Patent Publication Number: US-2021181774-A1

Title: Voltage conservation using advanced metering infrastructure and substation centralized voltage control

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation application of application Ser. No. 13/931,145, filed Jun. 28, 2013, which is a continuation of application Ser. No. 12/774,507, filed May 5, 2010, now U.S. Pat. No. 8,577,520, issued Nov. 5, 2013, which claims priority and the benefit thereof from U.S. Provisional Application No. 61/176,398, filed on May 7, 2009 and entitled VOLTAGE CONSERVATION USING ADVANCED METERING INFRASTRUCTURE AND SUBSTATION CENTRALIZED VOLTAGE CONTROL, the entirety of which are herein incorporated by reference. This application is indirectly related to U.S. application Ser. No. 13/567,473, filed Aug. 6, 2012. now U.S. Pat. No. 8,437,883, issued May 7, 2013, and U.S. application Ser. No. 14/554,917, filed Nov. 26, 2014. 
    
    
     FIELD OF THE DISCLOSURE 
     The present disclosure relates to a method, an apparatus, a system and a computer program for conserving energy. More particularly, the disclosure relates to a novel implementation of voltage conservation using advanced infrastructure and substation centralized voltage control. 
     BACKGROUND OF THE INVENTION 
     Electricity is commonly generated at a power station by electromechanical generators, which are typically driven by heat engines fueled by chemical combustion or nuclear fission, or driven by kinetic energy flowing from water or wind. The electricity is generally supplied to end users through transmission grids as an alternating current signal. The transmission grids may include a network of power stations, transmission circuits, substations, and the like. 
     The generated electricity is typically stepped-up in voltage using, for example, generating step-up transformers, before supplying the electricity to a transmission system. Stepping up the voltage improves transmission efficiency by reducing the electrical current flowing in the transmission system conductors, while keeping the power transmitted nearly equal to the power input. The stepped-up voltage electricity is then transmitted through the transmission system to a distribution system, which distributes the electricity to end users. The distribution system may include a network that carries electricity from the transmission system and delivering it to end users. Typically, the network may include medium-voltage (for example, less than 69 kV) power lines, electrical substations, transformers, low-voltage (for example, less than 1 kV) distribution wiring, electric meters, and the like. 
     The following describe subject matter related to power generation or distribution: Power Distribution Planning Reference Book, Second Edition, H. Lee Willis, 2004; Estimating Methodology for a Large Regional Application of Conservation Voltage Reduction, J. G. De Steese, S. B. Merrick, B. W. Kennedy, IEEE Transactions on Power. Systems, 1990; Implementation of Conservation Voltage Reduction at Commonwealth Edison, IEEE Transactions on Power Systems, D. Kirshner, 1990; and Conservation Voltage Reduction at Northeast Utilities, D. M. Lauria, IEEE, 1987. Further, U.S. Pat. No. 5,466,973, issued to Griffioen on Nov. 14, 1995, describes a method for regulating the voltage at which electric energy is supplied at the delivery points in a network for distributing electricity. 
     The disclosure provides a novel method, apparatus, system and computer program for conserving energy in electric systems. More particularly, the disclosure provides a novel solution to conserve energy by implementing voltage conservation using advanced infrastructure and substation centralized voltage control. 
     SUMMARY OF THE DISCLOSURE 
     According to an aspect of the disclosure, a voltage control and conservation (VCC) system is provided for monitoring, controlling and conserving enemy. The VCC system comprises: a substation configured to supply electrical power to a plurality of user locations; a smart meter located at one of the plurality of user locations and configured to generate smart meter data based on a measured component of electrical power received by the smart meter; and a voltage controller configured to generate an energy delivery parameter based on the smart meter data, wherein the substation is further configured to adjust a voltage set point value of the electrical power supplied to the plurality of user locations based on the energy delivery parameter, and wherein the smart meter is configured to operate in a report-by-exception mode and sua sponte send the smart meter data to the voltage controller when the measured component of electrical power is determined to be outside of a target component band. 
     The VCC system may further comprise a second smart meter located at a second one of the plurality of user locations and configured to generate second smart meter data based on a second measured component of electrical power received by the second smart meter, wherein the voltage controller is further configured to determine an average user voltage component by averaging the measured component of electrical power received by the smart meter and the second measured component of electrical power received by the second smart meter. 
     The VCC system may further comprise a collector configured to receive the smart meter data from the smart meter and generate collector data, wherein the voltage controller is further configured to generate the energy delivery parameter based on the collector data. 
     In the VCC system, the target component band may include a target voltage band, and the voltage controller may be configured to compare the measured component of electrical power received by the smart meter to the target voltage band and adjust the voltage set point based on a result of the comparison. 
     The substation may comprise: a load tap change transformer that adjusts the voltage set point value based on a load tap change coefficient; or a voltage regulator that adjusts the voltage set point value based on the energy delivery parameter. The substation may comprise a distribution bus that supplies the electrical power to the plurality of user locations, wherein an electrical power supply voltage component is measured on the distribution bus. 
     The voltage controller may comprise: a meter automation system server (MAS); a distribution management system (DMS); and a regional operation center (ROC). The voltage controller may be configured to adjust the voltage set point at a maximum rate of one load tap change step. The voltage controller may be configured to adjust the voltage set point based on the average user voltage component. The voltage controller may be configured to maintain the measured component of electrical power received by the smart meter within the target voltage band based on the result of the comparison. The voltage controller may be configured to select said smart meter for monitoring and create a connection to said smart meter after receiving the smart meter data sent sua sponte by said smart meter while operating in the report-by-exception mode. The voltage controller may be configured to de-select another smart meter that was previously selected to be monitored. The voltage controller may be configured to create a connection to said smart meter and terminate a connection to said another smart meter. The sua sponte smart meter data received from said smart meter may be representative of a low voltage limiting level in the system. The voltage controller may be configured to: store historical component data that includes at least one of an aggregated energy component data at a substation level, a voltage component data at a substation level, and a weather data; determine energy usage at each of the plurality of user locations; compare the historical component data to the determined energy usage; and determine energy savings attributable to the system based on the results of the comparison of the historical component data to the determined energy usage. The voltage controller may be configured to determine energy savings attributable to the system based on a linear regression that removes effects of weather, load growth, or economic effects. The voltage controller may be further configured to increase the voltage set point when either the electrical power supply voltage component or the average user voltage component falls below a target voltage band. 
     According to a further aspect of the disclosure, a VCC system is provided that comprises: a substation configured to supply electrical power to a plurality of user locations; a smart meter located at one of the plurality of user locations and configured to generate smart meter data based on a measured component of electrical power received by the smart meter; and a voltage controller configured to control a voltage set point of the electrical power supplied by the substation based on the smart meter data. The smart meter may be configured to operate in a report-by-exception mode, which comprises sua sponte sending the smart meter data to the voltage controller when the measured component of electrical power is determined to be outside of a target component band. 
     The VCC system may further comprise: a second smart meter located at a second one of the plurality of user locations, the second smart meter being configured to generate second smart meter data based on a second measured component of electrical power received by the second smart meter, wherein the voltage controller is further configured to determine an average user voltage component by averaging the measured component of electrical power received by the smart meter and the second measured component of electrical power received by the second smart meter. 
     The substation may comprise: a load tap change transformer that adjusts the voltage set point value based on a load tap change coefficient; or a voltage regulator that adjusts the voltage set point value based on the energy delivery parameter. The substation may comprise a distribution bus that supplies the electrical power to the plurality of user locations, wherein an electrical power supply voltage component is measured on the distribution bus. 
     The voltage controller may be configured to increase the voltage set point when either the electrical power supply voltage component or the average user voltage component falls below a target voltage band. The voltage controller may be configured to adjust the voltage set point at a maximum rate of one load tap change step. The voltage controller may be configured to compare the measured component of electrical power received by the smart meter to a target component band and adjust the voltage set point based on a result of the comparison. The voltage controller may be configured to adjust the voltage set point based on the average user voltage component. The target component band may include a target voltage band, and the voltage controller may be configured to maintain the measured component of electrical power received by the smart meter within the target voltage band based on the result of the comparison. 
     According to a still further aspect of the disclosure, a method is provided for controlling electrical power supplied to a plurality of user locations. The method comprises: receiving smart meter data from a first one of the plurality of user locations; and adjusting a voltage set point at a substation based on the smart meter data, wherein the smart meter data is sua sponte generated at the first one of the plurality of user locations when a measured component of electrical power that is supplied to the first one of the plurality of user locations is determined to be outside of a target component band. 
     The method may further comprise maintaining the average user voltage component within the target voltage band. The method may further comprise measuring a voltage component of the supplied electrical power on a distribution bus. The method may further comprise increasing the voltage set point when either the electrical power supply voltage component or an average user voltage component falls below the target component band. The method may further comprise: selecting said smart meter for monitoring; and creating a connection to said smart meter after receiving the smart meter data sent sua sponte by said smart meter while operating in a report-by-exception mode. The method may further comprise de-selecting another smart meter from a group of smart meters previously selected to be monitored. The method may further comprise terminating a connection to said another smart meter. The method may further comprise: storing historical component data that includes at least one of an aggregated energy component data at a substation level, a voltage component data at a substation level, and a weather data; determining energy usage at each of the plurality of user locations; comparing the historical component data to the determined energy usage; and determining energy savings attributable to the system based on the results of the comparison of the historical component data to the determined energy usage. The target component band may include a target voltage band. The method may further comprise: determining the target voltage band; and comparing an average user voltage component to the target voltage band. 
