transmission interconnection study 660 mw hvdc near newman …

XXXXXXXXXXXXXXXXXXX

TRANSMISSION INTERCONNECTION

FEASIBILITY STUDY

FATAL FLAW ANALYSIS

System Operations Department System Planning Section

January 2002

TABLE OF CONTENTS 1.0 Executive Summary ......................................................................................... Page 1 2.0 Cost Estimates .................................................................................................. Page 3

2.1 Task II .................................................................................................... Page 3 2.1.1 Task II, Scenario A System Modification Costs ......................... Page 3

2.1.1.1 Interconnection Costs For Task II.................................. Page 3 2.1.1.2 System Modification Costs to Deliver Output to Grid .. Page 4

2.1.2 Task II, Scenario B System Modification Costs ......................... Page 5 2.1.3 Task II, Scenario C System Modification Costs ......................... Page 6 2.1.4 Task II, Scenario D System Modification Costs ......................... Page 6 2.2 Task III................................................................................................... Page 7 2.2.1 Task III, Scenario A System Modification Costs........................ Page 7

2.2.1.1 Interconnection Costs For Task III ................................ Page 7 2.2.1.2 System Modification Costs to Deliver Output to Grid .. Page 8 2.2.2 Task III, Scenario B System Modification Costs ........................ Page 9 2.2.3 Task III, Scenario C System Modification Costs ........................ Page 9 2.2.4 Task III, Scenario D System Modification Costs........................ Page 10

3.0 Introduction...................................................................................................... Page 11

3.1 Assumptions........................................................................................... Page 12 3.2 Criteria ................................................................................................... Page 12 3.3 Procedure ............................................................................................... Page 12

3.3.1 Base Case Development .............................................................. Page 13 3.3.2 List Of Contingencies.................................................................. Page 14 3.3.3 Transient Stability Analysis ........................................................ Page 14 3.3.4 Q-V Analysis ............................................................................... Page 15 3.3.5 Short-Circuit Analysis................................................................. Page 15 4.0 Powerflow Analysis Results ............................................................................ Page 16

4.1 Task I .................................................................................................... Page 16

4.2 Task II .................................................................................................... Page 17 4.2.1 Task II, Scenario A...................................................................... Page 18 4.2.2 Task II, Scenario B...................................................................... 1

4.2.3 Task II, Scenario C...................................................................... Page 23 4.2.4 Task II, Scenario D...................................................................... Page 25

Transmission Interconnection Feasibility Study i El Paso Electric Company For XXXXXXXXXXXXX January 2002

4.3 Task III................................................................................................... Page 26 4.3.1 Task III, Scenario A .................................................................... Page 27 4.3.2 Task III, Scenario B..................................................................... 0

4.3.3 Task III, Scenario C..................................................................... Page 32 4.3.4 Task III, Scenario D .................................................................... Page 34

5.0 Transient Stability Analysis Results .............................................................. Page 36 5.1 Task I ..................................................................................................... Page 36

5.2 Task II .................................................................................................... Page 36 5.2.1 Task II, Scenario A...................................................................... Page 36

5.2.2 Task II, Scenario B...................................................................... Page 37 5.2.3 Task II, Scenario C...................................................................... Page 37 5.2.4 Task II, Scenario D...................................................................... Page 38 5.3 Task III................................................................................................... Page 38 5.3.1 Task III, Scenario A .................................................................... Page 38 5.3.2 Task III, Scenario B..................................................................... Page 39

5.3.3 Task III, Scenario C..................................................................... Page 39 5.3.4 Task III, Scenario D .................................................................... Page 40

6.0 Q-V Analysis Results ....................................................................................... Page 41 6.1 Task I ..................................................................................................... Page 41 6.2 Task II .................................................................................................... Page 42 6.2.1 Task II, Scenario A...................................................................... Page 42 6.2.2 Task II, Scenario B...................................................................... Page 43 6.2.3 Task II, Scenario C...................................................................... Page 43 6.2.4 Task II, Scenario D...................................................................... Page 43 6.3 Task III................................................................................................... Page 44 6.3.1 Task III, Scenario A .................................................................... Page 44 6.3.2 Task III, Scenario B..................................................................... Page 45 6.3.3 Task III, Scenario C..................................................................... Page 45 6.3.4 Task III, Scenario D .................................................................... Page 46 7.0 Disclaimer ......................................................................................................... Page 47 8.0 Certification...................................................................................................... Page 48

Transmission Interconnection Feasibility Study ii El Paso Electric Company For XXXXXXXXXXXXX January 2002

APPENDICIES Transmission Interconnection Feasibility Study: Study Scope ..............................Appendix 1 EPE FERC Form 715..............................................................................................Appendix 2 Load and Resources Tables ....................................................................................Appendix 3 Powerflow Maps ....................................................................................................Appendix 4 List of Contingencies .............................................................................................Appendix 5 XXX Stability Parameters ......................................................................................Appendix 6 Base Case & Contingency Criteria Violation Tables ............................................Appendix 7 Transient Stability Plots .........................................................................................Appendix 8 Q-V Plots ................................................................................................................Appendix 9 XXX HVDC Interconnection One-line diagrams.................................................Appendix 10

Transmission Interconnection Feasibility Study iii El Paso Electric Company For XXXXXXXXXXXXX January 2002

1.0 EXECUTIVE SUMMARY On February 14, 2001, XXXXXXXXXXXXXX (XXX) submitted to El Paso Electric Company (EPE) a request for a Transmission and Facilities Study with the intention of requesting a Fatal Flaw and Feasibility Analysis. This request was made concerning XXX’s plans to construct facilities needed to interconnect a High Voltage Direct Current (HVDC) terminal into the EPE transmission system in the 2003 time frame. Subsequently, EPE and XXX signed an Agreement for a Feasibility Transmission Interconnection Study. Pursuant to the above Agreement, on September 10, 2001 EPE and XXX signed a Feasibility Transmission Interconnection Study: Study Scope (Appendix 1). This Study Scope discussed the system studies to be conducted by EPE concerning the proposed XXX interconnection. The study analyzed two 330 MW HVDC terminals interconnected into the EPE transmission system, for a total of 660 MW. Heavy Summer (HS) and Light Winter (LW) benchmark cases without the XXX interconnection were developed for the year 2003. These benchmark cases included potential generation that may be interconnected into the EPE system ahead of the XXX interconnection. These included the following: 1) 600 MW of generation interconnected at the Luna 345 kV Substation, 2) 135 MW of generation interconnected to EPE’s Luna-Newman 345 line, and 3) 380 MW of generation interconnected at the Newman 115 kV Substation. Results of the benchmark case analyses are listed under the Task I sections of this report. The Task I “Benchmark” cases were established by integrating the latest available EPE and New Mexico system representations with the existing WSCC 03HS2SA case. In the Task I cases, New Mexico utilities were flagged for criteria violations. Consequently, these initial system criteria violations are not due to the interconnection of the XXX HVDC terminal. It is suspected that most of these criteria violations probably do not exist and may be a result of EPE not having the latest system representations of the utilities in question. Two alternatives were analyzed in the Study. Alternative #1 modeled the interconnection into a new substation connecting the Newman-Caliente 345 kV and Amrad-Caliente 345 kV lines. Analyses for Alternative #1 are listed under the Task II sections of this report. Alternative #2 modeled the interconnection directly into EPE’s Newman 345 kV bus. Analyses for Alternative #2 are listed under the Task III sections of this report. The results from analyses of Task II and Task III were then compared against results from Task I to determine the impacts due to the interconnection of the XXX HVDC terminal. Under Task II and Task III, four (4) scenarios were analyzed. Scenario A was the Interconnection scenario. It modeled the imported power from XXX as being distributed throughout all the Western Systems Coordinating Council (WSCC) without a specific transmission path. Scenario’s B, C, and D were performed at the request of XXX and modeled transmission scenarios, which specified transmission paths for each particular scenario. Scenario B analyzed the impacts of transferring the XXX power west (California) of the EPE area. Scenario C analyzed the impacts of transferring the XXX

Transmission Interconnection Feasibility Study -1- El Paso Electric Company For XXXXXXXXXXXXXXXXX January 2002

power north (northern New Mexico and Colorado) of the EPE area. Scenario D analyzed the impacts of transferring the XXX power to both the EPE area and throughout the other WSCC areas. The purpose of this study was to identify all “Fatal Flaws” on the southern New Mexico system if XXX is to interconnect its HVDC terminal into the EPE transmission system. Any additional facilities needed to correct these “fatal flaws” are noted and “rough estimates” of the costs of these facilities are provided in this study.

The Study Scope Agreement was used as a guide by EPE to conduct its system studies, which included power flow, Q-V reactive margin, and transient stability analyses. A short-circuit analysis was not performed because XXX consultants advised EPE that the DC Lite technology they propose to use for the HVDC terminal interconnection acts as a constant voltage source and does not contribute any fault current into the system. Therefore, a short-circuit analysis for this study is not required. However, if it is determined later that the proposed DC Lite technology does contribute fault current into the system, a short-circuit study will be required to verify that the existing circuit breaker interruption ratings are not exceeded due to the interconnection of the XXX HVDC terminal. Results of the study indicate that numerous impacts occur in the existing southern New Mexico system when the XXX HVDC terminal is interconnected into the EPE transmission system. Utilizing engineering judgement, proposed system modifications are included in the Study, which, in EPE’s opinion, will correct the criteria violations and “rough” estimates for these proposed modifications to EPE’s system are provided. The study also shows that modifications will be needed to other southern New Mexico area utility’s systems. These include Public Service Company of New Mexico (PNM), Texas-New Mexico Power Company (TNMP), and Tri-State Generation & Transmission Association (Tri-State). System modifications are also proposed to correct the system impacts to the utilities mentioned above, and “rough” cost estimates (using EPE’s prices) are provided. As per the Study Scope, further evaluation of the system with the recommended modifications installed has not been performed. Therefore, these modifications may not represent the optimal solution in correcting the impacts to the system. The requestor (XXX) will need to follow up with the other utilities in question to mitigate the impacts and to get more detailed cost estimates of the recommended system modifications. The lists of recommended system modifications for EPE, as well as for the other southern New Mexico utilities, along with the estimated "rough" costs, are shown in the following section of this report (Section 2.0) for each of the scenarios analyzed.


2.0 COST ESTIMATES The following estimated costs are for system modifications to the EPE and other neighboring utilities systems required to correct the criteria violations due to the interconnection of the XXX HVDC terminal into the EPE transmission system. The XXX’s interconnection was analyzed as two 330 MW HVDC terminals (660 MW total) interconnected into the EPE transmission system in the 2003 heavy summer and light winter seasons. These costs are “rough” estimates only. Project dollar amounts shown are in year 2001 U.S. dollars. Costs for system modifications to other neighboring utilities’ systems are also only “rough” estimates using EPE’s prices and approximate transmission line distances.

2.1 Task II

The Task II Alternative simulated the XXX HVDC terminal interconnection, totaling 660 MW, as being interconnected into the EPE transmission system at a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Four scenarios were analyzed in Task II. Scenario A analyzed the impacts of interconnecting the XXX HVDC terminal into the EPE system and delivering the output into the grid. This scenario determined XXX’s minimum responsibility for interconnecting into the EPE transmission system. Scenarios B, C, and D analyzed specific transmission service scenarios, which determined costs in addition to those in Scenario A. Below is a description of each Scenario in Task II, including estimated costs.

2.1.1 Task II, Scenario A System Modification Costs:

XXX power totaling 660 MW is interconnected into the EPE transmission system at a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines and distributed throughout the WSCC area. This simulates the interconnection of the XXX HVDC terminal into the EPE system and the distribution of that power without a specific transmission path. This scenario determines the impacts, modifications, and costs required to interconnect the proposed project and deliver its output to the grid. As per the Federal Energy Regulatory Commission (FERC), this scenario determines the project interconnection costs. Estimated costs for this scenario are divided into two categories a) Interconnection Costs, and b) System Modification Costs to Deliver Output to the Grid. These estimated costs are listed below:

2.1.1.1 Interconnection Costs For Task II The following table shows the estimated costs necessary for XXX to physically interconnect into a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. This estimate is for the physical interconnection only and does not include the costs associated with delivering its power to the grid. This estimated cost applies to all scenarios in Task II and is in addition to the “System Modification


Costs” estimated for each scenario. The second XXX-Newman line is required because an outage of the first XXX-Newman line creates overloads on the EPE 345 kV and 115 kV system near the Newman power plant. These include overloading both Newman 345/115 kV autotransformers and some 115 kV lines connected to the Newman 115 kV bus. The second XXX-Newman 345 kV line will prevent these overloads from occurring. The cost of adding the second XXX-Newman 345 kV line is far less expensive than correcting all of the overloaded facilities in the area during that outage. In addition to the facilities listed below, the reactor on the Caliente-Amrad 345 kV line may need to be changed out for all scenarios in Task II. This is because the length of the line will be shortened with the new substation intersecting this line. An analysis of this will need to be performed in a more detailed “Facilities Study” to determine if any change is required. Costs for this have not been included here.

INTERCONNECTION COSTS FOR TASK II

FACILITY MODIFICATION

OWNER

ESTIMATED COST

2nd XXX-Newman 345 kV line (4 miles) EPE $920,000 (13) 345 kV Gas Circuit Breakers EPE $3,575,000 (26) 345 kV Motor operated disconnect switches EPE $650,000 (5) Dead End Towers EPE $100,000 (1) Protection Scheme EPE $50,000 (1) Controls Equipment EPE $20,000 (1) Communication Scheme EPE $25,000

Total Interconnection Costs for Task II: $5,340,000

Please note that the above cost is a "rough" estimate only and may change when detailed engineering and design studies are performed for the interconnection into the new substation. Please refer to Appendix 10 for the one-line diagram of the proposed XXX HVDC terminal interconnection for Task II.

