Revised March 2006
Dated February 2005
ELECTRONIC VERSION 1.3
Dated March 1, 2006
Photovoltaic Power Systems
2005 National Electrical Code:
Southwest Technology Development Institute
New Mexico State University
PO Box 30001, MSC 3 SOLAR
Corner of Research Drive and Sam Steel Way
Las Cruces, NM 88003
suggested practices manual examines the requirements of the 2005
National Electrical Code (NEC) as they apply to photovoltaic (PV) power
systems. The design requirements for the balance-of-systems
components in a PV system are addressed, including conductor selection
and sizing, overcurrent protection device rating and location, and
disconnect rating and location. PV array, battery, charge
controller, and inverter sizing and selection are not covered, as these
items are the responsibility of the system designer, and they in turn
determine the items in this manual. Stand-alone, hybrid, and
utility-interactive PV systems are all covered. References are
made to applicable sections of the NEC.
Code® and NEC ® are registered trademarks of the National Fire
Protection Association, Inc., Quincy, Massachusetts 02269
people throughout the photovoltaic industry and the electrical
inspector community reviewed the earlier editions of this manual and
provided comments that are incorporated in this edition. The
author sends heartfelt thanks to all who have supported the efforts to
improve and expand the document. With inputs from all involved,
each succeeding edition is progressively more detailed and
complete. Ward Bower at Sandia National Laboratories deserves
special thanks for his dedicated and continuing support and review of
this document. Ronald Donaghe, Southwest Technology Development
Institute, performed document editing and layout.
TECHNICAL COMMENTS TO:
John C. Wiles
Southwest Technology Development Institute
New Mexico State University
P.O. Box 30001/MSC 3 SOLAR
Corner of Research Drive and Sam Steel Way
Las Cruces, New Mexico 88003-0001
Phone: 505-646-6105 FAX 505-646-3841 e-mail: email@example.com
Copies may be downloaded from the PV and Codes links on the SWTDI/NMSU
web site at http://www.nmsu.edu/~tdi
document is intended to contribute to the widespread installation of
safe, reliable PV systems that meet the requirements of the National
This guide provides
information on how the 2005 National Electrical Code (NEC) applies to
photovoltaic systems. The guide is not intended to supplant or replace
the NEC; it paraphrases the NEC where it pertains to photovoltaic
systems and should be used with the full text of the NEC. Users of this
guide should be thoroughly familiar with the NEC and know the
engineering principles and hazards associated with electrical and
photovoltaic power systems. The information in this guide is the best
available at the time of publication and is believed to be technically
accurate. Application of this information and results obtained are the
responsibility of the user.
In most locations, all electrical
wiring including photovoltaic power systems must be accomplished by, or
under the supervision of, a licensed electrician and then inspected by
a designated local authority. Some municipalities have additional codes
that supplement or replace the NEC. The local inspector has the final
say on what is acceptable. In some areas, compliance with the NEC is
NATIONAL FIRE PROTECTION ASSOCIATION (NFPA) STATEMENT
National Electrical Code including the 2005 National Electrical Code is
published and updated every three years by the National Fire Protection
Association (NFPA), Batterymarch Park, Quincy, Massachusetts 02269. The
National Electrical Code and the term NEC are registered trademarks of
the National Fire Protection Association and may not be used without
their permission. Copies of the current edition of the National
Electrical Code and the National Electrical Code Handbook are available
from the NFPA at the above address, most electrical supply
distributors, and many bookstores.
Table of Contents
for ease of browsing this entire document, use the links in the Table
of Contents. To return, hit the back button on your browser. You can
also use the "find" function in the browser to go to each occurrence of
a word or phrase.|
SUGGESTED PRACTICES 1
Methods of Achieving Objectives 3
Scope and Purpose of the National Electrical
This Guide 5
Longevity, Materials, and Safety 5
Testing and Approval 6
Photovoltaic Modules 7
Module Marking 7
Conductor Color Codes 18
Module Interconnections 9
Tracking Modules 10
Transition Wiring 13
Module Connectors 15
Module Connection Access 15
PV Array Ground-Fault Protection 18
PV Array Installation and service 19
Size of DC Grounding Electrode
Point of Connection 21
Unusual Grounding Situations 23
Charge Controllers—System Grounding 24
Ungrounded Systems 25
Equipment Grounding 25
Inverter AC Outputs 26
PV Inverters Create Separately Derived Systems 26
AC Grounding 27
DC Grounding 27
Backup Generators 28
Conductor Ampacity 31
Suggested AC Grounding 29
Grounding Electrode 29
Stand-Alone Systems—Inverters 33
Overcurrent Protection 33
Ampere Rating 34
Disconnecting Means 41
Branch Circuits 37
Amperes Interrupting Rating (AIR)—Short-Circuit
Fusing of PV Source Circuits 39
Current-Limiting Fuses—Stand-Alone Systems 40
Current-Limiting Fuses—Utility-interactive Systems 41
Fuse Servicing 41
Photovoltaic Array Disconnects 42
Panelboards, Enclosures, and Boxes 47
PV DISCONNECT LOCATION 42
Equipment Disconnects 43
Battery Disconnect 44
Charge Controller Disconnects 46
Ungrounded Systems 47
Multiple Power Sources 47
Hydrogen Gas 48
Battery Rooms and Containers 49
Acid or Caustic Electrolyte 49
Electric Shock Potential 50
Battery and other large Cables 50
Charge Controllers 52
Stand-Alone Distribution Systems 53
Interior DC Wiring and Receptacles 56
AC PV Modules 61
Smoke Detectors 58
Ground-Fault Circuit Interrupters 58
Interior Switches 58
Multiwire Branch Circuits 59
System Labels and Warnings 62
Photovoltaic Power Source 62
Multiple Power Systems 62
INTERACTIVE SYSTEM POINT OF INTERCONNECTION 62
Switch or Circuit Breaker 62
APPENDIX A: Sources of Equipment Meeting the
The National Electrical Code A-1
APPENDIX B: PV Module Operating Characteristics Drive
NEC Requirements B-1
DC-RATED FUSES A-2
ENCLOSURES AND JUNCTION BOXES A-4
APPENDIX C: Utility-Interactive
UNSPECIFIED DETAILS B-2
NEC REQUIREMENTS BASED ON MODULE PERFORMANCE B-2
Additional NEC Requirements B-3
APPENDIX D: Cable and Device Ratings at High
PV Source-Circuit Conductors C-3
Overcurrent Devices C-3
Backfed Circuit Breakers, The National Electrical Code and UL
Utility-Interactive PV Systems C-3
Blocking Diodes C-5
Surge Suppression C-6
Equipment Ratings D-1
APPENDIX E: Example Systems E-1
NEC VOLTAGE Limitation D-4
Voltage Remedies D-4
Cable Sizing and Overcurrent
APPENDIX F: DC Currents on Single-Phase Stand-alone
APPENDIX G: Grounding PV Modules G-1
H: PV Ground Fault Protection Devices and The
National Electrical Code, Section
APPENDIX I: Selecting Overcurrent Devices and
Conductors in PV Systems I-1
APPENDIX J: Module series fuse
PV Modules and the Series Overcurrent
K: Flexible, Fine-Stranded Cables: Incompatibilities
with Set-Screw Mechanical Terminals and Lugs K-1
APPENDIX L: Ungrounded PV Systems
APPENDIX M: Service Entrance Conductor Taps for
Utility-Interactive Inverter Systems M-1
INDEX 1 [Not available in the html version]
Distribution List 1 [Not available in the html version]
List of Figures
Figure 1|| Warning Label||6|
|Figure 2||Label on Typical PV Module||8|
|Figure 3||Strain Reliefs||9|
|Figure 4||Terminal Crimping Tools||12|
|Figure 5||Crimp Terminals/Lugs||12|
|Figure 6||Mechanical Terminals||13|
|Figure 7||PV Combiner with Circuit Breakers||14|
|Figure 8||Common Splicing Devices||16|
|Figure 9||Module Interconnect Methods||17|
|Figure 10||Typical System: Possible Grounding Conductor Locations||22|
|Figure 11||Utility-Interactive Inverter with Internal
DC Bonding Point, GFPD, and Connection Point for Grounding Electrode Conductor||23|
|Figure 12||External Ground-Fault Protection Device||28|
|Figure 13||Example Grounding Electrode System||30|
|Figure 14||Typical Array Conductor Overcurrent Protection (with Optional Subarray Disconnects)||35|
|Figure 15||Listed Branch-Circuit Rated
|Figure 16||Recognized (left) and listed (right) DC
|Figure 17||Listed Supplementary (left) and Branch
|Figure 18||Unacceptable Automotive Fuses (left) and
Unacceptable AC Fuses (right) ||38|
|Figure 19||Small System Disconnects||45|
|Figure 20||Separate Battery
|Figure 21||Charge Controller
|Figure 22||Disconnects for Remotely Located Power
|Figure 23||Typical Charge
|Figure 24||12-Volt DC Load Center||55|
|Figure 25||12-Volt DC Combining Box and Load
|Figure 26||NEMA Plug Configurations||57|
|Figure 27||Diagram of a Multiwire Branch
|Figure C-1||400 Amp Panel – Commercial PV
|Figure D-1||Typical Bipolar System with
|Figure E-1||Direct Connected System||E-4|
|Figure E-2||Direct-Connected PV System with Current
|Figure E-3||Stand-Alone Lighting
|Figure E-4||Remote Cabin DC-Only
|Figure E-5||Small Residential Stand-Alone
|Figure E-6||Medium Sized Residential Hybrid
|Figure E-7||Roof-Top Utility-interactive
|Figure E-8||Center-Tapped PV
|Figure E-9||Utility-Interactive Three-Inverter
|Figure F-1||Inverter Current Waveform (dc
|Figure G-1|| ILSCO GBL4-DBT Lug||G-2|
|Figure G-2||Improper Module
|Figure H-1||Ground-Fault Current
|Figure K-1|| Examples of Mechanical
|Figure K-2||Destroyed Mechanical Termincal From PV System||K-2|
|Figure K-3||Typical Compression Lug||K-3|
2005 NATIONAL ELECTRICAL CODE
most portions of the National Electrical Code apply to all
power systems, including photovoltaic power systems, those listed below
are of particular significance.
||Requirement for Electrical
||Use and Identification of
||Grounding and Bonding
||Conductors for General
Types NM, NMC, and NMS
||Power and Control Tray
Cable: Type TC
Types SE and USE
||Underground Feeder and
Branch-Circuit Cable: Type UF
||Rigid Nonmetallic Conduit:
Nonmetallic Conduit: Type LFNC
||Flexible Cords and Cables
||Switchboards and Panelboards
||Equipment, Over 600 Volts,
||Solar Photovoltaic Systems
Power Production Sources
||Circuits and Equipment
Operating at Less Than 50 Volts
|Ch 9, Table 8
||Conduit and Tubing Fill
Tables for Conductors and Fixture Wires of the Same Size
- SAFE, RELIABLE, DURABLE PHOTOVOLTAIC POWER SYSTEMS
- KNOWLEDGEABLE MANUFACTURERS, DESIGNERS, DEALERS,
INSTALLERS, CONSUMERS, AND INSPECTORS
- WIDESPREAD DISSEMINATION OF THESE SUGGESTED PRACTICES AND
KNOWLEDGE OF THE NEC
- TECHNICAL INTERCHANGE AMONG INTERESTED PARTIES
National Fire Protection Association has acted as sponsor of the
National Electrical Code (NEC) since 1911. The original
was developed in 1897. With few exceptions, electrical power systems
installed in the United States in the 20th and 21st centuries have had
to comply with the NEC. This compliance requirement applies to most
permanent installations of photovoltaic (PV) power systems. In 1984,
Article 690 Solar Photovoltaic Systems, which addresses safety
requirements for the installation of PV systems, was added to the Code.
This article has been updated and expanded in each edition of the NEC
Many of the PV systems in use and being installed
today may not be in compliance with the NEC and other local codes.
There are several contributing factors to this situation:
|Factors that have reduced local
and NEC compliance
The PV industry has a strong “grass roots,”
faction that is not fully aware of the dangers associated with
low-voltage and high-voltage, direct-current (dc) and
alternating-current (ac) electrical power systems.
Electricians and electrical inspectors have not had
experience with direct-current portions of the Code or PV power systems.
The electrical equipment industries do not advertise
distribute equipment suitable for dc use that meets NEC requirements.
Popular publications present information to the
public that implies
that PV systems are easily installed, modified, and maintained by
manufacturers have, in some cases, been unable to afford the costs
associated with testing and listing by approved testing laboratories
like Underwriters Laboratories (UL), Canadian Standards Association
(CSA) or ETL, Inc.
and dealers in many cases have not had significant training or
experience installing ac residential and/or commercial power systems.
PV installers in the United States are licensed electricians or use
licensed electrical contractors and are familiar with all sections of
the NEC. These installer/contractors are trained to install safe and
more reliable PV systems that meet the NEC and minimize the hazards
associated with electrical power systems. On the other hand, some PV
installations have numerous defects that typically stem from
unfamiliarity with electrical power system codes or unfamiliarity with
dc currents and power systems. These installations often do not meet
the requirements of the NEC. Some of the more prominent problems are
• Improper ampacity of conductors
• Improper types of conductors
• Improper or unsafe wiring methods
• Lack of or improper overcurrent
protection on conductors
• Inadequate number and placement of
• Improper application of listed
• No, or underrated, short-circuit or
overcurrent protection on battery circuits
• Use of non-listed components when
listed components are available
• Improper system grounding
• Lack of, or improper, equipment
• Use of underrated hardware or
• Use of ac components (fuses and
switches) in dc applications
NEC generally applies to any PV power system, regardless of size or
location. A single, small PV module may not present a significant
hazard, and a small system in a remote location may present few safety
hazards because people are seldom in the area. On the other hand, two
or three modules connected to a battery can be lethal if not installed
and operated properly. A single deep-cycle storage battery (6 volts,
220 amp-hours) can discharge about 8,000 amps into a
terminal-to-terminal short-circuit. Systems operate with voltages
ranging from 12 volts to 600 volts or higher and can present shock
hazards. Short circuits, even on lower voltage systems, present fire
and equipment hazards. Storage batteries can be dangerous; hydrogen gas
and acid residue from lead-acid batteries, although not NEC-specific,
need to be dealt with safely.
The problems are compounded
because, unlike with ac systems, there are few listed components that
can be easily “plugged” together to result in a safe PV
system. The available PV hardware does not have mating inputs or
outputs, and the knowledge and understanding of “what works with
what” is not second nature to the installer. The dc PV
“cookbook” of knowledge does not yet exist.
To meet the objective of safe, reliable, durable photovoltaic power
systems, the following suggestions are offered:
Dealer-installers of PV systems should become
familiar with the NEC
methods of and requirements for wiring residential and commercial ac
All PV installations should
be permitted and inspected, where required, by the local inspection
authority in the same manner as other equivalent electrical systems.
Photovoltaic equipment manufacturers should build
equipment to meet UL
or other recognized standards and have equipment tested and listed.
Listed subcomponents should be used in
field-assembled equipment where
formal testing and listing is not possible.
Electrical equipment manufacturers should produce,
advertise, listed, reasonably priced, dc-rated components.
Electrical inspectors should become familiar with dc
and PV systems.
The PV industry should educate the public, modify
encourage all installers to comply with the NEC.
Existing PV installations should be upgraded to
comply with the NEC and other minimum safety standards.
PURPOSE OF THE NATIONAL ELECTRICAL CODE
local inspection authorities use regional electrical codes, but most
jurisdictions use the National Electrical Code–sometimes with
slight modifications. The NEC states that adherence to the
recommendations made will reduce the hazards associated with electrical
installations. The NEC also says these recommendations may not lead to
improvements in efficiency, convenience, or adequacy for good service
or future expansion of electrical use [90.1]. (Numbers in brackets
refer to sections in the 2005 NEC.)
The National Electrical Code
addresses nearly all PV power installations, even those with voltages
of less than 50 volts . It covers stand-alone and
utility-interactive systems. It covers billboards, other remote
applications, floating buildings, and recreational vehicles (RV)
[90.2(A), 690]. The Code deals with any PV system that has external
wiring or electrical components that must be assembled and connected in
the field and that is accessible to the untrained and unqualified
There are some exceptions. The National Electrical
Code does not cover PV installations in automobiles, railway cars,
boats, or on utility company properties used for power generation
[90.2(B)]. It also does not cover micro-power systems used in watches,
calculators, or self-contained electronic equipment that have no
external electrical wiring or contacts.
Article 690, Solar
Photovoltaic Systems of the NEC specifically deals with PV systems, but
many other sections of the NEC contain requirements for any electrical
system including PV systems [90.2, 720]. When there is a conflict
between Article 690 of the NEC and any other article, Article 690 takes
The NEC suggests (in some cases requires),
and most inspection officials require, that equipment identified,
listed, labeled, or tested by an approved testing laboratory be used
when available [90.7, 100, 110.3]. The three most commonly encountered
national testing organizations commonly acceptable to most
jurisdictions are the Underwriters Laboratories (UL), Canadian
Standards Association (CSA) and ETL Testing Laboratories, Inc. (ETL).
Underwriters Laboratories and UL are registered trademarks of
Underwriters Laboratories Inc. ETL is a registered
trademark of ETL Testing Laboratories, Inc. CSA is a registered
trademark of the Canadian Standards Association.
and electrical inspectors expect to see a listing mark (UL, CSA, ETL)
on electrical products used in electrical systems in the United States.
This listing requirement presents a problem for some in the PV
industry, because low production rates may not justify the costs of
testing and listing by UL or other laboratory. Some manufacturers claim
their product specifications exceed those required by the testing
organizations, but inspectors readily admit to not having the
expertise, time, or funding to validate these unsubstantiated claims.
recommended installation practices contained in this guide progress
from the photovoltaic modules to the electrical outlets (in a
stand-alone system) or to the utility interconnection (in a
utility-interactive system). For each component, NEC requirements are
addressed, with the appropriate Code sections referenced in brackets. A
sentence, phrase, or paragraph followed by a NEC reference refers to a
requirement established by the NEC. The words “will,”
“shall,” or “must” also refer to NEC
requirements. Suggestions based on field experience with PV systems are
worded as such and will use the word “should.” The
recommendations apply to the use of listed products. The word
“Code” in this document refers to the 2005 NEC.
In some places references will also be made to Article 690 from the
2002 NEC that have been significantly changed in the 2005 NEC.
recent times, monetary incentives have resulted in large numbers of
utility-interactive PV systems being installed. While most of
these systems are purely grid-tied, many have batteries included to
provide energy during blackouts, and some even include
generators. With these added features, there are many
similarities between the code requirements for utility-interactive
systems and stand-alone systems. In this suggested practices
manual, the code requirements are addressed at the component level and
at the interconnection level between components. Where unique
requirements apply, they are addressed as they relate to a particular
system. Appendices provide additional details.
provides a limited list of sources for dc-rated and identified, or
listed, products, and references to the products are made as they are
Other appendices address details and issues associated with
implementing the NEC in PV installations. Examples are included.
MATERIALS, AND SAFETY
PV modules are warranted for power output for periods from 10-25 years,
they can be expected to deliver dangerous amounts of energy (voltage
and current) for periods of 40 to 50 years and longer. The
warning on the back of PV modules is worth reading and heeding.
See Figure 1. Each and every designer and installer of PV systems
should strive to make the installation as durable and as safe as
possible. The NEC provides only minimal safety requirements and
general guidance on materials, and does not fully address the
durability issues associated with installing electrical systems that
must last for 50 years or longer. The PV module environment is
harsh with temperatures ranging from –50°C to +85°C, very
dry to monsoon moisture conditions, long-term ultraviolet exposure, and
high mechanical loading from winds and ice. The use of materials
tested and listed for outdoor exposure in the outdoor sections of the
system is an absolute safe-practices requirement. Exceeding Code
minimums for materials and installation practices is encouraged to
ensure PV array and system longevity.
Figure 1. Warning Label
TESTING AND APPROVAL
NEC suggests (and in some cases requires), and many inspectors require
that listed devices be used throughout a PV system. A listed device by
UL or other approved testing laboratory is tested against an
appropriate UL standard. A recognized device is tested by UL or other
approved testing laboratory to standards established by the device
manufacturer. In most cases, the requirements established by the
manufacturer are less rigorous than those established by UL. Few
inspectors will accept recognized devices, particularly where they are
required for overcurrent protection. Recognized devices are generally
intended for use within a factory assembly or equipment that will be
further listed in its entirety.
PV module manufacturers offer listed modules. In some cases (building
integrated or architectural structures), unlisted PV modules have been
installed, but these installations should have been approved by the
local authority having jurisdiction (electrical inspector).
electrical information must appear on each module. The information on
the factory-installed label shall include the following items [690.51]:
• Polarity of output terminals or
• Maximum series fuse for module
• Rated open-circuit voltage
• Rated operating voltage
• Rated operating current
• Rated short-circuit current
• Rated maximum power
• Maximum permissible system
Figure 2 shows a typical label that appears on the
back of a module.
not required by the NEC, the temperature rating of the module terminals
and conductors are given to determine the temperature rating of the
insulation of the conductors and how the ampacity of those conductors
must be derated for temperature [110.14(C)]. While module terminals are
usually rated for 90°C, most other terminals throughout the PV
system will have terminals rated only for 60°C or 75°C.
These terminal temperatures may significantly affect conductor
Other critical information, such as
mechanical installation instructions, grounding requirements,
tolerances of indicated values of Isc, Voc and Pmax, and statements on
artificially concentrated sunlight are contained in the installation
and assembly instructions for the module.
Figure 2. Label on Typical PV Module
of connecting wiring to the modules vary from manufacturer to
manufacturer. A number of manufacturers make modules with 48-inch
lengths of interconnection cables permanently connected to the
modules. There are no junction boxes for connection of
conduit. The NEC does not require conduit, but local
jurisdictions, particularly in commercial installations, may require
conduit. The Code requires that strain relief be provided for
connecting wires. If the module has a closed weatherproof junction box,
strain relief and moisture-tight clamps should be used in any knockouts
provided for field wiring. Where the weather-resistant gaskets are a
part of the junction box, the manufacturer’s instructions must be
followed to ensure proper strain relief and weatherproofing [110.3(B),
UL Standard 1703]. Figure 2 shows various types of strain relief
clamps. The one on the left is a basic cable clamp for interior use
with nonmetallic-sheathed cable (Romex) that cannot be used for module
wiring. The clamps in the center (Heyco) and on the right (T&B) are
watertight and can be used with either single or multiconductor
cable—depending on the insert.
Figure 3. Strain Reliefs
conductors are recommended for almost all photovoltaic system wiring
[110.5]. Copper conductors have lower voltage drops and better
resistance to corrosion than other types of comparably sized conductor
materials. Aluminum or copper-clad aluminum wires can be used in
certain applications, but the use of such cables is not
recommended—particularly in dwellings. All wire sizes presented
in this guide refer to copper conductors.
The NEC requires 12
AWG (American Wire Gage) or larger conductors to be used with systems
under 50 volts [720.4]. Article 690 ampacity calculations yielding a
smaller conductor size might override Article 720 considerations, but
some inspectors are using the Article 720 requirement for dc circuits
[690.3]. The Code has little information for conductor sizes smaller
than 14 AWG, but Section 690.31(D) provides some guidance. Many
listed PV modules are furnished with attached 14 AWG conductors.
Type UF (Underground Feeder—Identified (marked) as Sunlight
Resistant), Type SE (Service Entrance), or Type USE/USE-2 (Underground
Service Entrance) cables are permitted for module interconnect wiring
[690.31(B)]. Type UF cable must be marked “Sunlight
Resistant” when exposed outdoors as it does not have the inherent
sunlight resistance found in SE and USE conductors [UL Marking Guide
for Wire and Cable]. Unfortunately, single-conductor, stranded, UF
sunlight-resistant cable is not readily available and may have only a
60°C temperature rating. This 60°C-rated insulation is not
suitable for long-term exposure to direct sunlight at temperatures
likely to occur near PV modules. Such wire has shown signs of
deterioration after four years of exposure. Temperatures exceeding
60°C normally occur in the vicinity of the modules; therefore,
conductors with 60°C insulation cannot be used. Stranded wire
is suggested to ease servicing of the modules after installation and
for durability [690.34].
The widely available Underground
Service Entrance Cable (USE-2) is suggested as the best cable to use
for module interconnects. When manufactured to the UL Standards, it has
a 90°C temperature rating and is sunlight resistant even though not
commonly marked as such. The “-2” marking indicates a
wet-rated 90°C insulation, the preferred rating. Additional
markings indicating XLP or XLPE (cross-linked polyethylene) and RHW-2
(90°C insulation when wet) ensure that the highest quality cable is
being used [Tables 310.13, 16, and 17]. An additional marking (not
required) of “Sunlight Resistant” indicates that the cable
has passed an extended UV exposure test over that normally required by
USE-2. USE-2 is acceptable to most electrical inspectors. The RHH
and RHW-2 designations frequently found on USE-2 cable allow its use in
conduit inside buildings. USE or USE-2 cables, without the other
markings, do not have the fire-retardant additives that SE and
RHW/RHW-2 cables have and cannot be used inside buildings.
more flexible, two-conductor cable is needed, electrical tray cable
(Type TC) is available but must be supported in a specific manner as
outlined in the NEC [336 and 392]. TC is sunlight resistant and is
generally marked as such. Although sometimes used (improperly) for
module interconnections, SO, SOJ, and similar flexible, portable cables
and cordage may not be sunlight resistant and are not approved for
fixed (non-portable) installations [400.7, 8].
derated ampacity of conductors at any point must generally be at least
156% of the module (or array of parallel-connected modules) rated
short-circuit current at that point [690.8(A), (B)]. See later
sections of this manual for details on ampacity calculations.
there are moving parts of an array, such as a flat-plate tracker or
concentrating modules, the NEC does allow the use of flexible cords and
cables [400.7(A), 690.31(C)]. When these types of cables are used, they
should be selected for extra-hard usage with full outdoor ratings
(marked "WA" or “W” on the cable). They should not be used
in conduit. Temperature derating information is provided by Table
690.31C. A temperature correction factor in the range of 0.33 to 0.58
should be used for flexible cables used as module interconnects.
in PV systems operate at relatively slow angular rates and with limited
motion. Normal stranded wire (exposed USE-2 or THWN-2 inside flexible
conduit) has demonstrated good performance without deterioration due to
Another possibility is the use of extra flexible (400+
strands) building cable type USE-RHH-RHW or THW. This cable is
available from the major wire distributors (Appendix A). However, it
should be noted that few mechanical terminals (screw or setscrew types)
are listed for use with other than the normal Class B or C stranded
cables (7, 19 or 37 strands). Cable types, such as THW or RHW
that are not sunlight resistant, should be installed in flexible
Module junction boxes have
various types of terminals inside junction boxes or
permanently-connected leads (with and without connectors). The
instructions furnished with each module will state the acceptable size
and type of wires for use with the terminals. Ampacity calculations
will dictate the minimum conductor sizes allowed. Some modules
may require the use of crimp-on terminals when stranded conductors are
used. The use of a crimp-on (compression) terminal is usually
required when fine stranded conductors are being used with mechanical
terminals (setscrew or screw fasteners) unless the terminal is marked
for use with fine stranded cables. Very few, if any, are marked
for use with fine stranded conductors.
Light-duty crimping tools
designed for crimping smaller wires used in electronic components
usually do not provide sufficient force to make long-lasting crimps on
connectors for PV installations even though they may be sized for 12-10
AWG. Insulated terminals crimped with these light-duty crimping tools
frequently develop high-resistance connections in a short time and may
even fail as the wire pulls out of the terminal. It is strongly
suggested that only listed or device specific, heavy-duty
industrial-type crimping tools be used for PV system wiring where
crimp-on terminals are required. Figure 4 shows four styles of crimping
tools. On the far left is a common handyman locking pliers that should
not be used for electrical connections. On the left center is a
stripper/crimper used for electronics work that will crimp only
insulated terminals. These two types of crimping tools are frequently
used to crimp terminals on PV systems; however, since they are not
listed devices, their use is discouraged. The two crimping tools
on the right are listed, heavy-duty industrial designs with ratcheting
jaws and interchangeable dies that will provide the highest quality
connections. They are usually available from electrical supply houses.
