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.

Contract No. DE-AC36-08GO28308

Southern California Edison 

High-Penetration Photovoltaic 

Project – Year 1 

Barry Mather and Benjamin Kroposki

National Renewable Energy Laboratory

Russell Neal

Southern California Edison

Farid Katiraei, Atousa Yazdani, and 

Julio Romero Aguero

Quanta Technology

Thomas E. Hoff, Benjamin L. Norris and 

Andrew Parkins

Clean Power Research

Richard Seguin

Electrical Distribution Design, Inc.

Colin Schauder

Satcon Technology Corporation

Technical Report

NREL/TP-5500-50875

June 2011
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.

National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Southern California Edison 

High-Penetration Photovoltaic 

Project – Year 1 

Barry Mather and Benjamin Kroposki

National Renewable Energy Laboratory

Russell Neal

Southern California Edison

Farid Katiraei, Atousa Yazdani, and 

Julio Romero Aguero

Quanta Technology

Thomas E. Hoff, Benjamin L. Norris and 

Andrew Parkins

Clean Power Research

Richard Seguin

Electrical Distribution Design, Inc.

Colin Schauder

Satcon Technology Corporation

Prepared under Task No. ARPB.HT22

Technical Report

N REL/TP-5500-50875

June 2011
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iii

Table of Contents 

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

2 Analysis of High Penetration Levels of PV into the Distribution Grid in California .................... 3

2.1 Selected Distribution Feeders for Study and Monitoring ................................................. 3

2.2 PV Interconnection Requirements ................................................................................... 5

2.3 SCE Circuit Operating Methodology ............................................................................... 6

2.3.1 Transformer Load Tap Changers (LTC) ................................................................... 7

2.3.2 Capacitor Banks ........................................................................................................ 7

2.3.3 Remote Control Switches ......................................................................................... 7

2.3.4 Voltage Adjustment Levels ....................................................................................... 8

2.3.5 Demand Response Programs .................................................................................... 8

2.4 Future Circuit Configuration and Characteristics ............................................................ 9

2.5 Advanced PV Inverter Features ..................................................................................... 10

2.5.1 Target Feature: Voltage Regulation ........................................................................ 10

2.5.2 Target Feature: VAr Control ................................................................................... 11

2.5.3 Target Feature: Power Curtailment ......................................................................... 13

2.5.4 Target Feature: Ramp Rate Control (During Connection/ Disconnection or Sudden 

Output Variation) .................................................................................................... 13

2.6 Classification and Generalization of Study Findings and Impacts ................................ 14

2.6.1 Similarity Measure .................................................................................................. 15

2.6.2 Data Pre-Processing ................................................................................................ 16

2.6.3 Correlation Examination ......................................................................................... 18

3 Distribution System Modeling and Simulation Tools for High-Penetration PV System 

Integration ......................................................................................................................................... 21

3.1 Part 1: Integration of PV into Distribution Modeling Tools .......................................... 21

3.1.1 Background ............................................................................................................. 21

3.1.1.1 PV Impacts on Distribution Studies ................................................................ 21

3.1.1.2 Load Flows with Distributed Generation ........................................................ 21

3.1.1.3 Protection Studies ............................................................................................ 22

3.1.1.4 Fault Location .................................................................................................. 22

3.1.1.5 Harmonic Analysis .......................................................................................... 22

3.1.1.6 Conservation Voltage Reduction ..................................................................... 22

3.1.2 Data Requirements .................................................................................................. 23

3.1.3 Limitations of Existing Tools ................................................................................. 23

3.1.4 Objective ................................................................................................................. 24

3.1.5 Approach ................................................................................................................. 24

3.1.6 Definition of Statistical Output Results .................................................................. 26

3.1.7 PV System Technical Data ..................................................................................... 26

3.1.8 Output Sample ........................................................................................................ 28

3.1.9 Next Steps ............................................................................................................... 29

3.2 Part 2: Distribution System Modeling and Simulation Requirements for Evaluating 

High-Penetration PV Integration .................................................................................... 29

3.2.1 Background ............................................................................................................. 29

3.2.2 Modeling Needs for High-Penetration PV Studies ................................................. 31

3.2.2.1 Component Immittance ................................................................................... 31

3.2.2.2 Load Estimation ............................................................................................... 31
iv

3.2.2.3 Power Flow ...................................................................................................... 32

3.2.2.4 Network Fault .................................................................................................. 32

3.2.2.5 Protection Coordination ................................................................................... 32

3.2.2.6 Power Quality .................................................................................................. 32

3.2.2.7 Harmonic Analysis .......................................................................................... 33

3.2.2.8 Flicker Analysis ............................................................................................... 33

3.2.2.9 Contingency Analysis ...................................................................................... 33

3.2.2.10 Reliability Analysis ......................................................................................... 33

3.2.2.11 Feeder Performance ......................................................................................... 33

3.2.2.12 Power Flow Assessment – Study Example ..................................................... 33

3.2.2.13 Network Fault Assessment – Study Example.................................................. 34

3.2.2.14 Penetration Limits............................................................................................ 35

3.2.3 Additional DEW Capability .................................................................................... 35

3.2.3.1 Penetration Limits and DER Technology Adoption Analysis Application ..... 35

3.2.3.2 Penetration Limits............................................................................................ 36

3.2.3.3 DER Technology Adoption Analysis Application .......................................... 37

4 Data Acquisition Requirements for Analysis of High Penetration Levels of PV into the 

Distribution Grid in California ......................................................................................................... 40

4.1 Introduction .................................................................................................................... 40

4.2 Distribution System Monitoring and Data Collection .................................................... 40

4.2.1 Feeder Modeling ..................................................................................................... 41

5 Advanced Inverter Technology for High Penetration Levels of PV Generation in Distribution 

Systems ............................................................................................................................................. 43

5.1 Introduction .................................................................................................................... 43

5.2 Utility Concerns about the Impact of High-Penetration PV on MV Feeders ................. 43

5.3 Capabilities of Inverters ................................................................................................. 45

5.3.1 Controlled Output Current ...................................................................................... 45

5.3.2 Grid-Smart Control Features ................................................................................... 48

5.3.3 Reactive Power Generation..................................................................................... 50

5.3.3.1 Inverter Reactive Power Generation Capability .............................................. 51

5.3.3.2 Inverter Output Power Control ........................................................................ 53

5.3.4 Effect of Inverter Output Power on Distribution Feeder Voltage ........................... 56

5.3.5 Simplified Distribution Feeder with Large PV System Connected ........................ 60

5.3.5.1 Steady State Analysis with Voltage Control at the PV System ....................... 61

5.3.5.2 Demonstration of Fast Automatic Voltage Control ......................................... 64

5.3.5.3 Fast Voltage Control for Flicker Reduction .................................................... 67

5.4 Main Issues Delaying or Blocking the Connection of Large PV Projects ..................... 69

5.5 Conclusions .................................................................................................................... 71

6 References ........................................................................................................................................ 73

Appendix A. Summary of Interconnection Requirements for SCE Distribution Systems ................ 74

Appendix B. Example XML Schema of Delivered Solar Resource Datasets ...................................... 81

Appendix C. Data Requirements for Distribution Feeder Model Development .................................. 83
1

1 Introduction 

The National Renewable Energy Laboratory (NREL), Southern California Edison (SCE), Quanta 

Technology, Satcon, Electrical Distribution Design (EDD), and Clean Power Research (CPR) 

have teamed together to analyze the impacts of high-penetration levels of photovoltaic (PV) 

resources interconnected onto the SCE distribution system. Specifically, SCE will be 

interconnecting a total of 500 MW of commercial scale PV by 2015 within their service territory 

through a program approved by the California Public Utility Commission (CPUC). Research 

efforts under this project include: 

• Development of distribution and PV system models required to evaluate the impacts of highpenetration PV 

• Identification and development of the necessary distribution system studies and analysis 

appropriate for determining the impacts of high-penetration PV 

• Data collection on study distribution circuits to quantify the impacts of high-penetration PV 

• Development of high-penetration PV impact mitigation strategies in the form of advanced 

inverter functions to enable high-penetration PV interconnection 

• Lab testing of advanced PV inverter functions 

• Field testing of advanced PV inverter functions. 

In the first year of the project, research efforts have focused on (1) identifying the needed PV 

system models and distribution system analysis tool capability, (2) identifying prospective 

distribution circuits within the SCE service territory to be studied, (3) understanding the 

challenges of integrating high-penetration PV levels onto the SCE distribution system, (4) 

identifying appropriate data acquisition equipment, and (5) investigating the capability of PV 

inverters to realize advanced inverter functions that may be useful for mitigating highpenetration PV impacts on the SCE distribution system. 

Section 2 of this report describes the need for investigating high-penetration PV scenarios on the 

SCE distribution system. A few of the expected impacts of high-penetration PV are described, 

and typical distribution system operation is explained. Two study distribution circuits are also 

identified in this chapter and discussed in terms of the expected PV penetration levels attained as 

SCE builds out the 500 MW of installed PV within their service territory. 

The necessary PV system modeling and distribution system simulation advances are discussed in 

Section 3. To properly simulate high-penetration PV operation on a distribution circuit, the 

expected solar resource of a given PV installation needs to be determined. The first part of 

Section 3 outlines how solar resource data, collected through remote sensing satellites, can be 

processed and formatted for inclusion in a distribution system modeling tool such as Distributed 

Engineering Workstation (DEW), CYMDIST, or Synergee. The second part of Section 3 

describes the additional functionality required of the distribution system modeling software 

package itself to properly and effectively evaluate high-penetration PV scenarios. 

Section 4 describes the available distribution circuit data available for the two study distribution 

circuits identified in Section 2. Data acquisition on the study distribution circuits is required to 
2

quantify the impacts of high-penetration PV installations and to verify distribution system 

models of the study feeders developed during the course of this project. Locations of additional 

data acquisition systems, capable of measuring medium voltage (15 kV Class) line voltage and 

phase current, also are identified. 

The PV inverter is the active control component within a single PV installation. As such, its 

characteristic operation determines the overall behavior of the PV system from the perspective of 

the distribution circuit to which it is connected. Section 5 discusses the additional inverter 

functionality that could be implemented in order to specifically mitigate some of the undesirable 

distribution system impacts caused by high-penetration PV installations. 
3

2 Analysis of High Penetration Levels of PV into the 

Distribution Grid in California 

This section provides supportive material and information required to facilitate various activities 

of the high-penetration PV project including (1) data requirements for modeling and simulation 

studies, (2) a summary and highlights of SCE distribution system design, operation 

methodologies, and interconnection requirements, and (3) a brief review of desired features for 

the next generation of PV inverters from the utility engineers’ point of view. 

Because only two or three distribution circuits (feeders) will be selected and studied under the 

limited scope of the project, this report also describes a generalization and classification method 

to characterize any distribution feeder in the SCE territory in terms of the level of similarity to 

the studied feeders. This approach can be used to identify expected PV integration impacts and 

mitigation solutions on other feeders with common attributes. 

The information provided in this section presently is a work in progress and may include 

additional information as identified throughout the course of the project. 

2.1 Selected Distribution Feeders for Study and Monitoring 

Presently, two 12.0 kV distribution feeders that already include utility scale PV installations have 

been selected for inclusion in this project. Various feeder characteristics and existing/expected 

number of PV systems were considered as part of the selection criteria. The selected study 

feeders can also be defined as typical representations of 12.0 kV feeders for the SCE distribution 

systems, which have high PV penetration potential due to the type of commercial buildings with 

large roof-top areas suitable for PV installations. 

The first study feeder, denoted as the Fontana, CA study feeder due to its approximate location, 

is a 12.0 kV feeder supplying an area with dominant commercial loads (Figure 2-1) fed from a 

66 kV substation. The feeder includes three switched (automatic) capacitor banks. The Fontana 

2.0 MW roof-top PV system is the first roof-top PV installation by SCE constructed under SCE’s 

Solar Photovoltaic Program (SPVP). It is also expected that a total of 5.5 MW of PV generation 

will be added to the study feeder by the end of 2011. The Fontana PV system is electrically 

located close to the substation as it is at the end of an express feeder line section with a length of 

approximately one mile. The PV system is on the first part of the main feeder trunk before any 

branches and there are very few customers between the PV system location and the substation. 
4

Figure 2-1. Schematic representation of the study feeder in Fontana, CA. 

The second selected study feeder is located in Chino, CA and connects an existing 1.0 MW rooftop PV installation. This feeder is supplied from a 66 kV substation through a considerable 

length of the mainline feeder as shown in Figure 2-2. This feeder is expected to include an 

additional 3.0 MW of roof-top PV, partly based on current installations as part of the SPVP 

program (0.75 MW) and additional PV installations presently in the interconnection queue (2.25 

MW) based on power purchase agreements with independent producers. 

The PV system location for the Chino, CA feeder is toward the end of the feeder after some 

major customer loads. This feeder also includes four switched capacitor banks. 

Figure 2-2. Schematic representation of the study feeder in Chino, CA. 
5

The PV system specifications for each of the selected feeders are provided in Table 2-1 and 

Table 2-2 [1]. 

Table 2-1. PV Source Specifications. 

System Customer_ID Manufacturer Model Quantity Surface Area

SPVP 1 Fontana First Solar FS272, Cadmium-Telluride Thin-Film ~33700 600000 sq ft

SPVP 2 Chino First Solar Thin-Film TBD 458000 sq ft

PV Module

TBD: To be determined

Table 2-2. PV System ac Specifications. 

System Customer_ID Manufacturer Rating Model Quantity

SPVP 1 Fontana Satcon Tech Group 500kVA, 600Vdc, 480Vac #AE-500-60-PV-A 4

SPVP 2 Chino Xantrex 250kVA, 300Vdc, 200Vac TBD 4

Inverter

TBD: To be determined 

2.2 PV Interconnection Requirements 

The SCE Interconnection Handbook [2] and California Rule 21 [3] provide the general design, 

interconnection, and operating requirements for connecting and operating a generation facility in 

parallel with SCE’s distribution networks. Appendix A provides a summary of the requirements 

based on these references for a generation system with an aggregated size of 200 kVA or higher 

that is connected to systems with voltage levels of 34.5 kV or lower. The utility scale roof-top 

PV installations primarily fall into this category. 

Table 2-3 outlines the main aspects of SCE design and interconnection requirements, which are 

applicable for large scale solar PV integration onto distribution feeders. The focus is on those 

requirements that may affect the operation and/or power quality of the distribution grid as a 

result of integrating a PV system to the conventionally designed feeders. In Table 2-3 the point 

on the distribution system at which the utility and the customer interface is referred to as the 

point of common coupling (PCC). The utility energy meter location and connection is often 

synonymous with the PCC of an interconnection. 

 
6

Table 2-3. General Requirements for 200 kVA and Higher System (Plant) Connecting to 34.5 kV or 

Lower Voltage Level. 

Requirements Reference/Range/Solution Comments

Standards and regulatory 

compliance 

• SCE Interconnection Handbook 

• California Rule 21 

• Joint NERC & WECC standards 

• CAISO & SCE reliability requirements 

SCE Interconnection Handbook 

includes provision from IEEE 

1547 & UL1741 and IEEE 929-

1999 for utility interactive PV 

systems 

Unity power factor For generating units with P < 10 MW; at 

the interconnection point 

Through the generation source 

and/or additional VAr control 

device 

Interconnection equipment Dedicated transformer 

Transformer configuration • Delta high side 

• Ground band for 4 wire systems 

• Ground fault detector for 3-wire 

systems 

Transformer should be equipped 

with no-load taps for ± 5% 

adjustment of ratio in 2.5% steps 

Voltage range ± 5% of nominal feeder voltage The plant should not cause 

voltage deviations beyond this 

level 

Reactive power 

requirements 

• Ability to deliver ± 0.95 power factor 

at the interconnection point 

• The maximum voltage rise ≤ 1% per 

step change in reactive power output 

of a generation facility 

Except for the reactive power 

demand of facility load, inverter 

source should not impose any 

additional reactive power burden 

on the grid 

Voltage imbalance Less than 1% at PCC in steady-state Worst case < 1.5% 

Harmonics IEEE 519-1992 & IEEE 1547-4.3.3. 

Flicker IEEE 519-1992 & IEEE 1547 4.3.2 

Response to grid faults 

and/or loss of main 

(islanding) 

Immediately cease operation (IEEE 

1547) 

Upon islanding or faults on the 

interconnecting feeder, single 

facility generation can separate 

its own load from the grid and 

continue supplying load 

2.3 SCE Circuit Operating Methodology 

SCE distribution feeders can be categorized in three voltage classes of 4.7 kV, 12 kV, and 21 kV. 

Most distribution substations are connected to either 66 kV or 115 kV high voltage systems. 

Among all distribution systems, the dominant category is 12 kV feeders supplied from 66 kV 

substations. 
7

2.3.1 Transformer Load Tap Changers (LTC) 

In a typical SCE distribution system, a load tap changer (LTC) is not used on substation 

transformers connecting to 66 kV systems. Substations connecting to 115 kV systems will be 

equipped with a LTC. Because all the distribution feeders of interest in this project are supplied 

from 66 kV substations, any effect of high-penetration PV installation on LTC operation may 

need to be investigated separately. 

The 115 kV LTCs typically regulate the voltage at the distribution bus (LV side of substation 

transformer) without load drop compensation. The reference voltage is typically set at 122 Vac 

with a bandwidth of ±1.5 V. The tap changer delay may vary in the range of 30 to 90 seconds, 

depending on the application and the coordination requirement with any downstream voltage 

regulator. 

2.3.2 Capacitor Banks 

The SCE general practice is to install capacitor banks as required on distribution feeders as a 

preference to voltage regulators. In addition to substation-level capacitor banks (typically two 

banks), generally three or more capacitor banks may be found along the feeders to reduce the 

reactive power demand from high voltage systems (e.g. 66 and 115 kV systems). 

SCE uses commercial capacitor bank controllers from Fisher Pierce, S&C, and Cooper 

Industries. The capacitor bank controllers operate based on voltage control with a time or a 

temperature offset to enhance daytime operation. The voltage control has override capability to 

disconnect or re-connect, respectively, on voltage increase or decrease beyond a pre-set range. 

Once disconnected on voltages beyond the high-level threshold, a pre-specified delay is applied 

to prevent instantaneous reconnection of a capacitor bank on possible voltage fluctuations. 

However, for disconnection on excessive voltage increase, typically no additional delay is 

applied beyond the capacitor bank internal measurement, filtering, and processing time. 

The capacitor bank controller uses the voltage measurement from a single-phase voltage 

transformer (PT) to determine the feeder voltage. The phase connection of the capacitor bank PT 

is not generally identified on the drawings or in the records. These PTs are typically connected 

phase-to-phase. There may be some general practices suggested in the SCE distribution design 

guidelines (e.g. utilizing phase A&B connection always), but the practices are not routinely 

applied to all feeders and connections. 