2.1.1.2 System Modification Costs to Deliver Output To Grid In addition to the estimated costs in Section 2.1.1.1, this section shows the system modifications and costs necessary to deliver the 660 MW of XXX power to the grid. Scenario A simulates the interconnection of the XXX HVDC terminal into the EPE system and the distribution of that power throughout the WSCC area without a specific transmission path. This scenario determines the impacts, modifications, and costs required to interconnect the proposed project and deliver its output to the grid. WSCC area loads, including EPE’s, were proportionally increased by 660 MW in order to distribute the imported XXX power. The following table describes the modifications necessary to deliver the XXX imported power into the WSCC transmission grid:


TASK II SYSTEM MODIFICATION COSTS TO DELIVER OUTPUT TO GRID


OWNER

ESTIMATED COST

Change out Taps on Arroyo 345 kV PST EPE $4,000,000 Anthony-Newman 115 kV line upgrade (12.3 miles) EPE $2,700,000 Arroyo-Las Cruces 115 kV line upgrade (4.1 miles) EPE $900,000 Cromo-ANP 115 kV line upgrade (19.9 miles) EPE $4,380,000 Second 200 MVA Arroyo 345/115 kV XFMR EPE $4,500,000 Second 100 MVA Milagro 115/69 kV XFMR EPE $600,000 Third 200 MVA Arroyo 345/115 kV XFMR EPE $4,500,000 Third 200 MVA Caliente 345/115 kV XFMR EPE $4,500,000 Third 200 MVA Newman 345/115 kV XFMR EPE $4,500,000 Austin-Dyer 69 kV line upgrade (2.2 miles) EPE $473,000 Elephant Butte-Socorro 115 kV line upgrade (85 miles) Tri-State $18,700,000 Elephant Butte-Picacho 115 kV line upgrade (50 miles) Tri-State $11,000,000 Las Cruces-Dona Ana 115kV line upgrade (5 miles) Tri-State $1,100,000 Hurley-Luna 115 kV line upgrade (12 miles) TNMP $2,640,000 Central-Hurley 115 kV line upgrade (18) miles TNMP $3,960,000 SVG for voltage support in TNP/Tri-State areas TNMP/Tri-State $5,000,000

Total System Modification Costs to deliver output to grid: $73,453,000

Therefore, the total estimated cost for Task II, Scenario A is $78,793,000. This is the estimated amount that, as per FERC, XXX is responsible for in order to correct the impacts caused by its interconnection into the EPE system and delivery of its output into the grid in a Task II interconnection configuration. All estimated costs in Scenarios B, C, and D are in addition to the costs determined in Scenario A.

2.1.2 Task II, Scenario B System Modification Costs:

XXX power totaling 660 MW is imported into the EPE transmission system at a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines and sold to California. This simulates the interconnection of the XXX HVDC terminals into the EPE transmission system and a XXX transmission agreement that allows XXX to sell all of its power to California. Generation in the Pacific Gas and Electric (PG&E) area was reduced by 660 MW in order to distribute the imported XXX power. Estimated costs for this scenario are in addition to those determined in Section 2.1.1.

TASK II, SCENARIO B SYSTEM MODIFICATION COSTS


OWNER

ESTIMATED COST

Luna-Hidalgo 345 kV line upgrade (50.5 miles) EPE $11,615,000 Belen-Bernardo 115 kV line upgrade (15 miles) Tri-State $3,300,000 Bernardo-Socorro 115 kV line upgrade (20 miles) Tri-State $4,400,000

Total Incremental Costs for Task II, Scenario B: $19,315,000


Therefore, the total estimated cost for Task II, Scenario B, including the costs shown in Section 2.1.1, is $98,108,000. 2.1.3 Task II, Scenario C System Modification Costs:

XXX power totaling 660 MW is imported into the EPE system at a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines and sold to northern New Mexico and Colorado. This simulates the interconnection of the XXX HVDC terminal into the EPE system and a XXX transmission agreement that allows XXX to sell all of its power north of the EPE system to northern New Mexico and Colorado. Generation in the Public Service Company of New Mexico (PNM) area and the Public Service Company of Colorado (PSCO) area were reduced by a total of 660 MW in order to distribute the imported XXX power. Estimated costs for this scenario are in addition to those determined in Section 2.1.1.

TASK II, SCENARIO C SYSTEM MODIFICATION COSTS


OWNER ESTIMATED

COST Dyer-Shearman 115 kV line upgrade (9.63 miles) EPE $2,119,000 Butterfield-ANP115 kV line upgrade (16.7 miles) EPE $3,674,000 Hernandez-Ojo 115 kV line upgrade (17 miles) Tri-State $3,740,000 Bernardo-Socorro 115 kV line upgrade (20 miles) Tri-State $4,400,000 Belen-Bernardo 115 kV line upgrade (15 miles) Tri-State $3,300,000

Total Incremental Costs for Task II, Scenario C: $17,233,000

Therefore, the total estimated cost for Task II, Scenario C, including the costs shown in Section 2.1.1, is $96,026,000. 2.1.4 Task II, Scenario D System Modification Costs:

XXX power totaling 660 MW is imported into the EPE system at a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines and sold to EPE and throughout the WSCC. This simulates the interconnection of the XXX HVDC terminal into the EPE system and a XXX transmission agreement that allows XXX to sell half of its power to EPE and the other half throughout the WSCC area. Generation in the EPE area was reduced by 330 MW and loads in the other WSCC areas were increased by 330 MW in order to distribute the imported XXX power.

No additional modifications other than the ones described in Section 2.1.1 were required for Scenario D. Therefore, the total estimated cost for Task II, Scenario D, including the costs shown in Section 2.1.1, is $78,793,000.


2.2 Task III

The Task III Alternative simulated the XXX HVDC terminal interconnection, totaling 660 MW, as being interconnected directly into the EPE transmission system at the Newman 345 kV bus. The same four scenarios analyzed in Task II were also analyzed in Task III. Scenario A analyzed the impacts of interconnecting the XXX HVDC terminal into the EPE system and delivering its power output into the grid. This scenario determined XXX’s minimum responsibility for interconnecting into the EPE transmission system. Scenarios B, C, and D analyzed specific transmission service scenarios, which determined costs in addition to those in Scenario A. Below is a description of each Scenario in Task III, including estimated costs.

2.2.1 Task III, Scenario A System Modification Costs:

XXX power totaling 660 MW is interconnected into the EPE transmission system at the Newman 345 kV bus and distributed throughout the WSCC area. This simulates the interconnection of the XXX HVDC terminal into the EPE system and the distribution of that power without a specific transmission path. This scenario determines the impacts, modifications, and costs required to interconnect the proposed project and deliver its output to the grid. As per the Federal Energy Regulatory Commission (FERC), this scenario determines the project interconnection costs. Estimated costs for this scenario are divided into two categories a) Interconnection Costs, and b) System Modification Costs to Deliver Output to the Grid. These estimated costs are shown below:

2.2.1.1 Interconnection Costs For Task III: The following table shows the estimated costs necessary for XXX to physically interconnect its HVDC terminal directly into the Newman 345 kV bus. This estimated cost applies to all scenarios in Task III and is in addition to the “System Modification Costs” estimated for each scenario.

INTERCONNECTION COSTS FOR TASK III


OWNER ESTIMATED

COST (1) 345 kV Gas Circuit Breaker EPE $275,000 (2) 345 kV Motor operated disconnect switches EPE $50,000 (1) Dead End Tower EPE $20,000 (1) Protection Scheme EPE $50,000 (1) Controls Equipment EPE $20,000 (1) Communication Scheme EPE $25,000

Total Interconnection Costs for Task III: $440,000

Please note that the above cost is a "rough" estimate only and may change when detailed engineering and design studies are performed for the interconnection into the Newman 345 kV bus. Please refer to


Appendix 10 for the one-line diagram of the proposed XXX HVDC interconnection of Task III.

2.2.1.2 System Modification Costs to Deliver Output To Grid In addition to the estimated costs in Section 2.2.1.1, this section shows the system modification costs necessary to deliver the 660 MW of XXX power to the grid. Scenario A simulates the interconnection of the XXX HVDC terminal into the EPE system and the distribution of that power throughout the WSCC area without a specific transmission path. This scenario determines the impacts, modifications, and costs required to interconnect the proposed project and deliver its output to the grid. WSCC area loads, including EPE’s, were proportionally increased by 660 MW in order to distribute the imported XXX power. The following table describes the modifications necessary to deliver the XXX imported power into the WSCC transmission grid:

TASK III SYSTEM MODIFICATION COSTS

TO DELIVER OUTPUT TO GRID


OWNER ESTIMATED

COST Change out Taps on Arroyo 345 kV PST EPE $4,000,000 Arroyo-Las Cruces 115 kV line upgrade (4.1 miles) EPE $900,000 Anthony-Newman 115 kV line upgrade (12.3 miles) EPE $2,700,000 Cromo-ANP 115 kV line upgrade (19.9 miles) EPE $4,380,000 Second 200 MVA Arroyo 345/115 kV XFMR EPE $4,500,000 Second 100 MVA Milagro 115/69 kV XFMR EPE $600,000 Third 200 MVA Arroyo 345/115 kV XFMR EPE $4,500,000 Third 200 MVA Caliente 345/115 kV XFMR EPE $4,500,000 Third 200 MVA Newman 345/115 kV XFMR EPE $4,500,000 Newman-Vista 115 kV line (20.4 miles) EPE $4,488,000 Austin-Dyer 69 kV line upgrade (2.2 miles) EPE $473,000 Elephant Butte-Socorro 115 kV line upgrade (85 miles) Tri-State $18,700,000 Elephant Butte-Picacho 115 kV line upgrade (50 miles) Tri-State $11,000,000 Las Cruces-Dona Ana 115kV line upgrade (5 miles) Tri-State $1,100,000 Hurley-Luna 115 kV line upgrade (12 miles) TNMP $2,640,000 Central-Hurley 115 kV line upgrade (18) miles TNMP $3,960,000 SVG for voltage support in TNP/Tri-State areas TNMP/Tri-State $5,000,000


Therefore, the total estimated cost for Task III, Scenario A is $78,381,000. This is the estimated amount that, as per FERC, XXX will be responsible for in order to interconnect into the EPE system and deliver its output into the grid in a Task III interconnection configuration. All estimated costs in Scenarios B, C, and D are in addition to the costs determined in Scenario A.


2.2.2 Task III, Scenario B System Modification Costs:

XXX power totaling 660 MW is imported into the EPE system directly at the Newman 345 kV bus and sold to California. This simulates the interconnection of the XXX HVDC terminal into the EPE system and a XXX transmission agreement that allows XXX to sell all of its power to California. Generation in the Pacific Gas and Electric (PG&E) area was reduced by 660 MW in order to distribute the imported XXX power.

TASK III, SCENARIO B SYSTEM MODIFICATION COSTS


OWNER

ESTIMATED COST

Luna-Hidalgo 345 kV line upgrade (50.5 miles) EPE $11,615,000 Las Cruces-Dona Ana 115kV line upgrade (5 miles) Tri-State $1,100,000 Belen-Bernardo 115 kV line upgrade (15 miles) Tri-State $3,300,000 Bernardo-Socorro 115 kV line upgrade (20 miles) Tri-State $4,400,000

Total Incremental Costs for Task III, Scenario B: $20,415,000

Therefore, the total estimated cost for Task III, Scenario B, including the costs shown in Section 2.2.1, is $98,796,000.

2.2.3 Task III, Scenario C System Modification Costs:

XXX power totaling 660 MW is imported into the EPE system directly at the Newman 345 kV bus and sold to northern New Mexico and Colorado. This simulates the interconnection of the XXX HVDC terminal into the EPE system and a XXX transmission agreement that allows XXX to sell all of its power north of the EPE system to northern New Mexico and Colorado. Generation in the Public Service Company of New Mexico (PNM) area and the Public Service Company of Colorado (PSCO) area were reduced by a total of 660 MW in order to distribute the imported XXX power.

TASK III, SCENARIO C SYSTEM MODIFICATION COSTS


OWNER

ESTIMATED COST

Dyer-Shearman 115 kV line upgrade (9.63 miles) EPE $2,119,000 Cromo-ANP115 kV line upgrade (19.9 miles) EPE $4,378,000 Butterfield-ANP115 kV line upgrade (16.7 miles) EPE $3,674,000 Austin N-Chevron S 115 kV line upgrade (1.2 miles) EPE $264,000 Shearman-ANP 115 kV line upgrade (7.26 miles) EPE $1,597,000 Hernandez-Ojo 115 kV line upgrade (17 miles) Tri-State $3,740,000 Bernardo-Socorro 115 kV line upgrade (20 miles) Tri-State $4,400,000 Belen-Bernardo 115 kV line upgrade (15 miles) Tri-State $3,300,000 Total Incremental Costs for Task III, Scenario C: $23,472,000

Therefore, the total estimated cost for Task III, Scenario C, including the costs shown in Section 2.2.1, is $101,853,000.


2.2.4 Task III, Scenario D System Modification Costs:

XXX power totaling 660 MW is imported into the EPE system directly at the Newman 345 kV bus and sold to EPE and throughout the WSCC. This simulates the interconnection of the XXX HVDC terminal into the EPE system and a XXX transmission agreement that allows XXX to sell half of its power to EPE and the other half throughout the WSCC area. Generation in the EPE area was reduced by 330 MW and loads in the other WSCC areas were increased by 330 MW in order to distribute the imported XXX power.

No additional modifications other than the ones described in Section 2.2.1 were required for Task III, Scenario D. Therefore, the total estimated cost for Task III, Scenario D, including the costs shown in Section 2.2.1, is $78,381,000.


