References · Interconnection is the process of connecting power generation sources to the electric...

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Nearly all electric utilities allow the interconnection of customer-owned and operated PV systems to their distribution systems. The technical and safety requirements for interconnected power sources are addressed in national codes and standards, while the specific procedures and policies vary among local utilities.

References:Photovoltaic Systems, Chap. 12Connecting to the Grid – A Guide to PV Interconnection Issues, Interstate Renewable Energy Council: www.irecusa.orgDatabase of State Incentives for Renewable Energy: www.dsireusa.org

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Reference: Photovoltaic Systems, p. 327

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Interconnection is the process of connecting power generation sources to the electric utility network.


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Technical interconnection issues include safety, power quality, and impacts on the utility system, and are addressed in national codes and standards. Interconnection procedures are based on state and utility policies, and include the application process and schedule, customer agreements, and permitting and inspection. Contractual aspects of interconnection policies include fees, metering requirements, billing arrangements, and size restrictions on the distributed generator.

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Electric utilities have concerns about PV systems and other forms of distributed generation operating on their systems that they do not own, operate, maintain or control. The foremost concern is the safety of utility personnel and the public, and the associated liabilities. Additionally, utilities are concerned about the protection, reliability and impacts on the sizing and operation of utility distribution equipment and services to other customers. These concerns are addressed by standards for equipment and installations, including product certification and listing, and electrical codes that help ensure the safe and reliable interconnection of PV systems to the utility grid.

Reference: Photovoltaic Systems, p. 342-347

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The Public Utilities Regulatory Policy Act (PURPA) of 1978 was the first federal legislation affecting the interconnection of distributed generation resources. This law was intended to decrease U.S. dependence on foreign oil by encouraging the use of renewable energy and cogeneration resources. PURPA established the first opportunities for non-utility power producers by eliminating barriers that previously hindered their entry into a market controlled by public utilities. PURPA requires electric utilities to establish reasonable rates and to purchase energy from independent power producers, and to establish the technical and procedural requirements for their interconnection to the utility system, subject to regulatory approval.

A qualifying facility (QF) is non-utility power generator, meeting the technical and procedural requirements for interconnection to the utility system. PURPA mandates that utilities purchase power from QFs at the utility's avoided cost. Avoided costs are the costs that a utility incurs to generate or purchase power, synonymous with the wholesale value of electricity. PURPA requires regulated utilities to file their QF tariffs with the Federal Energy Regulatory Commission (FERC) for approval.


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The technical requirements for PV system interconnections are established through national codes and standards developed by the Institute of Electrical and Electronics Engineers (IEEE), Underwriters Laboratory (UL) and the National Fire Protection Association (NFPA). These organizations work collectively to ensure electrical equipment and installations are inherently safe through the combination of standards, equipment testing and certification, and enforceable codes.


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IEEE 1547 Standard for Interconnection of Distributed Resources with Electrical Power Systems establishes the technical requirements for interconnecting all types of distributed generation equipment, including photovoltaics, fuel cells, wind generators, reciprocating engines, microturbines, and larger combustion turbines with the electrical power system. It also establishes requirements for testing, performance, maintenance and safety of the interconnection, as well as response to abnormal events, anti-islanding protection and power quality.

The focus of IEEE 1547 is on distributed resources with capacity less than 10 MVA, and interconnected to the electrical utility system at primary or secondary distribution voltages. The standard provides universal requirements to help ensure a safe and technically sound interconnection. It does not address limitations or impacts on the utility system in terms of energy supply, nor does it deal with procedural or contractual issues associated with the interconnection.

References:Photovoltaic Systems, p. 332-334http://grouper.ieee.org/groups/scc21/

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IEEE-1547.1 Standard for Conformance Test Procedure for Interconnecting Distributed Resources with Electrical Power Systems

IEEE 1547.2 Application Guide for IEEE Standard 1547 for Interconnection of Distributed Resources with Electrical Power Systems

IEEE 1547.3 Guide for Monitoring, Information Exchange and Control of Distributed Resources Interconnected with Electrical Power Systems

IEEE P1547.4 Draft Guide for Design, Operation and Integration of Distributed Resource Island Systems with Electrical Power Systems

IEEE P1547.5 Draft Technical Guidelines for Interconnection of Electric Power Sources Greater than 10MVA to the Power Transmission Grid

IEEE P1547.6 Draft Recommended Practice for Interconnecting Distributed Resources with Electric Power Systems Distribution Secondary Networks

IEEE P1547.7 Draft Guide to Conducting Distribution Impact Studies for Distributed Resource Interconnection

IEEE P1547.8 Draft Recommended Practice for Establishing Methods and Procedures that Provide Supplemental Support for Implementation Strategies for Expanded Use of IEEE Standard 1547

References:Photovoltaic Systems, p. 332-334http://grouper.ieee.org/groups/scc21/

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Islanding is a condition where part of a utility system containing both load and generation is isolated from the remainder of the utility system but remains energized. Islanding of PV systems and other distributed generation is an undesirable condition, and presents two basic problems for electric utilities in terms of safety and operation of the utility system.

