U.S. Department of Energy | December 2012 

Table of Contents 

Executive Summary ................................................................................................................. ii
 

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

1.1 Purpose and Scope ....................................................................................................... 1
 

1.2 Background about VVO ................................................................................................ 2
 

1.3 Organization of this Report .......................................................................................... 2
 

2. Devices, Systems, and Expected Benefits.......................................................................... 4
 

2.1 Voltage Support and Reactive Power Compensation .................................................. 4
 

2.2 Automated Controls....................................................................................................... 8
 

2.3 Expected Benefits ....................................................................................................... 11
 

3. SGIG VVO Projects and Deployment Progress................................................................. 15
 

3.1 SGIG VVO Project Objectives...................................................................................... 17
 

3.2 Deployment of VVO Devices and Systems ................................................................. 18
 

3.3 Project Examples ........................................................................................................ 19
 

4. Analysis of Initial Results................................................................................................ 23
 

4.1 Capacitor Bank Switching ........................................................................................... 24
 

4.2 Line Loss Reductions................................................................................................... 24
 

5. Next Steps ...................................................................................................................... 30
 

Appendix A. Reactive Power Compensation and Line Losses ...............................................A-1
 

Appendix B. SGIG VVO Projects..............................................................................................B-1
 

Voltage and Reactive Power Management – Initial Results Page i 
 

 

 

 

U.S. Department of Energy | December 2012 

Executive Summary 

The U.S. Department of Energy (DOE), Office of Electricity Delivery and Energy Reliability (OE), is 

implementing the Smart Grid Investment Grant (SGIG) program under the American Recovery 

and Reinvestment Act of 2009. The SGIG program involves 99 projects that are deploying smart 

grid technologies, tools, and techniques for electric transmission, distribution, advanced 

metering, and customer systems.1 

Of the 99 SGIG projects, 26 are implementing advanced voltage and volt-ampere reactive (VAR) 

optimization (VVO) technologies to improve electric distribution system operations. Advanced 

VVO is made possible through recent improvements in sensors, communications, control 

algorithms, and information processing technologies that for monitor voltage levels throughout 

the distribution system. This information is sent to devices that can adjust voltage regulating 

equipment and capacitor banks on distribution feeders in near‐real time enabling quick 

adjustments in response to constantly changing load and voltage conditions. Adjustments to 

individual devices and systems can also be coordinated so that voltage levels can be optimized 

along feeder lines. 

The 26 SGIG VVO projects are pursuing these strategies to achieve one or more of the following 

objectives: (1) lowering voltage levels during peak periods to achieve peak demand reductions, 

(2) lowering voltage levels for longer periods to achieve electricity conservation, and (3) 

reducing energy losses over feeders. Generally speaking, utilities applying VVO technologies 

expect to see 1% reductions in electricity consumption for every 1% reduction in voltage levels. 

Achieving these VVO objectives results in the following benefits: 

Deferred capital expenditures and improved capital asset utilization 

Reduced electricity generation and environmental impacts 

More efficient utility operations, greater flexibility to address resiliency, and more 

opportunities to keep rates affordable 

Analysis of Initial Results 

Most of the SGIG VVO projects are in the early stages of implementation and have not finished 

deploying, testing, and integrating the smart grid devices and systems. However, 8 of the 26 

SGIG projects implementing VVO have reported hourly load data for 31 feeders during the 

1 For further information, see the Smart Grid Investment Grant Program Progress Report, July 2012, found at 

www.smartgrid.gov. 

Voltage and Reactive Power Management – Initial Results Page ii 
 

 

 

U.S. Department of Energy | December 2012 

periods April 2011 to September 2011 (summer) and October 2011 to March 2012 (winter). 

Analysis focused on the automated switching of capacitor banks and the impacts of that 

switching on reactive power compensation and subsequent reductions in line losses. In 

addition, two VVO projects seeking to conserve energy during peak periods (conservation 

voltage reduction for peak) reported initial results. 

Observations from the analysis of these initial results and the efforts being undertaken by these 

projects include: 

For the 31 feeders for which projects have reported hourly load data, one-half are 

witnessing line loss reductions in the range of 0% to 5%, and 5 feeders experienced loss 

reductions greater than 5%. These results are in the range of other industry estimates 

which indicate that line loss reductions of 5%-10% are possible. 

In general, feeders with the worst baseline power factors (i.e., those with the highest 

amount of inductive loads) showed the greatest reductions in line losses. Many of the 

utilities are targeting their worst performing feeders. However, overcompensation for 

reactive power was observed in the remaining feeders, which resulted in line loss 

increases. In these cases, capacitor banks were often operated for voltage support 

rather than reactive power compensation. 

The initial results for conservation voltage reductions indicate a potential for peak 

demand reductions of approximately 1% to 2.5%. This is consistent with the 

expectations of the projects and results from other studies in the literature. There are 

no results yet from the SGIG VVO projects on conservation voltage reductions for longer 

periods to achieve electricity conservation. In comparison to energy savings attributable 

to line loss reductions, conservation voltage reduction practices have a greater impact 

on reducing energy requirements. 

Next Steps 

So far, most of the initial results reported by the SGIG VVO projects are focused on automated 

capacitor switching and its potential impacts on line loss reductions. Two projects have also 

reported initial results for conserving energy during peak periods. Future SGIG VVO analysis 

reports will continue to present the various approaches used to optimize voltage and reactive 

power levels in distribution feeders, as well as the benefits they will provide to utilities and 

customers. 

Voltage and Reactive Power Management – Initial Results Page iii 
 

 

 

 

U.S. Department of Energy | December 2012 

1. Introduction 

The U.S. Department of Energy (DOE), Office of Electricity Delivery and Energy Reliability (OE), is 

implementing the Smart Grid Investment Grant (SGIG) program under the American Recovery 

and Reinvestment Act of 2009. The SGIG program involves 99 projects that are deploying smart 

grid technologies, tools, and techniques for electric transmission, distribution, advanced 

metering, and customer systems. DOE-OE recently published the Smart Grid Investment Grant 

Program Progress Report (July 2012) to provide information about the deployment status of 

SGIG technologies and systems, examples of some of the key lessons learned, and initial 

accomplishments.2 

DOE-OE is analyzing the impacts, costs, and benefits of the SGIG projects and is presenting the 

results through a series of impact analysis reports. These reports cover a variety of topics, 

including: 

Peak demand and electricity consumption reductions from advanced metering 

infrastructure, customer systems, and time-based rate programs 

Operational improvements from advanced metering infrastructure 

Reliability improvements from automating distribution systems 

Energy efficiency improvements from advanced volt/volt-ampere reactive (VAR) 

controls in distribution systems 

Efficiency and reliability improvements from applications of synchrophasor technologies 

in electric transmission systems 

1.1 Purpose and Scope 

This impact analysis report presents information on the 26 SGIG projects that are installing 

devices and systems for voltage and volt-ampere reactive (VAR) optimization (VVO), the types 

of devices and systems being deployed, and deployment progress to achieve one or more of 

the following objectives: (1) lowering distribution voltage levels during peak periods to achieve 

peak demand reductions, (2) reducing voltage levels for longer periods to achieve electricity 

conservation, and (3) reducing energy losses in the electric distribution system. Expected 

benefits include deferral of capital expenditures, energy savings, and greater operational 

flexibility and efficiency. 

2 DOE-OE, Smart Grid Investment Grant Program Progress Report, July 2012, www.smartgrid.gov. 

Voltage and Reactive Power Management – Initial Results Page 1 
 

 

 

 

 

 

 

 

 

U.S. Department of Energy | December 2012 

The SGIG VVO projects are in the early stages of implementation and have not finished 

deploying, testing, and integrating the smart grid devices and systems. However, 8 of the 26 

SGIG VVO projects have reported hourly feeder load data covering the periods of April 2011 to 

September 2011 (summer) and October 2011 to March 2012 (winter). Initial results from these 

8 projects are presented, in addition to initial results from 2 projects applying techniques for 

conservation voltage reduction. The report also discusses how smart grid technologies can help 

optimize voltage profiles on distribution feeders. 

