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SynC · Historical revision

Electrical Power Monitoring and Metering

Revision3
EditedAug 26, 2026
StatusSuperseded
Contents

View changes in this revision   Revision history

Historical revision. This is editorial revision 3, kept so citations to it stay resolvable. It is not the current text of this standard — see the current revision.

SynC Standards Team — Specifier (Platform Standards) ✓ OfficialDiscloses employment SynC (SynC Platform Team)
Corpus sync: neutrality remakes, note hygiene, datasheet relocation, transformer-split cross-refs

1 Scope

NOTE This standard governs permanently installed electric power meters, power monitoring devices, branch-circuit monitoring systems, and their associated current and voltage sensors. The intent is to produce traceable, time-synchronized energy and demand data at defined metering points so that the building meets code-required metering, supports tenant sub-billing where authorized, and feeds an energy or power monitoring software platform. (1.1)
NOTE A metering point is any electrical node where current and voltage are sensed to compute power and energy for that node; metering points form a hierarchy from service entrance down to branch circuit. (1.2)
1.3 The Contractor shall furnish and install all meters, current sensors, voltage sensors, fuses, wiring, and terminations required to deliver complete and operational metering at each metering point shown.
1.4 The Contractor shall coordinate metering scope, communication protocol, and integration responsibility with the controls contractor and the energy monitoring software provider before rough-in.
NOTE Metering points designated revenue-grade for utility or tenant billing are subject to weights-and-measures and utility approval requirements that fall outside the National Electrical Code; these are Owner coordination items identified in this standard but not satisfied by code compliance alone. (1.5)

2 Referenced Standards

NOTE The following standards are referenced in this section; the edition in force at the date of the Contract Documents governs except where a specific edition is named. (2.1)
Standard Title
ANSI C12.1 American National Standard Code for Electricity Metering (primary U.S. code for revenue-grade metering; the 2026 edition absorbed the former ANSI C12.20 for 0.1, 0.2, and 0.5 accuracy classes — cite C12.1, not C12.20)
NEMA EG 1 Functional Performance Standards for Electric Metering
IEC 61557-12 Performance Requirements for Measuring Equipment for Power and Energy (PMD classes M1–M8)
IEEE 1459 Standard Definitions for the Measurement of Electric Power Quantities
IEEE C57.13 Standard Requirements for Instrument Transformers
UL 61010-1 Safety Requirements for Electrical Equipment for Measurement, Control, and Laboratory Use
ASHRAE 90.1 Energy Standard for Buildings Except Low-Rise Residential Buildings
IECC International Energy Conservation Code, Commercial Provisions
NFPA 70 National Electrical Code (Articles 230, 250, 408, 705)
NIST Handbook 44 Specifications, Tolerances, and Other Technical Requirements for Weighing and Measuring Devices

3 Definitions

NOTE The following terms are used throughout this standard: (3.1)
  • Revenue-grade meter means a meter that meets ANSI C12.1 accuracy, sealing, and tamper-evidence provisions and is suitable for utility or tenant billing.
  • Power monitoring device, or PMD, means a panel-mounted meter classified to IEC 61557-12 (classes M1 through M8) intended for energy management rather than legal-for-trade billing.
  • Branch-circuit power monitoring, or BCPM, means a multi-channel metering assembly that measures many individual branch circuits at one panelboard using one current sensor per circuit aggregated through a shared metering module.
  • Current transformer, or CT, means a current sensor whose secondary output is proportional to the primary conductor current; CTs are classified by ratio, accuracy class, and burden rating.
  • Voltage transformer, or VT, also called a potential transformer or PT, means a voltage sensor used where the system voltage exceeds the direct-connect voltage rating of the meter.
  • Burden means the total impedance presented to a CT secondary, expressed in volt-amperes at rated secondary current, and includes the meter input and the lead-wire resistance.
  • Energy or power monitoring software, or EPMS, means the platform that collects, stores, displays, and reports meter data and produces code-compliance reports.

