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

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

Contract No. DE-AC36-08GO28308

Residential Advanced 

Photovoltaic Inverter Pilot Study 

Results for Select Distribution 

Secondaries in Hawai’i

Preprint

Peter Gotseff, Nick Wunder, and Andy Hoke

National Renewable Energy Laboratory

Earle Ifuku

Hawaiian Electric Company

Presented at the 2018 World Conference on Photovoltaic Energy 

Conversion (WPEC-7)

Waikoloa, Hawaii

June 10-15, 2018

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Suggested Citation

Gotseff, Peter, Nick Wunder, Andy Hike, and Earle Ifuku. 2018. “Residential 

Advanced Photovoltaic Inverter Pilot Study Results for Select Distribution 

Secondaries in Hawai‘i: Preprint.” Golden, CO: National Renewable Energy 

Laboratory. NREL/CP-5D00-71587. https://www.nrel.gov/docs/fy18osti/71587.pdf

Conference Paper

NREL/CP-5D00-71587

August 2018
NOTICE

This work was authored in part by the National Renewable Energy Laboratory, operated by Alliance for 

Sustainable Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. 

Funding provided by the Hawaiian Electric Company and the U.S. Department of Energy Office of Energy 

Efficiency and Renewable Energy. The views expressed in the article do not necessarily represent the views of 

the DOE or the U.S. Government. The U.S. Government retains and the publisher, by accepting the article for 

publication, acknowledges that the U.S. Government retains a nonexclusive, paid-up, irrevocable, worldwide 

license to publish or reproduce the published form of this work, or allow others to do so, for U.S. Government 

purposes.

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

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NREL prints on paper that contains recycled content.
1 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Residential Advanced Photovoltaic Inverter Pilot Study Results for Select Distribution Secondaries in Hawai‘i

Peter Gotseff1, Nick Wunder1, Andy Hoke1, Earle Ifuku2, and Reid Ueda2

1

National Renewable Energy Laboratory, Golden, CO, 80401, USA

2 Hawaiian Electric Company, Honolulu, HI, 96813, USA

1

Abstract — Penetration levels of residential rooftop solar 

photovoltaic (PV) generation on the Hawaiian island of O‘ahu 

have increased significantly in recent years, with many circuits 

now at the limits of their PV hosting capacity. NREL and Hawaiian 

Electric have used this opportunity to deploy advanced inverters 

at new customer installations that would not otherwise have been 

approved, as a pilot study to gain first-hand operational field data 

and experience on the impact of inverter-based grid support

functions. At each customer location, the deployed advanced 

inverters were remotely controlled and monitored. Additionally, 

customer AMI (smart meter) and secondary distribution 

transformer data was also available for the analysis. The analysis

focused on quantifying the customer behind-the-meter voltage rise 

due to PV production, determining the customer voltage rise with 

advanced inverters in unity power factor as well as advanced grid 

support function modes, and estimating the curtailment when 

inverters have Volt-VAR and Volt-Watt enabled. The results show

that: 1) Behind-the-meter voltage rise is often not negligible. 2) An 

inverter’s operating point on a Volt-VAR/Volt-Watt curve depends 

strongly on the design of the secondary system on which it is 

installed. 3) The mitigation of voltage rise on the secondary system 

using Volt-VAR may not be effective if only a small proportion of 

inverters have grid support enabled, or if the reactance/resistance 

(X/R) ratio of the grid is low. 4) Volt-Watt curtailment can be 

estimated using co-located irradiance sensors but there may be 

opportunities to estimate it using inverter internal electrical 

measurements. 5) Estimated curtailment is very low for the 

locations analyzed to date.

