Chapter 4-Guidelines for 2009 California Solar Incentive Programs

CHAPTER 4: Solar Energy System Design and
Installation Standards and Incentives
SB 1 requires high quality design and installation of solar energy systems to promote the
greatest energy production per ratepayer dollar, and directs the Energy Commission to
establish design and installation standards or incentives. This chapter establishes the Guidelines
for design and installation standards and incentives needed to achieve this mandate. Program
administrators shall comply with these Guidelines by no later than July 1, 2009. POUs with
peak demand of 200 MW or less as reported for calendar year 2006 shall comply with the
requirements in this chapter no later than January 1, 2010.
To achieve high performing solar energy systems, the incentive structures shall be
performance‐based to reward performance. There are two acceptable performance‐based
approaches: the performance‐based incentive (PBI) approach and the expected performancebased
incentive (EPBI) approach. These are discussed further in this chapter.
Performance-Based Incentives
Providing a PBI33 is the preferred way to promote high performing systems since the solar
energy systems receive incentives based on their actual production (kWh) over the period
during which the incentives are being paid. The PBI incentive payment is calculated by
multiplying the incentive rate ($/kWh) by the measured kWh output.
The PBI payments shall be made over a minimum five‐year period following system
installation, submission, and approval of incentive claim materials. Payments shall be based on
a $/kWh incentive rate and the actual electricity (kWh) produced in periods established by the
program administrator.
Expected Performance-Based Incentives
The expected performance‐based incentive (EPBI) approach pays an upfront incentive that is
based on calculated expected performance, taking into account all major factors that affect
performance of the particular installation in the given location. This incentive method may be
more appropriate than a PBI approach for systems installed on newly constructed buildings or

for smaller systems. The EPBI approach shall be used for systems that do not use the PBI
approach.
To meet the expectations of SB 1 for optimal system performance during periods of peak
demand and IEPR policy to target PV deployment to achieve the greatest cost benefit, EPBI
shall be based on time‐dependent value (TDV) weighted hourly generation.34
The EPBI calculation shall be based on hourly modeling of the interactive performance of solar
energy systems using the third‐party tested performance characteristics of the specific modules
and the inverter over the range of conditions that impact component performance. This
calculation addresses all installation characteristics that are expected to have significant impacts
on the performance of the components and the solar radiation, ambient temperature, and wind
conditions expected at the site.
The hourly performance of the system shall be based on the interaction of the components due
to the expected conditions during each hour. The hourly production shall be weighted in each
hour to account for the time‐dependent value to the utility of that hourʹs production to obtain
the annual time‐dependent weighted energy results for the system (kWhTDV). The total incentive
for the solar energy system is based upon the annual kWhTDV performance.

Hourly Photovoltaic Production Calculation
The solar panels production shall be calculated using a model that complies with the following
minimum requirements:
• The calculation model shall cover fixed flat‐plate collector technologies at a
minimum and include single‐ and dual‐axis tracking if the program administrators
allow for these technologies to be incentivized under the EPBI approach.35
• Use hourly weather data for one of the 16 climate zones in California, with the use of
solar radiation (global horizontal, direct normal and diffuse), dry bulb temperature,
and wind speed as minimum parameters in calculation to describe the conditions for
the hour.
• Determine the incident solar radiation on the modules based on the azimuth and tilt
angle of the installation using the weather data and location longitude and latitude
information.
• Use the detailed performance characteristics data for modules (listed in Appendix 1,
Table 1) in determining the hourly production at given conditions for the hour (both

weather and electrical). This data shall be obtained from the library of eligible
modules listed with the Energy Commission.
• Have the ability to determine the operating voltage of a system at a given hour by
discerning the circuit design of the system in terms of the number of modules in each
string and the number of strings.
• Account for the mounting offset of the array from a surface below to assess the
change in operating temperature (Normal Operating Cell Temperature impact). This
is especially important to determine the performance of building‐integrated
photovoltaics (BIPV), as compared to rack‐mounted modules.
• Account for the height above the ground that the array is mounted to capture the
impact of wind speed on the module operating temperature.
• Use detailed performance data for inverters (performance curves over range of
voltage and power conditions applicable) in determining the hourly production at
given conditions for the hour (both weather and electrical). This data shall be
obtained from the library of eligible inverters listed with the Energy Commission.36
• Limit the production of the system based on the size and voltage of the array and
inverter voltage and power capacity.
• Generate hourly estimates of PV production for the entire year, which can then be
weighted by time‐dependent value (TDV) multipliers.
• Determine the solar position for each hour of the year in terms of altitude and
azimuth (used to determine the impact of shading from an obstruction).
• Determine the hourly impact of shading from obstructions using a shading protocol
as described in Shading Verification, Appendix 2.
• Report the effective hourly production values for the entire year after factoring the
impact of shading and applying the appropriate TDV multipliers for the climate
zone and building type (residential or nonresidential).
• Generate a performance verification table for each specific system that reports the
expected production for the specific system and installation as a function of incident
solar radiation and ambient temperature. This performance verification table shall
enable field verification of actual vs. expected instantaneous production through the
comparison of the output reported by the performance meter to the value in the
performance verification table at the specific incident radiation and ambient
temperature measured at the site at the time of the verification.
• Generate a certificate of compliance form as a printable report37. The certificate of
compliance shall include, at a minimum, the entire system description including
installation specifics for the system, location, shading details, echo all the inputs for
the calculation, and the performance verification table.

