Interconnection System Impact Re-Study Final Report – May ......Final Report – May 28, 2010 Interconnection Request No. TI-04-1214 88 MW Wind Energy Large Generating Facility In

Interconnection System Impact Re-Study Final Report – May 28, 2010

Interconnection Request No. TI-04-1214

88 MW Wind Energy Large Generating Facility In North Eastern New Mexico

Prepared By:

Jeremy Sneath of Electranix Corporation Andrew Isaacs, P. Eng. of Electranix Corporation

Final Review By:

Ray LaPanse, Gerald Brooks of 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 Re-Study for TI-04-1214 88MW Wind Farm Tri-State G&T FINAL 5/28/10

TI-04-1214 SIS Final Report_RAL3.doc Page 2 of 28

Table of Contents 1.0 Executive Summary ........................................................................................... 3

2.0 Background and Scope ....................................................................................... 5

3.0 LGF Modeling Data 7 4.0 Steady State Power Flow Studies 8

4.1 Criteria and Assumptions 8 4.2. Voltage Regulation And Reactive Power Criteria: .......................................... 13 4.3. Methodology .................................................................................................... 14 4.4 Powerflow Results ............................................................................................ 14 4.5 Reactive Power and Voltage Control Capability Results ................................. 16

5.0 Dynamic Stability Studies ................................................................................ 18

6.0 Short Circuit Studies ........................................................................................ 18

6.1 Assumptions and Methodology ........................................................................ 18 6.2 Results .............................................................................................................. 19

7.0 Cost Estimates and Schedule ............................................................................ 22

8.0 Conclusion ........................................................................................................ 24

Appendices ....................................................................................................................... 26

Appendix A: Tri-State 115kV Interconnection SS One-Line ................................. 27 Appendix B: Steady State Power Flow Study – Case Listing ................................ 28 Appendix C: TSGT Transmission POI Bus Voltage Historical Data ............... NOTE Appendix D: Generator Dispatch Listing ......................................................... NOTE Appendix E: TSGT Voltage Criteria Areas - Bus Name Listing ..................... NOTE Appendix F: Contingency ∆V Violations ......................................................... NOTE Appendix G: PSCAD Dynamics Study Report ................................................. NOTE NOTE - Appendices C through G are not included in this report, but are only

available to the TP, IC, and Affected System Parties unless otherwise noted in this report.



1.0 Executive Summary

This System Impact Re-Study (SIRS) is for Interconnection Request (IR) No. TI-04-1214, relating to a proposed 88 MW wind energy Large Generating Facility (LGF) in North Eastern New Mexico, with a Point of Interconnection (POI) at the midpoint of the line from Clapham to Rosebud, (see Figure 1). The LGF includes (59) GE 1.5 MW turbines and one 34.5/115 kV Grid transformer. The SIRS was conducted for the Transmission Provider (TP – Tri-State Generation and Transmission, Inc., or TSGT) in accordance with its Large Generator Interconnection Procedures (LGIP), and includes steady state power flow, dynamic stability, short circuit, and cost analyses for interconnection of 88 MW. This interconnection request was initially submitted with a size of 120 MW. At the request of the TP, and in accordance with a prior agreement with the IC, power flow analysis for a 120 MW generation level has been performed in addition to the 88 MW generation level, in order to identify any Network Upgrade requirements that would be associated with the IC project at the original 120 MW level.

Power Flow Analysis:

The requested full output of generation (88 MW or 120 MW) may be added provided that line termination equipment upgrades are completed on the present 120 MVA (600A) rated Gladstone to Springer 115 kV line to increase the line rating to the 169 MVA (850A) line conductor rating. There is a pre-existing ∆V violation at Taos and Black Lake that occurs during the loss of the San Juan – Ojo – Taos 345 kV path and during the loss of the Taos – Black Lake 115 kV line. The addition of either 88 MW or 120 MW worsens this violation by less than 2%, which is the cutoff point at which Tri-State requires an interconnection customer (IC) to mitigate a worsened pre-existing violation. This ∆V violation is severe, and must be addressed. The TP is aware of this regional need for reactive support, and is separately planning for installing additional 115kV switched capacitor bank(s) in this area of the TP transmission system (e.g., at either Springer Sub, Black Lake Sub, or possibly another location). The proposed wind interconnection does not significantly worsen or create any new or steady state voltage violations. The interconnection customer is required to comply with the TP’s reactive power capability criteria as set forth in section 4.2.



It was assumed that the GE 1.5 MW turbines proposed for this IR will have the expanded reactive power capability option, allowing them to operate with a power factor between 0.90 lagging and 0.90 leading at the machine terminals. It was also assumed that the turbines can supply or consume some reactive power even when there is no active power generation (WindFREE Reactive Power). With these capabilities, the TP’s reactive power capability criteria are satisfied. If turbines without these capabilities are used, additional equipment would need to be proposed by the IC to meet the criteria. Further study would be required to verify compliance.

Dynamic Stability Analysis:

A separate dynamic study was undertaken for the IC using the PSCAD software package to demonstrate acceptable performance of the wind farm under weak system conditions, to determine if the performance of the wind farm meets TSGT and IC operating criteria and to determine if additional MVARs from switched shunt devices are required to meet the TSGT reactive power capability requirement. The PSCAD study did not find any faults or disturbances where the GE turbines tripped or resulted in poor performance. If the optional 0.90 lead/lag capability is used, additional shunt devices are not required to meet reactive power requirements. This separate PSCAD study report is available only to the TP and IC as an appendix to the complete SIRS report.