1.2 Background about VVO 

Maintaining proper voltage levels throughout the electric distribution system is one of the most 

important challenges utilities face. 3 Customer demands for electricity change throughout the 

day, which means the power and voltage levels flowing through distribution systems increase 

and decrease throughout the day to meet changing loads. For decades, utilities have used 

voltage regulating equipment and capacitor banks to keep customer voltages within a desired 

range to meet demand. While this equipment works properly, utilities have known that 

performance could be improved if the equipment could also track loads and voltages more 

closely, and be operated to respond when those levels change. 

Recent advances in sensors, communications, and information processing and control 

technologies have made it possible to monitor voltages throughout the distribution system and 

report that information to devices that can adjust voltage regulating equipment and capacitor 

banks. This information is available in near-real time, enabling these technologies to make 

adjustments quickly in response to constantly changing load and voltage conditions. In addition, 

adjustments to individual devices and systems can be coordinated by distribution management 

systems and other techniques so that they can be optimized in a comprehensive manner. This is 

the goal of VVO to make quick adjustments to voltage and reactive power levels within 

distribution circuits to address system needs. 

1.3 Organization of this Report 

Section 2 of this report provides information on the types of devices and systems being 

deployed by the SGIG VVO projects and their expected benefits. Section 3 describes the status 

of deployment, including details about the specific VVO objectives the projects are trying to 

achieve. Section 4 provides a summary of the DOE-OE analysis of the 10 VVO projects that 

reported initial results. Section 5 discusses next steps for DOE-OE analysis of the SGIG electric 

distribution reliability projects. 

3 ANSI standard C84.1 specifies that the voltage provided to customers should be between 114 volts and 126 volts. 

Voltage and Reactive Power Management – Initial Results Page 2 
 

 

U.S. Department of Energy | December 2012 

Two appendices provide supplementary information. Appendix A provides technical 

background information on the relationship between reactive power compensation and line 

loss reductions. Appendix B provides a table of the SGIG VVO projects and includes the types of 

technologies they are deploying and their respective objectives for improving energy efficiency 

and system flexibility. 

Voltage and Reactive Power Management – Initial Results Page 3 
 

 

 

 

U.S. Department of Energy | December 2012 

2. Devices, Systems, and Expected Benefits 

There are approximately 160,000 distribution feeders that deliver electricity to customers in 

the United States.4 These distribution feeders vary with respect to the number of customers 

they serve, how they are configured (radial, looped, or networked), and what strategies are 

employed to maintain and control voltage and power levels. 

Capacitors, voltage regulators and transformer load tap changers have traditionally been used 

for many years for voltage support and reactive power compensation on distribution feeders. 

However, new technologies, tools, and techniques are now available for accomplishing 

intelligent control of the existing equipment. Devices and systems such as sensors, 

communications systems, distribution management systems, and automated control packages 

enable intelligent control. When successfully implemented, these new capabilities provide 

benefits to utilities and customers. 

2.1 Voltage Support and Reactive Power Compensation 

Voltage levels drop along the length of the feeder lines due to electrical impedance, as shown 

in Figure 1. The amount that voltages drop depends on several factors, including the level of the 

load on the feeder and the distance of the load from the power source. 

Table 1 summarizes the three types of equipment commonly used by utilities to keep voltage 

levels in the proper range along feeders. Load tap changers (LTCs) can increase or decrease 

voltage levels on transformers at substations. As feeder loads increase, LTCs can increase 

voltage levels to account for the larger voltage drop along the feeder caused by the higher load. 

Voltage regulators can also increase or decrease voltage levels and can be installed at 

substations or along distribution feeders. Like LTCs, voltage regulators adjust voltages as load 

changes. Capacitor banks installed along distribution feeders can increase voltage levels and 

compensate for reactive power to serve nearby inductive loads. 

Load Tap Changers and Voltage Regulators 

The electric grid is principally an alternating current (AC) system. A key advantage of AC is the 

ability to increase or decrease voltage levels with transformers. LTCs and voltage regulators are 

types of transformers. LTCs are devices on substation transformers used to raise or lower 

voltage outputs. Voltage regulators are devices that adjust voltage levels in response to 

4 Navigant onsulting Inc., “!ssessment of the Total Number of Distribution ircuits in the United States,” !nalysis 

Memorandum to the U.S. Department of Energy, June, 2012. 

Voltage and Reactive Power Management – Initial Results Page 4 
 

 

 

U.S. Department of Energy | December 2012 

Equipment Grid Locations Grid Functions 

Load tap 

changers 

Substation 

transformers 

Adjusts feeder voltages 

at the substation 

Voltage 

regulators 

Distribution 

feeders or 

substations 

Adjusts voltages at the 

substation or along the 

feeder 

Capacitor 

banks 

Distribution 

feeders or 

substations 

Compensates for 

reactive power and 

provides voltage 

support 

Table 1. Equipment for Voltage Support and Reactive Power Control 

changes in load. Voltage regulators are typically installed along distribution feeders to regulate 

voltage farther from the substation. 

On distribution feeders, as load increases, the amount voltages drop also increases. LTCs and 

voltage regulators make small adjustments to voltage as load changes. A voltage regulator on 

the feeder would detect that the voltage had decreased below its target level and step up to 

increase the voltage to return it to the desired range. LTCs and voltage regulators have multiple 

“raise” and “lower” positions and can adjust voltages automatically according to how they are 

configured. 

Figure 1 and Figure 2 illustrate the effects of LTCs and voltage regulators on a hypothetical 

distribution feeder voltage profile. In Figure 1, the LTC can adjust the voltage at the head of the 

feeder to keep the profile within the acceptable voltage range. 

Figure 2 shows how a voltage regulator placed mid-way along a feeder adds a control point to 

raise or lower the downstream voltage levels. The figure also shows that a voltage profile within a 

feeder can be effectively lowered, or flattened (see the dashed lines), by conservation voltage 

reduction (CVR) practices such that the range of voltage variation along the feeder is reduced. 

Voltage and Reactive Power Management – Initial Results Page 5 
 

S/S

2 3 4 5 6 7

Customer 

Loads

1

LTC M

126V

114V

120V

127V

110V

Transformer 

Load Tap 

Changer

ANSI Standard

Voltage Range

Hypothetical voltage profile

S/S

2 3 4 5 6 7

Customer 

Loads 1

LTC M

126V

114V

120V

127V

110V

Reg

Baseline Regulator Regulator + CVR

Line Voltage Regulator

The utility can use better voltage 

control to keep voltage closer to 

nominal, or lower it for a CVR effect.

U.S. Department of Energy | December 2012 

Figure 1. Hypothetical Feeder Voltage Profile with an LTC 

Figure 2. Hypothetical Feeder Voltage Profile with an LTC and Voltage Regulator 

Capacitors 

Utilities use capacitors to compensate for reactive power caused by inductive loads. Inductive 

loads involve equipment such as motors whose operation depends on magnetic fields. Using 

capacitors to compensate for reactive power reduces the total amount of power that needs to 

be provided by power plants. The end result is a flatter voltage profile along the feeder, and 

Voltage and Reactive Power Management – Initial Results Page 6 
 

 

 

 

 

S/S

2 3 4 5 6 7

Customer 

Loads 1

LTC M

126V

114V

120V

127V

110V

Reg

Baseline Reg + Cap Reg + Cap + CVR

Cap

Capacitor Bank

Coordination of multiple control 

devices can produce a flatter voltage 

profile, and allow more aggressive CVR.

U.S. Department of Energy | December 2012 

less energy wasted from electrical losses in the feeder. Appendix A provides a detailed 

discussion of the relationship between reactive power compensation and line losses. 

A distribution capacitor bank consists of a group of capacitors connected together. The capacity 

of the bank depends on the number of capacitors, and typically ranges from 300 kVAR to 1800 

kVAR.5 Capacitor banks are mounted on substation structures, on distribution poles, or in 

enclosures (“pad-mounted”).

Capacitor banks are either fixed or switched. Fixed banks are sized to compensate for relatively 

constant amounts of reactive load. Switched banks can be turned on or off as load and voltage 

conditions change. Switching frequencies depend on how often conditions change. Because the 

capacitors in the bank are normally switched as a group, reactive power and voltage levels 

change together in a single step. Typically, utility engineers specify the size of the bank so that 

switching the bank will not cause voltage to rise too high or fall too low. The voltage stepchange that results from switching capacitor banks can be large compared to the smaller 

changes created by LTCs or voltage regulators. As a result, capacitor banks are not applied as 

much for voltage control as they are for voltage support. 

