Insurance
Insurance Coverage: an EPC Contractor must maintain appropriate levels of insurance relative to project scale, complexity, and associated risk. An insurance engineer and underwriter should be engaged to evaluate a design or installation and to negotiate the following parameters: normal loss expected (NLE), which determines the dollar amount of the deductible without an insurance claim; probable maximum loss (PML), which determines the premium paid on a policy; and maximum foreseeable loss (MFL), which sets limits on coverage.
Coverage should include:
□ Commercial general liability (CGL) insurance ($1,000,000 per occurrence, $2,000,000 aggregate)
□ CGL umbrella policy
□ Professional liability insurance, also known as errors and omissions (E&O) insurance
□ Property insurance (builder’s risk), written on an “all-risks” structure and replacement cost basis; alternatively, this may be covered under the Developer’s coverage, depending on the specific arrangement between parties
□ Commercial vehicle insurance ($1,000,000 per occurrence)
□ Workers compensation insurance ($1,000,000 each accident, each employee)
□ Business interruption insurance, which covers lost revenue due to downtime caused by covered event
□ Inland marine insurance, which insures against loss of equipment not on the property premises
□ Insurance policies should name the developer or owner and any intermediaries as additional insured(s) and certificate holder(s).
Legal agreements between the Developer/Owner and EPC Contractor should require additional insured specification.
EPC Installer
Site Supervisor Qualifications
Most electricians work on AC building systems, and even a master electrician may be unfamiliar with DC-based PV systems.
PV-specific qualifications include:
□ Licensed electrical contractor
□ NABCEP PV Installation Professional Certification
□ UL Photovoltaic (PV) System Installation Certification
□ Experience with medium-voltage electrical systems
□ Experience with DC power systems
□ Familiarity with sections of the National Electric Code specific to PV (section 690).
2.3 Operator/O&M Provider Qualifications
Same as EPC installer site supervisor qualifications, plus:
□ Certification by the North American Energy Reliability Corporation (NERC) (necessary for positions that affect the power grid).
Developer Qualifications
Developers seeking these sources of capital must meet investor expectations. While not an exact science, certain general characteristics of developer qualifications should be strongly considered.
These considerations include:
□ A proven track record of capabilities and successful projects similar in type and size
□ Creditworthy off-takers
□ Strong company financials/low bankruptcy risk
□ Strong advisory team, with industry-specific expertise (legal, financial, technical, etc.)
□ Proficiency and standardization in
- Procurement
- Construction
- O&M contracts
- Offtake agreements
- Permitting
- Technical requirements
- Quality assurance/quality control (QA/QC) protocols,
- Other aspects of PV development.
Developers are expected to carry adequate insurance coverage with levels of coverage[MW1] commensurate with investor requirements, type and scale of development. Additional types of coverage and policies may also be required. Coverage may be extended to cover contractors under these policies, contractors may carry their own policies, or both.
Bidding & Project Estimation
Usage Data and Estimate of Utility Cost Savings
The EPC Contractor is responsible for analyzing the customer’s utility bills from the start of the contract and through at least one prior year, including electrical usage and current rate structure. It is vital that[MW2] usage and rate structure data is included in the system design to ensure that the customer receives a system that is well suited to that particular situation in order to maximize the system’s economic impact. Utility bill analysis may be contracted out by the EPC Contractor. Measuring the savings associated with the energy delivery of an RE system with accuracy requires estimating the annual utility bills based on the details of the utility rate structure, with and without the output of the PV system.
There are many different types of utility rate structures involving combinations of the following features:
• Energy (c/kWh): The output of a PV generator varies with conditions, but monthly or annual energy delivery is more predictable and reliable. This is the feature of the rate schedule in which most of the benefits of the PV delivery will accrue under net metering. Every kWh of net-metered PV delivery will reduce this part of the utility bill according to the energy rate (c/kWh).
