The US downstream PV industry is bracing itself for life without the Investment Tax Credit (ITC), but despite this potential blow to development, the long-term fundamentals of the sector look great. Andrew Kinross explains when the ITC is forecast to be extended, the current structure of the US downstream PV industry, the market drivers, and the shift to power purchase agreements.
Summer is nearly over, and participants in the US photovoltaic (PV) industry are bracing themselves for a gloomy future without the 30% investment tax credit (ITC). The critical federal government incentive that accounts for upwards of 30% of the economics of a solar project is being tossed around like a political football in Washington DC. It looks unlikely that the various sides in the debate will find a compromise solution before the end of the year, at which point the ITC is set to revert back to 10%, thereby killing the economics of all but a few select projects.
What a difference compared with earlier in the year, when companies were brimming with confidence about ramping up revenues, reaching profitability and putting the US on the PV map. Back then, most industry observers thought the ITC extension was a foregone conclusion. Not any more.
Life for these companies has taken a turn for the worse — as shown in Figure 1 (page 48) — declining by as much as 70% in the year to date. But while the short term is murky, the long-term fundamentals of the industry nonetheless look decidedly strong. The US$3.3 billion California Solar Initiative (CSI) has kicked in, many other states are bringing incentive programmes on line, system costs are declining and electricity rates in certain areas are poised for steep increases. In August 2008, California utility Pacific Gas & Electric (PG&E) tapped two companies, SunPower and OptiSolar, to install an unprecedented 800 MW of PV, subject to extension of the ITC.
For those companies that can weather the short-term storm a robust market with pent-up demand awaits if and when the ITC is extended. Certainly, most industry observers believe that the new administration in Washington — Democrat or Republican — will extend the ITC in 2009, if it doesn’t get settled in 2008.
The ITC: When will it pass and for how long?
The ITC was considered a certainty at the beginning of 2008. However, while it had widespread support in Congress, the Senate added — and then removed — the legislation on some eight different bills through July 2008. A stalemate ensued, with the main point of contention being over how the credit would be funded. The White House, for example, indicated that it would veto any bill that funded the ITC by taking subsidies away from the oil and gas industries. The next suggestion was to fund the credit by closing a loophole that hedge fund managers were taking to reduce their tax burden by setting up headquarters in offshore locales.
As the focus in Washington turned to the upcoming Presidential election and the number of legislative days dwindled, most felt that short of a quick deal being cut, the ITC would not be extended until 2009, despite pressure from the industry.
The good news is that most industry observers think that when the ITC is extended, it will be extended for a long time, some six to eight years, thereby affording the industry some long-term stability. And, if the ITC is not extended in 2008, then it is likely to be in 2009, either as a one year extension followed by a more comprehensive extension, or as a single shot, long-term measure.
Industry structure and key players
Industry structure relates to the scale of installations. For small projects, a large portion of modules and other components go through a wholesale distributor and then on to an integrator and/or installer for installation on a residential or small commercial rooftop. Until now, most systems were sold to the host customer, but in 2008 a number of leasing and Power Purchase Agreement (PPA) models emerged for the small-scale sector, mainly pioneered by Sun Run and SolarCity.
Under these models, the host customer pays for electricity on a $/kWh basis, but a third party owns the system. Key residential and small commercial players include SolarCity, Akeena, and Real Goods, although the market is highly fragmented, with relatively low barriers to entry. AEE, groSolar and SunWize are the leading distributors and the latter pair have now moved forward into the design and construction business. For large projects, say systems of 100 kW or more, a developer normally identifies the site and negotiates a PPA and financing for the project. Then an installer designs and installs the system.
SunEdison and SunPower are by far the biggest players in the large project market, together accounting for upwards of 50% of the US market. Both have become vertically integrated over the past few years. SunEdison, backed by Goldman Sachs and others, began as a pure play developer and then bought installation companies in California, New Jersey, Hawaii and Oregon. Meanwhile, SunPower began life as a module manufacturer and then acquired installers PowerLight in early 2007 for $332 million. Morgan Stanley also committed $190 million to SunPower in November 2007.
New entrants include European-based companies such as Iberdrola from Spain and Juwi of Germany, and Energy Service Companies (ESCOs) such as Johnson Controls.
Policy and regulatory market Drivers
To date, the industry has been largely buoyed by government subsidies and regulatory mandates, as PV is not currently competitive without subsidies. However, at some point, grid parity will be achieved and customers will begin to buy solar electricity without subsidy.
The key federal incentive is the investment tax credit (ITC) which allows a system owner to reduce its tax burden by 30% of the upfront cost of a system. It means that an investor with a tax base must be involved to take advantage of this benefit, but the certainty of receiving this tax credit at the commencement of operation of a new project makes it particularly attractive to investors. However, while for commercial applications, the ITC is not capped, for residential applications, it is capped at $2000.
Furthermore, while the ITC was increased to 30% from 10% through the Energy Policy Act of 2005, it is currently scheduled to revert back to the 10% from 1 January, 2009.