3.0 INTRODUCTION This system study is in response to a request for a Feasibility Transmission/Generation Interconnection Study by XXXXXXXXXXXXX (XXX) to determine any “Fatal Flaws” in XXX’s plan to interconnect a High Voltage Direct Current (HVDC) terminal into the EPE transmission system. The study analyzed the 2003 Heavy Summer and 2003 Light Winter time periods. Two alternatives were analyzed in the Study. Alternative #1 modeled the interconnection into a new substation connecting the Newman-Caliente 345 kV and Amrad-Caliente 345 kV lines. Analyses for Alternative #1 are listed under the Task II sections of this report. Alternative #2 modeled the interconnection directly into EPE’s Newman 345 kV bus. Analyses for Alternative #2 are listed under the Task III sections of this report. The proposed XXX project was modeled as two 330 MW DC terminals for a total of 660 MW of power being interconnected into the EPE transmission system. Four Scenarios were analyzed in each of the two Tasks described above. Scenario A was the interconnection scenario. It modeled the imported power from XXX as being distributed throughout all the Western Systems Coordinating Council (WSCC) without a specific transmission path. Scenario’s B, C, and D were performed at the request of XXX and modeled transmission service scenarios, which specified transmission paths for each particular scenario. Scenario B analyzed the impacts of transferring the XXX power west (California) of the EPE area. Scenario C analyzed the impacts of transferring the XXX power north (northern New Mexico and Colorado) of the EPE area. Scenario D analyzed the impacts of transferring the XXX power to both the EPE area and throughout the other WSCC areas. As part of the evaluation process in studying the impact of the XXX interconnection on the southern New Mexico transmission system, EPE conducted powerflow, transient stability, and Q-V reactive margin analyses. A short-circuit analysis was not performed because XXX consultants advised EPE that the proposed DC Lite technology they propose to use for the HVDC terminal interconnection acts as a constant voltage source and does not contribute any fault current into the system. Based on this information, a short-circuit analysis for this study is not required. However, if it is determined later that the proposed DC Lite technology does contribute fault current into the system, a short-circuit study will be required to verify that the existing circuit breaker interruption ratings are not exceeded due to the interconnection of the XXX HVDC terminal. Results of the analyses indicate that numerous impacts in the EPE area occur when the XXX HVDC terminal is interconnected into the EPE transmission system. Utilizing engineering judgement, proposed system modifications and “rough” estimates for these proposed modifications have been made, which, in EPE’s opinion, will correct the criteria violations. In addition, the analysis showed that system modifications would be needed to correct criteria violations in other surrounding southern New Mexico area utility systems. Criteria violations were found on the transmission systems of Public Service Company of New Mexico (PNM), Texas-New Mexico Power Company (TNMP) Transmission Interconnection Feasibility Study -11- El Paso Electric Company For XXXXXXXXXXXXXXXXX January 2002

and Tri-State Generation & Transmission Association (Tri-State). System modifications were also proposed to correct the criteria violations in these utilities’ areas and “rough” cost estimates using EPE’s prices were provided. However, because EPE did not evaluate the system with these modifications installed, these modifications may not represent an optimal solution. It should be noted that study results are based on the latest information available to EPE at the time of the analysis and some of the criteria violations revealed in the benchmark case may not really exist. These benchmark criteria violations were noted in the study and were not considered impacts due to the interconnection of the XXX HVDC terminal.

3.1 Assumptions

The following assumptions are consistent for all study scenarios unless otherwise noted:

• Project dollar amounts shown are in year 2001 U.S. dollars. • Costs of the XXX facilities are separate and are not included in this study. • This study assumes that EPE substation space is available for the system

modifications recommended. • The cost estimates are only “rough” estimates using EPE prices. Costs for

modifications on the other utilities systems are also “rough” estimates using EPE prices.

• The recommended modifications were not re-analyzed to determine if they corrected the criteria violation. Therefore, the recommended system modifications may or may not represent an optimal solution.

• This study assumes that XXX will acquire the transmission rights necessary to deliver its power.

3.2 Criteria

The reliability criteria standards used by EPE in performing this study are readily acceptable standards and are listed on pages 3 through 5 of the Transmission Interconnection Feasibility Study: Study Scope (Appendix 1) and in Section 4 of EPE’s FERC Form 715 (Appendix 2).

3.3 Procedure

As previously mentioned, the system study analyses conducted by EPE included powerflow, transient stability, and Q-V reactive margin. Detailed discussions for each topic have been included in this report. The following procedures were used in conducting this study:


3.3.1 Base Case Development 2003 Heavy Summer (HS) and Light Winter (LW) benchmark cases without the XXX HVDC terminal were developed in order to compare against the other scenarios that included the interconnection of the XXX HVDC terminal. The 2003 HS and 2003 LW Benchmark cases (Task I) were established by integrating the latest available EPE and New Mexico system representations with the existing WSCC 03HS2SA case. In the “Benchmark” case, New Mexico utilities were flagged for criteria violations. Consequently, these initial system criteria violations also existed in the cases including the XXX HVDC terminal and therefore, are not considered impacts due to the interconnection of the XXX HVDC terminal. Two alternatives were analyzed in the Study. Alternative #1 modeled the interconnection into a new substation connecting the Newman-Caliente 345 kV and Amrad-Caliente 345 kV lines. Analyses for Alternative #1 are listed in the Task II sections of this report. Alternative #2 modeled the interconnection directly into EPE’s Newman 345 kV bus. Analyses for Alternative #2 are listed in the Task III sections of this report.

Four scenarios were analyzed in each of the two Tasks described above. Scenario A was the interconnection scenario. It modeled 660 MW of imported power from XXX as being distributed throughout all the Western Area Coordinating Council (WSCC) without specifying a transmission path. This simulated the interconnection of the XXX HVDC terminal into the EPE transmission system and the distribution of that power without a specific transmission path. WSCC area loads, including EPE’s, were proportionally increased by 660 MW in order to distribute the imported XXX power. This scenario determined the impacts, modifications, and costs required to interconnect the proposed project and deliver its output to the grid. As per the Federal Energy Regulatory Commission (FERC), this scenario determines the project interconnection costs.

Scenario’s B, C, and D were performed at the request of XXX and modeled transmission service scenarios, which specified transmission paths for each particular scenario. Scenario B analyzed the impacts of transferring the XXX power west (California) of the EPE area. This simulated a scenario where the XXX power was interconnected into the EPE transmission system and sold to the Pacific Gas and Electric (PG&E) area. Scenario C analyzed the impacts of transferring the imported XXX power north of the EPE area. This simulated a scenario where the XXX power was interconnected into the EPE transmission system and sold to the Public Service Company of New Mexico (PNM) and Public Service of Colorado (PSCO) areas.


Scenario D analyzed the impacts of transferring the XXX power to both the EPE area and throughout the other WSCC areas. This simulated a scenario where the XXX power is interconnected into the EPE transmission system with 330 MW sold to EPE and 330 MW distributed throughout the rest of the WSCC areas. EPE’s local generation was reduced by 330 MW and loads were increased by 330 MW throughout the other WSCC areas in order to distribute all of the XXX imported power.

The purpose of this study was to determine all major problems, i.e., fatal flaws that could occur on the southern New Mexico system if the XXX HVDC terminal is interconnected into the EPE transmission system. The study recommends solutions that, using engineering judgement, should correct the criteria violations determined to be impacts due to the XXX HVDC terminal interconnection. However, these recommended solutions were not re-evaluated and therefore may not represent the optimal solution in correcting the system impacts. Load and resource information for the base cases is included in Appendix 3. EPE powerflow maps (one-line diagrams) are located in Appendix 4.

3.3.2 List of Contingencies The same contingencies were evaluated for all scenarios in each task and are identified in Appendix 5. In addition to these contingencies, loss of the XXX HVDC line was also evaluated in each scenario. These contingencies were selected base on engineering judgement that these would be the most likely to stress the EPE and southern New Mexico systems. Any contingency that resulted in a non-convergent system in the benchmark case (Task I) was not reevaluated in Task II or Task III. It is assumed that since these problems exist in the Benchmark cases, they are not impacts due to the XXX HVDC terminal interconnection. 3.3.3 Transient Stability Analysis The stability data representation for the XXX HVDC terminals is based on data provided by XXX. XXX supplied EPE with models for the Rectifier and Inverter components of the HVDC terminals. The models were then represented in the WSCC master stability file for analysis using the GE Transient Stability Program. Transient stability analyses were conducted on all Scenarios for Task I, Task II, and Task III. The parameters used in this analysis are shown in Appendix 6.


3.3.4 Q-V Analysis Reactive margin Q-V analyses were performed on all scenarios in Task I, Task II, and Task III to verify that the WSCC criteria for reactive power margin will be met under the worst contingencies on the EPE system. A procedure developed by WSCC was used to determine the reactive power margin. As outlined in this procedure, load was increased by 5% and the worst contingency was analyzed to determine the reactive margin on the system. The margin is determined by identifying the critical (weakest) bus on the system during the worst contingency. The critical bus is the most reactive deficient bus. Q-V curves are developed and the minimum point on the curve is the critical point. If the minimum point of the Q-V curve is positive, the system is reactive power deficient. If it is negative, then the system has sufficient reactive power margin and meets the WSCC criteria. Prior experience has shown that the worst contingencies impacting reactive power margin are the Springerville-Luna, Luna-Diablo, and Greenlee-Hidalgo 345 kV lines and the buses most impacted are the 345 kV buses at Luna, Hidalgo, Newman, Caliente, and Diablo. A Q-V analysis of these three 345 kV line contingencies on the Benchmark Case determined that the Luna-Diablo contingency was the worst contingency impacting the system reactive power margin. Therefore this contingency was used to evaluate reactive power margins for all cases. Q-V plots were created showing the margins available at the 345 kV buses listed above.

3.3.5 Short-Circuit Analysis A Short-Circuit analysis was to be performed as per the Study Scope Agreement. However, XXX consultants advised EPE that the proposed DC Lite technology they propose to use for the HVDC terminal interconnection acts as a constant voltage source and does not contribute any fault current into the system during a bus fault. Therefore, a short-circuit analysis for this study was not required and not performed. However, if it is determined later that the proposed DC Lite technology does contribute fault current into the system, a short-circuit study will be required to verify that the existing circuit breaker interruption ratings are not exceeded due to the interconnection of the XXX HVDC terminal.


4.0 POWERFLOW ANALYSIS RESULTS Powerflow analyses were performed for all Scenarios in Task I, Task II, and Task III. Base cases were developed for the 2003 HS and 2003 LW seasons in each scenario, simulating the system with all lines in service. Voltage and/or loading criteria violations in the base case were noted for EPE as well as other New Mexico utilities. These violations are shown in the Base Case and Contingencies Tables listed in Appendix 7. Contingency (N-1) powerflow analyses were then performed for all cases. A list of the contingencies analyzed is shown in Appendix 5. For the contingency analyses, criteria violations were noted and modifications were recommended using engineering judgement. However, the recommended modifications were not re-analyzed and therefore may not represent the optimal solutions in correcting these criteria violations. Contingencies that resulted in voltage and loading problems for non-EPE utilities were also noted in the tables (Appendix 7) and potential solutions were recommended using engineering judgement. Again, these solutions were not re-analyzed and may not represent the optimal solution in correcting the criteria violations for the non-EPE utilities. Results of the powerflow analyses are listed below.

4.1 Task I 2003 Heavy Summer (HS) and Light Winter (LW) benchmark cases were developed and analyzed in this study and contingency powerflow analyses were performed on these cases. The EPE system was represented with 2003 HS and 2003 LW loads and without the XXX HVDC terminal interconnection. These cases simulated the EPE system, as it may exist in the summer and winter of 2003 with all other potential generation interconnected into the EPE system but without the XXX HVDC terminal interconnection. In the 2003 HS case, the Shearman-ANP 115 kV line was found to be loaded to 101.2% of its normal rating with all lines in service (ALIS). This criteria violation was corrected and was not considered an impact due to the interconnection of the XXX HVDC terminal. There were also some criteria violations with ALIS in the PNM, TNMP, and Tri-State areas. The table below shows the overload criteria violations with all lines in service for the 2003 HS case:

Overload Criteria Violations for Task I (2003 HS) Case With All Lines In Service

LINE

OWNER

RATING (MVA)

FLOW (MVA)

% LOADING

Mejia_T-Norton_1 115 kV line PNM 115.5 145.5 123.2 AlamoGPG 69/115 kV XFMR Tri-State 10.5 10.9 109.1 Amrad-Alamotap 115 kV line TNMP 79.6 85.8 104.0 AlamoGCP-Alamotap 115 kV line TNMP 79.6 84.4 103.7 Sunshine 115/14 kV XFMR PNM 12.5 12.6 100.8


There were also criteria violations during contingency conditions in the EPE, Tri-State, PNM and TNMP areas. An overload of the Dyer-Leo 69 kV line was also discovered during contingency conditions in Task I and therefore, not considered an impact due to the project interconnection. The table below shows the overload criteria violations for the benchmark case during contingency conditions:

Overload Criteria Violations for Task I (2003HS) Case During Contingency Conditions

CONTINGENCY

OVERLOADED LINE / TRANSFORMER

OWNER

% LOADING

Luna-Diablo 345 kV line Cuchillo 115/25 kV XFMR Tri-State 100.0 Luna-Hidalgo 345 kV line Hurley-Luna 115 kV line TNMP 106.2

Luna 345/115 kV XFMR PNM 100.6 Milagro-ANP 115 kV line Dyer-Leo 69 kV line EPE 106.7 Milagro 115/69 kV XFMR Dyer-Leo 69 kV line EPE 106.1 The 2003 LW case impacts are not shown here because the impacts are less than in the HS case and thus, the 2003 HS case represents the worst case scenario. Also, it is assumed that any modification to correct a violation in the 2003 HS case will also correct the same violation in the 2003 LW case. All violations for Task I (HS and LW cases) are noted in Appendix 7. Violations in Task I are not impacts due to the interconnection of the XXX HVDC terminal. For a detailed listing of all the criteria violations in the Task I benchmark case, please refer to the “2003 HS Task I Case” Table in Appendix 7. 4.2 Task II The Task II Alternative simulated the XXX HVDC terminal interconnection, totaling 660 MW, as being interconnected into the EPE transmission system at a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Four scenarios were analyzed in Task II. Scenario A analyzed the impacts of interconnecting the XXX HVDC terminal into the EPE system and delivering the output into the grid. This is the minimum amount that XXX will need to spend in order to interconnect into the EPE system. Scenarios B, C, and D analyzed specific transmission service scenarios, which determined costs in addition to those in Scenario A.