• Demand ($/kW/month): Typically, demand charges are calculated as the 15-minute period of each month in which electricity consumption peaked. PV systems are able to reduce demand only when the system is producing during peak demand periods. Many commercial buildings have their peak load in the afternoon due to cooling loads, and many of these cooling loads are exacerbated by solar heat gain, so there is a coincidence of peak demand and solar output for many types of buildings in many climates. But it is possible that there will be some peaking demand period when the solar is not contributing and a new demand charge is determined. A rule of thumb is that solar can save demand equivalent to about 10% of its rated capacity- so a 1 MW PV system might be expected to save an average of 100 kW in demand. [MW3]
• Demand ratchet: This 10% rule of thumb would not apply if there is a demand ratchet, which bases demand charges on a historic (usually annual) demand peak (kW) rather than the measured peak in a month. Now it becomes much more likely that there will be some 15 minute demand period in the preceding year when the solar is not contributing. So a demand ratchet generally results in little or no demand savings for a PV system driven by the intermittent solar resource.
• Time-of-use (TOU) rates: Time of use rates are meant to discourage energy use during the day with higher rates when system loads are highest, and incentivize energy use at night with lower rates when loads are lower. PV is generally favored by this type of rate structure because they offset the most expensive power during the afternoon. However, the higher rates of usage must be during the time when solar panels make power.
Ex) Mid Carolina Electric Co-op changed their rate structure to have a peak demand, depending on if it is summer or winter months, but from 6-9am or 4-7pm. These are not peak solar energy generation times. We have another solution for this utility market.
• Seasonal rates: Many utilities have different rates for summer and winter months. PV produces additional cost savings for customers whose summer rates are higher than winter rates.
• Fixed customer charges and other riders: Fixed charges such as customer charges, metering and billing charges, or other fixed charges are not reduced by delivery of energy from a PV system, so they tend to reduce the average value (c/kWh) of the RE energy delivered in terms of utility cost savings. To accurately estimate the utility cost savings, the EPC contractor must analyze time-series data of the estimated PV generation and load, and use the rate schedule to calculate monthly bills with and without PV generation. This calculation must be performed for every hour of the year and is generally accomplished using specialized software, such as the System Advisor Model (SAM), which can automatically download the appropriate rate schedule from the Utility Rate Database (URDB). The URDB contains more than 38,000 rate schedules[MW4] from over 3,740 utility companies.
Site Data
C&I PV systems can be complex and require an extensive amount of site-specific information to be gathered early in the design process. If possible, the full structural and electrical plansets should be procured when mounting on an existing building. For ground mounts a detailed site survey should be performed including soils analysis and proposed utility interconnection location. Relevant information from the following list should be noted on the construction plans submitted for permit application.
Site data to be recorded includes:
Site Information
□ Property and building dimensions
□ Details of any existing easements, restrictions or open permits
□ Photos of building from a variety of angles.
Structural Information (if applicable)
□ Local design wind speed and source of information (e.g., ASCE 7, local AHJ) .
□ Local ground snow load and source of information (e.g., ASCE 7, local AHJ[MW5] )
□ Design roof snow load (indicate any snow load reductions)
□ Roof support system type (e.g., metal truss, wood laminate joist/beam) and dimensions
□ Support member spans and spacings
□ Lumber species and grade (indicate whether identified in field or assumed)
□ Photos of all components of the roof support system.
Roof Information (if applicable)
□ Dimensions, including the depth and height of any parapet walls
□ Locally required minimum roof setback dimensions (from 2012 IFC or local AHJ)
□ Age and type of roof covering (e.g., thermoplastic polyolefin (TPO), built-up asphalt, torchdown). To avoid unnecessary cost to the EPC or the building owner, the roof covering should have sufficient life remaining such that re-roofing is unlikely to be needed during the contract term.
□ Roof construction (e.g., mechanically attached, partly adhered, fully adhered)
□ Decking type and dimension (e.g., ¾” OSB, 8” reinforced concrete, corrugated metal) □ Roof condition (roof covering, decking, and roof framing)
□ Existing equipment locations and drainage path
□ Existing roof warranty (manufacturer and installer) information and original roofer of record
□ Safety or liability considerations such as skylights, pipes, and other trip or fall hazards □ Photos of the entire roof, with close-ups of features, equipment, and existing damage.
Grade Information (if applicable)
□ Soil analysis
□ Environmental impact study
□ Topical graphical information
□ Ground cover information
□ Location of all easements, underground utilities, or other features that could impact system design or installation
□ Photographs of site conditions
□ Identification of outstanding easements or non-disturbance agreements.
