The Functionalities and Benefits of a Two-Way Centralized Volt/VAR Control and Dynamic

Voltage Optimization Guohui Yuan, PhD, Director of Product

Management, CURRENT Group

Brian Deaver, P.E., VP of Product Management, CURRENT Group

Robert Davis, Director of Software, CURRENT Group

Kelly Bloch, Manager of Distribution Planning, PSCO, Xcel Energy

Tom Yohn, P.E., Consulting Engineer, Energy Services, Xcel Energy

Rob Webb, P.E., Principal Area Engineer, PSCO, Xcel Energy

Kerry McBee, P.E., Special Projects Engineer, PSCO, Xcel Energy

I. BACKGROUND Voltage regulation and system efficiency are two of the most important issues facing today’s utilities. First and

foremost, utilities have the responsibility to keep the customers’ delivered voltage within specified tolerances. Failing to do so can result in customer complaints and penalties. Secondly, utilities are increasingly obligated to meet energy efficiency goals that have been mandated by local, state, and central governments. Again, if they fail to act, they face non-recoverable penalties.

One major source of system losses is the reactive load - defined as Volt-Ampere Reactive, or “VAR”, which is

created mainly by load devices involving electric motors. Examples are washing machines and air conditioning units. VAR load also increases the need for system capacity. Consequently, utilities have been using various “Volt/VAR control” methods to regulate and reduce the amount of VAR on their systems while keeping voltage within regulated range.

So far the most commonly used method of Volt/VAR control includes utilizing Load Tap Changers (LTCs) or

regulators to regulate substation bus voltage and using locally controlled switched line capacitors to support feeder voltages and regulate VARs. However, the voltage and VAR controls are not coordinated, resulting in suboptimal performance in the distribution system. Capacitor control devices usually make switching decisions based on local settings and the status at the particular capacitor bank locations without knowledge of the overall feeder network. Meanwhile, the substation LTC control device makes tap adjustments based on its local settings and the status at the substation without any information from the feeder circuits. One major problem with uncoordinated capacitor bank and LTC operations is that local switching activities sometimes run the line voltages outside of regulatory limits. Although temporary deviations from specified ranges are generally allowed, frequent and persistent violations can result in perceptible negative impacts to customers. A high steady-state voltage can reduce the life of customer equipment such as light bulbs and electronic devices, while at the same time increase customer demand and system losses. A low steady-state voltage can lead to low illumination levels, slow heating of heating devices, motor starting problems, and overheating in motors.

A more advanced, integrated, and centralized voltage and VAR control solution is called for in order to address

the aforementioned problems. Given the different approaches utilities currently use for voltage and VAR control at various levels of sophistications, this advanced Volt/VAR control solution must also have the flexibility to adapt to the need of each individual utility.

Xcel Energy is very familiar with the typical Volt/VAR control approach, but has been looking for new and

better ways to further improve system performance and reliability. In addition to performance gains on distribution power factors, it also wants to be able to dispatch the line capacitors to meet system-wide HV delivery-point power factor requirements designed to minimize VAR impacts to the transmission system. Another interest is to evaluate the energy saving potentials through conservation voltage reduction. In working with CURRENT Group beginning in September 2008, Xcel Energy has deployed a two-way centralized Volt/VAR Control solution in Boulder as part of the SmartGridCity project.

II. PROJECT SCOPE Xcel Energy has chosen one substation – NCAR, two feeders – 1554B and 1556B, eight switchable capacitor

banks and controls, a transformer LTC and control, and dozens of feeder voltage sensors to demonstrate the new two-way centralized voltage and VAR control method. These numbers and locations are carefully selected based on the power flow studies of the load patterns. In the case of the feeder voltage monitoring, since every NCAR distribution transformer is monitored through the SmartGridCity infrastructure, we have the flexibility to select any small subset which are representative of the high and low voltages in the system.

