Technical Report

NREL/TP-550-46093

July 2009

Impact of SolarSmart 

Subdivisions on SMUD’s 

Distribution System 

Peter McNutt and Joshua Hambrick

National Renewable Energy Laboratory

Golden, Colorado

Michael Keesee and David Brown

Sacramento Municipal Utility District

Sacramento, California
National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393

303-275-3000 • www.nrel.gov

NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency and Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

Contract No. DE-AC36-08-GO28308

Technical Report

NREL/TP-550-46093

July 2009

Impact of SolarSmart 

Subdivisions on SMUD’s 

Distribution System 

Peter McNutt and Joshua Hambrick

National Renewable Energy Laboratory

Golden, Colorado

Michael Keesee and David Brown

Sacramento Municipal Utility District

Sacramento, California

Prepared under Task No. PVD9.1450
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Table of Contents 

List of Figures ................................................................................................................................. ii 

List of Tables .................................................................................................................................. ii 

1 Purpose .................................................................................................................................... 1

2 System Description .................................................................................................................. 1

2.1 SolarSmart Home and PV System Description ................................................................ 1

2.2 Distribution System Description ...................................................................................... 2

2.3 Load Tap Changer ............................................................................................................ 5

2.4 Capacitors ......................................................................................................................... 6

2.5 Monitoring the Distribution System ................................................................................. 7

3 Monitoring Results and Analysis ............................................................................................ 9

3.1 Inadvertent Switching Due To Utility Voltage Transients ............................................. 10

3.2 Solar Monitor Station ..................................................................................................... 15

3.3 Service- and Substation-Voltage Impacts due to PV Output ......................................... 18

3.4 Impact of PV Output Variability Due to Clouds ............................................................ 22

3.5 Substation voltage impact on home voltage due to clouds ............................................ 26

4 Modeling ................................................................................................................................ 27

4.1 Overview ........................................................................................................................ 27

4.2 Secondary Voltage Rise ................................................................................................. 29

4.3 Overall System Validation ............................................................................................. 31

5 Problems Encountered ........................................................................................................... 33

6 Findings ................................................................................................................................. 33

7 Next Steps .............................................................................................................................. 33

8 References ............................................................................................................................. 35
List of Figures 

Figure 1. SMUD Anatolia one-line diagram and monitor locations ............................................... 3

Figure 2. Map of the Anatolia III Community ................................................................................ 4

Figure 3. ANSI C84.1 voltage ranges ............................................................................................. 5

Figure 4. SMUD Anatolia-Chrysanthy substation Capcon operating parameters .......................... 6

Figure 5. Substation operation Wednesday, June 18, 2008 – clear day, 96oF .............................. 10

Figure 6. Home 3 power Wednesday, June 18, 2008 – clear day, 96oF ....................................... 12

Figure 7. Transformer 3 power Wednesday, June 18, 2008 – clear day, 96oF ............................. 13

Figure 8. System voltages Wednesday, June 18, 2008 – clear day, 96oF ..................................... 14

Figure 9. Solar monitor / meteorological station .......................................................................... 15

Figure 10. Solar calendar for March 2009 .................................................................................... 16

Figure 11. System voltages and solar irradiance March 7, 2009 .................................................. 18

Figure 12. Substation operation March 7, 2009 ............................................................................ 19

Figure 13. Transformer 3 power March 7, 2009 ........................................................................... 20

Figure 14. Home 3 power March 7, 2009 ..................................................................................... 21

Figure 15. System voltages and solar irradiance March 6, 2009 .................................................. 22

Figure 16. Substation operation March 6, 2009 ............................................................................ 23

Figure 17. Transformer 3 power March 6, 2009 ........................................................................... 24

Figure 18. Home 3 power March 6, 2009 ..................................................................................... 25

Figure 19. System voltages and solar irradiance March 1, 2009 .................................................. 26

Figure 20. DEW model of the Anatolia system ............................................................................ 27

Figure 21. DEW transformer, secondary, and service connections .............................................. 28

Figure 22. Secondary connection to Home 3 ................................................................................ 29

Figure 23. Voltage rise vs. apparent power for Home 3 ............................................................... 30

Figure 24. Modeled voltage profiles for transformer 5K7 ............................................................ 32

List of Tables 

Table 1. Distribution system power-quality monitors .................................................................... 7

Table 2. Possible technical concerns and days analyzed ................................................................ 9

Table 3. Comparison of estimated to calculated distances ........................................................... 29
1 Purpose 

The purpose of this study is to analyze the distribution impacts of high penetrations of gridintegrated renewable energy systems, specifically photovoltaic (PV) equipped SolarSmart 

HomesSM found in the Anatolia III Residential Community (hereafter referred to as Anatolia) in 

Rancho Cordova, California. SolarSmart Homes combine high-efficiency features along with 

rooftop-integrated 2.0 kWac PV systems; they have no energy storage. Ultimately, Anatolia will 

have 795 homes, 600 of which will be SolarSmart, eventually amounting to 1.2 MWac potential 

generation. 