Electrical Information
□ Service type and size (e.g., 208/120 V or 480/277 V; wye or delta configuration; location of ground connection)
□ Main service panel details (e.g., make and model, main breaker and busbar ratings, available breaker spaces)
□ Location of other electrical equipment (e.g., sub-panels, transformers, disconnects, gutters)
□ Photos of all electrical equipment
□ Utility meter location.
Potential Locations for New Equipment
□ Inverter(s)/transformer(s)
□ Conduit runs/wire trays/gutters
□ PV modules
□ Disconnects
□ Monitoring equipment.
Production Estimate
There are multiple tools for estimating PV system production, with more options becoming available every year. The key features for a tool include accurate weather data, shading functionality, adjustable system derate factors, component hardware selection, and monthly energy production estimates. It is important to use the same production model for initial design, ongoing performance monitoring and metric reporting, so that the design model can be a baseline for comparison to operating results.
Estimating Tools
Popular tools for production estimates are estimating algorithms like PVWatts or more complex simulating software like PVsyst, PV Complete, Aurora, Helioscope or Energy Pariscope. NREL’s System Advisor Model includes the PVWatts v1 algorithm.
Modeling Tools
Sophisticated modeling software, such as PV Syst, PV Sol, Aurora SIM, and PV SAM, should be used to estimate C&I system performance. Software tools should have accuracy validation from an independent third party such as NREL, DNV GL, or Black and Veatch.
The software should include:
□ Module-level performance simulation showing the current-voltage (I-V) curve at module level □ Real equipment electrical characteristics for modules, inverters, and power optimizers (unlike PVWatts, for example)
□ Ability to include multiple types of inverters (micro versus string) as well as module level DC optimization
□ A wire-loss calculator used to model wire losses in long distances[MW6] [MW7]
□ Specific losses should be calculated based on real system design, for example, DC to AC derates, conductor sizes, and other factors as applicable (as opposed to a general loss factor)
□ A soiling/snow study of the local region could be taken before the production is modeled to improve the accuracy of including these losses.
Designing Mounting Systems:
□ Ballasted racking
□ Hybrid racking (ballast and anchors)
□ Anchored racking.
Monitoring
A monitoring system with connectivity (99.5% uptime preferred) to the O&M provider is recommended to support revenue and O&M, including regular performance and availability alerts. It is preferred that the monitoring system be application programming interface (API) compatible with SunSpec Alliance Best Practices in Solar Performance Monitoring guidelines. Data structures should conform to SunSpec Alliance’s SunSpec Plant Information Exchange document to support compatibility of the system lifetime. One common standard for monitoring protocols is IEC 61724 – Performance Monitoring[MW8] .
Electrical Components
Additional electrical components such as junction boxes, combiner boxes and ancillary electrical equipment should be subject to the following criteria:
□ IEC 62852 – ultraviolet (UV) exposure for connectors/cables
□ IEC 62790 – UV exposure for junction boxes
□ UL 1565 Wire Positioning Devices
□ National Electrical Manufacturers Association (NEMA) or Ingress Protection (IP) ratings for electrical enclosures.
Permitting and Inspections
The EPC Contractor is responsible for procuring all necessary permits and approvals for PV system construction and inspection. Permitting processes vary based on the project capacity, requirements of the Owner, AHJ, and the utility.
Installation Best Practices
Equipment Best Practices
PV Modules
Regardless of construction type (e.g., metal-framed, frameless, building-integrated, “peel and stick”), care must be taken to comply with all manufacturer instructions concerning the transportation, storage, mounting, grounding, and connecting of the PV modules. Failure to do so could result in voiding of the module warranty, underproduction of the PV system over time, and increased shock- or fire-hazard risk.
Important items to consider when installing the PV modules include:
□ Awareness of any specific mounting location stipulations from the module manufacturer, which may or may not vary based on the potential wind load at the site or proximity to marine environment.
□ Understanding of the different module mounting options, such as bolting the module frame to the mounting structure or clamping the frame with the appropriate hardware and compression force.
□ Appropriate use of fall protection equipment is particularly important during array installation because PV modules tend to be large and unwieldy, presenting elevated risk for installer injury and to workers on the ground if any equipment is dropped. This risk is further exacerbated on steeper roofs.
□ Knowledge of electrical safety protocols, such as ensuring that homerun conductors are not connected during installation to ensure the safety of any personnel wiring electrical equipment.
