+---
+title: Electrical Power Monitoring and Metering
+category: Electrical
+toc_depth: 3
+description: >
+ When to use: Permanently installed electric power metering and monitoring for new and retrofit
+ commercial, institutional, and multi-tenant buildings, including service-entrance revenue metering,
+ tenant sub-metering, panelboard and feeder load-category metering, branch-circuit power monitoring,
+ and the current and voltage sensors that serve them. Covers accuracy classes, current-sensing
+ methods, measured parameters, data logging, communication protocols, and integration scope.
+ Not intended for: Utility-owned primary metering installed and maintained by the serving utility;
+ portable or temporary power-quality recorders; protective relaying with incidental metering
+ (specify under switchgear protection); thermal-energy or water metering; control wiring and
+ enclosures covered by [[syncs/building-automation-system]].
+---
+
+# Scope {toc}
+
+## 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. {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. {note}
+
+## 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.
+
+## The Contractor shall coordinate metering scope, communication protocol, and integration responsibility with the controls contractor and the energy monitoring software provider before rough-in.
+
+## 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. {note}
+
+# Referenced Standards {toc}
+
+## 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. {note}
+
+| 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 |
+| IEC 61869 series | Instrument Transformers (metering classes 0.2S and 0.5S) |
+| 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 |
+
+# Definitions {toc}
+
+## The following terms are used throughout this standard: {note}
+
+- **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.
+
+# Submittals {toc}
+
+## Action Submittals {toc}
+
+### 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
+
+```datasheet
+label: Action submittals required
+type: checkbox
+options:
+ - 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)
+default:
+ - Meter / PMD / BCPM product data
+ - Current sensor 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)
+```
+
+## Informational Submittals {toc}
+
+### 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
+
+```datasheet
+label: Informational submittals required
+type: checkbox
+options:
+ - Manufacturer installation instructions
+ - Field calibration / commissioning report
+ - Time-synchronization configuration evidence
+ - Utility coordination record
+ - Weights-and-measures certification record
+default:
+ - Manufacturer installation instructions
+ - Field calibration / commissioning report
+ - Time-synchronization configuration evidence
+```
+
+## Closeout Submittals {toc}
+
+### 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
+
+```datasheet
+label: Closeout submittals required
+type: checkbox
+options:
+ - Operation and maintenance manuals
+ - As-built metering point schedule
+ - Final register map / object list
+ - Warranty documentation
+default:
+ - Operation and maintenance manuals
+ - As-built metering point schedule
+ - Final register map / object list
+ - Warranty documentation
+```
+
+# Quality Assurance {toc}
+
+## Meters and monitoring devices shall be listed to UL 61010-1 by a nationally recognized testing laboratory.
+
+## Revenue-grade meters shall comply with ANSI C12.1 for the specified accuracy and current classes.
+
+## 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.
+
+## Current transformers used with revenue meters shall comply with IEEE C57.13 metering accuracy class.
+
+## The accuracy class of each current sensor shall be equal to or better than the accuracy class of the meter it serves.
+
+### 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. {note}
+
+## The installer shall be trained or certified by the meter manufacturer where the manufacturer requires certified installation to maintain accuracy warranty.
+
+## Where a metering point is designated for tenant re-billing, the Owner shall confirm with the state weights-and-measures authority whether NIST Handbook 44 legal-for-trade certification is required before the meter model is approved.
+
+### Many jurisdictions require legal-for-trade certification and public utilities commission approval for billing sub-meters; specifying a non-certified meter for re-billing can create legal exposure for the Owner. This is a coordination item outside the National Electrical Code scope. {note}
+
+# Metering Points and Hierarchy {toc}
+
+## 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.
+
+## Each metering point shown on the drawings shall be metered to the tier and accuracy class assigned to it on the metering point schedule.
+
+### 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. {note}
+
+## Service-entrance metering shall be revenue-grade where it serves utility billing or whole-building accounting.