Figure 4. Terminal Crimping Tools-Two on Left
Unlisted, Two on Right Listed
Figure 5. Crimp Terminals/Lugs-All Listed, but Not
All Suitable for All Applications
5 shows some examples of insulated and uninsulated terminals. In
general, uninsulated terminals are preferred (with insulation applied
later if required), but the heavier, more reliable listed electrical
terminals, not unlisted electronic or automotive grades, are required.
Again, an electrical supply house rather than an electronic or
automotive parts store is the place to find the required items.
Terminals are listed only when installed using the instructions
supplied with the terminals and when used with the related crimping
tool (usually manufactured or specified by the manufacturer of the
terminals). If the junction box provides mechanical pressure terminals,
it is not necessary to use crimped terminals unless fine stranded
conductors are used.
Figure 6 shows a few mechanical
terminals. The screws and setscrews used in these devices usually
indicate that they are not listed for use with fine stranded, flexible
conductors, but are intended for use only with the normal 7 or 19
strand conductors. Any terminal block used must be listed as suitable
for use with “field-installed wiring [110.3(B)].”
Figure 6. Listed Mechanical Terminals
of the relatively higher cost of USE-2 and TC cables and wire, they are
usually connected to less expensive cable at the first junction box
leading to an interior location. In many cases, a PV combiner as shown
in Figure 7 is used to make the transition from the single conductor
module wiring to one of the standard wiring methods. All PV
system wiring must be made using one of the specific
installation/materials methods included in the NEC [690.31, Chapter 3].
Single-conductor, exposed wiring is not permitted except for module
wiring or with special permission [Chapter 3]. The most common methods
used for PV systems are individual conductors in electrical metallic
tubing (EMT) , rigid nonmetallic conduit (RNC) , or
liquidtight flexible nonmetallic conduit (LFNC) .
Figure 7. PV Combiner with Circuit Breakers
individual conductors are used in conduit installed in outdoor, sunlit
locations, they should be conductors with at least 90°C insulation
such as RHW-2, THW-2, THWN-2 or XHHW-2. Conduits installed in exposed
locations are considered to be installed in wet locations
[100-Locations (wet, damp, dry)]. These conduits may have water trapped
in low spots and therefore only conductors with wet ratings are
acceptable in conduits that are located in exposed or buried locations.
The conduit can be either thick-wall (rigid, galvanized-steel, RGS, or
intermediate, metal-conduit, IMC) or thin-wall electrical metallic
tubing (EMT) , and if rigid nonmetallic conduit is used,
electrical (gray) PVC (Schedule 40 or Schedule 80) rather than plumbing
(white) PVC tubing must be used .
ground) UF cable (a jacketed or sheathed cable) or tray cable (type TC)
that is marked sunlight resistant is sometimes used between the module
interconnect wiring and the PV disconnect device.
exposed cable runs can also be made with sheathed, multi-conductor
cable types such as NM, NMB, and UF. The cable should not be subjected
to physical abuse. If abuse is possible, physical protection must be
provided [300.4, 334.15(B), 340.12]. Exposed, single-conductor cable
(commonly used improperly between batteries and inverters) shall not be
used—except as module interconnect conductors [300.3(A)].
Battery-to-inverter cables are normally single-conductor cables
installed in conduit.
PV conductors must not be routed through
attics unless they are installed in a metallic raceway between the
point of first penetration of the building structure and the first dc
disconnect [690.14, 690.31(E)]. Attic temperatures will be at
higher-than-outdoor temperatures due to solar heating, and the ampacity
of the conductors will have to be derated for these elevated
temperatures. However, due to the PV disconnect location
requirements established by NEC Section 690.14, conductors routed
through attics are becoming less frequent. The 2005 NEC allows
conductors to be routed through the structure when they are installed
in metallic raceways. [690.31(E)]
connectors that are concealed at the time of installation must be able
to resist the environment, be polarized, and be able to handle the
short-circuit current. They shall also be of a latching design with the
terminals guarded. The equipment-grounding member, if used, shall make
first and break last [690.32, 33]. UL Standard 1703 also requires
that the connectors for positive and negative conductors should not be
All junction boxes
and other locations where module wiring connections are made shall be
accessible. Removable modules and stranded wiring may allow
accessibility [690.34]. The modules should not be permanently fixed
(welded) to mounting frames, and solid wire that could break when
modules are moved to service the junction boxes should be used
sparingly. Open spaces behind the modules would allow access to the
All splices (other than the
connectors mentioned above) must be made in approved junction boxes
with an approved splicing method [300.15]. Conductors must be twisted
firmly to make a good electrical and mechanical connection, then
brazed, welded, or soldered, and then taped [110.14(B)]. Mechanical
splicing devices such as split-bolt connectors or terminal strips are
also acceptable. Crimped splicing connections may also be made if
listed splicing devices and listed, heavy-duty crimping tools are used.
Splices in the module conductors where made of jacketed two-conductor
UF or TC cable when located outside must be protected in rain-proof
junction boxes such as NEMA type 3R [300.15]. Cable clamps must also be
used [300.15(C)]. Figure 8 shows some common splicing
devices. Many of the “power blocks” (on the left) are
only “Recognized” by UL for use inside factory-assembled,
listed devices. These “Recognized” devices are not
suitable for installation or assembly in the field.
Figure 8. Common Splicing Devices
can be exposed in exposed single-conductor USE-2 cables and may be made
by soldering and covering the splice with appropriate heat shrink
tubing listed for outdoor use containing sealant. The electrical and
mechanical properties of the spliced conductor and the insulation
around the splice must equal or exceed the unspliced conductor. Inline
mechanical crimped splices may be used when listed for the application
and installed with appropriately rated insulation listed for outdoor
Properly used box-type mechanical terminal
connectors (Figures 6 and 8) give high reliability. If used, they
should be listed for at least damp conditions even when used in
rainproof enclosures. However, few are listed for use with any
type of conductor other than the normal Class B stranded wires (7 and
19 strands). Fuse blocks, fused disconnects, and circuit breakers
frequently have these mechanical pressure terminals.
wire connectors (approved for splicing wires), when listed for the
environment (dry, damp, wet, or direct burial), are acceptable splicing
devices. Unless specifically marked for ac only, they may be used on
either ac or dc circuits. In most cases, they must be used inside
enclosures, except when used in direct-burial applications [110.3(B),
Where several modules are connected in series and
parallel, a terminal block or bus bar arrangement must be used so that
one source circuit can be disconnected without disconnecting the
grounded (on grounded systems) conductor of other source circuits
[690.4(C)]. On grounded systems, this indicates that the popular
“Daisy Chain” method of connecting modules may not always
be acceptable, because removing one module in the chain may disconnect
the grounded conductor for all of those modules in other parallel
chains or source circuits. This becomes more critical on larger systems
where paralleled sets of long series strings of modules are used.
Figure 9 shows unacceptable and acceptable methods. The required
module-protective fuse or other overcurrent device is usually required
on each module (12-volt systems) or string of modules.
Figure 9. Module Interconnect Methods
CONDUCTOR COLOR CODES
NEC established color codes for electrical power systems many years
before either the automobile or electronics industries had standardized
color codes. PV systems are being installed in an arena covered by the
NEC and, therefore, must comply with NEC standards that apply to both
ac and dc power systems. In a system where one conductor is grounded,
the insulation on all grounded conductors must be white, gray or have
three white stripes or be any color except green if marked with white
plastic tape or paint at each termination (marking allowed only on
conductors larger than 6 AWG). Conductors used for module frame
grounding and other exposed metal equipment grounding must be bare (no
insulation) or have green or green with yellow-striped insulation or
identification [200.6, 7; 210.5; 250.119]. Any insulated
equipment-grounding conductor used to ground PV module frames must be
an outdoor-rated conductor such as USE-2.
The NEC requirements
specify that the grounded conductor be white. In most PV-powered
systems that are grounded, the grounded conductor is the negative
conductor. Telephone systems that use positive grounds require special
circuits when powered by PV systems that have negative grounds. In
older PV systems where the array is center tapped, the center tap must
be grounded [690.41], and this becomes the white conductor. There is no
NEC requirement designating the color of the ungrounded conductor, but
the convention in ac power wiring is that the first two ungrounded
conductors are colored black and red. This suggests that in two-wire,
negative-grounded PV systems, the positive conductor could be red or
any color with a red marking except green or white, and the negative
grounded conductor must be white. In a three-wire, center-tapped
system, the positive conductor could be red, the grounded, center tap
conductor must be white, and the negative conductor could be black.
NEC allows grounded PV array conductors, such as non-white USE/USE-2,
UF or SE that are smaller than 6 AWG, to be marked with a white marker
690.5 of the NEC requires a ground-fault detection, interruption, and
array disconnect (GFPD) device for fire protection if the PV arrays are
mounted on roofs of dwellings. Ground-mounted arrays are not required
to have this device. Several external devices or devices built into
utility-interactive inverters are available that meet this requirement.
These particular devices generally require that the system grounding
electrode conductor be routed through or connected to the device.
These devices include the following code-required functions:
• Ground-fault detection
• Ground-fault current interruption
• Array disconnect/inverter shutdown
• Ground-fault indication
detection, interruption, and indication devices might, depending on the
particular design, accomplish the following actions automatically:
• Sense ground-fault currents
exceeding a specified value
• Interrupt the fault currents
• Open the circuit between the array and the load
• Indicate the presence of the ground fault
devices have been developed for both grid-tied inverters (Figure 11)
and stand-alone systems (Figure12), and others are under
development. See Appendix H for more details.
The 1999 NEC
added a Section 690.6(D) permitting (not requiring) the use of a device
(undefined) on the ac branch circuit being fed by an ac PV module to
detect ground-faults in the ac wiring. There are no commercially
available devices as of mid 2004 that meet this permissive requirement.
Standard 5-milliamp anti-shock receptacle GFCIs or 30-milliamp
equipment protection circuit breakers should not be used for this
application. The receptacle GFCIs interrupt both the hot
(ungrounded) and neutral (grounded) conductor, and the equipment
protection circuit breaker may be destroyed when backfed.
2005 NEC will allow ungrounded PV arrays and the requirements for
ground-fault protection will differ slightly from these requirements
for grounded systems. See Appendix L.
INSTALLATION AND SERVICE
690.18 requires that a mechanism be provided to allow safe installation
or servicing of portions of the array or the entire array. The term
"disable" has several meanings, and the NEC is not clear on what is
intended. The NEC Handbook does elaborate. “Disable” can be
defined several ways:
• Prevent the PV system from
producing any output
• Reduce the output voltage to zero
• Reduce the output current to zero
• Divide the array into non-hazardous segments
The output could be measured either at the PV source terminals or at
the load terminals.
fighters are reluctant to fight a fire in a high-voltage battery room
because there is no way to turn off a battery bank unless the
electrolyte can somehow be removed. In a similar manner, the only way a
PV system can have zero output at the array terminals is by preventing
light from illuminating the modules. The output voltage may be reduced
to zero by shorting the PV module or array terminals. When this is
done, short-circuit current will flow through the shorting conductor
which, in a properly wired system, does no harm. The output current may
be reduced to zero by disconnecting the PV array from the rest of the
system. The PV disconnect switch would accomplish this action, but
open-circuit voltages would still be present on the array wiring and in
the disconnect box. In a large system, 100 amps of short-circuit
current (with a shorted array) can be as difficult to handle as an
open-circuit voltage of 600 volts.
During PV module
installations, the individual PV modules can be covered to disable
them. For a system in use, the PV disconnect switch is opened during
maintenance, and the array is either short circuited or left open
circuited depending on the circumstances. In practical terms, for a
large array, some provision (switch or bolted connection) should be
made to disconnect portions of the array from other sections for
servicing. As individual modules or sets of modules are serviced, they
may be covered and/or isolated and shorted to reduce the potential for
electrical shock. Aside from measuring short-circuit current, there is
little that can be serviced on a module or array when it is shorted.
The circuit is usually open circuited for repairs.
requirement that the PV source and output conductors be kept outside
the building until the readily accessible disconnect is reached
indicate that these conductors are to be treated in a manner similar to
ac service entrance conductors [690.14]. First response personnel
are less likely to cut these energized cables since they are on the
outside of the building. The 2005 NEC allows PV source and output
circuits inside the building providing that they are installed in a
metallic raceway [690.31(E)].
Even in dim light conditions
(clouds, dawn, dusk) when sunlight is not directly illuminating the PV
module or PV array, voltages near the open-circuit value will appear on
PV source and output circuit wiring. Distributed leakage paths
caused by dirt and moisture will ground-reference, supposedly
ungrounded, disconnected conductors, and they may be energized with
respect to ground posing a safety hazard.
subject of grounding is one of the most complex issues in electrical
installations. Definitions from Articles 100 and 250 of the NEC will
help to clarify the situation when grounding requirements are discussed.
||Connected to the earth or to
a metallic conductor or surface that serves as earth.
or gray or three white stripes)
|A system conductor
that normally carries current and is intentionally grounded. In PV
systems, one conductor (normally the negative) of a two-conductor
system or the center-tapped conductor of a bipolar system is grounded.
green, or green with yellow stripe)
|A conductor not
normally carrying current used to connect the exposed metal portions of
equipment that might be accidentally energized to the grounding
electrode system or the grounded conductor.
||A conductor not normally
used to connect the grounded conductor to the grounding electrode or
grounding electrode system.
element in contact with the earth (e.g., a ground rod, a
concrete-encased conductor, grounded building steel, and others).
a two-wire PV system over 50 volts (125% of open-circuit PV-output
voltage), one dc current-carrying conductor shall be grounded. In a
three-wire system, the neutral or center tap of the dc system shall be
grounded [690.41]. These requirements apply to both stand-alone and
grid-tied systems. Such system grounding will enhance personnel safety
and minimize the effects of lightning and other induced surges on
equipment. In addition, the grounding of all PV systems (even 12-volt
systems) will reduce radio frequency noise from dc-operated fluorescent
lights and inverters.
Size of DC Grounding Electrode Conductor
250.166 of the NEC addresses the size of the dc grounding electrode
conductor (GEC). Many PV systems can use a 6 AWG GEC if that is the
only connection to the grounding electrode [250.166(C)] and that
grounding electrode is a rod, pipe, or plate electrode. In some cases
(a very small system with circuit conductors less than 8 AWG), an 8 AWG
GEC may be used and should be installed in conduit for physical
protection. Many inspectors will allow a 6 AWG GEC to be used
without additional physical protection. Other grounding
electrodes will require different sizes of grounding electrode
conductors. In a few cases, the direct-current system-grounding
electrode conductor shall not be smaller than 8 AWG or the largest
conductor supplied by the system [250.166(B)]. If the conductors
between the battery and inverter are 4/0 AWG (for example) then the
grounding-electrode conductor from the negative conductor (assuming
that this is the grounded conductor) to the grounding electrode may be
required to be as large as 4/0 AWG. However, in most PV installations,
a smaller GEC (usually 6 AWG) will be allowed if it is connected only
to a rod, pipe, or plate electrode [250.166(C)].
If the grounding electrode were a concrete-encased conductor, then a 4
AWG GEC would be required. [250.66(B), 250.166(D)]
Point of Connection
stand-alone systems, primarily, the system grounding electrode
conductor for the direct-current portion of a PV system shall be
connected to the PV-output circuits [690.42] at a single point. When
this connection (the dc bonding point) is made close to the modules,
added protection from surges is afforded. However, real-world
considerations affect this connection point.
In stand-alone PV
systems, the charge controller may be considered a part of the
PV-output circuit, and the point-of-connection of the grounding
electrode conductor could be before or after the charge controller.
However, this grounding conductor may be a very large conductor (e.g.,
4/0 AWG) while the conductors to and from the charge controller may be
10 AWG or smaller. Connecting the 4/0 AWG grounding conductor on the
array side of the charge controller, while providing some degree of
enhanced surge suppression from lightning induced surges, may not meet
the full intent of the grounding requirements. Connecting the grounding
conductor to the system on the battery side of the charge controller at
a point where the system conductors are the largest size will provide
better system grounding at the expense of less lightning protection.
Since the NEC allows smaller grounding electrode conductors in many
circumstances, either grounding conductor point of connection may be
acceptable [250.166]. Figure 10 shows two possible locations for the
grounding electrode conductor.
Figure 10. Typical System: Possible Grounding
NEC does not specifically define where the PV-output circuits end.
Circuits from the battery toward the load are definitely load circuits.
Since the heaviest conductors are from the battery to the inverter, and
either end of these conductors is at the same potential, then either
end could be considered a point for connecting the grounding conductor.
The negative dc input to the inverter is connected to the metal case in
some unlisted stand-alone inverter designs, but this is not an
appropriate place to connect the grounding electrode conductor and
other equipment-grounding conductors, since this circuit is a dc-branch
circuit and not a PV-output circuit. Connection of the grounding
electrode conductor to or near the negative battery terminal would
avoid the “large-wire/small-wire” problem outlined above.
the presence of ground-fault protection devices [690.5] may dictate
that this bonding point be made in the ground-fault device or inside
the inverter. Many utility-interactive inverters have internal
ground-fault protection devices that dictate the connection point for
the dc grounding electrode conductor. Figure 11 shows a
utility-interactive inverter installation where the grounding electrode
conductor is connected to a point inside the inverter and the inverter
furnishes the bond to the grounded conductor.
11. Utility-Interactive Inverter with Internal DC
Bonding Point, GFPD, and Connection Point for Grounding Electrode
It is imperative that there be no
more than one ground
connection to the dc grounded conductor of a PV system. Failure to
limit the connections to one (1) will allow objectionable currents to
flow in uninsulated equipment-grounding conductors and will create
unexpected ground faults in the grounded conductor [250.6]. The
ground-fault protection systems will sense these extra connections as
ground faults and may not function correctly. There are exceptions to
this rule when PV arrays, generators, or loads are some distance from
the main loads [250.32].
Unusual Grounding Situations
unlisted stand-alone inverter designs use the entire chassis as part of
the negative circuit. Also, the same situation exists in certain
radios—automobile and shortwave. These designs will not pass the
current UL standards for consumer electrical equipment or PV systems
and will probably require modification in the future since they do not
provide electrical isolation between the exterior metal surfaces and
the current-carrying conductors. They also create the very real
potential for multiple grounded-conductor connections to ground.
the case of these non-listed inverters and other non-listed products is
connected to the negative conductor and that case must be grounded as
part of the equipment ground described below, the user has no choice
whether or not the system is to be grounded [250 VI]. The system is
grounded even if the voltage is less than 50 volts and the point of
system ground is the negative input terminal on the inverter. It is
strongly suggested that these unlisted inverters not be used and, in
fact, to use them or any unlisted component may result in the inspector
not accepting the system.
Some telephone systems ground the
positive conductor, and this may cause problems for PV-powered
telephone systems with negative grounds. An isolated-ground, dc-to-dc
converter may be used to power subsystems that have different grounding
polarities from the main system. In the ac realm, an isolation
transformer will serve the same purpose.
In larger utility-tied
systems and some stand-alone systems, high impedance grounding systems
or other methods that accomplish equivalent system protection and that
use equipment listed and identified for the use might be used in lieu
of, or in addition to, the required hard ground [690.41]. The
discussion and design of these systems are beyond the scope of this
guide. Grounding of grid-tied systems will be discussed later in this
Charge Controllers—System Grounding
grounded system, it is important that the charge controller does not
have electronic devices or relays in the grounded conductor. Charge
controllers listed to the current edition of UL Standard 1741 meet this
requirement. Relays or transistors in the grounded conductor create a
situation where the grounded conductor is not at ground potential at
times when the charge controller is operating. This condition violates
provisions of the NEC that require all conductors identified as
grounded conductors always be at the same potential (i.e. grounded). A
shunt in the grounded conductor is equivalent to a wire, if properly
sized, but the user of such a charge controller runs the risk of having
the shunt bypassed when inadvertent grounds occur in the system. The
best charge controller design has only a straight-through conductor
between the input and output terminals for the grounded
current-carrying conductor (usually the negative conductor).
690.35 of the 2005 NEC, will permit (not require) ungrounded PV systems
when a number of conditions are met. These conditions are
intended to make ungrounded PV installations in the United States as
safe as equivalent ungrounded PV systems in Europe. Given the
100+-year history of grounded electrical systems, the U.S. PV industry
and the electricians and inspectors may not have the experience,
knowledge, and infrastructure to properly and safely install and
inspect ungrounded PV systems. The NEC requirements were
developed to bring the US PV industry in line with the rest of the
world by adopting some of the European techniques and experience for
installing ungrounded systems. They include:
- Overcurrent protection and
disconnects on all circuit conductors
- Ground-fault protection on all
- Jacketed or sheathed multiconductor
cables or raceways
- Additional warning labels
- Inverters listed specifically for
non-current-carrying exposed metal parts of junction boxes, equipment,
and appliances in the entire electrical system that may be accidentally
energized shall be grounded [690.43; 250 VI; 720.10]. All PV systems,
regardless of voltage, must have an equipment-grounding system for
exposed metal surfaces (e.g., module frames and inverter cases)
[690.43]. The equipment-grounding conductor shall be sized as required
by Article 690.45 or 250.122. Generally, this will mean an
equipment-grounding conductor (in other than PV source and output
circuits) based on the size of the overcurrent device protecting the ac
or dc circuit conductors. Table 250.122 in the NEC gives the sizes. For
example, if the inverter-to-battery conductors are protected by a
400-amp fuse or circuit breaker, then at least a 3 AWG conductor must
be used for the equipment ground for that circuit [Table 250.122]. If
the current-carrying conductors have been oversized to reduce voltage
drop, then the size of the equipment-grounding conductor must also be
proportionately adjusted [250.122(B)].
In the PV source and
output circuits, the equipment grounding conductors should generally be
sized to carry at least 125% of the short-circuit currents from the PV
circuits (not including backfeed currents from other sources) at that
point in the circuit. They should not be less than 14 AWG to afford
some degree of mechanical strength—particularly when they are
installed between modules in free air. Where the circuit
conductors are oversized for voltage drop, the equipment-grounding
conductor shall be proportionately oversized in accordance with
250.122(B) except where there are no overcurrent devices protecting the
circuit as allowed by 690.9 EX. [690.45]. See Appendix G
for additional details on grounding PV modules.
single-conductor cables are run along and adjacent to metal racks, then
these racks may be subject to being energized and should be
grounded. Installations using conductors in conduits may not seem
to require grounded racks since the module grounding and the conduit
grounding (if metallic conduits were used) would provide the
code-required protection. However, modules have been known to shatter
and conductive elements come into contact with the racks, therefore the
racks should also be grounded. Frequently, module racks are
grounded to provide additional protection against lightning.
INVERTER AC OUTPUTS
inverter output (120 or 240 volts) must be connected to the ac
distribution system in a manner that does not create parallel paths for
currents flowing in grounded conductors [250.6]. The NEC requires that
both the green or bare equipment-grounding conductor and the white ac
neutral conductor be grounded, and this is normally accomplished by the
ac distribution equipment or load center and not in the inverter. The
Code also requires that current not normally flow in the
equipment-grounding conductors. If the stand-alone inverter has ac
grounding receptacles as outputs, the equipment-grounding and neutral
conductors are most likely connected to the chassis and, hence, to
chassis ground inside the inverter. This configuration allows plug-in
devices to be used safely. However, if the outlets on the inverter are
plug and cord connected (not allowed) to an ac load center used as a
distribution device, then problems can occur.
The ac load
center usually has the grounded neutral and equipment-grounding
conductors connected to the same bus bar. This bus bar is also
connected to the enclosure and has a grounding electrode conductor
connected to a grounding electrode. Parallel current paths are created
with neutral currents flowing in the equipment-grounding conductors
when the inverter also has the neutral bonded to the
equipment-grounding conductor. This problem can be avoided (where
stand-alone inverters with internal bonding are used) by using a load
center with an isolated/insulated neutral bus bar that is separated
from the equipment-grounding bus bar.
Inverters with hard-wired
outputs may or may not have internal bonding connections. Most
listed stand-alone inverters and all utility-interactive inverters do
not have an internal neutral-to-ground bond. Some stand-alone
inverters with ground-fault circuit interrupters (GFCIs) for ac outputs
must be connected in a manner that allows proper functioning of the
GFCI [110.3(B)]. A case-by-case analysis will be required.
INVERTERS CREATE SEPARATELY DERIVED SYSTEMS
systems will generally have dc circuits and ac circuits and both must
be properly grounded [250, 690 V]. Although the NEC has parts of
Article 250 that deal with the grounding of ac systems and parts that
deal with the proper grounding of dc systems, it does not specifically
deal with systems that have both ac and dc components.
Article 100 of the NEC, the definition of “Separately Derived
Systems” includes PV systems, and in most cases this is
correct. Most, but not all, PV systems (both stand-alone systems
and utility-interactive systems) employ an inverter that converts the
dc from the PV modules to ac that is used to feed loads or the utility
grid. These inverters use a transformer that isolates the dc side
of the system from the ac side. The grounded dc circuit conductor
is not directly connected to the grounded ac circuit conductor.
Although the normal definition of separately derived systems applies
only to ac systems with transformers, in fact, the isolation between ac
and dc circuits in PV inverters makes many PV systems also separately
As in any separately
derived system, both parts must be properly grounded [250.30].
There is usually no internal bond between the ac grounded circuit
conductor and the grounding system inside either stand-alone or
utility-interactive inverters. Both of these PV systems rely on
the neutral-to-ground main bonding jumper in the service equipment
(utility-interactive systems) or the bonding jumper in the first load
center (stand-alone systems) for grounding the ac side of the system.
dc side of the system must also be grounded when the system voltage
(open-circuit PV voltage times a temperature-dependent constant) is
above 50 volts. See NEC Section 690.41 for more details.
NEC Table 690.7 gives the temperature-dependent constant, and the
application of this constant usually indicates that PV systems with a
nominal voltage of 24-volts or greater must have the dc side
grounded. Only infrequently are 12-volt dc systems found that do
not have one of the dc circuit conductors grounded, and even those
systems must have an equipment-grounding system [690.43]. Most of
the 12-48 volt balance-of-systems PV equipment is designed to be used
only with a grounded system. See NEC Section 690.43. Nearly
all utility-interactive PV systems operate with a nominal voltage of 48
volts or higher so they must have one of the dc circuit conductors
grounded [690.41], although some ungrounded systems will be permitted
[690.31(E)], when the 2005 NEC is applied.
the dc side of a PV system is somewhat complicated by Section 690.5 of
the NEC that requires a ground-fault protection device (GFPD) on some
PV systems. Many utility-interactive inverters have an internal
GFPD (Figure 11). Inverters (both stand-alone and utility-interactive)
that are used in systems with PV modules mounted on the roofs of
dwellings that do not have the internal GFPD must have an external GFPD
installed in the system [690.5]. See Figure 12. In nearly
all cases, these GFPDs (either inside the inverter or externally
mounted) actually make the grounded circuit conductor-to-ground
Figure 12. External Ground-Fault Protection Device
systems employing a GFPD, there should be no external bonding
conductor, and to add one to these systems would bypass the GFPD and
render it inoperative.
In most dc systems, the negative conductor is the grounded
dc bond inside the inverter with a GFPD or a dc bond in a GFPD external
to the inverter establishes the need for, and connection location of, a
dc grounding electrode conductor. Some inverters with an internal GFPD
have a terminal designated for connecting the usual 8 AWG to 4 AWG
grounding electrode conductor. Other inverters lack this
connection. Some inverter manufacturers provide a field-installed
lug kit for this connection that has been evaluated by their listing
agency. PV systems with an externally installed GFPD will have an
appropriate connection place (and instructions) for the grounding
PV systems that do not have PV modules
mounted on the roofs of dwellings are not required to have the GFPD
that is required in Section 690.5, but many inverters in those systems
will have it anyway. In those systems not requiring or having a
GFPD, the dc bonding jumper may be installed at any single point on the
PV output circuits, and this is where the dc grounding electrode
conductor should be connected.
generators used for battery charging pose problems similar to using
inverters and load centers. Many of these smaller generators usually
have ac outlets that may have the neutral and grounding conductors
bonded to the generator frame. When the generator is connected to the
system through a load center to a stand- alone inverter with battery
charger, or to an external battery charger, parallel ground paths are
likely. These problems need to be addressed on a case-by-case basis. A
stand-alone PV system, in any operating mode (inverting or battery
charging), must not have currents in the equipment-grounding conductors
In some cases, manual or automated transfer switches
must be used that switch both the grounded neutral conductor as well as
the ungrounded circuit conductor [250.6]. In some cases, this
neutral switching can eliminate the double bonding points.