Reference System and Location
The incentive calculation shall use a reference system and location established by the program
administrator to convert an incentive level established in terms of $/W to the $/kWhTDV
equivalent through the following calculation:
Reference System Annual kWh
Reference System Watts $/Watt (incentive level)

The specification of the reference system shall include:38
• Location of the system to determine the weather data and corresponding applicable
TDV factors to be used.
• Size of a system that is representative of the median in the applicable utility program.
• Selection of a reference module from the Energy Commission’s Eligible Equipment List,
along with all its performance characteristics, that is considered as a median for the
applicable utility program.
• Selection of an inverter from the Energy Commission’s Eligible Equipment List that is
considered a median for the applicable utility program.
• The installation characteristics that comprehensively describe the system, including, but
not limited to:
o Azimuth
o Tilt
o Mounting offset (BIPV or rack with specific height above substrate)
o Height above ground (one story or higher)
o Electrical circuit design (modules per string and number of strings)
o Shading conditions (minimal shading)
o Other system losses (such as dirt, dust, and wiring losses)
The $/kWhTDV (or the $/W before the above conversion) shall be chosen to ensure that the full
range of improvement in performance (in kWhTDV) is provided with increasing incentives.
Incentive Calculation
The total incentive for the applicant system shall be determined by multiplying the TDV
weighted annual kWh production with the $/kWhTDV determined in the previous step (using the
reference system)39.

Total Incentive $ = Applicant System Annual kWh ×$/kWh
The basic structure of the Energy Commission’s PV calculator40 can be used to meet these
requirements. The calculator can be modified or another calculator used, as long as it meets
requirements 1 through 15 of the Hourly Photovoltaic Production Calculation. The reference
system and location and the incentive level is specified by the program administrator. POU
program administrators may use time of use multipliers that are applicable to their service
territories instead of TDV.
EXCEPTION: The CPUC and POU Program Administrators are not required to comply with
the above Hourly Photovoltaic Production Calculation requirements by July 1, 2009. The CPUC
should determine whether it believes that changes should be made to the CPUC’s CSI
calculation methods and under what timeframe it would make changes. POU Program
Administrators may choose to use a calculation method that complies with the Hourly
Photovoltaic Production Calculation requirements or the expected performance based incentive
calculation method used by the CPUC. The Energy Commission strongly encourages the
CPUC’s CSI program to upgrade its current methods for estimating the expected performance
of solar electric generating systems to better promote high‐quality solar energy systems with
maximum system performance to promote the highest energy production per ratepayer dollar
and to achieve optimal system performance during periods of peak electricity demand. The
Energy Commission recommends that as the CPUC upgrades its calculation methods, it
endeavors to meet the hourly photovoltaic production calculation provisions of these
guidelines. POU Program Administrators who choose to use the CPUC’s expected performance
based incentives calculation method are expected to use improved versions that are updated to
better meet the hourly photovoltaic production calculation provisions. The CPUC shall comply
with the shading, performance verification, and field verification requirements of these
guidelines.

Shading
The method that shall be used as the minimum criteria for addressing shading is detailed in
Appendix 2‐Field Verification and Diagnostic Testing of Photovoltaic Systems.

Peak Load
For systems receiving incentives under the expected performance calculation approach, the
incentive shall be based on weighting the hourly production with TDV factors to promote
systems with higher performance at peak load conditions. TDV factors have been developed for
the 16 Building Energy Efficiency Standards climate zones in California using IOU generation,
transmission and distribution cost data.41
POU program administrators should use either the TDV factors determined for the 16 climate zones or
hourly time‐of‐use weighting factors that are applicable for their service territories.
Field Verification
To be eligible for incentive payment, EPBI applicants and PBI applicants whose systems are
smaller than 50 kW shall be required to successfully complete third‐party field verification on a
sampling basis. Field verification is encouraged for other PBI applicants. The field verification,
at a minimum, shall include visual inspection of components, installation characteristics, and
shading conditions. For EPBI systems only, performance shall be verified using the protocol
described in Appendix 2‐Field Verification and Diagnostic Testing of Photovoltaic Systems.
The third‐party field verification shall be carried out on a minimum sample size of one in seven
by a qualified Home Energy Rating System (HERS) rater, the program administrator, or a
designated qualified contractor, as determined by the program administrator.
Installation
The installers shall certify all aspects of the installation using the protocol for field verification
(Appendix 2). This includes the actual components used, the installation characteristics, shading
conditions and the specified onsite instantaneous performance verification. The same protocol
will be used by both the installer and the verifier, with the difference of the installer having
better access to the installation in some cases. It will be the responsibility of the installer to
document all proof for items that may be more easily observed and measured by the installer
than by the verifier.
EXCEPTIONS: The program administrator may waive the installer requirement to follow the
field verification protocol under any one of the following conditions:

1. The program requires field verification on 100 percent of the systems (without using
sampling approach).
2. The installer follows the alternate protocol described in Installer System Inspection,
Appendix 2, and signs a certificate of having completed the same.
Performance Monitoring and MaintenanceAll systems using the PBI approach shall have a five‐year service contract42 with a performance
monitoring and reporting service (PMRS).43
For systems using the EPBI approach, a PMRS shall be required if the program administrator
determines that it is economically reasonable, comparing the cost of available PMRS to the cost
caps shown in the table below.

For all systems, it is recommended that program administrators ensure that information
regarding system maintenance is provided to the owner or facility manager of the property who
has oversight of the system. The information should address, at a minimum, the following
considerations:
• Cleaning schedule for the array to remove dirt and dust buildup.
• Periodic checking of electrical connections (for corrosion, and so forth).
• Checking the inverter for instantaneous power, long‐term energy output, and diagnosing
and taking corrective action if production is significantly lower than expected.
• Checking for tree/plant growth or other obstructions that are causing shading on the array
and advise how to minimize or eliminate that shading.