Specific questions to investigate include: 

1. Will there be excessive service voltage due to reverse power flow from exporting PV 

systems? 

2. Will there be excessive substation voltage due to reverse power flow from exporting PV 

systems? 

3. Do PV inverters trip off line due to utility-line voltage transients? 

4. Will inverter power be limited by utility distribution operating voltages? 

5. Do intermittent cloud conditions affect overall PV system performance (PV ramp rates) and 

affect grid conditions? 

6. Can more SolarSmart Homes be connected to each distribution transformer, or can the 

transformers be smaller for the same number of homes? 

This report covers data collected between March 2008 and March 2009. 

2 System Description 

As of March 2009, there were 115 homes built in Anatolia. Although one quarter of the homes to 

be built will not have PV systems, all the homes built so far had PV systems, comprising 238 

kWac. 

2.1 SolarSmart Home and PV System Description 

SolarSmart Homes are advertised as being able to reduce annual residential electric bills by 60%. 

They combine cost-effective, energy-efficient features and a rooftop PV system. 

Typical Features in a SolarSmart Home 

• Radiant barrier: reflects summer heat that would otherwise enter the attic and cause greater 

need for air conditioning. 

• Furnace efficiency: a 90%-efficient furnace, exceeding the required 80% efficiency. 

• Air conditioner: a 14 SEER / 12 EER HVAC system. 

• Compact-fluorescent lighting: incandescent light bulbs are replaced by more energy efficient 

CFLs. 

• ENERGY STAR-qualified windows. 

1 
2 

• Third-party certification: independent verification is required that all energy-efficiency 

measures are installed and will operate correctly. 

• PV systems: a 2.0 kWac PV system can generate a major portion of the electrical energy 

consumed in the home. If the system exports energy during the year, SMUD writes a check 

to the owner for the exported energy at full residential rates. The orientation of the PV 

systems being monitored range from southeast to south to southwest. The majority of the PV 

systems consist of 36 SunPower 63-watt SunTile roof-integrated modules that utilize backcontact, monocrystalline silicon cells powering a SunPower SPR-2800x positive-ground, 

grid-connected inverter. The inverter is mounted in the garage and can be remotely accessed 

by SunPower if the homeowner connects it via the internet. The systems have a 10-year 

warranty and the power output of the arrays is warranted for 25 years. 

2.2 Distribution System Description 

Anatolia is served by individual single-phase lateral circuits from a three-phase primary feeder 

(Feeder 1201) which connects to a 20 MVA, 69 kV / 12.47 kV delta-wye transformer at the 

Anatolia-Chrysanthy Substation (hereafter referred to as Anatolia-Chrysanthy or substation). 

Figure 1 show the one-line diagram along with monitoring points. The feeder has several points 

along the line that allow for switching through cubicles represented as circles with an “F” in 

them. The length of the feeder to the switching cubicle furthest from the substation, U-10891, is 

about 18,895 feet and the furthest distribution transformer, 5K7, is 22,360 feet from the 

substation. In Anatolia, there are a total of 85 single-phase pad-mounted distribution 

transformers: 23 are 75 kVA and 62 are 50 kVA. Also connected to the same substation feeder is 

a rendering plant fed by two 1500 kVA transformers, consuming between 20 and 200 kW, a 

water storage plant, and residential communities between the substation and Anatolia, connected 

at U-10597, U-10596 and U-10763. There are 2 additional feeders (1202 and 1203) that also 

connect to the 20 MVA transformer that have additional customer loads. 

Figure 2 is a map showing the layout of the community, its distance from the substation, and the 

location of the distribution transformers being monitored. 
Figure 1. SMUD Anatolia one-line diagram and monitor locations

3 
 Figure 2. Map of the Anatolia III Community 

4 
The primary distribution voltage, 12.47 kV, at the substation is transformed down to 124.7 V on 

the distribution transformer secondaries. There is a load-tap changer (LTC) and six banks of 

1800-kVAR capacitors (two on each of the three feeders) in the substation to regulate the 

voltage. The primary distribution voltage needs to remain within ANSI C84.1 limits (Figure 3), 

114 – 126 V, or 11.4 kV – 12.6 kV, over the length of the feeder. The service voltage is what is 

provided to the customer meter and includes any voltage drop from the primary service through 

the distribution transformer and service conductors. The electric supply system is designed so 

that the voltage is within Range A most of the time and infrequently within Range B. The 

utilization voltage is the voltage within which user systems and loads are designed to operate. 

During heavy loading, the substation voltage may be adjusted as high as 12.75 kV to account for 

the voltage drop at the end of the feeder. SMUD tends to operate the voltage at higher levels for 

reliability; although lower system voltages would translate to lower transformer losses, they also 

usually result in more complaints and customer-equipment failures [1]. 

