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Interconnection System Impact Study Final Report – May 11, 2015

Generator Interconnection Request No. TI-15-0227

25 MW Solar Photovoltaic (PV) Energy Generating Facility In Luna County, New Mexico

Prepared By:

Jeffery L. Ellis of Utility System Efficiencies, Inc.

Reviewed By:

Mark Stout Tri-State Generation and Transmission Association, Inc.

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITY THIS DOCUMENT WAS PREPARED FOR TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC., IN ITS CAPACITY AS TRANSMISSION PROVIDER (TP), IN RESPONSE TO A LARGE GENERATOR INTERCONNECTION REQUEST. NEITHER TP, NOR ANY PERSON ACTING ON BEHALF OF TP: (A) MAKES ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, WITH RESPECT TO THE USE OF ANY INFORMATION, METHOD, PROCESS, CONCLUSION, OR RESULT INCLUDING FITNESS FOR A PARTICULAR PURPOSE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY, INCLUDING ANY CONSEQUENTIAL DAMAGES, RESULTING FROM USE OF THIS DOCUMENT OR ANY INFORMATION CONTAINED HEREIN.

System Impact Study for TI-15-0227: Final Report Tri-State Generation and Transmission Association, Inc.

TABLE OF CONTENTS

Page No.

1.0 EXECUTIVE SUMMARY ...............................................................................................3

2.0 BACKGROUND AND SCOPE ........................................................................................5

3.0 GF MODELING DATA ....................................................................................................7

4.0 STEADY-STATE POWER FLOW ANALYSIS ............................................................7 4.1 Criteria and Assumptions .......................................................................................7 4.2. Voltage Regulation and Reactive Power Criteria ...................................................9 4.3 Steady-State Power Flow Results...........................................................................9

5.0 DYNAMIC STABILITY ANALYSIS ............................................................................13 5.1 Criteria and Assumptions .....................................................................................13 5.2 Base Case Model Assumptions ............................................................................15 5.3 Methodology ........................................................................................................15 5.4 Results ..................................................................................................................16

6.0 SHORT-CIRCUIT ANALYSIS ......................................................................................17 6.1 Assumptions and Methodology ............................................................................17 6.2 Results ..................................................................................................................17

7.0 SCOPE, COST AND SCHEDULE .................................................................................20

NOTE: Appendices are Tri-State Confidential, are available only to the IC and Affected Systems upon request, and are not for posting on OASIS.

Appendix A: Steady State Power Flow – List of N-1 Contingencies

Appendix B: Steady State Power Flow – Plots Appendix C: Dynamic Stability - Switching Sequences

Appendix D: Dynamic Stability – Waveform Plots

Appendix E: Generation Dispatch Summary (BAs 10, 70, 73)

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1.0 EXECUTIVE SUMMARY This System Impact Study (SIS) is for Generator Interconnection Request No. TI-15-0227, a proposed 25 MW solar photovoltaic Generating Facility (GF) located in Luna County, New Mexico (Project). This SIS was conducted for the Transmission Provider, Tri-State Generation and Transmission Association, Inc., (Tri-State) in accordance with its Generator Interconnection Procedures, and includes steady-state power flow, dynamic stability, short-circuit and cost and schedule analyses for interconnection of the Project as a Network Resource.

Cost and schedule estimates are as provided by Tri-State, and are good faith estimates only (typically +/-30% accuracy). Higher accuracy (+/- 20%) will be provided as part of an Interconnection Facilities Study.

The proposed Project consists of 28 SMA 900CP 0.9 MW solar inverters with one 34.5-115 kV, 15/20/25 MVA transformer at the main solar energy Generating Facility. The primary Point of Interconnection (POI) is 27 miles north of the Mimbres 115 kV Substation on the Mimbres - Caballo 115 kV transmission line (see Figure 1 for reference). In addition to analyzing the proposed 25 MW generation project, a sensitivity to determine the maximum generation output at this location was simulated.

Steady-state power flow results:

Single contingency analysis was completed using 2019 heavy summer and light autumn load and dispatch conditions with the planned Project. With the GF at its full 25 MW output there were no transmission elements that exceeded emergency thermal limits as a result of the Project generation. No voltage violations were observed.

For the sensitivity, a maximum Project output of 65 MW was determined. Loss of the Mimbres - New Sub 115 kV line, results in the Cuchillo - Elephant Butte 115 kV line loading to its maximum thermal limit of 62 MVA. No voltage violations were observed with the higher generation.

