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Contract No. DE-AC36-08GO28308

High Penetration Photovoltaic 

Case Study Report 

J. Bank, B. Mather, J. Keller, and 

M. Coddington 

National Renewable Energy Laboratory

Technical Report

NREL/TP-5500-54742

January 2013
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

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Contract No. DE-AC36-08GO28308

High Penetration Photovoltaic 

Case Study Report 

J. Bank, B. Mather, J. Keller, and 

M. Coddington 

National Renewable Energy Laboratory

Prepared under Task No. SS12.1310

Technical Paper

NREL/TP-5500-54742

January 2013
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Table of Contents 

Introduction.................................................................................................................................................. 1

1 Case Study: 10 MW Plant near Carlsbad, New Mexico ..................................................................... 2

System Highlights................................................................................................................................... 2

Introduction............................................................................................................................................. 3

System Overview.................................................................................................................................... 3

Interconnection of the PV System .......................................................................................................... 4

Effects of the PV System ........................................................................................................................ 5

Conclusions and Ongoing Studies.......................................................................................................... 5

2 Case Study: Colorado State University Foothills Campus, Fort Collins, Colorado....................... 7

System Highlights................................................................................................................................... 7

Introduction............................................................................................................................................. 8

System Overview.................................................................................................................................... 8

Interconnection of the PV System ........................................................................................................10

Effects of the PV System ......................................................................................................................12

Conclusions and Ongoing Studies........................................................................................................14

3 Case Study: Kapa’a Solar Project, Olohena Road, Kaua’i, Hawaii ............................................... 15

System Highlights................................................................................................................................. 15

Introduction...........................................................................................................................................16

System Overview..................................................................................................................................16

Interconnection of the PV System ........................................................................................................18

Effects of the PV System ......................................................................................................................19

Conclusions and Ongoing Studies........................................................................................................19

4 Case Study: 2 MW Plant in Fontana, California ...............................................................................20

System Highlights................................................................................................................................. 20

Introduction...........................................................................................................................................21

System Overview..................................................................................................................................21

Interconnection of the PV System ........................................................................................................22

Effects of the PV System ......................................................................................................................23

Conclusions and Ongoing Studies........................................................................................................23
1 

Introduction

Technical concerns with integrating higher penetrations of photovoltaic (PV) systems

include grid stability, voltage regulation, power quality (voltage rise, sags, flicker, and 

frequency fluctuations), and protection and coordination. The current utility grid was 

designed to accommodate power flows from the central generation source to the 

transmission system and eventually to the distribution feeders. At the distribution level, 

the system was designed to carry power from the substation toward the load. Renewable 

distributed generation, particularly solar PV, provides power at the distribution level 

challenging this classical paradigm. As these resources become more commonplace the 

nature of the distribution network and its operation is changing to handle power flow in 

both directions. 

A large portion of distribution system components, including voltage regulators and 

protection systems, were not designed to coordinate with bidirectional power flow and 

bidirectional fault currents from distributed generation and PV systems in particular. 

Coordinating these devices in the presence of high penetration PV areas introduces 

additional challenges to feasibility and system impact studies. Some cases require 

modification of existing protection schemes, additional distribution equipment, or 

reactive power requirements on the PV inverters.

This report is focused on large PV installations in which penetration is significantly 

greater than 15% of maximum daytime feeder load. To date the impact on the electric 

utility and its customers has not been problematic in any of these cases. The PV system 

installations described in this report exceeds what most experts consider high penetration

scenarios. The voltage, power quality, and other operating parameters have been 

maintained within the required ranges with minimal negative impact on distribution 

operations and utility customers. These case studies are intended to demonstrate success 

stories with integration of large PV plants at the distribution level as well as some of the 

solutions used by the utility to ensure safe, reliable operation of both the PV system and 

the distribution network. 
2 

1 Case Study: 10 MW Plant near Carlsbad, New 

Mexico

System Highlights

System Owner: SunEdison

Utility: Xcel Energy

System Integrator: SunEdison

System Size: 9.9 MWDC

Network Type: Radial, Dedicated Feeder for PV Plant

Special 

Interconnection 

Requirements:

• Fixed power factor to avoid high voltages

• Inverters required to energize incrementally
3 

Introduction

This PV plant is a 10 MW ground mount facility located near Carlsbad, New Mexico. It 

is connected in the distribution network 0.75 miles from the substation on a dedicated 

branch of the feeder. It is located within Southwestern Public Service Company’s service 

territory. Southwestern Public Service Company is a subsidiary of Xcel Energy. 

Information for this case study was compiled from data provided by Xcel Energy’s 

distribution engineers responsible for the applicable circuit, from Xcel Energy’s 

published reports, and manufacturer data sheets.