4 Submittals

4.1 Action Submittals

4.1.1 The Contractor shall submit the following action submittals for review before fabrication or ordering:
  • Product data for each meter, PMD, and BCPM, including accuracy class, measured parameters, and listing
  • Product data for each current sensor, including type, ratio, accuracy class, and rated burden
  • Product data for each voltage transformer, including ratio, accuracy class, and fusing
  • CT secondary burden calculation for each CT-rated meter, including lead length, wire gauge, and total VA
  • Metering point schedule listing each meter, its location, sensor ratios, and measured parameters
  • Communication architecture diagram showing protocol, network segmentation, and device addressing
  • Modbus register map or BACnet object list for each meter model
  • Wiring diagrams showing CT and VT connections, polarity, grounding, and fusing
Action submittals requiredcheckbox
☑ Meter / PMD / BCPM product data
☑ Current sensor product data
☐ Voltage transformer product data
☑ CT secondary burden calculation
☑ Metering point schedule
☑ Communication architecture diagram
☑ Modbus register map / BACnet object list
☑ Wiring diagrams (CT/VT, polarity, grounding, fusing)

4.2 Informational Submittals

4.2.1 The Contractor shall submit the following informational submittals:
  • Manufacturer's installation instructions for meters and sensors
  • Field calibration or commissioning report for each metering point
  • Time-synchronization configuration evidence (NTP source or BAS time-sync)
  • Utility coordination record confirming approved meter model and socket form, where applicable
  • Weights-and-measures certification record for legal-for-trade tenant meters, where applicable
Informational submittals requiredcheckbox
☑ Manufacturer installation instructions
☑ Field calibration / commissioning report
☑ Time-synchronization configuration evidence
☐ Utility coordination record
☐ Weights-and-measures certification record

4.3 Closeout Submittals

4.3.1 The Contractor shall submit the following closeout submittals before final acceptance:
  • Operation and maintenance manuals for each meter and EPMS component
  • As-built metering point schedule reflecting installed ratios and addresses
  • Final register map or object list as configured in the EPMS
  • Warranty documentation for meters, sensors, and EPMS licenses
Closeout submittals requiredcheckbox
☑ Operation and maintenance manuals
☑ As-built metering point schedule
☑ Final register map / object list
☑ Warranty documentation

5 Quality Assurance

5.1 Meters and monitoring devices shall be listed to UL 61010-1 by a nationally recognized testing laboratory.
5.2 Revenue-grade meters shall comply with ANSI C12.1 for the specified accuracy and current classes.
5.3 Panel-mounted power monitoring devices shall be classified to an IEC 61557-12 PMD class equal to or better than the class specified for the metering point.
5.4 Current transformers used with revenue meters shall comply with IEEE C57.13 metering accuracy class.
5.5 The accuracy class of each current sensor shall be equal to or better than the accuracy class of the meter it serves.
NOTE Pairing a higher-accuracy meter with a lower-accuracy current sensor caps the combined accuracy at the weaker element; a Class 0.5 meter on a Class 1.0 CT can drift to ±1.5 percent combined, defeating the meter selection. (5.5.1)
5.6 The installer shall be trained or certified by the meter manufacturer where the manufacturer requires certified installation to maintain accuracy warranty.

6 Metering Points and Hierarchy

6.1 Metering points shall be established at the service entrance, at feeders and switchboards serving distinct tenants or load groups, at panelboards by load category, and at branch circuits where end-use monitoring is required.
6.2 Each metering point shown on the drawings shall be metered to the tier and accuracy class assigned to it on the metering point schedule.
NOTE Code-required metering and owner-programmatic metering coexist in the same project; the hierarchy clarifies which points are mandatory under the energy code and which serve energy-management goals so that scope and accuracy are not over- or under-specified. (6.2.1)
6.3 Service-entrance metering shall be revenue-grade where it serves utility billing or whole-building accounting.
6.5 Panelboard metering shall capture energy by load category where required by the energy code for the building area served.
6.6 Branch-circuit monitoring shall be provided where individual circuit-level data is required for the building area served.
6.7 The metering tier at this point shall be as indicated in the datasheet.
Metering tier at this pointselect
Service entrance (revenue / whole-building)
Feeder / switchboard (tenant sub-metering)
Panelboard (load category)
Branch circuit (BCPM)
Per drawings — metering point schedule (deferred by default)

6.8 Building Metering Thresholds

6.8.1 Buildings exceeding 25,000 square feet shall be metered for whole-building energy consumption where required by the adopted energy standard.
6.8.2 Tenant spaces exceeding 10,000 square feet shall be individually sub-metered where required by the adopted energy standard.
6.8.3 Buildings exceeding 10,000 square feet shall provide energy monitoring by load category where required by the adopted energy code.
NOTE Square-footage thresholds vary between ASHRAE 90.1 and the IECC; the more stringent of the adopted code and the Owner's program governs. The thresholds above reflect common adopted editions and shall be confirmed against the locally adopted code. (6.8.4)
6.8.5 The code basis governing the metering thresholds shall be as indicated in the datasheet.
Code basis for metering thresholdsselect
ASHRAE 90.1
IECC Commercial Provisions
Both (more stringent governs)
Owner program only (no code mandate)