The major system components of the two-way centralized Volt/VAR control project are:

1. Switched capacitor banks 2. Advanced capacitor bank controls 3. Distribution (bellwether) voltage sensors 4. Secure communication network 5. Interface to SCADA database 6. Centralized monitoring and control software for both capacitors and LTC’s

CURRENT Group provides the Volt/VAR control software applications and bellwether voltage sensors, as well

as the two-way high speed SmartGridCity communication network, which is built with CURRENT Broadband-Over-Power-Line (BPL) and fiber technologies. S&C IntelliCAP Plus was chosen for the capacitor bank control. OSIsoft provides the PI servers to collect, validate, store, and service the real time substation SCADA data. In additional to providing the equipment and software to Xcel Energy SmartGridCity, CURRENT Group also provides project management across multiple functional teams among the partners to coordinate system design, equipment installation, software deployment, training, and system integration and testing. The two-way centralized Volt/VAR control has been operational since June 2009.

III. SOLUTION DETAILS CURRENT® Volt/VAR Control and Dynamic Voltage Optimization (DVO) is a system that integrates software,

communications, sensors and grid control devices to enable significant efficiency gains in the operation of the electric distribution system. The CURRENT solution does this by providing dynamic real-time VAR reduction and tighter voltage regulation. The CURRENT solution coordinates and automates the operations of line capacitors and LTCs to maintain voltages at all feeder locations within desired limits and to achieve optimized power factor, while minimizing the amount of switching of those devices.

Above all, CURRENT DVO provides utilities with an effective energy efficiency tool to reduce customer demand

via voltage reduction. Conventional distribution voltage control methods regulate the service voltages at the substation bus and few feeder capacitor locations. Because the voltage delivered to the customer is not monitored, a significant operation margin has to be provisioned in order to comply with the regulatory limits. With CURRENT DVO, the voltage delivered to the customer is directly monitored by bellwether sensors and automatically controlled by coordinated operations of capacitor banks and LTCs. (In Boulder, the bellwether sensors monitor the distribution transformers. Therefore provisions must be made to account for the voltage drop across the secondary conductors, which is typically 3V.) As a result, the voltages along the feeder can be regulated within a much narrower range,

and there will be room for operating the system at a lower voltage to reduce customer demand and energy consumptions.

CURRENT Volt/VAR Control and DVO solutions are comprised of the following key functions:

1. Real-time monitoring of feeder voltages through strategically positioned bellwether sensors 2. Real-time monitoring and control of distribution line capacitors and voltage regulators through integration with

their corresponding controllers. 3. Real-time monitoring and control of substation LTCs and substation capacitor banks through integration with

the utility’s substation SCADA system. 4. Real-time monitoring of substation feeder metrology through integration with SCADA system. 5. Advanced analytic and control software that directs the switching of distribution line capacitors, substation

LTCs, distribution voltage regulators and/or substation capacitors to achieve the desired levels of regulation 6. Visualization of real time status of the entire feeder network from the substation down to the end of feeder lines

OpenGridDistribution

OpenGridClients

GIS

DNP3 Master

Capacitor Bank Controls

OpenGridNetwork

Management

OpenGridServers

XML Import

SCADA DB ( OSIsoft PI)

Volt/VAR DVO

Secure IP NetworkSecure IP Network

Substation Gateway/RTU

SCADA NetworkSCADA Network

Sensing, control, protection

Enterprise IT Network

Device, Network Topology

SCADA Data (kW, kVAR)

Bellwether LV Voltage Sensor

Management

A. System Architecture The above diagram is a software-centric view of the system architecture. CURRENT OpenGridTM Network

Manager, a component of the Volt/VAR Control software, manages the communication interface to the IntelliCAP Plus capacitor bank controls as a DNP master. It collects real time voltage and VAR measurements from each capacitor controller and passes them to the analytics modules.

The feeder voltage data are collected in real time from the bellwether sensors. Again, CURRENT OpenGrid

Network Manager acts as the master for the data collection – in this case using SNMPv3 protocol. The substation voltage and VAR measurements are collected by SEL-3351 System Computing Platform and then

pushed into OSIsoft PI system. The Volt/VAR Control application regularly contacts the PI server to retrieve the latest substation data.

Feeder network topology is derived from Xcel Energy’s GIS data and normalized to OpenGrid XML format. The

network topology is maintained by the CURRENT OpenGrid Distribution Manager. In the future, the system has the

flexibility to receive OMS-managed as-operated network using standards based interface adaptor.

