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Office of Energy Efficiency & Renewable Energy

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Contract No. DE-AC36-08GO28308

NREL/SCE High-Penetration PV 

Integration Project: Report on 

Field Demonstration of 

Advanced Inverter Functionality 

in Fontana, CA

Barry Mather

National Renewable Energy Laboratory

Technical Report

NREL/TP-5D00-62483

August 2014
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

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

NREL/SCE High-Penetration 

PV Integration Project: Report 

on Field Demonstration of 

Advanced Inverter 

Functionality in Fontana, CA 

Barry Mather

National Renewable Energy Laboratory

Prepared under Task No. SS12.2910

Technical Report

NREL/TP-5D00-62483

August 2014 
NOTICE

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Cover Photos: (left to right) photo by Pat Corkery, NREL 16416, photo from SunEdison, NREL 17423, photo by Pat Corkery, NREL 

16560, photo by Dennis Schroeder, NREL 17613, photo by Dean Armstrong, NREL 17436, photo by Pat Corkery, NREL 17721.

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Acknowledgments

This work was supported by the U.S. Department of Energy under Contract No. DOEEE0002061 with the National Renewable Energy Laboratory and by the California Public Utility 

Commission (CPUC) through the California Solar Initiative (CSI) Research, Development, and 

Deployment (RD&D) Program managed by iTron. Additionally, the project would like to thank 

Southern California Edison (SCE) and its constituent staff for their willing participation in this 

field demonstration of advanced photovoltaic (PV) inverter functionality to mitigate some of the 

impacts of high-penetration PV integration.
ii

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List of Acronyms

CPR Clean Power Research

DMU distribution monitoring unit

EDD Electrical Distribution Design

NREL National Renewable Energy Laboratory

PMU phasor measurement unit

PS pole switch

PV photovoltaic

RCS remote controllable switch

SCADA supervisory control and data acquisition

SCE Southern California Edison
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Abstract

The National Renewable Energy Laboratory/Southern California Edison High-Penetration PV 

Integration Project is (1) researching the distribution system level impacts of high-penetration 

photovoltaic (PV) integration, (2) determining mitigation methods to reduce or eliminate those 

impacts, and (3) seeking to demonstrate these mitigation methods on actual high-penetration PV 

distribution circuits. This report describes a field demonstration completed during the fall of 

2013 on the Fontana, California, study circuit, which includes a total of 4.5 MW of 

interconnected utility-scale rooftop PV systems. The demonstration included operating a 2-MW 

PV system at an off-unity power factor that had been determined during previously completed 

distribution system modeling and PV impact assessment analyses. Data on the distribution circuit 

and PV system operations were collected during the 2-week demonstration period. This 

demonstration reinforces the findings of previous laboratory testing that showed that utility-scale 

PV inverters are capable of operating at off-unity power factor to mitigate PV impacts; however, 

because of difficulties setting and retaining PV inverter power factor set points during the field 

demonstration, it was not possible to demonstrate the effectiveness of off-unity power factor 

operation to mitigate the voltage impacts of high-penetration PV integration. Lessons learned 

from this field demonstration are presented to inform future field demonstration efforts.
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Table of Contents

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

2 Overview of the Fontana, California, Study Circuit........................................................................... 2

3 Overview of Field Demonstration ....................................................................................................... 4

4 Field Demonstration Results and Analysis ....................................................................................... 5

5 Conclusions and Lessons Learned.................................................................................................. 13

References................................................................................................................................................. 14
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List of Figures

Figure 1. Simplified circuit diagram of the Fontana, California, study circuit showing the general 

connectivity and equipment placement. ............................................................................................ 3

Figure 2. Real and reactive power flow and the calculated operating power factor of the 2-MW PV 

system being demonstrated on a clear weather day (September 27, 2013)................................... 5

Figure 3. Real and reactive power flow and the calculated operating power factor of the 2-MW PV 

system being demonstrated on a partly cloudy weather day (September 26, 2013)..................... 7

Figure 4. Real and reative power flow and the calculated operating power factor of the 2-MW 

system being demonstrated during the entire demonstration period............................................ 8

Figure 5. Reactive power flow from the substation to the distribution circuit and the reactive 

power flow from the 2-MW PV system on September 26, 2013, the second day of the 

demonstration period......................................................................................................................... 10

