AIC Smart Inverter Volt/Var Setting Impact on VO

AIC Smart Inverter Volt/Var Setting Impact on VO

Prepared by Ameren Illinois : July 31, 2019

Insert Name of Report 2

Table of Contents

INTRODUCTION 3

Executive Summary 4 Project Background 5

Project Objective 5 Feeders Analyzed 5

Conversion of Feeder Data 6 Literature Review 6

ANALYSIS 8

Methodology 8 Circuit/Feeder Selection 8 PV Placement Methodology 9 PV Control 10 Simulation Scenarios 12 Time-Series 8760 simulation 13 Assumptions 14

Metrics 15 Location-Specific Voltage 15 Average Voltage Change 16

EPRI Analysis 16

AMEREN ILLINOIS STUDY RESULTS 19

Annual Voltage Impact 19 Annual Voltage Change Averaged Across All Sections 19 Annual Community Solar PV Location Voltage Change 20 Annual Voltage Profile Flatness 21

Monthly Voltage Impact 25 Monthly Voltage Change Averaged Across All Sections 25 Monthly Voltage Change at Community Solar PV Location 28 Monthly Voltage Profile Flatness 30

EPRI'S STUDY RESULTS - SUMMARY 33

Comparing EPRI Results to Ameren's 33 Five Joint Feeders 33

Tailored Volt-var Curve 39 PV Reactive Power Flows 39 PV Curtailment 46 Impact on Regulator Tap Operations 46

RESULTS - SUMMARY AND CONCLUSION 50

APPENDIX A – EPRI'S EXTENDED RESULTS 53



Introduction On November 1st, 2018, the Illinois Commerce Commission issued its order in docket 18-0537, and approved Ameren Illinois' interim Smart Inverter Specifications. In addition, the Commission directed Ameren Illinois to investigate how smart inverters with the volt-var default setting may reduce the cost and/or increase the effectiveness of its voltage optimization (VO) program. From page 43 of the Commission's order:

" Given the potential to increase the effectiveness or lower the cost of AIC’s significant investment in VO, the Commission agrees with the Intervenors that it is worth investigating how smart inverter deployment could support or enhance the VO program. The Commission also agrees with the AG that the approved VO Plan should not be put on hold as a result of adopting this recommendation. The Commission will therefore direct Ameren to investigate how smart inverters with Volt-VAR may reduce the cost and/or increase the effectiveness of its VO program. The Commission further directs Ameren to provide a report on its investigation to Staff and the various Intervenors within this proceeding within 9 months of the date of this Order. The Commission further directs Staff to conduct workshop(s) on the results of this investigation with the interested parties to determine if significant savings could be found, and whether Ameren should amend its VO Plan to incorporate these findings." (emphasis added)

For purposes of this investigation, a "smart inverter" is defined as a device that converts direct current (DC) into alternating current (AC) and can autonomously contribute to grid support during excursions from normal operating voltage and frequency conditions by providing each of the following: dynamic reactive and real power support, voltage and frequency ride-through, ramp rate controls, communication systems with ability to accept external commands, and other functions from the Company. This study assumes that smart inverters meet the interim technical specifications approved by the Commission in 18-0537 and attached as an information sheet to Ameren Illinois' Rider CGR – Customer Generation Rebate. In order to fulfill the Commission's requirements and expectations, and to ensure that the investigation and its findings had appropriate rigor, Ameren Illinois worked with its planning software provider, Synergi and the Electric Power Research Institute (EPRI) to study the impact of Smart Inverter settings on VO and feeder voltage overall. The study included 15 circuits which were selected based on the following criteria:

• VO circuits: Given the focus of the investigation, circuits were selected based on their current or imminent inclusion in the VO program. One circuit had VO equipment already deployed in 2019, nine are scheduled for VO deployment in 2019, and five are planned for deployment in 2020.

• Geographic area: Circuits were selected from across all of Ameren Illinois' operational divisions.

• Customer type: Circuits analyzed included varying ranges of rural and urban customers, as well as differing mixtures of residential, non-residential-commercial and non-residential-, industrial customers.



Additionally, the study's scope included distributed energy resource (DER) penetration scenarios ranging from no DER deployment to scenarios with DER's at several penetration levels, as well as assuming varying smart inverter operating settings ranging from unity power factor, the approved default volt/var setting, and tailored volt-var modes. (For this study, "DER" is assumed to represent solar-fueled generation, although, as noted in the detailed study analysis, the same conclusions apply to other renewably-fueled generation).

To further verify the accuracy of the study's findings, Ameren modeled 10 circuits in Synergi, and EPRI modeled 10 circuits using Open DSS, with 5 of those circuits analyzed by both Ameren and EPRI.

In all simulation cases, the analysis utilized one year of historical hourly data (8760 hours) for both feeder loads and solar output. No modeling or analysis was performed using active control of the inverters, consistent with the level of communication and control allowed in the order for docket 18-0537, and Ameren Illinois current infrastructure capabilities. In addition to its primary research activities, Ameren Illinois reviewed available literature/studies on the impact of DER with smart inverters on operating voltages and regulating equipment on distribution circuits.

Executive Summary The investigation yielded the following primary findings:

• Even at very high penetration levels, the impact of solar using smart inverters on voltage profile flatness, and, consequently, VO effectiveness, is negligible on most feeders. On feeders where the flatness improved, the impact was relatively small and primarily driven by the smaller, highly dispersed installations. Additionally, the impact of any one specific generator installation, even very large installations, is negligible.

• The impact of solar generators using smart inverters on average voltage, feeder-end voltage and voltage profile flatness, even for a very high penetration scenario, is so minimal that it will not reduce the scope or cost of line conditioning work where necessary to meet VO targets. In other words, the capabilities of smart inverters are not enough to enable Ameren Illinois to avoid installing capacitors and/or regulators to implement VO.

• The AIC volt-var settings have no impact on VO cost or overall effectiveness, and serve primarily as a local resource to prevent low and high voltage during specific hours.

• The ability to communicate with and control smart inverters for reactive power production may have some potential, on a location and circuit case by case basis, to improve voltage reduction and reduce tap operations. Ameren Illinois did not specifically analyze the effect of active communication and control of the inverters for this study since the exercise of those capabilities exceeds the scope of the Commission's order in 18-0537.

• As the deployment of DER with smart inverters grows, Ameren Illinois will consider how best to modify the settings on its voltage control equipment to better coordinate their operations with the output of the DER.

