In most of the markets my company is active in, solar is close enough to grid parity that it can no longer be considered “too expensive” or “not efficient”.  Colleague Aidan Foley has a great post that 50% of US markets are now solar-ready.

Now it’s about discovering what the off-taker’s investment threshold is, and how you compete for investment dollars.

Most of my corporate customers use discount rates of seven to nine percent—solar now meets that easily with the value put on RPS compliance using tradable RECs.  Investment solar gives you mid-teens returns if you are a corporate owner [not subject to passive loss restrictions].  Not a bad return on investment given the low risk of solar energy production. 

CREBs—Clean Renewable Energy Bonds—$2.2B of them were allocated as part of the American Recovery and Reinvestment Act of 2009—are a tool for schools and public agencies to fund solar electric and hot water systems on their buildings.  Called “new CREBs”, the borrower pays back only the bond principal, and the bondholder receives federal tax credits in lieu of interest payments.  All in costs are lower than issuing most tax-exempt muni bonds and lower than current power purchase agreement rates as well as continuing to pay for grid power.  Here is the way Santa Clara County compared the options.

Simply put, CREBs are a financing tool to put solar on public schools—a noble intention. 

California government agencies were allocated about $640M of these bonds—Palo Alto Unified School district allocated over $20M, Mt. Diablo USD allocated over $50M, San Diego USD allocated $74M for 111 projects, and LAUSD received over $120M for 90 projects.  These allocations are good for three years.

Problem is, the $1.2B 2005 allocation of “old CREBs” authorized under the Energy Policy Act of 2005 never got much traction—only $50M of them were issued.  A real missed opportunity.

Part of the problem is that CREBs are allocated on a smallest to largest basis, but you needed to aggregate about $10M of CREBs to have the costs of issuance be covered by the two percent cost cap allowed.  The other part of the problem is that public agencies have their credit rating re-examined every time they go back to the market—and risking your agency’s current rating for a small issuance of CREBs could be a bad career move these days.

The bonds yield about 6% pretax—and since they are paid in tax credits, borrows can use 70% of the payment to offset their federal tax liabilities.  To make the bonds attractive, bondholders have been asking for either discounts or interest payments in addition the federal tax credits—these have been averaging about 1 to 1.5% to make them equivalent to munis.  Repayment is established through a sinking fund, and the power savings can be redirected into this interest bearing sinking fund account.  Currently, the tax credit can be stripped by the issuer or holder and sold separately.

I don’t understand why California’s Investor Owned Utilities don’t make a market in these bonds—they have the tax appetite, they have a vested interest in seeing solar distributed generation more widely adopted, they would have first crack at buying the system SRECs to offset their RPS requirements, you have a market size of north of $500M—seventy to a hundred megawatts of solar created—and the halo effect of sponsoring solar on schools would be huge.  They could buy these bond in private placements, so a school district’s credit ratings would not be publicly bandied about.  They seem like the perfect buyer for the school’s new CREBs.

What don’t I get here?

PACE—Property Assessed Clean Energy Financing district—is going live in San Francisco on 1MAR.  Green Finance SF will provide $150M in bond capacity to help property owners finance making their real estate more energy efficient and increasing property value by lowering utility costs via onsite generation.  Click here for more information about how PACE works.

This is the perfect way to cover the upfront cost of energy efficiency and renewable energy, and has spread nationwide—seventeen states in the last 18 months have authorized similar programs.  Scientific American calls it A World Changing Idea.  Harvard Business Review identifies it as 2010’s Breakthrough Idea Number 5 [pdf here]. 

Cost of capital [aka assessment rate] hasn’t been set yet—but probably not too far off of Sonoma County’s Energy Independence Program’s [SCEIP]  seven percent [deductible as a property tax expense]  assessment rate with a 15 or 20 year term.  Sonoma allows you to borrow up to 50% of the assessed value of the property, and you also get the Treasury Cash Grant and California Solar Initiative incentives for solar if you are eligible. The assessment goes with the property, eliminating any due on sale clauses typical with current lease programs offered. Commercial property owners will need to get consent from their lenders—most banks are on-board with PACE, since the value of the asset increases by more than the cost of the improvements.