Reactive power / voltage regulation:

The system model provided by the Interconnecting Customer shows that this GF can meet Tri-State's 0.95 p.f. lag (producing) criteria at the POI. However, the GF cannot meet Tri-State's 0.95 p.f. lead (absorbing) criteria at the POI. When absorbing VARs, the Project is deficient at all levels of power output. See Table 7. Therefore, supplemental reactive power equipment of approximately 3 MVAR of switched shunt reactors will be required at the full 25.2 MW GF output to meet the net 0.95 p.f. lag (producing VAR) criteria at the POI. If the actual inverter capability is greater than that assumed by this study, the amount of reactive power equipment may be reduced. The same amount of reactive equipment (3 MVAR) will be required on the 34.5 kV bus to offset the collector system VARs and meet Tri-State’s VAR neutral requirement (less than 2 MVAR flow at 0 MW output at the POI).

Dynamic stability analyses:

Transient stability analysis was completed using an SMA Sunny Central 900 kVA Inverter dynamic model. The GF at the 25 MW generation level did not trip during any of the simulated disturbances with acceptable voltage levels for the SMA inverters. Local area generators showed stable performance and remained in synchronism for all contingencies. Acceptable damping and voltage recovery was observed. (Appendix D).

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Short - Circuit analyses:

Results indicate that the GF increases the fault duty by approximately 110 amperes at the 115 kV POI bus. The resultant total fault currents are well within Tri-State’s planned substation equipment ratings.

The estimated cost for interconnecting the proposed Project at the 115 kV POI is as follows (refer to Figure 3):

• Network Upgrade Costs (Reimbursable): $ 4.4 M • Interconnection Facilities Costs (Non-Reimbursable): $ 0.9 M • TOTAL Cost (2016 dollars) for Interconnection: $ 5.3 M

The in-service date for this GF will depend on construction of the Interconnection Facilities and Network Upgrades, and be a minimum of 18 months after the execution of a Generator Interconnection Agreement or Engineering and Procurement contract.

NOTE: Pursuant to Section 3.2.2.4 of Tri-State’s Generator Interconnection Procedures, “Interconnection Service does not convey the right to deliver electricity to any customer or point of delivery. In order for an Interconnection Customer to obtain the right to deliver or inject energy beyond the Generating Facility Point of Interconnection or to improve its ability to do so, transmission service must be obtained pursuant to the provisions of Transmission Provider’s Tariff by either Interconnection Customer or the purchaser(s) of the output of the Generating facility.” See Tri-State’s Open Access Same Time Information System (OASIS) web site for information regarding requests for transmission service, related requirements and contact information.

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System Impact Study for TI-15-0227: Final Report Tri-State Generation and Transmission Association, Inc. 2.0 BACKGROUND AND SCOPE

On February 27, 2015, the Interconnecting Customer submitted a Generator Interconnection Request for a 25 MW solar energy GF to be connected to Tri-State’s Mimbres - Caballo 115 kV transmission line. The application was deemed complete on March 3, 2015 and an Interconnection System Study Agreement was executed on March 20, 2015. The model data used in this study is that which was provided by the Customer in its Generator Interconnection Request.

This System Impact Study was prepared in accordance with Tri-State’s Generator Interconnection Procedures and relevant FERC, NERC, WECC and Tri-State guidelines. The objectives are: 1) to evaluate the steady state performance of the system with the proposed project, 2) identify Interconnection Facilities and Network Upgrades, 3) check the GF’s ability to meet Tri-State’s voltage regulation and reactive power criteria, 4) assess the dynamic performance of the transmission system under specified stability contingencies, 5) perform a basic short circuit analysis to provide the estimated maximum (N-0) and minimum (N-1) short circuit currents, and 6) provide a preliminary estimate of the costs and schedule for all necessary Interconnection Facilities and Network Upgrades, subject to refinement in a Facilities Study.

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System Impact Study for TI-15-0227: Final Report Tri-State Generation and Transmission Association, Inc. Figure 1: Area Map - One-Line Diagram Of Study Area And Location of GF

TI-15-0227 25 MW

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System Impact Study for TI-15-0227: Final Report Tri-State Generation and Transmission Association, Inc. 3.0 GF MODELING DATA

The Project consists of a 25 MW equivalent solar inverter with one 34.5-115 kV transformer to be connected approximately 27 miles north of the Mimbres 115 kV Substation on the Mimbres - Caballo 115 kV transmission line. Model data is based upon information provided by the Interconnecting Customer (IC). The IC must provide actual data and confirm actual reactive power operating capabilities prior to interconnecting this project, and ultimately prior to the IC’s GF being deemed by Tri-State as suitable for commercial operation.