System Overview

Utility: Xcel Energy is an investor-owned utility serving several states in the midwest 

and west. Its service territory includes portions of Michigan, Wisconsin, Minnesota, 

North Dakota, South Dakota, Colorado, New Mexico, and Texas. Southeastern New 

Mexico and northwest Texas are served by Southwestern Public Service Company. 

Southwestern Public Service Company serves about 350,000 customers and one million 

people across its territory.

In 2011, Southwestern Public Service supplied about 4,700,000 MWh to customers. New 

Mexico’s rule 572 requires that a public utility source 10% of its retail energy from 

renewable sources. Additionally at least 20% of these renewable source are required to be 

solar generation and at least 1.5% distributed generation.

1

 The Carlsbad PV Plant helps 

to satisfy these goals.

PV System: The Eddy County PV plant is a 9.9 MWDC facility owned by SunEdison. It 

is located 0.7 miles west of the intersection of Old Cavern Highway and Hopi Road near 

Carlsbad, New Mexico. The plant is connected to a distribution feeder 0.75 miles west of 

the substation. This plant was commissioned on August 5 2011. 

The PV panels are Trina TSM270PC14 cells with a max DC output power of 270 Watts 

(W) at standard test conditions (STC). The manufacturer stated efficiency of these 

modules is 13.9% at STC.

2

 These modules are ground mounted and use a single axis 

tracking system. These PV modules feed a set of Power One inverters which includes 

three types of inverters: the PVI-330-TL-EN, PVI-275-TL-EN, and PVI-220-TL-EN. 

These inverters are 330, 275, and 220 kWAC units respectively.

3

 

 

1 Southwestern Public Service Company -- 2011 Annual Renewable Energy Portfolio Procurement Plan, 

http://www.xcelenergy.com/staticfiles/xe/Regulatory/Regulatory%20PDFs/CLB22011RPSPlanfor2013.pdf Xcel Energy. July 1, 2011

2 Trina Solar TSM PC-14 Datasheet. http://www.trinasolar.com/images/PDF/datasheets/us/TSMPA14_US.pdf Trina Solar. 2011. 

3 Power One PVI Inverter Series Datasheet. http://www.power-one.com/sites/power-one.com/files/pvi55.0...330.0_en_2.pdf Power One, 2011.
4 

Distribution Network: The PV plant is served by the Hopi Substation, located at the 

intersection of Old Cavern Highway and Hopi Road near Carlsbad, New Mexico. The PV 

system is 0.75 miles from the substation on 336ACSR conductor. A one-line diagram of 

the distribution network and the PV system is given in Figure 2-1. 

Figure 2-1: Carlsbad, New Mexico PV System, Substation, and Distribution Circuit

The Hopi Substation operates at 69 kV on the transmission side and 12.47 kV on the 

distribution side. The transformer in the substation is rated at 28 MVA. Voltage 

regulation on this distribution system is handled by a load tap changer located on the 

substation transformer and switched capacitors on the feeders.

The peak load on this substation exceeds 10 MVA. The minimum daytime load on the 

substation is about 3.87 MVA. No other distributed generation (DG) is located on this 

feeder or substation. Since no other DG is present, the penetration level is determined by 

the single PV plant. The 9.9 MVADC rating of the plant is close to the typical peak load 

of 10 MVA and thus the PV penetration level, defined as total installed PV divided by 

max load, would be in the 90% to 100% range. During minimum daytime load times the 

PV system power output can exceed the load on the substation. 

Interconnection of the PV System 

System Impact Studies: Given the size of this PV system in relation to the load and 

substation, Xcel Energy had several concerns prior to interconnection of the system. As 

clouds or other solar transients move across the PV array, the output power necessarily 

drops. If the PV is acting as a major source on the distribution circuit, this power loss can 

have the effect of depressing the voltage. A sudden drop in distribution voltage resulting 

from passing clouds was a major concern for the utility. Additionally, the effects of 
5 

system energization and de-energization with regards to voltage and power flow were 

also a concern. Xcel Energy was also concerned about the changes in steady-state voltage 

profile along the circuit and desensitization of substation protection relays with the 

additional power injections. 

In order to address these concerns, Xcel Energy’s distribution engineers performed 

several studies prior to interconnection of the PV plant on the Hopi Substation. These 

studies included fault current contribution, protection coordination, voltage delta, and 

voltage profiling studies. These studies were primarily performed in the SynerGEE 

distribution modeling software package. 

