or Case Event voltage loading problems base PSL @ 2124 MW gross 239.6 none 1 PSL2 tripped 238.8 none 2 PSL1 off, PSL2 tripped 237.6 none 3 SL-Midway #3 line tripped 239.1 none 4 Midway 500/230 Tx tripped 237.8 none 5 Duval-Thalmann 500 tripped 239.5. none 6 Andytwn-Nobhill line tripped 239.9 none 7 (2) Nobhill lines tripped 240.0 none 4

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L-2010-144 Attachment 2 Page 9 of 11

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L-2010-144 Attachment 3 Page 1 of 30 GENERATION INTERCONNECTION SERVICE And NETWORK RESOURCE INTERCONNECTION SERVICE SYSTEM IMPACT STUDY FPL EXTENDED POWER UPRATE PROJECTS ST. LUCIE 1 & 2 Q114 & Q115 11/24/08

L-2010-144 Attachment 3 Page 2 of 30 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 I extended power uprate project ("SLI EPUP") & 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 request 114 is for an increase in the capacity of the existing St. Lucie unit I 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 SLIEPUP and SL2EPUP;

" Identification of any thermal overload or voltage limit violations resulting from SL I EPUP and SL2EPUP; and

" Identification of any instability or inadequately damped response to system disturbances resulting from the interconnection; and

• A description and non-binding estimated cost of facilities required to integrate SLIEPUP 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 SL IEPUP 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 SLIEPUP 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 r~sults 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 SL I EPUP and SL2EPUP projects' incremental increase in MW output to the FPL transmission system must meet the requirements of the Standard Large Generator Interconnection Procedures in FPL's OATT. In order to

L-2010-144 Attachment 3 Page 3 of 30 determine whether the incremental increase in MW output of each unit meets the requirements, a 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 reactive 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 criteria the analysis results were that:

• The SLIEPUP 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 SLIEPUP 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 increase in power output of the SLIEPUP and SL2EPUP. Withdrawal of one or more of these preceding GIS requests may result in SLIEPUP 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 SLI EPUP and SL2EPUP.

Please refer to Appendix I for detailed results.

Provision of NRIS for SLIEPUP Based on the current status of FPL's GIS queue and transmission service requests the following are the results of this part of the evaluation:

• The integration of SLIEPUP 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 service requests the following are the results of this part of the evaluation:

• 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 (1 85F/85C) for the 2XI691AAAC and 3395A (239F/1 15C) 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.

L-2010-144 Attachment 3 Page 4 of 30 Dynamic Stability Analysis

• The existing BFBU total clearing time at Midway 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 simulations 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 SLIEPUP 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.

L-2010-144 Attachment 3 Page 5 of 30 APPENDIX I SHORT CIRCUIT ANALYSIS

L-2010-144 Attachment 3 Page 6 of 30 I. SHORT CIRCUIT ANALYSIS FOR SL1EPUP-QI14 PURPOSE:

Determine the impact on breaker interrupting capability at FPL's substations due to the SLIEPUP-Q 114 as specified in the following configuration (See Figure A).

Figure A - SL1EPUP - Q114 Hutot~eson

'If I~slnd Midw~ay

1. 3 Midway#2 Midway #1 4

t N,.0 L 67 64 55 52 43 40I 30 169 21 61 I,,ý, I 49 23 +,,

26192 Start-upL Start-up 475 475 MVA 475 635 ,JIa ILJ 635 MVA MVA MVA MVA Uprat-QT14 Key In-service Date a Upgraded facility 11-24-2011I Uprated to 1200 MVA mai New facility 1000 MVA SL2 SL 1 *1032/1052MW

• "89/905 MW

• Summer/Winter gross continuous MW capability METHODOLOGY:

The analysis was performed 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.

L-2010-144 Attachment 3 Page 7 of 30 ASSUMPTIONS:

Base Case

• Given the SL 1EPUP 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 and reflects changes in load, generation capacity, and transmission capacity that have been planned 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 SLIEPUP. SLIEPUP 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 exceeded the rating of any existing circuit breakers as a result of the SLIEPUP GIS request. The following table below shows the impact of SLIEPUP on fault current levels at Midway and St. Lucie 230 kV substations:

Rating STUDY kA prior STATION kV kA kA 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 capability at FPL's substations due to the SL2EPUP-Q 115 as specified in the following configuration (See Figure B).

L-2010-144 Attachment 3 Page 8 of 30 Figure B - SL2EPUP - Q115 Hutchinson Island Midway #3 Midway #2 Midway #1 N.O.

