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

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

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

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

Contract No. DE-AC36-08GO28308

Value Streams from Distribution 

Grid Support Using Utility-Scale 

Vanadium Redox Flow Battery 

NREL-Sumitomo Electric Battery 

Demonstration Project

Adarsh Nagarajan, Dylan Cutler, Aadil Latif, 

Xiangkun Li, Richard Bryce, Ying Shi, Jin Tan, 

Qian Long, Peter Gotseff, Ershun Du, 

and Murali Baggu

National Renewable Energy Laboratory

Yoshihiro Hirata, Katsuya Yamanishi, 

Keiji Yano, Riichi Kitano, 

and Yoshiyuki Nagaoka

Sumitomo Electric USA (SEUSA)

Technical Report

NREL/TP-5D00-71545

August 2018 
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

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

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

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Value Streams from 

Distribution Grid Support 

Using Utility-Scale Vanadium 

Redox Flow Battery 

NREL-Sumitomo Electric Battery 

Demonstration Project

Adarsh Nagarajan, Dylan Cutler, Aadil Latif, 

Xiangkun Li, Richard Bryce, Ying Shi, Jin Tan, 

Qian Long, Peter Gotseff, Ershun Du, 

and Murali Baggu

National Renewable Energy Laboratory

Yoshihiro Hirata, Katsuya Yamanishi, 

Keiji Yano, Riichi Kitano, 

and Yoshiyuki Nagaoka

Sumitomo Electric USA (SEUSA)

Technical Report

NREL/TP-5D00-71545

August 2018
iii

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

NOTICE

This work was authored in part by the National Renewable Energy Laboratory (NREL), operated by 

Alliance for Sustainable Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DEAC36-08GO28308. Funding provided by the New Energy and Industrial Technology Development 

Organization (NEDO) and Sumitomo Electric. This work is based on results obtained from a project 

commissioned by the New Energy and Industrial Technology Development Organization (NEDO). The 

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

SDG&E does not prescribe to all the values stream NREL has assigned in this report. The economic 

conclusions arrived to by NREL and NREL only. 

This report is available at no cost from the National 

Renewable Energy Laboratory (NREL) at 

www.nrel.gov/publications.

U.S. Department of Energy (DOE) reports produced 

after 1991 and a growing number of pre-1991 

documents are available 

free via www.OSTI.gov.

Cover Photos by Dennis Schroeder: (left to right) NREL 26173, NREL 18302, NREL 19758, NREL 29642, NREL 19795.

NREL prints on paper that contains recycled content.
iv

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List of Acronyms

ANN Artificial neural network

BLAST Battery Lifetime Analysis and Simulation Tool

CAISO California Independent System Operator 

CSV Comma Separated Value

DoY Day of year

HRRR High-Resolution Rapid Refresh

LFP Lithium iron phosphate/graphite 

LIB Lithium-ion battery

Li-ion Lithium-ion

LMP Locational marginal price

LTC Load tap changer

NCA Lithium nickel cobalt aluminum oxide/graphite

NGR Non-generator resource

NMC Lithium nickel manganese cobalt oxide/graphite

NREL National Renewable Energy Laboratory

O&M Operation and maintenance

PCS Power conditioning system

PDR Proxy demand resource

PG Participating generator

PL Participating load

PS Participating system

PV Photovoltaic 

RDRR Reliability demand response resource

REM Regulation Energy Management 

REopt Renewable Energy Integration and Optimization

RMSE Root mean square error 

SDG&E San Diego Gas & Electric Company

SOC State of charge

VAR Volt-ampere reactive 

VRFB Vanadium redox flow battery

WDAT Wholesale distribution access tariff

WDT Wholesale distribution tariff

XML Extensible Markup Language
v

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Executive Summary

The National Renewable Energy Laboratory (NREL) collaborated with Sumitomo Electric to 

provide research support in modeling and optimally dispatching a utility-scale vanadium redox 

flow battery (VRFB) energy storage system. The primary objective of the project was to identify 

value streams through the application of utility-scale VRFB for local grid support use cases, 

including:

• Voltage regulation (droop): When operated in this mode, the system maintains the

voltage on the feeder close to its nominal value. To accomplish this objective, the 

reactive power dispatched from the VRFB is based on the voltage at the battery’s point of 

common coupling using a voltage droop curve.

• Capacity firming: In this mode, the VRFB smooths high-frequency power flow 

fluctuations at the substation to a constant or low-frequency timescale average value.

• Peak shaving and valley filling: Peak shaving is defined as displacing the power 

consumption of the feeder by a predetermined amount for a specific time; this is a special 

case of load shifting. In this control mode, the VRFB is used to regulate the peak power 

of the feeder within a predefined limit. 

• Energy arbitrage: To take advantage of the price difference of electricity across time 

periods, the VRFB is charged during off-peak hours and discharged during peak hours.

The revenue obtained is the price differential between buying and selling electrical 

energy minus the cost of losses during the full charge/discharge cycle. 

This project was also supported by San Diego Gas & Electric Company (SDG&E). SDG&E 

provided data and approval to operate their VRFB energy storage system on an SDG&E 

distribution feeder. NREL worked with Sumitomo Electric to evaluate optimal dispatch 

strategies to VRFB, analyze the technical impacts, and calculate the associated cost-benefit ratio 

of substation-level energy storage on an SDG&E distribution feeder. 

To support this research, NREL evaluated the impacts of the battery use cases suggested by 

Sumitomo on the SDG&E host feeder. In addition to evaluating the battery use case, this effort 

identified possible ways to monetize the benefits from distribution feeder support.

Distribution Feeder Under Study

A utility-scale VRFB was commissioned in the distribution feeder on May 2017 at a location 

shown in Figure ES-1. A portion of the TEST FEEDER feeder between the VRFB and the 

primary overhead line connecting to the substation (marked ‘S’) is capacity-constrained (Figure 

28). This 1.5-mile #6 overhead cable has a maximum rating of 2.25 MVA, and it directly impacts 

the maximum charging capacity of the VRFB system. Because the VRFB is installed 

downstream of the capacity-constrained line, total load from that point of the feeder and below

(along with VRFB charging power) cannot exceed 2.25 MVA.
vi

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Figure ES-1. Topology of the distribution feeder highlighting the location of the energy storage 

system

Key tasks that were performed included:

• Modeling and simulation of the distribution substation including all seven feeders 

(detailed test feeder and aggregated loads for the other six feeders).

• Developed and validated the battery control models for voltage regulation, peak 

shaving/valley filling and capacity firming.

• Assigned costs to distribution feeder support and optimally dispatched the energy storage 

system.

• Generated optimal battery operation schedules.

• Assessed battery energy storage participation in California Independent System Operator 

(CAISO) markets.

• Developed an understanding and compared value streams between the VRFB and 

lithium-ion (Li-ion) battery chemistries.

• Developed high-fidelity loss models for the VRFB.

• Generated load forecasts for one week and performed day-ahead dispatch of the VRFB 

under test based on CAISO day-ahead price signals.

Following are descriptions of key methodologies and results.

Model the Distribution Substation 

The models of the distribution feeders in Synergi (provided by SDG&E) were converted by 

NREL; i.e. the Synergi files were parsed to generate a feeder model in the OpenDSS format. The 

converted model was validated for node voltages, and the feeder sequence impedance was 
vii

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compared with the original Synergi models. This task involved running a snapshot simulation in 

Synergi and OpenDSS for identical loading/photovoltaic levels. The node voltages and sequence 

impedances were compared between Synergi and OpenDSS. Ultimately, the voltage comparison 

errors were successfully restricted and sequence impedance comparison errors to a range within 

1% of the intended values. 

The requisite data provided by SDG&E included annual feeder load data, annual solar irradiance

profiles, and VRFB energy storage system charge and discharge rates and limits, such as the 

monitoring point for power, voltage, frequency, range of state of charge, and range of 

active/reactive power. Additionally, SDG&E provided the technical specifications data sheets for 

the inverter and voltage control equipment (e.g., regulators and capacitors).

Develop and Validate VRFB Controls

Control models were developed to simulate the various VRFB use cases (i.e., voltage regulation, 

peak shaving, and capacity firming) to understand the impacts of the VRFB on local grid 

support. The simulations were carried out using seasonal load profiles from the year 2016. The 

aim of this effort was to gain insight on different modes under which the battery can operate. 

Sumitomo Electric provided the performance characteristics of the VRFB that were needed for 

detailed modeling and cross-validation for the various use cases. Figure ES-2 shows a 

comparison between our control model for peak shaving and the field measurements. A similar 

comparison was performed for capacity firming and voltage regulation, as is detailed later in the 

report.

Figure ES-2. Comparison of peak-shaving algorithms using the field data 

Analyze Value Stream 

The economics of using the VRFB to provide grid support functions were evaluated through a 

combination of OpenDSS simulations and mixed-integer linear programming optimizations 

using NREL’s Renewable Energy Integration and Optimization (REopt) framework. Figure ES-3
viii

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shows a schematic of the simulation workflow developed to assess the value streams from 

utility-scale energy storage while considering the battery performance characteristics. 

Figure ES-3. Schematic illustrating the simulation framework

The quasi-static model of the SDG&E distribution feeder in OpenDSS was used to establish the 

impact of load growth on the year a transformer or capacitor upgrade is required (both with and 

without the VRFB system). The OpenDSS model was also used to analyze the impact of capacity 

firming on load tap changer (LTC) operations and to determine the reactive power requirements 

from the VRFB system to provide voltage support services. Economic parameters and relevant 

cost key assumptions are summarized in Table ES-1.

Table ES-1. Economic Parameters and Cost Assumptions

Economic Parameters and Costs Assumption

Analysis period 25 years

Discount rate 6%

General inflation 0.1%

Electricity escalation rate 1.5%

Annual load growth 3%

Line upgrade cost $670,000

Transformer upgrade cost $1,497,000

New capacitor bank cost $56,054

The value streams analyzed along with the main optimal dispatch results are shown in Table ES2. This report describes how these values were derived and other details of the analysis.
ix

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Table ES-2. Summary of the Value Streams Analyzed Along with Key Optimal Dispatch Results

Value Stream Monetization Mechanism Year 1 Savings Life-Cycle Savings

Peak shaving Transformer upgrade deferral – $121,135

Capacity firming Operation and maintenance

savings from reduced LTC 

operations

– –

Voltage support New capacitor bank deferral – $7,463

Energy arbitrage Time-shifting energy purchases 

on the LMP market

$56,069 $837,115

Total $965,713

Field-Test Battery

Operational testing of the VRFB system lasted for a one-week period in April. The peakshaving/base-loading strategy was executed from April 2–4, 2018; the cost-optimal arbitrage 

strategy was executed from April 4–5, 2018; and the hybrid strategy was executed from April 5–

6, 2018. This testing included three different approaches to dispatching the battery:

1. Heuristic peak shaving/base-loading: This strategy determines set points that the VRFB 

attempts to maintain over multiple hours. One set point is selected for peak shaving 

(battery discharging) and is applied during high-load periods of a day, and a second set

point is selected for base-loading (battery charging) during low-load periods. This 

strategy requires a load forecast to identify the set points and associated periods of the 

day in which to implement them. A heuristic method was also used to attempt to align the 

set points with high/low LMP hours.

2. Cost-optimal arbitrage: This strategy determines multiple set points throughout the day 

with a goal of optimizing the revenue that the battery can achieve from the day-ahead 

LMP market. A total of eight distinct power set points—and associated start times—can 

be input to the power conditioning system (PCS) during a given period. The REopt 

optimization model determines the eight (or fewer) optimal set points to maximize 

revenue from the day-ahead LMP markets. No load forecast is required for this strategy.

3. Hybrid peak shaving and optimal arbitrage: This strategy uses the same PCS control 

strategy as the cost-optimal arbitrage (max of eight power set points) and optimizes 

revenue from the LMP market while ensuring that the load on the feeder does not exceed 

a prescribed power limit. This strategy uses the REopt model to determine these set

points, and it uses a load forecast to inform the peak-shaving objective.

Load prediction was performed using artificial neural network (ANN) to forecast the feeder load 

as a function of meteorological forecasts. The meteorological forecasts and the subsequent feeder 

load forecasts were extended through an 18-hour-ahead time horizon at an hourly resolution. The 

true feeder load and the operating state variables of the VRFB were continuously monitored 

during the week of testing to enable comparisons with the expected feeder load obtained from 

the load forecasts and the resultant operational plan. The net forecasts obtained from two 

separate forecasting techniques—namely, the singular ANN and multiple ANN methods—are 

shown in Figure ES-4.
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Figure ES-4. Net forecast for the singular ANN and the multiple ANN methods along with the 

measured feeder load

The total revenue during the two days of hybrid peak shaving and optimal arbitrage was 

calculated from the observed data to be $217 (with $192 of that resulting from the first 24 hours, 

without the peak-shaving constraint). The modeled revenue expected by the model was $223 

during the two days. The results show good agreement on both the dispatch of the systems and 

the achievable revenue generation.
xi

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Table of Contents

1 Modeling SDG&E Distribution System............................................................................................... 1

1.1 Synergi-to-OpenDSS Conversion ................................................................................................. 1

1.1.1 Model Conversion............................................................................................................ 1

1.1.2 OpenDSS Model Verification .......................................................................................... 4

1.1.3 Modeling the Substation with All Feeders....................................................................... 7

1.2 Battery Model and Details............................................................................................................. 8

1.2.1 Overview of Battery Characteristics ................................................................................ 8

1.3 Annual Data Analysis.................................................................................................................. 11

1.3.1 Data Processing Description .......................................................................................... 11

1.3.2 Results of Annual Analysis............................................................................................ 14

2 Modeling Battery Use Cases in Distribution System Simulator.................................................... 18

2.1 Modes of Operation..................................................................................................................... 18

2.2 Simulation Setup ......................................................................................................................... 18

2.3 Peak Shaving and Capacity Deferral........................................................................................... 19

2.4 Capacity Firming (Smoothing).................................................................................................... 24

2.5 Voltage Regulation...................................................................................................................... 27

3 Energy Storage Value Streams from Distribution Support............................................................ 30

3.1 Introduction and Background...................................................................................................... 30

3.2 Value Streams for Distribution Grid Support Monetization ....................................................... 30

3.2.1 Applications Chosen for Distribution Grid Support....................................................... 30

3.2.2 Distribution Feeder and Substation Conditions.............................................................. 32

3.3 Framework for Value Stream Modeling and Comparison .......................................................... 34

3.3.1 Calculating the Value of Distribution Upgrade Deferral ............................................... 34

3.3.2 Framework for Peak Shaving......................................................................................... 36

3.3.3 Framework for Capacity Firming................................................................................... 36

3.3.4 Framework for Voltage Support .................................................................................... 36

3.3.5 Framework for Energy Arbitrage ................................................................................... 37

3.4 REopt Simulation Framework for Identifying Value Streams.................................................... 39

3.4.1 Input Data for Value Stream Analysis ........................................................................... 40

3.4.2 REopt Overview............................................................................................................. 41

3.4.3 VRFB Loss Modeling in REopt..................................................................................... 41

3.4.4 Expected Outputs from REopt ....................................................................................... 44

3.5 Value Stream Assessment and Results........................................................................................ 44

3.5.1 Value Stream from Peak Shaving and Energy Arbitrage............................................... 44

3.5.2 Value Stream from Capacity Firming ............................................................................ 46

3.5.3 Value Stream from Voltage Support: Capacitor Avoidance Costs................................ 47

3.5.4 Modeling Shutting Off Auxiliary Pumps when the Battery Is Idle................................ 51

3.5.5 Value from Line Upgrade Deferral ................................................................................ 52

4 CAISO Market for Energy Storage .................................................................................................... 53

4.1 Introduction ................................................................................................................................. 53

4.1.1 Market Participants ........................................................................................................ 53

4.1.2 Markets in CAISO.......................................................................................................... 53

4.2 Market Participation Model/Resource Model ............................................................................. 54

4.2.1 NGRs.............................................................................................................................. 55

4.2.2 Demand Response Product............................................................................................. 57

5 Dynamic Efficiency and Dynamic Loss Modeling........................................................................... 59

5.1 Data Sampling............................................................................................................................. 59

5.2 Dynamic Efficiency Modeling .................................................................................................... 59

5.3 Dynamic Loss Modeling Techniques.......................................................................................... 62
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5.3.1 Metrics for Evaluating Model Accuracy ........................................................................ 62

5.3.2 Triangular Interpolation ................................................................................................. 62

5.3.3 Composite Quadratic Fitting .......................................................................................... 63

5.3.4 Bivariate Quadratic Fitting............................................................................................. 64

5.3.5 Nonlinear ANN Model................................................................................................... 65

5.3.6 Dynamic Loss Modeling ................................................................................................ 67

5.4 Accuracy Impacts Operation Strategies...................................................................................... 67

5.4.1 Accuracy Impacts Operation Strategies......................................................................... 68

6 Operational Planning and Field-Testing .......................................................................................... 75

6.1 Scope of Testing.......................................................................................................................... 75

6.2 ANN Model for Feeder Load Forecasting .................................................................................. 75

6.2.1 Historical Feeder Load Data .......................................................................................... 75

6.2.2 High-Resolution Rapid Refresh Meteorological Data ................................................... 76

6.2.3 Singular ANN Model Training ...................................................................................... 76

6.2.4 Multiple ANN Model Training ...................................................................................... 77

6.2.5 Metrics for Performance Evaluation .............................................................................. 78

