Burn Some Daylight

Two things matter in developing PV--the system design, and the cap stack. 

Luigi Sciabarrasi reminded me again of this fact the other day when he pointed out that most public companies are judged by their book earnings, and if the after tax value of their pv power system has a greater net present value than the book value, the system has an effect beyond merely saving the planet.

Now, I am not a tax accountant, but I needed to understand if this book vs tax thing was a headwind or a tailwind in adopting this new technology.  Turns out it is a nice little tailwind--but you get your tax advice from your accountant, not your pv power developer.

The difference is basically the early year benefits of the 5 year MACRS versus the 25 year straight line w/ $0 salvage value.  I didn't include a residual system value in this analysis, but it would be the same for either option.

I am the first to counsel that you don't do PV for the tax benefits.  We have larger problems to fix.  But it is comforting to know that these systems are CFO-friendly.

Grazie mille, Luigi!

Had a meeting with an office building developer yesterday and we reviewed a migration path for renewables on their project.

They are merchant builders--they permit, manage construction risk, and then sell--so the long term benefits of pv, and the multiplier effect on residual value, is not compelling for them.  They focus on first costs, not life cycle costs.

"PV ready" was my recommendation to them.  PV ready is defined as:

• the future array area is mapped out, and an array is sized based on general performance data.
• the future inverter location and point of grid interconnection is selected.
• Provide DC only conduits from the array location to the inverter location,
• Provide AC conduits from the inverter connection to the point of interconnection
• The bus at the point of interconnection is sized per NEC for backfeeding the PV power production, and
• We certify the project as "PV Ready" and stand by to reserve the California Performance Based Incentive, and design, permit and provision the system--all the owner needs to say is GO.

When this builder sells the property, their brokers can advertise it as "PV Ready", and the new owner, who will be more focused on life-cycle costs, can reduce their carbon footprint and operating costs through a PV power system--the conduit will already be there.  Now that's thinking ahead.  There is a value to the builder of such thinking ahead.  This property is worth more than one that isn't PV ready--more than the incidental cost of installing the conduits and getting the certification.

The Senate's recent filibuster of the tax extender for the 2009 30% Solar Investment Tax Credit is the latest manic-depressive moment in our industry.

What does this mean if you want to power your World with onsite clean power?  There is little time to waste--we typically need six months from GO to power up--and we only have a little over ten months left before the 30% Solar ITC reverts to a 10% credit.

Why should you care?  Here is the value stack under the present tax law, present California incentives, and present avoided power costs.

Here is what it will look like if you flip the switch after 31DEC08, under present law.

The 25% system value-add drops to 5%.  Still positive, but much harder to justify the investment.  The after tax IRR drops from high teens to below 10%.  Not enough to pull demand for renewables forward five years--to accelerate the job creation and adoption--that the 30% stimulus does. 

And the cost of doing the right thing is about what we burn in two months in Iraq using the President's $186B 2008 Iraq war cost estimate.

The McKinsey report did not acknowledge that a long term distributed generation + renewables federal tax policy is critical to kicking our brown power habit. Think of it as The Patch.  It helps us get where we need to be.

There are a number of institutional investors sitting on the sideline ready to get in the game if there is a multi-year tax policy to pull demand for renewables forward five years--which is exactly what the solar ITC does.  It creates green collar jobs in California and elsewhere, and provides a stable platform for R&D and getting the costs out of distributed PV power.

There are three things you don't wanna do when harvesting your available solar resource.  Number three is procrastinate.

A friend with a client seeking approvals on a biotech campus in the SF Bay Area called this week.  His client wanted a pv power purchase agreement proposal for a biotech campus in SF.  So far, so good.

Turns out the city is apparently asking for a percentage of the project's power be generated onsite. And they want the commitment as part of the entitlement process.

If the project draws a total of, say, 25 kWh/SF/year [average for a biotech building in SF], you would need 2SF of PV array area to feed 1SF of gross building area[GBA] to meet 100% of demand.  For example, to power 10% of this complex with onsite pv generation means 1SF of array area for every 5SF of GBA.  A 40,000SF array over a parking garage would meet 10% of forecast power demand for 200,000 square foot biotech building, or 500,000 SF of a general office building.