The following table shows the estimated costs necessary for XXX to physically interconnect into a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines without delivering any power to the grid. This estimated cost applies to all scenarios in Task II and is in addition to the “System Modification Costs” estimated for each scenario. The second XXX-Newman line is required because an outage of the first XXX-Newman line creates overloads on the EPE 345 kV and 115 kV system near the Newman power plant. These include overloading both Newman 345/115 kV autotransformers and some 115 kV lines connected to the Newman 115 kV bus. The second XXX-Newman 345 kV line will prevent these


overloads from occurring. The cost of adding the second XXX-Newman 345 kV line is far less expensive than correcting all of the overloaded facilities in the area. In addition to the facilities listed below, the reactor on the Caliente-Amrad 345 kV line may need to be changed out for all scenarios in Task II. This is because the length of the line will be shortened with the new substation intersecting this line. An analysis of this will need to be performed in a more detailed “Facilities Study” to determine if any change is required. Costs for this have not been included here.

INTERCONNECTION COSTS FOR TASK II

FACILITY MODIFICATION OWNER ESTIMATED COST

2nd XXX-Newman 345 kV line (4 miles) EPE $920,000 (13) 345 kV Gas Circuit Breakers EPE $3,575,000 (26) 345 kV Motor operated disconnect switches EPE $650,000 (5) Dead End Towers EPE $100,000 (1) Protection Scheme EPE $50,000 (1) Controls Equipment EPE $20,000 (1) Communication Scheme EPE $25,000

Total Interconnection Costs for Task II: $5,340,000

Please note that the above cost is a "rough" estimate only and may change when detailed engineering and design studies are performed for the interconnection into the new substation. Please refer to Appendix 10 for the one-line diagram of the proposed XXX HVDC terminal interconnection for Task II. Below are the results of the powerflow analyses for each scenario in Task II, including estimated costs.

4.2.1 Task II, Scenario A 2003 HS and 2003 LW cases for Task II, Scenario A were developed and analyzed in this study and compared to the Task I cases. Contingency powerflow analyses were then performed on these cases. The EPE system was represented as in the Task I cases, except that the XXX HVDC terminal was now included. The XXX HVDC terminal was modeled as an interconnection into a new substation connecting the Newman-Caliente 345 kV and Amrad-Caliente 345 kV lines. The imported power from XXX was modeled as being distributed throughout all the Western Area Coordinating Council (WSCC) without a specific transmission path. This scenario determined the impacts, modifications, and costs required to interconnect the proposed project and deliver its output to the grid. As per Federal Energy the Regulatory Commission (FERC), this scenario determines the project interconnection costs.

The importation of 660 MW of power into the EPE system and distributed throughout the WSCC caused some major impacts to the EPE and surrounding areas systems under All Lines In Service (ALIS) conditions. First, the tap on the Arroyo Phase Shifting Transformer (PST) reaches its minimum limit of –34° when the 660 MW of XXX power is distributed


throughout the WSCC area. At that point, only 15 MW is flowing through the West Mesa-Arroyo (EP) 345 kV line. Therefore, in order to allow EPE to import its maximum limit of 186 MW across the EP line, the PST taps need to be changed out. In addition to this, the Anthony-Newman 115 kV line, Arroyo-Las Cruces 115 kV line, Cromo-ANP 115 kV line, and Arroyo 115/345 kV transformer are all overloaded with ALIS. The EPE violations were corrected before the contingency analyses were performed. There were also some overloaded lines in the Tri-State and TNMP areas that were due to the interconnection of the XXX HVDC terminal. The table below shows the overload criteria violations for Task II, Scenario A, during ALIS conditions for the 2003 HS case:

Overload Criteria Violations for Task II, Scenario A (2003 HS) Case

With All Lines In Service

LINE/TRANSFORMER

OWNER

RATING (MVA)

% LOADING WITH XXX IMPORTED

POWER

% LOADING WITHOUT XXX

IMPORTED POWER

Anthony-Newman 115 kV line EPE 143.6 108.3 90.8 Arroyo-Las Cruces 115 kV line EPE 143.6 105.8 76.2 Cromo-ANP 115 kV line EPE 117.7 100.9 73.8 Arroyo 115/345 kV XFMR EPE 200.0 114.1 84.7 Elephant Butte-Socorrop 115 kV line Tri-State 60.0 135.0 70.3 Elephant Butte-Picacho 115 kV line Tri-State 40.0 131.5 46.6 Hurley-Luna 115 kV line TNMP 79.6 123.8 98.6 Las Cruces-Dona Ana 115 kV line Tri-State 117.7 105.7 46.6

There were also criteria violations during contingency conditions in the EPE, TNMP, and Tri-State areas. The table below shows the overload criteria violations for the Task II, Scenario A Case during contingency conditions:

Overload Criteria Violations for Task II, Scenario A (2003 HS) Case

During Contingency Conditions

CONTINGENCY


OWNER


POWER


IMPORTED POWER

Luna-Hidalgo 345 kV line Central-Hurley 115 kV line TNMP 148.3 86.9 Bernardo-Socorrop 115 kV line Tri-State 108.7 46.5

BelenPG-Bernardo 115 kV line Tri-State 105.6 43.1 Loss of XXX HVDC Line Newman 345/115 kV XFMR #1 EPE 125.1 N/A

Newman 345/115 kV XFMR #2 EPE 124.9 N/A Dyer-Austin N 115 kV line Austin-Dyer 69 kV line EPE 105.3 98.5 Dyer-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 100.9 97.5 ANP-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 102.2 98.9 Arroyo 345/115 kV XFMR Arroyo 345/115 kV XFMR #2 EPE 100.3 N/A Caliente 345/115 kV XFMR Caliente 345/115 kV XFMR #2 EPE 107.7 82.3


Another criteria violation in this scenario was the extremely low voltages in the TNMP/Tri-State areas during an outage of the Luna-Hidalgo 345 kV line. Bus voltages in those areas ranged from 0.8489-0.9189 p.u. during the outage in this scenario. An analysis of the same outage in the Task I (Benchmark) scenario did not reveal any under voltage criteria violations. Therefore, this undervoltage impact is a result of the interconnection of the XXX HVDC terminal. The proposed solution to correct this criteria violation is the addition of a Static Var Generator (SVG) device to be placed somewhere in the TNMP/Tri-State area. Since this criteria violation is not on the EPE system, a “rough” cost estimate for this recommended modification is provided using EPE prices.

The table below shows the system modification costs necessary to deliver the 660 MW of XXX power to the grid. This is in addition to the interconnection costs shown in Section 4.2. Scenario A simulates the interconnection of the XXX HVDC terminal into the EPE system and the distribution of that power throughout the WSCC area without a specific transmission path. It determines the impacts, modifications, and costs required to interconnect the proposed XXX project and deliver its output to the grid.

TASK II, SCENARIO A SYSTEM MODIFICATION COSTS

FACILITY MODIFICATION OWNER ESTIMATED COST Change out Taps on Arroyo 345 kV PST EPE $4,000,000 Anthony-Newman 115 kV line upgrade (12.3 miles) EPE $2,700,000 Arroyo-Las Cruces 115 kV line upgrade (4.1 miles) EPE $900,000 Cromo-ANP 115 kV line upgrade (19.9 miles) EPE $4,380,000 Second 200 MVA Arroyo 345/115 kV XFMR EPE $4,500,000 Second 100 MVA Milagro 115/69 kV XFMR EPE $600,000 Third 200 MVA Arroyo 345/115 kV XFMR EPE $4,500,000 Third 200 MVA Caliente 345/115 kV XFMR EPE $4,500,000 Third 200 MVA Newman 345/115 kV XFMR EPE $4,500,000 Austin-Dyer 69 kV line upgrade (2.2 miles) EPE $473,000 Elephant Butte-Socorro 115 kV line upgrade (85 miles) Tri-State $18,700,000 Elephant Butte-Picacho 115 kV line upgrade (50 miles) Tri-State $11,000,000 Las Cruces-Dona Ana 115kV line upgrade (5 miles) Tri-State $1,100,000 Hurley-Luna 115 kV line upgrade (12 miles) TNMP $2,640,000 Central-Hurley 115 kV line upgrade (18) miles TNMP $3,960,000 SVG for voltage support in TNP/Tri-State areas TNMP/Tri-State $5,000,000

Total Incremental Costs for Task II, Scenario A: $73,453,000 Including the estimated costs necessary for XXX to physically interconnect into the EPE transmission system, the total estimated cost for Task II, Scenario A is $78,793,000. This is the amount that, as per FERC, XXX is responsible for in order to correct the impacts caused by the interconnection of its proposed project into the EPE system and delivery of its output into the grid in a Task II interconnection configuration. All estimated costs in Scenarios B, C, and D are in addition to the costs determined in Scenario A. For a detailed listing of all criteria violations in the Task II Scenario A Case, please refer to the “2003 HS Task II Scenario A Case” Table in Appendix 7.


4.2.2 Task II, Scenario B The 2003 HS and 2003 LW cases for Task II, Scenario B were developed and analyzed in this study and compared to the Task I cases. Contingency powerflow analyses were then performed on these cases. The EPE system was represented as in the Benchmark cases, except that the XXX HVDC terminal power source is now included. The XXX HVDC terminal was modeled as an interconnection into a new substation connecting the Newman-Caliente 345 kV and Amrad-Caliente 345 kV lines. The imported power from XXX was modeled as a sale to California (PG&E area). This scenario determined the system impacts to the EPE and surrounding areas due to the interconnection of the XXX HVDC terminal and a transmission service agreement to the west of the EPE area. The importation of 660 MW of power into the EPE system and sold to the west caused major impacts to the EPE and surrounding areas systems under ALIS conditions. First, the tap on the Arroyo Phase Shifting Transformer (PST) reaches its minimum limit of –34° when the 660 MW of XXX power is exported west of the EPE area and into California. At that point, only 3 MW is flowing through the EP 345 kV line. Therefore, in order to allow EPE to import its maximum limit of 186 MW across the EP line, the PST taps need to be changed out. In addition to this, the Hidalgo-Luna 345 kV line, Anthony-Newman 115 kV line, Arroyo-Las Cruces 115 kV line, and Arroyo 115/345 kV transformer are all overloaded with ALIS. The table below shows the overload criteria violations for Task II, Scenario B, with all lines in service for the 2003 HS case:

Overload Criteria Violations for Task II, Scenario B (2003 HS) Case


LINE/TRANSFORMER

OWNER

RATING (MVA)


POWER


IMPORTED POWER

Anthony-Newman 115 kV line EPE 143.6 107.6 90.8 Arroyo-Las Cruces 115 kV line EPE 143.6 106.6 76.2 Hidalgo-Luna 345 kV line EPE 717.1 100.4 73.8 Arroyo 115/345 kV XFMR EPE 200.0 113.5 84.7 Elephant Butte-Socorrop 115 kV line Tri-State 60.0 138.3 70.3 Elephant Butte-Picacho 115 kV line Tri-State 40.0 136.7 46.6 Hurley-Luna 115 kV line TNMP 79.6 124.7 98.6 Las Cruces-Dona Ana 115 kV line Tri-State 117.7 108.8 46.6

There were also some criteria violations during contingency conditions in the EPE, TNMP, and Tri-State areas. The table below shows the overload criteria violations for the Task II, Scenario B Case during contingency conditions:


Overload Criteria Violations for Task II, Scenario B (2003 HS) Case During Contingency Conditions

CONTINGENCY


OWNER


POWER


IMPORTED POWER



Newman 345/115 kV XFMR #2 EPE 131.4 N/A Dyer-Austin N 115 kV line Austin-Dyer 69 kV line EPE 101.0 98.5 ANP-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 100.4 98.9 Caliente 345/115 kV XFMR Caliente 345/115 kV XFMR #2 EPE 104.2 82.3

Another criteria violation in this scenario was the extremely low voltages in the TNMP/Tri-State areas during an outage of the Luna-Hidalgo 345 kV line. Bus voltages in those areas ranged from 0.8407-0.9248 p.u. during the outage in this Scenario. An analysis of the same outage in the Task I (Benchmark) Scenario did not reveal any under voltage criteria violations. Therefore, this undervoltage impact is due to the interconnection of the XXX HVDC terminal. The proposed solution to correct this criteria violation is the addition of a Static Var Generator (SVG) device to be placed somewhere in the TNMP/Tri-State area. Since this criteria violation is not on the EPE system, a “rough” cost estimate for this recommended modification is provided using EPE prices. Some of the proposed solutions for correcting the criteria violations in Task II, Scenario B, have been incorporated in Task II, Scenario A. The following table lists those system modifications required in Task II, Scenario B that are in addition to those listed in Scenario A, with rough cost estimates also provided.

TASK II, SCENARIO B SYSTEM MODIFICATION COSTS


OWNER ESTIMATED

COST Luna-Hidalgo 345 kV line upgrade (50.5 miles) EPE $11,615,000 Belen-Bernardo 115 kV line upgrade (15 miles) Tri-State $3,300,000 Bernardo-Socorro 115 kV line upgrade (20 miles) Tri-State $4,400,000

Total Incremental Costs for Task II, Scenario B: $19,315,000

The total estimated cost for Task II, Scenario B, including the estimated costs from Task II, Scenario A, is $98,108,000. For a detailed listing of all the criteria violations in the Task II Scenario B Case, please refer to the “2003 HS Task II Scenario B Case” Table in Appendix 7.