     The voltage set point may be adjusted based on the result of comparing the average user voltage component to the target voltage band. The sua sponte smart meter data received from the smart meter may be representative of a low voltage limiting level in the system. 
     According to a still further aspect of the disclosure, a computer readable medium is provided that tangibly embodies and includes a computer program for controlling electrical power supplied to a plurality of user locations. The computer program comprises a plurality of code sections, including: a receiving smart meter data code section that, when executed on a computer, causes receiving smart meter data from a first one of the plurality of user locations; and a voltage set point adjusting code section that, when executed on a computer, causes adjusting a voltage set point at a substation based on the smart meter data, wherein the smart meter data is sua sponte generated at the first one of the plurality of user locations when a measured component of electrical power that is supplied to the first one of the plurality of user locations is determined to be outside of a target component band. 
     The computer program may comprise an average user voltage component maintaining code section that, when executed on the computer, causes maintaining the average user voltage component within the target voltage band. The computer program may comprise a voltage component measuring code section that, when executed on the computer, causes a voltage component of the supplied electrical power to be measured on a distribution bus. The computer program may include a voltage set point increasing code section that, when executed on the computer, causes increasing the voltage set point when either the electrical power supply voltage component or an average user voltage component falls below the target component band. The computer program may comprise: a smart meter selection code section that, when executed on the computer, causes selecting said smart meter for monitoring; and a connection creation code section that, when executed on the computer, causes creating a connection to said smart meter after receiving the smart meter data sent sua sponte by said smart meter while operating in a report-by-exception mode. The computer program may comprise a smart meter de-selecting code section that, when executed on the computer, causes de-selecting another smart meter from a group of smart meters previously selected to be monitored. The computer program may comprise connection terminating code section that, when executed on the computer, causes terminating a connection to said another smart meter. 
     The computer program may comprise: a storing code section that, when executed on the computer, causes storing historical component data that includes at least one of an aggregated enemy component data at a substation level, a voltage component data at a substation level, and a weather data; an energy usage determining code section that, when executed on the computer, causes determining energy usage at each of the plurality of user locations; a comparing code section that, when executed on the computer, causes comparing the historical component data to the determined energy usage; and an energy savings determination code section that, when executed on the computer, causes determining energy savings attributable to the system based on the results of the comparison of the historical component data to the determined energy usage. The target component band may include a target voltage band. The computer program may comprise: a target voltage band determining code section that, when executed on the computer, causes determining the target voltage band; and a comparing code section that, when executed on the computer, causes comparing an average user voltage component to the target voltage band. The voltage set point may be adjusted based on the result of comparing the average user voltage component to the target voltage band. The sua sponte smart meter data received from the smart meter may be representative of a low voltage limiting level in the system. 
     Additional features, advantages, and embodiments of the disclosure may be set forth or apparent from consideration of the detailed description and drawings. Moreover, it is to be understood that both the foregoing summary of the disclosure and the following detailed description are exemplary and intended to provide further explanation without limiting the scope of the disclosure as claimed. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The accompanying drawings, which are included to provide a further understanding of the disclosure, are incorporated in and constitute a part of this specification, illustrate embodiments of the disclosure and together with the detailed description serve to explain the principles of the disclosure. No attempt is made to show structural details of the disclosure in more detail than may be necessary for a fundamental understanding of the disclosure and the various ways in which it may be practiced. In the drawings: 
         FIG. 1  shows an example of an electricity generation and distribution system, according to principles of the disclosure; 
         FIG. 2  shows an example of a voltage control and conservation (VCC) system, according to the principles of the disclosure; 
         FIG. 3  shows an example of a control screen that may be displayed on a regional operation center (ROC) computer, according to principles of the disclosure; 
         FIG. 4  shows an example of a voltage control and conservation (VCC) process according to principles of the disclosure; 
         FIG. 5A  shows an example of a process for monitoring the voltage component and electrical energy received and measured at selected smart meters, according to principles of the disclosure; 
         FIG. 5B  shows an example of a process for selecting a smart meter operating in a report-by-exception mode and de-selecting a previously selected smart meter, according to principles of the disclosure; 
         FIG. 6  shows an example of a graph of a voltage of electric power supplied to users versus a time of day, according to principles of the disclosure; 
         FIG. 7  shows an example of a graph of substation voltages of electric power produced by, for example, an LTC transformer at a substation, which may be associated with, for example, the information displayed on the control screen shown in  FIG. 3 ; 
         FIG. 8  shows an example of data collected (including voltage and energy measurement) hourly by the DMS in the example of  FIG. 7 , before application of the voltage control according to the principles of the disclosure; 
         FIG. 9  shows an example of the data collected (including voltage and energy measurement) hourly by the DMS in the example of  FIG. 7 , after application of the voltage control according to the principles of the disclosure; 
         FIG. 10  shows an example of calculation data for hours 1-5 and the average for the full twenty-four hours in the example of  FIGS. 7-9 ; 
         FIG. 11  shows an example where data may be collected for weather variables for the days before and after voltage control and/or conservation, according to principles of the disclosure; 
         FIG. 12  shows an example of an application of a paired test analysis process, according to principles of the disclosure; 
         FIG. 13  shows an example of a scatterplot of kW-per-customer days with VCC ON to kW-per-customer days with VCC OFF; 
         FIG. 14  shows an example of a summary chart for the data shown in  FIG. 13 , according to principles of the disclosure; 
         FIG. 15  shows an alternative example of a scatterplot of historical data before the VCC system is implemented, according to principles of the disclosure; 
         FIG. 16  shows an alternative example of a scatterplot of historical data after the VCC system is implemented, according to principles of the disclosure; and 
         FIG. 17  shows an alternative example of a summary chart, including 98% confidence intervals, according to principles of the disclosure. 
     
    
    
     The present disclosure is further described in the detailed description that follows. 
     DETAILED DESCRIPTION OF THE INVENTION 
     The disclosure and the various features and advantageous details thereof are explained more fully with reference to the non-limiting embodiments and examples that are described and/or illustrated in the accompanying drawings and detailed in the following description. It should be noted that the features illustrated in the drawings are not necessarily drawn to scale, and features of one embodiment may be employed with other embodiments as the skilled artisan would recognize, even if not explicitly stated herein. Descriptions of well-known components and processing techniques may be omitted so as to not unnecessarily obscure the embodiments of the disclosure. The examples used herein are intended merely to facilitate an understanding of ways in which the disclosure may be practiced and to further enable those of skill in the art to practice the embodiments of the disclosure. Accordingly, the examples and embodiments herein should not be construed as limiting the scope of the disclosure. Moreover, it is noted that like reference numerals represent similar parts throughout the several views of the drawings. 
     A “computer”, as used in this disclosure, means any machine, device, circuit, component, or module, or any system of machines, devices, circuits, components, modules, or the like, which are capable of manipulating data according to one or more instructions, such as, for example, without limitation, a processor, a microprocessor, a central processing unit, a general purpose computer, a super computer, a personal computer, a laptop computer, a palmtop computer, a notebook computer, a desktop computer, a workstation computer, a server, or the like, or an array of processors, microprocessors, central processing units, general purpose computers, super computers, personal computers, laptop computers, palmtop computers, notebook computers, desktop computers, workstation computers, servers, or the like. 
     A “server”, as used in this disclosure, means any combination of software and/or hardware, including at least one application and/or at least one computer to perform services for connected clients as part of a client-server architecture. The at least one server application may include, but is not limited to, for example, an application program that can accept connections to service requests from clients by sending back responses to the clients. The server may be configured to run the at least one application, often under heavy workloads, unattended, for extended periods of time with minimal human direction. The server may include a plurality of computers configured, with the at least one application being divided among the computers depending upon the workload. For example, under light loading, the at least one application can run on a single computer. However, under heavy loading, multiple computers may be required to run the at least one application. The server, or any if its computers, may also be used as a workstation. 
     A “database”, as used in this disclosure, means any combination of software and/or hardware, including at least one application and/or at least one computer. The database may include a structured collection of records or data organized according to a database model, such as, for example, but not limited to at least one of a relational model, a hierarchical model, a network model or the like. The database may include a database management system application (DBMS) as is known in the art. The at least one application may include, but is not limited to, for example, an application program that can accept connections to service requests from clients by sending back responses to the clients. The database may be configured to run the at least one application, often under heavy workloads, unattended, for extended periods of time with minimal human direction. 
     A “communication link”, as used in this disclosure, means a wired and/or wireless medium that conveys data or information between at least two points. The wired or wireless medium may include, for example, a metallic conductor link, a radio frequency (RF) communication link, an Infrared (IR) communication link, an optical communication link, or the like, without limitation. The RF communication link may include, for example, WiFi, IEEE 802.11, DECT, 0G, 1G, 2G, 3G or 4G cellular standards, Bluetooth, and the like. 
     The terms “including”, “comprising” and variations thereof, as used in this disclosure, mean “including, but not limited to”, unless expressly specified otherwise. 
     The terms “a”, “an”, and “the”, as used in this disclosure, means “one or more”, unless expressly specified otherwise. 
     Devices that are in communication with each other need not be in continuous communication with each other, unless expressly specified otherwise. In addition, devices that are in communication with each other may communicate directly or indirectly through one or more intermediaries. 
     Although process steps, method steps, algorithms, or the like, may be described in a sequential order, such processes, methods and algorithms may be configured to work in alternate orders. In other words, any sequence or order of steps that may be described does not necessarily indicate a requirement that the steps be performed in that order. The steps of the processes, methods or algorithms described herein may be performed in any order practical. Further, some steps may be performed simultaneously. 