PV systems with batteries and possibly backup generators may have
similar or more complex grounding and bonding issues.
SUGGESTED AC GROUNDING
ac generators and inverters should be hard-wired to the ac-load center.
Neither should have an internal bond between the neutral and grounding
conductors. Neither should have any receptacle outlets that can be used
when the generator or inverter is operated when disconnected from the
load center. The single bond between the neutral and ground should be
made in the system ac load center. If receptacle outlets are desired on
the generator or the inverter, they should be
ground-fault-circuit-interrupting devices (GFCI).
of the NEC presents alternate methods of achieving a safe grounding
system in a limited number of installations where the various parts of
the system (generator, PV modules, dc load center, and inverter) are
remotely located from each other.
system grounding electrode shall be common with, or bonded to, the ac
grounding electrode (if any) [690.47, 250 III]. The dc system grounded
conductor and the equipment-grounding conductors shall be tied to the
same grounding electrode or grounding electrode system. The conductors
are usually first connected by a main dc bonding jumper and then a
grounding electrode conductor is run from the bonding point to the
grounding electrode. Even if the PV system is ungrounded
(optional at less than 50 volts [typically 125% of Voc]),
equipment-grounding conductors must be used and must be connected to a
grounding electrode [250.110]. Metal water pipes and other metallic
structures as well as concrete encased electrodes are to be used in
some circumstances [250.50]. When a manufactured grounding electrode is
used, it shall be a corrosion resistant rod, a minimum of 5/8 inch
(16mm) in diameter (1/2 inch (13mm) if stainless steel)) with at least
8 feet (2.4m) driven into the soil at an angle no greater than 45
degrees from the vertical [250.53]. Listed connectors must be used to
connect the grounding electrode conductor to the ground rod [110.3(B)].
bare-metal well casing makes a good grounding electrode. It should be
part of a grounding electrode system. The central pipe to the well
should not be used for grounding, because it is sometimes removed for
For maximum protection against lightning-induced
surges, it is suggested that a grounding electrode system be used with
at least two grounding electrodes. One electrode would be the
main-system grounding electrode as described above. The other would be
a supplementary grounding electrode located as close to the PV array as
practical. The module frames and array frames would be connected
directly to this grounding electrode to provide as short a path as
possible for lightning-induced surges to reach the earth. This
electrode is usually not bonded to the main system grounding electrode
[250.54]. This supplementary ground rod is an auxiliary to the module
frame grounding that is required to be connected with an
equipment-grounding conductor connected to the main grounding electrode
as discussed in the section on Equipment Grounding, above.
not connect the negative current-carrying conductor to the grounding
electrode, to the equipment-grounding conductor, or to the module or
array frame at the modules. There should be one and only one point in
the system where the dc grounding electrode conductor is attached to
the dc system grounded conductor. See Figure 13 for clarification. The
wire sizes shown are for illustration only and will vary depending on
system size. Chapter 3 of the NEC specifies the ampacity of various
types and sizes of conductors. As is common throughout the NEC, there
are exceptions to this guidance. See NEC Section 250.32(B).
Figure 13. Example Grounding Electrode System
Tables 310.16 and 310.17 give the ampacity (current-carrying capacity
in amps) of various sized conductors at temperatures of 30°C
(86°F). There are several adjustments that normally must be made to
these ampacity numbers before a conductor size can be selected [310.15].
installation method must be considered. Are the conductors in free air
[Table 310.17] or are they bundled together or placed in conduit [Table
What is the ambient air temperature, if not 30°C (86°F)?
How many current-carrying conductors are grouped together?
These adjustments are made using factors presented in Chapter 3 of the
most conductors used in electrical power systems are restricted from
operating on a continuous basis at more than 80% of their rated
ampacity [210.19, 215.2, 690.8]. This 80% factor also applies to
overcurrent devices and switchgear unless listed for operation at 100%
of rating [210.20(A)]. PV conductors are also restricted by this factor
Conductors carrying PV module currents
are further restricted by an additional derating factor of 80% because
of the manner in which PV modules generate electrical energy in
response to sunlight and because the noon-time intensity of the
sunlight may exceed the standard test condition value of 1000 W/m2
[690.8(A)]. Also, nearby reflective surfaces (sand, snow, and
water) may enhance the solar intensity on the module and increase its
It should be noted that these ampacity adjustment
factors may be applied to the basic conductor ampacities (e.g.,
multiply them by 0.80) or they may be applied to the anticipated
current in the circuit (e.g., multiply the current by 1.25, the
reciprocal of 0.8).
Photovoltaic modules are limited in their
ability to deliver current. The short-circuit current capability of a
module is nominally 10 to 15% higher than the operating current.
Normal, daily values of solar irradiance may exceed the standard test
condition of 1000W/m2. These increased currents are considered by using
the 1.25 adjustment in the ampacity calculations. Another design
requirement for PV systems is that the conductors connected to PV
modules or in contact with the back of PV modules may operate at
temperatures as high as 75-80°C when the modules are mounted close
to a structure, there are no winds, and the ambient temperatures are
high. Temperatures in module junction boxes frequently occur within
this range. This will require that the ampacity of the conductors be
derated or corrected with factors given in NEC Table 310.16 or 310.17.
For example, a 10 AWG USE-2/RHW-2 single-conductor cable used for
module interconnections in conduit has a 90°C insulation and an
ampacity of 40 amps in an ambient temperature of 26-30°C. When it
is used in ambient temperatures of 61-70°C, the ampacity of this
cable is reduced to 23.2 amps.
It should be noted that the
ampacity values associated with conductors having 90°C insulation
could only be used if the terminals of the module and connected
terminal blocks or overcurrent devices are rated at 90°C
[110.14(C)]. If the terminals are rated at only 75°C, then the
ampacity values associated with 75°C insulation must be used, even
when conductors with 90°C insulation are being used. Of course, if
the 90°C insulation wire is used, the temperature derating may
start with the 90°C ampacity values. All module terminals are
rated for use with 90°C conductors. However, there are no
overcurrent devices rated for 90°C. Most overcurrent devices
are marked for use with 75°C conductors, and if not marked and
rated at less than 100 amps, must be used with conductors rated at
60°C or conductors limited to 60°C conductor ampacity levels
There are several rules that must be followed to determine the ampacity
of conductors in a PV system.
The ampacity of conductors in PV source circuits shall be
at least 125%
of the rated module or parallel-connected modules short-circuit current
The ampacity of the PV-output
circuit conductors shall be at least 125% of the short-circuit output
The ampacity of
conductors to and from an inverter or power conditioning system shall
be 125% of the rated operating current for that device [690.8(A)].
In a similar manner, other conductors in the system should
ampacity of 125% of the rated operating current to allow for long
duration operation at full power [215.2].
requirements are to ensure that the connected overcurrent devices or
panelboards operate at no more than 80% of their ampacity. Operation
when snow or cloud enhancement increases the PV output currents above
normal, but these are generally short-term effects and are not
considered in the ampacity calculations. Daily expected values of solar
irradiance will exceed the standard test condition of 1000W/m2 at many
UL Standard 1703 for PV modules requires
installation instructions include an additional 25% of the 25°C
ratings for short-circuit current and open-circuit voltage to allow for
expected daily peak irradiance and colder temperatures. This 1.25
factor, while still in the 2002 edition of UL Standard 1703, is also
contained in Section 690.8(A) of the NEC as mentioned above. There are
only two 1.25 factors applied to PV module currents and the combined
factor is 1.56 (1.25x1.25). Correct design practices require correctly
determining wire size and the ampere rating of overcurrent devices on
PV source and output circuits. However, the rating of the overcurrent
device should always be less than, or equal to, the ampacity of the
cable. The NEC makes only infrequent exceptions to this rule. [240.3].
ampacity of conductors and the sizing of overcurrent devices is an area
that demands careful attention by the PV system designer/installer.
Temperatures and wiring methods must be addressed for each site
[310.15]. Calculations start with the 125% of Isc value to comply with
the UL 1703 requirements [also in Section 690.8(A)], and additional
125% must then be used for code compliance [690.8. 690.9]. Finally, the
cable ampacity is adjusted for temperature. See Appendix E for
Overcurrent devices may have terminals
rated for connection to 60°C conductors necessitating a reduction
in the cable ampacity when using 75°C or 90°C conductors.
Appendix I summarizes the complex calculations required to properly
calculate conductor sizes and overcurrent device ratings.
the battery bank is tapped to provide multiple voltages (i.e., 12 and
24 volts from a 24-volt battery bank), the common negative conductor
will carry the sum of all of the simultaneous load currents. The
negative conductor must have an ampacity at least equal to the sum of
all the amp ratings of the overcurrent devices protecting the positive
conductors or have an ampacity equal to the sum of the ampacities of
the positive conductors [690.8(C)].
The NEC does not allow
paralleling conductors for added ampacity, except that cables 1/0 AWG
or larger may be paralleled under certain conditions [310.4]. DC-rated
switchgear, overcurrent devices, and conductors cost significantly more
when rated to carry more than 100 amps. It is suggested that large PV
arrays be broken down into subarrays, each having a short-circuit
output of less than 64 amps. This configuration will allow the use of
100-amp-rated equipment (156% of 64 amps) on each source circuit.
stand-alone systems, inverters are used to change the direct current
(dc) from a battery bank to 120-volt or 240-volt, 60-Hertz (Hz)
alternating current (ac). The conductors between the inverter and the
battery must have properly rated overcurrent protection and disconnect
mechanisms [240, 690.8, 690.9]. These inverters frequently have
short-duration (seconds) surge capabilities that are four to six times
the rated output. For example, a 2,500-watt inverter might be required
to surge to 10,000 volt-amps for 5 seconds when a motor load is
started. The NEC requires the ampacity of the conductors between the
battery and the inverter to be sized by the rated 2,500-watt continuous
output of the inverter. For example, in a 24-volt system, a 2,500-watt
inverter would draw 134 amps at full load (85% efficiency at 22 volts)
and 420 amps for motor-starting surges. The required ampacity of the
conductors between the battery and the inverter is 125% of the 134 amps
or 167 amps.
To minimize steady-state voltage drops to account
for surge-induced voltage drops and to increase system efficiency, some
well-designed systems have conductors that are larger than required by
the NEC. When the current-carrying conductors are oversized, the
equipment-grounding conductor must also be oversized proportionately
See Appendices F and I for additional considerations on conductor
NEC requires that every ungrounded conductor be protected by an
overcurrent device [240.20]. In a PV system with multiple sources of
power (PV modules, batteries, battery chargers, generators, power
conditioning systems, etc.), the overcurrent device must protect the
conductor from overcurrent from any source connected to that conductor
[690.9]. Blocking diodes, charge controllers, and inverters are not
considered as overcurrent devices and must be considered as
zero-resistance wires when assessing overcurrent sources [690.9(A)
FPN]. If the PV system consists of a single string of modules (or
possibly two strings of modules) and is directly connected to the load
without battery storage or other source of overcurrent, then no
overcurrent protection is required if the conductors are sized at 156%
of the short-circuit current [690.8(B)(1)EX].
utility-interactive inverters are not capable of back feeding utility
currents into the faults in the PV array. With these inverters,
one, two and possibly more strings of modules may be connected to the
inverter with no overcurrent device at the inverter input. See
Appendix J for more details.
When circuits are opened in dc
systems, arcs are sustained much longer than they are in ac systems.
This presents additional burdens on overcurrent-protection devices
rated for dc operation. Such devices are required to carry the rated
load current and sense overcurrent situations as well as be able to
safely interrupt dc currents. AC overcurrent devices have the same
requirements, but the interrupt function is considerably easier.
PV source circuits shall have overcurrent devices rated at least 156%
(1.25 x 1.25) of the module short-circuit current. The PV-output
circuit overcurrent devices shall be rated at least 156% of the
short-circuit PV currents from the parallel connected modules or
strings of modules [690.8]. Time-delay fuses or circuit breakers would
minimize nuisance tripping or blowing. In all cases, dc-rated devices
having the appropriate dc-voltage rating must be used. See Appendix I
for more detailed information on the calculation of the ratings of
Overcurrent devices have standard ratings
as follows: 15, 20, 25, 30, 35, 40, 45, 50, 60, 70, 80, 90, 100,
110, 125, 150, 175, 200, 225, 250, 300, 350, 400, 450, 500 amps and
higher. [240.6(A)]. If a conductor has an ampacity that
falls between one of the standard values, the next larger overcurrent
device shall be used [240.4(B)]. However, in PV source and output
circuits, the overcurrent device standard ratings for supplementary
devices (where used) are in one-amp increments from 1 amp to 15 amps
[690.9(C)]. At 15 amps and above, the standard values apply.
ungrounded conductors from the PV array shall be protected with
overcurrent devices [Article 240, Diagram 690.1]. Grounded conductors
(not shown in Diagram 690.1) must not have overcurrent devices since
the independent opening of such a device might unground the system.
Since PV module outputs are current limited, these overcurrent devices
are actually protecting the array wiring from backfeed from
parallel-connected modules, the battery, or the inverter.
the conductors and overcurrent devices are sized to deal with 156% of
the short-circuit current for that particular PV circuit, overcurrents
from those modules or PV sources, which are limited to the
short-circuit current (or at worst, 125% of the short-circuit current),
cannot trip the overcurrent device in this circuit. The overcurrent
devices in these circuits protect the conductors from overcurrent from
parallel-connected sets of modules or overcurrent from the battery
bank. In stand-alone systems or utility-interactive systems, these
array overcurrent devices protect the array wiring from overcurrent
from parallel strings of modules, the battery, or from the generator or
ac utility power.
Often, PV modules or series strings of modules
are connected in parallel. As the conductor size used in the array
wiring increases to accommodate the higher short-circuit currents of
paralleled modules, each conductor size is protected by an
appropriately sized overcurrent device. These overcurrent devices must
be placed nearest all sources of potential overcurrent for that
conductor [240.1]. Figure 14 shows an example of array conductor
overcurrent protection for a medium-size array broken into subarrays.
The cable sizes and types shown are examples only. The actual sizes
will depend on the ampacity needed.
Figure 14. Typical Array Conductor Overcurrent
Protection (with Optional Subarray Disconnects)
fuses or circuit breakers are acceptable for overcurrent devices
provided they are rated for their intended uses—i.e., they have
dc ratings when used in dc circuits, the ampacity is correct, and they
can interrupt the necessary currents when short circuits occur .
Figure 15 shows typical branch-circuit-rated, dc-rated, listed circuit
breakers. The NEC allows the use of less-robust listed
supplementary-type overcurrent devices only for PV source circuit
protection [690.9(C)]. See Figures 16 and 17.
overcurrent devices rated at less than 100 amps may have terminals that
are rated for use with 60°C conductors unless marked for use with
75°C conductors. The ampacity calculations of the connected cables
may have to be adjusted. See Appendix I for the details of how
the ratings of overcurrent devices are calculated.
Figure 15. Listed Branch-Circuit Rated Breakers-Three
on left are DC rated
Figure 16. Recognized (left) and listed (right) DC
branch circuits in stand-alone systems start at the battery and go to
the receptacles supplying the dc loads or to the dc loads that are hard
wired, such as inverters. In direct-connected systems (no battery), the
PV output circuits go to the power controller or master dc power switch
and a branch circuit goes from this location to the load. In
utility-intertie systems, the circuit between the inverter and the
ac-load center may be considered a feeder or possibly a branch circuit.
used to protect dc or ac branch (load) and feeder circuits must be
listed for that use. They must also be of different sizes and markings
for each amperage and voltage group to prevent unintentional
interchange [240 VI]. These particular requirements eliminate the use
of glass fuses and plastic automotive fuses as branch-circuit
overcurrent devices because they are neither tested nor rated for this
application. DC-rated fuses that meet the requirements of the NEC are
becoming more available. Figure 17 shows listed, dc-rated, time-delay
fuses on the right that are acceptable for branch circuit use, which
would include the battery fuse. The cut-away fuse shows the complexity
of the mechanisms required to interrupt dc currents. Acceptable
dc-rated, listed fast-acting supplementary fuses are shown on the left
and can be used in the PV source circuits. The fuses shown are made by
Littelfuse (Appendix A) and Bussmann. Ferraz and others also have
listed dc ratings on the types of fuses that are needed in PV systems.
Figure 17. Listed Supplementary (two on left) and
Branch Circuit (right) Fuses
fuses have no dc rating by the fuse industry or the testing
laboratories and should not be used in PV systems. When rated by the
manufacturer, they have only a 32-volt maximum rating, which is less
than the open-circuit voltage from a 24-volt PV array. Furthermore,
these fuses have no rating for interrupt current, nor are they
generally marked with all of the information required for
branch-circuit fuses. They are not considered supplementary fuses under
the UL listing or component recognition programs. Figure 18 shows
unacceptable automotive fuses on the left and unacceptable (for dc
applications) ac fuses on the right. Unfortunately, even the listed ac
fuses are intended for ac use and frequently have no dc ratings.
Figure 18. Unlisted, Unacceptable Automotive Fuses
(left) and Listed, Unacceptable AC Fuses (right)
breakers also have specific requirements when used in branch circuits,
but they are generally available with the needed dc ratings [240 VII].
provide maximum protection and performance (lowest voltage drop) on
branch circuits (particularly on 12 and 24-volt systems), the ampacity
of the conductors might be increased, but the rating of the overcurrent
devices protecting that cable should be as low as possible consistent
with load currents. A general formula for cable ampacity and
overcurrent device rating is 100% of the noncontinuous loads and 125%
of the continuous loads anticipated [215.2]. Normally only
worst-case continuous currents are used for ampacity and overcurrent
calculations in PV systems. See Appendix I for the details of
selecting appropriate overcurrent devices.
INTERRUPTING RATING (AIR)—SHORT-CIRCUIT CONDITIONS
devices—both fuses and circuit breakers—are required to be
able to safely open circuits with short-circuit currents flowing in
them. Since PV arrays are inherently current limited, high
short-circuit currents from the PV array are normally not a problem
when the conductors are sized as outlined above. In stand-alone systems
with storage batteries, however, the short-circuit condition is very
severe. A single 220 amp-hour, 6-volt, deep-discharge, lead-acid
battery may produce short-circuit currents as high as 8,000 amps for a
fraction of a second and as much as 6,000 amps for a few seconds in a
direct terminal-to-terminal short circuit. Such high currents can
generate high temperatures and magnetic forces that can cause an
underrated overcurrent device to burn or blow apart. Two paralleled
batteries could generate nearly twice as much current, and larger
capacity batteries would be able to deliver proportionately more
current under a short-circuit condition. In dc systems, particularly
stand-alone systems with batteries, the interrupt capability of every
overcurrent device is important. This interrupt capability or interrupt
rating is specified as Amperes Interrupting Rating (AIR) and sometimes
Amperes Interrupting Capability (AIC).
Some dc-rated, listed,
branch circuit breakers that can be used in PV systems have an
interrupt rating of 5,000 amps at 48 volts dc. However, Heinemann and
AirPax make numerous circuit breakers with interrupt ratings of 25,000
amps at voltages from 65 to 125 volts (Appendix A). Some dc-rated,
listed supplementary circuit breakers have an AIR of only 3,000 amps.
Many listed, dc-rated class-type fuses have an AIR of up to 20,000 amps.
or circuit breakers shall never be paralleled or ganged to increase
current-carrying capability unless done so by the manufacturer and
listed for such use [240.8].
Since PV systems may have
transients—lightning and motor starting as well as
others—inverse-time circuit breakers (the standard type) or
time-delay fuses should be used in most cases. In circuits where no
transients are anticipated, fast-acting fuses can be used. They should
be used if relays and other switchgear in dc systems are to be
protected. Time-delay fuses that can also respond very quickly to
short-circuit currents may also be used for system protection.
FUSING OF PV
NEC allows supplementary overcurrent devices (fuses and circuit
breakers) to be used in PV source circuits [690.9(C)]. (See Figure 17.)
A supplementary overcurrent device is one that is designed for use
inside a piece of listed equipment. These devices supplement the main
branch-circuit overcurrent device and do not have to comply with all of
the requirements of fully rated branch overcurrent devices. They shall,
however, be dc rated, listed, and able to handle the short-circuit
currents they may be subjected to [690.9(D)]. Unfortunately, many
supplementary fuses are not dc rated, and if they are, the interrupt
rating (when available) is usually less than 5,000 amps. A mitigating
factor is that the location of supplementary fuses in PV source
circuits and PV output circuits places them at some electrical distance
from potentially high short-circuit currents from the battery. At
this location, the available short-circuit currents may be within their
interrupt rating. The use of ac-only-rated supplementary fuses is not
allowed for the dc circuits of PV systems [110.3(B)].
current-limiting fuse must be used in each ungrounded conductor from
the battery where the down-stream overcurrent devices or switchgear
have interrupt ratings less than the available short-circuit currents
[690.71(C), 240.2, 110.9]. This fuse will limit the current that
a battery bank can supply to a short circuit and should reduce the
short-circuit currents to levels that are within the capabilities of
downstream equipment [690.71(C)]. These fuses are available with dc
ratings of 125, 300, and 600 volts dc, currents of 0.1 to 600 amps, and
a dc interrupt of 20,000 amps. They are classified as RK5 or RK1
current-limiting fuses and should be mounted in Class-R rejecting fuse
holders or dc-rated, fused disconnects. Class J or T fuses with dc
ratings might also be used. For reasons mentioned previously,
time-delay fuses should be specified, although some designers are
getting good results with Class T fast-acting fuses.
these fuses and the associated disconnect switch should be used in each
bank of batteries with a paralleled amp-hour capacity up to 1,000
amp-hours. Many 12, 24 and 48-volt battery banks are connected without
overcurrent devices in each string of batteries and these have proved
durable over the years. However, as batteries age and load
conditions change, string current becomes unbalanced and the fuse in
each string may help to prevent total battery bank failures under
normal and fault conditions. On battery systems with higher than 48
volts nominal rating, the use of a disconnect and overcurrent device in
each string of cells is necessary to prevent system failures that could
result in fires and explosions and to allow for proper servicing
Batteries with single-cell amp-hour capacities higher
than 1,000 amp-hours will require special design considerations,
because these batteries may be able to generate short-circuit currents
in excess of the 20,000 AIR rating of the current-limiting fuses. When
calculating the available short-circuit currents at a particular point
in the circuit, the resistances of all connections, terminals, wire,
fuse holders, circuit breakers, and switches to that point need to be
considered. These resistances serve to reduce the magnitude of the
available short-circuit currents at any particular point. The
suggestion of one fuse per 1,000 amp-hours of battery size is only a
general estimate, and the calculations are site specific. The listed
branch-circuit fuses shown in Figure 17 are current limiting.
lieu of current-limiting fuses, circuit breakers with high interrupt
ratings may be used throughout the system for all overcurrent
devices. These circuit breakers are not current limiting, even
with the high interrupt rating, so they cannot be used to protect other
types of fuses or circuit breakers. An appropriate use would be in the
conductor between the battery bank and the inverter. This single device
would minimize voltage drop and provide the necessary disconnect and
overcurrent features. When high interrupt rating circuit breakers are
used throughout a PV system, there is NO requirement for a
current-limiting fuse, since each circuit breaker is capable of
interrupting the short-circuit currents that may be impressed upon it.
electrical installation practice requires that utility service entrance
equipment have fault-current protection devices that can interrupt the
available short-circuit currents [110.9]. This requirement applies to
the utility side of any power conditioning system in a PV installation.
If the service is capable of delivering fault currents in excess of the
interrupt rating of the overcurrent devices used to connect the
inverter to the system, then current-limiting overcurrent devices must
be used [110.9]. In utility-interactive systems that are
connected to the line side of the service disconnect, particular
attention should be paid to the amount of available short-circuit
current from the utility feeder.
utility-interactive PV systems make the utility connection through a
back-fed circuit breaker in an existing load center and the existing
load center is designed to handle the available short-circuit
currents. No additional current limiting is required. If a
new service entrance is added for the output of the PV system, then the
service entrance equipment must have the appropriate ratings
[690.64]. See Appendix C for additional details.
a fuse is used as an overcurrent device and is accessible to
unqualified persons, it must be installed in such a manner that all
power can be removed from both ends of the fuse for servicing. It is
not sufficient to reduce the current to zero before changing the fuse.
There must be no voltage present on either end of the fuse prior to
service. This may require the addition of switches on both sides of the
fuse location—a complication that increases the voltage drop and
reduces the reliability of the system [690.16]. Because of this
requirement, the use of a fusible pullout-style disconnect,
“finger-safe” fuse holder, or circuit breaker is
Optionally ungrounded 12-volt and some 24-volt PV
systems require an overcurrent device in both of the ungrounded
conductors of each circuit. Since an equipment-grounding system is
required on all systems, grounding the system and using overcurrent
devices only in the remaining ungrounded conductors may reduce costs.
are many considerations in configuring the disconnect switches for a PV
system. The National Electrical Code deals with safety first
requirements last—if at all. The PV designer should also consider
equipment damage from over voltage, performance options, equipment
limitations, and cost.
A photovoltaic system is a power
generation system, and a specific minimum number of disconnects are
necessary to deal with that power. Untrained personnel will be
operating the systems; therefore, the disconnect system must be
designed to provide safe, reliable, and understandable operation [690
Disconnects may range from nonexistent in a self-contained
PV-powered light for a sidewalk to those found in the
space-shuttle-like control room in a large, multi-megawatt,
utility-tied PV power station. Generally, local inspectors will not
require disconnects on totally enclosed, self-contained PV systems like
a PV-powered, solar, hot-water circulating system. This would be
particularly true if the entire assembly were listed as a unit and
there were no external contacts or user serviceable parts. However, the
situation changes as the complexity of the device increases and
separate modules, inverters, batteries, and charge controllers having
external connections are wired together and possibly operated and
serviced by unqualified personnel.
690 requires all current-carrying conductors from the PV power source
or other power source to have disconnect provisions. This provision
includes the grounded conductor, if any [690 III]. Ungrounded
conductors must have a switch or circuit breaker disconnect [690.13,
15, 17]. Grounded conductors which normally remain connected at all
times, may have a bolted disconnect (terminal or lug) that can be used
for service operations and for meeting the NEC requirements. Disconnect
switches must not open grounded conductors [690.13]. Grounded
conductors of faulted source circuits in roof-mounted dc PV arrays on
dwellings are allowed to be automatically interrupted as part of
ground-fault protection requirements in 690.5. [690.13]
ungrounded 12-volt PV system (as allowed by [690.41]), both positive
and negative conductors must be switched, since both are ungrounded.
Since all systems must have an equipment-grounding system, costs may be
reduced and performance improved by grounding 12-volt systems and using
one-pole disconnects on the remaining ungrounded conductor.
systems operating at higher voltages, as will be allowed by the 2005
NEC in 690.35, will also require switched disconnects and overcurrent
protection in all of the circuit conductors since both the positive and
negative circuit conductors will be ungrounded. See Appendix L
for additional discussions of ungrounded PV systems.
PV DISCONNECT LOCATION
us first consider the ac utility service to the typical
residence. Either an overhead or an underground feeder will
deliver the power. Before this service feeder gets into the
house, it usually first goes through a billing kilowatt-hour meter and
then the service entrance disconnect. In many jurisdictions, the
local code allows the main disconnect to be immediately inside the home
at the point of first penetration by the conductors of the building as
allowed by the National Electrical Code (NEC) See NEC Section
230. In other locations, and the number is increasing, the
service entrance disconnect must be located on the outside of the house
with the load center sans disconnect inside the house [local
codes]. In all cases this disconnect must be “readily
accessible,” which means it must not be in locked compartments,
no ladders are required to access it, and no building material must be
removed to get to it [690.14, 100-readily accessible].
These requirements were established many years ago to allow fire
response personnel to quickly and safely shut off power to a building
on fire that might require the firefighters to enter and cut holes in
walls, ceilings and roofs. In life threatening situations, time
is of the essence.