Keywords—Inverters, Volt-var control, Volt-watt control, 

Photovoltaics

I. INTRODUCTION

It is well known that high penetrations of solar photovoltaic 

systems (PV) can adversely impact distribution system 

operations and power quality, and it is an emerging 

interconnection requirement that advanced inverters provide 

grid support services (Volt-VAR, Volt-Watt, frequency-Watt, 

voltage/frequency ride-through) to mitigate these impacts and 

increase the cumulative benefits from distributed PV

generation. In fact, the current version of Hawaiian Electric’s 

Rule 14H interconnection standard, as approved by the Hawai‘i 

Public Utility Commission, requires activation of ride-through, 

This work was authored in part by Alliance for Sustainable Energy, LLC, the 

manager and operator of the National Renewable Energy Laboratory for the 

U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. 

Funding provided by Hawaiian Electric and by the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy. The views expressed in 

the article do not necessarily represent the views of the DOE or the U.S. 

Volt-VAR control, and frequency-Watt control for all 

distributed inverters [1]. Volt-Watt control is permitted to be 

enabled on an as-needed basis. The California Public Utility 

Commission (CPUC) is also currently implementing advanced 

inverter functionality including Volt-VAR and Volt-Watt into 

Rule 21 [2]. In addition, the underlying standard, IEEE 1547, 

was recently rewritten to support implementation of these 

functions [3]. 

However, most work that has been done to address the 

implementation of the function settings and the impact these 

functions will have on grid performance has been through 

laboratory testing [4]–[6] and computer modeling studies [7], 

[8]. Most computer modeling studies evaluate the effect of 

advanced inverter functions as if they were connected at the 

primary voltage level of the distribution system or with a 

homogeneous generic representation of the secondary voltage 

lines to the final customer location or Point of Common 

Coupling (PCC or electric meter) and PV generator. However, 

in practice, customer secondary design is very diverse, 

especially in older non-homogeneous residential 

neighborhoods. 

More recent modeling efforts by NREL and HECO have 

focused on distribution circuit analysis from the primary 

distribution voltage level complete to the distribution 

transformer and finally to the customer premises using 

representative sampled secondaries [8]. This study found 

significant benefits of Volt-VAR and Volt-Watt control in 

terms of power quality, with minimal impact on PV energy 

production.

However, these secondary models and expected Volt-VAR 

effectiveness should be consistent with field measurements. To 

this end Hawaiian Electric, in collaboration with the National 

Renewable Energy Laboratory (NREL), extended an offer to 

some number of queued net energy metering (NEM) residential 

PV customers whose systems were not able to be installed due 

to expected issues with voltage or thermal limits. Note that 

inverter grid support functions may address voltage issues but 

are not expected to address thermal issues. The offer included 

an option to install advanced inverters with Volt-VAR/VoltWatt grid support functions activated with allowances that the 

Government. The U.S. Government retains and the publisher, by accepting the 

article for publication, acknowledges that the U.S. Government retains a 

nonexclusive, paid-up, irrevocable, worldwide license to publish or reproduce 

the published form of this work, or allow others to do so, for U.S. Government 

purposes.
2 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

data be used for research. This paper describes several initial 

outcomes of that field pilot study, which is ongoing at the time 

of publication. This pilot study hopes to build on the results of 

other residential advanced inverter pilots [9], [10], by 

evaluating both utility-side impacts and customer-side impacts.

II. FIELD DEPLOYMENT AND TEST CASES

At the time of this writing, the pilot was made up of 15 

separate customer locations representing 12 240V secondary 

circuits. Typically, the secondary circuit is a radial design 

where a main conductor is fed from the distribution transformer 

and each house is “tapped” off the main secondary conductor. 

Of the new controllable inverters in this study, there were 11 

string inverters and four microinverter arrays. In all cases there 

were existing “legacy” PV systems (i.e., not capable of 

providing voltage support functions) already connected on the 

secondary circuits.

The field data for the pilot study consisted of the inverter, 

pilot customer and distribution transformer electrical 

parameters collected at intervals that ranged from 5 minutes to 

less than one minute (Fig. 1). Additional hardware included 

plane of array (POA) irradiance sensors located at two PV 

arrays. 