6.3 VRFB Dispatch Strategies .......................................................................................................... 78

6.3.1 Operational Constraints.................................................................................................. 78

6.4 Results 79

6.4.1 Load Forecasting Results............................................................................................... 79

6.4.2 Optimal Dispatch Results............................................................................................... 81

7 Conclusions and Remarks ................................................................................................................ 84

7.1 Peak Shaving............................................................................................................................... 85

7.2 Capacity Firming......................................................................................................................... 85

7.3 Voltage Support........................................................................................................................... 86

7.4 Energy Arbitrage ......................................................................................................................... 86

7.5 Multiuse....................................................................................................................................... 86

7.6 Current System Under Consideration.......................................................................................... 86

7.7 Value Streams Monetization Results .......................................................................................... 87

7.8 Field-Testing the Battery............................................................................................................. 87

References................................................................................................................................................. 89
xiii

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List of Figures

Figure ES-1. Topology of the distribution feeder highlighting the location of the energy storage system . vi

Figure ES-2. Comparison of peak-shaving algorithms using the field data................................................ vii

Figure ES-3. Schematic illustrating the simulation framework ................................................................. viii

Figure ES-4. Net forecast for the singular ANN and the multiple ANN methods along with the measured 

feeder load................................................................................................................................ x

Figure 1. Geographical view of TEST FEEDER distribution feeder in Synergi format and OpenDSS 

format ....................................................................................................................................... 3

Figure 2. Diagram of Synergi-to-OpenDSS model conversion depicting the syntax identification process 4

Figure 3. Percentage error of voltage with respect to distance from the feeder head for the TEST FEEDER 

feeder........................................................................................................................................ 6

Figure 4. Percentage error of sequence impedances with respect to distance from the feeder head for the 

TEST FEEDER feeder............................................................................................................. 7

Figure 5. Overview of the substation model with TEST FEEDER feeder ................................................... 8

Figure 6. Topology of the distribution feeder highlighting the location of the energy storage system ...... 10

Figure 7. Inverter operation region (shaded region) shown by the circle diagram ..................................... 11

Figure 8. Locations of irradiance weather stations..................................................................................... 12

Figure 9. La Mesa weather correlation with the Chula Vista station.......................................................... 13

Figure 10. Annual load data MW and MVAR............................................................................................ 13

Figure 11. Example of creating native load ................................................................................................ 14

Figure 12. Plot comparing DoY 111 with DoY 5. The top tile represents the substation kW and kVAR, 

and the bottom tile represents the sum of all PV system generation...................................... 15

Figure 13. Plot comparing DoY 111 with DoY 142. The top tile represents the substation kW and kVAR, 

and the bottom tile represents the sum of all PV system generation...................................... 16

Figure 14. Voltage heat map of the distribution feeder at the maximum load point on August 15, 2016, at 

18:19:00 ................................................................................................................................. 17

Figure 15. Simulation setup overview ........................................................................................................ 19

Figure 16. Peak-shaving control setup........................................................................................................ 20

Figure 17. Substation active/reactive power with battery performing peak shaving on DoY 228 (August 

15, 2016) ................................................................................................................................ 22

Figure 18. Battery SOC as the device goes through peak shaving for DoY 228........................................ 22

Figure 19. Comparison of peak-shaving algorithm with the field data....................................................... 23

Figure 20. Distribution of the error calculated between the field-measurement and the simulation results23

Figure 21. Validation of capacity-firming algorithm using actual field data.............................................. 25

Figure 22. Active power variability with and without capacity firming..................................................... 26

Figure 23. Substation power for varying ramp rate limit with time fixed at 10 min .................................. 26

Figure 24. Volt/VAR droop (without deadband) settings for simulation study cases ................................ 27

Figure 25. Volt/VAR droop (with deadband) settings for simulation study cases ..................................... 28

Figure 26. Storage reactive power output for voltage support mode.......................................................... 28

Figure 27. Voltage profile for voltage-support mode ................................................................................. 29

Figure 28. OpenDSS diagram of feeder TEST FEEDER showing the capacity-constrained line.............. 33

Figure 29. Calculating the value of deferring a new asset installation or upgrade ..................................... 35

Figure 30. LMP values throughout 2016 .................................................................................................... 38

Figure 31. Heat map showing how 2016 LMP prices vary throughout the day and during the year.......... 39

Figure 32. Schematic illustrating the simulation framework ...................................................................... 39

Figure 33. Linearized PCS and storage losses as a function of charging/discharging power..................... 42

Figure 34. Auxiliary power consumption during charging and discharging as a function of SOC............ 43

Figure 35. Feeder load with and without the optimal VRFB dispatch........................................................ 45

Figure 36. Detailed dispatch results for five days surrounding the peak load day of 2016 ........................ 45
xiv

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Figure 37. Monthly averaged VRFB charging and discharging profiles along with the corresponding LMP 

signal...................................................................................................................................... 46

Figure 38. LTC operations with and without the VRFB system................................................................. 47

Figure 39. Voltage heat map for the time step with the lowest network voltage when no capacitor banks 

are operating (based on 2016 system load data) .................................................................... 48

Figure 40. Voltage heat maps for the time step with the lowest network voltage when only existing 

capacitor banks are operating................................................................................................. 49

Figure 41. Voltage heat maps for the time step with the lowest network voltage when the VRFB system is 

performing volt/VAR regulation............................................................................................ 50

Figure 42. Comparison of optimal dispatch and auxiliary power consumption for two scenarios: (left) 

18.4-kW baseline pump consumption when battery is idle and (right) pumps turn off and 

draw no power when battery is idle ....................................................................................... 51

Figure 43. Capacity-constrained line limits for battery charging ............................................................... 52

Figure 44. Electricity power dispatch processes......................................................................................... 53

Figure 45. VRFB state variables for charging and discharging at 1,000 kW, 750 kW, 500 kW, 372 kW, 

and 300 kW, respectively....................................................................................................... 59

Figure 46. A heat map of the measured VRFB charging and discharging efficiency as a function of the 

active power and the SOC...................................................................................................... 60

Figure 47. Measured discharge efficiency against the SOC when operated for various fixed values of 

active power........................................................................................................................... 61

Figure 48. Measured charging efficiency against the SOC when operated for various fixed values of 

active power........................................................................................................................... 61

Figure 49. Three-dimensional plot of the field data and its projection along the x-axis............................. 63

Figure 50. Composite model for loss as a function of the active power and SOC ..................................... 64

Figure 51. Bivariate model of losses against active power and SOC ......................................................... 65

Figure 52. Basic structure of the nonlinear neural network. One input layer with a virtual bias node, one 

hidden layer, and one output layer are used. The w(i,h) and x(h) terms denote the weights on 

the links between nodes, which are found via the back-propagation algorithm. ................... 66

Figure 53. ANN model of losses against active power and SOC ............................................................... 66

Figure 54. RMSE of the ANN model when including various numbers of hidden nodes. The standard 

deviation caused random sampling is shown. ........................................................................ 67

Figure 55. Substation power in KW............................................................................................................ 68

Figure 56. Active power of the VRFB (both transformers) when operated for peak shaving .................... 69

Figure 57. SOC of the VRFB when operated for peak shaving.................................................................. 69

Figure 58. Modeled losses (both transformers) of VRFB when operated for peak shaving....................... 70

Figure 59. Dynamic efficiency of the VRFB when operated for peak shaving, assuming each loss model

................................................................................................................................................ 70

Figure 60. LMP signal at the feeder on the most typical day ..................................................................... 71

Figure 61. Optimal active power (both transformers) for the VRFB on the most typical day, solved 

assuming each VRFB loss model........................................................................................... 71

Figure 62. Simulated VRFB SOC on the most typical day, calculated via OpenDSS based on the optimal 

active power and assuming each VRFB loss model .............................................................. 72

Figure 63. Losses for the VRFB (both transformers) on the most typical LMP day for each loss model.. 72

Figure 64. Dynamic efficiency for the VRFB on the most typical LMP day, calculated assuming each loss 

model...................................................................................................................................... 73

Figure 65. Expected cumulative value generated by the VRFB on the most typical day, assuming each 

VRFB loss model................................................................................................................... 73

Figure 66. Trajectory of the VRFB operating states through the efficiency space when the battery is 

operated for energy arbitrage (white) and peak shaving (magenta), assuming the ANN loss 

model (A single transformer is shown.)................................................................................. 74

Figure 67. General structure of the ANN model......................................................................................... 77
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Figure 68. (Left) Adjusted R-squared value of the ANN model as a function of the number of hidden 

nodes and (right) training time for the ANN as a function of the hidden nodes.................... 77

Figure 69. Results of 50 unique ANN forecast results and the mean through the training data set............ 78

Figure 70. Rolling forecast for the singular ANN method. The net forecast is shown along with the 

measured feeder load. ............................................................................................................ 79

Figure 71. Rolling forecast for the multiple ANN method. The net forecast is shown along with the 

measured feeder load. ............................................................................................................ 80

Figure 72. Net forecast for the singular ANN and the multiple ANN methods along with the measured 

feeder load.............................................................................................................................. 80

Figure 73. Residual errors relative to the measured feeder load of the net forecasts obtained from the 

singular ANN and multiple ANN methods............................................................................ 81

Figure 74. VRFB dispatch during optimal dispatch.................................................................................... 82

Figure 75. Testing results during the hybrid cost-optimal/peak-shaving dispatch ..................................... 83
xvi

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List of Tables

Table ES-1. Economic Parameters and Cost Assumptions........................................................................viii

Table ES-2. Summary of the Value Streams Analyzed Along with Key Optimal Dispatch Results .......... ix

Table 1. Characteristics of Selected Feeder.................................................................................................. 1

Table 2. Battery Specifications as Shared by Battery Manufacturer ............................................................ 9

Table 3. Inverter Specifications and Control Mode .................................................................................... 10

Table 4. Feeder Measurements................................................................................................................... 11

Table 5. Selected Days for Analysis from 2016 ......................................................................................... 14

Table 6. Modes of Operation for Battery Storage....................................................................................... 18

Table 7. Modes of Operation for Peak Shaving and Base Loading ............................................................ 19

Table 8. Pseudocode for Peak Shaving at Every Time Step ....................................................................... 21

The control algorithm mimics the behavior of the battery controller very well. Figure 20 presents the 

histogram of the residuals between the actual field-measurement and the simulation results. 

The histogram shows that the residuals have a relatively low standard deviation. Other 

metrics used to quantify the performance of the implemented algorithm are listed in .......... 23

Table 9. Quality Metrics Calculated for the Field Measurements and Simulation Results ........................ 24

Table 10. Modes of Operation for Capacity Firming.................................................................................. 24

Table 11. Pseudocode for Capacity Firming for Each Time Step............................................................... 25

Table 12. Distribution Substation Transformer Upgrade Costs.................................................................. 36

Table 13. Costs for 1,200-kVAR Pad-Mounted Capacitors in Past SDG&E Projects ............................... 37

Table 14. Statistics for the 2016 LMP Signal Used in This Analysis......................................................... 38

Table 15. Economic Parameters and Cost Assumptions............................................................................. 40

Table 16. Summary of the Value Streams Analyzed Along with Key Optimal Dispatch Results ............. 44

Table 17. Participation Model for Different Storage Scenarios.................................................................. 55

Table 18. Comparison of NGR and NGR-REM......................................................................................... 56

Table 19. Participation Requirement for NGRs......................................................................................... 57

Table 20. Participation Options for PDR and RDRR ................................................................................. 57

Table 21. Participation Requirements for PDR ......................................................................................... 58

Table 22. Participation Requirements for RDRR ....................................................................................... 58

Table 23. RMSE, Maximum Absolute Error, and Coefficient of Determination for Each VRFB Loss 

Model ..................................................................................................................................... 67

Table 24. Summary of the Accuracy of the Singular ANN and Multiple ANN Feeder Load Forecasting 

Methods.................................................................................................................................. 81

Table 25. Economic Parameters and Cost Assumptions............................................................................. 85

Table 26. Summary of the Value Streams Analyzed Along with Key Optimal Dispatch Results ............. 87
1

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1 Modeling SDG&E Distribution System

This chapter describes the conversion and validation of the feeder model provided by San Diego 

Gas & Electric (SDG&E) in Synergi to OpenDSS format and the performance of the yearly 

quasi-static time-series analysis on selected use cases. In this context, this chapter was divided 

into three parts:

1. Part one focuses on the conversion of the distribution system model provided in Synergi 

format to OpenDSS file format. The files were parsed using an interface developed by the 

National Renewable Energy Laboratory (NREL), and an equivalent OpenDSS circuit was 

created.

2. Part two is a continuation of the work done in Part 1. The circuit created in Part 2 was 

cross-validated against the original distribution system model provided by SDG&E. The 

validation process involved running snapshot simulations in both OpenDSS and Synergi. 

3. Part three focuses on the preparation of the load and photovoltaic (PV) profiles 

compatible with OpenDSS. Data provided by SDG&E include but are not limited to 

annual load profiles, substation load data, annual irradiance data, PV profiles, a storage 

system data sheet, and data pertaining to other active elements (capacitors, voltage 

regulators). The final step was cross-validating the simulation results against fieldmeasured results provided by SDG&E. 

This section describes the process involved in the model conversion from Synergi format to 

OpenDSS format. The distribution feeder was provided by SDG&E. A brief description of the 

characteristics of the selected feeders is provided prior to the details about the model conversion.

1.1 Synergi-to-OpenDSS Conversion

SDG&E, partner utility, identified a distribution feeder for the purpose of studying the impacts of

the energy storage system. The identified feeder is referred as TEST FEEDER. The 

characteristics of the selected feeders are listed in Table 1. The selected feeder has a peak load of 

6.2 MW and 2.5 MW of PV penetration. 

Table 1. Characteristics of Selected Feeder

Components TEST 

FEEDER

Feeder length 8 miles

Peak load 6.2 MW

Capacitor banks 3

PV generation 2.5 MW

Node count 2,500

1.1.1 Model Conversion

The distribution feeder selected by SDG&E, circuit TEST FEEDER, was converted from 

Synergi format to OpenDSS format. The geographical view of the Synergi model and OpenDSS 

model is shown in Figure 1.
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The Synergi-to-OpenDSS conversion uses an automated Python script that takes network 

configuration (.xml) and line configuration (.txt) as input. To use the tool, the feeder model 

provided by SDG&E in Microsoft access database format was opened in Synergi and then 

exported in Extensible Markup Language (XML) format. Additionally, the line impedance 

information was extracted from Synergi using the line construction report and used as an input 

by the tool. The conversion tool takes the two files described (the feeder in XML format and the 

line construction report in text format) as inputs and creates a folder with the OpenDSS files. The 

user can then open the master circuit file and run it in OpenDSS.

The conversion software code is programmed in Python and is structured such that properties for 

each instance of a Synergi object are collected for all objects in the feeder file in XML format 

and then operated on via syntax or mathematical conversions to create a corresponding 

OpenDSS element, associated DSS file, and master circuit file. 
3 

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Figure 1. Geographical view of TEST FEEDER distribution feeder in Synergi format and OpenDSS

format 

Specifically, the conversion process reads the XML file and identifies, collects, and categorizes 

objects and their parameters for all object blocks within the XML file. As shown in Figure 2, the 

object blocks are identified by the symbol “<” with six space characters of indentation from the 

margin. After the object type is identified, a function defined for that object type is called, and 

the values for each property are collected. The called function then assigns the collected property 

values to the container for that object type. In the functions, the values are not altered, and the 
4 

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names of each object are kept the same as assigned in the Synergi XML file, which assists in the 

debugging process. The next step in the conversion process is to create objects in the OpenDSS 

script using the collected Synergi objects and their properties. A view of the syntax identification 

process is presented in Figure 2. 

Figure 2. Diagram of Synergi-to-OpenDSS model conversion depicting the syntax identification 

process 

The process of converting objects in Synergi to the equivalent objects in the OpenDSS script is 

not always a direct one-to-one conversion. Object types that exist in Synergi do not always exist 

in OpenDSS and vice versa. This is also true for the properties of objects. Switches, reclosers, 

and fuses are not separate objects in OpenDSS. The conversion tool creates short, lowimpedance lines with switching capabilities for these components. 

Finally, the converted OpenDSS script is written to a master file, and separate DSS files for each 

object type are created. The master file initiates a new circuit that creates a voltage source and 

source bus. The voltage and source impedances are specified based on data from the Synergi 

model. The master file also redirects to DSS component files containing scripts for the different 

object types separated into different categories. 

1.1.2 OpenDSS Model Verification

The verification of the OpenDSS model was performed based on the following metrics: 

• The feeder topology for the converted model is similar to the original Synergi model

based on visual inspection.
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• The difference between the node voltages for the converted model and the original

Synergi model are less than 1%.

• The difference between the node sequence impedances for the converted model and the

original Synergi model needs to be as low as possible.

Figure 2 shows the feeder topology in Synergi and the converted model in OpenDSS; as shown, 

the line distances and coordinates are appropriately converted. The subsequent step for 

verification will compare the voltages obtained from OpenDSS with the Synergi voltages. Figure 

3. shows the voltage profiles and voltage errors (obtained at full load) as a function of distance

and as a histogram. As shown, the voltage errors are less than 1%, and, as is typical, the voltage

errors increase toward the end of the feeder.