A A A L 67 I

9543 52 I, I30 169 218 61 49I 23 126 1.2 Start-up Start-up 635 635 MVA MVA

_1kVj 635 635 IJ.A Z2223- 635 MVA MVA

' MVA Uprate-QI 15 Uprate-Q 114 Key In-service Date In-service Date I Upgraded facility 6-24-2012 11-24-2011 0 MVA Uprated to 1200 MVA New facility Uprated to 1200 SL2 SL 1 *1032/1052 MW

• 1052/1072 N'

• Summer/Winter gross continuous MW capability 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 0 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 and reflects changes in load, generation capacity,

L-2010-144 Attachment 3 Page 9 of 30 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 57.3 57.1 St. Lucie 230 63 45.7 45.0

L-2010-144 Attachment 3 Page 10 of 30 APPENDIX II NRIS ASSESSMENT

L-2010-144 Attachment 3 Page 11 of 30 SL1EPUP NRIS Assessment:

PURPOSE Determine the transmission system additions/modifications for the proposed SL 1EPUP to be integrated as an FPL's Network Resource.

SUMMARY

0 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 M

HutdainsetIsland Midway #3 Midway 02 Midway #1 NO,,

AL k L 64 6

55 52 43 40 30 169 216 6149 23 2- 192 Start-up Start-up 475 475 MVA tLa. LLJ__3 kV 47 635 22r230 635 MVA MA MVA MVA Uprat-QI 114 Key In-service Date III Upgraded facility 11-24-2011 New facility 1000 MVA Uprated to 1200 MVA "889/905 SL 2 SL 1 *1032/1052MW

• Summer/Winter gross continuous MW capability The integration of SL 1EPUP as a Network Resource 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 the reference case or overloads that were not existing in the reference case, for the same contingency, are attributed to SLIEPUP. Similarly,

L-2010-144 Attachment 3 Page 12 of 30 low voltages, less than 0.95 p.u., that were materially lower (more than 2%) when compared to the reference case, for the same contingency, are attributed to SL IEPUP.

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 methodology of analyzing overloads 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 compared to the reference case or overloads that were not existing in the reference case, for the same contingency, are attributed to SL I EPUP 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 SL I EPUP 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 updated 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.

SL 1EPUP 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 SLIEPUP. Also, no existing overloads in the cases were materially aggravated (more than 3%) due to the SLIEPUP. Similarly, there were no low voltages observed that were materially lower (lower than 2%) due to the SL I EPUP.

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

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

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

L-2010-144 Attachment 3 Page 13 of 30 SL2EPUP NRIS Assessment:

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

SUMMARY

0 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 Hutchinson Island Start-up

. U~pgradedfacilty 1 Uprated to 1200 MVA Uprated to 1200 MVA

• 1052/1072 MW SL 2 SL 1 t1032/1052MW

• Summer/Winter gross continuous MW capability 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/1 15C) 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.

L-2010-144 Attachment 3 Page 14 of 30 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 the 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 materially lower (more than 2%) when compared to the reference case, for the same contingency, 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 methodology of analyzing overloads 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 compared to the reference case or overloads that were not existing in the reference case, for the same contingency, are attributed to SLIEPUP 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 SL 1EPUP 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 obligations, 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 analysis show the following overloads as a result of SL2EPUP:

2012 Summer Case No Overloads as a result of SL2EPUP 2012 Winter Case Overload Rating Loading Contingency Violation(%) (MVA @ Comments W/

230kV) 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

~~IIW~~~~~t Slight difirrences inISVIIIiIIC IC.J.LLA-VI ;IIIJIC t LIULL U u;uALaLa laily 1 UIIY 1 L jCIjaj ;nLujCIu,A system impedances causeu t1je 3L. Luc e-1vi dway J c rcU LLO e oa e s g t y e OW LSL erma rat ng un er com ngencyý lvjv however the line is recommended to he inaraded with the #1 and ~2 circuits however the line is recommended to be ungraded with the #1 and #2 circuits

L-2010-144 Attachment 3 Page 15 of 30 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 withdrawn, 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 SLIEPUP or SL2EPUP. Also, no existing overloads in the cases were materially aggravated (more than 3%) due to the SLIEPUP or SL2EPUP. Similarly, there were no low voltages observed that were materially lower (lower than 2%) due to the SLIEPUP or SL2EPUP. Below are the results of the Category C3 contingency power flow analysis which indicate the following overloads as a result of SLIEPUP and SL2EPUP:

Category C3 Results:

Table 1 - Thermal Overloads for 2011 Winter Case SN-2 Conti u~vrod ' Violation (V /~aig~~o~ig.fgency..

pro to C'/uments S LIEPUIP ~to,219OK0A .1 D:MIDWAY -ST LUCIEI reduce generation at St. Lucie MIDWAY - ST LUCIE & increase generation in the 2303 184.6 948 170.1 157.4 Southeast D-MIDWAY -ST LUCIE) reduce generation at St. Lucie

+MIDWAY -ST LUCIE3 MIDWAY - ST LUCIE & increase generation in the 2302 184.6 948 170.1 157.4 Southeast D:MIDWAY -ST LUCIE2 reduce generation at St. Lucie

+MIDWAY -ST LUCIE2 MIDWAY - ST LUCIE & increase generation in the 230 1 184.5 948 170 1 157.3 Southeast Table 2 - Thermal Overloads for 2012 Summer Case

~ '~ Over~a :Ratinig7 Overloadupgad % La ing odn omet i N1-2 Coutiugencyý , ~~~io~ition NIVA prio to N pgml

+:MIDWAY -ST LUCIEI MIDWAY -ST LUCIE & increase generation in the

+MDAS UI2 2303 184.6 948 170.1 157.4 Southeast D:MIDWAY -ST LUCIEI reduce generation at St. Lucie MIDWAY - ST LUCIE & increase generation in the 2302 184.6 948 170.1 157.4 Southeast D:MIDWAY -ST LUCIE1 reduce generation at St. Lucie

+MIDWAY -ST LUCIE2 MIDWAY - ST LUCIE & increase generation in the 230 I 184.5 948 170.1 157.3 Southeast D:EMERSON -

NIGHTHAWI HARTMAN- Needs to be addressed by

+HARTMAN -F PIERCEI LAWNWOOD 69 1 136.9 92 133.1 - transmission owner D:HARTMAN -F PIERCEI +MIDWAY- HARTMAN- Needs to be addressed by NIGHTHAWI LAWNWOOD 69 1 140.9 92 137.1 transmission owner D:MIDWAY -

NIGHTHAWI +F HARTMAN- Needs to be addressed by PIERCE-INDRIO I LAWNWOOD 69 1 133.3 92 129.6 transmission owner

L-2010-144 Attachment 3 Page 16 of 30 Category C3 contingencies allow for system adjustments to be performed after the first contingency in order to prepare for the second contingency. For the loss of one St. Lucie-Midway circuit, either an emergency rating for each circuit to be capable 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 service 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/1 15C) 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.

L-2010-144 Attachment 3 Page 17 of 30 Attachment 1

,rn~ ROCEOURE NQ1WER St. Lucie/Midway Nuke-5 Transmission capability S r uno c C WP' FL and Plant Notification Sys-Tran-Nuke-Plant notification 112712007 Power Supply _PAGE 1 OF 1 TO: Memo Book Holders LOCATION: Mia3mi, Florida FnOM: C. M. Mennes DATE: March 26, 1992 SUBmEcT: ST. LUCIEMIWAY COPES TO: D. A. Sager-PSL TRANSMISSION CAPACITY G. J. Boissy-PSL AND PLANT NOTFICATION The System Operator p= notify St. Lucie Plant of any changes to the status of the three Midway/St. Lucie 230kV lines.

In addition to immediate notification of status change, for the conditions listed the following actions shall'be taken:

UNIT FRt-ECONErION POSr CONDITION lENT AIR 7 I LJNES IN # L24ES IN TET"ERATUIM FOR SERV'cE SERVIECE AT ST. LVCIJWPB ACTION ACTION 2 UNITS 2 LIS ILINS Oreater than 80*V 4 MWr Drop plawtoutput below 1000 MW 2 UNITS 2 LINES I LINE Leas d= or 9 MWN Dropplantoutput equal to 80"F below 000MW 2 UNITS 3 LINES I LINE Greter tbau 80F 6.5 MIN Dropplantourput below 1000 NtW 2 UNITS 3 LINES I L24E Less than or tU MIN Dropplaoloutput equal to SO1F below 1000 MW Any time them are 2 units with 2 lines or 1 unit with 1 line the plant should be placed in uert and may require load reduction or trip of a unit.

St. Lucie plant mu* be notified on a= changes to the line status Out of the plant to and including Midway Substation. This would include line outages in the sum bay as a PSL line at Midway, as a bus lockout would open the terminal. Also, any testing either at St.

Lucie or Midway which may involve the power supply to the plant must be reported.