2.3.3 Remote Control Switches 

A remote control switch (RCS) is an automated voltage controlled disconnect switch with the 

ability to open or close on a remote operator command. Typically, a RCS operates on loss of 

voltage with delay and uses single-phase voltage measurement for disconnection. Upon loss of 

voltage for a pre-specified period, an RCS operates and disconnects all three phases (three-phase 

gang-operated switching). The operating delay of RCSs is time coordinated with the recloser 

timer. The switch on/off position is communicated through the SCADA system. No phase 

voltage measurement is available from the RCSs via SCADA communication. 

As shown in Figure 2-3, most average length feeders have one recloser located close to the 

substation and an RCS located about halfway (electrical load) on the backbone feeder or on any 
8

major laterals. Also, there will be additional RCSs with normal open (N.O) position at 

interconnection points with adjacent feeders to facilitate load transfer when required. 

Figure 2-3. Utilization of reclosers and RCSs on distribution circuits. 

Following a line fault and feeder clearing, typically a recloser utilizes two reclosing attempts (at 

5 s and 55 s, approximately). After 30 s from time of voltage loss, about 25 s from the first 

reclosing shot and unsuccessful reclosing attempt, a downstream RCS disconnects the second 

half of a circuit. The second reclosing attempt tends to pick up the upstream load between the 

opened RCS and recloser location. If the reclosing is unsuccessful, a distribution operator can 

conclude that a fault is between the recloser and the RCS location. By observing the status of an 

RCS and a recloser, and based on the load level and available capacity of an adjacent feeder, the 

operator can decide whether to close or not close the intertie RCS to transfer the load 

downstream of the first RCS to an adjacent feeder. 

2.3.4 Voltage Adjustment Levels 

Presently, SCE does not use any active voltage control on their distribution feeders. The nearfuture plan is also to optimize the set points for voltage regulating devices (LTCs, capacitor 

banks, voltage regulators, etc.) off-line and set them once at pre-specified values based on 

reactive power and loss conservation criteria. The set points may be revisited occasionally if 

there is any planned maintenance or modification to a feeder. 

In general, to achieve conservation voltage reduction (CVR), SCE practice is to set capacitor 

banks and/or transformer taps to operate the distribution circuits at the lowest permissible 

voltage range of 114 V to 120 V. The objective is to passively reduce load and losses by 

operating at the lowest permissible voltage level. 

2.3.5 Demand Response Programs 

SCE has many different types of demand response programs with customer engagements at 

various levels. The primary demand response programs that may be applicable to some 

customers on the selected study feeders are: 

• Radio broadcast air-conditioning unit cycling (automatic) 

• Customer initiated load curtailment—based on system operator phone calls to customer to 

apply previously negotiated level of load reduction to avoid complete power outage of the 

customer facility (applicable to commercial and industrial customers). 
9

2.4 Future Circuit Configuration and Characteristics 

SCE presently has no major upgrade plan or proposed changes in the general distribution feeder 

designs to address any potential enhancement that may facilitate high-penetration PV system 

integration. However, as part of SCE distribution Smart Grid initiatives, SCE has engaged in two 

projects involving advanced distribution automation and active voltage control that may provide 

some insight into future distribution system designs. The two projects are (1) Avanti circuit of 

the future [4], and (2) Irvine Smart Grid demonstration (ISGD) project [5]. 

Figure 2-4 shows a schematic diagram of the Avanti circuit. The circuit design includes a 

distribution level dynamic reactive power compensator to provide voltage and VAr support. The 

selected circuit is also equipped with solid-state fault current limiter, remote control switches, 

and fault interrupters to facilitate integration of distributed generation and protection 

coordination. The project objective was to demonstrate an integrated design, interoperability of 

various control devices, and operational features that can be achieved in distribution circuits 

equipped with intelligent devices, coordinated and operated through a SCADA system. 

Figure 2-4. Schematic diagram of Avanti circuit of the future [5]. 

Figure 2-5 shows a schematic diagram of the ISGD project implemented on part of the UC Irvine 

campus. The customer loads are distributed on two adjacent feeders (Arnold and Rommel) that 

can be operated as a closed or an open loop. Universal remote control interruption devices 

(URCIs) with two-way communication infrastructure are provisioned to change circuit topology 

and transfer loads from one circuit to another during faults and contingency conditions. The 

project includes several subprojects targeting specific Smart Grid aspects such as (1) automatic 
10

volt/VAr control, (2) utilization of community-level energy storage for distribution constraint 

management, and (3) advanced control and protection strategies for self-healing circuits. 

Figure 2-5. Schematic diagram of ISGD project [6]. 

2.5 Advanced PV Inverter Features 

The following is a list of targeted and desired advanced features to be supported by intelligent 

PV inverters in order to reduce (or eliminate) adverse impact on power quality of the system as 

well as to enhance interaction with the grid. The recommended features are based on discussions 

with SCE distribution engineers and/or collected from review of relevant literature on the 

subject. For each feature, the control/operation objectives and expected impacts are described. 

2.5.1 Target Feature: Voltage Regulation 

Objective: To regulate the voltage at the point of common coupling during PV output 

fluctuations to maintain the voltage profile of the feeder within acceptable range. 

Quantity(ies) involved: Inverter voltage and reactive power output; voltage at PCC. 

Expected positive impact(s): Eliminate or reduce impact of a PV system on feeder voltage 

variations and support voltage quality at the customer site, especially for PV system installations 

toward the end of a feeder. The PV inverter can potentially act as an active filter to mitigate other 

power quality issues caused by non-linear loads, such as flicker and voltage sag/swell. 

Large 

Transportable 

Energy Storage

Battery Storage

URCI

I I RCS

Substation

CB

CB

URCI

URCI

URCI

4 3

1 2

..

.. .. .. ..

..

CB Circuit Breaker

Universal remote control 

interruption device (URCI)

I I Remote control switch (RCS)

Circuit 1

Circuit 2

Distribution XFMR

.

.
11

Potential adverse impact(s): Additional complexity in interconnection studies, higher degree of 

possible interactions with other voltage regulating devices, supervisory control and coordination 

requirements. 

Inverter changes: 

• Hardware changes: capacitor size or inverter topology to accommodate higher levels of 

reactive power support (common change aspect for any feature involving reactive power). 

Depending on the inverter topology and if it is not already oversized, the ratings of the power 

electronic switches may need to be increased to accommodate a reasonable amount of 

reactive power contribution at full active power. 

• Software changes: addition of voltage control loops and user-selectable (or communicated) 

set points. 

• Control schemes and requirements – reference control, voltage droop control, impedance 

measurement: 

o PV inverter may use control algorithms such as droop control or output 

impedance synthesis to determine voltage regulation needs. 

o The voltage control is primarily performed by an inverter supervisory control 

system to provide fast (sub-second) response. 

o A centralized dispatch of control modes and set points can be utilized in a multiinverter situation, or to coordinate inverter voltage regulation effect with slow 

responses of other existing voltage-regulating devices on the same feeder 

(capacitor banks and line voltage regulators). 

o A slow-acting and narrow bandwidth communication system may be needed due 

to low priority of data communication and usage (to transmit dispatch set points 

or control modes only). 

Other considerations and features: Communication with system operator or among devices to 

enable (1) status update of other voltage regulating devices and (2) regulating voltage at a 

selected point of the feeder rather than at the PCC. 

2.5.2 Target Feature: VAr Control 

Objective: To control reactive power output of a PV inverter to sink or source reactive power as 

a function of PV active power output variations, changes in the system, or by following prespecified reactive power generation profiles. 

Control modes and requirements: Based on applications, size of PV inverters, and operational 

desires, various VAr control modes can be defined. 

• Static VAr control – This control mode primarily adjusts inverter power factor (pf). The 

power factor can be fixed, pre-scheduled or communicated set points. This control mode can 

be utilized when periodical (e.g. seasonal) adjustment of power factor based on variations in 

a feeder load or feeder configuration is desired. Distribution operators may use a supervisory 

controller to broadcast or multicast the power factor set points to several PV inverters. Note 
12

that inverter operation at unity power factor as currently prescribed by IEEE 1547.1 can be 

achieved with this control mode. 

• Dynamic VAr control – This control mode automatically determines the reactive power 

output of a PV inverter based on pre-defined reactive power control algorithms and/or 

optimization strategies. The major application area desired by utility experts is to utilize 

dynamic VAr to cancel out or smooth out voltage fluctuations caused by power intermittency 

of PV inverters. Dynamic VAr control can also be utilized to compensate voltage drop on 

part of a feeder to achieve a flat voltage profile or reduce feeder losses. Dynamic VAr control 

mode may also be defined as a function of fast reactive power variations of a non-linear load 

to act as a distribution VAr compensator device. 

• Emergency (maximum) VAr control – This is a control mode highly desired for utility 

operation during system contingency to provide maximum reactive power support and 

prevent voltage collapse. In this control mode, upon distribution operator request, each PV 

inverter supplies the maximum available reactive power output without reducing the active 

power output or violating the voltage limits. The target is to support transmission VAr 

emergency demand. 

Quantity(ies) involved: Inverter active and reactive power output; indirect effect of system 

voltage, measured at PCC or load center (communicated). 

Expected positive impact(s): 

• Eliminating the adverse effect of PV inverters on feeder voltage increase. 

• Reducing the number of tap-changer operations for LTCs and voltage regulators and/or 

capacitor bank operations. 

• Actively contributing to and facilitating implementation of volt/VAr control strategies. 

Potential adverse impact(s): 

• Additional complexity in system design and interconnection studies. 

• Details of control modes and inverter behavior may vary widely by inverter design from one 

manufacturer to another. This aspect would potentially affect real-world operation and 

coordination. 

• Potential of dynamic interactions among multiple PV inverters with different control modes 

and responses. 

• Complexity in calculating availability and reliability of reactive power capacity for 

emergency use. This is mainly because all control modes assign the priority to active power 

generation; hence, there may not be any tangible capacity available from PV inverters to 

supply reactive power when needed (unless inverters are oversized). On the other hand, the 

PV inverter owner or operator may also override the reactive power control capability to 

maximize production. 
13

2.5.3 Target Feature: Power Curtailment 

Objective: The main objective of this feature is to provide some degree of dispatchability in PV 

inverters in terms of active power output reduction. The primary application of this control 

feature is aimed at enabling utility operators to control the aggregated effect of total generation 

on distribution feeders during contingency conditions. A distribution operator can use this 

control mode to throttle back fast-acting generation to an aggregated reduced level rather than 

shutting down PV inverters or transmission connected systems. 

Quantity(ies) involved: Inverter active power output, dc link voltage, and maximum point of 

power tracking schemes. 

Expected positive impact(s): 

• Additional degree of flexibility for utility operators. 

• Reducing the voltage rise effect, as necessary, beyond the control limits achievable based on 

reactive power limits. 

• Managing (preventing) unexpectedly large reverse power flow due to sudden loss of large 

loads. 

• Loss reduction. 

Potential adverse impact(s): 

• Potential voltage drop and under-voltage issues on part of a feeder. 

• Loss of a large amount of renewable energy generation if there is no provision for energy 

storage resulting in uncaptured revenue for PV system owner. 

2.5.4 Target Feature: Ramp Rate Control (During Connection/ 

Disconnection or Sudden Output Variation) 

Objective: This control feature can be used during fast power fluctuations caused by cloud 

effects or during start-up and shut-down of large PV inverters to balance the level of generation 

and load in the entire system. The maximum ramp rate of a system is typically determined by 

available spinning reserve and has to be oversized if there is no provision for power and load 

balancing by addition of PV systems. PV ramp rate control prevents change in spinning reserve 

requirements due to fast fluctuations of PV inverter outputs or sudden connection and 

disconnection of a large aggregated amount of PV generation. 

Quantities and requirements: Active power output, dc link voltage, and active power controls. 

• Implementing this feature requires a means of providing short-term storage based on the 

expected fluctuation rates for a PV system. 

• Ramp rate control may be used by independent system operators (ISOs) to achieve frequency 

regulation for a system under stress. 
14

• Reliable and accurate weather forecasting methods to determine cloud patterns and plan 

(coordinate) operation of various resources is also required and can enhance proper 

utilization of PV inverter ramp rate control. 

Expected positive impact(s): 

• Reducing the overall spinning reserve capacity requirements. 

• Minimizing down-time of renewable energy sources. 

• Contribution to frequency regulation of a system. 

Some of the desirable (wishful) features for the PV inverter controls are: 

• Low voltage and fault ride-through. 

• Islanding and microgrid operation capability. 

Characteristics of low voltage and fault ride-through for distribution applications are not well 

defined yet. The principal objective of these features is to prevent frequent disconnection of PV 

inverters during system transients that may cause significant voltage and frequency variations. 

The main target is to prevent adverse impact of transients originated from high voltage system to 

continue to support the load demand during such situations. 

Intentional islanding and microgrid operation is a practice recommended by some utilities to 

enhance customer-based reliability during sustained power outages. Incorporating this feature in 

a PV inverter requires a means of frequency regulation and low following capability. Although 

the control feature already exists in stand-alone PV inverters with battery storage, it is not 

typically implemented on large scale PV inverters due to the cost of energy storage and the 

additional hardware to perform simultaneous voltage/frequency regulation. The inverter (and 

microgrid) protection methodology and fast/accurate islanding detection schemes are some other 

barriers that are not well established. 

2.6 Classification and Generalization of Study Findings and Impacts 

SCE’s distribution system has more than 4,000 circuits. Given the fact that studying impacts of 

PV-based distributed generation (PV-DG) on all distribution feeders is neither practical nor 

economically feasible, the objective of the proposed classification methodology is to generalize 

the results of impact studies performed on a single feeder to a set of feeders with similar 

characteristics. The assumption is that impacts and mitigation measures for this set of feeders 

would be similar to those identified for the studied feeder. 

The methodology uses geographic and statistical analysis to determine the similarity of a large 

set of non-studied feeders with respect to a small set of studied feeders. Then it ranks all nonstudied feeders as a function of a similarity measure. Finally, for each studied feeder, it selects 

the group of most similar non-studied feeders on the basis of a customer-defined threshold. 

Study of the impact of PV-DG on each studied feeder, and appropriate weighting of the results, 

will provide an accurate picture of overall impacts on the utility system. 

The distribution system’s diversity of equipment, types of circuit configurations, voltages, and 

the study of the customers’ geographic and demographic variations are used to determine and 
15

evaluate the similarity measure used in the classification method. The features of the summary 

data on SCE distribution systems and customer base are shown in Table 2-4. 

Table 2-4. SCE T&D System Summary Features.1

OH Main Line Miles OH Trans Count 2006 Peak Date 

UG Main Line Miles OH Trans kVA 2007 Peak Date 

OH 3 Phase Miles UG Trans Count 2008 Peak Date 

UG 3 Phase Miles UG Trans kVA Automated kVAr 

Voltage OH Manual Switch AR Count 

Weather Zone Tie Count OH RCS 

Customer Count CI 2006 UG RCS 

2006 Actual Peak CI 2007 Substation Name 

2007 Actual Peak CI 2008 Switched kVAr 

2008 Actual Peak CMI 2006 Fixed kVAr 

OH Miles CMI 2007 Total kVAr 

UG Miles CMI 2008 Burd Switch 

Total Miles UG Manual Switch 

2.6.1 Similarity Measure 

The most commonly used similarity measure is Euclidean distance: 

( ) 22 2

11 2 2 , i j i j ip jp dij x x x x x x = − +− + − 

where ( ) 1 2 , ,, i i ip i xx x =  and ( ) 1 2 , ,, j j jp j = xx x  are two circuits with p attributes considered 

for comparison. 

Euclidean distance is suitable for objects with all numerical information since it requires 

mathematical calculations. However, the summary data of SCE circuits contain not only 

numerical information but also categorical information. For instance, weather zone 2 doesn’t 

mean that it is greater than weather zone 1. 

To determine the similarity of two circuits with mixed numerical and categorical information, the 

similarity measure d i( ) , j is defined as2

: 

( )

( )

1 ,

p f

ij f

d

dij

p

= = 

 

1

 OH = Overhead, UG = Underground, CI = Customer Interruptions, CMI = Customer Minutes of Interruption, 

AR = Automatic Recloser, BURD = Buried Underground Residential Distribution. 

2

 “Data Mining: Concepts and Techniques,” Jiawei Han and Micheline Kamber, Morgan Kaufman, 2005. 
16

If f is a numeric variable: 

( )

max min

if jf f

ij

h hf h hf

x x

d

x x

− = −

where h runs over all non-missing objects for variable f . 

This equation shows the percentage of the distance between two specific numerical variables to 

the maximum possible distance between them. 

If f is a categorical variable:

( ) 0, 

1, otherwise

f if jf

ij

x x

d  = = 



This equation indicates that if two categorical variables match with each other, the distance 

between them is 0; otherwise, the distance between them is 1. 

With the similarity measure defined above, the differences of any circuit attribute between two 

feeders ( ) f

ij d are normalized. For categorical attributes, ( ) fij d is either 0 or 1. For numerical 

attributes, ( ) f

ij d ranges between 0 and 1. Therefore, it is not necessary to further implement a 

normalization process. 

2.6.2 Data Pre-Processing 

Weighting 

Multiple circuit attributes representing the feeder characteristics have been used to evaluate the 

similarity measure. Not all of the attributes are equally important in presenting feeder 

characteristics, so appropriate weighting is required. The weighting strategy is closely related to 

the type of study to be carried out. For example, peak load and customer count are more 

important features for studying the impact of high penetration of photovoltaic-based distributed 

generation (PV-DG), but protective devices are more important for studying system reliability. 

Four levels of importance have been defined for this type of study: most important, important, 

good to consider, and not necessary. The attributes included in each category are shown in Table 

2-5, Table 2-6, Table 2-7, and Table 2-8, respectively. 
17

Table 2-5. "Most Important" Data Fields. 

Data Field Weight Label 

OH Main Line Miles Most important

UG Main Line Miles Most important

OH 3 Phase Miles Most important

UG 3 Phase Miles Most important

Voltage Most important

Weather Zone Most important

Customer Count Most important

2006 Actual Peak Most important

2007 Actual Peak Most important

2008 Actual Peak Most important

Table 2-6. "Important" Data Fields. 

Data Field Weight Label

OH Miles Important 

UG Miles Important 

Total Miles Important 

OH Trans Count Important 

OH Trans kVA Important 

UG Trans Count Important 

UG Trans kVA Important 

Table 2-7. "Good to Consider" Data Fields. 

Data Field Weight Label 

OH Manual Switch Good to consider

Tie Count Good to consider

CI 2006 Good to consider

CI 2007 Good to consider

CI 2008 Good to consider

CMI 2006 Good to consider

CMI 2007 Good to consider

CMI 2008 Good to consider

2006 Peak Date Good to consider

2007 Peak Date Good to consider

2008 Peak Date Good to consider

Automated kVAr Good to consider
18

Table 2-8. "Not Necessary" Data Fields. 