Figure 6. Real power produced and voltage near the point of common coupling of the PV system 

(test) on September 26, 2013, the second day of the demonstration period, and the voltage 

near the point of common coupling during a typical day when the PV system was operating at 

unity power factor (BL = baseline).................................................................................................... 12

List of Tables

Table 1. Fontana, California, Study Circuit Characteristics ................................................................... 3
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1 Introduction

The field demonstration of the off-unity power factor operation of a photovoltaic (PV) system for 

the purposes of mitigating the voltage-related PV impacts on the interconnected distribution 

system is described in the following four sections and had the following objectives:

• Demonstrate the capability of PV inverters to implement advanced reactive power 

functions

• Demonstrate the effectiveness of these advanced functions to effectively mitigate the 

voltage-related PV impacts on an actual high-penetration PV distribution circuit.

This field demonstration is part of a project undertaken in 2010 when the National Renewable 

Energy Laboratory (NREL), Southern California Edison (SCE), Quanta Technology, Satcon

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

(CPR) teamed together to (1) analyze the impacts of high penetration levels of PV systems

interconnected onto the SCE distribution system, (2) develop PV inverter capabilities to mitigate 

these impacts, and (3) demonstrate the use of these advanced PV inverter functions to mitigate 

PV impacts in the field. As this project has matured, the capability of PV inverters to implement 

various advanced functionalities has significantly improved; however, analysis completed on the 

project in the earlier stages showed that constant off-unity power factor operation would 

effectively mitigate the bulk of the voltage-related impacts at the distribution system level 

(Mather et al. 2011). Following the findings of these earlier studies, and taking advantage of the 

fact that constant power factor operation (also denoted as off-unity power factor operation) was 

one of the first advanced functionalities/capabilities implemented in many manufacturers’ PV 

inverters, this field demonstration was undertaken to show the capability and effectiveness of 

constant power factor operation on an actual high-penetration PV distribution circuit. 

Section 2 of this report gives a brief description of the Fontana, California, study circuit, which is 

helpful to understand the results of the field demonstration. A description of the particulars of the 

field demonstration is reported in Section 3. Section 4 contains the bulk of this report, and it 

presents the results and analysis arising from the field demonstration. Section 5 concludes the 

report, and it lists lessons learned from this field demonstration.
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2 Overview of the Fontana, California, Study Circuit

The Fontana, California, study circuit is one of three circuits in SCE’s territory that has been 

comprehensively modeled and instrumented to better understand the distribution system level 

impacts of high-penetration PV integration under the auspices of the NREL/SCE HighPenetration PV Integration Project. In 2010, at the start of the project, the Fontana, California, 

study circuit had a single 2-MW PV system, which interconnected to the circuit approximately 

one mile from the substation and had no customers connected between the PV system and the 

substation (i.e., the first mile of the circuit is considered an “express” section). During the period 

of the project, the 2-MW PV system was enlarged, resulting in a total nameplate capacity rating 

of 3 MW for that system. At a later date, a 1.5-MW PV system was installed near the 3-MW PV 

system, for a total PV capacity rating of 4.5 MW interconnected to the circuit. Figure 1 shows 

the general configuration of the Fontana, California, study circuit. The PV systems are shown as 

“2 + 1 MW,” denoting the original 2-MW PV system that was enlarged by 1 MW, and “1.5 

MW,” denoting a nearby but separate system that was installed at a later date. 

This medium-voltage (12 kV) circuit serves primarily commercial customers. The primary load 

on the circuit is a portion of a retail business district located near the end of the circuit. Overhead 

lines with a flat configuration comprise most of the circuit. The circuit does contain an 

underground cable section for the main line conductors located on the far half of the circuit as 

seen from the substation. Table 1 provides some general circuit characteristics.

The circuit’s voltage regulation is accomplished solely through the use of switched capacitors. 

There are no voltage regulators on the circuit, and there is no load tap-changing transformer at 

the substation. The locations of the four automatically controlled switched capacitor banks are 

shown in Figure 1. There are also numerous medium-voltage switches, including both remote 

controllable switch (RCS) and manual pole switch (PS) types. These switches are used for circuit 

reconfiguration during planned and unplanned outages on this and adjacent circuits.