First, utilities have no control over the voltage and frequency with distributed generation islanding. If an island condition develops with a distributed generator when the utility becomes de-energized, damage to the distributed generator or utility equipment may result if the island is allowed to be reconnected to the grid. Islanding can also interfere with the utility’s normal procedures for bringing their system back into service following an outage, primarily because the islanded electrical system is no longer in phase with the utility system.

Second and more importantly, the creation of an island presents a safety hazard for utility linemen working to restore power after an outage. While utilities are able to ensure their equipment is isolated properly, they are less confident about customer-owned generation that they do not control.


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IEEE 1547 requires PV systems and other distributed generation sources to be able to detect when an island is forming and stop supplying power to the grid until the utility system returns to its normal operating limits. Interactive PV inverters must have a minimum of two detection methods for both passive and active islanding (total of four). This is accomplished through anti-islanding circuitry internal to inverters, and evaluated under UL 1741 as part of the equipment listing. Inverters meeting this standard are often referred to as “non-islanding” inverters – in part distinguishing them from stand-alone inverters. Conventional rotating generators use external over/under voltage and frequency relaying equipment to prevent islanding.


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IEEE 1547 requires monitoring for distributed generators 250 KVA and larger, and specifies a readily accessible, lockable, visible-break disconnecting means subject to local utility policies.

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Power quality is among the principal concerns for electric utilities, especially for distributed generation equipment interconnected to their system. Power quality addresses a broad range of utility waveform properties, including voltage, frequency, harmonic distortion, power factor, DC injection, voltage flicker and noise on the utility system.


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UL 1741 Inverters, Converters, Controllers and Interconnection System Equipment for Use with Distributed Energy Resources addresses requirements for all types of distributed generation equipment, including inverters, charge controllers and combiner boxes used in PV systems, as well as equipment used for the interconnection of wind turbines, fuel cells, microturbines and engine-generators. This standard covers requirements for the utility interface, and is intended to supplement and be used in conjunction with IEEE 1547. The products covered by the UL 1741 listing are intended to be installed in accordance with the National Electrical Code, NFPA 70.


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Distributed generation technologies can be classified as using either with rotating generators or static electronic inverters. The type of prime mover has important distinctions when considering the requirements for interconnecting these systems to the electric utility grid.


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Synchronizing is the process of connecting a generator to an energized electrical system. Synchronizing is also called paralleling a generator, or bringing it on-line. The prerequisites for synchronizing a rotating electrical generator with the grid are extremely critical, and involves four important steps before the interconnection can be made.

1. The phase sequence of the generator must be the same as other generators already operating on the electrical system. This means it must be rotating in the same direction. A phase-sequence indicator is used to determine in what order the phases reach their maximum voltage. 2. The synchronizing generator must be operating at the same frequency as other generators on the system. Frequency is controlled by the rotating speed of the generator, and based on the number of field poles. 3. The voltages of the generator and grid at the point of connection must be the same. Voltage is controlled by varying the generator field current and magnet strength.4. The generator and grid voltages must be in phase.

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Interactive PV systems operate in parallel with and are interconnected to the electric utility grid. The primary component in interactive PV systems is the inverter, which directly interfaces between the PV array and electric utility network, converts DC power from a PV array to AC power, synchronizes with the grid and provides protective functions.


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The most common type interactive PV system is one that does not use energy storage. These systems make a bi-directional interface at the point of utility interconnection, typically at a site distribution panel or electrical service entrance. Consequently, power can be exchanged in a bi-directional manner between an interactive system and the utility at the point of interconnection, making it a supplementary generation source operating on the electric utility network. The interconnection allows the AC power produced by the PV system to either supply on-site electrical loads or to back-feed the grid when the PV system output is greater than the site load demand. At night and during other periods when the electrical loads are greater than the PV system output, the balance of power required by the loads is received from the electric utility.