Short Circuit Analysis: Short circuit analysis was performed using Aspen OneLiner with 3-phase and single line-to-ground faults performed at the 115 kV POI and at the Clapham and Rosebud 115 kV substations. The results have been supplied to the TP to evaluate equipment ratings to determine the impact, and no equipment replacements are expected to result from this. The wind farm was modeled with the highest possible short circuit current contribution. For applications where higher short circuit currents are ‘better’, (such as calculating system strength), these results are optimistic and should be adjusted.

Cost:

The total estimated cost of Network Upgrades as performed by the TP for this interconnection is approximately $1,075,000

. This work includes: upgrades of the substation line termination equipment for the Gladstone to Springer 115 kV line; microwave communications equipment installation from Clapham to the new TP 115kV Interconnection Substation site; 115kV TP transmission line work to tap the new Interconnection Substation into the existing Clapham – Bravo Dome 115kV line; and review of the IC design and construction activities and commissioning associated with the new TP-owned 115kV Interconnection Substation.



Schedule: Per the IC, the presently planned revised in-service date (ISD) for energization / back-feed power is May 1, 2012.

2.0 Background and Scope

The IC submitted an IR for an 88 MW wind energy LGF to be connected at the midpoint of the 115 kV line from Clapham to Bravo Dome (Rosebud). Prior study work was performed for this interconnection as follows:

• This interconnection was initially studied with a size of up to 120 MW.

• A System Impact Study (SIS) report was prepared on May 31, 2004.

• A Facility Study report was prepared on November 17, 2004.

• A Facility Study addendum was prepared on July 12, 2005.

• An Interconnection Facility Study report was prepared on February 27, 2007.

• A technical memorandum was prepared on June 9, 2008 to address study assumptions that had changed.

The current System Impact Re-Study (SIRS) was performed with a revised project size (88 MW) and with the latest system changes included. The powerflow portion of the study also considered the original project size (120 MW) This SIRS is prepared in accordance with the TP’s LGIP and relevant FERC, NERC, WECC and TP guidelines. The study has the following objectives: • Evaluate the steady state performance of the system to determine the

Interconnection Facilities and Network Upgrades required to interconnect and deliver the proposed generation during heavy loading, light loading and high loop flow conditions;

• Evaluate the ability of the LGF to meet the TP’s voltage regulation and reactive power criteria;

• Evaluate the dynamic performance of the Transmission System under specified stability contingencies;



• Perform a basic short circuit analysis to provide the estimated maximum (N-0) and minimum (N-1) short circuit currents, with and without the new generation connected, and determine whether there are any negative impacts on the Transmission System; and

• Provide a preliminary estimate of the costs and schedule for all necessary Transmission Provider’s Interconnection Facilities and Network Upgrades, subject to refinement in an Interconnection Facilities Re-Study.

Figure 1: Area Map - One-Line Diagram Of Study Area And Location Of TI-04-

1214 and TI-08-0312 Note – Refer to Appendix A for a One-Line Diagram of the TP 115kV TI-04-1214 Interconnection Substation.

230 kV

Gladstone

Storrie Lake

Springer Black Lake

York Canyon

Clapham

Bravo Dome Motor Load

71MW

115 kV

Walsenburg

Taos

Colorado

New Mexico

345 kV

Comanche

88 MW Wind Farm TI-04-1214

30 MW Solar TI-08-0312

Bravo Dome (Rosebud)

Van Bremmer



3.0 LGF Modeling Data

Some model data was provided by the IC. Where the IC has not provided specific data, modeling assumptions were based on typical values and data taken from the manufacturer’s available technical documents. The IC shall provide to the TP a complete final design study report, based upon detailed final design model data for the major IC Large Generation Facilities (LGF) that illustrates the LGF’s capability to meet the TP’s criteria for voltage regulation, reactive capability, and transient voltage operation. It is the responsibility of the IC to supply this report early enough in the final design process such that any comments by the TP that may impact the final LGF design may be implemented without impacting the project’s critical path schedule. Lastly, the final LGF equivalence “as-built” model data, specifically for the equipment previously modeled using estimated data in the TP SIRS studies, shall be supplied to the TP prior to the IC Facilities being declared as suitable for Commercial Operation. Generator Data: The LGF is comprised of (59) 1.5 MW GE wind turbines. The generator data assumptions for power flow modeling are shown in Table 1. The data from the manufacturer’s technical documentation is shown in Table 2. This includes the individual pad-mounted generator step-up transformer (GSU) (assumed 575 V to 34.5 kV) transformer data. The voltage ride through (VRT) protection trip levels are shown in Table 3.

Table 1 Generator Data for Steady-State Power Flow Analysis

Unit Description Details

Pmax Name plate rating (lumped equivalent gen model) 88 MW

Qmin, Qmax Reactive capability 0.90 lag to 0.90 lead [*] Et Terminal voltage 0.575 kV

Rs Synchronous resistance (p.u.) 0 (see Sec. 6.1.3e)

Xd’’ Synchronous reactance (p.u.) 0.2 p.u. (see Sec. 6.1.3e)

SCR Short circuit ratio Fault current/rated current 10 (see Sec. 6.1.3e)

*NOTE: Actual reactive power operating capabilities must be confirmed by IC.