Figure 3. ANSI C84.1 voltage ranges 

2.3 Load Tap Changer 

The substation voltage is automatically controlled by a LTC on the secondary of the substation 

transformer and managed by a voltage regulating relay. The LTC effectively varies the 

transformer turns ratio to maintain the transformer secondary voltage at the substation as 

primary-voltage changes occur due to changes in loading of the transmission system, or as the 

load on the transformer itself varies. The base voltage, or band center, is 123 V (12.3 kV line-toline at the substation). The bandwidth is +/- 1.5 V (or 3 V) total. The time delay for adjustments 

is 60 seconds. The base voltage also compensates for added load by increasing linearly from 123 

volts at no load to 126 volts at full load (about 20 MVA or 1200 A). 

5 
2.4 Capacitors 

The substation has six three-phase, 1800-kVAR capacitor banks (hereafter referred to as 

capacitors). The capacitors are computer controlled remotely using an algorithm called Capcon 

(Figure 4), based on the 69 kV primary voltage. Capacitors are reactive power sources that 

affect the voltage by supplying leading reactive current that compensates for the lagging reactive 

current of the load. During "normal" operations, one capacitor is turned on each time the VAR 

flow exceeds 900 kVAR (into the substation from the 69 kV source), and a capacitor is switched 

off each time the VAR flow exceeds -1200 kVAR. These set points are modified on "hot days" 

as indicated by the red bars. Days exceeding 100oF are considered hot, but this setting can be 

manually overridden depending upon weather forecasts. These settings are also adjusted for high 

or low system voltages (very rarely) as depicted in the left or right sets. 

Figure 4. SMUD Anatolia-Chrysanthy substation Capcon operating parameters 

 

6 
2.5 Monitoring the Distribution System 

The distribution system is monitored at the substation, on Feeder 1201, using the Supervisory 

Control and Data Acquisition (SCADA) and a PMI Eagle 440 monitor; at the secondary of four 

distribution transformers using PMI Eagle 440 monitors; and at the service panels of four homes 

using PMI iVS-2SX+ power monitors. The substation utilizes a DAQ Electronics ART-073-79-0 

SCADA system. The SCADA collects data from various devices, i.e. Main Bus and Feeder 

Relays, capacitor positions, etc. Thus for the transformer, load data are gathered on the main bus, 

and feeder load data are gathered at their respective breaker positions. The main bus CT is a 

1200-to-5. The feeder CTs are multiple tap 1200-to-5 CTs set at 600-to-5. The PT is 6900-to-120 

volt, phase-to-ground. The metering is ANSI class high-accuracy, within 0.5%. The sampling 

rate is every two seconds with an average recorded every five minutes. Details of the system 

power-quality monitors are given in Table 1. 

Table 1. Distribution system power-quality monitors 

Location Equipment Data Collected Interval Full-Scale Accuracy 

Substation DAQ Electronics 

ART-073-79-0 

V, MW, MVAR, 

Capacitors, LTC 

5 minute 

Sample every 2 

seconds 

0.5% 

Substation PMI Eagle 440 V, kW, kVAR 5 minute 

256 samples / 

cycle 

Voltage 0.33% 

Current 1.0% * 

Power 1.0% 

Transformer 1 - 9K1 

Village Mill Way 

PMI Eagle 440 V, kW, kVAR 5 minute 

256 samples / 

cycle 

Voltage 0.33% 

Current 1.0% * 

Power 1.0% 

Home 1 

Village Mill Way 

PMI iVS-2SX+ V, kW, kVAR 5 minute 

128 samples / 

cycle 

Voltage: 0.33% 

Current & Power: 1% 

Transformer 2 - 2K1 

Heather Ranch Way 

PMI Eagle 440 V, kW, kVAR 5 minute 

256 samples / 

cycle 

Voltage 0.33% 

Current 1.0% * 

Power 1.0% 

Home 2 

Heather Ranch Way 

PMI iVS-2SX+ V, kW, kVAR 5 minute 

128 samples / 

cycle 

Voltage: 0.33% 

Current & Power: 1% 

Transformer 3 - 8K6 

Otter Pond Way 

PMI Eagle 440 V, kW, kVAR 5 minute 

256 samples / 

cycle 

Voltage 0.33% 

Current 1.0% * 

Power 1.0% 

Home 3 

Otter Pond Way 

PMI iVS-2SX+ V, kW, kVAR 5 minute 

128 samples / 

cycle 

Voltage: 0.33% 

Current & Power: 1% 

Transformer 4 - 5K7 

Copper Sunset Way 

PMI Eagle 440 V, kW, kVAR 5 minute 

256 samples / 

cycle 

Voltage 0.33% 

Current 1.0% * 

Power 1.0% 

Home 4 

Copper Sunset Way 

PMI iVS-2SX+ V, kW, kVAR 5 minute 

128 samples / 

cycle 

Voltage: 0.33% 

Current & Power: 1% 

* The accuracy of the Flex CT 4/24 is +/- 1% of full scale when set to1000 A for use in the transformers. 

The PMI Eagle 440 wireless power-quality monitors can measure a maximum of 600 V and 

5000 A at 256 samples per cycle per channel. Voltage resolution is 0.01 V measured, 0.1 V 

7 
rounded and logged. Current resolution is 5 A. The Eagle 440 monitors are placed inside the 

distribution transformer enclosures. Data are gathered via a wireless Bluetooth connection. 