7 Accuracy Class

7.1 Each meter shall meet the accuracy class assigned to its metering tier on the metering point schedule.
7.2 Revenue-grade meters shall meet ANSI C12.1 accuracy class 0.2 or 0.5 as assigned.
7.3 Panel sub-metering devices shall meet IEC 61557-12 PMD class M2, M3, or M5 as assigned.
NOTE Panel PMDs are rated to IEC 61557-12 PMD classes, not to ANSI C12.1 accuracy classes; specifying "ANSI C12.20 class 0.2" for a panel PMD is a category error that generates requests for information and substitution requests because C12.20 applies to revenue-grade socket and switchboard meters. (7.3.1)
7.4 Branch-circuit power monitoring channels shall meet IEC 61557-12 PMD class M5 or M6 where used for energy management.
NOTE Class M5 to M6 is acceptable for branch-circuit energy management because branch loads are individually small and the aggregated reporting tolerates wider per-channel error than a billing meter. (7.4.1)
7.5 The meter accuracy class shall be as indicated in the datasheet.
Meter accuracy classselect
ANSI C12.1 Class 0.2 (revenue)
ANSI C12.1 Class 0.5 (revenue)
IEC 61557-12 PMD Class M2
IEC 61557-12 PMD Class M3
IEC 61557-12 PMD Class M5
IEC 61557-12 PMD Class M6
Per drawings — metering point schedule (deferred by default)

8 Current Sensing

8.1 The current-sensing method at each metering point shall be selected from solid-core current transformer, split-core current transformer, or Rogowski coil based on installation access, accuracy, and conductor size.
8.2 Solid-core current transformers shall be used where the highest accuracy is required and the primary conductor can be disconnected for installation.
NOTE A solid-core CT has a continuous magnetic core that fully encircles the conductor, giving the lowest error; installation requires disconnecting the conductor to thread it, so solid-core is favored on new work and revenue points. (8.2.1)
8.3 Split-core current transformers shall be used for retrofit where the primary conductor cannot be disconnected.
NOTE A split-core CT has a hinged core that opens to clamp around an energized conductor, trading a small accuracy penalty for retrofit access without a shutdown. (8.3.1)
8.4 Split-core current transformers shall have a positive locking or latching mechanism that holds the core closed.
NOTE A split-core CT that opens under vibration creates an open-circuit secondary, which on a 5 A secondary develops dangerous voltages and loses all measurement on that phase; positive latching and open-secondary protection prevent this. (8.4.1)
8.5 Rogowski coils shall be used where the conductor is too large or the panel too congested for a solid-core or split-core CT, or where high harmonic content requires a saturation-free sensor.
NOTE A Rogowski coil is an air-core sensor that cannot saturate and stays linear at high current and high harmonics; it outputs a low-level voltage signal proportional to the rate of change of current and requires a meter with a matching integrator input. (8.5.1)
8.6 Meters serving Rogowski coils shall have a Rogowski-compatible input or a universal current-sensor input.
NOTE A Rogowski coil outputs roughly 150 mV or 333 mV and cannot drive a standard 5 A or 1 A CT input; specifying a Rogowski coil with a 5 A-input meter results in no signal, so the meter input type shall be confirmed explicitly. (8.6.1)
8.7 The current-sensing method at this metering point shall be as indicated in the datasheet.
Current-sensing methodselect
Solid-core CT
Split-core CT (locking)
Rogowski coil
NOTE All three sensing methods are correct in their own conditions — solid-core on new work with a disconnectable conductor, split-core on energized retrofit, Rogowski on oversized or congested and harmonic-rich installations — so the field carries no default and the Engineer selects per point. (8.8)

