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APS: Gila Bend Cluster 2010 Q1Q2 SIS Q133

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Q133 Cluster Addendum

1. INTRODUCTION

This Interconnection Customer (IC), submitted a Small Generator Interconnection Request (IR) to Arizona Public Service Company (APS) for their proposed project, located SE of Palomas Rd and Avenue 64E in Wellton, AZ. The Interconnection Customer (IC) requested Energy Resource Interconnection Service (ERIS), and plans to install 20 MW of photovoltaic solar generation with a requested In-Service Date of October 31, 2012. The project’s requested Point of Interconnection (POI) is the Aztec Tap - Aztec 69 kV line. The project is Queue Position 133 (Q133) in the APS FERC generation interconnection queue. On August 23, 2010, Arizona Public Service Company (APS) filed a request for a one-time waiver of the current study order of Interconnection Requests (IR) to allow a cluster study based in the Gila Bend area. This geographically targeted one-time waiver request of APS’ current interconnection queue procedure was changed to: 1) allow APS to study all SGIP and LGIP projects submitted in the Gila Bend area in first and second quarter of 2010 as a single cluster, 2) the clustered IRs will share the cost of common upgrades on a pro-rata basis, 3) each project subject to the cluster was given a one-time opportunity to opt out of the cluster, and 4) APS will evaluate projects outside of the cluster as if the clustering never occurred. On September 29, 2010, the Federal Energy Regulatory Commission (FERC) granted this waiver. Q133 is one of the projects in the cluster. General cluster results are captured in the general cluster SIS report. This addendum addresses project specific details and results. The Interconnection Customer has chosen to interconnect as an ERIS. Therefore, delivery of the Q133 output beyond the POI would be on an “as-available” basis only. The delivery of the Q133 output would be subject to the firm or non-firm transmission capacity that may be available when a transmission service request is made. Nothing in this report constitutes an offer of transmission service or confers upon the Interconnection Customer, any right to receive transmission service. APS may not have the Available Transfer Capability (ATC) to support the Transmission Service for the interconnection described in this report. It should also be noted that the results in this SIS are dependent upon the assumed topology and timing of new projects in the Gila Bend area, which are subject to change. The APS transmission and sub-transmission systems are continuously being evaluated. The planned reinforcements and their in-service dates are often revised depending upon local area load forecasts. A summary of the Interconnection costs and schedule estimates are shown below in Tables 1.1 and 1.2.

Table 1.1: Summary of Interconnection Cost and Schedule Estimates

Facility Costs Timeline

Local Network Upgrades (LNUs) $1,763,000 12 Months

Transmission Provider's Interconnection Facilities

$141,000 12 Months

Total $1,904,000 12 Months

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Table 1.2: Pro-Rata Share of System Network Upgrade Costs and Schedule Estimate


Q133 Pro-Rata Share of System Network Upgrades (SNUs) $7,656,561 43 - 49 Months

Total $7,656,561 43 - 49 Months

The interconnection costs shown in Table 1.1 above are specifically to interconnect Q133 into the APS transmission system. The System Network Upgrades (SNUs), as described in the main report, are shown in Table 1.2 above. The total cost to interconnect Q133 into the APS system is $9,560,561. The total estimated completion time for interconnecting the Q133 project is 43 – 49 Months due to the construction of the SNUs. The actual start of construction would occur when the IC provides written authorization to proceed, provided all interconnection studies are complete, and agreements and funding arrangements are in place. Therefore, the requested In-Service Date of October 31, 2012 cannot be met. Q133 will be given the first available In-Service Date once the Interconnection Agreement has been signed, which will be based on the Network Upgrades required at that time. Figure 1.2 below shows a general depiction of the 69 kV system around Q133’s proposed POI. The other Cluster projects are not shown, however higher queued projects are shown, as well as any non-FERC 12 kV projects.

Figure 1.2: Project Location and 69 kV System

Note: The numbers within the circles represent MW values.