Table 2 Power Flow Data for Individual Generating Units





MBase Generator MVA base 1.717 MVA Prated Generator active power rating 1.545 MW Pmin Minimum generation 0 MW Vrated Terminal voltage 0.575 kV Srated Unit transformer Rating 1.75 MVA Xt Unit Transformer Reactance (on transformer base) 5.75% Xt/Rt Unit Transformer X/R ratio 7.5

Table 3 Voltage Ride-Through Thresholds and Durations (See NERC Fig. 1 in Section 5.1)

V (%) at HV POI

Bus Delta V (p.u) Time (sec) 90 -0.10 > 3.00 75 -0.25 2-3.00 65 -0.35 0.30 – 2.00 45 -0.55 0.15 - 0.30 0 -1.00 < 0.15

110 0.10 >1.000 115 0.15 0.50 -1.00

117.5 0.175 0.20 – 0.50 120 0.20 < 0.20

34.5 kV Collection System: The medium voltage (MV) collection system and generation was modeled as a single lumped equivalent impedance and generator. The collector impedance values used were estimated at: R = 0.001 p.u., jX = 0.001 p.u., and B = 0.0786 p.u. These values were assumed in the absence of specific customer-provided data. Main LGF Substation Transformer: The substation transformer rating is three-winding, 115-34.5-13.8 kV, 59/79/99 MVA. The impedance of the station transformer is assumed to be 9% on the base 59 MVA base ONAN rating. Additional data confirming the actual impedance (R + jX), winding configuration, available and actual voltage taps used (HV DETC or OLTC) is required from the IC prior to entering into an LGIA. 115 kV Generator Tie Line: The LGF to POI tie line was assumed to be very short and was not modeled.



4.0 Steady State Power Flow Studies

4.1 Criteria and Assumptions PSLF version 17 was used for steady state power flow analysis, with the following study criteria and assumptions:

1. The base case for this study was a 2012 Heavy Summer WECC case provided

by the TP on September 22, 2008, as this was the most reliable base case then available for use in the vicinity of the project, with modifications per subsequent input from the Transmission Provider.

2. The light loading case was constructed with input received from the Transmission Provider on May 22, 2009.

3. At the suggestion of Public Service Company of New Mexico (PNM)

engineers, the loop flow cases were constructed by setting the angles on the following phase shifters to 34 degrees: Shiprock, Sigurd, Pinto, San Juan, and both phase shifters at H Allen. Historical data from Tri-State G&T indicates a peak MW flow south on the Walsenburg to Gladstone 230 kV line of around 180 MW, with TI-04-1214 and TI-08-0312 not yet installed. This can be compared to case 4 in table 4 below. It can be concluded, based on this historical data, that the 34 degree loop flow cases represent a ‘worst case’ loop flow condition for this area.

4. The LGF plant was modeled according to data provided by the IC. Where

data was not provided, reasonable assumptions were made (Chapter 3.0).

5. A total of 30 base cases were utilized, summarized in Table 4.



Table 4 Base Case Descriptions

Case Number Case Description

Southern Power flow from

Walsenberg to Gladstone (MW)

1 HS with 0 MW added 117 2 HS with 0 MW added and 30 MW Solar plant removed 129 3 HS with 34 degrees loop flow with 0 MW added 170 4 HS, 34 degrees and no solar plant with 0 MW added 179 5 Light loading case with 0 MW added 110 6 Light load, no 30 MW solar and 0 MW added 122 7 HS with 88 MW added 59 8 HS with 88 MW added and 30 MW solar plant removed 71 9 HS with 34 degrees loop flow and 88 MW added 113

10 HS, 34 degrees and no solar plant with 88 MW added 125 11 Light loading case with 88 MW added 54 12 Light load, no 30 MW solar and 88 MW added 66 13 HS with 120 MW added 41 14 HS with 120 MW added and 30 MW solar plant removed 53 15 HS with 34 degrees loop flow and 120 MW added 95 16 HS, 34 degrees and no solar plant with 120 MW added 106 17 Light loading case with 120 MW added 36 18 Light load, no 30 MW solar and 120 MW added 48 19 HS with 88 MW added, 25 MVAR Cap at BL 59

20 HS with 88 MW added and 30 MW solar plant removed, 25 MVAR Cap at BL 71

21 HS with 34 degrees loop flow and 88 MW added, 25 MVAR Cap at BL 113

22 HS, 34 degrees and no solar plant with 88 MW added, 25 MVAR Cap at BL 125

23 Light loading case with 88 MW added, 25 MVAR Cap at BL 54

24 Light load, no 30 MW solar and 88 MW added, 25 MVAR Cap at BL 66

25 HS with 120 MW added, 30 MVAR Cap at BL 41

26 HS with 120 MW added and 30 MW solar plant removed, 30 MVAR Cap at BL 53

27 HS with 34 degrees loop flow and 120 MW added, 30 MVAR Cap at BL 95

28 HS, 34 degrees and no solar plant with 120 MW added, 30 MVAR Cap at BL 106

29 Light loading case with 120 MW added, 30 MVAR Cap at BL 36

30 Light load, no 30 MW solar and 120 MW added, 30 MVAR Cap at BL 48



(HS = heavy summer, BL = Black Lake, 30 MW solar refers to TI-04-1214)

6. Power flow starting (N-0) solution parameters were as follows: Transformer LTC Taps - Stepping; auto adjust function active for Area Interchange - Ties and Loads; Phase Shifters - Adjusting; DC Taps - Adjusting; and Switched Shunts - Enabled. For initial N-1 runs, the settings were modified to locked phase shifters, locked tap changers, no DC adjustments and no area interchange control. Note – The TP also performs additional N-1 runs for allowing tap- changer and switched shunt operation to determine post-transient voltages applicable for the few minutes after initial trip in determining reactive support needs to address stable voltage deviation events (transmission capacitor banks and reactors).