The PMI iVS-2SX+ socket-mounted monitors can measure a maximum of 140 V and 200 A at 

128 samples per cycle per channel. The collar monitors plug in-line with the residential watthour meter. Voltage resolution is 0.1 V measured, 0.5 V rounded and logged. Current resolution 

is 0.2 A. Data are gathered via a serial cable. 

Solar and metrological data is also collected from a solar/meteorological station installed at the 

substation. One-minute-interval data from the solar/meteorological station are collected 

automatically each day and can be found at http://www.nrel.gov/midc/smud_anatolia/. 

8 
3 Monitoring Results and Analysis 

In order to address the issues of grid impacts of the PV systems, the results selected from several 

days were analyzed. Table 2 lists the technical issues that were examined, parameters that were 

measured in order to determine the effect, types of days where the issue was likely to occur, the 

actual days selected for analysis, the figure numbers, and status of the issue. 

Table 2. Possible technical concerns and days analyzed 

Possible Technical 

Concern 

Monitored 

Parameters 

Type of Day 

Issue Occurred 

Day Analyzed See 

Figures: 

Status 

1 Inadvertent switching due 

to utility voltage transients 

PV output, 

capacitor status 

Clear day with 

utility voltage 

transients 

Wed. 6/18/08 5 - 8 No 

problem 

found 

2 Service-voltage impact due 

to PV output 

Voltage at home 

and distribution 

transformer 

Clear day, low 

load, high local 

penetration 

Sat. 3/7/09 11 - 14 No 

problem 

found 

3 Substation-voltage impact 

due to PV output 

Voltage at 

substation 

Clear day, low 

load, high 

feeder 

penetration 

Sat. 3/7/09 11 - 14 No 

problem 

found 

4 Impact of PV-output 

variability due to clouds 

PV output passing clouds Fri. 3/6/09 15 - 18 No 

problem 

found 

5 Substation voltage impact 

on home voltage due to 

clouds 

Voltage at 

substation and 

home 

Overcast day, 

cool 

temperature 

Sun. 3/1/09 19 No 

problem 

found 

6 PV output limited by high 

utility voltage 

Voltage sags as 

PV systems drop 

offline 

Day of high 

substation 

voltage when 

PV should be 

on 

TBD 

7 PV output reduces peakload substation & 

distribution 

transformer 

loads 

high-load day TBD 

8 Feeder peak-load reduction substation & 

distribution 

transformer 

loads 

high-load day TBD 

For this analysis, “effective PV penetration” is defined as the amount of PV output divided by 

the load at that particular point in time. Using this definition, the penetration varies during the 

day as load and PV output changes. This is helpful in understanding the relative size of the PV 

generation to the load, and understanding if there were significant impacts on the distribution 

system. 

The following analyses give detailed performance data for the technical issues examined (listed 

above in Table 2) on the dates that provided optimal conditions for testing. 

9 
3.1 Inadvertent Switching Due To Utility Voltage Transients 

Wednesday, June 18, 2008 – Clear, Hot Weekday, 96°F 

Wednesday, June 18, 2008, was a hot, clear day with significant capacitor switching. As of this 

date, there was a 2.0 kWac PV system on Home 3, 30.1 kWac of PV (from twelve SolarSmart 

Homes) on Transformer 3, and 182 kWac of PV (from 85 SolarSmart Homes) on the distribution 

system. Because it was a clear day, it provided optimal conditions to examine whether the 

inverter tripped due to utility transients. At noon there was an effective PV penetration level of 

8.3% (182 kW / 2200 kW) on Feeder 1201 and 2.2% on the entire substation transformer. 

Figure 5 shows the operation of the substation on 6/18/08, including the voltage (plotted against 

the right y axis), the real and reactive power of the substation and the feeder for Anatolia, and 

status of the six capacitors. 

Figure 5. Substation operation Wednesday, June 18, 2008 – clear day, 96oF 

Annotation of Plots 

To simplify identification of voltage events due to capacitor switching, capacitor events were 

labeled C#, where the “#” indicates the hour of the day (military-time format), and a “+” or “-” 

10 
suffix indicates a capacitor switched on or off. The status of the six 1800-kVAR capacitors can 

be seen on the plot. A capacitor that is on or connected to the bus is shown as approximately “1”; 

if it’s off or disconnected, it’s approximately “0”. Event numbers, E#, were then assigned all 

capacitor events, with the numbers, again, based on the military time. Voltage events are noted to 

help determine if they were caused by substation operations, by loads in the Anatolia 

community, or by PV system operation. Faint vertical lines were drawn on each of the plots to 

help indicate when events occurred. Orange boxes enclose the time periods in which the 

transformer or home was exporting power to the distribution system, or when the home voltage 

was greater than the substation voltage during daylight hours. 