+
+## Feeder and switchboard metering serving individual tenants shall be sub-metering grade unless designated for legal-for-trade re-billing, in which case it shall be revenue-grade and certified.
+
+## Panelboard metering shall capture energy by load category where required by the energy code for the building area served.
+
+## Branch-circuit monitoring shall be provided where individual circuit-level data is required for the building area served.
+
+```datasheet
+label: Metering tier at this point
+type: select
+options:
+ - Service entrance (revenue / whole-building)
+ - Feeder / switchboard (tenant sub-metering)
+ - Panelboard (load category)
+ - Branch circuit (BCPM)
+default: Feeder / switchboard (tenant sub-metering)
+drawing_ref: true
+```
+
+## Building Metering Thresholds {toc}
+
+### Buildings exceeding 25,000 square feet shall be metered for whole-building energy consumption where required by the adopted energy standard.
+
+### Tenant spaces exceeding 10,000 square feet shall be individually sub-metered where required by the adopted energy standard.
+
+### Buildings exceeding 10,000 square feet shall provide energy monitoring by load category where required by the adopted energy code.
+
+### 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. {note}
+
+```datasheet
+label: Code basis for metering thresholds
+type: select
+options:
+ - ASHRAE 90.1
+ - IECC Commercial Provisions
+ - Both (more stringent governs)
+ - Owner program only (no code mandate)
+default: Both (more stringent governs)
+```
+
+# Accuracy Class {toc}
+
+## Each meter shall meet the accuracy class assigned to its metering tier on the metering point schedule.
+
+## Revenue-grade meters shall meet ANSI C12.1 accuracy class 0.2 or 0.5 as assigned.
+
+### Class 0.2 limits error to ±0.2 percent of reading and is used for utility and legal-for-trade billing; Class 0.5 limits error to ±0.5 percent and is acceptable for whole-building accounting where the utility permits. {note}
+
+## Panel sub-metering devices shall meet IEC 61557-12 PMD class M2, M3, or M5 as assigned.
+
+### 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. {note}
+
+## Branch-circuit power monitoring channels shall meet IEC 61557-12 PMD class M5 or M6 where used for energy management.
+
+### 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. {note}
+
+```datasheet
+label: Meter accuracy class
+type: select
+options:
+ - 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
+default: IEC 61557-12 PMD Class M3
+```
+
+# Current Sensing {toc}
+
+## 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.
+
+## Solid-core current transformers shall be used where the highest accuracy is required and the primary conductor can be disconnected for installation.
+
+### 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. {note}
+
+## Split-core current transformers shall be used for retrofit where the primary conductor cannot be disconnected.
+
+### 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. {note}
+
+## Split-core current transformers shall have a positive locking or latching mechanism that holds the core closed.
+
+### 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. {note}
+
+## 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.
+
+### 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. {note}
+
+## Meters serving Rogowski coils shall have a Rogowski-compatible input or a universal current-sensor input.
+
+### 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. {note}
+
+```datasheet
+label: Current-sensing method
+type: select
+options:
+ - Solid-core CT
+ - Split-core CT (locking)
+ - Rogowski coil
+default: Solid-core CT
+drawing_ref: true
+```
+
+## Current Transformer Ratio and Secondary {toc}
+
+### 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.
+
+### 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. {note}
+
+### The current transformer ratio shall be selected so that the CT does not saturate at the available fault current of the served equipment.
+
+### The CT secondary rating shall be 1 A for secondary lead runs exceeding 30 feet and may be 5 A for shorter runs.
+
+### 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. {note}
+
+### 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.
+
+### 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. {note}
+
+```datasheet
+label: CT secondary rating
+type: select
+options:
+ - 5 A secondary
+ - 1 A secondary
+ - 0.333 V output (Rogowski-compatible)
+default: 5 A secondary
+```
+
+```datasheet
+label: CT primary current rating
+type: range
+unit: A
+min: 100
+max: 4000
+step: 50
+default: 400
+drawing_ref: true
+```
+
+```datasheet
+label: CT accuracy class (IEEE C57.13 metering)
+type: select
+options:
+ - Class 0.15
+ - Class 0.3
+ - Class 0.6
+default: Class 0.3
+```
+
+## Voltage Transformers {toc}
+
+### 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.