7. All buses, lines and transformers with nominal voltages greater than or equal

to 69 kV in the Tri-State and surrounding areas (PSS/E areas 10, 70, and 73) were monitored in all study cases.

8. Shedding of wind generation under contingency scenarios was not considered

acceptable, except to address islanding.

9. The proposed 88 MW of wind generation was scheduled to the PNM Balancing Authority, and dispatched to generators in the San Juan area (specifically SJUAN_G4, bus 10321), based upon the existence of a Transmission Service Agreement (TSA) signed with the IC.

10. Cases were run with and without 30 MW of solar generation (TI-08-0312)

assumed to be operating (dispatched to Tri-State generators in the Denver area).

11. PNM has a series reactor (15 ohm) at the Norton terminal of the Norton-

Hernandez 115 kV line. The Norton series reactor is normally bypassed with a circuit breaker. Under certain N-1 contingencies or when the line exceeds its 175 MVA continuous thermal rating for more than one second, the bypass circuit breaker will trip, via a relay detection scheme, and put the reactor in series with the Norton-Hernandez 115 kV line.

12. As per instruction from the TP, the 12.5 MVAR shunt capacitor at Springer

115 kV was assumed to be automatically controlling voltage. This capacitor partially mitigates dV problems at Taos and Black Lake.

13. The LGF was evaluated based on N-0 conditions and the following N-1 single

contingency outage conditions:



Table 5 Steady State Contingencies Table 2 – Steady State Contingencies

No. Description C1 No Outages (N-0)

C2 Wals. - Comanche 230 kV (Cross-Trip Glad - Wals. 230 kV line, 20 MW load at Bravo Dome and 10 MW load at Hess).

C3 Wals. - Comanche 230 kV (Cross-Trip Glad - Wals. 230 kV) C4 Gladstone – Springer 115 kV C5 Taos - Black Lake 115 kV C6 Springer - Storrie Lake 115 kV C7 San Juan - Ojo - Taos 345 kV C8 San Juan - Reopuerc 345 kV C9 Gladstone - Walsenburg 230 kV

C10 72 MW Bravo Dome Load C11 Loss of all power at new wind facility C12 B-A - Guadalupe 345 kV C13 Fourcorners - Westmesa 345 kV C14 B-A - Westmesa 345 kV

14. All buses, lines and transformers with base voltages greater than or equal to

46 kV in the New Mexico and Colorado area were monitored in all study cases. Any flows greater than 95% of the branch rating were considered worthy of notice, and any flows greater than 100% were considered an overload. Where addition of the LFG caused pre-existing overloads to increase by less than 2% the impact was considered to be negligible.

15. The LGF should control the high voltage bus at the POI and should not

negatively impact any controlled voltage buses on the Transmission System.

16. Transmission line and transformer ratings were monitored for equipment rating violations using Normal Rating for N-0 and Emergency Rating for N-1 as listed in the power flow data.

17. Post contingency power transfer capability is also subject to voltage

constraints. Each option was tested against NERC/WECC reliability criteria and additions/exceptions as listed in the following table:



Table 6 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

4.2. Voltage Regulation and Reactive Power Criteria:

1. The LGF shall be capable of either producing or absorbing VAR as measured at the HV 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). For this 88 MW rated facility, at full ouput the required magnitude of VAR capability would range up to 29 MVAR, as measured at the 115 kV POI

. This would be the net MVAR to be produced or absorbed by the LGF, depending upon the applicable range of voltage conditions at the POI.

2. The LGF 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 LGF helps to support or raise the POI bus voltage.

3. The LGF 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 LGF helps to reduce the POI bus voltage. 4. The LGF 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 the typical target regulating voltage being 1.03 p.u. V.

5. The LGF may utilize switched capacitors or reactors so long as the

individual step size is rated to result in a step-change voltage of less than 3% of the POI operating bus voltage. This step change voltage magnitude shall be calculated based upon the minimum system (N-1) short circuit POI bus MVA level as supplied by the TP. The LGF is required to supply a portion of the VAR on a continuously adjustable or dynamic basis, as



may be supplied from the generators or from a STATCOM or SVC type system. The amount of continuously adjustable VAR shall be equivalent to a minimum of 0.95 p.f. produced or absorbed at the generator collector system medium voltage bus, across the full range (0 to 100%) of rated MW output. The remaining VAR required to meet the 0.95 p.f. net criteria at the HV POI bus may be achieved with switched capacitors and reactors.

6. When the LGF is not producing any real power (near 0 MW), the VAR

exchange at the POI shall be near 0 MVAR, i.e., VAR neutral. 7. All interconnections may be subject to additional detailed study, utilizing

more complex models and software such as PSCAD, EMTP or similar, and may require mitigation in excess of minimums imposed by published standards, according to the best judgement of the TP’s engineers.

4.3. Methodology

The following methodology was used for the steady state analysis:

1. As described in Section 4.1, 30 base cases were considered: 6 with 0 MW added, 6 with 88 MW added, 6 with 120 MW added, 6 with 88 MW added plus a shunt cap to control dV and 6 with 120 MW added plus a shunt cap to control dV.

2. Each bus in Balancing Authority Areas 10 (PNM), 70 (PSCo) and 73

(WAPA) was monitored for voltage, power flow and ∆V violations, and each violation was considered according to the criteria for its specific zone. Violations that differed from the base case by less than 2% were assumed to be not changing significantly due to the new generation, and were not considered in the conclusions.