Six capacitor-switching events took place on 6/18/09 (Figure 5). As a capacitor is switched on, 

there is a corresponding drop in the reactive power. One of these events can be seen, for 

example, at E8 when C2 is switched on – the “Sub MVAR” and “Fdr 1 MVAR” values both 

drop from about 0.9 MVAR to -0.9 MVAR. “Sub MVAR” is the total substation reactive power 

and “Fdr 1 MVAR” is the reactive power of Feeder 1201 that feeds the Anatolia community. The 

peak load for the day occurred around 19:30, peaking around 12 MW for the substation, and 4 

MW for the feeder. 

 

11 
Figure 6 shows the real and reactive power for Home 3. The daytime maximum temperature was 

96°F. The smooth plot of real power (blue line) indicates it was a clear, cloudless day. SMUD’s 

heaviest residential loads occur on hot days when people use air conditioning to cool their 

homes. The maximum loads for Home 3 on this day were about 5 kW and occurred around 2:00 

and 18:30. Figure 6 also shows that the inverter remained online during a couple utility voltage 

transients, E8 and E13. 

Figure 6. Home 3 power Wednesday, June 18, 2008 – clear day, 96oF 

Comparing the real power produced by the PV system on Home 3 (Figure 6) with the power 

produced from the twelve homes on Transformer 3 (Figure 7), the power exported from 

southeast-facing Home 3 peaks earlier in the day than the peak on Transformer 3 (12:30 vs. 

13:30). Seven of the twelve homes face southwest; the other five systems face southeast. Solar 

noon (when the sun is due south) occurred at 13:07. By orienting the PV arrays southwest, their 

peak production is shifted slightly. The peak loads on Transformer 3, about 31 kW, occurred 

between 18:30 and 21:00. 

12 
Figure 7. Transformer 3 power Wednesday, June 18, 2008 – clear day, 96oF 

In Home 3 (Figure 6), a cyclical load (air conditioner) operated early in the morning, between 

2:00 and 7:00, and in the early evening, between 17:00 and 19:00. At Transformer 3 (Figure 7) 

the coincident loads in the morning were noticeably lower than those in the evening when people 

returned home, turning on air conditioners to cool their homes after they heated up on a hot 

summer day. 

 

13 
Comparison of Distribution Voltages 

Figure 8 is a comparison of the voltages recorded at the substation, Transformer 3 and Home 3. 

The three voltages are plotted against each other at the top of the figure, and the difference 

between the substation and Home-3 voltage is plotted in purple at the bottom. Because the 

Home-3 voltage measurement (green) has a resolution of 0.5 V, it has a “stair-step” look to it. 

The substation and transformer voltages appear smoother due to the 0.1 V monitor resolution. 

During daylight hours there is a general rise in voltage at Home 3 of 0.4%, indicating the PV 

systems are exporting power to the distribution system. Positive spikes at E2 and between E21 

and E22, when there is no sunlight, were probably due to capacitor switching events. 

Figure 8. System voltages Wednesday, June 18, 2008 – clear day, 96oF 

 

14 
3.2 Solar Monitor Station 

On February 3, 2009, NREL installed a solar monitoring station (Figure 9) within the walls of 

the Anatolia-Chrysanthy substation to collect solar irradiance and air temperature data. These 

data allow researchers to view the solar resource on any given day and determine if a day was 

sunny and clear, variably cloudy, or overcast. The unit is wireless, self powered (using a 10-watt 

PV module to charge a battery that powers the sensors and data logger), and requires little 

routine maintenance. A cell phone modem is used to control the station and collect the data. Data 

are collected automatically every day. These data can be used to more-accurately estimate the 

output of the PV systems. Data from the solar/meteorological station can be found at 

http://www.nrel.gov/midc/smud_anatolia/. The solar monitoring station is approximately two 

miles northwest of the Anatolia Community. This location was selected because it was the 

nearest location the station would be secure against vandalism. 

Figure 9. Solar monitor / meteorological station 

15 
March 2009 Data 

The solar calendar for March 2009 is shown in Figure 10 with the three selected days having 

heavy red borders. March 1 was an overcast day with little sunlight. March 6 was a sunny day 

with passing clouds. March 7 was a clear, sunny day. 

Figure 10. Solar calendar for March 2009 

The Global Horizontal, or Total, (red) and Diffuse (blue) components of the solar irradiance are 

measured, and the Direct component (green) is calculated from the other two. 

Total = Direct x cos (Zenith Angle) + Diffuse (1) 

Where: 

• Total is the total irradiance falling on a horizontal surface; 

• Direct is the direct beam or direct normal irradiance coming from the disk of the sun; 

• Diffuse is the irradiance from the entire sky falling on a horizontal surface excluding 

irradiance coming from the disk of the sun; 

16 
• Zenith Angle (computed) is measured from straight overhead down an arc to a point at the 

center of the sun. 

Three days in March 2009 were selected for analysis : 

• Saturday, March 7, 2009 – clear, cool weekend day, 63°F daytime high 

• Friday, March 6, 2009 – variably cloudy, cool weekday, 61°F daytime high 

• Sunday, March 1, 2009 – overcast, cool, weekend day, 59°F daytime high. 