The NEC in Section 690.14 requires that the
main PV disconnect be in a similar location. It therefore must be
in a readily accessible location (no bathrooms, no attics—unless
served by a permanent fixed stairs) at the point of first penetration
of the dc PV source or output conductors. As in the ac service
entrance disconnect, this PV disconnect may be located immediately
inside the point of first penetration of the conductors. If the
attic is reached by fixed stairs (not pull down), then the disconnect
might be mounted in that location. Disconnects in bathrooms are
not allowed. Other readily accessible rooms are acceptable as
long as there are no locked doors.
Although commonly done in the
past, many inspectors are not allowing PV conductors from the
roof-mounted PV array to penetrate the attic and be run through the
walls to the first floor or the basement where the main PV disconnect
is located. These “always energized” conductors pose
hazards to fire response personnel and possibly a fire hazard since
they are in locations where potential short circuits might start fires.
The 2005 NEC allows an inside circuit installation provided it
meets certain additional requirements. If the conductors are
installed in a metal conduit or raceway, they will be permitted (not
required) to be routed inside the house to the dc disconnect located at
some distance from the point of first penetration. The disconnect
will still have to be readily accessible, but this allowance, if
adopted, will permit more design and installation flexibility.
The metal conduit/raceway provides for added fire protection (does not
burn), mechanical protection (difficult to accidentally cut), and
ground-fault detection (in the event there is an internal ground
Each piece of
equipment in the PV system shall have disconnect switches to disconnect
it from all sources of power. The disconnects shall be circuit breakers
or switches and shall comply with all of the provisions of Section
690.17. DC-rated switches are expensive; therefore, the ready
availability of moderately priced dc-rated circuit breakers with
ratings up to 125 volts and 110 amps would seem to encourage their use
in all 12-, 24-, and 48-volt systems. When properly located and used
within their approved ratings, circuit breakers can serve as both the
disconnect and overcurrent device. In simple stand-alone systems, one
switch or circuit breaker disconnecting the PV array and another
disconnecting the battery may be all that is required.
utility-interactive systems, there may be several string disconnect
switches, sub array disconnects, main PV disconnects for each inverter,
ac output disconnects for each inverter and a complete system ac
disconnect (sometimes operating at 12 kV).
A 2,000-watt inverter
on a 12-volt system can draw more than 235 amps at full load. A 250kW
utility-interactive inverter may have a PV dc input disconnect that
carries 800 amps at 300 volts or more. Disconnect switches must
be rated to carry the current and have appropriate voltage and
interrupt ratings [110.3(B)]. Again, a dc-rated, listed circuit breaker
may prove less costly and more compact than a switch and fuse with the
same ratings; at least in systems operating up to a nominal voltage of
When the battery is disconnected
from the stand-alone system, either manually or through the action of a
fuse or circuit breaker, care should be taken that the PV system not be
allowed to remain connected to the load. Depending on the design
of the charge controller, small loads may allow the PV array voltage to
increase from the normal battery charging levels to the open-circuit
voltage, which will shorten dc lamp life and possibly damage electronic
This potential problem can be alleviated somewhat by
using ganged multi-pole circuit breakers or ganged fused disconnects as
shown in Figure 20. This figure shows two ways of making the
connection. Of course, fuses in a ganged unit may operate
independently, which may still create a problem. Separate circuits,
including disconnects and fuses between the charge controller and the
battery and the battery and the load, as shown in Figure 19, may be
used if it is desired to operate the loads without the PV array being
connected. If the design requires that the entire system be shut down
with a minimum number of switch actions, the switches and circuit
breakers could be ganged multi-pole units.
Figure 19. Small System Disconnects
Figure 20. Separate Battery Disconnects
unlisted charge controllers are fussy about the sequence in which they
are connected and disconnected from the system. These charge
controllers do not respond well to being connected to the PV array and
not being connected to the battery. The sensed battery voltage (or lack
thereof) would tend to rapidly cycle between the array open-circuit
voltage and zero as the controller tried to regulate the nonexistent
charge process. This problem will be particularly acute in
self-contained charge controllers with no external battery sensing. The
use of charge controllers listed to UL Standard 1741 will minimize this
problem. In this case, such a listed charge controller has been
designed to operate properly with all of the overcurrent protection and
disconnects required by the NEC.
Again, the multi-pole switch or
circuit breaker can be used to disconnect not only the battery from the
charge controller, but the charge controller from the array. Probably
the safest method for self-contained charge controllers is to have the
PV disconnect switch disconnect both the input and the output of the
charge controller from the system. Larger systems with separate charge
control electronics and switching elements will require a case-by-case
analysis—at least until the controller manufacturers standardize
their products. Figure 21 shows two methods of disconnecting the charge
Figure 21. Charge Controller Disconnects
that do not have one of the current-carrying conductors grounded must
have disconnects and overcurrent devices in all of the ungrounded
conductors [240.20, 690.13]. This means two-pole devices for the PV,
battery, and inverter disconnects and overcurrent devices. The
additional cost is considerable. See Appendix L for more
MULTIPLE POWER SOURCES
When multiple sources of
power are involved, the disconnect switches shall be grouped and
identified [230.72, 690.14(C)(5)]. No more than six motions of the hand
will be required to operate all of the disconnect switches required to
remove all power from the system [230.71]. These power sources include
PV output, the battery system, any generator, and any other source of
power. Multi-pole disconnects or handle ties should be used to keep the
number of motions of the hand to six or fewer.
Article 230 in
the NEC allows each structure to have more that one source of supply.
The sources might be a utility connection and a PV system. The
disconnects of these two sources of supply do not have to be grouped
[230.2, 230.71]. However placards are required showing where all
of the disconnects are located [230.70, 690.54, 705.10].
ENCLOSURES, AND BOXES
and overcurrent devices shall be mounted in listed enclosures,
panelboards, or boxes [240 III]. Wiring between these enclosures must
use a NEC-approved method [110.8]. Appropriate cable clamps,
strain-relief methods, or conduit shall be used. All openings not used
shall be closed with the same or similar material to that of the
enclosure [110.12(A)]. Metal enclosures must be bonded to the
equipment-grounding conductor [250.110, 408.40]. The use of wood or
other combustible materials is discouraged. Conductors from different
systems such as utility power, gas generator, hydro, or wind shall not
be placed in the same enclosure, box, conduit, etc., as PV source
conductors unless the enclosure is partitioned [690.4(B)]. This
requirement stems from the need to keep "always live" PV source
conductors separate from those that can be turned off. The ac
outputs of a specific PV system may be routed in the same conduit or
raceway as the dc PV source conductors from the same system providing
that all conductors meet the insulation requirements of 300.3(C)(1).
designing a PV distribution system or panel board, a listed NEMA type
box and listed disconnect devices and overcurrent devices should be
used. The requirements for the internal configuration of these devices
are established by NEC Articles 110, 408, portions of article 690 as
well as other articles in the code and must be followed. Dead
front-panelboards with no exposed current-carrying conductors,
terminals, or contacts are generally required [408.38]. Underwriters
Laboratories also establishes the standards for the internal
construction of panelboards and enclosures. The use of a listed
commercial product designed for use in PV systems is encouraged.
general, NEC Articles 480 and 690 VIII should be followed for
installations having storage batteries. Battery storage in PV systems
poses several safety hazards:
• Hydrogen gas generation from
• High short-circuit current
• Acid or caustic electrolyte
• Electric shock potential
flooded, non-sealed, lead-acid batteries are charged at high rates, or
when the terminal voltage reaches 2.3 - 2.4 volts per cell, the
batteries produce hydrogen gas. Even sealed batteries may vent hydrogen
gas under certain conditions. This gas, if confined and not properly
vented, poses an explosive hazard. The amount of gas generated is a
function of the battery temperature, the voltage, the charging current,
and the battery-bank size. Hydrogen is a light, small-molecule gas that
is easily dissipated and is very difficult to contain. Small battery
banks (i.e., up to 20, 220-amp-hour, 6-volt batteries) placed in a
large room or a well-ventilated (drafty) area may not pose a
significant hazard. Larger numbers of batteries in smaller or tightly
enclosed areas require venting. Venting manifolds attached to each cell
and routed to an exterior location are not recommended because flames
in one section of the manifold may be easily transmitted to other areas
in the system. The instructions provided by the battery manufacturer
should be followed.
Closed battery boxes with single vents to
outside-the-house air may pose problems unless carefully designed. Wind
may force hydrogen back down the vent.
A catalytic recombiner
cap (Hydrocap® Appendix A) may be attached to each cell of a
flooded, lead-acid battery to recombine some of the evolved hydrogen
and oxygen to produce water. If these combiner caps are used, they will
require occasional maintenance. It is rarely necessary to use power
venting. Flame arrestors are required by NEC Section 480.9, and battery
manufacturers can provide special vent caps with flame-arresting
properties when the local authority requires them.
charge controllers are designed to minimize the generation of hydrogen
gas, but lead-acid batteries need some overcharging to fully charge the
cells. This produces gassing that should be dissipated.
case should charge controllers, switches, relays, or other devices
capable of producing an electric spark be mounted in a battery
enclosure or directly over a battery bank. Care needs to be exercised
when routing conduit from a sealed battery box to a disconnect.
Hydrogen gas may travel in the conduit to the arcing contacts of the
switch. It is suggested that any conduit openings in battery
boxes be made below the tops of the batteries, since hydrogen rises to
the top of the enclosure as it displaces the air.
BATTERY ROOMS AND
systems are capable of generating thousands of amps of current when
shorted. A short circuit in a conductor not protected by overcurrent
devices can melt wrenches or other tools, battery terminals and cables,
and spray molten metal around the room. Exposed battery terminals and
cable connections must be protected. Live parts of batteries must be
guarded [690.71]. This generally means that the batteries should be
accessible only to a qualified person. A locked room, battery box, or
other container and some method to prevent access by the untrained
person should reduce the hazards from short circuits and electric
shock. The danger may be reduced if insulating caps or tape are placed
on each terminal and an insulated wrench is used for servicing.
Note that with protective caps, corrosion may go unnoticed on the
terminals. The NEC requires certain spacing around battery enclosures
and boxes and other equipment to allow for unrestricted
servicing—generally about three feet [110.26]. Batteries should
not be installed in living areas, nor should they be installed below
any enclosures, panelboards, or load centers [110.26].
the more suitable, readily available battery containers is the
lockable, heavy-duty black polyethylene toolbox. Such a box can hold up
to four L-16 size batteries and is easily cut for ventilation holes in
the lid and for conduit entrances.
NEC Section 690.71(D)
prohibits the use of conductive cases for flooded, lead-acid batteries
operating above 48-volts nominal. Racks for these batteries may have no
conductive parts within than 6” (150 mm) of the tops of the
cases. These requirements were established to minimize the
probability of high-voltage ground faults developing in the dust and
electrolyte film that develops on these vented batteries during normal
ACID OR CAUSTIC
A thin film of
electrolyte can accumulate on the tops of the battery and on nearby
surfaces. This material can cause flesh burns. It is also a conductor
and, in high-voltage battery banks, poses a shock hazard, as well as a
potential ground-fault path. The film of electrolyte should be removed
periodically with an appropriate neutralizing solution. For lead-acid
batteries, a dilute solution of baking soda and water works well.
Commercial neutralizers are available at auto-supply stores.
controllers are available that minimize the dispersion of the
electrolyte and water usage because they minimize battery gassing. They
do this by keeping the battery voltage from climbing into the vigorous
gassing region where the high volume of gas causes electrolyte to mist
out of the cells. A moderate amount of gassing is necessary for proper
battery charging and de-stratification of the electrolyte in flooded
Battery servicing hazards can be minimized by using
protective clothing including facemasks, gloves, and rubber aprons.
Self-contained eyewash stations and neutralizing solution are good
precautionary additions to any battery room. Water should be used to
wash acid or alkaline electrolyte from the skin and eyes.
sprays and greases are available from automotive and battery supply
stores and they generally reduce the need to service the battery bank.
Hydrocap® Vents also reduce the need for servicing by reducing the
need for watering.
in dwellings must operate at less than 50 volts (48-volt nominal
battery bank) unless live parts are protected during routine servicing
[690.71(B)(1)]. It is recommended that live parts of any battery bank
should be guarded [690.71(B)(2)].
OTHER LARGE CABLES
cables, even though they can be 2/0 AWG and larger, must be a standard
building-wire type conductor [Chapter 3]. Welding and automobile
“battery” cables (listed and non-listed) are not allowed.
Flexible, highly-stranded, building-wire type cables (USE/RHW and THW)
are available for this use. Flexible cables, identified in Section 400
of the NEC are permitted (not required) from the battery terminals to a
nearby junction box and between battery cells. These cables shall be
listed for hard service use and moisture resistance [690.74]. As
is the case with flexible PV module interconnecting cables, it is
rarely necessary to use anything other than the normal building wire
types of cables identified in Chapter 3 of the NEC. Also the
types of terminals that can be used with these flexible cables are
limited. In general, the manufacturer’s data should be
consulted or the terminal or lug should be marked indicating
compatibility with the fine stranded cables. The few lugs that
are compatible are made of solid copper, have a flared entry section
and look somewhat like the three lugs on the far right in Figure 5.
electrical power generators such as wind, hydro, and
gasoline/propane/diesel must comply with the requirements of the NEC.
These requirements are specified in the following NEC articles:
Article 230 Services
Article 250 Grounding
Article 445 Generators
Article 700 Emergency Systems
Article 701 Legally Required Standby Systems
Article 702 Optional Standby Systems
Article 705 Interconnected Power Production Sources
multiple sources of ac power are to be connected to the PV system, they
must be connected with an appropriately rated and listed transfer
switch [702.6]. AC generators frequently are rated to supply larger
amounts of power than that supplied by the PV/battery/inverter. The
transfer switches (external to the inverter or a relay built into
listed inverters) must be able to safely accommodate either power
Grounding, both equipment and system, needs
to be carefully considered when a generator is connected to an existing
system. There must be no currents flowing in the equipment-grounding
conductor under any normal operating mode of the system [250.6]. Bonds
(connections) between the ac grounded conductor (neutral) and the
grounded frame in generators are common and have caused circulating,
The circuit breakers or fuses that are built
into the generator are usually not sufficient to provide NEC-required
protection for the conductors from the generator to the PV system. An
external (branch circuit rated) overcurrent device (and possibly a
disconnect) must be mounted close to the generator [240.21]. The
conductors from the generator to this overcurrent device must have an
ampacity of not less than 115% of the nameplate current rating of the
generator [445.12]. Figure 22 shows a typical one-line diagram for a
system with an auxiliary backup generator.
22. Disconnects for Remotely Located Power
Sources. Disconnects for Remotely Located Power Sources
charge controller or self-regulating system shall be used in a
stand-alone system with battery storage. The mechanism for adjusting
state of charge shall be accessible only to qualified persons [690.72].
are several charge controllers on the market that have been tested and
listed to UL standards by recognized testing organizations.
mounting of unlisted charge controllers with external terminals readily
accessible to the unqualified person will not be accepted by the
inspection authority. Dead-front panels with no exposed contacts are
generally required for safety. Figure 23 shows a typical charge
controller and remote display panel. It is a listed device, has
no exposed terminals, is ready for installation with conduit, and has
no readily-accessible user adjustments.
charge controllers are designed with a “straight” conductor
between the negative input and output terminals. A shunt is sometimes
placed in that conductor. This design will allow the controller to be
used in a grounded system with the grounded conductor running through
the controller. The installation manual of the charge controller must
be reviewed to ensure proper system grounding [110.3(B)].
Figure 23. Typical Charge Controller
Inverters can have stand-alone, utility-interactive, or combined
ac output wiring is not significantly different from the ac wiring in
residential and commercial construction, and the same general
requirements of the Code apply. In the case of utility-interactive
systems and combined systems, ac power may flow through circuits in
both directions. This two-way current flow will normally require
overcurrent devices at both ends of the circuit.
The dc input
wiring associated with stand-alone or hybrid inverters is the same as
the wiring described for batteries. Most of the same rules apply;
however, the calculation of the dc input current needs special
consideration since the NEC does not take into consideration some of
the finer points required to achieve the utmost in reliability.
Appendix F discusses these special requirements in greater detail.
dc input wiring associated with utility-interactive inverters is
similar, in most cases, to the wiring in PV source and output circuits.
with combined capabilities will have both types of dc wiring:
connections to the batteries and connections to the PV modules.
National Electrical Code has evolved to accommodate
relatively cheap energy. As the Code was expanded to include other
power systems such as PV, many sections were not modified to reflect
the recent push toward more efficient use of electricity in the home.
Stand-alone PV systems may be required to have dc services with 60- to
100-amp capacities to meet the Code [230.79]. DC receptacles for
appliances and lighting circuits, where used, may have to be as
numerous as their ac counterparts [220, 422]. In a small one- to
four-module system on a remote cabin where no utility extensions or
local grids are possible, these requirements may be excessive, since
the power source may be able to supply only a few hundred watts of
Changes in the 1999 NEC in Section 690.10 clarified some of the code
requirements for stand-alone PV systems.
local inspection authority has the final say on what is, or is not,
required and what is, or is not, safe. Reasoned conversations may
result in a liberal interpretation of the Code. For a new dwelling, it
seems appropriate to install a complete ac electrical system as
required by the NEC. This will meet the requirements of the inspection
authority, the mortgage company, and the insurance industry. Then the
PV system and its dc distribution system can be added. If an inverter
is used, it can be connected to the ac service entrance. NEC Section
690.10 elaborates on these requirements and allowances. DC branch
circuits and outlets can be added where needed, and everyone will be
happy. If or when grid power becomes available, it can be integrated
into the system with minimum difficulty. If the building is sold at a
later date, it will comply with the NEC if it has to be inspected. The
use of a listed dc power center will facilitate the installation and
Square D has received a direct current (dc), UL
listing for its standard QO residential branch circuit breakers. They
can be used up to 48 volts (125% PV open-circuit voltage) and 70 amps
dc. This limits their use to a 12-volt nominal system and a few 24-volt
systems in hot climates [Table 690.7]. The AIR is 5,000 amps, so a
current-limiting fuse (RK5 or RK1 type) must be used when they are
connected on a battery system [690.71(C). The Square D QOM main
breakers (used at the top of the load center) do not have this listing,
so the dc load center based on Square D QO circuit breakers should be
obtained with main lugs and no main breakers (Appendix A).
small 12-volt PV system (less than 5000 amps of available short-circuit
current), a two-pole Square D QO breaker could be used as the PV
disconnect (one pole) and the battery disconnect (one pole).
Alternatively, a fused disconnect or fusible pullout could be used in
this configuration. This would give a little more flexibility since the
fuses can have different current ratings. Figure 19 shows both systems
with only a single branch circuit.
In a system with several dc
branch circuits, the Square D QO load center can be used. A standard,
off-the-shelf Square D QO residential load center without a main
breaker can be used for a dc distribution panel in 12-volt dc systems
and a very few hot-climate 24-volt systems. The main disconnect would
have to be a “back fed” QO breaker, and it would have to be
connected in one of the normal branch circuit locations. Back-fed
circuit breakers must be identified for such use [690.64(B)(5)] and
clamped [408.16(F)]. See Appendix C for additional details. Since the
load center has two separate circuits (one for each line), the bus bars
will have to be tied together in order to use the entire load center.
Figure 24 illustrates this use of the Square D load center.
possibility is to use one of the line circuits to combine separate PV
source circuits, then go out of the load center through a breaker
acting as the PV disconnect switch to the charge controller. Finally,
the conductors would have to be routed back to the other line circuit
in the load center for branch-circuit distribution. Several options
exist in using one and two-pole breakers for disconnects. Figure 25
presents an example.
Figure 24. 12-Volt DC Load Center
Figure 25. 12-Volt DC Combining Box and Load Center
DC WIRING AND RECEPTACLES
dc interior wiring used in PV systems must comply with the NEC .
Nonmetallic sheathed cable (type NM - "Romex") may be used, and it must
be installed in the same manner as cable for ac branch circuits [334,
690.31(A)]. The bare grounding conductor in such a cable must not be
used to carry current and cannot be used as a common negative conductor
for combination 12/24-volt systems [334.108]. Exposed, single-conductor
cables are not permitted—they must be installed in conduit
[300.3(A)]. Conductors in the same current (i.e., positive and negative
battery conductors and equipment-grounding conductors) must be
installed in the same conduit or cable to prevent increased circuit
inductances that would pose additional electrical stresses on
disconnect and overcurrent devices [300.3(B)].
The code allows
the equipment-grounding conductors for dc circuits only to be run apart
from the current-carrying conductors [250.134(B) EX2]. However,
separating the equipment-grounding conductor from the circuit
conductors may increase any fault-circuit time constant and impair the
operation of overcurrent devices. The effects of transient pulses are
also enhanced when equipment-grounding conductors are separate. It is
suggested that dc equipment-grounding conductors be run in the same
conduit or cable as the dc circuit conductors.
used for dc must be different from those used for any other service in
the system [406.3(F)]. The receptacles should have a rating of not less
than 15 amps and must be of the three-prong grounding type [406.2(B),
406.3(A)]. Numerous different styles of listed receptacles are
available that meet this requirement. These requirements can be met in
most locations by using the three-conductor 15-, 20-, or 30-amp
240-volt NEMA style 6-15, 6-20, 6-30 receptacles for the 12-volt dc
outlets. If 24-volt dc is also used, the NEMA 125-volt locking
connectors, style L5-15 or L5-20, are commonly available. The NEMA
FSL-1 is a locking 30-amp 28-volt dc connector, but its availability is
limited. Figure 26 shows some of the available configurations.
Cigarette lighter sockets and plugs frequently found on
“PV” and “RV” appliances do not meet the
requirements of the National Electrical Code and should not be
Figure 26. NEMA Plug Configurations
is not permissible to use the third or grounding conductor of a
three-conductor plug or receptacle to carry common negative return
currents on a combined 12/24-volt system. This terminal must be used
for equipment grounding and may not carry current except in fault
A 30-amp fuse or circuit breaker
protecting a branch circuit (with 10 AWG conductors) must use
receptacles rated at 30 amps. Receptacles rated at 15 and 20 amps must
not be used on this 30-amp circuit [Table 210.21(B)(3)].
building codes require that smoke and fire detectors be wired directly
into the ac power wiring of the dwelling. With a system that has no
inverter, two solutions might be offered to the inspector. The first is
to use the 9-volt or other primary-cell, battery-powered detector. The
second is to use a voltage regulator to drop the PV system voltage to
the 9-volt or other level required by the detector.
regulator should be able to withstand the PV open-circuit voltage and
supply the current required by the detector alarm. Building such
a device should only be attempted by the well-qualified individual.
inverter systems, the detector on some units may trigger the inverter
into an “on” state, unnecessarily wasting power. In other
units, the alarm may not draw enough current to turn the inverter on
and thereby produce a reduced volume alarm or, in some cases, no alarm
at all. Small, dedicated inverters might be used, but this would waste
power and decrease reliability when dc detectors are available.
building codes require detectors to be connected to the power line and
have a battery backup. Units satisfying this requirement might also be
powered by dc from the PV system battery and by a primary cell.
ac ground-fault circuit interrupters (GFCI) do not operate reliably on
the output of some non-sine-wave inverters. If the GFCI does not
function when tested, it should be verified that the neutral
(white-grounded) conductor in the system is solidly grounded and bonded
to the equipment-grounding (green or bare) conductor and both are
connected to ground in the required manner. If this bond is present and
does not result in the GFCI testing properly, other options are
possible. Changing the brand of GFCI may rectify the solution. A direct
measurement of an intentional ground fault may indicate that slightly
more than the 5 milliamp internal test current is required to trip the
GFCI. The inspector may accept this. Some modified square wave
inverters will work with a ferro-resonant transformer to produce a
waveform more satisfactory for use with GFCIs, but the no-load power
consumption may be high enough to warrant a manual demand switch. A
sine-wave inverter should be used to power those circuits requiring
GFCI protection. Since sine-wave stand-alone inverters are
becoming the norm, the problems of using GFCIs (and smoke detectors)
with non sine-wave inverters are diminishing.
rated for ac only shall not be used in dc circuits [404.14(A)]. AC-DC
general-use “snap” switches are available by special order
from most electrical supply houses, and they are similar in appearance
to normal “quiet switches” [404.14(B)].
There have been some failures of dc-rated snap switches when used as PV
array and battery disconnect switches. If these switches are used on
12- and 24-volt systems and are not activated frequently, the contacts
may build up oxidation or corrosion and not function properly.
Periodically (recommend monthly) activating the switches under load
will keep the contacts clean.
PV and PV/Hybrid systems are frequently connected to a
building/structure/house that has been previously completely wired for
120/240-volts ac and has a standard service entrance and load center.
structures may employ one or more circuits that the National
Code (NEC) defines as a multiwire branch circuit. See Section 100
the NEC, “Branch Circuit, Multiwire.” These circuits take a
three-conductor plus ground feeder from the 120/240-volt load center
and run it some distance to a location in the structure where two
separate 120-volt branch circuits are split out. Each branch circuit
uses one of the 120-volt hot, ungrounded conductors from the
120/240-volt feeder and the common neutral conductor. See Figure 27.
a utility-connected system or a stand-alone system with a 120/240-volt
stacked pair of inverters, where the 120/240-volt power consists of two
120-volt lines that are 180 degrees out of phase, the currents in the
common neutral in the multiwire branch circuit are limited to the
difference currents from any unbalanced load. If the loads on each of
the separate branch circuits were equal, then the currents in the
common neutral would be zero.
A neutral conductor overload may
arise when a single 120-volt inverter is tied to both of the hot input
conductors on the 120/240-volt load center as shown in Figure 27. This
is a common practice for stand-alone PV homes. At this point the two
hot 120-volt conductors are being delivered voltage from the single
120-volt inverter and that voltage is in phase on both conductors. In
multiwire branch circuits, the return currents from each of the
separate branch circuits in the common neutral add together. A sketch
of the multiwire branch circuit is presented in Figure 27.
branch circuit is protected by a circuit breaker in the ungrounded
conductor in the load center. The neutral conductor is usually the same
size as the ungrounded conductors and can be overloaded with the
in-phase return currents. The circuit breakers will pass current up to
the ampacity of the protected conductors, but when both branch circuits
are loaded at more than 50%, the unprotected, common neutral conductor
is overloaded and may be carrying up to twice its rated currents.
definite fire and safety hazard exists. All existing stand-alone PV
installations using single inverters tied to both ungrounded conductors
at the service entrance should be examined for multiwire branch
The NEC requires that multiwire branch circuits in
some, but not all, cases use a two-pole circuit breaker so that both
circuits are dead at the same time under fault conditions and for
servicing. This two-pole, side-by-side circuit breaker rated at 15 or
20 amps may be one indication that multiwire branch circuits have been
used. Common handle circuit breakers rated at 30 amps and higher are
usually dedicated to 240-volt circuits for ranges, hot water heaters,
dryers, and the like and the conductors are usually 8 AWG and
larger. The Code requires that there must be no 240-volt outlets
in a structure fed by a single 120-volt inverter [690.10].
of the wiring in the load center may show a three-wire cable (14 or 12
AWG red, black, and white conductors) with bare ground leaving the load
center. This may be connected to a multiwire branch circuit. The
circuit breakers connected to this cable and the outputs of this cable
should be traced to determine the presence or absence of a multiwire
The following options are suggested for dealing with this situation:
systems where multiwire branch circuits are used with stacked
(120/240-volt) inverters, a sign should be placed near the inverters
warning that single inverter use (one inverter removed for repair and
the system is rewired to accommodate all branch circuits) may cause
overloaded circuits. The maximum current from the single inverter
should be limited to the ampacity of the common neutral conductor.
Figure 27. Diagram of a Multiwire Branch Circuit
all systems (multiwire or not), the neutral busbar of the load center
must be rated at a higher current than the output of the inverter
[690.10(C)]. In other words, do not connect an inverter with a 33-amp
output to a load center rated at 20 or 30 amps.
information is found in the NEC in sections 100, 210.4, 240.20(B), and
300.13(B), and in the NEC Handbook. Section 690.10(C) provides
requirements and allowances on connecting a single inverter to a
code-compliant ac wiring system.