     When a single device or article is described herein, it will be readily apparent that more than one device or article may be used in place of a single device or article. Similarly, where more than one device or article is described herein, it will be readily apparent that a single device or article may be used in place of the more than one device or article. The functionality or the features of a device may be alternatively embodied by one or more other devices which are not explicitly described as having such functionality or features. 
     A “computer-readable medium”, as used in this disclosure, means any medium that participates in providing data (for example, instructions) which may be read by a computer. Such a medium may take many forms, including non-volatile media, volatile media, and transmission media. Non-volatile media may include, for example, optical or magnetic disks and other persistent memory. Volatile media may include dynamic random access memory (DRAM). Transmission media may include coaxial cables, copper wire and fiber optics, including the wires that comprise a system bus coupled to the processor. Transmission media may include or convey acoustic waves, light waves and electromagnetic emissions, such as those generated during radio frequency (RF) and infrared (IR) data communications. Common forms of computer-readable media include, for example, a floppy disk, a flexible disk, hard disk, magnetic tape, any other magnetic medium, a CD-ROM, DVD, any other optical medium, punch cards, paper tape, any other physical medium with patterns of holes, a RAM, a PROM, an EPROM, a FLASH-EEPROM, any other memory chip or cartridge, a carrier wave as described hereinafter, or any other medium from which a computer can read. 
     Various forms of computer readable media may be involved in carrying sequences of instructions to a computer. For example, sequences of instruction (i) may be delivered from a RAM to a processor, (ii) may be carried over a wireless transmission medium, and/or (iii) may be formatted according to numerous formats, standards or protocols, including, for example, WiFi, WiMAX, IEEE 802.11, DECT, 0G, 1G, 2G, 3G or 4G cellular standards, Bluetooth, or the like. 
     According to one non-limiting example of the disclosure, a voltage control and conservation (VCC) system  200  is provided (shown in  FIG. 2 ), which includes three subsystems, including an energy delivery (ED) system  300 , an energy control (EC) system  400  and an energy regulation (ER) system  500 . The VCC system  200  is configured to monitor energy usage at the ED system  300  and determine one or more energy delivery parameters C ED  at the EC system (or voltage controller)  400 . The EC system  400  may then provide the one or more energy delivery parameters C ED  to the ER system  500  to adjust the energy delivered to a plurality of users for maximum energy conservation. 
     The VCC system  200  may be integrated into, for example, an existing load curtailment plan of an electrical power supply system. The electrical power supply system may include an emergency voltage reduction plan, which may be activated when one or more predetermined events are triggered. The predetermined events may include, for example, an emergency, a short circuit, an overheating of electrical conductors, when the electrical power output from the transformer exceeds, for example, 80% of its power rating, or the like. The VCC system  200  is configured to yield to the load curtailment plan when the one or more predetermined events are triggered, allowing the load curtailment plan to be executed to reduce the voltage of the electrical power supplied to the plurality of users. 
       FIG. 1  shows an example of an electricity generation and distribution system  100 , according to principles of the disclosure. The electricity generation and distribution system  100  includes an electrical power generating station  110 , a generating step-up transformer  120 , a substation  130 , a plurality of step-down transformers  140 ,  165 ,  167 , and users  150 ,  160 . The electrical power generating station  110  generates electrical power that is supplied to the step-up transformer  120 . The step-up transformer steps-up the voltage of the electrical power and supplies the stepped-up electrical power to an electrical transmission media  125 . 
     As seen in  FIG. 1 , the electrical transmission media may include wire conductors, which may be carried above ground by, for example, utility poles  127  and/or underground by, for example, shielded conductors (not shown). The electrical power is supplied from the step-up transformer  120  to the substation  130  as electrical power E In (t), where the electrical power E In  in Megawatts (MW) may vary as a function of time t. The substation  130  converts the received electrical power E In (t) to E Supply (t) and supplies the converted electrical power E Supply (t) to the plurality of users  150 ,  160 . The substation  130  may adjustably transform the voltage component V In (t) of the received electrical power E In (t) by, for example, stepping-down the voltage before supplying the electrical power E Supply (t) to the users  150 ,  160 . The electrical power E Supply (t) supplied from the substation  130  may be received by the step-down transformers  140 ,  165 ,  167  and supplied to the users  150 ,  160  through a transmission medium  142 ,  162 , such as, for example, but not limited to, underground electrical conductors (and/or above ground electrical conductors). 
     Each of the users  150 ,  160  may include an Advanced Meter Infrastructure (AMI)  155 ,  169 . The AMI  155 ,  169  may be coupled to a Regional Operations Center (ROC)  180 . The ROC  180  may be coupled to the AMI  155 ,  169 , by means of a plurality of communication links  175 ,  184 ,  188 , a network  170  and/or a wireless communication system  190 . The wireless communication system  190  may include, but is not limited to, for example, an RF transceiver, a satellite transceiver, and/or the like. 
     The network  170  may include, for example, at least one of the Internet, a local area network (LAN), a wide area network (WAN), a metropolitan area network (MAN), a personal area network (PAN), a campus area network, a corporate area network, a global area network (GAN), a broadband area network (BAN), or the like, any of which may be configured to communicate data via a wireless and/or a wired communication medium. The network  170  may be configured to include a network topology such as, for example, a ring, a mesh, a line, a tree, a star, a bus, a full connection, or the like. 
     The AMI  155 ,  169  may include any one or more of the following: A smart meter; a network interface (for example, a WAN interface, or the like); firmware; software; hardware; and the like. The smart meter may be configured to determine any one or more of the following: kilo-Watt-hours (kWh) delivered; kWh received; kWh delivered plus kWh received; kWh delivered minus kWh received; interval data; demand data; and the like. If the smart meter is a three phase meter, then the low phase voltage may be used in the average calculation. If the meter is a single phase meter, then the single voltage component will be averaged. 
     The AMI  155 ,  169  may further include one or more collectors (shown in  FIG. 2 ) configured to collect smart meter data from one or more smart meters tasked with, for example, measuring and reporting electric power delivery and consumption at one or more of the users  150 ,  160 . Alternatively (or additionally), the one or more collectors may be located external to the users  150 ,  160 , such as, for example, in a housing holding the step-down transformers  140 ,  165 ,  167 . Each of the collectors may be configured to communicate with the ROC  180 . 
     VCC System  200   
       FIG. 2  shows an example of the VCC system  200 , according to principles of the disclosure. The VCC system  200  includes the ED system  300 , the EC system  400  and the ER system  500 , each of which is shown as a broken-line ellipse. The VCC system  200  is configured to monitor energy usage at the ED system  300 . The ED system  300  monitors energy usage at one or more users  150 ,  160  (shown in  FIG. 1 ) and sends energy usage information to the EC system  400 . The EC system  400  processes the energy usage information and generates one or more energy delivery parameters C ED , which it sends to the ER system  500 . The ER system  500  receives the one or more energy delivery parameters C ED  and adjusts the electrical power E Supply (t) supplied to the users  150 ,  160  based on the received energy delivery parameters C ED . 
     The VCC system  200  minimizes power system losses, reduces user energy consumption and provides precise user voltage control. The VCC system  200  may include a closed loop process control application that uses user voltage data provided by the ED system  300  to control, for example, a voltage set point V SP  on a distribution circuit (not shown) within the ER system  500 . That is, the VCC system  200  may control the voltages V Supply (t) of the electrical power E Supply (t) supplied to the users  150 ,  160 , by adjusting the voltage set point V SP  of the distribution circuit in the ER system  500 , which may include, for example, one or more load tap changing (LTC) transformers, one or more voltage regulators, or other voltage controlling equipment to maintain a tighter band of operation of the voltages V Delivered (t) of the electric power E Delivered (t) delivered to the users  150 ,  160 , to lower power losses and facilitate efficient use of electrical power E Delivered (t) at the user locations  150  or  160 . 
     The VCC system  200  controls or adjusts the voltage V Supply (t) of the electrical power E Supply (t) supplied from the EC system  500  based on smart meter data, which includes measured voltage V Meter (t) data from the users  150 ,  160  in the ED system  300 . The VCC system  200  may adjust the voltage set point V SP  at the substation or line regulator level in the ER system  500  by, for example, adjusting the LTC transformer (not shown), circuit regulators (not shown), or the like, to maintain the user voltages V Meter (t) in a target voltage band V Band-n , which may include a safe nominal operating range. 
     The VCC system  200  is configured to maintain the electrical power E Delivered (t) delivered to the users  150 ,  160  within one or more voltage bands V Band-n . For example, the energy may be delivered in two or more voltage bands V Band-n  substantially simultaneously, where the two or more voltage bands may be substantially the same or different. The value V Band-n  may be determined by the following expression [1]: 
         V   Band-n   =V   SP   +ΔV    [1]
 
     where V Band-n  is a range of voltages, n is a positive integer greater than zero corresponding to the number of voltage bands V Band  that may be handled at substantially the same time, V SP  is the voltage set point value and ΔV is a voltage deviation range. 
     For example, the VCC system  200  may maintain the electrical power E Delivered (t) delivered to the users  150 ,  160  within a band V Band-1  equal to, for example, 111V to 129V for rural applications, where V SP  is set to 120V and ΔV is set to a deviation of seven-and-one-half percent (+/−7.5%). Similarly, the VCC system  200  may maintain the electrical power E Delivered (t) delivered to the users  150 ,  160  within a band V Band-2  equal to, for example, 114V to 126V for urban applications, where V SP  set to 120V and ΔV is set to a deviation of five (+/−5%). 