B. Communication Communications to and from capacitor bank control devices and bellwether voltage sensors are provided by the

SmartGridCity BPL/fiber network. Communication with bellwether voltage sensors are straightforward because the CURRENT equipment integrates sensing and communication in one device. However, a CURRENT Low Voltage Repeater (LVR) had to be installed next to the IntelliCAP Plus capacitor bank control for communication. In addition, a protocol converter (e.g. RuggedCom RMC30) device is required to bridge the native serial DNP interface into a DNP-over-IP interface. The RMC30 is mounted inside the IntelliCAP Plus enclosure and powered from the same 1kVA transformer. An industrial Ethernet cable connects the RMC30 and the LVR.

C. Configuration Most settings in the Volt/VAR Control application are configurable. Some of the most important settings are:

Name Values Program cycle time Default = 5 minutes VAR control mode Enable/Disable Voltage control mode Enable/Disable THD management Enable/Disable Automation levels Monitor/Suggest/Auto HV VAR thresholds Leading/lagging 0.98 PF MV VAR thresholds Leading/lagging 0.98 PF Feeder VAR thresholds -300 to 1500 kVAr Bellwether feeder voltage thresholds

Configurable

Capacitor control settings

Configurable

D. Monitoring

The Volt/VAR Control and DVO applications monitor the real time operation status of the entire feeder network including the voltage, active load, VAR load, total load, power factor, and THD at both MV and HV sides of the substation transformer, each feeder breaker, each capacitor bank, and each voltage sensing location. The application also monitors the open/close status of the capacitor banks and the LTC tap positions.

E. Control The Volt/VAR control and DVO software is able to dynamically make optimal switching decisions based on real

time measurements and system status. Each substation bus is independently controllable. The application also

performs a number of routine checks to ensure that optimization is achieved and all operating criteria are observed. For example, one of these parameters is the maximum daily switching counts for the capacitor banks.

The application provides three control automation modes: Monitor Only, Suggest Only, and Automatic.

Automated controls can be completely disabled at any time if there are safety and/or reliability concerns. The standard control methods tested in the Boulder project are:

1. Centralized VAR control 2. Centralized voltage control 3. Fully integrated VAR and voltage control

In method #1, the substation bus voltage is regulated by the LTC control or remotely from the SCADA console.

The system VARs are regulated centrally from the Volt/VAR application by remote operations of the feeder capacitor banks. To ensure feeder voltages are within regulatory limits, the IntelliCAP Plus controls are set in the voltage override mode. The VAR control logics occur at three levels: substation transformer HV-side, MV-side, and individual feeders. There are corresponding VAR thresholds at each control levels. When there is conflict, the HV (or MV) logic takes precedence over individual feeder logic.

In method #2, the feeder bellwether voltages are regulated centrally from the Volt/VAR and DVO application by

remote operations of the substation LTC – regardless of VAR control and capacitor banks switching. By monitoring and controlling the feeder voltages at appropriate locations – in this project we have selected nine sensing locations per feeder that are concentrated at the end of the lines, this bellwether voltage control method allows voltages to be directly regulated near the customer loads, rather than indirectly through the regulation of the substation bus.

In method #3, both system VARs and feeder bellwether voltages are regulated centrally from the Volt/VAR and

DVO application by remote operations of the substation LTC and capacitor banks. The voltage and VAR controls are fully integrated and the operations of substation LTC and feeder capacitor banks are fully coordinated. Since system voltages and VARs are always inter-dependent of each other, the voltage and VAR controls need to be coordinated to achieve optimal control objectives, and prevent conflicting control decisions and unnecessary wear and tear of the switching devices.

While the standard control features are implemented for the Boulder project, the application does have the

flexibility to incorporate custom control strategies in order to meet utilities’ specific control objective

F. User Interface The Volt/VAR Control and DVO software client is a standard internet browser such as IE8 or Firefox. No special

software is required to be installed on the operator’s machine, therefore eliminating the maintenance headaches related to the IT compatibility and security.