This program can pay for an entire Green Package--solar electric, solar hot water, sub-metering and demand response, real time monitoring, lighting retrofits, and HVAC retrofits.  These Green Package improvements are a great way to add value and distinguish your property in a very competitive real estate market.  And the payback time goes to zero—improvements with a roughly five year payback amortized on your tax bill over fifteen or twenty years.  Think about this for your next lease renewal—a tenant incentive that adds real value to your property.

Noted is the fact that 50% of Sonoma County’s investment to date has been for PV—a natural step for our climate.

The first step is getting a PG&E or equivalent energy audit and then reviewing your current baseline and real estate with us to discuss project feasibility.

Your property not located in San Francisco?  You are in luck if you are in Sonoma County [application here .pdf] —and programs are in development elsewhere in the Bay Area with deployment expected later this year.  CaliforniaFIRST, a program available from Renewable Funding, is recruiting pilot counties and cities.  Want to get a program launched in your community?  Start here.

UPDATE:  Go Live date postponed. “Money awarded from the ARRA funds through the State Energy Program (SEP) was provided recently, and there are legal considerations about the proper use of this money and how it affects program requirements that still need to be figured out before the program is ready to launch.  All of the information available on March 1 will be put up on the website at www.greenfinancesf.org and the program is now expected to roll-out on or before April 1.”

Maintaining your LEED AP credential is an idea whose time has come, and starting this year, you need to earn 30 CE hours every two years to maintain your credential.

My Investment Solar course, taught at UC Berkeley Extension’s Downtown Center [425 Market Street, SF] is now accredited for 30 CE hours.  If you are a LEED AP, take the course and you are good for the next two years!

Next class starts 13MAR2010, so enroll now—space is limited.

The California Solar Initiative has been very successful in inducing demand for distributed solar while preventing the herky-jerk of incentives starting then stopping customer demand [see: Spain].  There is a glide path—but we are approaching a big step down, and we are working hard to get our partners positioned appropriately. 

The big idea behind the CSI was to lay out a ten year glide path of incentives that decreased in step with projected system costs.

Step 6 down to Step 7 is percentage-wise the biggest decrement in the glide path, and it is difficult to see where we are going to be able to take ten percent out of the cost stack to restore equilibrium—or recruit investors at a 75bps lower return.

If we look at what has happened historically, you get an idea of what the next several months are likely to look like—a rush of epic proportions to get your claim reservation form in when we get close to the end of this step.  The vertical bars represent reservations made per month.  Note for Step 5 the monthly reservations volume tripled as the end neared.  This analysis was done by the good people at Santa Clara County [PBI numbers are governmental, not commercial] and says it all:

Here is where we presently stand:

We are encouraging all of our site hosts to move with us now.  For most of our partners, this next step down is a mid six figure loss on the value of their investment—easily preventable by Doing It Now.

With the 2010 deadline for our big three investor owned utilities [IOUs] to meet their 20% Renewable Portfolio Standard [RPS] hurdle, the CPUC is weighing a decision to allow the renewable energy credit attribute to be stripped from green power generation and be a tradable asset, usable by the IOUs to meet their RPS requirements.  This provides our investors a reliable price signal for the renewable attribute, something not previously available in the California energy markets. 

The hammer in the original 20% RPS target was a $50/MWH penalty incurred by the IOUs and their shareholders for not meeting the 20% requirement.  The CPUC recently released a decision allowing utilities to meet 40% of their obligation by purchasing and retiring RECs generated by renewable generation assets in the western power [WREGIS] markets, since it looks like we are three to four years behind schedule in meeting the requirement. And the CPUC capped value of these tradable RECs at what the compliance penalty is, so not to motivate IOUs to shift non-compliance costs from shareholders to ratepayers (us).  The price cap allows the IOUs to shift up to 40% of their shareholder-borne non-compliance costs [non-recoverable] into a recoverable cost through the purchase of TRECs at the same price as the penalty price.