3. Additional steady state analysis was conducted to demonstrate the ability

of the project to operate within its reactive limits at POI.

4.4 Powerflow Results

1. Loading: The addition 88 MW or 120 MW creates new N-1 overloads on the Gladstone to Springer 115 kV line. These can be seen on the following table:



Table 7 Gladstone – Springer 115 kV loading

Base Case

*Per Unit Loading on Springer to Gladstone 115 kV line Under Selected Contingencies

San Juan- Ojo - Taos 345kV

Circuit 1 Outage

San Juan - Rio Puerco 345kV

Circuit 1 Outage

Bravo Dome Load

Outage

Four Corners – West Mesa

345kv Circuit 1 Outage

0mw_HS 0.261 0.094 0.162 0.07 0mw_HS_ns 0.381 0.169 0.255 0.126 0mw_34_HS 0.614 0.47 0.67 0.435 0mw_HS_34_ns 0.718 0.562 0.744 0.527 88mw_HS 0.576 0.428 0.475 0.381 88mw_HS_ns 0.691 0.523 0.616 0.475 88mw_34_HS 0.938 0.838 0.904 0.799 88mw_HS_34_ns 1.053 0.941 0.999 0.893 120mw_HS 0.672 0.538 0.625 0.492 120mw_HS_ns 0.797 0.636 0.717 0.589 120mw_34_HS 1.037 0.96 1.007 0.914 120mw_HS_34_ns 1.157 1.056 1.109 1.015 *Note: Per Unit values are based on a 120 MVA line rating. The 120 MVA rating on this line is due to the CTs (600 Amps). The thermal rating of the conductors is 169 MVA.

2. Voltage: The proposed 88 MW or 120 MW of wind generation can be added

without creating or significantly worsening any steady state voltage violations during N-0 or N-1 conditions.

3. There is a pre-existing ∆V violation at Taos and Black Lake that occurs

during the loss of the San Juan – Ojo – Taos 345 kV path and during the loss of the Taos – Black Lake 115 kV line. The addition of either 88 MW or 120 MW worsens this violation by less than 2%, which is the cutoff point at which Tri-State typically requires an IC to mitigate a worsened pre-existing violation. Power flow analysis was performed in this SIRS to size a shunt device to address this issue, however the TP is performing additional study work outside of the SIRS to optimize the size and location of the necessary capacitor bank.

4. The following table shows the critical ∆V conditions that were found in these

studies. A complete list of cases and full dV reporting is provided in Appendix B.



Table 8 Worst Case Contingency ∆V Violations

Wind Level Black Lake Capacitor

Worst dV Bus experiencing

worst dV Outage

0 MW 0 >10%* Taos 69 kV San Juan - Ojo - Taos 345 kV 88 MW 0 11.0% Taos 69 kV San Juan - Ojo - Taos 345 kV

120 MW 0 12.5% Taos 69 kV San Juan - Ojo - Taos 345 kV 88 MW 25 5.7% Taos 345 kV San Juan - Ojo - Taos 345 kV

120 MW 30 6.3% Taos 345 kV San Juan - Ojo - Taos 345 kV * This value is extrapolated from similar cases due to solution convergence failure ** Worst case dV results generally occur during high loop flow conditions without the solar facility present.

4.5 Reactive Power and Voltage Control Capability Results

1. Reactive power required at the POI: At full 88 MW output, the VAR capability required at the POI is 29 MVAR produced (0.95 p.f. lag) to 29 MVAR absorbed (0.95 p.f. lead)

. Utilizing only the LGF capability based on model data supplied by the IC, a steady-state analysis was performed to confirm that the Tri-State criteria are met.

2. For reference, Table 9 shows the net VAR flow at the critical levels of LGF output and generator bus p.f. levels, based on voltage at the lumped equivalent model generator terminals and voltage at the POI bus.

3. These results show that, assuming the turbines have the expanded reactive power capability of operating between 0.90 leading and lagging at the machine terminals and the WindFREEtm Reactive Power capability, the Tri-State reactive power capability requirements documented in section 4.2 will be satisfied. However, in particular as these calculations utilized estimated model data for the 34.5kV collector system equivalent model, and this can have significant effect on the reactive power capability simulations, it is the responsibility of the IC to provide final design study results that illustrate the ability of the LGF to meet the reactive power and voltage regulation criteria of the TP. This capability will be verified through actual operational field testing during the commissioning of the LGF and prior to the LGF being declared ready for Commercial Operation.



Table 9 Reactive Power Produced at Rated Power and Zero Power to Meet TSGT Criteria

Gen 575V

Bus MW

Gen 575V Bus

MVAR

Gen 575V Bus

Voltage (PU)

Gen 575V

Bus PF

MV 34.5kV Bus MVAR

MV 34.5kV Bus PF

MV 34.5kV

Bus Voltage

(PU)

HV 115kV POI Bus

MW (Required)

HV 115kV POI Bus MVAR (Required @

0.95 PF)

HV 115kV POI Bus MVAR (Actual)

HV 115kV POI Bus PF

(Actual)

HV 115kV

POI Bus Voltage

(PU) Plant Producing VARs (Capacitive)

88 MW 33 MVAR 1.034 PU 0.94 PF 38 MVAR 0.92 PF 1.0 PU 88 MW 29 MVAR 29 MVAR 0.95 PF 1.0 PU 66 21 1.026 0.95 27 0.926 1.0 66 21.7 22 0.95 1.0 44 10 1.017 0.975 17 0.933 1.0 44 14.5 14.5 0.95 1.0 22 0 1.008 1.00 8 0.94 1.0 22 7.2 7 0.95 1.0