Generator Data: The study modeled an equivalent generator with a Pmax of 25.2 MW and reactive capability of 0.95 lag and 0.95 lead, 8.28 and -8.28 MVAr, respectively.

Table 1 - Generator Data for Steady-State Power Flow Analyses Unit Description

Pmax Name plate rating (lumped equivalent gen model) 25.2 MW

Qmin, Qmax Reactive capability 0.95 lag to 0.95 lead

Et Terminal voltage 0.357 kV

RSORCE Synchronous resistance 0.0000 p.u.

XSORCE Synchronous reactance 9999 p.u.

34.5 kV Collector System: The medium voltage collector system was modeled with data provided by the IC. The solar inverters interconnect to the POI via one 34.5-115 kV transformer and an equivalent feeder circuit.

Main GF Substation Transformer: The substation transformer was modeled with ratings of 15/20/25 MVA and a voltage ratio of 34.5 kV (gnd-wye) - 115 kV (gnd-wye). The transformer impedance is 8% on the 15 MVA base FA rating with X/R of 27.

4.0 STEADY-STATE POWER FLOW ANALYSIS

4.1 Criteria and Assumptions Siemens-PTI PSS/E version 33.5.0 software was used for performing the steady-state power flow analysis, with the following study criteria:

1. Tri-State’s GIP 2019 HS and LA (PSS/E-v33) base cases were developed from WECC approved seed cases (17HS1A_v33, for 2013 CCPG Compliance Study), with updates from the latest loads and resources data, topology (line and transformer ratings data, planned and budgeted projects, etc.), and updates received from several regional utilities and Affected Systems. The following base cases were utilized for this SIS:

a. 2019 HS cases with and without the IC’s new GF Project b. 2019 LA cases with and without the IC’s new GF Project

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2. The output from TI-14-0227 was accommodated by displacing Tri-State generation resources at Craig (applicable as if this GIR were a Network Resource, but with results similar to a Non-Network Resource.

3. The GF was modeled according to data provided by the IC. The Project was adequately represented both for assessing power flow and dynamic performance.

4. The Picacho - Dona Ana - Las Cruces 115 kV line rating was uprated to 153 MVA based on a Tri-State approved project to be completed in 2016.

5. Power flow (N-0) solution parameters were as follows: Transformer LTC Taps – stepping; Area Interchange Control – tie lines and loads; Phase Shifters and DC Taps – adjusting; and Switched Shunts - enabled.

6. Power flow contingencies (N-1) utilized the following solution settings: Transformer LTC Taps – locked taps; Area Interchange Control – disabled; Phase Shifters and DC Taps – non-adjusting; and Switched Shunts – locked all. (Not allowing these voltage regulating solution parameters to adjust provides worse case results.)

7. All buses, lines and transformers with nominal voltages greater than or equal to 69 kV in the Tri-State and surrounding areas were monitored in all study cases for N-0 and N-1 system conditions.

8. All three of the nearby study areas (PNM, Tri-State, and XE/PSCo) were investigated using the same overload criteria. Any thermal loading greater than 95% of the branch rating with a thermal overload increase of 2% or more was documented.

9. Analysis assumes that the GF controls the high voltage bus at the POI and should not negatively impact any controlled voltage buses on the transmission system.

10. Post-contingency power transfer capability is subject to voltage constraints as well as equipment ratings. The Project was tested against NERC/WECC reliability criteria and additions/exceptions are as listed in the following Table 2.

Table 2 - Voltage Criteria Tri - State Voltage Criteria for Steady State Power Flow Analysis

Conditions Operating Voltages Delta-V Areas

Normal N-0 0.95 - 1.05 All

Contingency N-1 0.90 - 1.10 7% Northeastern New Mexico

Contingency N-1 0.90 - 1.10 7% Southern New Mexico

Contingency N-1 0.90 - 1.10 6% Other buses in PNM area

Contingency N-1 0.90 - 1.10 7% Western Colorado

Contingency N-1 0.90 - 1.10 7% Southern Colorado

Contingency N-1 0.90 - 1.10 6% Other Tri-State areas

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4.2. Voltage Regulation and Reactive Power Criteria 1. The GF must be capable of either producing or absorbing VAR as measured at the high

voltage POI bus at a 0.95 power factor (p.f.), across the range of near 0% to 100% of facility MW rating, as calculated on the basis of nominal POI voltage (1.0 p.u. V).