Security is managed at three levels: At the network level, the Volt/VAR Control application runs within the

utility private network (or VPN) with firewall protections. At the application level, Volt/VAR Control uses specific ports for required processes. The system administrator must open these ports in order for the system to communicate properly. At the user level, only authorized personnel can login the system with Username/Password authentication. Each login session is recorded in the audit log.

The Volt/VAR Control includes one-line diagrams, feeder network trees, graphs and tables, event windows, and

interactive dialog windows for visualization of system status and for network control. Navigation is as easy as browsing the Internet.

The application also provides many useful reports such as Daily/Weekly/Monthly/ report of events for each

substation bus or total switching count for each capacitor bank. These reports can be scheduled or generated on-demand.

Figure 1 CURRENT Volt/VAR Control and Dynamics Voltage Optimization software main screen showing the navigation tabs at the top, the tree view to the left, the one-line diagram, and the event window

IV. TEST RESULTS

Once installations of field equipment and CURRENT software were all completed, preliminary system integration tests were conducted to verify connectivity between system components and their correct configuration settings. Afterwards, the joint Xcel-CURRENT team conducted two series of operation tests to verify the performance of the centralized voltage and VAR control system. The first series, designed to validate the centralized VAR control functions, were conducted between September 8 and September 18. Testing would start each day at approximately 9 am Mountain Daylight Saving Time (MDT) and end at about 2 pm. The second series were conducted between November 9 and November 17, where the objective was to validate the centralized voltage control functions. Testing would start at approximately 12 pm Mountain Standard Time (MST) and end at about 4 pm.

Overall, the Volt/VAR Control and DVO software performed all designed functionalities very well. It was able to

collect and display real time substation SCADA and capacitor status data every 5 minutes. The software was able to detect voltage and VAR threshold violations, make the correct switching decisions, automatically operate the capacitor banks or make recommendations for LTC tap changes, and eventually bring the system voltage and VAR within the specified range.

The historical data are stored in the CURRENT OpenGrid database for a user configurable period of time – up to

one year or longer. These data include capacitor bank and LTC operation status, sequence of events, and

voltage/current/power measurements at the substation and along the feeders. These historical data are valuable for Xcel system planning and operation activities because all the relevant data are stored in a single database. Some examples are trend analysis, event correlation, control algorithm improvements, and better system planning.

A. VAR Control Tests The VAR control tests were conducted under both normal and extreme operating conditions. The Volt/VAR

Control software proved to be able to handle changing conditions such as light and heavy loads high and low voltages, and unavailable capacitor banks.

In Xcel’s existing practice, the capacitor banks are individually controlled by the IntelliCAP Plus devices

operating in VAR mode. During the VAR control tests, the IntelliCAP Plus devices were configured for remote operations so that the CURRENT software was able to take over the control of the capacitor banks. We observed a clear difference between switching decisions made by the two different (i.e. local and centralized) control methods, particularly during the transitions at the beginning and end of each test. While the local control method could not always maintain the bus and feeder VARs to within the thresholds, the centralized method did. The simple reason is that the individual IntelliCAP Plus did not “know” or “see” the VAR at the bus or feeder level. We also observed that different sets of capacitors were closed under the two methods for the same VAR condition. We believe the centralized control method is more optimal because it uses system wide information to make switching decisions. To quantify the benefits, we are currently working on a detailed analysis of system losses using CURRENT distribution power flow model.

Figures 2 (a)-(g) captured a sequence of capacitor switching events during the test on September 11, 2009,

between 9:00am and 12:00 pm MDT (or 15:00 – 18:00 UTC). Before test started, two capacitors (OC765158 and OC224487) were in CLOSED position as controlled by the IntelliCAP Plus. Clearly as shown in Figure 2(a), the HV-side VAR stays above the upper threshold (red line). At around 9:40 am testing started and the control turned over to the CURRENT software. The two closed capacitors were manually opened to amplify the VAR condition. After some settling time, all capacitors were OPEN at 9:55 am. Then the software suggested closing OC213035 at 10 am because the HV VAR was out of threshold. Closing action of OC213035 was manually taken at 10:17 am. Subsequently three more capacitors (OC765158, OC224487, and OC303016) were manually closed according to control suggestions. At about 11:06 am the HV-side VAR was finally brought back within threshold and the power factor was approximately 0.995 lagging. Figures 2(b) and 2(c) show the same event sequence at the feeder and capacitor bank level. It should be noted that the VAR at each feeder breaker and capacitor bank was measured on the MV side of the substation transformer. The difference between the MV and HV VARs are the contribution from the transformer, which we modeled using simple X and R impedance.