8.9 Current Transformer Ratio and Secondary

8.9.1 The current transformer ratio at each metering point shall be selected so that the expected load current is at least 10 percent of the CT rated primary current.
8.9.2 A CT operating below about 10 percent of its rated primary current loses accuracy; a 600:5 CT on a circuit averaging 80 A runs near the lower accuracy limit, so a 200:5 CT is more appropriate for that load. The ratio shall match the actual load, not only the conductor ampacity.
8.9.3 The current transformer ratio shall be selected so that the CT does not saturate at the available fault current of the served equipment.
8.9.4 The CT secondary rating shall be 1 A for secondary lead runs exceeding 30 feet and may be 5 A for shorter runs.
NOTE Secondary lead resistance dissipates I²R burden; at 5 A the burden grows 25 times faster than at 1 A for the same lead, so long runs use a 1 A secondary to stay within the CT rated burden. (8.9.5)
8.9.6 The Contractor shall submit a CT secondary burden calculation demonstrating that the meter input plus lead-wire burden does not exceed the CT rated burden.
NOTE A CT delivers its rated accuracy only within its rated burden (for example B-0.5 to B-2.0); an undocumented long 5 A lead run routinely exceeds the rated burden and introduces systematic error, so the burden calculation is a required submittal. (8.9.7)
8.9.8 The current transformer secondary rating shall be as indicated in the datasheet.
CT secondary ratingselect
5 A secondary
1 A secondary
0.333 V output (Rogowski-compatible)
8.9.9 The current transformer primary current rating shall be as indicated in the datasheet.
CT primary current ratingrange
A
506000
Per drawings — metering point schedule (deferred by default)
8.9.10 The current transformer accuracy class shall be as indicated in the datasheet.
CT accuracy class (IEEE C57.13 metering)select
Class 0.15
Class 0.3
Class 0.6
NOTE The CT accuracy class follows the accuracy class of the meter it serves, which is assigned per metering point, so no class is correct across the schedule and the field carries no default. (8.9.11)

8.10 Voltage Transformers

8.10.1 Meters serving systems at 600 V and below shall connect directly to the phase conductors where the meter voltage input is rated for the system voltage.
8.10.2 Meters serving systems above 600 V shall be served through metering-class voltage transformers.
NOTE A meter cannot connect its voltage inputs directly to a medium-voltage bus; a voltage transformer steps the system voltage down to a safe metering level and isolates the meter from the primary, and omitting it from scope leads to change orders when the utility or inspector requires it. (8.10.3)
8.10.4 Voltage transformers serving metering shall meet IEEE C57.13 metering accuracy class 0.3 or 0.6.
8.10.5 Voltage transformer primary connections shall be fused.
8.10.6 Voltage transformer secondaries shall be grounded in accordance with NFPA 70 Article 250.
8.10.7 The voltage connection method shall be as indicated in the datasheet.
Voltage connection methodselect
Direct connect (≤ 600 V)
Through voltage transformers (> 600 V)
8.10.8 The voltage transformer accuracy class shall be as indicated in the datasheet.
Voltage transformer accuracy classselect
Not applicable — direct-connect metering
IEEE C57.13 Class 0.3
IEEE C57.13 Class 0.6

9 Measured Parameters

9.1 Each meter shall measure and report the parameters assigned to its metering point on the metering point schedule.
Measured parameters required at this pointcheckbox
☑ Real energy (kWh)
☑ Real demand (kW, 15-min)
☐ Reactive energy / demand (kVARh)
☐ Apparent power (kVA)
☐ Power factor (displacement and true)
☑ Voltage (L-L and L-N)
☑ Current per phase
☐ Frequency
☐ THD voltage and current
☐ Voltage unbalance
9.2 Real energy in kilowatt-hours shall be measured at every metering point.
9.3 Real demand in kilowatts on a 15-minute interval shall be measured where demand reporting or demand billing is required.
9.4 Reactive energy in kilovar-hours and reactive demand shall be measured where the load includes significant inductive or capacitive content.
9.5 Apparent power in kilovolt-amperes shall be measured where power factor reporting is required.
9.6 Displacement power factor and true power factor shall be reported per IEEE 1459 where power factor monitoring is required.
NOTE Displacement power factor reflects only the fundamental phase angle, while true power factor includes harmonic distortion; IEEE 1459 defines both so that meters report consistent values on nonlinear loads. Reporting only one can misstate the actual apparent power. (9.6.1)
9.7 Line-to-line and line-to-neutral voltage shall be measured at every metering point that monitors power quality.
9.8 Per-phase current and frequency shall be measured at every metering point that monitors power quality.
9.9 Total harmonic distortion of voltage and of current shall be measured where power-quality monitoring is required.
9.10 Voltage unbalance shall be measured where three-phase load balance monitoring is required.
NOTE Not every parameter is available on every tier; branch-circuit and basic sub-metering devices may report energy and demand only, while feeder and service meters report the full power-quality set. The schedule assigns parameters per point so that meter selection matches the data actually needed. (9.10.1)

