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Energy and Power Management System

CSI Spec 26 09 13

Square D™ by Schneider Electric

PART 1 GENERAL

1.3 SUMMARY

A. Scope: Furnish and install an Energy and Power Management System (EPMS) as detailed on the Drawings and as herein specified. The system is defined to include data and analytics functionality in the broad categories of (a) energy performance optimization, (b) power reliability and availability, and (c) sustainability metrics. Features like real-time monitoring, alarming and event management, energy, power, and sustainability data analytics and visualization will facilitate the following functions at a high level: 1. Analyze energy usage and uncover savings opportunities. 2. Meet and exceed energy efficiency and sustainability standards and certifications. 3. Measure return on investment of energy capital projects. 4. Allocate and bill energy costs accurately to processes, tenants, cost centers, and departments. 5. Decrease the frequency and duration of unplanned outages. 6. Improve workplace safety by minimizing exposure to electrical hazards. 7. Provide accurate and automated documentation for regulatory compliance. 8. Improve the effectiveness of equipment maintenance activities. 9. Manage multiple power generation sources effectively. 10. Increase the return on electrical distribution assets. 11. Measure and achieve sustainability targets.

B. The work specified in this Section includes but shall not be limited to the following: 1. Hardware—such as metering devices for monitoring, protection, and control; device communication interface hardware; servers; mobile or workstation devices; and ancillary equipment. 2. Software—such as on premise installed software and cloud based software-as-a-service (SaaS) applications. 3. Services, support, and training.

C. The EPMS shall use Ethernet as the high-speed backbone network for device communications.

D. The high-speed network shall allow direct access to data provided by the power monitoring devices for implementing automatic control.

E. Data and analytics provided by the EPMS system for centralized display, analysis, logging, alarming, event recording, and other EPMS operations shall be accessible from a computer workstation with supported operating system and interface software.

F. The EPMS shall be manufactured by Schneider Electric, or approved equal using Schneider Electric’s EPMS system components as the basis-of-design products.

G. Single Source Responsibility: Obtain LV Switchgear, Breakers, Metering Devices, Gateways, Energy Servers and required accessories from a single source with resources to produce products of consistent quality in appearance and physical properties without delaying the work. Materials not produced by the manufacturer shall be acceptable to and approved by the manufacturer.

V1.1 Modified February 18, 2016 Page 1 of 32 1.4 REFERENCES

A. General: The publications listed below form a part of this Specification to the extent referenced. The publications are referred to in the text by the basic designation only. The edition or revision of the referenced publications shall be the latest date as of the date of the Contract Documents, unless otherwise specified.

B. All metering devices shall be UL 508 listed, CSA approved, and have CE marking.

C. The system shall comply with the applicable portions of NEMA standards. In addition, the control unit shall comply with FCC emission standards specified in Part 15, Sub-Part J for Class A application.

D. The Energy and Power Management System and components shall comply with codes and standards as applicable.

1.5 SUBMITTALS

A. Product Data: EPMS product catalog sheets and technical data sheets specifying physical data and electrical performance, electrical characteristics, and connection requirements of each device shall be supplied under the EPMS scope of work.

B. Drawings, Documentation, Operation and Maintenance (O&M) Manuals: 1. EPMS drawings shall show elementary and interconnection diagrams for all relevant field-monitoring devices and networking components including power, signal, control, communications wiring and network addresses. Drawings shall identify network connections and protocols. Drawings shall identify device room locations and recommended installation notations. Specific locations and mounting details are subject to the discretion and responsibilities of the installation contractor. Where LV Switchgear interconnection is specified, drawings shall not be typical, but shall be provided for each Switchgear and Breaker furnished. 2. Sequence of operation (for control applications such as automatic transfer schemes, load control, etc.), layout drawings, as-built wiring diagrams, bill of material, spare parts list, and component catalog information shall be included in a final documentation package that will be delivered to the owner prior to training.

1.6 QUALITY ASSURANCE

A. Manufacturer Qualifications: Manufacturer shall be a firm engaged in providing EPMS systems, and shall be able to prove an installed base of such systems successfully operating in at least one hundred customer sites for a minimum of five years.

B. The EPMS vendor shall bear full responsibility to ensure that the EPMS system performs as specified.

C. The EPMS solution shall be fully tested in a test-bed environment with hardware devices representative of a large scale functional power distribution system (including both physical and simulated devices) such as advanced power quality meters, low voltage main meters, low voltage feeder meters, circuit breaker trip units, transformer monitoring units, protective relays, branch circuit power meters, etc. Documented test results including system response times, network performance, and recommended network architectures shall be published and provided upon request.

V1.1 Modified February 18, 2016 Page 2 of 32 D. No products shall violate patents filed in any country.

PART 2 PRODUCTS

1.7 METERING—MV MAINS—STANDARD

A. The metering device used to monitor medium voltage mains for network management, energy cost allocation, power quality analysis, asset management, operational efficiency, and compliance reporting, shall have at minimum the following features: 1. Voltage and current inputs—three (3) phase inputs; direct connect to circuits up to 600 VAC, eliminating the need for voltage (potential) transformers; five (5) amperes (A) nominal current inputs. 2. Supported measured and calculated metering parameters—four-quadrant metering, full range of three (3) phase voltage, current, power and energy measurements, percentage unbalance, power factor (true and displacement per phase and three (3) phase) demand (minimum/maximum, present demand interval, running average demand, and predicted demand), total harmonic distortion (THD), individual current and voltage harmonics readings. 3. High accuracy standards—meets stringent IEC and ANSI measurement accuracy standards such as IEC 62053-22 Class 0.2S, ANSI C12.20 0.2 Class 10 and 20. 4. High-visibility display with the following characteristics: a. User programmable to display up to four (4) quantities per screen. b. Capable of displaying graphical metering data such as phasor diagrams, watt-hour disk simulator, spectral components etc. c. Capable of displaying harmonics content (THD, K-factor, crest-factor) in histogram format. 5. I/O: integrated or expandable with the following characteristics: a. Minimum four (4) digital inputs and four (4) digital outputs for equipment status/position monitoring and equipment control/interface. b. Minimum four (4) analog inputs (4-20 mA). c. Pulse output relay operation for kWh/kVARh total/imported/exported. 6. Communications Capability—multi-port serial and Ethernet communications with at least two Modbus serial ports and one Ethernet port with Ethernet-to-serial RS-485 gateway. 7. On-board logging: a. Non-volatile time stamps with on-board logging of I/O conditions, minimum/maximum values, energy and demand, maintenance data, alarms, and any measured parameters; trending and short-term forecasting of energy and demand. b. Ability to record any parameter in the meter and trigger multiple such recordings in continuous succession (triggered manually or through internal event conditions, including periodic timers or set-point activity). c. Continuous recording of intervals from 100 years down to one-half (½) cycle. d. Number of records (depth) and overflow conditions (stop-when-full or circular) shall be programmable 8. On-board web server can be used for: a. Access to real-time values and basic power quality information using standard web browser. b. Basic meter configuration. 9. Alarming capabilities: a. Set-point driven alarming capability. b. Generate an email notification upon an alarm condition. c. Millisecond resolution timestamp on alarm entries. d. Support consecutive high-speed triggers for alarms and waveform recording, triggering on a cycle-by-cycle basis with no “dead” time between events (i.e. no need for a re-arming delay time between events). e. Operate relays or initiate data logging captures on alarm conditions

V1.1 Modified February 18, 2016 Page 3 of 32 f. Control any number of digital output relays in an AND or an OR configuration, using pulse mode or latch mode operation, for control and alarm purposes. g. Combine any logical combination of available set-point conditions to control an internal or external function/event. 10. Time-stamped event log (1 millisecond (ms.) resolution) with the following characteristics: a. Support at least 500 events, programmable up to a maximum of 20000 events. b. For each event, record date and time, cause and effect, and priority. c. Record all events relating to set-point activity, relay operation and self-diagnostics. d. Capable of synchronizing time stamps between devices on the same serial communications network to within 100 ms. e. Minimum event recording response time is one-half (½) cycle (8.3ms 60Hz, 10ms 50Hz) for high-speed events and one (1) second for other events. f. Programmable set-point events. 11. Power quality analysis and compliance monitoring: a. Without separate software, have the following capabilities: 1) Display statistical indicators of power quality on the front display. 2) Compare power quality parameters (present, predicted, average, or calculated values) with an absolute or relative set point, and alert (via e-mail or pager), or enable control (via a local interface to power quality (PQ) mitigation equipment/control systems through relays and analog or digital outputs) when set-point is exceeded. 3) Support EN50160 reporting for compliance monitoring. b. Third party laboratory tested to the power quality standards—IEC 61000-4-30 Class 'A' 2nd edition, IEC 61000-4-15 – Flicker. c. Low pass anti-aliasing signal filters to meet the requirements of IEC 61000-4- 7:2002. 12. Fault recording and waveform capture: a. Simultaneously capture voltage and current channels for sub-cycle disturbance, transients, as well as multi-cycle sags, swells and outages in quick succession, without dead time between recordings. b. 512 samples per cycle waveform recording, minimum 33/40 μs transient capture (60/50 Hz). c. Configurable to provide COMTRADE waveforms for all captures. 13. Disturbance detection: a. High-speed sag/swell detection of voltage disturbances on a cycle-by-cycle basis, providing duration of the disturbance, the minimum, maximum, and average value of the voltage for each phase during the disturbance. b. Detect disturbances less than one cycle in duration. c. Determine the location of a disturbance more quickly and accurately by determining the direction of the disturbance relative to the meter. Capture analysis results in the event log, along with a timestamp and confidence level indicating level of certainty. 14. Programmability: a. Capable of deriving values for combinations of measured or calculated parameters, using arithmetic, trigonometric, logic, thermocouple linearization, and temperature conversion functions. b. Capable (through a graphical flexible programming language) of creating programmable modules with metered and input data, through arithmetic and logic operations (such as minimum, maximum, set point, digital input, digital output, etc.) that can be arbitrarily linked together to create application functionality.