Fig. 1. Data collection locations. Microinverter data was recorded 

at each individual microinverter in each PV array.

To gauge advanced inverter effectiveness, each of the

inverters were programmed, for a period of time anywhere from 

three days to four weeks, with different combinations of fixed 

power factor and the Volt-VAR and Volt-Watt curves shown in 

Fig. 2. The curves selected were based on those currently being

used or proposed in Hawai‘i and California. Results presented 

below focus on test cases using the HECO Volt-VAR and VoltWatt curves; results using other curves will be presented in 

future work.

Fig. 2. Volt-VAR curves (top) and Volt-Watt curves (bottom) used 

in the pilot. The MAITAI curve was produced based on guidance from 

the Manufacturing Alliance of Inverters Technical Assessment of 

Integration Issues (MAITAI), as described in [4]. 

III. RESULTS

A. Behind-the-Meter Voltage Rise

The root-mean-square (RMS) voltage difference between the

inverter and customer meter was obtained for all string and 

microinverters in the pilot. This is also known as the behindthe-meter voltage rise (ΔVbtm) and is dictated by the impedance 

of the wiring on the customer’s premises (Zbtm) and the current 

flowing in that wiring, as shown in Fig. 3 for the simple case 

where the effect of load local current on ΔVbtm is small enough 

be neglected. Behind-the-meter voltage rise is typically not 

modeled even in very detailed computer simulations of 

distribution feeders with distributed PV systems, but its impact 

can be important, especially considering that Volt-VAR and 

Volt-Watt output changes substantially over a range as small as 

0.01 pu voltage. 

Fig. 3. Behind-the-meter voltage rise is one of several sources of 

voltage change and loss in a PV system.

Inverter Distribution primary 

(and rest of grid)

Distribution 

transformer

Zgrid Z2nd ~ ZDC

Meter

Zbtm

PV / DC 

source

Wires between 

meter and 

inverter AC 

terminals

- + ΔVbtm

Distribution 

transformer

~

Inverter AC & DC:

Sub-minute (string 

inverters);

Five-minute 

(microinverters)

Irradiance:

Sub-minute, 

selected 

locations 

only 

AMI: 

1-minute 

intervals

Grid2020:

1-minute 

intervals

Substation
3 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

String inverters are often – but not always – installed very 

near the meter and hence ΔVbtm is expected to be negligible in 

many cases. Microinverters are installed under the PV modules 

and hence have longer wire runs and are expected to experience 

greater voltage rise.

For this test, the inverters were set to unity power factor for 

three days. Fig. 4. shows the voltage rise from the customer 

meter to the inverter plotted against the inverter current, as well 

as the fitted linear regression (light blue), for string inverters. 

As expected, the string inverters experience a relatively small 

voltage rise ranging from 0.002 pu to 0.007 pu at full power

(0.5 to 1.7 V for a 240 V service). 

Fig. 4. Behind-the-meter voltage rise for all string inverters in the 

pilot

Microinverters have shown higher voltage rise, on the order 

of 0.005 pu to 0.025 pu (1.4 V to 6 V for a 240 V service) at 

full power as shown in Fig. 5. The negative voltage rise offsets 

seen in the figures are attributed to voltage drop due to customer 

loads, inaccuracy in the inverter measurements, and timestamp 

mismatch between the inverter and AMI (advanced metering 

infrastructure, or smart meter) measurements.

Fig. 5. Behind-the-meter voltage rise for all microinverters in the 

pilot

B. PV Power-Voltage Relationships

The RMS voltage difference from the distribution

transformer to the inverter will drive the Volt-VAR and VoltWatt functions and is dictated by the utility’s secondary system, 

behind-the-meter circuitry, and loads and PV generation on that 

system. Fig 6 shows a case of high voltage rise (~0.06 pu) from 

the transformer to one customer’s inverter in an overhead 

secondary system with 15 customers, 25 kW of legacy PV at 

unity or fixed power factor, and 9.8 kW of new controllable

advanced inverters. The blue dots show the RMS voltage rise 

dependency on PV power production with the controllable 

inverters operating at unity power factor. The red dots show 

the voltage rise for the inverters operating per HECO curve 14H 

Volt-VAR/Volt-Watt (per Fig 2). The linear regression is 

plotted for each mode. 