10 Data Logging and Time Synchronization

10.1 Meters required to log data shall record measured parameters at the interval indicated in the datasheet.
NOTE ASHRAE 90.1 and the IECC both require 15-minute interval data for compliant energy metering; a coarser interval cannot satisfy the code, and a finer interval consumes log memory without code benefit. (10.1.1)
10.2 On-board data log depth, where the meter buffers data locally, shall be as indicated in the datasheet.
NOTE Local buffering bridges network or EPMS outages so that no interval data is lost; 35 days of depth covers a monthly polling cycle plus margin. Deeper logs are specified where the EPMS polls less frequently. (10.2.1)
10.3 Meters shall be time-synchronized to a common time source by NTP or by the building automation system time-sync protocol.
NOTE Meters that free-run their clocks drift apart over weeks, so their 15-minute intervals no longer align; misaligned intervals cannot be summed or correlated across meters for code reporting. A common time source keeps every meter on the same interval boundary. (10.3.1)
10.4 The Contractor shall configure the time source and submit evidence of synchronization.
10.5 Metered data shall be retained for the period indicated in the datasheet.
10.6 The logging interval shall be as indicated in the datasheet.
Logging intervalrange
min
1515
NOTE An interval coarser than 15 minutes will not satisfy the adopted energy standard where code-required metering applies. (10.7)
10.8 The on-board log depth shall be as indicated in the datasheet.
On-board log depth at 15-min intervalrange
days
3590
Default: 35 days
10.9 The time-synchronization source shall be as indicated in the datasheet.
Time-synchronization sourceselect
NTP server
BAS time-sync (BACnet)
BAS time-sync (Modbus)
10.10 The data retention period shall be as indicated in the datasheet.
Data retention periodrange
months
1260
Default: 36 months
NOTE Where the adopted energy standard mandates a retention period longer than the value indicated, the code period governs. (10.11)

11 Communication and Integration

11.1 Each meter shall communicate to the energy monitoring software or building automation system over the protocol assigned on the metering point schedule.
11.2 The communication protocol shall be selected from Modbus RTU, Modbus TCP/IP, BACnet MS/TP, or BACnet/IP based on compatibility with the EPMS or BAS.
11.2.1 Modbus RTU on RS-485 supports up to 32 devices per segment and is economical for clustered panel meters; Modbus TCP and BACnet/IP scale across the building network. The protocol shall match what the receiving platform can ingest natively, because protocol gateways add cost and a failure point.
11.3 Modbus RTU segments shall not exceed 32 devices per segment and shall use a single baud rate per segment.
11.4 The meter manufacturer's Modbus register map or BACnet object list shall be provided as a submittal.
NOTE Integration fails most often not at the meter but at the register map; without the manufacturer's map the controls contractor cannot map points, leaving meters installed but unread at substantial completion. The map is therefore a required submittal, not an optional reference. (11.4.1)
11.5 The Contract Documents shall assign integration programming scope explicitly to either the electrical contractor or the controls contractor.
NOTE Register-map configuration and point mapping are routinely excluded from both the electrical and controls scopes, producing unconnected meters at closeout; this standard requires the scope to be assigned in writing so the gap cannot occur. (11.5.1)
11.6 Except where the datasheet indicates a shared building network, meters using Modbus TCP or BACnet/IP shall reside on an isolated operational-technology network segment separated from the building information-technology network.
NOTE Panel meters placed on the general IT LAN expose operational equipment to network threats and can themselves be an attack surface; an isolated OT VLAN with read-only acquisition from the BAS side limits exposure. (11.6.1)
11.7 Data acquisition from the building automation system to the meters shall be read-only where the OT segment is isolated for cybersecurity.
11.8 The communication protocol shall be as indicated in the datasheet.
Communication protocolselect
Modbus RTU (RS-485)
Modbus TCP/IP
BACnet MS/TP
BACnet/IP
NOTE The protocol is set by what the receiving EPMS or building automation system ingests natively, so no protocol is correct across projects and the field carries no default. (11.9)
11.10 The integration programming scope shall be assigned as indicated in the datasheet.
Integration programming scope assigned toselect
Electrical contractor
Controls contractor
EPMS / metering manufacturer
11.11 The network segmentation shall be as indicated in the datasheet.
Network segmentationradio
● Isolated OT VLAN with read-only acquisition from the BAS
○ Shared building network
NOTE The isolated segment is the default because a panel meter on the general IT LAN is both exposed and an attack surface; the shared-network value exists for small buildings with no separate OT network, and selecting it is an Owner risk acceptance. (11.12)