4.2.3 Task II, Scenario C The 2003 HS and 2003 LW cases for Task II, Scenario C were developed and analyzed in this study and compared to the Benchmark cases. Contingency powerflow analyses were then performed on these cases. The EPE system was represented as in the Benchmark cases, except that the XXX power source is now included. The XXX HVDC terminal was modeled as an interconnection into a new substation connecting the Newman-Caliente 345 kV and Amrad-Caliente 345 kV lines. The imported power from XXX was modeled as a sale to northern New Mexico and Colorado (PNM & PSCO areas). This scenario determined the system impacts to the EPE and surrounding areas due to the interconnection of the XXX HVDC terminal and a transmission service agreement to the north of the EPE area. The importation of 660 MW of power into the EPE system and sold to the north caused some major impacts to the EPE and surrounding areas systems under ALIS conditions. First, the tap on the Arroyo Phase Shifting Transformer (PST) reaches its minimum limit of –34° when the 660 MW of XXX power is exported north of the EPE area and into northern New Mexico and Colorado. At that point, 22 MW is flowing in the opposite direction on the EP 345 kV line. Therefore, in order to allow EPE to import its maximum limit of 186 MW across the EP line, the PST taps need to be changed out. In addition to this, the Anthony-Newman 115 kV line, Dyer-Shearman 115 kV line, Arroyo-Las Cruces 115 kV line, Cromo-ANP 115 kV line, Butterfield-ANP 115 kV line, and Arroyo 115/345 kV transformer are all overloaded with ALIS. There were also some criteria violations in the Tri-State and TNMP areas with ALIS. The table below shows the overload criteria violations for Task II, Scenario C, with all lines in service for the 2003 HS case:

Overload Criteria Violations for Task II, Scenario C (2003 HS) Case


LINE/TRANSFORMER

OWNER

RATING (MVA)


POWER


IMPORTED POWER

Anthony-Newman 115 kV line EPE 143.6 112.7 90.8 Dyer-Shearman 115 kV line EPE 117.7 108.4 93.1 Arroyo-Las Cruces 115 kV line EPE 143.6 107.7 76.2 Cromo-ANP 115 kV line EPE 117.7 104.9 73.8 Butterfield-ANP 115 kV line EPE 117.7 103.0 88.6 Arroyo 115/345 kV XFMR EPE 200.0 113.5 84.7 Elephant Butte-Socorrop 115 kV line Tri-State 60.0 152.0 70.3 Elephant Butte-Picacho 115 kV line Tri-State 40.0 140.0 46.6 Hurley-Luna 115 kV line TNMP 79.6 123.9 98.6 Las Cruces-Dona Ana 115 kV line Tri-State 117.7 110.4 46.6 Hernandez-Ojo 115 kV line Tri-State 117.7 100.3 94.9


There were also criteria violations during contingency conditions in the EPE, TNMP, and Tri-State areas. The table below shows the overload criteria violations for the Task II, Scenario C Case during contingency conditions:

Overload Criteria Violations for Task II, Scenario C (2003 HS) Case


CONTINGENCY


OWNER


POWER


IMPORTED POWER



Newman 345/115 kV XFMR #2 EPE 131.1 N/A Dyer-Austin N 115 kV line Austin-Dyer 69 kV line EPE 109.4 98.5 Dyer-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 102.1 97.5 ANP-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 100.4 98.9 Amrad 345/115 kV XFMR Las Cruces-Dona Ana 115 kV line Tri-State 102.1 50.9 Caliente 345/115 kV XFMR Caliente 345/115 kV XFMR #2 EPE 105.6 82.3

Another criteria violation in this scenario was the extremely low voltages in the TNMP/Tri-State areas during an outage of the Luna-Hidalgo 345 kV line. Bus voltages in those areas ranged from 0.8235-0.9195 p.u. during the outage in this Scenario. An analysis of the same outage in the Task I (Benchmark) Scenario did not reveal any under voltage criteria violations. Therefore, this undervoltage impact is due to the interconnection of the XXX HVDC terminal. The proposed solution to correct this criteria violation is the addition of a Static Var Generator (SVG) device to be placed somewhere in the TNMP/Tri-State area. Since this criteria violation is not on the EPE system, a “rough” cost estimate for this recommended modification is provided using EPE prices. Some of the proposed solutions for correcting the criteria violations in Task II, Scenario C, have been incorporated in Task II, Scenario A. The following table lists those system modifications required in Task C that are in addition to those listed in Scenario A, with rough cost estimates also provided.

TASK II, SCENARIO C SYSTEM MODIFICATION COSTS


OWNER

ESTIMATED COST

Dyer-Shearman 115 kV line upgrade (9.63 miles) EPE $2,119,000 Butterfield-ANP115 kV line upgrade (16.7 miles) EPE $3,674,000 Hernandez-Ojo 115 kV line upgrade (17 miles) Tri-State $3,740,000 Bernardo-Socorro 115 kV line upgrade (20 miles) Tri-State $4,400,000 Belen-Bernardo 115 kV line upgrade (15 miles) Tri-State $3,300,000

Total Incremental Costs for Task II, Scenario C: $17,233,000

The total estimated cost for Task II, Scenario C, including the estimated costs from Task II, Scenario A, is $96,026,000. For a detailed listing of all criteria


violations in Task II Scenario C, please refer to the “2003 HS Task II Scenario C Case” Table in Appendix 7. 4.2.4 Task II, Scenario D The 2003 HS and 2003 LW cases for Task II, Scenario D were developed and analyzed in this study and compared to the Benchmark cases. Contingency powerflow analyses were then performed on these cases. The EPE system was represented as in the Benchmark cases, except that the XXX power source is now included. The XXX HVDC terminal was modeled as an interconnection into a new substation connecting the Newman-Caliente 345 kV and Amrad-Caliente 345 kV lines. The imported power from XXX was modeled as a 330 MW sale to EPE and the remaining 330 MW of XXX power as being distributed throughout the WSCC. This scenario determined the system impacts to the EPE and surrounding areas due to the interconnection of the XXX HVDC terminal and a transmission service agreement to sell one half of its power to EPE and the other half throughout the WSCC. The importation of 660 MW of power into the EPE system, with 330 MW sold to EPE and 330 MW sold throughout the WSCC, caused major impacts to the EPE and surrounding areas systems under ALIS conditions. First, the tap on the Arroyo Phase Shifting Transformer (PST) reaches its minimum limit of –34° when 330 MW of the 660 MW of XXX power is exported throughout the WSCC. At that point, 111 MW is flowing through the EP 345 kV line. Therefore, in order to allow EPE to import its maximum limit of 186 MW across the EP line, the PST taps need to be changed out. In addition to this, the Arroyo-Las Cruces 115 kV line and Arroyo 115/345 kV transformer are overloaded with ALIS. There were also some criteria violations in the Tri-State and TNMP areas with ALIS. The table below shows the overload criteria violations for Task II, Scenario C, with all lines in service for the 2003 HS case:

Overload Criteria Violations for Task II, Scenario D (2003 HS) Case


LINE/TRANSFORMER

OWNER

RATING (MVA)


POWER


IMPORTED POWER

Arroyo-Las Cruces 115 kV line EPE 143.6 103.0 76.2 Arroyo 115/345 kV XFMR EPE 200.0 109.4 84.7 Elephant Butte-Socorrop 115 kV line Tri-State 60.0 104.5 70.3 Hurley-Luna 115 kV line TNMP 79.6 111.9 98.6

There were also some criteria violations during contingency conditions in the EPE, TNMP, and Tri-State areas. The table below shows the overload criteria violations for the Task II, Scenario D Case during contingency conditions:


Overload Criteria Violations for Task II, Scenario D (2003 HS) Case During Contingency Conditions

CONTINGENCY


OWNER


POWER


IMPORTED POWER

Luna-Hidalgo 345 kV line Central-Hurley 115 kV line TNMP 116.0 86.9 Elephant Butte-Picacho 115 kV line Tri-State 110.9 67.4 Arroyo 345/115 kV XFMR Arroyo 345/115 kV XFMR #2 EPE 103.6 N/A Caliente 345/115kV XFMR Caliente 345/115 kV XFMR #2 EPE 124.6 82.3

Another criteria violation in this scenario was the extremely low voltages in the TNMP/Tri-State areas during an outage of the Luna-Hidalgo 345 kV line. Bus voltages in those areas ranged from 0.8235-0.9195 p.u. during the outage in this Scenario. An analysis of the same outage in the Task I (Benchmark) Scenario did not reveal any under voltage criteria violations. Therefore, this undervoltage impact is due to the interconnection of the XXX HVDC terminal. The proposed solution to correct this criteria violation is the addition of a Static Var Generator (SVG) device to be placed somewhere in the TNMP/Tri-State area. Since this criteria violation is not on the EPE system, a “rough” cost estimate for this recommended modification is provided using EPE prices. All of the proposed solutions for correcting the criteria violations in Task II, Scenario D, have been incorporated in Task II, Scenario A. Therefore, there are no additional costs in Scenario D and the total estimated cost for Task II, Scenario D is $78,793,000. For a detailed listing of all the criteria violations in the Task II Scenario D Case, please refer to the “2003 HS Task II Scenario D Case” Table in Appendix 7.

4.3 Task III The Task III Alternative simulated the XXX HVDC terminal interconnection, totaling 660 MW, as being interconnected directly into the EPE transmission system at the Newman 345 kV bus. The same four scenarios analyzed in Task II were also analyzed in Task III. Scenario A analyzed the impacts of interconnecting the XXX HVDC terminal into the EPE system and delivering the output into the grid. This is the minimum amount that XXX will need to spend in order to interconnect into the EPE system. Scenarios B, C, and D analyzed specific transmission service scenarios, which determined costs in addition to those in Scenario A. The following table shows the estimated costs necessary for XXX to physically interconnect directly into the EPE transmission system at the Newman 345 kV bus without delivering any power to the grid. This estimated cost applies to all scenarios in Task III and is in addition to the “System Modification Costs” estimated for each scenario.


INTERCONNECTION COSTS FOR TASK III FACILITY MODIFICATION OWNER ESTIMATED COST

(1) 345 kV Gas Circuit Breaker EPE $275,000 (2) 345 kV Motor operated disconnect switches EPE $50,000 (1) Dead End Tower EPE $20,000 (1) Protection Scheme EPE $50,000 (1) Controls Equipment EPE $20,000 (1) Communication Scheme EPE $25,000

Total Interconnection Costs for Task III: $440,000

Please note that the above cost is a "rough" estimate only and may change when detailed engineering and design studies are performed for the interconnection into the Newman 345 kV bus. Please refer to Appendix 10 for the one-line diagram of the proposed XXX HVDC interconnection of Task III.

4.3.1 Task III, Scenario A The 2003 HS and 2003 LW cases for Task III, Scenario A were developed and analyzed in this study and compared to the Benchmark cases. Contingency powerflow analyses were then performed on these cases. The EPE system was represented as in the Benchmark cases, except that the XXX power source is now included. The XXX HVDC terminal was modeled as an interconnection directly into the Newman 345 kV bus. The imported power from XXX was modeled as being distributed throughout all the Western Area Coordinating Council (WSCC) (without specifying a transmission path). This scenario determined the system impacts to the EPE and surrounding areas due to the interconnection of the XXX HVDC terminal. This scenario is similar to the Task II, Scenario A case, except that the XXX interconnection is directly into the Newman 345 kV bus instead of into a new substation connecting the Caliente-Newman and Caliente-Amrad 345 kV lines.

The importation of 660 MW of power into the EPE system and sold throughout the WSCC caused the same impacts to the EPE and surrounding areas systems under ALIS conditions as in the Task II, Scenario A case. In addition to the impacts seen in the Task II case, the Newman-Vista 115 kV line overloads in Task III. The tap on the Arroyo Phase Shifting Transformer (PST) reached its minimum limit of –34° when the 660 MW of XXX power was exported throughout the WSCC area and therefore requires the PST taps to be changed out. In addition to this, the Arroyo-Las Cruces 115 kV line, Dyer-Shearman 115 kV line, Anthony-Newman 115 kV line, Butterfield-ANP 115 kV line, Cromo-ANP 115 kV line, and Arroyo 115/345 kV transformer are all overloaded with ALIS. The EPE violations were corrected before the contingency analyses were performed. There were also some overloaded lines in the Tri-State and TNMP areas that were due to the interconnection of the XXX HVDC terminal.


The table below shows the overload criteria violations for Task III, Scenario A, with all lines in service for the 2003 HS case:

Overload Criteria Violations for Task III, Scenario A (2003 HS) Case


LINE/TRANSFORMER

OWNER

RATING (MVA)


POWER


IMPORTED POWER

Arroyo-Las Cruces 115 kV line EPE 143.6 108.2 76.2 Anthony-Newman 115 kV line EPE 143.6 107.4 90.8 Cromo-ANP 115 kV line EPE 117.7 101.6 73.8 Arroyo 115/345 kV XFMR EPE 200.0 117.4 84.7 Elephant Butte-Socorrop 115 kV line Tri-State 60.0 135.0 70.3 Elephant Butte-Picacho 115 kV line Tri-State 40.0 131.5 46.6 Hurley-Luna 115 kV line TNMP 79.6 123.8 98.6 Las Cruces-Dona Ana 115 kV line Tri-State 117.7 105.7 46.6

There were also some criteria violations during contingency conditions in the EPE, TNMP, and Tri-State areas. The table below shows the overload criteria violations for the Task III, Scenario A Case during contingency conditions:

Overload Criteria Violations for Task III, Scenario A (2003 HS) Case


CONTINGENCY


OWNER


POWER


IMPORTED POWER



Newman 345/115 kV XFMR #2 EPE 141.6 N/A Newman-Vista 115 kV line EPE 105.8 N/A Austin-Dyer 69 kV line EPE 101.4 N/A

Dyer-Austin N 115 kV line Austin-Dyer 69 kV line EPE 109.4 98.5 Dyer-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 102.3 97.5 ANP-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 103.7 98.9 Arroyo 345/115 kV XFMR Arroyo 345/115 kV XFMR #2 EPE 103.1 N/A Dyer 69/115 kV XFMR Milagro 115/69 kV XFMR EPE 100.8 97.5 Caliente 345/115 kV XFMR Caliente 345/115 kV XFMR #2 EPE 100.1 82.3

Another criteria violation in this scenario was the extremely low voltages in the TNMP/Tri-State areas during an outage of the Luna-Hidalgo 345 kV line. Bus voltages in those areas ranged from 0.8487-0.9181 p.u. during the outage in this Scenario. An analysis of the same outage in the Task I (Benchmark) Scenario did not reveal any under voltage criteria violations. Therefore, this undervoltage impact is due to the interconnection of the XXX HVDC terminal. The proposed solution to correct this criteria violation is the


addition of a Static Var Generator (SVG) device to be placed somewhere in the TNMP/Tri-State area. Since this criteria violation is not on the EPE system, a “rough” cost estimate for this recommended modification is provided using EPE prices.