Fig. 6. Transformer-to-inverter voltage rise dependency on PV 

power in an overhead system for two inverter operating modes

Fig. 7 shows the much smaller voltage rise (~0.012 pu) from 

the transformer to one customer PCC in an underground 

secondary system with 7 customers, 32 kW of legacy PV at 

unity or fixed power factor and 22 kW of new, controllable, 

advanced inverters. In this case, because the absolute voltage 

at the customer PCC never went above 1.03 pu, the VoltVAR/Volt-Watt function, even though active, did not cause the 

inverters to consume VARs. This location was more typical of 

most of the customers in the pilot in that the voltages were 

rarely high, and thus the impacts of Volt-VAR and Volt-Watt 

on PV energy production were negligible. 

Fig. 7. Inverter-Transformer voltage rise dependency on PV power 

in an underground system for two inverter operating modes
4 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

C. Curtailment Estimates

Despite the fact that the pilot customers were preselected

based on expected problematic secondary locations, customer 

voltages were rarely high enough anywhere in the pilot study 

for Volt-Watt curtailment to be activated (i.e. > 1.06 pu) for 

more than a few minutes in any one day. However, the HECO 

Volt-VAR and Volt-Watt curves were active when a 

distribution primary high voltage event occurred for three days

on one feeder, as seen in Fig. 8. The calculated curtailment 

during the high-voltage period is shown in Fig. 9, where dark 

blue dots are measured power at a given irradiance, light blue 

dots are determined to be curtailed values and orange dots are 

estimated power without curtailment. Total energy over these 

three days was 74.46 kWh. Total estimated energy without 

curtailment (e.g., pf 1.0 without Volt-Watt) would have been 

75.69 kWh. The estimated curtailment is then 1.23 kWh, or 

1.6% of the energy produced during the three-day high voltage 

period. Figure 10 shows a similar analysis for a three-day 

period when the voltage was in its typical range for this 

location. During this period, the actual energy produced was 

69.19 kWh, and the estimated energy that could have been 

produced without Volt-VAR and Volt-Watt active was 69.22 

kWh, yielding an estimated curtailment of 0.02 kWh, or 0.04%. 

Thus the overall impact of Volt-VAR and Volt-Watt on PV 

energy production for this customer is negligible. This 

illustrates one of the key use-cases for Volt-Watt control, where 

the overall impact on the customer is small, but the function 

serves as safety-valve to minimize overvoltage during 

occasional voltage deviations. In this case the secondary has

many other PV systems operating at unity power factor without 

Volt-VAR and Volt-Watt, so the impact of Volt-VAR and VoltWatt in mitigating high voltages is small. Future work will use 

computer simulations to estimate the improvement in 

effectiveness if all inverters on the secondary were performing 

Volt-VAR and Volt-Watt.

Fig. 8. Meter (AMI) and inverter (Inv) voltages at second-highestvoltage customer, showing high-voltage condition in late October due 

to a feeder primary configuration change. 

Fig. 9. Curtailment estimates for a PV system with Volt-VAR and 

Volt-Watt activated during a three-day period where voltage was 

unusually high due to a temporary feeder configuration change.

Fig. 10. Curtailment estimates for a PV system with Volt-VAR and 

Volt-Watt activated during a typical three-day period. 

Figure 11 shows inverter active power and reactive power, 

AC inverter voltage, and irradiance at the same location as in 

Figs. 8-10 for a typical day (feeder primary in normal 

configuration). Note the high correlation between irradiance 

and voltage: PV output is clearly driving voltage magnitude. 