Plant Absorbing VARs (Inductive) 88 MW -24 MVAR 0.963 PU -0.965 PF -21 MVAR -0.97 PF 0.973 PU 88 MW -29 MVAR -29 MVAR -0.95 PF 1.0 PU

66 -22 0.97 -0.95 -17 -0.97 0.98 66 -21.7 -22 -0.95 1.0 44 -18 0.979 -0.926 -11 -0.97 0.987 44 -14.5 -14.5 -0.95 1.0 22 -14 0.987 -0.844 -7 -0.95 0.993 22 -7.2 -7 -0.95 1.0

VAR Neutral Condition 0 MW -8 MVAR 0.996 PU N.A. 0 N.A. 0 MW 0 MVAR 0 MVAR N.A. 1.0 PU

NOTES: 1) It is assumed that the POI voltage is constant at 1.0 PU, however note that the TP will likely require actual HV POI bus to be regulated to near 1.03 PU V. 2) It is assumed that the turbines are capable of operating between 0.90 leading and lagging, the max and min Qgen at the machine terminals is +/- 42.6 MVAR @ 88

MW. 3) It is assumed that the turbines are capable of consuming 8 MVAR when the real power output is 0 MW. This should be confirmed by the IC. 4) Gen bus PF conditions highlighted in red where the PF is outside of the assumed gen +/-0.90 pf capability are the result of the assumed / modeled MV collector

system estimated equivalent impedance (inductance and capacitance). The actual final design MV collector system impedance characteristics will impact these results, and may result in additional reactive support (e.g. switched capacitors and/or reactors) to be installed on the MV collector system main substation bus. IC is responsible for the final design required to meet the TSGT operational capability criteria as measured at the HV POI.



5.0 Dynamic Stability Studies A separate PSCAD based dynamic stability study was undertaken for the IC to demonstrate acceptable performance of the wind farm under weak system conditions, to determine if the performance of the wind farm meets TSGT and IC operating criteria and to determine if additional MVARs from switched shunt devices are required to meet the TSGT reactive power capability requirement.

6.0 Short Circuit Studies

6.1 Assumptions and Methodology

1. The Tri-State reduced (regional system equivalence) Aspen One-Liner software model was used.

2. One-Liner binary file NE_New_Mexic_2010-02-10.olr was provided by the TP on February 10, 2010. This case included the TI-08-0312 Solar interconnection request.

3. The tie line, transformers, and generators were modeled as follows:

a. The high voltage transformer was modeled as a grounded Y-delta- grounded Y transformer based on the following impedance data supplied by the IC:



b. The generator step-up transformer was modeled as a 34.5/0.690 kV delta-Y lumped equivalent transformer with Z = 0.76 + j5.70 % on a 103.25 MVA base according to the turbine manufacturer’s recommended specifications.

c. The collector was assumed to be insignificant and was not included in the model.

d. The tie line was assumed to be insignificant and was not included in the model.

e. The lumped turbine equivalent was modeled with an impedance of X = 0.2 and an X/R ratio of 10 based on a 98 MVA rating. It should be noted that this is a conservative estimate based on GE’s documentation. This approximation will yield the highest possible fault current contribution from the generator. The following is GE’s description of the turbine’s short circuit characteristics:

GE 1.5 turbine is a doubly fed asynchronous generator – with the stator directly connected to the grid while the rotor is interfaced through a frequency converter to the grid. This arrangement does not lend itself very well to synchronous generator type simplification (Xd’’ etc). For most faults that occur on the grid, the turbine will act as a controlled current source – contributing up to 3 pu fault current for up to 3 cycles, after which it returns to normal current contribution (i.e. 1pu). For faults on the grid, the contribution from the turbines is minimal compared to that from the grid.

One exception to the above is for “close in” faults (eg: inside the wind farm, at the WF substation etc) – where, depending on the severity, the converter may “crowbar” (i.e. disconnect itself to protect the power electronics within) – in which case the turbine rotor is short circuited like that of a squirrel cage induction generator. In this case, the behavior can be approximated to X’ = 0.2, contributing a max of 5 pu fault current.

6.2 Results Short circuit analysis was performed at the 115 kV POI, at the Clapham 115 kV bus, and at the Bravo Dome 115 kV bus. Single line-to-ground (SLG) and three line-to-ground (3-ph) faults were applied with the system intact, with the Gladstone to Walsenburg 230 kV line out of service and with the Gladstone to Springer 115 kV line out of service. Tables 10, 11 and 12 list the results.



Table 10 Short Circuit Results – Faults on TI-04-1214 POI

System Condition Three-Phase Fault Level

(Amps)

Single Line-To-Ground Fault Level (Amps)

Thevinin System Equivalent Impedance (R + jX in ohms)

Existing system 2550 1388 Z1: 4.4584 + j25.6577 Z2: 5.25961 + j29.1095 Z0: 24.3725 + j84.6799

TI-04-1214 added 3737 3307 Z1: 2.49458 + j17.5905 Z2: 2.74748 + j19.1514 Z0: 2.82897 + j22.9521