The table below shows the system modifications and costs necessary to deliver the 660 MW of XXX power to the grid. This is in addition to the costs shown in Section 4.3. Scenario A simulates the interconnection of the XXX HVDC terminal into the EPE system and the distribution of that power throughout the WSCC area without a specific transmission path. It determines the impacts, modifications, and costs required to interconnect the proposed XXX project and deliver its output to the grid.

TASK III SYSTEM MODIFICATION COSTS

TO DELIVER OUTPUT TO GRID


OWNER ESTIMATED

COST Change out Taps on Arroyo 345 kV PST EPE $4,000,000 Arroyo-Las Cruces 115 kV line upgrade (4.1 miles) EPE $900,000 Anthony-Newman 115 kV line upgrade (12.3 miles) EPE $2,700,000 Cromo-ANP 115 kV line upgrade (19.9 miles) EPE $4,380,000 Second 200 MVA Arroyo 345/115 kV XFMR EPE $4,500,000 Second 100 MVA Milagro 115/69 kV XFMR EPE $600,000 Third 200 MVA Arroyo 345/115 kV XFMR EPE $4,500,000 Third 200 MVA Caliente 345/115 kV XFMR EPE $4,500,000 Third 200 MVA Newman 345/115 kV XFMR EPE $4,500,000 Newman-Vista 115 kV line (20.4 miles) EPE $4,488,000 Austin-Dyer 69 kV line upgrade (2.2 miles) EPE $473,000 Elephant Butte-Socorro 115 kV line upgrade (85 miles) Tri-State $18,700,000 Elephant Butte-Picacho 115 kV line upgrade (50 miles) Tri-State $11,000,000 Las Cruces-Dona Ana 115kV line upgrade (5 miles) Tri-State $1,100,000 Hurley-Luna 115 kV line upgrade (12 miles) TNMP $2,640,000 Central-Hurley 115 kV line upgrade (18) miles TNMP $3,960,000 SVG for voltage support in TNP/Tri-State areas TNMP/Tri-State $5,000,000


Therefore, the total estimated cost for Task III, Scenario A is $78,381,000. This is the estimated amount that, as per FERC, XXX is responsible for in order to interconnect into the EPE system and deliver its output into the grid in a Task III interconnection configuration. All estimated costs in Scenarios B, C, and D are in addition to the costs determined in Scenario A. For a detailed listing of all the criteria violations in the Task III Scenario A Case, please refer to the “2003 HS Task III Scenario A Case” Table in Appendix 7.


4.3.2 Task III, Scenario B The 2003 HS and 2003 LW cases for Task III, Scenario B were developed and analyzed in this study and compared to the Benchmark cases. Contingency powerflow analyses were then performed on these cases. The EPE system was represented as in the Benchmark cases, except that the XXX power source is now included. The XXX HVDC terminal was modeled as an interconnection directly into the Newman 345 kV bus. The imported power from XXX was modeled as a sale to California (PG&E area). This scenario determined the system impacts to the EPE and surrounding areas due to the interconnection of the XXX HVDC terminal and a transmission service agreement to the west of the EPE area. This scenario is similar to the Task II, Scenario B case, except that the XXX interconnection is directly into the Newman 345 kV bus instead of into a new substation connecting the Caliente-Newman and Caliente-Amrad 345 kV lines. The importation of 660 MW of power into the EPE system and sold to the west caused basically the same impacts to the EPE and surrounding areas systems under ALIS conditions as in the Task II, Scenario B case. First, the tap on the Arroyo Phase Shifting Transformer (PST) reached its minimum limit of –34° when the 660 MW of XXX power was exported throughout the WSCC area and therefore requires the PST taps to be changed out. In addition to this, the Hidalgo-Luna 345 kV line, Anthony-Newman 115 kV line, Arroyo-Las Cruces 115 kV line, and Arroyo 115/345 kV transformer are all overloaded with ALIS. The table below shows the overload criteria violations for Task II, Scenario B, with all lines in service for the 2003 HS case:

Overload Criteria Violations for Task III, Scenario B (2003 HS) Case


LINE/TRANSFORMER

OWNER

RATING (MVA)


POWER


IMPORTED POWER

Anthony-Newman 115 kV line EPE 143.6 106.5 90.8 Arroyo-Las Cruces 115 kV line EPE 143.6 108.6 76.2 Hidalgo-Luna 345 kV line EPE 717.1 100.3 73.8 Arroyo 115/345 kV XFMR EPE 200.0 116.3 84.7 Elephant Butte-Socorrop 115 kV line Tri-State 60.0 137.9 70.3 Elephant Butte-Picacho 115 kV line Tri-State 40.0 136.2 46.6 Hurley-Luna 115 kV line TNMP 79.6 124.6 98.6 Las Cruces-Dona Ana 115 kV line Tri-State 117.7 111.1 46.6

There were also some criteria violations during contingency conditions in the EPE, TNMP and Tri-State areas. The only difference between this scenario and the Task II, Scenario B scenario is that there is an overload of the 2nd Arroyo 345/115 kV instead of the 2nd Caliente 345/ 115 kV transformer. The


table below shows the overload criteria violations in Task III, Scenario B during contingency conditions:

Overload Criteria Violations for Task III, Scenario B (2003 HS) Case


CONTINGENCY


OWNER


POWER


IMPORTED POWER



Newman 345/115 kV XFMR #2 EPE 143.7 N/A Newman-Vista 115 kV line EPE 104.9 N/A Milagro 115/69 kV XFMR EPE 104.6 N/A

Dyer-Austin N 115 kV line Austin-Dyer 69 kV line EPE 105.0 98.5 Dyer-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 100.4 97.5 ANP-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 101.8 98.9 Arroyo 345/115 kV XFMR Arroyo 345/115 kV XFMR #2 EPE 102.3 N/A

Another criteria violation in this scenario was the extremely low voltages in the TNMP/Tri-State areas during an outage of the Luna-Hidalgo 345 kV line. Bus voltages in those areas ranged from 0.8484-0.9241 p.u. during the outage in this scenario. An analysis of the same outage in the Task I (Benchmark) scenario did not reveal any under voltage criteria violations. Therefore, this undervoltage impact is due to the interconnection of the XXX HVDC terminal. The proposed solution to correct this criteria violation is the addition of a Static Var Generator (SVG) device to be placed somewhere in the TNMP/Tri-State area. Since this criteria violation is not on the EPE system, a “rough” cost estimate for this recommended modification is provided using EPE prices. The following table lists those system modifications required in Task III, Scenario B that are in addition to those listed in Scenario A, with rough cost estimates also provided.

TASK III, SCENARIO B SYSTEM MODIFICATION COSTS


OWNER

ESTIMATED COST

Luna-Hidalgo 345 kV line upgrade (50.5 miles) EPE $11,615,000 Las Cruces-Dona Ana 115kV line upgrade (5 miles) Tri-State $1,100,000 Belen-Bernardo 115 kV line upgrade (15 miles) Tri-State $3,300,000 Bernardo-Socorro 115 kV line upgrade (20 miles) Tri-State $4,400,000

Total Incremental Costs for Task III, Scenario B: $20,415,000

The total estimated cost for Task III, Scenario B, including the estimated costs from Task III, Scenario A, is $98,796,000. For a detailed listing of all the criteria violations in Task III, Scenario B, please refer to the “2003 HS Task III Scenario B Case” Table in Appendix 7.


4.3.3 Task III, Scenario C The 2003 HS and 2003 LW cases for Task III, Scenario C were developed and analyzed in this study and compared to the Benchmark cases. Contingency powerflow analyses were then performed on these cases. The EPE system was represented as in the Benchmark cases, except that the XXX power source is now included. The XXX HVDC terminal was modeled as an interconnection directly into the Newman 345 kV bus. The imported power from XXX was modeled as a sale to northern New Mexico and Colorado (PNM & PSCO areas). This scenario determined the system impacts to the EPE and surrounding areas due to the interconnection of the XXX HVDC terminal and a transmission service agreement to the north of the EPE area.

The importation of 660 MW of power into the EPE system and sold to the west caused the basically the same impacts to the EPE and surrounding areas systems under ALIS conditions as in the Task II, Scenario C case. First, the tap on the Arroyo Phase Shifting Transformer (PST) reached its minimum limit of –34° when the 660 MW of XXX power was exported throughout the WSCC area and therefore requires the PST taps to be changed out. In addition to this, the Anthony-Newman 115 kV line, Dyer-Shearman 115 kV line, Arroyo-Las Cruces 115 kV line, Cromo-ANP 115 kV line, Butterfield-ANP 115 kV line, and Arroyo 115/345 kV transformer are all overloaded with ALIS. There were also some criteria violations in the Tri-State and TNMP areas with ALIS. The table below shows the overload criteria violations for Task III, Scenario C, with all lines in service for the 2003 HS case:

Overload Criteria Violations for Task III, Scenario C (2003 HS) Case


LINE/TRANSFORMER

OWNER

RATING (MVA)


POWER


IMPORTED POWER

Anthony-Newman 115 kV line EPE 143.6 111.7 90.8 Dyer-Shearman 115 kV line EPE 117.7 110.4 93.1 Arroyo-Las Cruces 115 kV line EPE 143.6 109.8 76.2 Cromo-ANP 115 kV line EPE 117.7 105.4 73.8 Butterfield-ANP 115 kV line EPE 117.7 104.7 88.6 Arroyo 115/345 kV XFMR EPE 200.0 116.7 84.7 Elephant Butte-Socorrop 115 kV line Tri-State 60.0 149.2 70.3 Elephant Butte-Picacho 115 kV line Tri-State 40.0 131.8 46.6 Hurley-Luna 115 kV line TNMP 79.6 123.1 98.6 Hernandez-Ojo 115 kV line Tri-State 117.7 100.3 94.9 There were also some criteria violations during contingency conditions in the EPE, TNMP, and Tri-State areas. The table below shows the overload criteria violations for the Task III, Scenario C Case during contingency conditions:


Overload Criteria Violations for Task III, Scenario C (2003 HS) Case During Contingency Conditions

CONTINGENCY


OWNER


POWER


IMPORTED POWER



Newman 345/115 kV XFMR #2 EPE 149.2 N/A Newman-Vista 115 kV line EPE 108.9 N/A Milagro 115/69 kV XFMR EPE 106.7 N/A Austin-Dyer 69 kV line EPE 104.3 N/A Austin N-Chevron S 115 kV line EPE 101.1 N/A Shearman-ANP 115 kV line EPE 100.4 N/A

Dyer-Austin N 115 kV line Austin-Dyer 69 kV line EPE 113.5 98.5 Dyer-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 103.5 97.5 ANP-Shearman 115 kV line Milagro 115/69 kV XFMR EPE 104.9 98.9 Amrad 345/115 kV XFMR Las Cruces-Dona Ana 115 kV line Tri-State 102.3 50.9 Arroyo 345 kV XFMR Arroyo 345/115 kV XFMR #2 EPE 102.5 82.3

Another criteria violation in this scenario was the extremely low voltages in the TNMP/Tri-State areas during an outage of the Luna-Hidalgo 345 kV line. Bus voltages in those areas ranged from 0.8411-0.9194 p.u. during the outage in this Scenario. An analysis of the same outage in the Task I (Benchmark) Scenario did not reveal any under voltage criteria violations. Therefore, this undervoltage impact is due to the interconnection of the XXX HVDC terminal. The proposed solution to correct this criteria violation is the addition of a Static Var Generator (SVG) device to be placed somewhere in the TNMP/Tri-State area. Since this criteria violation is not on the EPE system, a “rough” cost estimate for this recommended modification is provided using EPE prices. The following table lists those system modifications required in Task III, Scenario C that are in addition to those listed in Scenario A, with rough cost estimates also provided. TASK III, SCENARIO C SYSTEM MODIFICATION COSTS


OWNER

ESTIMATED COST

Dyer-Shearman 115 kV line upgrade (9.63 miles) EPE $2,119,000 Cromo-ANP115 kV line upgrade (19.9 miles) EPE $4,378,000 Butterfield-ANP115 kV line upgrade (16.7 miles) EPE $3,674,000 Austin N-Chevron S 115 kV line upgrade (1.2 miles) EPE $264,000 Shearman-ANP 115 kV line upgrade (7.26 miles) EPE $1,597,000 Hernandez-Ojo 115 kV line upgrade (17 miles) Tri-State $3,740,000 Bernardo-Socorro 115 kV line upgrade (20 miles) Tri-State $4,400,000 Belen-Bernardo 115 kV line upgrade (15 miles) Tri-State $3,300,000 Total Incremental Costs for Task III, Scenario C: $23,472,000


The total estimated cost for Task III, Scenario C, including the estimated costs from Task III, Scenario A, is $101,853,000. For a detailed listing of all the criteria violations in the Task III Scenario C Case, please refer to the “2003 HS Task III Scenario C Case” Table in Appendix 7.

