Solar electric systems can be a... investment for homeowners

Solar  electric  systems  can  be  a... investment for homeowners
By Andy Black
Good system performance, high electric rates, Net Metering
and Time-Of-Use rate structures, Solar Renewable Energy
Certificates (SRECs) and government incentives have
contributed to the financial viability of solar electricity. How
these factors come together varies significantly by location.
Some locations have the combination of factors that yield
excellent results; in others, it makes no economic sense to go
solar, especially when including the maintenance and inverter
In places where solar is economically attractive, rates of return replacement costs.
from 9% to 15% or better are common. If financed, the monthly
The key element for most analyses is the ongoing value
net loan cost is usually less than the monthly utility bill savings. generated by the solar system (the savings on the electric utility
And if the home is sold, the solar system should increase the bill or the monetary value of system output that can be sold). A
resale value by more than the system cost to install.
properly sited, sized, designed, and installed solar system can
The above claims are big, so rigorous treatment and critical usually eliminate most or all of a customer’s total annual
analyses from several angles including Compound Annual Rate electric bill.
Solar electric systems can be a good financial
investment for homeowners and businesses,
depending on a variety of factors including system
performance, electric rates, favorable utility rate
structures, and incentives. Several US states have the
right combination of conditions to strongly encourage
end-consumer investment in solar electric systems
based on economics alone.
of Return, Cash Flow, Lifecycle Payback, and Appraisable
The next pages will discuss system performance, electric rate
Resale Value need to be considered to do a fair assessment. structures, and incentives. The pages following will detail how
Using the above analysis methods helps compare the solar the economics can then be analyzed using Rate of Return,
investment to other investments on an even basis.
Payback and Lifecycle Payback, Property Value Increase, and
Cash Flow when Financing.
! What factors need to be considered to determine the
economic payoff of solar, including rates, rate structures,
systems performance, solar RECs, and incentives
! How to test the economic value in the ways listed above
Lots of Sunlight is just one of the many factors that must be
included in a system performance calculation. Across much of
the United States, the amount of available sunlight is
surprisingly uniform, with most areas within ± 20% of the
This article also includes “Policy Discussion” paragraphs to sunlight level of Miami, Florida, as can be seen in Fig. 1. The
help individuals and policy makers in locations without strong National Renewable Energy Laboratory (NREL) has data on
economics understand the issues around creating solar-friendly 239 locations across the U.S. and its territories available at: and its PVWatts
policies, which motivate and leverage individual investment.
calculator will determine performance for a user specified PV
Equivalent Noontime Sun Hours per Day (Annual
Portland, OR
Buffalo, NY
Chicago, IL
Newark, NJ
Boston, MA
Baltimore, MD
Raleigh, NC
Miami, FL
Austin, TX
San Francisco, CA
Boulder, CO
Los Angeles, CA
Phoenix, AZ
Fig. 1. Most U.S. locations are ± 20% of Miami’s
sunlight level. Sources: NREL: and
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 1 of 19
There are numerous loss factors that affect real system
performance including component performance, wire losses,
soiling, module degradation, module mismatch, system uptime
and reliability, manufacturer production tolerance, and system
design factors such as tilt, orientation, shading, and air flow.
The California Energy Commission has produced “A Guide To
Photovoltaic (PV) System Design And Installation” available at:
and is an excellent overview of system design considerations.
Fig. 2 lists performance loss factors, and the significance of
potential relative losses from tilt, orientation, and shading.
Inverters aren’t 100% efficient, with most achieving 94-96%
efficiency. Similarly, PV modules in operation put out
approximately 7-14% less power at realistic operating
temperatures compared to the Standard Test Conditions (STC)
commonly measured in factory or laboratory settings. The State
of California provides lists of module and inverter ratings at:
Soiling, module degradation, and module mismatch also must
be accounted for. The designer and installer have some control
over wire losses, but by code, must not exceed 5%.
Manufacturer production tolerance losses result from some
modules having a performance specification of +X%, -Y%. If
there is a negative tolerance, the customer can be sure she will
be on the losing end of that bargain to at least some extent.
The system designer in coordination with the property owner
has control over how the modules are mounted, especially how
far off the roof, affecting how much airflow occurs. Thermal
stagnation starts to occur with less than 6” clear airflow space
behind the modules and can reduce performance up to 10% at
0” air gap.
The designer and property owner also have control of solar
system orientation (tilt angle or ‘altitude’ above horizontal and
direction or azimuth), and usually some control over shading.
Shading and/or orientation are usually the #1
underestimated system performance loss factors except in
locations where incentive programs specifically (directly or
indirectly) include these in the calculation of the incentive to be
paid. It is critical that the site analyst / installer use a shade
analysis tool to accurately determine shade. Quality shade tools
include the Solar Pathfinder (,
Solmetric SunEye (, and the Wiley
ASSET ( It is impossible
to estimate shading by eye, and even a few percent can be
significant. Avoiding shading is often the most important
criteria, even over selecting a south-facing roof.
System availability (uptime) is dependent on system
reliability and monitoring. A well-designed system with
known reliable components (particularly the inverter) is
important. Placing inverters in shaded, well-ventilated locations
that won’t accumulate ventilation-inhibiting debris will
eliminate many common overheating-related problems (reduced
power output due to thermal protection or shortened component
lifetime). Placing the inverter close to the utility connection
point will eliminate many common utility interconnection
Economics of Solar Electric Systems
related problems (long wires can have a kind of ‘voltage
buildup’ in the wiring causing the inverter to think the utility is
not safe to connect with, requiring it to shut down for at least 5
minutes). The only way to know if a system is operating
reliably is to monitor it as often as possible. Monthly
observations via the electric bill savings are a crude minimum
but can take 45 days or longer to make even a simple problem
(sometimes only requiring a simple reset of the inverter) visible,
resulting in over 12% of a year’s energy to be lost. Active
continuous real-time monitoring and automated alerting
solutions are available that should more than pay for themselves
in increased savings, peace of mind, and owner satisfaction.
System Performance Factors Policy Discussion: Including
predicted or actual system performance in determining the level
of incentive to be paid (then actually verifying compliance with
the approved design) is an excellent way for incentive agencies
to improve system quality. Before California adopted the
requirements of the new California Solar Initiative (CSI)
program, a significant fraction of sold and installed systems
had major shading or other site-selection design problems,
often only disclosed to the customer with a hand-wave of
“you’ll lose a little performance due to shading…” The CSI has
received a lot of criticism because of the increased level of
paperwork, scrutiny and repercussions for “failures” from
those who would rather do things the old, easy, loosey-goosey
way, but in the author’s opinion, the new level of accountability
is the best thing that could have happened to raise the quality of
installations in the state. This higher level of quality is nothing
new to those in some other states such as Colorado and in some
municipal utilities like SMUD. Going forward, the author has
grave concerns about the quality of systems that will be
installed as a result of the expansion of the federal Investment
Tax Credit, which has no performance or quality safeguards.
Typical Loss and Performance Factors:
Module Temperature
Inverter Efficiency
Dust & Dirt
Module Degradation over 20
Wiring (AC & DC combined)
Module Mismatch
Manufacturer Production
Typical Totals for the
Best Systems
Additional Design-Dependent Factors:
Air Flow
Orientation & Tilt
System Availability (uptime)
Fig. 2. Summary of Performance and Loss Factors
! 2009, Andy Black. All rights reserved.
July 2009 - 2 of 19
2007 U.S. Average Retail Price per kWh is 9.13 Cents
Average Retail Price (Cents per kWh)
Fig. 3. The graphic above shows the 2007 U.S. average electric rates for all
sectors. The table at right shows 2008 average residential electric rates for
selected states and their Compound Annual Growth Rates (CAGR) for three
time periods before 2008. Source: U.S. Energy Information Administration:
High Electricity Rates are an expensive fact of life in a
number of US states and can be worse still in other countries.
Hawaii has the highest electric rates in the U.S. topping out at
32¢/kWh for the average residential consumer (certain islands
are higher), however, rates are also very high in Connecticut,
California, New York and other states (Fig. 3).
Rates have risen fast across the land since 2001 and especially
fast since 2004 (Fig. 3). Electric rate increases will likely be
tempered by the Great Recession of 2009. Future rate hikes can
only be guessed at, as they depend on many factors.
efficient with how she uses electricity is to charge more for it,
but there are limits to how this can be applied
consumers. Many utilities have adopted a
tiered pricing structure, as can been see in Fig.
5, where the first part of a consumers
consumption is charged at a lower rate, but
if the consumer uses more than a
“baseline” allocation (an amount deemed
to be required to cover a consumer’s
“basic needs”) she will pay more for
the next part of her usage. The
more she uses, the more each
kWh costs. The more tiers there
are in the system, the more the
In comparison, the Consumer Price index (CPI-U) has been
increasing at 3.1% on average since 1982. One might ask, how
is it that electric rates have continuously increased faster than
the CPI – wouldn’t electricity become a bigger and bigger
portion of our consumer
expenses, until eventually
something brought it into
check? The answer lies in
the fact that we are
continuously getting more
efficient with how we use
electricity, so we are able
to produce more economic
value per unit of electricity.
We are therefore able to
spend more per kWh.
Fig. 4. Residential electric rates in California from 1970 to 2001 increased at a 6.7% compound
One of the ways consumers
annual rate (source: CPUC “Electric Rate Compendium” Nov. 2001 from EIA data). Since 2001,
can be motivated to be more
there has been no change in Tiers 1 & 2, but an exaggerated increase in Tiers 3-5. Enactment of
AB413 and expiration of AB1X may alter these trends. Note: this graphic is to scale.
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 3 of 19
$43/mo bill at top of Tier 1
Fig. 5. Progressive tiered rate pricing penalizes large users most with a marginal electricity cost at ever increasing rates. In
these cases, solar offsets the highest tier usage first, making the solar customer look like a smaller user with a lower marginal
cost. The graphic on the left indicates which tier a user is in for a given monthly electric usage (1650 kWh) and bill ($499) in
San Jose, CA. On the right, the green area represents how much is offset by solar (1225 kWh and $463 out of $499).
can be fine-tuned, but also, the more complicated billing
becomes. Fig. 5 illustrates a “progressive” pricing model for
rates (similar to progressive tax structures), which attempts to
discourage large use while protecting smaller using consumers.
The progressive model encourages conservation, efficiency, and
conveniently for the solar industry, solar installations as well.