1.8 METERING—LV MAINS—STANDARD

A. The metering device used to monitor the low voltage mains for network management, energy cost allocation, power quality analysis, asset management, operational efficiency, and compliance reporting, shall have at minimum the following features:

V1.1 Modified February 18, 2016 Page 4 of 32 1. High-visibility color graphical display. 2. Direct connect to circuits up to 600 VAC, eliminating the need for voltage (potential) transformers; five (5) amperes (A) nominal current inputs. 3. Supported monitoring parameters—full range of three (3) phase voltage, current, power and energy measurements, total harmonic distortion (THD), individual current and voltage harmonics readings, waveform capture, voltage and current disturbances (dip/swell) detection, ability to determine the location of a disturbance (upstream/downstream). 4. COMTRADE—up to 255 COMTRADE disturbance capture files available via FTP and providing client notification of new captures through IEC 61850 (RDRE logical node). 5. Power Quality compliance—without using separate software, determine statistical indicators of power quality that include but are not limited to voltage dips and swells, harmonics, and frequency in accordance with EN 50160 power quality standard and provide an indication of pass/fail in a web interface. 6. User customization—capable of deriving values for any combination of measured or calculated parameters using arithmetic, trigonometric, and logic functions through graphical, flexible object oriented, programmable modules. Modules can be linked together in an arbitrary manner to create functionality such as totalization, efficiency measurements, control functions, load shedding, demand response, power factor correction, and compliance monitoring. 7. Communications capability—multi-port Ethernet and serial communications with at least two Ethernet ports and one RS485 serial port. Functionality through Ethernet connectivity includes e-mail on alarm, e-mail interval energy data, on-board web server, SNMP network management, NTP time synchronization, Ethernet-to-serial RS-485 gateway, Modbus, DNP3, and IEC 61850. 8. On-board logging—non-volatile time stamped on-board logging of input/output (I/O) conditions, min/max values, energy and demand, maintenance data, alarms, and any measured parameters; trending and short-term forecasting of energy and demand; custom alarming with time stamping; trigger alarms on at least 50 definable power or I/O conditions; use of Boolean logic to combine alarms. 9. I/O—at least three (3) digital inputs and one (1) digital output for equipment status/position monitoring and equipment control or interfacing with millisecond timestamp. 10. Expandable I/O—the ability to add optional I/O of at least 24 digital inputs and 16 relay outputs, 16 analog inputs and eight (8) analog outputs, or combinations of digital and analog I/O in the field.

1.9 METERING—LV FEEDERS—STANDARD

A. The metering device used to monitor the medium voltage mains for network management, energy cost allocation, power quality analysis, asset management, operational efficiency, and compliance reporting, shall have at minimum the following features: 1. High-visibility color graphical display. 2. Direct connect to circuits up to 600 VAC, eliminating the need for voltage (potential) transformers; 5 A nominal current inputs. 3. Supported monitoring parameters—full range of 3-phase voltage, current, power and energy measurements, total harmonic distortion (THD), individual current and voltage harmonics readings, waveform capture, voltage and current disturbances (dip/swell) detection, ability to determine the location of a disturbance (upstream/downstream). 4. COMTRADE—up to 255 COMTRADE disturbance capture files available via FTP and providing client notification of new captures through IEC 61850 (RDRE logical node). 5. Power Quality compliance—without using separate software, determine statistical indicators of power quality that include, but are not limited to, voltage dips and swells, harmonics, and frequency in accordance with EN 50160 power quality standard and provide an indication of pass/fail in a web interface. 6. User customization—capable of deriving values for any combination of measured or calculated parameters using arithmetic, trigonometric, and logic functions through graphical, flexible object oriented, programmable modules. Modules can be linked together in an arbitrary manner to create functionality such as totalization, efficiency measurements, control functions, load shedding, demand response, power factor correction, and compliance monitoring.

V1.1 Modified February 18, 2016 Page 5 of 32 7. Communications capability—multi-port Ethernet and serial communications with at least two Ethernet ports and one RS485 serial port. Functionality through Ethernet connectivity includes e-mail on alarm, e-mail interval energy data, on-board web server, SNMP network management, NTP time synchronization, Ethernet-to-serial RS-485 gateway, Modbus, DNP3, and IEC 61850. 8. On-board logging—non-volatile time stamped on-board logging of I/O conditions, min/max values, energy and demand, maintenance data, alarms, and any measured parameters; trending and short-term forecasting of energy and demand; custom alarming with time stamping; trigger alarms on at least 50 definable power or I/O conditions; use of Boolean logic to combine alarms. 9. I/O—at least three (3) digital inputs and one (1) digital output for equipment status/position monitoring and equipment control or interfacing with millisecond timestamp. 10. Expandable I/O—the ability to add optional I/O of at least 24 digital inputs and 16 relay outputs, 16 analog inputs and eight (8) analog outputs, or combinations of digital and analog I/O in the field.

1.10 SUB METERING—INDIVIDUAL CIRCUITS—STANDARD

A. The metering device used to monitor circuits for purposes of network management, energy cost management, energy allocation, and operational efficiency shall have the following minimum features:

1. Connections and form factor - direct connect to circuits up to 600 VAC, eliminating the need for voltage (potential) transformers; five (5) amperes (A) nominal current inputs. Removable connectors for voltage inputs, control power, communications, inputs and outputs; easily mountable in the pre-made cutout without tools; form factor shall be ¼ DIN with 92 X 92 cut-out and 96 x 96 panel mount integrated display. 2. Supported monitoring parameters—full range of 3-phase voltage, current, power and energy measurements, power factor, frequency, total harmonic distortion (THD), individual power harmonics (up to 63rd order). 3. Accuracy standards - use four-quadrant metering and sample current/voltage simultaneously without gaps with 64 samples per cycle (zero bling); comply with ANSI C12.20 class 0.2 and IEC 61557-12 class 0.2 for revenue meters. 4. Display - Backlit dot-matrix LCD display, anti-glare and scratch resistant with a minimum of 128 x128 pixels, capable of displaying four values in one screen simultaneously; a summary screen to allow the user to view a snapshot of the system; support either integrated or remote display. 5. Support four (4) digital inputs for Demand Synch Pulse, Time Synch Input, and Conditional Energy Control; have two (2) digital outputs that operate either by user command sent over communication link, or in response to a user defined alarm or event. 6. Communications - serial RS-485 Modbus and Ethernet Modbus TCP; provide two Ethernet ports to allow wiring from meter to meter as a daisy-chain; be capable of serve data over the Ethernet network accessible through a standard web browser; the monitor shall contain default pages from the factory. 7. Onboard data logging capabilities - to log data, alarms and events; logged information will include data logs, minimum/maximum log files of selected parameter values, and alarm logs for each user defined alarm or event log; support the following on-board nonvolatile memory—14 parameters every 15 minutes for 90 days. 8. Alarming capabilities - support 29 set-point driven alarms, four (4) digital alarms, (4) unary alarms, 10 Boolean alarms and five (5) custom alarms; user definable alarm events; set- point driven alarms shall be available for voltage/current parameters, input status, and end of interval status. 9. Firmware-upgradeable to enhance functionality through the Ethernet or serial communication connection and shall allow upgrades of individual meters or groups. 10. Integrated gateway functionality, enabling the capability to connect via Ethernet to downstream, serially connected devices.

V1.1 Modified February 18, 2016 Page 6 of 32 11. Designed accordingly to eco-design complying with ISO 14062, especially MCCB materials shall be halogen free type; designed for easy disassembly and recycling at end of life, and comply with environmental directives ROHS and WEEE.

1.11 METERING—UTILITY REVENUE

A. The revenue grade metering device used to monitor incoming utility medium voltage mains for grid revenue, substation automation, network management, energy cost allocation, power quality analysis, asset management, operational efficiency, and compliance reporting, shall have at minimum the following features: 1. Form factor—ANSI socket 9S, 29S, 35S and 36S; user-selectable 9S, 29S, and 36S; FT-21 switchboard/draw-out style 2. Voltage and current inputs—three (3) phase inputs; Direct connect to circuits up to 600 VAC, eliminating the need for voltage (potential) transformers; five (5) amperes (A) nominal current inputs; equipped with two spring-loaded socket grounding tabs to ensure reliable electrical contact; optional mechanical bonding ground. 3. Supported measured and calculated metering parameters—four-quadrant metering, full range of three-phase voltage, current, power and energy measurements, percentage unbalance, power factor (true and displacement per phase and three-phase) demand (minimum/maximum, present demand interval, running average demand, and predicted demand), total harmonic distortion (THD), individual current, and voltage harmonics readings. 4. High accuracy standards—meet in a single device over the Class 2/10/20 current classes in a single device (over all environmental conditions and influence factors outlined in the standard and its referenced standards). a. Less than half the measurement error of ANSI C12.20 class 0.2 accuracy over the Class 2/10/20 current classes. b. Less than half the measurement error of IEC62053-22 class 0,2S accuracy from 0.010A-20A in a single device. c. Less than twenty times the measurement error of IEC62053-23 class 2 accuracy from 0.010A-20A in a single device. d. Support up to eight (8) points of magnitude and phase correction for each voltage and current measurement input. e. Overvoltage/overcurrent protection—capable of meeting all accuracy specifications after withstanding 500A for one (1) second or 2500 VAC RMS for one (1) minute (with internal protection disabled). 5. High-visibility display with the following characteristics: a. User programmable to display up to four (4) quantities per screen. b. Capable of displaying graphical metering data such as phasor diagrams, watt-hour disk simulator, spectral components etc. c. Capable of displaying harmonics content (THD, K-factor, crest-factor) in histogram format. 6. I/O—integrated or expandable with the following characteristics: a. Minimum four (4) digital inputs and four (4) digital outputs for equipment status/position monitoring and equipment control or interfacing. b. Minimum four (4) analog inputs (4-20 mA). c. Pulse output relay operation for kWh/kVARh total/imported/exported. 7. Communications Capability. a. Ethernet, RS485/232 serial, ANSI 12.18 compliant optical port. b. Protocol support: DNP3.0(Ethernet/serial); Modbus slave/mastering (Ethernet/serial); SMTP/SNTP(Ethernet); MV90(Ethernet/serial); XML(TCP); IEC61850(TCP). c. IRIG-B port to allow GPS time synchronization to +/-1ms accuracy from GPS source.