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Bimodal systems are utility-interactive systems that use battery storage. They can operate in either interactive or stand-alone mode, but not simultaneously. Bi-modal PV systems operate in a similar manner to uninterruptible power supplies, and have many similar components. Under normal circumstances when the grid is energized, they inverter acts as a diversionary charge controller and limits battery voltage and state-of charge. When the primary power source is lost, a transfer switch internal to the inverter opens the connection with the utility, and the inverter operates dedicated loads that have been disconnected from the grid. An external bypass switch is usually provided to allows the system to be taken off-line for service or maintenance, while not interrupting the operation of electrical loads.


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NEC Article 690 Part VII addresses the connection of PV systems to other power sources, and applies to all interactive PV systems connected to the utility grid. For the 2011 NEC, many of the common interconnection requirements applicable to all distributed generators, including PV systems, fuel cells and wind turbines were moved to Article 705.

See NEC Article 100 for definition of qualified persons [705.6].

References:Photovoltaic Systems, p. 334-340NEC Articles 690, 705

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References:Photovoltaic Systems, p. 334-340NEC Articles 690, 705

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Reference: NEC 690.54

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A directory of power sources and location of disconnecting means are required for safety and access to emergency responders.

References: NEC 690.56, 705.10

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All inverters and AC modules that are specifically intended to be used in utility-interactive PV systems must be listed and identified for interactive operations, and this information must be marked on the product label. Battery-based inverters intended only for stand-alone off-grid applications do not have these special identification markings, and may not be used for grid-connected applications. However, all inverters used in PV systems must be listed to the UL 1741 standard, whether they are used for stand-alone or interactive systems.


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Inverters or AC modules must be capable of de-energizing their output to the utility grid when the grid voltage is lost. This concern relates to islanding, and requires the inverter to automatically disconnect from the grid to prevent from potentially backfeeding an un-energized grid and creating a safety hazard. This grid output must also remain de-energized until grid voltage is restored. These functions are accomplished by internal inverter circuitry, and can also be demonstrated with equipment in the field. Other forms of distributed generation may require external equipment to provide this protection.

A normally interactive solar photovoltaic system is also permitted to operate as a stand-alone system to supply loads that have been disconnected from electrical production and distribution network sources. This requires a special battery-based inverter intended for this purpose, with a separate dedicated load subpanel.


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Most single-phase inverters have two ungrounded conductors, operating at 208/240 V output, and avoid this concern.

Some single-phase PV inverters have two-wire output, one neutral and one hot. If these inverters are connected to the neutral and one ungrounded conductor of a 3-wire split-phase system, or of a 3-phase, 4-wire Wye-connected system, the potential exists for overloading the neutral conductor. The sum of the maximum load between the neutral and ungrounded conductor and the inverter power rating must not exceed the ampacity of the neutral conductor. Many single-phase inverters have two-wire output with no neutral connection, which avoids this problem.

References:Photovoltaic Systems, p. 335NEC 690.62 (2008), 705.95 (2011)

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Precautions must be taken to ensure that larger single-phase inverters connected to 3-phase power systems do not result in unbalanced phase voltages. Solutions are to use three smaller single-phase inverters connected to each phase, or a larger single 3-phase inverter. Three-phase inverters must have all phases automatically de-energized upon loss of, or unbalanced, voltage in one or more phases unless the interconnected system is designed so that significant unbalanced voltages will not result. Three-phase inverters are common above 15 to 30 kW.

References: Photovoltaic Systems, p. 335NEC 690.63 (2008), 705.100 (2011)

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The output of interactive PV inverters may be connected to either the supply side or load side of the service disconnecting means. For many smaller systems, the point of connection is usually made on the load side of the service disconnect at any distribution equipment on the premises, usually at a panelboard. When the requirements for load side connection become impractical, interactive PV systems and other interconnected power sources may be connected to the supply side of the service disconnecting means. In cases of very large PV installations, existing service conductor ampacity or distribution transformers may not be sufficient and separate services may be installed. Power flow can occur in both directions at the point of connection, and the interface equipment and any metering must be sized and rated for the operating conditions.

Systems larger than 100 kW at other points on a premises, provided qualified persons operate and maintain the systems, and that appropriate safeguards, procedures and documentation are in place.

References:Photovoltaic Systems, p. 336-340

NEC 690.64, 705.12, 230.82(6)

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Interactive PV systems are permitted to connected to the supply side of the service disconnecting means. These requirements are similar to installing another service entrance, which involves tapping service conductors or installing new service equipment. Supply side interconnections are often required for larger installations where existing services and/or main distribution panels do not have sufficient capacity or can not meet the requirements for load side interconnections. The sum of the ratings for overcurrent devices supplying a service must not exceed the service ratings.

