Q95 Vicksburg 69kV. System Impact Study. APS Contract No Arizona Public Service Company Transmission Planning.

Transcription

1 A subsidiary of Pinnacle West Capital Corporation Q95 Vicksburg 69kV System Impact Study APS Contract No By Arizona Public Service Company Transmission Planning December 1, 2010 Version 2.6 Final Prepared by Utility System Efficiencies, Inc.

2 Q95 SYSTEM IMPACT STUDY TABLE OF CONTENTS EXECUTIVE SUMMARY Study Description and Assumptions Post Project Case Modeling Dynamic Data Reliability Criteria... 7 (Steady State) Power Flow Criteria Transient Stability Criteria Study Methodology Power Flow Post-Transient Transient Stability Results and Findings Power Flow and Post-Transient Analysis Flicker Analysis Transient Stability Analysis Short Circuit / Fault Duty Analysis Results & Findings Summary Cost & Construction Time Estimates LIST OF APPENDICES Appendix A Power Flow Diagrams Appendix B List of Contingencies Appendix C Transient Stability Modeling Appendix D Transient Stability Plots Page 1

3 EXECUTIVE SUMMARY This section summarizes the System Impact Study (SIS) results for a proposed generation interconnection of 20 MW in the Arizona Public Service (APS) system. Additional specific details of the proposed interconnection s impact on the surrounding transmission system can be found in the Results and Findings section of this report. Disclaimer Nothing in this report constitutes an offer of transmission service or confers upon the Interconnection Customer ( IC ) any right to receive transmission service. APS and other interconnected utilities may not have the Available Transmission Capacity to support the interconnection described in this report. It should also be noted that all results for the SIS are highly dependent upon the assumed topology and timing of new projects in the vicinity of the interconnection, which are subject to change. Background: Arizona Public Service Company ( APS ) received a valid small generator interconnection request for a proposed interconnection at Vicksburg Substation. The Applicant elected to bypass the Feasibility Study and proceed directly to the System Impact Study ( SIS ) phase of the Small Generator Interconnection Process ( SGIP ). On behalf of, and with the oversight of APS, Utility System Efficiencies, Inc. ( USE ) performed a SIS under the APS Tariff. The interconnection request was assigned queue position #95. The Applicant has proposed to add solar photo-voltaic generation with a maximum net output of 20MW, connecting to the Vicksburg 69kV bus in the fourth quarter of Figure E.1 illustrates this proposed interconnection and the nearby transmission facilities. Figure E-1. Q95 and Nearby Transmission Facilities This SIS used the machine parameters and characteristics provided by the Applicant. Analyses consisted of computer-based power flow analysis, transient stability analysis, post-transient analysis, voltage flicker analysis, and short circuit/fault duty analysis. This study modeled the proposed generation interconnection under 2012 Summer Peak conditions. Select contingencies which stressed the transmission system were simulated. Power flow, transient stability, and post-transient results were monitored for APS, WAPA, and other neighboring systems. Flicker was monitored for the buses in the immediate project area. System performance criteria used in the study: The criteria applied in this study are consistent with NERC/WECC Reliability Criteria. For more detailed information on the criteria used for each analysis see section 1.3 Reliability Criteria. Page 2

4 Results: The results of the study indicate that the there are two reliability violations caused by the addition of the Q95 project. One is an N-0 condition due to low voltages on the 69kV side of the Eagle Eye 230/69 kv transformer. The other is a voltage flicker concern with a 1.88% deviation as the project reduces its output from 100% to 10%. Both reliability violations can be eliminated by re-building the Salome-Vicksburg 69kV line to 795ACSS. Another mitigation option considered was reduction in plant output. Unfortunately the amount of MW reduction required was outside of the 15% reduction allowed at this phase of the process. In addition the transient stability data model provided by the IC has an error which results in high frequencies at the plant buses. This model will need to be revised so the unit does not trip offline for nearby faults on the transmission system. For the time being the over frequency protection has been disabled to move forward with the interconnection. Prior to the start of construction the IC will need to demonstrate that the new model fixes the problems and does not trip offline for nearby faults. Interconnection cost and timeline estimates are listed on the table below: Table 1.1 Summary of Project Interconnection Cost Facility Costs Timeline Network Upgrades $2,186, Months Q95 Trans. Provider's $1,238, Months Interconnection Facilities Grand Total $3,425, Months As can be seen in Table 1.1 above, the total estimated completion time for interconnecting the Q95 project is 36 to 48 months. Therefore, the desired In-Service Date of fourth quarter of 2012 cannot be met. APS and the Interconnection Customer must therefore discuss and mutually agree to a new and acceptable projected In-Service Date. Page 3