The graphic in the right half of Fig. 5 shows how a solar system
makes a user look like a smaller consumer (the green area is
solar generation, the red area is the remaining net usage), and
offsets the most expensive electricity first, yielding the greatest
savings first, boosting the economics of solar. This particular
case is saving 44¢/kWh for the first set of production, 38¢/kWh
for the next set, and so on. Not all utilities use the above
“progressive” pricing model. Some utilities offer discounts for
buying in bulk – the larger the use, the less expensive the cost of
the next kWh. This may be rational in some utility cost models,
but it doesn’t encourage conservation, energy efficiency or solar
Fig. 4 shows the California rate history since 1970. From 1970
to 2001, rates increased at a compound annual average rate of
6.7%, as can be seen in the lower left portion of the graphic.
Things got considerably more complicated in 2001 because of
the California Power Crisis in conjunction with the deregulation
process that affected rates starting in 1996.
During the power crisis California’s AB1X legislation froze
the rates for residential users using at or below the average
usage for their local climate zone (which equals usage at or
below the top of Tier 2), but at the same time, created Tiers 3, 4
and 5 at much higher rates (17-26¢/kWh). The users using well
above average found their bills almost doubled upon
implementation of the change. It had the desired effect: high
using residential consumers quickly became motivated to
reduce their usage by conservation, efficiency, and some turned
to solar systems, dramatically increasing the solar market.
Rates in Tier 3, 4 & 5 have gone up and down dramatically
since 2001, with a recent average rate of increase that has been
very high (double digit). This high average will not continue
forever because of the eventual expiration of California AB1X
(the date of this is unknown for a variety of complicated
reasons, but may be soon, depending on what happens with
AB413). When this happens, it is anyone’s guess how the
politics will fall, but one of three possibilities is likely: 1. Rates
in all tiers will move in lock step at a more normal rate of
escalation, 2. Rates in Tier 3-5 will be frozen while Tier 1 & 2
catch up, or 3. Rates in Tier 3-5 will be reduced and rates in
Tier 1 & 2 will move up to compensate.
A conservative approach to electricity escalation suggests a
5% annual escalation – anything more than that might be
viewed as “optimistic” which may cause customers to become
concerned. The scenario examples depicted later will assume
5% except as noted. The goal of this article is to provide a
conservative set of assumptions and a “bullet-proof” analysis
methodology, that if followed, will be acceptable to the broad
majority of serious potential customers, and provide them and
their financial advisors a solid basis for making an informed
Tiered Rate Policy Discussion: Progressive Tiered Rates are
excellent motivators of conservation and energy efficiency (and
conveniently, solar), but they may also be the government and
utility officials ‘public relations friend’ as well. By creating
multiple tiers, policy makers can shift some of the burden of
future rate increases to the larger (above average), more
wasteful users (residential only) and thereby lighten the burden
on the users who are at or below average consumption. This
works well for residential usage, because it is easy to quantify
the average consumption per typical household, however
average consumption per business would be meaningless in this
context, since most communities want their local business to
grow (efficiently) from year to year, so penalizing ever growing
usage would be counterproductive.
Rate escalation in California got more complicated thereafter
as well. Because state law AB1X prohibits changes to the rates
for Tier 1 and Tier 2, all the increase must be borne in Tiers 3, 4
High electric rates are among the most important factors
and 5. If revenue needs to increase by 10%, Tier 3, 4 & 5 rates determining who will have the best economics with solar,
must increase approximately 50%. That happened on January however, high rates are only valuable if the customer can also
1st, 2006 to PG&E residential customers, as seen in Fig. 4.
enjoy Net Metering, a regulatory structure set up for solar
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 4 of 19
Time-Of-Use (TOU): Most residential electricity is billed to
customers on a flat (or time independent) rate schedule, where
electricity costs the customer the same at any time of the day.
However, utilities often have increased demand for electricity
during certain times of the day and certain days or months of the
year. When this “Peak” demand occurs usually depends on local
climate factors. For example, Arizona and California have their
peak times near 4-6pm Monday thru Friday during the summer,
because that’s the overlap of the workday and home activity,
which both use air conditioning, which is one of the largest
loads. At night and in the morning, because of the dry climate, it
cools off, so the load is less. Eastern U.S. utilities see their peak
demand all day long because the humidity keeps consumers
using their air conditioning 24/7 in the home, and during the
workday at work, so a typical peak period is 9am-9pm.
To solve the increased demand regardless of when it occurs,
utilities could build more power plants, but those plants would
only run during peak times, which is only a relatively few hours
of the year, and would therefore be an expensive solution on a
per kWh produced basis because of the capital costs. Another
solution is to encourage conservation during or load-shifting
away from those “Peak” time periods.
Fig. 6. Net Metering allows the exchange of electricity
produced or purchased to be valued at retail rates allowing
the grid to act like a 100% efficient battery for the consumer
to “store” her excess production during the day or over a
season until she needs it at night or during another season.
To create this encouragement, some utilities offer Time of Use
(TOU) or Time of Day (TOD) rates, where the cost of
electricity depends on the time of day and sometimes on the
season of year. The TOU time periods and rates are usually
labeled something like “Peak”, “Part-Peak” and “Off-Peak” and
often have a “Summer” and a “Winter” season.
electricity producers (and sometimes certain other renewable
The upper graphic in Fig. 7 shows the TOU pricing periods
producers depending on the state) in 42 of the 50 U.S. states.
for the PG&E E6 rate in California illustrating peak, part-peak,
Under Net Metering, full retail value is credited when excess and off-peak time periods. Notice that there are also part-peak
electricity is produced and “sold” back to the utility, offsetting rates on weekends. The lower graphic shows the typical
the customer’s electric bill (Fig. 6). There are a variety of Net (approximate) time periods of many Eastern U.S. utilities, such
Metering forms, the implementation of which vary by state and as in New Jersey, New York, and Pennsylvania.
utility. An older form is “Monthly Net Metering,” whereby a
High rates during peak periods encourage consumers to use
solar producer can eliminate her monthly electric bill, and any
less or to change behavior and instead, consume the electricity
excess production would typically be paid to the producer at the
during off-peak periods. Easy ways to shift usage are changing
utility’s “avoided cost” or “fuel cost” per kWh (approximately
what time of day laundry is done or when the pool filter pumps
1-3¢/kWh). The problem is that solar production varies
run at home. Small business sometimes have choice over
substantially by season, so it is hard to design a system that
whether to take service under a TOU rate schedule, and if so,
balances a user’s needs in each of the 12 months without underthey may be able to save money by shifting how or when they
producing in one season (usually winter) and over-producing in do things, such as change to 2 or 3 shifts of work hours, or
the other. Under-production results in large bills charged at high change when they make ice or pump water or do other energy
retail costs of electricity. Over-production creates small credits intensive activities. Large businesses and many agricultural
based on the “avoided cost” value of the excess energy.
(pumping and refrigeration) operations have no choice and must
The solution is the newer “Annual Net Metering,” which take TOU service, so are always encouraged in a financial way.
allows summer excess production to offset winter shortfalls,
TOU rate differentials between Peak and Off-Peak can range
with the goal of allowing the customer (or her knowledgeable
from just a cent or two, to up to 20¢/kWh or more, depending
and experienced designer/installer) to right-size the system to
on the utility’s need to motivate change. In PG&E territory in
fully offset the annual electric bill, but not over-size it. With
California, a further twist is that the tiered rate structure is
annual Net Metering, the utility ends up looking like a 100%
applied on top of the TOU rates (residential only), so off-peak
efficient battery that can store energy for up to a year at no loss
Tier 1 rates are as low as 9-10¢/kWh depending on season, but
or penalty. The other half of this compromise is that any excess the summer peak Tier 5 rate can be over 61¢/kWh. That sounds
production credit after the 12 month is given to the utility, expensive, and it is, and one might question the wisdom of even
discouraging over-sizing of systems and simplifying the utility’s considering switching to a TOU rate schedule, but there is a
accounting and saving them the processing costs of sending a
convenient opportunity that solar customers can apply in their
check or carrying a credit.
Economics of Solar Electric Systems
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July 2009 - 5 of 19
Residential PG&E "E6" Time-of-Use Pricing Periods
Midnight - 6am
6am - 10am
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Off-Peak Off-Peak Off-Peak Off-Peak Off-Peak Off-Peak Off-Peak
Off-Peak Off-Peak Off-Peak Off-Peak Off-Peak Off-Peak Off-Peak
10am - 1pm
Off-Peak Part-Peak Part-Peak Part-Peak Part-Peak Part-Peak Off-Peak
1pm - 7pm
7pm - 9pm
Part-Peak Part-Peak Part-Peak Part-Peak Part-Peak Part-Peak Part-Peak
9pm - Midnight Off-Peak Off-Peak Off-Peak Off-Peak Off-Peak Off-Peak Off-Peak
Eastern U.S. Typical Residential Time-of-Use Pricing Periods
Midnight - 9am
9am - Noon
Noon - 9pm
9pm - Midnight
Monday Tuesday Wednesday Thursday
Off-Peak Off-Peak Off-Peak
Off-Peak Off-Peak Off-Peak
Off-Peak Off-Peak Off-Peak
Off-Peak Off-Peak Off-Peak
Fig. 7. Time-of-Use rate structures showing typical peak, part-peak and off-peak time
periods for Western and Eastern U.S. utilities.
Combining Net Metering with TOU allows a solar customer
to take advantage of the benefits of Net Metering on a TOU rate
schedule and, if timing and consumption patterns allow, “sell”
energy to the utility during peak periods at the high rate, then
buy energy during off-peak hours. The customer gets credited or
charged for the value of the electricity when it is bought or sold
(at its prevailing retail rate at that time). The utility then looks
like a >100% efficient battery because in many cases, most
solar electricity is produced during peak hours, and most is
consumed in a residence during part-peak and off-peak hours.
The customer gets more value for the same kWh produced, and
therefore needs a smaller solar system to offset her electric bill.
The greater the differential in peak to off-peak rates, and the
better the solar production matches peak hours, and the better
the homes consumption matches off-peak hours, the greater the
benefit of opting for the TOU rate schedule upon adding the
solar system.
This approach often (but not always) works well in utility
areas that have large daytime summer peak loads (often due to
air conditioning load), such as in the Eastern, Southern, and
Southwestern U.S., because this usually matches solar
production well. However, some northern utilities are winter
night peaking because their peak load is caused by electric
heating loads of homes. In these cases, solar is a poor match.