Data Field Weight Label

AR Count Not necessary

OH RCS Not necessary

UG RCS Not necessary

Substation Name Not necessary

Switched kVAr Not necessary

Fixed kVAr Not necessary

Total kVAr Not necessary

Burd Switch Not necessary

UG Manual Switch Not necessary

The circuit attributes are grouped into different categories according to their contribution to the 

feeder characteristics for this particular type of study. The "most important" group has the 

highest weight followed by the "important" group, then the "good to consider" group, and last the 

"not necessary" group. The attributes within one group are assigned the same weight. Higherweight feeder features have more influence in determining the similarity of two circuits than 

lower-weight features do. In other words, the algorithm tends to group circuits into the same 

class if their high-weight attributes are closer. 

2.6.3 Correlation Examination 

Some circuit attributes are fully dependent on other attributes. For example, given any two of the 

overhead line mileage, underground line mileage, and total line mileage, the value of the third 

can be calculated. Therefore the total line miles and the percentage of overhead lines are used in 

the study. 

Some circuit attributes are highly correlated with other attributes. For instance, the 2008 actual 

peak load of a feeder may be generally close to its peak load from 2007 and 2006. Table 2-9 

shows the correlation among these three attributes. As a result, the 2006–2008 average peak load 

is used instead of individual year peak loads to indicate the electric usage of customers of this 

feeder. 

Table 2-9. Correlation Matrix for 2006–2008 Actual Peak. 

2006 

Actual Peak 

2007 

Actual Peak 

2008 

Actual Peak 

2006 Actual Peak 1.0000 0.8008 0.7179 

2007 Actual Peak 0.8008 1.0000 0.7906 

2008 Actual Peak 0.7179 0.7906 1.0000 

Excluding the feeder attributes that are closely related to other attributes can not only reduce the 

data dimension and expedite the computation process (because the dependent attributes are not 

providing more information) but it also can alleviate the potential impact of these dependent 

attributes on the weighting strategy (because redundant information is counted multiple times in 

measuring the similarity of two circuits). 
19

The final feeder feature set used in the analysis is shown in Table 2-10 with variable type and 

corresponding importance shown as well. The fields shown in bold and italic are the ones that 

have been modified as described above. 

Table 2-10. Data Fields Used in Cluster Analysis and Their Weights. 

Data Field Variable Type Weight Label 

OH Main Line Miles Numerical Most Important 

UG Main Line Miles Numerical Most Important 

OH 3 Phase Miles Numerical Most Important 

UG 3 Phase Miles Numerical Most Important 

Voltage Categorical3

 Most Important 

Weather Zone Categorical Most Important 

Customer Count Numerical Most Important 

2006-2008 Average Peak Numerical Most Important 

% of OH Miles Numerical Important 

Total Miles Numerical Important 

OH Trans Count Numerical Important 

Average OH Trans kVA Numerical Important 

UG Trans Count Numerical Important 

Average UG Trans kVA Numerical Important 

OH Manual Switch Numerical Good to consider 

Tie Count Numerical Good to consider 

2006-2008 Average CI Numerical Good to consider 

2006-2008 Average CMI Numerical Good to consider 

2006 Peak Month Categorical Good to consider 

2007 Peak Month Categorical Good to consider 

2008 Peak Month Categorical Good to consider 

Automated kVAr Numerical Good to consider 

Figure 2-6 shows the flow chart of the classification algorithm. It is worth mentioning that 

depending on how the studied feeders are selected, it is possible that a non-studied feeder ended 

up being classified as similar to more than one studied feeder. If this is the case, the highest 

similarity measure will be used to finalize the classification and assign the non-studied feeder to 

a single similarity set. 

 

3

 It can be treated as numerical variable as well. 
20

Figure 2-6. Flow chart of classification algorithm. 

Select studied feeder 

Evaluate similarity measure 

for all non-studied feeders 

Are there more 

studied feeders 

Rank non-studied feeders as 

a function of similarity 

measure

Classify non-studied 

feeders using threshold 

No 

Yes 

Classify non-studied feeders 

that are similar to more 

than one studied feeder

Classification 

results
21

3 Distribution System Modeling and Simulation Tools for 

High-Penetration PV System Integration 

As the penetration level of interconnected PV systems increases on a distribution system there is 

an increasing need for both accurate models of the solar resource and advanced distribution 

system analysis tools to evaluate high-penetration PV system impacts. This report provides 

initial assessments of solar resource data for use in distribution system studies and addresses the 

capability of existing distribution system modeling tools. 

3.1 Part 1: Integration of PV into Distribution Modeling Tools 

Software tools that model hourly production of PV systems have grown substantially in usage 

over the past decade, driven by the growth of the industry itself. These tools have supported the 

calculations of hourly and monthly PV energy production and the financial modeling necessary 

to determine cost-effectiveness. Tools have likewise evolved to support online processing of PV 

incentive programs, the incorporation of satellite-derived irradiance data (rather than groundmounted measurements or Typical Meteorological Year [TMY] data), and features such as 

performance monitoring. 

All of these advancements have been oriented around individual PV systems: the amount of 

energy produced by a system, economic payback of the system, etc. Until now, tools to model 

the behavior of multiple systems – or PV "fleets" – has been lacking. The work described in this 

report may therefore be considered as the introduction to a new class of PV software related to 

the behavior of PV fleets. 

3.1.1 Background 

Utility distribution engineers responsible for the design of safe, efficient, and cost-effective 

distribution systems have historically used tools that model lines and components (such as 

switches, capacitors, and transformers) under specific loading conditions, in particular the "peak" 

hour. In some cases, distributed generators have had to be modeled to adequately account for 

their impacts on load flows. 

Distribution engineering tools, however, have generally not included support for PV modeling. 

The present work is intended to address this omission. With the continued growth of the PV 

market, and the increasing penetration of PV resources in the distribution grids, the modeling 

tools will have to begin to incorporate support for PV. The present work represents an initial 

attempt by Clean Power Research (CPR) to address the shortcoming. 

3.1.1.1 PV Impacts on Distribution Studies 

The following sections describe some of the important types of studies that are performed by 

utility distribution engineers using various modeling and analysis tools, and the impacts of PV 

generation that need to be considered in these studies. 

3.1.1.2 Load Flows with Distributed Generation 

Line loading is calculated in load flow studies – currents, voltages, and power factors – on 

different sections of the circuits at specific times (e.g. the time of peak loading). These are steady 
22

state calculations typically done to ensure that currents and voltages are within physical and 

regulatory limits. 

PV in the distribution system can be considered a "negative load" like other distributed 

generation sources, but its output is more complicated because it varies every hour. Furthermore, 

PV output is dependent upon several factors, such as hourly solar irradiance, hourly ambient 

temperature, hourly sun angle, array azimuth and tilt, and PV module and inverter 

characteristics. 

In high-penetration PV scenarios, the hours of maximum line loading do not necessarily 

correspond with maximum consumption. It will be necessary for engineers to consider other 

times in their load flow studies. For example, daytime consumption could be offset by PV and 

maximum line currents could be shifted from daytime to evening hours. 

3.1.1.3 Protection Studies 

Protection engineers need to determine settings and locations for protective devices such as 

reclosers and fuses. These settings are dependent upon stiffness of generation sources, 

impedances, and loadings. 

PV will source current at the interconnection point, even causing current to flow in a reverse 

direction depending upon generation and local loads at the time. The magnitude of the PV 

contribution must be known in order to properly perform these studies. Utilities generally require 

compliance with UL 1741 in order to connect to the grid. 

3.1.1.4 Fault Location 

The tools may include the ability to determine probable locations of faults, given the line 

configuration and EMS readings at the time of the fault. These are presented as graphical 

locations on the circuit to facilitate dispatch of line crews. 

PV will impact line currents during the time of the fault, so the outputs of PV systems need to be 

accounted for in the calculations of fault location. 

3.1.1.5 Harmonic Analysis 

Engineers need to determine the harmonic distortion (both individual harmonics as well as total 

harmonic distortion, THD) at selected locations on the line. This is historically caused by 

variable speed motor drives and other electronic loads. 

PV inverters are electronic sources that also introduce harmonic content. 

3.1.1.6 Conservation Voltage Reduction 

There are potential energy-saving impacts associated with conservation voltage reduction 

(CVR). Distribution modeling tools are able to calculate energy savings that would be realized 

under different voltage scenarios. 

In order to correctly model the voltages and energy use, PV generation must be considered 

during the critical low-voltage hours. 
23

3.1.2 Data Requirements 

Table 3-1. Data Requirements Table. 

Data Needed Notes 

Load Flow Studies Minimum, maximum, and 

average PV output for all hours 

of interest. 

Protection Studies Minimum, maximum, and 

average PV output for all hours 

of interest. 

Grid-connected inverters are 

current-source devices (unlike 

synchronous generators). 

Inverters operate at the 

prevailing voltage and source 

current that corresponds with the 

maximum available power. 

Fault Location Estimated PV output at the time 

of the fault. 

If actual PV output is measured 

(from EMS), then this data would 

be used. 

Real-time PV output estimation 

for fault location could be 

provided in the future as a web 

service. 

Harmonic Analysis Average PV output for all hours 

of interest. 

Inverter characteristics. 

CPR does not have harmonic 

data on inverters but can provide 

expected output. 

Conservation Voltage Reduction Minimum, maximum, and 

average PV output for all hours 

of interest. 

3.1.3 Limitations of Existing Tools 

Clean Power Research (CPR) has held a series of discussions with a software developer of a 

nationally recognized distribution engineering modeling tool. One approach used by this tool is 

to model PV as a negative load. That is, for a given hour, PV may be treated as a constant power 

source with a specified power factor (usually unity power factor). An example customer load 

editing tool is shown below in Figure 3-1. An apartment building load is presented. 
24

Figure 3-1. Customer load editing. 

The same interface can be used to describe a PV output profile. As a result, distribution 

engineers are able to describe 12 month x 24 hour matrices for PV output under three scenarios: 

peakday, weekday, and weekend. 

In practice, however, there are limitations with this approach: 

• Modeling PV systems is complicated. Most utility distribution engineers are not familiar with 

hourly PV production models. 

• Data input is time consuming. Even if hourly PV output values were known, the time to use 

editors such as the one presented above would not be practical. 

• While customer demand may depend on whether it is a weekday or weekend, PV system 

generation does not. 

3.1.4 Objective 

CPR’s objective was to produce a sample data set of PV output data that can be used by SCE 

distribution planners to analyze the effect of PV system output from a specific set of PV systems 

within the SCE distribution system and to conduct studies such as the ones described above. 

3.1.5 Approach 

Rather than entering PV production estimates for every PV system on the distribution system, 

hourly customized estimates could be generated automatically using existing PV system 
25

configuration data and existing PV modeling tools. The resulting output file could then be 

imported into the distribution tool in a suitable format. 

Figure 3-2. Process flow. 

The approach includes the following: 

• CPR software suite models the PV systems. PV system technical data is entered into 

PowerClerk for the SCE systems under consideration. Hourly modeling is performed using 

SolarAnywhere resource data, the PV systems as configured in PowerClerk, and the 

PVSimulator simulation engine. 

• CPR creates the PV Production File. CPR developed the code necessary to create the output 

file. 

• The process can be done for any number of systems as a batch process. To facilitate the data 

transfer, all of the PV systems for a given utility can be processed at one time. The service 

will create a single PV Production File for the entire utility system. 

• The distribution tool associates PV output with a given distribution transformer. PowerClerk 

provides for Customer ID as a custom field. The output file will include Customer ID for 

location on the line. 

• The distribution tool then models load flows using hourly PV output at the distribution 

transformer level. 

SolarAnywhere® 

(Solar Resource 

Database) 

CPR 

PowerClerk® 

(PV System 

Configuration) 

PVSimulatorTM 

(PV Modeling 

Tool) 

PV Production File 

Loads Database 

Distribution 

Modeling 

Distribution Tool 
26

3.1.6 Definition of Statistical Output Results 

CPR produced three matrices for each PV system under study: one matrix for maximum power, 

one matrix for average power, and one matrix for standard deviation of power. Each matrix 

contains 12 months by 24 hours of data. Each matrix may be used by the engineering tool for 

different purposes or scenario analyses. 

The maximum power, average power, and standard deviation of power arrays were created as 

follows: 

• NREL supplied CPR with the system specifications (e.g. rating, orientation, shading, etc.) for 

each of the PV systems under consideration at SCE. 

• PV system specification data was entered into the database and then combined with CPR’s 

time- and location-specific solar resource database (SolarAnywhere) and CPR’s PV 

simulation tool (PVSimulator) to calculate the hourly PV system output for each system for 

the past 10 years. 

• The resulting data was used to calculate the maximum power, average power, and standard 

deviation of power for each system for each month and hour of the year. All values were in 

kW. 

• The maximum power for a particular month and hour was defined as the maximum PV 

system output over the previous 10-year period for that specific month and hour for a specific 

PV system. For example, the maximum power for January at 10 a.m. was determined by 

examining PV output on every January day at 10 a.m. for the past 10 years. The maximum 

value from the 310 possible values (10 years x 31 days/year) was selected. 

• The average power and standard deviation of power for a particular month and hour were 

similarly defined by calculating the average and standard deviation of PV system output over 

the previous 10-year period for that specific month and hour for a specific PV system. 

A minimum power array is implicit in the data containing all zero values corresponding to 

system downtime. This data was not passed. 

3.1.7 PV System Technical Data 

Technical data (inverter make and model, PV make and model, quantities, orientation) was 

provided by NREL for two PV systems located in the service territory of Southern California 

Edison: a 2 MW ac system in Chino and a 1 MW ac system in Fontana. These two systems were 

used to create the sample data output file. 

In Figure 3-3, the customer data is entered into the PowerClerk database. Since this system was 

not part of an incentive program, the incentive-related fields were ignored. However, the Utility 

Account Number field must be used to identify the location of the PV system on the distribution 

line. The distribution software includes the mapping to line location (or alternatively, a mapping 

of customer to distribution transformer). 
27

Figure 3-3. Customer editing and account linking. 

Figure 3-4 and Figure 3-5 show the selection of inverter and PV module. PowerClerk provides 

the selection of manufacturers and models and other details such as the association of modules to 

specific inverters. Orientation and shading details were also entered. 

Figure 3-4. Inverter editing. 
28

Figure 3-5. PV module editing. 

3.1.8 Output Sample 

The data file produced (as a deliverable to NREL) was in a format decided on and agreed to 

during the course of the project. It was to contain the following information: 

• PV_System_1 

o CustomerID 

o Maximum Power in kW (matrix of 12 months x 24 hours) 

o Average Power in kW (matrix of 12 months x 24 hours) 

o Standard Deviation in kW (matrix of 12 months x 24 hours) 

• PV_System_2

o CustomerID 

o Maximum Power in kW (matrix of 12 months x 24 hours) 

o Average Power in kW (matrix of 12 months x 24 hours) 

o Standard Deviation in kW (matrix of 12 months x 24 hours) 

• PV_System_3

o Etc...

The delivered data file was in XML format and is shown in Appendix B. 
29

3.1.9 Next Steps 

The data file may be used for upload into a compatible engineering tool. This tool should be 

designed with an understanding of the unique characteristics of PV. For example, while 

conventional load flow studies are primarily concerned with the hour of greatest load (demand), 

this rule does not necessarily follow on circuits with high penetration of PV. 

For example, during lightly loaded hours with high solar production (such as weekends), there 

may be significant back-feed on some sections of the line. The highest loading may actually 

occur in these "off-peak" hours. 

3.2 Part 2: Distribution System Modeling and Simulation 

Requirements for Evaluating High-Penetration PV Integration 

This section will be broken into three parts: background modeling applications, modeling needs 

for enabling high-penetration PV studies, and additional DEW capability needed to support the 

project goals. 

3.2.1 Background 

Solar cost reductions, increasing costs of traditional sources, and Renewable Portfolio Standards 

have created the possibility of significant levels of distributed solar generation being installed on 

distribution systems. This emerging situation could lead to high-penetration scenarios. To aid in 

evaluation and help with this expansion of solar resources, there needs to be significant changes 

in the way that the electric power infrastructure is designed and operated. In particular, new 

high-penetration software analysis tools need to be developed and integrated with existing 

software analysis tools such that utility planning and operation engineers can determine impacts 

as they do their normal work. This document outlines some analytical and software needs that 

will support expansion. 

Modeling needs in support of the NREL/SCE high-penetration project will be broken into the 

following major headings: 

1. Utility distribution modeling 

2. Solar side modeling. 

The following are general utility concerns or issues to be addressed with interconnecting a 

distributed resource (DR) to a utility system. These concerns are broken into the need for 

quantifying the impacts of DR on protection, operation, and planning and engineering studies.

From a protection point of view software capabilities need to address loadability, selectivity, 

and sensitivity, with the following definitions: 

Loadability – ability to serve load without tripping. 

Selectivity – the system protective devices nearest the fault isolate the fault before more remote 

device(s) operate to isolate the fault. 

Sensitivity – the ability to sense faults. 
30

The following are examples of study concerns: 

• Improper coordination, nuisance fuse blowing, and upstream single phase faults resulting in 

fuse blowing 

• Close-in faults causing voltage dips that trip DRs, isolating DRs from upstream faults 

• DR stability during faults, islanding, reclosing out of synchronism, and transfer trip 

• Equipment over-voltage, switchgear ratings, under-frequency relaying, and distribution 

automation studies. 

From an operational point of view, software capabilities need to address the following examples 

of study concerns: 

• Equipment over-voltage, resonant over-voltage 

• LTC regulation affected by DRs, voltage regulation malfunctions, and line drop 

compensators fooled by DRs 

• Substation load monitoring errors 

• Loss of exciters causing low voltage, self excited induction generators, in-rush of induction 

machines causing voltage dips, voltage cancelled by forced commutated inverters, and 

capacitor switching causing inverter trips 

• Cold load pickup with and without DRs, flicker, harmonics, stability during faults, and long 

feeder steady state stability 

• Switching impacts resulting from large levels of solar generation 

• Not allowing DRs to limit system operations during normal and emergency conditions 

including switching operations 

• Protection and coordination with inverters, including sectionalizer miscounts 

• Interoperability of multiple inverters from various manufacturers and voltage control with 

multiple sources on a distribution feeder 

• Forecasting/planning for peak and light load 

• Reliability impacts on both momentary and forced outage rates 

• Economic impacts on operations energy and capacity 

• Financial impact on capital and O&M. 

From a planning and engineering point of view, software capabilities need to address the 

following examples of study concerns: 

• Feeder loading criteria and forecasting 

• Load forecasting that considers multiple generation sources 

• The amount of generation that can be installed on a distribution feeder 

• Feeder design that considers large levels of DR generation 
31

• Distribution planning models that reflect actual system operation with high levels of DR 

generation 

• Dynamics of small generators 

• Economic analysis of losses 

• Generation planning and operation for both capacity and energy, including production profile 

throughout the year and type of production. 