5 1 Study Description and Assumptions This section of the report provides details pertaining to the power flow case development and an overview of the major study assumptions. All power flow, transient, voltage flicker, and post-transient study work was completed using General Electric s Positive Sequence Load Flow (GE-PSLF), version 16.3_02. The study utilized two sets of base cases. For the 2012 power flow analysis, voltage flicker, and posttransient analysis the 2012 Heavy Summer APS detailed planning case sm12#18_q95.sav was used. This case has undergone review and updates by all of the Arizona utilities, for Arizona/regional planning purposes. This case does not have a corresponding dynamic data file so an additional base case was used for the transient stability study. The 2013 Heavy Summer APS detailed planning case sm13#10.sav was used. Similar to the 2012 case this case has undergone review and updates by all of the Arizona utilities, for Arizona/regional planning purposes. The load in this case was scaled to the 2012 level and the 2013 transmission projects were removed. There were no higher queued projects modeled in this study. A pre- and post-project base case was developed. The new generation was offset at the Palo Verde Hub (PV). The additional modifications described below were then used to develop the SIS base cases. All Cases: Base case changes 1) Study base case sm12#18.sav was obtained from APS Transmission Planning. General Changes 2) Changed all isolated/islanded busses from Type 0 to Type -4. Arizona Changes 3) The Palo Verde Devers line model was corrected. The conductor ratings were set to MVA normal and MVA emergency. The series capacitor ratings were set to MVA normal and MVA emergency. 4) Emergency ratings ( % of normal) were added to for selected APS 230/69kV transformers. 5) Emergency ratings of 1225MVA were added to the Four Corners 500/345kV transformer. 6) The Cholla-Saguaro 500kV line ratings were set to 1515MVA normal and 2046MVA emergency. 7) Emergency ratings of 717MVA were added to the Pinnacle Peak 500/230kV transformers. 8) The Yavapai-Verde 230kV line ratings were set to 318MVA normal and 374MVA emergency. 9) The Yavapai-Willow Lake 230kV line ratings were set to 306MVA normal and 354MVA emergency. 10) Moenkopi-Yavapai and Yavapai-Westwing 500kV series capacitors set to 25.7 Ohms each. 11) Pinto-Four Corners 345kV series capacitors were added (28.5 Ohms). 12) Emergency ratings of 750MVA were added to the Cholla 500/345kV transformers. 13) The Shiprock 345/230kV transformer was updated to reflect the recent transformer replacement. The new transformer is rated at 600MVA normal and 720MVA emergency. 14) Various shunt capacitors where switched to increase of lower bus voltages. Page 4