TOU Net Metering works best if the customer can mount her
solar array in a way that maximizes production during the peak
period, for example facing southwest or south at an angle near
25 degrees up from horizontal (equal to a 6:12 roof). Slopes
from 5 to 40 degrees and southeast and west arrays generally
also work quite well. Note: it is usually not economically
feasible to tilt a solar array away from parallel with the roof’s
surface to optimize performance, because the gain in production
(bill savings) is often not worth the additional mounting
hardware and labor cost or the aesthetic penalty.
between peak and off-peak, the more motivated the user will be
(solar or not) to conserve during peak pricing periods. Effective
TOU rate implementations help flatten out the utility’s load
profile, requiring fewer “peaker” power plants which operate
at very high cost per kWh delivered (once capital costs/debt
service are included), because such plants run only a few hours
per year. In the right locations, solar can provide some of this
“peaker” benefit. Solar advocates can use this to encourage
their Public Utility Commissions and Legislatures to adopt proTOU policies.
Rate Structure vs. (Cash) Incentives Policy Discussion:
Economically viable solar systems are incentivized thru both
cash or cash equivalent (tax saving) payments and electric ratebased (or regulatory) savings. Solar-friendly rate structures are
incentives because they provide a higher value benefit to solar
customers compared to the “commodity” value of the electricity
producers could otherwise sell into the power pool at
commodity rates (as QFs or Qualifying Facilities). Using cash
incentives to encourage solar is easy to understand, but it is
also highly visible, and there are several drawbacks compared
with solar-friendly rate structure incentives. Cash and cash
equivalent incentives can and do come and go depending on the
political winds. Even long-term incentive programs, such as
German EEG law or the California Solar Initiative could be
overturned or modified with a change in government or its
attitude. Spain is learning this the hard way after the summer
and fall of 2008. The U.S. solar market became painfully aware
of its dependence on the extension of the 30% Federal
Investment Tax Credit which was due to expire at the end of
2008 but was passed at the last moment as part of the
Emergency Economic Stabilization Act of 2008. Regulatory
incentives are much more difficult to achieve, however, once
won, they are also much more difficult to lose. Any state with
Net Metering, TOU, or Tiered rates is likely to have them for a
long time and it will be a huge battle to take them away.
TOU Policy Discussion: Time-of-Use rates are a powerful
tool to motivate customers to voluntarily use less power during
predictable times of shortage. The greater the differential
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 6 of 19
There are several ways the government (in its various forms)
can provide incentives for solar. Already discussed were the
regulatory forms of incentive via favorable rate structures. Here,
we discuss the various “Cash” or “Cash Equivalent” incentives,
which include:
! Tax Credits and the U.S. Treasury Grant
! Accelerated Depreciation
! Sec. 179 Tax Deduction interaction with the ITC & Grant
! Cash Rebates and Buy-downs
! Performance Based Incentives (PBIs)
! Feed-In Tariffs
! Tax abatements (waivers of sales and/or property taxes)
! SRECs (Green Tags) mandated by state law
The Database for State Incentives for Renewable Energy (The
DSIRE database, is a database
of all state and federal incentive programs around the country
for all types of renewable energy and also energy efficiency,
and provides specific details and links state by state and at the
federal level.
Equipment delivered and construction / installation
completed. Minor tasks like painting need not be finished
Taxpayer has taken legal title and control
Pre-operational tests demonstrate the equipment functions
as intended
Taxpayer has licenses, permits, and PTO (permission to
Both the residential (Sec. 25D) and commercial (Sec. 48) ITC
are one-time credits received when filing taxes for the year the
system was placed in service. If not completely useable in the
system installation tax year, in theory, the residential ITC can be
carried forward indefinitely but may run into the practical
difficulty that the 5695 tax form may no longer exist after the
2016 tax year unless the IRS makes it available. SEIA is
working to address this with the IRS. The ITC can be carried
forward only by necessity, and must be claimed as soon as
possible (i.e. can’t be carried forward simply for convenience).
The business credit can be carried forward 20 years and may be
able to be carried back for certain businesses under the Net
Operating Loss rules.
The Solar Energy Industries Association (SEIA) has put
As part of the American Recovery and Reinvestment Act of
together an excellent and well researched “Guide to Federal Tax 2009 (ARRA), in order to stimulate the economy, and in
Incentives for Solar Energy”, available free to members as a particular, the solar industry, commercial solar systems (Sec. 48
membership benefit. Learn more at:
ITC only) are able to convert the ITC that would normally be
received at the end of the tax year, and only if there was tax
Tax Benefits such as Tax Credits and Depreciation may be
appetite, into a U.S. Treasury Grant that can be received as
available to certain taxpayers who install solar energy
early as 60 days after project completion or application
equipment. The information in this article regarding taxes, tax
(whichever is later). Only projects placed in service in 2009 or
credits and depreciation is meant to make the reader aware of
2010, or projects started in 2009 or 2010 and placed in service
these benefits, risks and potential expenses, and help avoid
before the end of 2016 are eligible for Grant treatment. This
overblown claims by aggressive salespeople. It is not tax
solves the lost “time value of money” due to lengthy carryadvice, and the author is not a qualified tax professional.
forwards for taxpayers with limited ability to use the ITC.
Please seek professional advice from a qualified tax advisor
to check the applicability and eligibility of incentives for a
Most of the rules and eligibility for the Grant are the same as
particular situation.
for the ITC, except as noted above. More information is
Tax Credits come in several forms: Federal, State and Local.
Thru the end of 2008, the Federal Investment Tax Credit
(ITC) for Residential (individual tax filers) was 30% of system
Although the ITC is received effectively “up-front” when the
cost basis, capped at $2,000 for systems installed before the end system is installed (or at the end of that tax year), it is actually
of 2008. From 2009 thru 2016 it is a full 30% (without cap). earned over 5 years in equal 20% increments. If the property
The residential ITC can be found in Sec. 25D of the Internal becomes ineligible for the ITC (is disposed of or sold by the
Revenue Code (IRC) and can be claimed using IRS form 5695. taxpayer, taken out of service, or taken outside of the U.S.), IRC
Sec. 50(a)(1) stipulates that the taxpayer must repay the
The residential ITC will expire at the end of 2016 if not
unearned portion via the recapture mechanism. For example, if
extended. Federal taxability of state, local, or utility rebates
the taxpayer sells the system after 2.8 years of ownership, she
affect the ITC system cost basis significantly, so please see the
has only earned 2 of 5 years (40%) of the ITC, and must repay
“No Double Benefit” section of this article (below) that
discusses Sec. 136(b) of the IRC.
The U.S. Treasury Grant has the same recapture mechanism,
The Federal Investment Tax Credit (ITC) for Business
but is slightly more relaxed. If the property is sold to another
owned systems (IRS Schedule C business tax filers) is 30% of
eligible party, the original party receiving the grant is not
net system cost with no cap for systems that are “placed in
subject to recapture as long as the receiving party maintains the
service” by the end of 2016 (IRC Sec. 48). After 2016, if not
property’s Grant eligibility for the remainder of the 5 years. If
extended, the tax credit will revert to the previous permanent
they don’t, the original party will suffer the recapture event.
level of 10%. The IRS current federal form is 3468 available at
In 2008, home-based businesses (if >20% business allocation
of the home) typically qualified for the ITC as well. Because the
“Placed in service” as defined by the SEIA “Guide to Federal
credit applies on both individual (residential) and business tax
Tax Incentives for Solar Energy” occurs when all of the
returns, but was capped on residential, it needed to be properly
following have occurred:
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 7 of 19
apportioned on each part of the tax return to ensure the right
credit amount is claimed. Home-based businesses are typically
apportioned based on percentage of square footage attributed
exclusively to the business. To figure the credit, one typically
applies the percentages to the two separate calculations then
sums the results. From 2009 to 2016 with the uncapped ITC,
this distinction is probably no longer relevant.
$85K ($100K minus one half of the $30K ITC). If the
customer’s federal tax rate were 28%, the federal depreciation
benefit would be approximately $24K ($85K times 28%).
The state depreciation benefit is the state tax rate times the
state depreciation basis, which may be different from the federal
depreciation basis, and may be affected by any state rebates
received. Unfortunately, for the same reasons that state income
Beginning in 2009 taxpayers (individuals and businesses) will tax credits aren’t really worth their face value, similarly, the
be able to claim the federal ITC even if they are subject to the state depreciation net benefit must factor in the effective federal
Alternative Minimum Tax (AMT). Systems placed in service taxation effect of reducing state taxes.
before the end of 2008 can suffer AMT limitation because the
Federal depreciation for solar uses the MACRS 5-year
solar ITC (and Accelerated Depreciation discussed in the next
Accelerated Depreciation schedule and is calculated on IRS
section) are ‘Tax Preference Items’ that can cause AMT and
form 4562. MACRS stands for Modified Accelerated Cost
limit the enjoyment of the ITC benefit, even if the taxpayer
Recovery System, and is a way of allowing businesses to
wasn’t subject to AMT before getting the solar system. Even
depreciate some property more quickly than the normal
with the ITC “AMT relief” starting in 2009, the Accelerated
schedule, to receive the write-off sooner (accelerate the benefit).
Depreciation may still cause an AMT situation for businesses.
Though it is called “5 year MACRS” it generally uses the “halfThere is an open question in the solar industry about the year convention” assuming the property is placed in service in
application of the ITC to “property used for lodging”. Sec. the middle of the tax year, which allows a lesser share of the
50(b)(2) indicates that the Federal ITC is not available for write-off in the first year and extends the write-off into the 6th
“property used for lodging”. This sentence has created a fair bit year. Different numbers may apply if the property was placed in
of concern for the solar industry, because it appears to exclude service late in the tax year. Home-based business systems may
hotels/motels and rental property. However, Sec. 50(b)(2)(D) also qualify for proportional depreciation (if the business use of
seems to exempt “Any energy property” (which solar is as the property is greater than 50%).
defined in Sec. 48(a)(3)(A)(i) “equipment which uses solar
In 2008 and 2009 only, as part of the Economic Stimulus Act
energy to generate electricity”) from this exclusion. The author
of 2008 and the ARRA of 2009, businesses can also receive
has not received a definitive answer from a qualified tax
‘50% Bonus Depreciation’ meaning that they can further
professional or the IRS as to whether hotels and rentals are
accelerate half the future depreciation amounts into the first
eligible. Thanks to Chad Blanchard and Michael Masek for
year (2008 or 2009) the project was placed in service (it does
helping research this.
not mean they are getting 50% extra depreciation, just getting
Please seek qualified tax advice before accepting anyone’s half of it even sooner). The 5-Year MACRS schedules (halfclaims of applicability of these or other tax benefits to a year convention) are:
particular situation.