In a nutshell, this proposed decision sets out:

• Cap of $50/REC imposed for 24 months
• Generation Assets may be located outside of California
• Limited to 40% of compliance obligation
• RECs must be tracked in WREGIS database
• No solar premium

The price cap is higher than the ~$10 value of solar RECs in California previously, equal to what City of Palo Alto Utilities pays 3 Degrees, Inc., but less than the $120 value in Colorado, where they have a separate REC market for smaller solar generation.  Adds a nice little boost to our investor owned systems, particularly in the early years where demand for our solar RECs will outstrip supply.  What it really does is define a value for an attribute that was previously hard to pin down.

So the new sweet spot is 1MW installations on the customer side of the meter [under the CSI program], offsetting high retail electrical rates, and remarketing the SRECs to the IOU.  Five year paybacks on a thirty year asset.

Eventually, the TREC price will revert back to the unbundled price of renewable generation less the cost of brown energy, but demand is likely to create attractive valuations for the next three to four years.

UPDATE:  CPUC approved the use of TRECS for IOU's to meet their RPS on 11MAR.  Click here for a copy of the decision [.pdf, 500k]

Our solar component manufacturing partners won a significant piece of the Section 48c manufacturing tax credits awarded for renewable energy equipment manufacturing facilities.  183 awards were made from an applications pool of over 500, with tax credit applications totaling over $8B. The solar industry ended up with over $1B in awards.  The awards were made to facilities across 43 states.  They are designed to help rebuild domestic manufacturing and bring private capital off the sidelines. 

The big winners:

• CIGS technology was a big winner—at a capex of $0.50/W, this adds 1.2GW of production capacity
• CdTe technology—at a capex of $2.00/W, this adds 30MW of capacity.
• 55,000 metric tons of polysilicon and 5,000MT of uMg Si added—enough for 8GW of xSi modules annually.

So now is when it gets interesting--

Time for the heavy lifting of project development to start.  I see two big risks—

1. On-time, on-budget completion of clean-tech manufacturing facilities--with hard completion deadlines or you lose the 30% tax credit, and
2. Getting good value from third party tax investors for the credit.

Our integrated solar project delivery [Bridging] tool may be the best way to deal with the first risk.  It accomplishes the following:

1. defends the price,
2. protects against “fastrack” or GMax-type change orders,
3. maintains clear responsibility for post-construction problems, and
4. gets to an enforceable contract sooner. 

The 30% tax credit is all or nothing—if you miss either your certification or completion deadlines, you lose the credit.  Selecting the right delivery tool is a big deal.

The second risk is mitigated by using a market-friendly tax equity structure.  Of course, the best answer is to put the tax equity on your balance sheet and match it with your federal tax liabilities, but not everyone has the cash flow to do that.  If you need to monetize the tax equity piece [like most solar developers do],  you typically have three options:

1. equity flip partnership
2. operating lease, or
3. inverted lease with an tax credit pass-through. 

What follows is my take on what needs to be done—please remember I am a solar developer, not a tax accountant, so please confirm your own understanding on the tax equity side. 

Monetizing tax equity—No cash grant option in this program—so credit monetization structures, such as partnership flips, sale leasebacks, or inverted leases will have to be utilized if the credit cannot be used directly.  If the facility takes over two years to build, the credits can be used during construction.  Not describing a partnership or leasing structure in the credit application, but admitting an investor later using a partnership or lease structure does not appear to change the project in a “significant” way, provided the investor signs the same credit agreement executed by the original taxpayer. 