     The VCC system  200  may maintain the electrical power E Delivered (t) delivered to the users  150 ,  160  at any voltage band V Band-n  usable by the users  150 ,  160 , by determining appropriate values for V SP  and ΔV. In this regard, the values V SP  and ΔV may be determined by the EC system  400  based on the energy usage information for users  150 ,  160 , received from the ED system  300 . 
     The EC system  400  may send the V SP  and ΔV values to the ER system  500  as energy delivery parameters C ED , which may also include the value V Band-n . The ER system  500  may then control and maintain the voltage V Delivered (t) of the electrical power E Delivered (t) delivered to the users  150 ,  160 , within the voltage band V Band-n . The energy delivery parameters C ED  may further include, for example, load-tap-changer (LTC) control commands. 
     The VCC system  200  may further measure and validate energy savings by comparing energy usage by the users  150 ,  160  before a change in the voltage set point value V SP  (or voltage band V Band-n ) to the energy usage by the users  150 ,  160  after a change in the voltage set point value V SP  (or voltage band V BAND-n ), according to principles of the disclosure. These measurements and validations may be used to determine the effect in overall energy savings by, for example, lowering the voltage V Delivered (t) of the electrical power E Delivered (t) delivered to the users  150 ,  160 , and to determine optimal delivery voltage bands for the energy power E Delivered (t) delivered to the users  150 ,  160 . 
     ER System  500   
     The ER system  500  may communicate with the ED system  300  and/or EC system  400  by means of the network  170 . The ER system  500  is coupled to the network  170  and the EC system  400  by means of communication links  510  and  430 , respectively. The EC system  500  is also coupled to the ED system  300  by means of the power lines  340 , which may include communication links. 
     The ER system  500  includes a substation  530  which receives the electrical power supply E In (t) from, for example, the power generating station  110  (shown in  FIG. 1 ) on a line  520 . The electrical power E In (t) includes a voltage V In (t) component and a current I In (t) component. The substation  530  adjustably transforms the received electrical power E In (t) to, for example, reduce (or step-down) the voltage component V In (t) of the electrical power E In (t) to a voltage value V Supply (t) of the electrical power E Supply (t) supplied to the plurality of smart meters  330  on the power supply lines  340 . 
     The substation  530  may include a transformer (not shown), such as, for example, a load tap change (LTC) transformer. In this regard, the substation  530  may further include an automatic tap changer mechanism (not shown), which is configured to automatically change the taps on the LTC transformer. The tap changer mechanism may change the taps on the LTC transformer either on-load (on-load tap changer, or OLTC) or off-load, or both. The tap changer mechanism may be motor driven and computer controlled. The substation  530  may also include a buck/boost transformer to adjust and maximize the power factor of the electrical power E Delivered (t) supplied to the users on power supply lines  340 . 
     Additionally (or alternatively), the substation  530  may include one or more voltage regulators, or other voltage controlling equipment, as known by those having ordinary skill in the art, that may be controlled to maintain the output the voltage component V Supply (t) of the electrical power E Supply (t) at a predetermined voltage value or within a predetermined range of voltage values. 
     The substation  530  receives the energy delivery parameters C ED  from the EC system  400  on the communication link  430 . The energy delivery parameters C ED  may include, for example, load tap coefficients when an LTC transformer is used to step-down the input voltage component V In (t) of the electrical power E In (t) to the voltage component V Supply (t) of the electrical power E Supply (t) supplied to the ED system  300 . In this regard, the load tap coefficients may be used by the ER system  500  to keep the voltage component V Supply (t) on the low-voltage side of the LTC transformer at a predetermined voltage value or within a predetermined range of voltage values. 
     The LTC transformer may include, for example, seventeen or more steps (thirty-five or more available positions), each of which may be selected based on the received load tap coefficients. Each change in step may adjust the voltage component V Supply (t) on the low voltage side of the LTC transformer by as little as, for example, about five-thousandths (0.5%), or less. 
     Alternatively, the LTC transformer may include fewer than seventeen steps. Similarly, each change in step of the LTC transformer may adjust the voltage component V Supply (t) on the low voltage side of the LTC transformer by more than, for example, about five-thousandths (0.5%). 
     The voltage component V Supply (t) may be measured and monitored on the low voltage side of the LTC transformer by, for example, sampling or continuously measuring the voltage component V Supply (t) of the stepped-down electrical power E Supply (t) and storing the measured voltage component V Supply (t) values as a function of time t in a storage (not shown), such as, for example, a computer readable medium. The voltage component V Supply (t) may be monitored on, for example, a substation distribution bus, or the like. Further, the voltage component V Supply (t) may be measured at any point where measurements could be made for the transmission or distribution systems in the ER system  500 . 
     Similarly, the voltage component V In (t) of the electrical power E In (t) input to the high voltage side of the LTC transformer may be measured and monitored. Further, the current component I Supply (t) of the stepped-down electrical power E Supply (t) and the current component I In (t) of the electrical power E In (t) may also be measured and monitored. In this regard, a phase difference φ In (t) between the voltage V In (t) and current  140  components of the electrical power E In (t) may be determined and monitored. Similarly, a phase difference φ Supply (t) between the voltage V Supply (t) and current I Supply (t) components of the electrical energy supply E Supply (t) may be determined and monitored. 
     The ER system  500  may provide electrical energy supply status information to the EC system  400  on the communication links  430  or  510 . The electrical energy supply information may include the monitored voltage component V Supply (t). The electrical energy supply information may further include the voltage component V In (t), current components I In (t), I Supply (t), and/or phase difference values φ In (t), φ Supply (t), as a function of time t. The electrical energy supply status information may also include, for example, the load rating of the LTC transformer. 
     The electrical energy supply status information may be provided to the EC system  400  at periodic intervals of time, such as, for example, every second, 5 sec., 10 sec., 30 sec., 60 sec., 120 sec., 600 sec., or any other value within the scope and spirit of the disclosure, as determined by one having ordinary skill in the art. The periodic intervals of time may be set by the EC system  400  or the ER system  500 . Alternatively, the electrical energy supply status information may be provided to the EC system  400  or ER system  500  intermittently. 
     Further, the electrical energy supply status information may be forwarded to the EC system  400  in response to a request by the EC system  400 , or when a predetermined event is detected. The predetermined event may include, for example, when the voltage component V Supply (t) changes by an amount greater (or less) than a defined threshold value V SupplyThreshold  (for example, 130V) over a predetermined interval of time, a temperature of one or more components in the ER system  500  exceeds a defined temperature threshold, or the like. 
     ED System  300   
     The ED system  300  includes a plurality of smart meters  330 . The ED system  300  may further include at least one collector  350 , which is optional. The ED system  300  may be coupled to the network  170  by means of a communication link  310 . The collector  350  may be coupled to the plurality of smart meters  330  by means of a communication link  320 . The smart meters  330  may be coupled to the ER system  500  by means of one or more power supply lines  340 , which may also include communication links. 
     Each smart meter  330  is configured to measure, store and report energy usage data by the associated users  150 ,  160  (shown in  FIG. 1 ). Each smart meter  330  is further configured to measure and determine energy usage at the users  150 ,  160 , including the voltage component V Meter (t) and current component I Meter (t) of the electrical power E Meter (t) used by the users  150 ,  160 , as a function of time. The smart meters  330  may measure the voltage component V Meter (t) and current component I Meter (t) of the electrical power E Meter (t) at discrete times t s , where s is a sampling period, such as, for example, s=5 sec., 10 sec., 30 sec., 60 sec., 300 sec., 600 sec., or more. For example, the smart meters  330  may measure energy usage every, for example, minute (t 60 sec ), five minutes (t 30 sec ), ten minutes ( t600 sec ), or more, or at time intervals variably set by the smart meter  330  (for example, using a random number generator). 
     The smart meters  330  may average the measured voltage V Meter (t) and/or I Meter (t) values over predetermined time intervals (for example, 5 min., 10 min., 30 min., or more). The smart meters  330  may store the measured electrical power usage E Meter (t), including the measured voltage component V Meter (t) and/or current component I Meter (t) as smart meter data in a local (or remote) storage (not shown), such as, for example, a computer readable medium. 
     Each smart meter  330  is also capable of operating in a “report-by-exception” mode for any voltage V Meter (t), current I Meter (t), or energy usage E Meter (t) that falls outside of a target component band. The target component band may include, a target voltage band, a target current band, or a target energy usage band. In the “report-by-exception” mode, the smart meter  330  may sua sponte initiate communication and send smart meter data to the EC system  400 . The “report-by-exception” mode may be used to reconfigure the smart meters  330  used to represent, for example, the lowest voltages on the circuit as required by changing system conditions. 
     The smart meter data may be periodically provided to the collector  350  by means of the communication links  320 . Additionally, the smart meters  330  may provide the smart meter data in response to a smart meter data request signal received from the collector  350  on the communication links  320 . 
     Alternatively (or additionally), the smart meter data may be periodically provided directly to the EC system  400  (for example, the MAS  460 ) from the plurality of smart meters, by means of, for example, communication links  320 ,  410  and network  170 . In this regard, the collector  350  may be bypassed, or eliminated from the ED system  300 . Furthermore, the smart meters  330  may provide the smart meter data directly to the EC system  400  in response to a smart meter data request signal received from the EC system  400 . In the absence of the collector  350 , the EC system (for example, the MAS  460 ) may carry out the functionality of the collector  350  described herein. 