The protection coordination studies identified desensitization of relaying at the substation 

as a potential problem resulting from the addition of the PV plant, and additional line 

protection was added to address this issue. Voltage supervised reclosing was added to the 

substation breakers because the load flow studies identified potential problems given the 

size of the PV system and expected minimum loading on the distribution circuit. The load 

flow studies also indicated that high voltages may result from the PV interconnection; 

consequently the PV owner was required to regulate their output power factor to a fixed, 

leading value. Additionally the PV owner was required to energize the inverters 

incrementally in order to avoid large voltage steps. 

Distribution System Upgrades: In anticipation of the new PV system, two reclosers 

were added to the distribution feeder. The utility also installed 0.75 miles of 336ACSR 

conductor to provide a primary distribution feeder from the substation out to the PV 

system. This conductor was sized to handle full solar production from this PV plant. 

Additionally, the substation protection schemes were upgraded to include voltage 

supervised reclosing and extended line protection as mentioned above. No additional 

issues requiring equipment upgrades were identified after interconnection of the PV 

system.

Effects of the PV System 

Many of the issues identified by the interconnection studies have been observed on the 

distribution system after commissioning of the PV plant. The mitigation steps and system 

upgrades detailed above have prevented these issues from having adverse effects on the 

distribution system and feeder. No additional protection issues have been observed since 

the connection of the PV plant. 

Xcel Energy engineers have not observed any reverse power flows in collected data, but 

expect that, given the size of the PV system and the load, power sometimes flows up to 

the 69 kV transmission level when the PV is at full output and the local load is relatively 

light. These occurrences have not produced any reportable problems to date. 

Conclusions and Ongoing Studies

Utility Perspectives: Results from this system and other 10 MW-scale PV plants in west 

Texas and New Mexico have helped to guide Xcel Energy in performing impact studies 

and approval of interconnection requests. Xcel Energy now strongly encourages that PV 
6 

plants which are to be attached on 15 kV class distribution feeders and are 10 MW or 

larger be located within 2 miles of the substation. Currently, the furthest 10 MW scale 

plant in this region is located 1.7 miles from the substation on a 556AA conductor. 

Continuing Studies and Research: No additional studies have been performed on this 

circuit since the interconnection process. As the circuit is operating without issue, they 

have not been necessary to this point. This circuit will be re-evaluated on a periodic basis 

to ensure that it is operating correctly. Operational experience and collected data will 

necessarily inform and direct these studies. Currently, no research projects are focusing 

on this PV system or distribution network. 
7 

2 Case Study: Colorado State University Foothills 

Campus, Fort Collins, Colorado

System Highlights

System Owner: Colorado State University

Utility: • Xcel Energy

• Public Service Company of Colorado 

System Size: 5.2 MWAC

Network Type: Radial

Special Interconnection 

Requirements:

• Inverters required to energize incrementally

• Required to set inverters to absorb 100 kVAr 

or 150 kVAr at utility request to avoid high 

voltages 

Figure 3-2: PV System at Colorado State University Foothills Campus 
8 

Introduction

Xcel Energy owns and operates the distribution circuit described in this study where this 

is approximately 47% PV penetration. 5.2 MW of PV is installed on the Colorado State 

University (CSU) Foothills Campus, on the western edge of Fort Collins, Colorado. 

Xcel Energy’s primary concern with the installation of this PV system is maintaining 

voltage levels within ANSI C84.1 (range A). The PV system was built in two phases. 

After completion of Phase I, a 2 MW installation, there were no measured voltage or 

power quality aberrations. Phase II added 3.2 MW of additional PV, and the voltage and 

power quality parameters remained within acceptable levels. 

System Overview

Utility: Overall, Xcel Energy is ranked as the fifth highest in installed solar system rated 

capacity according to the Solar Electric Power Association, and first in wind energy 

according to the American Wind Energy Association. The regulated Xcel Energy 

operating companies operate in eight states (Colorado, Michigan, Minnesota, New 

Mexico, North Dakota, South Dakota, Texas, and Wisconsin) with approximately 3.4 

million electric customers and 1.9 million natural gas customers. The operating company 

in Colorado is Public Service Company of Colorado (PSCo). 

PSCo has 74 MW of PV interconnected to distribution circuits and substations, for a total 

of over 7,000 systems. PSCo has 1,260 MW of wind power providing about 10% of the 

PSCo energy sold in Colorado, and has plans to add an additional 700 MW of wind 

power by 2013. 

In particular, solar installations in the form of PV systems have been increasing due to

substantial financial incentives in Colorado. Xcel Energy has provided a significant 

portion of the funding for the project through its Solar Rewards program. 