Mounting Systems
PV modules are typically attached to roofs via purpose-built metal (usually aluminum) mounting systems. Module mounting systems must be listed for the application and capable of withstanding the uplift (due to wind) and downward forces (e.g., snow load) that they could potentially be exposed to, based on the specific location of the installation.
Important items to consider when installing the mounting system include:
□ Appropriate weather sealing of all penetrations of the building envelope.
□ I-codes guidelines on array setbacks (requirements vary based on roof design).
□ Complying with local guidelines when navigating existing vents or equipment on the roof.
□ Layout on roof should provide walkways for firefighter access including areas for laydown of equipment and places for people walking in opposite directions to pass each other.
□ Understanding best practices for working with a given roof covering as per the National Roofing Contractor’s Association Roofing Manual.
□ Balancing customer aesthetics expectations with code requirements and airflow directives from the module or racking manufacturer.
□ Assessment of the roof structure (usually via attic or crawl-space inspection) for lumber type, dimension, and condition.
□ Assessment of the condition of the roof covering. If the roof covering will need replacement before the end of the expected PV system lifetime (20–25 years), the Project Owner should consider roof replacement prior to PV system installation.
□ Using the appropriate size and type of fasteners for the application, and achieving the proper embedment in the substrate.
□ Understanding the cause and effect of inter-row shading in tilted arrays and identifying when such shading may become an issue.
□ Understanding of the span and cantilever limitations of the mounting system.
Work Quality Best Practices
System Grounding and Bonding
Proper grounding and bonding (or earthing and continuity) is a crucial safety element of an installed PV system. Grounding and bonding of PV systems is covered in NEC 690(V), along with many sections of Article 250. There are two forms of PV grounding: system grounding and equipment grounding. An equipment grounding ‘network’ consists of equipment-grounding conductors, a grounding electrode system, and a grounding-electrode conductor. The purpose of the equipment grounding (EG) system is to ensure there is no hazardous voltage between any exposed metal parts of a system and earth. If a system is properly “earthed,” a barefoot person standing on the ground and touching any exposed metal surface of the system will not experience an electrical shock. All metallic equipment (both DC and AC) should be grounded per the requirements of the NEC and equipment manufacturer. This includes metal raceways, enclosures, mounting hardware, module frames, conduit fittings, metal fences, etc. If there is a lightning protection system (LPS) existing on a building, the electric engineer of record should make a determination as to whether, and how, to bond the array EG to the LPS main ground. It is essential that a current-carrying conductor of a PV output circuit is bonded to ground at only one point, as per NEC Article 250 requirements. PV strings with the fuse on the positive side are grounded on the negative side so that if the fuse blows the path to ground is not interrupted. In “bi-polar” systems the reverse will also be true: strings with the fuse on the negative side are grounded on the positive side. Article 690.35 of the NEC allows ungrounded PV systems of any voltage, if conditions are met, particularly groundfault protection (see below). “Ungrounded” systems do not have a bonding connection between a current-carrying conductor of the PV output circuit and ground. They are becoming increasingly common due to lower equipment costs and higher efficiency. Note that the name refers only to the fact that there is no “system ground” (i.e., grounded current-carrying conductor), but that all equipment grounding and bonding requirements do still apply.
DC Ground-Fault Protection (DCGFP)
All PV systems now incorporate DC ground-fault protection (GFP), as required by the NEC. The two types of GFP are 1) directly fused (reference grounded) or 2) differential “residual” current sensors. A third type of GFP is a combination of both, depending on the grounding application. For separated (isolated DC/AC) systems, a residual current device (RCD) is essential to measure the difference in polarity currents (leakage) because there is no singular fault path to earth to monitor. Grounded DC system inverters typically still use a fuse between the grounded pole and earth that blows when more than an amp or more flows through the common bond between them. Sometimes the fuse is paralleled with an RCD to signal the inverter when fault current is first sensed, in an attempt to disconnect the DC input as quickly as possible and possibly avert a blown fuse. A particular hazard still exists for systems using inverters with the “directly fused” ground fault detection and interruption (GFDI) protection, which many inverters still incorporate (see Solar America Board for Codes and Standards’ [Solar ABC’s] Ground Fault Detection Blind Spot for details). The situation of having a blown (open) GFDI fuse, with no defined path for any fault current to earth, can have severe consequences for the safety of personnel, structures, and equipment. The industry is gradually moving away from fused ground fault detectors and toward differential RCDs that do not open the path to earth (as with “ungrounded” inverters).