Figure 3 shows how a capacitor bank placed along a feeder supports voltage. The combined 

effect of the three types of equipment is to help utilities keep overall profiles closer to desired 

levels under a variety of load conditions. 

Figure 3. Feeder Voltage Profile with LTC, Voltage Regulator and Capacitor Bank 

5 The unit of measurement for reactive power is kilovolt-ampere reactive (kVAR). 

Voltage and Reactive Power Management – Initial Results Page 7 
 

 

 

 

U.S. Department of Energy | December 2012 

2.2 Automated Controls 

For many years, engineers designed the electric distribution system to serve customers over a 

wide range of expected load conditions. The size and placement of LTCs, voltage regulators, and 

capacitors were typically based on off-line modeling of peak- and light-load conditions, and 

operating experience. Historically, most utilities have not actively monitored loads and voltages 

along distribution feeders beyond the substation. For the last several decades, supervisory 

control and data acquisition (SCADA) systems have been used by many utilities for distribution 

system monitoring, but these reach only substations and do not monitor feeder conditions 

from substations to customers. The lack of operating visibility on distribution feeders has 

required utilities to design and operate their systems in a relatively conservative manner, often 

manually, to accommodate worst case scenarios. There has been little opportunity to optimize 

voltage and reactive power levels for constantly changing load conditions. 

Centralized and Decentralized Controls 

Utilities are applying both centralized and decentralized control schemes to enable VVO. 

Figure 4 provides a schematic that summarizes some of the differences between these two 

approaches. 

In general, centralized control involves a centrally located computer and SCADA or other 

communication networks to coordinate automated equipment operations among multiple 

feeders. In contrast, decentralized controls use local control packages to operate equipment on 

a single feeder, or on a relatively small numbers of feeders according to pre-established logic 

schemes. Many projects use a combination of centralized and decentralized approaches, 

depending on feeder characteristics and VVO objectives. 

The two types of approaches can vary on the amount of time it takes to accomplish VVO 

actions. For example, centralized systems can account for more factors when determining 

control strategies but may take longer to execute the strategies than do decentralized systems. 

However, centralized systems can deal with a broader spectrum of system conditions and thus 

can be more flexible than decentralized systems. This includes better integration with 

transmission providers. 

Communications Systems 

Communications systems connect sensors to information processors (e.g., a distribution 

management system [DMS]), and connect information processors to the control devices that 

regulate voltage and power factor. Most power companies use a two-layer system to support 

communications between the DMS and control devices. The first layer, which connects the 

Voltage and Reactive Power Management – Initial Results Page 8 
 

 

 

 

 

U.S. Department of Energy | December 2012 

Feeder 1

DMS with central logic

LTC

control

Voltage 

regulator 

control

Capacitor 

control

Feeder 2

LTC

control

Voltage 

regulator 

control

Capacitor 

control

Feeder 1

Local logic

LTC

control

Local logic Local logic

Voltage 

regulator 

control

Capacitor 

control

Feeder 2

Local logic

LTC

control

Local logic Local logic

Voltage 

regulator 

control

Capacitor 

control

Centralized automation Decentralized automation

Figure 4. Centralized and Decentralized Controls 

DMS to utility substations, consists of high-speed fiber optic or microwave communications 

systems. Some utilities utilize existing SCADA communications networks for this layer. Wireless 

technology is commonly used for the second layer connecting substations to VVO devices. 

The expansion of communications networks to connect VVO devices to SCADA and DMS, and to 

each other, increases the ability of power companies to manage voltages and other aspects of 

distribution system operations. Communications architectures are being designed to 

accommodate future growth and the broader use of sensing and control capabilities, including 

those used for feeder switching and smart meter operations. 

Distribution Management Systems 

Some utilities are deploying a central computer and software to analyze distribution power flow 

data and make decisions about switching capacitor banks and adjusting load tap changer and 

voltage regulator set points.6 Such a DMS typically uses an electrical model of the distribution 

system, SCADA information, and data from other control packages to predict how distribution 

systems will respond to certain control actions. 

After calculating the best control actions, the DMS implements its decision by sending 

commands to the control packages to adjust the capacitors, load tap changers, and voltage 

6 Distribution management systems are also used for automated feeder switching, fault identification, and equipment health 

monitoring. 

Voltage and Reactive Power Management – Initial Results Page 9 
             

                 

                                 

                           

                          

     

                         

                     

                         

                   

       

                           

                           

                             

                           

                         

                               

   

   

                       

                             

                             

                       

                         

                             

                

                             

                       

                         

                               

         

 

                                     

        

U.S. Department of Energy | December 2012

regulators. The result is that the DMS can operate a group of VVO devices in a coordinated

fashion to achieve specific performance objectives in the set of distribution circuits it controls,

for example, reducing demand during a system peak by lowering distribution voltage levels.

Automated Control Packages

Automated control packages integrate the control of field devices with user interfaces and

communications systems. New voltage regulators and capacitor banks equipped with these

controls are available, and retrofitting new control packages on existing equipment is also

common. Interoperability of automated controls with existing equipment is an important

concern for utilities considering deployment.

Automated control packages use data from sensors to determine voltage and current on the

distribution line.7 Controllers can be programmed to switch capacitors in or out of service

automatically, depending on the voltage level and power factor, or in response to a command

from an operator or other control system. Controllers may also use more complex software

algorithms to coordinate its operation with other devices or systems to perform different

operations. The control software may be built into the controller itself, or may reside in a

central computer.

Voltage Sensors

Voltage sensors provide engineers and grid operators with voltage information from virtually

any part of the distribution system, including customer premises. This makes it possible to see

voltage profiles on distribution feeders and the changes made by VVO equipment. In the past,

utility engineers might only obtain actual voltage and load information along feeders

infrequently by making manual measurements in the field. Knowledge of low voltage points,

often at the end of the feeder, will allow utilities to operate distribution feeders less

conservatively and regulate voltage closer to design specifications.

Two types of voltage sensors are commonly used: (1) dedicated voltage sensors located on the

primary distribution system (e.g., pole‐mounted), and (2) voltage sensors built into smart

meters. A communications network is required to collect data from stand‐alone sensors. This

data is sent to another device or system for processing. Voltage sensors may also be connected

directly to automated control packages.

7 Some controls use voltage information only. Controls that use power factor information must also have a current sensor,

which increases the cost.

Voltage and Reactive Power Management – Initial Results Page 10
 

 

 

 

U.S. Department of Energy | December 2012 

2.3 Expected Benefits 

The VVO operations provide utilities with enhanced capabilities compared to traditional 

approaches. Expected benefits include optimization of voltage profiles to address changing 

system conditions, energy conservation, and reduced costs for operations and maintenance. 

Table 2 provides a summary of expected VVO impacts and benefits. 

Improvement Area Impacts Primary Benefits 

Better voltage 

Lower real power (MW) 

peak demand from CVR 

Reduce capacity payments 

and/or defer capacity 

additions/upgrades 

control 

Lower real power (MWh) 

consumption from CVR 

Reduce fuel consumption 

with lower greenhouse gas 

and polluting emissions 

Better VAR control 

Lower reactive power 

(MVAR) peak demand 

Reduce capacity payments 

and/or defer capacity 

additions/upgrades 

Lower line losses (MW) 

Reduce fuel consumption 

and environmental 

emissions 

Better operations 

and maintenance Fewer service trips Reduce O&M cost and vehicle emissions 

Better integration 

of distributed 

energy resources 

Acceptable voltage profiles 

over a wider range of 

generation and load 

conditions 

Less expensive distribution 

system upgrades 

Table 2. Summary of Impacts and Benefits 

Improved Voltage Control 

Coordinated VVO devices and systems enable utilities to more precisely control voltage and 

reactive power levels when and where they want. Operators can execute control decisions with 

more confidence, knowing that they will be alerted if customer voltages exceed limits. Since 

customer loads change constantly, VVO operations can respond and quickly adjust voltages to 

keep them closer to optimum levels, including flattening voltage profiles along feeders, when it 

is advantageous to do so. 