In the major states it serves, Xcel Energy is required to comply with state Renewable 

Portfolio Standards, implemented in part to reduce carbon emissions. In Colorado, Xcel 

Energy has a compliance requirement for distributed energy resources (DER) and 

provides customer and developer incentives for the deployment of PV systems. Xcel 

Energy has established requirements for DER interconnections and, provided the 

interconnection meets specific standards (based on IEEE 1547), allows them as long as 

the grid can reliably accept the new generation sources. Xcel Energy reviews all proposed 

DER interconnections.

PV System: The PV system installed at the CSU west campus is one of the largest PV 

systems in Colorado and one of the largest PV systems on a university campus.4 The 

energy produced will offset about one-third of the energy requirements for the CSU west 

campus over the next 20 years. The PV system covers 15 acres, and utilizes both singleaxis tracking and fixed-axis PV arrays. The CSU PV system was built in two phases, with 

a total peak rating of 5.2 MW. Phase 1 was completed in 2009 using Trina Solar 

 

4 http://www.news.colostate.edu/Release/4991 See press release from Colorado State University.
9 

crystalline-silicon PV modules, Array Technologies Wattsun single-axis tracking system, 

and Advanced Energy Solaron inverters. Phase 2 used the same modules and inverters, 

but utilized a fixed mounting system for the arrays. 

Distribution Network: The CSU Foothills Campus is currently supplied by an Xcel 

Energy distribution feeder (13.2 kV) that is 6.5 miles in length. The substation is served 

by 115 kV on the high-voltage side stepped down to 13.2 kV for the distribution voltage, 

with the substation transformer being a 24 MVA oil-cooled unit. The feeder’s average 

daily peak load was 7.5 MVA in 2010, with a peak demand load of 9.1 MVA and a 

minimum daytime load of 3.1 MVA. 

Figure 3-2 is a one-line diagram of the Xcel Energy substation and distribution system, 

and illustrates the components of the circuit as well as the 2 MW and 3 MW PV systems.

Figure 3-3: One-line Diagram of the Xcel Energy Distribution System, PV Systems, and 

Loads

The CSU Foothills Campus will eventually be served by a new substation located on the 

campus footprint. The new College Lake Substation will be supplied by the Platte River 

Power Authority-owned 230 kV transmission system and will serve the CSU Foothills 

Campus at 13.2 kV. 

Figure 3-3 illustrates the load profile of the distribution feeder to which the PV system is 

connected during one week of February, 2011. 
10 

Figure 3-4: Load Profile of Distribution Feeder

Interconnection of the PV System

System Impact Studies: Xcel Energy engineers completed both a feasibility study and a 

system impact study for the PV system installation. Engineers used a distribution 

simulation analysis package to evaluate the performance of the distribution feeder, loads, 

and PV systems prior to the installation of Phase 1 and once again prior to Phase 2. 

One of the potential problems identified by these impact studies was that high voltages 

may occur during periods of light feeder loads and high PV system production. If high 

voltage becomes a problem, Xcel Energy has planned a four-step mitigation approach 

which progresses through mitigation options until the problem is rectified. 

1. Adjust the voltage regulators to stabilize the voltage levels. 

2. The inverters (10 total) will be configured to absorb 100 kVAr each. 

3. The inverter configurations will be changed so they will absorb 150 kVAr each. 

4. Xcel Energy will notify the system operator to disconnect all or part of the PV 

system and install an additional power factor controller or dynamic VAR 

compensator. 

System Voltage: Xcel Energy is primarily concerned about system voltage fluctuations 

on any large PV installation, including flicker and high or low voltage levels and 

excessive regulator and load tap changer (LTC) operations. Tools to address voltage 

aberrations include:

1. LTC at substation transformer for voltage regulation 

• LTCs have the capability to buck or boost voltage, typically through steps covering 

a total of 10% of the source side voltage, and are controlled at the substation level 

automatically, manually, or on occasion set via SCADA. 

2. Voltage regulators on the distribution feeder (some with advanced controls) 

• Regulators can buck or boost voltage and may be bi-directional.
11 

• Regulators can use sophisticated controls to maintain voltage levels several miles 

from the regulator banks, typically using an X/R scheme. 

• A tool used in some locations is the use of directional setting groups for bidirectional regulators. This requires different settings depending on the direction of 

current flow, and may be used in higher penetration circuits. 

3. Capacitor bank (with remote controllability) 

• Capacitors will raise voltage levels in most cases, and their use with large PV 

systems on the same feeder must be controlled carefully. Many distribution circuits 

employ fixed capacitor banks, and are often used to inject VARs onto a circuit. 

4. Inverters having power factor control capability 

• Some newer models of inverters, such as the Advanced Energy Solaron inverters 

used in this installation, may be programmed to supply VARs. Ultimately, a power 

factor control would be the preferred method to maintain voltage stability once 

equipment is available. The capability of supplying VARs is in conformance with 

IEEE 1547 and UL 1741; however the use of reactive power must be coordinated 

with the electric utility engineers.

