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LEARNING GOALS: Compare the differences in the interconnection of rotating generators and electronic inverters. Identify the applicable codes and standards for utility interconnection. Describe how interconnected PV systems can affect utility operations. Differentiate between load-side and supply-side interconnections and identify the code and installation requirements for each type. Compare the technical and policy issues between net metering and dual metering. Identify the common issues addressed in interconnection agreements for PV systems. DISTRIBUTED GENERATION Distributed generation is a system in which many smaller power-generating systems create electrical power near the point of consumption. Operating these systems in parallel with the utility’s distribution grid makes these systems interactive. Distributed generation is an increasingly common supplement to traditional central power generation. This arrangement increases the diversity and security of the electrical energy supply and benefits both customers and electric utilities. For customers, these systems provide power to on-site loads and some pro vide back-up in the event of a utility outage. For utilities, the additional power sources sup plying their excess power to the grid increase the utility’s capacity to serve customers with out building new power plants. Accordingly, a great deal of attention is focused on interconnecting these power re sources. However, there are technical, procedural, and contractual requirements to making interconnections that are safe and reliable and that do not adversely impact the rest of the electricity distribution system. Many distributed-generation technologies can be interconnected to the utility grid, including engine generators, fuel cells, wind turbines, micro-hydroelectric turbines, and , of course, PV systems. Distributed-generation technologies are also classified by the way AC power is generated, either with rotating generators or with electronic inverters. This has important implications for connecting these systems to the electric utility grid. Interconnected PV systems provide supplemental power and some can be used as back-up power in the event of a utility outage. Solar World Industries America 1. Distributed Generation -- With distributed generation, utility customers are served by both the centralized power plants and the power exported from interconnected distributed generators. UTILITY DISTRIBUTION; CENTRALIZED POWER PLANT Generators Most electrical power is produced by rotating generators that are mechanically driven. The mechanical energy is produced by engines or by turbines driven by steam, wind, or water. Current is induced in a conductor as it moves through a magnetic field. If the movement is from rotation, the current varies sinusoidally, producing AC power. If a set of coils rotates through a stationary magnetic field, the design is known as a generator. With three sets of equally-spaced coils, three- phase power is produced. Alternatively, a design with a magnetic field rotating around a set of stationary coils produces the same output. The resulting voltage is proportional to the strength of the magnetic field, and the frequency is proportional to the rotational speed. The electric utility system consists of hundreds or thousands of interconnected generators operating in parallel. These generators must all be synchronized with one another to prevent damaging themselves or the interconnection interfaces. Synchronizing is the process of connecting a generator to an energized electrical system. Synchronizing is extremely critical and involves precisely matching the phase sequence, frequency, and voltage of the generator to the rest of the electrical system before they are connected. The electric utility system must also maintain a critical balance between load and generation. If generation exceeds the load on the utility system, the frequency of the system increases. Conversely, if the load exceeds the generation, frequency decreases. Frequency is one of the most important utility parameters be cause it establishes the speed for devices using motors, including some clocks. In North America, it must be maintained at exactly 60 Hz. Frequency control is established by varying power generation to match the load. Other parameters are also constantly monitored for variations, which requires external sensors and controls. If the interface parameters go beyond acceptable limits, the controls automatically disconnect the generator from the utility system. Inverters Solid-state electronic inverters are substantially different from generators in the way they operate, which has important implications for connecting them to the utility system. Solid-state inverters use electronic switching elements to produce AC power, so they have no moving parts. Generators act like a voltage source, while interactive inverters act like a current source. Generators can operate independently of the grid and produce high fault currents. Inverters feed much less current into a fault and are less capable of supporting an islanded electrical power system. However, unlike generators, inverters can't act as loads and consume power from other generators or inverters. 2. Generators: ROTATING COILS, MECHANICAL ROTATION; THREE-PHASE AC POWER; MAGNETIC FIELD -- Most power is generated by rotating generators, which require precise interconnection procedures to avoid damage to the equipment and the utility. DEGREES OF ROTATION: 0’, 60, 120’, 180’, 240’, 300’, 360’ Inverters are also loaded differently than generators. Since the sun can't be turned ON and OFF, most interactive PY inverters initially load the array at its open-circuit voltage where it produces no power. Once loaded, the inverter decreases the array operating voltage to the maximum power voltage. Maximum power point tracking (MPPT) electronics then continually make adjustments to the array operating voltage to maximize output. Power output is limited by the capacity of the PY array, the inverter output rating, and temperature. For interactive inverters, synchronizing functions are performed automatically and internally. Since inverters have the ability to monitor and regulate system output directly through microprocessor controls, synchronizing can be done cost-effectively and directly. Inverters can also incorporate additional protective and safety features that may otherwise be required as external equipment on generators. Since the interactive inverter is the primary utility interface device, it must meet all requirements for utility interconnection and be listed and identified for use in interactive PV systems. Inverters can be stand-atone interactive, or bimodal types There is no special type for use in hybrid systems as it is not possible for most inverters to interconnect multiple sources Instead multiple separate inverters are used when necessary Interactive-Only Systems. The most common type of interactive PV system is one that does not use energy storage. The array is connected to the DC input of an interactive-only inverter. The inverter output interfaces with the utility, typically at a site distribution panel or electrical service entrance. Power can flow in both directions at the point of service, making the PV system a supplementary generation source operating on the electric utility