• The support provided by smart inverters for VO programs has little impact on the amount of real power provided by DER given the width of the dead-band associated with the Ameren Illinois smart inverter settings. This also holds true when the tighter dead-band settings for the tailored volt/var setting analysis used.



• The independent investigations by Ameren Illinois and EPRI of the five overlapped circuits yielded consistent results, providing confidence in the conclusions reached in this analysis.

• Existing literature on this topic is minimal due to the relatively recent deployment of smart inverters and the limited implementation of VO programs, but the preliminary conclusions of those studies are consistent with the conclusions reached by Ameren Illinois in this study.

• Based on the results of the study, AIC has no plans to alter its existing VO plan, as approved by the Commission.

Project Background In addition to complying with the Commission's order in 18-0573, the proliferation of DER on the Ameren Illinois system is expected to be significant over the next 5 – 10 years, and Ameren Illinois needs to appropriately prepare for this increase to ensure continued customer value and reliability. Ameren Illinois is also deploying Voltage Optimization (VO) through much of its territory. By the end of 2019, Ameren Illinois will have deployed VO to 151 circuits. By 2024, the number of VO circuits deployed is expected to be over 1000. Ameren Illinois defines “VO” as a combination of Volt/VAR Optimization (“VVO”) and Conservation Voltage Reduction (“CVR”), which are implemented to first reduce the VAR flows on a circuit, and then lower the voltage to reduce end-use customer energy consumption and utility distribution system losses. VVO optimizes capacitor bank operations to improve power factor and reduce system losses. CVR utilizes voltage regulators, transformer load tap changers, and capacitors to control and reduce end-user voltages, which, in turn, lowers customers’ energy consumption. For the VO to be effective, voltages are maintained within permitted ranges, and then collectively reduced. The Illinois Future Energy Jobs Act (FEJA) requires Ameren Illinois to offer rebates to qualifying Net Metering customers whose renewable DER uses a smart inverter, with the expectation that Ameren Illinois will ultimately be able to monitor, operate, control and support additional uses of the smart inverter controlled DER. Following FEJA, Ameren Illinois filed with the Commission its proposed interim Smart Inverter Specifications, which provided default parameters/settings and industry safety codes as requirements for rebates. The default activated functions were: Anti-islanding, low/high voltage ride through, low/high frequency ride through, ramp rates and volt-var. Ameren Illinois' default volt-var function operates with a voltage dead band between 0.967pu to 1.033pu. With such a wide dead band, which is to be maintained at all times, the smart inverter will inject VAR into the grid at voltages less than 0.967pu and absorbs VAR from the grid at voltages greater than 1.033pu.

Project Objective The overall objective of this project is to develop a study to evaluate the impact of smart inverter volt-var settings to the Ameren Illinois VO program, at the location of the DER and the overall voltage profile on the circuit.

Feeders Analyzed Ameren Illinois selected 15 12kV feeders for analysis. The feeders were split between Ameren Illinois and EPRI for analysis. Ameren Illinois studied 10 feeders using Synergi, while EPRI studied 10 feeders using OpenDSS, with 5 feeders overlapping for comparison purposes. The feeders were also split between residential and non-residential customer mixes, and urban and rural areas to more



comprehensively model PV adoption on those feeders. The Phase 1 PV distribution type represents the low penetration PV allocation method utilized for those feeders.

Conversion of Feeder Data Ameren uses the Synergi planning tool for system planning. Synergi houses all of Ameren Illinois distribution circuits, including circuit details, device and conductor ratings, loadings, PV profiles etc., and uses the mdb file extension. EPRI uses the OpenDSS (DSS) distribution planning tool to conduct their analyses. Synergi feeder models were converted into DSS format by EPRI for analysis prior to any simulation studies.

Literature Review Smart Inverter volt-var operations is a relatively new practice. The introduction of Hawaii Rule 14H and California Rule 21, and the publication of UL 1741SA1, introduced as many as nine non-traditional grid functions. California mandated UL 1741SA configured Smart Inverters in September, 2017, while Hawaii implemented its UL 1741SA Smart Inverters in March, 2018. Volt-var mode, as a grid support function, is currently required as default mode for California and Hawaii. In an interim report by EPRI and National Grid (NG) on Smart Inverter settings for Grid Support2,3, EPRI helped NG evaluate different volt-var curves (VVC) and Power Factor (PF) functions for 18 solar DER sites with Smart Inverters. EPRI incorporated three methods to analyze VVC for the circuits: (1) Based on generic out of the box settings, (2) Based on feeder model location, (3) Based on feeder model, DER location, and service transformer impedance. EPRI is currently analyzing the impact of the Smart Inverter functions on those 18 circuits. This project is still ongoing, so no final conclusions have been drawn, however, a preliminary analysis indicates:

• Out of the box settings will provide slight voltage improvements on the circuits • Tailored settings will maximize voltage improvements, and may often require updates to

system changes (as depicted by load and DER penetration)

EPRI and the Salt River Project (SRP), a utility in Arizona, collaborated to evaluate the field performance of Smart Inverters whose operations were controlled using a Distribution Management System (DMS)4. Over 700 Smart Inverters were deployed in SRP territory. The Smart Inverters were tested with three control levels: (1) autonomous settings (set and forget), (2) seasonal changes to settings using the DMS, and (3) real time control of settings using the DMS. The key findings were:

• Voltage benefits: The value of using voltage support features from Smart Inverters increases with the size of the Smart Inverter. This is because larger systems have more influence on grid voltage

• Active power curtailment: There were no observed impacts on active power generation due to normal operation of the Smart Inverter

• Active control via DMS: Control of the traditional assets was most effective at reducing voltage violations and maintaining tighter voltages

1 https://www.ul.com/newsroom/pressreleases/ul-launches-advanced-inverter-testing-and-certification-program/ 2 Recommended Smart Inverter Settings for Grid Support and Test Plan: Interim Report. EPRI, Palo Alto, CA: 2018. 3002012594 3 Effectiveness of Grid Support from Smart Inverters and Recommended Settings in Field Deployment: EPRI, Palo Alto, CA: 2017. 3002011029 4 SRP Advanced Inverter Project: Research Findings. EPRI, Palo Alto, CA: 2019. 3002016625