Figure 4 shows the sequence impedance profiles and errors (obtained at full load) as a function 

of distance and as a histogram. As shown, the sequence impedance errors are less than 0.06%, 

and, as is typical, the voltage errors increase toward the end of the feeder. 
6 

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Figure 3. Percentage error of voltage with respect to distance from the feeder head for the TEST 

FEEDER feeder
7 

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Figure 4. Percentage error of sequence impedances with respect to distance from the feeder head 

for the TEST FEEDER feeder

1.1.3 Modeling the Substation with All Feeders

The substation containing the feeder TEST FEEDER was modeled to understand the impacts of 

energy storage on the substation transformer. The substation contains a total of seven distribution 
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feeders adding up to 50 MVA catered from two 28-MVA substation transformers. The line 

diagram is shown in Figure 5.

Figure 5. Overview of the substation model with TEST FEEDER feeder

Among the seven distribution feeders, only one feeder (TEST FEEDER) was modeled in detail. 

TEST FEEDER is the distribution feeder in which the utility-scale vanadium redox flow battery

(VRFB) is commissioned. 

1.2 Battery Model and Details

1.2.1 Overview of Battery Characteristics

A utility-scale battery energy storage system was commissioned in the distribution feeder on 

May 2017 at a location shown in Figure 6. The battery use cases explored are as follows: voltage 

regulation (droop), peak shaving, and capacity firming. NREL evaluated the impacts of the 

battery use cases with stacking the listed feeder support functions. Along with the battery use 

case evaluation, this effort identifies possible ways to monetize the benefits from the distribution 

feeder support. 

Details of the battery use cases are as follows: 

1. Voltage regulation (droop): The reactive power dispatch from the energy storage system 

is calculated based on the voltage (at the battery point of common coupling) using a 

voltage droop curve.

2. Capacity firming: In this mode, the energy storage system will smooth high-frequency 

power flow fluctuations at the substation to a constant or low-frequency timescale 

average value. 

3. Peak shaving and load shifting: Load shifting is defined as displacing the power 

consumption of the feeder by a predefined amount for a specific time. Peak shaving is 
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defined as using the energy storage to regulate the peak power of the feeder within a 

predefined limit. Peak shaving is a special case of load shifting.

A 2-MW/4-hour battery energy storage system with redox flow battery chemistry was 

commissioned; the battery specifications are listed in Table 2. The battery energy storage system 

uses an inverter and a 480-V/12-kV transformer to connect with the grid. The specifications of 

the inverter are as shown in Table 3. 

The active power capacity of the battery system is 2 MW, and the inverter has a capacity of 3

MVA. The inverter is oversized to accommodate increased reactive power support. Figure 7

shows the inverter’s region of operation with a circle diagram. 

Table 2. Battery Specifications as Shared by Battery Manufacturer

Power rating 3 MVA

Nominal real power 2 MW

Energy capacity 8 MWh

Maximum real power 3 MW (We might never use this.)

Maximum reactive power 3 MVAR

Maximum state of charge 100%

Minimum state of charge 0%

Battery efficiency for charging Dynamic model (Section 1.2.2)

Battery efficiency for discharging Dynamic model (Section 1.2.2)

Auxiliary power services in real power Dynamic model (Section 1.2.2)
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Figure 6. Topology of the distribution feeder highlighting the location of the energy storage 

system

Table 3. Inverter Specifications and Control Mode

Three-phase AC voltage 480 V

Power rating 3 MVA

Maximum real power 3 MW

Maximum reactive power 3 MVAR

Frequency 60 Hz

Inverter efficiency Dynamic model (Section 1.2.2)

Real power ramp rate Infinity kW/min

Reactive power ramp rate Infinity kVAR/min
11

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Figure 7. Inverter operation region (shaded region) shown by the circle diagram

1.3 Annual Data Analysis

This section describes the methodology used to preprocess load and PV data for the time-series 

analysis. The distribution utility partner made a significant amount of supervisory control and 

data acquisition data available to NREL for this project. Table 4 summarizes the data associated 

with the study feeder that was used for this project. 

1.3.1 Data Processing Description

Table 4. Feeder Measurements

Equipment 

Name

Type Measurement (All 

Three-Phase)

Interval Range Output 

Interval Range

TEST FEEDER: 

Feeder head

Feeder 

breaker

P, Q, I 15-minute: 24

hours

1 minute: 24 

hours

D5256 La Mesa 

PV irradiation

Mesonet 

weather 

station

Irradiance 5-minute: 24 hours 1 minute: 24

hours

To capture the large ramp rates associated with the PV plant variability on the feeder and to 

generate accurate feeder statistics, a complete 1-minute data set (i.e., 525,600 measurements per 

year) for 2016 was used. All missing or out-of-range supervisory control and data acquisition 

values were replaced with a 30-minute running average value before and after the missing data 

sample or group of samples.

Figure 8 presents the weather stations in the vicinity of the feeder under study. The weather 

station closest to the distribution under study is MIGC1, and the resolution of the PV irradiance 

was hourly; however, the D5256 La Mesa weather station, located approximately 6 miles north 

of MIGC1, had 5-minute irradiance data for the year 2016. The correlation between the E7837 

weather station and the D5256 weather station is presented in Figure 9. Because the slope of the 
12

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correlation is 1.03, which is close to 1, we can confirm that the La Mesa weather station is a

good replacement. 

Figure 10 shows the annual load data as obtained from the utility. Four points of the year 2016 

data, with a total of seven days, were missing and were filled from averages of past days. To 

create a “native” feeder-head load (i.e., the original load not masked by PV power production), 

the positive 1-minute feeder head real power was added to the negation of the real measurement 

from overall PV generation for each time stamp. There was a close synchronism in the time 

stamping of the weather station irradiance and feeder-head measurements. A sample day 

demonstrating the native load extraction is shown in Figure 11. 

Figure 8. Locations of irradiance weather stations

MIG

E783

D525
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Figure 9. La Mesa weather correlation with the Chula Vista station

Figure 10. Annual load data MW and MVAR

19 June 2016 

18:45

5.672MW

22 July 2016 

18:23

6.032MW 15 Aug 2016 

20:18 6.25MW

26 Sep 2016 19:48 

6.416MW
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Figure 11. Example of creating native load

1.3.2 Results of Annual Analysis

The annual data were processed as described in the previous section. Starting from gross load 

and PV irradiance, net load was extracted. Using the net load data and PV irradiance annual data,

few analytically important days were calculated for analysis. Table 5 presents the list of days 

from 2016 that could be of interest for annual analysis. 

Table 5. Selected Days for Analysis from 2016

Day Type Date DoY

Maximum load day September 26, 2016 270

Minimum load day March 6, 2016 65

Clear PV day April 20, 2016 111

Intermittent PV day May 21, 2016 142

Cloudy PV day January 5, 2016 5

Minimum voltage day August 15, 2016 228
15 

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Figure 12. Plot comparing DoY 111 with DoY 5. The top tile represents the substation kW and 

kVAR, and the bottom tile represents the sum of all PV system generation. 

To aid the analysis, we developed a suite of visualization codes to capture load voltages, PV 

voltages, PV active/reactive power, energy storage system voltages, energy storage system 

active/reactive power, and voltage topology heat maps. 
16 

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Figure 13. Plot comparing DoY 111 with DoY 142. The top tile represents the substation kW and 

kVAR, and the bottom tile represents the sum of all PV system generation. 

The days listed in Table 5 were simulated for the selected use cases described in Section 1.2. The 

details of the results related to the use cases (reactive power, capacity deferral, and capacity 

firming) are described in the following chapter. This section captures and presents some results 

from the selected days of interest (Table 5). The dotted line in Figure 12 and Figure 13 captures 

the baseline, which is the clear day; the solid line in Figure 12 represents the cloudy day; and the 

solid line in Figure 13 represents the intermittent day.

Figure 12 presents the substation kW/kVAR and the PV accumulated power on a clear day and a 

cloudy day. The difference between the clear and the cloudy day is shown in yellow. The top tile 

represents the substation kW/kVAR, and the bottom tile represents the sum of all PV systems in 

the feeder TEST FEEDER. The figure shows that on a cloudy day, the duck curve, or the dip in

the substation kW, is minimal compared to the clear day, when the PV generation is at its 

maximum and there are no clouds. 

Figure 13 compares the clear day with an extremely intermittent day. Again, the top tile captures 

the substation active/reactive power, and the bottom tile represents the sum of all PV active 

power for three consecutive days. The comparison is between day of year (DoY) 111 (April 20, 

2016) and DoY 142 (May 21, 2016). The dotted line represents the clear day, the solid line 

represents the intermittent day, and the difference between them is shown with a solid color. 

The distribution feeder attains the minimum voltage on the maximum load day, i.e., DoY 228 

(August 15, 2016) at 6:19 p.m. The voltage heat map of the distribution feeder when the feeder 

goes through the lowest voltage is presented in Figure 14. As shown, the primary overhead 
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conductor near the energy storage system location reaches 0.95 p.u. voltage and has very few 

laterals as well.

Figure 14. Voltage heat map of the distribution feeder at the maximum load point on August 15,

2016, at 18:19:00
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2 Modeling Battery Use Cases in Distribution System 

Simulator

This section describes the battery model development used to simulate the battery use cases (i.e., 

voltage regulation, peak shaving, capacity firming) and the battery control models developed to 

understand the impacts of the VRFB on local grid support. The simulations were carried out 

using seasonal load profiles from the year 2016. The aim of this effort was to gain insight on 

different modes under which the battery can operate. The battery manufacturer provided the 

performance characteristics of the battery system that are needed for detailed modeling and 

cross-validation for all the use cases.

2.1 Modes of Operation

The intent of this research was to develop battery control models in a distribution system 

analysis tool that match inverter operation in the field. The data sheet for the inverter interfacing 

the battery with the grid lists seven modes of operation. In this study, however, only three modes 

are investigated. Table 6 lists the modes of operation for the battery storage under investigation.

Table 6. Modes of Operation for Battery Storage

Higher Level Controls

1 Voltage regulation

2 Peak shaving and base loading

3 Capacity firming (smoothing)

The scope of this report is threefold. The first objective is to provide an overview for each of 

these modes. This also includes a brief description of the input, output, and tuning parameters. 

The second objective is to provide the reader with a pseudocode for the algorithms implemented 

in Python for each mode of operation. The third and final objective is to provide a set of 

simulation results that can be used to validate the design and implementation approach used in 

this work. 

2.2 Simulation Setup

The distribution feeder and the accompanying active elements (e.g., capacitors, transformers, 

storage) and their controllers (i.e., voltage regulator) have been implemented in OpenDSS. The 

high-level control modes for the battery storage listed in the previous section have been 

implemented using Python, a high-level open-source programming language. A direct DLL 

interface provided by OpenDSS has been used to facilitate communication between the 

OpenDSS engine and Python. The load and PV profiles saved in Comma Separated Value format 

(.CSV) are accessed directly by the OpenDSS engine. Figure 15 provides a graphical overview 

of the simulation setup.
19

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Figure 15. Simulation setup overview

2.3 Peak Shaving and Capacity Deferral

In this mode, the operator specifies the trigger values for peak shaving and base loading. The 

storage will discharge power into the grid if the load’s consumption (as measured) is greater than 

the peak shaving limit. Inversely, the energy storage system will charge if the load’s 

consumption at the measured point is lower than the base-loading limit.

Control Mode Overview

The controller implemented for peak shaving and base loading has three modes of operation, as 

shown in Figure 16. Table 7 lists the modes of operation and relative parameters.

Table 7. Modes of Operation for Peak Shaving and Base Loading

Modes of Operation Relevant Parameters

1 Active powertriggered peak 

shaving and base 

loading

SSSSSS: Battery state of charge (%)

PPrrrrrr: Active power measurement from reference point for peak shaving

(kW)

PPbbbbbbbb: Battery active power output (kW)

PP UUUU, PP LL : Reference set points at which peak shaving triggers (kW)

ΔΔ bb : Rate at which storage goes to idling (% of rate power)

2 Time-triggered peak 

shaving and base 

loading

PPbbbbbbbb: Battery active power output (kW)

TThh / TTmmmmmm: Time at which peak shaving starts

TTcccc

hh / TTccccmmmmmm: Current hour and minute 

PPdd dd: Battery discharge set point (kW)

3 Active power- and 

time-triggered

All of the above

Active Power-Triggered Mode

The active power-triggered mode requires two inputs: the active power threshold after which 

peak shaving is active and the active power measurement from the reference point for peak 

shaving. If the measured value exceeds the reference value and the battery state of charge (SOC)

is less than 98%, the battery output is updated to cater to the difference between the measured 

and the reference value.

Time-Triggered Mode

The time-triggered mode requires two inputs: current time and the time at which peak shaving is 

to be activated. If operating under this mode, the controller compares the current time with 
20

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trigger time. If the current time exceeds the trigger time, the battery starts to discharge with a

constant output of 600 kW. Peak shaving continues until the battery resources have been 

completely depleted. Time-triggered operation does not require feedback. 

Active Power-Triggered and Time-Triggered Mode

Under this operational mode, peak shaving mode is set to active if both the active power-trigger 

and time-trigger conditions have been met. If both conditions have been met, the battery output 

is updated to cater to the difference between the measured and the reference value. Storage 

controls are iterative and converge to the steady-state solution at every time step. The error 

tolerance for the simulation study has been set at 0.1 kW.

Figure 16. Peak-shaving control setup

Pseudocode
21

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Table 8. Pseudocode for Peak Shaving at Every Time Step

Simulation Results

This section presents results related to peak shaving. Peak shaving was run on the peak load day 

for 2016, which is August 15. The algorithm for peak shaving, as described in the previous 

section, is implemented along with the distribution system simulator.

Figure 17 and Figure 18 present the active/reactive power at the substation and the battery SOC

with and without peak-shaving grid support. Peak-shaving functionality charges the battery 

during the morning and discharges during peak hours. The charging and discharging can be 

enabled using either active power measurement at the substation or time of day. 

Input: PPrrrrrr[tt], SSSSSS [tt], TThrr, TTmmmmmm, PP UUUU, PP LL , SSSSSSUUUU , SSSSSSLL , MMMMMMMM, ΔΔ bbbbbbbb, PPddddhgg

Output: bbbb bbbbbbbb [tt + 1]

1 if MMMMMMMM == 1 (Active power triggered) then

2 if (PPrrrrrr [tt] > PP UUUU) and SSSSSS [tt] < SSSSSSUUUU then

3 PPbbbbbbbb[tt + 1] = PPbbbbbbbb[tt] + (PPrrrrrr[tt] − PP UUUU)

4 else if (PPrrrrrr[tt] < PP LL ) and SSSSSS [tt] > SSSSSSLL then

5 PPbbbbbbbb[tt + 1] = PPbbbbbbbb[tt] − (PPrrrrrr[tt] − PP LL )

6 Else

7 if PPbbbbbbbb[tt + 1] < II IIIIIIIIII then

8 PPbbbbbbbb[tt + 1] = PPbbbbbbbb[t] + ΔΔ bbbbbbbb. PPrr rr

9 else

10 PPbbbbbbbb[tt + 1] = PPbbbbbbbb[t] − ΔΔ bbbbbbbb. PPrr rr

11 else if MMMMMMMM == 2 (Time triggered) then

12 if (tt > TThrr + TTmmmmmm ∗ 60 ) and SSSSSS [tt] < SSSSSS SS then

13 PPbbbbbbbb[tt + 1] = PPdd ddddh

14 else 

15 PPbbbbbbbb[tt + 1] = PPbbbbbbbb[tt]

16 else if MMMMMMMM == 3 ( Active power and Time triggered) then

17 if (PPrrrrrr [tt] > PP ddh ) and (tt > TThrr + TTmmmmmm ∗ 60 ) and (SSSSSS [tt] < SSSSSS SS ) then

18 PPbbbbbbbb[tt + 1] = PPbbbbbbbb[tt] + (PPrrrrrr[tt] − PP ddh )

19 Else

20 PPbbbbbbbb[tt + 1] = PPbbbbbbbb[tt]
22

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Figure 17. Substation active/reactive power with battery performing peak shaving on DoY 228 

(August 15, 2016)

Figure 18. Battery SOC as the device goes through peak shaving for DoY 228

Peak-Shaving Field Validation

This section compares the simulation results with the field data. Sumitomo Electric shared the 

field measurements for peak shaving (i.e., substation power and battery energy storage operation 

details). Peak shaving was enabled on September 13, 2016, starting from 10 a.m., with 3,300 kW 

and 3,400 kW as the lower bound and upper bound, respectively. For identical net load and 

battery inverter settings, the TEST FEEDER feeder model was run, and the results were 

captured. Figure 19 presents the power at the substation from the field as well as the simulation 

while the energy storage system was performing peak shaving with 3,300 kW and 3,400 kW as

the lower and upper limits, respectively.
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Figure 19. Comparison of peak-shaving algorithm with the field data 

Figure 20. Distribution of the error calculated between the field-measurement and the simulation 

results

The control algorithm mimics the behavior of the battery controller very well. Figure 20 presents 

the histogram of the residuals between the actual field-measurement and the simulation results. 

The histogram shows that the residuals have a relatively low standard deviation. Other metrics 

used to quantify the performance of the implemented algorithm are listed in Table 9.
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Table 9. Quality Metrics Calculated for the Field Measurements and Simulation Results

Metric Value Unit

Max error 341.19 kW

Error mean -3.368 kW

Error std. 21.197 kW

RMSE 21.463 kW

RR2 value 99.83 %

2.4 Capacity Firming (Smoothing)

The basic principal behind capacity firming is improving power quality by limiting a large rate 

of change in active power ( dd⁄ ) at the measurement point. When the output power of the 

renewable plant changes at a rate greater than the allowed dd⁄ , storage will output power at an 

opposite dd⁄ to cancel out the excessive rate of change. Once the output at the point of 

measurement stabilizes, the output power of the energy storage system will ramp down to 0 per 

the operator-defined dd⁄ . The effect is that the net power at the point of common coupling 

will not have abrupt changes, only smooth power transitions.