network. When on-site power demand exceeds the supply from the PV system, supplementary power is drawn from the utility. If the PV array produces more power than is needed on-site, the excess power is fed to the grid. 3. Inverter Labeling: Inverters must be identified as interactive and listed to required standards before being interconnected. Bimodal Systems. Bimodal systems are interactive systems that include battery storage, so they can operate in either interactive or stand-alone mode, providing a back-up power supply for critical loads such as computers, refrigeration, water pumps, or lighting. Unlike interactive- only inverters, the DC input of the inverter is connected to the battery bank, not the array. The array charges the battery bank, through the charge controller. Under normal circumstances, bimodal systems operate in interactive mode. The inverters serve the on-site loads or send excess power back to the grid while the array keeps the battery bank fully charged. If the grid de-energizes, control circuitry in the inverter opens the connection with the utility and draws power from the batteries to supply an isolated subpanel, typically for critical loads. 4. Interactive-only systems are the simplest way to interconnect a PV system with the utility: UTILITY GRID; LOADS 5. Bimodal Systems -- The inverters in bimodal systems can continue to supply power to certain loads in the event of a utility outage. For servicing the system without interrupting the load operation, a manual transfer switch and bypass circuit can isolate the PV array, battery, and inverter from the system and directly connect the subpanel loads to the utility supply. Bimodal systems with battery storage can also be employed to manage and optimize utility energy use by utility customers that are billed using time-of-use electric rates, or those that incur demand charges for peak power use. Bimodal inverters are programmed to supply electrical loads with energy from the battery and PV generation during peak times, minimizing the use of high-priced utility energy. During off-peak times, less-expensive utility energy powers system loads and charges the battery system. Interconnection Codes and Standards In the United States, the technical requirements for PV systems are established through national codes and standards published by the Institute of Electrical and Electronics Engineers (IEEE), Underwriters Laboratories (UL), and the National Fire Protection Association (NFPA). These organizations work collectively to ensure electrical equipment and installations are safe, through the combination of standards, equipment testing and certification, and enforceable codes. As a PV system is an electrical system, any general electrical codes and standards apply, such as the National Electrical Code®. Additional standards dealing specifically with the interconnection of PV systems also apply. Interconnection Codes and Standards IEEE 929. ANSI/IEEE 929-2000, Recommended Practice for Utility Interface of Photovoltaic (PV) Systems provided uniform interconnection requirements widely accepted by many utilities and jurisdictions, and recommended no additional requirements for small PV systems of 10 kW and less. IEEE 929 is no longer an active standard, but its requirements have been incorporated into the current standard ANSI/IEEE 1547. IEEE 929 was important to the early history of PV systems because it established requirements for power quality and safety features for interactive inverters. Power quality requirements included specifications for service voltage, frequency, harmonic distortion, and power factor. Safety features included anti-islanding, reconnection to the utility service after an interruption, and responses to abnormal utility conditions, such as voltage and frequency disturbances. It also provided guidance on DC isolation, grounding, and manual disconnects. These and other requirements have been incorporated into IEEE 1547.
Recommended Practice for Utility Interlace of Photovoltaic (PV) Systems Standard for Interconnecting Distributed Resources with Electric Power Systems Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems Application Guide for IEEE Standard 1547, Standard for Interconnecting Distributed Resources with Electric Power Systems -- Guide for Monitoring, Information Exchange, and Control of Distributed Interconnected with Electric Power Systems Draft Guide for Design, Operation, and Integration of Distributed Resource Island Systems with Electric Power Systems - - - - Draft Technical Guidelines for Interconnection of Electric Power Sources Greater than 10 MVA to the Power Transmission Grid - - Draft Recommended Practice for Interconnecting Distributed Resources with - Electric Power Systems Distribution Secondary Networks Draft Guide to Conducting Distribution Impact Studies for Distributed Resource Interconnection Inverters, Converters, Controllers, and Interconnection System Equipment for Use with Distributed Energy Resources * IEEE 929 is r k active and has been replaced by IEEE 1547. 6. Several codes and standards address specific interconnection issues with PV systems. IEEE 1547. ANSI/IEEE 1547-2003, Standard for Interconnecting Distributed Resources with Electric Power Systems, is a broader interconnection standard addressing requirements for all types of distributed power sources, including PY systems, fuel cells, wind turbines, engine generators, and large combustion turbines. It establishes requirements for testing, performance, maintenance, and safety of inter connections, as well as responses to abnormal events, islanding, and power quality. The focus of IEEE 1547 is on distributed- generation resources with capacities of less than 10 MW that are interconnected to the electrical utility system at typical primary or secondary distribution voltages. The standard provides universal requirements to help ensure safe and technically sound interconnections. It does not address limitations or impacts on the utility system in terms of energy supply, nor does it deal with procedural or contractual is sues associated with the interconnection. IEEE 1547 is actually a family of standards, guides, and recommended practices. While IEEE 1547 addresses core issues regarding interconnection, specific technical issues are addressed in the IEEE 1547.X series. IEEE 1547.1-2005, Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems, specifies commissioning tests that shall be performed to demonstrate that the equipment and operation of distributed power sources conforms to IEEE 1547. In particular, emphasis is placed on anti-islanding protection. IEEE 1547.2-2008, Application Guide for IEEE Standard 1547, Standard for Interconnecting Distributed Resources with Electric Power Systems, provides technical background and application details to support the under standing of IEEE 1547. It characterizes the various distributed-generation technologies and their associated interconnection issues and discusses the background and rationale of the technical requirements. IEEE 1547.3-2007, Guide for Monitoring, Information Exchange, and Control of Distributed Resources Interconnected with Electric Power Systems, facilitates the interoperability of one or more distributed-generation resources interconnected with electric power systems. IEEE P1547.4, Draft Guide for Design, Operation, and Integration of Distributed Resource Island Systems