References:Photovoltaic Systems, p. 339-340NEC 690.64, 705.12(A), 230.86(6)

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References:Photovoltaic Systems, p. 339-340NEC 690.64, 705.12, 230.82(6)

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Supply side connections must have appropriate disconnecting means and overcurrent protection. The connection can be made by tapping the service conductors at the main distribution panel prior to the existing service disconnect, or it may be made on the load side of the meter socket if the terminals permit. Additional pull boxes may be installed to provide sufficient room for the tap. Service equipment for larger commercial facilities often has busbars with provisions for connecting tap conductors.

References:Photovoltaic Systems, p. 339-340NEC Article 230

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References: Photovoltaic Systems, p. 339-340NEC Articles 230 and 240

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Many small residential and commercial PV systems can be interconnected by adding backfed circuit breakers to distribution panels as long as certain conditions are met.

References:Photovoltaic Systems, p. 336-339NEC 690.64, 705.12(D)

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Where the distribution equipment is supplied by both the utility and one or more utility-interactive inverters, and where the distribution equipment is capable of supplying multiple branch circuits or feeders, or both, load side connections must comply with seven requirements.

References:Photovoltaic Systems, p. 336-339NEC 690.64, 705.12(D)

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References:Photovoltaic Systems, p. 336-339NEC 690.64, 705.12(D)(1)

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For a typical 200 A residential service with a 200 A panel, up to 40 A of backfed PV breakers would be allowed, allowing a maximum inverter continuous output current rating of 32 A.

For interactive PV systems with energy storage intended to supply backup load during grid outages, the bus or conductor loading is evaluated at 125% of the inverter maximum continuous current output rather than the overcurrent device rating.


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This requirement only applies to main breakers and backfed breakers from PV systems that supply power to the busbar. It does not include load circuit breakers. This requirement is intended to prevent potential overload conditions from occurring at the point of connection.


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Supply side connections are usually required for larger commercial services having ground-fault protection for the entire service.


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References:Photovoltaic Systems, p. 336-339NEC 690.60, 690.64, 705.12(D)(6), 408.36(D)

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Large PV systems are interconnected to primary and secondary distribution systems, and require additional transformers and protective equipment.

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Interconnection agreements are a contract between a distributed generation owner (utility customer) and an electric utility, and establish the terms and conditions for the interconnection. Most utilities have simple interconnection agreements for the installation of small PV systems at residential and commercial facilities. Larger commercial installations generally have additional requirements, while solar farms larger than 5 to 10 MW are often owned and operated by utilities themselves. Independently-owned solar generation may be subject to qualifying facility requirements.

While the administrative details for interconnection agreements vary between utilities, most have common technical requirements based on national codes and standards. For investor-owned utilities, interconnection rules and policies are often dictated by state public utilities commissions. Although municipal and cooperative utilities may be exempted from state utility commission rules, most follow similar technical guidelines and administrative practices for interconnection as investor-owned utilities.

Suggested Exercise: Obtain and review the utility interconnection agreement from your local utility.

References:Photovoltaic Systems, p. 342-347Database of State Incentives for Renewable Energy (DSIRE): www.dsireusa.org

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Utility interconnection agreements include requirements for using listed interactive equipment (inverters), and the installation must be permitted, inspected and approved by the Authority Having Jurisdiction (AHJ).


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Safety and protections for the public and utility workers will always be a concern for customer-owned distributed generation. Most utilities require the owner to maintain a liability insurance policy to cover any accidents or adverse effects due to the operation of a customer’s PV system. Utilities may also require the PV system owner to indemnify the utility and hold them harmless.


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Some utilities may require inspections or testing for PV systems and other distributed generators to ensure they are operating within prescribed voltage and frequency limits, especially for installations larger than 100 kW. For rotating generators, utilities usually require the use of protective relaying equipment to isolate the equipment from the grid if either operate outside allowable limits. All interactive PV inverters have integral anti-islanding protection that disconnects their output to the grid if the inverter output or grid are not operating within the prescribed limits.


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Utilities may require disconnects for PV systems that are external to a building, lockable by utility personnel, and provide a visible-break isolation from the grid. In accordance with NEC Article 690, interactive inverters already must have a manual means of isolation from the grid, and must automatically disconnect if grid voltage is lost. All inverters listed to UL1741 employ anti-islanding provisions to disconnect from the grid automatically.

If the PV system disconnect is not co-located with the utility service disconnect, a directory and map of the facility must be provided indicating the location of the PV disconnect. This disconnect means can usually be located to meet utility requirements. Generally, additional utility disconnects are not required for small residential PV systems, but are usually required for commercial installations 10 to 100 kW and larger. Utility disconnects are intended for safety, but in some cases may be used for administrative purposes by locking out a distributed generator that does not comply with the terms and conditions of their interconnection agreement.