AC PV MODULES
An AC PV
module is a photovoltaic device that has an alternating current output
(usually 120 volts at 60 Hz in the U.S.). The AC PV module is listed
(by UL and other listing agencies) as a unified device and is actually
a standard dc PV module with an attached (non-removable)
utility-interactive inverter. The ac output is only available when the
ac PV module is connected to a utility grid circuit where there is a
stable 120 volts at 60 Hz present. With no utility power, there will be
NO energy flow from the ac PV modules.
A number of ac PV modules
may be connected on the same circuit (according to ampacity
limitations), but that circuit must be dedicated to the ac PV module(s)
and must terminate in a dedicated circuit breaker [690.6].
are no external dc circuits in the ac PV module and none of the dc code
requirements apply. Unlisted combinations of small listed inverters
mated to listed dc PV modules do not quality as an ac PV module and
will have to have all code-required dc switchgear, overcurrent, and
ground-fault equipment added.
AC PV modules shall be marked with the following:
• Nominal AC Voltage
• Nominal AC Frequency
• Maximum AC Power
• Maximum AC Current
• Maximum Overcurrent Device Rating for AC Module
SYSTEM LABELS AND
A permanent label shall be applied near the PV disconnect switch that
contains the following information: [690.53]
• Operating Current (System maximum-power current)
• Operating Voltage (System maximum-power voltage)
• Maximum System Voltage
• Short-Circuit Current
data will allow the inspector to verify proper conductor ampacity and
overcurrent device rating. It will also allow the user to compare
system performance with the specifications.
MULTIPLE POWER SYSTEMS
with multiple sources of power such as PV, gas generator, wind, hydro,
etc., shall have a permanent plaque or directory showing the
interconnections [705.10]. Diagrams are not required, but may be useful
and should be placed near the system disconnects.
POINT OF INTERCONNECTION
interactive system(s) points of interconnection with other sources
shall be marked at an accessible location at the disconnecting means as
a power source with the maximum ac output operating current and the
operating ac voltage [690.54].
SWITCH OR CIRCUIT
switch or circuit breaker has all of the terminals energized when in
the open position, a label should be placed near it indicating: [690.17]
- ELECTRIC SHOCK HAZARD - DO NOT TOUCH TERMINALS. TERMINALS ON BOTH THE
LINE AND LOAD SIDES MAY BE ENERGIZED IN THE OPEN POSITION
piece of equipment that might be opened by unqualified persons should
be marked with warning signs. In some cases, a listed product is
required to have similar warnings:
- ELECTRIC SHOCK
HAZARD - DANGEROUS VOLTAGES AND CURRENTS - NO USER SERVICEABLE PARTS
INSIDE - CONTACT QUALIFIED SERVICE PERSONNEL FOR ASSISTANCE
battery container, box, or room should also have warning signs to
encourage safety for both qualified and unqualified people:
- ELECTRIC SHOCK HAZARD - DANGEROUS VOLTAGES AND CURRENTS - EXPLOSIVE
GAS - NO SPARKS OR FLAMES - NO SMOKING - ACID BURNS - WEAR PROTECTIVE
CLOTHING WHEN SERVICING
Involving the inspector as
early as possible in the planning stages of the system will begin a
process that should provide the best chance of installing a safe,
durable system. The following steps are suggested.
Establish a working relationship with a local electrical
electrician to determine the requirements for permits and inspections.
Contact the inspector and review the system plans.
Solicit advice and suggestions from the inspector.
Obtain the necessary permits.
Involve the inspector in the design and installation
information as needed. Have one-line diagrams and complete descriptions
of all equipment available.
companies are not familiar with photovoltaic power systems. They are,
however, willing to add the cost of the system to the homeowner's
policy if they understand the additional liability risk. A system
description may be required. Evidence that the array is firmly attached
to the roof or ground is usually necessary. The system must usually be
permitted and inspected if those requirements exist for other
electrical power systems in the locale [Local Codes].
companies will not insure homes that are not grid connected because
there is no source of power for a high-volume water pump for fighting
fires. In these instances, it may be necessary to install a
fire-fighting system and water supply that meets their requirements. A
high-volume dc pump and a pond might suffice.
As with the
electrical inspector, education and a full system description
emphasizing the safety features and code compliance will go a long way
toward obtaining appropriate insurance.
APPENDIX A: Sources of Equipment Meeting the
Requirements of The National Electrical Code
number of PV distributors and dealers stock the equipment needed to
meet the NEC requirements. Some sources are presented here for
specialized equipment. This list is not intended to be all-inclusive or
to promote any of the products.
multiconductor cable such as 10-2 with ground Nonmetallic Sheathed
Cable (NM and NMC), Underground Feeder (UF), Service Entrance (SE),
Underground Service Entrance (USE and USE-2), larger sizes (8 AWG)
single-conductor cable, uninsulated grounding conductors, and numerous
styles of building wire such as THHN can be obtained from electrical
supply distributors and building supply stores. See NEC Table 310-13
for cable types and characteristics.
cables should not be used with terminals or lugs that have a setscrew
or screw mechanical attachment. These terminals and lugs (also
found on circuit breakers, fuse holders, and PV equipment) are not
generally listed for use with other than normal 7, 19, and 37 stranded
conductors. Appendix K presents additional details.
highest quality, most durable USE-2 cable will also have RHW-2, and
600V markings and be made of cross-linked polyethylene (marked XLP or
XLPE). Flexible USE, RHW, and THW cables in large sizes (1/0 - 250
kcmil) and stranded 8-, 10-, and 12-AWG USE single conductor cable can
be obtained from electrical supply houses and wire distributors.
The following short list provides information on a cable distributor
2201 Main Street
Evanston, Illinois 60202
800-323-8166 for the nearest distributor
Cobra Wire and Cable, Inc.
PO Box 790
2930 Turnpike Drive
Hatboro, PA 19040
15, 20, 30 amp and higher rated fuses can be used for dc branch-circuit
overcurrent protection depending on conductor ampacity and load. Larger
sizes (100 amp and up) are used for current-limiting and overcurrent
protection on battery outputs. DC rated, listed fuses are manufactured
by the following companies, among others:
P.O. Box 14460
St. Louis, MO 63178-4460
314-527-1270 (Technical Questions)
374 Merrimac Street
Newburyport, MA 01950
Power Fuse Division
800 E. Northwest Highway
Des Plaines, Illinois 60016
800-TEC FUSE (Technical Questions)
800-227-0029 (Customer Service)
following fuses may be used for battery circuit and dc branch circuit
overcurrent protection and current limiting applications. If transients
are anticipated in PV circuits, these fuses can also be used in those
Fuse Description||Size||Manufacturer||Mfg #|
125-volt dc, RK5 Time delay, current-limiting||0.1-600
125-volt dc, RK5 Time delay, current-limiting||0.1-600
dc, RK5 Time delay, current-limiting fuse||0.1-600-amp||Bussmann||FRS-R|
300-volt dc, RK5 Time delay, current-limiting fuse||
dc, RK5 Time delay, current-limiting fuse||0.1-600
dc, RK5 Time delay, current-limiting fuse||0.1-600
dc, RK5 Time delay, current-limiting fuse||70-600
following fuses should be used for PV source-circuit protection if
problems are not anticipated with transients. They may also be used
inside control panels to protect relays and other equipment.
Fuse Description||Size||Manufacturer||Mfg #|
Fast-acting, midget fuse || 0.1-30 amp||Gould||ATM|
Fast-acting, midget fuse|| 0.1-30 amp||Littelfuse||KLK-D|
ENCLOSURES AND JUNCTION BOXES
and outdoor (rainproof) general-purpose enclosures and junction boxes
are available at most electrical supply houses. These devices usually
have knockouts for cable entrances, and the distributor will stock the
necessary bushings and/or cable clamps. Interior component
mounting panels are available for some enclosures, as are enclosures
with hinged doors. If used outdoors, all enclosures, clamps, and
accessories must be listed for outdoor use [110.3(B)]. For visual
access to the interior, NEMA 4X enclosures are available that are made
of clear, transparent plastic.
Hydrocap® Vents are available from Hydrocap Corp. and some PV
distributors on a custom-manufactured basis.
975 NW 95 St.
Miami, FL 33150
APPENDIX B: PV Module Operating Characteristics Drive
the photovoltaic (PV) power industry moves into a mainstream position
in the generation of electrical power, some people question the
seemingly conservative requirements established by Underwriters
Laboratories (UL) and the National Electrical Code (NEC) for
installation safety. This short discourse will address those concerns
and highlight the unique characteristics of PV systems that dictate the
The National Electrical Code (NEC) is written with
the requirement that all equipment and installations are approved for
safety by the authority having jurisdiction (AHJ) to enforce the NEC
requirements in a particular location. The AHJ readily admits to not
having the resources to verify the safety of the required equipment and
relies exclusively on the testing and listing of the equipment by
independent testing laboratories such as Underwriters Laboratories
(UL). The AHJ also relies on the installation requirements for field
wiring specified in the NEC to ensure safe installations and use of the
The standards published by UL and the material
in the NEC are closely harmonized by engineers and technicians
throughout the electrical equipment industry, the electrical
construction trades, the national laboratories, the scientific
community, and the electrical inspector associations. The UL Standards
are technical in nature with very specific requirements on the
construction and testing of equipment for safety. They in turn are
coordinated with the construction standards published by the National
Electrical Manufacturers Association (NEMA). The NEC, however, is
deliberately written in a manner to allow uniform application by
electricians, electrical contractors, and electrical inspectors in the
The use of listed equipment (by UL or other nationally
recognized testing laboratory) ensures that the equipment meets
well-established safety standards. The application of the requirements
in the NEC ensures that the listed equipment is properly connected with
field wiring and is installed in a manner that will result in an
essentially hazard-free system. The use of listed equipment and
installing that equipment according to the requirements in the NEC will
contribute greatly not only to safety, but also the durability,
performance, and longevity of the system.
NEC does not present many highly detailed technical specifications. For
example, the term "rated output" is used in several cases with respect
to PV equipment. The conditions under which the rating is determined
are not specified. The definitions of the rating conditions (such as
Standard Test Conditions (STC) for PV modules) are made in the UL
Standards that establish the rated output. This procedure is
appropriate because of the NEC level of writing and the lack of
appropriate test equipment available to the NEC user or inspector.
NEC REQUIREMENTS BASED ON MODULE PERFORMANCE
690.7 of the NEC establishes a temperature-dependent voltage correction
factor that is to be applied to the rated (at STC) open-circuit voltage
(Voc) in order to establish the system voltage. This factor on the
open-circuit voltage is needed because, as the operating temperature of
the module decreases, Voc increases. The rated Voc is measured at a
temperature of 25°C and while the normal operating temperature is
40-50°C when ambient temperatures are around 20°C, there is
nothing to prevent sub-zero ambient temperatures from yielding
operating temperatures significantly below the 25°C standard test
A typical crystalline silicon module will have a
voltage coefficient of -0.38%/°C. A system with a rated
open-circuit voltage of 595 volts at 25°C might be exposed to
ambient temperatures of -30°C. This voltage (595V) could be handled
by the common 600-volt rated conductors and switchgear. At dawn and
dusk conditions, the module will be at the ambient temperature of
-30°C, will not experience any significant solar heating, and can
generate open-circuit voltages of 719 volts (595 x (1 + (25 - 30) x
-0.0038)). This voltage substantially exceeds the capability of
600-volt rated conductors, fuses, switchgear, and other equipment. High
wind speeds can also cause modules to operate at or near ambient
temperatures, even in the presence of moderate levels of sunlight. The
very real possibility of this type of condition substantiates the NEC
requirement for the temperature dependent factor on the rated
Thin-film PV technologies may have other
voltage-temperature relationships, and the manufacturers of modules
employing such technologies should be consulted for the appropriate
NEC Section 690.8(A) requires that the rated
(at STC) short-circuit current of the PV module be multiplied by 125%
before any other factors, such as continuous current and conduit fill
factors, are applied. This factor is to provide a safe margin for wire
sizes and overcurrent devices when the irradiance exceeds the standard
1000 W/m2. Depending on season, local weather conditions, and
atmospheric dust and humidity, irradiance exceeds 1000 W/m2 every day
around solar noon. The time can be as long as four hours with
irradiance values that approach 1200 W/m2, again depending on the
aforementioned conditions and the type of tracking system being used.
These daily irradiance values can increase short-circuit currents 20%
over the 1000 W/m2 value. Since these increased currents can be present
for three hours or more, they are considered continuous currents. By
multiplying the short-circuit current by 125%, the PV output currents
are adjusted in a manner that puts them on the same basis as other
continuous currents in the NEC
Enhanced irradiance due to
reflective surfaces such as sand, snow, or white roofs, and even nearby
bodies of water can increase short-circuit currents by substantial
amounts and for significant periods of time. Reflections from cumulus
clouds also can increase irradiance by as much as 50%. These transient
factors are not considered continuous and are not addressed by either
UL or the NEC
Another factor that needs to be addressed is that
PV modules typically operate at 30-40°C above the ambient
temperatures when not exposed to cooling breezes. In crystalline
silicon PV modules, the short-circuit current increases as the
temperature increases. A typical factor might be 0.1%/°C. If the
module operating temperature was 60°C (35°C over the STC of
25°C), the short-circuit current would be 3.5% greater than the
rated value. PV modules have been measured operating over 75°C. The
combination of increased operating temperatures, irradiances over 1000
W/m2 around solar noon, and the possibility of enhanced irradiance
provide additional justification for the NEC requirement [690.8(A)] of
125% on the rated short-circuit current.
ADDITIONAL NEC REQUIREMENTS
NEC requires that the continuous current of any circuit be multiplied
by 125% before calculating the ampacity of any cable or the rating of
any overcurrent device used in these circuits [690.8(B) and 240]. This
factor is in addition to the required 125% discussed above and is
needed to ensure that overcurrent devices and conductors are not
operated above 80% of rating.
Since short-circuit currents in
excess of the rated value are possible from the discussion of the
Section 690.8(A) requirements above, and these currents are independent
of the requirements established by Section 690.8(B), the NEC dictates
that both factors will be used at the same time. This yields a
multiplier on short-circuit current of 1.56 (125% x 125%).
NEC also requires that the ampacity of conductors be derated for the
operating temperature of the conductor. This is a requirement because
the ampacity of cables is given for cables operating in an ambient
temperature of 30°C. In PV systems, cables are operated in an
outdoor environment and should be subjected at least to a temperature
derating due to an ambient temperature of 40°C to 45°C. PV
modules operate at high temperatures and, in some installations, may be
over 75°C. Concentrating modules operate at even higher
temperatures. The temperatures in module junction boxes approach these
temperatures. Conductors in free air that lie against the back of these
modules are also exposed to these temperatures. These high temperatures
require that the ampacity of cables be derated by factors of 0.33 to
0.58 depending on cable type, installation method (free air or
conduit), and the temperature rating of the insulation [310.16, 310.17].
in conduit where the conduit is exposed to the direct rays of the sun
are also exposed to elevated operating temperatures.
insulation rated at 60°C have no ampacity at all when operated in
environments with ambient temperatures over 55°C. This precludes
their use in most PV systems. Cables with 75°C insulation have no
ampacity when operated in ambient temperatures above 70°C. Because
PV modules may operate at temperatures in the 45-75°C range, it is
strongly suggested that only cables with an insulation rated at
90°C be used.
The conditions under which PV
modules operate (high and low ambient temperatures, high and low winds,
high and low levels of sunlight) and the electrical characteristics of
those modules dictate that all of the requirements in the NEC be fully
considered and applied.
There appears to be little question that
the temperature-dependent correction factor on voltage is necessary in
any location where the ambient temperature drops below 25°C. Even
though the PV system can provide little current under open-circuit
voltage conditions, these high voltages can damage electronic equipment
and stress conductors and other equipment by exceeding their voltage
In ambient temperatures from 25 to 40°C
and above, module short-circuit currents are increased at the same time
conductors are being subjected to higher operating temperatures.
Irradiance values over the standard rating condition may occur every
day. Therefore the NEC requirements for adjusting the short-circuit
current are necessary to ensure a safe and long-lived system.
APPENDIX C: Utility-Interactive Systems
(grid-connected) systems present some unique challenges for the PV
designer and installer in meeting the NEC.
inverters that connected to the utility grid should meet the
requirements established by UL Standard 1741 and be so listed. Some of
the larger inverters cannot have both the dc PV circuits and the ac
output circuits grounded as required by code without causing
operational and functional problems. These units require an
external ac isolation transformer. Newer versions of these inverters
may have solutions for this problem, and the 2005 NEC will allow
ungrounded PV systems as are used in Europe.
part 690 VII and section 690.64 provide some detailed requirements for
connecting the utility-interactive inverter to the utility. Most
are relatively clear. However, 690.64(B)(2) needs elaboration.
Consider the diagram of a backfed commercial load center shown in
In this figure, a 400-amp load center has a
400-amp main breaker (a common arrangement where the main breaker is
sized the same as the load center rating). The maximum continuous
loads on the load center, in a properly designed system, should not
exceed 320 amps (80% of the main breaker rating). Although the
sum of the rating of the circuit breakers supplying loads connected to
the panel will usually significantly exceed the rating of the panel,
the actual loads should be less than 320 amps. Otherwise, the
main breaker would trip on the overloads, thereby protecting the load
center and the feeder.
A utility-interactive PV system
is connected to this panel through a 100-amp backfed circuit breaker
installed as shown at or near the top of the load center. As long
as the loads on the system do not exceed 320 amps, no problems exist as
far as safety.
However, at some later date, the loads on the
load center may increase. This may be due to added circuits,
which should be installed by an electrician or by just increasing the
existing plug loads. For example, office modules with outlets may
be added with high desktop publishing loads. If the extra loads
are present only during the daytime, the main breaker will not trip
since the PV system will be picking up the excess loads. However,
the bus bar in the load center at point B will be carrying more than
its 400-amp rating. Up to 400 amps can be supplied to the load
center through the main breaker and up to 100 amps can be supplied
through the backfed PV breaker. This current of up to 500 amps
will cause excess heating of the bus bar. It may cause nuisance
tripping of breakers in the load center and may also result in
premature failure of the load center or the circuit breakers. No
circuit breakers will be overloaded, none will trip, and no one will be
alerted to the problem. In any event, the load center is being
used in a manner for which it was not designed. In fact, NEC
requirements generally dictate that the load center bus bars will not
be required to handle more than 320 amps on a continuous basis.
Figure C-1. 400 Amp Panel – Commercial PV Installation
the requirement of 690.64(B)(2) ensures that the currents being
supplied by the PV system (as limited by the backfed breaker) plus the
currents supplied by the utility (as limited by the main circuit
breaker) will not exceed the rating of the load center. In
commercial installations, each feeder panel subject to backfed PV
currents must meet the requirements of 690.64(B)(2).
In commercial installations, the requirements of 690.64(B)(2) may be
met in several ways.
If the existing load center is fully loaded (i.e. 320 amps on a 400-amp
load center), then the load center may be replaced with a larger unit
(i.e. 600 amps) with a smaller main breaker (i.e. 400 amps). This
will leave 200 amps of capacity for backfeeding PV.
When an analysis of the electrical system reveals that several load
centers (feeder panels) in the building need to be replaced/upgraded to
handle backfed PV currents, it is usually easier to install a second
service entrance on the building. In this case the service
entrance conductors between the utility meter and the primary service
disconnect can be tapped and routed to a dedicated disconnect which
serves as a second service entrance just for the PV system.
PV SOURCE-CIRCUIT CONDUCTORS
older grid-tied inverters operate with PV arrays that are center tapped
and have cold-temperature open-circuit voltages of ±325 volts
and above. The system voltage of 650 volts or greater exceeds the
insulation rating of the commonly available 600-volt insulated
conductors. Each disconnect and overcurrent device and the insulation
of the wiring must have a voltage rating exceeding the system voltage
rating [110.3(B)]. Type G and W cables are available with the higher
voltage ratings, but are flexible cords and do not meet NEC
requirements for fixed installations. Cables suitable for NEC
installations requiring insulation greater than 600 volts are available
Other older inverters have been designed to
operate on systems with open-circuit voltages exceeding ±540
volts requiring conductors with 2000-volt or higher insulation. See
Appendix D for a full discussion of this area.
UL tests and lists fuses for dc operation, the voltage rating is
frequently one-half the ac voltage rating. This results in a 600-volt
ac fuse rated for 300-volt dc. Fuses with high enough dc ratings for
grid systems operating at ±300 volts or 600 volts to ground
(600-volt system voltage) need to be carefully selected. There
are a number of listed, dc-rated 600-volt fuses available. See Appendix
BACKFED CIRCUIT BREAKERS, THE NATIONAL ELECTRICAL CODE AND UL
Utility-Interactive PV Systems
Section 690.64(B)(5) of the National Electrical Code (NEC)
that backfed circuit breakers be identified for the use.
Laboratories (UL) standards indicate that any circuit breaker that is
not marked “Line” and “Load” is identified as
suitable for backfeeding. Most circuit breakers used in
residential and commercial load centers are not marked
“Line” and “Load” and are suitable for
It should be noted that when the ac output of a
utility-interactive inverter is connected to a circuit breaker, the
current/power flow through the breaker is indeed backward. The
closed breaker, connected in only one of the current-carrying
conductors, is not affected by which way the ac power or current is
flowing. However, when a fault occurs in this circuit, it will be
grid current flowing through the breaker in the forward direction
toward a fault in the inverter side that causes the breaker to
trip. There is no reverse current or backfeeding of current in
this breaker under fault conditions.
Section 408.16(F) of the NEC requires that “plug-on”
backfed circuit breakers be clamped to the load center.
certainly a valid requirement when the circuit breaker under discussion
is a backfed main breaker. It would also be valid when the
backfed breaker was connected to a voltage source such as a rotating
generator. In both cases, pulling the circuit breaker from the
load center bus bars could result in a energized surface (the plug-on
contact) exposed on the breaker—either at grid voltage or voltage
from the output of the generator. However, if an unqualified
person has access the exposed panel, there is at least as great a
hazard from the exposed bus bars and main lugs as from the possibly
energized breaker contact.
This requirement also originated in
the days of exposed industrial panel boards that did not have dead
fronts and where the plug-on breakers were easily accessed and pulled
off without much thought.
3. In PV systems,
where the backfed breaker is being fed by the output of a
utility-interactive PV inverter identified and listed for such use, the
situation changes substantially.
IEEE Standards 929 and 1547 and
UL Standard 1741 require that utility interactive inverters cease
exporting power within 0.1 seconds upon loss of ac utility voltage
(voltage below 50% of nominal). This means that when a backfed
breaker from a PV utility-interactive inverter is pulled off of a load
center bus bar, the breaker essentially becomes completely de-energized
in a fraction of a second; probably before it is moved more that a
small fraction of an inch away from the bus bars. There is no electric
shock hazard from either terminal on the circuit breaker after it has
been disconnected from the bus bar.
Furthermore all currently
available load centers, both residential and commercial, have dead
front covers that are fastened with one to four or more screws.
This very effectively clamps all internal circuit breakers to the bus
bars. Although not explicitly stated, there is an implicit
“rule” in the code that a tool must be used to gain access
to energized circuits. This applies nearly universally from the
screw-cover on an ac receptacle outlet or ac wall switch to the screw
covers on terminal boxes and termination boxes for transformers, motors
and other equipment.
If the unqualified or qualified person
gains access by removing the clamping front cover on a load center with
backfed breakers, the exposed main lugs and the exposed bus bars pose
greater immediate shock hazards than the backfed breaker which has not
yet even been unplugged.
There appears to be no
safety hazard (either shock or fire) that would require backfed circuit
breakers connected to the output of utility-interactive PV inverters to
be clamped to the load center bus bars.
utility-interactive inverters operate at dc PV voltages in the 250-600
volt range and these voltages preclude the use of a circuit breaker as
a dc disconnect. In most cases, a fused or unfused safety switch
is used as a disconnect. These safety switches normally require
that two of the three poles be wired in series to achieve the 600-volt
dc rating and these two poles are then used to open the ungrounded
positive PV conductor. This requirements dictate that one switch
be used for each inverter or for each string of PV modules.
the smaller inverters (up to about 3.5-4 kW), the dc currents are in
the 10-15 amp range. Square D has obtained a special listing on
their three-pole, 600-volt fused (H361) and unfused (HU361) Heavy Duty
Safety Switches that allows them to be used on PV systems with only one
switch pole per string of PV modules or one switch pole per inverter
where the maximum currents are less than about 18 amps (rated
short-circuit currents less than 11 amps).
NEC does not require blocking diodes. The language of the code
simply allows their use, which is rapidly declining. The
use of the required overcurrent device in each series string of modules
provides the necessary reverse-current protection.
diodes are not overcurrent devices. They block reverse currents in
direct-current circuits and help to control circulating ground-fault
currents if used in both ends of high-voltage strings. Lightning
induced surges are tough on diodes. If isolated case diodes are used,
at least 3500 volts of insulation is provided between the active
elements and the normally grounded heat sink. Choosing a peak reverse
voltage as high as is available but at least twice the PV open-circuit
voltage will result in longer diode life. Substantial amounts of surge
suppression will also improve diode longevity.
may not be substituted for the UL-1703 requirement for module
protective fuses in each series-connected string of modules.
suppression is covered only lightly in the NEC because it affects
system performance more than safety. Surges are a utility problem
at the transmission line level in ac systems . PV arrays mounted
in the open, on the tops of buildings, act like lightning rods. The PV
designer and installer should provide appropriate means to deal with
lightning-induced surges coming into the system.
grounding conductors should be routed directly to supplementary ground
rods located as near as possible to the arrays [250.54].
conduit will add inductance to the array-to-building conductors and
slow down any induced surges as well as provide some electromagnetic
Metal oxide varistors (MOV) commonly used as surge
suppression devices on electronic equipment have several deficiencies.
They draw a small amount of current continually. The clamping voltage
lowers as they age and may reach the open-circuit voltage of the
system. When they fail, they fail in the shorted mode, heat up, and
frequently explode or catch fire. In many installations, the MOVs are
protected with fast acting fuses to prevent further damage when they
fail, but this may limit their effectiveness as surge suppression
devices. Other electronic devices are becoming available that do not
change performance characteristics as they age or are subjected to
Several companies specialize in lightning protection
equipment, but much of it is for ac systems. Electronic product
directories, such as the Electronic Engineers Master Catalog should be
APPENDIX D: Cable and Device Ratings at High Voltages
is a concern in designing PV systems that have system open-circuit
voltages above 600 volts. The concern has two main issues—device
ratings and NEC limitations.
discontinued, out of production, utility-intertie inverters operate
with a grounded, bipolar (three-wire) PV array. In a bipolar PV system,
where each of the monopoles is operated in the 220-235-volt peak-power
range, the open-circuit voltage can be anywhere from 290 to 380 volts,
depending on the module characteristics such as fill-factor. Such a
bipolar system can be described as a 350/700-volt system (for example)
in the same manner that a 120/240-volt ac system is described. This
method of describing the system voltage is consistent throughout the
electrical codes used not only in residential and commercial power
systems, but also in utility practice.
In all systems, the
voltage ratings of the cable, switchgear, and overcurrent devices are
based on the higher number of the pair (i.e., 700 volts in a
350/700-volt system). That is why 250-volt switchgear and overcurrent
devices are used in 120/240-volt ac systems and 600-volt switchgear is
used in systems such as the 277/480-volt ac system. Note that it is not
the voltage to ground, but the higher line-to-line voltage that defines
the equipment voltage requirements.
The National Electrical Code
(NEC) defines a nominal voltage for ac systems (120, 240, etc.) and
acknowledges that some variation can be expected around that nominal
voltage. Such a variation around a nominal voltage is not considered in
dc PV systems, and the NEC requires that a temperature-related
connection factor on the open-circuit array voltage must be used
[690.7(A). The open-circuit voltage is defined at Standard Test
Conditions (STC) because of the relationship between the UL Standards
and the way the NEC is written. The NEC Handbook elaborates on the
definition of “circuit voltage,” but this definition may
not apply to current-limited dc systems. Section 690.7(A) of the NEC
requires that the voltage used for establishing dc circuit requirements
in PV systems be the computed open-circuit voltage for crystalline PV
technologies. In new thin-film PV technologies, open-circuit voltages
are determined from manufacturers’ specifications for temperature
The Code specifically defines the PV system
voltage as the product of a temperature-dependent factor (that may
reach 1.25 at –40°C) and the STC open-circuit voltage
[690.7]. The systems voltage is also defined as the highest voltage
between any two wires in a 3-wire (bipolar) PV system [690.2].
comparison to ac systems can be carried too far; there are differences.