with Electric Power Systems, provides alternative approaches and practices for the interconnection of distributed- generation systems that also provide critical load backup (bimodal systems). It includes provisions to separate from and reconnect to an area electric power system while providing power to the islanded local power system. IEEE P1547.5, Draft Technical Guidelines for Interconnection of Electric Power Sources Greater than 10 MVA to the Power Transmission Grid, provides guidelines for interconnecting utility-scale power sources to a bulk power transmission grid. IEEE P 1547.6, Draft Recommended Practice for Interconnecting Distributed Resources with Electric Power Systems Distribution Secondary Networks, provides guidance on technical issues associated with the interconnection of distributed-generation systems, including recommendations for the performance, operation, testing, safety considerations, and maintenance of the interconnection. Consideration is given to the needs of the local utility to be able to provide enhanced service to site loads as well as to other loads served by the grid. IEEE P 1547.7, Draft Guide to Conducting Distribution Impact Studies for Distributed Resource Interconnection, provides criteria and scope for engineering studies regarding the impact of interconnected distributed power sources to an area electric power distribution system. This guide facilitates a methodology for when such impact studies are appropriate, what data is required, how the studies are performed, and how the study results are evaluated. The IEEE 1547 base standard, and the related 1547 1 15472, and 15473 standards, are approved and published documents. The 15474 through 1547 7 standards are stall in development designated by the letter P before their numbers and the word Draft in their names UL 1741. UL 1741-2005, Inverters, Converters, Controllers, and Interconnection System Equipment for Use with Distributed Energy Resources, addresses requirements for distributed-generation equipment, including inverters and charge controllers, and for the utility inter face. The standard is intended to supplement IEEE 1547 and IEEE 1547.1. The products covered by these requirements are intended to be installed in accordance with the NEC and NFPA 70E. NEC Article 690. The NEC Article 690, “Solar Photovoltaic Systems” covers installation requirements for all types of PV systems. In particular, Part VII of Article 690 addresses the requirements for connecting interactive PV systems to other power sources, such as the electric utility grid. Many of these requirements are based on equipment standards and listing requirements for interactive inverters under UL 1741. Article 690 includes several fundamental requirements for interactive inverters. First, inverters must be listed and identified for interactive operation. This information must be included on the inverter nameplate or label. Also, inverters must be anti-islanding, or capable of disconnecting from the utility grid when grid voltage is lost. The PV system must remain disconnected until grid voltage is restored. Large scale systems owned and operated by the electric utility and connected to the utility $ own distribution substations often are not always subject to the same requirements for installation and interconnection as residential and commercial interactive systems Interconnection Concerns Electric utilities have legitimate concerns about connecting distributed-generation equipment to their grid system. For one, the electric utility distribution system was not designed to handle many distributed power sources. For example, many utility service meters are not designed to monitor two-way power flow. Also, because utilities do not operate, control, or maintain customer-owned distributed-generation equipment connected to their system, there are concerns about the impact it may have on safety and the reliability of utility service to other customers. Islanding. Islanding is the undesirable condition where a distributed-generation power source, such as a PV system, continues to transfer power to the utility grid during a utility outage. 7. Islanding is a serious safety hazard for utility lineworkers working to restore power after an outage. Since the workers expect the grid to be de-energized, they may be shocked by the power present in the system from an islanding inverter. Also, islanding can damage utility equipment by interfering with the utility’s normal procedures for restoring service following an outage, primarily because the islanded electrical system is no longer in- phase with the utility system. All utility-interactive inverters must be able to detect power outages and discontinue transfer of power until the utility system returns to normal operation. This precaution is evaluated under UL 1741 as part of the equipment listing. Inverters meeting this standard are often referred to as “non-islanding” or “anti-islanding” inter active inverters. As an added precaution against islanding, utilities may also require easily accessible outdoor switches to physically disconnect interactive PV systems. Bimodal systems may continue operating in stand-alone mode if completely disconnected from the utility. Power Quality. Power quality encompasses the voltage, frequency, harmonic distortion, power factor, DC injection, voltage flicker, and noise on the utility system. Power quality is influenced by the performance of the electrical generation and distribution equipment, as well as electrical loads operating on the system. Power quality is among a utility’s chief concerns for interconnected distributed- generation equipment. Because electrical loads are designed to operate at prescribed conditions, the electric utility system must be maintained within stringent power quality limits. Otherwise, poor performance or even damage to electrical loads and utility system equipment may result. 7. Islanding -- During a utility outage, an islanding inverter can energize the utility lines around the PV system, potentially damaging equipment and creating a serious safety hazard. Utilities routinely test and monitor their generation, transmission, and distribution equipment for performance and power quality. Correspondingly, utilities also require assurances that interactive distributed-generation systems are operating within these limits and do not adversely affect the quality of utility service to other customers. Neutral Loading. Inverter and utility service types must be matched to prevent overloading. If a two-wire, single-phase inverter is connected to the neutral and one of the ungrounded conductors of a split-phase 120/240 V service or a three-phase, wye-connected service, the return current on the neutral (grounded) conductor will not balance and may overload the conductor. 8. Therefore, the neutral conductor must be oversized. NEC Section 690.62 requires that the sum of the maximum load between the neutral and ungrounded conductor and the inverter’s current output rating must not exceed the ampacity of the neutral conductor. Some inverters avoid this problem with two ungrounded outputs. Alternatively, multiple inverters can be installed, one for each ungrounded conductor. Unbalanced Phases. Section 690.63 does not allow the connection of single-phase interactive PV inverters to three-phase power systems unless the interconnection can be designed to minimize unbalanced voltages between the phases. 