+
+### Meters serving systems above 600 V shall be served through metering-class voltage transformers.
+
+### 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. {note}
+
+### Voltage transformers serving metering shall meet IEEE C57.13 metering accuracy class 0.3 or 0.6.
+
+### Voltage transformer primary connections shall be fused.
+
+### Voltage transformer secondaries shall be grounded in accordance with NFPA 70 Article 250.
+
+```datasheet
+label: Voltage connection method
+type: select
+options:
+ - Direct connect (≤ 600 V)
+ - Through voltage transformers (> 600 V)
+default: Direct connect (≤ 600 V)
+drawing_ref: true
+```
+
+```datasheet
+label: Voltage transformer accuracy class
+type: select
+options:
+ - IEEE C57.13 Class 0.3
+ - IEEE C57.13 Class 0.6
+default: IEEE C57.13 Class 0.3
+```
+
+# Measured Parameters {toc}
+
+## Each meter shall measure and report the parameters assigned to its metering point on the metering point schedule.
+
+## Real energy in kilowatt-hours shall be measured at every metering point.
+
+## Real demand in kilowatts on a 15-minute interval shall be measured where demand reporting or demand billing is required.
+
+## Reactive energy in kilovar-hours and reactive demand shall be measured where the load includes significant inductive or capacitive content.
+
+## Apparent power in kilovolt-amperes shall be measured where power factor reporting is required.
+
+## Displacement power factor and true power factor shall be reported per IEEE 1459 where power factor monitoring is required.
+
+### 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. {note}
+
+## Line-to-line and line-to-neutral voltage shall be measured at every metering point that monitors power quality.
+
+## Per-phase current and frequency shall be measured at every metering point that monitors power quality.
+
+## Total harmonic distortion of voltage and of current shall be measured where power-quality monitoring is required.
+
+## Voltage unbalance shall be measured where three-phase load balance monitoring is required.
+
+### 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. {note}
+
+```datasheet
+label: Measured parameters required at this point
+type: checkbox
+options:
+ - 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
+default:
+ - Real energy (kWh)
+ - Real demand (kW, 15-min)
+ - Voltage (L-L and L-N)
+ - Current per phase
+```
+
+# Data Logging and Time Synchronization {toc}
+
+## Meters required to log data shall record measured parameters at a 15-minute interval.
+
+### 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. {note}
+
+## On-board data log depth shall be sufficient to retain at least 35 days of 15-minute interval data where the meter buffers data locally.
+
+### 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. {note}
+
+## Meters shall be time-synchronized to a common time source by NTP or by the building automation system time-sync protocol.
+
+### 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. {note}
+
+## The Contractor shall configure the time source and submit evidence of synchronization.
+
+## Metered data shall be retained for at least 36 months where required by the adopted energy standard.
+
+```datasheet
+label: Logging interval
+type: select
+options:
+ - 15 minutes
+ - 5 minutes
+ - 1 minute
+default: 15 minutes
+```
+
+```datasheet
+label: On-board log depth at 15-min interval
+type: range
+unit: days
+min: 35
+max: 90
+step: 5
+default: 35
+```
+
+```datasheet
+label: Time-synchronization source
+type: select
+options:
+ - NTP server
+ - BAS time-sync (BACnet)
+ - BAS time-sync (Modbus)
+default: NTP server
+```
+
+```datasheet
+label: Data retention period
+type: range
+unit: months
+min: 12
+max: 60
+step: 12
+default: 36
+```
+
+# Communication and Integration {toc}
+
+## Each meter shall communicate to the energy monitoring software or building automation system over the protocol assigned on the metering point schedule.
+
+## 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.
+
+### 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. {note}
+
+## Modbus RTU segments shall not exceed 32 devices per segment and shall use a single baud rate per segment.