230/69kV100 MVA

230/69kV100 MVA

Gila BendSubstation

To WhySubstation

Gillespie Substation

Cotton Center Substation

Butterfield

Substation

PalomaSubstation

BunyanSubstation

HyderSubstation

Aztec

Substation

Horn

Substation

County Line

Substation 87

Q3120

Q85

20Q86

20Q87

1818

17

13.5Q84

#1

#2

#3

9.4Q64

5Q77

To Saddle MountainSubstation

To Lower RiverSubstation

Patterson

Substation

To BuckeyeSubstation

69kV bus

69kV line

69kV breaker

New 69 kV ring bus

Cluster generator

Non-cluster generator

Non-FERC 12 kV projects#

20Q133

POI#4

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2. RESULTS

The Cluster report details the overall results. Individual project results will only be noted in the project specific appendix if something is deemed confidential from the remainder of the Cluster or if it specifically affects the project or project model. All other results are included in the main Cluster report. Transient Stability: One N-1 contingency resulted in low level undamped behavior of most Project output variables. In addition, the frequency and voltage of nearby buses were affected and showed similar undamped behavior. As noted in the main Cluster report: Although multiple inverter models were affected, and the larger variable was location, further testing indicated that one particular inverter model seemed to cause the undamped behavior. In addition, although all of the Cluster inverter models have the required +/- 0.95 dynamic pf at the generator terminals, not all respond in the transient timeframe. That said, further testing of these contingencies showed that adding sufficient capacitance in the transient timeframe eliminated the violations, and showed the inverter models responding as expected. The dynamic data provided by the project resulted in the model operating in a "fixed" mode. Although this model doesn't appear to cause the localized undamped behavior noted in the main report, the results show that operating in the fixed mode as compared to a variable reactive power mode may limit the system's ability to recover.

Table 2.1: Transient Stability Results

Contingency Description 2013 2014

Sensitivity Mitigation

N N-1 HARQUATAP-DELANY 69 kV (#665m) LL only LL only Install dynamic reactive device at Saddle Mountain

69 kV, if review/update of applicable dynamic models does not resolve issue.

Sample Transient Plots for two contingencies are shown on the following pages. They reflect a 2013 LL case. The first plot represents the undamped behavior noted in the table above, prior to mitigation with a dynamic reactive device. The last plot (N-1 SADDLE MTN-HARQAHALA TAP 69 kV) shows a more typical response. The project needs to confirm that the selected inverter can be run in variable reactive power mode prior to any further studies.

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N-1 Contingency: HARQUAHALA TAP - DELANY 69 kV, fixed mode

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N-1 Contingency: Saddle Mountain - Harquahala Tap 69 kV

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3. PROJECT MODELING

All projects were assumed to be generating at maximum output. Projects consisted of an equivalent generator, equivalent inverter transformer, station transformer, and gen-tie. Individual project collector systems were not modeled. New switching stations were modeled, bisecting existing lines, based on interconnection requirements and locations. Some projects required additional shunt devices to provide the full +/- 0.95 pf at the POI.

APS allows the project's reactive support to be made up of dynamic VAr and switched static VAr devices. The reactive devices used to achieve +/- 0.95 power factor as measured at the generator terminal must be dynamic. Any additional reactive support required to compensate for losses between the generator terminals and the POI may be made up of switched static reactive devices and/or any additional reactive capability of the generator beyond 0.95 power factor. Q133 selected the SMA Sunny Central 500 CP inverters (500 kW). Based on the data provided, the inverter pf capability is affected by temperature. At 25 degrees C (77 F), the inverter would be able to provide +/- 0.95 pf at the generator terminals for all generator output levels, utilizing its ability to provide up to 110% apparent power. At 50 degrees C (122 F), the inverter would be limited to its 500 kVA rating, and unable to provide the +/- 0.95 pf at all output levels. According to historical temperature data obtained from the Western Regional Climate Center (WRCC), the highest average temperature for the Gila Bend area is 42.8 degrees C (109 F). Due to the high temperatures in the project's location, the temperature limitation on the inverters drives the need for additional dynamic support to provide the +/- 0.95 pf at the generator/inverter bus. The dynamic reactive power requirement is based upon the +/- 0.95 power factor requirement and is calculated as follows:

In order to meet the dynamic reactive power requirements for the project, Q133 elected to install additional inverters to the project, installing a total of forty-four (44) 500 kW inverters. This provides a worst case (maximum temperature) MVA of 22.0, which meets the dynamic reactive power requirements and provides +/- 0.91 pf at Pmax.1 (The generator output is still limited to 20 MW.) The additional reactive power requirement to provide +/- 0.95 pf at the POI may be provided by static reactive support. Assuming a 0.91 pf, Q133 needs to install a 1.1 MVAr shunt capacitor at the 34.5 kV bus, or equivalent. As part of the Cluster study, the project was modeled more conservatively, with a +/- 0.95 pf generator which then required a 3.7 MVAr shunt capacitor at the 34.5 kV bus.

1 APS has since determined that inverters with temperature dependent performance must only provide dynamic reactive power

requirements sufficient to support the highest average monthly temperature for the area, which would be 109⁰F for the Cluster

projects. In some cases this may reduce the need for additional VAr support.

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Major components of the equivalent project model include:

Gen-tie: 0.1 miles 3/0 ACSR

Station Transformer: 1 x 22.5 MVA, 69/34.5 kV transformer

Inverter Transformer: 1 x 22 MVA, 34.5/0.27 kV transformer

Generator: 20 MW, equivalent of forty (40) 500 kVA SMA Sunny Central 500 CP inverters, +/- 0.95 pf capability (pf provided by additional inverters)

Shunt capacitor: 3.7 MVAr shunt capacitor at 34.5 kV bus to compensate for project losses and achieve +/- 0.95 pf at the POI2.

Figure 3.1: Project Model and POI

2 This value was calculated to meet the minimum power factor requirements, based upon the project model provided.

Aztec Tap69 kV

New POI BUS

Aztec69 kV

Gen-tie0.1 miles3/0 ACSR

22.5 MVAZ= 8.5% on 13.5 MVAX/R= 15

22 x 1 MVA

Z= 5.75% on 1 MVAX/R= 8

Q13320 MW

69 kV

34.5 kV

0.27 kV

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4. TRANSIENT STABILITY MODELING

Q133 provided a user defined epcgen model for the SMA Sunny Central 500 CP inverter. Initially the project was tripping for over-voltage and over-frequency on specific contingencies. The IC provided updated values for OV2L and OFT, as noted below in red, which resolved the problem.

NOTE: Changing QREG and RMOD from "0" to "1" puts the model into a variable reactive power mode.

smascpv.p Rev C1

12/14/10

PSLF Modeling

Rev D, 10/31/10 Default Q133

Q133 Rev

9/15/11 rsrc 0 0 0 xsrc 0 0 0 Vratio 1.2 1.2 1.2 Iratio 1.1 1.1 1.1 Tdc 0.002 0.002 0.002 Kpdc 2.0 2 2 Kidc 20.0 20 20 Kpq 0.1 0.1 0.1 Kiq 10 10 10 Ilim 1.11 1.11 1.11 PFC 0 or 1 1 1 PPS -0.25 -0.25 -0.25 RPS -5.17 -5.17 -5.17 PFS -0.40 -0.4 -0.4 FSP 60.50 999.9 999.9 FRP 60.05 60.05 60.05 QREG 0 0 0 RMOD 0 0 0 OV1L 1.2 1.2 1.2 OV1T 0.16 0.16 0.16 OV2L 1.1 1.1 1.15 OV2T 1.0 1.0 1.0 UV1L 0.45 0.45 0.45 UV1T 0.16 0.16 0.16 UV2L 0.85 0.85 0.85 UV2T 2.0 2.0 2.0 OFL 62.0 62.0 62.0 OFT 0.16 0.16 1.0 UFL 57.0 57.0 57.0 UFT 0.16 0.16 0.16 LVL 0 0 0 VSP 0.2 0.2 0.2 VRP 0.25 0.25 0.25

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5. COST AND CONSTRUCTION SCHEDULE ESTIMATES

The cost and time estimates represent good faith estimates necessary to interconnect to the system. The non-binding, good faith cost and time estimates are tabulated below.