9. One option would be to use three small inverters and connect each inverter to a different phase. A better solution would be to use a single three-phase inverter. With a three-phase inverter, all phases must automatically dc-energize when voltage becomes unbalanced or any phase is lost completely. 8. Neutral Loading When a single-phase inverter is added to a system with more than one ungrounded (hot) conductor, the neutral conductor can become overloaded. POWER FLOWING; OUT OF PV SYSTEM; INTO GRID ISLAND; 120/240V SERVICE; AC POWER DISTRIBUTION PANEL- -NEUTRAL (GROUNDED); CONDUCTOR RECEIVES UNBALANCED RETURN CURRENT; INERACTIVE INVERTER 9. Unbalanced Phases Adding single-phase output from an interactive inverter to a three-phase power system can result in unbalanced voltages between the phases. Point of Connection The point of connection is the location at which an interactive distributed-generation system makes its interconnection with the electric utility system. Power flow between the utility and distribution system may occur in both directions at the service connection, so all the service equipment must be sized and rated to allow this. Section 690.64 permits the output of inter active PV inverters to be connected to either the load side (customer side) or supply side (utility side) of the service disconnect. 10. For many smaller systems, the point of connection is usually made on the load side, usually at a circuit breaker in the distribution panel. When the requirements for a load-side connection are not possible (such as due to the size of the PV system), interactive systems may be connected to the supply side. In cases of very large PV installations, existing service conductor ampacity may not be sufficient and separate services may need to be installed. Load-Side Interconnections. Many small interactive PV systems are interconnected on the load side of the main service disconnect at a customer’s facility. The NEC® permits load- side connections at any distribution equipment on the premises, providing the following seven conditions are satisfied: Point of Connection 10. Interactive inverters can be connected to either the load side or the supply side of the main service disconnect. SUPPLY SIDE; LOAD SIDE; -AC POWER DISTRIBUTION PANEL; MAIN SERVICE DISCONNECT; 11. Load-Side Connection: Interconnection on the load side of the service disconnect is done through back-fed circuit breakers. BUSBAR 1. Each source interconnection must be made at a dedicated circuit breaker or fused disconnect. 11. Multiple inverters are considered multiple sources. Each requires a dedicated interconnection device, unless their out puts are first combined at a subpanel. 2. The sum of the ratings of overcunent protection devices in all circuits supplying power to a busbar or conductor must not exceed 120% of the rating of the busbar or conductor. This prevents potential overload conditions from occurring at the point of connection. This limit applies only to the breakers for power sources, which are the main utility- fed circuit breakers and any back-fed circuit breakers from PV systems that supply power to the busbar. It does not include load circuit breakers. For example, consider a 200 A distribution panel with a main circuit breaker and busbar rated at 200 A. The sum of the ratings for devices supplying power is al lowed to be 120% of the busbar rating, or 240A (200 Ax 120% = 240 A). Since the panel busbar is already fed with a 200 A circuit breaker, additional circuit breakers with ampere ratings totaling up to 40 A are permitted to supply power from a PV system. Alternatively, if the busbar rating were 225A and the main circuit breaker rating were 200 A, then the PV system’s back-fed breakers could have a total rating of up to 70 A. 3. The interconnection point must be on the supply side of all ground-fault protection equipment. This requirement prevents potential damage to, or improper operation of, ground-fault protection equipment. An exception is allowed for connection to the load side of ground-fault protection equipment that is protected from all ground-fault current sources. 4. All panels with more than one source of power must be marked showing all sources of power. This labeling is required to alert maintenance and service personnel to the presence of multiple power supply sources to distribution equipment. It is not required for equipment with power sup plied from a single source. This requirement can be met by installing placards on all back-fed panelboards and fused disconnects indicating the rated output current and nominal line voltage of all connected inverters and utility services. 5. Any back-fed circuit breaker used for an interconnection must be identified for such operation. Any circuit breaker not marked with “line” and “load” designations are considered suitable for backfeeding. 6. Dedicated circuit breakers back-fed from listed utility-interactive inverters are not required to be individually clamped to the panelboard busbars with additional fasteners. 7. A back-fed circuit breaker in a panelboard shall be positioned at the opposite (load) end from the main circuit location. A permanent warning label must be applied by the back-fed breaker with the following or equivalent marking: “WARNING: INVERTER OUTPUT CONNECTION, DO NOT RELOCATE THIS OVERCURRENT DEVICE.” Bimodal systems present special issues in meeting these requirements because many of these inverters are capable of delivering 60A continuously. Although the inverter may be rated for 60 A continuous, the external conductors and circuit breaker must be able to handle 125% of this current continuously. This requires an 80 A circuit breaker and conductors sized to handle 75 A. (Reducing the inverter output current to 48 A may allow the use of equipment rated at 60 A, but this would also reduce the peak output capability of the inverter.) 12. Back-Fed Circuit Breakers Back-fed circuit breakers are circuit breakers on the load side of the main service disconnect that supply PV power to the busbar. - MAIN SERVICE DISCONNECT; AC POWER DISTRIBUTION PANEL; - INVERTER OUTPUT CIRCUIT; BACK-FED; CIRCUIT BREAKER; WARNING: INVERTER OUTPUT CONNECTION DO NOT RELOCATE THIS OVERCURRENT DEVICE === Load-Side Interconnection Capacity: The capacity of existing service and distribution equipment limits the size of PV systems that can be interconnected to the load side of a utility service without modifications. For example, a 2500 W, 240 V inverter has a rated current output of 10.4 A. Overcurrent protection must be sized for 125% of the inverter’s rated output, yielding 13 A. This value is rounded up to the next available overcurrent protection device size of 15 A. Since a common panel with a 200 A busbar and 200 A main circuit breaker is limited to 40 A of additional back-fed circuit breakers, the interconnection at this panel is limited to only two of these inverters. Inverter Subpanels To increase the allowable PV system capacity, a subpanel can be installed that feeds into a single 40A circuit breaker on the main panel. The subpanel can accommodate three inverters with three 15 A circuit breakers. The system is sized correctly, because the overcurrent protection device rating for each inverter is actually 13 A, and the total is 39 A (3 x 13 A = 39 A). An additional 40 A circuit breaker protects the entire subpanel. The subpanel rating is sized based on the total ampacity of circuit breakers supplying this panel and the application, which is 85 A ( A x 3] + 40 A 85 A). Since panels are permitted to be supplied with circuit breaker ampacities at 120% of the busbar rating, this panel would need to be sized for at least 71A (85 A ÷ 120% = 71A).This would still require a standard 100 A panel. 