6 All Cases: Stability Base case changes 1) Study base case sm12#10_stab.sav was obtained from APS Transmission Planning. General Changes 2) Changed all isolated/islanded busses from Type 0 to Type -4. Arizona Changes 3) The Palo Verde Devers line model was corrected. The conductor ratings were set to MVA normal and MVA emergency. The series capacitor ratings were set to MVA normal and MVA emergency. 4) Emergency ratings ( % of normal) were added to for selected APS 230/69kV transformers. 5) Emergency ratings of 1225MVA were added to the Four Corners 500/345kV transformer. 6) The Cholla-Saguaro 500kV line ratings were set to 1515MVA normal and 2046MVA emergency. 7) Emergency ratings of 717MVA were added to the Pinnacle Peak 500/230kV transformers. 8) The Yavapai-Verde 230kV line ratings were set to 318MVA normal and 374MVA emergency. 9) The Yavapai-Willow Lake 230kV line ratings were set to 306MVA normal and 354MVA emergency. 10) Moenkopi-Yavapai and Yavapai-Westwing 500kV series capacitors set to 25.7 Ohms each. 11) Pinto-Four Corners 345kV series capacitors were added (28.5 Ohms). 12) Emergency ratings of 750MVA were added to the Cholla 500/345kV transformers. 13) The Shiprock 345/230kV transformer was updated to reflect the recent transformer replacement. The new transformer is rated at 600MVA normal and 720MVA emergency. 14) Remove the Youngs Canyon 345/69kV transformer. 15) Remove the Pinal Central connections, planned in-service date of ) Remove the San Manuel Loop-in to the Apache-Hayden 115kV line. 17) Scale the 2013 load and generation to the 2012 levels. 18) Various shunt capacitors were switched to increase or lower bus voltages. 1.1 Post Project Case Modeling Request #95 consists of 46 units each rated at 0.5 MVA. This was represented in the power flow model as a single 20 MW unit operated with a +/ power factor 1 range (+/-6.6MVAR dynamic capability) connected to a kv bus with a scheduled voltage of 1.03 p.u. A single transformer steps the voltage up from 12.47kV to 69 kv. The project was connected to the Vicksburg 69-kV bus by a 1 mile line. The 5 mile line from the Black Peak Eagle Eye 69 kv line to the Vicksburg bus was upgraded. The project model was provided by the applicant. Figure 1-1 represents the Q95 power flow model. The Utting Vicksburg Tap 69 kv line section is normally open, the addition of the project will mean that the Q95 Utting 69 kv line will be normally open. 1 As specified in the Tariff, Q95 will be required to possess the capability of providing +/ Power Factor at the POI when called upon by APS. Page 5

7 Utting 69 kv Vicksburg 69 kv N.O. 69 kv kv 20 MW +/-6.6 MVAR Figure 1-1: Q95 Power Flow Model Power scheduled to Palo Verde Red Hawk generation was reduced to offset the interconnection Power flow diagrams of the transmission system along with the new generation interconnection are provided in Appendix A. Table 1.2 summarizes the case attributes for each scenario. Table Case Attributes Pre- Project with Post- Project with mitigation Major Branch Flows Pre- Project Post- Project Pre- Project (Stability) Post- Project (Stability) mitigation Black Peak-Utting 69kV Vicksburg Tap-Utting 69kV Vicksburg Tap-Vicksburg 69kV Salome-Vicksburg Tap 69kV Eagle Eye-Salome 69kV Black Peak 161/69kV Transformer Eagle Eaye 230/69kV Transformer Parker-Eagle Eye 230kV Eagle Eye-Liberty 230kV Bouse-Black Peak 161kV Parker-Bouse 161kV Bouse-Kofa 69kV Q95-Vicksburg 69kV Arizona Area 14 (incl. WALC) AZ Load 19,909 19,909 20,548 20, AZ Lossess AZ Generation 28,109 28,109 29,269 29, AZ Exports 7,510 7,511 7,906 7, Case Page 6

8 1.2 Dynamic Data Appendix C provides the transient stability model used in this study, and the details of these assumptions. Modeling for the new generation utilized machine characteristics provided by the Applicant. A stability plot of the flat run simulation is also provided in Appendix C. Dynamic Data File 1. Dynamic data file stab_2013.dyd (developed by APS) was obtained from APS Transmission Planning. 2. Representation of Q95 model was added. 1.3 Reliability Criteria In general, an evaluation of the system reliability investigates the system s thermal loading capability, voltage performance (not too high or low), and transient stability (the system should not oscillate excessively and generators should remain synchronized). The evaluation of these criteria must be conducted for credible emergency conditions, such as loss of a single or double circuit line, a transformer, or a generator. Performance of the transmission system and neighboring Control Areas were measured against the Western Electricity Coordinating Council (WECC) Reliability Criteria and the North American Electric Reliability Council (NERC) Planning Standards described in the following subsections. The criteria for Category A (normal, All lines in service ) and Category B (single element outage) conditions were explicitly applied both internally (within APS system) and to external Control Areas. (Steady State) Power Flow Criteria Normal conditions All line loading must be less than 100% of the continuous (normal) thermal ratings. All transformer loading must be less than 100% of the continuous (normal) ratings. Contingency Conditions For a single (N-1) contingency, no transmission element will be loaded above the emergency rating. Established loading limits and voltage performance for other neighboring utilities will be monitored. deviations at any bus must be no more than 5% for N-1 contingencies and no more than 10% for N-2. Page 7