12 Local Display

12.1 Each meter shall provide the local display indicated in the datasheet.
Local displayselect
Integral LCD display
Integral LED display
Remote display panel
None — data via network
12.2 Where a local display is required, it shall show at minimum real energy, real power, voltage, current, and power factor.
NOTE A local display lets a technician verify a meter is live and reading correctly without a laptop or network access, which speeds commissioning and troubleshooting; meters intended for data-only service may omit the display to reduce cost. (12.2.1)

13 Form Factor and Installation Location

13.1 The meter form factor shall be selected from socket-type, switchboard-mounted, DIN-rail panel-mount, or bus-bar branch-circuit module based on the equipment served and the installation location.
13.2 Socket-type revenue meters shall match the ANSI meter socket form required by the serving utility.
NOTE Utilities prescribe the meter socket form (such as Form 2S, 9S, 12S, or 45S) and may reject a contractor-furnished meter that does not match; the socket form is confirmed with the utility before purchase. (13.2.1)
13.3 The Owner shall coordinate the socket form and the approved meter model list with the serving utility before any revenue meter is purchased.
13.4 Switchboard-mounted and panelboard-mounted meters shall be coordinated with the switchboard or panelboard manufacturer for factory-installed or field-installed mounting.
NOTE A meter mounted in the door or compartment of a switchboard affects the equipment listing and arrangement, so its mounting is coordinated with the gear manufacturer rather than improvised in the field. See Low Voltage SwitchboardsLow Voltage SwitchboardsResolves to the current adopted revision.sync/low-voltage-switchboards and PanelboardsPanelboardsResolves to the current adopted revision.sync/panelboards. (13.4.1)
13.5 Branch-circuit power monitoring modules that clip onto the panelboard bus shall be factory-installed by the panelboard manufacturer where the design requires bus-bar mounting.
13.5.1 Field-installing a bus-bar-mounted branch-circuit monitoring module that is rated for factory installation only voids the panelboard listing; the installation method shall be stated in the Contract Documents and on the drawings so the panelboard is ordered correctly.
13.6 The meter form factor shall be as indicated in the datasheet.
Meter form factorselect
Socket-type (ANSI meter socket)
Switchboard-mounted panel meter
DIN-rail panel-mount meter
Bus-bar branch-circuit module
Per drawings — metering point schedule (deferred by default)
13.7 The branch-circuit module installation method shall be as indicated in the datasheet.
Branch-circuit module installation methodradio
● Factory-installed by panelboard manufacturer
○ Field-installed in dedicated enclosure

14 Revenue Designation and Tenant Sub-Metering

14.1 Each metering point shall be designated revenue-grade or energy-management-grade on the metering point schedule.
14.2 Revenue-grade meters shall provide tamper-evident sealing provisions where the utility or weights-and-measures authority requires sealing.
NOTE Revenue meters are sealed so that the calibration and configuration cannot be altered after certification; energy-management meters do not require sealing because their data is not used for billing. (14.2.1)
14.4 The Owner shall confirm with the serving utility whether the utility requires its own meter or will accept a sub-metering meter model at each revenue point.
14.5 The designation of this metering point shall be as indicated in the datasheet.
Metering point designationradio
○ Revenue-grade (billing, sealed)
○ Energy-management grade (PMD)
Per drawings — metering point schedule (deferred by default)
Legal-for-trade certification (tenant re-billing)radio
○ Required (NIST HB 44 certified)
● Not required — energy management use