In addition to new analysis tools, training for engineers that will use the new tools will be 

important to the overall success. 

3.2.2 Modeling Needs for High-Penetration PV Studies 

Modeling systems will need modifications in order to study impacts of high-penetration solar 

generation. 

Detailed PV inverter models need to be developed for power flow, short circuit, and dynamic 

studies. Modeling should include programmable drag and drop solar inverter models that can 

accommodate solar input measurements to facilitate the study of high penetration of PV as part 

of the normal utility planning and operation process. This should include specific inverters, 

default inverters, and programmable inverter parts. The inverter models should be configured to 

emulate their control settings. The inverter models will also accept time sequence measurement 

data provided by Clean Power Research, the National Renewable Energy Laboratory, and others 

for load estimation and power flow. 

The study system needs to be modeled across the entire load spectrum. Load modeling studies 

will need to be made across time-varying load curves, such as 8,760 hourly time points. The load 

modeling should be as close to customer load and generation as possible and represent all 8,760 

annual-hourly load points. The modeling time points for analysis will need to be modified to 

accommodate the time sequence of the solar data stream. 

Modeling systems needs to be capable of stepping through an operational time sequence that is 

granular enough to capture the operational movement of all active elements within the circuit, 

such as time delays for voltage regulation, protective device operation, etc. The step sizes should 

be programmable. 

The following discussion goes into more specific modeling needs required for detailed studies. 

3.2.2.1 Component Immittance 

The component immittance type of analysis will need to be capable of calculating line and cable 

impedances and admittances as a function of construction, temperature, and frequency. This 

should include inverter impedances as well, particularly to facilitate harmonic analysis. 

3.2.2.2 Load Estimation 

The load estimation type of analysis is primarily a steady state analysis function. It needs to 

include time-sequenced analysis down to one-minute intervals or, in some analyses, features 

such as fault current analysis down to the millisecond. The load estimation function should be 

able to combine start of circuit measurements, interior circuit measurements, PV output, and the 
32

allocation of customer loading. Load modeling should be as close to customer load and 

generation as possible. Customer load estimation should be able to handle kWh measurements, 

load research statistics, single large customer (kW, kVAr, kVA) load measurements, special load 

measurements, and load growth factors (either for entire circuit or individual load) to estimate 

kW and kVAr loading as a function of time. Load forecasting should include weather dependent 

adjustments for both loads and solar generation.

3.2.2.3 Power Flow 

The power flow type of analysis needs to solve large scale problems from transmission-level 

voltages down to secondary service points, including heavily meshed secondary systems. The 

power flow analysis should address both steady-state and quasi-dynamic overload, voltage, 

flicker, and control concerns. A power flow and voltage drop study should be performed to 

determine the steady-state loading profile of the system. The power flow should be capable of 

stepping through time-sequenced operations of the circuitry’s active components, including rapid 

changes in loading such as system responses to changes in PV outputs and loading associated 

with rapid configuration changes. 

3.2.2.4 Network Fault 

The network fault type of analysis should be capable of calculating fault currents for radial and 

looped systems; work for multiple substations looped together; and analyze fault currents from 

distributed resource generators. It should be capable of running for loaded or unloaded systems 

as well as other model variations. Short circuit current studies are necessary to quantify the 

impacts on breaker duty, momentary interrupting capability, and protection/coordination needs to 

accommodate in-feed from multiple distributed resources and coordination for inverter fault 

performance. Inverter modeling and data inputs need to be developed. The characteristics of the 

inverter fault capability will need to be incorporated. 

Analysis of multiple DR devices/technologies should be possible to determine the potential for 

oscillations and the effectiveness of anti-islanding controls. 

3.2.2.5 Protection Coordination 

The protection coordination type of analysis should locate protection and coordination problems 

within a circuit and should work with multiple sources of solar inverters and their protection 

systems. The protection coordination analysis should search protection databases to find lists of 

devices that will coordinate, display zones of protection, and update circuit protective devices. 

This analysis will aid in contingency analysis studies involving high-penetration PV. 

3.2.2.6 Power Quality 

The power quality type of analysis should address harmonic impacts, flicker, outages, 

momentary faults, and sag/swell concerns. Although many utilities have moved away from 

harmonic analysis of late with a focus on outage, we expect a renewed interest in harmonic 

analysis as the number of inverters increases. The need to quantify the harmonic impact on both 

the utility as well as on the individual inverter systems will be of increasing concern. 
33

3.2.2.7 Harmonic Analysis 

The harmonic type of analysis will require the study of harmonics generated by PV inverters and 

possible resonant interactions of inverters with the distribution system. In order to simulate 

harmonics on an ac distribution network, models for harmonic generating loads as well as system 

components must be developed. In general, the power electronics that generate harmonic 

currents can be modeled by using current source models. If the interactions between the ac and 

dc systems are needed, more complicated device-level models will be required that take into 

account the harmonic currents as a function of system reactance, delay angle, and commutation 

angle. Getting this information to support the latter may be a challenge. 

3.2.2.8 Flicker Analysis 

The flicker type of analysis should be capable of calculating voltage dip percentages resulting 

from loads cycling and capacitors switching, modeling the rapid fluctuations in PV output, and 

comparing the resulting voltage dips with the standard ANSI flicker curves. 

3.2.2.9 Contingency Analysis 

The contingency type of analysis, which typically runs first and second contingencies on a 

system of feeders to determine loss of load events, should be updated to include inverter 

response to contingencies. This function could be accomplished through updating existing power 

flow and short circuit analysis.

3.2.2.10 Reliability Analysis 

The reliability type of analysis is used to predict changes in reliability as a result of circuit 

modifications. Reliability impacts of DRs, including intentional islanding, should be included in 

this analysis. In addition to normal feeder component reliability, inverter operational statistics 

will need to be developed. Note that some utilities may not have good reliability statistics on 

individual feeder components. 

3.2.2.11 Feeder Performance 

The feeder performance type of analysis should address time-varying load, such as all 8,760 

annual-hourly load points. The efficiency should be examined and quantified across the entire 

load spectrum. 

High penetration analysis modeling and the results should be managed through dashboard and 

visualization aids, providing a presentation layer to aid analyst understanding. 

All of the above analysis methods are needed for planning, design, and operation. The modeling 

should be integrated with existing tools in a manner that imports field measurements. Quasidynamic modeling will provide detailed understanding of system response, which can offer 

guidance for system planning, design, and operation. In addition to new analysis tools, training 

for engineers who will use the new tools will be important to the overall success. 

3.2.2.12 Power Flow Assessment – Study Example 

The following is an example analysis of how to determine voltage and current effects of highpenetration solar. 
34

Study 1. Run base case 1 at daylight peak load to develop normal circuit peak load baseline. 

Study 2. Run base case 2 at daylight light load to develop normal circuit minimum load baseline. 

Study 3. Run base case 1 again with a high penetration of solar generation and compare results 

with those from Study 1. 

Study 4. Run base case 2 again with a high penetration of solar generation and compare the 

results with those from Study 2. 

Study 5. Run base case 1 again with a high penetration of solar with the solar output varying 

from maximum to minimum with the circuit regulation frozen (remaining in its steady state 

condition before the solar variation occurred) to determine maximum circuit voltage variation. 

Compare results with those from studies 1 and 3. 

Study 6. Run base case 2 again with a high penetration of solar with the solar output varying 

from maximum to minimum with regulation frozen (remaining in its steady state condition 

before the solar variation occurred) to determine maximum circuit voltage variation. Compare 

results with those from studies 2 and 4. 

3.2.2.13 Network Fault Assessment – Study Example 

The following is an example analysis of how to determine fault current impacts on a circuit with 

and without solar inverters present. 

1. Run power flow applications and obtain results (voltages and currents) for the stabilized 

pre-fault system. 

2. Run the network fault application to obtain short circuit current results at the time of the 

fault along with voltages to determine protective device operation along the circuit. 

3. Run power flow applications on the post-fault system with the circuit regulation frozen

(remaining in its steady state condition from the previous run), which may include 

configuration changes, to determine currents, voltages, and load loss without circuit 

regulation changes. 

4. Rerun component immittance, load estimation, and power flow applications on the postfault system, with circuit regulation performing its control function. 

5. Rerun Step 4 above for a return of inverters that were outaged as a result of sags. 

6. Rerun Step 5 with the return of the outaged area to quantify cold load pickup issues. 

First obtain results on the circuitry without high penetrations of solar generation. Then repeat the 

study with the addition of high penetrations of solar. Each of the above should be run at daylight 

peak and light loads. The studies should be repeated for switching and contingency 

configurations that are normally studied in planning. 
35

From these studies we expect to quantify the protection issues associated with the high 

penetration of solar on the SCE circuitry. These would include the issues such as loadability, 

selectivity, sensitivity, and cold load pickup issues. 

3.2.2.14 Penetration Limits 

From previous penetration studies, there are essentially three criterion dictating penetration 

limits, fault current sensitivity, reverse power, and voltage/overload restrictions. Typically at the 

beginning and middle of radial circuits, penetration limits are dictated by fault current sensitivity 

and reverse power. Near the end of the radial circuits, penetration limits are typically restricted 

by a combination of fault current sensitivity and voltage/overload. 

We may want to examine the need to develop a high-penetration PV application. This could be 

done by modifying existing penetration/technology adoption analysis applications developed by 

EDD to determine initial high-penetration solar limits. The existing application criteria will need 

to be modified for reverse power, fault current sensitivity, and voltage/overload problems for 

high solar penetration. We recognize that problems may be resolved with additional circuit 

protection and control, but the application will be needed to help define those required circuit 

changes. In addition, the application may help to define new circuit configurations and operating 

characteristics (newly built circuits designed to accommodate high-penetration PV levels, 

microgrids, and Smart Grid implementation). See Section 3.2.3 for more information on DEW’s 

Penetration Limits Application and Distributed Energy Resource (DER) Technology Adoption 

Analysis Application. 

As a result of our previous DER penetration analysis experience, three main studies are proposed 

for assessing the penetration limit for a distribution circuit: 

• Power flow results for highest penetrations of solar inverter-based generation, which 

corresponds to the maximum local area hourly solar output equal to circuit loading. 

• Repeat of the above with a maximum short term solar variation, first with regulation not 

allowed to move and then again with regulation allowed to move. 

• Power flow results for maximum penetration based on reverse power criterion. 

The above procedure will be repeated through time-sequenced events with and without solar 

inverters present. The inverter output will be bracketed for output variations, including Volt/VAr 

operation and control possibilities.

3.2.3 Additional DEW Capability 

3.2.3.1 Penetration Limits and DER Technology Adoption Analysis Application 

Although not a part of our original proposal, we would like to recommend that DEW’s 

Penetration Limits Application be modified for this project. We also recommend that this would 

best be done by merging this application with DEW’s DER Technology Adoption Analysis 

Application. The following is a discussion of those existing applications. 
36

3.2.3.2 Penetration Limits 

A DER Penetration Limits Application has previously been created. Criteria for penetration 

limits were established, which include over-voltage, flicker, overload, reverse power, and fault 

sensitivity, both with and without active regulation. The penetration limits were calculated for 

circuit head, mid circuit, and end of circuit. The penetration application within DEW was 

established and supplemented with power flow and short circuit analysis applications. 

The Penetration Limits Application determines the largest distributed generator that can be 

placed on a circuit without violating constraints, including flicker, component overload, 

customer level voltage, and reverse power at the substation transformer. Using either a bisection 

search method or a brute force method, the real power output of the generator is increased until 

one or more of these criteria are violated. The bisection search can greatly decrease the solution 

time by reducing the number of iterations the algorithm must perform to arrive at an acceptable 

solution. Solution parameters such as iteration size (for brute force) and acceptable real power 

window (for bisection search) can be adjusted to achieve the desired balance of solution time and 

accuracy. The user may also select which conditions to check for failure and specify failure 

points for flicker and customer level voltage. 

The user may also choose to either actively control the reactive power output of the generator or 

simply hold the power factor constant at unity. Configurable parameters for active control 

include power factor as well as rated power factor for the generator. 

The penetration limit reactive power control algorithm was adjusted to find the reactive power 

output for both maximum released capacity as well as minimum circuit losses. The algorithm no 

longer increases the real power output once any selected criteria are violated. Low customer 

voltage is a failure criterion. 
37

Figure 3-6. DEW's Penetration Limits Application dialog.

A protection sensitivity criterion is included. A rule of thumb is used such that the DR is not 

allowed to contribute more than 10% of the system’s available fault current as a means of 

maintaining circuit protection selectivity and sensitivity. The maximum DR size is calculated for 

the points of interest as a means of maintaining the circuit protection. 

3.2.3.3 DER Technology Adoption Analysis Application 

Another potential addition to the project would be to combine the Penetration Limits Application 

with the DER Technology Adoption Analysis Application. 
38

Figure 3-7. DEW's DER Technology Adoption Analysis Application dialog. 

Electrical Distribution Design created an analysis program that runs with the DEW modeling 

system to aid DTE Energy in the analysis of the growth or adoption of electric vehicles. In 

particular, a DER Adoption Analysis Application was developed to study plug-in electric 

vehicles (PEV). 

Monte Carlo simulation is used to randomly place PEV units at locations throughout the circuit. 

The simulation provides customer arrival home and plug-in time models, including automated 

charging during early morning hours. 

After the PEV adoption program was completed, NREL funded the further development of the 

application. The PEV adoption program was expanded and renamed the DER Technology 

Adoption Analysis Application. The application was expanded to enable studies of simultaneous 

adoption of various technologies such as customer-owned solar generation, customer-owned 

wind generation, and utility-owned battery storage. An objective is to evaluate adoption levels of 

solar and wind generation supplemented with battery storage that will offset the adoption of 

electric vehicle loads. 

The National Renewable Energy Laboratory’s solar data is utilized for the solar generator. For a 

given solar generation location and size, the NREL interface provides hourly generation data for 

an entire year, and thus 8,760 hours of generation are used in the analysis. For the wind 

generation, wind speed data is obtained using U.S local climatological data from the National 

Climatic Data Center (NCDC). The wind power used in this analysis is calculated by the wind 

turbine power equation. For each hour of analysis, customer loads are estimated from averaged 
39

hourly SCADA measurements, hourly customer kWh load data, and monthly kWh load data 

processed by load research statistics to create hourly loading estimates for each customer. 

Customer battery storage is also included. 

The application, once modified by incorporating penetration limit analysis, would allow the 

analysis of any of SCE’s distribution circuits. 
40

4 Data Acquisition Requirements for Analysis of High 

Penetration Levels of PV into the Distribution Grid in 

California 

4.1 Introduction 

This section provides supportive material and information required to facilitate data acquisition 

requirements for evaluating the distribution system impacts of high-penetration PV integration. 

The collected data will be used to develop and verify models and simulations used to study the 

impacts of high-penetration PV integration and develop methods for mitigating these effects. 

4.2 Distribution System Monitoring and Data Collection 

This section describes measurement quantities and recording resolutions for data being 

periodically collected by SCE from their distribution substations and feeders as well as 

provisions in this project to install monitoring devices and collect feeder voltages and currents at 

pre-specified locations. 

SCE utilizes a data streaming and historian tool entitled eDNA. Through this tool, it is possible 

to log rms voltages at the distribution substation as well as the rms current and reactive power of 

each feeder. The total substation current (in Arms) and reactive power of the transformer is also 

monitored. This information is typically logged at 10-second intervals as soon as a pre-specified 

level of variations in voltages or currents occurs. The data resolution at substation level also can 

be increased to 4-second intervals. 

In addition to substation data, several voltage monitoring points along the feeder are available, 

mainly at capacitor bank locations. The capacitor bank voltage is captured for the only phase that 

has a connecting single-phase PT and used by the capacitor bank controller. The capacitor bank 

on/off status is also reported upon changes. 

Table 4-1 provides a list of substation and feeder data available through eDNA that may be 

relevant to this project. 

Table 4-1. Data Measurement Quantities from eDNA System. 

Data Data Availability Resolution 

Substation load data (Vrms, Irms, and Q) Daily per feeder 4-second updates 

on changes* 

Feeder load data (Vrms, Irms, and Q) Daily per feeder 4-second updates 

on changes* 

Capacitor bank status and voltage Daily per feeder 5 minute 

Voltage profile at capacitor bank locations Daily per feeder 5 minute 

Voltage profile at PV system location Daily per PV system Sensitive info ** 

PV system power output profile Daily per PV system Sensitive info** 

 
41

The following aspects of data capturing and streaming of SCE’s distribution SCADA system 

should be noted: 

* Data is only logged as soon as a specific level of change in the targeted quantity occurs. 

As a result, the captured data points for three-phase quantities are not synchronized in an 

output file. However, the recorded data is time stamped based on the eDNA time clock. 

In other words, numbers of data points are not the same per voltages and currents 

measured on different phases. Therefore, some post-processing work is needed to overlay 

data properly utilizing the time stamp. On the other hand, generating data profiles would 

be an easy and effective way of demonstrating daily variations. 

** This information is considered very sensitive data about generation systems. SCE has 

some limitations on what information about PV systems can be published due to 

sensitivity of PV developers on PV performance analysis and the ability to calculate or 

compare system efficiencies. 

The aforementioned data server (eDNA) has the ability to allow one-way streaming of prespecified data to an external server without affecting SCE’s cyber security. To set up a gateway, 

a mapping of required data from eDNA to the external database should be defined. 

As part of the feeder monitoring plan for the project, it was also discussed that an independent 

(from SCE system) voltage and current monitoring apparatus should be installed at several points 

along each of the selected feeders. The measurement points of interest are generally: 

• Voltage and current measurements immediately upstream of PV system interconnection 

point(s) 

• Voltage and current measurements at the middle of a feeder (load center) or close to major 

load sites 

• Voltage measurement toward the end of a backbone feeder or on the farthest point of long 

laterals and branches with major load flow. 

4.2.1 Feeder Modeling 

One of the applications of data monitoring and measurement is to verify feeder models, and 

typical phenomena may be observed during simulation studies. Appendix C provides a 

comprehensive list of data requirements for modeling a distribution feeder. SCE normally uses 

CYMDIST and PSCAD/EMTDC software tools, respectively, for steady-state and dynamic 

modeling of their distribution feeders. 

Most of the feeder characteristic data can be extracted from the CYMDIST models. Examples 

are: 

• Conductor types per line section 

• Capacitor bank size and locations 

• Load type (residential, commercial, single/three-phase) and locations 

• Fuse and switch ratings and locations 
42

• Rating and impedance for some of the three-phase transformers feeding large 

commercial/industrial loads. 