     The request signal may include, for example, a query (or read) signal and a smart meter identification signal that identifies the particular smart meter  330  from which smart meter data is sought. The smart meter data may include the following information for each smart meter  130 , including, for example, kilo-Watt-hours (kWh) delivered data, kWh received data, kWh delivered plus kWh received data, kWh delivered minus kWh received data, voltage level data, current level data, phase angle between voltage and current, kVar data, time interval data, demand data, and the like. 
     Additionally, the smart meters  330  may send the smart meter data to the meter automation system server MAS  460 . The smart meter data may be sent to the MAS  460  periodically according to a predetermined schedule or upon request from the MAS  460 . 
     The collector  350  is configured to receive the smart meter data from each of the plurality of smart meters  330  via the communication links  320 . The collector  350  stores the received smart meter data in a local storage (not shown), such as, for example, a computer readable medium. The collector  350  compiles the received smart meter data into a collector data. In this regard, the received smart meter data may be aggregated into the collector data based on, for example, a geographic zone in which the smart meters  330  are located, a particular time band (or range) during which the smart meter data was collected, a subset of smart meters  330  identified in a collector control signal, and the like. In compiling the received smart meter data, the collector  350  may average the voltage component V Meter (t) values received in the smart meter data from all (or a subset of all) of the smart meters  330 . 
     The EC system  400  is able to select or alter a subset of all of the smart meters  330  to be monitored for predetermined time intervals, which may include for example 15 minute intervals. It is noted that the predetermined time intervals may be shorter or longer than 15 minutes. The subset of all of the smart meters  330  is selectable and can be altered by the EC system  400  as needed to maintain minimum level control of the voltage V Supply (t) supplied to the smart meters  330 . 
     The collector  350  may also average the electrical power E Meter (t) values received in the smart meter data from all (or a subset of all) of the smart meters  330 . The compiled collector data may be provided by the collector  350  to the EC system  400  by means of the communication link  310  and network  170 . For example, the collector  350  may send the compiled collector data to the MAS  460  (or ROC  490 ) in the EC system  400 . 
     The collector  350  is configured to receive collector control signals over the network  170  and communication link  310  from the EC system  400 . Based on the received collector control signals, the collector  350  is further configured to select particular ones of the plurality of smart meters  330  and query the meters for smart meter data by sending a smart meter data request signal to the selected smart meters  330 . The collector  350  may then collect the smart meter data that it receives from the selected smart meters  330  in response to the queries. The selectable smart meters  330  may include any one or more of the plurality of smart meters  330 . The collector control signals may include, for example, an identification of the smart meters  330  to be queried (or read), times) at which the identified smart meters  330  are to measure the V Meter (t) I Meter (t), E Meter (t) and/or φ Meter (t) (φ Meter (t) is the phase difference between the voltage V Meter (t) and current I Meter (t) components of the electrical power E Meter (t) measured at the identified smart meter  330 ), energy usage information since the last reading from the identified smart meter  330 , and the like. The collector  350  may then compile and send the compiled collector data to the MAS  460  (and/or ROC  490 ) in the EC system  400 . 
     EC System  400   
     The EC system  400  may communicate with the ED system  300  and/or ER system  500  by means of the network  170 . The EC system  400  is coupled to the network  170  by means of one or more communication links  410 . The EC system  400  may also communicate directly with the ER system  500  by means of a communication link  430 . 
     The EC system  400  includes the MAS  460 , a database (DB)  470 , a distribution management system (DMS)  480 , and a regional operation center (ROC)  490 . The ROC  490  may include a computer (ROC computer)  495 , a server (not shown) and a database (not shown). The MAS  460  may be coupled to the DB  470  and DMS  480  by means of communication links  420  and  440 , respectively. The DMS  480  may be coupled to the ROC  490  and ER SYSTEM  500  by means of the communication link  430 . The database  470  may be located at the same location as (for example, proximate to, or within) the MAS  460 , or at a remote location that may be accessible via, for example, the network  170 . 
     The EC system  400  is configured to de-select, from the subset of monitored smart meters  330 , a smart meter  330  that the EC system  400  previously selected to monitor, and select the smart meter  330  that is outside of the subset of monitored smart meters  330 , but which is operating in the report-by-exception mode. The EC system  400  may carry out this change after receiving the sua sponte smart meter data from the non-selected smart meter  330 . In this regard, the EC system  400  may remove or terminate a connection to the de-selected smart meter  330  and create a new connection to the newly selected smart meter  330  operating in the report-by-exception mode. The EC system  400  is further configured to select any one or more of the plurality of smart meters  330  from which it receives smart meter data comprising, for example, the lowest measured voltage component V Meter (t), and generate an energy delivery parameter C ED  based on the smart meter data received from the smart meter(s)  330  that provide the lowest measured voltage component V Meter (t). 
     The MAS  460  may include a computer (not shown) that is configured to receive the collector data from the collector  350 , which includes smart meter data collected from a selected subset (or all) of the smart meters  330 . The MAS  460  is further configured to retrieve and forward smart meter data to the ROC  490  in response to queries received from the ROC  490 . The MAS  460  may store the collector data, including smart meter data in a local storage and/or in the DB  470 . 
     The DMS  480  may include a computer that is configured to receive the electrical energy supply status information from the substation  530 . The DMS  480  is further configured to retrieve and forward measured voltage component V Meter (t) values and electrical power E Meter (t) values in response to queries received from the ROC  490 . The DMS  480  may be further configured to retrieve and forward measured current component V Meter (t) values in response to queries received from the ROC  490 . The DMS  480  also may be further configured to retrieve all “report-by-exception” voltages V Meter (t) from the smart meters  330  operating in the “report-by-exception” mode and designate the voltages V Meter (t) as one of the control points to be continuously read at predetermined times (for example, every 15 minutes, or less (or more), or at varying times). The “report-by-exception voltages V Meter (t) may be used to control the EC  500  set points. 
     The DB  470  may include a plurality of relational databases (not shown). The DB  470  includes a large number of records that include historical data for each smart meter  330 , each collector  350 , each substation  530 , and the geographic area(s) (including latitude, longitude, and altitude) where the smart meters  330 , collectors  350 , and substations  530  are located. 
     For instance, the DB  470  may include any one or more of the following information for each smart meter  330 , including: a geographic location (including latitude, longitude, and altitude); a smart meter identification number; an account number; an account name; a billing address; a telephone number; a smart meter type, including model and serial number; a date when the smart meter was first placed into use; a time stamp of when the smart meter was last read (or queried); the smart meter data received at the time of the last reading; a schedule of when the smart meter is to be read (or queried), including the types of information that are to be read; and the like. 
     The historical smart meter data may include, for example, the electrical power E Meter (t) used by the particular smart meter  330 , as a function of time. Time t may be measured in, for example, discrete intervals at which the electrical power E Meter magnitude (kWh) of the received electrical power E Meter (t) is measured or determined at the smart meter  330 . The historical smart meter data includes a measured voltage component V Meter (t) of the electrical energy E Meter (t) received at the smart meter  330 . The historical smart meter data may further include a measured current component I Meter (t) and/or phase difference φ Meter (t) of the electrical power E Meter (t) received at the smart meter  330 . 
     As noted earlier, the voltage component V Meter (t) may be measured at a sampling period of, for example, every five seconds, ten seconds, thirty seconds, one minute, five minutes, ten minutes, fifteen minutes, or the like. The current component I Meter (t) and/or the received electrical power E Meter (t) values may also be measured at substantially the same times as the voltage component V Meter (t). 
     Given the low cost of memory, the DB  470  may include historical data from the very beginning of when the smart meter data was first collected from the smart meters  330  through to the most recent smart meter data received from the smart meter  330   s.    
     The DB  470  may include a time value associated with each measured voltage component V Meter (t), current component I Meter (t), phase component φ Meter (t) and/or electrical power E Meter (t), which may include a timestamp value generated at the smart meter  330 . The timestamp value may include, for example, a year, a month, a day, an hour, a minute, a second, and a fraction of a second. Alternatively, the timestamp may be a coded value which may be decoded to determine a year, a month, a day, an hour, a minute, a second, and a fraction of a second, using, for example, a look up table. The ROC  490  and/or smart meters  330  may be configured to receive, for example, a WWVB atomic clock signal transmitted by the U.S. National Institute of Standards and Technology (NIST), or the like and synchronize its internal clock (not shown) to the WWVB atomic clock signal. 
     The historical data in the DB  470  may further include historical collector data associated with each collector  350 . The historical collector data may include any one or more of the following information, including, for example: the particular smart meters  330  associated with each collector  350 ; the geographic location (including latitude, longitude, and altitude) of each collector  350 ; a collector type, including model and serial number; a date when the collector  350  was first placed into use; a time stamp of when collector data was last received from the collector  350 ; the collector data that was received; a schedule of when the collector  350  is expected to send collector data, including the types of information that are to be sent; and the like. 
     The historical collector data may further include, for example, an external temperature value T Collector (t) measured outside of each collector  350  at time t. The historical collector data may further include, for example, any one or more of the following for each collector  350 : an atmospheric pressure value P Collector (t) measured proximate the collector  350  at time t; a humidity value H Collector (t) measured proximate the collector  350  at time t; a wind vector value W Collector (t) measured proximate the collector  350  at time t, including direction and magnitude of the measured wind; a solar irradiant value L Collector (t) (kW/m 2 ) measured proximate the collector  350  at time t; and the like. 