+
+## The meter manufacturer's Modbus register map or BACnet object list shall be provided as a submittal.
+
+### 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. {note}
+
+## The Contract Documents shall assign integration programming scope explicitly to either the electrical contractor or the controls contractor.
+
+### 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. {note}
+
+## Meters using Modbus TCP or BACnet/IP shall reside on an isolated operational-technology network segment separated from the building information-technology network.
+
+### 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. {note}
+
+## Data acquisition from the building automation system to the meters shall be read-only where the OT segment is isolated for cybersecurity.
+
+```datasheet
+label: Communication protocol
+type: select
+options:
+ - Modbus RTU (RS-485)
+ - Modbus TCP/IP
+ - BACnet MS/TP
+ - BACnet/IP
+default: Modbus TCP/IP
+```
+
+```datasheet
+label: Integration programming scope assigned to
+type: select
+options:
+ - Electrical contractor
+ - Controls contractor
+ - EPMS / metering manufacturer
+default: Controls contractor
+```
+
+```datasheet
+label: Network segmentation
+type: radio
+options:
+ - Isolated OT VLAN (read-only from BAS)
+ - Shared building network
+default: Isolated OT VLAN (read-only from BAS)
+```
+
+# Local Display {toc}
+
+## Each meter shall provide the local display assigned to its metering point.
+
+## Where a local display is required, it shall show at minimum real energy, real power, voltage, current, and power factor.
+
+### 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. {note}
+
+```datasheet
+label: Local display
+type: select
+options:
+ - Integral LCD display
+ - Integral LED display
+ - Remote display panel
+ - None (data via network only)
+default: Integral LCD display
+```
+
+# Form Factor and Installation Location {toc}
+
+## 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.
+
+## Socket-type revenue meters shall match the ANSI meter socket form required by the serving utility.
+
+### 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. {note}
+
+## The Owner shall coordinate the socket form and the approved meter model list with the serving utility before any revenue meter is purchased.
+
+## Switchboard-mounted and panelboard-mounted meters shall be coordinated with the switchboard or panelboard manufacturer for factory-installed or field-installed mounting.
+
+### 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 [[syncs/low-voltage-switchboards]] and [[syncs/low-voltage-panelboards]]. {note}
+
+## 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.
+
+### 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. {note}
+
+```datasheet
+label: Meter form factor
+type: select
+options:
+ - Socket-type (ANSI meter socket)
+ - Switchboard-mounted panel meter
+ - DIN-rail panel-mount meter
+ - Bus-bar branch-circuit module
+default: DIN-rail panel-mount meter
+drawing_ref: true
+```
+
+```datasheet
+label: Branch-circuit module installation method
+type: radio
+options:
+ - Factory-installed by panelboard manufacturer
+ - Field-installed in dedicated enclosure
+default: Factory-installed by panelboard manufacturer
+```
+
+# Revenue Designation and Tenant Sub-Metering {toc}
+
+## Each metering point shall be designated revenue-grade or energy-management-grade on the metering point schedule.
+
+## Revenue-grade meters shall provide tamper-evident sealing provisions where the utility or weights-and-measures authority requires sealing.
+
+### 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. {note}
+
+## Meters used to re-bill tenants shall be legal-for-trade certified to NIST Handbook 44 where the state weights-and-measures authority requires certification for sub-metered billing.
+
+## 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.
+
+```datasheet
+label: Metering point designation
+type: radio
+options:
+ - Revenue-grade (billing, sealed)
+ - Energy-management grade (PMD)
+default: Energy-management grade (PMD)
+```
+
+```datasheet
+label: Legal-for-trade certification (tenant re-billing)
+type: radio
+options:
+ - Required (NIST HB 44 certified)
+ - Not required (energy management only)
+default: Not required (energy management only)
+```
+
+# Energy Monitoring Software {toc}
+
+## The energy monitoring software platform shall be identified in the Contract Documents and its data ingestion requirements coordinated with the meter selection.