While the focus of this report is to "investigate how Smart Inverters with volt-var may impact the VO program", it is worth pointing out that EPRI has been involved in numerous projects that have tried to determine proper volt-var settings for Smart Inverters. In such projects, some concluded and other still ongoing, it was noted that volt-var modes do flatten voltage profile and may also improve DER Hosting Capacity5,6 (Hosting Capacity refers to the amount of DERs a specific line section can accommodate without requiring utility investments to remediate violation of limits). However, determining how volt-var operations affects VO operations at different locations on the grid has been limited field of study by research organizations and utilities. A recent EPRI publication describes how Smart Inverter will impact the optimization of voltage and var flows7. The technical report concludes that two way communication should be established to VO assets, and Smart Inverters were listed as one of the VO assets (other assets being Load Tap Changers, Voltage regulators, and Capacitors). The report further categorizes Smart Inverters as the "fine tuning control" for voltage optimization. EPRI also carried out a demonstration project for the Department of Energy (DOE). The EPRI/DOE project included simulation work to analyze impact of Smart Inverter functions on the three demonstration feeders8. One finding from this project was that volt-var improves customer energy efficiency via improved CVR. In 2016, the National Renewable Energy Laboratory (NREL), issued a technical report on PV impact assessment of Smart Inverter volt-var control on CVR and Power Quality9. In the report, two case studies were analyzed: One involving 12kV HECO feeder, and the other involving a 21kV PG&E feeder. Both studies implemented a VO scheme and Smart Inverter volt-var curve in the analysis. Key conclusions were:

• With no PV, the voltage reduction energy savings were 1.51% for HECO and 3.86% for PG&E. NREL noted that the most likely reason for this difference is the difference in circuit characteristics i.e. higher distribution voltage for the PG&E circuit, the nature of urban environment, and the presence of 7 capacitors in the PG&E feeder (the HECO feeder had no capacitors). In this case, the capacitors helped flatten the voltage profile, which further lowered the regulator tap

• With PV, and Smart Inverters on volt-var mode utilized, a lower voltage distribution profile and increased energy savings were achieved. Compared to the no PV case, the HECO feeder achieved a further 1.06% increase in energy savings, while the PG&E saw a 0.41% further increase in energy savings

The VO scheme in NREL's report had one objective: lowering the voltages as much as possible. The Smart Inverter volt-var curve was then determined based on the VO objective. Similar to the NREL report, Ameren Illinois' optimal volt-var curve could vary for circuits with VO and circuits without VO. For the purpose of this report, the focus is on addressing the Illinois Commerce Commission (ICC) request that "Ameren Illinois is to investigate how smart inverters with volt-var may reduce the cost and/or effectiveness of its VO program." 5 Voltage Regulation Support from Smart Inverters: EPRI, Palo Alto, CA: 2017. 3002012033 6 Grid Impacts of DG with Advanced Inverters: Hosting Capacity of Large Scale PV using Smart Inverters: EPRI, Palo Alto, CA: 2013. 3002001246 7 Advanced Distribution Management System with Distributed Energy Resources Volt/VAR. EPRI, Palo Alto, CA: 2015. 3002006130 8 Smart Grid Ready PV Inverters with Utility Communication: Results from Field Demonstrations. EPRI, Palo Alto, CA: 2016. 3002008557 9 NREL: PV Impact Assessment of volt-var control on CVR: https://www.nrel.gov/docs/fy17osti/67296.pdf



Analysis Since adoption of the distributed generation interconnection rules and the Net Metering functionality in 2008, Ameren Illinois has seen a steady increase in the number of small, residential, rooftop PV DER interconnections. The installation of residential PV accelerated with the implementation of the Illinois Power Agency's Solar Renewable Energy Credit (REC) program in 2015. With the implementation of the Smart Inverter Rebate and REC program from FEJA, the number of non-residential and Community Solar installation applications has increased dramatically, and promises to even more significantly increase PV penetration on the Ameren distribution system. The differences in the sizing and geographic distribution of the three different types of PV installations (i.e. residential, non-residential and community solar), combined with the variety of feeder configurations and characteristics they will be connected to, are all important factors when determining the magnitude of the impact that the DER will have on planned VO operations. The addition of the Smart Inverter volt-var function further complicates the analysis, as the voltage regulation functions are so highly dependent on local feeder conditions and PV distribution.

Methodology

Circuit/Feeder Selection This section presents AIC's strategy for selecting circuits to model DER Smart Inverter impacts on Voltage Optimization (VO). The following strategy/approach was used to select circuits:

1. Number of Circuits: A total of 15 distribution circuits with operating voltages of 12KV were selected for analysis. Ameren will model 10 circuits. EPRI will also model 10 circuits, with 5 of the 10 being the same as Ameren's. This number of circuits will provide a good diverse sample size to validate and confirm the effects that DER Smart inverters have on VO.

Additionally, to ensure that the 15 circuits selected were representative of Ameren Illinois' distribution system, the team utilized the following selection criteria:

2. Diverse Geographic Area: Circuits were selected from all 6 Ameren Illinois divisions and considered both urban and rural areas. The urban areas covered the potential for behind the meter DER penetration such as Walmart and Lowe's, while rural areas covered the potential for community solar (2MW) DER penetration. By default, the majority of the circuits chosen for community solar analysis were rural as rural areas are more suitable for land acquisition and site sizing needs of large DER. (NOTE: For this report, residential circuits consisted of predominantly single-phase load. Urban-Mixed and Rural-Mixed both consisted of relatively equal amounts of single-phase and three-phase load, but Urban-Mixed feeders had load more concentrated near the substation, while load on Rural-Mixed feeders was distributed across a wider area)

3. VO Implementation: Circuits were primarily selected from the 2018 VO pilot circuit list or the 2019 VO circuit list, which comprise a total of 151 circuits available for analysis/modeling. The 2020 VO circuit list were also incorporated, which represented an additional 170 circuits for a total of 319 potential circuits.

4. DER: Circuits were selected taking into consideration existing large scale DER existing on Ameren's system, and the potential circuits to which community solar developers applied for interconnection in 2019.

5. Data Availability: The circuits selected were required to have at least one year of historical hourly load data at the feeder exit (i.e. the point at which the feeder exits the substation.) This is necessary to properly perform the time-series analysis.



Table 1 provides a quick summary of the 15 circuits that were selected for analysis. All of Ameren Illinois six divisions were represented. Of the 15 circuits, five were categorized as residential, five as urban-mixed customer, and five as rural-mixed. The number of customers on these circuits ranged from 454 to 1939 customers, with the circuit length miles ranging from as little as 2.28 miles to as long as 13.64 miles.

Table 1: Fifteen (15) Circuits Identified for Modeling DER Smart Inverter impacts on VO.