2. The GF may be required to produce VAR from 0.90 p.u. V to 1.04 p.u. V at the POI. In this range the GF helps to support or raise the POI bus voltage.

3. The GF may be required to absorb VAR from 1.02 p.u. V to 1.10 p.u. V at the POI. In this range the GF helps to reduce the POI bus voltage.

4. The GF may be required to either produce VAR or absorb VAR from 1.02 p.u. V to 1.04 p.u. V at the POI, with typical target regulating voltage being 1.03 p.u. V.

5. It is assumed that the GF will supply a portion of the VAR requirement by dynamic control of the inverters. The amount of dynamically adjustable VAR shall be equivalent to a minimum of 0.95 p.f. produced or absorbed at the invertor collector system medium voltage bus, across the near full range (0 to 100%) of rated MW output. The remaining VARs required to meet the 0.95 p.f. net criteria at the high voltage POI bus may be achieved with switched reactive devices.

The GF may utilize switched capacitors or reactors as long as the individual step size results in a step-change voltage of less than 3% at the POI operating bus voltage. This step change voltage magnitude shall be calculated based on the minimum system (N-1) short circuit POI bus MVA level as supplied by Tri-State.

6. When the GF is not producing any real power (near 0 MW), the VAR exchange at the POI should be near 0 MVAR, i.e., VAR neutral.

4.3 Steady-State Power Flow Results

1. N-0 (System Intact, Category A) Study Results:

a) Primary 115 kV POI

The proposed Project generation can be added with no thermal or voltage violations with all lines in-service.

b) Sensitivity

A 65 MW Project size with reactive power capability of 0.95 lag and lead was modeled at the new Project collector system with no thermal or voltage violations and with all lines in-service.

2. N-1 (Single Contingency Category B) Study Results: a) Primary 115 kV POI

Study results for N-1 studies of the 2019 HS and 2019 LA cases did not result in any thermal or voltage violations.

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b) Sensitivity

A 65 MW Project was modeled at the primary POI, 27 miles north of the Mimbres 115 kV Substation on the Mimbres - Caballo 115 kV transmission line.

Loss of the Mimbres - New Sub 115 kV line results in the Cuchillo - Elephant Butte 115 kV line loading to its maximum thermal limit of 62 MVA. No voltage violations were observed with the higher generation.

3. Steady-state voltage violations:

With Tri-State’s operating voltage criteria range of 0.90 p.u. to 1.10 p.u., under single contingency outage conditions there were no voltage violations with the GF at full output.

4. Steady-state contingency voltage deviation:

Each Balancing Authority Area’s ∆V requirement was applied as per Table 2. There were no ∆V violations at any of the monitored buses.

5. Reactive power required at the POI:

At full 25.2 MW output, the VAR capability required at the POI ranges from 10.1 MVAR produced (0.95 p.f. lag) to 5.9 MVAR absorbed (0.95 p.f. lead). This is the net MVAR to be produced or absorbed by the GF, depending upon the applicable range of voltage conditions at the POI.

The system model provided by the Interconnecting Customer shows that this GF can meet Tri-State's 0.95 p.f. lag (producing) criteria at the POI. However, studies identify that the GF cannot meet Tri-State's 0.95 p.f. lead (absorbing) criteria at the POI. When absorbing VARs, the Project is deficient at all levels of power output. See Table 7. Therefore, supplemental reactive power equipment of approximately 3 MVAR of switched shunt reactors will be required at the full 25.2 MW GF output to meet the net 0.95 p.f. lag (producing VAR) criteria at the POI. If the actual inverter capability is greater than that assumed by this study, the amount of reactive power equipment may be reduced. The same amount of reactive power equipment (3 MVAR) will be required on the 34.5 kV bus to offset the collector system VARs and meet Tri-State’s VAR neutral requirement (less than 2 MVAR flow at 0 MW output at the POI).

The Interconnecting Customer is responsible for equipment that will be installed to ensure that the GF can achieve the net 0.95 p.f. lag and lead capability across the 0 to 25.2 MW net generation output rating as measured at the POI. Prior to entering into a Generator Interconnection Agreement, the Interconnecting Customer will be required to provide data that demonstrates compliance with Tri-State's reactive criteria.

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System Impact Study for TI-15-0227: Final Report Tri-State Generation and Transmission Association, Inc. Table 3: 2019 Heavy Summer – Primary 115 kV POI

AFFECTED ELEMENT CONTINGENCY Emergency

Rating (MVA)

Pre-Project Loading

(%)

Post-100 MW

Project Loading

(%)

Delta (%)

Maximum Project Output w/out

Additional NU (MW)

Owner Notes –

Limiting Elements

No thermal overloads triggered.