4.3.4 Task III, Scenario D The 2003 HS and 2003 LW cases for Task III, Scenario D were developed and analyzed in this study and compared to the Benchmark cases. Contingency powerflow analyses were then performed on these cases. The EPE system was represented as in the Benchmark cases, except that the XXX HVDC terminal is now included. The XXX HVDC terminal was modeled as an interconnection directly into the Newman 345 kV bus. The imported power from XXX was modeled as a 330 MW sale to EPE and the remaining 330 MW of XXX power was modeled as being distributed throughout the WSCC. This scenario determined the system impacts to the EPE and surrounding areas due to the interconnection of the XXX HVDC terminal and a transmission service agreement to sell one half of its power to EPE and the other half throughout the WSCC. The importation of 660 MW of power into the EPE system, with 330 MW sold to EPE and 330 MW sold throughout the WSCC caused basically the same impacts to the EPE and surrounding areas systems under ALIS conditions as in the Task II, Scenario D case. First, the tap on the Arroyo Phase Shifting Transformer (PST) reached its minimum limit of –34° when the 660 MW of XXX power was exported throughout the WSCC area and therefore requires the PST taps to be changed out. In addition to this, the Arroyo-Las Cruces 115 kV line and Arroyo 115/345 kV transformer are overloaded with ALIS. There were also some criteria violations in the Tri-State and TNMP areas with ALIS. The table below shows the overload criteria violations for Task III, Scenario D, with all lines in service for the 2003 HS case:

Overload Criteria Violations for Task III, Scenario D (2003 HS) Case


LINE/TRANSFORMER

OWNER

RATING (MVA)


POWER


IMPORTED POWER

Arroyo-Las Cruces 115 kV line EPE 143.6 104.2 76.2 Arroyo 115/345 kV XFMR EPE 200.0 119.6 84.7 Elephant Butte-Socorrop 115 kV line Tri-State 60.0 101.7 70.3 Hurley-Luna 115 kV line TNMP 79.6 111.0 98.6

There were also some criteria violations during contingency conditions in the EPE, TNMP, and Tri-State areas. The table below shows the overload criteria violations for the Task III, Scenario D Case during contingency conditions:


Overload Criteria Violations for Task III, Scenario D (2003 HS) Case During Contingency Conditions

CONTINGENCY


OWNER


POWER


IMPORTED POWER

Luna-Hidalgo 345 kV line Central-Hurley 115 kV line TNMP 115.8 86.9 Elephant Butte-Picacho 115 kV line Tri-State 110.2 67.4 Arroyo 345/115 kV XFMR Arroyo 345/115 kV XFMR #2 EPE 106.6 N/A Caliente 345/115 kV XFMR Caliente 345/115 kV XFMR #2 EPE 116.6 82.3

Another criteria violation in this scenario was the extremely low voltages in the TNMP/Tri-State areas during an outage of the Luna-Hidalgo 345 kV line. Bus voltages in those areas ranged from 0.8235-0.9195 p.u. during the outage in this Scenario. An analysis of the same outage in the Task I (Benchmark) Scenario did not reveal any under voltage criteria violations. Therefore, this undervoltage impact is due to the interconnection of the XXX HVDC terminal. The proposed solution to correct this criteria violation is the addition of a Static Var Generator (SVG) device to be placed somewhere in the TNMP/Tri-State area. Since this criteria violation is not on the EPE system, a “rough” cost estimate for this recommended modification is provided using EPE prices. The proposed solutions for correcting the criteria violations in Task III, Scenario D, with rough cost estimates, are listed below:

All of the proposed solutions for correcting the criteria violations in Task III, Scenario D, have been incorporated in Task III, Scenario A. Therefore, there are no additional costs in Scenario D and the total estimated cost for Task III, Scenario D is $78,381,000. For a detailed listing of all the criteria violations in the Task III Scenario D Case, please refer to the “2003 HS Task III Scenario D Case” Table in Appendix 7.

In conclusion, the results of the powerflow analyses indicate that there were major impacts to the transmission systems in the EPE and surrounding areas for all scenarios analyzed. A summary of the estimated costs to correct the impacts in each scenario analyzed is listed below:

ESTIMATED SYSTEM MODIFICATION COSTS BY SCENARIO SCENARIO ESTIMATED COST

TASK II, SCENARIO A (interconnect and distribute power to the grid) $78,793,000 TASK II, SCENARIO B (send XXX power to the west) $98,108,000 TASK II, SCENARIO C (send XXX power to the north) $96,026,000 TASK II, SCENARIO D (send 50 % of XXX power to EPE and 50% to WSCC) $78,793,000 TASK III, SCENARIO A (interconnect and distribute power to the grid) $78,381,000 TASK III, SCENARIO B (send XXX power to the west) $98,796,000 TASK III, SCENARIO C (send XXX power to the north) $101,853,000 TASK III, SCENARIO D (send 50 % of XXX power to EPE and 50% to WSCC) $78,381,000


5.0 TRANSIENT STABILITY ANALYSIS RESULTS Transient stability analyses for each scenario in Task I, Task II and Task III were performed for a three-phase 3.5 cycle bus fault. Using Engineering judgement, it was determined that the Hidalgo-Luna (HL) and Caliente-Newman (CN) three phase faults would be the worst faults on the EPE system for the scenarios that were analyzed. The transient stability analyses were performed on each of the following buses:

• The Newman bus and dropping the CN 345 kV line. • The Luna bus and dropping the SL 345 kV line.

The fault was cleared at 3.5 cycles. Results of these analyses are listed below.

5.1 Task I

The Task I case simulated the existing EPE system without the XXX HVDC terminal. Analysis was performed on the 2003 Heavy Summer (2003 HS) case. Pages 1-1 to 2-7 of Appendix 8 contains plots of the six worst case deviations of the angle (ang), bus voltage (vbu*) and bus frequency (fbu*) for the 03HS and 03LW Task I cases. The “*” can represent an “l” for a bus with load, “s” for a bus without load, or “g” for a generator bus. The case was reviewed for conformance to the WSCC criteria for voltage and frequency dips. No criteria violations were found in either the 2003 HS Task I case. 5.2 Task II The Task II Alternative simulated the XXX HVDC terminal interconnection, totaling 660 MW, as being interconnected into the EPE transmission system at a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Four scenarios were analyzed in Task II. Scenario A analyzed the impacts of interconnecting the XXX HVDC terminal into the EPE system and delivering the output into the grid. Scenarios B, C, and D analyzed specific transmission service scenarios. Scenario B modeled a transmission service agreement to sell the XXX power west of the EPE area (California). Scenario C modeled a transmission service agreement to sell the XXX power north of the EPE area (New Mexico and Colorado). Scenario D modeled a transmission service agreement to sell half of the XXX power to EPE and distribute the other half throughout the WSCC. Below are the results of the Transient Stability analyses for each scenario in Task II.

5.2.1 Task II, Scenario A

The Task II Scenario A cases consisted of importing 660 MW of XXX HVDC power into the EPE system and then exporting that power throughout the WSCC. Stability data for the XXX HVDC terminals was modeled based on the information provided by XXX. Pages 3-1 to 4-7 of Appendix 8 contains plots of the six worst case deviations of the angle (ang), bus voltage


(vbu*) and bus frequency (fbu*) for the 03HS Task II Scenario A case. The “*” can represent an “l” for a bus with load, “s” for a bus without load, or “g” for a generator bus. Each case was reviewed for conformance to the WSCC criteria for voltage and frequency dips. No criteria violations were found in the 2003 HS Task II Scenario A case.

5.2.2 Task II, Scenario B

The Task II Scenario B cases consisted of importing 660 MW of XXX HVDC power into the EPE system and then exporting that power to California. Stability data for the XXX HVDC terminals was modeled based on the information provided by XXX. Pages 5-1 to 6-7 of Appendix 8 contains plots of the six worst case deviations of the angle (ang), bus voltage (vbu*) and bus frequency (fbu*) for the 03HS Task II Scenario B case. The “*” can represent an “l” for a bus with load, “s” for a bus without load, or “g” for a generator bus. Each case was reviewed for conformance to the WSCC criteria for voltage and frequency dips. No criteria violations were found in the 2003 HS Task II Scenario B case.

5.2.3 Task II, Scenario C

The Task II Scenario C case consisted of importing 660 MW of XXX HVDC power into the EPE system and then exporting that power to northern New Mexico and Colorado. Stability data for the XXX HVDC terminals was modeled based on the information provided by XXX. Pages 7-1 to 8-7 of Appendix 8 contains plots of the six worst case deviations of the angle (ang), bus voltage (vbu*) and bus frequency (fbu*) for the 03HS Task II Scenario C case. The “*” can represent an “l” for a bus with load, “s” for a bus without load, or “g” for a generator bus. Each case was reviewed for conformance to the WSCC criteria for voltage and frequency dips. Frequency and Voltage criteria violations were found in the analyses of a fault at both the Luna and Newman 345 kV buses. Engineering judgement concludes that these criteria violations are a result of a voltage collapse on the Tri-State system due to lack of MVAR support. As can be seen in the 2003 Task II Scenario C Table in Appendix 7, extremely low voltages exist in the Tri-State area due to the importation of the XXX power. Therefore, additional MVAR support is needed in the Tri-State area in order to correct these transient stability violations. It is assumed that an SVG of undetermined size (recommended in the powerflow analysis in Section 4.4) will be sufficient to correct the transient stability criteria violations. However, a detailed analysis will need to be performed in order to determine an optimal solution for correcting these criteria violations.


5.2.4 Task II, Scenario D The Task II Scenario D case consisted of importing 660 MW of XXX HVDC power into the EPE system and selling 330 MW to EPE, and exporting the remaining 330 MW of power throughout the WSCC. Stability data for the XXX HVDC terminals was modeled based on the information provided by XXX. Pages 9-1 to 10-7 of Appendix 8 contains plots of the six worst case deviations of the angle (ang), bus voltage (vbu*) and bus frequency (fbu*) for the 03HS Task II Scenario D case. The “*” can represent an “l” for a bus with load, “s” for a bus without load, or “g” for a generator bus. Each case was reviewed for conformance to the WSCC criteria for voltage and frequency dips. No criteria violations were found in the 2003 HS Task II Scenario D case.

5.3 Task III

The Task III Alternative simulated the XXX HVDC terminal interconnection, totaling 660 MW, as being interconnected directly into the EPE transmission system at the Newman 345 kV bus. The same four scenarios analyzed in Task II were also analyzed in Task III. Scenario A analyzed the impacts of interconnecting the XXX HVDC terminal into the EPE system and delivering the output into the grid. Scenarios B, C, and D analyzed specific transmission service scenarios. Scenario B modeled a transmission service agreement to sell the XXX power west of the EPE area (California). Scenario C modeled a transmission service agreement to sell the XXX power north of the EPE area (New Mexico and Colorado). Scenario D modeled a transmission service agreement to sell half of the XXX power to EPE and distribute the other half throughout the WSCC. Below are the results of the Transient Stability analyses for each scenario in Task III.

5.3.1 Task III, Scenario A The Task III Scenario A case consisted of importing 660 MW of XXX HVDC power into the EPE system and then exporting that power throughout the WSCC. The difference between this scenario and the Task II scenario was that in this scenario, the XXX HVDC terminal is interconnected directly into the Newman 345 kV bus; in the Task II scenario, it is interconnected into a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Stability data for the XXX HVDC terminals was modeled based on the information provided by XXX. Pages 11-1 to 12-7 of Appendix 8 contains plots of the six worst case deviations of the angle (ang), bus voltage (vbu*) and bus frequency (fbu*) for the 03HS Task III Scenario A case. The “*” can represent an “l” for a bus with load, “s” for a bus without load, or “g” for a generator bus. Each case was reviewed for conformance to the WSCC criteria for voltage and frequency dips. No criteria violations were found in the 2003 HS Task III Scenario A case.


5.3.2 Task III, Scenario B The Task III Scenario B case consisted of importing 660 MW of XXX HVDC power into the EPE system and then exporting that power to California. The difference between this scenario and the Task II scenario was that in this scenario, the XXX HVDC terminal is interconnected directly into the Newman 345 kV bus; in the Task II scenario, it is interconnected into a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Stability data for the XXX HVDC terminals was modeled based on the information provided by XXX. Pages 13-1 to 14-7 of Appendix 8 contains plots of the six worst case deviations of the angle (ang), bus voltage (vbu*) and bus frequency (fbu*) for the 03HS Task III Scenario B case. The “*” can represent an “l” for a bus with load, “s” for a bus without load, or “g” for a generator bus. Each case was reviewed for conformance to the WSCC criteria for voltage and frequency dips. No criteria violations were found in the 2003 HS Task III Scenario B case.

5.3.3 Task III, Scenario C The Task III Scenario C case consisted of importing 660 MW of XXX HVDC power into the EPE system and then exporting that power to northern New Mexico and Colorado. Stability data for the XXX HVDC terminals was modeled based on the information provided by XXX. Pages 15-1 to 16-7 of Appendix 8 contains plots of the six worst case deviations of the angle (ang), bus voltage (vbu*) and bus frequency (fbu*) for the 03HS Task III Scenario C case. The “*” can represent an “l” for a bus with load, “s” for a bus without load, or “g” for a generator bus. Each case was reviewed for conformance to the WSCC criteria for voltage and frequency dips. Frequency and Voltage criteria violations were found in the analysis of a fault at both the Luna and Newman 345 kV buses. Engineering judgement concludes that these criteria violations are a result of a voltage collapse on the Tri-State system due to lack of MVAR support. As can be seen in the 2003 Task III Scenario C Table in Appendix 7, extremely low voltages exist in the Tri-State area due to the importation of the XXX power. Therefore, additional MVAR support is needed in the Tri-State area in order to correct these transient stability violations. It is assumed that an SVG of undetermined size (recommended in the powerflow analysis in Section 4.8) will be sufficient to correct the transient stability criteria violations. However, a detailed analysis will need to be performed in order to determine an optimal solution for correcting these criteria violations.