Control Mode Overview`

Capacity firming has two sub modes of operation, which are listed in Table 10.

Table 10. Modes of Operation for Capacity Firming

Modes of Operation Relevant Parameters

1 Without considering 

stabilization window

PPrrrrrr – Active power measurement from reference point for peak 

shaving (kW)

PPbbbbbbbb – Battery active power output (kW)

ΔΔ ll – Ramp limit for measured point (kW/min)

KK − Controller gain

ΔΔ ss ss − Rate at which storage goes to idling (% of rated power)

2 With considering 

stabilization window

All of the above

TTww – Time widow during which ramp-rate stability is checked

2.4.1.1.1 Without Stability Time Horizon

The first mode does not consider the stability window, and storages goes directly to idle mode 

(the output goes to 0 linearly using the dd⁄ limits) if dd⁄ is within prescribed limits.

2.4.1.1.2 With Stability Time Horizon

The second mode of operation checks a predefined time horizon for any violations and goes to 

idle mode only if there are no violations within this time horizon (the internal clock waits for the

event flag to clear).
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Table 11. Pseudocode for Capacity Firming for Each Time Step

Capacity-Firming Field Validation

This section presents simulation results pertaining to validation of the capacity firming. Figure 

21 compares the simulation results with actual field data. The battery was operated in capacityfirming mode for an entire day. Because of low solar intermittence on the particular day,

however, battery use is low. 

Figure 21. Validation of capacity-firming algorithm using actual field data

Input: PPrrrrrr [tt], K , ΔΔ ll , Mode, TTww , ΔΔ ss

Output: batterykW [tt + 1]

1 ΔΔ rrrrrr[tt] = PPrrrrrr [tt] – PPrrrrrr [tt − 1]

2 if ΔΔ rrrrrr[tt] > ΔΔ ll or ΔΔ rrrrrr[tt] < – ΔΔ ll then

3 ∆PPbbbbbbbb [tt] = K. ΔΔ rrrrrr[tt].[1 − ΔΔ ll / |ΔΔ rrrrrr[tt]| ]

4 EventFlag = tt

5 else 

6 if Mode == 1 and Battey_Idle == False then

7 ∆PPbbbbbbbb[tt] = PPrrrrrr[tt]/|PPrrrrrr[tt]| . – ΔΔ ss . PPrr rr

8 else if Mode == 2 and Battey_Idle == False and tt − EventFlag > TTww then

9 ∆PPbbbbbbbb[tt] = PPrrrrrr[tt]/|PPrrrrrr[tt]| . – StepBackRate. PPrr rr

10 Else

11 ∆PPbbbbbbbb[tt] = 0

12 PPbbbbbbbb[tt + 1] = PPbbbbbbbb[tt] + ∆PPbbbbbbbb[tt]
26

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Figure 22. Active power variability with and without capacity firming

Figure 22 shows the active power variability at the feeder head with and without the battery 

operating in capacity-firming mode. The upper and lower variability limits have been set at 40 

kW/min and -40 kW/min, respectively. The figure shows that the capacity-firming controller 

does well to keep the active power variability within the limits. Although the actual controller 

manages to mitigate variability, there are instances when the variability considerably violated the 

prescribed bounds. Two factors that contribute to these violations are:

1. Error pertaining to sensing in the measurement device 

2. The fact that unlike in the simulation, the battery controller always lags behind the actual 

state of the system. The inherent lag is because of the delays in recording, transmitting,

and reading measurements at the remote site (in this case, the feeder head).

Figure 23. Substation power for varying ramp rate limit with time fixed at 10 min
27

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2.5 Voltage Regulation

The data sheet provided by inverter manufacturer details two modes for voltage regulation:

droop-based voltage control and PI-based voltage control. In this work, only droop-based voltage 

control has been implemented. 

Control Mode Overview

Droop-based voltage regulation is the recommended method for voltage regulation while 

operating in parallel with other voltage regulation devices, such as switchable capacitors and onload tap changers (LTCs). The controller compensates for voltage violation by either injecting or 

absorbing reactive power. For simulating scenarios for volt/volt-ampere reactive (VAR) control, 

the controller implemented in OpenDSS has been used. Controller details are available in 

OpenDSS documentation.

Simulation Results

Simulations for volt/VAR control have been conducted for six study cases. These include 

volt/VAR control with and without a deadband. Figure 24 and Figure 25 show the droop setting 

for each simulated scenario.

Figure 24. Volt/VAR droop (without deadband) settings for simulation study cases 

Voltage [p.u.]

Reactive power output [p.u.]
28

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Figure 25. Volt/VAR droop (with deadband) settings for simulation study cases

Figure 26. Storage reactive power output for voltage support mode

The simulation study has been run for a day with high peak load and renewable generation

corresponding to DoY 228. Figure 26 captures the reactive power support from the energy 

storage system (per phase) for all volt/VAR curves (VV1 to VV6). Volt/VAR curves with 3% 

deadband do not enable the energy storage system for reactive power support. As shown in 

Figure 26, for curves VV4, VV5, and VV6, reactive power support is insignificant. 

The results in Figure 27 show that running the battery in volt/VAR mode can potentially improve

the voltage profile by providing reactive power support, particularly for volt/VAR curves 

without any deadband. The maximum change in storage reactive power output is approximately 

20% of overall capacity, or 600 kVAR (sum of three phases). Reactive power output [p.u.]

Voltage [p.u.]
29

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Figure 27. Voltage profile for voltage-support mode
30

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3 Energy Storage Value Streams from Distribution 

Support 

3.1 Introduction and Background

This section identifies methods to evaluate the monetary value derived from the VRFB energy 

storage system by providing distribution support. The purpose of this task is to monetize the 

benefits from distribution support, such as voltage regulation, capacity firming, and peak 

shaving. For the optimization, each benefit needs to be converted into a monetary value that the 

model can chose between. This section performs a detailed literature review and develops

effective ways to evaluate cost-benefits for feeder support functions. 

This work also involves formulating and solving the optimization problem using NREL’s 

Renewable Energy Optimization (REopt) model.

1 The optimization solver will be used to 

generate operation profiles that maximize benefits from the energy storage system. The methods 

to monetize the feeder support functions derived from the prior task will be implemented to 

generate optimal operation profiles.

The description in the chapter will focus on gaining real-world experience and data from 

distribution-connected battery energy storage system operation and evaluating the value provided 

by this system.

3.2 Value Streams for Distribution Grid Support Monetization

This section describes the potential value streams that could be realized through appropriate 

dispatch of the VRFB system. The VRFB battery is connected as a distribution system asset and 

considered to be under full utility ownership and control. Distribution assets are managed by the

SDG&E Distribution Control Center.

First, the three main battery applications are described in brief, and the potential value streams 

are outlined. Then, a description of the TEST FEEDER feeder characteristics is presented, and 

the modeling approaches for monetizing specific value streams are identified. Finally, the 

simulation framework for the VRFB value stacking using an optimal dispatch model is 

described.

3.2.1 Applications Chosen for Distribution Grid Support

The battery applications in this project focus on providing distribution system support services as 

follows:

• Peak shaving: Energy storage charges during low-load periods and discharges during 

high-load periods to reduce the peak demand on the feeder during the highest loading 

condition.

• Capacity firming: The objective of capacity firming is to use storage to smooth the output 

of intermittent renewable energy generation. Storage is able to react quickly to 

 1 https://reopt.nrel.gov/
31

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compensate for rapid fluctuations in output, resulting in reduced ramping and a more 

consistent, less variable load on the system. 

• Voltage support: Energy storage can also provide voltage support to maintain feeder 

voltages within acceptable bounds, typically ±5% of nominal. For sensitive electric 

appliances and electronics, it is important that voltage is supplied within these limits. 

Utilities typically install capacitor banks or voltage regulators to boost the voltage at the 

end of a line. With power electronics capable of injecting and absorbing both real and 

reactive power at different rates, energy storage is now able to provide the same services. 

The value streams listed in the sections below have been explored to identify monetary benefits 

from a battery. The value streams identified by NREL are described in the following sections.

Value Streams from Peak Shaving

An energy storage system capable of reducing peak system loading is assumed to be able to 

offset all or part of an investment toward substation or distribution circuit upgrades. To quantify 

the value of an upgrade deferral, the following information is required:

• System loading level at which an upgrade is required

• Cost of upgrades

• Forecasted load growth on the network (to establish when limits will be met/exceeded 

with and without the storage system).

To capture the value from providing a distribution upgrade deferral, the battery storage system 

must be able to continuously keep the overall network demand less than a predetermined level.

Value Streams from Capacity Firming 

3.2.1.2.1 Substation Capacity Firming

Capacity firming can reduce the number of LTC operations required at the substation level, 

resulting in a reduction of operation and maintenance (O&M) costs.

3.2.1.2.2 Renewables Capacity Firming

Storage coupled with PV can firm highly variable generation output. If a capacity market exists, 

PV production alone might not coincide with capacity needs (e.g., when the capacity is called for 

and/or tested to establish total available capacity). A battery system can be used to firm PV 

output during critical hours, increasing the total capacity payment that a stand-alone PV system

can achieve. 

Value Streams from Voltage Support

The uncertainty and variability introduced by distributed PV increases the need for flexible 

reactive power support. Additional capacitor banks are required to regulate system voltages. 

Currently, utilities maintain voltages within specified limits using tap-changing regulators at the 

distribution substation and by switching capacitors to follow changes in load. This is especially 

important on long, radial feeders where a large load such as an arc welder or a residential PV 

system might cause unacceptable voltage excursions for neighboring customers. An energy

storage system can effectively dampen these voltage fluctuations by discharging small amounts 

of active power.
32

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There is currently no financial compensation for reactive power services in distribution 

networks. One way to account for the increasing demand for flexible reactive power support in 

distribution systems is to replicate the lost opportunity cost model currently used with spinning 

generation at the transmission level.

Value Streams from Energy Arbitrage 

Energy storage is charged during off-peak hours and discharged during peak hours to take 

advantage of the price difference of electricity across time periods. The revenue obtained is the 

price differential between buying and selling electrical energy minus the cost of losses during the 

full charge/discharge cycle. 

Although market participation is not the focus of the current phase of the project, the value of 

energy arbitrage is modeled to fully capture the economic impacts of battery operation to provide 

other distribution system services. 

Stacking Value Streams for Multiuse

A storage system used for upgrade deferral can simultaneously provide voltage support and 

capacity firming. Value streams might be stacked, with multiple services provided through a 

single asset. The added value provided by this flexibility could be quantified and assigned to the 

battery system as an additional benefit. 

3.2.2 Distribution Feeder and Substation Conditions

The TEST FEEDER feeder that the VRFB system are located on is one of seven feeders that 

connect to the distribution substation. This substation has two 28-MVA LTC transformer banks 

built out and two free spots for potential banks in the future. The existing LTC banks operate in 

parallel and have the ability to support 100–110% loading for 30–60 minutes. OpenDSS analyses 

show that under current loading conditions, voltages along the feeder are all within the operating 

limit from 0.95–1.05 p.u. Capacitor banks are present on the feeder, but no regulators are

installed. Load growth on the feeder is estimated to be 3% per year.

A combination of low feeder load and high PV penetration causes the feeder head to experience 

power export: up to -500 kW was measured during the commissioning phase; however, there is 

no active curtailment of PV systems at the distribution level. Although system operators can 

curtail renewable energy to maintain generation on baseload units at the transmission level, this 

does not impact the feeder directly, and the VRFB system cannot reduce that curtailment. 
33

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Figure 28. OpenDSS diagram of feeder TEST FEEDER showing the capacity-constrained line

A portion of the TEST FEEDER feeder between the VRFB and the primary connecting to the 

substation is capacity constrained (Figure 28). This 1.5-mile #6 overhead cable has a maximum 

rating of 2.25 MVA, and it directly impacts the maximum charging capacity of the VRFB 

system. Because the VRFB system is installed downstream of the capacity-constrained line, the

total load from that point of the feeder and below along with battery charging power cannot 

exceed 2.25 MVA. For example, if the load below the capacity-constrained line is measured at 

500 kW, then the battery must charge at or less than 1.75 MW (less than its 2-MW total inverter 

rating).

This constraint is considered in the modeling approach. Loads less than the capacity-constrained 

line are continuously monitored to ensure that battery charging in optimized dispatches never 

exceeds the line limits unless a line upgrade cost is paid. Optimizations are solved with the 

option to respect charging constraints based on feeder load at each time step or pay the upgrade 

cost and avoid all charging limitations. 

The line upgrade cost was estimated using past projects from rate case testimonies (Jenkins 

2014). The cost of aluminum cables was averaged among all relevant projects found, and it

determined to be approximately $84.53/ft. This unit cost includes material, labor, direct charges, 

contract costs, and contingency, making the total cost of upgrading the 1.5-mile line 

approximately $670,000. This value is likely to be an underestimation because potential sitespecific considerations and other component costs (e.g., poles, cross-arms) are not considered;

however, this cost penalty was sufficient to disincentivize line upgrades in the scenarios 

considered in this analysis.

Capacity 

Constrained
34

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3.3 Framework for Value Stream Modeling and Comparison

To quantify the monetary value provided by the VRFB storage system through the value streams 

listed in Section 3.2.1 two scenarios—with and without storage—are compared:

• Benchmark scenario: A multiyear simulation is performed assuming no storage system is 

installed to determine:

o LTC transformer upgrade required to meet demand growth

o Total cost of electricity purchased on the locational marginal price (LMP) market

o Additional capacitor investments required for reactive power and voltage support 

to ensure system reliability

o Baseline levels of LTC and capacitor switching to maintain power quality.

• Utility-storage scenario: A multiyear simulation is performed accounting for the VRFB 

installation, and new distribution system investment and operation costs are determined. 

It is assumed that the battery is located on the utility side of the meter, with the utility 

having full control of its operation. This simulation will leverage data from OpenDSS 

runs to accurately capture how the VRFB system can be used in different grid support 

modes. Further, the REopt model will be used to optimally trade-off between value 

streams and to determine how the VRFB system should be operated to achieve its 

maximum revenue potential as it provides distribution grid support services. 

The value of the VRFB system is quantified as the difference between these two scenarios. 

Details about how different value streams are monetized are listed in Figure 32 along with an 

explanation of how deferral value is calculated in this analysis.

3.3.1 Calculating the Value of Distribution Upgrade Deferral

This section outlines the set of value streams that are assessed in this analysis. This set of value 

streams is determined by checking whether each potential value stream in Section 2.2.4.2 applies

to the distribution feeder substation network. Because a primary way the VRFB system captures 

value by providing distribution system support services is through the deferral of existing 

equipment upgrades or new asset installations, an example calculation of how deferral value is 

quantified is provided first. 

To quantify the monetary value of an asset upgrade or installation deferral, the total value of the

deferral is first determined and then converted to a $/kW amount for each kW of battery capacity 

allocated toward providing a specific service. An example calculation is shown in Figure 29.
35

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Figure 29. Calculating the value of deferring a new asset installation or upgrade

First, the years in which the upgrade would be required with and without the VRFB storage 

system accounting for projected load growth are determined using OpenDSS simulations. As 

shown in Figure 29, the storage system is able to defer transformer upgrades from Year 8 to Year 

11 if the full capacity of the battery is used for peak shaving. The total cost of the upgrade varies 

depending on which year the upgrade occurs because of the time value of money. Using an 

estimate of $1,497,000 for transformer upgrade costs and a discount rate of 6%, an upgrade 

would cost would be $939,236 if done in Year 8 and $788,601 if pushed to Year 11 (no cost 

escalation rates were applied to the capital cost of an asset in this analysis). Therefore, the 

maximum deferral value the storage system can provide is:

$939,236 - $788,601 = $150,635

If the full inverter capacity is used for peak shaving, distribution utility will be able to save

$150,635 in transformer upgrade deferral costs; however, to allow the optimization to choose 

how much battery capacity to assign to different value streams, the maximum deferral value is 

divided by total inverter capacity to find the value of each kW of peak load reduction:

Value per kW shaved = $150,635/2000kW = $75.32/kW

Hence, each kilowatt of peak load reduction is valued at $75.32, and the optimization may now 

choose how much peak shaving to perform depending on the value provided by engaging in 

other distribution grid support services (e.g., capacity firming, energy arbitrage).

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

$1,600,000

0 5 10 15 20 25

Present Value of Transformer Upgrade

Year of Purchase

Present Value of Upgrade

Calculated Deferral Years
36

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

3.3.2 Framework for Peak Shaving

Distribution upgrade deferral is achieved through peak shaving. The VRFB system is able to 

decrease peak loading at the test distribution substation, thus deferring when a transformer 

upgrade must occur. 

To calculate the value of this deferral, the year in which the distribution substation will require a 

transformer upgrade with and without the VRFB system is determined. The maximum deferral 

value the battery can provide is the difference in present value of the cost of transformer upgrade 

in the two out-years. This is translated into a $/kW value, where each kW of peak reduced 

captures a portion of the total deferral value.

Transformer upgrade costs were estimated using past projects costs from the distribution utility

rate case testimony documents (Jenkins 2014). SDG&E identified the Salt Creek and Mira 

Sorrento substation projects as the sites most comparable to the distribution substation. 