Voltage and Reactive Power Management – Initial Results Page 11 
 

 

 

 

 

 

 

 

 

 

 

U.S. Department of Energy | December 2012 

Conservation voltage reduction (CVR) is an operational strategy designed to reduce the energy 

used by customer appliances and equipment by reducing distribution feeder voltages. While 

utilities have known about CVR for a long time, the inability to observe voltage levels along the 

length of distribution feeders has limited its use. The improved visibility and control provided 

by VVO is prompting more utilities to consider using CVR as a way to achieve peak demand 

reduction and energy conservation. 

Reducing feeder voltage reduces energy consumption proportionately. The proportionality 

constant, shown in Equation 1, is called the “VR factor.” ! VRf of 1 indicates that a 1% 

reduction in voltage corresponds to a 1% reduction in energy consumption. 

∆E(%) CVRf = 

∆V(%) 

Equation 1. CVR factor 

The CVR factor depends on the type of load connected to the feeder. Studies conducted by 

utilities in different parts of the country have shown that CVR factors between about 0.7 and 

1.0 are common.8 

Peak demand reduction 

Utilities can apply CVR for short periods of time to reduce peak demand. This can be valuable 

for deferring capacity additions and distribution upgrades. One utility attempting to reduce 

peak demand with a distribution energy efficiency project estimated a potential demand 

reduction of 200 MW if implemented on its over 560 distribution feeders.9 Another example is 

a utility implementing capacitor controls and an integrated VVO model aimed at reducing both 

line losses and peak demand. Deployment of advanced VVO on 400 circuits is anticipated to 

reduce peak demand by about 75 MW. Pilot testing on four circuits has produced peak demand 

reductions between 0.8% and 2.4%.10 Reductions on this scale are significant; a 200 MW 

reduction is similar in size to a large peaking power plant. 

CVR can also help reduce capacity payments for those distribution companies that are billed on 

the basis of their maximum monthly peak demand. This could be especially valuable to smaller 

electric cooperatives and public power utilities that purchase wholesale power with a capacity 

8 "Voltage Optimization More than Pays for Itself," Transmission & Distribution World, August 1, 2010. 

9 "Can a Grid be Smart without Communications? A look at an Integrated Volt VAR Control (IVVC) Implementation," Barry 

Stephens, Georgia Power, Bob McFetridge, Beckwith Electric, April 25, 2012. 

10 "Ventyx Launches Network Manager DMS v5.3 With Model-Based Volt/VAR Optimization," Ventyx, December 5, 2011. 

Voltage and Reactive Power Management – Initial Results Page 12 
 

 

 

 

U.S. Department of Energy | December 2012 

charge. These utilities could reduce their annual capacity-rated costs even if CVR were applied 

for only a few hours per year. 

Electricity conservation 

Utilities can use CVR for longer periods of time to conserve electric energy. This reduces the 

amount of fuel required to produce electricity, along with the associated cost and 

environmental impacts of power plants. In a recent utility study, VVO capabilities were 

deployed on eleven feeders at five substations for a 60-day evaluation. Ten of the eleven 

feeders showed lower energy consumption, with an average reduction of 2.9%. Over thirty 

operating days, CVR saved 251 MWh of electricity in total over the eleven feeders. Three 

feeders contributed 83% of the savings, with a reduction in energy consumption of 7% on one 

feeder.11 

Since CVR reduces the energy consumed by connected appliances and equipment, customers 

use less electricity and have lower bills. This results in losses of revenues for utilities. One of the 

reasons that CVR is not commonly used is because many utilities cannot earn rates of return on 

lost revenues. In addition, gaining regulatory approvals for CVR investments also needs to be 

examined. 

Improved VAR Control 

As discussed, compensating for reactive power from inductive loads using switched capacitors 

improves power factor and reduces line losses. This saves energy and the fuel required to 

produce electricity to serve customers. Overall, line losses in distribution feeder lines range 

from 5%-13%12 of the electricity produced to serve customers. A fraction of the line losses may 

be saved by improving power factor. For example, an overall savings of 0.04% to 0.2% of total 

electricity generation can be achieved with line loss reductions of 1% to 5% where utilities can 

correct for power factor. VVO can help improve power factor, while optimizing voltage profiles 

for better power quality and reliability. 

Improved Operations and Maintenance 

Adding automation to capacitor banks, LTCs and voltage regulators can reduce operations and 

maintenance (O&M) costs. Without automation a service worker must travel to a capacitor 

bank to physically operate the switch or check on the health of a voltage regulator. This can 

take hours and require many miles of driving if the equipment is far away from a service center, 

11 K.P. Schneider and T.F. Weaver "Volt-VAR Optimization on American Electric Power Feeders in Northeast Columbus." 

12 Wagner, T.P., Chikhani, A.Y., Hackam, R. Feeder Reconfiguration for Loss Reduction: An Application of Distribution 

Automation. IEEE Transactions on Power Delivery, Vol. 6, No. 4, October 1991. 

Voltage and Reactive Power Management – Initial Results Page 13 
 

 

 

U.S. Department of Energy | December 2012 

increasing both time and fuel costs. Automation can also provide operators and engineers with 

important status and condition information for maintenance. For example, one SGIG project 

recently reported failure rates of 20% on some of their capacitor banks.13 Failures went 

undetected until a technician was sent to adjust the switch on the bank. Automation can notify 

operators of blown fuses or other maintenance requirements, saving time, money and vehicle 

miles. 

Improved Integration of Distributed Energy Resources 

Integrating renewable and distributed energy sources and electric vehicles into the grid 

presents new challenges for grid planners and operators. VVO enables control of voltage 

profiles along distribution feeder lines and helps with the grid integration of renewable energy 

systems, distributed generation and storage, and electric vehicles. 

13 Avista Corp., "Spokane Smart Circuit" Smart Grid Investment Grant Proposal, August 11, 2009. 

Voltage and Reactive Power Management – Initial Results Page 14 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Department of Energy | December 2012 

3. SGIG VVO Projects and Deployment Progress 

Table 3 provides a list of the 26 SGIG projects that are deploying various VVO technologies, 

tools, and techniques. The projects include a range of types and sizes of utilities from across the 

country and provide a representative sample for analysis of the impacts of VVO operations. 

Electric Cooperatives 

Northern Virginia Electric 

Cooperative, Virginia 

Rappahannock Electric 

Cooperative, Virginia 

Talquin Electric Cooperative, 

Inc., Florida 

Public Power Utilities 

City of Auburn, Indiana 

City of Wadsworth, Ohio 

EPB, Tennessee 

Knoxville Utilities Board 

Modesto Irrigation District, 

California 

Public Utility District No. 1 of 

Snohomish County, 

Washington 

Sacramento Municipal 

Utility District, California 

Investor-Owned Utilities 

Avista Utilities, Washington 

Consolidated Edison Company of 

New York, Inc., New York 

Duke Energy Carolinas, LLC, 

North Carolina, South Carolina 

FirstEnergy Service Company, 

New Jersey, Ohio, Pennsylvania 

Florida Power & Light Company, 

Florida 

Indianapolis Power and Light 

Company, Indiana 

NSTAR Electric Company, 

Massachusetts 

Oklahoma Gas and Electric, 

Oklahoma 

PECO, Pennsylvania 

Investor-Owned Utilities (cont.) 

Potomac Electric Power Company –

Atlantic City Electric Company, 

New Jersey 

PPL Electric Utilities Corporation, 

Pennsylvania 

Progress Energy Service Company, 

Florida, North Carolina 

Southern Company Services, Inc., 

Alabama, Georgia, Louisiana, 

Mississippi 

Sioux Valley Southwestern Electric 

Cooperative Inc., Minnesota, South 

Dakota 

Vermont Transco, LLC, Vermont 

Wisconsin Power and Light Company, 

Wisconsin 

Table 3. SGIG VVO Projects 

Table 4 describes the different VVO devices and systems being deployed by the 26 SGIG VVO 

projects. As shown, most are installing capacitor banks with automation controls, or are 

retrofitting existing capacitor banks with control packages. Many projects are also automating 

voltage regulators or transformer load tap changers to work in conjunction with the automated 

capacitors. Some projects plan to coordinate the operation of this equipment using DMS or 

other forms of control algorithms. 