PV Placement Methodology The primary goal of this study is to determine the impact that DERs with Smart Inverter volt-var functionality will have on the overall VO effectiveness. Since residential rooftop, commercial rooftop, and Community Solar installations vary so significantly in sizing and geographic configuration, it is important to separately identify the effects of each. Phase One will model only one type of installation (residential, non-residential, Community Solar) per feeder to better isolate the relative impact of that type. Phase two will represent a high penetration, future case that combines the effects of all three. Both cases will examine the effects of the PV on VO, with and without the use of Smart Inverter volt-var settings. Phase 1 Methodology: Each circuit will have PV added according to one of the methods below.

• Residential: Add 60% of total non-three-phase peak load as PV, following a typical rooftop PV

output curve. Installations will be distributed to all sections with single-phase transformers and proportioned based on the section load.



• Non-Residential: Add 80% of total three-phase peak load as PV, following a typical rooftop PV output curve. Installations will be distributed to all sections with three-phase transformers and proportioned based on the section load.

• Community Solar: Add one 2 MW Community Solar installation on the feeder at either a) the proposed location of an actual Community Solar installation or b) a location on the feeder where Ameren interconnection criteria are met without major modifications, but far enough from the substation that the local voltage rise is significant. Specific locations for the studies will be determined by Ameren using these criteria.

The 60% and 80% values were selected so that, on average, each feeder is modelled with the same penetration of solar when measured as a percentage of peak load. This maintains the ability to compare the results across feeders of different distribution types. The difference between three-phase and non-three-phase penetrations also reflects the improved access to DERs for businesses as a result of earlier access to the Smart Inverter rebate and higher availability of investment capital. Phase 2 Methodology: Phase 2 will utilize the same three PV types as specified in Phase one, but will include all three distribution methods on the same feeder at the same specified penetration levels.

PV Control The PV control included looking at effectively no control (unity power factor operation) and the Illinois default volt-var curve. Both PV Phases were examined with and without the use of smart inverter volt-var settings.

Illinois Default Volt-var Settings: The volt-var function enables the smart inverter of either supplying or absorbing reactive power based on local voltage. Ameren Illinois' default volt-var (similar to CA Rule 21) curve is shown in Figure 1.

Fig.1: Volt-var Setting Illustration

The volt-var mode, which is intended to stabilize grid voltages, is equipped with a dead-band, at which point the Smart Inverter neither injects nor absorbs vars. The curve is typically categorized with four pairs of data points (V and Q). Ameren Illinois' default set points for V and Q is shown in Table 2. The dead-band is located between V2 and V3, at which the Var injection/absorption is zero (I.e. there is no voltage regulation). If voltages drop lower than V2, the Smart Inverter is expected to inject vars



into the grid in order to bring the voltages back to the dead-band. V1, which is associated with Q1, is where the maximum reactive injection of 30% can occur. If voltages raises past V3, then the Smart Inverter should absorb vars from the grid to bring the voltages back to the dead-band. V4, which is associated with Q4, is the location at which maximum absorption of 30% can occur. The position of the dead-band, as well as the Smart Inverter ability to inject/absorbs vars have the potential to affect VO operations on a feeder.

Table 2: Volt-var Setting Definitions and Ameren Illinois settings

Fig 2: Ameren Illinois' Approved Volt-var Setting



Simulation Scenarios Several different scenarios will be examined on each feeder in order to identify the impact of the DER as well as the volt-var function on planned VO schemes. In each scenario, an 8760 analysis will be performed, which modeled the feeder over an hourly period for the entire year. This method utilized actual/measured feeder head hourly loading data from 2018, as well as an 8760 DER profile (also measured from 2018), providing a more holistic view of the behavior between loads and DER's. Scenario 1: Feeder with VO Implemented (Baseline Case) This scenario will model the feeder after the initial implementation of VO. It is intended to serve as a control case so that the cases with additional DER added can be compared against a known quantity and the relative impact properly quantified. Each feeder was modeled with the set point of all voltage regulators reduced by 3.5V from their baseline, existing set point to model the voltage reductions required to meet VO reduction targets. Though some feeders may be capable of voltage reductions in excess of 3.5 V, especially during periods of lower feeder loading, a constant reduction of 3.5 V across all feeders and regulation devices will allow for consistent measurement and comparison of the results with PV across different feeders and at different times. Figure 3 shows the VO baseline voltages (along with the 3.5V Drop from the nominal voltages) that were utilized for all the 15 circuits.

Fig 3: VO baseline Voltages utilized through-out the modeling scenarios

Scenario 2: Feeder with VO and Phase 1 PV Distribution at Unity Power Factor This scenario will model the effects of additional PV installations on the voltage planned under VO for the three different PV placement types. PV generators at unity power factor will be added to the baseline feeder model according to the Phase 1 Methodology. Examining different types of PV distribution will isolate the effects of that distribution type and provide valuable insights into the expected effect on VO efforts.



Scenario 3: Feeder with VO and Phase 2 PV at Unity Power Factor

This scenario will model the combined effects of additional residential, non-residential, and community solar adoption. PV generators at unity power factor will be added to the feeder as outlined in the Phase 2 Methodology. Studying the combined case will give perspective on the potential impact of PV as a whole on VO efforts.

Scenario 4: Feeder with VO and Phase 1 PV Using Ameren Volt-var Curve

This scenario will model the effects of the implementation of the Ameren volt-var smart inverter functionality on planned VO for the three different PV placement types. PV will be added in the same quantities and locations as in Scenario 2, but will utilize the Ameren volt-var smart inverter profile specified in the Ameren Illinois Smart Inverter Specifications.

Scenario 5: Feeder with VO and Phase 2 PV Using Ameren Volt-var Curve

This scenario will model the combined effects of the Ameren volt-var smart inverter functionality on a feeder with a variety of PV distributions. PV will be added in the same quantities and locations as in Scenario 3, but will utilize the Ameren volt-var smart inverter profile specified in the Ameren Illinois Smart Inverter Specifications.

In addition to these five scenarios, EPRI's study considered two additional cases to analyze the impact of a volt-var curve more tailored to Voltage Optimization.

Scenario 6: Feeder with VO and Phase 1 PV Using Tailored Volt-var Curve

This scenario will model the effects of the implementation of a VO tailored volt-var smart inverter functionality on planned VO for the three different PV placement types. PV will be added in the same quantities and locations as in Scenario 2, but will utilize the tailored volt-var smart inverter profile that was jointly determined by Ameren and EPRI after analyzing the results from Scenarios 1-5.