Therefore, an average of the relevant component costs from both of these projects were used to 

estimate the transformer upgrade cost at substation. Table 12 shows the breakdown of how total 

transformer upgrade costs were derived. 

Table 12. Distribution Substation Transformer Upgrade Costs

Component Cost

Transformer bank (30 MW) $1,164,000

Circuit breaker $91,000

Disconnect switch $64,000

Control panel $178,000

Total $1,497,000

3.3.3 Framework for Capacity Firming

Substation capacity firming allows LTC operations to be reduced. If significant LTC operation 

reduction is possible, the associated O&M reduction along with the battery capacity necessary to 

achieve the required level of substation capacity firming are added to the optimization model as a 

potential revenue stream. The impact of the VRFB system on LTC operations is evaluated by 

operating the energy storage system in capacity-firming mode and evaluating the corresponding 

impact at the substation. Because of the lack of a capacity market in the California Independent 

System Operator (CAISO) territory, renewables capacity firming is not evaluated in this analysis.

3.3.4 Framework for Voltage Support

The value of voltage support is quantified through the deferral of new capacitor bank 

installations along the feeder where the VRFB system is located and through reductions in O&M 

costs for existing capacitor and LTC banks:

• New capacitor bank deferral: Similar to the transformer upgrade deferral calculations, 

the value of capacitor bank deferral is calculated by establishing when an installation or 

upgrade is required with and without the VRFB system and then taking the difference in

the present value of the installation/upgrade cost in the out-years. 
37

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• Reduced O&M for capacitor and LTC banks: Changes in capacitor and LTC use because 

of the VRFB system are assessed in OpenDSS, and O&M savings as a result of reduced 

switching are quantified. 

These values streams can be stacked directly without impacting other grid support functions in 

most circumstances because the inverters of the VRFB can supply 1 MVAR of reactive power 

capacity without impacting the real power output of the system. Consequently, these value 

streams are not modeled within the optimization because they do not compete with the other 

value streams for battery capacity. OpenDSS is used to confirm that 1 MVAR is sufficient to 

perform the required voltage support services. 

New capacitor bank costs were estimated using past project costs found in the SDG&E rate case

testimonies (Jenkins 2014). Six separate costs were found for the 1,200-kVAR pad-mounted 

capacitors from five different projects (Table 13). Costs were given per capacitor and cover 

material, labor, direct charges, contract costs, and contingency. A distinction was made for 

whether the capacitor was installed in a new area or through an intercept conduit. Without 

additional information about how new capacitors might be installed on the TEST FEEDER

feeder, the new capacitor bank cost was assumed to be the average of all previously identified 

costs: $56,054.

Table 13. Costs for 1,200-kVAR Pad-Mounted Capacitors in Past SDG&E Projects

Project Intercept Conduit New Area

C928, POM: new 12-kV circuit $57,200 -

C1288, MSH: new 12-kV circuit - $56,100

C1090, JM: new 12-kV circuit $101,200 -

C1120, BQ: new 12-kV circuit $57,200 $35,750

GH new 12-kV circuit - $28,875

Average $56,054

3.3.5 Framework for Energy Arbitrage

It is assumed that the utility purchases the energy required to meet the network load on the LMP 

market (through some combination of day-ahead and real-time markets). With the VRFB system, 

the utility is able to charge the battery during low-price hours and discharge during high-price 

hours to take advantage of the price differential. The battery dispatch can be optimized to reduce 

the cost to the utility of purchasing the electricity needed to serve its customers. 

The value of energy arbitrage is modeled with 2016 day-ahead LMP data from the nearest LMP 

node to the distribution substation (TELECYN_1_014). The cost of energy at each hour is used 

an input to the optimization to inform the trade-offs of using battery capacity to capture different 

value streams. 
38

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Table 14. Statistics for the 2016 LMP Signal Used in This Analysis

Minimum

($/MW)

Maximum

($/MW)

Average

($/MW)

Median

($/MW)

Standard Deviation 

($/MW)

-$27.70 $180.60 $29.60 $27.70 $13.80

Table 14 outlines basic statistics around the LMP signal, and Figure 31 show how prices vary 

throughout the day and during the course of the year. The average 2016 LMP value at the 

TELECYN_1_014 node is approximately $30/MW with a standard deviation of $13.80/MW. 

Prices are typically highest in the evening between 5–8 p.m.; and lowest throughout the night, 

from 12–4 a.m., or during midday, from 8 a.m.–4 p.m. A less distinct morning peak between 5–8

a.m. is seen in some months (e.g., late fall/winter). Prices tend to trend upward slightly in the 

summer months (June–September), with higher daytime prices seen.

Figure 30. LMP values throughout 2016

-50

0

50

100

150

200

LMP Signal [$/MW]
39

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Figure 31. Heat map showing how 2016 LMP prices vary throughout the day and during the year

3.4 REopt Simulation Framework for Identifying Value Streams 

This section calculates and lists the monetary value of distribution device upgrade deferral. The 

economics of using the VRFB system to provide grid support functions is evaluated via a 

combination of OpenDSS simulations and optimizations through a mixed-integer linear program 

using NREL’s REopt model. Figure 32 shows a schematic of the simulation workflow, and the 

following sections explain the details of each component. 

Figure 32. Schematic illustrating the simulation framework

 Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec

24

20

16

12

 8

 4

0

Hour of the day

LMP [$/MW]
40

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The quasi-static model of the TEST FEEDER feeder in OpenDSS is used to establish the impact 

of load growth on the year a transformer or capacitor upgrade is required (both with and without 

the VRFB system). The OpenDSS model is also used to analyze the impact of capacity firming 

on LTC operations and to determine the reactive power requirements from the VRFB system to 

provide voltage support services. 

3.4.1 Input Data for Value Stream Analysis

Inputs to the optimization model include:

• Hourly load profile for one full year of total network load

• Hourly load profile for one full year of loads downstream of the capacity-constrained 

feeder (to determine if a line upgrade to avoid charging limitations during the analysis 

period is cost-effective)

• Full year of historic day-ahead LMP values at the identified node near the distribution

substation (corresponding to the same time period for which load data were provided)

• Feeder constraints (e.g., export limits)

• Storage system parameters (e.g., minimum SOC, operating limits, efficiency and loss 

characteristics)

• Value of transformer and capacitor upgrade deferral as well as any O&M savings 

potential (calculated using the OpenDSS outputs)

• Economic parameters and relevant costs (key assumptions are summarized in Table 15).

Table 15. Economic Parameters and Cost Assumptions

Economic Parameters and Costs Assumption

Analysis period 25 years

Discount rate 6%

General inflation 0.1%

Electricity escalation rate 1.5%

Annual load growth 3%

Line upgrade cost $670,000

Transformer upgrade cost $1,497,000

New capacitor bank cost $56,054

Using the input data described, the optimization model determines how to best operate the VRFB 

system and stack value streams to minimize the total cost of operating the feeder during the 

analysis period. NREL’s REopt software modeling platform for energy systems integration and 

optimization was used. A brief overview of the REopt model is given in this section, followed by 

an explanation of the specific alterations made to accurately model the existing VRFB system. 
41

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3.4.2 REopt Overview 

The REopt model is based on a mixed-integer linear program that seeks to minimize the lifecycle cost of energy at a site during the analysis period, subject to a variety of constraints. The 

life-cycle cost of energy considers:

• All of the costs associated with providing energy to the site, including the cost of 

purchasing energy from the utility grid or wholesale electricity market

• The capital cost of building new technologies

• All O&M costs 

• Income from utility or state incentive programs 

• Any tax benefits. 

The model performs an hourly simulation of the energy system, solving an energy balance at 

every time step where loads must be met by some combination of renewable and conventional 

generation, purchased energy from the utility grid or wholesale electricity market, discharges 

from energy storage, or dispatchable loads. This energy balance is solved for the first year and 

then assumed to repeat for each of the ensuing years in the analysis period. The output of the 

REopt model is a set of cost-optimal sizes for each technology in the candidate pool and the net 

present value that is achieved if the technologies in the solution are implemented. The optimal 

dispatch strategy for each technology required to achieve the net present value is also provided. 

The technology sizing and selection components of REopt were not used in this study. Building 

additional renewable energy generation to potentially reduce feeder operation costs was not 

considered, and sizing for the storage system was based on specifications of the existing VRFB. 

The analysis focused on modeling the existing battery as accurately as possible to determine an 

optimal dispatch strategy that minimizes total life-cycle costs through stacking all monetizable 

value streams. 

For mathematical formulations and additional details of the REopt model, see Cutler et al. 

(2017).

3.4.3 VRFB Loss Modeling in REopt

To accurately capture VRFB performance characteristics, total system losses are modeled within 

REopt based on field data from the existing VRFB system. Total system losses are separated into 

three main sources of loss: power conditioning system (PCS) losses, storage losses, and the 

auxiliary power consumption of the electrolyte pump. It is assumed that the battery has no other 

loss components. Because REopt is a mixed-integer linear program, losses were derived as linear 

functions of explanatory variables. 

Within the optimization, PCS and storage losses are combined and modeled together as functions 

of active power. Two separate equations were derived: one for losses during battery charging and 

one for losses during battery discharging. Figure 33 shows the linear fits of the combined PCS 

and storage losses field data points as a function of the charging and discharging power. The Rsquared values for each show that a linear fit aligns closely with observed measurements.
42

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Figure 33. Linearized PCS and storage losses as a function of charging/discharging power

It is assumed that the VRFB system serves both the PCS and storage losses. These losses 

decrease the available charge in the battery and impact its operation in future time steps. 

The third loss component is the power consumption of the auxiliary pumps. This was determined 

to be a function of the active power as well as the battery SOC. The top two plots in Figure 33

show the field data of auxiliary power consumption across the full SOC range for separate 

charging and discharging rates. To linearize this complex behavior, auxiliary power consumption 

modeling is split into five regimes:

• Charging to less than 60% SOC: Because the battery is at a low SOC, relatively little 

pumping power is required to raise the SOC. Auxiliary power consumption is modeled as 

a constant 18.4 kW in this regime. 

• Charging to more than 60% SOC: Pumping power requirements increase the more the 

battery is trying to charge close to full SOC. Auxiliary power consumption data are first 

averaged among different charging rates at each SOC level, and a linear fit is done using 

the new data points (bottom left plot in Figure 33). Pump consumption is modeled as a 

linear function of SOC for battery operation in this regime. 

• Discharging to less than 60% SOC: Pumping power requirements also increase the more 

the battery is trying to discharge when it is nearly drained. Auxiliary power consumption 

data are first averaged among different discharging rates at each SOC level, and a linear 

fit is done using the new data points (bottom right plot in Figure 33). Pump consumption 

is modeled as another linear function of SOC for battery operation in this regime.

• Discharging to more than 60% SOC: Because the battery is at a high SOC, relatively little 

pumping power is required to meet the requested discharge rate. Auxiliary power 

consumption data are averaged among the different discharge powers to arrive at a 

constant 12.9-kW pump consumption rate for any operation within this regime. 

y = -0.1163x

R2 = 0.9663

y = 0.1488x

R2 = 0.9178

0

50

100

150

200

250

-1500 -1000 -500 0 500 1000 1500 Losses [kW]

Charging/discharging power [kW]
43

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• Idling: Two scenarios are compared for auxiliary power consumption when the battery is 

neither charging nor discharging, but based on input from battery manufacturer, Scenario 

2 is assumed for all results presented in Chapter 3: 

o Scenario 1: A constant 18.4-kW pump consumption is modeled to maintain 

electrolyte circulation when the battery is idle.

o Scenario 2: Pumps shut off when the battery is idle, consuming no energy. It is 

assumed that the system can restart in a negligible amount of time so that the 

ability of the battery to capture any of the modeled value streams is unaffected. It 

is also assumed that frequent restarts do not increase degradation or other 

equipment O&M costs enough to introduce an additional cost to the analysis. 

Figure 34. Auxiliary power consumption during charging and discharging as a function of SOC

Pump losses are modeled as external to the battery. The auxiliary power consumption is costed at 

LMP and factored into revenue calculations, but it does not directly subtract from the battery 

SOC. The VRFB system is allowed to supply its own auxiliary load if it is economical to do so, 

but auxiliary load consumption could also be purchased directly from the LMP market. 

Simulations with the VRFB assume that the battery starts at 0 SOC to avoid free energy in the 

system, and no minimum SOC is imposed because flow batteries are able to operate within the 

full SOC range without incurring heavy degradation penalties.
44

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3.4.4 Expected Outputs from REopt

The optimization model determines the total life-cycle cost for operating the feeder with and 

without the VRFB system, including the cost of energy acquisition and new capital investments. 

The model also outputs the cost-optimal dispatch strategy of the VRFB system that minimizes 

total life-cycle cost. Finally, other economic parameters associated with the VRFB dispatch are 

also provided (e.g., a breakdown of the contribution of different value streams to total VRFB 

system revenue).

3.5 Value Stream Assessment and Results

This section summarizes the value stacking potential of the VRFB system and provides the 

modeling results of key technical operating constraints (e.g., comparison of different battery loss 

scenarios and analysis of impacts of charging limitations because of line constraints).

The value streams analyzed along with the main optimal dispatch results are shown in Table 16. 

The following sections describe how these values were derived and other details of the analysis.

Table 16. Summary of the Value Streams Analyzed Along with Key Optimal Dispatch Results

Value Stream Monetization Mechanism Year 1 Savings Life-Cycle Savings

Peak shaving Transformer upgrade deferral – $121,135

Capacity firming O&M savings from reduced LTC 

operations

– –

Voltage support New capacitor bank deferral – $7,463

Energy arbitrage Time-shifting energy purchases 

on the LMP market

$56,069 $837,115

Total $965,713

3.5.1 Value Stream from Peak Shaving and Energy Arbitrage

The value of peak shaving and energy arbitrage are both quantified here because these value 

streams are optimized together. Furthermore, discharging the battery to peak shaving aligns well 

with energy arbitrage objectives because the hours with the highest demand typically also 

correspond to hours with high LMP values. 

Peak shaving within the distribution feeder is monetized through transformer upgrade deferral. 

Assuming a 3%/year load growth rate, OpenDSS results showed that transformer upgrades could 

be deferred from 2023 to 2026 if the full 2-MW inverter capacity were allocated toward peak 

shaving. Using the value of deferral calculations from Chapter 2, this translates to a return of 

$75.32 per kW of peak load reduction. REopt considers this value along with the LMP signal at 

each time step to determine how to best operate the battery to minimize total life-cycle costs. 

Figure 35 shows the TEST FEEDER feeder load with and without VRFB dispatch. The original 

load peaks at 6.24 MW; the VRFB system optimally shaves 1.61 MW to obtain a new feeder 

peak of 4.63 MW. 
45

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Figure 35. Feeder load with and without the optimal VRFB dispatch

To further analyze the optimal battery dispatch, Error! Reference source not found. zooms in 

on the detailed operation of the VRFB system for five days around the highest load day of the 

provided 2016 data. Peak feeder demand occurs on September 26, so full battery capacity is used 

to flatten the evening peak (orange portion of the graph). The maximum load reduction the 

battery is able to achieve on this day sets a new annual peak for the feeder. Therefore, battery 

charging on September 26 (green portion of the graph) must also stay at less than the newly 

established peak while trying to charge during low LMP periods. On nonpeak load days, the 

VRFB system is dispatched purely for LMP arbitrage. Battery charging might set new intraday 

peaks (e.g., September 23) without affecting the annual feeder peak demand. 

Figure 36. Detailed dispatch results for five days surrounding the peak load day of 2016

0.20

0.10

0

7000

3500

 0

 Original load Optimal dispatch LMP Total losses

Power purchase VRFB discharge VRFB charge

400

 200

 0

$/kW

kW kW

 Sept 23 Sept 24 Sept 25 Sept 26 Sept 27
46

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Monthly averaged dispatch profiles are plotted to understand typical VRFB system operation 

trends. Figure 37 shows the monthly averaged profiles for battery charging and discharging 

along with the corresponding average LMP values. As expected, the battery charges during low 

LMP periods and discharges to offset high LMP hours throughout the year. 

Consistent discharging near the full 2 MW of inverter capacity occurs between 5–8 p.m. across 

all months. Reduced discharging occurs between 5–7 a.m. during the non-summer months. The 

battery typically charges during two low LMP periods each day: 12–4 a.m. and 8 a.m.–3 p.m. 

Charging tends to occur earlier in the day during the summer months because of a shift in LMP 

trends. Maximum average charging stays less than 1,500 MW and never reaches full inverter 

capacity because of the capacity-constrained line along the TEST FEEDER feeder. 

Figure 37. Monthly averaged VRFB charging and discharging profiles along with the 

corresponding LMP signal

3.5.2 Value Stream from Capacity Firming 

OpenDSS simulations with and without the VRFB system were run for the peak load day to 

analyze LTC operations at the distribution substation. To minimize LTC operations using energy 

storage, the VRFB system was set to peak shaving by discharging at 2 MW during the highest 

load hours. 

LMP [$/kW]

Hours of the Day

 Charging Power [kW] Discharging Power [kW] LMP [$/kW] 
47

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Figure 38 shows the difference in the TEST FEEDER feeder load, the distribution substation

load, and the LTC tap positions with and without VRFB operation. The LTC tap operations are 

hardly affected at maximum VRFB discharge; the battery system has minimal impact on 

substation capacity firming because of the other large loads connected at the substation through 

the six other feeders. As a result, O&M savings from reduced LTC operations are negligible and 

not considered as an additional value stream provided by the VRFB. 