State Income Tax Credits are available in several states,
Not 2008
such as Oregon, Hawaii, New Mexico, and New York, and can
20% 32% 19.2% 11.52% 11.52% 5.76%
or 2009
be quite generous. However, potential recipients should be
2008 and
aware that if they itemize their federal tax deductions, a state tax
60% 16% 9.6%
5.76% 2.88%
credit isn’t worth its full face value. When itemizing, state taxes
Fig. 8: MACRS Federal Depreciation Schedules for 2008 and
are usually deductible off federal taxable income. Reducing
2009 and years other than 2008 or 2009.
state taxes by the state tax credit means that federal taxable net
income will go up. In effect, federal income tax will be paid on
State depreciation sometimes depends on the type of business.
the value of the state tax credit. For most people, a state tax
In California, it is split between “Corporate” and “Noncredit is worth about 65-85% of its face value.
Corporate” businesses. Non-Corporate businesses use the
Depreciation and Accelerated Depreciation may be a regular federal MACRS 5-year accelerated depreciation
possibility for business owned systems. Depreciation is a (without the 50% bonus). California corporate businesses use
method of ‘writing-off’ expenses for long lasting (durable) 12-year straight-line depreciation for state depreciation. Please
goods such as cars, computers, etc. The ‘write-off’ is generally check the DSIRE database for the applicable depreciation for
required to be spread over several years, depending on the type other states.
of property. Since depreciation is a write-off, it reduces taxable
The Sec. 179 Deduction has a negative interaction with the
income, and thus reduces tax liability. The net federal benefit of
ITC and U.S. Treasury Grant. If the taxpayer uses either
depreciation is the federal tax rate times the federal depreciation
or the Grant for part or all of the property, they may not
basis. The federal depreciation basis amount is the federal ITC
the Sec. 179 deduction for that part. The ITC or
basis, minus one-half the federal ITC amount (85% of the ITC
basis in the case of the current 30% ITC). For example, a Grant benefit, combined with MACRS depreciation are much
system costing $100K (ignoring any rebate for this example) more valuable than the Sec. 179 Deduction. In previous
would have a tax credit basis was $100K, and thus receive a situations (typically Commercial Economics classes), the author
$30K federal ITC (30%). Its federal depreciation basis would be
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 8 of 19
incorrectly suggested that Sec. 179 may also be available and at either the federal or state level, or both. Contrary to what was
might be able to be used with caution in certain situations.
written in previous versions of this article, there appear to be
significant grounds for individual (residential) taxpayers in
Rebates, Buy-downs, and Grants provide direct cash
some states to claim the rebate payment is non-taxable. Sec.
incentives to purchasers or their installers. These types of
136(a) of the IRC specifies that ‘direct or indirect utility
incentives are usually proportional to system size based on the
payments (i.e. from ratepayer funds) for energy conservation
rated wattage of the system, and are often limited to a
measures may be excluded from taxable income, where energy
percentage of total system cost and/or a fixed total dollar
conservation measures reduce the consumption of energy in a
amount. The rating systems vary by program, using the CEC,
dwelling.’ PV systems are energy conservation measures
PTC, or STC rating systems. In cases where a rebate is received,
(source: Wiser & Bolinger, Lawrence Berkeley Lab - LBL).
the customer can usually also enjoy savings via Net Metering on
Therefore it seems clear that utility direct paid rebates for PV to
her electric bill.
homeowners are non-taxable, such as in most of California,
Rebate programs are usually run and/or overseen by either a Colorado, New Jersey, and some other states.
state agency or a utility, often in compliance with a state law or
Other states, such as Florida, or cities such as San Francisco,
voter initiative.
pay rebates from general funds collected from taxpayers (not
Rebate payments are paid and received up front, and are not ratepayers). In these cases, Sec. 136 would probably not apply,
based on actual system performance. At best, they can be and the rebate payments would probably be taxable.
adjusted to account for expected performance. Expected
Less clear are rebates that are funded from ratepayer sources,
performance rebates may be adjusted by the expected relative
but paid by non-utility administrators, such as the California
system performance compared to an optimal or ideal system,
Energy Commission or the Energy Trust of Oregon. In a private
taking into account reductions in performance due to shading,
letter ruling an IRS administrative law judge found that the
tilt, orientation, and/or geographic location (to account for
Energy Trust of Oregon rebate was indeed tax exempt, but the
variations in sunlight levels due to location).
reader is cautioned to note that private letter rulings are not
Performance Based Incentives (or PBIs) provide incentive precedents and do not bind a different IRS administrative law
payments based on actual delivered system performance, and so judge to the same finding, nor do they apply to any other
automatically account for shading, tilt, orientation, and taxpayer than the one named in the ruling. It is not expected that
geographic location, as well as the other factors mentioned in the IRS will make a public ruling, so it’s likely to remain a grey
Fig. 2. The PBI amount is usually a set value in cents per kWh area for now.
(commonly 10-40¢/kWh) paid for each kWh produced,
Some state agencies, such as the California Energy
measured, and reported by the system for a set number of years
Commission have issued 1099 tax forms to rebate recipients.
(commonly 1, 3, 5, 10, 15, or 20 years) from the date the system
Simply receiving a 1099 tax form may not require payment of
is first placed in service. Usually PBIs are received in addition
tax on the amount. Such a 1099 may be advisory and a way for
to the customer savings via Net Metering of her electric bill.
the issuer to cover itself and ensure compliance with IRS rules,
Since PBI payments are paid over time the customer must even if Sec. 136 applies. On the other hand, not receiving a
wait for payment, and bear the risk that something will interfere 1099 doesn’t excuse the taxpayer from tax liability if due (i.e. if
with system performance. Because of the time value of money, Sec. 136 doesn’t apply). Please check with a qualified tax
and this additional risk, the total of the PBI payments must be professional when making these important decisions.
more than a rebate would have been in order to provide an equal
It was mistakenly suggested in previous writings of this article
time- and risk-adjusted incentive. This increases the cash cost of
that if the installer accepted the rebate on the customer’s behalf,
the incentive program to the incentive provider, but increases
it might eliminate the customer’s rebate tax liability. The author
customer attention to her system (in order to receive payment),
has been informed that this is not true, and that tax is due when
so per kWh delivered, PBIs may be more cost effective to the
value is received (including non-monetary value in the form of
incentive providing agency and funding parties than rebate-type
part of a PV system), unless specifically exempted (as may be
the case if Sec. 136 applies) (source: Wiser, LBL).
There is a major marketing benefit to PBI programs as well.
Despite this, there are other reasons why it is still better for
Unlike rebates, which are received one-time up-front when the
the customer to have the installer accept the rebate as part of
customer is already excited about her system, PBIs are received
payment for the project: 1. Less cash is required (by the
at regular intervals (usually every 1, 3, or 6 months) providing
customer) during the project, and 2. The customer has greater
the customer a reminder of her solar system and a reason to
leverage over the installer should the installer do a substandard
smile (or call for warranty service). A smart installer or
job (if either the customer or inspector doesn’t sign off on the
salesperson will time her follow-up communications to the
job, the rebate may be withheld). This is less attractive for the
customer to ensure the customer got her PBI check, and also to
installer because it hurts her cash flow, but might provide her a
make sure she is remembered for referrals. This residual benefit
sales advantage over a competitor. It doesn’t impact the
can last for years, generating many new sales.
installer’s tax return because the rebate is part of the job’s
Taxability of Rebates and PBIs: Depending on the structure revenue whether received directly or thru the customer, and all
of the program, and the type of taxpayer (residential or job revenue minus expenses is already subject to taxation.
commercial), rebates, PBIs, and grants may be taxable income
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 9 of 19
A sales and cash flow optimization strategy is to have the
customer pay full price and receive the incentive directly unless
she requests otherwise, optimizing installer cash flow on as
many jobs as possible, while providing the sales flexibility to
match the competition upon customer request.
Non-profits, governments and schools don’t pay income taxes,
so incentives received are generally not taxable.
Business/commercial solar system rebates are likely subject to
taxation, as Sec. 136 applies only to systems installed on the
dwellings of individual taxpayers. There is no known exemption
for business taxpayers, but it turns out that, in general, a
business wouldn’t want to use it – more on this later.
No Double Benefit: Sec. 136(b) states that if the rebate is tax
exempt, then the taxpayer will need to reduce the tax credit
basis for any related ITC, and will then get less tax credit. On
the other hand, if she does pay tax on the rebate, then she does
not deduct the rebate amount when she calculates the tax credit
basis (and therefore get relatively more tax credit benefit).
For residential taxpayers, the above interaction and the
importance that Sec. 136 apply to any rebate she has received
was much more significant before 2009, because the Federal
ITC was capped at $2,000. Now that the Federal ITC is an
uncapped full 30%, the impact is usually far less, and depends
on the marginal tax rate of the customer. If the taxpayer’s
bracket is 30%, then it makes no difference to the customer
whether the rebate is federally taxable or not, since she will gain
the same amount either in no tax on the rebate or in higher ITC
value. See the 4 cases illustrated in Fig. 9. If her tax bracket
Case 1: Non-Taxable Rebate
$100K System Cost
-$30K Rebate
-$21K Tax Credit Value (30% of $70K after rebate cost)
=$49K Net Cost
Case 2: Taxable Rebate at 30% Federal Tax Bracket
$100K System Cost
-$30K Rebate
+9K Rebate Tax ($30K * 30% Fed Tax)
-$30K Tax Credit Value (30% of $100K)
=$49K Net Cost
Case 3: Taxable Rebate at 20% Federal Tax Bracket
$100K System Cost
-$30K Rebate
+$6K Rebate Tax ($30K * 20% Fed Tax)
-$30K Tax Credit Value (30% of $100K)
=$46K Net Cost
Case 4: Taxable Rebate at 40% Federal Tax Bracket
$100K System Cost
-$30K Rebate
+$12K Rebate Tax ($30K * 40% Fed Tax)
-$30K Tax Credit Value (30% of $100K)
=$52K Net Cost
Fig. 9. Residential examples of rebate/ITC interactions.
Economics of Solar Electric Systems
were lower than 30%, then she would prefer the rebate be
taxable (if she had a choice or if she and her tax advisor feel
there is enough uncertainty in the applicability of Sec. 136)
because she would then pay less in rebate tax than she would
gain in getting the full ITC. On the other hand, a taxpayer in a
tax bracket over 30% would prefer the rebate to be non-taxable.