Scenario 7: Feeder with VO and Phase 2 PV Using Tailored Volt-var Curve

This scenario will model the effects of the implementation of a VO tailored volt-var smart inverter functionality on planned VO for a feeder with a variety of PV types. PV will be added in the same quantities and locations as in Scenario 3, but will utilize the tailored volt-var smart inverter profile that was jointly determined by Ameren and EPRI after analyzing the results from Scenarios 1-5.

Time-Series 8760 simulation The seven scenarios for each feeder are examined using a time-series analysis. To conduct the time series analysis, load and PV profiles are added to model the variation of those conditions over time. The PV profile used for all modeled PV systems and in all feeders is shown in Figure 4. The profile utilizes actual/measured data from Ameren Illinois 125kW array for the year 2018, at the Technology Application Center, in Champaign, Illinois.



Fig.4: Normalized PV Profile Applied to all PV Systems

The load profile for each load was based on the feeder head active power SCADA measurement for the year 2018. This provided a unique load curve for each feeder as shown in Figure 5. Each customer within a specific feeder shared the similar profile.

Fig.5: Active Power Profiles for All 10 Feeders

Assumptions There were several necessary additional assumptions in this analysis that may have had an impact on the overall results.

• Capacitor switching – Temperature switching was based on power flow rather than actual temperature. High power flow approximated high temperature and air conditioning load when capacitors would likely be in-service.

• Regulator control – Regulated voltage set point was dropped 3.5 V for all regulators/LTC • Load type – Load types and their response behaviors to voltage changes were modeled using the

ZIP (constant impedance, constant current, and constant power) model coefficients previously



determined to be broadly representative of Ameren's typical mix. The load type mix is assumed to be 40% constant impedance, 10% constant current, and 50% constant power for all feeders in the study.

• Exclusion of service transformers and services – The impedance of service transformers and services will impact the actual voltage at customer locations which would impact the volt-var response of inverters in the field. For the purposes of this study, service transformer and service impedance were not included in the model. This maintains modeling consistency between the residential, non-residential, and community solar, as well as with other DER studies performed by both Ameren and EPRI.

• Inverter/PV ratio is 1:1 – Inverters are assumed sized the same as the installed PV system. This can impact the inverter output when operating under active or reactive power priority.

• Reactive power priority inverters – This is the current industry approach and consistent with the approved smart inverter specification, but active power priority is still defined within IEEE 1547. Active power priority and a 1:1 inverter/PV ratio would restrict the reactive power output when the system might need it most during high voltage and high PV active power output.

Real-time Monitoring & Control - In all simulation cases, the analysis utilized one year of historical hourly data (8760 hours) for both feeder loads and solar output. No modeling or analysis was performed using active control of the inverters, consistent with the level of communication and control allowed in the order for docket 18-0537, and Ameren Illinois current infrastructure capabilities.

Metrics The metrics are the results from the time-series analysis that will be used to quantify the impact of PV penetration and PV volt-var control. The metrics within this study will focus primarily on voltage. This is done to evaluate the potential for improved VO performance. By observing the change in voltage, consumption impact can be estimated, and by observing the feeder-exit and most remote section voltage, a flattening of the voltage profile can be estimated which might allow further regulator voltage drop than the 3.5V assumed in this study.

The voltage metrics will also be reported on different time intervals. Monthly and yearly average daytime voltage will summarize the impact during the time when PV is likely producing power (8am – 6pm), while specific hour impacts will be examined to determine how the VO operation might change feeder performance during special planning and operating intervals. The specific hours examined include highest/lowest gross load and highest/lowest net load. These specific hours are derived from the No PV scenario. All hours are examined for highest/lowest gross load and highest net load, while only daytime hours are examined for lowest net load.

Location-Specific Voltage The feeder-end/remote section voltage is key to identify because of how VO was implemented in the models. The reduction of the feeder-exit voltage of 3.5 V was used to provide a consistent comparison across feeders. This value provides a good approximation of the planned VO impacts, but does not represent that actual maximum voltage reduction possible on each feeder. The real constraint for the voltage reduction is the lowest voltage of a remote section on the feeder (or within a regulation zone). A comparison of the feeder-end voltage across the different cases will quantify any impact that the PV has on raising the voltage profile and the potential for voltage reduction at the feeder-exit.



The feeder-exit voltage measurement will also allow quantification of the ‘smoothness’ of the voltage profile across the feeder. Other location-specific measurements will help understand the impact of VO-schemes based on single measurement points on the feeder.

Average Voltage Change The average voltage change values from the study show the voltage increase on the feeder due to the distributed generation present. This value, combined with the lowest section voltage information, will allow for the calculation of the expected net voltage impact of DER on VO feeders. A comparison of the average voltage change across different feeders will also allow for conclusions to be drawn regarding the effect of the different DER configurations.

EPRI Analysis EPRI followed the same analysis approach as Ameren did, with the addition of analyzing scenarios 6 & 7. EPRI automated the analysis in OpenDSS to conduct the study across three PV control schemes, three PV placement schemes, and ten feeders. The flowchart below summarizes EPRI's methodology

Fig.6: Flowchart of Methodology



In addition to the unity pf and default volt-var curve, EPRI considered a third control scheme, tailored volt-var control. The tailored volt-var curve shown in Figure 7 is designed to use PV inverters to help flatten feeder voltage by increasing the capacitive region response to help raise voltage in low-voltages areas and more inductive region response to help lower voltage in areas where PV pushes voltage up. The tailored volt-var settings were initially determined based on simulated voltage regulator settings (~2V bandwidth and 121.5 V setpoint), but the center of the dead-band was reduced to account for ~1.5 V drop to the modeled PV locations. This also correlated to the range in voltages observed across the feeders. Observed voltages seldom went above 1.02 Vpu or below 0.98 Vpu. Therefore, the inverters would potentially be operating in both the capacitive and inductive regions. Finally, it was desired to have more reactive impact within the ANSI voltage range. To achieve this, the V1 and V4 setpoints were adjusted to 0.95 Vpu and 1.05 Vpu, respectively.

Fig.7: Tailored Volt-var Setpoints

Putting it all together, EPRI evaluated seven scenarios. Scenarios 1-5 are identical to those considered by Ameren. The two additional scenarios evaluated the tailored volt-var curve:

Scenario 6: Feeder with VO and Phase 1 PV Using VO-Specific Volt-var Curve

This scenario will model the effects of the implementation of the VO-Specific volt-var smart inverter functionality on planned VO for the three different PV placement types. PV will be added in the same quantities and locations as in Scenario 2, but will utilize the VO-Specific volt-var smart inverter profile determined jointly by Ameren and EPRI.