DC Arc-Fault Circuit Protection (DCAFP)
Arc-fault circuit protection, which is now required by the 2014 NEC for all systems 80VDC or more, should safely extinguish any series arcing faults resulting from a loose or broken connection in a PV source or output circuit. These devices open the faulted circuit at some point to interrupt arcing current across the faulty connection. Note that these devices do not detect or interrupt “parallel” arc-faults, which occur between two current-carrying wires or connections of opposite polarity. Arc fault detection and interruption is recommended even if not required by the AHJ due to the safety benefits.
Rapid Shutdown of PV Systems on Buildings
2014 NEC requires that all PV systems installed in or on buildings include a rapid shutdown function to. The DC section of a PV system can still be energized during an emergency, even if the inverter has been shut down. The rapid shutdown function protects first responders. For reference, a building is defined by NEC as a structure that stands alone or is adjacent to other structures but separated by a fire wall. This definition includes any structure, such as canopies, or even a pole, billboard, sign, or water tower.
Marking (Labeling) Best Practices
Strict conformance to system marking (or labeling) requirements of PV systems and their components is crucial for the safety of operators, service personnel, emergency responders and others. PV system general labeling requirements are covered in NEC 2014 690 Chapter VI, as well as specific accompanying requirements throughout Articles 690 and 705. All required and desired labeling language should be included in the design drawings.
Electrical equipment and components used in PV systems have markings identifying the manufacturer, size, type, ratings, hazard warnings, and other specifications. Equipment markings should never be removed, and all equipment markings must be durable for the environment in which the equipment is installed. Markings must be visible or easily accessible during and after installation. Field-applied markings are required for certain components and for the inclusive PV system. These markings must be designed to withstand the environment in which they are installed (e.g., “UV rated” for outdoor labels) and permanently affixed to the respective equipment in a manner appropriate for the environment and compatible with the substrate materials. Field-applied markings are required on many types of equipment and components, including (but not limited to) conductors, connectors, conduits, disconnecting means, point of utility connection, as well as special markings for bi-polar arrays, ungrounded arrays, battery storage systems, standalone inverters providing a single 120-volt supply, and other marking as required by codes and local AHJ requirements. One common mistake to avoid is to use combiner boxes that are labeled as negative ground in a bi-polar system in a location that is actually positive ground, or to re-label one that is supplied as negative ground to positive ground with labels or markers that are not permanent.
Mechanical Components
Though a PV system’s purpose is electrical in nature, it is very important that the components are mechanically installed in a manor appropriate for the local environment. This holds true for all types of installations, but is particularly important for rooftop installations due to the load forces they may be exposed to (e.g., wind and snow), and the potential damage to life or property that could occur if mechanical connections were to fail.
Systems with Module-Level Power Electronics
For future O&M purposes, the serial numbers of module-level power electronics (e.g., power optimizers, microinverters) should be mapped during installation (e.g., Enphase installation guide). There are numerous technology solutions to capturing equipment barcode information through mobile technology.
Additional resources:
• International Building Code Section 1504
• PV Racking and Attachment Criteria for Effective Asphalt Shingle Roof System Integration
• A Guide to Photovoltaic (PV) System Design and Installation
• Field Inspection Guidelines for PV Systems
• Photovoltaic Power Systems, 2005 National Electric Code: Suggested Best Practices
• Southwest Technology Development Institute, Codes and Standards Resources
• NABCEP Photovoltaic (PV) Installer Resource Guide
• Best Practices for Solar Photovoltaic Installations – Renewable Energy Vermont Partnership Program
• IEC 62446 Commissioning Standard
• Green Job Hazards: Solar Energy
• Solar Construction Safety.
System Documentation
EPCs should store basic Project Owner and system information for the term of the initial customer agreement. Data naming methodology should follow the SunSpec Data Dictionary. Outlining the minimum documentation that should be provided for grid-tied PV systems will ensure transparency to investors of basic system components, information on design and installation, and O&M requirements. Additional data representing the consumer credit worthiness are not included in this list.
Required Site Data Points
□ Plant identifier
□ Site owner name
□ Site owner address
□ Site owner city
□ Site owner state
□ Site owner zip code
□ Site owner phone number
□ Site owner email address
□ Activation date
□ Individual PV system boundaries for buildings that have more than one system.