+
+### 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 [[syncs/building-automation-system]]. {note}
+
+## The energy monitoring software shall produce energy and demand reports at hourly, daily, monthly, and annual granularity where required by the adopted energy code.
+
+## The energy monitoring software shall produce the compliance reports required by the adopted energy standard.
+
+```datasheet
+label: EPMS platform source
+type: select
+options:
+ - Meter manufacturer platform
+ - Third-party EPMS platform
+ - Integrated into building automation system
+default: Integrated into building automation system
+```
+
+```datasheet
+label: EPMS reporting granularity
+type: checkbox
+options:
+ - Hourly
+ - Daily
+ - Monthly
+ - Annual
+default:
+ - Daily
+ - Monthly
+ - Annual
+```
+
+# Installation {toc}
+
+## Meters and sensors shall be installed in accordance with the manufacturer's instructions and NFPA 70.
+
+## Current transformers shall be installed with the correct polarity orientation relative to the metered conductor and the source.
+
+### 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. {note}
+
+## Current transformer secondary circuits shall be grounded at one point only in accordance with NFPA 70 Article 250.
+
+## Current transformer secondary leads shall not be opened while the primary conductor is energized unless the secondary is first short-circuited.
+
+### 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. {note}
+
+## Voltage transformer primary fuses shall be installed and verified before the meter is energized.
+
+## Meter wiring shall be identified at each termination in accordance with [[syncs/equipment-labeling]].
+
+## Communication wiring shall be installed separately from power conductors to limit electrical noise on the data circuit.
+
+## Meters serving motor control equipment shall be coordinated with the equipment served per [[syncs/motor-control-centers]].
+
+# Testing and Commissioning {toc}
+
+## Each metering point shall be commissioned to verify correct sensor ratio, polarity, and parameter reporting before acceptance.
+
+## The Contractor shall verify that the configured CT and VT ratios in each meter match the installed sensor ratios.
+
+### 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. {note}
+
+## The Contractor shall verify per-phase current and voltage magnitudes against a calibrated reference instrument at each metering point.
+
+## The Contractor shall verify that the measured real-power direction is correct for the known load.
+
+## The Contractor shall verify that each meter communicates to the EPMS or BAS and that the expected points appear in the platform.
+
+## The Contractor shall verify that all meters share a common time and that interval boundaries align.
+
+## The Contractor shall submit a commissioning report documenting the verifications for each metering point.
+
+```datasheet
+label: Commissioning verifications required
+type: checkbox
+options:
+ - 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
+default:
+ - 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
+```
+
+# Delivery, Storage, and Handling {toc}
+
+## Meters and sensors shall be delivered in the manufacturer's original packaging with calibration seals intact.
+
+## Meters and sensors shall be stored indoors in a dry, temperature-controlled space until installation.
+
+## Current transformers shall be protected from impact and from forces that could distort the core and alter accuracy.
+
+# Warranty {toc}
+
+## The meter manufacturer shall warrant each meter against defects in materials and workmanship for a minimum of 3 years from substantial completion.
+
+## The meter manufacturer shall warrant the metering accuracy for the warranty period where accuracy warranty is offered.
+
+## Energy monitoring software licenses shall be warranted and supported for the warranty period.
+
+```datasheet
+label: Meter warranty period
+type: range
+unit: years
+min: 1
+max: 10
+step: 1
+default: 3
+```
+
+# Spare Parts {toc}
+
+## The Contractor shall furnish spare current transformers of each ratio used, in a quantity sufficient to replace failed units without procurement delay.
+
+## The Contractor shall furnish spare fuses for each voltage transformer type used.
+
+```datasheet
+label: Spare current transformers per ratio
+type: range
+unit: each
+min: 0
+max: 6
+step: 1
+default: 2
+```
+
+```datasheet
+label: Spare VT fuse sets
+type: range
+unit: sets
+min: 0
+max: 6
+step: 1
+default: 2
+```