For example, the typical wall switch in a 120/240-volt ac residential
or commercial system is rated at only 120 volts, but such a switch in a
120/240-volt dc PV system would have to be rated at 240 volts. The
inherent differences between a dc current source (PV modules) and a
voltage source (ac grid) bear on this issue. Even the definitions of
circuit voltage in the NEC and NEC Handbook refer to ac and dc systems,
but do not take into account the design of the balance of systems
required in current-limited PV systems. In a PV system, all wiring,
disconnects, and overcurrent devices have current ratings that exceed
the short-circuit currents by at least 25%. In the case of bolted
faults or ground faults involving currents from the PV array, the
overcurrent devices do not trip because they are rated to withstand
continuous operation at levels above the fault levels. In an ac system,
bolted faults and ground faults generally cause the overcurrent devices
to trip or blow removing the source of voltage from the fault.
Therefore, the faults that pose high-voltage problems in PV, dc systems
cause the voltage to be removed in ac, grid-supply systems. For these
reasons, a switch rated at 120 volts can be used in an ac system with
voltages up to 240 volts, but in a dc, PV system, the switch would have
to be rated at 240 volts.
Another consideration that we are
dealing with is the analogy of dc supply circuit and ac load circuits.
An analysis of ac supply circuits would be similar to dc supply
Underwriters Laboratories (UL) Standard 1703 requires
that manufacturers of modules listed to the standard include, in the
installation instructions, a statement that the open-circuit voltage
should be multiplied by 125% (crystalline cells), further increasing
the voltage requirement of the balance-of-systems (BOS) equipment. This
requirement has been in the NEC Section 690.7 as a
temperature-dependent constant since the 1999 edition of the Code.
PV modules that are listed to the UL Standard 1703 are listed with a
maximum system voltage of 600 volts. A few are listed to 1000
volts to meet European standards. Engineers caution all
installers, factory and otherwise, to not exceed this voltage. This
restriction is not modified by the fact that the modules undergo
high-pot tests at higher voltages.
Although not explicitly
stated by the NEC, it is evident that the intent of the Code and the UL
Standards is that all cable, switches, fuses, circuit breakers, and
modules in a PV system be rated for the maximum system voltage. This is
clarified in the 1999 NEC [690.7(A)].
While reducing the
potential for line-to-line faults, the practice of wiring each monopole
(one of two electrical source circuits) in a separate conduit to the
inverter does not eliminate the problem. Consider the bipolar system
presented in Figure D-1 with a bolted fault (or deliberate short) from
the negative to the positive array conductor at the input of the
inverter. With the switches closed, array short-circuit current flows,
and neither fuse opens.
Figure D-1. Typical Bipolar System with Fault
Now consider what happens in any of the following cases.
1. A switch is opened
2. A fuse opens
3. A wire comes loose in a module junction box
4. An intercell connection opens or develops high
5. A conductor fails at any point
any of these cases, the entire array voltage (740 volts) stresses the
device where the circuit opens. This voltage (somewhere between zero at
short-circuit and the array open-circuit voltage) will appear at the
device or cable. As the device starts to fail, the current through it
goes from Isc to zero as the voltage across the device goes from zero
to Voc. This process is very conducive to sustained arcs and heating
Separating the monopoles does not avoid the high-voltage
stress on any component, but it does help to minimize the potential for
some faults. There are other possibilities for faults that will also
place the same total voltage on various components in the system. An
improperly installed grounding conductor coupled with a module ground
fault could result in similar problems.
Section 690.5 of the NEC
requires a ground-fault device on PV systems that are installed on the
roofs of dwellings. This device, used for fire protection, must detect
the fault, interrupt the fault current, indicate the fault, and
disconnect the array.
Some large (100 kW) utility-interactive PV
systems like the one at Juana Diaz, Puerto Rico have inverters that,
when shut down, crowbar the array. The array remains crowbarred until
the ac power is shut off and creates a similar fault to the one
pictured in Figure D-1.
NEC VOLTAGE LIMITATION
The second issue
associated with this concern is that the NEC in Section 690.7(C) only
allows PV installations up to 600 volts in one and two-family
dwellings. Inverter and system design issues may favor higher system
System designers can select
inverters with lower operating and open-circuit voltages.
Utility-intertie inverters are available with dc input voltages as low
as 24 volts. The system designer also can work with the manufacturers
of higher voltage inverters to reduce the number of modules in each
series string to the point where the cold-temperature open-circuit
voltage is less than 600 volts. The peak-power voltage would also be
lowered. Transformers may be needed to raise the inverter ac output
voltage to the required level. All utility-interactive inverters listed
in the US operate with PV arrays that have open-circuit voltages of
less than 600 volts.
Cable manufacturers produce UL-Listed,
cross-linked polyethylene, single-conductor cable. It is marked
USE-2/RHW-2, Sunlight Resistant and is rated at 2000 volts. This cable
could be used for module interconnections in conduit after all of the
other NEC requirements are met for installations above 600 volts.
manufacturers issue factory certified rating on their three-pole
disconnects to allow higher voltage, non-load break operation with
series-connected poles. The NEC will require an acceptable method of
obtaining non-load break operation.
Some OEM circuit breaker
manufacturers will factory certify series-connected poles on their
circuit breakers. Units have been used at 750 volts and 100 amps with
10,000 amps of interrupt rating. Higher voltages may be available.
High-voltage industrial fuses are available, but dc ratings are unknown
at this time.
Individual 600-volt terminal blocks can be used with the proper spacing
for higher voltages.
Module manufacturers can have their modules listed for higher system
voltages. Most are currently limited to 600 volts.
diodes may be connected across each monopole. When a bolted
line-to-line fault occurs, one of the diodes will be forward biased
when a switch or fuse opens, thereby preventing the voltage from one
monopole from adding to that of the other monopole. The diodes are
mounted across points A-B and C-D in Figure D-1. Each diode should be
rated for at least the system open-circuit voltage and the full
short-circuit current from one monopole. Since diodes are not listed as
over-voltage protection devices, this solution is not recognized in the
The NEC allows PV installations over 600 volts in
non-residential applications, which will cover the voltage range being
used in most current designs.
It should be noted that there are
numerous requirements throughout the NEC that apply specifically to
installations over 600 volts:
690.7(E) allows specially configured and listed inverters to be used in
a system where the voltages are measured line-to-ground rather than
APPENDIX E: Example Systems
systems described in this appendix and the calculations shown are
presented as examples only. The calculations for conductor sizes and
the ratings of overcurrent devices are based on the requirements of the
National Electrical Code (NEC) and on UL Standard 1703
instructions for the installation of UL-Listed PV modules. Local codes
and site-specific variations in irradiance, temperature, and module
mounting, as well as other installation particularities, dictate that
these examples should not be used without further refinement. Tables
310.16 and 310.17 from the NEC provide the ampacity data and
temperature derating factors.
CABLE SIZING AND OVERCURRENT PROTECTION
procedure presented below for cable sizing and overcurrent protection
of that cable is based on NEC requirements in Sections 690.9, 690.8,
110.14(C), 210.20(A), 215.2, 215.3, 220.10, 240.3(B), and
240.6(A). See Appendix I for a slightly different method of
making ampacity calculations based on the same requirements.
Circuit Current. For circuits carrying currents from PV modules,
multiply the short-circuit current by 125% and use this value for all
further calculations. For PV circuits in the following examples, this
is called the CONTINUOUS CURRENT calculation. In the Code, this
requirement has been included in Section 690.8, but also remains in UL
1703. This multiplier should not be applied twice. For dc and ac
inverter circuits in PV systems, use the rated continuous currents.
These currents are continuous by definition and are not multiplied by
125% at this step. AC and dc load circuits should follow the requirements of Sections 210,
220, and 215.
Overcurrent Device Rating.
The overcurrent device must be rated at 125%
of the current determined in Step 1. This is to prevent overcurrent
devices from being operated at more than 80% of rating. This
calculation, in the following examples, is called the 80% OPERATION. If
the overcurrent device is operating in ambient temperatures above
40°C, the rating of the device must be adjusted based on data
obtained from the manufacturer. See Step 7.
Cable Sizing. Cables shall have a 30°C ampacity of 125% of the
continuous current determined in Step 1 to ensure proper operation of
connected overcurrent devices. There are no additional deratings
applied with this calculation.
Derating. Based on the determination of Step 3 and the location of the
cable (raceway or free-air), a cable size and insulation temperature
rating (60, 75, or 90°C) are selected from the NEC Ampacity Tables
310.16 or 310.17. Use the 75°C (a short-cut) cable ampacities to
get the size, then use the ampacity from the 90°C column—if
needed—for the deratings. This cable is then derated for
temperature, conduit fill, and other requirements. The resulting
derated ampacity must be greater than the value found in Step 1. No
125% multiplier is used for this determination. If not greater, then a
larger cable size or higher insulation temperature must be selected.
The current in Step 3 is not used at this point to preclude over sizing
Ampacity vs. Overcurrent
Device. The derated ampacity of the cable selected in Step 4 must be
equal to or greater than the overcurrent device rating determined in
Step 2 [240.4]. If the derated ampacity of the cable is less than the
rating of the overcurrent device, then a larger cable must be selected.
The next larger standard size overcurrent device may be used if the
derated cable ampacity falls between the standard overcurrent device
sizes found in NEC Section 240.6.
Note: This step may result in a larger conductor size than that
determined in Step 4.
Device Terminal Compatibility. Since most overcurrent devices have
terminals rated for use at a maximum temperature of 75°C (or
60°C), compatibility must be verified [110.3(B)]. If a
90°C-insulated cable was selected in the above process, the
30°C current of the same size cable with a 75°C (or 60°C)
insulation must be greater than or equal to the current found in Step
2, 125% of the continuous current [110.14(C)]. NEC Table 310.16 is
always used for this determination. This ensures that the cable
will operate at temperatures below the temperature rating of the
terminals of the overcurrent device. If the overcurrent device is
located in an area with ambient temperature higher than 30°C, then
the 75°C (or 60°C) current used to determine the maximum
allowable current for that size wire must also be derated by the
temperature correction factors at the bottom of the 75°C (or
60°C) column [110.3(B)].
Device Mounting. If the
overcurrent device is mounted in a location that has an ambient
temperature higher than 40°C (for example, in a PV combiner box),
then the rating of the device must be adjusted per manufacturer's
specifications with an increased rating. Verify that the OCPD still
protects the selected cable under conditions of use.
Here is an example of how the procedure is used:
task is to size and protect two PV source circuits in conduit, each
with an Isc = 40 amps. Four current-carrying conductors are in the
conduit and are operating in a 45°C ambient temperature.
Conductors with a 90°C insulation are going to be used. The
fuse is also in an ambient temperature of 40°C.
Step 1: 1.25 x 40 = 50 amps. (continuous current)
2: The required fuse (with 75°C terminals) is
1.25 x 50 = 62.5 amps. The next standard fuse size is 70 amps. (ensures
operation below 80% of rating). The fuse is operating in an
ambient temperature of 40°C, so no additional derating of the fuse
rating is required.
Step 3: Same calculation as Step 2. Cable ampacity
without deratings must be 62.5 amps.
4: From Table 310.16, cables with 75°C
insulation: A 6 AWG conductor at 65 amps is needed. This meets Step 3
requirements. At least a 6 AWG XHHW-2 cable with 90°C insulation
and a 30°C ampacity of 75 amps should be installed. Conduit fill
derating is 0.8 and temperature derating is 0.87. Derated ampacity is
52.2 amps (75 x 0.8 x 0.87). This is greater than the required 50 amps
in Step 1 and meets the requirement.
It is acceptable to protect a cable with a derated ampacity of 52.2
amps with a 60-amp overcurrent device since this is the next larger
standard size. However, this circuit requires at least a 62.5 amp
device (Step 2). Therefore, the conductor must be increased to a 4 AWG
conductor with a derated ampacity of 66 amps (95 x 0.87 x 0.8). A
70-amp fuse or circuit breaker is acceptable to protect this cable
since it is the next larger standard size.
6. The ampacity of a 4 AWG cable with 75°C
insulation (because the fuse has 75°C terminals) operating at
45°C is 70 amps (85 x .82), and is higher than the calculated
continuous circuit current of 50 amps found in Step 1. Using the
75°C column in Table 310.16 or 310.17 for starting Step 4 usually,
but not always ensures that this check will be passed.
EXAMPLE 1 Direct-Connected Water Pumping System
Array Size: 4, 12-volt, 60-watt modules; Isc = 3.8 amps, Voc = 21.1
Load: 12-volt, 10-amp motor
modules are mounted on a tracker and connected in parallel. The modules
are wired as shown in Figure E-1 with 10 AWG USE-2 single-conductor
cable. A loop is placed in the cable to allow for tracker motion
without straining the rather stiff building cable. The USE-2 cable is
run to a disconnect switch in an enclosure mounted on the pole. From
this disconnect enclosure, 8 AWG XHHW-2 cable in electrical nonmetallic
conduit is routed to the wellhead. The conduit is buried 18 inches
deep. The 8 AWG cable is used to minimize voltage drop.
requires the disconnect switch. Because the PV modules are current
limited and all conductors have an ampacity greater than the maximum
output of the PV modules, no overcurrent device is required, although
some inspectors might require it and it might serve to provide some
degree of lightning protection. A dc-rated disconnect switch or a
dc-rated fused disconnect must be used. Since the system is ungrounded,
a two-pole switch must be used. All module frames, the pole, the
disconnect enclosure, and the pump housing must be grounded with
equipment-grounding conductors, whether the system is grounded or not.
fuses shown connected to each module are required to protect the module
from reverse currents from all sources. In this system, the only
sources of potential reverse currents for an individual module are the
modules connected in parallel. Those other three (out of four
modules) could source 3 x 3.8 x 1.25=14.25 amps of current into a fault
in a single module. If the module series protective fuse were 15
amps or less, these fuses would not be required; the potential currents
could not damage any module. Of course, the conductors to each
module should also have an ampacity of 15 amps or greater if the fuses
were omitted. The 10 AWG USE-2 cable meets this requirement.
Figure E-1. Direct Connected System
The array short-circuit current is 15.2 amps (4 x 3.8).
CONTINUOUS CURRENT: 1.25 x 15.2 = 19 amps (Step 1)
No fuse, no Step 2
80% OPERATION: 1.25 x 19 = 23.75 amps (Step 3)
The ampacity of 10 AWG USE-2 at 30°C is 55 amps.
The ampacity at 61-70°C is 31.9 amps (0.58 x 55) which is more than
the 19 amp requirement. (Step 4)
The equipment grounding conductors should be 10 AWG (typically 1.25 Isc
with a 14 AWG minimum).
The minimum voltage rating of all components is 26 volts (1.25 x 21.1).
EXAMPLE 2 Water Pumping System with Current Booster
Array Size: 10, 12-volt, 53-watt modules; Isc = 3.4 amps, Voc = 21.7
Current Booster Output: 90 amps
Load: 12-volt, 40-amp motor
system has a current booster before the water pump and has more modules
than in Example 1. Initially, 8 AWG USE-2 cable was chosen for the
array connections, but a smaller cable was chosen to attach to the
module terminals. As the calculations below show, the array was split
into two subarrays. There is potential for malfunction in the current
booster, but it does not seem possible that excess current can be fed
back into the array wiring, since there is no other source of energy in
the system. Therefore, these conductors do not need overcurrent devices
if they are sized for the entire array current. If smaller conductors
are used, then overcurrent devices will be needed.
there are now 10 modules in parallel connected via the two 30-amp
circuit breakers. The potential reverse current from 9 modules
would be 9 x 3.4 x 1.25 = 38.25 amps. This is well in excess of
the ability of the module to handle reverse currents (possibly as low
as 10 amps), so a fuse or circuit breaker must be used in series with
each module. The minimum value would be 1.56 x 3.4 amps = 5.3
amps and the next higher standard value is 6 amps. These fuses
would normally be contained in a PV combiner mounted in the shade
behind the PV array.
Since the array is broken into two
subarrays, the maximum short-circuit current available in either
subarray wiring is equal to the subarray short-circuit current under
fault conditions plus any current coming back through one of the 30-amp
breakers form the other subarray. Overcurrent devices are needed to
protect the subarray conductors under these conditions.
grounded system is selected, and only single-pole disconnects are
required. Equipment grounding and system grounding conductors are shown
in Figure E-2
If the current booster output conductors are sized
to carry the maximum current (3-hour) of the booster, then overcurrent
devices are not necessary, but again, some inspectors may require them.
Figure E-2. Direct-Connected PV System with Current
The entire array short-circuit current is 34 amps (10 x 3.4).
CONTINUOUS CURRENT: 1.25 x 34 = 42.5 amps
80% OPERATION: 1.25 x 42.5 = 53.1 amps
The ampacity of 6 AWG USE-2 cable at 30°C in conduit is 75 amps.
ampacity at 45°C (maximum ambient air temperature) is 65.5 amps
(0.87 x 75), which is greater than the 42.5 amp requirement; so a
single array could have been used. However, the array is split into two
subarrays for serviceability. Each is wired with 10 AWG USE-2
The subarray short-circuit current is 17 amps (5 x 3.4).
CONTINUOUS CURRENT: 1.25 x 17 = 21.3 amps
80% OPERATION: 1.25 x 21.25 = 26.6 amps
The ampacity of 10 AWG USE-2 at 30°C in free air is 55 amps.
ampacity at 61-70°C (module operating temperature) is 31.9 amps
(0.58 x 55), which is more than the 21.3 amp requirement. Since this
cable is to be connected to an overcurrent device with terminals rated
at 60°C or 75°C, the ampacity of the cable must be evaluated
with 60°C or 75°C insulation. Overcurrent devices rated at 100
amps or less may have terminals rated at only 60°C. The ampacity of
10 AWG 75°C cable operating at 30°C is 35 amps, which is more
than the 26.6 amps requirement. Therefore, there are no problems with
the terminals on a 75°C overcurrent device.
circuit breakers are used to protect the 10 AWG subarray conductors.
The required rating is 1.25 x 21.25 = 26.6 amps, and the next largest
size is 30 amps. Note: The maximum allowed overcurrent
device for a 10AWG conductor is 30 amps [240.4(D)].
The current booster maximum current is 90 amps.
The current booster average long-term (3-hours or longer) current is 40
amps (continuous current).
80% OPERATION: 1.25 x 40 = 50 amps
The ampacity of 8 AWG XHHW-2 at 30°C in conduit is 55 amps.
ampacity does not need temperature correction since the conduit is
buried in the ground. The ampacity requirements are met, but the cable
size may not meet the overcurrent device connection requirements when
an overcurrent device is used.
The 6 AWG conductors are
connected to the output of the circuit breakers, and there is a
possibility that heating of the breaker may occur. It is therefore good
practice to make the calculation for terminal overheating. The ampacity
of a 6 AWG conductor evaluated with 75°C insulation (the rated
maximum temperature of the terminals on the overcurrent device) is 65
amps, which is greater than the 27-amp requirement. This means that the
overcurrent device will not be subjected to overheating when the 6 AWG
conductor carries 27 amps.
All equipment-grounding conductors should be 10 AWG. The grounding
electrode conductor should be 8 AWG or larger.
Minimum voltage rating of all components: 1.25 x 21.7 = 27 volts
EXAMPLE 3 Stand-Alone Lighting System
Array Size: 4, 12-volt, 64-watt modules; Isc = 4.0 amps, Voc = 21.3
Batteries: 200-amp-hours at 24 volts
Load: 60 watts at 24 volts
modules are mounted at the top of a 20-foot pole with the metal-halide
lamp. The modules are connected in series and parallel to achieve the
24-volt system rating. The lamp, with an electronic ballast and
timer/controller, draws 60 watts at 24 volts. The batteries, disconnect
switches, charge controller, and overcurrent devices are mounted in a
box at the bottom of the pole. The system is grounded as shown in
Figure E-3. Stand-Alone Lighting System
The array short-circuit current is 8 amps (2 x 4).
CONTINUOUS CURRENT: 1.25 x 8 = 10 amps
80% OPERATION: 1.25 x 10 = 12.5 amps
Load Current: 60/24 = 2.5 amps (continuous)
80% OPERATION: 1.25 x 2.5 = 3.1 amps
size 10 AWG USE-2/RHW-2 is selected for module interconnections and is
placed in conduit at the modules and then run down the inside of the
The modules operate at 61-70°C, which requires that
the module cables be temperature derated. Cable 10 AWG USE-2/RHW-2 has
an ampacity of 40 amps at 30°C in conduit. The derating factor is
0.58. The temperature-derated ampacity is 23.2 amps (40 x 0.58), which
exceeds the 10-amp requirement. Checking the cable with a 75°C
insulation, the ampacity at the fuse end is 35 amps, which exceeds the
12.5-amp requirement. This cable can be protected by a 15-amp fuse or
circuit breaker (125% of 10 is 12.5). An overcurrent device rated at
100 amps or less may only have terminals rated for 60°C, not the
75°C used in this example. Lower temperature calculations may be
The same USE-2/RHW-2, 10 AWG cable is selected for
all other system wiring, because it has the necessary ampacity for each
A three-pole fused disconnect is selected to provide
the PV and load disconnect functions and the necessary overcurrent
protection. The fuse selected is a RK-5 type, providing current
limiting in the battery circuits. A pullout fuse holder with either
Class RK-5 or Class T fuses could also be used for a more compact
installation. Fifteen-amp fuses are selected to provide overcurrent
protection for the 10 AWG cables. They are used in the load circuit and
will not blow on any starting surges drawn by the lamp or controller.
The 15-amp fuse before the charge controller could be eliminated since
that circuit is protected by the fuse on the battery side of the charge
controller. The disconnect switch at this location is required.
of the two strings of PV modules could be subjected to reverse currents
from the other string (1.25 x 4 = 5 amps) plus 15 amps from the battery
through the 15-amp fuse. If this 20-amp potential backfed current
exceeds the module series fuse requirement, then the string fuses and a
PV combiner must be added to the system.
The equipment-grounding conductors should be 10 AWG conductors. An 8
AWG (minimum) conductor would be needed to the ground rod.
The dc voltage ratings for all components used in this system should be
at least 53 volts (2 x 21.3 x 1.25).
EXAMPLE 4 Remote Cabin DC-Only System
Array Size: 6, 12-volt, 75-watt modules; Isc = 4.8 amps, Voc = 22 volts
Batteries: 700 amp hours at 12 volts
Load: 75 watts peak at 12-volts dc
modules are mounted on a rack on a hill behind the house. Nonmetallic
conduit is used to run the cables from the junction box to the control
panel. A control panel is mounted on the back porch, and the batteries
are in an insulated box under the porch. All the loads are dc with a
peak-combined power of 75 watts at 12 volts due, primarily, to a
pressure pump on the gravity-fed water supply. The battery bank
consists of four 350-amp-hour, 6-volt, deep-cycle batteries wired in
series and parallel. Figure E-4 shows the system schematic.
Figure E-4. Remote Cabin DC-Only System
The array short-circuit current is 28.8 amps (6 x 4.8).
CONTINUOUS CURRENT: 1.25 x 28.8 = 36 amps
80% OPERATION: 1.25 x 36.0 = 45 amps
module interconnect wiring and the wiring to a rack-mounted junction
box will operate at 65°C. If USE-2 cable with 90°C insulation
is chosen, then the temperature derating factor will be 0.58. The
required ampacity of the cable at 30°C is 62 amps (36/0.58), which
can be handled by 8 AWG cable with an ampacity of 80 amps in free air
at 30°C. Conversely, the ampacity of the 8 AWG cable is 46.4 amps
(80 x 0.58) at 65°C which exceeds the 36 amp requirement.
PV combiner with a fuse for each module will be required because the
available potential short-circuit current from these six modules in
parallel plus the 45-amps from the PV disconnect circuit breaker will
far exceed the maximum reverse current rating of a module.
the rack-mounted junction box to the control panel, the conductors will
be in conduit and exposed to 40°C temperatures. If XHHW-2 cable
with a 90°C insulation is selected, the temperature derating factor
is 0.91. The required ampacity of the cable at 30°C would be
36/0.91 = 39.6 amps in conduit. Cable size 8 AWG has an ampacity of 55
amps at 30°C in conduit. Conversely, the 8 AWG conductor has an
ampacity of 50 amps (55 x 0.91) at 40°C in conduit that exceeds the
39.6 amp requirement at this temperature.
The 8 AWG cable,
evaluated with a 75°C insulation, has an ampacity at 30°C of 50
amps, which is greater than the 45 amps that might heat the fuse
The array is mounted 200 feet from the house, and the
round trip cable length is 400 feet. A calculation of the voltage drop
in 400 feet of 8 AWG cable operating at 36 amps (125% Isc) is 0.778
ohms per 1000 feet x 400 / 1000 x 36 = 11.2 volts. This represents an
excessive voltage drop on a 12-volt system, and the batteries cannot be
effectively charged. Conductor size 2 AWG (with a voltage drop of 2.8
volts) was substituted; this substitution is acceptable for this
installation. The conductor resistances are taken from Table 8 in
Chapter 9 of the NEC and are given for conductors at 75°C.
PV conductors are protected with a 45-amp (1.25 x 36) single-pole
circuit breaker on this grounded system. The circuit breaker should be
rated to accept 2 AWG conductors and have terminals rated for use with
Cable size 6 AWG THHN cable is
used in the control center and has an ampacity of 65 amps at 30°C
when evaluated with 75°C insulation. Wire size 2 AWG from the
negative dc input is used to the point where the grounding electrode
conductor is attached instead of the 6 AWG conductor used elsewhere to
comply with grounding requirements.
The 75-watt peak load draws
about 6.25 amps and 10-2 with ground (w/gnd) nonmetallic sheathed cable
(type NM) was used to wire the cabin for the pump and a few lights.
DC-rated circuit breakers rated at 20 amps were used to protect the
load wiring, which is in excess of the peak load current of 7.8 amps
(1.25 x 6.25) and less than the cable ampacity of 30 amps.
fuses in a fused disconnect are used to protect the dc-rated circuit
breakers, which may not have an interrupt rating sufficient to
withstand the short-circuit currents from the battery under fault
conditions. RK-5 fuses were chosen with a 45-amp rating in the charge
circuit and a 30-amp rating in the load circuit. The fused disconnect
also provides a disconnect for the battery from the charge controller
and the dc load center.
The equipment grounding conductors
should be 10 AWG and the grounding electrode conductor should be 2
AWG. A smaller grounding electrode conductor (as small as 8 AWG)
may be acceptable to the local inspector.
All components should have a voltage rating of at least 1.25 x 22 =
EXAMPLE 5 Small Residential Stand-Alone System
Array Size: 10, 12-volt, 51-watt modules; Isc = 3.25 amps, Voc = 20.7
Batteries: 800 amp-hours at 12 volts
Loads: 5 amps dc and 500-watt inverter with 90% efficiency
PV modules are mounted on the roof. Single-conductor cables are used to
connect the modules to a roof-mounted junction box. Potential reverse
fault currents indicate that a PV combiner be used with a series fuse
for each PV module. UF two-conductor sheathed cable is used from
the roof to the control center. Physical protection (wood barriers or
conduit) for the UF cable is used where required. The control center,
diagrammed in Figure E-5, contains disconnect and overcurrent devices
for the PV array, the batteries, the inverter, and the
Figure E-5. Small Residential Stand-Alone System
The module short-circuit current is 3.25 amps.
CONTINUOUS CURRENT: 1.25 x 3.25 = 4.06 amps
80% OPERATION: 1.25 x 4.06 = 5.08 amps per module
The maximum estimated module operating temperature is 68°C.
From NEC Table 310.17:
The derating factor for USE-2 cable is 0.58 at 61-70°C.
14 AWG has an ampacity at 68°C of 20.3 amps (0.58 x 35) (max fuse
is 15 amps—see notes at bottom of Tables 310-16 & 17).