Scenario 7: Feeder with VO and Phase 2 PV Using VO-Specific Volt-var Curve

This scenario will model the combined effects of the VO-Specific volt-var smart inverter functionality on a feeder with a variety of PV distributions. PV will be added in the same quantities and locations as in Scenario 3, but will utilize the VO-Specific volt-var smart inverter profile determined jointly by Ameren and EPRI. The ten circuits analyzed by EPRI, are shown in the table below. The PV placement on each feeder for Phase 1 and 2 can be seen on the table.



A total of ten feeders were evaluated by EPRI, five of which coincided with those analyzed by Ameren. Table 3 shows the ten EPRI feeders, as well as the PV placement for phase 1 and 2.

Table 3: Phase 1 PV Placement



Ameren Illinois Study Results The voltage impact of PV integration and volt-var functionality are assessed in two timeframes: annual impact and monthly impact. Annual and monthly voltage impacts are averaged across those respective time frames. The reactive power generation and potential active power curtailment associated with volt-var function are also evaluated in this section as well as the impact of regulator tap operations.

Annual Voltage Impact The annual voltage metrics indicate the overall impact of PV penetration and smart inverter functionality over the duration of the year. Voltage values are averaged over daytime hours, when the PV is online, for this assessment.

Annual Voltage Change Averaged Across All Sections The annual voltage change is averaged across all sections on each feeder to assess the overall PV and volt-var control impact. The resulting values are listed in Table 4 and shown in Figure 9. Positive value in Figure 5 indicates a voltage increase from the baseline no-PV scenario 1. Generally, voltage increases with PV penetration except for Feeder N95824, which sees a voltage reduction in low PV penetration scenarios (2,4). This is caused by a regulator tapping down as shown in Figure 10. The high PV penetration scenarios (3,5) see a greater voltage rise than the low penetration scenarios (2,4).

Distributed PV deployments (non-residential and residential) more likely cause feeder wide voltage increase than Community PV, indicated by the low voltage change on the community solar feeders in scenario 2 and 4.

Enabling volt-var functionality generally has negligible impact on the feeders when averaged across the duration of the year. The default smart inverter volt-var setting scenarios (4,5) has minimal impact on all ten feeders as indicated by comparing the results in scenario 2 versus scenario 4 and scenario 3 versus scenario 5.

Table 4: Annual Voltage Change Averaged Across All Sections (Volts on 120V base)



Fig.9: Annual Voltage Change Averaged Across All Sections (120 V base)

Fig.10: Tap Position Change for N95824 feeder for Phase 1 & Phase 2 PV scenarios

Annual Community Solar PV Location Voltage Change The annual voltage change from the baseline scenario at the Community Solar PV location is listed in Table 5 and shown in Figure 11. This comparison focuses on the voltage impact at a specific location rather than the impact feeder-wide. The location of the Community Solar site for that feeder, regardless of whether its output was included in the scenario, was monitored as part of the study. Similar to the voltage change averaged across all sections, the community PV site annual voltage change increases with PV penetrations. Also, the default volt-var curve does not have impact.

For the Community Solar feeders, as expected, there is a large increase in local voltage at the DER site relative to the base case. For the residential and non-residential feeders, there is typically



marginal impact, if any, on the voltage at the location of the Community Solar site (with no output in this scenario). Under the high penetration cases, some feeders see a significant voltage increase at this location, while others see a much smaller increase. This is dependent on the feeder layout, Community Solar site location, and feeder loading.

Table 5: Annual Community PV Location Voltage Change (Volts on 120V base)

Fig.11: Annual Community PV Location Voltage Change (120 V base)

Annual Voltage Profile Flatness Voltage profile flatness is assessed by examining the difference between the feeder-exit voltage and the feeder-end voltage (measured as the lowest section voltage), averaged across daylight hours. This metric serves as a relative measure of potential voltage reductions that can be achieved by active control of the voltage regulator taps. A lower result indicates a relatively flat profile with a higher capability for voltage reduction when VO is enabled. Below, feeder-end and feeder exit voltage



impacts are examined separately, then combined to examine the overall voltage profile flattening effect.

The overall impact on the feeder-end voltage is shown in Table 6 and in Figure 12. It can be seen that PV penetration with or without volt-var functionality increases the lowest section voltage on most feeders except for Feeder N95824., which is attributed to the single regulator tap change that occurred. Overall, the feeder-end voltage increases by a small magnitude on most feeders because of the injection of real power from the solar. The reactive power contribution of the volt-var curve has a negligible impact on the feeder-end voltage.

Table 6: Annual Feeder-End Voltages

Fig.12: Annual Feeder-End Voltages



The absolute (non-averaged) lowest section voltage of the entire year for all ten feeders is plotted in Figure 13. For the feeders and scenarios with only Community Solar installations, there is very little impact on the lowest section voltage. Due to the highly localized voltage impact of community solar, this result may vary significantly depending on the location of the installation relative to the feeder-end.

For the more distributed residential and non-residential distributions, the increase in feeder-end voltage is more pronounced, though still dependent on the feeder characteristics. The highly distributed residential configuration shows the largest and most consistent increase, as a portion of the added DER is always near the feeder-end node.

Fig.13: Absolute Lowest Feeder-End Voltage (120 V base)

The feeder-exit (location just downstream the feeder head regulator) voltage is summarized in Figure 14 for all ten feeders. The voltages increase for most of the feeders but are very small in magnitude. This is because voltage rise at that location is limited due to the regulator control and relative strength of the substation source. As mentioned earlier, the voltage decrease on feeder N95824 is a result of the regulator tapping down at the beginning of the year.



Fig.14: Annual Feeder-Exit Voltage (120 V base)

The flatness results for each feeder are shown below in Table 7 and Figure 15. For most feeders, the high penetration case shows a lower flatness value, indicating a flatter overall voltage profile. Though the flatness results are lower on a majority of the feeders, the magnitudes of the changes, even for very high penetrations of PV, are negligible, considering the operating characteristics of the voltage regulating equipment being deployed for VO.



Table 7: Differences between Annual Feeder Exit Voltage and Annual Feeder-End Voltage

Fig.15: Differences between Annual Feeder Exit Voltage and Annual Feeder-End Voltage

Monthly Voltage Impact The PV and smart inverter impact on feeder voltages is similarly addressed to the annual impact in this section but quantified based on specific months during daytime hours. Again, the voltages reported are averaged over the respective time periods.