It should be noted that generally the detailed load data (per customer) based on seasonal or daily 

variations is not incorporated in the CYMDIST. However, using the eDNA system, a load profile 

of a feeder for targeted days can be obtained. Available load measurements are for the entire 

feeder. A load allocation method should be used to perform load distribution for customers along 

the feeder for any specific load profile. 

 
43

5 Advanced Inverter Technology for High Penetration Levels 

of PV Generation in Distribution Systems 

5.1 Introduction 

Practically all of the renewable energy sources, and most forms of energy storage, produce either 

dc or variable frequency output power. In many ways this is unfortunate because all power from 

these sources must pass through a frequency converter in order to feed the constant-frequency ac 

power grid. This extra stage of power conversion introduces additional equipment cost and 

power losses. On the plus side, however, this need for frequency conversion has resulted in a 

rapidly-growing class of electronically coupled generators (ECGs) connected to the grid, with 

control capabilities that are broadly superior to those of conventional rotating synchronous 

machine generators. Understandably, electric utilities have viewed the advent of these ECGs 

with a certain amount of fear, both because of their unfamiliar operating characteristics and 

because of their location in distribution systems where there traditionally has been minimal 

power generation. The level of concern has increased with the rapidly increasing size of 

proposed projects relative to the feeder rating and/or the minimum load levels. It is of course 

perfectly feasible to generate power in new or existing distribution circuits, and even to export 

power back into the transmission system, but in so doing we challenge some of the traditional 

assumptions that have been made in the design of protection and voltage regulation schemes for 

these circuits. This is especially true in the case of higher penetration levels for PV generation. 

5.2 Utility Concerns about the Impact of High-Penetration PV on MV 

Feeders 

As a leading supplier of inverters for large PV generating projects, Satcon has participated in 

industry forums and IEEE working groups for standards development, where electric utilities are 

also strongly represented. Satcon also provides support for project developers, in the United 

States and abroad, as they negotiate with utilities over interconnection impact assessments, 

connection rules, and similar issues that arise in regard to their requested grid connections. 

Because Satcon must comply with interconnection rules in the many countries where their 

inverters are installed, they also follow emerging regulations very closely and are aware of the 

world-wide trends in this area. Finally, they are called in to help solve real problems that occur in 

the field. As a result Satcon has a good overview of the main concerns of electric utilities in 

relation to the installation of large PV generating projects in distribution systems. These concerns 

can be roughly grouped into three categories as follows: 

• What will be the effect of fluctuating real power output from renewable sources on the 

normal operation and power quality of the distribution system? 

o Increased switching operations for line regulators, tap changers, switchedcapacitors. 

o Steady-state voltage regulation over the range of real power generation, especially 

on long feeders. Should PV generators be allowed/required to participate in 

voltage regulation automatically, or on the basis of reactive power dispatch or 

scheduling? If autonomous local automatic voltage control is allowed, can stable 
44

operation be expected when multiple PV generators are involved on the same 

feeder? Will fast automatic voltage controllers "fight" with slower line regulators? 

o Flicker due to rapidly fluctuating voltage caused by sudden changes in real power 

generation. 

o Transient voltage changes on sudden trip of PV generation system, especially if 

the system is actively participating in voltage regulation. 

o Harmonics generated by the PV inverters, and possible resonant interactions of 

inverters with the distribution system. 

o Conductor and equipment loading due to new power flows resulting from the 

introduction of local power generation in the distribution system. 

• How should the protection relay schemes be changed/designed for existing/new distribution 

feeders when large new generators are connected? 

o Reversible real and reactive power flows possible. 

o Protective relay settings and operation. 

o Contribution of new generators to short circuit levels. 

o Islanding of generators with residual load connected. 

o Auto-reclosing feeder breaker onto energized generators. 

o Appropriate grounding schemes for new generators to allow ground fault 

detection and prevent transient over-voltages. 

• Additional concerns about providing real power management for frequency regulation in 

smaller grids (e.g. islands) with limited aggregate generator rotational inertia. 

o Rapid curtailment of real power sources on over-frequency. 

o Rapid load-shedding and/or "spinning reserve" deployment on under-frequency. 

o Ramping of real power from variable sources to minimize impact on the grid 

frequency. 

o Transient frequency excursion on sudden trip of generating system. 

Many of these concerns can be addressed through a proper understanding of the capabilities and 

operating characteristics of the modern inverters that are used to couple PV systems to the grid. 

There is little doubt that the introduction of large-scale ECG into distribution systems will 

eventually force utilities to depart from some of the traditional practices that have been 

established over a century. This is bound to be a difficult process, and possibly risky at the 

outset, but should ultimately result in a better power system. Most of the issues listed as concerns 

do not in fact present fundamental obstacles to the implementation of high penetration levels of 

PV generation, and in many cases the presence of inverter-based PV generation can facilitate 

solutions rather than complicate the problems. This is especially true in regard to the area of 

system protection, because inverters are inherently fast acting and current-limited. 

First we describe the basic output characteristics of inverters and the control capabilities that are 

relevant to their grid interconnection in a high-penetration scenario. This should serve to provide 
45

a basis for further consideration of system protection and circuit requirements from the utility 

perspective. Next we provide details of how the PV inverters can participate actively in the 

regulation of voltage in the distribution system. Because inverters bring to the table their unique 

ability to generate or absorb controlled reactive power, and there is little consensus on how this 

capability should be used in a distribution system, this is by far the most important topic that 

needs to be addressed. 

5.3 Capabilities of Inverters 

Inverters are electronic power converters that can be used to couple dc or variable-frequency 

power sources to the grid. Practically all renewable power generation systems depend on 

inverters for their grid connection. In these applications, the primary function of the inverter is 

simply to deliver the maximum possible generated real power (P) as efficiently as possible to the 

grid. The first generation of inverters for PV power was typically designed with only the basic 

controls necessary to perform this primary function, while complying with UL 1741 and IEEE 

1547 requirements. For low power levels (less than 500 kW) and low levels of PV power 

penetration, certification of the equipment to these standards was sufficient for utilities to allow 

interconnection to the grid without much concern. 

In addition to frequency conversion and basic real power delivery, inverters also have a number 

of other inherent control capabilities that are widely used elsewhere in power systems for power 

management and power quality improvement. As the penetration levels increase for PV 

generation, and as more sophisticated rules for interconnection emerge, it has become clear that 

harnessing these inverter control capabilities will be key to the successful implementation of 

large-scale PV generation in distribution systems. Consequently, a wide range of control 

functions have already been incorporated into newer PV inverter designs that will allow them to 

play an important role in the operation of the distribution system. In this section we will briefly 

describe the most relevant inverter capabilities and the ways in which they can facilitate the 

successful implementation of high penetration levels of PV generation. 

5.3.1 Controlled Output Current 

When connected to an established power grid (i.e. where the frequency and voltage are actively 

regulated), inverters typically operate as controlled current sources. This means that the high 

frequency switching of the inverter is controlled so that the output current from the inverter is 

actively forced to follow a reference signal. The design of the feedback control system that 

accomplishes this may differ from one manufacturer to another, but with an optimum design the 

output current control can be extremely fast (< 1 ms response) and accurate (< 1%). Furthermore, 

the control response can be practically unaffected by disturbances in the grid voltage. 

The controlled output current of an inverter has several important implications: 

• As seen from the grid, the "impedance" of the inverter is very high. As a result, the inverter 

output current continues to follow the internal reference signal, even when power system 

faults cause large changes in voltage. This is generally true for positive and negative 

sequence components. Most inverters provide a three-wire native output from their power 

electronics to an ungrounded winding on an isolation transformer, so they do not influence 

the zero sequence component of output current. Thus the apparent zero sequence impedance 
46

seen from the grid is a combination of the zero sequence impedance of the isolation 

transformer plus the effect of any neutral grounding impedance. With alternative inverter 

topologies, it is possible for the inverter to also control the zero sequence component, but the 

extra equipment expense is rarely justified. The high output impedance of an inverter is quite 

different from the case of a rotating synchronous machine generator, which can contribute 

relatively large transient output currents under fault conditions. It is important to note that 

although an inverter acts as a current source with high output impedance, it also has a limited 

maximum output voltage available. In other words, it will not present "infinite" voltage at its 

terminals if an upstream feeder breaker is suddenly opened while the inverter is running. The 

maximum output voltage is in fact determined by a combination of the inverter dc terminal 

voltage and the action of the control system. 

• The output current is limited. The internally generated current reference signal takes account 

of prevailing voltage variations to maintain a required power output, but it is always subject 

to an over-riding current limit that corresponds to the level of current needed to output rated 

kVA at the minimum specified working voltage, usually 0.9 per-unit (pu). This means that 

with a properly designed control system, the output current from an inverter during a grid 

fault should not exceed 1.1 pu approximately. In most cases, a 1.1 pu fault contribution from 

distributed generators should be negligible in relation to the conventional fault contribution 

fed from the transmission system. Add to this the consideration that the inverter output 

currents are largely in phase with the system voltage, whereas the conventional fault currents 

are largely in quadrature, and it is safe to say that inverters contribute a negligible amount to 

the total fault level on a distribution feeder. 

• The output current can be reduced to zero in an extremely short time. If necessary, the native 

output current from the inverter bridge can be stopped in a few microseconds (followed by 

some short-lived [< 1 cycle] decaying transients between the output filter and the grid). This 

can be very important for the protection and management of the distribution system. If the 

utility is concerned about circuit breaker capacity, provision can be made for the output 

current from an inverter-based generator to be stopped well before any mechanical 

switchgear starts to operate. In this situation, the inverter controls can autonomously initiate 

rapid shutdown when abnormal grid conditions are sensed, or the controls can respond to a 

signal from the utility (e.g. transfer trip) 

• The complex (apparent) output power (S = P + jQ) can be controlled in any of the four 

power quadrants. Because the magnitude and the phase angle of the fundamental output 

current relative to the grid voltage can be arbitrarily selected, the real (P) and reactive (Q) 

components of S can be directly and independently controlled. The P output is typically 

controlled so as to regulate another internal quantity such as the dc voltage or power at the 

PV array. The active control of P also allows important over-riding real-power-limiting 

functions, such as power curtailment and power ramping, to be implemented in response to 

inputs received from a remotely located system operator (e.g. via SCADA). These real power 

management functions are expected to become essential tools for utilities under a highpenetration scenario, especially in smaller grids (e.g. islands) where the power system may 

not always be able to accept additional real power and where frequency regulation is a 

concern. Apart from the management of real power output, the inverter has unique 

capabilities to generate and strategically deploy reactive power (Q) output. This topic is 

especially important and warrants a separate in-depth discussion in the following sections. 
47

The Q output that can be generated by inverters at a PV system is a valuable resource for 

utilities and is expected to be crucial for regulating the voltage in a distribution system with 

high penetration of PV. 

• The complex output power can be controlled with very high bandwidth. In most cases it is not 

desirable to change real power output very rapidly because of the impact on system voltage 

(and frequency in weaker systems). Consequently, real power changes are usually made to 

follow slow time ramps whenever possible. The same consideration may often be true for 

reactive power. However, by means of the high bandwidth control of Q, the inverter can also 

act as a fast autonomous local voltage control system. Fast automatic response is essential for 

correction of the voltage deviations associated with voltage flicker, for example. This will be 

discussed in more detail in the following sections. 

• The inverter can absorb real power from the grid and deliver it to charge an energy storage 

device connected to the dc-side collector bus (also fed by a PV array). This can facilitate the 

implementation of an energy management system where the inverter supplies real power to 

the grid from storage at times when PV power is not available. To achieve different 

objectives, the energy storage device might be relatively small (to facilitate power ramping) 

or very large (e.g. for frequency regulation or power output leveling). 

• The inverter output current can be controlled to correct pre-existing low-order voltage (or 

current) harmonics on the grid. In order to do this, the inverter must deliberately produce 

corresponding harmonics in the output current. This rather specialized "active filter" function 

is sometimes performed by dedicated inverters installed specifically for this purpose. To 

facilitate the production of controlled harmonic output currents, an inverter would ideally 

switch at the highest practical frequency, and it would be designed with a small output filter 

inductor in order to minimize the inverter voltage needed to drive the harmonic currents. In 

addition, because the oscillating harmonic power produced at the ac terminals must be 

matched by an approximately equal harmonic power at the dc terminals, it is desirable to 

provide a larger-than-normal dc bus capacitance in order to minimize the corresponding 

harmonic voltage that develops on the dc bus. It would be relatively costly to produce a PV 

inverter designed to simultaneously deliver real power while also serving as an active filter. 

However, active-filter capability might be useful when normal PV power production is very 

low or zero, such as during the night. 

• The inverter can help to correct for unbalanced fundamental voltage at the point of 

connection to the grid by controlling output current to include a negative sequence 

fundamental component. In this mode the inverter essentially acts as an active filter for the 

minus-one (-1) order harmonic. The negative sequence fundamental output current produces 

a second harmonic power pulsation at the ac terminals, matched by a similar power pulsation 

at the dc terminals. As in the case of the active filter, a large dc capacitance is needed to 

absorb this pulsating power with acceptably small dc voltage deviation. As mentioned 

previously, most inverters can only correct for the negative sequence fundamental. However, 

using a more costly alternative inverter topology (e.g. a four-leg inverter bridge), a similar 

correction could be provided for the zero-sequence components in an unbalanced system. 
48

5.3.2 Grid-Smart Control Features 

Under the DOE SEGIS program Satcon set out to develop an inverter design for the future grid 

that would have all of the capabilities needed to facilitate the integration of large-scale PV 

generation into distribution systems. To do this, it was necessary to define a new set of "GridSmart" control features for the inverter, which would make full use of the inherent capabilities 

listed in the previous section. The main inverter features that were selected are as follows: 

• Local communication with site-level controller,* providing utility SCADA communications 

and multi-unit control through: 

o Control of real power limit (curtailment) 

o Controlled ramp rate for real power limit

o Control of reactive power output OR power factor.

* NOTE: The site-level controller is a shared local computer that complements the features 

of each inverter in a multi-inverter installation by providing aggregate output power 

management at the point of interconnection with the utility. The site controller is a 

communications hub that communicates with all inverters and the utility control center, and 

receives and processes real-time V, I measurements from POI. By issuing commands to the 

inverters it can provide:

• Aggregate power factor control – accounting for site transformers 

o Automatic voltage control if required 

o Long duration real power ramping by means of curtailment commands to 

inverters

 Ride-through* capability for specified grid disturbances, requiring: 

• Adjustable tolerance for voltage and frequency deviation 

• Enhanced dynamic control to continue operating successfully with 

unbalanced or distorted grid voltages during faults 

• An un-interruptible power source for control and communications. 

* NOTE: "Ride-through" means that the generator must stay online and operate as specified 

during voltage disturbances caused by faults on the transmission system or an adjacent 

feeder. The ride-through requirement originated from experience in wind power generation, 

mainly at transmission level voltages, and has now become the most common new 

requirement for interconnection with medium voltage distribution systems. It is a 

contradiction of IEEE 1547, which requires generators to cease operating within specified 

maximum time periods when the grid voltage deviates from normal. New ride-through 

requirements differ considerably in regard to voltage levels and duration. In general they are 

intended to ensure that generators will be online and ready to carry their share of system load 

after the disturbance. In some cases the generator is required to generate reactive power 

according to a special schedule when voltage deviates beyond set limits. It is assumed that 

generators will use anti-islanding and other fault sensing methods to distinguish between a 
49

voltage disturbance that requires ride-through and the occurrence of a fault within the feeder 

or the opening of the feeder breaker that requires operation to cease.

• Bi-directional power flow to support charging of a dc energy store using grid power. 

• Permissive signal* based on Power Line Carrier Communication (PLCC) – an alternative to 

conventional transfer trip schemes. 

* NOTE: While it is generally understood that transfer trip schemes are needed for 

synchronous machine generators that cannot easily detect an island condition, there is 

considerable dispute over the need for these expensive schemes in the case of PV inverters 

that are usually certified to be compliant with the anti-islanding requirements of IEEE 1547. 

Often a utility will question the effectiveness of anti-islanding when there are multiple PV 

units connected on one feeder. Because there is, as yet, no definitive way to prove this point 

one way or another, the utility will usually choose to err on the safe side and insist on the 

provision of a transfer trip scheme. The PLCC carrier permissive signal provides an 

alternative approach, whereby all generators on a grid segment can rapidly and reliably detect 

when islanding has occurred and cease operating.

The SEGIS program work led to the development of Satcon's Solstice Inverter products that 

incorporate the Grid-Smart control features. These features provide a flexible basic control 

interface for the inverters, allowing higher-level power-management strategies to be 

implemented either from a remote control center or on site by means of a site-level control 

system. 

Some of the Grid-Smart control features are illustrated in Figure 5-1 using waveforms generated 

from a transient simulation model. In this case the output currents to the grid are displayed 

together with the calculated associated instantaneous real and reactive power output. Real power 

curtailment, sudden change of irradiance at the PV array, and leading and lagging reactive power 

generation are all shown. For this illustration, fast internal ramp rates were set to speed up the 

transition between each operating state of interest. Note that there is no downward ramp of 

output power when the solar irradiance is suddenly dropped. The fall of power cannot be 

controlled in this situation without the addition of a suitable energy storage device. 
50

INDUCTIVE

0.9 P.F.

POWER

CURTAILED

1.0 P.F. CAPACITIVE

0.9 P.F.

1.0 P.F. IRRADIANCE

FLUCTUATION

REAL

REACTIVE

INDUCTIVE

0.9 P.F.

POWER

CURTAILED

1.0 P.F. CAPACITIVE

0.9 P.F.

1.0 P.F. IRRADIANCE

FLUCTUATION

REAL

REACTIVE

Figure 5-1. Illustration of some advanced grid support control features using a transient 

simulation model of a Grid-Smart inverter. 

5.3.3 Reactive Power Generation 

The name "reactive power" is really a misnomer, because the quantity it describes is actually the 

redundant current that flows at a given point in a power circuit in relation to the electrical power 

(watts) measured at that point. The notion of reactive power often causes confusion because it is 

an artifice created for circuit analysis, with no basis in physics. The concept of reactive power is 

also not uniformly applicable to three-phase and single-phase circuits. 

In a three-phase circuit carrying positive and negative sequence currents only (i.e. where the sum 

of the three currents is zero), the instantaneous reactive current is defined at any given point in 

the circuit. It describes the part of the instantaneous three-phase current set that is redundant at 

that point (i.e. the part that could be discarded without changing the instantaneous electrical 

power calculated at that point). This redundant set of currents is uniquely defined using space 

vector theory. Specifically, it is the component of the current vector that is in space quadrature 

with the voltage vector. For convenience in circuit analysis, the instantaneous reactive current is 

multiplied by the voltage in order to define a quantity (VAr) with the same dimensions as power. 