Figure 38. LTC operations with and without the VRFB system

3.5.3 Value Stream from Voltage Support: Capacitor Avoidance Costs

To calculate the potential of the VRFB system to defer a new capacitor bank installation, annual 

OpenDSS simulations for the lowest voltage day were run in five-year increments (2016, 2021, 

2026, and 2031) using the expected load growth for the network. 

The lowest voltage along the TEST FEEDER feeder based on 2016 data was found to occur on 

August 15 at 18:19:00. Figure 39 shows a voltage heat map of the point in time when the lowest 

voltage occurs. No capacitor banks are operating in this voltage snapshot.

Using August 15 as the reference day, Figure 40 and Figure 41 show how network voltages 

evolve every five years with expected load growth until voltage limits are violated (dropping to 

less than 0.95 p.u.). Figure 40 shows network voltages on the lowest voltage day when existing 

capacitor banks are operating, and Figure 41 shows network voltages on the lowest voltage day 

when the VRFB system is used to perform volt/VAR regulation. 
48

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Figure 39. Voltage heat map for the time step with the lowest network voltage when no capacitor 

banks are operating (based on 2016 system load data)
49

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Figure 40. Voltage heat maps for the time step with the lowest network voltage when only existing

capacitor banks are operating
50

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Figure 41. Voltage heat maps for the time step with the lowest network voltage when the VRFB 

system is performing volt/VAR regulation
51

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The results show that existing capacitor banks can maintain voltages within bounds along the 

TEST FEEDER feeder until 2026. Performing volt/VAR regulation using the additional 1

MVAR of reactive capacity from the battery, the VRFB system can defer the installation of a 

new capacitor bank until 2031. 

Assuming that a capacitor costs $56,054 (based on SDG&E rate case testimonies) and 

discounting it to the calculated out-years using a 6% discount rate, the present value of deferral 

savings is $7,463. Because the battery can supply 1 MVAR of reactive power without impacting 

the real power output of the system, this value stream was not included in the optimization but

instead added directly as another source of revenue for the VRFB system. 

3.5.4 Modeling Shutting Off Auxiliary Pumps when the Battery Is Idle 

As requested by the battery manufacturer, the optimal dispatch and value stacking results

presented in this chapter assume that the electrolyte pump can turn off when the battery is neither

charging nor discharging. This impacts only the modeled auxiliary power consumption, not the 

PCS and storage losses. 

Figure 42 shows an example dispatch during the peak load week of 2016. The plot on the left 

assumes a baseline 18.4-kW auxiliary power consumption when the battery is idle, and the plot 

on the right shows the results when the battery is allowed to turn off and not draw power when it 

is not charging nor discharging. 

Figure 42. Comparison of optimal dispatch and auxiliary power consumption for two scenarios: 

(left) 18.4-kW baseline pump consumption when battery is idle and (right) pumps turn off and 

draw no power when battery is idle

Total life-cycle costs decrease only marginally, by 0.17%, if the pumps can shut off when the 

battery is idle. Battery capacity is not affected, and optimal dispatch results are identical because 

18.4 kW is a relatively small loss for a 2-MW/8-MWh system. When they are able to shut off,

the pumps are switched an average of 6.8 times per day or a little during three on/off cycles. 

70

35

0

kW

200

0

100

0

 

kW

Sept 25 Sept 27 Sept 29 

 

Sept 25 Sept 27 Sept 29 

 

 Charging Discharging Auxiliary Power Auxiliary Power 

 (battery always on) (battery off 
52

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3.5.5 Value from Line Upgrade Deferral

Battery charging is limited by a 2.25-MVA capacity-constrained line between the VRFB 

installation and the distribution substation. Load less than the capacity-constrained line was 

monitored at every time step within the optimization to ensure that battery charging never 

exceeded line limits unless the line upgrade cost was paid. REopt was given the choice of 

accounting for the upgrade cost to avoid charging limits, but this option was not selected. 

Because REopt has perfect foresight, the model can optimally dispatch the VRFB system to 

avoid capacity-constrained periods. 

Throughout the year, the line limits restrict battery charging to less than 412 kW–1,618 kW. 

Figure 43 shows an example of the charging limit as well as the rate at which the VRFB system 

is charging during the peak load week of 2016. As shown, charging tends to occur at the limit 

that is allowed to take full advantage of low LMP periods as long as the rate of charge does not 

set a new system peak and the battery is not at full SOC. 

Figure 43. Capacity-constrained line limits for battery charging
53

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4 CAISO Market for Energy Storage 

4.1 Introduction

This section evaluates CAISO’s potential reforms on financial compensation for reactive power 

support from an asynchronous generating facility, i.e., energy storage system. The existing 

market and operation rules for reactive power service in CAISO will be explored.

The distribution utility operates within the CAISO balancing authority, which manages the 

power flow for about 80% of California. As a balancing authority, CAISO operates a 

transmission control area and balances the generation and load to maintain grid frequency within 

a specific range. As a market operator, CAISO runs the day-ahead and real-time market for 

energy and ancillary services and also manages the energy imbalance market among different 

areas. 

The majority of CAISO’s electricity demand is met through the utility-owned or bilaterally 

procured resources. The remaining unbalance between the generation and demand is handled by 

day-ahead market and real-time market, as shown in Figure 44.

Figure 44. Electricity power dispatch processes

4.1.1 Market Participants 

CAISO’s market participants include generators; retail marketers; and utility customers ranging 

from investor-owned utilities—such as Pacific Gas & Electric, Southern California Edison, and

SDG&E—to others such as the Valley Electric Association, to some municipal utilities and 

financial participants.

4.1.2 Markets in CAISO

Day-Ahead Energy Market

The day-ahead energy market is based on forecasts of energy usage, and it procures the bulk of 

the energy needed to meet California’s electricity demand the following day.
54

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Real-Time Energy Market

CAISO’s real-time markets include the 15-minute market and 5-minute market, which CAISO 

uses to manage the differences between the day-ahead forecasted energy loads with actual 

energy loads. These differences are a function of inaccuracies of forecasts of load and generation 

as well as unexpected disturbances in the utility grid.

Ancillary Services

In addition to the energy market, CAISO has an ancillary service market that includes four 

services: regulation-up, regulation-down, spinning reserve, and nonspinning reserve.

• Frequency regulation (regulation-up and regulation-down) is used to manage the 

difference between energy forecasts in the 5 minutes with actual demand in real time. 

This difference is also called the area control error, which is a small discrepancy because 

of the inherent nature of forecasts not being completely accurate.

• Spinning reserve is the additional capacity the independent system operator needs to have

available to ensure system stability and reliability when the system is suffering from an 

unexpected event. Spin resources must be synchronized to the grid to be available to 

provide ramping during a specified range within 10 minutes and be capable of running at 

least 2 hours.

• Nonspinning reserve is another type of additional capacity the independent system 

operator procures to ensure system reliability. The nonspinning resource does not need to 

be synchronized to the grid, but it must be capable of synchronizing with the grid and 

ramping during a specified range within 10 minutes and be capable of running at least 2 

hours.

4.2 Market Participation Model/Resource Model

Different resources might choose different participation/resource models to participate in 

CAISO’s energy and ancillary service market. The participation models include:

• Participating generator (PG)

• Participating load (PL)

• Proxy demand resource (PDR)

• Reliability demand response resource (RDRR)

• Non-generator resource (NGR)

• Pumped storage hydropower (PSH) model.

Considering the different storage scenarios, the corresponding potential participation models are 

summarized in Table 17
55

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Table 17. Participation Model for Different Storage Scenarios

Storage Scenario Participation Model

PG PL PDR RDRR NGR PSH

Transmission 

connected 

storage

Stand-alone ES PS

Storage behind the 

meter of a 

generating facility

ES PS

WDATconnected 

DERs

Stand-alone GEN Pumps ES PS

Behind meter of 

generating facility

GEN Pumps ES PS

Behind end-use 

customer meter

GEN Pumps ES PS

Rule 21-

connected 

DERs

Behind end-use 

customer meter

GEN Pumps Demand

Response

Demand

Response

ES PS

Storage may participate in CAISO markets as an NGR or wholesale demand response product 

(PDR and RDRR). The VRFB system can fall into the category of interconnected device under 

wholesale distribution access tariff (WDAT) or interconnected under California’s Rule 21, then 

NGR, PDR, and RDRR could be the resource model options.

4.2.1 NGRs

In 2010, CAISO began an effort to revise its tariff to treat NGRs on a comparable basis with 

conventional generators. In 2012, CAISO implemented NGR functionality within the wholesale 

markets. Within the non-generator tariff framework, CAISO developed additional functionality 

for resources providing regulation services called Regulation Energy Management, or REM. 

NGR and NGR-REM are defined as follows:

• NGR: A new resource type and model for energy-constrained resources that can operate 

continuously between generation and load 

• NGR-REM: An option for NGRs that provide only regulation services.

NGR-REM is proposed to allow NGR resources to bid their capacity more effectively into the 

independent system operator regulation markets. It allows energy storage to use full capacity to 

provide grid support services with a shorter time period.

Model 

NGR resources are modeled as a generator with positive and negative energy. They are 

constrained by an upper and lower capacity (MW) limit to inject or withdraw energy and are also 

constrained by an energy (MWh) limit to inject or withdraw energy on a continuous basis. 

CAISO will use energy limits and SOC values to co-optimize the NGR resource during multiple 
56

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intervals in the independent system operator markets. CAISO will use SOC values to prevent 

infeasible dispatches or control signals. Because of these NGR characteristics, this model is 

suitable for the full participation of energy storage resource in the day-ahead and real time 

wholesale market.

NGRs can participate in energy regulation-up, regulation-down, spinning reserve, and 

nonspinning reserve, but for each of these services the NGR must meet the minimum capacity 

and continuous energy requirement. 

NGRs may comprise aggregated physical resources as long as they meet metering, telemetry,

and modeling requirements. NGR aggregations at a distribution-level interconnection for 

wholesale participation will be subject to distribution interconnection requirements as well.

The REM option is intended for short-duration energy storage resources for which CAISO 

manages the SOC of the resource near 50%, and the non-REM option is intended for longer 

duration energy storage resources where the SOC is managed by the resource operator.

A comparison between the NGR and NGR-REM is shown in Table 18.

Table 18. Comparison of NGR and NGR-REM

NGR NGR-REM

Energy, spin, non spin, and regulation 

up/down

Regulation up/down only

Managed through energy schedules to 

maintain SOC

No energy schedules used

30-60 minute continuous energy requirements 15 minute continuous energy requirement for 

regulation service

Day-ahead ancillary service capacity value is 

based on 60-minute energy requirement

Day-ahead ancillary service capacity value is 

4 times the regulation energy it can provide in 

15 minutes

Co-optimized in day-ahead and real-time 

market subject to SOC constraints

Co-optimized in real-time market subject to 

SOC constraints

Participation Requirement

CAISO uses existing business processes and agreements to interconnect and model NGR 

resources. The participation requirements are shown in Table 19.
57

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Table 19. Participation Requirement for NGRs

Telemetry Parameters Requirements

Resource instantaneous output, instantaneous SOC, max/min operating limit, resource connectivity 

status, resource automatic generation control status.

Bidding parameters requirements

Upper charge limit (MWh), lower charge limit (MWh)

Minimum Continuous Energy Ancillary Service Procurement Requirements for NGRs and 

NGR/REMs

Day-ahead regulation-up/-down 60 min (non-REM)/15 min (REM)

Real-time regulation-up/-down 30 min

Spinning and nonspinning 30 min (non-REM)/NA (REM)

Minimum capacity requirements 500 kW

4.2.2 Demand Response Product

PDR was implemented in 2010, and the RDRR implementation was finalized in 2014 after 

Federal Energy Regulatory Commission ruling and compliance filing delays. The PDR and 

RDRR products are defined as follows:

• PDR: A load or aggregation of loads that provides demand response services pursuant to 

a demand response provider agreement between the independent system operator and a 

demand response provider.

• RDRR: Enables emergency responsive demand response resource participation.

Model 

Table 20. Participation Options for PDR and RDRR
58

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Participation Requirements

The participation requirements for PDR and RDRR are shown in Table 21.

Table 21. Participation Requirements for PDR

PDR Participation Requirements

Minimum load curtailment >= 100 kW for energy

Minimum load curtailment >= 500 kW for ancillary services

Allow aggregation to achieve minimum targets

10-kW minimum increments

Telemetry is required for resources >= 10 MW or participating in ancillary services

Scheduling Coordinator Metered Entity 

Scan rate = 60 s for PDR; scan rate = 2 s for resources > 10 MW or ancillary services participation at 

any size (not applicable for spinning reserve participation)

Table 22. Participation Requirements for RDRR

RDRR Participation Requirements

Minimum load curtailment >= 500 kW

Allow aggregation to achieve minimum targets

10-kW minimum increments

Telemetry is not required

Scheduling Coordinator Metered Entity

For Real-Time Reliability Participation

Must be capable of reaching full curtailment within 40 min

May elect to receive discrete dispatches in real time under this option:

-Size limited to 50 MW

-Cannot participate in day-ahead market

Minimum run time not greater than 1 h

Maximum run time of at least 4 h
59

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5 Dynamic Efficiency and Dynamic Loss Modeling

5.1 Data Sampling

Several variables were recorded in situ while the VRFB was charged and discharged, including 

the power losses associated with the PCS, internal battery losses, and parasitic losses 

corresponding to running the auxiliary electrolyte pumps and cooling system; along with the DC 

current, DC voltage, SOC, and active power measurements. The DC current, DC voltage, SOC, 

and active power were recorded for one of the transformers as the VRFB charged and discharged 

while operating at various active power settings (Figure 45). Hence, the measured active power 

is for half of the total capacity of the VRFB. All measured data are reported in this way, whereas

all simulated results (Section 5.4) are reported with both transformers together, i.e., twice the 

measured data. The three loss vectors aggregate to contribute to the total system losses and 

ultimately decrease the charging and discharging efficiencies. This section discusses both the 

dynamic efficiencies and the dynamic losses.

Figure 45. VRFB state variables for charging and discharging at 1,000 kW, 750 kW, 500 kW, 372

kW, and 300 kW, respectively

5.2 Dynamic Efficiency Modeling

We calculate the energy efficiency while charging and discharging. The three loss vectors—PCS 

losses, internal battery losses, and parasitic losses—decrease the efficiency. These are measured 

at the VRFB, whereas the active power is measured slightly farther down the line. The power 

measurements were recorded at constant time intervals. Thus, the energy efficiency can be 

calculated directly from the power measurements. We ignore the line losses, which are negligible 

given the proximity of the VRFB to the point at which active power is measured. Thus, as the 

VRFB is charged, the active power is measured before the losses occur. Therefore, given our 

experimental data and collection method, the charging efficiency is defined as:

ηηCChrr VVVVVV ≡

|PPVVVVVV |

|PPII | = |PPII | − (LLPP PP + LLII +LLPP )|PPII |

As the VRFB is discharged, the active power is measured after the losses occur. Therefore, the 

discharging efficiency is defined as:

ηηDD

VVVVVV ≡

|PPOOOO |

|PPVVVVVV |

= |PPOOOO |

(LLPP PP + LLII +LLPP ) + |PPOOOO |
60

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The dynamic efficiency while charging is asymmetric to the efficiency while discharging (see 

Figure 46). The asymmetry is a result of the differences in parasitic losses for the two operational 

modes, such as the electrolyte pumps and cooling system. The heat map is generated via thinplate-spline interpolation among the measured field data. 

The system efficiency was also recorded as a function of the SOC from the measured field data 

when operated at various fixed values of active power (see Figure 47 and Figure 48). The 

maximum and minimum efficiencies recorded while discharging were 86.16% and 72.55%, 

respectively. While charging, the maximum and minimum efficiencies recorded were 87.32% 

and 76.14%, respectively—generally higher than while discharging. The step discontinuities 

correspond to pump motor drives activating and deactivating, creating parasitic losses. The 

higher efficiencies while discharging are, again, because of the differences in parasitic losses for 

the two operational modes. 

Figure 46. A heat map of the measured VRFB charging and discharging efficiency as a function of 

the active power and the SOC
61

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Figure 47. Measured discharge efficiency against the SOC when operated for various fixed values 

of active power

Figure 48. Measured charging efficiency against the SOC when operated for various fixed values 

of active power

The parasitic losses significantly impact the system efficiency; the most significant of these is the 

pump motor drives. Given the existing pumping scheme, when a motor drive is activated, the 

system efficiency might rapidly drop by more than 5%, as shown while charging at 500 kW and

with an SOC of more than 80%. The system efficiency could potentially be improved by 

optimizing the pumping controller to minimize these losses while charging and discharging the 

VRFB. 

Still, the utility-scale VRFB features charging and discharging efficiencies that are significantly 

higher than those for smaller capacity units. This is primarily because of the larger motor drives 

on the electrolyte pumps and cooling systems. Larger motors have higher partial-load 

efficiencies than smaller motor drives. Therefore, the parasitic losses, as a percentage of the 

active power, detract less from the efficiency of the utility-scale VRFB than for smaller capacity 

units, which require smaller motor capacities. 
62 

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The higher efficiency for the utility-scale VRFB, and long cycle life, suggest that this technology 

has reached a level of maturity that has not been previously demonstrated. Efficiencies are useful 

for comparing one storage technology to another, but the losses that contribute to the dynamic 

efficiencies can impact the operation strategy of the technology. Further, the accuracy of the loss 

modeling can impact the operation strategy. Therefore, we also model the losses as a function of 

the VRFB operating state variables. 