Monthly Voltage Change Averaged Across All Sections Figure 16, Figure 17, and Figure 18 show the monthly impact based on average section voltage for the phase 1 PV integration of commercial, non-residential, and residential, respectively. Generally, voltages rise the most over the summer months. Voltage change is also more significant due to higher penetration of PV (Phase 2 PV penetrations scenarios (3,5) cause more voltage rise than phase 1 PV penetration scenarios (2,4)).



The default volt-var scenario (4,5) has minimal impact on voltage on average over the year compared to the unity power factor setting.

Fig.16: Monthly Voltage Change Averaged Across All Sections for Feeders with Phase 1 Community PV: Feeder P73182, Feeder T08502, Feeder U31598, and Feeder A91004



Fig.17: Monthly Voltage Change Averaged Across All Sections for Feeders with Phase 1 Non-residential PV: Feeder N95824, Feeder K39153, and Feeder Y98532



Fig.18: Monthly Voltage Change Averaged Across All Sections for Feeders with Phase 1 Residential PV: Feeder M45212, Feeder H00163, and Feeder D89002

Monthly Voltage Change at Community Solar PV Location At the Community Solar PV location, the voltage rise is higher than the feeder-wide average voltages as shown in Figure 19, Figure 20, and Figure 21. Similar to what was observed for all sections, voltages rise the most in the summer months, penetration level of PV has a significant impact on overall voltage change, while default volt-var curve has minimal impact compared to the unity power factor setting.



Fig.19: Monthly Voltage Change at Community PV Location for Feeders with Phase 1 Community PV: Feeder P73182, Feeder T08502, Feeder U31598, and Feeder A91004

Fig.20: Monthly Voltage Change at Community PV Location for Feeders with Phase 1 Non-residential PV: Feeder N95824, Feeder K39153, and Feeder Y98532



Fig.21: Monthly Voltage Change at Community PV Location for Feeders with Phase 1 Residential PV: Feeder M45212, Feeder H00163, and Feeder D89002

Monthly Voltage Profile Flatness The impact of PV penetration and smart inverters on feeder voltage profile flatness is assessed by the monthly feeder-exit voltage minus the feeder-end voltage. The reduction from the baseline case (scenario 1) indicates a flatter voltage profile, as can be seen on almost every feeder for each month in Figure 22, Figure 23, and Figure 24.

Residential PV penetration has the greatest impact on flattening the voltage profile. This can be seen in Figure 21 which has Phase 1 Residential PV penetration, but this can also be seen on all feeders in higher penetration scenarios (3,5). The feeder voltage profiles are also flattest during the shoulder months, but there is more pronounced flattening that occurs from PV penetration over the summer months. Volt-var functionality with the Illinois Smart Inverter settings does show some potential to improve in the profile flatness, especially in the summer, though the effect is somewhat limited in this study.



Fig.22: Monthly Voltage Profile Flatness for Feeders with Phase 1 Community PV: Feeder P73182, Feeder T08502, Feeder U31598, and Feeder A91004

Fig.23: Monthly Voltage Profile Flatness for Feeders with Phase 1 Non-residential PV: Feeder N95824, Feeder K39153, and Feeder Y98532



Fig.24: Monthly Voltage Profile Flatness for Feeders with Phase 1 Residential PV: Feeder M45212, Feeder H00163, and Feeder D89002



EPRI's Study Results - Summary EPRI carried out a similar set of studies as those done by Ameren. EPRI analyzed their ten feeders in OpenDSS, and their result is captured in greater detail in Appendix A. This section:

• Compares EPRI's results to those of Ameren's, including what is similar or different to Ameren's

• Covers new/additional work that was done by EPRI but not Ameren. This includes assessments of: Tailored volt-var curve (VO-Specific curve), PV reactive power output, PV curtailment, and the impact of PV settings on regulator tap positions

Comparing EPRI Results to Ameren's In general, it was determined that the overall voltage results are the same as those done by Ameren. There were clear similarities in voltage behavior across Ameren's and EPRI's analysis, with just minor differences between the two studies. Note- due to the differences in the analysis software used by EPRI and Ameren Illinois (and associated data output formats and functionalities), it was not feasible to overlay the EPRI and Ameren Illinois data on the same graphs.

Five Joint Feeders

Table 8 summarizes the similarities and differences between the circuits analyzed. Of the fifteen feeders analyzed, five were jointly modeled by both EPRI and Ameren. The five joint circuits are listed in Table 9. These joint feeders (studied by EPRI in OpenDSS and Ameren in Synergi), should provide for a good result comparison across the three types of PV allocation techniques (Community Solar, non-residential, and residential type PV). Again, as mentioned earlier, EPRI's complete results for the ten feeders are included in Appendix A.

Table 8: Similarities and Differences in the types of circuits analyzed

Table 9: Joint feeders analyzed in both OpenDSS and Synergi

The results for the five joint feeders are compared in terms of monthly voltages: (1) Averaged across all sections, (2) At the location of the community PV, and (3) Flatness of the profile. (NOTE: Ameren only analyzed scenario 1-5, while EPRI analyzed scenarios 1-7. For comparison purposes, scenario 6-7 does not apply)



Feeder P73182

Feeder P73182 is a rural circuit that had 2MW community PV allocated for phase 1. Figure 25-27 shows a comparison of the monthly average voltage changes between Open DSS and Synergi. Voltage profiles are fairly consistent across the two set of studies, in that voltages increased with PV penetration, and that the default volt-var (scenarios 4-5) had little impact on the voltages when averaged over an entire year. This should be expected, since the volt-var operating set points have such a wide dead-band that it only typically operates near minimum or peak conditions and only on feeders where some areas experience voltages outside of the dead-band. The volt-var curve's purpose is to counteract voltage extremes, which are relatively infrequent relative to the average but are critical to address.

Fig.25: Comparison of Monthly Average Voltages Changes between OpenDSS and Synergi

Fig.26: Comparison of Monthly Average Voltage Changes at Community PV location

Fig.27: Comparison of Monthly Voltage Profile Flatness between OpenDSS and Synergi



Feeder N95824

Feeder N95824 is a mixed circuit that had non-residential PV allocated for phase 1. Figure 28-30 shows a comparison of the monthly average voltage changes between Open DSS and Synergi. Feeder N95824 is a special case, in that, negative delta voltages can be seen in Figure 25-26. The negatives voltages, which is also consistent across EPRI's and Ameren's results, is because of the regulator tap position tapping down. Once again, the voltage profiles are fairly consistent across the two set of studies, though there are some differences in the magnitude of the values. These differences are relatively constant throughout all feeders, and stem from differences in the model characteristics between Synergi and OpenDSS.