References:Photovoltaic Systems, p. 342-347NEC 690, 705

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Different arrangements and types of metering may be used to record energy flows for facilities with PV systems, depending on the size and type of system, interconnection policies, and the intended revenue structure.


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Electronic metering is becoming more prevalent and allows utilities to monitor and record a number of parameters in addition to the energy delivered. Electronic watt-hour meters use current transformers (CTs) and voltage transformers (VTs) to measure current and voltage, and contain small microprocessors to collect and record data. Many electronic meters can also be used for automated meter reading (AMR) applications, allowing the meter data to be read remotely by RF signals, telephone modems, network or power line carrier signals.


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Revenue metering measures and records the energy delivered to a customer’s facility for billing purposes at the point of service entrance. The customer is billed at the retail rate per kWh for energy consumed. Utilities often have different rate tiers for different levels of energy consumption, and for residential or commercial customers. For example, to promote energy conservation, a lower rate might apply to residential monthly energy consumption up to 1000 kWh, and a higher rate for usage over 1000 kWh.


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Demand metering is installed on most larger commercial and industrial facilities, and customers are billed monthly for the peak power (kW) demand in addition to energy consumption (kWh). Different tiers and higher rates usually apply to customers having greater peak loads. The peak power consumption over a defined interval, usually 15 minutes, sets the peak demand charges for the month.

Large industrial facilities with low power factor may also be metered and billed for reactive power and energy, using VAR meters.


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Time-of-use metering uses electronic meters to record energy use in separate registers for different times of the day, corresponding to on-peak and off-peak times for the utility. The customer is billed at lower rates for energy used during off-peak times than for on-peak times. Time-of-use metering is generally optional, but may be increasingly required as a form of demand metering. This type of metering encourages a customer to curtail energy use during peak times, or to shift the use of major loads to off-peak times. Consequently, time-of-use rates also encourage the adoption of energy management and distributed energy storage systems.


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PV output metering uses a dedicated meter to record the energy production from PV systems independently. For feed-in tariff programs that pay the customer separately for PV generation, the PV output and metering are connected to the utility side of normal utility revenue metering. Since the customer is paid directly for the PV generation, the energy is not supplied to the load side of the normal utility revenue meter. PV output metering is also required to document production for renewable energy credits.


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Dual metering (net purchase and sale metering) uses two unidirectional meters (or an electronic meter) to record energy flow to and from a facility. One meter registers electricity drawn from the grid and the customer pays retail rate for this energy. The other meter records energy fed back into the grid for which the customer is credited the wholesale rate (avoided cost). Two electromechanical meters can be wired in series, and use detents to prevent them from recording when the power is flowing in the opposite direction. More commonly today, a single electronic meter that measures positive and negative energy flows is used.

There is usually a significant difference in the retail rate and the avoided cost. A typical retail rate might be 12¢/kWh, while the avoided cost may be 4¢/kWh. Consequently, dual metering is less favorable for renewable generators when production exceeds the facility loads. If all PV energy is consumed on site and none is sent back into the grid, dual metering has the same result on utility billing as net metering.

For example, assume a customer has a PV system that produces 30 kWh/day, of which 10 kWh is consumed on site and 20 kWh is sent back to the grid. Under a dual metering arrangement, 10 kWh will offset the full retail energy costs, while the 20 kWh send back to the grid will only be credited at a lower wholesale rate, regardless

if that energy is later used at the facility or not.


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Net metering allows a certain amount of excess energy generated from PV systems or other distributed generators to be sent onto the grid, for which the customer receives full retail credit. This credit can be later used to offset facility loads. Most utilities allow monthly carryover energy credits, and the customer may or may not be compensated for excess generation over time. This affects the value of larger PV systems that consistently produce more energy than the facility loads require. Some utilities may pay the customer wholesale rate or even full retail rate for excess generation, depending on the local interconnection policies.

For example, assume a customer has a PV system that produces 30 kWh/day, of which 10 kWh is consumed on site and 20 kWh is sent back to the grid. Under a net metering arrangement, the 20 kWh sent back to the grid is credited at retail price, up to certain limits. Net metering s arrangement is more advantageous to the customer than a dual meter net purchase and sale arrangement.


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Net metering in an incentive for renewable power generation, and does not apply to systems larger than permitted under local interconnection and net metering rules. Nearly every state has net metering rules applying to PV systems and other types of renewable generation. Different size limits and tiers apply for different utilities and states, ranging from 10 kW residential to over 2 MW.

Reference: www.dsireusa.org

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