9 1.3.1 Transient Stability Criteria The SIS applies reliability criteria contained within the WECC disturbance-performance table of allowable effects on other systems. Table 1.3 and Figure 1-2 are excerpts from the WECC Reliability Criteria. Table 1.3 WECC Disturbance-Performance Table of Allowable Effects on Other Systems NERC and WECC Categories A System normal B One element out-of-service C Two or more elements out-of-service D Extreme multipleelement outages Outage Frequency Associated with the Performance Category (outage/year) Not Applicable Transient Dip Standard Not to exceed 25% at load buses or 30% at non-load buses. Not to exceed 20% for more than 20 cycles at load buses. Not to exceed 30% at any bus. Not to exceed 20% for more than 40 cycles at load buses. Minimum Transient Frequency Standard Nothing in addition to NERC Not below 59.6Hz for 6 cycles or more at a load bus. Not below 59.0Hz for 6 cycles or more at a load bus. < Nothing in addition to NERC Post Transient Deviation Standard Not to exceed 5% at any bus. Not to exceed 10% at any bus. Figure 1-2. NERC/WECC Performance Parameters Page 8

10 2 Study Methodology This section summarizes the methods used to derive the power flow, post transient, voltage flicker, and transient stability results. 2.1 Power Flow Power flow analysis considers a snapshot in time where the transformer tap changers and SVD s have had time to adjust, the phase shifters have not adjusted, and the system swing bus balances the system during each contingency scenario. All power flow analysis was conducted with version 16.3_02 of General Electric s PSLF/PSDS/SCSC software. Power flow results were monitored and reported for APS and other neighboring systems, including TEP and SRP. Traditional power flow analysis was used to evaluate the thermal and voltage performance of the system under Category A (all elements in service) and Category B (N-1, single contingency) conditions. The applicable WECC reliability planning criteria is listed below. Changes in bus voltages from pre- to post-contingency must be less than 5% for single contingencies. All equipment loadings must be below their normal ratings under normal conditions. All equipment loadings must be below their emergency ratings for single contingencies. Thermal loading was reported when a modeled transmission element was loaded over 98% of its appropriate MVA rating modeled in the power flow database and when the incremental change in loading, between Pre-Project and Post-Project, exceeded 1%. Transmission voltage violations for Category A (no contingency) conditions were reported where per unit voltages were less than 0.95 or greater than For Category B outages the voltage violations were reported when the post-contingency voltage deviation was greater than 5%. 2.2 Post-Transient Post-transient analysis determines if the voltage deviations at critical buses meet the maximum allowable voltage dip criteria and if any transmission elements exceed their maximum rating for selected Category B and Category C disturbances. This snapshot focuses on the first few minutes following an outage where the transformer tap changers have adjusted, the phase shifters and SVD s have not adjusted, and all of the system generation reacts by governor control to balance the system during each contingency scenario. All loads are modeled as constant power during the Post-Transient time frame. All voltages at distribution substations will be restored to their normal values by the transformer tap changers and other voltage control devices. Generator VAR limits will be modeled as a constant single value for each generator since the reactive power capability curve will not be modeled in the power flow program. Alpha min and Gamma min of the PDCI and IPPDC will be adjusted to 5 degrees and 13 degrees, respectively. Shunt capacitors (132 MVAR) at Adelanto and Marketplace will be used if the post-transient voltage deviation exceeds 5% at those buses. 2.3 Transient Stability Transient stability analysis is a time-based simulation that assesses the performance of the power system during (and shortly following) a contingency. Transient stability studies were performed to verify the system stability following a critical fault on the system. Prior to finalization of the power flow and dynamic Page 9