Figures 2(d) and 2(e) depict the VAR operating points on a MVA-MVAR phase diagram, at the HV-side of the

transformer and feeder breakers respectively. It is easily seen from these graphs that the VARs decreased as the capacitors were switching in while the total transformer load and the loads on each feeder remained relatively unchanged.

Figure 2(f) shows that the voltages at the substation bus and all capacitor locations fell nicely within the 114 V

and 126 V band, which did not trigger any switching events due to voltage violations.

Figure 2(a) Bus VAR versus time.

Figure 2(b) Feeder VAR versus time

Figure 2(c) Bus and capacitor bank VAR versus time

Figure 2(d) Phase diagram of bus VAR operating points

Figure 2(e) Phase diagram of feeder VAR operating points

Figure 2(f) Bus and capacitor bank voltages versus time

B. Voltage Control Tests The voltage control tests were designed to validate the basic feeder voltage monitoring and control functionalities

including • Real time feeder voltage monitoring and visualization, • Historical feeder voltage visualization • Dynamic voltage control in Suggest mode As illustrated in Figures 3, the real time voltage profile along the feeder was updated every 5 minutes. The

algorithm tries to keep operating voltages as low as possible while making sure that all voltage measurements are still above the regulatory threshold of 114V. (Actual lower threshold was set 117V rather than 114V because measurements were taken at the distribution transformers, not customer meter panels.) Since the bellwether voltage measurements were in the 122.5V – 123.5V range at the beginning, “Lower LTC” suggestions were made so that the voltages were maintained closer to 117V.

Figures 4 (a)-(d) captured a sequence of LTC tap change events during the test on November 09, 2009, between

11:00am and 4:00 pm MST (or 18:00 – 23:00 UTC). At 1:05 pm MST, the test team began to manually lower the LTC tap from SCADA console based on the suggestions. In each step the LTC was lowered by 1 or 2 tap positions, resulting in average voltage decrease of about 0.75 volt. Between 1:05 pm and 2:35 pm the LTC tap was lowered 5 times and the average voltage was reduced from 123V to 119.5V. The lowest bellwether voltages had reached 117V lower threshold and no more “Lower LTC” suggestion was made.

It was not coincidental that a low bus voltage alarm was triggered when the LTC tap was at the lowest point

during this test. In the SCADA system the high and low voltages were set at approximately 126V and 121.5V. Without actual voltage measurements along the feeder, the 121.5V substation bus voltage serves as the proxy for 114V lower limit at the customer meter panel. With DVO we know that the 121.5V control threshold is a little conservative.

At 3:20 pm, testing was complete and the LTC control was returned to from the SCADA Auto. The bus voltage

and bellwether voltages immediately increased to the pre-test level, which is between 122.5V and 124V.

The system VAR was steady and HV power factor was above 0.98 for the duration of the test, therefore no automatic capacitor bank switching events occurred. (Note, capacitor OC168109 was closed unexpectedly by the IntelliCAP Plus at 3:10 pm and opened at 3:15 pm, resulting in a spike in the system VAR measurement.)

Preliminary testing results show that the average voltage was reduced by 3.5 volts (or 3%) between 1:05 pm and 2:45 pm; however, the load reduction was obscured by several factors, one of which is the afternoon load ramp. The data did show that the total MV reactive load decreased from 1750 VAr to 1550 VAr, or by 12%, for the same duration. As reference, Figure 5 shows a three-day MVA load trend between November 09 and November 11. We are currently conducting more DVO tests to demonstrate the CVR effect, taking into account the various factors that affect the load changes. These factors include: time of day, day of week, voltage reduction steps, voltage reduction durations, and weather.