Data presented in Section 4 of this report was taken from either SCE equipment connected to 

their distribution supervisory control and data acquisition (SCADA) system (i.e., substation-level 

data and PV system data) or from a few of the data collection instruments installed on the 

distribution circuit specifically to quantify the impacts of high-penetration PV integration. These 

instruments are distribution monitoring units (DMUs). These devices have been developed at 

NREL and are effectively distribution-level phasor measurement units (PMUs) because they 

provide 1-second resolution visibility of the circuit’s three-phase voltage magnitude and phase 

angle (referenced to a global positioning system [GPS] disciplined clock) (Bank and Hambrick 

2013, Bank and Mather 2013). 
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Figure 1. Simplified circuit diagram of the Fontana, California, study circuit showing the general 

connectivity and equipment placement.

Table 1. Fontana, California, Study Circuit Characteristics

Nominal circuit voltage (primary) 12 kV

Total circuit length (three-phase runs) 7.8 mi

Feeder loading capacity at substation (thermal) 11.9 MVA
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3 Overview of Field Demonstration

The field demonstration took place during the 2-week period from September 25, 2013, to

October 8, 2013. Scheduling the field demonstration took into account many considerations,

such as the expected loading on the distribution circuit during the demonstration period, the 

likelihood of real power curtailment as a result of the increased apparent power (VA)

requirements on PV inverters to operate at off-unity power factor, and SCE’s general 

maintenance schedule and availability for supporting the field demonstration. Previously 

completed model-based analysis of the Fontana, California, circuit—completed specifically to 

determine the most effective way to mitigate the impacts of a large PV system interconnected to 

the circuit using off-unity power factor operation (Mather et al. 2014)—indicated that fall and 

spring were the seasons when the ratio of PV power generation to distribution circuit load was 

the highest and thus represented the expected periods of the highest PV-related distribution 

circuit impacts. This analysis also showed that an operating constant power factor of -0.95 

(inductive/absorbing power factor) would effectively counteract the modeled voltage increase 

along the distribution circuit caused by the real power injection from the large interconnected PV 

systems.

Additional distribution system modeling was completed to determine the worst-case reactive 

power flows sourced from equipment located at a substation and/or the general subtransmission 

system if all reactive power control elements (switched capacitor banks) on the circuit became 

inoperable and the PV system included in the demonstration continued to operate at the planned 

inductive power factor. This worst-case reactive power flow was compared to reactive power 

capability estimates for the interconnected substation, and it was concluded that this unlikely 

contingency would cause a voltage collapse and/or overload at the local substation and the 

subtransmission system in general.

Because various models from different manufacturers of PV inverters were used in the two 

systems in the Fontana, California, study circuit, only 2 MW of the total 4.5 MW of installed PV 

were available for off-unity power factor operational testing. Four 500-kVA PV inverters that 

interfaced to the original 2-MW PV system installed in 2009 comprised the study system.

On the morning of September 25, 2013, SCE engineers changed the power factor operating set 

points on the aforementioned four 500-kVA PV inverters. On the morning of October 8, 2013, 

the same engineers changed the power factor operating set points back to unity, concluding the 

field demonstration.
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4 Field Demonstration Results and Analysis

Results and analysis from the completed field demonstration are presented below in two 

subsections that relate to the two primary objectives of the demonstration: demonstration of the 

capability of PV inverters to implement advanced reactive power functions and the 

demonstration of these advanced functions to effectively mitigate the voltage-related PV impacts 

on an actual high-penetration PV distribution circuit.

4.1 Demonstration of PV Inverter Capabilities to Implement Advanced 

Functionalities (Off-Unity Power Factor Operation)

Figure 2. Real and reactive power flow and the calculated operating power factor of the 2-MW PV 

system being demonstrated on a clear weather day (September 27, 2013).
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Figure 2 shows the real (MW) and reactive power (MVAR) flow from the 2-MW PV system 

included in this field demonstration and the calculated operating power factor of the PV system. 