As of March 2009, there was a 2.0 kWac PV system on Home 3, 30.1 kWac of PV (serving 

twelve SolarSmart Homes) on Transformer 3, and 238 kWac of PV (serving 115 SolarSmart 

Homes) on the distribution system. 

 

17 
3.3 Service- and Substation-Voltage Impacts due to PV Output 

Saturday, March 7, 2009 – Clear, Cool Weekend Day, 63° F

Saturday, March 7, 2009, was a clear, cool, weekend day with a daytime high temperature of 

63°F (Figure 11). The solar irradiance (orange) is smooth from sunrise to sunset indicating a 

cloudless day. The slight bump after sunrise is due to shading from the east substation wall, as 

the solar irradiance station is mounted in the south-east corner inside the substation. The global 

horizontal irradiance peaked at about 800 W/m2

. Because of the cooler temperatures, the utility 

load was low and the PV arrays were producing more power. This was a good day to examine 

for excessive voltage at the home, transformer, and substation. All voltages remained within 

ANSI C84.1 limits, below 126 volts. At night, the substation voltage was approximately 0.3% 

higher than the home voltage. This is representative of a typical circuit with voltage drops 

through the line and transformer impedances. During daylight hours, the home voltage (green) 

was greater than the transformer (blue) and substation (red) voltages (within the orange box). 

The home voltage was approximately 0.6% above the voltage at the substation due to the 

exported power from the PV system. 

Figure 11. System voltages and solar irradiance March 7, 2009 

18 
Figure 12 shows the substation and feeder voltage, real and reactive power, and capacitor status. 

On this day at noon, there was an effective PV penetration level of 11.3% (238 kW / 2100 kW) 

on Feeder 1201 and 4.6% on the entire substation transformer. There was no capacitor switching. 

The substation voltage (red) remained within ANSI C84.1 limits, below 12.6 kV. The increase in 

the substation (blue) and feeder (purple) real power after 17:00 was probably due to people 

turning on lights in their homes after sunset. 

Figure 12. Substation operation March 7, 2009 

 

19 
Figure 13 shows the real power (blue) being exported to Transformer 3 (within the orange box). 

By drawing an imaginary line on the real power (blue) curve while it was exporting power 

(negative), you can make out the smooth solar output from the PV systems. Dips in the real 

power curve were caused by loads on the transformer. The increase in load after sunset was 

probably caused by people turning on lights. 

Figure 13. Transformer 3 power March 7, 2009 

 

20 
Figure 14 shows the real power (blue) being exported from Home 3 (within the orange box). By 

drawing an imaginary line on the real power (blue) curve while it was exporting power 

(negative), you can make out the smooth solar output from the PV systems. Dips in the real 

power curve were caused by loads in the home. The increase in load after sunset was probably 

caused by people turning on lights. 

Figure 14. Home 3 power March 7, 2009 

 

21 
3.4 Impact of PV Output Variability Due to Clouds 

Friday, March 6, 2009 – Variably Cloudy, Cool Weekday, 61°F 

Friday, March 6, 2009, was a day with clear skies, passing clouds, and a daytime high of 61°F. 

The solar irradiance curve was relatively smooth except for periods when clouds passed over the 

community. Figure 15 shows the voltages at the substation, Transformer 3, and Home 3. At 

night, the substation voltage was higher than the home voltage by up to 0.7%. This is 

representative of a typical circuit with voltage drops through the line and transformer 

impedances. During daylight hours however, the reverse was true depending on the sunlight. The 

home voltage was up to 0.4% greater than the substation. This was due to the power being 

exported from Home 3 along with the power exported from the other eleven PV systems 

connected to Transformer 3. 

Figure 15. System voltages and solar irradiance March 6, 2009 

22 
Figure 16 shows the substation operation. There were six utility voltage transients due to 

capacitor switching. Some of these capacitor switches caused noticeable changes in the voltage 

on the circuit. At 13:00 there was an effective PV penetration level of 13.2% (238 kW / 1800 

kW) on Feeder 1201 and 4.2% on the entire substation. 

Figure 16. Substation operation March 6, 2009 

23 
Figure 17 shows the real power (blue) being exported to Transformer 3 (within the orange box). 

By drawing an imaginary line on the real power (blue) curve while it is exporting power 

(negative), you can make out the smooth solar output from the PV systems. Dips in the real 

power curve were caused by passing clouds and loads on the transformer. 

Figure 17. Transformer 3 power March 6, 2009 

 

24 
Figure 18 shows the real power (blue) being exported from Home 3 (within the orange box). By 

drawing an imaginary line on the real power (blue) curve while it is exporting power (negative), 

you can make out the smooth solar output from the PV systems. Dips in the real power curve 

were caused by passing clouds and loads in the home. 

Figure 18. Home 3 power March 6, 2009 

 

25 
3.5 Substation voltage impact on home voltage due to clouds 

 Sunday, March 1, 2009 – Overcast, Cool, Weekend Day, 59°F

Sunday, March 1, 2009, was a cool, overcast day with a daytime high of 59°F. Figure 19 shows 

the solar irradiance (almost flat orange line because it is an overcast day), the voltages at the 

substation, Transformer 3, and Home 3 and the difference between the substation and Home 3 

voltages (purple line). Because there was very little sunlight on this day, minimal power was 

exported from the PV arrays, so the home and transformer voltages remain lower than the 

substation voltage. Figure 19 shows an approximate 3% drop in voltage between the substation 

and the Home 3. 