Required System Design Data
□ Design model
□ Installed DC capacity
□ Derate factor
□ Nominal power rating
□ Module manufacturer
□ Module model
□ Module units
□ Inverter manufacturer
□ Inverter model
□ Inverter units
□ Racking manufacturer(s)
□ Racking model(s)
□ Wiring layouts:
o Wiring of modules into strings; strings into combiner boxes; combiner boxes into re-combiner boxes; disconnects; source circuits into inverter. Wiring layouts help personnel locate the origin of faults.
As-Built Photograph Inventory The EPC Contractor shall maintain a photograph inventory of all active systems. Photographs may be captured through the installation EPC Contractor, third-party inspector, or in-house personnel. A photograph inventory allows the provider to have a strong understanding of onsite conditions and overall level of quality. A photograph inventory will reduce O&M costs. Photographs shall be stored through the life of the service contract and retrievable through Customer/Address query. Electronic capture and cataloguing of site information is preferred to ensure consistency and accuracy. Mandatory photographs include at least one onsite photo of each system component outlined in Table 1.
Table 1. Required System Photographs[MW9]
- Roof (array)
- Balance of System
- Site Address
- Confirmation
- Overall Array
- Under Array
- Array Horizon (shading)
- Module Nameplate
- Conduit Runs and Support Junction Box Locations
- Junction Box
- Interior Wire Management
- Flashing of roof penetrations
- DC Disconnect location and interior Inverter Location
- Inverter
- Nameplate AC
- Disconnect location and interior Main service panel (cover open)
- Main service panel (cover closed)
- Connection to premise’s grounding system
- Production meter
- Monitoring system
- Net meter
- Vegetation and other shading objects
- EPC Submittal Information Copies of additional key information should be provided to the system owner and stored through the duration of the service agreement.
Electrical Design
□ Company name
□ Company address
□ Company phone number, email, website
□ Contact person (contact name, address, phone number)
□ Structural/mechanical design (if provided by mounting equipment manufacturer, list manufacturer information).
PV Installer (If more than one company, list for each and note company roles)
□ Company name
□ Company address
□ Company phone number, email, website
□ Contact person (contact name, address, phone number).
Electrical Design
Documentation at minimum, a one-line or three-line wiring diagram that includes:
□ General specifications
□ String diagram
□ 3-line diagram
□ Electrical details/inverter information
□ Grounding/overvoltage protection
□ AC system specification
□ Equipment data sheets
□ Warranty information
□ Installation manuals
□ O&M manuals
□ Test results/commissioning (Cx) data.
Third-Party Inspection and Verification
Field Inspection Verification
EPC Contractors should verify and measure installed asset quality through a continuous process of third-party field inspection verification (FIV) of the EPC Contractor’s completed systems. For purposes of this document, a third-party inspector means any technically qualified entity that was not directly involved in the installation or system design process. The third-party inspector can be part of the installation company (e.g., part of the O&M division) or an entirely separate entity. The FIV process includes onsite inspections of completed system installations to verify the systems have been installed to equipment manufacturer specifications, relevant codes, and installation best practices. This process is essential to the checks and balances of solar as an asset class.
• To ensure an objective process, the inspector(s) should be a third-party provider, not involved in the design or installation of the inspected system(s)
• Data collected by the FIV are subject to approval by the EPC Contractor and may be modified by the EPC Contractor upon review
• FIV results should be shared with the EPC Contractor for a continuous improvement process for installation quality.
Third-Party Inspector Qualifications
The third-party inspector should have at least one of the following professional certifications and have specific knowledge of solar PV design and installation.
□ NABCEP Certified Installer
□ UL Certified PV System Installer
□ Licensed Professional Engineer
□ Licensed Electrician
□ ICC Certified Electrical Inspector and/or Plans Examiner
□ Equivalent proprietary training programs.
All inspectors shall have a minimum OSHA 10-hour certification and applicable skills (climbing and carrying ladder, walking on roof surface, etc.) to perform an objective inspection.
Scoring System
The FIV will also result in a system quality scoring metric that can be used as a single quality assessment of the initial installation. The scoring system should numerically quantify the level of risks associated with the safety and performance of the system.