Table 4: 2019 Light Autumn – Primary 115 kV POI


Rating (MVA)

Pre-Project Loading

(%)

Post-100 MW

Project Loading

(%)

Delta (%)


Additional NU (MW)

Owner Notes –

Limiting Elements

No thermal overloads triggered.

Table 5: 2019 Heavy Summer – Sensitivity: Maximum Project Generation, 65 MW


Rating (MVA)

Pre-Project Loading

(%)

Post-100 MW

Project Loading

(%)

Delta (%)


Additional NU (MW)

Owner Notes –

Limiting Elements

Cuchillo - Elephant Butte 115 kV Line Loss of Mimbres - Project HS 115 kV Line 62 † 98.6 98.6 75 TSGT None †Pre-Project - Only breakers at Mimbres and Elephant Butte 115kV buses. Therefore, line trips for this contingency - no contingency loading.

Table 6: 2019 Light Autumn – Sensitivity: Maximum Project Generation, 65 MW


Rating (MVA)

Pre-Project Loading

(%)

Post-100 MW

Project Loading

(%)

Delta (%)


Additional NU (MW)

Owner Notes –

Limiting Elements

Cuchillo - Elephant Butte 115 kV Line Loss of Mimbres - Project HS 115 kV Line 62 † 99.4 99.4 65 TSGT None

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Table 7: Reactive Power Delivered to the Solar Bus and at POI Bus Project Size: 25.2 MW, SMA 900CP 0.90 MW-28 Units

Base Case

Fixed P.F. at MV Gen

Equiv Collector

Bus

P, Q, V At Gen Equiv MV Net P, Q, V, PF At HV POI Bus

Pgen (MW)

Qgen (MVAR)

Voltage (p.u.)

P (MW)

Q (MVAR)

PF at POI

Voltage (p.u.)

MVAR to meet

PF Reqd at POI of 0.95

MVAR Short(+)

or Excess(-)

HS Base Case – 0.95 power factor lag (producing MVAR)

0.95 0 0.0 0.959 0 2.8 0 0.95 0 -2.8

0.95 6.3 2.1 0.971 6.3 4.8 0.795 0.95 2.1 -2.7

0.95 12.6 4.1 0.981 12.5 6.7 0.881 0.95 4.1 -2.6

0.95 18.9 6.2 0.992 18.8 8.5 0.911 0.95 6.2 -2.3

0.95 25.2 8.3 1.002 25 10.1 0.927 0.95 8.2 -1.9

LA Base Case – 0.95 power factor lead (absorbing MVAR)

-0.95 0 0 1.06 0 3.4 0 1.05 0 -3.4

-0.95 6.3 -2.1 1.058 6.3 1.2 0.982 1.05 -2.1 3.3

-0.95 12.6 -4.1 1.056 12.6 -1 0.997 1.05 -4.1 3.1

-0.95 18.9 -6.2 1.053 18.8 -3.4 0.984 1.05 -6.2 2.8

-0.95 25.2 -8.3 1.05 25 -5.9 0.973 1.05 -8.2 2.3

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System Impact Study for TI-15-0227: Final Report Tri-State Generation and Transmission Association, Inc. 5.0 DYNAMIC STABILITY ANALYSIS

5.1 Criteria and Assumptions 5.1.1 NERC/WECC Dynamic Criteria

PSSE version 33.5.0 was used for dynamic stability analysis. Dynamic stability analysis was performed in accordance with the dynamic performance criteria shown in Table W-1 and Figure W-1 from the NERC and WECC TPL-001 through 004 System Performance Criteria. These criteria are shown below.

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In addition, the NERC/WECC standard states that “[r]elay action, fault clearing time, and reclosing practice should be represented in simulations according to the planning and operation of the actual or planned systems. When simulating post transient conditions, actions are limited to automatic devices and no manual action is to be assumed.”

5.1.2 Voltage Ride-Through Requirements

1. The GF shall be able to meet the dynamic response low voltage ride through

(LVRT) requirements consistent with the latest WECC / NERC criteria, as stated in Tri-State’s Generation Interconnection Procedures Appendix G and FERC Order 661a for LVRT.