Figure 19. System voltages and solar irradiance March 1, 2009 

26 
4 Modeling 

4.1 Overview 

The SMUD Anatolia SynerGee electrical model was converted into a Distributed Engineering 

Workstation (DEW) model for analysis. DEW models the secondary and service connections 

which are important in evaluating the effects of high penetrations of PV systems on customer 

service voltage. Additionally, DEW has tools specifically geared toward analysis of penetration 

limits as well as an open architecture which allows the user to design custom analysis 

applications. Figure 20 shows the DEW model of the Anatolia system. Once validated, the DEW 

model will be used to estimate the effects of a high penetration of PV on the test system. 

Figure 20. DEW model of the Anatolia system 

An average estimate of 160 feet was used for the secondary cable segments. An average estimate 

of 50 feet was used for the service drops. Figure 21 shows the secondary and service 

connections in the DEW model. 

27 
Figure 21. DEW transformer, secondary, and service connections 

Feeder 1201 contains significant loads which are not part of the system under evaluation 

including a rendering plant and approximately 1,000 residential customers. Additionally, the 

substation transformer and LTC are shared by two other feeders. 

For initial testing and model verification, the unknown residential loads are represented as a 

lumped spot load. Eventually, the residential loads will either be calculated from load research 

statistics or distributed based on distribution transformer size. The rendering plant load is 

represented as a spot load based on recorded data. 

The load on the other feeders is modeled using a spot load placed immediately after the LTC. 

Since the additional feeders share the LTC, the load on those feeders will affect the position of 

the tap as well as the regulation set-point. While the load on the other feeders will not greatly 

affect the voltage profile of the system under study, these loads may affect the voltage 

regulation. 

28 
Verification 

To verify the topology of the DEW model and to ensure the switching devices are represented in 

their correct states, the electrical distances from the substation of the measurement points are 

compared against the estimated values from Figure 1. Table 3 describes this comparison. All 

modeled electrical distances are within 3.5% of the estimated distances. 

Table 3. Comparison of estimated to calculated distances 

Transformer Estimated Distance 

(ft) 

DEW Distance from 

Substation (ft) 

Difference 

(%) 

9K1 10,150 10,476 3.21 

2K1 14,925 15,045 0.8 

8K6 16,430 16,223 1.3 

5K7 22,360 22,606 1.1 

4.2 Secondary Voltage Rise 

Figure 22 shows the secondary and service connections for Home 3 from distribution 

transformer 8K6. The voltage rise measured between the secondary of 8K6 and the service 

entrance to Home 3 will be affected by the loads and generation of the other homes on the 

secondary connection. The voltage measurement at Home 3 has a resolution of 0.5 V rounded 

and logged. 

Figure 22. Secondary connection to Home 3 

29 
Figure 23 shows the simulated and measured voltage rise from Home 3 to the secondary of 8K6. 

The sampled data reflects roughly a month of data where Home 3 is net exporting real power 

with an inductive load of between 0.18 and 0.22 kVAR. The top graph reflects all of the sampled 

data in the set. The bottom graph reflects the averaged measured voltage rise with bars indicating 

the expected error from the voltage measurement device at the home. 

Figure 23. Voltage rise vs. apparent power for Home 3 

30 
The secondary system was simulated assuming uniform generation from all customers connected 

to the secondary of the transformer. The generation from the homes was increased while 

maintaining a constant inductive load of 0.2 kVAR. The homes were modeled as constant current 

loads. 

The variation in measured-voltage rise data is largely due to uncertainties with the other 

customers sharing the secondary connection as well as the resolution of the voltage measurement 

device at the home. The graphs in Figure 23 indicate that the model reasonably reflects the 

behavior of the actual system to the extent that can be determined given the limitations described 

above. With improved monitoring and meter accuracy, the model could be better validated and, 

if necessary, adjusted to more accurately reflect the system. 

4.3 Overall System Validation 

A large number of unknown loads and electrical quantities as well as measurement 

inconsistencies make it difficult to perform a meaningful whole-system model evaluation at this 

time. The following is a list of concerns and their impacts on the overall system model 

validation: 

• The voltage at the substation is measured phase-to-phase; however, the distribution 

transformers are connected phase-to-ground. To establish the measured rise from the 

substation to the service entrance at the home, the customer and transformer voltages should 

be compared to the phase-to-ground voltage at the substation. Since the voltages at the 

substation are imbalanced, the conversion to phase-to-ground from the measured values is 

not straightforward and will be done programmatically. 

• The rendering plant load is not well known. The load has been represented as a spot load 

based on recorded data of a short period (about a week). Since the rendering plant shares a 

relatively short feeder path with the system under study (approximately 400 feet according to 

the model), the impact of this unknown load on voltage regulation is expected to be minor. 