V1.1 Modified February 18, 2016 Page 7 of 32 d. Automatically e-mail alarm notifications, scheduled system status updates and data logs on an event-driven or scheduled basis. 8. On-board logging. a. Non-volatile time stamps with on-board logging of I/O conditions, minimum/maximum values, energy and demand, maintenance data, alarms, and any measured parameters; trending and short-term forecasting of energy and demand. b. Ability to record any parameter in the meter and trigger multiple such recordings in continuous succession (triggered manually or through internal event conditions, including periodic timers or set-point activity). c. Continuous recording of intervals from 100 years down to ½ cycle. d. Number of records (depth) and overflow conditions (stop-when-full or circular) shall be programmable. 9. On-board web server that can be used for: a. Access to real-time values and basic power quality data through a web browser. b. Basic meter configuration. 10. Alarming capabilities: a. Set-point driven alarming capability. b. Generate an email notification upon an alarm condition. c. Millisecond resolution timestamp on alarm entries d. Support consecutive high-speed alarm conditions for alarms and waveform recording, triggering on a cycle-by-cycle basis with no “dead” time between events (i.e., no need for a re-arming delay time between events). e. Operate relays or initiate data logging captures on alarm conditions. f. Control any number of digital output relays in an AND or an OR configuration using pulse mode or latch mode operation for control and alarm purposes. g. Combine any logical combination of any number of available set-point conditions to control an internal or external function or event. 11. Time-stamped event log (one (1) millisecond resolution) with the following characteristics: a. Support at least 500 events, programmable up to a maximum of 20000 events. b. For each event, record date and time, cause and effect, and priority. c. Record all events relating to set-point activity, relay operation, and self-diagnostics. d. Capable of synchronizing time stamps between devices on the same serial communications network, to within 100 milliseconds. e. Minimum event recording response time is ½ cycle (8.3ms 60Hz, 10ms 50Hz) for high-speed events and one (1) second for other events. f. Programmable set-point events. 12. Power quality analysis and compliance monitoring. a. Without separate software, have the following capabilities: 1) Display statistical indicators of power quality on the front display. 2) Compare power quality parameters (present, predicted, average, or calculated values) with an absolute or relative set point. When set-point is exceeded, alert via e-mail or pager, or enable control via a local interface to PQ mitigation equipment or control systems through relays and analog or digital outputs. 3) Support EN50160 reporting for compliance monitoring. b. Third party Laboratory tested to the power quality standards IEC 61000-4-30 Class 'A' 2nd edition, IEC 61000-4-15, and Flicker. c. Low pass anti-aliasing signal filters to meet the requirements of IEC 61000-4- 7:2002. 13. Fault recording and waveform capture. a. Simultaneously capture voltage and current channels for sub-cycle disturbance, transients, as well as multi-cycle sags, swells and outages in quick succession, without dead time between recordings. b. 1024 samples per cycle waveform recording, minimum 17/20 μs transient capture (60/50 Hz). c. Configurable to provide COMTRADE waveforms for all captures.

V1.1 Modified February 18, 2016 Page 8 of 32 14. Disturbance detection. a. High-speed sag/swell detection of voltage disturbances on a cycle-by-cycle basis, providing duration of the disturbance, the minimum, maximum, and average value of the voltage for each phase during the disturbance. b. Detect disturbances less than one cycle in duration. c. Determine the location of a disturbance more quickly and accurately by determining the direction of the disturbance relative to the meter. Capture analysis results in the event log, along with a timestamp and confidence level indicating level of certainty. 15. Programmability. a. Capable of deriving values for any combination of measured or calculated parameter using arithmetic, trigonometric, logic, thermocouple linearization, and temperature conversion functions, b. Capable (through a graphical flexible programming language) of creating programmable modules with metered and input data through arithmetic and logic operations (such as minimum, maximum, set point, digital input, digital output, etc.) that can be arbitrarily linked together to create application functionality. 16. System Integration—capable of integrating with custom reporting, spreadsheet, database and other applications with XML compatible data.

1.12 METERING—TRANSFER SWITCHES—STANDARD

A. The metering device used to monitor transfer switches for purposes of automated generator test documentation such as Emergency Power Supply System (EPSS) Test Automation, shall have at minimum the following features: 1. High-visibility display. 2. Direct connect to circuits up to 600 VAC, eliminating the need for voltage (potential) transformers; five (5) amperes (A) nominal current inputs. 3. Supported monitoring parameters—full range of 3-phase voltage, current, power and energy measurements, total harmonic distortion (THD), individual current and voltage harmonics readings, waveform capture, and voltage and current disturbance (sag/swell) detection. 4. Communications capability—multi-port serial and Ethernet communications with at least two Modbus serial ports and one (1) Ethernet port. The Ethernet port offers e-mail on alarm, web server, and an Ethernet-to-serial RS-485 gateway. 5. On-board logging—non-volatile time stamped on-board logging of I/O conditions, minimum/maximum values, energy and demand, maintenance data, alarms, and any measured parameters; trending and short-term forecasting of energy and demand; custom alarming with time stamping; trigger alarms on at least 50 definable power or I/O conditions; use of Boolean logic to combine alarms. 6. I/O—at least four (4) digital inputs and four (4) digital outputs for equipment status/position monitoring, and equipment control or interfacing.

1.13 METERING—GENERATORS—STANDARD

A. The metering device used to monitor generators for purposes of automated generator test documentation, Emergency Power Supply System (EPSS) Test Automation, shall have at minimum the following features: 1. High-visibility display. 2. Direct connect to circuits up to 600 VAC, eliminating the need for voltage (potential) transformers; five (5) amperes (A) nominal current inputs. 3. Supported monitoring parameters—full range of 3-phase voltage, current, power and energy measurements, total harmonic distortion (THD), individual current and voltage harmonics readings, waveform capture, and voltage and current disturbance (sag/swell) detection. 4. Communications Capability—multi-port serial and Ethernet communications with at least two Modbus serial ports and one (1) Ethernet port. The Ethernet port offers e-mail on alarm, web server and an Ethernet-to-serial RS-485 gateway.

V1.1 Modified February 18, 2016 Page 9 of 32 5. On-board logging—non-volatile time stamped on-board logging of I/O conditions, minimum/maximum values, energy and demand, maintenance data, alarms, and any measured parameters; trending and short-term forecasting of energy and demand; custom alarming with time stamping; trigger alarms on at least 50 definable power or I/O conditions; use of Boolean logic to combine alarms. 6. I/O—at least four (4) digital inputs and four (4) digital outputs for equipment status/position monitoring and equipment control or interfacing, four (4) analog inputs (4-20 mA) to monitor engine parameters such as oil pressure, coolant temperature, etc. 7. High accuracy standards—meet stringent IEC and ANSI measurement accuracy standards such as IEC 62053-22 Class 0.2S, ANSI C12.20 0.2 Class 10 and 20. 8. Digital fault recording—simultaneously capture voltage and current channels for sub-cycle disturbance, transients, as well as multi-cycle sags, swells and outages; 512 samples per cycle waveform recording, 40/33 μs transient capture (50/60 Hz). 9. Power quality analysis and compliance monitoring—a choice of THD metering, individual current and voltage harmonics readings, waveform capture, and voltage and current disturbance (sag/swell) detection. 10. Disturbance direction detection—determines the location of a disturbance more quickly and accurately by determining the direction of the disturbance relative to the meter. Analysis results are captured in the event log, along with a timestamp and confidence level indicating level of certainty. 11. Integration of fuel parameters—communications with the fuel monitoring system shall provide integration of parameters such as fuel level, water content, run time remaining with fuel on hand, etc. Communications shall be direct or through a protocol converter. 12. Battery Health Monitoring—the system shall be capable of capturing the voltage of the engine start battery during engine starting with a minimum sampling rate of one sample per millisecond for purposes of signature analysis.

1.14 METERING—ENCLOSURES

A. Any metering enclosed cabinets supplied shall meet the following specifications: 1. Minimum UL type 1 listed steel enclosure with factory-supplied knockouts. 2. Lockable and provide for the application of a security seal. 3. Available options for NEMA Type 1 and Type 3R applications. 4. Single set of incoming terminals for connecting the voltage metering leads. 5. Control power and voltage sensing power separated for distribution to each meter from main set of incoming terminals. 6. External control power transformers not required for any power systems up to, and including, 480 volts. 7. Standard wiring harnesses for control power and voltage sensing to connect each meter internally. The harness may daisy chain the voltage connections from meter to meter on each row of meters. Finger safe terminals to terminate the meter end of the wiring harness. 8. Common daisy chain wiring for communications wiring, with a single loop for all meters connected to the circuit and each end terminated in a common location. Communication wiring installed such that interference from the power wiring is minimized. 9. Shorting terminal blocks for connecting the current transformer leads from the field to all ordered meters. Factory installed wiring harness shall be provided to connect the CT circuit from the shorting block to the meter. 10. Capability to field-install meters without cutting or splicing the voltage or communication wiring harnesses to be provided. 11. Terminal blocks for incoming and outgoing communications circuit connections.

1.15 GATEWAYS AND ENERGY SERVERS—ENERGY SERVER LOCAL

A. The energy server appliance shall collect and log WAGES (water, air, gas, electricity, steam) data by connecting to meters, as well as environmental parameters, such as temperature,

V1.1 Modified February 18, 2016 Page 10 of 32 humidity, and CO2 levels connected to its input/output modules. The appliance shall be capable of the following: 1. Logging the historical data for up to two years to its own local storage. 2. Communicating directly to compatible on premise software for gateway access to real-time or historical data used in dashboards, real-time screens, and reports. 3. Basic energy awareness functionality through display of real time and historical energy data. 4. Entry level energy management software in a box. 5. No software to install. Web pages and data visualization embedded in Energy Server.

B. Gateway Features. 1. The energy server shall have the ability to serve as a Modbus serial to Modbus TCP/IP gateway for connected software. 2. The energy server shall have the ability to serve as a gateway for connected input devices.

C. Appliance Operating Features—the appliance shall support the following minimum features: 1. Environmental—operating temperature range: -25°C to + 60°C; Humidity 5% to 95%. 2. Power Supply—24 VDC (+/- 10%); Power over Ethernet (POE Class 3, IEEE 802.3 af) at 50 W. 3. Internal Memory—internal memory for web pages with the ability to utilize SD memory cards for data logging storage. 4. Connectivity—support for a maximum of 64 connected devices (serial port, Ethernet network via another Ethernet gateway or devices with embedded Modbus TCP) for real-time readings and data logging. 5. Digital Inputs—minimum of six IEC62053-31 Class A with LED indication for status and pulse reception. The digital input shall be supplied directly from the data logger (see power supply output section below) or from a 10 to 30 VDC external power supply. The maximum pulse frequency is 25 Hz. 6. Analog Inputs—minimum two inputs supporting RTD probes (1% accuracy), 0-10 V sensors (0.5% accuracy), or 4-20 MA sensors (0.5% accuracy). 7. Ethernet ports—two Ethernet ports, which can be used either as a switch or separated ports (one (1) IP address for each). Ethernet port shall be configurable as DHCP client or DHCP server. 8. Serial port—configurable for RS232/485 with 2-wire and 4-wire support. 9. Protocol: Ethernet–Modbus TCP/IP, HTTP, FTP, SNMP (MIB2), TCP, UDP, IP, ICMP, ARP; Serial– MODBUS. 10. Troubleshooting—indicators to show failure mode and firmware updating; detection and reporting for device communication loss, CPU and memory overuse, weak GPRS signals.