The power factor set point (PFref) is also shown for reference. When the PV system is not 

generating positive real power, the calculated power factor is undefined. At these points the

calculated power factor was set to zero, as shown in Figure 2. At low PV power production 

levels—because of the limited numerical accuracy of the real and reactive power measurements 

for low-power operating levels—the calculated power factor is somewhat variable. This 

variability generates the “Gibbs-ears-like” transitions of the calculated power factor in the 

morning, when the PV system begins to generate real power, and the evening hours, when real 

power production tails off.

As shown in Figure 2, the reactive power was being supplied by the PV system. This is contrary 

to the desired power factor set point determined in earlier modeling studies that suggested that an 

inductive (absorbing) power factor of -0.95 would mitigate some of the voltage-related impacts

on the Fontana, California, circuit. Although there are many conflicting conventions for 

assigning the direction of reactive power flow, when considering the reactive power flows in the 

entire distribution circuit (which is shown in the next section), it is clear that the PV system was 

operating at a capacitive power factor of 0.95 (generating reactive power). Regardless, the power

factor set point of the 2-MW PV system that consists of four 500-kW PV inverters was tracked 

well at the reference set point (albeit an erroneous set point).

Figure 3 presents the same data as those shown in Figure 2, except the weather on the day shown 

was one of the few variable cloudy days that occurred during the testing period. As shown, the 

real power (MW) of the PV system ramped up and down during the majority of the daytime,

with power swings greater than 1 MW apparent numerous times during the day. Reactive power 

flow (MVAR) also ramped up and down during the day because the PV system controlled

reactive power output to maintain a constant power factor set point. The calculated power factor 

shows that the PV system being demonstrated tracked the 0.95 power factor set point with 

considerable accuracy. There were a few periods of time when the calculated power factor 

diverged from the power factor set point. This plot was developed using 15-s resolution SCADA 

data from SCE. It is possible that there were short periods of time during large ramping events 

when the PV system was incapable of accurately tracking the desired PV set point; however, it is 

more likely that the temporal resolution of the data sensed and reported though the SCADA 

system may not have been exactly time aligned so that during periods of high variability the 

sensed real and reactive power measurements during slightly different 15-s intervals could 

produce similar calculated power factor excursions from the ideally tracked power factor set 

point. 

Regardless, Figure 2 and Figure 3 provide evidence that the PV system being demonstrated is 

capable of operating at off-unity power factor and that reactive power can be adjusted to regulate 

the operating power factor to match the power factor set point. Even during periods of high PV 

system real power variability resulting from partly cloudy weather, the PV system appeared to 

track the power factor set point with a high accuracy and it is likely that excursions from the set 

point power factor were caused by the use of slightly non-synchronized real and reactive power 

measurements.
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Figure 3. Real and reactive power flow and the calculated operating power factor of the 2-MW PV 

system being demonstrated on a partly cloudy weather day (September 26, 2013).
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Figure 4. Real and reative power flow and the calculated operating power factor of the 2-MW 

system being demonstrated during the entire demonstration period.

Post-processing of the field demonstration data determined that the effective power factor set 

point (or the individual power factor set points of the four 400-kW PV inverters that comprise 

the PV system) was not constant during the testing period. SCE engineers and field crew 

implemented the power factor set points at the beginning of the field demonstration period and 

did not modify the power factor set points until the end of the field demonstration period; thus,

any changes during the field demonstration were the result of the operation of the PV system and 

its constituent components. As shown in Figure 4, which presents the real and reactive power 

supplied by the 2-MW PV system as well as the calculated power factor, the power factor set 

point of 0.95 was implemented for approximately the first 4 days of the demonstration period. 

On the fifth day (or during the preceding evening), two of the 500-kW PV inverters apparently 

reverted to unity power factor operation, which resulted in an overall PV system operating power 

factor of 0.975. This set point was accurately tracked for slightly more than 1 day, at which point

it appears that another 500-kW PV inverter reverted to unity power factor operation. For the rest 

of the demonstration period, the PV system operating power factor was greater than 0.9875, 

which would be the expected overall PV system operating power factor if all PV inverters had
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the same real power output, three PV inverters were operating at unity power factor, and one PV 

inverter was operating at the demonstration power factor set point of 0.95.

Figure 4 shows that the field demonstration ended on October, 8, 2013, and that no reactive 

power output resulted even though the system began to generate real power in the afternoon.