100 A SUBPANEL Panel Ratings Another, though often impractical, method of increasing the limit for additional back-fed circuit breakers is to decrease the rating of the main panel utility service circuit breaker. For example, reducing the main circuit breaker rating from 200 A to 175 A would allow for an additional 25 A of back-fed circuit breakers. However, this approach limits the utility supply to the panel and may cause nuisance circuit breaker trips or violate the original panel load calculations. A better solution would be to install a panel with a higher-rated busbar and a downsized main circuit breaker. For example, if a 320 A rated panel (busbar) with a 200 A main circuit breaker were installed, the allowable additional back-fed circuit breakers would be 184 A ( A x 120%] — 200 A = 184 A). When panel modifications become impractical to meet this requirement, a supply-side connection may be used. === Also, a 60 A back-fed circuit breaker requires a panelboard rated to at least 300 A to meet the second requirement. Residential panels rated above 300A are available but uncommon. For these reasons, a supply-side interconnection might be a more practical alternative. Supply-Side Interconnections. When PV systems are too large to interconnect on the load side, due to the capacity of the distribution equipment, a supply side interconnection must be used. The supply-side connection of interactive PY systems requires adding another service in parallel with an existing service disconnect. Accordingly, the rules for service entrance equipment apply to this connection. The equipment must be rated as service equipment and the existing service conductors must be rated for the additional PV system output. The interconnection requires tapping the service entrance conductors, which is usually done between the existing main service disconnect and meter socket. Service entrance equipment is avail able that splits the incoming service into individual services, which can be used for this purpose. Alternatively, the connection can be made at a new meter, which would constitute a new service. The NEC requires this new service to have disconnects and overcurrent protection as described in Article 230, “Services.” A service-rated circuit breaker or fused disconnect meets these requirements and may also satisfy a utility’s requirement for an accessible, lockable safety disconnect that clearly indicates open status. Because a service disconnect with at least a 60A rating must be used (per Article 230), even for lower-output-rated PV systems, smaller fuses and adapters may be required. Because services and taps are unprotected on the line side up to the fuse on the primary side of the distribution transformer, this new service disconnect must also have appropriate interrupting ratings consistent with potential utility fault currents and other service equipment. Fused disconnects with 200,000A interrupting ratings are Interconnection standards provide guidelines on the placement, connection, available to meet this requirement, and operation of utility-interactive equipment. 13. Supply Connection: Interconnection on the supply side of the service disconnect must include a separate service-rated fused disconnect or circuit breaker. FUSED DISCONNECT; TO LOADS; AC POWER DISTRIBUTION The load side interconnection requirements in the 2005 NEC° particularly those regarding the allowable ratings of back fed circuit breakers, differentiated between commercial and residential Installations This distinction was removed in the 2008 edition, making compliance and inspections easier. The service conductors must be sized for at least 125% of the continuous load current as required in Article 230, based on the PV sys tem inverter maximum current output rating. However, the conductors between the service tap and disconnect must be rated at no less than the disconnect rating, which is at least 60 A. Consequently, smaller systems may require larger service tap conductors than the PV system output would otherwise dictate. Best practice suggests using tap conductors as large as the service equipment terminals will permit. The best location for the tap will vary depending on the application and equipment. This connection may be done at the main distribution panel prior to the existing main service disconnect, or it may be done on the load side of the meter socket. Regardless of the point of connection, NEC® Article 705, “Interconnected Electric Power Production Sources,” requires that a permanent directory be placed at each service location showing all power sources for a building. If the PV system is connected on the load side, this labeling may be in addition to labeling at the panelboard. If the point of connection is on the supply side, this labeling may serve the purposes of a supply- side label near the service disconnects. Metering Electricity is metered to determine the amount of energy delivered to (or from) a customer’s facility for billing purposes. Metering used for billing is the responsibility of electric utilities and is often called “revenue metering.” Revenue meters are installed at the service entrance and establish the transition between utility and customer-owned equipment. The type of metering installed in facilities with interactive systems is determined by the type and size of the facility and distributed-generation equipment and the applicable interconnection policies and rules. Net Metering. Net metering uses one meter that can operate in both directions, effectively subtracting exported electricity from imported electricity. This assigns them the same, full retail value, which is most advantageous to the customer. Sometimes a customer’s existing meter is capable of operating backwards without any modifications. If a different meter must be installed, it is the responsibility of the utility to do this, though it may charge the customer a fee. 14. Interconnected PV systems must include labeling that clearly identifies the disconnects and point of interconnection. 