• Pass/Fail – For each inspection, a report shall be issued that summarizes the issues identified and provides the EPC Contractor with a list of deficiencies requiring corrective action. The report shall also include the overall QA score.
• Define System Components – The sample breakout includes inverter, models, conduit/junction box, AC disconnects, DC disconnects, PV system labeling, grounding/bonding, wire management, roof conditions, flashing, shading, and system layout.
Interconnection
Before a PV system is allowed to operate legally, the appropriate utility provider must approve the system for operation. Similar to PV permitting, PV interconnection requirements vary around the country but are generally based on one or a combination of the following major interconnection standards:
• FERC’s Small Generator Interconnection Standards (SGIP)
• California’s Rule 21
• IREC’s Model Interconnection Standards
• The Mid-Atlantic Demand Resource Initiative procedures (MADRI).
The interconnection of a distributed generation system such as a PV system with the local utility depends upon state regulations and utility policies and practices. Interconnection guidelines and state- and utility-specific rules can usually be accessed by installers through utility websites. Contractual aspects of interconnection include fees, metering requirements, billing arrangements, and size restrictions on the system. Understanding the local utility’s requirements is a very important process. In addition, national and local codes have interconnection and system equipment and labeling requirements so that the system can be easily identified and/or shut off. For example, some states or utilities require an easily accessible external disconnect switch. The NEC governs how the output of a PV system can be connected to the utility in Article 705. The two relevant connections would be: 1. Supply side (similar to installing another service onsite and usually found on larger installations) 2. Load side (most commonly used for smaller systems and requires a dedicated circuit breaker or overcurrent device with the sum total of overcurrent devices supplying the busbar should not exceed 120% of the busbar rating for commercial applications as per 2014 NEC 705.12(D)(2)). Before investing in a solar PV system, it is wise to apply for interconnection approval as early in the process as possible. This allows added costs or barriers to be factored into the decision to install at a particular location; it can impact decisions about system design. With PV market penetration increasing, there are emerging issues around the need for transformer or other equipment upgrades on local circuits and the question of who pays for this. In the case of nonresidential systems, even more equipment and local circuit considerations may arise, making it unfeasible to install a system at a particular location or at the intended size. These factors can change the economics of a project and should be identified as early as possible. Further details on interconnection requirements can be found on the Database of State Incentives for Renewable Energy. Additional information on interconnection requirements can be found on the Freeing the Grid website. • IEEE 1547 Series of Interconnection Standards
O&M Best Practices
Solar PV Operations, Maintenance, and Monitoring (OM&M)
The ongoing operation, monitoring and maintenance of a solar PV generating system throughout its lifespan is absolutely critical to keeping the system running, achieving optimal performance and realizing the expected rate of return. The OM&M requirements and plan need to be roughly defined during the design phase of the project so they can be adequately budgeted and included in the energy production and financial models. All instrumentation should be designed and installed as part of the larger PV system. Production models typically assume a system availability of at least 99% of daylight hours, which equals less than two days of total downtime during the year–including scheduled maintenance. Meeting these uptime requirements can be very difficult unless the system is properly designed and carefully operated, monitored, and maintained. Solar PV operations, procedures, and maintenance best practices are still evolving and new tools are becoming available for improving the quality of maintenance inspections and testing. Monitoring systems also continue to advance and provide ever more detailed data on the system’s operation and performance, some even down to the individual module level (as in optimizers and microinverters). The administrative effort required to keep track of warranty paperwork, recruit and contract with service providers and suppliers can be considerable and should be included in the initial planning. Similarly, reviewing performance information and plan O&M activities should be included as part of the OM&M plan. As outlined in the Electric Power Research Institute’s (EPRI’s) Addressing Solar Photovoltaic Operations and Maintenance Challenges (EPRI 2010), there are several different approaches and strategies for solar PV O&M, each attempting to reduce costs while improving availability and increasing productivity. The three major approaches identified are:
• Preventive maintenance (PM)
• Corrective/reactive maintenance (RM)
• Condition-based maintenance (CBM).
Performance Guarantee with O&M Agreement – if system does not produce within 10% of annual estimated output, additional panels will be installed after a thorough inspection of existing equipment is completed and no issues exist.