Voltage and Reactive Power Management – Initial Results Page 15 
             

                 

           

     

            

       

   

              

         

     

            

         

     

     

          

     

           

     

       

   

   

     

           

         

            

       

   

     

   

     

   

     

     

            

             

             

                                 

                           

             

 

                                   

         

U.S. Department of Energy | December 2012

SGIG Project

Objectives VVO Devices Voltage Sensors

CVR for

Peak

CVR for

Energy

Reduce

Losses Capacitors LTCs orRegulators

Coordination

Operations14

VVO

Controller

Line

Sensor

Smart

Meter

Avista Utilities      

City of Auburn, Indiana  

City of Wadsworth, Ohio         

Consolidated Edison

Company of New York, Inc.      

Duke Energy Carolinas, LLC      

EPB       

FirstEnergy Service

Corporation      

Florida Power & Light

Company    

Indianapolis Power & Light

Company       

Knoxville Utilities Board      

Modesto Irrigation District       

Northern Virginia Electric

Cooperative     

NSTAR Electric Company     

Oklahoma Gas & Electric       

PECO         

Potomac Electric Power

Company – Atlantic City

Electric Company

   

PPL Electric Utilities

Corporation      

Progress Energy Service

Company     

Public Utility District No. 1

of Snohomish County  

Rappahannock Electric

Cooperative   

Southern Company

Services, Inc.      

Sacramento Municipal

Utility District       

Sioux Valley Southwestern

Electric Cooperative Inc.    

Talquin Electric

Cooperative     

Wisconsin Power and Light   

Vermont Transco, LLC    

Totals 11 7 16 20 19 21 22 10 9

Note: Regulation devices include transformer load tap changers and voltage regulators at the substation or along the

distribution feeder. A dedicated smart meter may be used as a line voltage sensor.

Table 4. Summary of SGIG VVO Projects

14 Coordinated operation may be accomplished with centralized automation using a DMS or similar system with central logic, or

with decentralized automation using local logic.

Voltage and Reactive Power Management – Initial Results Page 16
 

 

 

 

 

 

U.S. Department of Energy | December 2012 

Figure 5 provides an update on deployment progress and shows the number of automated 

capacitors and voltage regulators that have been installed and were operational as of June 30, 

2012. This represents approximately 50% and 51%, respectively, of the total numbers of these 

devices expected at completion of the SGIG program. 

Figure 5. Numbers of Automated Capacitors and Voltage Regulators Deployed 

as of June 30, 2012 

3.1 SGIG VVO Project Objectives 

All of the SGIG VVO projects are interested in improving power factors and flattening voltage 

profiles on their distribution feeders. Better management of voltage on the distribution system 

presents opportunities to improve operations and electric service quality for customers. The 

primary objectives for the SGIG VVO projects generally fall into three main categories: 

Reduce peak demand (CVR for Peak)
 

Reduce electricity consumption (CVR for Energy)
 

Reduce distribution line losses
 

Some recipients are focused on only one objective, while others aim for multiple objectives. 

Figure 6 shows the number of projects that are pursuing each of the three primary VVO 

objectives. 

Voltage and Reactive Power Management – Initial Results Page 17 
 

 

 

 

 

U.S. Department of Energy | December 2012 

Figure 6. SGIG VVO Projects by Type of Objective 

3.2 Deployment of VVO Devices and Systems 

The SGIG VVO projects are deploying three types of VVO devices and systems for controlling 

voltage levels and power factors: 

Automated voltage regulators (including load tap changers) 

Automated capacitor banks 

Distribution management systems or other types of coordination algorithms 

Figure 7 shows the number of projects deploying the various types of VVO devices and systems. 

Voltage monitors and sensors deployed along distribution feeders communicate voltage 

information to control equipment, and are an enabling capability for VVO operations. In many 

cases, the control packages installed on capacitor banks and voltage regulation equipment 

include voltage sensors that monitor voltage levels at that device. In some cases, line voltage 

sensors are being installed independently on feeders. Several of the projects are also using 

voltage information provided by smart meters. 

Voltage and Reactive Power Management – Initial Results Page 18 
 

 

 

U.S. Department of Energy | December 2012 

Figure 7. SGIG VVO Projects by Type of Devices and Systems 

3.3 Project Examples 

The SGIG VVO projects are pursuing objectives using a variety of devices and systems. To 

provide a better understanding of what the projects are doing and why, this subsection 

presents three examples. 

Avista 

!vista’s VV project coordinates substation voltage regulators and line capacitor banks using a 

DMS. The objective is to flatten voltage profiles on distribution feeders in order to safely lower 

the voltage levels and achieve energy savings with CVR. Avista also expects to reduce line losses 

by improving feeder power factor. Figure 8 shows !vista’s equipment configuration. 

Figure 8. Avista's VVO Configuration 

The DMS collects voltage information by polling voltage regulators and capacitor banks through 

SCADA RTUs at each substation. The DMS is connected to the SCADA RTUs by a new or existing 

Voltage and Reactive Power Management – Initial Results Page 19 
 

 

 

 

 

 

 

 

 

 

U.S. Department of Energy | December 2012 

fiber optic backhaul network. When appropriate, the DMS can send control signals to the 

voltage regulator to lower baseline voltage at the substation and switch in capacitor banks on 

the feeder as load increases. If switching a capacitor causes voltage levels to rise too much, the 

substation voltage regulator lowers the voltage to compensate. 

The Avista DMS includes an Integrated Voltage and VAR Control (IVVC) algorithm that 

automatically monitors and controls individual capacitor banks to minimize feeder losses while 

maintaining voltages and power factor within specified limits. The DMS estimates the feeder 

loads to calculate voltage, branch flows, and power factor. The capacitor banks are sorted 

according to the reactive load they detect, and the capacitor seeing the highest reactive load 

becomes the switching candidate. The DMS checks the capacitor banks on each feeder and 

prioritizes the “OFF” capacitors according to the reactive loads they detect. If switching can be 

done without violating a voltage limit, the capacitor is switched “ON”. If the capacitor cannot be 

switched the DMS selects the next capacitor down the list. The DMS uses a dead-band to prevent 

excessive switching. Failures of the capacitor bank switches are reported through alarms. 

Northern Virginia Electric Cooperative (NOVEC) 

NOVEC is pursuing two VVC objectives. One focuses on improving feeder power factor with 

switched capacitor banks, and the other focuses on lowering feeder voltage at the substation. 

Switched capacitors can improve distribution feeder power factor and reduce line losses while 

flattening the feeder voltage profile. NOVEC expects to achieve significant cost savings from 

operating the switched capacitors to achieve peak demand reductions and lower line losses. 

One of the expected results involves releasing over 20 MVA of peak capacity. Figure 9 is a view 

of NOVE’s configuration. 

Lowering substation voltage regulator set points reduces peak demand by lowering distribution 

feeder voltage. NOVEC is installing electronic voltage regulator controls on the single-phase 

voltage regulators at the substation. These control packages include communications and are 

accessible through the SCADA system, enabling NOVEC to adjust the feeder voltage set point 

according to system conditions. 

Figure 9. NOVEC's VVO Configuration 

Voltage and Reactive Power Management – Initial Results Page 20 
 

 

U.S. Department of Energy | December 2012 

NOVEC has installed 600 kVAR switched capacitor banks and equipped them with automated 

controllers. The controllers do not include communications, but operate autonomously 

according to a proprietary control algorithm. NOVEC does not plan to coordinate their operation 

at this time due to the cost of adding the communications, and the fact that the technology is 

working so well to maintain voltage using the local control algorithm. The system could be 

upgraded in the future if it can be shown that the benefits are worth the added expense. 