15. With a net metering arrangement, exported power makes the electric meter run backward, crediting the PV system owner for power supplied to the utility grid at the retail rate. POWER FLOWS IN BOTH DIRECTION; BIDIRECTIONAL METER; AC POWER DISTRIBUTION PANEL; POWER FROM INTERACTIVE INVERTER Metering Basics: For billing purposes, electricity consumption is metered as power enters a customer’s building. For residential and small commercial buildings, standard watt-hour meters accumulate total energy passing through the meter, and the utility charges the customer a certain rate per kilowatt-hour. For larger commercial facilities, metering typically also includes peak power demand in kilowatts (kW), and customers are billed for both peak power demand and energy consumption. Electromechanical induction watt-hour meters are conceptually similar to motors. Electricity passing through coils creates magnetic fields, which rotate a metal disk. The rate of disk revolution is proportional to the power passing through the meter, so each revolution accounts for a certain amount of energy transfer. The watt-hour constant (designated “Kh”) is the number of watt-hours per disk revolution. The number of disk revolutions is counted mechanically and the corresponding energy use is displayed on the register in digits or dials. Watt-hour meters rotate in the positive direction when the meter is fed from the overhead service entrances. However, electromechanical meters can operate with power passing through in the opposite direction, which simply reverses the direction of disk rotation, and the meter register counts backward instead of forward. This is the basis for net metering. Today, many electromechanical watt-hour meters are being replaced by electronic meters using current and voltage transformers and microprocessors to measure, process, and record data. Some can record other electrical service information, including peak power demand, power factor, reactive energy, time-of-use consumption, or, in the case of distributed generation, exported energy. Many electronic meters can also be used for automated meter reading (AMA) applications, allowing the meter data to be read remotely by either infrared, radio frequency, telephone, wide-area network, or power line carrier signals. Under most state rules, residential, commercial, and industrial customers with small to medium-sized PV systems are eligible for net metering. In other areas, eligibility can vary by location, customer type, utility, and technology (such as PV array, wind turbine, or engine generator). Net metering is also a low- cost and easily administered way of promoting direct customer investment in renewable energy, though at the utility’s expense. Dual Metering. Two-meter arrangements are more common for larger independent power producers, though they are also used for a variety of PV systems in states that have not yet mandated net metering rules. Two unidirectional meters, or a single multi-register meter, record exported and imported energy separately. Because they are measured separately, the energy sent to or supplied from the utility can be assigned different values. Usually the utility pays a lower rate for electrical energy exported from a customer, which is less advantageous to the customer than net metering. Under the most common dual-metering arrangement, referred to as “net purchase and sale:’ excess electrical energy produced by a customer can be purchased by the utility at a different rate than it charges to sell electricity to the customer. Under this arrangement, the utility usually pays its avoided cost when purchasing electricity. There is generally a significant difference in the retail rate and the avoided cost. For instance, a retail rate might be about 9 while the avoided-cost rate may be only 3 Electromechanical induction watt-hour meters are the most common type of meters installed by electric utility companies. 16. Dual metering can be accomplished with two separate meters or with one meter that can measure and record energy flow in both directions separately. UTILITY INTERCONNECTION POLICIES Utility interconnection policies and practices have been a major barrier to the expanded adoption of PV and other distributed power systems, though procedures are gradually be coming more consumer friendly in many areas. Some policies dealing with the interconnection of these systems are legislated by federal, state, and local governments. Where governmental policies are absent, interconnection policies are established by local utility companies. Public Utilities Regulatory Policy Act (PURPA) Over the past 30 years, a number of policies developed at the state and federal levels have impacted the utility interconnection of privately owned power generation systems. The first significant legislation was the Public Utilities Regulatory Policy Act (PURPA) of 1978, passed by the U.S. Congress during the energy crises of the 1970s. This law was intended to decrease U.S. dependence on foreign oil by increasing energy conservation and efficiency and 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 electric utilities. The most significant part of PURPA was that it required electric utilities to purchase power from independent power producers (IPPs) and establish the technical and procedural requirements for their interconnection to the utility system, subject to state regulatory approval. Qualifying Facility. PURPA defines a class of IPPs known as qualifying facilities. A qualifying facility (QF) is a non-utility large-scale power producer that meets the technical and procedural requirements for interconnection to the utility sys tem. PURPA mandates that utilities purchase power from QFs at the utility’s avoided cost. Avoided cost is the cost that a utility would normally incur to generate a given amount of power, often synonymous with the wholesale market value of electricity. When purchasing this energy, the utility “avoids the cost” of generating it themselves. 17. Public Utilities Regulatory Policy (PURPA): PURPA defines the entities that can contribute to the collective energy supply. INDEPENDENT POWER PRODUCERS; MULTIREGISTER METER; PURCHASED ELECTRICITY; CUSTOMERS === Case Study:
In an effort to make PV systems more affordable and encourage installer training, the New York State Energy Research and Development Authority (NYSERDA) granted $148,000 toward the installation of a large PV system at the Tn-City JATC in Latham, NY. This covered more than 60% of the system costs. The local worked with PV organizations to design the system, and the local apprentices and journeymen gained PV system experience by installing the system themselves. The annual output of the PV system is about 28,500 kWh, which offsets a large proportion of the electricity demand of the building and significantly lowers the utility bill. The system is also utility-interactive, so any excess electricity when demand is low is transferred back to the utility grid. However, the local utility company supports net metering for residential customers only. For commercial customers like the training center, the utility installs a second meter to record any exported energy. The billing for energy used and credits for energy exported are processed separately. The wholesale rate the utility pays for exported energy varies daily. At the end of each month, the training center receives both a low bill and a refund check. The modules are set on a standard rack mounting system designed for ground applications. However, instead of using typical concrete foundations for the main pole structures, the training center worked with the rack mount manufacturer to adapt the design for screw pile foundations. This is a unique application of screw pile foundations. Screw piles are strong metal posts with an auger tip that is drilled into the ground under pressure. Screw piles are usually used to support failing foundations or structures in difficult soil conditions. They are more than strong enough for the relatively light array mounting structure, with a real advantage in ease of installation. This innovation turned out to be a considerable improvement. The Tn-City JATC PV system consists of 152 modules arranged in groups to supply 15 inverters with DC power. One meter measures energy used from the utility and another meter measures energy exported back to the utility. The ground