$2.3B is the total award, and some companies will be able to use the credit to offset their own tax bill.  A significant share of third party tax equity will be needed however—and to solicit this from a market that is just opening up again after being shut down during the financial crisis—I question how much of this equity gets placed.  Will the IRS want to see a tax investor prior to certifying your project as eligible for the credit?  Do you start construction and buy equipment without your tax investor lined up?

Tax Basis [263A cost]--Eligible investment credits cover future expenditures and cover investments made after 17FEB09.  This credit does not apply to a building or its structural components—the basis can only involve the equipment portion of the facility, meaning building leases make more sense than owned real estate—but lease costs are not includable in basis.  Good news for Silicon Valley, where the commercial property vacancy rate is north of 20%.  Qualifying property must be “necessary for the production of specified advanced energy property” and qualify as tangible personal property.   Base building upgrades—power, technical infrastructure, HVAC, industrial gases, lighting, logistic systems and disposal facilities—need to be clearly tied to equipment support, and probably won’t be includable as basis unless specifically needed for the project.

IRS Terms for the credit will be dictated by 15MAR2010.  This credit agreement needs to be executed and returned to the IRS so that they can execute it by 16APR2010.  Any successor taxpayer will have to file a new credit agreement, or face forfeiture or recapture of the credit. 

The taxpayer will have one year from the date of the award letter to provide evidence that all requirements for the allocation have been met—construction contracts, all permits, long lead-time components ordered, the balance of project financing, and off-take agreements.   The IRS may disallow the credit if facility plans are changed significantly.

Integrated Project Development—To mitigate or eliminate risks of forfeiting the credit, the facility description needs to translated from the business plan into working drawings and construction contracts in a manner that demonstrates consistency with the original facility description. 

The applicant will have one year from the date of the IRS acceptance letter, or 8JAN2011 to pull all permits and complete all other long lead-time work required to demonstrate a placed in service date no later than three years after this certification date.

Pull all permits within 12 months of Treasury acceptance letter >> 8JAN2011.

Treasury will certify that project is eligible for tax credits.

Place project in service within three years of certification date.

The taxpayer will have three years from the certification date to place the property into service, Including receipt and satisfactory signoff of all federal, state, and local permits—including occupancy permits, if applicable.  If you don’t complete within that three year window—the certification is no longer valid.

DOE or Treasury can audit the project—so care in project development and management practices, along with the accountant certs and opinions need to be in the development files.

Construction risks when you have already locked in the value of your credit and when you face deadlines in placing the equipment in service are significant, and rest squarely on the taxpayer’s shoulders.  That is why I like our integrated, two step project delivery tool for this application—we lock in certification at the same time we have price and schedule certainty.  And with the most enforceable construction contract in the industry, to boot.

Recapture—the credit vests at at 20% per year, so the recapture risk exists for five years after the date of service due to the taxpayer selling the project or more than one-third of their stake in the facility.

Don’t hesitate to email or call with any questions, or to discuss a potential project.  Successful project execution will need both tax equity structuring and integrated project delivery expertise to meet these deadlines.  We can do both, or be part of a team that gets it done.

  Tom Friedman is right--our clean energy future and energy independence depend on deploying these credits and getting these new clean technologies right. Now.

My spring commercial solar course—promising The Shortest Possible Path to Profitable PV Projects—starts on Saturday 13MAR10 with a full day overview of the industry, and a discussion of the story arc of the class over the next five weeks.  I developed this course over a year ago because I felt I was spending too much time on bad deals, and there had to be a better way to get solar out into urban areas. 

Taught at UC Berkeley’s Downtown Center (425 Market Street, San Francisco),  I use the feasibility report as the framework for understanding what goes into a profitable project.  Click here for a current draft of the syllabus.  Here is a course overview

This course may be a great use of ~20 hours of your time if you really want to dive into what comprises a feasible solar project.  The course capstone is a day of student team presentations on 24 APR.  You and your team present your feasibility report on a potential solar project of your choosing.