Cable 12 AWG has an ampacity at 68°C of 23.2 amps (0.58 x 40) (max
fuse is 20 amps).
Cable 10 AWG has an ampacity at 68°C of 31.9 amps (0.58 x 55) (max
fuse is 30 amps).
Cable 8 AWG has an ampacity at 68°C of 46.4 amps (0.58 x 80).
array is divided into two five-module subarrays. The modules in each
subarray are wired from module junction box to the PV combiner for that
subarray and then to the array junction box. Cable size 10 AWG USE-2 is
selected for this wiring, because it has an ampacity of 31.9 amps under
these conditions, and the requirement for each subarray is 5 x 4.06 =
20.3 amps. Evaluated with 75°C insulation, a 10 AWG cable has an
ampacity of 35 amps at 30°C, which is greater than the actual
requirement of 20.3 amps (5 x 4.06) [Table 310.16 must be used]. In the
array junction box on the roof, two 30-amp fuses in pullout holders are
used to provide overcurrent protection for the 10 AWG conductors. These
fuses meet the requirement of 25.4 amps (125% of 20.3) and have a
rating less than the derated cable ampacity.
In this junction
box, the two subarrays are combined into an array output. The ampacity
requirement is 40.6 amps (10 x 4.06). A 4 AWG UF cable (4-2 w/gnd) is
selected for the run to the control box. It operates in an ambient
temperature of 40°C and has a temperature-corrected ampacity of 86
amps (95 x 0.91). This is a 60°C cable with 90°C conductors and
the final ampacity must be restricted to the 60°C value of 70 amps,
which is suitable in this example. Appropriately derated cables
must be used when connecting to fuses that are rated for use only with
A 60-amp circuit breaker in the control box
serves as the PV disconnect switch and overcurrent protection for the
UF cable. The minimum rating would be 10 x 3.25 x 1.56 = 51 amps.
The NEC allows the next larger size; in this case, 60 amps, which will
protect the 70 amp rated cable. Two single-pole, pullout fuse holders
are used for the battery disconnect. The charge circuit fuse is a
60-amp RK-5 type.
The inverter has a continuous rating of 500
watts at the lowest operating voltage of 10.75 volts and an efficiency
of 90% at this power level. The continuous current calculation for the
input circuit is 64.6 amps ((500 / 10.75 / 0.90) x 1.25).
cables from the battery to the control center must meet the inverter
requirements of 64.6 amps plus the dc load requirements of 6.25 amps
(1.25 x 5). A 4 AWG THHN has an ampacity of 85 amps when placed in
conduit and evaluated with 75°C insulation. This exceeds the
requirements of 71 amps (64.6 + 6.25). This cable can be used in the
custom power center and be run from the batteries to the inverter.
The discharge-circuit fuse must be rated at least 71 amps. An 80-amp
fuse should be used, which is less than the cable ampacity.
The dc-load circuit is wired with 10 AWG NM cable (ampacity of 30 amps)
and protected with a 15-amp circuit breaker.
grounding electrode conductor is 4 AWG and is sized to match the
largest conductor in the system, which is the array-to-control center
wiring. This size would be appropriate for a concrete-encased
Equipment-grounding conductors for the
array and the charge circuit can be 10 AWG based on the 60-amp
overcurrent devices. The equipment ground for the inverter must be an 8
AWG conductor based on the 80-amp overcurrent device. [Table 250.122]
All components should have at least a dc voltage rating of 1.25 x 20.7
= 26 volts.
EXAMPLE 6 Medium Sized Residential Hybrid System
Array Size: 40, 12-volt, 53-watt modules; Isc = 3.4 amps, Voc = 21.7
Batteries: 1000 amp-hours at 24 volts
Generator: 6 kW, 240-volt ac
Loads: 15 amps dc and 4000-watt inverter, efficiency =.85
40 modules (2120 watts STC rating) are mounted on the roof in five
subarrays consisting of eight modules mounted on a single-axis tracker.
The eight modules are wired in series and parallel for this 24-volt
system. Five source circuits are routed to a custom power center.
Single-conductor cables are used from the modules to roof-mounted PV
combiners for each source circuit. The fuse for each series
string of modules is rated at least 1.56 times the module Isc, but less
than or equal to the maximum module protective fuse marked on the back
of the module. From the combiners, UF sheathed cable is run to
the main power center.
Blocking diodes are not required or used to minimize voltage drops in
A ground-fault protection device provides compliance with the
requirements of NEC Section 690.5.
The charge controller is a relay type.
loads consist of a refrigerator, a freezer, several telephone devices,
and two fluorescent lamps. The maximum combined current is 15 amps.
The 4000-watt sine-wave inverter supplies the rest of the house.
6-kW natural gas fueled, engine-driven generator provides back-up power
and battery charging through the inverter. The 240-volt output of the
generator is fed through a 5-kVA transformer to step it down to 120
volts for use in the inverter and the house. The transformer is
protected on the primary winding by a 30-amp circuit breaker
[450.3(B)]. Figure E-6 presents the details.
Figure E-6. Medium Sized Residential Hybrid System
The subarray short-circuit current is 13.6 amps (4 x 3.4).
CONTINUOUS CURRENT: 1.25 x 13.6 = 17 amps
80% OPERATION: 1.25 x 17 = 21.25 amps
The temperature derating factor for USE-2 cable at 61-70°C is 0.58.
The ampacity of 10 AWG USE-2 cable at 70°C is 31.9 amps (55
x 0.58). [310.17]
The temperature derating factor for UF cable at 36-40°C is 0.91 for
the 90°C conductors [310.16].
ampacity of 10-2 w/gnd UF cable at 40°C is 36.4 amps (40 x 0.91),
but is restricted to use with an overcurrent device of no more than 30
The source-circuit circuit breakers are rated at 25 amps (requirement
is 125% of 17 amps = 21.25).
The PV array short-circuit current is 68 amps (5 x 13.6).
CONTINUOUS CURRENT: 1.25 x 68 = 85 amps
80% OPERATION: 1.25 x 85 = 106 amps
A 110-amp circuit breaker is used for the main PV disconnect after the
five source circuits are combined.
110-amp RK5 current-limiting fuse is used in the charge circuit of the
power center, which is wired with 2 AWG THHN conductors (115 amps with
The dc-load circuits are wired with 10-2
w/gnd NM cable (30 amps) and are protected with 20- or 30-amp circuit
breakers. A 100-amp RK-5 fuse protects these breakers and the load
circuits from excess current from the batteries.
The inverter can produce 4000 watts ac at 22 volts with an efficiency
The inverter input current ampacity requirements are 267 amps ((4000 /
22 / 0.85) x 1.25). See Appendix F for more details.
2/0 AWG USE-2 cables are paralleled in conduit between the inverter and
the batteries. The ampacity of this cable (rated with 75°C
insulation) at 30°C is 280 amps (175 x 2 x 0.80). The 0.80 derating
factor is required because there are four current-carrying cables in
A 275-amp circuit breaker with a 25,000-amp
interrupt rating is used between the battery and the inverter.
Current-limiting fusing is not required in this circuit.
output of the inverter can deliver 4000 watts ac (33 amps) in the
inverting mode. It can also pass up to 60 amps through the inverter
from the generator while in the battery charging mode.
requirements, ac output: 60 x 1.25 = 75 amps. This reflects the NEC
requirement that circuits are not to be operated continuously at more
than 80% of rating.
The inverter is connected to the ac load
center with 4 AWG THHN conductors in conduit, which have an ampacity of
85 amps when used at 30°C with 75°C overcurrent devices. An
80-amp circuit breaker is used near the inverter to provide a
disconnect function and the overcurrent protection for this cable.
6-kW, 120/240-volt generator has internal circuit breakers rated at 27
amps (6500-watt peak rating). The NEC requires that the output
conductors between the generator and the first field-installed
overcurrent device be rated at least 115% of the nameplate rating
((6000 / 240) x 1.15 = 28.75 amps). Since the generator is connected
through a receptacle outlet, a 10-4 AWG SOW-A portable cord (30 amps)
is run to a NEMA 3R exterior circuit breaker housing. This circuit
breaker is rated at 40 amps and provides overcurrent protection for the
8 AWG THHN conductors to the transformer. These conductors have an
ampacity of 44 amps (50 x 0.88) at 40°C (75°C insulation
rating). The circuit breaker also provides an exterior disconnect for
the generator. Since the transformer isolates the generator conductors
from the system electrical ground (separately derived system), the
neutral of the generator is grounded at the exterior disconnect.
The generator equipment-grounding conductors and grounding electrode
conductor are bonded to the main system equipment-grounding conductors
and the grounding electrode conductor.
A 30-amp circuit breaker
is mounted near the PV Power Center in the ac line between the
generator and the transformer. This circuit breaker serves as the
interior ac disconnect for the generator and is grouped with the other
disconnects in the system.
The output of the transformer is 120
volts. Using the rating of the generator, the ampacity of this cable
must be 62.5 amps ((6000 / 120) x 1.25). A 6 AWG THHN conductor was
used, which has an ampacity of 65 amps at 30°C (75°C insulation
The module and dc-load equipment grounds
must be 10 AWG conductors. Additional lightning protection will be
afforded if a 6 AWG or larger conductor is run from the array frames to
ground. The inverter equipment-grounding conductor must be a 4 AWG
conductor based on the size of the overcurrent device for this circuit.
[250.122] The grounding electrode conductor must be 2-2/0 AWG or a 500
kcmil conductor, unless there are no other conductors connected to the
grounding electrode and that electrode is a ground rod; then this
conductor may be reduced to 6 AWG [250.50].
DC Voltage Rating
All dc circuits should have a voltage rating of at least 55 volts (1.25
x 2 x 22).
EXAMPLE 7 Rooftop Utility-interactive System
Array Size: 24, 50-volt, 240-watt modules
Isc = 5.6
Voc = 62
Inverter: 200-volt nominal dc input
240-volt ac output at 5000 watts with an efficiency of 0.95.
rooftop array consists of six parallel-connected strings of four
modules each. A PV combiner contains a fuse for each string of modules
and a surge arrestor. All wiring is RHW-2 in conduit. The inverter is
located adjacent to the service entrance load center where PV power is
fed to the grid through a back-fed circuit breaker. Figure E-7 shows
the system diagram.
Figure E-7. Rooftop Utility-interactive System
The string short-circuit current is 5.6 amps.
CONTINUOUS CURRENT: 1.25 x 5.6 = 7 amps
80% OPERATION: 1.27 x 7 = 8.75 amps
The array short-circuit current is 33.6 amps (6 x 5.6).
CONTINUOUS CURRENT: 1.25 x 33.6 = 42 amps
80% OPERATION: 1.25 x 42 = 52.5 amps
modules in each string are connected in series. The modules and
attached conductors operate at 63°C. The temperature-derating
factor for RHW-2 at this temperature is 0.58. The required 30°C
ampacity for this cable is 15 amps (8.75 / 0.58). RHW-2 14 AWG cable
has an ampacity of 25 amps with 90°C insulation and 20 amps with
75°C insulation so there is no problem with the end of the cable
connected to the fuse (with 75°C terminals) since the 7 amps is
below either ampacity. Even with 60°C fuse terminals, the
ampacity of a 14 AWG conductor would be 20 amps at 30°C. If
the PV combiner were operating at 63°C, the fuse would have to be
temperature corrected according to the manufacturer’s instruction
and the use of 14 AWG conductors would still be acceptable when
evaluated at 7 amps.
This cable is protected with a 9-amp fuse.
cable from the PV combiner to the main PV disconnect operates at
40°C. The temperature derating factor for RHW-2 with 90°C
insulation is 0.91. This yields a 30°C ampacity requirement of 58
amps (52.5 / 0.91). RHW-2 6 AWG meets this requirement with an ampacity
of 75 amps (90°C insulation), and a number 6 AWG cable with
75°C insulation has an ampacity of 65 amps, which also exceeds the
42 amp requirement for overcurrent devices with 75°C terminals.
protection is provided with a 60-amp fused disconnect. Since the
negative dc conductor of the array is grounded, only a single-pole
disconnect is needed.
The inverter output current is 21 amps (5000 / 240).
80% OPERATION: 1.25 x 21 = 26 amps.
cable from the inverter to the load center operates at 30°C. Cable
size 8 AWG RHW-2 (evaluated with 75°C insulation) has an ampacity
of 50 amps.
A back-fed 30-amp, two-pole circuit breaker provides an ac disconnect
and overcurrent protection in the load center.
equipment-grounding conductors for this system should be at least 10
AWG conductors. The ac and dc grounding electrode conductors should be
a 6 AWG conductor. An 8 AWG grounding electrode conductor might
be allowed if provided with physical protection by installing in
Although not shown on the diagram, there will be a dc
grounding electrode conductor from the inverter to a separate dc
grounding electrode (or system). The dc grounding electrode must
be bonded to the ac grounding electrode. Alternatively, the dc
grounding electrode conductor may be connected directly to the ac
All dc circuits should have a voltage
rating of at least 310 volts (1.25 x 4 x 62). Typically, 600-volt
rated conductors, fuses, and related dc equipment would be used.
EXAMPLE 8 Integrated Roof Module System, Utility-Interactive
Array Size: 192, 12-volt, 22-watt thin-film modules
Isc = 1.8 amps
Vmp = 15.6 volts
Voc = 22 volts
Inverter: ±180-volt dc input
120-volt ac output
array is integrated into the roof as the roofing membrane. The modules
are connected in center-tapped strings of 24 modules each. Eight
strings are connected in parallel to form the array. Strings are
grouped in two sets of four and a series fuse protects the module and
string wiring as shown in Figure E-8. The bipolar inverter (not
currently in production) has the center tap dc input and the ac neutral
output grounded. The 120-volt ac output is fed to the service entrance
load center (fifty feet away) through a back-fed circuit breaker.
manufacturer of these thin-film modules has furnished data that show
that the maximum Voc under worst-case low temperatures is 24 volts. The
multiplication factor of 1.25 on Voc does not apply [690.7(A)]. The
design voltage will be 24 x 24 = 576 volts. The module manufacturer has
specified (label on module) 5-amp module protective fuses that must be
installed in each (+ and -) series string of modules.
Figure E-8. Center-Tapped PV System
Each string short-circuit current is 1.8 amps.
CONTINUOUS CURRENT (estimated for thin-film modules): 1.25 x 1.8 = 2.25
80% OPERATION: 1.25 x 2.25 = 2.8 amps
Each source circuit (4 strings) short-circuit current is 7.2 amps (4 x
CONTINUOUS CURRENT: 1.25 x 7.2 = 9 amps
80% OPERATION: 1.25 x 9 = 11.25 amps
The array (two source circuits) short-circuit current is 14.4 amps (2 x
CONTINUOUS CURRENT: 1.25 x 14.4 = 18 amps
80% OPERATION: 1.25 x 18 = 22.5 amps
cable is used for the module connections and operates at 75°C when
connected to the roof-integrated modules. The temperature-derating
factor in the wiring raceway is 0.41. For the strings, the 30°C
ampacity requirement is 5.5 amps (2.25 / 0.41)[310.16].
source circuit conductor is also exposed to temperatures of 75°C.
The required ampacity for this cable (at 30°C) is 22.0 amps (9 /
Wire size 10 AWG USE-2 is selected for moisture and heat
resistance. It has an ampacity of 40 amps at 30°C (90°C
insulation) and can carry 35 amps when limited to a 75°C insulation
rating (used for evaluating terminal temperature limitations on the
fuses). This cable is used for both string and source-circuit wiring.
Fifteen-amp fuses are used to protect the string and source-circuit
The array wiring is inside the building and RHW-2 is
used in metal conduit (2005 NEC 690.31(E)]. It is operated at 50°C
when passing through the attic. The temperature derating factor is
0.82, which yields a 30°C ampacity requirement of 22 amps (18 /
0.82). Cable size 10 AWG has an ampacity of 40 amps (90°C
insulation) or 35 amps (evaluated with 75°C insulation). Both of
these ampacities exceed the 22-amp requirement. Twenty-five amp fuses
are required to protect these cables, but 30-amp fuses are selected for
better resistance to surges. Since the inverter has high voltages on
the dc-input terminals (charged from the ac utility connection), a
load-break rated, pullout fuse holder is used.
The inverter is
rated at 4000 watts at 120 volts and has a 33-amp output current. The
ampacity requirement for the cable between the inverter and the load
center is 42 amps ((4000 / 120) x 1.25) at 30°C. Wire size 8 AWG
RHW-2 in conduit connects the inverter to the ac-load center, which is
fifty feet away and, when evaluated at with 75°C insulation, has an
ampacity of 50 amps at 30°C. A 50-amp circuit breaker in a small
circuit-breaker enclosure is mounted next to the inverter to provide an
ac disconnect for the inverter that can be grouped with the dc
disconnect. Another 50-amp circuit breaker is back-fed in the service
entrance load center to provide the connection to the utility.
modules have no frames and, therefore, no equipment grounding
requirements. The inverter and switchgear should have 10 AWG equipment
grounding conductors. The dc system grounding electrode conductor (GEC)
should be an 8 AWG conductor installed in conduit for mechanical
protection. This dc GEC is connected to the existing ac GEC.
All dc components in the system should have a minimum voltage rating of
600 volts (24 x 24 = 576).
Example 9 Residential Utility-Interactive, Multiple-Inverter
PV array: 3, 12-module
strings of 185 watt, 24V modules
Voc = 42V
Isc = 6.2A
Inverters: 3, 2500-watt,
Residential Service Entrance/Load Center: 200A
with 200A main circuit breaker
PV modules are connected in three series strings of 12 modules
each. The coldest ambient temperature is 15°F. Maximum
system voltage is 570V (12 x 42 x 1.13) [690.7]. Each series
string is connected to one pole of a Square D HU361RB heavy-duty safety
switch with a special listing suitable for this application (each pole
rated at 600 volts dc). The three outputs of the disconnect are
connected to three 2500-watt inverters.
The modules are connected in series with the attached 14 AWG USE-2
conductors and attached connectors.
a 75°C operating temperature, the 14 AWG USE-2 conductors in free
air have an ampacity of 14 amps (35 x 0.41) which is higher than the 10
amps needed (6.2 x 1.56). At the ends of each string of 12
modules, the 14 AWG conductors are spliced (soldered and covered with
listed, outdoor-rated heat-shrink tubing [110.14(B)]) to 10 AWG
USE-2/RHW-2 conductors which are run in conduit to the readily
accessible Square D disconnect located on the outside of the residence
near the utility meter [690.14(C)].
The inverter has been
certified by the manufacturer as having no capability to backfeed ac
current from the utility grid into faults in the dc PV wiring and
therefore no overcurrent devices are required in the dc PV disconnect
[690.9(A)EX]. The local inspector must accept or reject this
certification until the UL Standard 1741 for inverters includes a test
for back feeding from the utility.
Inverter output current is 10.4 amps (2500/240)
Ampacity requirements: 13 amps (10.4 x 1.25)
Circuit breaker for each inverter: 15 amps
ac output conductors of the inverter could be 14 AWG THWN-2 that meets
ampacity requirements at 45°C and with 75°C insulation (circuit
breaker terminal temperature limitations). However, 10 AWG THWN-2
conductors were used to minimize voltage rise between the inverter
outputs and the utility point of connection.
690.64(B)(2) imposes a 40-amp maximum PV backfed circuit breaker rating
limitation on the main panel (1.2 x 200 – 200). Connecting
three double-pole 15-amp circuit breakers from the inverters would
total 45 amps exceeding the limitation of 40 amps. Each bus of the
120/240 load center should be analyzed separately, but they are
identical in this example. Therefore, a subpanel is used to
combine the output of the three inverters before sending the combined
output to the main panel.
Subpanel Main Breaker: 3 x 10.4 x 1.25 = 39
amps, round to 40 amps
Subpanel rating from 690.64(B)(2) where X is minimum subpanel rating:
1.20 X = 3 x 15 + 40 = 85, X= 70.8, round up to 100 amp
Conductors between subpanel and main panel must be rated for 39 amps.
AWG THHN in conduit is rated at 46.2 amps (55 x 0.91) at
45°C. With 75°C insulation, the ampacity is 50 amps at
30°C and 41 amps at 45°C. Both are adequate for the
required 40 amps.
A 40-amp backfed breaker is installed in the main panel for the
residence and meets NEC 690.64(B)(2) at this location.
Figure E-9. Utility-Interactive Three-Inverter System
APPENDIX F: DC Currents on Single-Phase Stand-alone
the sinusoidal ac output current of a stand-alone inverter goes to zero
120 times per second, the input dc current also goes nearly to zero.
With a resistive ac load connected to the inverter, the dc current
waveform resembles a sinusoidal wave with a frequency of 120 Hz. The
peak of the dc current is significantly above the average value of the
current, and the lowest value of dc current is near zero.
example of this is shown in the Figure F1. This is an example of a
single-phase stand-alone inverter operating with a 4000-watt resistive
load. The input battery voltage is 22 volts. The figure shows the dc
current waveform. The measured average dc current is 254 amps. The RMS
value of this current is 311 amps.
Figure F-1. Inverter Current Waveform (dc side)
calculated dc current for this inverter (as was done in Example 6 in
Appendix E) is 214 amps (4000/22/0.85) when using the manufacturer's
specified efficiency of 85%.
The RMS value of current is the
value that causes heating in conductors and is the value of current
that causes overcurrent devices to trip. In this case, if the inverter
were operated at 100% of rated power and at a low battery voltage, the
conductors and overcurrent devices would have to be rated to carry 311
amps, not the calculated 214 amps. Code requirements would increase the
cable ampacity requirements and overcurrent device ratings to 388 amps
(1.25 x 311).
Loads that have inductive components may result in even higher RMS
values of dc currents.
systems designer should contact the inverter manufacturer in cases
where it is expected that the inverter may operate at loads approaching
the full power rating of the inverter. The inverter manufacturer should
provide an appropriate value for the dc input current under the
expected load conditions.
Some inverters may employ topologies that filter the dc input current
resulting in less ripple.
APPENDIX G: Grounding PV Modules
PV modules to reduce or eliminate shock and fire hazards is necessary
but difficult. Copper conductors are typically used for electrical
connections, and the module frames are generally aluminum. It is well
known that copper and aluminum do not mix as was discovered from
numerous fires in houses wired with aluminum wiring in the
1970’s. PV modules generally have aluminum frames. Many have mill
finish, some are clear coated, and some are anodized for color. The
mill finish aluminum and any aluminum surface that is scratched quickly
oxidizes. This oxidation and any clear coat or anodizing form an
insulating surface that makes for difficult long-lasting, low
resistance electrical connections (e.g. frame grounding). The
oxidation/anodizing is not a good enough insulator to prevent
electrical shocks, but it is good enough to make good electrical
Underwriters Laboratories (UL) which
tests and lists all PV modules sold in the US requires very stringent
mechanical connections between the various pieces of the module frame
to ensure that these frame pieces remain mechanically and electrically
connected over the life of the module. These low-resistance connections
are required because a failure of the insulating materials in the
module could allow the frame to become energized at up to 600 volts
(depending on the system design). The National Electrical Code
requires that any exposed metal surface be grounded if it could be
energized. The installer of a PV system is required to ground each
module frame. The code and UL Standard 1703 require that the module
frame be grounded at the point where a designated grounding provision
has been made. The connection must be made with the hardware provided
using the instructions supplied by the module manufacturer.
designated point marked on the module must be used since this is the
only point tested and evaluated by UL for use as a long-term grounding
point. UL has established that using other points such as the module
structural mounting holes coupled with typical field installation
“techniques” do not result in low-resistance, durable
connections to aluminum module frames. If each and every possible
combination of nut, bolt, lock washer and star washer could be
evaluated for electrical properties and installation torque
requirements AND the installers would all use these components and
install them according to the torque requirements, it might be possible
to use the structural mounting holes for grounding.
Most US PV
module manufacturers are providing acceptable grounding hardware and
instructions. Japanese module manufactures are frequently providing
less-than-adequate hardware and unclear instructions. Future revisions
of UL 1703 should address these issues.
In the meantime,
installers have to struggle with the existing hardware and
instructions, even when they are poor. SWTDI has identified suitable
grounding hardware and provides that information when installers ask
about grounding—a frequent topic.
For those modules that
have been supplied with inadequate or unusable hardware or no hardware
at all, here is a way to meet the intent of the code and UL Standard
For those situations requiring an
equipment-grounding conductor larger than 10 AWG, a thread-forming or
thread-cutting stainless steel 10-32 screw can be used to attach an
ILSCO GBL4 DBT lug to the module frame at or adjacent to the point
marked for grounding. A #19 drill is required to make the proper size
hole for the 10-32 screw. The 10-32 screw is required so that at least
two threads are cut into the aluminum (a general UL requirement for
connections of this kind). The thread-forming or thread-cutting screw
is required so that an airtight, oxygen-free mating is assured between
the screw and the frame to prevent the aluminum from reoxidizing. It is
not acceptable to use the hex-head, green grounding screws (even when
they a have 10-32 threads) because they are not listed for outdoor
exposure and will eventually corrode. The same can be said for other
screws, lugs, and terminals that have not been listed for outdoor
applications. Hex-head stainless steel “tech” screws and
sheet metal screws do not have sufficiently fine threads to make the
necessary low resistance, mechanically durable connection. The only
thread-forming or thread-cutting, 10-32 stainless steel screws that
have been identified so far have Phillips heads; not the fastest for
installation. (See Figure G-1.)
Figure G-1. ILSCO GBL4-DBT Lug
ILSCO GBL4 DBT lug is a lay-in lug with a stainless steel screw made of
solid copper and then tin plated. It accepts a 4 AWG to 14 AWG copper
conductor. It is listed for direct burial use (DB) and outdoor use and
can be attached to aluminum structures (the tin plate). The much
cheaper ILSCO GBL4 lug looks identical but is tin plated aluminum, has
a plated screw, and is not listed for outdoor use. An alternative to
the GBL4 DBT has not been identified, but the search continues.
the module grounding is to be done with a 14 AWG to 10 AWG conductor,
then the ILSCO lug is not needed. Two number 10 stainless steel flat
washers would be used on the 10-32 screw, and the copper wire would be
wrapped around the screw between the two flat washers that would
isolate the copper conductor from the aluminum module frame.
size conductor should be used? The minimum code requirement is for the
equipment grounding conductor for PV source and output circuits to be
sized to carry 1.25 times the short-circuit currents at that point.
While this may allow a 14 AWG conductor between modules, a conductor
this small would require physical protection between the grounding
points. Some inspectors will allow a 10 AWG bare conductor to be routed
behind the modules from grounding point to grounding point if the
conductors are well protected from damage, as they would be in a
roof-mounted array. If needed, an 8 AWG or 6 AWG sized conductor may be
required (to meet the code or to satisfy the inspector) and then the
ILSCO lugs should be used.
It is desirable to use the module
mounting structure for grounding. Rack manufacturers have been urged to
get their products listed as field-installable grounding devices, but
they may be running up against that aluminum oxidation problem also as
well as the lack of consistency in tightening nuts and bolts in the
The code allows metal structures to be used for grounding
and even allows the paint or other covering to be scraped away to
ensure a good electrical contact. Numerous types of electrical
equipment are grounded with sheet metal screws and star washers. This
works on common metals like steel, but not on aluminum due to the
Module manufacturers are being encouraged to make
that aluminum connection in the factory and to provide a
copper-compatible terminal in the j-box or on the frame as is done with
the 300-watt RWE-Schott modules.
Unfortunately many PV systems
are being grounded improperly even when the proper hardware has been
supplied. Figure G-2, a photo taken in March 2004, illustrates that
even the proper hardware can be misused. Here, the stainless-steel
isolation washer has been installed in the wrong sequence and the
copper grounding wire is being pushed against the aluminum frame; a
condition sure to cause corrosion and loss of electrical contact in the
Figure G-2. Improper Module Grounding
APPENDIX H: PV Ground Fault Protection Devices and
The National Electrical Code, Section 690.5
690.5, Ground Fault Protection, of the 1987 National Electrical Code
(NEC) added new requirements for photovoltaic (PV) systems mounted on
the roofs of dwellings. The requirements are intended to reduce fire
hazards resulting from ground faults in PV systems mounted on the roofs
of dwellings. There is no intent to provide any shock protection
since the 5ma level of protection would not be possible on a PV array
with distributed leakage currents, and the requirement is not to be
associated with a direct current (dc) GFCI. The ground fault
protection device (GFPD) is intended to deal only with ground faults
and not line-to-line faults.