PV is cost effective--PG&E rates and current incentives work--our industry deployed over $700 million of PV in California last year alone.  PV is basically a prepaid clean power contract--you get 20 to 25 years of power for an upfront payment of six to eight years of electrical demand.  You have to get over the first costs problem, and then you have to match onsite pv power generation with onsite demand.

The problem is not that the math doesn't work, it is timing, and agreeing to a commitment that allows for a couple of different ways to get the job done.

Onsite clean power generation typically comes from the user, or increasingly, from the institutional investor partner.  This is the first time I have heard of a jurisdiction making onsite green power generation part of the entitlement process--well intended, but you need to add some carrot to the stick...

The wrinkle is the area I want to use would not be built for four years and they wanted a price now.  PV is, and will be, a tax driven deal for the next four to five years in California--designed to pull demand forward and grow the 40,000 or so green collar jobs expected in this industry sector.  The federal incentives presently available will expire at the end of this year.  Any forecast more than nine months out is based on the probability these incentives will continue.  Not a bad bet--current sense is that a one year extension has an 80%+ probability of happening this year--but you can't take it to the bank.  Four years out?  No way to predict a green power price in a market that is growing 60% a year--globally.  PV is a great plug and play solution--but to propose on something that is four years out, for a real estate investment that has not been entitled yet?  There had to be another way.

So no proposal--but I wanted to help my friend out with an answer--what I would do if it were my project.  Here's what I would do:

Plug in SREC's for the 10% renewables component until the garage is built and the buildings are occupied.  And get a quid pro quo with the jurisdiction that we provide 10% renewable energy if they offer to buy the renewable energy credits--something that is already starting to happen here in Northern California.  The system owner owns the SREC attribute in California--it is ours to sell or use.

I like Solar Renewable Energy Credits [SREC's} as an interim solution. The SREC is the "green" attribute of solar power stripped off from the clean energy produced and sold separately.

A 100,000SF biotech building would require roughly 250 green tags a year to offset 10% of total demand.  At current pricing of $50/solar green tag, this would add $12,500 to the occupancy costs, probably passed through to the tenant on a triple net lease, similar to other utility costs.  It would add $0.06PSF a year to the rent.

The City of Palo Alto is currently purchasing green tags [pdf, 30k] for solar power generated within the city limits, paid for by the ratepayer. 

Could this jurisdiction set up a similar program?  This would be a great motivator for a property owner to quit buying SRECS and install the actual onsite generation at the time you have leased up sufficiently to put in the system.  A nice carrot, indeed...

President Obama is due to sign HR1, the $787 billion American Recovery and Reinvestment Act tomorrow in Denver.  Contained in HR1 are 19 provisions that provide critical incentives to reduce our dependence on foreign oil, help create over 100,000 jobs, and starts to put in place a smart energy grid that doesn't carbon load our atmosphere.  This is a great extension to the pipeline created by the 2 to $3B of venture capital that has gone into funding renewable energy startups over the past twenty-four months.

This Mother-of-All project finance incentives--$25 billion--is just what our industry needs to retake the USA's global leadership in the solar industry--a position we last held more than twenty years ago.  

Project finance was the single largest obstacle in continuing our path to a cleaner future.  HR1 is a huge win for energy independence.  Kudos to our President for getting this achieved so quickly.  Now that's Shock and Awe...

1.  Renewable Energy Grants

With the goal of doubling renewable energy generating capacity over three years, this legislation restarts our project pipeline.  HR1 creates a new program through the Department of Treasury that gives us another option to placing the solar investment tax credit with a bank or life company.  Treasury is now authorized to buy our Section 48 Solar Investment Tax Credits with cash grants equal to 30 percent of the cost of solar property placed in service during 2009 and 2010. 

Projects we don't power up prior to 31DEC10 qualify for the grant program as long as we begin construction prior to 31DEC10 and we place in service by 1JAN17. Applications must be filed by 1OCT10.

The single biggest impediment to capitalizing commercial projects was the inability to monetize the tax equity [PTC/ITC above] because the banks were kaput. HR1 fixes this.