What is new this semester?  We will discuss the $700M in Clean Renewable Energy Bonds that have been allocated to hosts in California, and what it will take to get this financing tool more widely used. Understanding Utility Feed in Tariffs and how to use them to capitalize projects.  And PACE—Property Assessed Clean Energy financing—a potential blockbuster capitalization tool.

You will learn a great deal from your fellow students—you will be working with them to understand, underwrite, and present potential solar investments.  We use Microsoft Excel [or Google Docs], Google Sketchup and Google Earth as evaluation tools—give yourself a headstart, download them now [they are free] and start to play with this software to understand how these tools work.  All course materials will be available on a class-specific Google Groups site that serves as the online partner to your classroom work.  Here are the texts I use:

           and           

Course intent is to build a foundation for getting commercial solar projects identified, quickly selecting the feasible ones, and putting them on a track to a real deal.  Planning and Installing is technically complete enough that you can really dive in, or just refer to it when needed.  I believe this is the best current overview and reference on PV--it covers what is happening in Europe and the world, for PV is a globally applicable technology.    When you do a feasibility study, you want it to lead to a project, and the study isn't going to do it on its own. I added Strategic Selling because no one has a project until someone sells something.

My perspective is that of a seasoned solar developer with over twenty years of commercial real estate investment and development experience here in Northern California.

I hope you can join me for this course.  First session is Saturday, 13 March from 9A to 5P, then five Tuesday evenings from 630P to 930P, capping off with Presentation Day on Saturday, 24APR from 9A to 3P with a debrief afterward at a local restaurant.

Click here for the enrollment site.

I started responding to some great questions asked by a Stanford MBA student preparing for a class presentation on emerging business demand.    The questions prompted answers that I thought would be most productive noted as an essay on PV, commercial real estate, and where demand is today.

What do you think the biggest business need is in relation to the installation of solar modules on new and existing buildings?

Finding a home for the 5 gigawatts of modules being produced this year that aren't contracted for.  This twenty eight times what California installed in 2008.  This oversupply is a massive opportunity to add value to real estate if you execute correctly.

Module prices have dropped 40% this year, and manufacturers are experiencing rising break-even percentages as prices drop, forcing them to run their factories at higher utilization rates, putting a collar on the amount produced--and setting the conditions for a price war.  Net installed price is about a wash--because lower California incentives just about equal the price drop in modules. 

We are at grid parity in the markets I work in, the need is to recruit users who want to insulate themselves from utility company rate shock and add value to their real estate.

Taking a couple of steps back from this over-supply condition, you have a more fundamental need. 

Solar is part of an overall approach of designing and developing real estate to be a net-zero energy user.  Form follows Energy.  PV is a harvesting technology and is best used as the third energy strategy you deploy.  For new buildings, site planning to work with, rather than against the elements, is the most important thing you can do.  Minimize the amount of sun that hits western glazing, for example.

Intervention, also called passive solar design--daylighting, shading, night flushing of heat trapped inside a building, landscaping to minimize heat gain [in California] or heat loss [northern Europe] is the second strategy we utilize.  Keeping heat out of a building means you don't need to pay to remove it.

We deploy PV as an active harvesting technique only after we are satisfied we have maximized the first two phases.  A general rule of thumb is that it makes sense on 65% of flat commercial rooftops and 20% of residential rooftops.

How big does the building have to be for solar panels to be used efficiently? 

Solar is a modular technology--it scales very easily--so it scales well with the size of the building.  You don't need a big building to make solar work for you.  More relevant than the size of the building is the size of the harvestable area, whether it be rooftops, parking, or open area. 

If you are trying to balance energy consumption w onsite generation, the intensity of the energy used by the building user, and when it is demanded, is important.  You size the system to offset a portion of the cost-based energy demand of the building.  A typical solar system will produce 10 to 15kWh/SF per year, and office buildings use roughly 15/20kWh/SF/yr--a rough rule of thumb is a 1 to 1 offset on square footage--an 80,000SF office building for general office use would need 80,000SF of harvestable area to zero out its electrical use. 