The requirements for the
ground-fault protection device have been modified in subsequent
revisions of the Code. The requirements for the device in the current
code are as follows.
1. Detect a ground fault
2. Interrupt the fault current
3. Indicate that there was a ground fault
4. Open the ungrounded PV conductors
the 1990 NEC was published, no hardware had been developed to meet
these requirements. Under a two-year contract (1990-1991) from
the Salt River Project, a Phoenix, Arizona utility, John Wiles at the
Southwest Technology Development Institute at New Mexico State
University developed prototype designs and hardware to meet the
requirements. The designs were released to the PV industry and
GFPDs based on these designs and other concepts began appearing in PV
equipment and subsystems in the late 1990’s. Listed
equipment is now available for both stand-alone and utility-interactive
To understand how these GFPDs work, it must be
understood that nearly all currently available inverters, both
stand-alone and utility-interactive, employ a transformer that isolates
the dc grounded circuit conductor (usually the negative) from the ac
grounded circuit conductor (usually the neutral). With this
transformer isolation, the dc side of a PV system may be considered
similar to a separately derived system and, as such, must have a single
dc bonding connection that connects the dc grounded circuit conductor
to a common grounding point where the dc equipment-grounding conductors
and the dc grounding electrode are connected. Like grounded ac
systems, only a single dc bonding connection is allowed. If more
than one bonding connection (a.k.a. bonding jumper) were allowed on
either the ac side of the system or on the dc side of the system,
unwanted currents would circulate in the equipment-grounding conductors
and would violate NEC Section 250.6.
Currently available GFPDs
as both separate devices for adding to stand-alone PV systems and as
internal circuits in most utility-interactive inverters serve as the dc
In any ground-fault scenario on the dc side
of the PV system, ground-fault currents from any source (PV modules or
batteries in stand-alone systems) must eventually flow through the dc
bonding connection on their way from the energy source through the
fault and back to the energy source. This includes single ground
faults involving the positive conductor faulting to ground or in the
negative conductor faulting to ground. In negative-conductor (a
grounded conductor) ground faults, parallel paths for the negative
currents are created by the fault path and they will flow through the
dc bonding connection. Double ground faults are beyond the
ability of any equipment to deal with and are not required to be
addressed by the NEC or standards established by Underwriters
To meet the NEC Section 690.5 requirements, a
typical GFPD has a 1/2 amp to 1 amp and sometimes 5 amp overcurrent
device installed in the dc bonding connection. When the dc
ground-fault currents exceed the current rating of the device, it
opens. By opening, the overcurrent device interrupts the
ground-fault current as required in NEC Section 690.5. If a
circuit breaker is employed as the overcurrent device, the tripped
position of the breaker handle provides the indicating function.
When a fuse is used, an additional electronic monitoring circuit in the
inverter provides an indication that there has been a
ground-fault. The indication function is also an NEC 690.5
requirement. There is no automatic resetting of these devices.
the GFPD using a circuit breaker as the sensing device, an additional
circuit breaker is mechanically connected (common handle/common trip)
to the sensing circuit breaker. These types of GFPDs may be found
in both stand-alone and utility-interactive systems. This
additional circuit breaker (usually rated at 100 amps and used as a
switch rather than an overcurrent device) is connected in series with
the ungrounded circuit conductor from the PV array. In this
manner, when a ground-fault is sensed and interrupted, the added
circuit breaker disconnects the PV array from the rest of the circuit
providing an additional indication that something has happened that
Even though the GFPD uses a 100-amp circuit
breaker in the ungrounded PV conductor, the 100-amp circuit breaker may
not be used as the PV disconnect because in normal use of the system,
turning off this breaker would unground the system and this is
undesirable in non-fault situations.
In the GFPD installed in
utility-interactive inverters using a fuse as the sensing element, the
electronic controls in the inverter that indicate that there has been a
fault, also turn the inverter off and open the internal connections to
the ac line. In listing these inverters, UL had indicated that
this method of turning off the inverter to provide an additional
indication of trouble meets the requirements of 690.5(B) for
disconnecting the ungrounded PV conductor.
It should be noted
that the dc GFPD detects and interrupts ground faults anywhere in the
dc wiring and the GFPD may be located anywhere in the dc system.
Because the normal location for the dc bonding connection is at or near
the dc disconnect, this bonding connection is usually made at the dc
power center where there is ready access to the dc grounding
electrode. GFPDs installed in the utility-interactive inverters
or installed in dc power centers on stand-alone systems are the most
logical places for these devices. There is no significant reason
to install them at the PV module location. This configuration
would significantly increase the length of the dc grounding electrode
conductor and complicate its routing. To achieve significant
additional safety enhancements would require a GFPD at every
module. Equipment to do this does not exist and there are no
requirements for such equipment.
The diagram (Figure H-1) shows
both positive (red) and negative (blue) ground faults and the paths
that the fault currents take. As noted above, all ground fault
currents must pass through the dc bonding connection where the GFPD
sensing device is located.
Figure H-1. Ground-Fault Current Paths
devices are fully capable of interrupting ground faults occurring
anywhere in the dc system including faults at the PV array or anywhere
in the dc wiring from the PV module to the inverter and even to the
battery in stand-alone systems. All of this can be done from any
location on the dc circuit. Fire reduction and increased safety
are achieved by having these GFPD on residential PV systems.
Keeping the PV source and output conductors outside the dwelling until
the point of first penetration and requiring the readily accessible dc
disconnect also enhance the safety of the system. See Section
690.14 of the Code for details. The 2005 NEC allows conductors in
metallic raceways to be routed inside the structure. [690.31(E)]
a ground-fault, the dc system bonding connection is opened, and if the
ground fault cures itself for some reason (e.g., an arc extinguishes),
the dc system remains ungrounded until the system is reset. A
positive-to-ground fault may allow the negative conductor (now
ungrounded) to go to the open-circuit voltage with respect to
ground. This is addressed by the marking requirements of Section
690.5(C). A very high value resistance is usually built into the
GFPD and this resistance bleeds off static electric charges and keeps
the PV system loosely referenced to ground (but not solidly grounded)
during ground-fault actions. The resistance is selected so that
any fault currents still flowing are only a few milliamps—far too
low to be a fire hazard.
APPENDIX I: Selecting Overcurrent Devices and
Conductors in PV Systems
1. Define Continuous Currents
unique nature of PV power generators dictate that all ac and dc
calculated currents are continuous and are based on the worst-case
conditions. There are no non-continuous currents and all currents
are treated as continuous.
A. DC currents in
PV source and PV output circuits are calculated as 125% of the
short-circuit current (Isc) (690.8(A)(1)).
AC inverter (stand-alone or utility-interactive) output currents are
calculated at the rated output of the inverter (690.8(A)(3)).
DC inverter input currents from batteries are calculated based on the
rated output power of the inverter at the lowest battery voltage that
can maintain that output (690.8(A)(4)). Inverter dc to ac
efficiency must also be factored into the calculation.
2. Select Overcurrent Device
A. The overcurrent device will be rated at 125% of
continuous current (690.8(B)(1)).
If the overcurrent device is in a listed assembly and the combined
assembly is listed for 100% duty, then use 100% continuous current to
size the overcurrent device (690.8(B)(1) EX)).
The calculated value of the overcurrent device may be rounded up to
next standard rating (where the rating is less than or equal to 800A
(240.4(B). Standard values of overcurrent devices in PV source
and output circuits are 1-15 amps in 1-amp increments (690.9(C)).
PV source circuits, the value should be less than or equal to the value
of the maximum series protective fuse marked on the back of the
module. If desired (for unforeseeable reasons), this selected
value could be increased to the size of the maximum protective fuse
found on the back of the module. However, this will impact
conductor sizing and other overcurrent device requirements.
If the overcurrent device is exposed to temperatures (operating
conditions) greater than 40°C and/or less than 25°C,
temperature correction factors must be applied to the device rating
3. Select Conductor
A conductor should be selected with a 30°C ampacity not less than
125% of continuous current (215.2(A)(1)).
The conductor selected must have 30°C ampacity after corrections
for conditions of use (ambient temperature and conduit fill) not less
than the continuous currents (no 125% used at this time).
1.) Apply the conductor selection requirements at all
points of different temperatures and or conduit fill.
2.) Use the 10%/10-foot rule where appropriate
C. Select the larger conductor from 3.A. or 3.B
4. Evaluate conductor temperature at each termination
A current for conductor size selected in 3.C should be selected from
Table 310.16 using 60°C or 75°C ampacity columns depending on
conductor temperature rating of the device terminals (110.14(C)).
If the terminals are in an ambient temperature greater than 30°C,
the current found in 4.A. should be derated for the higher temperature
using the correction factors at the bottom of the 60°C or 75°C
columns as appropriate.
C. The current in 4.B. must not be less than 125% of
D. Increase the conductor size, if necessary, to meet
4.C at all terminations.
5. Verify that the Overcurrent Device Protects
The rating of the overcurrent device (after any corrections for
conditions of use—2.B.) selected in 2 must not be more than the
ampacity of the conductor selected in 4.C. The ampacity used for
the conductor is that found under the conditions of use (3).
Rating round up is allowed (240.4(B)).
larger conductor size should be selected if the conductor selected in
4.C is not protected by the overcurrent device.
APPENDIX J: Module series fuse requirements
PV MODULES AND THE SERIES OVERCURRENT DEVICE
issue is: How can PV modules or strings of modules be connected in
parallel and still meet the National Electrical Code (NEC) and
Underwriters Laboratories (UL) requirements (marked on the back of each
module) for a series fuse (or breaker, both known as overcurrent
protective devices (OCPD)) for each module/string of modules? UL marks
the modules based on the reverse-current tests. The NEC requires that
the manufacturer's instructions and labels be followed. The intent of
the module marking is to protect the module at the marked level from
reverse currents. This is a maximum value for the OCPD. Lesser values
can be used as long as they meet the NEC requirement of 1.56 * Isc to
protect the conductor associated with the module or string of modules.
installers of 12, 24, and 48-volt PV systems ignore the module OCPD
requirement and connect modules/strings in parallel. Can it be done and
how? Dave King at Sandia National Laboratories and I have smoked a few
modules and determined that the module OCPD requirement is valid.
n modules or strings connected in parallel. The NEC requires that an
OCPD be installed in the combined paralleled output of all strings
(modules) to protect the cable from reverse currents from batteries and
back feed of ac currents through an inverter. The OCPD will have a
minimum rating of 1.56 * n * Isc amps. It is sized at this value to
allow maximum forward currents from the array to pass through without
interruption and to keep the overcurrent device from operating at more
than 80% of rating.
Examine the circuit where there are n
modules/strings connected in parallel. Place a ground-fault in one
module/string. Examine the sources of fault current that would affect
that module string. Let us ignore current from the faulted
module/string itself since the wiring in that string is already sized
to carry all currents generated in the string.
First there is
the back feed current from the battery or the inverter in those systems
with these components. It is limited to the NEC required OCPD of 1.56 *
n * Isc. This current is added to the current from the remaining
modules connected in parallel. In this case the current is (n-1) * 1.25
* Isc. The 1.25 is required because of daily-expected irradiance
values that are greater than the STC-rated Isc.
I-fault = 1.56 * n * Isc + (n-1) * 1.25 * Isc
With a little algebra, the resulting fault current is:
I-fault = (2.81 * n-1.25) * Isc amps. (Fault Current Equation)
Note that this equation does not account for OCPD roundup, so each
system must be checked with the actual OCPD values.
the module can pass the UL reverse current test at this I-fault value
or greater and be so marked (the maximum protective series fuse on the
label), then is it possible to parallel modules (pick your n) without a
series OCPD for each module/string?
For example, a module is
rated at 60 watts and has a maximum series OCPD requirement of 20 amps
marked on the back of the PV module. The Isc for this module is 3.8
amps. Here are the required calculations and checks for two strings in
The paralleled circuit OCPD installed at the output of
the two paralleled strings will be 2 * 1.56 * 3.8 = 11.8 amps (assume
12-amp OCPD is used—The NEC now requires module/string OCPDs in
one-amp increments up to 15 amps; fuses are available in these values
except that there is a jump from 10 to 12 or 12.5 and then to 15). This
OCPD will allow 12 amps of fault current to reach the faulted
module/string from back feed from a charge controller/battery or from
the utility grid through a utility-interactive inverter. Actually,
OCPDs are tested to pass 110% of rating at 25o C, but let’s not
factor that in. Another 1.25 * 3.8 = 4.75 amps will come from the
parallel-connected module for a total of 16.75 amps. This is acceptable
since this module is marked for 20 amps.
However, if we try to
parallel three of these modules, the fault current equation yields a
fault current of 29+ amps that exceeds the 20-amp limit on the module.
The single OCPD is 3 * 1.56 * 3.8 = 17.8 amps (since OCPDs at this
rating are not common, a 20-amp OCPD must be used). The two
parallel-connected modules contribute 2 * 1.25 * 3.8 = 9.5 amps for a
total potential fault current of 29.5 amps. This is significantly above
the maximum series protective fuse of 20 amps.
In most cases, it
is not possible to parallel many more than 2 modules with a single OCPD
unless the marked maximum series OCPD is very large in relation to Isc
for the module. Some of the thin-film technologies may be able to do
this and that will be an installation benefit for them.
about driving voltages to produce these currents? The faults can occur
anywhere in the module/string so a fault involving a single cell could
be the trouble spot and driving voltages over 1 volt could produce the
What about currents generated within the
faulted module string? In the portion of the module/string below the
fault (toward the grounded end of the module/string), the currents flow
in the forward direction toward the fault and may or may not cause
problems. As far as the contribution to the fault current is concerned,
the contribution only appears in the fault path/arc and does not affect
the ampacity of the cable. Above the fault, the currents in that
portion of the module/string appear to oppose to the external fault
currents that are trying to reverse the flow of current, but the string
is reverse biased, and the external driving currents are flowing. Since
the location of the fault cannot be controlled ahead of time,
worst-case currents must be assumed.
The increased marking value
of 20 amps on the example module allows for two modules to be connected
in parallel and it does make it easier for the installer to use a
single OCPD with larger cable to meet both the NEC required cable
protection and the UL-required module protection with one large OCPD
instead of two smaller OCPDs plus a larger OCPD.
ampacity must also be addressed if modules are going to be paralleled
on a single OCPD. The conductors for each string must be able (under
fault conditions) to carry the current from the other parallel strings
(modules) plus the current that may be back fed from the inverter or
battery. In the case with n strings in parallel and a single OCPD in
the combined output, the conductor ampacities would be as follows:
of the string conductors would have to have an ampacity of 1.25 (n-1) *
Isc + 1.56 n Isc. If the equation is factored the required ampacity
becomes A=(2.81 * n-1.25) * Isc. As before, OCPD roundup is not
considered and the values should be recalculated with actual OCPD
The combined output circuit conductors would require an ampacity of
1.56 * n * Isc .
utility-interactive inverters on the market have redundant internal
circuitry that prevents currents from being backfed through the
inverter from the utility to faults in the PV array. This removes one
source of currents in the above equation. With these products, it is
possible to have two and sometimes more strings of modules in parallel
with no OCPDs in the dc circuits. The inverter manufacturers
should be contacted for information in this area. The above equations
can be modified by deleting the combined circuit OCPD and then solved
to determine both the requirements for OCPDs and the necessary ampacity
of the conductors.
In this case, the current flowing through the
forward fuse (n * 1.56 * Isc) is set equal to 0 (zero) or removed from
the equation. In a system with n strings of modules connected in
parallel, if one of the n strings develops a fault, the fault current
is now reduced to:
I fault= (n-1) * 1.25 * Isc. For two strings in parallel, n=2 and
the fault current becomes
I fault = 1.25 Isc.
NEC requires that all PV wiring generally be sized at 1.56 Isc. The
required module series protective fuse is nearly always greater than
Therefore, in a system with two strings of modules
connected in parallel, there are no sources of fault current that
exceed the ampacity of the conductors or the requirements for a module
protective fuse. No dc string or array fuses would be needed. NEC
Section 690.9(A) Exception applies.
If there are more than two
strings of modules connected in parallel, then the calculations
outlined above will have to be made to ensure that (n-1) * 1.25 * Isc
is less than the module series protective fuse value. If not, fuses
should be used in each string.
John Wiles 505-646-6105 firstname.lastname@example.org 10/12/05
APPENDIX K: Flexible, Fine-Stranded Cables:
Incompatibilities with Set-Screw Mechanical Terminals and Lugs
have been received over the last several years about field-made
connections that have failed when flexible, fine-stranded cables have
been used with mechanical terminals or lugs that use a set screw to
hold the wire in the terminal. See Figure K-1 for examples of
These terminals are used on nearly all circuit
breakers (except those with stud-type terminals), fuse holders,
disconnects, PV inverters, charge controllers, power distribution
blocks, some PV modules, and many other types of electrical equipment.
Figure K-1. Examples of Mechanical Terminals
conductors and cables are considered as those cables having stranding
more numerous than Class B stranding. Class B stranding (the most
common) will normally have 7 strands of wire per conductor in sizes
18-2 AWG, 19 strands in sizes 1-4/0 AWG, and 37 strands in sizes
250-500 kcmil. Conductors having more strands than these are
widely available and are in different classes such as K and M used for
portable power cords and welding cables. Commonly used
building-wire cables such as USE, THW, RHW, THHN and the like are most
commonly available with Class B stranding, but are also readily
available with higher stranding. Fine-stranded cables are frequently
used by PV installers to ease installation and are used in PV systems
for battery cables, power conductors to large utility-interactive
inverters and elsewhere.
Some modules are supplied with
fine-stranded interconnecting cables with attached connectors.
While the crimped-on connectors listed with the module are suitable for
use with the fine-stranded conductors, an end-of-string conductor with
mating connector may also be supplied with the fine-stranded conductor,
and the unterminated end of that conductor will not be compatible with
According to UL Standard 486 A-B, a
terminal/lug/connector must be listed and marked for use with
conductors stranded in other than Class B. With no marking or
factory literature/instructions to the contrary, the terminal may only
be used with conductors with the most common Class B stranded
conductors. They are not suitable and should not be used with
fine-stranded cables. UL engineers have said that few (if any) of
the normal screw-type mechanical terminals that the PV industry
commonly uses have been listed for use with fine stranded wires.
The terminal must be marked or labeled specifically for use with
UL suggests two problems, both
of which have been experienced in PV systems. First, the turning screw
tends to break the fine wire strands, reducing the amount of copper
available to meet the listed ampacity. Second, the initial torque
setting does not hold and the fine strands continue to compress after
the initial tightening. Even after subsequent retorquing, the
connection may still loosen. The loosening connection creates a
higher-than-normal resistance connection that heats and may eventually
fail. See Figure K-2 for a failed mechanical terminal from a PV system.
Figure K-2. Destroyed Mechanical Terminal From PV
All electrical equipment listed to UL Standards has:
• Terminals rated for the required current and sized
to accept the proper conductors
Sufficient wire bending space to accommodate the Class B stranded
conductors in a manner that meets the wire bending requirements of the
• Provisions to accept the appropriate conduit size
for these conductors where conduit is required.
It is therefore unnecessary to use the fine-stranded cables except
possibly when dealing with conductors 4/0 AWG and larger.
those cases where a fine-stranded cable must be used, a few
manufacturers make a limited number of crimp-on compression lugs in
various sizes that are suitable for use with fine-stranded
cables. See Figure K-3.
Figure K-3. Typical Compression Lug
markings and literature indicate which lugs are suitable. An
example is the ILSCO FE series of lugs in sizes 2/0 AWG and
larger. Burndy makes a YA series of lugs in sizes 14 AWG and
up. In both cases the lugs are solid copper. It should be
emphasized: Most crimp-on lugs are not listed for use with
fine-stranded wire. Where the crimp-on compression lugs can be
used, they must be installed using the tools recommended by the
manufacturer and, of course, they must be attached to a stud with a nut
Burndy and others make pin adapters (a.k.a. pigtail
adapters) that can be crimped on fine-stranded cables. These pin
adapters provide a protruding pin that can be inserted into a standard
screw-type mechanical connector. Again, not all pin
adapters/pigtail adapters are listed for use with fine-stranded
conductors; some are intended for use with aluminum wire and others
provide only a conversion to a smaller AWG size for B Class conductor
or a pin adapter for Class B conductors.
It is suggested that
the use of fine-stranded conductors be avoided wherever possible.
Where such cables must be used, they should only be terminated with the
appropriate connectors/lugs. Previously installed systems should
be revisited and the cables replaced where possible or terminated
APPENDIX L: Ungrounded PV Systems
2005 NEC will permit (not require) the installation of PV systems that
do not have one of the dc PV source and PV output conductors
grounded. This new go-ahead for ungrounded systems will be in
addition to the existing allowance for ungrounded PV systems operating
below a systems voltage of 50 volts.
There are a number of
additional requirements for these ungrounded PV systems. These
additional requirements were established to ensure the safety of the
system. Since the United States has over a 100-year tradition of
installing, inspecting, and servicing grounded electrical systems, the
training and the infrastructure for installing and inspecting
ungrounded systems will need to be established.
in common use in the United States is designed for use only on grounded
electrical systems. Much of the existing PV balance of systems
equipment such as power centers and charge controllers, and even some
inverters are designed today for use in grounded systems. Radio
frequency (RF) filters, required to meet FCC emissions requirements are
frequently installed from only the positive conductor to chassis
assuming that the negative conductor is grounded. Disconnects in
power centers are installed only in the positive conductor and the
negative conductors are routed through grounding blocks bonded to the
chassis. . The transition to ungrounded PV systems will
necessitate new hardware designs and new thinking for surge protection,
overcurrent protection, and disconnects.
Electricians and PV
installers are trained to install grounded systems. Inspectors
are trained and experienced in inspecting grounded, not ungrounded,
Europe, on the other hand, has many years of
experience installing not only ungrounded PV systems but also
ungrounded ac electrical systems.
installation practices and available equipment on each side of the
Atlantic have few commonalities. The few items that are common in
both arenas, such as the availability of conduit, are used in entirely
different ways. The ungrounded European PV systems have as good a
safety record as the grounded US PV systems. This addition to the 2005
NEC was made to permit the US PV industry to utilize European
experience while using US equipment and still meet all safety
requirements. The resulting requirements are as follows:
Ground-fault detectors will be required on all ungrounded PV arrays for
fire protection purposes, not shock protection.
Disconnects and overcurrent protection will be required on each circuit
conductor unless the system design requires no overcurrent protection
in that circuit.
3. The PV source and PV output
circuit conductors will be required to be in a raceway or be part of a
multi-conductor sheathed cable. This requirement emulates the
European use of “double insulated” cable, which is not yet
available in the US. When such “double-insulated”
cables become available, are tested and listed to an appropriate UL
safety standard, then it is anticipated that they too would meet the
intent of this requirement.
4. A warning label
shall be placed on any termination or location where the ungrounded
conductors in raceways may be exposed stating the following:
ELECTRIC SHOCK HAZARD. THE DIRECT CURRENT CIRCUIT CONDUCTORS OF THIS
PHOTOVOLTAIC POWER SYSTEM ARE UNGROUNDED BUT MAY BE ENERGIZED WITH
RESPECT TO GROUND DUE TO LEAKAGE PATHS AND/OR GROUND FAULTS.|
The inverters or charge controllers used in systems with ungrounded
photovoltaic source and output circuits shall be listed for the purpose.
APPENDIX M: SERVICE ENTRANCE CONDUCTOR TAPS FOR
UTILITY-INTERACTIVE INVERTER SYSTEMS
690.64 of the National Electrical Code (NEC) establishes how and where
a utility-interactive PV system may be connected to the utility system.
The point of connection may be either on the load side of the service
disconnect or the utility (supply) side of the service disconnect. In
many cases, the complex requirements for load-side connections
established by 690.64(B)(2) make such a connection impractical and
dictate that the utility-interactive inverter be connected on the
supply side of the service disconnect. Here are some, but not all, of
the major code sections that address the requirements for such a
Section 690.64(A) allows a supply (utility) side connection as
permitted in 230.82(6).
Section 230.82(6) lists solar photovoltaic equipment as permitted to be
connected to the supply side of the service disconnect.
is evident that the connection of a utility-interactive inverter to the
supply side of a service disconnect is essentially connecting a second
service entrance disconnect to the existing service and many, if not
all, of the rules for service entrance equipment must be followed.
Section 240.21(D) allows the service conductors to be tapped and refers
230.91 requires that the service overcurrent device be co-located with
the service disconnect. A circuit breaker or a fused disconnect would
meet these requirements. A utility-accessible, visible break, lockable
(open) fused disconnect (aka safety switch) may also meet utility
requirements for an external PV ac disconnect.
specifies that the service disconnecting means for each set of service
entrance conductors shall be a combination of no more than six switches
and sets of circuit breakers mounted in a single enclosure or in a
group of enclosures. The addition of the photovoltaic equipment
disconnect would be one of the six.
establishes the location requirements for the service disconnect.
Section 705.10 requires that a directory be placed showing the location
of all power sources for a building. Locating the PV service disconnect
adjacent to or near the existing service disconnect may facilitate the
installation, inspection, and operation of the system.
230.79(D) requires that the disconnect have a minimum rating of 60
amps. This would apply to a service-entrance rated circuit breaker or
Section 230.42 requires that the service
entrance conductors be sized at 125% of the continuous loads (all
currents in a PV system are worst-case continuous). The actual rating
should be based on 125% of the rated output current for the
utility-interactive PV inverter as required by 690.8. The disconnect
must have a 60-amp minimum rating. Larger conductors may be required
after temperature and conduit fill factors have been applied.
a small PV system, say a 2500-watt, 240-Volt inverter requiring a
15-amp circuit and overcurrent protection, these requirements would
appear to require a minimum 60-amp rated disconnect, but 15-amp fuses
could be used; fuse adapters would be required. While 15-amp conductors
could be used between the inverter and the 15-amp fuses in the
disconnect, Section 230.42(B) requires that the conductors between the
service tap and the disconnect be rated not less than the rating of the
disconnect; in this case 60 amps.
How we would deal with the
60-amp disconnect, 15-amp over current requirements using circuit
breakers is not as straightforward. A circuit breaker rated at 60-amps
would serve as a disconnect and it could be connected in series with a
15-amp circuit breaker to meet the inverter overcurrent device
requirements. In this case the requirements of 690.64(B)(2) should be
applied for the series connection.
Section 110.9 requires that
the interrupt capability of the equipment be equal to the available
fault current. The interrupt rating of the new
disconnect/overcurrent device should at least equal the interrupt
rating of the existing service equipment. The utility service should be
investigated to ensure that the available fault currents have not been
increased above the rating of the existing equipment. Fused disconnects
with RK-5 fuses are available with interrupt ratings up to 200,000 amps.
230.43 allows a number of different service entrance wiring systems.
However, considering that the tap conductors are unprotected from
faults, it is suggested that the conductors be as short as possible
with the new PV service/disconnect mounted adjacent to the tap
point. Conductors installed in rigid metal conduit would provide
the highest level of fault protection. All equipment must be properly
grounded per Article 250 requirements.
The actual location of
the tap will depend on the configuration and location of the existing
service entrance equipment. The following connection locations have
been used on various systems throughout the country. On the smaller
residential and commercial systems, there is sometimes room in the main
load center to tap the service conductors just before they are
connected to the existing service disconnect. In other installations,
the meter socket has lugs that are listed for two conductors per
lug. Combined meter/service disconnects/load centers frequently
have significant amounts of interior space where the tap can be made
between the meter socket and the service disconnect. Of course, adding
a new pull box between the meter socket and the service disconnect is
always an option. In the larger commercial installations, the main
service entrance equipment will frequently have bus bars that have
provisions for tap conductors.
In all cases, safe working practices dictate that the utility service
be de-energized before any tap connections are made.
Additional service entrance disconnect requirements in Article 230 and
other articles of the NEC will apply to this connection.
John Wiles email@example.com 505-646-6105 10/20/2005
Not available in .html format