2. Generating plants are required to remain in service during faults (three-phase or

single line-to-ground (SLG) whichever is worse) with normal clearing times of approximately 4 to 9 cycles or SLG faults with delayed clearing, and subsequent post-fault voltage recovery to pre-fault voltage unless clearing the fault effectively disconnects the generator from the system. The clearing time requirement for a three-phase fault will be specific to the circuit breaker clearing times of the affected system to which the Customer facilities are interconnecting. The maximum clearing time the PV inverter generating plant shall be required to withstand for a fault shall be 9 cycles. After which, if the fault remains following

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the location-specific normal clearing time for faults, the PV generating plant may disconnect from the transmission system. A PV generating plant shall remain interconnected during such a fault on the transmission system for a voltage level as low as zero volts as measured at the POI. The Customer may not disable LVRT equipment while the plant is in-service.

3. This requirement does not apply to faults that may occur between the PV inverter generator terminals and the POI.

4. PV generating plants may meet the LVRT requirements by the performance of the generators or by installing additional equipment, e.g., a Static VAR Compensator, or by a combination of generator performance and additional equipment.

5.2 Base Case Model Assumptions 1. The generic transient stability models provided by the Customer for the Project

were not compatible with the version of PSS/E utilized for this study. Therefore, an SMA user written model was used for the simulations. Transient stability analysis was completed using the SMA 900 kVA Inverter model (SMASC_Kdk_32_IVF111.obj).

2. The collector system was modeled with an equivalent collector system and one 115/34.5 kV substation transformer.

3. The load at the Rosebud 13.8 kV bus (12063) in northeast New Mexico was load netted for this analysis to yield stable system conditions during faults. Transmission system upgrades are planned for the northeast New Mexico area to address potential voltage instability. The instability is not related to this Project.

5.3 Methodology Dynamic stability was evaluated as follows:

1. The 2019 HS and LA base cases were utilized with the GF in service.

2. System stability was observed by monitoring the voltage, frequency and relative rotor angles of local machines and system damping.

3. Three-phase faults were simulated for all contingencies. Two contingencies were simulated for each line: a fault was applied at the near end and then applied at the far end of the transmission line. Contingencies to evaluate compliance with NERC/WECC criteria for dynamic stability are listed in the following table.

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Table 8 - List of Dynamic Stability Contingencies Dynamic Stability Contingencies

Bus Numbers No. Description 1 4-cycle 3-phase fault at POI 15-0227 115 kV, trip Mimbres - POI 15-0227 115 kV line 10206-10616 2 4-cycle 3-phase fault at POI 15-0227 115 kV, trip Elephant Butte - POI 15-0227 115 kV line 12028-10616 3 4-cycle 3-phase fault at Mimbres 115 kV, trip Mimbres - Luna 115 kV line 10186 - 10206 4 4-cycle 3-phase fault at Mimbres 115 kV, trip Mimbres - Airport/Pichaco 230 kV line 10206-12059 5 4-cycle 3-phase fault at Luna 345 kV, trip Luna - Springerville 345 kV line 11093-16104 6 4-cycle 3-phase fault at Arroyo 345 kV, trip Arroyo - West Mesa 345 kV line 11017-10369 7 4-cycle 3-phase fault at Luna 345 kV, trip Luna 345/115 kV Transformer 11093-10186

5.4 Results Transient stability results demonstrate that the project does not require additional mitigation and is compliant with the NERC/WECC criteria. Simulation results for both summer and autumn show that:

1. With the SMA Photovoltaic Inverters (25.2 MW), the Project did not trip during any contingencies and had acceptable voltage levels. In addition, the GF was able to operate at full capacity.

2. Local area generators showed stable performance, and remained in synchronism for all contingencies.

3. Acceptable damping and voltage recovery was observed.

Study conclusions for summer and autumn cases are shown in the following table.

Table 9 - Dynamic Stability Results - 2019 Heavy Summer and Light Autumn

Dynamic Stability Contingencies 2019 Heavy Summer/Light

Autumn No. Description 1 4-cycle 3-phase fault at POI 15-0227 115 kV, trip Mimbres - POI 15-0227 115 kV line Stable 2 4-cycle 3-phase fault at POI 15-0227 115 kV, trip Elephant Butte - POI 15-0227 115 kV line Stable 3 4-cycle 3-phase fault at Mimbres 115 kV, trip Mimbres - Luna 115 kV line Stable 4 4-cycle 3-phase fault at Mimbres 115 kV, trip Mimbres - Airport/Pichaco 230 kV line Stable 5 4-cycle 3-phase fault at Luna 345 kV, trip Luna - Springerville 345 kV line Stable 6 4-cycle 3-phase fault at Arroyo 345 kV, trip Arroyo - West Mesa 345 kV line Stable 7 4-cycle 3-phase fault at Luna 345 kV, trip Luna 345/115 kV Transformer Stable

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System Impact Study for TI-15-0227: Final Report Tri-State Generation and Transmission Association, Inc. 6.0 SHORT-CIRCUIT ANALYSIS

6.1 Assumptions and Methodology Short-circuit analysis was performed for 3-phase-to-ground and single-line-to-ground faults at the 115 kV POI bus, using the Aspen OneLiner model. Faults were applied with and without the generation project. Model assumptions are as follows.