5.3.4 Task III, Scenario D The Task III Scenario D case consisted of importing 660 MW of XXX HVDC power into the EPE system and selling 330 MW to EPE, and exporting the remaining 330 MW of power throughout the WSCC. Stability data for the XXX HVDC terminals was modeled based on the information provided by XXX. Pages 17-1 to 18-7 of Appendix 8 contains plots of the six worst case deviations of the angle (ang), bus voltage (vbu*) and bus frequency (fbu*) for the 03HS Task III Scenario D case. The “*” can represent an “l” for a bus with load, “s” for a bus without load, or “g” for a generator bus. Each case was reviewed for conformance to the WSCC criteria for voltage and frequency dips. No criteria violations were found in the 2003 HS Task III Scenario D case.

In conclusion, the results of the transient stability analyses indicate that for all scenarios except Scenario C in both Task II and Task III, there were no voltage or frequency criteria violations. Frequency and voltage criteria violations were found in the Task II and Task III, Scenario C cases. Although system modifications were not analyzed, engineering judgement assumes that these violations will be corrected if the system modifications recommended in Sections 4.4 and 4.8 of this report are implemented. However, a detailed analysis will need to be performed in order to determine an optimal solution for correcting these criteria violations.


6.0 Q-V ANALYSIS RESULTS As outlined in the Study Scope Agreement, Q-V analyses are conducted in order to verify that the scenarios, which include the importation of XXX power, comply with the WSCC Voltage Stability Criteria. Q-V analysis provides a way to investigate the potential for voltage collapse during the post-transient period within 3 minutes after the disturbance. Q-V analyses were performed on the Task I, Task II Scenarios A-D, and Task III, Scenarios A-D. A procedure developed by WSCC is used to determine the reactive power margin. As outlined in this procedure, load is increased by 5% and the worst contingency is analyzed to determine the reactive margin on the system. The margin is determined by identifying the critical (weakest) bus on the system during the worst contingency. The critical bus is the most reactive deficient bus. Q-V curves are developed and the minimum point on the curve is the critical point. If the minimum point of the Q-V curve is positive, i.e., above the x-axis, the system is reactive power deficient. If it is negative, i.e., below the x-axis, then the system has some reactive power margin and meets the WSCC criteria. From experience, it has been established that the worst contingencies impacting reactive power margin on the EPE system are the Springerville-Luna (SL), Luna-Diablo (LD), and Greenlee-Hidalgo (GH) 345 kV lines. During this analysis, it has been determined that the worst contingency for voltage stability on the EPE system is the Luna-Diablo 345 kV line. This contingency, therefore, was used in the final analysis to verify that EPE reactive power margins are in compliance with the WSCC criteria. Q-V analyses were conducted for the 2003 Heavy Summer system configuration. EPE 345 kV buses monitored included Hidalgo, Newman, Caliente and Diablo. Q-V analyses for the Base Case, and a contingency of the LD 345 kV line was performed. Resulting plots and reactive power margins of the analyses can be found in Appendix 9. Following are the results of the Q-V analysis. The tables that follow show the reactive power margins available in each scenario and the most critical bus in each case. Please note that a negative number indicates that there is sufficient reactive power to meet WSCC criteria and a positive number indicates that the system is deficient in reactive power and does not meet the criteria.

6.1 Task I

The Task I case simulated the existing EPE system without the XXX HVDC terminal. Analyses were performed on the 2003 HS and 2003 LW cases.

Task I Case – Available Reactive Power Margin System Condition MVAR Margin Critical Bus

2003 HS All Lines in Service -598.8 Caliente 2003 HS Luna-Diablo Contingency -216.3 Diablo 2003 LW All Lines in Service -703.2 Caliente 203 LW Luna-Diablo Contingency -294.2 Diablo


As can be seen in the above table, there were no reactive power margin deficiencies in any of the Task I Cases analyzed. Of all the buses monitored, the Diablo 345 kV bus had the least MVAR margin. It had a -216.0 MVAR margin during a LD contingency in the 2003 HS case, and a margin of -294.2 in the 2003 LW case. However, this margin indicates that there is sufficient reactive power to meet WSCC criteria. Also, the table above indicates that the HS case is the worst case scenario because it has less of a margin than in the LW case. It was assumed that this is also the case for all of the other scenarios analyzed. Therefore, only the 2003 HS cases for each of the scenarios in Task II and Task III were analyzed. The Q-V analysis plots and reactive power margins for Task I can be found on pages 1-1 through 1-4 of Appendix 9.

6.2 Task II The Task II Alternative simulated the XXX HVDC terminal interconnection, totaling 660 MW, as being interconnected into the EPE transmission system at a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Four scenarios were analyzed in Task II. Scenario A analyzed the impacts of interconnecting the XXX HVDC terminal into the EPE system and delivering the output into the grid. Scenarios B, C, and D analyzed specific transmission service scenarios. Scenario B modeled a transmission service agreement to sell the XXX power west of the EPE area (California). Scenario C modeled a transmission service agreement to sell the XXX power north of the EPE area (New Mexico and Colorado). Scenario D modeled a transmission service agreement to sell half of the XXX power to EPE and distribute the other half throughout the WSCC. Below are the results of the Q-V analyses for each scenario in Task II.

6.2.1 Task II, Scenario A The Task II, Scenario A case simulated the XXX HVDC power as being imported into the EPE system and the power being distributed throughout the WSCC area. Analysis was performed on the 2003 HS case. Results of the analysis for this scenario are shown below:

Task II, Scenario A Case – Available Reactive Power Margin

System Condition MVAR Margin Critical Bus 2003 HS All Lines in Service -531.5 Caliente 2003 HS Luna-Diablo Contingency -269.1 Diablo

As can be seen in the table above, there was no reactive power margin deficiency in the Task II Scenario A case. The Luna-Diablo 345 kV line contingency had a MVAR margin of -269.1 MVAR, which is sufficient to meet WSCC criteria. The Q-V analysis plots and reactive power margins for Task II, Scenario A can be found on pages 2-1 through 2-2 of Appendix 9.


6.2.2 Task II, Scenario B The Task II, Scenario B case simulated the XXX HVDC power as being imported into the EPE system and the power being sold to California (PG&E area). Analysis was performed on the 2003 HS case. Results of the analysis for this scenario are shown below:

Task II, Scenario B Case – Available Reactive Power Margin


As can be seen in the table above, there was no reactive power margin deficiency in the Task II Scenario B case. The Luna-Diablo 345 kV line contingency had a MVAR margin of –284.2 MVAR, which is sufficient to meet WSCC criteria. The Q-V analysis plots and reactive power margins for Task II, Scenario B can be found on pages 2-3 through 2-4 of Appendix 9.

6.2.3 Task II, Scenario C The Task II, Scenario C case simulated the XXX HVDC power as being imported into the EPE system and the power being sold to northern New Mexico and Colorado (PNM & PSCO areas). Analysis was performed on the 2003 HS case. Results of the analysis for this scenario are shown below:

Task II, Scenario C Case – Available Reactive Power Margin


As can be seen in the table above, there was no reactive power margin deficiency in the Task II Scenario C case. The Luna-Diablo 345 kV line contingency had a MVAR margin of –253.0 MVAR, which is sufficient to meet WSCC criteria. The Q-V analysis plots and reactive power margins for Task II, Scenario C can be found on pages 2-5 through 2-6 of Appendix 9.

6.2.4 Task II, Scenario D The Task II, Scenario D case simulated the XXX HVDC power as being imported into the EPE system and the half of the power being sold to EPE, and the other half being distributed throughout the WSCC. Analysis was performed on the 2003 HS case. Results of the analysis for this scenario are shown below:


Task II, Scenario D Case – Available Reactive Power Margin System Condition MVAR Margin Critical Bus

2003 HS All Lines in Service -559.2 Caliente 2003 HS Luna-Diablo Contingency -250.9 Diablo

As can be seen in the table above, there was no reactive power margin deficiency in the Task II Scenario D case. The Luna-Diablo 345 kV line contingency had a MVAR margin of –250.9 MVAR, which is sufficient to meet WSCC criteria. The Q-V analysis plots and reactive power margins for Task II, Scenario D can be found on pages 2-7 through 2-8 of Appendix 9.

6.3 Task III

The Task III Alternative simulated the XXX HVDC terminal interconnection, totaling 660 MW, as being interconnected directly into the EPE transmission system at the Newman 345 kV bus. The same four scenarios analyzed in Task II were also analyzed in Task III. Scenario A analyzed the impacts of interconnecting the XXX HVDC terminal into the EPE system and delivering the output into the grid. Scenarios B, C, and D analyzed specific transmission service scenarios. Scenario B modeled a transmission service agreement to sell the XXX power west of the EPE area (California). Scenario C modeled a transmission service agreement to sell the XXX power north of the EPE area (New Mexico and Colorado). Scenario D modeled a transmission service agreement to sell half of the XXX power to EPE and distribute the other half throughout the WSCC. Below are the results of the Q-V analyses for each scenario in Task III.

6.3.1 Task III, Scenario A The Task III, Scenario A case simulated the XXX HVDC power as being imported into the EPE system and the power being distributed throughout the WSCC area. The difference between this scenario and the Task II scenario was that in this scenario, the XXX HVDC terminal is interconnected directly into the Newman 345 kV bus; in the Task II scenario, it is interconnected into a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Analysis was performed on the 2003 HS case. Results of the analysis for this scenario are shown below:

Task III, Scenario A Case – Available Reactive Power Margin

System Condition MVAR Margin Critical Bus 2003 HS All Lines in Service -564.0 Newman 2003 HS Luna-Diablo Contingency -256.4 Diablo

As can be seen in the table above, there was no reactive power margin deficiency in the Task III, Scenario A case. The Luna-Diablo 345 kV line contingency had a MVAR margin of -256.4 MVAR, which is sufficient to


meet WSCC criteria. The Q-V analysis plots and reactive power margins for Task III, Scenario A can be found on pages 3-1 through 3-2 of Appendix 9. 6.3.2 Task III, Scenario B The Task II, Scenario B case simulated the XXX HVDC power as an import into the EPE system and the power sold to California (PG&E area). The difference between this scenario and the Task II scenario was that in this scenario, the XXX HVDC terminal is interconnected directly into the Newman 345 kV bus; in the Task II scenario, it is interconnected into a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Analysis was performed on the 2003 HS case. Results of the analysis for this scenario are shown below:

Task III, Scenario B Case – Available Reactive Power Margin


As can be seen in the table above, there was no reactive power margin deficiency in the Task III, Scenario B case. The Luna-Diablo 345 kV line contingency had a MVAR margin of –274.7 MVAR, which is sufficient to meet WSCC criteria. The Q-V analysis plots and reactive power margins for Task III, Scenario B can be found on pages 3-3 through 3-4 of Appendix 9.

6.3.3 Task III, Scenario C The Task III, Scenario C case simulated the XXX HVDC power as an import into the EPE system and the power sold to northern New Mexico and Colorado (PNM & PSCO areas). The difference between this scenario and the Task II scenario was that in this scenario, the XXX HVDC terminal is interconnected directly into the Newman 345 kV bus; in the Task II scenario, it is interconnected into a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Analysis was performed on the 2003 HS case. Results of the analysis for this scenario are shown below:

Task III, Scenario C Case – Available Reactive Power Margin


As can be seen in the table above, there was no reactive power margin deficiency in the Task III, Scenario C case. The Luna-Diablo 345 kV line contingency had a MVAR margin of –256.0 MVAR, which is sufficient to meet WSCC criteria. The Q-V analysis plots and reactive power margins for Task III, Scenario C can be found on pages 3-5 through 3-6 of Appendix 9.


6.3.4 Task III, Scenario D The Task III, Scenario D case simulated the XXX HVDC power as an import into the EPE system and with half of the power being sold to EPE, and the other half being distributed throughout the WSCC. The difference between this scenario and the Task II scenario was that in this scenario, the XXX HVDC terminal is interconnected directly into the Newman 345 kV bus; in the Task II scenario, it is interconnected into a new substation intersecting the Caliente-Newman and Caliente-Amrad 345 kV lines. Analysis was performed on the 2003 HS case. Results of the analysis for this scenario are shown below:

Task III, Scenario D Case – Available Reactive Power Margin


As can be seen in the table above, there was no reactive power margin deficiency in the Task III, Scenario D case. The Luna-Diablo 345 kV line contingency had a MVAR margin of –235.3 MVAR, which is sufficient to meet WSCC criteria. The Q-V analysis plots and reactive power margins for Task III, Scenario D can be found on pages 3-7 through 3-8 of Appendix 9.

In conclusion, the Q-V analyses indicate that there is sufficient MVAR margin to meet the WSCC criteria in all the scenarios analyzed. Also, there is little difference in MVAR margins between the Task II and Task III cases.


7.0 DISCLAIMER The transfer capacities of certain transmission lines and paths within the southern New Mexico transmission system are limited by contracts between the New Mexico transmission owners. Therefore, notwithstanding the physical transmission transfer capacities determined in this Study, any changes in or use of the transfer capacities above those contractual limits will require agreement of the contractual parties or re-negotiation of the applicable contracts.



8.0 CERTIFICATION El Paso Electric Company (EPE) has performed this Transmission Interconnection Feasibility Study (Fatal Flaw Analysis) for XXXXXXXXXXXXXX (XXX) pursuant to XXX’s Request for Interconnection Agreement and Study dated February 14, 2001. The Study analyzes the EPE and southern New Mexico system impacts due to the importation of 660 MW of HVDC power, interconnected into the EPE transmission system. It also provides rough cost estimates for modifications required to correct these impacts, as per the Feasibility Transmission Interconnection Study: Study Scope received by EPE on September 10, 2001. EPE performed powerflow, QV reactive margin, and transient stability analyses. Name: Dennis H. Malone Title: Supervisor, System Planning

Signature: Dennis H. Malone Date: January 11, 2002

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