Pennsylvania Power and Light (PPL) 

Development of a DMS and an integrated communications network is at the heart of the PPL 

project. As shown in Figure 10, the DMS monitors and controls all of the smart devices being 

installed in the PPL distribution system including automated switches, sectionalizers, and 

capacitors. PPL is building new multiprotocol-label-switching (MPLS) fiber communications 

between substations and the service center located in Harrisburg, PA, and WiMAX point-tomultipoint communications between substations and field devices. The company is building a 

new fiber network to connect the MPLS network to the DMS and other back office systems. An 

important outcome of the project is that it extends PPL's existing substation SCADA system to 

the new distribution automation system. The project has two primary goals: reduce restoration 

time following outages, and reduce overall energy consumption through improved VVO and 

voltage stabilization. PPL expects to reduce line losses and reduce customer energy 

consumption by optimizing voltage. 

Figure 10. PPL’s VVO Configuration 

Southern Company 

The primary objective of the Southern Company project is peak demand reduction from CVR. 

To this end, Southern Company is automating capacitor banks and voltage regulators on several 

Voltage and Reactive Power Management – Initial Results Page 21 
 

 

 

U.S. Department of Energy | December 2012 

thousand distribution feeders. This allows Southern Company to lower feeder voltages at the 

substation and reduce customer demand during peak periods. Southern Company is doing CVR 

projects in its Georgia Power and Alabama Power service territories. The goal for each service 

territory is to reduce peak demand by 200 MW, for a total peak demand reduction of 400 MW. 

Figure 11 depicts Southern ompany’s equipment configuration. 

Figure 11. Southern Company’s VVO Configuration 

Southern Company is using capacitor controls to switch on capacitor banks in the event that 

voltage reductions at the substation reduce the end-of-line voltage below the desired range. 

Operators can adjust the voltage set points of the voltage regulator controls through SCADA. 

However, the capacitor controls operate independently in response to the voltage at each 

capacitor bank. So far Southern Company has seen good results from this approach and has 

been able to operate its distribution feeders close to unity power factor most of the time. In the 

future, the company plans to incorporate AMI smart meter data to monitor end-of-line 

voltages. Southern Company will also use a VVO control algorithm in its DMS, which is currently 

under development. 

Voltage and Reactive Power Management – Initial Results Page 22 
 

 

 

 

 

 

U.S. Department of Energy | December 2012 

4. Analysis of Initial Results
 

This section examines the results obtained from the operation of automatically or remotely 

controlled switched capacitor banks, as well as efforts by two projects to apply CVR practices. 

Demonstrating the successful operation of automatically switched capacitor banks and other 

equipment is an important step in the progression toward fully capable VVO in response to 

changing load and system conditions. 

As of March 31, 2012, 8 of the 25 SGIG VVO projects have reported initial results on 59 

switched capacitor banks involving 31 feeders. Some of the capacitor banks involve new 

equipment, and some involve retrofits to existing equipment. Four of the eight projects use 

coordinated capacitor switching with voltage regulators at the substation or on distribution 

feeders. Six of the eight projects expect to use distribution management systems to control 

capacitor switching. 

Figure 12 provides a summary of the types and sizes of the capacitor banks for the 8 projects, as 

estimated from analysis of hourly load data recorded from each feeder. All of the 31 feeders 

had at least one switched capacitor bank, more than half had two, and nearly a third had three. 

Six feeders also used a fixed capacitor bank. The sizes of the banks range from 0.1 MVAR to 2.0 

MVAR. 

Figure 12. Number and Size of the Capacitor Banks 

Section 4.1 provides information on the extent of capacitor bank switching. Section 4.2 

provides information on the impacts of capacitor bank switching on line losses. Section 4.3 

provides an example of CVR for achieving peak load reductions. Section 4.4 provides several 

observations about the initial results in these three areas. 

Voltage and Reactive Power Management – Initial Results Page 23 
 

 

 

U.S. Department of Energy | December 2012 

4.1 Capacitor Bank Switching 

Hourly data from the 31 feeders were analyzed to estimate switching statistics for each of the 

switched capacitor banks. Figure 13 shows the number of switching events on the capacitor 

banks. The period of analysis is 1–6 months, depending on the feeder, with an average duration 

of about four months. 

The data shows that the projects operated the switched capacitor banks relatively frequently. 

There is some uncertainty associated with estimating switching events from hourly load data, 

but, compared to the traditional approach of seasonal switching by line crews (where manual 

switching may occur twice a year), the number of switching events initiated by the 

automatically-switched capacitor banks is orders of magnitude greater. Having the capability 

for automated capacitor bank switching is an important step toward fully-functional VVO. 

Figure 13. Capacitor Bank Switching Statistics 

4.2 Line Loss Reductions 

Figure 14 provides an example of capacitor bank control for a nine day period in July, 2011. The 

capacitor bank in this example switched on and off four times, as shown by the shaded areas in 

the chart. Switching intervals of several hours were common for the equipment deployed on 

this feeder. The chart shows that one of the results was an improvement in the power factor of 

the feeder of about 0.05 due to reactive power compensation by the capacitor banks. 

Improvement in the power factor reduces the amount of current flowing on the feeder and 

results in line loss reductions of about 4%. 

Voltage and Reactive Power Management – Initial Results Page 24 
 

 

U.S. Department of Energy | December 2012 

Figure 14. Example of Automated Capacitor Bank Control 

Figure 15 presents the results of analysis to estimate line loss reductions for the 31 feeders 

from automated capacitor switching. Positive values indicate line loss reductions while negative 

values indicate line loss increases. The figure shows that 21 of the 31 feeders experienced line 

loss reductions. 

Because of higher amounts of inductive loads on the feeders during the summer (primarily due 

to air conditioning), line loss reductions from automated feeder switching tended to be higher 

then. About one-half of the feeders experienced line loss reductions in the 0% to 5% range, 

which is in line with expectations and examples from the literature.15 

15 For example, Hydro One estimated line loss improvements of 3.1% with reactive power compensation. Source: Hydro One, 

“Distribution Line Losses,” available at http://www.hydroone.com/RegulatoryAffairs/Documents/EB-2007­

0681/Exhibit%20A/Tab_15_Schedule_3_Distribution_Line_Losses_Study.pdf, accessed June 16, 2012. 

Voltage and Reactive Power Management – Initial Results Page 25 
 

 

 

 

U.S. Department of Energy | December 2012 

Figure 15. Histogram of Line Loss Reductions 

4.3 Conservation Voltage Reduction 

There are 11 SGIG VVO projects with the objective of accomplishing conservation voltage 

reductions during peak periods to reduce peak demand. Two of the projects – Oklahoma Gas 

and Electric (OG&E) and Sacramento Municipal Utility District (SMUD) – reported initial results 

from test operations for the summer of 2011. Figure 16 is a schematic of the devices and 

systems being implemented by OG&E for its CVR and other VVO activities. 

OG&E is pursuing CVR on nearly 100 feeders with the objective of reducing peak demand by 

about 16 MW. They have plans to expand this effort to 300 more feeders by 2017 to increase 

peak demand reduction capabilities to approximately 74 MW, subject to business needs and 

regulatory approvals. The project uses two-stage control in near real-time. The first stage 

corrects power factor through capacitor switching, minimizing losses and levelizing voltage 

along the feeders. The second stage regulates load tap changer voltage to reduce demand 

while maintaining minimum voltage thresholds for each connected feeder. In addition, meter 

reads are sampled off line to gather customer-level voltage information. This helps ensure that 

voltages are maintained within acceptable ranges and guide adjustments of the minimum 

voltage thresholds that are used by the control scheme. 

Voltage and Reactive Power Management – Initial Results Page 26 
 

 

 

 

U.S. Department of Energy | December 2012 

Figure 16. OG&E Devices and Systems for VVO Operations 

OG&E test results from the summer of 2011 on the first 42 feeders showed an average peak 

demand reduction of 2.06%, which exceeded slightly the 2.0% target. This resulted in the 

capability for 8 MW of peak demand reduction for the 42 feeders. There will be about 474 

capacitor banks equipped for CVR operations once the efforts on the nearly 100 feeders are 

completed in 2013. Once fully implemented, the utility plans to set controls to activate CVR for 

peak demand reductions during high demand periods. 

SMUD is pursuing CVR and VVO for both peak demand reductions and electricity conservation. 