Also note that when irradiance reaches (and exceeds) the 

nominal peak irradiance of 1000 W/m2

, the voltage peaks below 

1.06 pu, so Volt-Watt is not curtailing power. While the voltage 

is above 1.03 pu, the inverter absorbs reactive power as 

specified by the HECO Rule 14H Volt-VAR curve. This results 

in minimal impact on PV energy production as the inverter still 

produces about 3.8 kW (its rated power) even while sinking 

VARs. This customer had a relatively low ratio of peak PV 

array power to inverter rated power (DC:AC ratio) at 1.0; future 

work will examine the effect of adding additional PV panels to 

bring the DC:AC ratio up to a more typical value in the 1.1-1.3 

range. The relatively high voltage at this location is largely due 

to the long shared overhead secondary conductors with multiple 

PV systems connected. Because the impedance of the 

conductors (largely resistive) is large compared to that of the 

distribution transformer (largely reactive), the grid X/R ratio 

Aug 2017 Sep 2017 Oct 2017 Nov 2017 Dec 2017 Jan 2018 Feb 2018 Mar 2018

time

0.94

0.96

0.98

1

1.02

1.04

1.06

1.08

V (pu)

AMI 15min avg

AMI Daily Max

AMI Daily Min

Inv Daily Max

Inv Daily Min

Inv Avg Daily Max

 Inv V avg = 1.026

Inv V avg daily max = 1.040

 Inv V avg daily min = 0.992

 AMI Vavg = 1.014

AMI V avg daily max = 1.039

 AMI V avg daily min = 0.991

0 200 400 600 800 1000 1200 1400

Irradiance (W/m2)

0

2000

4000

6000

Power (W)

Actual

Identified as curtailed

Estimated

Jan 08 Jan 09 Jan 10 Jan 11

2018 

0

2000

4000

6000

Power (W)
5 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

seen by the inverter is low, and VAR absorption can only 

reduce voltage to a certain degree. This will be examined 

further in future publications. 

The customer analyzed in Figs. 8-11 is the second-highestvoltage location in the pilot, so is expected to represent a near 

worst-case curtailment condition. This location has a string 

inverter, and as seen in Fig. 8, behind-the-meter voltage rise is 

small (maximum AMI voltage and maximum inverter voltage 

are very similar). The highest voltage location was not yet 

equipped with an irradiance sensor, so curtailment was not 

quantified, but will be in ongoing work. Behind-the-meter 

voltage rise is a significant factor in the highest-voltage 

location, as seen in Fig. 12. 

Fig. 12. Histograms of nighttime AMI voltages (blue), daytime AMI 

voltages (orange), and daytime inverter voltages (yellow) at the 

highest voltage location in the study. Each histogram is semitransparent to allow visibility of the others. 

In Fig. 13, inverter active power, reactive power, and voltage 

are plotted over a typical day for a more typical location, where 

the secondary is stronger (lower impedance). In this location 

there is minimal correlation between voltage and PV output 

despite the many PV systems on the secondary. Voltage rarely 

exceeds 1.03 pu, so Volt-VAR rarely absorbs VARs, Volt-Watt 

never curtails active power, and the impact on PV production 

of having Volt-VAR and Volt-Watt active is negligible. This 

location has a newer underground secondary with larger 

conductors. The location failed its initial interconnection screen 

not due to voltage issues but due to distribution transformer 

loading, which the grid support functions do not address. The 

lack of major voltage issues makes this location more typical of 

the distribution secondaries in the pilot study.

Fig. 13. Inverter PV power dependency on AC voltage showing 

upper cutoff of the HECO Volt-Watt curve and relationship to DC bus 

voltage (dot color)

A PV inverter curtails power by taking its maximum power 

point tracker off the knee point of its present current-voltage 

(IV) curve and, for the case of the string inverters in this study,

the inverter allows the DC bus voltage to rise toward the array

open-circuit voltage, Voc. Fig. 14 shows the inverter AC power

plotted against the AC terminal voltage with inverter DC bus

voltage represented as the color of the dots. Further analysis in

future work will show whether curtailed power can be

estimated directly from the inverter AC and DC electrical

properties without requiring a plane of array irradiance

measurement.