C M. Mennes O(, rector Power Supply CMM/SYht/bk

L-2010-144 Attachment 3 Page 18 of 30 APPENDIX III DYNAMIC STABILITY ANALYSIS

L-2010-144 Attachment 3 Page 19 of 30

SUMMARY

A dynamic stability analysis was performed for the SLIEPUP 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 SLIEPUP and 1072 MW gross for SL2EPUP.

Figure A St. Lucie Substation Midway 2 Midway #1 NO.

67 55 43 169 64 52 40 30 21i 61 r923 26 12 Start-up Start-up 22,230V 63V 221230 kV 65 635 635 LL 635 MVA MVA MVA MVA TSTL2 Uprate Uprate Key In-service Date In-service Date ji Upgraded facility 6-24-2012 11-24-2011 I New facility Uprated to 1200 MVA SL2,U prated to 1200 MVA

-1052/1072 MW 1032/1052 MW

• Summer/Winter gross continuous MW capability ASSUMPTIONS:

Dynamic simulations were performed using the latest 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 SL 1EPUP and SL2EPUP (and attendant incremental facilities for each such GIS request) in the base case that may have an impact on the SL 1EPUP and SL2EPUP stability.

In the study cases SLIEPUP and SL2EPUP units (GIS #114 & 115), with the maximum potential cold winter capability of 1052 MW gross and 1072 MW gross respectively were

L-2010-144 Attachment 3 Page 20 of 30 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 SLIEPUP 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 delayed 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 Midway Substation SltL-. MSU3b. St.L.

. . X2 E-.S. sttu-m 91 S

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 SL IEPUP and SL2EPUP on the system stability.

Disturbances electrically remote from the SL IEPUP 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 simulation of relay failure is not required.

L-2010-144 Attachment 3 Page 21 of 30 RESULTS:

Midway 230kV Substation

• The existing BFBU total clearing time at Midway 230kV substation of 9.9 cycles is adequate.

• Results of the dynamic simulations 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 (See Ref. Table I case C11). 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. See Ref. Table I cases C 11 & Cl lipo.

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 C lincl and Clncl pss.

Table 1 2012 Summer Loading with SLIEPUP AND SL2EPUP Run ID Description Peak Load Off Peak Load 3-pha fault at Midway 500/230kV System Stable System Stable Auto TX, At 3 cy open Auto TX & Loadshed 0 MW Loadshed 0 MW C Incl clear fault. St. Lucie units have poorly damped oscillations, need to add PSS.

3-pha fault at Midway 500/230kV System Stable System Stable C I _nclpss Auto TX, At 3 cy open Auto TX & Loadshed 0 MW Loadshed 0 MW clear fault. PSS on at SLI & SL2 St. Lucie units well damped with PSS.

3-pha fault at Midway 500/230kV System stable following System stable following Auto TX, BRK 77 fails, At 3 cy open loss of synchronism by loss of synchronism by C11 Auto TX, At 9.9 cy open S 230kV & unstable St. Lucie #1 and unstable St. Lucie #1 and 138kV bus breakers at Midway & #2 units. #2 units.

clear fault. Loadshed 845 MW Loadshed 1347 MW 3-pha fault at Midway 500/230kV System Stable System Stable Cl l-ipo Auto TX, BRK 77 fails, At 3 cy open Loadshed 0 MW Loadshed 0 MW Auto TX and convert fault to SLG,

L-2010-144 Attachment 3 Page 22 of 30 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.

SLG fault at Midway 500/230kV Auto System Stable System Stable TX, BRK 77 fails, At 3 cy open Auto Loadshed 0 MW Loadshed 0 MW CIl -sig TX, At 9.9 cy open S 230kV &

138kV bus breakers at Midway &

clear fault.

3-pha fault at Midway N 230kV Bus, System stable following System stable following BRK 15 fails, At 3 cy open all N loss of synchronism by loss of synchronism by 230kv & 138kV bus breakers tripping unstable St. Lucie #1 and unstable St. Lucie #1 and C12 Midway 230/138kV N Auto TX, At #2 units. #2 units.. Out of Step 9.9 cy open BRK 41 tripping St. Loadshed 1503 MW scheme at Ft. White splits Lucie-Midway#1 230kV line & clear Ft. White substation.

fault. Loadshed 1894 MW 3-pha fault at Midway S 230kV Bus, System Stable System stable following BRK 65 fails, At 3 cy open all S Loadshed 0 MW loss of synchronism by 230kv & 138kV bus breakers tripping unstable St. Lucie #1 and C13 Midway 230/138kV S Auto TX, At #2 units. Out of Step 9.9 cy open BRK 212 tripping St. scheme at Ft. White splits Midway-Ranch 230kV line & clear Ft. White substation.

fault. Loadshed 1892 MW 3-pha fault at Midway on Midway- System Stable System stable following Rails 230kV line, Mid BRK 212 fails Loadshed 0 MW loss of synchronism by At 3 cy open Midway-RaIls line at unstable St. Lucie #1 and C14 Rails, At 9.9 cy open Midway-Ranch #2 units.. Out of Step line at Midway & clear fault at scheme at Ft. White splits Midway 230kV. At 10.9 cy open Ft. White substation.