D. Communications Interface—the appliance shall support one of the following three modes of communication depending on the specified ordering option: 1. Wi-Fi—two modes–connection to LAN infrastructure as an access point without additional Wi-Fi infrastructure shall be supported. The appliance shall support uploading logged data through the Wi-Fi connection to a centralized server. 2. GPRS/3G—when equipped with the appropriate cellular contract and SIM card, the appliance shall support uploading logged data through a GPRS or 3G network to a centralized server. Management of the GPRS/3G telecom contract is the responsibility of the customer and is out of scope for this specification. 3. Direct Connect (Gateway—connect directly to compatible on premise software as specified in the other sections of the specification.

E. Configuration and Setup—appliance configuration shall include the following capabilities: 1. On-board web pages for setup and configuration. 2. Equipped with Device Profile for Web Services (DPWS) technology (available on Windows operating systems starting with Vista) with two specific web services, discovery and identification. 3. Login secured with https: SSL protocol. 4. Support for multiple user accounts with encrypted passwords. 5. Configure data logging intervals at 5, 15, 30, or 60 minutes.

V1.1 Modified February 18, 2016 Page 11 of 32 6. Configure a different logging interval for each of six (6) device types–water, air, gas, electricity, steam, or environmental values. 7. Count for digital inputs. 8. Export logged data in CSV format. 9. Manage data export through proxy servers. 10. Ability to schedule data file export through email or FTP. 11. Ability to connect to a remote or digital service provider for M2M services.

F. Basic Energy Analytics Capabilities—the appliance shall support some basic energy analytics capabilities without the need for additional software. Features shall include the display of the following: 1. Real-time data through trends. 2. Historical energy data through dashboards and trends.

1.16 ENERGY AND POWER MANAGEMENT SOFTWARE—GENERAL

A. The Energy and Power Management System (EPMS) software platform shall facilitate applications in the broad categories of (a) energy performance, (b) power availability, quality and reliability, and (c) sustainability performance. At a high level, the feature-set shall provide functions in: 1. Real-time monitoring. 2. Alarming and event management. 3. Energy cost analysis. 4. Energy, power, and sustainability data analytics and visualization.

B. The software platform shall be certified for use as a part of an ISO50001 program and verifiably support compliance. In addition, the functionality shall support ongoing ISO50001 programs per the following areas of Section 4 of the ISO standard: 1. Energy review. 2. Energy baseline. 3. Energy performance indicators. 4. Monitoring, measurement, and analysis. 5. Input to management review.

C. The EPMS shall verifiably support compliance with EN 16247-1 for energy audits.

1.17 ENERGY AND POWER MANAGEMENT SOFTWARE—REAL TIME MONITORING

A. The Energy and Power Management System (EPMS) software shall include the capability to provide screens including real-time data about the electrical infrastructure showing incoming utility feeds, medium voltage, and low voltage distribution. Relevant data from other energy and facility metadata, such as water, air, gas, electric, and steam meters (WAGES), industrial process data, weather, occupancy, etc., can be integrated, provided the communications and data infrastructure are in place. The capability to provide real-time monitoring data within other analytics functions, such as dashboard views, shall also be provided.

B. Electrical single line diagrams: The EPMS shall include a set of screens that show the electrical single line diagram for the facility with the following: 1. Links to navigate between various levels of the single line diagram. 2. Animated power component of the single line (for example, MV switchgear, MV transformers, generators, unit substations, LV switchboards, UPS, isolated panel system) shall link to a power equipment details screen, assuming that the necessary protection and metering hardware is in place as defined in the Appendix.

V1.1 Modified February 18, 2016 Page 12 of 32 C. Equipment details: The EPMS shall include a set of screens that show equipment details including: 1. Details pertaining to each piece of equipment. This includes a picture of the equipment (if available), local single line (if applicable), information for each electrical section (for example, breaker and disconnect switch), and all alarm points. 2. A link to each of the default diagrams of each meter/protection device that apply to the piece of equipment shall be provided. 3. The EPMS shall have a graphic library with electrical one-line symbols to simplify the creation of single line diagrams.

D. Floor plans: The EPMS shall include the capability to overlay the display of real time data on facility floor plans when available. Links to summary screens, equipment details screens, etc., can be integrated.

E. Status panel: The EPMS shall include a summary status screen for alarm status indication for major power equipment components of the electrical distribution system.

F. Web-enabled real-time tables: The system shall have the following capabilities for interactive side-by-side visualization of real-time measurements: 1. Display a tabular view to compare device readings from multiple meters in the power monitoring network quickly. 2. Permit users to create, modify, view and share table views through a browser without the need for a separate software application. 3. Have built-in functions that allow users to easily and instantly filter out measurements when viewing a table. 4. Support both physical and virtual devices defined in the system. 5. Support exporting real time tabular data into Excel formats.

G. Power monitoring trending: The EPMS shall include graphical charts for real-time trending of power usage (kW, Volt, Amp, and kWh) or any measurement supported by metered equipment such as generators and MV/LV switchgear. These trends shall include the capability to: 1. Trend up to 14 measurements on the same chart (limit may be increased if desired). 2. Customize attributes such as color, line thickness, overlays, display name, and display units for each data series. 3. View the trend using an auto-scaling or manual chart axis. 4. Adjust the desired time viewing window for the trend. 5. Inspect the trend by zooming and panning to focus in on key areas of the trend. 6. Provide drill-down detail for the highlighted trend data point to help identify root causes of concern. 7. Trend measurements with different units on the same chart using two different axes. 8. Provide calculated values of minimum, maximum, and average values for a trend. 9. Configure a target threshold line for comparison against actual measurements. 10. Configure up to two target bands with visual indicators to identify when a measurement is outside specified limits. 11. Display real-time data and/or historical data per data series, with optional back-filling of the real-time data using historical data. 12. Export trend data to .CSV/Excel format. 13. Access trend data from a web browser or mobile environment. 14. Save specified trends in a library for later use. 15. Share trends with other users or restrict use. 16. Simultaneously view multiple trend charts, or alternatively maximize a selected trend to display it in full screen mode.

V1.1 Modified February 18, 2016 Page 13 of 32 1.18 ENERGY AND POWER MANAGEMENT SOFTWARE—ALARM AND EVENT ANALYSIS AND NOTIFICATION

A. The Energy and Power Management System (EPMS) software shall provide alarm and event annunciation features that include the following: 1. An alarm viewer that provides a summary of the active alarms shall be provided. The viewer shall: a. Be visible in any screen when logged into the web interface of the system. b. Display the total number of unacknowledged alarms, and the breakdown of how many of those alarms are high priority, medium priority and low priority. c. Provide an audible alarm and a simple means for muting the alarm. d. Allow a simple mechanism to acknowledge alarms for users with appropriate user privileges. e. Allow a mechanism to sort and group alarms. f. Allow a mechanism to set configurable alarm thresholds, for example, high, medium, and low. g. Allow a mechanism to create user defined alarm views that fit user defined criteria. h. Provide an active alarms view to show alarms currently in the active state.

B. The EPMS shall provide an alarm notification system. 1. The alarm evaluation and notification system shall ensure that appropriate staff members are notified of power system events. The system shall collect data, evaluate alarm conditions, and annunciate the alarms to specified users through email or SMS text messages. 2. The alarm evaluation and notification system shall include: a. An alarm evaluation engine. b. An alarm notification/annunciation engine that supports annunciation through email and SMS text message. c. Flexible alarm scheduling capabilities. d. Web-based configuration tools for notification configuration, log viewing, and filtering. e. The ability to control alarm flooding by intelligent aggregation through alarm filtering and consolidation. f. Message delivery mechanisms such as: 1) Electronic mail (Email). 2) Text messaging for cell phones (GSM Modem). 3) Short messaging peer-to-peer protocol (SMPP). 4) Simple Network Paging Protocol (SNPP). 5) Simple Network Management Protocol (SNMP). 6) Traditional dial-up Pager (TAP).

1.19 ENERGY AND POWER MANAGEMENT SOFTWARE—DATA ANALYTICS AND VISUALIZATION

A. The Energy and Power Management System (EPMS) software shall provide web-enabled dashboards. 1. The system shall have a web client interface that presents interactive auto-updating dashboard views that may contain water, air, gas, electric, and steam (WAGES) energy summary data, historical data trends, images, and content from any accessible URL address. 2. Users shall be able to create, modify, view, and share their dashboards (including graphics, labels, scaling, measurements, date ranges, etc.) using only a browser and without a separate software application. 3. Users shall be able to create with configurable drag and drop gadgets to show the following data: a. Images from any web-based content b. Energy consumption c. Energy cost

V1.1 Modified February 18, 2016 Page 14 of 32 d. Energy comparison e. Energy savings f. Emissions g. Trends 4. The system shall facilitate kiosk displays by assigning individual dashboards to slideshows to run in unattended mode, scrolling through designated dashboards at a configurable time interval. 5. The system shall permit users to create, save, and share an unlimited number of dashboards and slideshows.

B. The system shall provide a web-enabled reporting platform. 1. The system shall provide a web-enabled reporting tool to view historical data in pre-formatted or user-defined report templates. 2. The system shall support reporting on all supported physical devices and virtual (or calculated) meters as defined in the device hierarchy. 3. Users shall be able to create, modify, view and share their reports in the web reports interface. 4. The reporting tool shall provide standard pre-formatted report templates for: a. Billing. b. Energy cost. c. Load profile. d. System-wide interactive power quality with CBEMA/ITIC evaluation. e. EN50160 compliance. f. EN50160 Edition 4 compliance. g. IEE519-1992 Harmonics compliance. h. IEC61000-4-30. i. 100 ms. power quality. j. Energy Usage: period-over-period, by shift, single and multi-device comparison. k. Tabular and trend report. l. Alarm and event history. m. System configuration. n. Hourly usage report. o. Single and multi-device usage reports. 5. The reporting tool shall support exporting to the following output formats: .HTML, .PDF, .TIFF, .Excel, and .XML. 6. The reporting tool shall be capable of subscriptions to facilitate automatic distribution of reports according to a configurable schedule by saving to network locations, email, or print. 7. The system shall support the ability to trigger the generation and delivery of a pre-configured report based on pre-specified event criteria.The system shall be capable of configuring event monitoring detection filters criteria. 8. The reporting tool shall have a framework to support: a. Simple customizations to reports such as colors, image inclusions, turning report sections on/off, and logo changes without programming. b. Additional more complex report customization through a programming kit. 9. The reporting tool shall be capable of subscriptions to facilitate automatic distribution of reports according to a configurable schedule by saving to network locations, email, or print.