11 data set, a flat run and bump test were run to ensure true power system behavior was not masked by any remote dynamic modeling anomalies. Transient stability analysis was performed based on WECC Disturbance-Performance Criteria for selected system contingencies. Initial transient stability contingencies were simulated out to 11 seconds to ensure a damped system performance. All simulated faults were assumed to be three-phase. The following table identifies the breaker clearing times for faults on different voltage levels. Level Breaker clearing times 69 kv 7-cycles 115/161 kv 6-cycles 230 kv 5-cycles All transient stability simulations were conducted using version 16.3_02 of General Electric s PSLF/PSDS/SCSC software. The Worst Condition Analysis (WCA) tool, available in the PSDS software package, tracks and records the transient stability behavior of all output channels contained within the binary output file of a transient stability simulation. The monitoring of channel output was initiated two cycles after fault clearing, to ensure that all post-fault stability behavior would be captured. System damping was assessed visually with the aid of stability plots. Parameters Monitored to Evaluate System Stability Performance: Rotor Angle Rotor angle plots provide a measure for determining how the proposed generation unit would swing with respect to other generating units in the area. This information is used to determine if a machine would remain in synchronism or go out-of-step from the rest of the system following a disturbance. Bus Bus voltage plots, in conjunction with the relative rotor angle plots, provide a means of detecting out-of-step conditions. The bus voltage plots are useful in assessing the magnitude and duration of post-disturbance voltage dips and peak-to-peak voltage oscillations. Bus voltage plots also five an indication of system damping and the level to which voltages are expected to recover in the steady state conditions. Bus Frequency Bus frequency plots provide information on magnitude and duration of post-fault frequency swings with the new project(s) in service. These plots indicate the extent of possible overfrequency or under-frequency, which can occur due to an area s imbalance between load and generation. Other plotted Parameters Generator Terminal Generator Rotor Speed Page 10

12 3 Results and Findings This section provides the results obtained by applying the previous assumptions and methodology. It illustrates all findings associated with the power flow, post-transient, voltage flicker, and transient stability analysis. 3.1 Power Flow and Post-Transient Analysis The power flow and post-transient analysis focused on high load and generation conditions for summer of The Pre-Project cases were used as a baseline to measure the impact of the new generation and planned transmission upgrades. Contingencies were then applied to the cases. The list of contingencies simulated is provided in Appendix B. Selected power flow plots from the Pre-Project case under pre-contingency and postcontingency system conditions are included in Appendix A. Thermal Results There were no Pre-Project overloads in the base study scenario. The addition of the project did not cause any new overloads. Due to the normally open circuit between Utting and Vicksburg Tap 69kV loss of any section east of Vicksburg up to and including the Eagle Eye 69/230kV transformer cause the new unit to be tripped off. Results When modeling the project, a low voltage was seen at the Eagle Eye 69kV bus. APS maintains a standard that all 69kV buses connected to the transmission system be operated at 1.03 pu or as close as possible. Addition of the project reduces the voltage at the Eagle Eye 69kV bus to 1.02 pu or less. An attempt was made to increase the voltage by using the Salome 69kV capacitors. Addition of the capacitors caused voltages in the area greater than 1.05 pu. Mitigation for the voltage violation is to re-build the Salome-Vicksburg 69kV line section to 795ACSS. There were no contingency voltage violations due to the addition of the project generator. 3.2 Flicker Analysis flicker analysis was performed on the post-project case. Table 3.1 details the results of the voltage flicker analysis. The greatest flicker is observed at the Eagle Eye 69 kv bus with a 1.88% increase with Q95. This occurs as the unit(s) adjusts from 100% to 10% output. Per APS criteria Flicker on the 69kV system is no to exceed 1% for a change in the plant s output. Table 3.1 Flicker Results, Q95 100% Generation (base) 10% Generation 30% Generation 60% Generation 90% Generation Bus Deviation % Deviation % Deviation % Deviation % BLACK PK 69.00kV UTTING 69.00kV VICKSBRG 69.00kV SALOME 69.00kV EAGLEY W 69.00kV EAGLEYE kV Page 11