Voltage Regulators on LaPorte 1605: There are two sets of 15 kV class voltage 

regulators on the feeder, which were in operation prior to the PV installation. The voltage 

regulators closest to the CSU campus (Reg 2 on Figure 3-2) have been programmed to 

maintain a 1 Volt (V) bandwidth (on a 120 V base) at the campus service entrance point. 

This tight bandwidth was initiated before the PV system was installed, primarily due to 

the configuration of some un-grounded wye transformers on the campus. Maintaining a 

tight voltage bandwidth has created a situation where the regulators have operated 

hundreds of thousands of times over a one year period. Two of the regulators were found 

to be non-operational when checked during normal maintenance procedures, and had to 

be rebuilt by Xcel Energy technicians. Those failures, while unfortunate yet predicable, 

did not create complaints by utility customers on the feeder. 

Staggered Energization of Inverters after an Outage: Energizing the CSU circuit by 

the inverters must be staggered so that only one inverter comes online at a time. The 

inverters were programmed to connect to the grid in intervals (typically after an outage 

has caused the system to cease to energize). This staggered re-energization will minimize 

the potential of 5.2 MW in PV generation coming online too quickly and causing a 

voltage swell. 

Table 3-1 shows the inverter's staggered start-up scheme for the reconnect time after any 

PV system trip.
12 

Table 3-1: Start-up Scheme for PV Inverters

Inverter No. Start-up time Inverter size

1 230 seconds 500kW

2 260 seconds 500kW

3 290 seconds 500kW

4 320 seconds 500kW

5 350 seconds 500kW

6 380 seconds 500kW

7 410 seconds 500kW

8 440 seconds 500kW

9 470 seconds 500kW

10 500 seconds 500kW

Distribution System Upgrades: A new distribution substation is being constructed 

within one mile of the 5.2 MW PV system and campus load, and was completed during 

the summer of 2011. Building a multi-megawatt PV system adjacent to a substation is 

understood to have a significantly lower impact on a distribution feeder compared to PV 

systems located miles from a substation. This is due to lower impedance between the PV 

system and the substation transformer, higher available fault current due to the proximity 

to the substation and greater system stiffness factor, resulting in additional operational 

advantages desired by CSU. 

Effects of the PV System 

Exporting and Non-Exporting PV Systems: Much of the power generated by the 5.2 

MW PV systems is consumed at the university campus. However, there are times when 

the PV system generates more power than the campus can consume and the PV system 

exports power back to the Xcel Energy distribution feeder where it is consumed by 

neighboring loads. Figure 3-4 indicates power levels measured at the campus primary 

meter. Any PV system which exports power back to the utility system has the capability 

to create a high voltage condition if not properly addressed by the utility distribution 

engineers. Both exporting and non-exporting PV systems have the capability to create 

voltage flicker with passing clouds. 
13 

Figure 3-5: Real Power Measured at the CSU West Campus, 

which includes the PV System Generation

Note the times when power drops below zero, which are times when power is being 

exported to the utility distribution system.

Power Quality: Voltage, harmonics, flicker, and other power quality measurements have 

been in the acceptable range and there have been no complaints from customers 

following the installation of the PV system. This was verified on several occasions (see

Figure 3-5) by having Xcel Energy technicians set power quality recording devices at the 

primary metering locations and recording voltage, current, harmonics, etc. 

Figure 3-6: Harmonic Analysis at the Primary Meter Serving Load and the PV Systems

Although the distribution feeder has very high levels of penetration, well in excess of the 

15% threshold considered high penetration, the electric distribution system generally 

operates within normal parameters and without any significant customer complaints or 

customer equipment failures due to power quality problems. 
14 

Conclusions and Ongoing Studies

Utility Perspectives: The installation of the PV on this circuit has not had any significant 

effects on the day-to-day operation of this system. All power quality issues including 

flicker, harmonics, sags, and swells have been within acceptable ranges and, for the most 

part, unnoticeable. Utility concerns about elevated voltages on the circuit have been 

somewhat alleviated by the mediation steps put in place and through operational 

experience. However, the fixed leading power factor approach outlined above was taken 

as an interim step until additional planned distribution system architecture was installed.

Although successful, it was not intended as a long-term solution.

Continuing Studies and Research: Currently no major research projects are studying 

the PV system or feeder. As with all of their circuits, PSCo will review the operation of 

this circuit on a periodic basis to ensure that it is operating correctly and there are no 

voltage, power quality, or protection issues. They are currently collecting Supervisory 

Control and Data Acquisition (SCADA) data for this circuit as well as power quality 

data.
15 

3 Case Study: Kapa’a Solar Project, Olohena 

Road, Kaua’i, Hawaii

System Highlights

System Owner: Kapa’a Solar LLC

Utility: Kaua’i Island Utility Cooperative

System Integrator: REC Solar, Inc.