How much sun in the year is needed (or what locations in the country make solar module installations viable)?

The answer depends how much you pay for electricity, and what incentives are provided to stimulate demand.

PV has been proven in Germany as a means of obtaining energy independence--the climate comparable in the USA is Nome, Alaska.  German solar incentives are much higher to stimulate demand, their grid prices are higher, and much of their natural gas is imported from Russia.

In California, electricity from a solar generation asset is now cheaper than utility grid power in the higher residential tiers, and for the A1 and A-6 Time of Use [TOU] tariffs where we can spin the meter backward at the higher $/kWh rate and offtake at a lower nights and weekend rate [think parking lot lighting].

From a big picture perspective, anywhere in the red or orange portions of the solar atlas to the left are feasible areas for solar development in the Western USA.

PV is distributed generation, so it fits where there is demand, high energy prices, and incentives.  From the National Renewable Energy Laboratory:

The northeast and California are great locations due to high energy prices, and Florida and the Southwest due to high insolation, and summer air conditioning loads.

Does it make more sense to use solar panels on certain types of buildings (e.g. on retail vs industrial vs residential)?

The key here is net metering--you want to offset the amount of energy used onsite.  Net metering is based on the value of the kWh generated--kWh generated by the asset during peak period times are worth three times what a kWh used at night or weekends costs.  To maximize the value of the system under a net metering scheme, you maximize how much surplus you generate during peak times, and time shift as much demand into off-peak times.  Parking lot lighting loads are a prime example.

Demand is generated by the user--and some users value the benefit of solar more than others:

This chart shows universities and corporate real estate users are adopting PV as a component of their real estate faster than other types of users.  Developers have a first-cost problem--PV is basically a pre-paid, tax incentivized power contract.  Reducing future operating expense is not as attractive as reducing first costs.

Where it makes tremendous sense for developers is to make the building PV Ready--installing the conduits and configuring the electrical system for a PV system that may be installed by a future user.  The first cost is minimal, and the fact that the property is set up to accept a system can be a key feature at the time of sale or leasing.

How much does installing solar panels help with getting LEED qualifications?

It can help a lot if you are pursuing LEED Core and Shell [LEED-CS], and only a little if you are pursuing LEED Commercial Interiors [>50% of total energy use].    Core and shell energy demands are only for the building shell and services such as elevators, and you get credit for reducing heat islands and introducing innovative technologies. 

We can get up to 50% of LEED certification score on LEED-CS.  LEED CI requires 50% of all energy used to be renewable, and I find it harder to score in multiple areas since the criteria is only energy use and is not concerned with sustainable sites.

Are cities actually requiring solar panel installation or how is demand being driven for this product?  Any idea how you would measure demand or how much demand there is?

Demand is driven by the user.  Cities are beginning to require LEED certification and in some instances, will expedite permitting or reduce permit fees for solar project installations.  Net zero energy real estate requirements are still in the discussion stage and not a permitting requirement as yet.

Demand is driven primarily by the ability to monetize the tax attributes of a system [~52 to 54% of cost] + the ability to lock in power costs competitive with the market, and secondarily by using PV as a way to architecturally brand your real estate. 

McKinsey had a tough time estimating demand, but reported that PV's greenhouse gas reduction abatement potential exhibited the widest range of outcomes.  Depending on cost compression and learning rates for production and installation--demand could be significant.

And we are getting material amounts of both cost compression and learning rates today.

Carbon cap & trade and Feed-in Tariff programs add to demand--I have a hard time throwing a number at this now--but it adds to the snowball effect.

Who currently provides financing to developers for this?

30% of the system installed cost for commercial projects is covered by a cash grant from the US Treasury.  The state of California has a performance based incentive that covers about 15% of the cost.  The remainder of project finance requirement is met via cash, equipment leasing firms, or debt.