13 Mitigation for the violation is to re-build the Salome-Vicksburg 69kV line section to 795ACSS. Table 3.2 details the results of the voltage flicker with the line rebuild. Table 3.2 Flicker Results, Q95 w/mitigation 100% Generation (base) 10% Generation 30% Generation 60% Generation 90% Generation Bus Deviation % Deviation % Deviation % Deviation % BLACK PK 69.00kV UTTING 69.00kV VICKSBRG 69.00kV SALOME 69.00kV EAGLEY W 69.00kV EAGLEYE kV Transient Stability Analysis Twelve (12) transient stability outages were simulated in addition to the Flat Run. All of these transient stability simulations met Western Electricity Coordinating Council (WECC) Disturbance Performance Criteria. As referenced in the Reliability Criteria section of this report, the system should meet the following transient stability performance criteria for a NERC/WECC Category B disturbance (N-1): Transient voltage dip should not be below 25% at any load busses or 30% at any non-load busses at anytime. The duration of a transient voltage dip greater than 20% should not exceed 20 cycles at load busses. The minimum transient frequency should not fall below 59.6 Hz for more than 6 cycles at load busses. Appendix D contains transient stability plots of selected contingencies that provide a representative illustration of the transmission system s Pre-Project and Post-Project voltage response. A problem was identified with the original Q95 transient stability data provided by the applicant. The under-voltage trip setting #1 was set to trip the unit offline for a voltage drop below 0.5pu for longer than 0.02 sec (1.2 cycles). Since the clearing time in the 69kV system is 7 cycles, the unit would trip offline for any contingency near the project. APS recommended changing the delay to 8 cycles and the IC approved the change. The stability plots and results are based on the updated setting. The transient stability data model provided by the IC has an error which results in high frequencies at the plant buses. This model will need to be revised so the unit does not trip offline for nearby faults on the transmission system. For the time being the over frequency protection has been disabled to move forward with the interconnection. Prior to the start of construction the IC will need to demonstrate that the new model fixes the problems and does not trip offline for nearby faults. Page 12

14 Table 3.3 summarizes the results of the transient stability simulations where instability was noted. Pre-Project Post-Project Contingency 05_12HS_PRE 06_12HS_PST Black Peak-Utting 69kV No Violations No Violations Utting-Vicksburg 69kV No Violations No Violations Vicksburg Tap-Vicksburg 69kV No Violations No Violations Vicksburg Tap-Salome 69kV No Violations No Violations Salome-Eagle Eye 69kV No Violations No Violations Eagle Eye 69/230kV Transformer No Violations No Violations Black Peak 69/161kV No Violations No Violations Transformer Utting-Q95 69kV NA No Violations Q95-Vicksburg 69kV NA No Violations Utting 69/12kV Load Bank No Violations No Violations Vicksburg 69/12kV Load Bank No Violations No Violations Salome 69/12kV Load Bank No Violations No Violations 3.4 Short Circuit / Fault Duty Analysis Short circuit analysis of the proposed generator was performed by the APS Protection Department, using the CAPE program and parameters supplied by the Applicant. Fault duties were calculated for both single-phase to-ground and three-phase faults at substations busses in the immediate surrounding area before and after the proposed generator installation. The results presented here assume a worst-case scenario. Table 3.4 summarizes the results of the Short-Circuit analysis Station Base Case With Q95 Min. Brkr 3 Ph. (ka) X/R Ph-G (ka) X/R 3 Ph. (ka) X/R Ph-G (ka) X/R Rating -ka Q95 69kV NA NA NA NA As Required Black Peak 69kV Eagle Eye 69kV As can be seen from Table 3.4, the interconnection of the project does not cause the existing substation breakers to exceed their minimum rating. 3.5 Results & Findings Summary The results of the study indicate that there are two reliability violations caused by the addition of the Q95 project. One is an N-0 condition due to low voltages on the 69kV side of the Eagle Eye 230/69 kv transformer. The other is a voltage flicker concern with a 1.88% deviation as the project reduces its output from 100% to 10%. Both reliability violations can be eliminated by re-building the Salome-Vicksburg 69kV line to 795ACSS. Another mitigation option considered was reduction in plant output. Unfortunately the amount of MW reduction required was outside of the 15% reduction allowed at this phase of the process. In addition the transient stability data model provided by the IC has an error which results in high frequencies at the plant buses. This model will need to be revised so the unit does not trip offline for nearby faults on the transmission system. For the time being the over frequency protection has been disabled to move forward with the interconnection. Prior to the start of construction the IC will need to demonstrate that the new model fixes the problems and does not trip offline for nearby faults. Page 13