5.3 Dynamic Loss Modeling Techniques

The most relevant operating state variables for determining the grid support strategies are the 

SOC and the active power. For this reason, each of the subsequent loss models are a function of 

these variables. Toward modeling the total system losses of the VRFB, we employ several 

techniques and evaluate the accuracy of each method. First, we employ a simple triangular 

interpolation between the measured field data instances. This simple interpolating technique fails 

to capture any nonlinearities between the total system losses and the operating state variables, so 

we explore several techniques, each with increasing complexity, to capture these nonlinearities. 

A composite quadratic function of the SOC and active power is explored. Additionally, we 

model the total system losses as a bivariate quadratic function of the VRFB operating state 

variables. Finally, we train a nonlinear artificial neural network (ANN) to predict the system 

losses as a function of the VRFB SOC and active power. 

5.3.1 Metrics for Evaluating Model Accuracy

Each modeling method is evaluated for accuracy as its ability to predict the total system losses 

from the VRFB operating state variables. The root mean square error (RMSE) and the maximum 

error are calculated to gauge the accuracy of each model. Finally, the coefficient of 

determination, or r-squared statistic, is calculated to gauge how well the variance in the total 

system losses are explained by the variance among the operating state variables: 

RMSE = �∑ (yi − y�i) n 2

i=1

n (3)

Max Error = max{|yi − y�i |} (4)

R2 = 1 − ∑ (yi − y�i) n 2

i=1

∑ (yi − y�i) n 2

i=1

 (5)

where yi are the measured losses, y�i are the modeled losses, y�iis the mean measured losses, and

n is the number of measured data points.

5.3.2 Triangular Interpolation 

To model total system losses, we used field data provided by battery manufacturer. Figure 49 

shows a polytope encompassing the field data points. A system of equations was generated 

from the polytope. 
63

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Figure 49. Three-dimensional plot of the field data and its projection along the x-axis

5.3.3 Composite Quadratic Fitting

Other works, such as Eller and Gauntlett (2017), separated loss modeling efforts from charging 

and discharging. For this reason, we explore a composite quadratic model composed of two 

quadratic functions of the VRFB SOC. The fitting coefficients are a function of the active power. 

This technique is somewhat disadvantageous because it requires manually investigating the 

losses as a function of each operating state variable independently, then carefully recoupling 

their impact, which is tedious. Generally, this poorly captures the parasitic losses, as shown in 

Figure 50.
64

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.

Figure 50. Composite model for loss as a function of the active power and SOC

5.3.4 Bivariate Quadratic Fitting

The total system losses seem to be well approximated by a quadratic function of the operating 

state (see Figure 51). The advantage is that the fitting coefficients can be easily found via any 

nonlinear solver. This technique also poorly captures the parasitic losses.

State of 

Charge [%]

100

0

50

-1000

Composite Model of Losses

100

50

150

Total Losses [kW]

-500

200

Active Power [kW]

250

0

300

500 0 1000

Measured Data

Composite Model
65

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Figure 51. Bivariate model of losses against active power and SOC

5.3.5 Nonlinear ANN Model

The underlying relationship between the total system losses and the VRFB operating state 

variables is not known a priori. In this situation, a model-free fitting technique, such as an ANN

model, lends itself well to the problem of predicting the total system losses. Model-free fitting is 

a technique wherein a meta model, such as a bivariate quadratic model, is not assumed in 

advance. Instead, the ANN is trained on the data using the batch back-propagation algorithm. 

The ANN is made nonlinear by introducing a hidden layer and is free to translate by some 

reference constant by introducing a bias weight and a virtual bias node as described by Eyer and 

Corey (2010, 5). The basic structure of the ANN is shown in Figure 52. The number of hidden 

nodes needed to accurately model the data is not known, so a sensitivity analysis is performed to 

investigate the relationship between the accuracy of the model and the number of hidden nodes 

that are included.

1

0

Bivariate Model of Losses

Losses vs Active Power, SOC

50

-1000

100

State of Charge 

0.5

150

Total Losses [kW]

-500

200

250

Active Power [kW]

0

300

500 0 1000

Losses vs Active Power,SOC

Measured Data
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Figure 52. Basic structure of the nonlinear neural network. One input layer with a virtual bias 

node, one hidden layer, and one output layer are used. The w(i,h) and x(h) terms denote the 

weights on the links between nodes, which are found via the back-propagation algorithm.

The back-propagation algorithm iteratively modifies the weights between nodes in the neural 

network to improve the model accuracy. If the model accuracy, as measured by the sum-ofsquares error, does not improve by more than some threshold, then the algorithm terminates after 

the current iteration. Additionally, a maximum iteration limit is imposed to prevent endless 

looping. Here, we use 90% of the measured data to train the ANN, and the remaining 10% is 

used for cross-validation. The ANN model is also advantageous because in this case the parasitic 

losses are highly nonlinear.

Figure 53. ANN model of losses against active power and SOC

1

Artificial Neural Network Model of Losses

0

50

-1000

100

State of Charge

0.5

150

Total Losses [kW]

200

-500

250

300

Active Power [kW]

0

500 0 1000

Measured Data

ANN Model
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5.3.6 Dynamic Loss Modeling

The following sections explore the accuracy of each model for predicting the total system losses 

of the VRFB as a function of the VRFB operating state variables. The accuracy of each model is 

evaluated in Table 23. As shown, the ANN model outperforms the bivariate model and the 

composite model, with a low RMSE of 4.43 and a high R2 value of 99.17%. 

Table 23. RMSE, Maximum Absolute Error, and Coefficient of Determination for Each VRFB Loss 

Model

Meta 

Model 

Fitting

X Y RMSE Maximum 

Error

RSquared

Composite Active 

power

SOC 14.72 38.58 92.29%

Bivariate Active 

power

SOC 9.63 36.01 96.41%

Modelfree 

fitting

Hidden 

nodes

Sample 

points

RMSE Maximum 

error

Rsquared

ANN 201 90% 4.43 26.38 99.17%

The primary degree of freedom associated with training the ANN is the number of hidden nodes. 

To evaluate how the accuracy of the model depends on the number of hidden nodes included, a 

sensitivity analysis is performed. We vary the number of hidden nodes and evaluate the model 

accuracy in Figure 54. 

Figure 54. RMSE of the ANN model when including various numbers of hidden nodes. The 

standard deviation caused random sampling is shown. 

Clearly, the model accuracy improves as more hidden nodes are included; however, the 

variability because of randomly selecting measured data for the training, prior to crossvalidation, increases. 

5.4 Accuracy Impacts Operation Strategies

We simulate the VRFB battery in OpenDSS and use dynamic programming to determine the 

optimal operating strategy under use cases—namely, peak shaving, for local grid support, and 
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energy arbitrage—to maximize the value of the VRFB. The various loss models are incorporated 

into OpenDSS simulations of the VRFB and feeder. For peak shaving, the VRFB charges or 

discharges to limit the load on the feeder to less than some threshold. For energy arbitrage, the 

VRFB charges and discharges to maximize the value of the energy supplied by the VRFB. Dayahead LMP prices are obtained for the feeder and are incorporated into the problem formulation 

to be solved via dynamic programming. Relying on historical data spanning 1 year, the LMP 

signal corresponding to the most typical day was identified. The most typical day has a mean 

value and variance most like the mean value and a variance of the historical data set. This 

approach was inspired by the method from Sandia National Laboratories for generating typical 

meteorological year data sets [3]. The optimal operating schedule for energy arbitrage for the 

typical day is then obtained using the backward value iteration algorithm. To improve the speed 

of the algorithm, state memorization is imposed. 

5.4.1 Accuracy Impacts Operation Strategies

Local Grid Support: Peak Shaving

We compare the various VRFB loss models by running a base-loading/peak-shaving simulation 

scenario in OpenDSS using a real feeder. The simulation is run for a day with the active power 

lower limits, PPll , and upper limits, Pub, at the feeder head set at 3,500 kW and 4,500 kW,

respectively (see Figure 55). 

Figure 55. Substation power in KW 

The VRFB charges as the substation power falls below PPll and discharges as demand exceeds

the upper active power bound, PP . The active power output from the VRFB peaks at 20% of 

PPrr rr while charging and about 20% of Prated while discharging (see Figure 56).
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Figure 56. Active power of the VRFB (both transformers) when operated for peak shaving

The accuracy of the loss models directly impacts the operating strategy. The significance of 

using an accurate system loss model for simulation studies is evident from Figure 57. The 

largest instantaneous deviation in the SOC profile is about 5%. For multiyear simulation studies 

or techno-economic analyses, this error can potentially accumulate during the simulation time. 

Using higher fidelity loss modeling, therefore, can significantly improve the quality and 

consequently usefulness of the simulation results. 

Figure 57. SOC of the VRFB when operated for peak shaving.

The modeled losses assuming the bivariate quadratic and the composite quadratic model closely 

follow those assuming the ANN model for the charge cycle at low states of charge (Time [m]: 0–

300), as shown in Figure 58. At high states of charge, however, there is a large deviation in the 

estimated losses. This deviation originates from the step discontinuities in the parasitic losses 

obtained from the field data. Unlike the ANN loss model, the bivariate and composite models are 
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unable to cater to these step discontinuities. For lower values of active power dispatch, the 

composite model fits the field better compared to the bivariate model.

Figure 58. Modeled losses (both transformers) of VRFB when operated for peak shaving

Because of the differences in the dynamic losses, the calculated dynamic efficiencies also feature 

significant differences, especially when the VRFB is discharging, or for very high states of 

charge (see Figure 59). Focusing on the dynamic efficiencies calculated assuming the most 

accurate loss model, the ANN, it is clear that when being operated for peak shaving and subject 

to the constraints on this substation, the dynamic efficiency of the VRFB is generally suboptimal. 

Figure 59. Dynamic efficiency of the VRFB when operated for peak shaving, assuming each loss 

model

Maximizing Value Generation: Energy Arbitrage

The accuracy of the loss model is also paramount when the VRFB is operated for energy 

arbitrage. Figure 60–Figure 65 demonstrate how the loss model can significantly impact the 
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optimal operating strategy for the VRFB and therefore the value generated during a single day. 

Generally, the reduced accuracy of the triangular interpolation, the composite model, and the 

bivariate model, relative to the ANN, result in errors when estimating the cumulative value of the 

VRFB during the most typical LMP day. The LMP signal at the feeder on the most typical day of 

2017 is shown in Figure 60. Clearly, the optimal operating strategy is impacted by the accuracy 

of the loss model being employed (see Figure 61). 

Figure 60. LMP signal at the feeder on the most typical day

Figure 61. Optimal active power (both transformers) for the VRFB on the most typical day, solved 

assuming each VRFB loss model
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Figure 62. Simulated VRFB SOC on the most typical day, calculated via OpenDSS based on the 

optimal active power and assuming each VRFB loss model

Figure 63. Losses for the VRFB (both transformers) on the most typical LMP day for each loss 

model
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Figure 64. Dynamic efficiency for the VRFB on the most typical LMP day, calculated assuming 

each loss model

Most importantly, the expected cumulative value generated by the VRFB, when employing the 

various loss models, can be significantly different by the end of the day (see Figure 65). When 

employing the composite quadratic loss model, the expected value generated by the VRFB is 

overestimated by more than 9% relative to the value obtained when employing the more accurate 

ANN. This overestimate of the generated value would persist for every other day of the year, and 

during the life cycle of the battery, as long as the composite loss model was employed. We show 

the simulated efficiency as a path through the efficiency heat map in Figure 66.

Figure 65. Expected cumulative value generated by the VRFB on the most typical day, assuming 

each VRFB loss model
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Figure 66. Trajectory of the VRFB operating states through the efficiency space when the battery 

is operated for energy arbitrage (white) and peak shaving (magenta), assuming the ANN loss 

model (A single transformer is shown.)
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6 Operational Planning and Field-Testing

6.1 Scope of Testing

At the request of the battery manufacturer, we assisted in operational testing of the VRFB system 

for a 1-week period in April. This testing included three different approaches to dispatching the 

battery:

1. Heuristic peak shaving/base-loading: This strategy selects set points that the VRFB 

attempts to maintain for multiple hours. One set point is selected for peak shaving 

(battery discharging) and is applied during high-load periods of day, and a second set

point is selected for base-loading (battery charging) during low-load periods. This 

strategy requires a load forecast to identify the set points and associated periods of the 

day in which to implement them. A heuristic method was also used to attempt to align the 

set points with high/low LMP hours.

2. Cost-optimal arbitrage: This strategy selects multiple set points throughout the day, with 

a goal of optimizing the revenue that the battery can achieve from the day-ahead LMP 

market. A total of eight distinct power set points—and associated start times—can be 

input to the PCS during a given period. This strategy uses the REopt model to select the 

eight (or fewer) optimal set points to maximize revenue from the day-ahead LMP 

markets. No load forecast is required for this strategy.

3. Hybrid peak shaving and optimal arbitrage: This strategy uses the same PCS control 

strategy as the cost-optimal arbitrage (max of eight power set points) and optimizes 

revenue from the LMP market while ensuring that the load on the feeder does not exceed 

a prescribed power limit. This strategy uses the REopt model to select the set points and 

uses a load forecast to inform the peak-shaving objective.

The peak-shaving/base-loading strategy was executed from April 2–4, the cost-optimal arbitrage 

strategy was executed from April 4–5, and the hybrid strategy was executed from April 5–6. 

Note that two of the three strategies require a forecast of the feeder load to execute the dispatch 

strategy. To achieve the load prediction, we trained an ANN to predict the feeder load as a 

function of the meteorological forecasts. The meteorological forecasts, and the subsequent feeder 

load forecasts, extended through an 18-hour-ahead time horizon at an hourly resolution. The true

feeder load and the operating state variables of the VRFB were continuously monitored during 

the week of testing to enable comparisons with the expected feeder load obtained from the load 

forecasts and the resultant operational plan.

6.2 ANN Model for Feeder Load Forecasting

This section discusses how the ANN model for the feeder load was developed and evaluated for 

accuracy. 

6.2.1 Historical Feeder Load Data

We received load data from the feeder, with the impact of the battery included, spanning the 

months of January and February on a 10-second resolution from the distribution utility. These 

data were downsampled to an hourly resolution by averaging across each hour. The data 
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corresponding to the feeder load with the impact of the battery were serially complete. 

Additionally, we received feeder load data without the impact of the battery included and

spanning the same time frame on an hourly resolution from Sumitomo. The data corresponding 

to the feeder load without the impact of the battery were not serially complete and featured 

missing data in rare cases. The missing data were represented in the time series as null values. 

6.2.2 High-Resolution Rapid Refresh Meteorological Data

The primary input variables used in training the ANN were meteorological variables. These 

variables were selected because temperature, solar irradiance, and other climatic variables have a 

large impact on both building electrical loads and solar PV performance on the feeder. For this 

analysis, we selected the High-Resolution Rapid Refresh (HRRR) data set that is provided by the 

National Center for Environmental Prediction on a 3-km by 3-km grid for the entire continental 

United States.

2 The HRRR data sat was selected because it is the only publicly available data set 

known to the authors that provides hourly forecast data for solar radiation as well as a wide 

variety of additional meteorological variables. 

The variables pulled from the HRRR data were atmospheric pressure (surface level), temperature 

(surface level and 2 m aboveground), dewpoint temperature (2 m aboveground), specific 

humidity (2 m aboveground), and downward shortwave radiation flux (surface level). These 

variables were pulled for the area bounded by the following grid of latitudes between 32.668 and 

32.67 and for longitudes between -116.98 and -116.97. 

6.2.3 Singular ANN Model Training 

A multilayer perceptron network, a class of feedforward ANNs, was trained to predict the feeder 

load without the impact of the battery as a function of the HRRR data. The network was 

composed of three layers: the input layer, the hidden layer to allow for nonlinearities in the 

model, and the output layer; see Figure 67. The input layer consisted of 19 hourly values for each 

of the six weather variables for a total of 114 inputs. The 19 hourly values correspond to the 

current hour and the 18-hourly forecasted values. The hidden layer consisted of 2,000 hidden 

nodes, a number selected after a sensitivity analysis that indicates there are diminishing returns 

on accuracy with a linear increase in time, as shown in Figure 68. Thus, 2,000 hidden nodes 

yield high performance while not requiring unnecessary time to train the network. The output is 

the feeder load and contains 19 hourly values, including the current hour and the next 18-hourly

values.

 2 http://www.nco.ncep.noaa.gov/pmb/products/hrrr/, accessed April 21, 2018
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Figure 67. General structure of the ANN model

Figure 68. (Left) Adjusted R-squared value of the ANN model as a function of the number of 

hidden nodes and (right) training time for the ANN as a function of the hidden nodes

6.2.4 Multiple ANN Model Training 

Training an ANN involves randomly selecting initial conditions for the weighting parameters

that interrelate the nodes in the network. Therefore, each time a network is trained on the same 

data set, different initial conditions will be used, and the resulting network will be slightly 

different after the training is complete. Further, the final trained network will feature some error 

relative to the training data and some bias error relative to “live” data outside of the training set. 

By training multiple networks of identical form on the same data set and taking the mean of their 

outputs, the bias error can be reduced on average. For this reason, we trained 50 ANNs of 

identical form against the training data set and took the mean of their outputs, as shown in Figure 

69.