Assumptions:

Permit costs are not included in the estimate.

All weather access road costs are not included in the estimate.

Land acquisition/ROW costs are not included in the estimate as it was assumed parcel for switchyard would be deeded to APS from the IC.

Access & Lay Down Yards are not included in the estimate.

Rough grading costs are not included in the estimate.

APS will construct, own and operate the 69 kV facilities in the new APS switchyard and the portion of line from the 69 kV bus up to the first structure outside the sub fence.

The IC will construct, own and maintain the 69 kV gen-tie from the first structure outside the sub fence to the Q133 site.

The IC will be responsible for providing a fiber optic communications path from the Q133 facility to the new APS switchyard.

Line estimates do not include costs to reconfigure APS lines as a result of IC 69 kV route or design.

All estimates are in 2012 dollars. Table 5.1 below provides a summary of the Local Network Upgrades (LNUs) and Transmission Provider’s Interconnection Facilities (TPIF) cost estimates. These costs include the construction of a new APS 3-breaker 69 kV switchyard. Table 5.2 below shows the pro-rata share of the SNU costs required for this cluster, as well as the estimated construction schedule to complete the upgrades.

Table 5.1: Q133 Project Cost Summary

.Equipment Description Local Network Upgrades (LNUs)

Transmission Provider's Interconnection Facilities

New APS 69 kV Switchyard $1,475,000 $141,000

Overhead Line Work $105,000 $0

Communications (Leased T1 Line) $183,000 $0

Subtotal $1,763,000 $141,000

Grand Total $1,904,000

Table 5.2: Pro-Rata Share of System Network Upgrade Costs and Schedule Estimate


Q133 Pro-Rata Share of System Network Upgrades (SNUs) $7,656,561 43 - 49 Months

Total $7,656,561 43 - 49 Months

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The interconnection costs shown in Table 5.1 above are specifically to interconnect Q133 into the APS transmission system. The System Network Upgrades (SNUs), as described in the main report, are shown in Table 5.2 above. The total cost to interconnect Q133 into the APS system is $9,560,561. The SNU cost responsibility for a specific individual project will be based on the pro-rata share as identified above, and may change (increase or decrease) depending on the remaining projects in the cluster as well as the timing of the specific project’s advancement through the APS interconnection process. All network upgrade costs (LNUs and SNUs) are considered APS Network Upgrades, which are typically repaid to the IC, per FERC rules, as transmission credits over a maximum of twenty (20) years. The Transmission Provider’s Interconnection Facilities (TPIF) include the necessary switches, bus work, etc needed to bring the Q133 generation tie-line into the new APS switchyard. These costs are the sole responsibility of the Interconnection Customer. Unlike Network Upgrades, these costs are not reimbursable. Table 5.3 below provides a summary of the construction schedule. The construction schedule for the SNUs can be found in Table 5.2 above.

Table 5.3: Q133 Construction Schedule Estimate

Facility Schedule

New APS 69 kV Switchyard 12 Months

Overhead Line Work 9 Months

Communications (Leased T1 Line) 8 Months

Total 12 Months

The total estimated completion time for interconnecting the Q133 project is 43 – 49 Months due to the construction of the SNUs. The actual start of construction would occur when the IC provides written authorization to proceed, provided all interconnection studies are complete, and agreements and funding arrangements are in place. Therefore, the requested In-Service Date of October 31, 2012 cannot be met. Q133 will be given the first available In-Service Date once the Interconnection Agreement has been signed, which will be based on the Network Upgrades required at that time. Note: This cluster SIS may need to be re-studied if all projects studied as part of this cluster do not move forward to the Facilities Study. If this occurs, the required upgrades, the total estimated costs and the pro-rata shares of the estimated costs will be adjusted and the pro-rata costs shown in Table 5.2 may change (network upgrade costs associated with each project could increase or decrease and may result in an increase in cost up to the full amount of total upgrades).

APS Contract #52367

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