• The capacitor control scheme is complex and can change states based on unmonitored inputs 

from the transmission and sub-transmission level. The capacitors are located on the 

secondary of the substation transformer, just down from the LTC. As long as the LTC is 

within operating limits, the impact of capacitor operations on voltage regulation is expected 

to be minor. 

• The polarity of measurement devices was switched during the study period. These data will 

be identified and programmatically adjusted to be compatible with the rest of the data set. 

• The residential loads on the feeder outside of the study group are presently completely 

unknown. Because they share the same distribution primary as the study system, these loads 

greatly impact the voltage regulation for the Anatolia subdivision. To remedy this, 

monitoring equipment will be installed at the entrance of the portion of the feeder under 

study. Once the equipment is installed, these data points will help validate the model by 

eliminating a large amount of uncertainty in the measurement set going forward. 

Additionally, by developing a profile for the unknown portion of the circuit, some 

uncertainty may be removed from the existing data set. 

31 
32 

• The cable characteristics have not been validated. Capacitance associated with long lengths 

of underground cabling may affect the voltage regulation of the circuit. Current simulations 

reflect generic cable parameters.

Figure 24 shows simulated voltage profiles for various levels of uniform customer loading and 

generation. Many of the issues discussed above are illustrated on this graph. 

Figure 24. Modeled voltage profiles for transformer 5K7
5 Problems Encountered 

1. Data-loss problems with the PMI transformer monitors were common especially after periods 

of high daytime temperatures. The estimated temperature inside the transformer enclosures, 

where the power-quality monitors are placed, could be 200°F on a 110°F day in full sunlight 

under heavy electrical load. The manufacturer of the monitors said they are only designed to 

operate reliably to 131°F; above that temperature, their operation cannot be guaranteed. 

2. The PMI meters installed on the homes may not be correctly reading reactive power. 

Typically in the data the reactive power is shown flowing in the opposite direction as the real 

power. Since the loads are typically inductive in nature, the reactive power should be flowing 

toward the loads. 

3. The substation SCADA data experienced at least six major data-loss incidents. 

4. Anatolia shares Feeder 1201 with a rendering plant, a water storage facility, a couple other 

residential communities, and agricultural pumps. This complicates efforts to determine the 

effect of PV on the voltage regulation of the circuit because of the low level of PV 

penetration. 

5. There are two additional feeders (1202 and 1203) that are connected to the substation 20 

MVA transformer. The loads on these feeders influence the total loading on the transformer 

and are typically more than 50% of the total load on the transformer. 

6 Findings 

1. There was no excessive service or substation voltage due to reverse power flow from 

exporting PV systems. The current level of penetration of PV on Feeder 1201 is 

approximately 11% to 13% under lightly-loaded conditions (2 MW) and around 4% of the 

total substation transformer load. Since the PV penetration levels are relatively low there 

were no adverse effects on voltage regulation. It was possible to see the effects of the PV 

systems on the voltage at the individual homes and the distribution transformers. This slight 

rise was approximately 0.6% on clear days in comparison to the normal drop of 0.3% without 

the PV exporting. 

2. There was no indication that utility voltage transients caused the PV systems to trip off. 

Further analysis will be conducted to identify if other utility-voltage events will trip off the 

PV inverters. 

3. Passing clouds did not seem to adversely affect the distribution system. At the current 

penetration levels, the ramps seen in the PV output due to clouds are less than the ramps 

produced by cycling loads such as air conditioners at the individual homes. 

7 Next Steps 

The following is a list of items that NREL and SMUD will address as the project continues: 

1. Install monitors in distribution transformers that can operate in hot environments without 

losing data. 

33 
2. Add monitors at more individual homes. 

3. Use monitors with cell-modem communication to automate data collection. 

4. Encourage more homeowners with PV systems to connect their inverters to the internet for 

system data collection so PV inverter operation data may be collected. 

5. Isolate power going into Anatolia III Community alone versus that going into other loads on 

Feeder 1201. 

6. Compare the performance of SolarSmart Homes with comparable Title 24-Compliant 

Homes. 

7. Plot expected PV power production based on solar irradiance and ambient temperature. 

8. Determine the effect of the PV systems’ output on the substation peak demand. 

9. Evaluate additional penetration scenarios using simulation model. 

34 
35 

8 References 

[1] Conversation with David Brown, Principal Distribution System Engineer, SMUD 

Distribution Services. 12/9/08. 

[2] SunPower literature. www.sunpowercorp.com. September 2007. 

[3] Photovoltaic Systems. Page 128. American Technical Publishers, Homewood, IL. 2007. 

[4] Conversation with Daryl Myers, Principal Scientist, NREL Resource Measurements and 

Forecasting Group. 4/29/09. 
F1147-E(10/2008) 

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Impact of SolarSmart Subdivisions on SMUD’s Distribution System

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This study analyzes the distribution impacts of high penetrations of grid-integrated renewable energy systems, 

specifically photovoltaic (PV) equipped SolarSmart Homes found in the Anatolia III Residential Community. 

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