Figure 3 Real time system status including substation metrologies, feeder capacitor bank status, and voltage profile along the feeders

Figure 4(a) Voltages measured by IntelliCAP Plus

Figure 4(b) Voltage measured by bellwether sensors. The red and blue lines are the voltage control thresholds. The lighter red and blue lines are buffer thresholds used to make the control algorithm more robust.

Figure 4(c) HV VAR during voltage reductions

Figure 4(d) HV load during voltage reductions

Figure 5 Three day MVA load pattern on the HV-side of the transformer.

V. CONCLUSION

The two-way centralized Volt/VAR Control and DVO allow Xcel Energy to optimally regulate VARs while

maintaining voltages within the regulatory limits. By adopting an integrated Volt/VAR Control approach, the operator is able to monitor the real time network status at both substations and along the feeder lines from a centralized location. The advanced analytical algorithms determine which capacitor bank to switch and whether to raise or lower LTC taps – using measurements from the substation SCADA and field devices including capacitor control and bellwether voltage sensors. Consequently, utilities and customers will both benefit from improved system efficiency as well as the service quality and reliability.

In addition, DVO enables customer energy savings and demand reduction through the reduction of delivery

voltage. Studies have shown that, through line voltage reductions, the potential customer energy savings (kWh) may be as much as 3% all year round. The potential savings in demand may be up to 3.5% in active load (kW) and up to 20% in reactive load (kVAR). DVO provides utilities an effective tool to meet peak demand, improve energy delivery efficiency, and reduce carbon emissions.

VI. REFERENCES

[1] Northwest Energy Efficiency Alliance Distribution Efficiency Initiative Project Final Report, R.W. Beck, December 2007 [2] National Standard for Electric Power Systems and Equipment—Voltage Ratings (60 Hertz), ANSI C84.1-2006, NEMA [3] Recommended Practice for Emergency and Standby Power Systems for Industrial and Commercial Applications (Orange Book), IEEE

Standard 446-1995 [4] The Power Quality Implications of Dynamic Voltage Optimization, EPRI PQ Commentary, No. 4, December 2001 [5] Jim Burke, Hard To Find Information About Distribution Systems, 5th Edition, ABB Inc Consulting, Raleigh, North Carolina, August 2002 [6] Leonard L. Grigsby, The Electric Power Engineering Handbook, CRC Press, 2001 [7] Lefebvre, S.; Gaba, G.; Ba, A.-O.; Asber, D.; Ricard, A.; Perreault, C.; Chartrand, D., “Measuring The Efficiency Of Voltage Reduction At

Hydro-Québec Distribution”, IEEE PES General Meeting, July 2008 Page(s):1 - 7

VII. AUTHOR BIOGRAPHY

Guohui Yuan, PhD, serves as Director of Product Management at CURRENT Group, a smart grid technology company. In this role he is responsible for defining smart grid system optimization software applications and their integration with communications, sensing, and enterprise IT systems. He works closely with the customers on requirements, design, deployment and testing of the CURRENT solution. He is also actively involved in product marketing and partnerships. Dr. Yuan has been directly and indirectly working in the smart grid field for the last 12 years. Most recently, he was the Director of Systems Engineering at GridPoint, Inc and the system architect of GridPoint SmartGrid Platform. Prior to that, he was the lead control engineer at WaveCrest Labs developing electric propulsion technologies and systems for electric and hybrid electric vehicles including PHEV. He currently holds 9 US patents on electric vehicle technologies and systems. He started out his career as a senior member of technical staff at Comsat Labs, where he had worked on many communication network technologies and systems, particularly data services over satellite and RF. He has published in IEEE Transactions on Circuits and Systems and conference proceedings. Dr. Yuan received a

B.S in Physics from Tsinghua University, Beijing, China, and a Ph.D. in Physics from the University of Maryland at College Park. He is a senior member of the IEEE.