Alternatively, there are financial companies that own the systems and just sell the power on a kWh basis, called power purchase agreements or PPA's.  We do not see much of this energy service model being utilized at present, as it depends heavily on the California performance based incentive to cover 25% or more of the system installed cost to meet investment hurdle rates, and incentive levels have dropped below this, to about 15% of installed costs.

The Treasury Cash Grant is paid at the time of the system's Commercial Operation Date, but vests similar to a tax credit over five years at a rate of 20% per year.  Should the system change ownership during that five year period, the cash grant is recaptured.   You should plan to own the generation asset until your tax benefits fully vest.

How much financing do they provide?  At what rates and deal terms?  Is there a huge shortage of financing currently? 

The Treasury cash grant program has met the demand for tax equity through the end of 2010.  Project financing depends on the corporate user's credit.  PPA financing is looking at mid-teens IRRs--most projects do not meet this hurdle due to lower California incentives.

Sale leaseback financing is starting to be offered again, after a dry period of nine months--since October 2008.  The off-taker needs to be a ratable credit, however.

The other option is to include the net costs in your renovation or new construction financing.  Since there is very little new construction financing at any price available at present, this may not be a viable option.

About how much does it cost/SF to buy solar panels? 

Net system installed costs, after the Cash Grant, are $40 to $60 PSF.  Integrating this into the architecture allows you to use the system as a UV and rain screen, which should save you about $25/PSF you would have spent for cladding or scrim material.

What tax benefits do developers get from installing solar panels?

At this point--we find users with a sustainable goal--think universities and Google--are the most attracted to onsite solar generation assets.  As is true with most parts of the energy market, there are very attractive tax benefits for those who own the systems during the vesting period.  These benefits include:

• 30% Investment Tax Credit or Cash Grant through 2010
• 5 year MACRS depreciation
• no state property taxes on the value of the system

Over the twenty five year life of one of our systems, they are net present value positive, reduce a user's carbon footprint, and help brand the real estate--for PV puts the sizzle in sustainability.  It is a visual brand of doing the right thing for the environment, for the company, and for the place we leave behind.

The key to commercial and utility scale solar is finding feasible projects and successfully capitalizing them.  I am the instructor for a UC Berkeley Extension course this fall, taught at the downtown campus, that has precisely this course objective.

Click here for the current draft of the syllabus.  The course commences with a low gear flyby of current technology and then dives into demand, capitalization and design of commercial PV systems.  The essence of the course is a team-based exercise in investment grade due diligence for a solar photovoltaic [PV] investment.  The capstone of the course is the preparation of your team's investment grade feasibility study for presentation to your classmates and a professional jury on 7NOV09.

These are the texts I use.

       and        

Intent is to build a foundation for getting commercial solar projects identified, quickly selecting the feasible ones, and putting them on a track to executing a deal.  Planning and Installing is exhaustive enough that you can really dive in, or just refer to it when needed.  I believe this is the best current overview and reference on PV--it covers what is happening in Europe and the world, for PV is a globally applicable technology.  Strategic Selling was added this semester, because when you do a feasibility study, you want it to lead to a project, and the study isn't going to do it on its own.

Cooperate and graduate is a big part of the course--you will learn a great deal from your fellow classmates, and you are expected to contribute your experience and perspective as well.  In addition, we are fortunate enough to have some great guest lecturers on several evenings.

My perspective is that of a seasoned solar developer with over twenty years of commercial real estate investment and development experience here in Northern California.

Here are a couple of slides from the course:

I hope you can join me for this course.  First session is Saturday, 26 September from 9A to 5P, then five Tuesday evenings from 630P to 930P, capping off with Presentation Day on Saturday, 7NOV from 9A to 3P with a debrief afterward at the Thirsty Bear.

Click here for enrollment information.