     The historical data in the DB  470  may further include historical substation data associated with each substation  530 . The historical substation data may include any one or more of the following information, including, for example: the identifications of the particular smart meters  330  supplied with electrical energy E Supply (t) by the substation  530 ; the geographic location (including latitude, longitude, and altitude) of the substation  530 ; the number of distribution circuits; the number of transformers; a transformer type of each transformer, including model, serial number and maximum Megavolt Ampere (MVA) rating; the number of voltage regulators; a voltage regulator type of each voltage regulator, including model and serial number; a time stamp of when substation data was last received from the substation  530 ; the substation data that was received; a schedule of when the substation  530  is expected to provide electrical energy supply status information, including the types of information that are to be provided; and the like. 
     The historical substation data may include, for example, the electrical power E Supply (t) supplied to each particular smart meter  330 , where E Supply (t) is measured or determined at the output of the substation  530 . The historical substation data includes a measured voltage component V Supply (t) of the supplied electrical power E Supply (t), which may be measured, for example, on the distribution bus (not shown) from the transformer. The historical substation data may further include a measured current component I Supply (t) of the supplied electrical power E Supply (t). As noted earlier, the voltage component V Supply (t), the current component I Supply (t), and/or the electrical power E Supply (t) may be measured at a sampling period of, for example, every five seconds, ten seconds, thirty seconds, a minute, five minutes, ten minutes, or the like. The historical substation data may further include a phase difference value φ Supply (t) between the voltage V Supply (t) and current I Supply (t) signals of the electrical power E Supply (t), which may be used to determine the power factor of the electrical power E Supply (t) supplied to the smart meters  330 . 
     The historical substation data may further include, for example, the electrical power E In (t) received on the line  520  at the input of the substation  530 , where the electrical power E In (t) is measured or determined at the input of the substation  530 . The historical substation data may include a measured voltage component V In (t) of the received electrical power E In (t), which may be measured, for example, at the input of the transformer. The historical substation data may further include a measured current component I In (t) of the received electrical power E In (t). As noted earlier, the voltage component V In (t), the current component I In (t), and/or the electrical power E In (t) may be measured at a sampling period of, for example, every five seconds, ten seconds, thirty seconds, a minute, five minutes, ten minutes, or the like. The historical substation data may further include a phase difference φ In (t) between the voltage component V In (t) and current component I In (t) of the electrical power E In (t). The power factor of the electrical power E In (t) may be determined based on the phase difference φ In (t). 
     According to an aspect of the disclosure, the EC system  400  may save aggregated kW data at the substation level, voltage data at the substation level, and weather data to compare to energy usage per smart meter  330  to determine the energy savings from the VCC system  200 , and using linear regression to remove the affects of weather, load growth, economic effects, and the like, from the calculation. 
     In the VCC system  200 , control may be initiated from, for example, the ROC computer  495 . In this regard, a control screen  305  may be displayed on the ROC computer  495 , as shown, for example, in  FIG. 3 . The control screen  305  may correspond to data for a particular substation  530  (for example, the TRABUE SUBSTATION) in the ER system  500 . The ROC computer  495  can control and override (if necessary), for example, the substation  530  load tap changing transformer based on, for example, the smart meter data received from the ED system  300  for the users  150 ,  160 . The ED system  300  may determine the voltages of the electrical power supplied to the user locations  150 ,  160 , at predetermined (or variable) intervals, such as, e.g., on average each 15 minutes, while maintaining the voltages within required voltage limits. 
     For system security, the substation  530  may be controlled through the direct communication link  430  from the ROC  490  and/or DMS  480 . 
     Furthermore, an operator can initiate a voltage control program on the ROC computer  490 , overriding the controls, if necessary, and monitoring a time it takes to read the user voltages V Meter (t) being used for control of, for example, the substation LTC transformer (not shown) in the ER system  500 . 
       FIG. 4  shows an example of a voltage control and conservation (VCC) process according to principles of the disclosure. The VCC process may be carried out by, for example, but not limited to, the VCC system  200  shown in  FIG. 2 . 
     Referring to  FIGS. 2 and 4 , a target voltage band V Band-n  may be determined for the voltage component V Meter (t) of the electrical power E Meter (t) received and measured at the smart meters  330  (Step  610 ). The target voltage band V Band-n  may be determined by setting a voltage set point value V SP  and a permissible voltage deviation range ΔV according to the expression [1] V Band-n =V SP +ΔV. For instance, the voltage set point V SP  value may be set to 120V with a permissible voltage deviation of ΔV of five percent (+/−5%) for the target voltage band V Band-1 . In this example, the target voltage band V Band-n  will be from about 114V (i.e., 120V−(120V.times.0.050)) to about 126V (i.e., 120V+(120V.times.0.050)). 
     The voltage component V Supply (t) and electrical power E Supply (t) values measured at substation  530  may be retrieved from the DMS  480  (Step  620 ). The current, or most recent voltage component V Meter (t) and electrical power E Meter (t) values received and measured at the selected subset of the plurality of smart meters  330  may be retrieved from the MAS  460  (or a local storage, such as, for example, a computer readable medium, in the ROC  490 ) (Step  630 ). The current, or most recent voltage component V Meter (t) and electrical power E Meter (t) values may have been measured by the select subset of smart meters  330  and forwarded to the MAS  460  via the collector  350 , as described above. 
     Alternatively, the current, or most recent voltage component V Meter (t) and electrical power E Meter (t) values may have been retrieved directly from the collector  350  or the selected subset of the smart meters  330  (Step  630 ). 
     The current, or most recent voltage component V Meter (t) and electrical power E Meter (t) values may have been measured at the selected subset of smart meters  330  in response to a smart meter data request signal received from the collector  350 . The collector  350  may have sent the smart meter data request signal in response to a collector control signal received from the MAS  460  (or the ROC  490 ). 
     The current, or most recent voltage component V Meter (t) values may be averaged for the selected number of smart meters  330  to determine an average voltage component V Meter-Avg (t) value for the electrical power delivered to the selected smart meters  330 . This average voltage component V Meter-Avg (t) value may then be compared to the target voltage band V Band-n  to determine whether the average voltage component V Meter-Avg (t) value is within the target voltage band V Band-n  (Step  650 ). 
     If the average voltage component V Meter-Avg (t) value is outside of the target voltage band V Band-n , then a determination is made to change the set point voltage V SP  of the voltage component V Supply (t) output by the substation  530  (YES at Step  660 ). Energy delivery parameters C ED  may be generated and sent to the substation  530  to adjust the set point voltage V SP  of the output voltage component V Supply (t) (Step  670 ). A new voltage set point voltage V SP  value may be calculated by the DMS  480 . Where a LTC transformer is used, the voltage set point voltage V SP  value may be increased (or decreased) at a maximum rate of, for example, one volt about every, for example, fifteen minutes (Note: for example, a 0.625% voltage change per step in a LTC transformer). It is noted that the voltage set point voltage V SP  value may be increased (or decreased) at a rate of, for example, a fraction of a volt, or multiple volts at one time. The energy delivery parameters C ED  may include, for example, load tap coefficients. The set point voltage V SP  may be adjusted up (or down) by, for example, a fraction of a Volt (e.g., 0.01V, 0.02V, . . . , 0.1V, 0.2V, . . . , 1.0V, . . . , or the like). 
     Furthermore; when either the V Supply t) or the V Meter-Avg (t) voltage components reach or fall below a predetermined minimum voltage range (for example, about 118V to about 119V), the set point voltage V SP  may be increased. When the voltage set point V SP  is raised, the V Supply (t) or the V Meter-Avg ) voltage components should remain in a higher voltage band for, e.g., twenty-four hours before the voltage set point V SP  may be lowered again. 
     If the average voltage component V Meter-Avg value is within the target voltage band V Band-n , then a determination is made not to change the set point voltage V SP  of the voltage component V Supply (t) output by the substation  530  (NO at Step  660 ), and a determination may be made whether to end the VCC process (Step  680 ). If a determination is made not to end the VCC process (NO at Step  680 ), the VCC process repeats. 
     According to an aspect of the disclosure, a computer readable medium is provided containing a computer program, which when executed on, for example, the ROC  495  (shown in  FIG. 2 ), causes the VCC process according to  FIG. 4  to be carried out. The computer program may be tangibly embodied in the computer readable medium, comprising a code segment or code section for each of the Steps  610  through  680 . 
       FIG. 5A  shows an example of a process for monitoring the voltage component V Meter (t) and electrical power E Meter (t) received and measured at selected smart meters  330 , according to an aspect of disclosure. 
     Referring to  FIGS. 2 and 5A , initially a subset of smart meters  330  is selected from the smart meters  330  that are coupled to the power lines  340 , which are supplied with the electrical energy E Supply (t) out from the substation  530  (Step  710 ). The subset may include, for example, one or more (or all) of the smart meters  330  that are selected randomly or based on predetermined criteria live predetermined criteria may include, for example, historical smart meter data, weather conditions, geographic area, solar irradiation, historical energy usage associated with particular smart meters  330 , and the like. The smart meters  330  may be selected, for example, at the ROC  490  or MAS  460 . 
     A schedule may be generated to obtain smart meter data from the selected subset of smart meters  330  (Step  720 ). The schedule may include, for example, measuring the received voltage component V Meter (t) and electrical power E Meter (t) every, for example, five seconds, ten seconds, thirty seconds, one minute, five minutes, ten minutes, fifteen minutes, or the like, at the selected subset of smart meters  330 . The generated schedule is provided to the collector  350  that is associated with the selected subset of smart meters  330  as part of a collector control signal (Step  730 ). The collector control signal may be generated at, for example, the ROC  490  or MAS  460  and sent to the collector  350  via communication link  410  and network  170 . 