System Size: 1.2 MWDC

Network Type: Radial

Special 

Interconnection 

Requirements:

None

Figure 4-7: 1.2 MWDC Photovoltaic array on Kaua’i, Hawaii (Credit J. Keller, NREL)
16 

Introduction

In late 2005, the Kaua’i Island Utility Cooperative (KIUC) updated its Integrated 

Resource Plan from one developed in 1997. Recognizing the important role of energy 

diversity, KIUC developed an aggressive strategic plan for 2008 through 2023. In 

November, 2007, KIUC committed to generate at least 50% of its electricity using 

renewable energy by 2023. Currently, KIUC derives the majority of its power from diesel 

generators and a combustion turbine that uses naphtha (93%). There is also 

approximately 7% hydro-electric power being generated on the island. The island 

presently has 5 MW of PV distributed throughout the island, and the new 1 MWAC (1.2 

MWDC) Kapa’a Solar PV project brought the total amount to 5 MW. A 1.5 MW utility 

scale battery storage (1.5 hours) that was installed by Xtreme Power has been operational 

(operating in frequency regulation mode) since October 2011. 

The Hawaii-wide Renewable Portfolio Standards calls for 40% of its electricity to be 

generated from renewables by 2030. KIUC has planned for utility scale solar PV totaling 

30 MW with 12 MW/9 MWH of Battery Energy Storage to come on line within the next 

2 years. This includes a PPA for 6 MW of PV located next to KIUC Port Allen facilities 

and two 12 MW Solar PV farms on the east and south shores of Kauai owned by KIUC 

subsidiaries. The project is scheduled to be completed by 2014. 

System Overview

Utility: KIUC, a non-profit entity with cooperative by-laws, operates two main power 

plants on Kaua’i: Port Allen and Kapaia Power Station (KPS). Port Allen has 12 

generating machines capable of producing 96.5 MW of power. It also has a heat recovery 

steam generator. The generator uses the waste heat from two of the combustion turbines 

to produce steam for additional electrical generation. KPS has a 27.5 MW steam-injected 

gas turbine facility purchased in 2003, and is KIUC’s more efficient and cleaner burning 

plant. This plant provides the majority of the power to the island. Currently KIUC derives 

93% of its power from diesel and naphtha. KIUC also maintains the Waiahi hydro power 

plant, which includes the Upper and Lower Waiahi hydro-electric units, rated at 500 kW 

and 800 kW respectively. The Waiahi hydro plant, along with several other existing 

hydros that KIUC purchases power from, provides approximately 7% renewable energy 

annually. 
17 

Figure 4-8: KIUC Electrical Generation and Distribution Map (Image courtesy of KIUC)

PV System: Kapa’a Solar LLC is the owner and financier of the PV system, and worked 

to negotiate a power purchase agreement with KIUC. REC Solar Inc. was the Kapa’a 

contractor for the installation of the PV system. KIUC, Kapa’a Solar, and REC Solar 

marked the official completion and commissioning of the 1.2 MWDC solar installation on 

February 11, 2011. The Kapa’a Solar project is located on Olohena Road, Kapa’a, 

Hawaii. Figure 4-1 shows an image of the Kapa’a 1.2 MWDC PV system.

Features of the Kapa’a Solar PV system include special corrosion resistance on the 

racking to protect against exposure, rapid design and build execution, and direct 

interconnection to the utility’s 12.47 kV distribution circuit using a 1000 KVA, 3 phase, 

480V/12.8 kV (12.47 kV nominal) transformer. The PV system is ground mounted with 

5,376 fixed 225 W PV panels tilted at 21 degrees, and covers an area of approximately 5 

acres. There are four 250 kW bipolar inverters by Solaron with an AC operating voltage 

range of 480 V (432 to 528V), three-phase grounded wye connected. The operating 

frequency range is 57 to 60.5 Hz. One of KIUC’s main concerns with adding more solar 

to its system is the coordination with the underfrequency load-shedding schemes. ULlisted inverters typically will trip at the IEEE 1547 recommended settings of 59.3 Hz. 

KIUC would like the inverters to stay on line to coordinate with its load shedding 

scheme. Thus the Solaron inverter under frequency trip set-point is 57.0 Hz. The inverter 

under-voltage and over-voltage time delay is set to 2.5 seconds. 