The project includes 109 feeders and uses 180 automated capacitor banks which cover about 

18% of their system. The CVR objective for peak demand reduction is 10.4 MW; the CVR 

objective for electricity conservation is 36,520 megawatt-hours per year of energy savings. The 

latter objective is achieved by implementing CVR over several additional hours during the days 

when the peak demand reduction capabilities have been activated. The VVO objectives include 

peak demand reduction of 6.1 MW and energy savings of 11,150 megawatt-hours per year by 

improving the efficiency of the distribution feeders. 

SMUD’s method of implementing VR is utilizing the voltage reduction feature of the LT 

control at the distribution substation. A command is issued to the LTC control by a Distribution 

System Operator via SMUD’s energy management system (EMS) which implements one of 

three levels of voltage reduction available in the control. The percent reduction at each level is 

a configurable value which SMUD has initially set at 1%, 2%, and 3%, for evaluation purposes. 

Voltage and Reactive Power Management – Initial Results Page 27 
 

 

 

U.S. Department of Energy | December 2012 

Additionally, SMUD is implementing VVO which centrally controls substation capacitor banks 

and line capacitor banks in order to achieve a target power factor at the high voltage side of the 

distribution substation transformer. The line capacitors are strategically located to reduce line 

losses and provide voltage support on the distribution feeder. The substation and line capacitor 

banks are automatically switched in a predetermined order based on SMUD-developed control 

logic that operates within their EMS system. 

In the summer of 2011, SMUD conducted a pilot test on two 69/12kV distribution substation 

transformers, each serving 3 - 12kV feeders, to demonstrate the CVR and VVO capabilities. For 

these two substations, the test showed an average peak demand reduction of 1% and 2.5%, 

respectively, for a 2% voltage reduction during the test implementation. SMUD plans to 

perform additional testing during 2013 and 2014 on forty-one 69/12kV distribution substation 

transformers and associated feeders. 

4.4 Observations 

While the SGIG VVO projects have not yet fully implemented all of their expected voltage 

management activities, eight of the projects have been operating switched capacitor banks and 

other devices and systems and initial results have been reported. In addition, two of the 

projects have tested conservation voltage reductions to lower peak demand. Observations from 

the initial results include: 

For the 31 feeders for which projects have reported hourly load data, one-half are 

witnessing line loss reductions in the range of 0% to 5% and 5 feeders experienced loss 

reductions greater than 5%. In general, feeders with the worst baseline power factors 

(i.e., those with the highest amount of inductive loads) showed the greatest reductions 

in line losses. Many of the utilities are targeting their worst performing feeders. 

However, overcompensation for reactive power was observed in the remaining feeders, 

which resulted in line loss increases. In these cases, capacitor banks were often 

operated for voltage support rather than reactive power compensation. 

The initial results for conservation voltage reductions indicate the potential for peak 

demand reductions of approximately 1% to 2.5%, which is consistent with expectations 

and the results of other studies in the literature. There are no results yet from the SGIG 

VVO projects on conservation voltage reductions for longer periods to achieve electricity 

conservation. In comparison to energy savings attributable to line loss reductions, 

practices to affect conservation voltage reduction will have the greatest impact on 

reducing energy requirements. 

Projects are applying different approaches depending on their objectives to better 

manage volt/VAR levels within their distribution systems. While all projects are 

Voltage and Reactive Power Management – Initial Results Page 28 
 

U.S. Department of Energy | December 2012 

deploying automated controls to new and existing equipment, the extent to which field 

devices are integrated and the application of distributed versus centralized control 

schemes differs across them. In addition, some are actively attempting to apply 

conservation voltage reduction practices to conserve energy during peak periods and for 

longer durations, while many others are more focused on improving volt/VAR 

management (including reducing related operations and maintenance costs) and hope 

to achieve line loss reduction through power factor correction in addition to voltage 

stabilization. 

Voltage and Reactive Power Management – Initial Results Page 29 
 

 

 

 

 

U.S. Department of Energy | December 2012 

5. Next Steps 

So far, most of the initial results reported by the SGIG VVO projects have focused on automated 

capacitor switching and its potential impacts on line loss reductions. Only two projects have 

reported initial results on the application of conservation voltage reduction practices. Future 

SGIG VVO analysis reports will continue to focus on impacts from activites related to 

conservation voltage reduction and power factor correction, as well as convey best practices 

and lessons learned. 

Collaboration between DOE-OE and the SGIG VVO projects is essential to ensure that 

appropriate data are gathered and reported, and for understanding the factors that lie behind 

the quantitative results. DOE-OE routinely discusses the progress being made and data being 

reported with the projects to validate the results of the analysis and encourage the active 

exchange of information among the projects. DOE-OE continues to monitor the installation of 

VVO devices and systems and to explore the technology configurations and operating 

techniques upon which impacts are based. DOE-OE will publish follow-up analysis on the SGIG 

VVO projects in the future. In the meantime, updates on deployment progress and case studies 

highlighting project examples are posted regularly on www.smartgrid.gov. 

Voltage and Reactive Power Management – Initial Results Page 30 
 

 

 

U.S. Department of Energy | December 2012 

Appendix A. Reactive Power Compensation and Line Losses 

The purpose of this appendix is to provide basic information on the significance of reactive 

power and the role of capacitors in reactive power compensation and line losses.16 

Direct and Alternating Current Circuits 

Electricity permits energy to be transferred to devices within electric circuits so they can do 

useful work in the form of heat, light, and motion. Power is defined as the rate of energy 

expended per unit time and is expressed in watts (energy/time). Power (P) is equal to the 

product of current (I) and voltage (V) in electrical circuits (P=IV). 

In a direct current (DC) circuit, current and voltage move in one direction along a conductor 

(wire) and energy is transferred to devices according to P=IV. In an alternating current (AC) 

circuit, current and voltage periodically reverse direction (60 cycles per second in North 

America) and there is an exchange of energy between magnetic and electric fields. In doing so, 

a portion of the energy is taken up in this exchange and the remainder is available to perform 

useful work. 

The fundamental circuit elements are resistors, inductors, and capacitors. Electrical resistance is 

the property of a material or an electric device to resist the flow of current through it. Examples 

of such devices (i.e., resistors) include incandescent light bulbs and toasters. Reactance is the 

property of devices (i.e., inductors and capacitors) to influence the relative timing of alternating 

voltage and current on AC circuits. Examples include motors in devices such as refrigerators and 

air conditioners. 

Real Power, Reactive Power, and Power Factor 

In AC circuits with only resistive loads, voltage and current are in phase, and oscillate 

simultaneously, as shown in Figure A-1 (a). Instantaneous power is equal to the product of 

current and voltage at any given point in time. Electrical energy is transmitted or consumed 

over more than a single point in time and is determined by average power. Average power (or 

real power) is measured as the product of the root-mean-square (RMS) values of I and V, and 

represents the actual power transmitted or consumed by devices on the circuit. The RMS value 

of voltage in a standard outlet is 120 V even though the maximum amplitude of the 

instantaneous voltage is 170 V. 

16 For further information see !lexandra von Meier “Electric Power Systems a onceptual Introduction”, IEEE Press, 2006 and

MIT “Future of the Electric Grid, !ppendix ” December, 2011.

Voltage and Reactive Power Management – Initial Results Page A-1 
 

 

 

 

 

U.S. Department of Energy | December 2012 

Inductors produce magnetic fields that interact with the flow of current in a conductor. This is 

because the current in an inductor cannot be changed instantaneously. As currents oscillate, so 

do the magnetic fields. This exerts inhibitory effects on the changes in current flows. This 

inhibitory effect results in a delay of the alternating current relative to the alternating voltage, 

as shown in Figure A-1 (b). As a result of inductance, the average power (and the power 

available to do real work) is reduced since the relative timing of voltage and current has been 

shifted and, in fact, one quantity is sometimes negative when the other is positive. 

The difference in the relative timing of the alternating current and voltage is also referred to as 

the phase angle, denoted by (phi), which is often specified in terms of radians or degrees 

(since oscillating current and voltage are mathematically represented as sinusoidal waves). In 

this case, the average power is related to the amount of phase shift according to Pave = 

IrmsVrmscos ( ) or Pave = 1⁄2ImaxVmaxcos ( ). Reactive power results when the voltage and current 

are out of phase and is measured in volt-amperes reactive (VAR). Reactive power is exchanged 

between the electric and magnetic fields in the power system and does no real work. 