Existing system Gladstone to Walsenburg

230 kV line out 2086 1267

Z1: 4.90653 + j31.4527 Z2: 5.94998 + j36.8123 Z0: 24.2948 + j84.9956

TI-04-1214 added Gladstone to Walsenburg

230 kV line out 3275 3028

Z1: 2.53675 + j20.1157 Z2: 2.80391 + j22.1839 Z0: 2.8172 + j22.9711

Existing system Gladstone to Springer

115 kV line out 2255 1316

Z1: 3.87883 + j29.1918 Z2: 4.53607 + j33.7592 Z0: 24.3221 + j84.8369

TI-04-1214 added Gladstone to Springer

115 kV line out 3445 3134

Z1: 2.15535 + j19.1533 Z2: 2.34318 + j21.019 Z0: 2.82234 +j22.9613

Table 11 Short Circuit Results – Faults on Clapham 115 kV bus


(Amps)




TI-04-1214 added 3461 2880 Z1: 3.5458 + j18.852 Z2: 3.70064 + j20.0007 Z0: 6.55074 + j28.9196


230 kV line out 2029 1509

Z1: 5.89981 + j32.1884 Z2: 6.69685 + j36.6105 Z0: 15.022 + j60.2973


230 kV line out 2863 2560

Z1: 4.08011 + j22.8328 Z2: 4.27619 + j24.5376 Z0: 6.52958 + j28.991


115 kV line out 2235 1595

Z1: 4.38856 + j29.3799 Z2: 4.78361 + j33.015 Z0: 15.0494 + j60.1386


115 kV line out 3069 2678

Z1: 3.29941 + j21.3832 Z2: 3.39693 + j22.866 Z0: 6.5375 + j28.955



Table 12 Short Circuit Results – Faults on Bravo Dome 115 kV bus


(Amps)




TI-04-1214 added 3386 2194 Z1: 2.62161 + j19.4311 Z2: 3.21545 + j21.9158 Z0: 12.0968 + j47.6436


230 kV line out 2198 1101

Z1: 3.51971 + j29.9994 Z2: 4.84001 + j36.386 Z0: 33.5632 + j109.688


230 kV line out 3092 2096

Z1: 2.48695 + j21.3301 Z2: 3.09499 + j24.3734 Z0: 12.085 + j47.6625


115 kV line out 2339 1130

Z1: 2.89691 + j28.2339 Z2: 3.86286 + j33.8373 Z0: 33.5905 + j109.529


115 kV line out 3207 2137

Z1: 2.26394 + j20.5822 Z2: 2.78589 + j23.4053 Z0: 12.0901 + j47.6528

The TP has determined that these results indicate that the nearby TP transmission substation equipment ratings are adequate, with minimal impact by the addition of the IC LGF.



7.0 Cost Estimates and Schedule 7.1 Cost Estimates & Scope:

Cost estimates provided are budgetary estimates in 2010 dollars (indicative level +/- 20%) for Network Upgrades only and do not include Interconnection Facility costs.

Note - These items will be discussed further and in more detail in the Final Facilities Study Report being prepared by the TP.

The TP Network Upgrades and associated estimated costs are:

a) TP Interconnection SS: Construct and interconnect a new TP 115kV Interconnection Substation next to the existing TP 115kV Clapham – Bravo Dome transmission line. For this particular project, based upon discussions made with the IC earlier in the study process, it is assumed that the majority of this design, equipment procurement, and construction will be completed by the IC, in compliance with the TP design and construction standards. It is further assumed that the 115kV TP Interconnection Substation will be turned over to the TP for ownership and operation by the TP, with the actual costs of construction initially incurred by the IC to be paid back over time to the IC by the TP through transmission credits based on energy sales to the TP. The details of this arrangement will be further defined in the final Interconnection Agreement (IA). However, there will be additional work that is assumed to be performed by the TP associated with this 115kV TP interconnection substation which includes the following items, at a total estimated cost of $450,000

.

• Design, install, test new TP SCADA RTU and interface panel.

• Design, install, test new TP revenue billing / power quality meter, to be installed on either a separate meter panel, or other planned equipment panel (e.g. relaying or communications equipment panel). Note that it is assumed that the IC will procure and install the associated 115kV metering CT/VT transformers based upon TP-supplied specifications.

• TP review the IC design / construction drawings / construction and

commissioning activities.

• Install new transmission line tap work necessary to: 1) initially provide a temporary bypass “fly line” to allow for de-energizing a section / span on the existing transmission line at the POI point; and 2) add structures and conductor required for the final connection



between the new TP Interconnection Substation and the TP’s existing 115kV line.

See Exhibit A (Station One-Line Diagram) for additional information.

b) Microwave Communications: Install a new licensed digital microwave

link between Clapham and the new TP Interconnection Substation site, for use with relaying channels, SCADA, and telemetry. Includes new 30-ft. monopole at the TP Interconnection Substation site, existing antenna / tower at Clapham, with the channels connected at Clapham to the existing microwave system to Rio Rancho and Westminster, CO (TP Operations Center). Estimated total cost = $ 300,000

.

c) Gladstone - Springer 115kV Line Upgrade: Equipment upgrades to substation line termination equipment are necessary to bring the existing Gladstone - Springer 115kV line up from its present 120 MVA (600A) rating to match the 169 MVA (848 A) line conductor rating. The items requiring replacing are as follows, at a total estimated cost of $150,000

.

• Metering 115kV current transformers (CTs) at Springer: Replace the existing 200/400:5, 1.5 TRF, 600A continuous thermal rating, with new 500/1000:5, TRF 1.5 or higher.