0.94 0.96 0.98 1 1.02 1.04 1.06 1.08

Vpu

0

0.02

0.04

0.06

0.08

0.1

0.12

0.14

0.16

Probability

AMI night <06:00 >18:00

AMI day 9:00-15:00

Inv day 9:00-15:00

 AMI Total Sample Days = 111.6

 AMI Total Samples = 2679

 AMI Perc daytime >= 1.03Vpu = 64.2

 AMI Perc daytime >= 1.06Vpu = 0.0

 AMI Vavg = 1.018

 AMInight Vavg = 1.011

AMIday Vavg = 1.033

 AMIday Vsd = 0.009

 AMIday Vskew = -0.510

 AMIday Vkurt = 3.84

Inv day Vavg = 1.040

 Inv Total Sample Days = 111.0

 Inv Total Samples = 2664

 Inv Perc daytime >= 1.03Vpu = 76.2

 Inv Perc daytime >= 1.06Vpu = 6.2

VA V, pu



Fig. 11. Inverter power, inverter reactive power, inverter AC voltage, and irradiance over one day for the second-highest voltage customer. 

• V peaks at 1.056 pu

• Irradiance peaks at 

1.1 kW/m2

• VARs absorbed when V>1.03, as expected.

• Inverter power still ~3.8 kW (rated P)



W V, pu

W/m2
6 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Fig. 14. Inverter PV power dependency on AC voltage showing 

upper cutoff of the HECO Volt-Watt curve and relationship to DC bus 

voltage (dot color)

IV. DISCUSSION

Advanced inverter functions intended to be used for voltage 

regulation are dependent on the voltage at the inverter 

terminals. This voltage may be higher behind the customer’s 

meter and is rarely monitored. In this study, behind-the-meter 

voltage rise was found to be less than 1% for string inverters 

and up to 2.5% for microinverters at full power. Furthermore, 

at the penetration levels in this study, there was strong 

dependence of voltage on the PV power production in some 

locations but minimal dependence in other locations. There was 

limited measurable effect of Volt-VAR on the PCC voltage for 

one particular high impedance overhead system due to the 

prevalence of legacy non-smart inverters and highly resistive 

secondary on that circuit. However, this is generally expected 

due to the low X/R ratio of many secondary systems. Finally, 

Volt-Watt curtailment, when it does occur, it can be directly 

estimated with a POA irradiance measurement. However, 

further analysis is required to determine if curtailment can be 

determined using inverter internal electrical measurements. 

Some previous work has examined the possibility of 

undesired dynamic interactions between multiple inverters 

performing Volt-VAR control at neighboring locations on 

distribution feeders using computer simulations and in 

laboratory settings [11], [12]. That work concluded that while 

adverse inverter-inverter interactions such as oscillations or 

“hunting” are possible with poorly-selected control parameters, 

such interactions are unlikely with well-selected Volt-VAR 

settings. This field study included two clusters of multiple PV 

systems on the same distribution secondary with highresolution (about 1 Hz) sampling of reactive power, voltage, 

and other parameters, so it afforded an opportunity to observe 

whether any adverse interactions occurred in the field. No 

adverse interactions were observed, adding to the growing 

confidence that autonomous inverter-based grid support 

functions can be a reliable addition to utility operations. 

To date, the findings of this study confirm the results of 

recent detailed computer simulations of Volt-VAR and VoltWatt on feeders with high levels of distributed PV, which found 

minimal impact on PV energy production, especially in nearterm scenarios [8]. Despite the pre-selection of customers with 

expected PV-related secondary problems, evidence of PV 

curtailment due to Volt-VAR and Volt-Watt is minimal, largely 

because voltages were rarely high enough for the functions to 

have a large impact on active power generation. However, 

additional ongoing work will better quantify these conclusions.

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