Solar's big advantage in being shovel-ready is that many of our projects take only six to twelve months to complete--no discretionary planning approvals required for California.  My projects can be powered up by the time another technology gets through running the gauntlet of discretionary approval.

Stay tuned--Treasury will have to clarify how to apply and what it means to commence construction.

2.  Coupling Renewable Energy Grants with Subsidized Renewable Energy Financing 

Starting in 2009, our projects can now qualify for the full amount of the solar tax credit, or the above grant, even if we are capitalizing a solar project with subsidized energy financing (e.g. below market loans, tax preferred bonds, state grants etc.). Winners here are public entities who need us to capitalize their solar plants as well as programs funded through district energy financing--Berkeley's being one of the first.  Together with state legislation authorizing non-charter cities to offer solar system loans through property tax assessment districts [CA AB811], this funding structure brings our cost of power down to below grid cost here in Northern California.

3.  Renewable Energy $60B Loan Guarantee Program

Leveraging off of a forecast $100B in private sector clean energy investments, HR1 includes a two year DOE loan guarantee program for renewable energy projects, renewable energy manufacturing facilities, and electric power transmission projects. The legislation appropriates $6 billion to pay the credit subsidy costs, which should support $60 billion worth of loan guarantees. Eligible renewable projects are those that generate electricity or thermal energy and facilities that manufacture related components.

One side benefit of these loans financing incremental renewable generation is that we insulate our economy and our standard of living from fossil fuel price spikes.

Projects must commence construction by 30SEP11. Davis-Bacon wage requirements (prevailing federal wage) apply to any project receiving a loan guarantee.  Missing piece is now a widely deployed feed in tariff [FiT] that allows us to harvest the available sun and not just offset onsite demand.  Both California and Hawaii should have a FiT in-place by mid 2009.

4.  Renewable Energy Manufacturing Investment Credit

Treasury will provide $2.3 billion to fund a 30 percent investment tax credit for manufacturing assets used to manufacture advanced energy property. Projects must be certified by the Treasury, in consultation with the Secretary of Energy, through a competitive application process. Effective upon enactment.

5.  Remove Limits on Solar Water Heating

Solar water heating is actually the most economic way to harvest daylight--it works in diffuse daylight conditions [cloudy days], in northern climates where you have a higher heat demand than a cooling demand [Seattle instead of Santa Barbara] and to date has not been well incentivized here in the US.  Section 25D of the Code provides a 30% personal tax credit, claimable against AMT, for the purchase of qualified solar water heating property that is used for a purpose other than heating swimming pools and hot tubs.

6.  Extend Bonus Depreciation

PV systems benefited from bonus depreciation in 2008.  HR1 extended bonus depreciation until the end of 2010.

Small business taxpayers are allowed to write-off up to $125,000 (indexed for inflation) of capital expenditures subject to a phase-out once capital expenditures exceed $500,000 (indexed for inflation).

7.  Solar and Green Renovations on Federal Property

HR1 added $5.5. billion to be deposited into the Federal Buildings Fund to construct, repair and make alterations on federal buildings to increase energy efficiency, including installing solar energy equipment.  $4.5 billion shall be available for measures necessary to convert GSA facilities to high-performance green buildings.

The Department of Veteran's Affairs was appropriated $1 billion for non-recurring maintenance on their facilities, including energy projects.

GSA estimates that 75% of the anticipated projects will include a solar component.

8.  Department of Energy Funding

Appropriates $16.8 billion to DOE’s Office of Energy Efficiency and Renewable Energy, including $2.5 billion for applied research, development, demonstration, and deployment projects.

The total amount includes specific appropriations for the following:

1. Conservation block grants  of $3.2 billion
2. Weatherization $5.0 billion
3. Batteries $2.0 billion
4. State Programs $3.1 billion and of these;

• California is allocated $172M,
• Hawaii, $25 million,
• Oregon $50 million,
• Washington $50 million.

9.  Department of Interior Funding

There are about 60GW of renewable projects planned on BLM lands in the Mojave Desert--more than California's current 33GW peak power need.  Lack of transmission and distribution (T&D) and permit approvals from the Bureau of Land Management have stymied these projects.  HR1 appropriates $125 million to BLM for the management of lands and resources and suggests funds be used for renewable energy rights-of-way and related permitting projects.