Each 1% of difference between the customer’s tax bracket and
30% makes 1% difference in the net value of the rebate to them.
For most taxpayers, this isn’t going to be very much in absolute
dollars either way compared to the total cost of a PV system, as
is evidenced by the examples.
For business taxpayers, Sec. 136 does not apply, and there is
no other known section of the IRC that might exempt the rebate
from federal taxation. This turns out to be convenient, because
while paying tax on the rebate is a cost, not only does it allow a
larger ITC to be enjoyed, but since the depreciation basis is
proportional to the ITC basis, it allows more depreciation to be
enjoyed as well. The larger amounts of both ITC and
depreciation far more than compensate for the tax on the rebate.
See Fig. 10 for a comparison of the two results.
Even when the rebate is taxed, it is usually only taxed by the
federal government. State governments that have enacted
rebates in support of solar generally don’t tax their own
incentives, however, tax laws vary by state, so check with your
state taxing authority.
PBI Taxation: Since PBIs are paid over time and the total
value that will be received is unknowable at the time the federal
ITC needs to be calculated, the interaction between them and
the ITC is less straightforward. For businesses, PBIs are almost
certainly taxable.
For residential customers however, one might be able to argue
that Sec. 136 should also make PBIs paid from ratepayer funds
for PV systems non-taxable, but this would create the difficulty
of calculating how much to reduce the ITC basis by, since it
would require the impossible task of calculating the present
value of the unknowable stream of PBI payments that will be
received as and if the PV system produces electricity. Even if
Case 1: Non-Taxed Rebate
$150K System Cost
-$50K Rebate
-$30K Tax Credit Value (30% of $100K)
-$35K Depreciation Value (85K * 41%)
=$35K Net Cost
Case 2: Taxed Rebate
$150K System Cost
-$50K Rebate
+17.5K Rebate Tax ($50K * 35% Fed Tax)
-$45K Tax Credit Value (30% of $150K)
-$52K Depreciation Value (127.5K * 41%)
=$20.5K Net Cost
41% = combined net federal & state tax rate (35% Federal
& 8.84% CA State)
Fig. 10. Commercial examples of rebate/ITC interactions.
! 2009, Andy Black. All rights reserved.
July 2009 - 10 of 19
you could agree with the IRS on a discount rate for PBI
industry (which was over 40% of the world solar market in
payments to be received in the future, no one can know how
2008) is effectively completely shut down as of 2009.
many kWh will actually be produced until it has happened,
! Solar benefits some customers much more than others
which is usually well after the ITC needs to be calculated and
(customers high in the rate tiers, those with avoidable
submitted with a tax return. Guidance from Mark Bolinger at
demand charges, and/or those who can benefit from Time-ofLBL (not a qualified tax professional, but someone who has
Use rates), each of which is a hidden artifact of Net Metering.
studied this in greater depth than the author, see “Further
Losing the Net Metering benefit levels the playing field, which
Reading” at end for more info) is to assume PBIs are taxable for
is democratic, but removes a lot of existing sales
residential customers as well as businesses, to be on the safe
opportunities for those who know where to look, and may
completely eliminate the market if the FIT is set too low.
Of course, the ideal and much more valuable result would be
! FITs have no ‘End Game’ unless the customer can switch
for the IRS to accept an argument that the PBIs are non-taxable
back to Net Metering (without other incentive) at her choice.
to homeowners due to Sec. 136, but also not challenge the
This means that if only FITs are available (without Net
higher claimed amount of the ITC since there was no rebate
Metering), the FIT payment can never be reduced to 0¢/kWh
received up front to reduce it. The author is not advocating this
because the customer will always need some payment to make
potentially risky strategy, and a competent qualified tax
it worth going solar (since she won’t be saving on her electric
professional should be consulted before considering this
bill). This makes the solar industry perpetually dependent on
maneuver. However, it is fairly certain that even if the IRS
the existence of FITs and their future renewal. If the customer
would to approve such an approach, they aren’t likely to chase
can always choose between a FIT or Net Metering, then this
the taxpayer around attempting to provide a refund unless she
problem goes away, because once the Net Metering benefit
files her taxes in this way.
becomes greater than the FIT payment, customers will chose
Feed-In Tariffs (FITs) are very similar to PBIs in that they
Net Metering.
provide a payment to the customer for each kWh delivered to
Tax Abatements are offered by some taxing jurisdictions in
the grid. The difference being that usually a Feed-In Tariff is the
the form of Sales Tax or Property Tax exemptions. Many states
only benefit received from owning the solar system – there is no
exempt solar systems from being included in the assessed value
Net Metering benefit, so the customer continues to pay her
of a home, so installing a solar system doesn’t cause the
regular electric bill. In order to make Feed-In Tariffs attractive,
homeowner’s property taxes to increase. For example, solar
the payment per kWh needs to be higher than a comparable PBI
systems installed in California between January 1, 1999 and
because of the lost Net Metering. Common feed-in tariff terms
January 1, 2017, are exempt from triggering Property Tax
are 10, 15, and 20 years.
reassessments (California Taxation Code, Sec. 73). Sales Tax
Gainesville, Florida and Ontario, Canada have implemented exemptions help reduce the up-front cost of the solar system.
feed-in tariffs. Gainesville’s tariff of 32¢/kWh for 20 years was
Solar Renewable Energy Credits/Certificates (often known
very popular and used up the first allocation of money quickly.
as SRECs, S-RECs, sRECs, RECs, or Green Tags) are a new
Ontario’s first attempt at CAD 42¢/kWh for 20 years was not
and growing way to value the greenness of the energy from a
high enough to be strongly popular, so in May 2009 revised
solar energy system. SRECs represent the bundle of legal rights
incentives of CAD 44-80¢/kWh depending on system size and
to the green part of each kWh produced by a solar system. This
mounting type were proposed (not yet finalized).
green part can be sold for a value, which generates additional
Feed-In Tariff Policy Discussion: Feed-In Tariffs (FITs) are revenue for the seller.
very simple incentives for solar, and are very popular in
SREC value is created in two common ways. The first is the
Germany and Spain because they have very quickly created
“voluntary” market, where individuals buy SRECs as a way of
large markets in each of those countries. There are a number of
“greening” their world by paying extra to someone else to
risks associated with FITs however:
install some new solar capacity, often because they can’t or
! The incentive is 100% visible, and makes solar look chose not to make the large, long-term investment themselves.
expensive, making it an easy target for solar detractors, This is common for apartment dwellers and business renting the
whereas Net Metering ascribes value to the publicly received space they occupy. Business such as Kinko’s, Wal-Mart, Whole
benefit of the electricity generated and delivered when the Foods, and White Wave (the makers of Silk soy milk) have
utility needs it. The cost to the ratepayer is equal, so it’s a bought SRECs to offset some of the emissions from their
matter of perceptions and visibility, however Net Metering operations.
better reflects the public benefits.
Voluntary SREC purchases do actually “green” the grid if
! The entire incentive for solar becomes vulnerable to political they result in net new solar (or wind or other renewable
changes – FITs can come and go with a change of elected or generation depending on the type of REC or Green Tag
appointed officials, creating potentially large changes in purchased) that wouldn’t have been installed if the SRECs
fortunes of the solar industry. Germany and Spain both found weren’t purchased for the agreed price. For example, a solar
their incentives aggressively cut back in the summer of 2008 ‘farmer’ wants to build a solar farm on some open land or on
when they started to be viewed as too expensive. Spain’s solar the roof she has access too. If the value of the electricity she
will be getting from the utility (via sales or Net Metering),
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 11 of 19
combined with the incentives discussed (excluding SRECs)
above isn’t enough to provide the rate of return the ‘solar
farmer’ is looking for, the investment won’t happen. If the
‘farmer’ can sell the SRECs to a buyer for enough extra value
(1-5¢/kWh is common in ‘voluntary’ locations), the total
investment may become attractive, and the ‘farmer’ will invest
the money and effort to make it happen, and Voila! – net new
generation happened in part because of the SREC value.
assurance of long-term agreements, the customers (homes and
businesses) installing solar don’t need to be paid as much for
their SRECs because they know the value is locked, which also
saves the utilities in the short term, and probably also in the
long term, because the risk-premium is eliminated.
Maryland has a 2009 ACP of 40¢/kWh which will decline
over time (see the DSIRE Database for current details).
Pennsylvania and other states will likely also have similar
The second common (and very important) way SREC value is arrangements. There is no guarantee that actual value will be
created is thru the regulatory “compliance” market where state anywhere near the ACP unless the ultimate buyer (the utility)
law or voter initiative has required that a certain percentage of agrees to it.
electricity in a given geographic or territorial area must come
Colorado has an RPS as well, but rather than paying for each
from solar sources. Often, the percentage is set to rise over time.
SREC as it is produced, the two main utilities, Xcel and Black
Fourteen states have Renewable Portfolio Standards (RPS) with
Hills Energy (formerly Aquila) buy 20 years worth of the SREC
such a requirement. In these states, the utilities must either build
output from smaller systems for $1.50/W STC of installed
and own solar installations (if allowed), or buy SRECs from
capacity (looking more like a rebate) in addition to the regular
producer/owners. Usually, there is an Alternate Compliance
$2/W rebate. This equates to an approximate SREC value of 5Payment (ACP) that sets a maximum on the value of the SREC
7¢/kWh depending on sunlight levels and system performance.
value, whereby, if the utility isn’t able to buy SRECs for less
than the ACP, they can pay the ACP as a penalty for failure to
California and several other states have Renewable Portfolio
do so.