A. The model used is shown in Figure 2 below. B. The GF’s 115-34.5 transformer is assumed to be Y-Y with a Delta tertiary. Only the

positive sequence P-S impedance was provided (8% with X/R ratio = 27). The positive P-T and S-T impedance and all zero sequence impedances were estimated from a previous installation of similar size.

C. Typical positive sequence impedances were used for the 34.5 kV GF collector system lumped equivalent feeder circuits. The zero sequence impedance was assumed to be 3 times the positive sequence impedance.

D. The 28 GF generator short-circuit impedances were provided as 0.000 + 0.2j per unit

on a .9 MVA base for a total of 25.2 MVA. E. The 14 GF generator step-up (GSU) transformers were assumed to have Z1=5.75%,

Z0=5.75% on 1.8 MVA base for a total of 25.2 MVA. 6.2 Results

Tables 10 lists results for the 115 kV bus faults, contributions from each of the 115 kV sources into the bus faults, and the network grid Thevenin equivalent impedances (see Figure 2 below). These results indicate that the GF increases the fault duty by approximately 2870-2760 = 110 Amperes at the 115 kV POI bus. The resultant total fault currents are well within Tri-State’s planned substation equipment ratings.

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Figure 2: Short-Circuit Model One-Line Diagram

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Table 10: Short Circuit Results

System Condition*

POI 115V Bus (Total) 3-Ph Fault

Level (Amps)

Mimbres to POI

115kV 3-Ph Fault

Flow (Amps)

Caballo to POI

115kV 3-Ph Fault

Flow (Amps)

Gen 115kV to

POI 115kV 3-Ph Fault

Flow (Amps)

POI 115kV Bus (Total) SLG Fault

Level (Amps)

Mimbres to POI 115kV

SLG Fault Flow

(Amps)

Caballo to POI 115kV SLG Fault

Flow (Amps)

Gen 115kV to

POI 115kV

SLG Fault Flow

(Amps)

Thevinin System Equivalent Impedance (R + jX p.u. on 100

MVA, 115 kV base)

POI 115kV Bus Fault (w/o

generation; all lines in service)

2760 1984 776 1943 1349 594 Z1(pos) = 10.1217+j 21.8229 Z0(zero) = 18.8208+j 51.1595

POI 115kV Bus Fault (w/o generation;

Mimbres to POI 115kV out-of-

service)

799 799 625 625 Z1(pos) = 36.2383 +j 74.7506 Z0(zero) = 47.6431 +j 145.867

POI 115kV Bus Fault (w/o

generation); Caballo to POI 115kV out-of-

service)

2007 2007 1324 1324 Z1(pos) = 14.0251 +j 29.9582 Z0(zero) = 30.7863+j 78.5323

POI 115kV Bus Fault (with IC

gen 25 MW); all lines in service)

2870 1984 776 113 2626 1518 644 473 Z1(pos) = 9.53254+j 21.0790 Z0(zero) = 6.45789 +j 29.2693

POI 115kV Bus Fault (with IC gen 25 MW); Mimbres to POI 115kV out-

of-service)

909 799 113 1044 716 333 Z1(pos) = 29.7225 +j 66.7146 Z0(zero) = 6.08401+j 45.5753

POI 115kV Bus Fault (with IC gen 25 MW); Caballo to POI 115kV out-

of-service)

2117 2007 113 2006 1560 454 Z1(pos) = 12.9221+j 285753 Z0(zero) = 7.15836+j 36.4735

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7.0 SCOPE, COST AND SCHEDULE

The Project will require the construction of a new three breaker 115 kV switching station interconnecting with the Mimbres - Caballo 115kV line approximately 27 miles north of the Mimbres Substation. The new switching station facilities will provide for a future 115 kV breaker (see Figure 3, One-Line Diagram).