1.20 ENERGY AND POWER MANAGEMENT SOFTWARE—TECHNICAL INFRASTRUCTURE

A. The Energy and Power Management System (EPMS) software shall provide the following operating system and browser support: 1. All associated core components of the EPMS software operate as Windows operating system services. 2. The web client interface shall support multiple browsers.

B. The EPMS shall provide the following data management support: 1. Microsoft SQL Server database engine per supported configurations.

V1.1 Modified February 18, 2016 Page 15 of 32 2. All network configuration settings relating to device routing and addressing, communication gateways, distributed I/O servers, and load-distributing application servers shall be stored in the EPMS databases. 3. Archiving, trimming, and on-demand or scheduled capabilities shall be supported. 4. The capability to view historical data from archived databases shall be included. 5. The EPMS shall be capable of retrieving data from devices in the monitoring network and provide the following abilities: a. Interrogate and download logs of interval, waveform, and alarm data stored onboard metering devices and related circuit breaker trip units. b. Interrogate and download logs of interval data generated by the software system (software-based logging). c. Interrogate and download logs of alarm and event data generated by the software system (software-based alarming). d. Automatically re-arm the waveform recorders upon upload of information. e. Detect unknown measurement quantities provided by devices in the network, and automatically generate appropriate database references for those quantities without user intervention.

C. The EPMS system shall include an Administrative interface with the following management functions: 1. Security: administer groups and user accounts with role based privileges. 2. Database: initiate backup, archiving, and trimming tasks. 3. Devices: Add or rename devices, map measurements, and communication settings. 4. Connections: Configure connection schedules and manage modem connections. 5. Events: View and manage software system events.

D. The EPMS system shall function without disruptions (including communications, logging, and alarming) and shall remain online during all system administration functions such as adding, modifying, or removing devices in the system; creating, modifying, or removing graphical diagrams, dashboards, tables, and reports; creating, modifying, or removing application logic programs in the application logic engine

E. The EPMS shall support the following device support and management features: 1. The system shall include factory-tested native support for at least 50 electrical distribution devices (energy and power meters, protection relays, circuit breakers, PLCs, etc.). 2. Native comprehensive device support shall include: a. Pre-engineered, interactive graphical display screens for viewing and analyzing real- time and historical device data. b. All registers pre-mapped to standard measurement names without additional mapping of internal device registers. c. Automatic upload of time-stamped onboard data logs, event strings, and waveform captures without additional configuration. d. Automatic time synchronization. 3. The system shall support integration with other third party intelligent electronic devices (IEDs) not directly supported natively. 4. The system shall support logical device definitions for user-friendly device and measurement names for inputs/outputs or channels on devices that represent a downstream device (in the case of PLCs and auxiliary inputs) or an individual circuit (in the case of multi-circuit devices). Bulk-import capability to create large numbers of logical devices without manual single-device configuration shall be supported. 5. The system shall support the concept of hierarchies to organize devices structurally into various levels. Examples include Tenants/Racks/Circuits, PDUs/RPPs/Panels, or Buildings/Floors/Rooms. The system shall include the ability to: a. Aggregate data at any location in the hierarchy. b. Track hierarchy configuration changes over time.

V1.1 Modified February 18, 2016 Page 16 of 32 c. Allow administrators to update names in a given hierarchy at any time (even in the past) to ensure accurate reporting of associated data points (for example, report on energy consumption for a Tenant who has re-located, expanded, added, or removed circuits during the billing period). d. Export the hierarchy structure to Excel format. e. Bulk-import capability to create and edit large hierarchies without manual per-device setup.

F. The system shall support extensibility in the following ways: 1. Provide a graphical, object-oriented application logic engine to create system-wide logic modules with arithmetic, XML data import, PC-based alarming, and logging capabilities. 2. The application logic engine shall have a comprehensive set of functions to create customized applications programs for functions such as weather or real-time price import, KPI calculations, energy units conversion, data aggregation, data normalization, data comparison, power loss calculations, power factor control, load shedding, etc.

G. The EPMS system shall support system integration in the following ways: 1. Device-level Modbus interoperability. a. The system shall be capable of supporting Modbus communicating devices and be capable of functioning as a Modbus master to read/write registers in Modbus devices for monitoring and control applications. b. The system shall be capable of Modbus device definition (device drivers) creation to enable integration of third-party Modbus protocol devices. 2. System-level OPC interoperability. a. The system shall be OPC DA 2.0.1 compliant (as per the OPC Foundation Compliance Testing process) for OPC Server and OPC Client data sharing applications amongst OPC compliant systems. b. The system shall provide default OPC Server tag mappings for all natively supported device types without the need to select, configure, or program the mapping of device registers to OPC tags. c. The system shall provide a flexible means to add or change OPC mappings and shall support the ability to add custom measurements. 3. Data-level interoperability. a. The system shall support the Extract, Transform, and Load (ETL) data log file transfer mechanism to import and export data log files to integrate functions such as manual data entry, offline device data import, push data to the cloud, or to other systems. b. The system shall include a mapping application for specifying log data file import- export mappings and import schedules to facilitate import/export in formats such as .CSV, .XML, etc.

4. Web application level integration. a. The system shall include: 1) The capability to integrate other web applications into its web interface through the use of pluggable web content widgets. 2) The capability to supply content such as dashboards, reports, trends and diagrams to other external web applications through addressable URLs. 5. Web services integration. a. The system shall include web services integration capabilities for machine-to- machine interactions with other application software systems with the following characteristics: 1) Based on SOAP (Simple Object Access Protocol) protocol specification. 2) Provide a Web Services Description Language (WSDL), machine-readable description.

V1.1 Modified February 18, 2016 Page 17 of 32 3) Allow access to real-time, historical (i.e., time stamped), and alarm/event type data. 4) Provide the ability to acknowledge alarms by authenticated and authorized clients. 5) Provide digest authentication functionality. 6) Provide the ability to be enabled or disabled.

H. The system shall support internationalization and regional settings for localization. The languages supported by default are: Chinese (Simplified), Chinese (Traditional), English, French, German, Italian, Russian, Spanish, Polish, Czech, and Japanese.

I. The EPMS shall support system configuration and advanced analysis tools in the following ways: 1. The system shall include a monitoring and analysis application with a rich set of power tools for water, air, gas, electric, and steam (WAGES) energy analysis, power quality analysis, power system monitoring and control, and include the following capabilities: a. Auto-diagram creation capability to create a comprehensive set of linked hierarchical graphical diagrams showing devices and their associated device specific diagrams in the network. b. Ability to import custom graphics or images to create electrical one-line diagrams, facility maps, plan views, floor layouts, equipment representations, and mimic displays. c. Support for power quality analysis. 1) Plot PQ events on an ITIC/CBMEA curve or SEMI F47 curve. 2) Manual waveform capture. 3) Visualization or analysis tools for sinusoidal electrical waveforms including waveform overlay, zooming, and calculations for RMS, peak, delta, harmonics spectrum bar charts, and phasor diagrams. 2. Ability to write to device registers for applications such as resetting, triggering, toggling, switching, manual waveform capture, controlling remote devices and equipment, including breakers. 3. Ability to develop custom graphics screens and application logic programs with the devices being offline or disabled to allow for project development in disconnected mode.

J. The system communications infrastructure shall support the following: 1. Multiple communications network topologies including Ethernet/TCP, serial RS-485/RS- 232, and Modem dial-up connections. 2. The capability to provide time-synchronization signals over an Ethernet network with 16ms accuracy or better. 3. The capability to communicate simultaneously with multiple devices, including devices on different physical communications channels. 4. Scalability to greater than a thousand devices. 5. The ability to automatically retrieve logged data (interval data, event data, and waveform data) from natively supported devices without additional configuration. 6. The ability to accept or reject duplicate data entries into the database. 7. The ability to schedule connection times for specific time-periods to conserve bandwidth. 8. The ability to automatically disconnect modem connections when all device data is database-synchronized (used to minimize long distance phone charges). 1. Support for modem pooling and assignment of communication sites to specific modems for communications optimization.

1.21 APPLICATIONS—POWER QUALITY MONITORING, COMPLIANCE AND ANALYSIS

A. Power Quality Monitoring: The Energy and Power Management System (EPMS) software shall provide power quality specific screens and reports as follows.

V1.1 Modified February 18, 2016 Page 18 of 32 1. Device Level Power quality summary screen—the data collected by any compliant PQ-capable metering device shall be summarized to show: a. Voltage disturbances, including the date and time of the last disturbance, the count of the number of transient events, and the count of the number of sag/swell events. b. Harmonic measurements, including a link to the harmonics log for the particular device. Additionally, there shall be a link to another screen that shall show the real- time Total Harmonic Distortion (THD) content and the maximum THD. c. Flicker measurements. d. Logged events, including a link to the event log for the particular device. e. Waveform logs, including a link for waveforms captured during transients and sag/swell events. f. Further detailed waveform analysis using a tool shall be provided.

2. System Level Power Quality summary screen—the power quality report shall display all power quality events collected in the EPMS for one or more measuring points for a given period of time. a. The report shall show a summary table of all the events in a given time period and provide the means to see further details (power quality details report) for any given event. b. The summary report shall contain a plot of the Information Technology Industry Council (ITI) (also known as ITIC or CBEMA) curve that displays the worst disturbance from each event listed in the summary table. The summary table shall contain the following components for each event: 1) Event identifier. 2) Source. 3) Event timestamp. 4) Phase identifier for the worst disturbance during this event (ex., "V1"). 5) Voltage magnitude for the worst disturbance during this event in % of nominal (for example, "68.80%") 6) Voltage magnitude maximum and minimum on phases V1, V2 and V3 for the worst disturbance during this event in % of nominal. 7) Duration for the worst disturbance during this event in seconds (for example, "0.084s"). 8) Disturbance type for the worst disturbance during this event (for example, "sag"). 9) ITI (ITIC, CBEMA) tolerance curve violations (for example, "outside tolerance"). 10) Link to the details report for this event. 11) Link to waveform report for the worst disturbance during this event. c. Each entry in the summary table shall include a link that provides further details for the given event. The details to be shown are: 1) Disturbance event timestamp. 2) Phase identifier. 3) Voltage magnitude in % of nominal (for example, "68.80%") 4) Voltage magnitude maximum and minimum on phase V1, V2 and V3 in percentage of nominal. 5) Duration in seconds. 6) Disturbance type. 7) ITI (CBEMA) tolerance curve violations (for example, "outside tolerance"). 8) Link to waveform report. d. Each entry in the summary table shall include a link that shows the waveforms of the given event (if any exist). The waveforms shown shall be for both the voltage and current readings of the measuring point.