Depending on who is responsible for system maintenance, the value of productivity, accessibility to the site, and many other factors, any one (or even a combination) of these approaches may be appropriate. Every system must be evaluated and cost-benefit tradeoffs for the different approaches analyzed to determine how best to proceed. In 2010, EPRI gathered anecdotal data for direct O&M costs for both in-house and outsourced approaches from several installers of systems of 1 MW and less. They ranged from $6/kW to $27/kW of rated capacity, and from <1% to 5% of the “all in” cost of the complete project. Scheduled comprehensive maintenance visits are usually required at least annually, sometimes semi-annually, or even quarterly—particularly at sites that often need the modules cleaned or weeds pulled, etc., to prevent shading and lost solar production. And inverters, despite being solid state devices, may still have cooling systems with fans and filters that need periodic cleaning and occasional replacement. Close monitoring of the AC output versus DC input of an inverter helps determine if there may be a problem, and it is possible for inverters to fault or even fail while still under warranty. Inverter manufacturers typically offer a range of extended warranties beyond the 10–12 year industry standard, which need to be carefully assessed for cost versus benefits by an experienced designer or installer. Some of the newer maintenance test procedures that have been instituted recently due to the availability of proper test equipment are thermographic imaging of modules and individual string tests[MW10] , including insulation resistance. Both of these tests can fairly quickly point out faults and trouble spots in a PV array that need attention. String testing data can also be compared from year to year to give an indication of the average degradation of module power to determine if the modules are still producing within their warranted power range (typically 80% of original rated capacity after 25 years).
PV System Warranty
Warranties for both work quality and products are an essential and integral component to the O&M program. Work quality warranties must clearly define what constitutes a required repair or replacement, whether it’s critical or non-critical, who is responsible for equipment replacement, labor and shipping costs, and response timeliness. Warranty coverages for modules and inverters usually have very clear terms and conditions for proper installation, operation and maintenance, and must be followed to the letter for the warranty to remain in effect. The detailed requirements of all equipment warranties must be understood and enforced by the commissioning authority during installation and final commissioning to assure full coverage is maintained.
Solar PV System Commissioning
The process of commissioning (Cx) PV systems has evolved into a comprehensive program that typically includes not only the EPC Contractor’s testing and inspections by their Cx authority but often full oversight and QA of an entire project by an independent, third-party consultant. Commissioning is the link between the EPC contractor and the operator. Documentation of the system, array testing, and whole-system performance test (as applicable to commercial, industrial, and field systems) should be performed as defined in IEC 62446: Grid Connected Photovoltaic Systems-Minimum Requirements for System Documentation, Commissioning Tests, and Inspections (2009). Ideally, Cx begins with the basis of design, continuing through construction and final acceptance testing, and sometimes beyond (retro-Cx, on-going Cx). It is best directed by an independent owner’s engineer (OE), usually an experienced consultant who works directly for, and represents only the interests of, the owner. The OE typically oversees the EPC Contractor’s Cx authority and plays an advisory role throughout the life of a project to assure a quality installation. The cost for an OE to fully oversee and commission a PV project can vary between 2%–3% (or more) of the total project cost, depending on the specific application and complexity of the installation. It can be advantageous and preferable to spend more up front, to get the project clearly defined and designed correctly, thus avoiding very costly and difficult mid-stream changes during procurement and construction. The Cx process follows a general path of design review, construction inspections, start-up and acceptance (functional) testing, and final performance testing. The final Cx report should include all design reviews, issue logs, inspection and testing data, and the OM&M plan. Performance Guarantees, if any, shall be clearly defined along with the responsibility for on-going monitoring of the system and enforcement of the contract.
System Monitoring
SunSpec PV Performance Metrics and IEC 61724 describe the basic data required for reporting standard PV performance metrics, including energy performance index and availability[MW11] . The monitoring system used should be capable of collecting this information.
[MW1]Ask John
[MW2]AVISTA: As part of our maintenance program, we have a scheduled recap on the previous year’s production and will continue to provide this annually
[MW3]Ask how Powerpods can effect peak demand charges
[MW4]Research this database; open to the public or must pay?
[MW5]Find a structural engineer- JDS???
[MW6]Make sure I get the binder back from hemphill
[MW7]AVISTA
[MW8]KYLE BLACK
[MW9]BOTH WARREN SOLAR AND HEMPHILL MUST HAVE DAILY PHOTOS LOGGED
[MW10]AVISTA
[MW11]AVISTA