The cost estimate is broken out into two categories: 1) Interconnection Facilities (Non-Reimbursable) which include all equipment installed between the POI on the main 115 kV bus and the Point of Change of Ownership (PCO) at the line dead-end structure, and 2) Network Upgrades (Reimbursable) consisting of the rest of the facilities constructed to accommodate the interconnection. The estimate includes all site work such as grading, grounding and conduit installation for a station site provided by the Customer.

Note that the Interconnecting Customer will be responsible for the cost, design and construction of the 115-34.5 kV main substation transformer and associated facilities. These facilities may be located adjacent to Tri-State’s facilities. The Customer is responsible for providing the primary protection (relaying and interrupting device) for the Customer’s step-up transformer. Tri-State anticipates providing telecommunications for SCADA and metering to the site via existing radio communication facilities. The Customer is to provide access to analog, indicating, control and data circuits, as required to integrate the Project into the design and operation of the Tri-State control system.

All costs are good faith estimates based on assumptions as stated in this SIS report. All estimates are in 2016 dollars.

The estimated cost for interconnecting the proposed Project at the Primary 115 kV POI is as follows (refer to Figure 3):

• Network Upgrade Costs (Reimbursable): $ 4.4 M • Interconnection Facilities Costs (Non-Reimbursable): $ 0.9 M • TOTAL Cost (2016 dollars) for Interconnection: $ 5.3 M

It is estimated that it will take approximately 18 months after receiving authorization to proceed for Tri-State to complete the engineering, design, procurement, construction, and testing activities identified in the scope of work for this Project.

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Figure 3: One-Line Diagram Showing 115 kV POI Interconnection

New 115kV Switching Station One-Line Diagram

M

VTs

PCO(At DE

Structure)

POI

POI – Point of InterconnectionPCO – Point of Change of Ownership

TSGT 115kV Line to Caballo

Substation

CTs

To Customer transformer and TI-15-0227 Project facilities

TSGT 115kV Line toMimbres

Substation

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Table 11: Summary Cost Estimate Details – Interconnection Facilities (Non-Reimbursable)

Element Description Cost Est. Millions

Customer

termination equipment

between PCO and POI

Engineer, purchase, construct / install and test all equipment between the PCO (Interconnecting Customer’s line termination dead-end) and the POI (main bus tap point), consisting primarily of the following equipment:

• One (1) 115 kV line dead-end structure. • 115 kV slack span from to station bus. • One (1) 115 kV 3-ph gang line end disconnect

switch and associated structure, if required. • *Three (3) 115 kV metering current transformers,

high accuracy class, extended range. • *Three (3) 115 kV metering voltage transformers,

high accuracy class. *Or alternative CT/VT combination metering units.

• PQ metering panel including SEL-735 Rev/PQ meter (typical), Bitronics (typical) line meters, testing / checkout / commissioning.

• Relaying, as required, for the Interconnecting Customers 115 kV line/transformer protection.

• 115 kV surge arresters (140 kV MCOV or as required).

• SCADA, metering and telemetry communication equipment.

$0.9 M

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Table 12: Summary Cost Estimate Details – Network Upgrades (Reimbursable)

Element Description Cost Est. Millions

New 115 kV

switching station

New 115 kV 3-breaker ring bus switching station. Includes typical testing, checkout, and commissioning. The switching station design will accommodate a future 115 kV breaker and bay position.

• Three (3) 115 kV power circuit breakers. • Nine (9) 115 kV 3-ph gang disconnect switches and

associated structures (for breakers / bus). • 115 kV capacitive voltage transformers (CCVTs),

1200/2000:1 ratio, dual secondary windings, for relaying and metering of 115 kV line terminations.

• One (1) 115 kV – 120/240V, 100 kVA, SSVT voltage transformer, for primary AC station service supply.

• Two (2) 115 kV single-pole transmission line dead-end / angle structures, including foundations.

• Two (2) 115 kV line meters Bitronics (typical). • Digital fault recorder (DFR). • Relaying for 115 kV line protection (SEL-311C

primary, SEL-311C secondary and SEL-501 breaker-failure).

• 115 kV surge arresters (140 kV MCOV or as required), for 115 kV line terminations.

• SCADA, metering and telemetry RTU communication equipment.

• Station equipment including, but not limited to foundations, support steel, bus, grounding conductor, conduit and cable, insulators, trenches, site prep / yard work, fencing, etc.

• Self-supporting communications tower, foundation, antennas, radio equipment and rack (installed in main switching station control building), interface and ancillary equipment.

• Control building including batteries, AC & DC load centers, panels, etc.

$4.4 M

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