15 4 Cost & Construction Time Estimates The cost estimates represent good faith estimates necessary to interconnect to the system. The nonbinding, good faith cost and time estimates are tabulated below. Assumptions: Land Values will fluctuate based on specific location. Terrain was not considered when estimating line route. R.O.W. = 40 foot width. N.E.P.A. Process estimated at $3,000 per Mile. Access & Lay Down Yards are not included in the Estimate. Private acquisition could be 18 months if condemnation is required. Rough grading costs are not included in the estimate. APS will construct, own and operate the 69kV facilities in the Q95 substation and the portion of 69 kv line from the Q95 69 kv bus up to the Point of Interconnection. All estimates are in 2010 dollars. Table 4.1 Q95 Project Cost Summary Equipment Description Network Upgrades Transmission Provider's Interconnection Facilities Substation Work $86,000 $668, kv Line Work $2,033,884 $565,334 Communications $38,607 $0 Right of Way $28,400 $4,900 Subtotal $2,186,891 $1,238,234 Grand Total $3,425,125 The facilities identified in Table 4.1 above as Transmission Provider s Interconnection Facilities would be the sole cost of the Interconnection Customer. Unlike Network Upgrades, these costs are not reimbursable. Table 4.2 Q95 Construction Time Estimates Facility Schedule Design Construction Substation Work 6 Months 6 Month 69 kv Line Work 8 Months 10 Months Communications 6 Months Right of Way Months Grand Total Months The summary provided in Table 4.2 above shows a total estimated completion time of 36 to 48 months. Therefore, the desired In-Service Date of fourth quarter of 2012 cannot be met. APS and the Interconnection Customer must therefore discuss and mutually agree to a new and acceptable projected In-Service Date. Page 14

16 Table 4.3 Q95 Network Upgrade Cost Estimates Equipment Description Cost Estimate Engineering and Design $9,600 Below Grade Construction $0 Above Grade Construction $0 Labor (Steel, Bus, & Equipment) Control/Relay Labor $30,000 Equipment/Relay/RTU/Security $46,400 Steel Structures $0 Land $0 Services/Siting/Permit/Etc 69kV Single Circuit $1,918,298 SA - VB 69kV Line Rebuilt $115,586 2 Communications $38,607 69kV Line Right of Way $28,400 Grand Total $2,186,891 Network Upgrades Estimates: are anticipated to consist of the above listed $2,186,891 shown for construction of Q95, Control, Communications, and Relay Protection Requirements. Network Upgrades are typically repaid to the customer per FERC Rules, as transmission credits and/or repaid within a 20 year period. Table 4.4 Q95 Transmission Provider s Interconnection Facilities Cost Estimates Equipment Description Cost Estimate Engineering and Design $78,000 Below Grade Construction $189,600 Above Grade Construction $49,200 Labor (Steel, Bus, & Equipment) Control/Relay Labor $51,600 Equipment/Relay/RTU/Security $285,600 Steel Structures $14,000 Land $0 Services/Siting/Permit/Etc 69kV Single Circuit $565,334 SA - VB 69kV Line Rebuilt $0 Communications $0 69kV Line Right of Way $4,900 Grand Total $1,238,234 2 The $115,586 estimate represents the cost of advancing the planned Salome tap Vicksburg tap 69kV line rebuilt from 2014 to Page 15

17 Figure 4.1 shows a single line diagram of the build-out for Q95 s interconnection facilities Page 16