3. One hundred (100)-millisecond Power Quality Report a. This report shall display data recorded at 100 millisecond intervals, with a data table for the measured point and selected measurement containing columns labeled: Timestamp, Source Label, Measurement Label, Measurement Unit, and Data Value.

V1.1 Modified February 18, 2016 Page 19 of 32 4. IEEE1159.3 Power Quality Data Interchange Format (PQDIF) Support 5. The system shall provide a mechanism to export power quality data to the non-proprietary standard PQDIF format with support for the following default templates: a. Flicker: Short-term and long-term flicker disturbance data on the voltage inputs. b. Sag/Swell: Sag/swell disturbance data for voltage inputs, including minimum, maximum and average values. c. Sag/Swell Waveforms: Waveform data for voltage sag/swell. d. Steady-state: Steady-state (RMS) data for trending. e. Steady-state Waveforms: Waveform data for steady-state data.

6. Disturbance Direction Detection a. For power quality compliant devices, the system will indicate the direction of the disturbance within the electrical distribution system in event logs, with associated confidence or certainty rating (for example, “Upstream: Confidence Rating - High”, or “Downstream: Confidence Rating – Medium” etc.).

B. Power Quality Compliance Reporting 1. EN50160 Edition 4 compliance report a. The EN50160 voltage characteristics of public distribution systems compliance report shall display a summary of EN50160 compliance for a set of measuring points in the system for a given time period for the following components: 1) Power frequency. 2) Supply voltage variations. 3) Flicker severity. 4) Supply voltage unbalance. 5) Harmonic voltage. 6) Inter-harmonic voltages. 7) Mains signaling voltages. 8) Interruptions of supply voltage. 9) Supply voltage dips and swells. b. Additionally, the report shall allow for detailed drill-down for a given measuring point and measurement period.

2. IEC61000-4-30 report The IEC61000-4-30 compliance report shall display a summary of the IEC61000-4-30 compliance for a set of measuring points in the system for a given period. The report shall: a. Include the following IEC61000-4-30 components: frequency, supply voltage magnitude, flicker, supply voltage unbalance and supply voltage THD. b. Provide a means to manually enter a baseline value for each component. c. Display a series of trends for each component listed with each component’s manually entered baseline. d. Include a data table that displays all the power quality-related events for the given report period including voltage dips, voltage swells, and voltage interruptions.

3. IEEE 519 Harmonics Compliance report The IEEE519 harmonics compliance report shall have the following capabilities: a. Provide a mechanism to report on IEEE519 limits. b. Provide a mechanism to report on user defined limits. c. Ability to determine voltage and Isc/I-l ratio directly from the device, where Isc is the maximum short circuit current at the point of common coupling (PCC), and the I-l is the maximum fundamental frequency demand current.

4. For both individual and total harmonic voltage distortion, display the following: a. The allowable IEEE519 limits.

V1.1 Modified February 18, 2016 Page 20 of 32 b. The % time out of compliance. c. The number of non-compliant three-second intervals. d. The number of total measured intervals. e. Number of missing or invalid intervals. f. Compliance levels of Warning, Out of compliance, or Compliant. g. A maximum value with a time-stamp of when that distortion was measured.

5. For both individual and total harmonic distortion for current, display all the values specified in the previous section for every range of harmonic orders.

6. For each phase, voltage, and current provide a graphical plot of THD versus time stamp. On the same plot, plot the allowable limit to allow for visual comparison of compliance.

7. Provide a graphical plot of “average value of voltage per harmonic” and “average value of current per harmonic” as a percentage of fundamental frequency, versus harmonic order to allow for visual identification of the worst harmonic problems.

8. For each phase voltage and current, provide a graphical plot of harmonic content versus time stamp with simultaneous plot lines for a set of harmonic orders (for example, h <= 11). This allows the user to identify the harmonic orders associated with the worst problems to enable mitigation measures such as active filtering.

C. Integration with Power Quality Mitigation Equipment 1. The system shall natively support interfaces with power quality mitigation equipment for power factor correction, harmonic filtering, voltage sag mitigation (UPS), and transient protection to provide end- to-end solutions for monitoring, correction and optimization of power quality.

1.22 APPLICATIONS—ASSET AND CAPACITY MANAGEMENT

A. Equipment Capacity Planning (NEC 220.87 compliant) reporting shall meet the following criteria: 1. For each device, monitor maximum load and compare to equipment capacity to indicate the degree of equipment loading. 2. Highlight when a user configurable threshold (for example, 80%) is exceeded. 3. Provide the ability to report on all power distribution equipment such as automatic transfer switches, medium and low voltage switch gear, transformers, power distribution panels, uninterruptible power supply, etc. 4. Show the peak load provided by the transfer switch or other equipment during a time period and compare the peak load to equipment capacity. 5. Provide a summary of all transfer switches or equipment in a group or daily information for each piece of equipment in the group.

1.23 APPLICATIONS—ENERGY COST ALLOCATION

A. The Energy and Power Management System (EPMS) software shall include energy cost allocation and bill generation features designed for the following applications. 1. Internal Cost Allocation 2. Tenant Bill Generation 3. Utility Bill Verification (Shadow Bill Generation)

B. The EPMS cost allocation and bill generation features shall include 1. Reporting on energy costs for all energy sources - WAGES (Water, Air, Gas, Electrical and Steam)

V1.1 Modified February 18, 2016 Page 21 of 32 2. Aggregating energy costs up to any point in the organizational hierarchy, such as areas, departments, cost centers, tenants etc. 3. Configurable start and end dates for energy cost reporting. 4. Calculated apportionment by creating virtual measurements allocating percentages of physical meters, for example, 20% (Meter 2) + 80% (Meter 3). 5. Calculated net metering by creating summed or subtracted physical meters, for example, Meter 1 + Meter 2 – Meter 3. 6. Common area allocation to allocate calculated values to various entities in the organization hierarchy 7. Allocation of cost by standard time intervals, such as daily, weekly, monthly, yearly, or by specified time intervals like production shift 8. Data integrity checks including warnings for data gaps or duplicates. 9. Customization of energy cost reports to allow for custom logos and headers.

C. The EPMS shall include a rate engine with the following capabilities. 1. Pre-engineered rate files for common utility rate structures. 2. Support for rate schedule configuration and business logic through configuration files (no programming) 3. Support for common rate determinants including: a. Energy usage (kWh, kVARh, kVAh) b. Demand (kW, kVAR) c. Power factor penalties d. Co-incident demand e. Time of use rates (off-peak, on-peak, etc.) f. Seasonal rates (summer, winter, etc.) g. Daily charges h. Tiered or block energy rates (kWh) i. Taxes j. Dynamic rate formulas 4. Web based interface for rate schedule editing.

D. The EPMS shall include the following user-configurable report templates to facilitate energy analysis. 1. Billing Report: Billing report for any entity in the hierarchy with a. configurable time-periods and rate structures b. Itemized entries with each item in the rate structure and associated costs clearly specified 2. Billing Summary Report: Billing Report for multiple entities in the hierarchy with a. Energy costs per entity represented as a subtotal section b. Grand Total for all entities 3. Multiple Billing Report: Billing Report for multiple entities in the hierarchy with a. Each individual entity represented as a distinct section b. Itemized entries with each item in the rate structure and associated costs clearly specified

E. The EPMS will support customizing the cost allocation reporting to different environments such as: 1. Industrial Environment: a. Energy cost while in operation versus shut down, by shift etc. b. Energy cost per unit of production. 2. Building Environment: a. Energy cost while building occupied versus empty. b. Energy cost per occupant. 3. Data Centers: a. Energy cost by colocation tenant.

V1.1 Modified February 18, 2016 Page 22 of 32 b. Energy cost by PDU, rack etc. 4. Provide above comparisons in graphical format such as bar and pie charts.

F. The EPMS shall have the capability of exporting energy cost data, along with pertinent metadata, to integrate with external billing systems. The export mechanisms must be flexible with 1. Support for common data file formats such as xml, csv and multiple files 2. Support for XSLT transformations to customize format to match systems for billing, accounting, SAP, ERP etc.

1.24 APPLICATIONS—POWER DISTRIBUTION EFFICIENCY (DATA CENTERS)

A. Power Usage Effectiveness (PUE) 1. The system shall provide pre-built templates for the display of PUE as a "real time" value in graphics screens and dashboards. 2. Measurement and reporting of PUE shall be able to utilize both Power and Interval Energy measurements, depending on whether the values displayed are "real time" values or historic values. 3. PUE real time and historic report set up shall be capable of utilizing a variety of available measurement sources including Modbus, ION, and SNMP devices. 4. Historic PUE reporting shall support Green Grid recommended reporting categories 1, 2, and 3. 5. The PUE report will support display of the following data: a. PUE summary table, showing aggregated rollup values for PUE, IT Equipment Power Consumption and Total Data Center Power Consumption for the following time periods - last 24 hours, last 7 days, last 30 days and last 12 months b. PUE trend showing a weekly roll-up of the Data center PUE for the last 12 months c. Up to two full years of PUE roll up values in trend and stacked bar graph display d. Energy trend plot showing a weekly roll-up of energy consumption for the last 12 months of both the IT and support loads in the facility

B. Calculated Power Losses Reporting 1. The EPMS shall include a report to calculate the power system losses from MV transformers, UPSs and LV transformers. This report shall: a. Provide a summary cost of the losses. b. Show both graphically (stacked bar chart) and in tabular format (for a user-selected time period) aggregation for four types of equipment losses (MV transformer, LV transformer, UPS): cost of losses and kW values for losses. c. Show in tabular format for each piece of equipment, grouped by the three types of losses (MV transformer, LV transformer, UPS), during the user-selected time period: efficiency (%), losses (kW), losses (cost), average over time frame of the above values.

1.25 APPLICATIONS—SEQUENCE OF EVENTS RECORDING

A. The Energy and Power Management System (EPMS) software shall include a comprehensive high accuracy and resolution Sequence of Events Recording (SER) sub-system to enhance power availability and reliability by providing root cause analysis tools.

B. All data points connected to the high accuracy SER system shall be date-time stamped to one millisecond accuracy and resolution, synchronized through GPS timing.