Also a polarity is assigned to the product, depending on whether the current vector leads or lags 

the voltage vector spatially. This quantity is treated as the imaginary part of an instantaneous 

complex power quantity (S) for computation purposes. There is no universal rule for the polarity 

of reactive power, but if current is defined as positive in a certain direction, and the associated 

current vector lags the voltage vector, then reactive power is usually said to be flowing in that 

direction (i.e. positive). Because the reactive power in three-phase circuits is defined on an 

instantaneous basis, irrespective of the voltage and current waveforms, it can also be controlled 

on an instantaneous basis (i.e. in a time-frame that can be much shorter than one fundamental 
51

cycle). This means that instantaneous reactive power in three-phase circuits can be used to 

influence voltages in the circuit very rapidly, which can provide an important way for improving 

power quality. 

Instantaneous reactive power is not defined for single-phase circuits. Instead, for single-phase 

circuits, the concept of reactive power is applied to steady state behavior with purely sinusoidal 

voltage and current, represented by sine-wave phasors. The reactive current phasor at a point in 

the circuit is defined as the component of the current phasor that is in quadrature with the voltage 

phasor at that point. This redundant component of current could be discarded without changing 

the average electrical power calculated at that point. Reactive current is once again multiplied by 

voltage to obtain reactive power. Of course, this steady-state phasor interpretation of reactive 

power can also be applied to three-phase circuits in the steady state, where it is entirely 

consistent with the instantaneous reactive power concept under steady state sinusoidal 

conditions. Phasor analysis also provides the only way of applying the reactive power concept to 

zero sequence currents flowing in three-phase circuits. 

Reactive current occurs naturally in power circuits due to the presence of reactive circuit 

elements (inductance and capacitance) and various electrical loads (motors, etc.) that draw 

current at non-unity power factor. The reactive current passes through the circuit causing voltage 

drops and power losses and without contributing directly to the useful transfer of electrical 

energy. Reactive power is conserved (like electrical power) as it passes through an ideal 

transformer, but in a non-ideal transformer substantial reactive power may be absorbed by the 

leakage inductance. Passive reactive components (capacitors and reactors) are often strategically 

switched into or out of a power circuit to compensate for the natural reactive current flow. In the 

case of so-called "static VAr generators," electronic switches are used to regulate the reactive 

current drawn by these components. 

Like electrical power, reactive power can be injected into a power circuit from a suitable 

generator. An ideal reactive power generator requires no electrical or mechanical power input, 

and no bulk reactive circuit elements, but instead uses a controlled source of voltage to drive the 

required reactive current output. The rotating synchronous machine is the traditional reactive 

power generator. The reactive power output from a synchronous generator is controlled by 

changing the field excitation, allowing reactive power generation up to rated kVA, as well as a 

more limited range of reactive power absorption. The ability to inject controlled reactive power 

into a power circuit is important because it provides a very effective means of regulating the 

voltage. 

5.3.3.1 Inverter Reactive Power Generation Capability 

Three-phase inverters are the ultimate reactive power generators, capable of generating or 

absorbing high quality reactive current that is controlled on an instantaneous basis. Modern 

inverters are unique in the world of VAr generators because they are able to change their reactive 

power output extremely rapidly. Response times of the order of 1 ms to full output are 

achievable (Figure 5-2), which is very fast compared to other devices such as rotating 

synchronous condensers and other switched devices using capacitors and inductors as the sources 

and sinks of reactive power. This fast response has allowed inverter-based VAr generators to be 

successfully applied for arc furnace flicker compensation and active power filtering, for example, 

where they operate in a sub-cycle control time frame. 
52

Real power 

output = 

0.8 p.u.

Reactive power 

output = 0 p.u.

Reactive power 

output = 0.5 p.u.

Reactive power 

output = - 0.5 p.u.

AC voltage 

variation 

+/-5% 

approx.

Real power 

output = 

0.8 p.u.

Reactive power 

output = 0 p.u.

Reactive power 

output = 0.5 p.u.

Reactive power 

output = - 0.5 p.u.

AC voltage 

variation 

+/-5% 

approx.

Figure 5-2. PV inverter simulation shows fast VAr step response capability and the effect on local 

bus voltage. 

Inverters can provide real (P) and reactive (Q) output power simultaneously, with a 

corresponding complex power output, S = P + jQ. For safe operation of the solid-state switches 

in the inverter, there are strict limits on the maximum working current. Therefore inverters are 

typically designed for a specific maximum kVA output (Smax) that cannot be exceeded. Thus at 

any operating point, the P and Q output must be constrained so that Smax > (P2 + Q2)

1/2. Note that 

the Q output does not add linearly to the total prevailing kVA output. So, for example, with Smax 

= 1 pu, and a reactive power output of Q = 0.2 pu, an inverter can still pass real power up to P = 

0.98 pu without exceeding Smax. This represents a very small impact on maximum real power 

production while generating a significant level of reactive power output. Some inverters are 

designed solely for the purpose of generating reactive power (i.e. P = 0). In that case the 

generated reactive power must account for the entire cost of the inverter. But if the cost of the 

inverter is already covered by its primary function (P delivery), then the incremental cost for 

simultaneous reactive power generation may be low. This is particularly true at times when the 

maximum real power capability of the inverter is not being used. This may occur, for example, in 

the case of PV power sources due to the daily cycle of solar irradiance. 

While it is broadly accepted that the ability of inverters to generate controlled reactive power is a 

useful feature, there has been little consensus on how this capability should be deployed in a 

power distribution system. There are many ways in which the reactive power output of PV 

inverters might be managed for the benefit of the distribution system. Some of these schemes 

have already been arbitrarily defined and included in published interconnection rules and private 

power producer agreements, but there is not yet any uniformity apparent in these requirements. 

One trend is to provide a predetermined schedule of reactive power output versus voltage at the 

point of interconnection. The typical schedule would not require any reactive power output from 
53

the inverter until the voltage deviates outside of normal working limits. Supposedly, this 

approach circumvents the thorny issue of allowing a generator to perform automatic voltage 

control and avoids the anticipated problem of fast voltage controllers fighting with each other 

and with slower mechanically-switched line regulators. It is worth noting that automatic local 

voltage control is routine in transmission systems, where reactive power generators are always 

required to autonomously regulate the voltage at the bus where they are connected. Furthermore, 

there are many instances where fast-acting VAr generators are either connected to the same bus, 

or within a short distance of each other, and work together in a stable way thanks to the 

appropriate control system designs. There is no fundamental reason why PV inverters should not 

be used to continuously and autonomously regulate voltage in a similar way in distribution 

systems. This topic will be discussed in much more detail in Section 5.3.5. 

5.3.3.2 Inverter Output Power Control 

With regard to the PV inverter control system, the first consideration is how to make sure that the 

maximum inverter kVA is not exceeded while simultaneously supplying real and reactive power 

to the grid. Other manufacturers may use different design approaches, but Satcon provides a 

choice of two basic control modes, which make it possible to implement a variety of reactive 

power strategies. 

The first control mode provides independent reactive power control. In this very flexible control 

mode, the maximum available reactive power at any time is calculated as a function of the 

prevailing real power curtailment level. Reactive power output follows a command (local or 

remote) up to the maximum available level. In a large utility-scale application, for example, the 

real power curtailment level is allowed to slowly track the prevailing real power output up to a 

pre-determined maximum, while the reactive power command is generated by a site-level 

controller following a specified algorithm in response to MV measurements at the point of 

interconnection. Figure 5-3 shows the available reactive power from the inverter versus the real 

power curtailment level. Note that available reactive power has been limited to 0.87 pu so that at 

least 0.50 pu real power is always achievable. This constraint is by design and does not represent 

an absolute limit. 
54

0.2 P.U. REACTIVE

POWER FOR ONLY

0.02 P.U. CURTAILMENT

CUTOFF AT 0.87 P.U. REACTIVE ALLOWS 0.5 P.U. REAL POWER 

ALWAYS AVAILABLE FOR CONTROL OR CHARGING ENERGY STORE

TOTAL APPARENT

POWER (KVA) OUTPUT IS

ALWAYS LIMITED TO 1 P.U.

REACTIVE POWER 

OUTPUT IS INDEPENDENT 

OF PREVAILING REAL 

POWER

0.2 P.U. REACTIVE

POWER FOR ONLY

0.02 P.U. CURTAILMENT

CUTOFF AT 0.87 P.U. REACTIVE ALLOWS 0.5 P.U. REAL POWER 

ALWAYS AVAILABLE FOR CONTROL OR CHARGING ENERGY STORE

TOTAL APPARENT

POWER (KVA) OUTPUT IS

ALWAYS LIMITED TO 1 P.U.

REACTIVE POWER 

OUTPUT IS INDEPENDENT 

OF PREVAILING REAL 

POWER

Figure 5-3. Independent reactive power control mode. 

The second control mode provided for the inverter is a power factor mode. In this mode the 

reactive power output automatically tracks the real power output, maintaining the Q:P ratio that 

is consistent with the prevailing power factor command but always staying within the kVA 

rating, and observing the prevailing curtailment level for real power output. Figure 5-4 shows the 

maximum available real power as a function of power factor (assuming 1.0 pu real power 

curtailment) and the associated reactive power levels. This control mode can be used to set a 

constant power factor prescribed by the utility, or it can be used to follow a variable power factor 

command generated by the site controller or received from a remote operator at the utility control 

center. 
55

REACTIVE

REAL POWER

REACTIVE POWER TRACKS REAL POWER 

TO MAINTAIN DESIRED POWER FACTOR 

WHILE LIMITING TOTAL APPARENT

POWER (KVA) TO 1 P.U.

REACTIVE

REAL POWER

REACTIVE POWER TRACKS REAL POWER 

TO MAINTAIN DESIRED POWER FACTOR 

WHILE LIMITING TOTAL APPARENT

POWER (KVA) TO 1 P.U.

Figure 5-4. Power factor control mode. 

The need for the site-level controller has emerged with the advent of larger PV projects that use 

multiple inverters to achieve the aggregate output power from the site. Multiple inverters are 

preferable to a single large inverter because of the physical layout of these projects over a large 

area and the logistics associated with providing the site-wide power collection circuits. The grid 

interconnection rules for these sites usually specify the required behavior at the point of 

interconnection (POI) with the utility MV feeder. Measurements at the POI are not usually 

available (or needed) in the individual inverter control systems, so the site controller provides a 

common local center of intelligence where higher-level power management algorithms can be 

executed. The site controller also serves as a communications hub for the site, exchanging 

commands and status information with the utility via SCADA and with the individual inverters 

via local serial communications. Figure 5-5 illustrates the role of the site controller. 
56

Utility Control 

Center

DC

AC

PV

DC

AC

DC

AC

DC

AC

PV PV PV

MV

LV

GEN

UNITS

SITE

CONTROLLER

modbus

SCADA RTU V, I SCADA RTU

DC

AC

PV

DC

AC

DC

AC

DC

AC

PV PV PV

MV

LV

GEN

UNITS

SITE

CONTROLLER

modbus

SCADA RTU V, I SCADA RTU

MV FEEDER

MV FEEDER

PV GENERATION SITE NO. 1

PV GENERATION SITE NO. 2

Commands/Status Commands/Status

Utility Control 

Center

DC

AC

PV

DC

AC

DC

AC

DC

AC

PV PV PV

MV

LV

GEN

UNITS

SITE

CONTROLLER

modbus

SCADA RTU V, I SCADA RTU

DC

AC

PV

DC

AC

DC

AC

DC

AC

PV PV PV

MV

LV

GEN

UNITS

SITE

CONTROLLER

modbus

SCADA RTU V, I SCADA RTU

DC

AC

PV

DC

AC

DC

AC

DC

AC

PV PV PV

MV

LV

GEN

UNITS

SITE

CONTROLLER

modbus

SCADA RTU V, I SCADA RTU

DC

AC

PV

DC

AC

DC

AC

DC

AC

PV PV PV

MV

LV

GEN

UNITS

SITE

CONTROLLER

modbus

SCADA RTU V, I SCADA RTU

MV FEEDER

MV FEEDER

PV GENERATION SITE NO. 1

PV GENERATION SITE NO. 2

Commands/Status Commands/Status

Figure 5-5. Site controller generates real and reactive power management commands for multiple 

inverters in utility-scale PV projects. 

5.3.4 Effect of Inverter Output Power on Distribution Feeder Voltage 

Voltage regulation on typical distribution feeders is achieved by switching taps on various kinds 

of transformers and also by means of reactive power injection from fixed or switched capacitor 

banks. In addition to the switching action associated with voltage regulation, the electrical loads 

connected to a typical feeder are constantly changing. A distribution system can thus be a rather 

complicated and very variable power circuit. However, it is instructive to consider a greatly 

simplified constant representation of a distribution feeder to illustrate the effect that might be 

expected from the connection of a PV generating system. 

Viewed from the bus at the POI between the feeder and the PV system, the 60 Hz impedance of 

the feeder is essentially Z = (R + jX) where X is mostly positive (i.e. inductive). Real power 

flowing away from the bus causes an increment in the local voltage magnitude mainly due to the 

drop across R. When reactive power is flowing away from the bus (i.e. when the current flowing 

away from the bus lags the voltage) it causes a local voltage magnitude increment due to the 

drop across X. The reactance, X, usually dominates over R in transmission and distribution 

circuits, especially in transformers. Reactive power injection (or absorption) at the PV bus 

therefore provides an effective means of increasing (or lowering) the voltage at the point of 

connection. 

Medium voltage distribution feeders vary widely in terms of length of line from the transmission 

substation, voltage, type and physical disposition of conductors, grounding schemes, etc. 

Accordingly the expected problems from the addition of high penetration levels of PV also 

depend on the particular feeder that is being considered. In this section we will focus on the ways 

in which high-penetration PV can affect feeder voltage under different conditions and discuss the 

positive role that PV inverters can play in terms of steady state and dynamic voltage regulation. 
57

Figure 5-6 shows the simplified representation of a PV system connected to a distribution feeder 

with 60 Hz impedance Z = (R + jX) pu. Obviously this model is highly simplistic, but it does 

capture the essence of the system captured at one point in time. The voltage at the utility 

substation is assumed to be constant with amplitude 1 pu, and the PV system output is S = (P + 

jQ) pu. All per-unit values are based on the PV system rating. Using this model, and assuming 

the PV system to be operating at unity power factor (Q = 0), the bus voltage at the system was 

calculated for the full range of real power output. The calculation was repeated for four different 

values of R, in each case assuming an X/R ratio of 4. The results, plotted in Figure 5-7, provide a 

quick overview of the different ways in which the bus voltage can be affected, depending on the 

feeder impedance. In each case, all of the reactive power absorbed by the feeder inductance is 

supplied from the substation. For the shorter line, with lower impedance, the resistance, R, 

dominates and the voltage rises approximately linearly with respect to output power. As the line 

length is increased (or the impedance is otherwise increased), the feeder inductance begins to 

dominate, causing the bus voltage to fall for generated power above a certain level. For a very 

long line the voltage at the PV bus can fall below the substation voltage, rapidly collapsing to the 

point where the inverter reaches its current limit. For a given X/R ratio in this scenario, the 

maximum bus voltage is the same, regardless of the total feeder impedance, but it occurs at 

different output power levels. The maximum bus voltage is higher for lower values of X/R, and it 

occurs at higher output power levels. 

R + j.X

V

1 0o s =

DISTRIBUTION FEEDER

SUBSTATION

UTILITY PV GENERATING

STATION

V

V αo p =

S

= P + j.Q

Figure 5-6. Simplified representation of a distribution feeder with PV generator connected. 
58

Figure 5-7. PV bus voltage versus real power generated. Inverter operates at power factor = 1. 

A further set of calculations was performed for the same feeder impedances and the same range 

of real power output from the PV system, but now assuming that the PV bus is automatically 

regulated at 1 pu by means of reactive power output generated by the system. The results are 

plotted in Figure 5-8a. The output power factors corresponding to the operating points shown in 

Figure 5-8a are plotted in Figure 5-8b. Figure 5-8a shows that in every case considered a 

relatively small amount of reactive power generated or absorbed at the PV system (~ 0.2 pu or 

less) can completely compensate for any voltage variation at the PV bus that would otherwise be 

caused by the generated real power output. The required level of reactive power will be different 

for different feeder impedances and X/R ratios and will also depend on the reactive loads 

connected, but the same basic principle is valid in most practical cases. In this example, it was 

necessary for the PV system to absorb Q at most operating points in order to regulate the voltage 

to 1 pu. A further observation, from Figure 5-8b, is that a wide range of power factors would be 

needed to hold the voltage constant over the range of real power output. A constant power factor, 

selected for one operating point (say full output), would result in voltage deviations at other 

output power levels. 
59

ABSORBING Q

GENERATING Q

Figure 5-8a. PV reactive power output versus real power generated. PV inverter holds the bus 

voltage at 1 pu. 

Figure 5-8b. PV inverter output power factors corresponding to Figure 5-8a. 

These results illustrate the general effect that an inverter-based PV system may be expected to 

have on different types of distribution feeders. The necessary reactive power output from the PV 

system can be determined in a variety of different ways, requiring a variety of different response 

times ranging from very slow to very fast. As mentioned before, there is still no consensus as to 

the proper way to use reactive power generation. However, what is certain is that local injection 

of reactive power on a distribution feeder can be used for voltage regulation and can correct 

voltage deviations caused by generated real power, as well as correcting for "pre-existing" 
60

conditions on the feeder. One of the main benefits of regulating feeder voltage by local reactive 

power generation is that the local VAr source can supply the reactive power requirements of 

nearby loads, thus reducing the overall current loading at the substation and reducing the power 

losses on the feeder. 

5.3.5 Simplified Distribution Feeder with Large PV System Connected 

To illustrate some of the capabilities and potential benefits of an inverter-based PV system for 

voltage control, a simplified benchmark distribution feeder is defined in the one-line diagram in 

Figure 5-9. The layout of the feeder and the total loading is loosely based on a proposed project 

in Massachusetts, recently submitted to National Grid for approval. The simplified representation 

of the system does not include any conventional voltage regulating equipment, and the 69 kV 

sub-transmission bus has been assumed to be infinite. The bus designations and the load 

distribution are hypothetical, but the line impedances are consistent with tables. Essentially 

Figure 5-9 is a long 13.8 kV feeder with a 5 MVA PV system at the end. Load flow and detailed 

transient simulation studies have been used to illustrate the capability of the PV inverters to 

actively regulate the voltage at the point of connection. 

Figure 5-9. Simplified benchmark system with a 5 MVA PV system connected to a 13.8 kV feeder. 
61

5.3.5.1 Steady State Analysis with Voltage Control at the PV System 

Two simple scenarios are considered. In the first, the PV system is producing 4 MW with Q = 0 

(i.e. pf = 1). The blue bars in Figure 5-10 show the feeder voltage profile for this case, and 

Figure 5-11a shows the corresponding values of P, Q generation, minus load, for each bus. Note 

the heavy reactive loading (2.949 MVAr) through the substation transformer at the transmission 

bus (No. 1) and the voltage sag on the line (well outside acceptable MV limits, but remember no 

taps, regulators, or capacitors are in use). 