Feeder K39153

Feeder K39153 is a mixed circuit that had non-residential PV allocated for phase 1. Figure 31-33 shows a comparison of the monthly average voltage changes between Open DSS and Synergi. Consistent with other feeders, the plots show monthly voltages to be closely aligned across OpenDSS and Synergi results






Feeder Y98532

Feeder Y98532 is a mixed circuit that had non-residential PV allocated for phase 1. Figure 34-36 shows a comparison of the monthly average voltage changes between Open DSS and Synergi. Comparing the two sets of data sets from EPRI and Ameren. It can be seen that Ameren's plots show more of smoother curve compared to EPRI's results. However, clear similarities can be observed in terms of the overall voltage profiles and peak months.






Feeder D89002

Feeder D89002 is a residential circuit that had residential PV allocated for phase 1. Figure 37-39 shows a comparison of the monthly average voltage changes between Open DSS and Synergi. Overall, the profiles look similar, however, during the summer months, the Ameren results indicate very minor voltage controls from the default volt-var curves. The December data on the plot from EPRI shows a drastically different result than Ameren's, with a reduction of approximately 0.5V. This is slightly less than the change due to one regulator tap. The expected cause is that a small difference in voltage at the regulator between Synergi and OpenDSS caused one to tap down while the other did not.






Summary of Joint Key Observations

In addition to the five joint feeders, where results were fairly consistent across EPRI and Ameren, general conclusions can also be drawn from EPRI's ten feeders and Ameren's ten feeders. Overall, based on scenarios 1-5, key takeaways are that:

• Voltage increases with PV penetration except for feeders that had regulator tapping down. • Voltage rises the most in the summer months. • The high PV penetration scenarios (3,5) see a greater voltage rise than the low penetration

scenarios (2,4). • Enabling volt-var functionality generally has a limited impact on the feeders when averaged

across the entire year, but does show the potential to impact specific hours to help return the voltage to the preferred operating range.

• Distributed PV deployment (non-residential and residential) are more likely to cause feeder wide voltage increase than Community Solar PV.

• The addition of residential type PV typically flattens the profile to a higher degree than non-residential or Community Solar installations.

• Voltage profiles are flattest during the shoulder months, but there is more pronounced flattening that occurs from PV over the summer months.

Summary of Key EPRI Observations Additionally, EPRI analyzed the VO-specific volt-var curve (scenarios 6-7), PV reactive power flow, PV curtailment, and the impact on regulator tap operations.

Tailored Volt-var Curve EPRI evaluated the tailored volt-var curve (VO Specific curve) on ten feeders. It was determined that:

• Annual Impact: The VO-Specific volt-var scenarios (6,7) slightly increase voltage impact, but that impact is still inconsistent across all feeders. This is in-part due to the smart inverter raising voltage when voltage is low, pulling voltage down when voltage is high, and the dynamics of that interaction with regulators on the feeder.

• Monthly Impact: The VO-Specific volt-var scenarios (6,7) can slightly limit the voltage rise on some feeders, however, the impact is based on the smart inverter output and the interaction with regulators

PV Reactive Power Flows In volt-var control scenarios (scenario 4 to7), inverters inject or absorb reactive power to control the local voltage based on the specified volt-var curve. Each inverter operates individually based on its local voltage, while its real and reactive power flows also impact the local voltage and subsequent behavior of other inverters. Some inverters may experience relatively higher voltages and operate more often consuming reactive power. Other inverters may experience lower voltage and operate more often generating reactive power. Table 10 illustrates this phenomenon for the high penetration scenario with the Ameren volt-var setting (scenario 5). Although this volt-var setting has not indicated much feeder-wide impact, on an individual basis, some inverters are operating quite often (indicated by max hours significantly greater than the average hours). These individual inverters are acting to mitigate local impacts, however, the aggregate feeder-wide inverter output and feeder impacts are minimal. Because the inverter's reactive power operation is controlled by the local voltage, the



reactive capabilities of inverters in certain areas operate significantly more than others. Active control of the inverters would enable for a more even distribution of reactive power needs and further reduce the potential for curtailment by more fully utilizing all available resources for voltage control.

Table 10: Number of Hours that Volt-var Operated with Reactive Power Flow in Scenario 5

[Note: Inductive refers to absorbing reactive power when voltage exceeds the volt-var V3 setpoint, while Capacitive refers to injecting reactive power when voltage is below the volt-var V2 setpoint] The usage of volt-var control with the tailored setting of Scenario 7 is shown in Table 11. Having control to adjust the volt-var setting improves the utilization of all inverters. Inverters are operating more often to consume and generate reactive power. Overall the inverters are operating more often to consume reactive power (inductive) as indicated by the average number of hours operating. Further tailoring of the settings might improve the usage as both capacitive and inductive.

Table 11: Number of Hours that Volt-var Operated with Reactive Power Flow in Scenario 7



As shown in Figure 40 to Figure 49, the aggregate inverter output from scenario 5 is relatively small compared to the inverter output in scenario 7. Again the difference between scenario 5 and 7 is the volt-var setting applied.

Fig.40: Total Reactive Power Output for Feeder P73182

Fig.41: Total Reactive Power Output for Feeder Q85162

Fig.42: Total Reactive Power Output for Feeder N70330



Fig.43: Total Reactive Power Output for Feeder V23522

Fig.44: Total Reactive Power Output for Feeder K39153

Fig.45: Total Reactive Power Output for Feeder Y98532



Fig.46: Total Reactive Power Output for Feeder N95824

Fig.47: Total Reactive Power Output for Feeder D89002

Fig.48: Total Reactive Power Output for Feeder L23145



Fig.49: Total Reactive Power Output for Feeder Q16867

The default volt-var scenario (5) slightly smooths the voltage waveform over the year at the Community Solar location as shown in Figure 50, Figure 51, and Figure 52. The VO-Specific volt-var scenario (7) further smooths the voltage due to the higher reactive power output as previously shown.

a) b) Fig.50: Time-series Voltages at Community PV Location for Feeders with Phase 1 Community PV a) Feeder P73182 b) Feeder Q85162

a) b)

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