15 Energy Monitoring Software

15.1 The energy monitoring software platform shall be identified in the Contract Documents and its data ingestion requirements coordinated with the meter selection.
NOTE Whether the EPMS is provided by the meter manufacturer, by a third party, or integrated into the building automation system determines the protocol and register map the meters must support; selecting meters before the platform risks an incompatible pairing. See Building Automation SystemBuilding Automation SystemResolves to the current adopted revision.sync/building-automation-system. (15.1.1)
15.2 The energy monitoring software shall produce energy and demand reports at hourly, daily, monthly, and annual granularity where required by the adopted energy code.
15.3 The energy monitoring software shall produce the compliance reports required by the adopted energy standard.
15.4 The energy monitoring software platform source shall be as indicated in the datasheet.
EPMS platform sourceselect
Meter manufacturer platform
Third-party EPMS platform
Integrated into building automation system
NOTE The platform is an Owner program decision that drives protocol and register-map compatibility, so it carries no default and shall be identified before meters are ordered. (15.5)
15.6 The reporting granularity produced by the energy monitoring software shall be as indicated in the datasheet.
EPMS reporting granularitycheckbox
☑ Hourly
☑ Daily
☑ Monthly
☑ Annual

16 Installation

16.1 Meters and sensors shall be installed in accordance with the manufacturer's instructions and NFPA 70.
16.2 Current transformers shall be installed with the correct polarity orientation relative to the metered conductor and the source.
16.2.1 A CT installed backwards reverses the measured power direction, reporting export when the load imports; polarity marks on the CT and the meter terminals shall be matched so the sign of real power is correct.
16.3 Current transformer secondary circuits shall be grounded at one point only in accordance with NFPA 70 Article 250.
16.4 Current transformer secondary leads shall not be opened while the primary conductor is energized unless the secondary is first short-circuited.
NOTE An open CT secondary under load develops high voltage across the open terminals, a shock and arc hazard; shorting blocks or shorting the secondary before opening it eliminates the hazard during service. (16.4.1)
16.5 Voltage transformer primary fuses shall be installed and verified before the meter is energized.
16.6 Meter wiring shall be identified at each termination in accordance with Equipment LabelingElectrical Equipment LabelsResolves to the current adopted revision.sync/equipment-labeling.
16.7 Communication wiring shall be installed separately from power conductors to limit electrical noise on the data circuit.
16.8 Meters serving motor control equipment shall be coordinated with the equipment served per Motor Control CentersMotor Control CentersResolves to the current adopted revision.sync/motor-control-centers.

17 Testing and Commissioning

17.1 Each metering point shall be commissioned to verify correct sensor ratio, polarity, and parameter reporting before acceptance.
17.2 The Contractor shall verify that the configured CT and VT ratios in each meter match the installed sensor ratios.
NOTE A meter reads correctly only if its configured ratio matches the installed CT; a mismatch scales every reading by a constant error that is invisible without a side-by-side current measurement at commissioning. (17.2.1)
17.3 The Contractor shall verify per-phase current and voltage magnitudes against a calibrated reference instrument at each metering point.
17.4 The Contractor shall verify that the measured real-power direction is correct for the known load.
17.5 The Contractor shall verify that each meter communicates to the EPMS or BAS and that the expected points appear in the platform.
17.6 The Contractor shall verify that all meters share a common time and that interval boundaries align.
17.7 The Contractor shall submit a commissioning report documenting the verifications for each metering point.
17.8 The commissioning verifications performed at each metering point shall be as indicated in the datasheet.
Commissioning verifications requiredcheckbox
☑ Configured ratio matches installed sensor
☑ Current and voltage against calibrated reference
☑ Real-power direction correct
☑ Communication to EPMS / BAS confirmed
☑ Time synchronization and interval alignment

18 Delivery, Storage, and Handling

18.1 Meters and sensors shall be delivered in the manufacturer's original packaging with calibration seals intact.
18.2 Meters and sensors shall be stored indoors in a dry, temperature-controlled space until installation.
18.3 Current transformers shall be protected from impact and from forces that could distort the core and alter accuracy.

19 Warranty

19.1 The meter manufacturer shall warrant each meter against defects in materials and workmanship, measured from substantial completion, for the period indicated in the datasheet.
Meter warranty periodrange
years
110
Default: 3 years
19.2 The meter manufacturer shall warrant the metering accuracy for the warranty period where accuracy warranty is offered.
19.3 Energy monitoring software licenses shall be warranted and supported for the warranty period.

20 Spare Parts

20.1 The Contractor shall furnish spare current transformers of each ratio used, in the quantity indicated in the datasheet.
Spare current transformers per ratiorange
each
06
Default: 2 each
20.2 The Contractor shall furnish spare fuses for each voltage transformer type used, in the quantity indicated in the datasheet.
Spare VT fuse setsrange
sets
06
Default: 2 sets

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