In the second scenario, the PV system is automatically generating VArs to keep the voltage at 

Bus No. 9 at 1 pu. The red bars in Figure 5-10 show the improved voltage profile. Figure 5-11b 

shows the corresponding P, Q profile. The PV system Q output is now 1.234 MVAr, while the 

substation reactive load has dropped to 1.595 MVAr. Feeder losses have also dropped by 38 kW. 

Figure 5-10. Feeder voltage profile with and without voltage control at the PV site. PV system 

output, P = 4 MW. No conventional compensation (regulators, capacitors, etc.). 

 
62

P and Q (Generation - Load)

With No VAR Generation at PV Site (Bus 9)

3.302

4

2.949

-2

-1

0

1

2

3

4

5

BUS NO. 123456789 MVAR / MW

MW

MVAR

Figure 5-11a. Feeder bus P, Q (gen - load) with no reactive power generation at the PV site 

(corresponding to the blue bars in Figure 5-10). 

P and Q (Generation - Load)

With Voltage Control at PV Site (Bus 9)

3.264

4

1.595 1.234

-2

-1

0

1

2

3

4

5

BUS NO. 123456789 MVAR / MW

MW

MVAR

Figure 5-11b. Feeder bus P, Q (gen - load) with reactive power generation at the PV site used to 

maintain Bus No. 9 voltage at 1 pu (corresponding to the red bars in Figure 5-10). 

The load flow analysis has also been used to produce a quasi-dynamic illustration of the effect on 

the feeder voltage profile as the real power production from the PV site changes. The same two 

scenarios are considered for the PV system, i.e. 1) Q = 0 and 2) automatic voltage control at the 

PV site. Figure 5-12a plots the bus voltages as the P output from the PV system is dropped from 

4 MW to zero and back again, while Q = 0. Figure 5-12b shows the second case, which is similar 

but now with Q output generated by the PV system to keep the Bus No. 9 voltage at 1 pu. Note 

that these illustrations are simply a succession of load flow solutions showing the steady state 

locus for different P, Q output from the PV system, and not a true time-domain transient 

simulation. 
63

Figure 5-12a. Feeder voltage profile plotted as PV system real power drops from 4 MW to zero and 

back. Q output = 0. In this case the voltage at the PV system is not controlled. 

Figure 5-12b. Same P output as for Figure 5-12a, but here the PV system generates Q to keep the 

local (Bus 9) voltage at 1 pu. 
64

5.3.5.2 Demonstration of Fast Automatic Voltage Control 

The simplified benchmark feeder system shown in Figure 5-9 has been translated into a detailed 

transient simulation model of the three-phase system including the differential equations for all 

circuit elements. In particular, the PV system is modeled in great detail, including every aspect of 

the digital control system for the inverter. For this type of study, the involvement of the inverter 

manufacturer is essential because proprietary design details are usually needed. The physics 

equations governing the behavior of the PV array are also represented in detail, allowing basic 

input quantities such as solar irradiance to be varied as a function of time. The top-level model 

diagram is shown in Figure 5-13a, with more detail on the main elements of the PV unit 

subsystem shown in Figure 5-13b. Note that the loads are modeled differently in Figure 5-13a 

(constant impedance loads specified at base voltage and frequency) and Figure 5-9 (constant P, 

Q loads). Constant P, Q loads are difficult to implement in transient simulation. Note also that 

the 5 MW aggregate output of the site typically originates from, for example, 10 separate 500 

kW inverter units with multiple coupling transformers, typically around 1 MVA each. To 

achieve a manageable transient model for grid interconnection studies, these multiple inverters 

and transformers are treated as a single lumped equivalent unit with 5 MVA rating. 

The objective for creating this transient system model is to illustrate the ability of a PV inverter 

to autonomously perform fast automatic local voltage control at the point of connection to a 

distribution feeder. As discussed earlier, it is possible for the inverter to achieve voltage control 

in a sub-cycle time frame because both reactive power and three-phase voltage are defined on an 

instantaneous basis. In order to demonstrate this capability, the inverter controls in the model 

were modified to incorporate an automatic voltage control system. The controller commands 

rapid changes in reactive power in order to correct errors in the measured voltage feedback. Two 

cases were studied, one with the voltage controller disabled (and no reactive power generation) 

and one with the automatic voltage control enabled. In each case, the PV system is initially 

running under real power curtailment at 4 MW output (although the available solar power from 

the array is higher). At t = 0.2 the irradiance starts to drop from 1000 W/m2

 at a rate of 104 

W/m2/s. At t ≈ 0.225 it crosses the threshold for supporting the curtailed power output, and site 

output power starts to fall. After 80 ms the irradiance reaches 200 W/m2 where it holds until 

t = 0.4, then rises again to 1000 W/m2

 at the same rate it dropped. This is a rather extreme 

interpretation of a passing cloud, although these fall and rise rates for irradiance might possibly 

occur. 

Figure 5-14a shows the waveforms obtained for the case with voltage control disabled. As 

expected from the earlier steady state analysis, in this case we see a large voltage variation at 

each of the feeder buses due to the rapid transition of output power from the PV system. Figure 

5-14b shows the case with fast automatic voltage control enabled. In this case the voltage control 

greatly reduces the voltage variations that occur over the length of the feeder. 

In the earlier steady state load flow analysis, we assumed that the PV inverter would generate 

precisely the reactive power needed to maintain the voltage at 1 pu at Bus No. 9. What the 

transient case in Figure 5-14b serves to show is that a fast automatic voltage controller using a 

relatively small amount of locally generated reactive power can, in fact, hold the local bus 

voltage practically constant during short-lived transient disturbances. Note that the initial current 

output from the PV system in Figure 5-14b is roughly the same as in Figure 5-14a despite the 

higher Q output. This is due to the higher bus voltage in the Figure 5-14b case. It is reasonable to 
65

assume that this voltage control capability could also be used to reduce the voltage flicker that 

might otherwise be caused by such events. In the following section we investigate this 

hypothesis further, using the transient simulation model to show the improvement that could be 

achieved. 

Figure 5-13a. Simulink transient model of the system in Figure 5-9. 

Figure 5-13b. PV unit subsystem in Figure 5-13a. 
66

Figure 5-14a. No VAr output (pf = 1) at PV site during PV power dip. Bus No. 9 voltage is not 

controlled. 
67

Figure 5-14b. PV system inverter actively controls the voltage at Bus No. 9 during PV power dip. 

 

5.3.5.3 Fast Voltage Control for Flicker Reduction 

The term "flicker" originates from the troublesome variation in light intensity, from incandescent 

lights in particular, as a result of even very small variations in voltage. Eye sensitivity, 

perception, and human tolerance play a large part in the assessment of flicker, which has made it 

difficult to define quantitatively in absolute engineering terms. Flicker sensitivity has been found 

to peak for voltage variations around 9 Hz, so flicker problems have traditionally been associated 

with industrial processes such as large electric arc furnaces and welding systems that draw 
68

fluctuating power at or around these frequencies. However, the concept of flicker has now been 

extended to cover all kinds of voltage fluctuations through the use of short-term (10 minutes) 

assessment (Pst) and long-term (a few hours) assessment (Plt). The International Electrotechnical 

Commission (IEC) has developed standards for measuring voltage flicker. The IEC method for 

flicker measurement is defined in the IEC Std. 61000-4-15 (formerly the IEC 868). IEC Standard 

61000-3-7 also provides target limits for Pst (0.9) and Plt (0.7) as measured according to the 

standard. These standards have enabled consistent measurements to be made at existing 

locations, but it remains difficult to assess the possibility of excessive flicker at the planning 

stage because the result is critically dependent on the time-varying nature of the expected voltage 

variations. The issue is further complicated by the random nature of power fluctuations from a 

PV system, subject to passing cloud cover. 

We have postulated that the fast automatic voltage control demonstrated by the results of Figure 

5-14b can have a beneficial effect in reducing the flicker caused in a distribution system due to 

rapid fluctuation of output power from a PV generator. To test this hypothesis, we would like to 

use the detailed transient model of Figure 5-13 to generate the voltage waveform at one of the 

feeder buses in the benchmark system, and from this data calculate the level of flicker according 

to the IEC standard. By repeating the experiment with and without the fast voltage control 

enabled, we would obtain an absolute assessment of the improvement in the flicker level due to 

the voltage control. Unfortunately the transient model runs with a 1 μs time-step and it would be 

impractical (though not impossible) to simulate the 10 minutes of real-time voltage data required 

for Pst assessment. In order to facilitate the proposed experiment, a slightly simplified process 

was developed. The approach that was used is to simulate one "cloud cover cycle" such as that 

simulated in Figure 5-14a and Figure 5-14b and then to assume that the event is repeated 

continuously for 10 minutes. In this way, 10 minutes of voltage waveform data can rapidly be 

generated. This approach introduces an unrealistic periodicity for the cloud cycle into the 

experiment, but the response to each event is accurately simulated, thus allowing us to capture 

the changes in the voltage transitions due to the voltage control system. These voltage transitions 

are thought to account in large part for the flicker produced. If the same periodicity for the cloud 

cycle is consistently used, this method at least allows a comparative assessment to be obtained 

for the two different operating conditions. 

An accurate, calibrated, discrete-time implementation of the IEC Flickermeter was then used to 

post-process the voltage measurement data and generate a value of Pst. Figure 5-15a shows a 

portion of the 10 minutes of data (4,000 Hz sampling) that was generated by repeating the Bus 

No. 7 A-phase voltage waveform for the event simulated in Figure 5-14a (i.e. with no VAr 

generation). This data was passed through the IEC Flickermeter and yielded a Pst measurement 

of 3.6492, which is well beyond the recommended limit of 0.9. Figure 5-15b shows the 

corresponding voltage data for the event in Figure 5-14b (i.e. with fast voltage control), which 

yielded a value of Pst = 0.3833, which is well inside the recommended limit. While these results 

may be open to interpretation, they do at least indicate the significant reduction of flicker that 

can be achieved by fast voltage control. 
69

Figure 5-15a. Bus No. 7 A-phase voltage (scaled to show only the peak variation) – (Figure 5-14a 

event repeated over 10 minutes). Pst = 3.6492 (> 0.9 – unacceptable). 

Figure 5-15b. Bus No. 7 A-phase voltage (scaled to show only the peak variation) – (Figure 5-14b 

event repeated over 10 minutes). Pst = 0.3833 (< 0.9 – acceptable). 

5.4 Main Issues Delaying or Blocking the Connection of Large PV 

Projects 

With the introduction of favorable feed-in tariff (FIT) rates and tax credits for renewable power, 

and the rapid decline in the cost of PV modules, there has been an unprecedented rush to install 

large PV projects in many parts of the world. Consequently, utilities have been inundated with 

requests for interconnection to the grid. In many cases the utilities have been unprepared to deal 

with this, especially in the case of large-scale projects (5 to 10 MW and even higher) requesting 

interconnection at distribution system voltage levels. In the United States the prevailing IEEE 

1547 standard does not provide the answers needed to reassure utilities because these highpenetration scenarios were simply not anticipated when the standard was drawn up. So in some 

cases project approvals are on hold simply because the utility is waiting for clear guidelines to 

emerge that will allow them to determine what additional measures (if any) are needed for the 

project to proceed safely. In other cases, especially in other countries and in Hawaii, utilities and 

various regulatory bodies have been hastily drawing up their own rules and regulations for 

interconnection of DR. In many cases these new rules have had the effect of slowing the progress 

of PV projects as developers scramble to understand the requirements and their financial 

impacts. Examination of some of these rules is instructive because it highlights some of the 
70

utility concerns and shows some of the ways in which the advanced capabilities of inverters can 

be utilized to address them. 

Some of the main issues and requirements currently affecting the interconnection of new PV 

systems are as follows: 

• Short circuit capacity limitation. This applies in cases where the short circuit level has been 

assessed to be so close to the maximum capacity of existing circuit breakers that it would be 

unsafe to connect any additional local generation that would contribute in any way to 

increase the fault level. Surprisingly, this unlikely scenario apparently exists at many 

transformer stations in Ontario, Canada, where attractive feed-in tariffs (FIT) have been 

announced. As developers rush to take advantage of the FIT, interconnection of any new 

distributed generators through these transformer stations has been refused. 

• Power/distance limitation. This applies especially in the case of the very long feeders 

encountered in Canada. These may be 44 kV feeders but are still classed as distribution level. 

The concern in this case is the regulation of voltage over a range of real power output from a 

PV system located far from the transformer station. Typically the utility allows connection of 

DR that falls within their acceptable power/distance rules and specifies remedies for those 

that are not acceptable. Such remedies are often expensive and include re-conductoring the 

feeder line, re-locating the system, or providing a separate reactive power generator to 

regulate voltage at the system location. The goal for many developers, whose projects are 

threatened by this rule, is to convince the utility to allow the PV inverters to participate in 

reactive power generation instead of using a separate VAr generator. 

• Transfer trip for PV system. While it is generally understood that transfer trip schemes are 

needed for synchronous machine generators, there is considerable disagreement over the 

need for these expensive schemes in the case of PV inverters that are usually certified to be 

compliant with the anti-islanding requirements of IEEE 1547. Often the utility will require a 

transfer trip because they question the effectiveness of anti-islanding when there are multiple 

PV units connected on one feeder. The cost of providing a transfer trip scheme can sink the 

budget for a PV project. 

• Special custom requirements for reactive power deployment. As the capability of inverters to 

generate reactive power becomes more widely understood, utilities are beginning to specify 

reactive power generation as a condition for interconnection. In some cases this calls for a 

fixed or adjustable power factor. In other cases a schedule is prescribed for reactive power 

output versus voltage or for reactive power output versus real power output. In general, rules 

for distribution feeders have stopped short of allowing generators to perform continuous 

autonomous local voltage control (as is commonly done in transmission systems).

• Customized ride-through requirements. Ride-through requirements differ considerably in 

regard to voltage levels and duration. In some cases the generator is required to generate 

reactive power according to a special schedule when voltage deviates beyond set limits.

• Voltage quality requirements at the PV station. This is an area where there is often 

disagreement about who is responsible for the grid voltage quality. It is impractical for a PV 

project developer to guarantee voltage quality at the point where the system is connected to 

the grid. Apart from any other consideration, the voltage quality depends on the impedance 
71

of the grid and the presence of other harmonic sources throughout the system. It could be 

possible to fail to meet a voltage quality criterion without ever turning on the PV system. 

Undeterred by these facts, utilities still try to insert voltage quality requirements into power 

producer agreements and regulations.

• PV system (ac output) grounding method. In some cases utilities are insisting on the 

provision of a solidly-grounded primary neutral at the PV inverter isolation transformer. It is 

easy to demonstrate that this is bad practice, especially when the upstream transformer in the 

distribution system is also solidly grounded with low zero sequence impedance. However, it 

is difficult to persuade utilities to change their interpretations of their standard practice.

• Transient over-voltage on islanding. When impact studies show an unacceptable rise in 

inverter terminal voltage following sudden interruption of the grid connection, the utility will 

sometimes insist on the provision of special surge arrestors. This is a problem that is easily 

addressed through inverter control capabilities and need not be the cause for large additional 

equipment expense. 

• General uncertainty about impact of a high-penetration PV project on an existing feeder. In 

these cases the utility may commission impact studies that will result in a number of special 

requirements being stipulated as the condition for approval. Sometimes the impact studies 

still leave room for doubts, and the approval may be further delayed. Main issues are usually 

the following: 

o Increased switching operations at line regulators, LTC, capacitor banks 

o Conductor and other equipment loading 

o Flicker 

o Protection relay settings with reverse power flow possible. 

5.5 Conclusions 

The advanced inverter capabilities we have discussed in this report could clearly facilitate high 

penetration levels of PV generation and also lead to potential savings for utilities by reducing 

line losses and drastically reducing regulator switching operations, thereby extending the life of 

equipment, reducing maintenance costs, and possibly deferring the cost of new capacitor banks 

and other equipment. In addition a new PV system on a feeder could improve the pre-existing 

power quality. 

On the other hand, owner/operators who install inverters to interface their power plant to the grid 

would prefer that the inverters only be used to deliver revenue-producing real power. Providing 

ancillary services to the utility incurs a cost, either in terms of lost power production or power 

losses or other operating costs. The preferred business model for this relationship is not yet clear. 

It raises issues about who pays for what, as well as some more basic questions such as liability 

(who is responsible for maintaining system voltage) and how to measure lost production from 

variable sources for accounting purposes. These thorny issues have yet to be resolved before the 

benefits discussed here can be fully realized. 

The report has shown that the advanced inverters in renewable power plants on distribution 

feeders can use their fast VAr generating capability to automatically regulate the voltage at the 
72

point of connection, thereby correcting for voltage swings due to their own real power 

fluctuations, reducing flicker that would otherwise occur, and improving power quality 

compared with the pre-existing conditions. Changes to existing regulations are needed if these 

potential benefits are to be fully realized. 

The inverters that are used to connect PV power sources to the grid should be viewed as valuable 

resources for the management of the distribution system. Most of their unique control 

capabilities stem from the fact that inverters provide fast and flexible control of their output 

current (unparalleled by other power generators) and hence the real and reactive power injected 

into the grid. 

The most important remaining questions for the integration of inverters into distribution systems 

lie in the area of voltage control. As we have seen, there are no fundamental technical barriers 

that would prevent PV inverters from actively and automatically controlling the voltage at their 

point of connection. Instead, the barriers lie in the unwillingness to adapt the existing 

infrastructure of the distribution system where necessary and to modify traditional practices to 

allow this to happen. This change will not come about quickly but, as with all innovation in the 

electric utility industry, will only start to happen after successful demonstration projects in the 

field have shown that the proposed new practices are safe, reliable, and beneficial. 

 
73

6 References 

[1] Nelsen D., Perez R., Holmes D. and Nelson M. “Megawatts of Solar,” in Transmission & 

Distribution World magazine, June 1, 2009, available online: 

http://tdworld.com/substations/edison-solar-energy-20090601/. 

[2] SCE Interconnection Handbook; available online: 

http://www.sce.com/NR/rdonlyres/851128D1-6820-43DD-BAD4-

B30DE27B0F35/0/Interconnection_Handbook_090317.pdf. 

[3] California’s General Rule 21; available online: 

http://www.energy.ca.gov/distgen/interconnection/california_requirements.html 

http://www.sce.com/NR/sc3/tm2/pdf/Rule21.pdf. 

[4] Hamilton, S., et al. "Circuit of the Future: Interoperability and SCE's DER Program," in 

Proceedings of Bulk Power System Dynamics and Control Conference, August 19-24, 2007, 

Charleston, South Carolina, USA; available online: 

http://www.cems.uvm.edu/~phines/publications/2007/Hamilton_2007_IREP.pdf. 