Standards too, but these RPSs don’t have requirements that any
of the energy be sourced from solar, so it is likely that most will
New Jersey is the best known of the states where its solar
come from wind and other sources, which are currently less
program is supported mostly by SREC value. Currently, the
expensive. That means that the SREC market in these states is
ACP in New Jersey is the equivalent of 71.1¢/kWh. The market
voluntary (including some speculators buying or trading SRECs
in which the NJ utilities can buy SRECs is set up as a bidon the bet that they will become more valuable if/as the
auction market, so supply and demand rule the price of SRECs
government and industry take on global warming). Current
at any given moment, with the artificial cap of the ACP. As of
voluntary SREC values are estimated to be in the range of 1June 2009, the auction market in NJ had set the price of SRECs
5¢/kWh, which is not insignificant compared to Net Metered
at 60-65¢/kWh. This value may continue for the short-, mid- or
electricity value that is sometimes as low as 6-20¢/kWh.
long-term, but there is no assurance of it. The price could also
collapse if an oversupply of SRECs becomes available,
The only way an SREC has any real value though, is to ensure
depending on the rate of installation of solar systems compared that the bundle of legal rights to the greenness it represents has
to the increasing requirements of the NJ RPS.
only been sold once to its ultimate consumer for “retirement”,
the same way as a publicly traded company can only sell a fixed
SREC Policy Discussion: The New Jersey style incentive
number of shares of its stock. Within a state RPS compliance
using SRECs is one of the author’s favorites, because it allows
market, this is usually done by an administrator who tracks all
market mechanisms to automatically readjust the incentive
the production, sales, and retirements. In voluntary markets,
(SREC) level to changes in market conditions. For example, the
SRECs should be certified by a certifier such as Green-e (a
uncapping of the federal ITC provided a lot more federal
service of the Center for Resource Solutions) http://www.greenincentive for solar, and so would require less state support and, which is the nation's leading independent consumer
would allow the SREC level to decline, all things being equal.
protection program for the sale of renewable energy and
Similarly, the recent rapid decline in solar module prices has
greenhouse gas reductions in the retail market. Only then can
lowered end-customer costs, again requiring less support to be
the consumer be sure she is buying something of value.
required in the form of SRECs. The U.S. economy of 2009 is in
such bad shape that the above two have not actually manifested
One should take care to consider whether she really wants to
in substantially increased solar purchasing and supply of sell the SRECs her system generates. By selling them, she loses
SRECs yet, but the Rate of Return on a solar investment in NJ the right to claim she is using any of the clean green energy
has been increasing due to the two events. Eventually, the generated by the system. That right would belong to the new
return will get good enough, and the economy will get stable SREC owner. The system owner could claim she is a host for
enough, that individuals will start to buy systems and put new the generation, but not a user. The distinction is important in
SRECs on the market, creating more supply to satisfy an order to prevent double counting of the SRECs, which is
inelastic demand, causing SREC values to come down at least important to maintaining their value.
The missing element in the New Jersey program has been
long-term contracts whereby solar customers can get an
assurance of future SREC value. Without such an agreement, a
potentially oversupplied SREC auction market could cause the
traded price to plummet, so customers installing systems need
to insist on a risk-premium. This is starting to shift. With the
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 12 of 19
after-tax savings of $100. The example would then be
Independent tests of the financial viability of solar energy calculated as follows:
! Rate of Return for comparison to other interest rate based
$100 $100
PreTax =
= $100 * 2 = $200
1" TaxRate 1" 50% 1" .50 .50
! Payback in a reasonable time
! Total Lifecycle Payback
Meaning that $100 after-tax is equivalent to $200 pre-tax at a
! Net increase in property value compared to solar system cost
tax rate. To put it in context of a solar system: if a
! Positive cash flow when financing the project
customer were choosing between investing $15K in a solar
All of the analyses and analysis methods presented here apply system that would save them $100/month on her electric bill
only to residential scenarios. Different mechanisms, (tax-free), vs. $15K in a taxable investment, the taxable
assumptions, and accepted financial and accounting practices investment would need to earn them $200/month so that after
apply to commercial cases, which are not discussed here. For she paid taxes on the $200, she would have $100 left over to
example, commercial analyses must be done on an after-tax pay the electric bill, for the two choices to be considered
basis, which has important consequences relating to the loss of equivalent. In reality, combined federal and state tax rates are
the electric bill tax deduction a business otherwise would have currently lower than 50%, with an effective rate of 20-40% for
enjoyed, and commercial property resale valuation is done using most taxpayers. At these rates, $100 after-tax savings would be
Capitalization Rate, rather than the method discussed here. equal to $125-$165 pre-tax equivalent.
Future versions of this article may include this material, so
Once the value of the savings, maintenance costs and other
check back later please.
amounts are properly adjusted to their pre-tax values, they can
be inserted into a 25-year financial timeline (the warranted life
Compound Annual Rate of Return on an investment is of most solar electric/PV modules) representing the cash flows
another term for effective interest rate or yield, which is a way for each year, to calculate the Compound Annual Rate of
of comparing one investment to another. For example, a savings Return. This allows the accurate inclusion of all relevant cost
account might pay 0.5%-1% interest, and the long-term (80 and benefit components.
year) Dow Jones Industrial Average of the stock market,
The initial capital cost is the only amount that doesn’t get
assuming dividend reinvestment had earned 8.5% per year
(CAGR) to its height of 13,500 in 2008. At its level of 8,000 in adjusted. That amount is the net system up-front cost (total out
of pocket), and is unaffected by the taxation or lack thereof of
June 2009, the long-term CAGR of the Dow has been 7.5%.
future savings in the utility bill. Consider it the same as
The author chose 10% as the test point for solar, because that principal that is invested anywhere. The principal is not taxed
compares favorably to other long term investment average upon its departure or return.
returns from common, readily accessible, higher yielding
Tax savings and consequences, inverter replacement,
investments such as stocks and bonds and provides a slight
premium to compensate for solar’s lack of familiarity to much maintenance, and other significant financial events can be
included at their appropriate places on the timeline. Inflation,
of the public.
escalation, and module degradation are also easily included. For
To properly value the savings from a solar system, it should each year, the values can be summed, creating a 25-year
be noted that solar saves after-tax expense, while most other timeline of net expense or net savings by year. The Internal Rate
investments earn pre-tax income. In order to compare solar to of Return (IRR) function in most spreadsheets can then
other investments, all investments should be placed on the same calculate the IRR, which is the same as the Compound Annual
side of the tax equation. Since most investments are taxable (i.e. (interest) Rate of Return (CARR) for the investment.
stocks, savings interest, etc.), and because most people think
One should note that there is a significant and very important
about their investments on the pre-tax side, it is most
meaningful to convert solar savings to its taxable equivalent difference between Compound Annual Rate of Return and
average return or total return divided by the number of years an
value (i.e. PreTax value).
investment is held. Average return does not factor in
AfterTax dollars are worth more to a taxpayer than the same compounding of interest, and may make an investment look
number of PreTax dollars, because PreTax dollars are subject to more attractive than it really is. This article uses CARR for all
taxation. Therefore, an AfterTax dollar saved (with solar) is items under consideration (solar, stocks, savings, etc).
worth more than $1 on a PreTax basis, by an amount
The difference becomes more visible the longer the time
proportional to the taxation rate. To make this conversion from
AfterTax value to PreTax value, the following equation can be horizon. A brief example: Suppose an investment doubles every
year. Its CARR would be 100% because you get 100% increase
used (where TaxRate is the net total effective income tax rate):
each year on your investment. No matter how long you hold it,
its CARR is 100% because you need to compound for the
PreTax =
number of years it’s held. Alternatively, if you were to look at
(1" TaxRate)
the “average rate of return”, over 1 year, it would still be 100%.
However, if you held it 3 years, your investment would be
To illustrate this with an example, let’s assume a Tax Rate of
800% of the original, or a total return of 800%
50% (unrealistically high, but easy to illustrate with) and an
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 13 of 19
(100%>200%>400%>800%). The average annual return would
be 800%/3years-100% or 167%, which looks great, but isn’t
representative, because it isn’t factoring in the compounding.
This faulty method of analysis is highlighted here because
unfortunately there are several inaccurate (misleading) solar
analyses and sales presentations being given to the public that
use averaging, rather than compounding.
Please see Fig. 14 for example analyses from several states
and their Compound Annual Rates of Return. These cases are
for full service residential system installations, using typical
installed system costs on a simple composition shingle roof.
Utility & state specific assumptions for the examples are listed
in Fig 13. General variables and assumptions are:
! 28% federal tax bracket, corresponding state tax bracket
! Facing south, 22° pitch, simple composition shingle roof by
full service provider, no complications
! Slightly conservative real system performance, no shade
! Final Net Cost = total installed system costs - Rebate (if any)
- 2009 Fed 30% ITC + $500 Permit + $0 Utility Fee
! System maintenance cost is 0.25% of gross system cost per
year, adjusted for inflation
! 5.0% electric escalation (2.2% in CO)
! Module degradation 0.5% per year
! Module PTC/STC Ratio: 89.6%, Inverter Efficiency: 95.0%
! Inverter replacement costing $700/kW occurs in year 15
These analyses were performed using the OnGrid Tool,
available at Other tools are
listed in the Design and Analysis Tools section at the end.
Initial Cost paid
back in 8 years
Total Lifecycle
Savings is
several times
Initial Cost
Fig. 12. Simple Payback vs. Total Lifecycle Payback. Total
Lifecycle Savings over 25 years is several times the initial cost
represented by the area up until year 8. Year 15 shows
diminished savings due to inverter replacement.
residential long-term investment; it does not properly include
the tax savings and consequences, it does not account for
maintenance or inverter replacement expenses, and it makes it
difficult to compare to other investments such as stocks,
savings, etc. because of inflation and other factors.
Comparing the savings of a solar electric system over 25 years
of operation to its initial cost is a better way of looking at
payback, because it more fairly values the savings due to the
compounding effect of electric rate escalation. Because of this
effect, the savings in the later years is much greater than the
savings in the first few years. Typical systems give back 1.5 to 3
times their initial cost. See Fig. 14 for several examples and Fig.
12 for an illustration. One drawback to this analysis is it fails to
account for the time value of money. A dollar saved in the
future isn’t worth as much as a dollar saved today, so that a total
lifecycle payback isn’t worth quite as much as it might initially
appear. The better methods of comparing solar as an investment
are the Compound Annual Rate of Return, Increase in Property
Value, and Cash Flow.
What about calculating the payback? Payback is a simple but
crude tool for comparing investments. Solar is an inflationprotected investment but many others are not. This improves the
payback for solar (electric rates double every 15 years at 5%
escalation). To properly calculate the solar payback, it is
necessary to add in the rate escalation adjusted savings of each
successive year, less the reduction due to module degradation
and maintenance costs, until payback has been achieved.
Savings in the latter years are larger than savings in the first
years, so the payback is faster than simply dividing the cost by
Solar electric systems increase property value by decreasing
the savings. See Fig. 12 for an illustration.
utility operating costs. According to the Appraisal Journal
Payback analysis on an after-tax basis does not reflect the true (Nevin, Rick et al, “Evidence of Rational Market Valuations for
value of the saved utility expense, because after-tax savings are Home Energy Efficiency,” Oct 1998 (available at various
worth more on a pre-tax basis. However, trying to do payback locations
using the pre-tax value gives an unrealistically optimistic view
of when “payback” has occurred. The examples in Fig. 11 show es/apj1098.pdf), a home’s value is increased by $20,000 for
how long paybacks on other investments really are in every $1,000 reduction in annual operating costs from energy
comparison to solar, when taken on an after-tax basis.