     The collector  350 , based on the provided collector control signal or a previously received schedule, may send a smart meter data request signal to the selected subset of smart meters  330  via communication links  320 . The smart meter data request signal may include, for example, the schedule provided in the collector control signal. The schedule may be stored at the selected subset of smart meters  330  and used by the smart meters  330  to control monitoring and reporting of the received voltage component V Meter (t) and electrical power E Meter (t) for the associated user  150  ( 160 ). 
     The collector  350  receives the reported smart meter data, including the voltage component V Meter (t) and electrical energy E Meter (t) for the associated user  150  ( 160 ), from the selected subset of smart meters  330  via communication links  320 . The collector  350  compiles the received smart meter data, generating collector data and sending the collector data to the EC system  400 . 
     The collector data is received from the collector  350  (Step  740 ) and stored locally (or remotely) in the EC system  400  (Step  750 ). In particular, the received collector data is stored locally in, for example, the ROC  490 , the MAS  460  and/or the DB  470 . 
     According to an aspect of the disclosure, a computer readable medium is provided containing a computer program, which when executed on, for example, the ROC  495  (shown in  FIG. 2 ), causes the process for monitoring the voltage component and electrical power to be carried out according to  FIG. 5A . The computer program may be tangibly embodied in the computer readable medium, comprising a code segment or code section for each of the Steps  710  through  750 . 
       FIG. 5B  shows an example of a process for selecting a smart meter  330  operating in a report-by-exception mode and de-selecting a previously selected smart meter, according to principles of the disclosure. 
     Referring to  FIG. 2  and  FIG. 5B , the EC system  400  is configured to listen or monitor for sua sponte smart meter data that may be received from one or more of the smart meters  330  operating in the report-by-exception mode (Step  760 ). If sua sponte smart meter data is received from a particular smart meter  330  (YES, at Step  760 ), then the EC system  400  will proceed to select that particular smart meter  330  (Step  765 ) and create a communication link to the smart meter  330  (Step  770 ), otherwise the EC system  400  continues to monitor for sua sponte smart meter data (NO, at Step  760 ). The EC system  400  de-selects a previously selected smart meter  330  (Step  775 ), which was selected as part of the subset smart meters  330  to be monitored from the plurality of smart meters  330 , and terminates the communication link to the de-selected smart meter  330  (Step  780 ). The EC system  400  may use the sua sponte smart meter data to determine a voltage set point and provide the voltage set point to the ER system  500  to adjust the voltage set point (Step  785 ). 
     According to an aspect of the disclosure, a computer readable medium is provided containing a computer program, which when executed on, for example, the ROC  495  (shown in  FIG. 2 ), causes the process for selecting a smart meter  330  operating in a report-by-exception mode and de-selecting a previously selected smart meter. The computer program may be tangibly embodied in the computer readable medium, comprising a code segment or code section for each of the Steps  760  through  785 . 
       FIG. 6  shows an example of a graph of a voltage of electric power supplied to users  150 ,  160 , versus a time of day, according to principles of the disclosure. In particular, the upper waveform  805  shows an example of voltage fluctuations in the electrical power delivered to the users  150 ,  160 , without the VCC system  200 . The lower waveform  808  shows an example of voltage fluctuations in the electric power delivered to users  150 ,  160 , with the VCC system  200 . The area  807  between the upper waveform  805  and lower waveform  808  corresponds to the energy saved using the VCC system  200 . 
     As seen in  FIG. 6 , the lower waveform  808  includes a tighter range (lower losses) of voltage fluctuations compared to the upper waveform  805 , which experiences higher voltage fluctuations and increased losses, resulting in substantially reduced power losses for the lower waveform  808 . For example, the voltage  805  may fluctuate between about 114V and about 127V. Whereas, in the VCC system  200 , the voltage waveform  808  fluctuation may be reduced to, for example, between about 114V and about 120V. As seen in the graph, the VCC system  200  may provide conservation through, for example, avoided energy imports and behind-the-meter savings. Further, the VCC system  200  may provide high confidence level of savings without having to depend on the actions of the users  150 ,  160 . 
       FIG. 7  shows an example of a waveform  810  of substation voltages V Supply (t) of electric power produced by, for example, an LTC transformer at the substation  530 , which may be associated with, for example, the information displayed on the control screen  305  shown in  FIG. 3 . A waveform  820  shows an average of, for example, twenty lowest level (or worst case) user voltages V Meter (t) (for example, the ten worst voltages on one distribution circuit averaged with the ten worst voltages on another distribution circuit) monitored at any one time on two distribution circuits that supply, for example, six-thousand-four-hundred users  150 ,  160  (shown in  FIG. 1 ) with electrical power during a period of time. In particular, the graph  810  shows an example of voltage fluctuations (for example, an average of voltage  812  fluctuations and voltage  814  fluctuations on the pair of circuits, respectively) in the electrical power produced by the substation  530  (for example, the TRABUE SUBSTATION in  FIG. 3 ) and the voltage  820  fluctuations (for example, on the pair of circuits) in the electrical power delivered to the users  150 ,  160 . 
     The waveforms  810  and  820  prior to time t 0  show an example of voltage fluctuations in the electrical power E Supply (t) supplied by the substation  530  and electrical power E Meter (t) received by the users  150 ,  160 , without the VCC system  200 . The waveforms  810  and  820  after time t 0  show an example of voltage fluctuations in the electrical power E Supply (t) supplied by the substation  530  and electrical power E Meter (t) received by the users  150 ,  160 , with the VCC system  200 . As seen in  FIG. 7 , before voltage control was applied (i.e., before t 0 ), the voltages  812 ,  814  (with an average voltage signal  810 ) of the electrical power E Supply (t) supplied by the substation  530  generally fluctuated between, for example, about 123V and about 126V; and the voltage waveform  820  of the electrical power E Meter (t) received by the users  150 ,  160 , generally fluctuated between, for example, about 121V and 124V. After voltage control was applied, the voltage waveforms  812 ,  814  ( 810 ) generally fluctuated between, for example, about 120V and about 122V, and the voltage waveform  820  generally fluctuated between, for example, about 116V and about 121V. Accordingly, the VCC system  200  is able to operate the users  150 ,  160 , in a lower band level. 
     Energy savings  807  (shown in  FIG. 6 ) that result from operation of the VCC system  200 , according to principles of the disclosure, may be measured and/or validated by measuring the voltage component V Supply (t) and electrical power E Supply (t) levels of electric power supplied by the substation  530  relative to the corresponding reference voltage set point V SP ( 1 ) value. In the example shown in  FIG. 7 , the voltage V Supply (t) and electrical energy E Supply (t) levels may be measured at the transformer output (not shown) where the voltage control may be implemented. However, the measurement may be performed at any point where measurements could be made for the transmission or distribution systems. 
       FIG. 8  shows an example of data collected (including voltage and energy measurement) hourly by the DMS  480  (shown in  FIG. 2 ), before time t 0  (shown in  FIG. 7 ), when voltage control is not carried out in the VCC system  200 . As seen in  FIG. 8 , the collected data may include, for example, a date, a time (hour:minute:second), a power level (MWatt), a reactive power level (MVAr), a voltage (V), an apparent power level (MVA), a power factor (PF), loss factor, and loss FTR, of the electrical power E Supply (t) output by the substation  530 . 
       FIG. 9  shows an example of data collected (including voltage and energy measurement) hourly by the DMS  480  (shown in  FIG. 2 ), after time t 0  (shown in  FIG. 7 ), when voltage control is carried out in the VCC system  200 . As seen in  FIG. 9 , the collected data may include, for example, a date, a time (hour:minute:second), a power level (MWatt), a reactive power level (MVAr), a voltage (V), an apparent power level (MVA), a power factor (PF), load financial transmission rights (FIR), and loss FTR, of the electrical power E Supply (t) output by the substation  530  with voltage control carried out by the VCC system  200 . 
     Comparing the data in  FIG. 8  to data of  FIG. 9 , the voltage V Supply (t) and electrical power E Supply (t) measurements show the substantial impact of lowering voltage on the electric power usage by, for example, users  150 ,  160 . In this regard, the hourly data at a transformer (not shown) in the substation  530  (shown in  FIG. 2 ) may be saved hourly. Voltage control and/or conservation may be carried according to the principles of the disclosure, and the energy use before ( FIG. 8 ) and after ( FIG. 9 ) implementation of the VCC system  200  may be compared at the two different voltage levels along the distribution circuit (for example, from or in the substation  530 ). In the examples shown in  FIGS. 8 and 9 , the before voltages may range from, for example, about 123V to about 125V, and the after voltages may range from, for example, about 120V to about 177V. 
     As shown in  FIG. 7 , the VCC system  200  can monitor the twenty worst case voltages supplied by the distribution circuits and control the source bus voltage V SP (t) to maintain the operation in the lower band, as shown, for example, in  FIG. 6 . The VCC system  200  can also reselect the smart meters  330  used for the 20 worse case voltages based on, for example, the information received from the EC system  400  “report-by-exception” monitoring of voltage. The VCC system  200  may select these new smart meters  330  from the total number of smart meters  330  connected to the substation  530 . 
     The voltage V Supply (t) and electrical power E Supply (t) data shown in  FIGS. 8 and 9  may be arranged by hour and averaged over twenty-four hour periods, retaining the correct average of voltage to electrical power (MW) by calculating the voltage to electrical power (MW) value for each hour, adding for the twenty-four hours, calculating the weighted twenty-four hour voltage using the average hourly electrical power (MW) value and the total twenty-four hour electrical power (MW) to Voltage ratio for the day. This may produce one value for average electrical power (MW) per hour for a twenty-four hour period and a weighted voltage associated with this average electrical power usage. 