C. The SER sub-system shall aggregate one millisecond accurate time-stamped events from multiple devices and provide a consolidated system view showing a list of events, ordered and categorized by time-stamp, priority, name of equipment, etc. All of the following

V1.1 Modified February 18, 2016 Page 23 of 32 necessary hardware and associated equipment status/alarm contacts must support the 1 ms requirement: 1. Utility distribution switchgear—multifunction electronic relays, power quality meters, and breaker open/closed/tripped position. 2. Generator paralleling switchgear—multifunction electronic relays, power quality meters, and breaker open/closed/tripped position. 3. Substations and low voltage switchgear/switchboards—power quality meters and breaker open/closed/tripped position.

D. The SER recording (high accuracy) hardware needed to implement the SER sub-system shall comprise an integrated collection of devices and components to provide synchronized time- stamp signals, and record events, with an accuracy of one millisecond. The devices chosen shall be compatible and natively supported by the EPMS software. 1. The hardware shall include any or all of the following devices to record the most critical system events as defined in the proposal point list: a. Antenna and lightning arrestor. b. GPS clock. c. Clock signal distribution hardware. d. Event recorders. e. Power quality meters. f. Multifunction electronic relays. g. Data network components. h. Enclosures. i. Computer hardware. 2. Device Level Recording. a. Time stamping and event recording should be implemented at the local device level where the event occurs (event recorders, meter I/O, or relays), rather than at the EPMS computer server. For instance, a breaker trip event shall be time-stamped by an event recorder that is local to the switchboard, or local to the location of the switchboard. The use of software to scan, poll, and time-stamp events through a PLC or on a server is not permissible, since this can introduce scan time and network communication delays. b. Hardware requirements for 1-millisecond accurate event recording of discrete inputs, such as breaker open/close and trip status, EPMS-compatible sequence-of-events recorders must have the following key features: 1) Onboard clocks time-synchronized to one millisecond accuracy. 2) Onboard data logs for storing events. 3) Modbus RTU or Modbus/TCP interface. 4) GPS time synchronization input per the IRIG-B time synchronization standard. 5) Thirty-two (32) high-speed digital inputs each with configurable filter, debounce, and chatter functions. 6) Discrete output to trigger waveform capture in a power quality meter (this output shall be pre-wired to the power quality meter by the switchgear manufacturer). 7) Event log capacity to store 8000 events accessible from multiple masters. Each event record shall contain descriptive information for root-cause analysis, such as time/date stamp, input number, event type, input status, time quality, and unique sequence number. 8) Ethernet network interface supporting Modbus TCP/IP and embedded web server for setup and monitoring. 9) Capability to customize embedded web pages. 10) Non-volatile memory to store setup and event data. 11) A built-in, standard SD flash memory card to store user setup values and other user files. 12) Ability to export event data in .CVS format directly from the device without the need for software integration

V1.1 Modified February 18, 2016 Page 24 of 32 3. Hardware requirements for compatible multi-function electronic relays include: a. For multifunction electronic relays with time synchronization capabilities, ANSI function codes of events with one millisecond time stamp shall be accessible for software integration, using a Modbus RTU or Modbus/TCP interface. 4. Hardware requirements for compatible power quality meters include: a. For power quality meters having time synchronization and waveform capability, the time stamps (one millisecond accuracy) of the waveform shall match the events that initiated the waveform capture.

E. Sequence of Events Recording (SER) software integration. 1. The SER functionality of the EPMS software shall provide the following functions: a. Upload event data from on-board device logs (meters, relays, event recorders), arrange chronologically, and store in the EPMS data store. b. Provide a consolidated system-wide event log view with one millisecond accuracy and resolution, with the following parameters: data/time stamp with one millisecond resolution, quality of date/time stamp, event description, state/value, priority, name of equipment or component being monitored, location of monitored equipment or component. c. Sorting and filtering capabilities based on event attributes. d. Note: Data collection via software based scanning or polling is not permissible since this can introduce scan time and network communication delays. 2. The technical infrastructure and configuration capabilities of the SER sub-system software must include the following: a. Role based security with user groups and levels to allow or restrict access to both event logs and setup and configuration based on user privileges. b. Run-as-a-Windows-service option to allow for critical applications. c. Support Modbus/RTU or Modbus/TPC communications to access device event logs. d. Web-based client. e. Full native compatibility with EPMS SER Hardware such as the following: 1) Schneider Electric Circuit Monitor series 4000. 2) Schneider Electric Power Meters, series 870. 3) Schneider Electric ION 7650 meters. 4) Schneider Electric Sepam protection relays, series 20, 40, 80. 5) CyTime SER-3200 and SER-2408 Sequence of Events Recorders. f. Ability to interrupt polling for device-out-of-service and communication loss conditions. g. Diagnostic health-check for the SER sub-system with one millisecond resolution time-stamped diagnostic messages.

1.26 [APPLICATIONS—UPS INFRASTRUCTURE MANAGEMENT (DATA CENTERS)

A. The Energy and Power Management System (EPMS) software shall include a report to compare the current state of the uninterruptible power supply (UPS) system with thresholds for redundancy design. The report shall help assess the available capacity of the UPS system(s) in relation to both UPS module de-rating and the intended redundancy design (ex., N+1, N+2, 2N, 2(N+1), 2(N+2)). This report shall: 1. Report the available capacity before the designed redundancy is compromised, or show if the system is oversubscribed and by how much. 2. Graphically display the UPS equipment in its redundancy configuration. 3. Show both graphically and in tabular format during the user-selected time period. 4. Show the redundancy design limit. 5. Show the peak system load. 6. Show the calculated difference between the redundancy design limit and the peak system load.

V1.1 Modified February 18, 2016 Page 25 of 32 7. Show the information rolled-up to a system level, but also in increasingly more granular detail down to each UPS itself.]

1.27 [APPLICATIONS—BRANCH CIRCUIT MANAGEMENT (DATA CENTERS)

A. Branch Circuit Configuration. 1. The Energy and Power Management System (EPMS) software shall provide a mechanism to: a. Automatically organize branch circuit meter data in to virtual branch circuits. This includes the ability to support 1-pole, 2-pole, and 3-pole breakers in a PDU/RPP/busway with mixed breaker types. b. Provide a browser-based graphical user interface (GUI) to organize and manage the relationships between branch circuits, PDUs. RPP, busway, IT rack, and IT customers. c. The GUI shall also allow for: 1) Simple, efficient work flow that supports the ability to make retroactive changes. 2) The ability to dynamically change associated start and end dates (for example customer move-in or move-out). 3) Electrical reconfiguration associated with IT customer changes to equipment. 4) Manage key attributes such as breaker size, rack name, rack location, and Customer name.

B. Branch Circuit Power Reporting. 1. The EPMS shall provide a report to analyze the average and maximum loading for branch circuits within the facility. The report can be run with historical configurations of racks, customers, and circuits. The report shall be filterable by customer name. This report shall provide: a. The average and maximum loading (current and power) values of the circuit, and percentage loads compared to the breaker size. b. Customer or group name associated with the given rack in the facility. c. Rack name. d. Branch circuit assigned to rack. e. Breaker size (A). f. Average loading (A). g. Average loading (kW). h. Average loading (%). i. Maximum loading (A). j. Maximum loading (kW). k. Maximum loading (%). l. Report timestamp.

C. Branch Circuit Energy Report. 1. The EPMS shall provide a report to allocate energy usage for customers for billing purposes. The report shall have configurable date ranges and be run with historical configurations of racks, customers, and circuits. The report shall be filterable by customer name. This report shall provide: a. A detailed rack by rack or summary view for a data center customer’s energy usage. b. The peak current for each circuit. c. The energy consumption per rack and customer summary. d. Title. e. Facility name. f. Facility location. g. Billing ID. h. Customer name. i. Rack name. j. Branch circuit. k. Start date. l. End date.

V1.1 Modified February 18, 2016 Page 26 of 32 m. Energy (kWh). n. (Coincident) Current (A). 1) Customer detail (per rack or circuit). a) Coincident by customer. b) Coincident by utility. 2) Customer summary (customer total). a) Coincident by customer. b) Coincident by utility. 3) Peak (coincident) demand (kW). 4) Customer detail (per rack or circuit). a) Coincident by customer. b) Coincident by utility. 5) Customer summary (customer total). a) Coincident by customer. b) Coincident by utility. 6) Peak demand time-stamp.]

1.28 [APPLICATIONS—GENERATOR INFRASTRUCTURE MANAGEMENT (DATA CENTERS)

A. The Energy and Power Management System (EPMS) software shall include a Generator Capacity Planning report customizable to accommodate the site’s redundancy with the following features: 1. Display the available capacity before the designed redundancy is compromised, or show if the system is oversubscribed and by how much. 2. Graphically display the generator equipment in its redundancy configuration. 3. Show both graphically and in tabular format for the backup generator system, during the user-selected time period. 4. Display the redundancy design limit. 5. Display the peak system load. 6. Display the calculated difference between the redundancy design limit and the peak system load.

B. The EPMS shall include a mechanism to document Backup Generator System testing for a written record of generator system inspection, performance, testing, and repairs. The EPMS shall include screens relating to generator system testing providing: 1. General information—generator name, nameplate ratings, and description. 2. Testing evaluation data—test load and test duration. 3. Generator status—starting, running, stopped. 4. Engine data—oil pressure, coolant temperature, and other user-defined measurements (as available). 5. Exhaust gas data—exhaust gas temperature (left/right) when available. 6. Electrical data—voltage, current, power (active, reactive, apparent), power factor, load percentage, and frequency.

C. The EPMS shall include a Generator Test Report showing: 1. Generator summary section displaying the overall grade (pass/fail) of the test (provided the “include pass/fail indicator” has been configured) and the test evaluation method used. 2. Generator load summary section showing: a. Load graph—when using the load evaluation method, the graph shall compare actually recorded test data to the required load threshold. When using the “exhaust gas temperature evaluation method,” the graph shall show the minimum required exhaust gas temperature along with recorded test data. When using the “load bank testing method,” the graph shall compare applicable acceptable power load thresholds with the respective test data.