mounting system was adapted to use screw piles as a foundation. === It is important to note that avoided costs are only part of the retail price for electricity sup plied to the consumer. Retail price also includes the utility’s administration costs and the costs of building, operating, and maintaining the electricity transmission and distribution system, and bringing services to consumers. These are services that a QF often uses but does not own or operate. Typically, avoided costs are less than half of retail electricity prices. The Federal Energy Regulatory Commission (FERC) is responsible for overseeing the electric utility industry in the United States, including the implementation of PURPA. FERC’s responsibilities include the regulation of the wholesale and interstate utility markets, power exchange transactions, and any rates, terms, or conditions established by state public utility commissions. Under PURPA, public utilities are required to submit their QF rates and billing structures to FERC for approval. The rates are an important part of interconnection agreements between utilities and QFs and in large part determine the economic value of distributed power generation. Qualifying-Facility Agreements. A qualifying facility agreement is a contract between a utility and a qualifying facility that establishes the terms and conditions for interconnection and the rates or tariffs that apply. Tradition ally, QF agreements are targeted to IPPs with generation levels of about 10MW and greater. These agreements include contractual commitments regarding prices and expected levels of generation. In the past, with the absence of interconnection agreements written specifically for small PV systems, utilities often used their general QF agreements for PV interconnection requests. These agreements are intended for large-scale power producers and include many requirements that are unnecessary for small, customer-owned systems. In addition, insurance requirements under QF agreements often exceed the cover age that most homeowners and small businesses carry. These complex legal documents therefore became financial, technical, and regulatory barriers to interconnecting small PV systems. This has prompted most states to pass legislation and adopt rules for a streamlined utility interconnection process and agreements for PV and other small distributed-generation systems. Large-scale PV systems may be subject to special interconnection requirements. Interconnection Agreements An interconnection agreement is a contract between a distributed power producer and an electric utility that establishes the terms and conditions for the interconnection. Many utilities have simple interconnection agreements for the installation of small PV systems at residential and commercial facilities. Permission of the local utility distribution provider is required to interconnect PV systems with the utility grid. Approvals for PV system interconnections are granted by electric utilities in cooperation with the local authority having jurisdiction (AHJ). The interconnection process begins with completing the system design and interconnection plan, and submitting applications for plans review and permits with the AHJ. Concurrently, applications are made to the local utility for interconnection. Once permits are received, the installation is completed and a request for inspection is made with the AHJ. After completing inspection, the utility is notified, inspects the system (if necessary), approves the interconnection agreement, and grants approval to interconnect the system. Usually, electric utilities permit installers to test a PV system with pre-approval. Finally, the system may be interconnected, commissioned, and operated. Utility interconnection agreements are governed by state utility commissions and local utility boards, so they vary somewhat by region. However, most have common requirements based on national codes and standards. Size Restrictions. Interconnection agreements typically limit the size of the distributed- generation system covered under the agreement, though the maximum size is often far larger than is feasible for most residential and commercial systems. Limits vary by state and range from 10 kW peak to a few MW peak. A larger system may still be interconnected, but will likely fall into the category of a QF, which involves more stringent technical requirements and legal issues. The size limitation allows for a simplified contract, making interconnection more accessible to homeowners and small businesses. Liability Insurance. Because of safety concerns, liability has always been a consideration for interconnecting distributed power sources. Liability insurance is required by most utilities that have interconnection standards, as a way to protect themselves and their employees should there be any accidents due to the operation of the customer’s generating system. Liability insurance in the amount of $100,000 is considered adequate for small PV systems by most utilities, and is generally covered in most home or property owner’s policies. If not, the customer must obtain a policy rider or an additional policy to cover the system. Utilities may require the PV system owner to indemnify the utility for any potential damages as a result of operation of the PV system, which may also be covered under a liability policy. Inspection and Monitoring. When interconnecting a PV system to the electric utility, the utility company assumes some of the risks and responsibilities of the system. It must ensure that the system is safe for the customer, their neighbors, and the utility lineworkers who may work on or near the system. The utility must also be sure that the PV system will not adversely affect the operation of the electric utility system. Therefore, most utilities require verification, inspections, and sometimes even testing of PV systems to ensure they are operating within the specified voltage and frequency limits. Inspection rights allow the utility to check for listed equipment and proper installation before interconnection. System Maintenance. After the utility inspections are completed and the PV system is interconnected with the utility system, it is the customer’s responsibility to properly maintain their PV equipment and to promptly contact the utility if there are any problems with the inter connection. The customer is also responsible for the protection of the PV system from the utility system, during both normal and abnormal operation, including installing and maintaining all protection devices. Disconnects. Utilities may require that PV systems have disconnects that are outside the building and accessible by utility personnel. The utility may retain the right to disconnect the system, without prior notice to the customer, if work is necessary on the utility’s part of the system or the customer fails to com ply with the interconnection agreement. 