Brian Deaver, P.E., serves as Vice President of Product Management at CURRENT Group. Mr. Deaver brings over 24 years of experience in the electric transmission and distribution industry with extensive experience in substation and distribution automation, reliability improvement, electric distribution planning, and advanced real time control systems. Previously, Mr. Deaver was Principal Engineer of System Control for Baltimore Gas and Electric, a wholly-owned subsidiary of Constellation Energy, which delivers power to more than 1.2 million electric customers in Central Maryland. At BGE, Mr. Deaver was responsible for substation SCADA, substation automation, distribution automation, volt/var regulation and was the lead engineer on BGE's comprehensive Electric System ReDesign Program. Mr. Deaver earned a Bachelor of Science in Electrical Engineering from the University of Maryland at College Park, and has been a Registered Professional Engineer in the State of Maryland since 1994.

Robert (Skip) Davis currently serves as Director of Software at CURRENT Group, a smart grid technology company, which he has been with for over 7 years. Robert is responsible for leading design and implementation of the Opengrid Software Product Suite as well as seeing through the integration into existing systems within utilities. Previous to CURRENT, he worked at Seneca Networks and TTC/Acterna (now JDSU) as a senior software engineer developing device management systems.

Kelly Bloch is Manager of Distribution Planning at Xcel Energy. She earned a Bachelor of Science in Electrical Engineering from South Dakota State University in 1989. She has been employed in the utility industry for nineteen years in several positions with Xcel Energy and its predecessors, New Century Energy and Public Service Company of Colorado. She has worked in Distribution Standards, Distribution Reliability Assessment, and Distribution System Planning. For the past five years she has managed the Distribution System Planning group which, has included responsibility for determining the capital project required to maintain and expand the distribution system infrastructure; both feeder and substations. She also leads the development of plans to maintain system power and to improve the efficiency of the electric distribution system.

Thomas Yohn, P.E., is a Consulting Engineer with Xcel Energy. He presently handles special technical projects for electric distribution in eight states. This includes distribution power factor studies, power quality studies, distributed generation interconnections, new technology proposal evaluations, various pilots including SmartGrid City, and reliability improvement initiatives. He has been with Xcel Energy and its predecessors since 1973. Earlier assignments included generation plant, transmission system, substation, and distribution system protective relaying design and settings. He has led teams to ensure transmission system reactive power adequacy, dynamic reactive power adequacy, black start plans, and acquisition due diligence teams. He conducted and directed the interconnection cost estimating and evaluation aspects of two all-source generation RFPs in Colorado. Mr. Yohn has received B.S. and M.S. degrees in electrical engineering from the University of Colorado at Boulder. He is a senior member of the IEEE and is registered as a Professional Engineer in Colorado.

Rob Webb, P.E. is a Principal Specialty Engineer with Xcel Energy. Rob presently handles special projects for the Electric Area Engineering group, including Distribution Automation, Interruptible Service Options, Distribution SCADA development, and Smart Grid City. Other duties include technical support for the Electric Distribution Design, Operations and Trouble departments; evaluation and approval of small renewable energy interconnection applications; reliability monitoring and improvement for the Central Metro Area of Denver; and technical support for the Area Engineering group. Rob has been with Xcel Energy and its predecessor companies since 1984. Past assignments include Electric Distribution Standards, Field Engineering, Planning and Electric Operations Technical Support. Rob earned a B.S. degree in electrical engineering from the University of Colorado at Boulder and is registered as a Professional Engineer in Colorado.

Kerry McBee, P.E., is Senior Specialty Engineer with Xcel Energy. He presently handles special projects related to the reliability of the electric distribution system in Colorado. Mr. McBee has worked extensively in incorporating the functionality of Smartgridcity, which included design, equipment selection, software application, and performance assessment. He has been employed at Xcel Energy since 2004, during which time he also investigated and mitigated hundreds of power quality and reliability deficiencies. Prior to Xcel Energy, his career focused on forensic investigations and designing distribution power systems for Knott Laboratory, Peak Power Engineering, and NEI Power Engineers. He is currently pursuing his PhD at Colorado School of Mines, which is where he received his BS degree in 1999. He received his MS degree in Electric Power Engineering from Rensselaer Polytechnic Institute in 2000. He is also a member of IEEE and is registered as a Professional Engineer in Colorado.