10.  New Clean Renewable Energy Bonds (“New CREBs”)

HR1 provides an additional $1.6 billion for new clean renewable energy bonds to finance facilities that generate electricity from renewable energy sources including solar facilities.

11.  5 Year Carryback of Net Operating Losses

For tax years 2008 and 2009, extends the maximum carryback period for net operating losses from two years to five years.  Eligible small business may elect to increase the carryback period for an applicable 2008 NOL from two years to any whole number of years elected by the taxpayer that is more than two and less than six. An eligible small business is a taxpayer meeting a $15,000,000 gross receipts test. (see Sec. 448(c))

An applicable NOL is the taxpayer’s NOL for any taxable year ending in 2008, or if elected by the taxpayer, the NOL for any taxable year beginning in 2008. However, any election under this provision may be made only with respect to one taxable year.

12.  Qualified Energy Conservation Bonds

HR1 authorizes an additional $2.4 billion, up from $800 million, in bonds to finance State, municipal and tribal government programs to reduce greenhouse gas emissions.  These bonds can be used by government agencies to reduce energy consumption in publicly-owned buildings by at least 20 percent, implement green community programs, or develop electricity from renewable energy resources. 

Demonstration projects that reduce peak electrical use also qualify.  Public education campaigns to promote energy efficiency can also be funded. 

13.  Electric Transmission Infrastructure

3,000 miles of new or modernized power transmission lines and 40 million smart meters.  HVDC grids need to run east/west to follow the sun.  Current HVDC transmission runs from Bonneville Power's dams on the Columbia to Los Angeles.  HR1 remedies this by permitting Western Area Power and Bonneville Power Administrations to borrow funds (up to $3.25 billion each) to construct or finance transmission lines.   It's a big, multivariable problem--here is the current report on available renewable resources.

DOE is directed to include analysis of renewable energy sources, including solar, in its 2009 National Electric Transmission Congestion Study.

14.  Solar for Schools

HR1 has a provision for a $53.6 Billion state fiscal stabilization fund.  Approximately $10B of this shall be used for public safety and other government services, including the renovation of facilities and schools to meet green building standards--including installation of solar electric and solar thermal.

15.  Green Collar Jobs

Appropriates $500 million to fund job training programs in energy efficiency and renewable energy.  Also appropriates $250 million for rehabilitation and construction projects on Job Corps Centers, including energy efficiency and renewable energy projects.

16.  Smart Grid

HR1 provides up to 50% reimbursement to smart grid demonstration projects in urban, suburban, tribal, and rural areas, including areas where electric system assets are controlled by nonprofit entities or investor owned utilities.  The Secretary of Energy is also required to maintain a smart grid information clearinghouse.  As a condition of qualification, demonstration projects are required to use open protocols and standards. This sounds like a great idea for our Marin Energy Authority.

The legislation provides a 30% tax credit for property designed to produce energy conservation technologies (including energy-conserving lighting technologies and smart grid technologies).

17.  Solar for the Military

The military is one of the biggest energy users in the Federal Government, and its operations are often in locations with limited or non-existent grid power.  HR1 appropriates $300 million for DOD research, development, testing and evaluation of projects to improve energy generation, transmission, and energy efficiency.

An additional $100 million is appropriated for Navy and Marine Corps facilities, and further specifies that funds are for energy efficiency and alternative energy projects.

18.  Remedy for AMT and R&D Credits in Lieu of Bonus Depreciation

Where a taxpayer is in a loss position, deductions in excess of income are unable to enjoy the benefit of bonus depreciation. HR1 extends the allowance in the Foreclosure Prevention Act of 2008 that permits AMT and loss taxpayers to receive 20% of the value of their old AMT or R&D credits to the extent such taxpayers invest in assets that qualify for bonus depreciation. The amount is capped at the lesser of 6% of outstanding and unused AMT and R&D credits or $30 million. 

The extension of the additional first-year depreciation deduction is generally effective for property placed in service after December 31, 2008. The extension of the election to accelerate AMT and research credits in lieu of bonus depreciation is effective for taxable years ending after December 31, 2008.