Midway-Ranch at Ranch & clear fault Loadshed 1896 MW on line.

3-pha fault at St. Lucie on St. Lucie- System Stable System Stable C1 Midway #1 230kV line. BRK 192 Loadshed 0 MW Loadshed 423 MW 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.

C2 3-pha fault at St. Lucie E 230kV Bus, System Stable System Stable BRK 192 fails, at 8.8 cy open BRK Loadshed 0 MW Loadshed 423 MW 218 tripping St. Lucie-Midway#1 230kV line & clear fault.

C3 3-pha fault at St. Lucie on St. Lucie- System Stable System Stable Midway #2 230kV line. BRK 43 fails, Loadshed 0 MW Loadshed 423 MW

L-2010-144 Attachment 3 Page 23 of 30 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- System Stable System Stable Midway #3 230kV line. BRK 52 fails, Loadshed 0 MW Loadshed 423 MW At 4 cy open St. Lucie-Midway #3 at Midway. At 8.8 cy open BRK 49 tripping St. Lucie Unit #2 & clear fault.

C4a 3-pha fault at St. Lucie on St. Lucie- System Stable System Stable Midway #3 230kV line. BRK 55 fails, Loadshed 0 MW Loadshed 423 MW At 4 cy open St. Lucie-Midway #3 at Midway. At 8.8 cy open BRK 52 &

clear fault.

C5 3-pha fault at St. Lucie W 230kV Bus, System Stable System Stable BRK 43 fails, at 8.8 cy open BRK 40 Loadshed 0 MW Loadshed 423 MW tripping St. Lucie-Midway#2 230kV line & clear fault.

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

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

L-2010-144 Attachment 3 Page 24 of 30 APPENDIX IV SOUTHERN/FLORIDA TRANSMISSION INTERFACE ASSESSMENT

L-2010-144 Attachment 3 Page 25 of 30 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 uprate 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 Reliability Council (SERC).

PURPOSE:

The purpose of this portion of the FPL SLIEPUP 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 States interconnection reacting to replace such lost power source until additional generation is dispatched 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 queued 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 Southeastern 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 Company, 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 the 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 previously 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 SVC and an additional 482 MVAR of capacitor banks at Duval 500 kV substation and a 110 MVAR capacitor bank at Tocoi 230 kV substation.

L-2010-144 Attachment 3 Page 26 of 30 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 SLIEPUP and SL2EPUP projects will not adversely affect the current Southern to Florida transfer capabilities 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 studies 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.

L-2010-144 Attachment 3 Page 27 of 30 APPENDIX V Transmission Projects Assessment

L-2010-144 Attachment 3 Page 28 of 30 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 thescope of changes required to the FPL system for the uprates of St.

Lucie Units I and 2 respectively. The interconnection 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 (8G37,8G24,8G39,8G41,8G42,8G44), and #3 (8G48,8G50,8G51,8G53,8G54,8G56) must be replaced with 3000A switches.

The switchyard pulloff structures have been evaluated. The structures will be able to support the new increased string bus tension without upgrades. The study has identified improvements that will be required to all six structures to address long term reliability concerns.

A study has been conducted to determine the ability of the GSU dead end structures in the nuclear plant to support the new string-busses and if improvements or replacements are required. 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 IA and 1B coolers and low side bushings on IA, 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.

L-2010-144 Attachment 3 Page 29 of 30

2. SCOPE OF WORK (PROTECTION AND CONTROL)

This study evaluates the scope of changes required to the FPL transmission protection systems for the SL 1EPUP and SL2EPUP unit uprate projects.

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 control and reclosing at St. Lucie or Midway Substations.

Metering & Data Acquisition:

No Changes.

3. SCOPE OF WORK (TRANSMISSION)

St. Lucie Switchyard The existing string-buses at St. Lucie for both Unit#1 and Unit #2 must be upgraded to bundled 1272ACSR, with spacers.

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 previously 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.

L-2010-144 Attachment 3 Page 30 of 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 work 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.