V1.1 Modified February 18, 2016 Page 27 of 32 b. Minimum, maximum, and average table—when using the load evaluation method, the min, max and average table shall contain corresponding values for active power, apparent power, current per phase, L-N, and L-L voltages. When using the load bank testing method the minimum, maximum, and average table shall contain corresponding values for each of the applicable stages. c. Generator exhaust temperature summary section—this section shall include the beginning and end date and time (HH:MM:SS) for the longest continuous temperature (LCT) at or above the manufacturer recommended minimum exhaust gas temperature. In addition, the manufacturer recommended minimum exhaust gas temperature, the required run duration (minutes) and the pass/fail status based on the LCT shall be displayed. 3. Exhaust temperature graph—this graph shall display the required manufacturer recommended minimum exhaust gas temperature and the actual recorded exhaust gas temperature data. 4. Minimum, maximum, and average exhaust temperature table—this table shall display the minimum, average, and maximum exhaust temperature readings for longest continuous temperature at or above the minimum acceptable exhaust temperature.

D. The EPMS shall include a Generator Activity Report to list each instance the generator was run, categorize the reason (test, emergency, etc.), and a cumulative total of emergency and non-emergency run time. The EPMS shall show a comparison of the number of non- emergency hours compared with the allowable threshold (for example, 100 hours as per EPA in the US) for the reporting period for each generator.

E. The EPMS shall include a Generator Battery Health Monitoring Report displaying the voltage of the engine start battery during engine starting (minimum sampling rate of one (1) sample/ms.). By comparing signatures, the system can provide predictive maintenance insight into when the batteries need to be replaced or other related equipment (such as the starter motor) needs to be serviced.

F. The EPMS shall include a tablet/smart phone Generator Test Data Recording Interface to allow input of generator test values and other values, such as maintenance events that include task/timestamp/name of person automatically into the EPMS database.]

1.29 [APPLICATIONS—BILLING DATA INTEGRATION (DATA CENTERS)

A. Energy Billing Support—Data Export. 1. The Energy and Power Management System (EPMS) software shall be capable of exporting branch-circuit energy data (including energy consumption, peak demand and peak current) in CSV format to billing software to facilitate electrical energy billing. The export mechanism shall support: a. Automatic export at configurable billing periods. b. Organization and presentation of data by IT customer and/or by IT rack. c. Multiple export file formats such as CSV and XML.

B. Data Center Infrastructure Management (DCIM) Data Integration. 1. The EPMS shall natively be able to export branch-circuit energy data to DCIM systems to facilitate power capacity planning. 2. The data export file shall include energy consumed, average power (block demand) and average current by circuit (utility main(s), mechanical loads, PDU incomers(s), PDU panel incomers(s), RPP incomer(s), RPP panel incomer(s), IT busway feeder, IT branch circuits). Calculations shall be done every 15 minutes. Data export shall be automatic with configurable frequency (minimum hourly). Data shall be tagged appropriately so DCIM software can automatically associate the data to the IT equipment in the system.]

V1.1 Modified February 18, 2016 Page 28 of 32 1.30 [EQUIPMENT - LOW VOLTAGE DRAWOUT (LVDO) SWITCHGEAR INTEGRATED INTO EPMS

When specified, Low Voltage Drawout Switchgear (identified as LV switchgear) constructed to ANSI C37.20.1 standards shall be provided as indicated on the drawings. Main and Feeder Circuit Breakers used in the LV Switchgear shall be Stored Energy Power Circuit Breakers designed, tested and manufactured to ANSI C37.13 and UL1066.

1. The switchgear manufacturer shall be a firm engaged in the manufacture of switchgear of types and sizes required, and whose products have been in satisfactory use in similar service for a minimum of fifteen (15) years.

2. The scope of work specified herein shall be coordinated with LV Switchgear manufacturer to ensure compatibility between software and hardware as follows: 1. The LV Switchgear lineup shall include an internal inter-wired communications network for connection to the user’s network for power monitoring, equipment status and alarms. 2. The following communications capabilities to the switchgear communications network will be provided. a. A connection to connect to on premise EPMS software b. Communications to each breaker’s embedded web pages for maintenance review, troubleshooting and monitoring through a standard web browser. 3. The switchgear communication system shall have the following characteristics. a. Ethernet Modbus TCPIP connection via daisy-chain architecture to each Stored Energy Power Circuit Breaker and meters b. Pre-configured and tested at the factory (including breakers and metering devices), with relevant network drawings provided. Final device addressing will be configurable by the end user. c. Network inter-wiring consisting of shielded cables with pluggable connectors to facilitate ease of connection across shipping splits. d. Documented communications test results including network connections provided upon request. 4. Each Stored Energy Power Circuit Breaker shall contain an embedded web server to provide breaker/cradle status, energy monitoring, historical trending, maintenance indicators/logging, email alerts and communications diagnostics without necessarily connecting to the system EPMS software i.e. via a direct connection to the web server. Downloadable software shall be available to adjust trip/alarm points, display tripping curves and update firmware. 5. EPMS software integration will include native communications drivers as specified in the “EPMS Software – Technical Infrastructure” section. 6. Each Stored Energy Power Circuit Breaker shall be compatible with the Breaker Aging Monitoring functionality as specified in the “Applications - Breaker (LV) Infrastructure Management” section, to provide an estimate of electrical and environmental aging data for preventive maintenance planning.]

1.2 [APPLICATIONS— BREAKER (LV) INFRASTRUCTURE MANAGEMENT

A. The Energy & Power Management System (EPMS) software shall include Low Voltage (LV) Breaker Aging Monitoring to provide an estimate of electrical and environmental aging data (for all supported breakers) that can then be used for preventive maintenance planning for LV switchgear.

B. The aging algorithm will use the following electrical and environmental parameters to estimate aging percentages for supported devices. 3. Overload tripping 4. Short circuit tripping 5. Operation

V1.1 Modified February 18, 2016 Page 29 of 32 6. Commissioning date 7. Ambient temperature 8. Vibration 9. Humidity

B. The system will include a breaker aging report providing maintenance information (for supported devices) related to: 1. Electrical aging in percent 2. Environmental aging in percent 3. Classification of breakers by group and aging status]

PART 3 EXECUTION

1.31 SERVICES—INSTALLATION AND COMMISSIONING

A. Installation. 1. System components, including meters, electronic trip units, sensors, motor protection devices, relays, etc. included within power equipment line ups, shall be factory installed, wired, and tested prior to shipment to the job site. 2. All control power, CT, PT, and data communications wiring shall be factory wired and harnessed within the equipment enclosure. 3. Where external circuit connections are required, terminal blocks shall be provided with manufacturer drawings clearly identifying any interconnection requirements and wire types. 4. All external wiring required to connect equipment lineups shall be installed by the electrical contractor. 5. Contractor interconnection wiring requirements shall be clearly identified on the system drawings. 6. Vendor field technicians shall verify accuracy of installation prior to commissioning.

B. System Commissioning and Acceptance. 1. Factory-trained personnel shall perform on-site commissioning using automated commissioning tools to improve consistency and quality of commissioning. 2. Central engineering resources in conjunction with onsite factory trained personnel shall be involved in preparing a client’s system for startup. 3. If needed, a trained and certified project manager shall be provided during project installation and commissioning. 4. If LV Switchgear is specified, a representative of the LV Switchgear manufacturer trained in the installation, operation, and maintenance of the LV Switchgear and Breakers, will perform commissioning and acceptance of the equipment. 5. Engineering drawings shall be made available to the client for all EPMS projects. 6. On-site commissioning and initial user training of the EPMS shall be included in the project bid. 7. Commissioning shall include a detailed scope of work checklist document with delivered functionality listed and checked. 8. Commissioning shall include a full working demonstration of the system under normal operating conditions and simulated scenarios. 9. For control applications such as automatic transfer, commissioning shall include a thorough verification of the approved sequence of operation in both manual and automatic modes. Testing of source outage and breaker exercising shall be included in test procedures. 10. For control applications, such as automatic transfer, source interruptions are necessary. The owner must schedule appropriate times for such commissioning, and must plan for time (typically a day) for system pre-testing and a day for acceptance testing. Weekends are preferred due to minimized impact on operations.

V1.1 Modified February 18, 2016 Page 30 of 32 1.32 SERVICES—TECHNICAL SUPPORT

A. The vendor shall have capabilities to deliver a full suite of ongoing technical support services to optimize and tune performance of the Energy and Power Management System (EPMS). Services shall include but not be limited to the following: 1. Basic product support via telephone and email during regular business hours to provide technical guidance, incident diagnosis, basic troubleshooting, and “how-to” instructions to operate installed software and hardware. 2. Fully staffed technical support teams for advanced problem escalation. 3. Troubleshooting using remote connectivity to the customer system. 4. Self-help web portal access to service packs and knowledge base detailing technical best practices and product details. 5. On-demand self-paced training with energy management, metering infrastructure, and power quality content modules. 6. Reserved support engineer as a “single point of contact” for customer support (when specified). 7. Emergency after-hours support with guaranteed response within two hours (when specified). 8. Software Assurance including service packs and upgrade licenses for installed EPMS software (upgrade-commissioning-services when specified). 9. Power Analysis Diagnostic Report including results of remote diagnostics to assess EPMS system health including configuration, data accuracy, and communications infrastructure. 10. Periodic monitoring of EPMS server and software to proactively alert for system problems. 11. Onsite maintenance including system repairs, database maintenance, firmware upgrades, and software installations.

1.33 SERVICES—TRAINING

A. The vendor shall have capabilities to deliver a full suite of training solutions focused on the operation, maintenance, and optimization of the customer's EPMS system. These training solutions shall address both initial and ongoing training needs for the customer and shall include the following: 1. Training delivered by experienced instructors with direct experience with the installed equipment and teaching proficiency. 2. Majority of the training is hands-on (up to 80%) with the equipment. Each student has access to their own mini power monitoring system through an electrical metering demo case, Ethernet communications, and laptop running applicable metering software, or through a virtual server if attending remotely (not applicable for self-paced on-demand training). 3. Training manuals including agenda, defined objectives for each lesson, detailed content organized by lesson, and descriptive labs to complete hands-on exercises shall be provided. 4. Training content (depending on class) will cover functionality and operation of electric meters, definition and use of various metering data (such as energy, demand, power factor, load profile, time of use, KYZ, etc.), communication methods applied in various design topologies, and capabilities and operation of applicable software.

B. Training options may include but are not limited to: 1. Self-paced on- demand training on energy management, metering infrastructure, and power quality. 2. Hands-on training at client’s site using metering and communications hardware, equipment and relevant software to implement, operate and maintain the power monitoring system. 3. Instructor led remote web based training with real time interaction with trainer and hands on training using virtual servers to perform labs and exercises. 4. At Schneider facility, hands-on training on how to design, implement, and operate the EPMS system. 5. Video recording services to complement custom client onsite training with professional post- production services to provide the customer with a professional customized training DVD.

V1.1 Modified February 18, 2016 Page 31 of 32 END OF SECTION

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