19.  Solar Water Treatment Plants

Water treatment is a huge energy user.  The stimulus bill provides $6 billion for the State and Tribal Assistance Grants account ($4 billion for the Clean Water State Revolving Funds and $2 billion for the Drinking Water State Revolving Funds). To ensure that the funds are used immediately to create jobs, the money must be committed to projects under contract or construction within 12 months of the date of enactment.

HR1 requires that not less than 20 percent of each Revolving Fund be available for projects to address green infrastructure, water and/or energy efficiency, or other environmentally innovative technologies. The bill allows States to use less than 20 percent for these types of projects only if the States lack sufficient applications.

________________________________________________

The single biggest issue to me is the lack of confidence among our customer base--solar happens when your customer believes it is the right thing to do, and commits.

California's Community Choice Aggregation Act [AB 117] looks like it may have been TOO good an idea.  Following on the heels of San Francisco and Marin issuing RFP's for community power, there is now a proposed ballot initiative that would change the power customer opt-out provision to basically an opt-in provision.  This makes quantifying the rate base asset much more difficult.  And if you ain't got the rate base, you got nothin'.

No word yet about how the SFPUC and the Marin Energy Authority are planning to handle this initiative--called the Taxpayer Right to Vote initiative but what should really be called the CCA Killer ballot initiative.

Follow the math, and you can understand how much this means to California's investor owned utilities.  PG&E, as one example, has about $1B in annual ratebase revenue.  San Francisco's CCA would have ripped about $200M in ratebase, and Marin would have pulled another $80M.  This represents a 30% reduction in PG&E revenues in 2010--a change from forecasts in 2006:

"In its medium case, PG&E assumed that 3% of its customers would begin to migrate to community choice aggregation in 2006 and the rate of loss to this market will increase by 1% annually, reaching 10% in 2013."[p 26]

A $240M delta in 2010.  So you can see why the money spent putting together the Taxpayer Right to Vote Act looks like a really good investment.  Efforts to defeat this initiative look insufficient at this point.

As a solar developer, a CCA is a great customer, typically with higher demand for renewables--Marin is planning on offering a 100% renewable program for customers.  More customers means more demand for clean renewable power.  Is this initiative bad news?  There is an interesting carveout in the initiative:

"This section shall not apply to any bonded or other indebtedness or liability or use of public funds that...is solely for the purpose of purchasing, providing, or supplying renewable electricity from...photovoltaic...[or other renewables].

This carveout sounds like it preserves the property assessed energy district financing that is a real innovation, but will it save a CCA if it is sourcing 100% renewable power?  Does this work if you are on the utility side of the meter? Looks like we stay on the customer side of the meter, and compete against retail power rates.  Or we focus on the feed in tariffs working their way through the CPUC and the legislature.

I will vote against this initiative if it makes it to the ballot this fall--the issue is about communities having the right to "own" their ratebase assets instead of the investor owned utility, not about taxpayers and right to vote. 

A close reading also leads me to conclude that it stops any municipally owned utility [MOU] from raising any additional capital or expanding their service territory without a 2/3 majority vote at the ballot box--a very tough restriction in a capital intensive industry.  No capital to establish or expand electric delivery service without first winning a 2/3 majority at the ballot box--this is going to slowly strangle a lot of MOU's. 

Competition in power is a good thing--and this initiative cripples competition because it locks in the rate base with the IOU.

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.

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.

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] Big change is that the cap was reduced to 25%.  Will the IOU’s step in and buy TRECS now?

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.

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.”

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?

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. 

My fall commercial solar course—promising The Shortest Possible Path to Profitable PV Projects—starts on Saturday 11SEP10 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 the 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 23 OCT.  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 what is the future of PACE—Property Assessed Clean Energy financing—after the Fannie Mae/Freddie Mac smackdown of this 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, 11 September from 9A to 5P, then five Tuesday evenings from 630P to 930P, capping off with Presentation Day on Saturday, 23OCT from 9A to 3P with a debrief afterward over pizza and beer w your fellow students.

Click here for the enrollment site.