• Protective relay settings at Gladstone: existing 643A at 0.87 p.f. -

likely easy to modify; • Protective relay settings at Springer: existing 672A at 0.87 p.f. - likely

easy to modify. • SCADA meter scaling at Springer: existing based on the 200/400:5

CTs and would likely change with the 115kV metering CT change out. • Wave trap: The existing 800A power line carrier line trap not presently

used for any communication channel at Springer, therefore would need to be removed from the circuit path and replaced or jumpered out with conductor.

d) Clapham 115kV Line Relaying Upgrades: Relaying addition or

modifications may be required at Clapham Substation to add directional relaying at Clapham looking towards Gladstone, due to new fault current source at the IC wind project / TP Interconnection Substation. Note that the Bravo Dome location consists primarily of motor load, and is not considered a fault current source. Estimated total cost = $75,000

.



e) Bravo Dome Substation Metering Upgrade: The Bravo Dome motor load metering is presently monitored by 115kV line metering installed at Clapham Substation, with line loss compensation. With the installation of the new IC generation on this Clapham – Bravo Dome 115kV line, new metering (revenue billing and power quality capable) will need to be installed utilizing existing 115kV CT/VTs on the line termination at Bravo Dome Substation. Additional communication circuit availability will need to be investigated for dial-up com needs associated with the new meter. Estimated total cost = $100,000

.

The total costs of all of these estimated Network Upgrades performed by the TP is =

$1,075,000.

7.2 Schedule: It is estimated that it will take approximately 9 to 12 months

to complete these Network Upgrades, after receiving authorization to proceed (e.g., IA signed, E&P agreement or similar). This is primarily due to the long lead time for the new replacement 115kV metering CTs required at Springer Substation.

8.0 Conclusions This report presents the powerflow and cost estimate components of a System Impact Study to connect 88 or 120 MW of new wind generation as described in Interconnection request No TI-04-1214. Short circuit study was performed at the 88 MW interconnection level. The short circuit results have been compared to equipment ratings by the TP, and deemed to be adequate. Based on the assumptions made and subject to the qualifications stated herein, it has been determined that 88 or 120 MW may be interconnected at this location, provided that the Network Upgrades are completing for increasing the Gladstone to Springer 115 kV line from its present terminal equipment limited 120 MVA (600A) continuous thermal rating to its line conductor 169 MVA (850A) rating. Furthermore, this SIRS has confirmed the existence of pre-existing regional voltage deviation problems, and the TP is in the process of completing study work in advance of installing additional reactive support (i.e., 115kV switched shunt capacitor banks) in the nearby 115kV TP system. Indicative level cost estimates for the cost of the Network Upgrades to be constructed by the TP are approximately $1,075,000.

Note that this does not include the costs of the work to be performed by the IC in constructing the TP portion of Network Upgrades at the new TP Interconnection Station.

The study has concluded that the proposed IC facilities meet the TP operational requirements for voltage regulation and reactive power support at the POI provided that



the GE 1.5 MW turbines have the optional expanded reactive power capability and the WindFREE reactive power capability. If the turbines will not be so equipped, additional voltage control devices will be required. The IC shall provide to the TP a complete final design study report, based upon detailed final design model data for the major IC Large Generation Facilities (LGF) that illustrates the LGF’s capability to meet the TP’s criteria for voltage regulation, reactive capability, and transient voltage operation. It is the responsibility of the IC to supply this report early enough in the final design process such that any comments by the TP that may impact the final LGF design may be implemented without impacting the project’s critical path schedule. Lastly, the final LGF equivalence “as-built” model data, specifically for the equipment previously modeled using estimated data in the TP SIRS studies, shall be supplied to the TP prior to the IC Facilities being declared as suitable for Commercial Operation.



Appendices Appendix A: Tri-State 115kV TI-04-1214 Interconnection SS & IC 115-34.5kV

Wind Project Substation One-Line. Appendix B: Steady State Power Flow Study – Case Listing. Appendix C: TSGT Transmission POI Bus Voltage Historical Data (available

only to IC and Affected System Parties upon request). Appendix D: Generator Dispatch Listing (available only to IC and Affected

System Parties upon request). Appendix E: TSGT Voltage Criteria Areas - Bus Name Listing (available only to

IC and Affected System Parties upon request). Appendix F: Contingency ∆V Violations (available only to IC and Affected

System Parties upon request). Appendix G: PSCAD Dynamics Study Report (available only to TP and IC).



Appendix A: Tri-State 115kV IC Interconnection Substation & IC Wind Project Substation



Appendix B: Steady State Power Flow Study – Case Listing

Case Number Case Description

1 HS with 0 MW added 2 HS with 0 MW added and 30 MW Solar plant removed 3 HS with 34 degrees loop flow with 0 MW added 4 HS, 34 degrees and no solar plant with 0 MW added 5 Light loading case with 0 MW added 6 Light load, no 30 MW solar and 0 MW added 7 HS with 88 MW added 8 HS with 88 MW added and 30 MW solar plant removed 9 HS with 34 degrees loop flow and 88 MW added

10 HS, 34 degrees and no solar plant with 88 MW added 11 Light loading case with 88 MW added 12 Light load, no 30 MW solar and 88 MW added 13 HS with 120 MW added 14 HS with 120 MW added and 30 MW solar plant removed 15 HS with 34 degrees loop flow and 120 MW added 16 HS, 34 degrees and no solar plant with 120 MW added 17 Light loading case with 120 MW added 18 Light load, no 30 MW solar and 120 MW added

Documents

Interconnection System Impact Re-Study Final Report – May ......Final Report – May 28, 2010 Interconnection Request No. TI-04-1214 88 MW Wind Energy Large Generating Facility In