Figure 4 3 depicts a simplified single-line diagram of the Kapa'a PV interconnection to 

KIUC 12.47 kV distribution system. 
18 

Figure 4-9: Simplified Kapa'a Single-line Diagram

Distribution Network: The mainland power grid uses very high transmission voltages 

(130 to 765 kV). Islands are smaller and generally transmit electricity at subtransmission 

levels (25 to 115 kV). The transmission system on Kaua’i is operated at 57.1 kV. 

Distribution substations around the islands contain transformers that reduce the voltage 

levels to the distribution voltage level of 12.47 kV. The distribution system was 

originally designed to deliver power in one direction — from the substation to the 

customer loads. 

Bulk power producers are generally large (greater than 10 MW) and connected at the 

subtransmission voltage level. Distributed energy resources are sources of electric power 

that are usually interconnected near the load to the electric power distribution system. 

They may also include distributed generation with distributed storage. 

The PV system is located approximately one mile from KIUC’s substation and the total 

length of the distribution feeder is approximately five miles. The daytime load on this 

distribution feeder is approximately 1.2 to 1.5 MW peak and night time loads are 2 MW 

peak. During sunny days, the PV system can supply approximately 90% of the demand 

required by the distribution circuit to which it is connected. The preliminary results in 

monitoring this circuit indicate that overall power quality has not been compromised. 

Interconnection of the PV System 

System Impact Studies: KIUC’s power modeling and simulation tools include Uplan, 

ASPEN Oneliner, Milsoft EA, and PSS/E. Currently, KIUC runs Uplan for its planning 

activities, PSS/E for powerflow and stability analysis, ASPEN Oneliner for short circuit 

and protection coordination studies, and Milsoft for Distribution Analysis. 
19 

One of KIUC’s primary concerns is with the IEEE Std 1547 over-frequency set point of 

60.5 Hz. As a small island system with a peak load of 70 MW, when system faults are 

cleared by the substation circuit breakers under load, frequency regularly exceeds 60.5 

Hz. When faults occur during daylight hours, large PV systems as well as the aggregate 

of smaller residential systems will trip off-line. Both PV customers and KIUC can realize 

a benefit if the IEEE Std 1547 (60.5 Hz) set point can be increased. PV customers can

stay connected through the event while KIUC would benefit from system stability. 

Distribution System Upgrades: Presently, there are no known upgrades to the 

distribution system. 

Effects of the PV System 

The initial results look very positive. According to KIUC, the monitored results on the 

distribution feeder on sunny days and cloudy days, with the PV system turned on and the 

PV system turned off, are showing very little difference in the voltage levels, harmonics, 

and overall power quality between the different scenarios. These preliminary results 

suggest that utilities could go to very high levels of PV penetration in localized areas 

without causing problems for the grid. 

Conclusions and Ongoing Studies

Utility Perspectives: KIUC continues to monitor power system events of this 

distribution feeder with high penetration of PV installed. At times the utility is supplying 

approximately 90% of a distribution load with PV during the day. To accurately monitor 

the steady-state and transient response of KIUC PV systems, KIUC has installed data 

acquisition to capture electrical and environmental data from the installed Kapaa PV 

system. The data recorded so far has indicated that voltage does vary, however, at the 

point of interconnection, the voltage remains within the tariff limits of +/- 5 percent of 

nominal. The data collection will help KIUC meet its goal of 50% of its electricity 

coming from renewables by 2023.
20 

4 Case Study: 2 MW Plant in Fontana, California

System Highlights

System Owner: Southern California Edison

Utility: Southern California Edison

System Integrator: Southern California Edison

System Size: 2.0 MWAC (prior to Dec. 2010)

Network Type: Radial 

Special 

Interconnection 

Requirements:

None

Figure 5-10: View of the 2.0 MW PV System Installed on a Warehouse Rooftop in Fontana, 

California (Photo courtesy Southern California Edison)
21 

Introduction

The 2.0 MW rooftop-mounted PV system in Fontana, California was the first installed 

and interconnected system in Southern California Edison’s (SCE) Solar Photovoltaic 

Program (SPVP). This program aims at installing a total of 500 MW of distribution 

connected PV systems within SCE’s territory by 2015. 

The PV system and interconnected distribution circuit described in this case study report 

is being studied under SCE's High-Penetration Photovoltaic Project. A report on the 

project is available and contains more information about integrating PV systems into the 

SCE distribution system5. 

SCE provided the technical information in this chapter. 

System Overview

Utility: Southern California Edison is one of the largest investor-owned utilities in the 

United States. It serves nearly 14 million people in the southern California including most 

of the greater Los Angeles area.

PV System: The Fontana PV plant denoted as SPVP #1 is located in a warehouse district 

in the city of Fontana. The system was procured, installed, and interconnected by SCE. 