Presented my current take on the solar industry to a group of family office managers in San Francisco last week. I was encouraged by the tremendous amount of interest shown in my cautionary tale about investing in a fast growing and volatile industry.

Solar has grown--and is forecast to continue to grow—at a 60% CAGR.  Tremendous amounts of capital are needed to augment the federal and state incentives available to clean up and smarten how we generate, distribute, and use energy.

And it is a global opportunity.  Solar is moving from a policy driven market to one driven by economics—and is scaled optimally for private equity investors.  Wind is an oligopoly and primarily offshore, the smart grid is, and will continue to be, a policy driven market—customers are afraid it will make their energy bills go up, and energy storage is way too early in the cycle to predict what a successful business model would look like.  Solar has a variety of technology, finance, and execution opportunities that can benefit from the $5 to $15M that a private equity fund can provide.

For that matter, I still don’t know what a successful business model in the solar sector will look like, but I do know two key elements will be: site control next to either loads or transmission w/ capacity, and project finance.

Prior to the talk, I was asked to address how the industry was going to survive after the subsidies disappear. 

With Senator Reid now saying that carbon trading is not going to happen for a while—the brown power industry continues to get a massive subsidy to use the air we breathe as a dumping ground--at no cost.  And China is set to start carbon trading next year.  All we ask for is a level playing field.  Price peak power realistically, value the renewable attributes of solar power transparently, charge a fair price for use of our clean air and water, and we don’t need the subsidies.

One of the most innovative features of the American Recovery and Reinvestment Act of 2009 was the option for commercial solar projects to opt for a cash grant from the US Treasury in lieu of the 30% investment tax credit.  Receiving cash equal to 30% of your total investment roughly two months after your commercial operation date is a very nice incentive—and as we close in on the end of the year, we expect a flurry of construction to lock in these incentives on solar projects throughout the USA.

In order to receive a cash grant for eligible energy property, such property must either (1) be placed in service during 2009 or 2010 or (2) be placed in service after 2010 and before a specified termination date, but only if the construction of such property began during 2009 or 2010.  We have to either substantially start construction or meet a safe harbor requirement of incurring or paying >5% of total construction cost [no planning, financing, or land costs included].  Treasury guidance here.

The real issue is how you demonstrate that construction has begun prior to the end of 2010.  Here is a very helpful FAQ from Treasury that helps to define what they mean by beginning construction.  A “developer-friendly” look-through rule is described in Q16A, Q17, and Q18.

For most of our projects, we will be providing a copy of the construction contract, a certificate for payment for completed work, and an independent engineer’s report including:

1. a detailed construction schedule,
2. project budget, and
3. description of work commenced including all invoices for work performed,

to Treasury to confirm our grant eligibility.

Had a very entertaining discussion about public policy and solar at a holiday party.  The discussion had two main thrusts:

1. Solar demand would evaporate without subsidies, and
2. Subsidies would be better spent on R&D rather than covering a percentage of installation costs.

My response on point one was that all we need is a level playing field.  The energy industry is the most subsidized industry in the world, and policy driven initiatives—such as reducing our dependence on coal, putting a real cost on carbon loading the atmosphere, or getting the US military out of the job of securing imported petroleum—as well as reducing the carbon intensity of our economy, means that solar incentives is money well spent.

Current solar value is 10% greater than unsubsidized cost, and energy payback is even greater—cSi takes <3years of energy to produce the entire installation, and will produce energy for ~25years.

Point two underestimates the importance of an installed base and agile capital markets in driving cost compression and learning rates.  R&D has provided us with innovative, even exotic, technologies, but solar is driven increasingly by balance of system costs [everything but the module & inverter] that are proven out in the field and with lower costs driven by more effective installation methods.  The balance of systems costs are now 20% higher than module costs—R&D in balance of systems is driven by the number of installations and how quickly you climb the learning curve.  To drive learning you need to drive installations—solar is a new model of distributed energy generation, not reliant on huge transmission towers.  Instead, this critical tool in our energy independence is reliant upon property owners who get the math, financiers that can capitalize the upfront costs, and agreeable utilities.

A level playing field, and recognition of the importance of cost compression and learning rates in preparing for our nation’s future.  Not to much to ask for, is it?