It is likely that the PV inverters reverted to operating at unity power factor because the power 

factor set point was implemented at the beginning of the field demonstration period. The power 

factor on all four PV inverters was set via the user-interface panel. Clearly, the PV inverters 

operated after the power factor set point had been entered via the user-interface panel, but it is 

speculated that as the PV inverters effectively reset (either by a hard reset or software reset), they 

reverted to a unity power factor set point that is stored in nonvolatile memory. 

4.2 Demonstration of Off-Unity Power Factor Operation to Mitigate 

the Distribution System Level Impacts of High-Penetration PV 

Integration

This section describes the data analysis completed to attempt to determine the effectiveness of 

mitigating voltage-related PV system impacts via off-unity power factor operation during the 

field demonstration. As mentioned in the preceding section, the implemented power factor set 

point realized during the field demonstration was not the proposed power factor set point 

determined for optimal studies of PV-impact mitigation. This error limited the usefulness of the 

overall demonstration, but a few important insights were determined.

At the beginning of the field demonstration, near-real-time SCADA-level data from SCE were 

queried to verify the operation of the PV system being demonstrated. As shown in Figure 2 and 

Figure 3, the PV system did operate at a power factor set point of 0.95, but there was some 

uncertainty as to the direction of the reactive power flow. There are many conventions for 

reactive power flow, and these conventions are a result of the viewpoints and objectives of the 

engineers who use them. For instance, transmission engineers typically denote positive reactive 

power flow as capacitive (i.e., capacitors generate vars). For distributed energy resources such as 

PV systems, there is often additional confusion surrounding real and reactive power flow 

because these resources typically generate real power instead of consuming real power, like 

typical loads on the distribution circuit; thus, metering is often set up with reversed-current 

transformers so that real power delivered to the grid is measured as positive. Regardless, the sign 

error (supplying instead of absorbing vars) occurred in the initiation of this field demonstration. 

It is important to note that this error was not caused by the SCE engineers and line crew who 

implemented the power factor set points on the PV system; rather, it was caused by not clearly 

communicating the expected power factor set point for the field demonstration and by not 

verifying the reactive power measurement sign convention before or during the demonstration.

To verify the implemented power factor set point, the reactive power flow supplied from the 

substation/subtransmission system was investigated. Figure 5 shows the reactive power flow at 

the start of the circuit from the substation (upper left) and the reactive power flow (shown as 

positive) from the PV system during variable weather conditions during the demonstration 

period. Voltage regulation along the distribution circuit was accomplished using switched 

capacitors that for this analysis were considered suppliers of positive vars (var generators). As 
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shown in Figure 5, one capacitor switched on at approximately 5:00 a.m. and another capacitor 

switched on at approximately 7:00 a.m. Bringing these var generators online greatly reduced the 

amount of capacitive vars sourced from the substation/subtransmission system. The red lines 

shown on the reactive power flow from the substation (MVARsub) plot indicate a var reduction of 

1.2 MVAR, which is equivalent to a rating of one of the capacitor banks on the Fontana, 

California, study circuit (see Figure 1). The preceding analysis verified that the convention of the 

substation reactive power flow is that inductive reactive power flow is positive and capacitive 

reactive power flow is negative.

Figure 5. Reactive power flow from the substation to the distribution circuit and the reactive 

power flow from the 2-MW PV system on September 26, 2013, the second day of the 

demonstration period.

Focusing on a time range of 15 minutes before and after noon, the plots on the right in Figure 5

show the impacts of the reactive power flow developed by the PV system being demonstrated,

and its reactive sign convention can be determined. The two large reactive power spikes shown 

during this time period occurred as a result of the highly variable operation of the real power of 

the PV system due to partly cloudy weather conditions. The magnitude of the largest spike—as 

delineated by red construction lines—was approximately 0.32 MVAR. A reactive power change 

of the same magnitude is also shown via construction lines in the reactive power flow from the 

distribution circuit’s substation (MVARsub). The two reactive power spikes were mirrored in the 
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substation reactive power flow, clearly indicating that the PV system was operating at a 

capacitive (supplying) power factor.

The ramifications of operating at a capacitive power factor instead of an inductive power factor 

are that voltage variations on the distribution circuit caused by the PV system should be 

exacerbated. As the real power of the PV system increases, the voltage at the point of 

interconnection should rise even higher than if the PV system operated at a unity power factor. 