       FIG. 10  shows an example of calculation data for hours 1-5 and the average for the full twenty-four hours in the example of  FIGS. 7-9 . 
       FIG. 11  shows an example where data may be collected for weather variables for the days before and after voltage control and/or conservation by the VCC system  200  according to the disclosure. In particular,  FIG. 11  shows the data collected from the National Weather Service for, for example, Richmond International Airport, the nearest weather station location to the TRABUE SUBSTATION (shown in  FIG. 3 ). The data shown is for the same period as the example of  FIG. 7 . The data shown in  FIG. 11  may be used to eliminate as much of the changes in power, other than those caused by voltage, to provide as accurate a measurement as possible. 
       FIG. 12  shows an example of an application of the paired test analysis process, according to principles of the disclosure. As seen, kW usage per customer per day in the time period from May to January when, for example, the VCC is in the OFF mode, is compared to kW usage per customer per day in the time period from January to November when, for example, the VCC is the ON mode. The Trabue Load growth demonstrates the process of pairing the test days from state 1 to state 2. Days from the pair 1 are picked from the May through January time period with voltage conservation turned OFF and matched with the days from the pair 2 period from, for example, January through November. The match may be based on the closest weather, season, day type, and relative humidity levels to remove as many other variables as possible, except for the change in voltage. Because the data is collected over a long period of time, where economic and growth can also impact the comparison of the characteristics of growth or economic decline are removed by using the kW-per-customer data to remove effects in customer energy usage increases and decreases and a monthly linear regression model to remove the growth or economic decline correlated to the month with the weather variables removed. 
       FIG. 13  shows an example of a scatterplot of a total power per twenty-four hours versus heating degree day. In this regard, the voltage and electrical power (MW) per hour may be recorded, and average voltage and electrical power (MW) per hour determined for a twenty-four hour period. The scatterplot may be used to predict the power requirements for the next day using the closest power level day from the historical data stored in DB  470  (shown in  FIG. 2 ). The calculation may use as inputs the change in the variables from the nearest load day to the day being calculated and the output may be the new load level. Using these inputs and a standard linear regression calculation a model may be built for the historical data The regression calculation may include, for example, the following expression [2]: 
         E   Total/Customer =−4.54−0.260 D   Season −0.213 D   Type +0.0579 H+ 0.0−691 V   Avg +0.00524 D   Month    [2]
 
     where: E Total  is a total power for a twenty-four hour period per customer for a particular day; D Type  is a day type (such as, for example, a weekend, a weekday, or a holiday) of the particular day, D Season  is one of four seasons corresponding to the particular day in the calendar year; D Month  is the particular day in the month; H is a Heating Degree Day level for the particular day; and V is the V Avg  average voltage supplied per customer for the particular day. 
     The data shown in the example of  FIG. 13  includes historic data for a 115 day period, before the VCC system  200  is implemented according to principles of the disclosure. The example shown in  FIG. 12  may correspond to a winter season for TRABUE SUBSTATION loads. As seen in  FIG. 13 , the model may be used represent the change in power level from one day to the next that is not related to the weather, growth, and economic variables in the linear regression expression [2]. 
     The historical data may be adjusted to match the heating degree day level for the measurements taken after the voltage control and/or conservation is carried out by the VCC system  200 . For example, referring to  FIG. 11 , a heating degree day of 19 may be read for a particular day, Feb. 1, 2009. The historical data may be searched in the DB  470  for all days with heating degree levels of 19. For example, two days in December may be found with the same heating degree day levels—for example, December 1 and 17. The linear regression model expression [2] for the historical data may be used to adjust the variables for December 1 and 17 to the same values as the data taken on Feb. 1. 2009, This may provide as close a match between the historical (operating at the higher voltage level) and Feb. 1, 2009 (operating at the lower voltage level). The calculation of (change in MW)/(change in Voltage) may be made from the high voltage to the low voltage operation. This may become one data point for the statistical analysis. 
     This process may be repeated for all measurements taken after the voltage conservation is turned on and compared to all similar days in the historical data taken for the matching season and other weather conditions. This may produce, for example, one-hundred-fifteen data points from, for example, 115 days of operation matched with all of the historical matching data. The resulting statistical analysis of this data is shown in  FIGS. 13-14 . 
     The normality of the data may be validated using the Anderson-Darling Normality test. In the case of the example of  FIGS. 13 and 14 , the P-Value may be 0.098, which may be well above the required value of 0.01, thereby demonstrating that the data may be normal with an approximately 99% confidence level, as shown in  FIG. 14 . This allows the application of a one sample T test to demonstrate the average of the mean value of the change in electrical power (MW) to change in voltage. The test may be performed to evaluate the statistical significance of the average value being above, for example, about 1.0. As shown in  FIG. 14  the test may demonstrate an approximately 99% confidence level that the savings in power to reduction in voltage may be above about 1.0% per 1% of voltage change. Using this type of statistical method continuous tracking of the energy saving improvement can be accomplished and recorded in kW/customer saved per day or aggregated to total kW saved for the customers connected to the substation  530 . 
       FIG. 15  shows an alternative example of a scatterplot of a total power per twenty-four hours versus heating degree day. In this regard, the voltage and electrical power (MW) per hour may be recorded, and average voltage and electrical power (MW) per hour determined for a twenty-four hour period. The scatterplot may be used to predict the power requirements for the next day using the closest power level day from the historical data stored in DB  470  (shown in  FIG. 2 ). The calculation may use as inputs the change in the variables from the nearest load day to the day being calculated and the output may be the new load level. Using these inputs and a standard linear regression calculation a model may be built for the historical data. The regression calculation may include, for example, the following expression [3]: 
         E   Total =(−801+0.069 Y+ 0.0722 D   Type +0.094 D   Year +0.0138 D   Month +0.126 T   max +0.131 T   min +9.84 T   avg +10.1 H −10.3 C +0.251 P   Std )−(0.102 T   max-d −0.101 T   min-d +0.892 T   avg-d +0.693 H   d −0.452 C   d −0.025 P   R +0.967 E   Total/Previous )   [3]
 
     where: E Total  is a total power for a twenty-four hour period for a particular day; Y is a calendar year of the particular day; D Type  is a day type (such as, for example, a weekend, a weekday, or a holiday) of the particular day; D Year  is the particular day in the calendar year; D Month  is the particular day in the month; T max  is a maximum temperature for the particular day; T min  is minimum temperature for the particular day; T avg  is the average temperature for the particular day; H is a Heating Degree Day level for the particular day; C is a Cooling Degree Day level; P STD  is a barometric pressure for the particular day; T max-d  is a maximum temperature for a closest comparison day to the particular day; T min-d  is minimum temperature for the closest comparison day to the particular day; T avg-d  is the average temperature for the closest comparison day to the particular day; H d  is a Heating Degree Day level for the closest comparison day to the particular day; C d  is a Cooling Degree Day level for the closest comparison day to the particular day; P R  is a Barometric pressure for the closest comparison day to the particular day; and E Total/Previous  is the total average hourly usage in MW on the closest comparison day to the particular day. The data shown in the example of  FIG. 15  includes historic data for a fifty day period, before the VCC system  200  is implemented according to principles of the disclosure. The example shown in  FIG. 15  may correspond to a winter season for TRABUE SUBSTATION loads. As seen in  FIG. 15 , the model may represent 99.7% of the change in power level from one day to the next using the variables in the linear regression expression [3]. 
     The historical data may be adjusted to match the heating degree day level for the measurements taken after the voltage control and/or conservation is carried out by the VCC system  200 . For example, referring to  FIG. 11 , a heating degree day of 19 may be read for a particular day, Feb. 1, 2009. The historical data may be searched in the DB  470  for all days with heating degree levels of 19. For example, two days in December may be found with the same heating degree day levels—for example, December 1 and 17. The linear regression model expression [3] for the historical data may be used to adjust the variables for December 1 and 17 to the same values as the data taken on Feb. 1, 2009. This may provide as close a match between the historical (operating at the higher voltage level) and Feb. 1, 2009 (operating at the lower voltage level). The calculation of (change in MW)/(change in Voltage) may be made from the high voltage to the low voltage operation. This may become one data point for the statistical analysis. 
     This process may be repeated for all measurements taken after the voltage conservation is turned on and compared to all similar days in the historical data taken for the matching season and other weather conditions. This may produce, for example, seventy-one data points from, for example, thirty days of operation matched with all of the historical matching data. The resulting statistical analysis of this data is shown in  FIG. 17 . 
     The normality of the data may be validated using the Anderson-Darling Normality test. In the case of the example of  FIGS. 6 and 7 , the P-Value may be 0.305, which may be well above the required value of 0.02, thereby demonstrating that the data may be normal with an approximately 98% confidence level, as shown in  FIG. 17 . This allows the application of one sample T test to demonstrate the average of the mean value of the change in electrical power (MW) to change in voltage. The test may be performed to evaluate the statistical significance of the average value being above about 0.8. As shown in  FIG. 17  the test may demonstrate an approximately 98% confidence level that the savings in power to reduction in voltage may be above about 0.8% per 1% of voltage change. 
     While the disclosure has been described in terms of exemplary embodiments, those skilled in the art will recognize that the disclosure can be practiced with modifications in the spirit and scope of the appended claims. These examples are merely illustrative and are not meant to be an exhaustive list of all possible designs, embodiments, applications or modifications of the disclosure.