18. Utility interconnection agreements commonly require outside disconnects for PV systems so that the system can be isolated in the event of an outage or emergency. When a PV system includes an anti-islanding inverter, utilities may relax some requirements for the utility-accessible disconnect, such as its location. Also, in accordance with Article 690, PV inverters must already have a manual means of isolation from the grid, which should satisfy the utility requirement if installed outdoors. Some utilities install electronic meters because they are easier to read and may include additional metering features. Interconnection Fees. To offset the additional costs of inspecting, monitoring, billing, and completing paperwork for interconnecting PV systems, utilities may impose interconnection application fees. The fees, if applicable, may be flat rates or may be based on the size of the system. The fee structures vary by state or utility, but range from about $20 to $800 for most small PV systems. State interconnection rules may limit the amount utilities are allowed to charge for interconnection applications. Additionally, the interconnection agreement may also include a schedule of fees for other services and equipment needed to interface with the PV system, especially for larger systems. For example, a new meter may need to be installed or an additional inspection may be needed to remedy code compliance issues. However, the interconnection agreement should also include assurances to customers that paid services or equipment installations will be completed in a reasonable timeframe. Metering and Billing. Interconnection agreements must establish some means to credit the customer for excess power supplied to the utility, usually via either net metering or dual metering. The interconnection agreement defines each party’s responsibilities regarding metering, billing, and rates. The agreement should also specify whether net metering, dual metering, or some other metering arrangement will be used, as well as the party responsible for installing and paying for the metering devices, which is usually the utility. If credits will be issued for exported electricity, customers are generally not monetarily compensated, but are allowed to carry energy credits over from month to month. Usually credits will be used quickly, during times when the customer’s electricity demand exceeds the PV electricity supply, but if credits begin to accumulate and carry over, the utility may specify an expiration date. Credits normally expire after one year, at which time the utility may purchase them at a special rate (usually the wholesale rate) or the credits may expire without compensation. Therefore, it is not advantageous to oversize a PV system without special agreements in place to purchase the excess energy. If the utility is in a state that mandates metering requirements, the utility must abide by those rules. In 2009, policies on net metering exist in 44 states and the District of Columbia. However, not every state has established rules regarding interconnections and metering. In states without established policies, utilities may choose to offer metering programs, though the implementation and requirements will vary between utility companies. States that mandate that utilities allow net metering still have varying rules on other requirements, such as how much electricity a customer can export. Customers should also be careful to note in the interconnection agreement whether the utility will claim the renewable energy certificates (REC5) produced by the PV system, since these can be a valuable financial resource for the customer. 19. Net metering policies vary by state and sometimes also by utility. • Distributed-generation systems provide power to on-site loads and back up the normal utility service in the event of an outage. • Rotating generators produce most of the power on the utility grid, but require precise synchronization procedures before interconnection. • Solid-state inverters include automatic and sophisticated synchronizing functions and have no moving parts. • Interactive-only PV systems connect the array directly to the inverter. • Bimodal systems connect the battery bank to the inverter, and the batteries are charged by the array through the charge controller. • In the event of a utility outage, bimodal inverters can power certain loads by drawing power from the batteries. • In addition to the NEC®, standards apply that deal specifically with the interconnection of PV systems. • Islanding results from an interactive inverter that continues to transfer power to the utility grid that would otherwise be de-energized from an outage. • Islanding is a serious safety hazard and can damage utility equipment. • Power quality is among a utility’s chief concerns for interconnected distributed-generation equipment. • The output from an interactive inverter may be connected to either the load side or the supply side of the service disconnect. • Interconnected systems should be clearly labeled in a central location, and other applicable locations, with all the building’s power sources and their disconnects indicated. • Net metering uses one meter that operates in both directions to subtract the amount of energy exported from the amount of energy purchased. Photovoltaic Systems • Dual metering uses two meters to measure exported energy and purchased energy separately. • Most utilities have simple interconnection agreements for the installation of small PV systems at residential and commercial facilities. • Approvals for PV system interconnections are granted by electric utilities in cooperation with the local authority having jurisdiction (AHJ). • Distributed generation is a system in which many smaller power-generating systems create electrical power near the point of consumption. • Synchronizing is the process of connecting a generator to an energized electrical system. • Islanding is the undesirable condition where a distributed-generation power source, such as a PV system, continues to transfer power to the utility grid during a utility outage. • The point of connection is the location at which an interactive distributed-generation system makes its interconnection with the electric utility system. • A qualifying facility (QF) is a non-utility large-scale power producer that meets the technical and procedural requirements for interconnection to the utility system. • Avoided cost is the cost that a utility would normally incur to generate a given amount of power, often synonymous with the wholesale market value of electricity. • A qualifying-facility agreement is a contract between a utility and a qualifying facility that establishes the terms and conditions for interconnection and the rates or tariffs that apply. • An interconnection agreement is a contract between a distributed power producer and an electric utility that establishes the terms and conditions for the interconnection. 1. Explain how the interconnection of solid-state inverters is different from synchronizing rotating generators. 2. Why is the DC input connection of an inverter different between interactive-only and bimodal systems? 3. How is the standard ANSIJIEEE 1547 related to interconnection? 4. Why is islanding a safety hazard to utility lineworkers? 5. What are the two points of interconnection allowed by the NEC? 6. How do net metering and dual metering affect the billing and crediting of power exchanged with the utility? 7. What types of interconnection-related labeling are potentially required for an interactive PV system? 8. Why are qualifying-facility agreements not appropriate for small residential and commercial PV systems? 9. Why are insurance requirements, inspection rights, and interconnection fees commonly included in inter connection agreements? Next: Permitting and Inspection Prev: Electrical Integration |