Historical HRRR Data

Historical Load Data 

Hidden Nodes

(N=2000 in 

Input Nodes

(19 hourly values for 6 weather variables , n=144 inputs)

ANN (simplified graphic)
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Figure 69. Results of 50 unique ANN forecast results and the mean through the training data set

6.2.5 Metrics for Performance Evaluation

The ANN models offer very high accuracy within the training data set, as expected. Outside of 

the training set, the accuracy can be quantified by characterizing the distribution of residuals 

between the forecast values and the measured load, obtained after the fact, using the first four

moments of the distribution. The first and central moment, the mean residual, is the mean bias 

error. The second moment, the variance, offers insight into the spread of the residuals. The third 

moment, the skewness, indicates whether the distribution is asymmetric. Finally, the forth 

moment, the kurtosis, gives insight into the frequency of the extreme residual errors. Aside from 

these metrics, we evaluate the performance of the two feeder load forecasting methods using the 

RMSE, both nominally and as a percentage of the mean measured load during the testing period. 

6.3 VRFB Dispatch Strategies

6.3.1 Operational Constraints

The approach for operational testing of the VRFB testing was constrained by a few different 

factors, including:

• Manual entry: There is currently not a way to automatically push set points to the PCS. 

All set points needed to be input manually.

• Scheduled delivery of forecasts and dispatch strategies: The acquisition of the HRRR 

forecast data, acquisition of day-ahead LMP data, generation of load forecast, ensuing

optimal dispatch of the VRFB, and set point entry to the PCS were all manual processes 

during this testing period. All steps prior to the set point entry were executed by NREL 

staff, and Sumitomo staff input the set points (and established set points for peakshaving/base-loading tests). It was determined to perform this process twice per day: at 8

a.m. and 3 p.m.

• Eight controller break points: The current source inverter mode allows for set points of P 

and Q to be input to the PCS, yet it accepts only eight set points with their associated start 
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times. Because we were scheduling the battery twice per day, this limited the number of 

times we could change the set point of the VRFB.

We see a significant opportunity to streamline and automate this entire process. This would 

provide the benefit of continuously updating the load forecast by pulling the HRRR data once 

every hour (instead of relying on hours-ahead forecasts in some cases during the twice per day 

testing). It would also allow for more continuous updating of the SOC of the VRFB for the LMP 

optimization and could enable participation in real-time markets. 

6.4 Results

In this section, we discuss the results of the forecasting during the week of field-testing. In 

practice, the single ANN forecast method was applied for the first stage of the testing: peak

shaving/base-loading. Then, during both subsequent stages, the multiple ANN method was 

applied. Here, we show the results of both methods applied throughout the full week of testing.

6.4.1 Load Forecasting Results

The rolling forecast obtained from the singular ANN method, along with the measured load, is 

shown in Figure 70. As each new forecast was generated, it superseded the existing forecast. The 

series of forecast data used in practice is called the net forecast.

Figure 70. Rolling forecast for the singular ANN method. The net forecast is shown along with the 

measured feeder load.

The rolling forecast obtained from the multiple ANN method along with the measured load and 

the net forecast is shown in Figure 71. 
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Figure 71. Rolling forecast for the multiple ANN method. The net forecast is shown along with the 

measured feeder load.

The net forecasts obtained from the singular ANN and multiple ANN methods are shown in 

Figure 72. The residual relative to the measured feeder load is shown in Figure 73. The 

distributions of residuals for each method are characterized in Table 24.

Figure 72. Net forecast for the singular ANN and the multiple ANN methods along with the 

measured feeder load
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Figure 73. Residual errors relative to the measured feeder load of the net forecasts obtained from 

the singular ANN and multiple ANN methods 

Generally, the multiple ANN forecasting method resulted in better performance with smaller 

nominal RMSE and percentage RMSE than the singular ANN method. Additionally, the mean 

residual was smaller and the distributions were tighter, albeit similarly skewed, but featured less 

extreme residuals than the singular ANN forecast method, as is summarized in Table 24.

Table 24. Summary of the Accuracy of the Singular ANN and Multiple ANN Feeder Load 

Forecasting Methods.

Metric Single 

ANN

Multiple 

ANN

Average actual 2226.80 2226.80

RMSE 272.22 247.04

% RMSE 12.22% 11.09%

Mean of residuals 111.62 48.47

Variance of residuals 61529.13 58656.99

Std. Dev. of residuals 248.0507 242.1920

Skewness of residuals 0.2203 0.2599

Kurtosis of residuals 0.5706 0.3268

6.4.2 Optimal Dispatch Results

From 4 p.m. on April 4 to 4 p.m. on April 6, the VRFB was put into current source inverter mode 

and eight set points were entered into the PCS two times per day (at 8 a.m. and 4 p.m.). During 

this time, the REopt model was used to optimize the set points of the VRFB. The following 

modifications were made to the optimization model to accommodate the real-time testing 

formulation:

• Charging the system was capped at 1,620 kW, and discharging was capped at 1,960.

(These limits were set because of site load limits based on conductor ratings.)
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• The optimization model was scaled down to perform a 24-hour optimization.

• The optimization was constrained to select only eight set points within the current 

scheduling period (either 8 a.m.–4 p.m. or 4 p.m.–8 a.m. on the following day)

• For the 24-hour period from 4 p.m. on April 5 to 4 p.m. on April 6, a peak limit constraint 

was added to the model such that the feeder load (including charging the VRFB) was 

forced to remain under that limit. This was set at 3,000 kW for that period.

Figure 74 shows the comparison of active power from the PCS and the optimal dispatch 

provided by the REopt model. Note that the two signals—commanded output and actual 

output—match extremely well throughout the testing period (with one exception midday on 

April 5). The one period in which the signals do not match closely is because the SOC of the 

system hit zero during that hour (see the dashed line in the figure), and the battery was not able 

to execute this command for the full period. The most likely reason for the VRFB reaching zero 

SOC prior to expected full discharge in the optimization model is that the expected SOC at the 

beginning of operation was 81% but the actual SOC was 71%; therefore, less capacity was

available than the model expected, resulting in a power discharge setting that was higher than 

physically achievable. If we exclude that hour from consideration, the percentage error between 

command and actual output was ~0.2%. 

Figure 74. VRFB dispatch during optimal dispatch

During the hybrid cost-optimal and peak-shaving test period (4 p.m. on April 5 to 4 p.m. on

April 6), the model was constrained to limit feeder load to less than 3,000 kW. It then optimized 

the dispatch schedule to maximize revenue from arbitrage in the LMP market. The results from 

this dispatch are shown in Figure 75. It is clear that the load without the VRFB would have 

reached ~3,400 kW during the late afternoon on April 5, yet with the optimized dispatch the 

feeder load was kept well below that target during those hours and exceeded the target of 3,000

kW by only 89 kW when our forecasting results showed a slightly lower expected feeder 

loading. Note also that the VRFB was dispatched to take advantage of discharging at high LMP 

periods (while observing the feeder peak limit set in the model). 
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Figure 75. Testing results during the hybrid cost-optimal/peak-shaving dispatch

The total revenue during the two days was calculated from the observed data to be $217 (with 

$192 of that resulting from the first 24 hours, without the peak-shaving constraint). The modeled 

revenue expected by the model was $223 during the two days. The results show good agreement 

on both the dispatch of the systems and the achievable revenue generation. 
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7 Conclusions and Remarks

Several possible value streams from a VRFB energy storage system were evaluated in this 

project, with particular focus on local distribution support. Value streams achievable from 

directly participating in bulk energy markets were not considered in this report. Generally, value 

from battery energy storage systems are multifold. The battery applications in this project focus 

on providing distribution system support services as follows:

• Peak shaving: Energy storage charges during low-load periods and discharges during 

high-load periods to reduce the peak demand on the feeder during the highest loading 

condition.

• Capacity firming: The objective of capacity firming is to use storage to smooth the 

output of intermittent renewable energy generation. Storage is able to react quickly to 

compensate for rapid fluctuations in output, resulting in reduced ramping and a more 

consistent, less variable load on the system. 

• Voltage support: Energy storage can also provide voltage support to maintain feeder 

voltages within acceptable bounds, typically ±5% of nominal. For sensitive electric 

appliances and electronics, it is important that voltage is supplied within these limits. 

Utilities typically install capacitor banks or voltage regulators to boost the voltage at the 

end of a line. With power electronics capable of injecting and absorbing both real and 

reactive power at different rates, energy storage is now able to provide the same services.

• Energy arbitrage: Energy storage is charged during off-peak hours and discharged 

during peak hours to take advantage of the price difference in electricity across time 

periods. The revenue obtained is the price differential between buying and selling 

electrical energy minus the cost of losses during the full charge/discharge cycle. 

The economics of using the VRFB system to provide grid support functions was evaluated via a 

combination of OpenDSS simulations and optimizations through a mixed-integer linear program 

using NREL’s REopt model. A novel schematic was developed to assess the value streams from 

utility-scale energy storage with consideration of the specific battery chemistry. 

The quasi-static model of the SDG&E’s TEST FEEDER feeder in OpenDSS was used to 

establish the impact of load growth on the year a transformer or capacitor upgrade is required 

(both with and without the VRFB system). The OpenDSS model was also used to analyze the 

impact of capacity firming on LTC operations and to determine the reactive power requirements 

from the VRFB system to provide voltage support services. 

Inputs to the optimization model included:

• Hourly load profile for one full year of total network load

• Hourly load profile for one full year of loads downstream of the capacity-constrained 

feeder (to determine if a line upgrade to avoid charging limitations during the analysis 

period is cost-effective)

• A full year of historic day-ahead LMP values at the identified node near the distribution

substation (corresponding to the same time period for which load data were provided)
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• Feeder constraints (e.g., export limits)

• Storage system parameters (e.g., minimum SOC, operating limits, efficiency and loss 

characteristics)

• The value of the transformer and capacitor upgrade deferral as well as any O&M savings 

potential (calculated using the OpenDSS outputs)

• Economic parameters and relevant costs. (Key assumptions are summarized in Table 29.)

Table 25. Economic Parameters and Cost Assumptions

Economic Parameters and Costs Assumption

Analysis period 25 years

Discount rate 6%

General inflation 0.1%

Electricity escalation rate 1.5%

Annual load growth 3%

Line upgrade cost $670,000

Transformer upgrade cost $1,497,000

New capacitor bank cost $56,054

The value streams were explored to identify the monetary benefits from a battery. The value 

streams identified by NREL are described in the following sections.

7.1 Peak Shaving

A battery energy storage system capable of reducing peak system loading is assumed to be able 

to offset all or part of an investment toward substation or distribution circuit upgrades. To 

quantify the value of an upgrade deferral, the following information was used:

• System loading level at which an upgrade is required

• Cost of upgrades

• Forecasted load growth on the network (to establish when limits will be met/exceeded 

with and without the storage system).

To capture the value from providing a distribution upgrade deferral, the battery storage system 

must be able to continuously keep the overall network demand less than a predetermined level.

7.2 Capacity Firming 

• Substation capacity firming: Capacity firming can reduce the number of LTC operations 

required at the substation level, resulting in a reduction of O&M costs.

• Renewables capacity firming: Storage coupled with PV can firm highly variable 

generation output. If a capacity market exists, PV production alone might not coincide 

with capacity needs (e.g., when the capacity is called for and/or tested to establish total 
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available capacity). A battery system can be used to firm PV output during critical hours, 

increasing the total capacity payment that a stand-alone PV system can achieve. 

7.3 Voltage Support

The high variability introduced by distributed PV increases the need for flexible reactive power 

support. Additional capacitor banks are required to regulate system voltages. Currently, utilities 

maintain voltages within specified limits using tap changing regulators at the distribution 

substation and by switching capacitors to follow changes in load. This is especially important on

long, radial feeders where a large load such as an arc welder or a residential PV system might

cause unacceptable voltage excursions for neighboring customers. An energy storage system can 

effectively dampen these voltage fluctuations by discharging small amounts of active power.

There is currently no financial compensation for reactive power services in distribution 

networks. One way to account for the increasing demand for flexible reactive power support in 

distribution systems is to replicate the lost opportunity cost model currently used with spinning 

generation at the transmission level.

7.4 Energy Arbitrage 

Energy storage is charged during off-peak hours and discharged during peak hours to take 

advantage of the price difference of electricity across time periods. The revenue obtained is the 

price differential between buying and selling electrical energy minus the cost of losses during the 

full charge/discharge cycle. 

Although market participation is not the focus of the current phase of the project, the value of 

energy arbitrage is modeled to fully capture the economic impacts of battery operation to provide 

other distribution system services. 

7.5 Multiuse

A storage system used for upgrade deferral can simultaneously provide voltage support and 

capacity firming. Value streams might be stacked, with multiple services provided through a 

single asset. The added value provided by this flexibility could be quantified and assigned to the 

battery system as an additional benefit.

7.6 Current System Under Consideration

A portion of the TEST FEEDER feeder between the VRFB and the primary overhead line 

connecting to the substation is capacity constrained (Figure 28). This 1.5-mile #6 overhead cable 

has a maximum rating of 2.25 MVA, and it directly impacts the maximum charging capacity of 

the VRFB system. Because the VRFB system is installed downstream of the capacityconstrained line, the total load from that point of the feeder and lower along with battery 

charging power cannot exceed 2.25 MVA. For example, if the load below the capacityconstrained line is measured at 500 kW, then the battery must charge at or less than 1.75 MW 

(less than its 2-MW total inverter rating).This constraint was considered in the modeling 

approach. Loads less than the capacity-constrained line are continuously monitored to ensure that 

battery charging in optimized dispatches never exceeds line limits unless a line upgrade cost is 

paid. Optimizations are solved with the option to respect charging constraints based on feeder 

load at each time step or pay the upgrade cost and avoid all charging limitations.
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

7.7 Value Streams Monetization Results

The value streams analyzed along with the main optimal dispatch results are shown in. The 

report described how these values were derived and other details of the analysis in Table 26.

Table 26. Summary of the Value Streams Analyzed Along with Key Optimal Dispatch Results

Value Stream Monetization Mechanism Year 1 Savings Life-Cycle Savings

Peak shaving Transformer upgrade deferral – $121,135

Capacity firming O&M savings from reduced LTC 

operations – –

Voltage support New capacitor bank deferral – $7,463

Energy arbitrage Time-shifting energy purchases on 

the LMP market $56,069 $837,115

Total $965,713

7.8 Field-Testing the Battery

At the request of the battery manufacturer, we assisted in operational testing of the VRFB system 

for a one-week period in April 2018. The peak-shaving/base-loading strategy was executed from 

April 2–4, the cost-optimal arbitrage strategy was executed from April 4–5, and the hybrid 

strategy was executed from April 5–6. This testing included three different approaches to 

dispatching the battery:

1. Heuristic peak shaving/base-loading: This strategy selects set points that the VRFB 

attempts to maintain for multiple hours. One set point is selected for peak shaving 

(battery discharging) and is applied during high-load periods of day, and a second set

point is selected for base-loading (battery charging) during low-load periods. This 

strategy requires a load forecast to identify the set points and associated periods of the 

day in which to implement them. A heuristic method was also used to attempt to align the 

set points with high/low LMP hours.

2. Cost-optimal arbitrage: This strategy selects multiple set points throughout the day, with 

a goal of optimizing the revenue that the battery can achieve from the day-ahead LMP 

market. A total of eight distinct power set points—and associated start times—can be 

input to the PCS during a given period. This strategy uses the REopt optimization model 

to select the eight (or fewer) optimal set points to maximize revenue from the day-ahead 

LMP markets. No load forecast is required for this strategy.

3. Hybrid peak shaving and optimal arbitrage: This strategy uses the same PCS control 

strategy as the cost-optimal arbitrage (max of eight power set points), and it optimizes 

revenue from the LMP market while ensuring that the load on the feeder does not exceed 
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a prescribed power limit. This strategy uses the REopt model to select the set points, and

it uses a load forecast to inform the peak-shaving objective. 

To achieve the load prediction, we trained an ANN to predict the feeder load as a function of 

meteorological forecasts. The meteorological forecasts, and the subsequent feeder load forecasts, 

extended through an 18-hour-ahead time horizon at an hourly resolution. The true feeder load 

and the operating state variables of the VRFB were continuously monitored during the week of 

testing to enable comparisons with the expected feeder load obtained from the load forecasts and 

the resultant operational plan.
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References 

Cutler, Dylan, Dan Olis, Emma Elgqvist, Xiangkun Li, Nick Laws, Nick DiOrio, Andy Walker, 

and Kate Anderson. 2017. REopt: A Platform for Energy System Integration and Optimization

(NREL/TP-7A40-70022). Golden, CO: National Renewable Energy Laboratory. 

https://www.nrel.gov/docs/fy17osti/70022.pdf.

Eller, A., and D. Gauntlett. 2017. Energy Storage Trends and Opportunities in Emerging 

Markets. Washington, D.C.: Energy Sector Management Assistance Program and International 

Finance Corporation/World Bank. 

Eyer, J., and G. Corey. 2010. Energy Storage for the Electricity Grid: Benefits and Market 

Potential Assessment Guide. Albuquerque, NM: Sandia National Laboratories. 

Jenkins, John D. 2014. “Capital Workpapers to Prepared Direct Testimony of John D. Jenkins on 

Behalf of San Diego Gas & Electric Company.” November 2014. 

https://www.sdge.com/sites/default/files/SDGE-09-CWP_EDIST.pdf.