Because the intended mitigating power factor set point of -0.95 (inductive) very nearly 

eliminated the voltage variation impact on the distribution circuit, the actual operating power 

factor of +0.95 capacitive should have nearly doubled the voltage variation impact at the point of 

interconnection.

Unfortunately, as shown in Figure 6, the effectiveness of mitigating PV impacts on voltagerelated distribution circuit impacts, or rather the exacerbation of these impacts as a result of

accidentally set power factor operating points, is not clearly reflected in the voltage data 

collected during the demonstration period. Figure 6 shows the real power produced by the 2-MW 

PV system during a partly cloudy day. The system was operating at a power factor of +0.95 

capacitive. The voltage at the point of common coupling is shown for the same period (VPCC,test) 

and a day with similar circuit loading, but with the PV system operating at unity power factor

(VPCC,BL). Plots on the left of the figure show variations throughout the entire day, and plots on 

the right of the figure show variations during a 30-minute period centered on noon. As shown, 

the variations in real power production, which caused variations in the reactive power supplied to 

the circuit, did not clearly change the voltage on the circuit at the closest voltage sensor on the 

instrumented distribution circuit. In fact, when comparing the VPCC,test to VPCC,BL plots, it is 

difficult to see any real difference in the system voltage and its character at that point because of

the operation of the PV system nearby. It should be noted that the voltage sensor (as shown in 

Figure 1) is not located directly at the PV system point of common coupling but is on a nearby 

short lateral. Sensing at the exact point of common coupling was not possible because of tariff 

regulations and the availability of three-phase pad-mount transformers near the PV system.
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Figure 6. Real power produced and voltage near the point of common coupling of the PV system 

(test) on September 26, 2013, the second day of the demonstration period, and the voltage near 

the point of common coupling during a typical day when the PV system was operating at unity 

power factor (BL = baseline).
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5 Conclusions and Lessons Learned

Although the field demonstration did not go as originally planned because the PV system 

operated at a capacitive power factor set point of +0.95 instead of the expected induction power 

factor set point of -0.95, there were a few conclusions and lessons learned that are applicable to 

additional field demonstrations in the future. The field demonstration did reinforce previous 

laboratory experiments that showed that utility-scale PV inverters are capable of implementing 

off-unity power factor operation with relatively high bandwidth (Mather, Kromer, and Casey 

2013; Langston et al. 2012). The data collected show that the PV system was able to implement 

off-unity power factor operation, meeting the first objective of the field demonstration.

The second objective, which was to show the effectiveness of off-unity power factor operation to

mitigate the voltage-related impacts of high-penetration PV integration on the Fontana, 

California, study circuit, was not met by this field demonstration. However, a number of lessons 

were learned that will make future field demonstrations, planned for completion on the Fontana, 

California, study circuit and one additional SCE study circuit in late 2014, more successful.

These lessons are:

• Utility engineers and line crews that interface with the PV systems to implement offunity power factor set points need to be better informed with regarding the specific set 

points requested. Capacitive reactive power use is very well understood within the utility 

sector, but the use of inductive reactive power is not. In fact, it is counterintuitive to 

many utility engineers and line crew members to operate any utility-controlled device in 

a manner that absorbs reactive power. Through better communication, the correct power 

factor set points can be assured in future field demonstrations.

• To ensure that power factor set points are maintained during the entirety of the field 

demonstration, the power factor set points need to be set in the nonvolatile memory of the 

PV inverters so that they do not revert to the off-unity power factor set points during hard 

or soft restarts.

• Voltage sensing for the purposes of measuring the effectiveness of PV mitigation needs 

to be connected as close as possible to the actual point of common coupling of the PV 

system. When sensing the system voltage on the secondary side of a transformer, 

transformer loading has proven to be too insensitive (even when accounting for 

transformer loading). A primary voltage-sensing solution may be the only way to 

accurately measure these voltage changes on circuits like those in the Fontana, California, 

study circuit that have relatively little impedance between the substation and the point of 

common coupling of the PV system. 
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References

Bank, J.; Hambrick, J. (2013). Development of a High-Resolution Real-Time Distribution-Level 

Metering System and Associated Visualization, Modeling, and Data Analysis Functions. 

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