[5] SCE press release for Avanti circuit; available online: 

http://www.edison.com/files/0607_sce_avanti.pdf. 

[6] Southern California Edison ARRA projects; available online: 

http://www.energy.ca.gov/2010_energypolicy/documents/2010-07-

13_workshop/presentations/06_SCE-Haralson.pdf. 
74

Appendix A. Summary of Interconnection Requirements for 

SCE Distribution Systems 

This appendix summaries SCE’s requirements as stated in the SCE interconnection handbook 

and California Rule 21 for interconnecting and operating a generation facility in parallel with 

SCE’s distribution networks. 

I. General Facility Design and Operation Requirements 

It is required that the INTFAC (Interconnection Facility) complies with NERC Standards, 

Facility Connection Requirements (FAC-001), and ANSI/IEEE 1547-2003. The INTFAC 

is responsible for conforming to applicable joint NERC and Western Electricity 

Coordinating Council (WECC) standards, California Independent System Operator 

(CAISO) and SCE reliability criteria, Federal Energy Regulatory Commission (FERC) 

regulation, as well as good engineering and utility practice. INTFACs have the 

responsibility to ensure that they comply with the most recent version of the 

Interconnection Requirements. Requirements provided in this document are applicable to 

interconnecting generators intending to operate in parallel with SCE grid. 

The parallel generator becomes a part of SCE’s electrical system, and must, therefore, be 

considered in planning the protection of SCE’s system. Prudent electrical practices 

require that certain protective devices (relays, circuit breakers, etc.) specified by SCE 

must be installed at any location where a Producer desires to operate its wholesale 

generating facilities in parallel with the SCE system. Other modifications to electrical 

system configuration or protective relays may also be required in order to accommodate 

parallel generation. SCE assumes no responsibility for determining protective equipment 

needed to protect Producer’s facilities. SCE requires that such facilities also have 

adequate protective devices installed to react to abnormal electric system conditions and 

isolate from SCE’s electric system. 

 In case of fault in SCE system the INTFAC should stop producing. 

 With SCE’s approval, it is possible to use scheme for transferring 

Producer’s loads from SCE’s Distribution System to Producer’s 

Generating Facility. The scheme may be used in lieu of the protective 

functions required for parallel operation. 

 When islanding occurs, all generating facilities within the electrical island 

must be disconnected to prevent continued operation. The larger the 

installation, the greater the effect it may have on SCE’s electrical system. 

SCE may require voltage and frequency protective functions or relays to 

detect islanding and shut down generation during islanding periods. 

Requirements are typically minimal for small installations, but increase in 

scope and/or complexity as the size of the generation installation 

increases. SCE may require voltage and frequency protective functions or 

relays to detect islanding and shut down generation during islanding 

periods. 
75

II. Protection Requirements and Categories for Parallel Generators 

SCE’s requirements identify three different categories for Producer wholesale generating 

facilities connecting to the SCE system each with distinctive protection requirements. If 

multiple generation facilities are connected to the SCE system at a single point of 

interconnection, an aggregate capacity should be used to determine applicable categories. 

These categories are: 

1. Interconnection voltage above 34.5 kV 

2. 200 kVA and above capacity, interconnection voltage 34.5 kV or below 

3. Less than 200 kVA capacity, interconnection voltage 34.5 kV or below 

i. Protection Requirements for Category 1: Voltage Over 34.5 kV

The protection requirements for INTFAC in this category are: 

1. Typically SCE-owned and controlled circuit breaker to disconnect 

generating facilities during SCE system trouble. 

2. Synchronizing supervision relays (exception applies to inverter based 

generator) and telecommunications as required. 

3. For non-inverter based (conventional) generators, either induction 

starting, automatic synchronizing or manual synchronizing supervised 

by a synchronizing relay must be provided by the Producer. 

4. Manual synchronizing without a supervising relay is not permitted. 

5. Protection related telecommunications may be required as determined 

by SCE Protection Engineering. 

SCE-owned and maintained protective relays to provide protection functionality 

indicated above: 

1. Short Circuit Protection (Devices 51V or 67V, 51N or 59G) 

2. Islanding Protection (Devices 27/59, 81-0, 81-U) 

3. Breaker Closing/Reclosing Control (Devices 25, 47, 79) 

4. Loss of Synchronism (Device 78) 

ii. Protection Requirements for Category 2: Total Generation 200 kVA and Above, 

Voltage at 34.5 kV or Below 

The protection requirements for INTFAC in this category are: 

1. Detect and clear the generator(s) from short circuits or grounds on the 

SCE system serving the Producer. 

2. Detect the voltage and frequency changes in case of islanding. 

3. Prevent re-paralleling the Producer's generation, after an incident of 

trouble. 
76

Protection devices which may be required to satisfy the above requirements are: 

1. Phase over-current trip devices (Device 51, 51V, or 67V) 

2. Residual over-current or over-voltage relays to trip for ground faults 

on the SCE system (Devices 51N or 59G) 

3. Under/over-voltage relays (Device 27/59) 

4. Under/over-frequency relays (Device 81) 

5. Phase sequence under-voltage relay (Device 47/27) 

6. Automatic Separation: If the Producer desires to automatically 

separate from SCE and commence isolated operation upon loss of the 

SCE source, additional devices will be necessary to effect the 

separation. 

Other specifications need to be taken into account for choosing the relays are: 

1. Utility Quality Relays as opposed to industry quality relay should be 

selected. 

2. Relay Operation Recorders are needed. 

3. Relay Testing should be performed prior to applying the relay. 

4. Four-wire Multi-grounded Neutral Distribution Circuits is required. 

For INTFAC based on induction generators or static inverters the phase over-current 

protective devices may not be required, since these generation sources will not deliver 

sustained over-currents. All other specified protective devices are required. 

iii. Protection Requirements for Category 3: Total Generation Less Than 200 kVA

1. Line Voltage Relay or Contactor 

2. Relays to Detect Islanding 

3. Fault Detection 

4. Four-wire Multi-grounded Neutral Distribution Circuits 

5. Dedicated Distribution Transformer 

6. Harmonic Requirements for inverters 

7. SCE Telecommunications 

8. Exception to Protection Devices: These requirements include, but are 

not limited to, the provisions of IEEE Standard 929, IEEE Standard 

1547, and UL Standard 1741. 

III. Operating Requirements

SCE may also require additional operating requirements specific to an INTFAC. If so, these 

requirements will be documented in SCE’s System Operating Bulletins (SOB), Substation 

Standard Instructions (SSI), and/or interconnection and power purchase agreements. SCE’s 

SOBs and/or SSIs specific to the INTFAC and any subsequent revisions will be provided by 
77

SCE to the INTFAC as they are made available. It is INTFAC’s responsibility to comply 

with applicable operating requirements. 

i. Voltage Variations 

The INTFAC should have no adverse effect on the voltage regulation of that portion of 

the SCE system to which it is connected. Also, the INTFAC shall not cause the service 

voltage at other customers' location to go outside the requirements of ANSI C84.1-1995, 

Range A (IEEE 1547-4.1.1). 

The step-up transformer ratio must be chosen such that the Producer can meet its voltage 

regulation obligation over the expected range of SCE system voltages. Step-up 

transformers must be equipped with no-load taps which provide ± 5% adjustment of the 

transformer ratio in 2.5% steps. The following voltage classifications apply to SCE 

distribution and sub-transmission systems: 

 Primary distribution voltage 2.4 to 34.5 kV (± 5% variation) 

 Subtransmission voltage 55 to 115 kV (± 5% variation) 

SCE uses various voltage regulation techniques to raise or lower primary distribution and 

subtransmission voltages in order to maintain the customer's service voltage at the 

desired level. Producers interconnected at primary distribution or subtransmission voltage 

levels must be able to withstand such voltage changes and to respond with proper power 

factor adjustment in order not to oppose or interfere with SCE's or the CAISO’s voltage 

regulation processes. The applicable voltage levels and response time of a generation 

facility to various levels of abnormal voltages are provided in the table below. 

Voltage at the Point of Common Coupling Maximum Trip Time # of Cycles 

120 V Base % of Normal 

Voltage 

60 Hz Nominal Seconds 

Less than 60 Volts 

>60 V or <106 V 

>132 V or <144 V 

>144 V 

Less than 50% 

>50% but <88% 

>110% but <120% 

>120% 

10 Cycles 

120 Cycles 

Normal Operation 

10% 

0.16 Seconds 

2 Seconds 

Normal Operation 

0.16 Seconds 

ii. VAr Correction

SCE shall not be obligated to supply or absorb reactive power for the INTFAC when it 

interferes with operation of the SCE transmission system. In subtransmission system an 

adequate VAr correction shall be provided for maximum coincident customer loads (onein-five year heat storm conditions), after adjusting for dependable local generation and 

loss of the largest local bypass generator. 
78

If power factor correction equipment is necessary, it may be installed by the INTFAC at 

the facility, or by SCE at SCE's facilities at the INTFAC’s expense. For SCE controlled 

subtransmission and distribution systems, power factor should be in the range of 0.95 

lagging to 0.95 leading at the point of delivery. 

iv. Reactive Power Supply Requirements for Inverter Systems

The following requirements are applicable for the dominant inverter technology utilized 

in today’s market (Forced-commutated Inverters). The requirements of Line-commutated 

Inverters (old technology) are not included: 

 Supply reactive power so that the generating facility does not impose any 

additional reactive power demand upon SCE other than the demand of loads 

within the facility. 

 It is not allowed that the producer delivers excess reactive power to SCE 

under normal operating conditions unless otherwise agreed to by SCE. 

 Under emergency operation, producer can deliver excess reactive power to 

SCE for ensuring voltage schedule compliance. 

 Producers connected to the subtransmission system or bulk power system 

(above 34.5 kV) must have the voltage regulation equipment and generator 

reactive power capability to maintain a voltage schedule or reactive power 

schedule prescribed. 

The size of any discrete step change in reactive output shall be limited by the following 

criteria: 

1. The maximum allowable voltage rise or drop (measured at the point of 

interconnection with the SCE system) associated with a step change in the 

output of the INTFAC’s reactive power equipment must be less than or 

equal to 1%; and 

2. The maximum allowable deviation from an INTFAC’s reactive power 

schedule (measured at the point of interconnection with the SCE system) 

must be less than or equal to 10% of the INTFAC’s maximum (boost) 

reactive capability. 

Inverter systems 200 kVA or less, which conform to the recommended practices in IEEE 

Standard 929-19 and which have been tested and approved for conformance to UL 

Subject 1741, are considered to have met all SCE’s reactive power supply requirements. 

v. Off-Nominal Frequency Requirements

It is the Producer’s responsibility to ensure conformance with the latest approved WECC 

Off-Nominal Generation Requirements. The CAISO is responsible for frequency control 

and therefore SCE can assume no responsibility for damage that occurs due to off 

nominal frequency operation. 

iii. Voltage Regulation/Reactive Power Supply Requirements
79

The following table shows the value of tripping time (cycles) based on the rating and 

frequency range of the generation facility: 

vi. Voltage Imbalance and Abnormal Voltage or Current Waveforms (Harmonics) 

SCE may require the facility to install equipment to eliminate the power quality problem. 

 Voltage Imbalance Criteria

 Unbalanced voltage level of an INTFAC should not exceed 1% at 

PCC at steady state condition. 

 Exceptions may be applied to the maximum range if it can be 

justified after a study conducted by SCE. In any case, the voltage 

imbalance should not reach higher than 1.5%. 

 INFACT responsibility to install mitigating devices. 

 Harmonics Criteria 

INTFACs are required to limit harmonic voltage and current distortion 

produced by static power converters or similar equipment. When the 

Generating Facility is serving balanced linear loads, harmonic current 

injection into SCE’s Distribution System at the PCC shall not exceed the 

limits stated in the table below. The harmonic current injections shall be 

exclusive of any harmonic currents due to harmonic voltage distortion present 

in SCE’s distribution system without the Generating Facility connected (IEEE 

1547-4.3.3.). The harmonic distortion of a Generating Facility located at a 

Customer’s site shall be evaluated using the same criteria as for the Host 

Loads. 
80

 

Individual 

harmonic order, h 

(odd harmonics) 

h<11 11≤h<17 17≤h<23 23≤h<35 35≤h Total 

demand 

distortion 

Max. distortion 

(%) 

4.0 2.0 1.5 0.6 0.3 5.0 

 Flicker Criteria 

The Generating Facility shall not create objectionable flicker for other 

customers on SCE’s Distribution System. To minimize the adverse voltage 

effects experienced by other customers (IEEE 1547 4.3.2), flicker at the PCC 

caused by the Generating Facility should not exceed the limits defined by the 

"Maximum Borderline of Irritation Curve" identified in IEEE 519-1992 (IEEE 

Recommended Practices and Requirements for Harmonic Control in Electric 

Power Systems, IEEE STD 519-1992). This requirement is necessary to 

minimize the adverse voltage effects experienced by other Customers on 

SCE’s Distribution System. Generators may be connected and brought up to 

synchronous speed (as an induction motor) provided these flicker limits are 

not exceeded. 

Photovoltaic Inverter Systems shall comply with IEEE 929-1999 and UL 1741. Utilityinteractive inverters do not require separate synchronizing equipment. Non-utility 

interactive or "stand-alone" inverters shall not be used for Parallel Operation with SCE’s 

Distribution System. The goal is providing high quality solar systems that promote 

highest energy production per ratepayer dollar, optimal system performance during peak 

demand periods, and appropriate energy efficiency (EE) improvement where solar 

systems are installed. 
81

Appendix B. Example XML Schema of Delivered Solar 

Resource Datasets 

- <PVOutputStatistics xmlns:xsi="http://www.w3.org/2001/XMLSchema-instance"

xmlns:xsd="http://www.w3.org/2001/XMLSchema">

- <Generators>

- <Generator>

<GeneratorId>Fontana</GeneratorId> 

- <Months>

- <Month>

<MonthNumber>1</MonthNumber> 

- <Hours>

- <Hour>

<HourNumber>0</HourNumber> 

<MaxPower_kW>0</MaxPower_kW> 

<AveragePower_kW>0</AveragePower_kW> 

<StandardDeviationPower_kW>0</StandardDeviationPower_kW> 

</Hour>

- <Hour>

<HourNumber>1</HourNumber> 

<MaxPower_kW>0</MaxPower_kW> 

<AveragePower_kW>0</AveragePower_kW> 

<StandardDeviationPower_kW>0</StandardDeviationPower_kW> 

</Hour>

+ <Hour>

+ <Hour>

+ <Hour>

+ <Hour>

+ <Hour>

+ <Hour>

+ <Hour>

+ <Hour>

+ <Hour>

- <Hour>

<HourNumber>11</HourNumber> 

<MaxPower_kW>1355</MaxPower_kW> 

<AveragePower_kW>980.9</AveragePower_kW> 

<StandardDeviationPower_kW>356.2</StandardDeviationPower_kW> 

</Hour>

- <Hour>

<HourNumber>12</HourNumber> 

<MaxPower_kW>1357.1</MaxPower_kW> 

<AveragePower_kW>967.8</AveragePower_kW> 

<StandardDeviationPower_kW>357.9</StandardDeviationPower_kW> 

</Hour>

- <Hour>

<HourNumber>13</HourNumber> 

<MaxPower_kW>1225.5</MaxPower_kW> 

<AveragePower_kW>856.9</AveragePower_kW> 

<StandardDeviationPower_kW>322.4</StandardDeviationPower_kW> 

</Hour>

- <Hour>
82

<HourNumber>14</HourNumber> 

<MaxPower_kW>972</MaxPower_kW> 

<AveragePower_kW>664</AveragePower_kW> 

<StandardDeviationPower_kW>244.1</StandardDeviationPower_kW> 

</Hour> 

 
83

Appendix C. Data Requirements for Distribution Feeder 

Model Development 

The following table provides a comprehensive list of data requirements for modeling a 

distribution feeder for the purpose of steady-state and dynamic impact studies. 

Data Category Component Required Data Note

1- Schematic diagram of the feeder that shows the equipment along the feeder (all 

the devices are listed in the second column of this table.) 3 copies per feeder

2- Power flow and short circuit model (CYMDIST, ASPEN, Synergy, etc.) CYMDIST for SCE

1- Rated Voltage (kV)

2- Operating voltage (kV)

3- Short circuit Capacity (MVA)

4- Voltage angel (degree or Radian)

5- Operating frequency (Hz)

6- Positive sequence impedance (HV side)

7- Zero sequence impedance (HV side)

8- Number of feeders

1- Rated Voltages (kV) for primary and secondary

2- Rated MVA

3- Series Impedance (Ω)

4- Winding configuration (primary/secondary)

5- Tap Setting for Manually adjusted seasonal tap, if applicable

6- LTC Settings for automatic tap adjustment, if applicable May not be in CYME

1- Substation Load (P&Q for HV side of transformer) - 8760 hourly or monthly 

profiles

2- Feeder load (P&Q) - 8760 hours or monthly profiles

3- Neighbor feeders load (a lump sum can be calculated from 1 and 2, if not 

available individually)

4- Location and size of large (fixed) loads - to be excluded from load allocation Customer information

1- Number, location and operating modes of feeder reclosers From CYMDIST

2- Number, location and operating mode of automatic feeder re-configuration 

switches May not be in CYME

1- Rated MVA

2- Impedance

3- Single phase or three phase

4- Delay time for turn on and turn of

5- Operating voltage boundary (set points)

6- No. of taps

6- Control mode

7- Location or Pole number

1- Rated kVAr

2- Control method (Manual or Voltage control)

3- Voltage boundary for turning off and on

4- Time delays

5- Location or Pole number

6- Cap bank status, if not fixed (manual) May not be in CYME

1- Length of each section

2- Conductor type of each section

1- Manufacturer name and data sheets

2- Inverter model diagram from the manufacturer

3- Generation capacity of the PV plant

4- Control and protection scheme used in the inverter model

1- MVA rating of the transformer associated with PV

2- Transformer configuration

3- Transformer impedance

4- Transformer rated voltages (kV)

PV Generation Profile 

(MW) Annual profile with the rosolution of 10 seconds or better SCADA data

Can be extracted from 

CYMDIST model

Automatic switches and 

recloser

Substaion data and 

Equivalent Source Model 

for HV system Can be extracted from 

CYMDIST model, if HV is 

modeled

Can be extracted from 

CYMDIST model, if HV is 

modeled

Load Data

Can be extracted from 

CYMDIST model

From SCADA Data

Interconnection drawings 

and design data (see next 

sheet)

PV Inverter

Manufacturer data (see 

next sheet)

Line Data

PV Transformer

Can be extracted from 

CYMDIST model

PV Generator Modelling

Distribution Network 

Modeling

Distribution Feeder 

Configuration

Capacitor Banks data, if 

applicable

Transformer at substation 

Voltage Regulators Data, if 

applicable