There are numerous other flaws in using payback for a
Interest Earned or
Payback / Time-toInvestment
Net Electric Bill
Value the
Value the
Doubling including
First Year
Eighth Year
taxes & inflation
$300 (at 1% rate)
153 years
$2,400 (at 8% rate)
19.1 years
Solar – CA PG&E 5.5 kW
$2,321 (1st year)
10.4 years
Fig. 11. Investment Payback Comparisons: Solar savings grow due to escalation (4.5% net w/ degradation). Assumed 28%
federal & 9.3% state tax rates play a big role in the different outcomes. Stocks & savings are more liquid, but it’s clear why
Wall Street and banks don’t talk “Payback”.
Investment Type
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 14 of 19
AC kWh Production
per rated kW per
Installed Cost per
rated Watt
(~October 2008)
Staring/Ending Rate
Schedule, Peak %
1660 / STC kW
$8.25 STC
E-12 / ET-2, 50%
$2.40/W Rebate (net)
25% State Tax Credit
San Francisco
1630 / CEC kW
E1XB / E6XB, 35%
$1.55/W Rebate
3kW: $9.50 CEC
6kW: $9.25 CEC
9kW: $9.00 CEC
D-10-Basic /
TOU-D-1, 36%
DR-Coastal-Basic /
DR-SES, 28%
Los Angeles
1675 / CEC kW
$1.90/W Rebate
San Diego
1700 / CEC kW
CO - Xcel
1398 / STC kW
$8.25 STC
$3.50/W Rebate & SREC
1262 / PTC kW
$8.75 PTC
R / RT, 45%
$1.75/W Rebate
1345 / ST kW
$8.25 STC
$4/W Rebate
1460 / STC kW
$8.25 STC
35% State Tax Credit
1236 / STC kW
$8.25 STC
R / RL-2, 65%
$1.20/W Rebate (net),
SRECs: 10¢/5yrs, 5¢/10yrs
NC - Progress
1260 / STC kW
$8.25 STC
RES / R-TOUD, 60%
35% State Tax Credit
1140 / STC kW
$8.25 STC
RS / RT, 58%
NY - ConEd
New York City
1178 / STC kW
$8.25 STC
Rate I / Rate II TOU,
1217 / STC kW
$8.25 STC
RS / RTD R, 70%
$1.55/W Rebate
SRECs: 48¢/1yr, 30¢/12yrs,
10¢/12yrs; $1.55/W Rebate
$2.81/W Rebate (net)
25% State Tax Credit
$2.25/W Rebate,
SRECs: 10¢/5yrs, 5¢/10yrs
Fig. 13. Utility specific residential assumptions. Module prices have dropped since October 2008, and selling prices are declining,
but still in a state of flux. For now, the analyses assume 10/2008 pricing.
Before Solar
Size & Net Cost
PV System
Size &
Final Net
Cost w/
& Rebate
5 kW STC
Results, Savings, and Benefits
Net Monthly Cash Flow
Lifecycle Years Pre-Tax Compared to 8% 30-yr
Equity /
Over First
25 Years
Ratio Payback Return
In First
In Fifth
First Year
3 kW CEC
6 kW CEC
9 kW CEC
3 kW CEC
9 kW CEC
3 kW CEC
CA - SDG&E $455
9 kW CEC
CO - Xcel
5 kW STC
5 kW PTC
5 kW STC
GA - GaPwr
5 kW STC
5 kW STC
5 kW STC
5 kW STC
5 kW STC
NY – ConEd
5 kW STC
5 kW STC
Fig. 14. Example residential cases with their net costs and financial benefits.
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 15 of 19
add more than 215% of their value upon resale (Alfano, Sal,
“2003 Cost vs. Value Report”, Remodeling Online – downloaded March 5, 2004). Other
types of remodels like kitchens and bathrooms had similar
results related to geography. So it makes sense that in certain
geographies where the sun shines brightly and the electric rates
are high, solar would return more than its installed cost, while in
other states with less sun and lower rates, the return might be
much lower, with a national average comparable to other types
of remodel. Fig. 16 lists projected resale value of various solar
systems, compared with nationwide averages for some other
home improvements.
The increase in property value is currently theoretical. A very
high fraction of the grid-tied solar electric systems in California
were installed since the state’s Power Crisis and the
Fig. 15. Resale value increases over time because savings get
Deregulation fiasco in 2001. Most of these homes have not been
larger each year. Total remaining lifetime savings in the
sold and there are no broad studies of comparable resale values
system declines annually, putting a limit on the increase in
available. However, some evidence is beginning to emerge that
resale value after year 11.
there are significant jumps in resale value being realized by
The rationale is that the money from the reduction in some solar home sellers.
operating costs can be spent on a larger mortgage with no net
It is also interesting to note that PV systems will appreciate
change in monthly cost of ownership. Nevin states that average over time, rather than depreciate as they age. The appreciation
historic mortgage costs have an after-tax effective interest rate comes from the increasing annual savings the system will yield
of about 5%. If $1,000 of reduced operating costs is put towards as electric rates and bill savings rise. All the calculations in this
debt service at 5%, it can support an additional $20,000 of debt. article assume electric rate escalation will be 5%. If so, the PV
To the borrower, total monthly cost of home ownership is system will save 5% more value each successive year, and thus
identical. Instead of paying the utility, the homeowner (or future gain from the 20:1 multiplier effect. The resale value will then
homeowner) pays the bank, but her total cost doesn’t change. increase 5% per year compounded, less 0.5% module
Since the Nevin article is from 1998, is it dated? No more than degradation.
2+2=4 is dated - the rationale is mathematical, not based on
This cannot continue forever, as the increase in resale value
market whims, so it is timeless.
runs into the second limit, which relates to the remaining life
Please see the column labeled “Appraisal Equity Increase” in left in the system. For these analyses, the system is assumed to
Fig. 14 for examples of the increase in home value. In some be worthless at the end of 25 years. This is probably very
cases, a solar system can increase home value by more than its conservative, since the panels are warranted to be working at
cost to install. This effectively reduces the payback period to 0 least 80% of their new performance. So if the system is
years if the owner chose or needed to sell the property worthless at the end of 25 years, the only value the system has
immediately. It could even lead to a profit on resale.
as it nears that time, are the remaining savings it can generate
There are two limits to the increase in resale value over before the end of the 25 year. Fig. 15 shows both the
system net installed cost. First, why should a homeowner pay in increasing value due to increasing annual savings and the
total more for a home with a solar system, when she could buy a remaining value limitation that takes over at approximately year
non-solar home, and solarize it for less money? Yet this 11. If the system does have additional resale value, so much the
happens with other remodels. Decks, on average across the better.
nation, return 104% of their cost upon resale. However, in
Still, the skeptical homebuyer might question the above
certain markets like St. Louis, San Francisco, and Boston, decks assertions in light of the lack of hard evidence. Perhaps the best
Home Improvement
Amount /
Net System
CA PG&E Solar 3 kW
CA PG&E Solar 6 kW
CA PG&E Solar 9 kW
Deck Addition
Bathroom Remodel
Window Replacement
Kitchen Remodel
Fig. 16. Resale value comparison of various home
Economics of Solar Electric Systems
evidence to present would be a stack of old bills showing usage
and cost before solar, and a stack of new bills showing a
substantial savings. The question might be posed, “What are a
continuous, if not growing, stream of these savings worth to the
prospective buyer?” That sort of evidence can’t easily be
ignored. Of course, other factors will weigh heavily in the
value. How attractive is the home? A tidy, attractive installation
should add all of the value shown above, but like a spa, some
prospective buyers may not care or value it, while others may
love it.
! 2009, Andy Black. All rights reserved.
July 2009 - 16 of 19
Utility Bill w/o
Solar at 5%
8% Loan (net cost), New
Smaller Bill, & Maintenance
Fig. 18. Accumulated net savings of solar system financed over
20 years, including all costs, thus showing pure cash profit
accumulated over time with no additional expense.
Net Annual
has 2 parts: principal and interest. As the balance is paid down,
the interest portion of each successive payment is reduced, so
the tax deduction benefit is also reduced. In after-tax terms, the
loan is least expensive in the first year when the borrower is
enjoying the maximum tax deduction for interest paid.
The difference between the two lines in the top of Fig. 17 is
the amount the scenario is cash-positive (or cash-negative) for
the customer, and is reflected in the lower graphic, which shows
Fig. 17. Effect of a solar system financed at a fixed 8% interest
“Net Annual Savings” by having purchased a solar system with
rate over 20 years showing a cash-positive result from the
a loan (put no money down). In this case, the savings are
first day of ownership, including maintenance costs and the
substantial even before the loan is paid off in the 20th year, and
inverter replacement at year 15.
gets even better after that. The Net Annual Savings can be
accumulated as shown in Fig. 18 to show how much extra cash
a purchaser will have in her pocket before the inverter needs to
Financing a solar system makes the purchase achievable to be replaced in year 15, or before the loan is paid off in year 20,
more consumers. If the situation is right, the savings on the or before the equipment is out of warranty in year 25.
electric bill can more than compensate for the cost of the loan
The uncapping of the residential federal ITC has made it more
and maintenance, making it a cash-positive maneuver. That is,
compared to the occupant’s current cost of energy (her current difficult to figure out how much a customer should borrow. The
electric bill), going solar but paying for it entirely with a loan problem is that the ITC is a significant incentive, but it isn’t
(no money down) can actually be less expensive on a monthly received until the customer files her taxes, which can be a year
or more after the system needs to be paid for.
Electric rates and electric bills are subject to electric rate
escalation, as can be seen in the top graphic in Fig. 17, where
the cost of energy increases steadily over the years, doubling
approximately every 15 years. While interest rates might vary
depending on the loan type, loans are not subject to inflation or
rate escalation, so the loan payments do not increase
continuously. This means that the difference between what the
electric bill will become and what the loan & maintenance costs
will become continues to move in the customer’s favor. Even if
a customer didn’t start out cash-positive in the first year, she
may become cash positive after a few years.
In what one might call the “Optimistic Loan” scenario, the
customer would borrow the net cost after all incentives
(including the ITC) have been received. This would produce the
lowest loan payments, and have the best chance of being cashpositive from the start, making the salesperson happy. However,
the customer would need to have the cash to cover the ITC
amount or get a bridge loan until the ITC is received because of
the optimistically low loan & payments.