The system interconnects to the distribution system using a transformer dedicated to the 

PV system. The system, although located on industrial warehouse rooftop, is not 

connected to the transformer serving the warehouse (i.e. the system is not a net energy 

metering installation). 

The installed system includes a total of 30,472 solar modules, 256 DC string combiner 

boxes, 12 master fuse boxes and four 500 kW inverters6

. The inverters each connect to 

200/480 V transformers that then connect in parallel to a single 480/12 kV transformer 

that interconnects with the local distribution system. 

Distribution Network: The Fontana PV plant is connected to the local 12 kV 

distribution system about one mile from the local substation. The entire length of the 

interconnected distribution circuit is 7.8 miles including all mainline and branch circuits. 

The distribution circuit serves primarily commercial customers as most of the area served 

by the circuit is a warehouse district. Near the end of the distribution circuit other types 

of commercial loads, such as retail shops in a mall, are served. 

Voltage regulation of the circuit is accomplished by switched capacitor banks placed 

along the length of the mainline of the distribution circuit. The capacitors are controlled 

using a time schedule with a voltage override. The voltage override operating set points 

are adjusted automatically if the ambient temperature, measured at the capacitor bank 

 

5 B. Mather, et. al, “Southern California Edison High-Penetration Photovoltaic Project – Year 1,” NREL 

Tech. Report – 5500-50875, 2011. 6 G. Rodriguez, “SCE Experience with PV Integration” presented at the EPRI/SEPA/SNL/NREL High 

Penetration PV Grid Integration Workshop, Tucson, AZ April 19th, 2012.
22 

controller, is above 90° F. Voltage regulation at the substation is also accomplished using 

switched capacitors located at the substation. The capacitors at the substation are 

operated to both regulate the voltage at the substation bus bars and compensate VAR 

flows in the subtransmission system. 

A representative one-line diagram of the distribution circuit that interconnects the 

Fontana PV system is shown in Figure 5-2. The circuit consists of an express overhead 

run of 653 ACSR (336 ACSR on the neutral) conductors running just past the PV system 

installation. Then the circuit continues to additional loads via primarily underground 

cabling. The mainline cabling is mostly 1000 mil JCN but tapers to 750 CLP near the end 

of the mainline circuit. Overall, with the PV system being nearly the first interconnection 

to the distribution circuit after it leaves the substation, and the large conductor size, 

means that the PV system is connected to a relatively stiff (from a voltage standpoint) 

interconnection. 

Figure 5-11: Fontana PV System, Substation, and Distribution Circuit

The peak load on the interconnected distribution circuit is approximately 4.2 MW 

resulting in a PV penetration of about 47%. As the load profile is dominated by 

commercial loads, specifically warehouses, the circuit loading on days when the 

warehouses are not operating, such as holidays and weekends, the circuit peak load for 

the day can be much lower. The peak loading for an off-peak day is estimated to be 2.6 

MW, resulting in a PV penetration above 75% for that day. 

Interconnection of the PV System 

System Impact Studies: SCE’s utility-owned PV systems installed under the SPVP were 

subject to the same application and study process that non-utility owned PV system 

installations were subject to. The SPVP systems were mostly, if not all, interconnected 

under the wholesale distribution access tariff (WDAT) process.

Distribution System Upgrades: No major distribution circuit upgrades were made 

during the interconnection process of the Fontana PV system. Although unconfirmed, it is 

likely that the capacitor bank controller settings were modified in order to mitigate some 

of the effects of variable generation caused by the interconnected PV plant. The capacitor 
23 

time delay settings, after capacitor operation, were likely reduced from a standard setting 

of 2 minutes to 30 seconds. 

Effects of the PV System 

SCE engineers investigated to see if the PV system resulted in reverse power flow 

conditions at the substation. Data, collected via the utility SCADA system, was collected 

and confirmed that no reverse power flow conditions were present at the substation. 

Conclusions and Ongoing Studies

Continuing Studies and Research: The circuit mentioned in this case study report was 

included in the SCE High-Penetration PV Integration Project because a number of other 

PV systems were likely to be interconnected during the course of the project. This has 

proven to be true as the aggregate nameplate generation of the interconnected PV plants 

on the circuit is now 5.5 MWAC. With the additional generation, the impact of the PV 

generators on the circuit has undoubtedly increased. As part of the SCE High-Penetration 

PV Integration Project, the circuit has been instrumented with high-speed voltage and 

current sensing data acquisition devices. This data will be used to quantify the impact of 

the installed PV systems on the circuit. Based on the impacts found the installed PV 

inverters will be modified to enable some forms of advanced inverter control (volt/VAR 

control, curtailment, etc.) in order to reduce the impacts of PV system interconnection on 

the distribution circuit.