Figure A-1. Current, Voltage, and Power in an AC System 

The mathematical relationship between real power and reactive power is represented by the 

power triangle shown in Figure A-2. The phase angle represents the shift of the current and 

voltage waveforms. Apparent power is the product of the magnitudes of currents and voltages. 

The magnitude of apparent power is denoted by the absolute value of S, where S = IrmsVrms. 

Apparent power is measured in terms of volt-amperes and is always greater than or equal to 

real and reactive power. 

System load is the power drawn by appliances and equipment. The apparent power of the load 

determines the total current supplied by the source, including the portion supporting reactive 

power. Therefore, loads with higher reactive power components draw higher currents. This is 

important because the capacity rating of some equipment is determined by current. 

Voltage and Reactive Power Management – Initial Results Page A-2 
 

U.S. Department of Energy | December 2012 

Power factor (pf) is a term used to express the relationship between real power and reactive 

power. As shown in Figure A-2, power factor can be expressed as the cosine of , or as average 

power/apparent power. A larger phase angle ( ) corresponds to a larger amount of reactive 

Figure A-2. Power Triangle 

power and a lower power factor. Power factor is always between zero and one, and a power 

factor of one is often referred to as “unity.”

Capacitors and Power Factor Correction 

Utilities can use capacitors to improve power factors. Like inductors, capacitors cause a phase 

shift between current and voltage, but in the opposite direction. A capacitor and inductor can 

exchange energy with each other in an alternating manner without consuming or dissipating 

real power. Capacitors are often connected near large inductive loads where they can 

compensate the load most directly. 

Without capacitors, additional current supplied by generators results in increased line losses 

(lost energy) due to the greater amount of current being carried through conductors according 

to P=I2

R, where P is the dissipated power (that is converted to heat) and R is the resistance of 

the conductor measured in ohms. Higher currents also mean that conductors, transformers, 

and other equipment must be sized to carry the total current, not just the current that does 

useful work. 

Voltage and Reactive Power Management – Initial Results Page A-3 
 

 

 

U.S. Department of Energy | December 2012 

Appendix B. SGIG VVO Projects
 

SGIG Project 

Objectives VVO Devices V Sensors 

Scale and Scope of Project Project Objectives 

CVR Peak

CVR Energy

Reduce Losses

Capacitors

Regulation 1

Coordination 2 

VVO Control 3 

Line Sensors

Smart Meters 

Avista Utilities       Expands existing program, adds DMS and 

integrated control. Reduce energy consumption and CO2 emissions 

City of Auburn, 

Indiana   10 new automated capacitor banks. Minimize changes in reactive power demand 

using power factor corrections 

City of 

Wadsworth, Ohio          20 capacitor controls, automated regulators 

and new DMS software. Improve power factors and reduce line losses 

Consolidated 

Edison Company 

of New York, Inc. 

      Deployment on a portion of the service 

territory. 

Use capacitors to decrease losses and release 

effective capacity. Use coordinated load tap 

changers to improve control on 4kV grids. 

Duke Energy 

Carolinas, LLC       Large-scale project with 2600 regulation 

devices and 3700 capacitor controls. 

Integrate devices with SCADA systems targeting 

line losses and voltage controls 

EPB       

Pilot program on five circuits. “Virtual Power 

Plant” with a DMS to control capacitors and

line voltage regulators. 

Testing if feeder voltage profiles can be 

flattened, with a goal of reducing peak demand 

by 30 MW 

FirstEnergy       Pilot project on 21 feeders in OH and 22 

feeders in PA (MetEd) 

Targeting 3% voltage/energy reduction, 5% peak 

demand reduction3 

Florida Power & 

Light Company     Replacing existing capacitor controls with 

automated capacitor controls Better operation of VVO equipment 

Indianapolis 

Power & Light        Large-scale project on 400 feeders across the 

service territory. 

Reduce peak demand by 40 MW to lower 

capacity costs 

Knoxville Utilities 

Board       Testing peak demand CVR on one circuit and 

VAR control two circuits. 

Looking to measure reduction in peak energy 

usage (peak demand). 

Modesto 

Irrigation District        Automation and communications for 40 

existing capacitor banks for 8 substations. 

Targeting reduction in system losses and peak 

demand. Focused on improving power factor and 

voltage stabilization. 

1

 Regulation includes load tap changers and voltage regulators.
 2

 Coordinated operation may be accomplished with centralized automation using a DMS or similar system with central logic, or with decentralized automation using local logic.
 3

 Voltage sensor is installed as part of VVO control packages.
 

Voltage and Reactive Power Management – Initial Results Page B-1 
 

 

U.S. Department of Energy | December 2012 

SGIG Project 

Objectives VVO Devices V Sensors 

Scale and Scope of Project Project Objectives 

CVR Peak

CVR Energy

Reduce Losses

Capacitors

Regulation 1

Coordination 2 

VVO Control 3 

Line Sensors

Smart Meters 

Northern Virginia 

Electric 

Cooperative 

     Adds automation and control to new and 

existing equipment. 

Energy savings by reducing line losses and 

reduce peak capacity by 25 MVA. 

NSTAR Electric 

Company      Adds automation to existing capacitor banks 

to allow better switching of the cap banks. 

Targeting reduction in system losses and 

improvement of power factor. Avoid truck rolls. 

Oklahoma Gas & 

Electric        Expanding existing VVO by 100 feeders 

enables voltage optimization. 

Defer capacity additions by reducing peak 

demand by 74 MW 

PECO          Expands existing program and enables 

advanced CVR. 

Simple CVR - 0.5% energy and demand 

reduction, Advanced CVR - Test and learn 

Pepco – Atlantic 

City Electric 

Company 

    Add controls and communications to new and 

existing capacitors. 

Reduce line losses with power factor correction, 

flatten distribution voltage profiles. 

PPL Electric 

Utilities 

Corporation 

      205 automated capacitors in the Harrisburg 

region of the service territory. Optimize voltages and reduce line losses 

Progress Energy 

Service Company      SGIG accelerates large-scale deployment (97% 

of service territory) in the Carolinas. Reduce peak demand with CVR 

Public Utility 

District No. 1 of 

Snohomish 

County 

  Small-scale project on up to 10 circuits. Reduce line losses 

Rappahannock 

Electric Coop    Adds controls to voltage regulators. Reduce voltages when called upon by PJM 

Southern 

Company       Large-scale (100s of feeders). Primary goal is reducing peak demand (200 MW 

at Georgia Power, 200 MW at Alabama Power) 

Sacramento 

Municipal Utility 

District 

       Large-scale deployment of automation 

equipment. Improve power factor and reduce peak demand 

Sioux Valley 

Southwestern 

Electric Coop 

   

Automation of voltage regulators to improve 

voltage optimization and reduce peak 

demand. 

Reduce peak demand by 1.5 MW in summer and 

2.5 MW in winter 

1

 Regulation includes load tap changers and voltage regulators.
 2

 Coordinated operation may be accomplished with centralized automation using a DMS or similar system with central logic, or with decentralized automation using local logic. 

3

 Voltage sensor is installed as part of VVO control packages.
 

Voltage and Reactive Power Management – Initial Results Page B-2 
 

U.S. Department of Energy | December 2012 

SGIG Project 

Objectives VVO Devices V Sensors 

Scale and Scope of Project Project Objectives 

CVR Peak

CVR Energy

Reduce Losses

Capacitors

Regulation 1

Coordination 2 

VVO Control 3 

Line Sensors

Smart Meters 

Talquin Electric 

Cooperative     

DMS will coordinate the operation of 55 new 

automated capacitor banks and existing 

regulators. 

Improve power quality and reduce line loss 

Wisconsin Power 

and Light    Upgrade 750 capacitor banks with 

communications and controls. Manage power factors closer to unity 

Vermont Transco, 

LLC     Automating 47 feeders, targeting reliability 

improvements and O&M savings. Reduce line losses 

1

 Regulation includes load tap changers and voltage regulators.
 2

 Coordinated operation may be accomplished with centralized automation using a DMS or similar system with central logic, or with decentralized automation using local logic. 

3

 Voltage sensor is installed as part of VVO control packages.
 

Voltage and Reactive Power Management – Initial Results Page B-3