In an “Inefficient Loan” scenario, the customer would borrow
the net cost after all other incentives, except the ITC. This will
allow them to acquire the system with no money down.
However it will also result in a lot of cash on hand once the ITC
is received, which she is paying interest on, which is expensive
and not very efficient. It is also less likely to be cash-positive,
which will be a disadvantage for the salesperson.
In the top graphic of Fig. 17, the lower line labeled “8% Loan
(net cost), New Smaller Bill, & Maintenance” represents all the
new costs compared to the old Utility Bill cost. While the loan
rate is fixed at 8% and the monthly loan payments are steady,
there are 3 components to this new set of costs that do increase
The solution is what OnGrid Solar calls “Smart Financing”
over time: 1. The new maintenance cost will rise with inflation. where the customer uses a “line of credit” financing source that
2. The new small electric bill will rise with electric rate she can borrow from and repay without pre-payment penalty.
escalation. 3. In fixed amortization loans, each loan payment Assuming the ITC will be received in a year, and that she can
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 17 of 19
apply it to the principal of the loan at that time, one can
calculate the necessary loan payment that allows them to pay off
the loan in the desired number of years including interest. The
calculation is complex, and is not a standard function in most
spreadsheets, but can be done. The resulting loan payment will
be somewhere between the Inefficient Loan and the Optimistic
Loan, typically tending to be pretty close to, but slightly more
expensive than the Optimistic Loan.
Results of Smart Financing can be seen in Fig. 17. A subtle
feature of it is the slight dip in savings in the 2nd year. In the 1st
year the loan principal is very high because it includes the ITC
amount causing the interest cost to be quite high. This allows
for a large 1st year tax deduction benefit, even though the loan
payments are fixed and steady. Once the ITC is received and
applied to reduce the principal, the interest is reduced, so the tax
deduction shrinks, effectively raising the cost of the loan
compared to the fixed loan payments.
Refer to Fig. 14 for several examples showing the initial and
5th year monthly cash flow assuming 100% Smart Financing of
a solar system using a 30-year loan. Because of the 2nd year dip,
the 5th year monthly cash flow isn’t always better than the 1st
year’s, but is a basis for continuous improvements in cash flow
going forward. Note, we use the 5th year because most
depreciation (in commercial systems) and PBI benefits (both of
which are applied to loan principal in the same way as the ITC)
have been received and included by then.
partnership with cities, whereby a citizen property owner can
receive a loan for a solar system and have it collateralized and
paid back on her property tax bill. The program was pioneered
in Berkeley, California, and is now available in several cities
thanks to AB811, the “Community Financing” bill.
The loans are obligations to the city, the interest is tax
deductible, and the property tax bill shows the itemization of the
loan amount, the principal and interest. The interest rate is set
by the city and their partner bank and is generally at market
rates. However, even if the financing was at what might be
considered a subsidized level, because of the ARRA of 2009,
there is no longer any negative interaction with the ITC (there
used to be a tax rule that allowed one but not both of an ITC or
subsidized energy financing to be enjoyed). The loans are
generally transferable to a future buyer of the property if she is
willing to agree to assume the loan payments.
These loans pose little risk to the city and their funding
partner, because property taxes are considered to be in “1st
position” to get paid in cased of a foreclosure. This has caused a
controversy in the banking community because this now places
more risk on the holder of the 1st mortgage (who is in 2nd
position), and the lawsuits have started. The mortgagees insist
these loans be in at least 3rd position to protect their mortgages.
Depending on how they are structured, that may work for the
cities. Stay tuned, it’s developing as this is written.
There are also two commercial financing products being
applied to residential situations: Power Purchase Agreements
(PPAs) and leases. PPAs are the agreement for one party to sell
power to another at agreed upon terms. The sale is for kWh of
energy only. The leases for solar are rentals, where a customer
rents (leases) a solar system from another party. In both
products, the parties owning the systems have large investors
who have money to finance systems and who can use both the
Unsecured financing can include credit cards or other types of
ITC and depreciation.
unsecured loans. These are generally a terrible idea for any kind
of long term financing because they usually have high interest
In the typical PPA scenario, the site occupant agrees to a PPA
rates and the interest is not tax deductible. It may be reasonable for electricity kWh at a certain price and in exchange allows a
to consider them to temporarily finance the rebate or tax credit solar system to be placed on her roof. In residential applications
until it is received, however, it requires discipline to ensure the of a PPA, the homeowner usually pays a deposit of anywhere
loan is paid off as soon as the incentive is received.
from $2,000 to 25% to 50% of the cost of the system in addition
to the price she will pay for the electricity. Naturally, the more
Home equity sources of funding can include 1 mortgage
she puts down as a deposit, the lower the price of the electricity.
refinances, 2 mortgages, Home Equity Loans, and Home
The contract lengths are typically 15-20 years, and there may be
Equity Lines of Credit (HELOCs). In general, home equity
a buyout cost at the end if the homeowner wishes to purchase it
borrowing is tax deductible, has the best unsubsidized interest
at that time, or she may have to pay a removal fee if she doesn’t.
rates, and has the longest repayment terms, all of which allow
The price of electricity may be fixed by the agreement, or it
for lowest monthly costs. However, the decline in real estate
may have an escalator, causing it to get more expensive over
values have hurt Loan-to-Value (LTV) ratios for most
time. There is usually a guaranteed minimum performance, but
homeowners, and the tight credit market in 2009 have put strict
the customer must purchase any extra electricity, whether she
limits on LTV ratios, credit scores, and income requirements,
wants it or not.
making use of home equity difficult. Only the Line of Credit is
likely to work with Smart Financing. Other loans tend to be less
A typical residential solar lease is similar, in that there is often
flexible on borrowing and repayment term. Attractive FHA a deposit paid and a long-term agreement to rent a system for
Energy Efficient Mortgages (EEMs) may be available from the placement on the customer’s roof. The monthly rent may
U.S. Dept of Housing and Urban Development (HUD) at: include an escalator, increasing costs over time, and may
include a buyout clause and termination costs. The buyout
clause must not allow the system to be purchased for less than
A new idea and source of funds are local loan programs called
Fair Market Value (FMV) at the end of the term, and that the
“Community Financing” developed by funding sources in
FMV must be determined at the end of the term, otherwise the
Sources of financing funds can include:
! Unsecured
! Home equity
! Community Financing
! Power Purchase Agreements (PPAs)
! Leases
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 18 of 19
lease will fail to satisfy IRS tax rules. The system usually comes
with a performance guarantee, and the homeowner enjoys any
extra production at no extra charge.
o Property Tax Assessments as a Finance Vehicle for
Residential PV Installations: …
o Exploring the Economic Value of EPAct 2005's PV Tax
Things a customer should watch out for regarding leases &
! SEIA “Guide to Federal Tax Incentives for Solar Energy”
PPAs: 1. High escalators in the contracts and their compounding, Solar Energy Industries Association
nature. These vehicles can be good hedges against future rate
! Utility Tariff and Rate Tables (see desired utility’s website) –
inflation, but a customer should be cautious about overpaying
great for insomnia
for that hedge. Rates may not rise fast in the future for any
number of reasons, and are certainly not likely to rise much DESIGN & ANALYSIS TOOLS:
faster than 6% per year over the long term. Currently, state or ! OnGrid Tool, which incorporates all of the elements of this
federal government does not regulate these products, so there is
paper, plus up-to-date rates and incentives, to allow the user
a lot of risk of customers agreeing to very expensive terms over
to design and analyze PV systems at a high level. It also
the long term. 2. Large deposits without performance guarantees
and without clarity in the contract on what happens to the
system in the event of the provider’s bankruptcy. 3. Large ! Clean Power Estimator:
buyout charges or removal costs at the end of the term.
! PVWatts:
Leases and PPAs with $0 deposits are easy to understand and
! PVSyst:
sell if the monthly costs or $/kWh are less than the customer’s
! RETscreen:
current costs. Otherwise the customer must figure out how soon
! PV Design Pro:
the deposit amount will be recovered.
! QuickQuotes:
Leases and PPAs can be attractive to customers who have no ! CPF Tools:
other way of financing a system, or who can’t use the ITC. But
if she has her own cash, or can get her own financing, she can
Thank you to the following that have provided invaluable
usually do better and keep more of the benefits for herself,
insights knowledge, corrections, and review:
rather than sharing them with the financing party and the
Michael Bishop, OnGrid Solar
provider. Customer shouldn’t be taken in by claims that these
Chad Blanchard
products are a lot less expensive because of the depreciation –
Mark Bolinger, Lawrence Berkeley Laboratory (LBL)
effectively the depreciation offsets the taxability of the revenue
Keith Martin & John Marciano, Chadbourne & Parke LLP
received the provider. These deals are currently a goldmine to
Ryan Wiser, Lawrence Berkeley Laboratory (LBL)
developers and providers, but are just “ok” for the consumer,
and will be until more competition comes along.
!Copyright 2009, Andy Black. All rights reserved. This
information changes periodically. The author maintains an
It is important to compare the solar investment to other For
investments on an even basis. Rigorous treatment and critical
more info on solar payback, analysis tools, upcoming classes,
analyses from several angles including Compound Annual Rate
and other papers and articles, see
of Return, Cash Flow, and Resale Value need to be considered
Andy Black is a Solar Financial Analyst and CEO of OnGrid
to do a fair assessment.
Solar, creator of the OnGrid Tool, and educator on the
Solar will make economic sense for many, but only a hard
financial aspects of solar electric systems. He is a former
look at the numbers will tell. The reader is encouraged to check
NABCEP Certified PV Installer, is on the Advisory Board of the
it out. Run the numbers, get evaluations and proposals from at
NorCal Solar Association, and is a recent past board member of
least 3 solar providers, and take them to a CPA to check them
the American Solar Energy Society. He can be contacted at
out. That way the smile on your wallet can be as big as the
(408) 428-0808x1 or [email protected] for questions about the
smile on your face!
payback on solar.
! OnGrid Solar’s papers, publications, and presentation slides:
! “A Guide To Photovoltaic (PV) System Design And
Installation”, California Energy Commission
! Bolinger, Wiser, et al, LBL papers and presentations at:, particularly:
o Shaking Up the Residential PV Market: …
o The Impact of Retail Rate Structures on the Economics of
Commercial Photovoltaic Systems in California
And at:
Economics of Solar Electric Systems
! 2009, Andy Black. All rights reserved.
July 2009 - 19 of 19
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