This draws worrying parallels with the wind industry’s production tax credit (PTC), which is similar to the ITC in that it accounts for a large portion of the project economics. The wind industry has seen years of start and stop growth as the PTC has expired and then been extended three times — in 2000, 2002 and 2004 — leaving investors uncertain and growth heaving through boom and bust cycles in response to the annual whims of government policy.
Meanwhile, a number of individual states provide either upfront rebates or production incentives (normally an amount per kWh of solar electricity produced) for solar projects. The California Solar Initiative (CSI), the largest state incentive programme in the US, offers rebates for smaller projects and production incentives for larger projects. These incentives are distributed through the large investor-owned utilities as well as the publicly-owned utilities. The California programme was designed to last a decade, with incentive levels declining as various installed capacity milestones were passed with the hope that at the end of the programme, solar would be able to compete on its own merits without subsidy.
In addition, a Renewable Portfolio Standard (RPS) is a regulatory policy that requires the increased production of renewable energy sources such as solar, wind, biomass and geothermal. The RPS mechanism generally places an obligation on electricity supply companies to produce a specified fraction of their electricity from renewable energy sources. California has the most aggressive goals, with an RPS target of 20% by 2010 and a goal of 33% by 2020. However, regulators have recently backed off on compliance as it has become clear that the utility companies won’t be able to meet the targets for 2010 and now utilities need only to have agreements in place to build the targeted renewable generation at that time.
As of July 2008 some 30 states had RPS programmes in place and some have specific targets for the solar industry.
Utilities that have announced plans to build 10 MW or more of PV (most of which is designed to satisfy RPS targets) include Southern California Edison, Long Island Power Authority, Duke Energy and Florida Municipal Power.
Some states have also implemented Renewable Energy Certificate (REC) trading systems. Under the terms of such schemes, for each kWh generated two commodities are created, both the electricity and an associated tradable certificate related to the environmental benefit of the renewable energy source. Utility companies may sell excess RECs or purchase them to satisfy shortfalls in their RPS targets. Other entities may also purchase RECs on a voluntary basis in order to offset a certain amount of their electricity usage with renewable electricity. The voluntary markets are generally driven by corporate desires to be ‘green’ and thus perceived favourably by their stakeholders.
In 2008, For example, New Jersey switched from a rebate-based programme to an all Solar Renewable Energy Certificate (SREC) programme in which the sole incentive for a solar system was the SREC that was generated from it. Under the state’s RPS programme, there was a minimum amount of solar that had to be included and if that was not satisfied, the utility would have to pay an alternative compliance payment according to a schedule that began at $250/MWh and increased substantially in subsequent years.
Solar resources are a fundamental driver of solar generation economics. The very best solar resource is in the south-west of the country and includes states such as Nevada, Arizona, and New Mexico, as well as in Hawaii. California also has a good solar resource in the southern portion of the state, but this becomes weaker in its more northern latitudes.
Decreasing system costs and increasing electricity prices will inevitably lead to a point where solar electricity becomes competitive with conventional electricity without government incentives and/or subsidies. Referred to as ‘grid parity’, this will not occur all at once. Rather, it will be progressive, with different customer segments in different geographies with different technologies at different times. Today, it is generally accepted that solar electricity is not at grid parity anywhere in the United States. That is, without incentives, customers could not be able to buy solar electricity for less than conventional electricity. Customers already paying high electricity prices in California would be the closest to achieving this and over time, will likely cross the ‘grid parity’ mark first.
Hawaii offers an interesting market where average electricity prices in 2008 are $0.29/kWh for residential customers and $0.26/kWh for commercial customers. However, higher labour rates, land costs and shipping costs make solar electricity much higher than on the mainland, too, and a large market has yet to emerge.
A major driver of lower system costs is expected to come from lower module prices. Module prices have actually gone up in the past three years as a result of the silicon shortage, but plenty of additional silicon and module capacity is expected to come on line over the next 12–24 months, which will result in lower prices not only in the US, but worldwide. In addition, conversion efficiencies continue to improve for modules, further contributing to the favourable cost per kilowatt-hour economics.
For those customers who purchase a solar system, the wider economic conditions play a major role. Indeed, a sluggish economy in 2008 is causing sales of residential systems to ramp down from previously high growth. However, tighter economic conditions have less impact when a customer procures solar electricity through a PPA and therefore is spared the high initial investment costs.
Feel the power
Just two years ago, almost all projects were built and then sold to the host customer. That meant that the host customer had to pay a large up-front capital cost and then recoup the savings over the subsequent years. On the residential side, that meant that only those with a large amount of disposable income and a long time horizon could even contemplate installing solar PV equipment. Commercial customers tend to be even more finicky about payback periods and return on investment (ROI) calculations.
That has all changed with the emergence of power purchase agreement contracts that involve third party financing. PPAs have allowed residential and commercial customers alike to benefit from solar electricity while someone else owns and manages the power plant on their rooftop or land. Indeed, solar PPA pioneer, SunEdison switched to an all PPA model in 2007. Instead of looking for a return on investment, or payback period, host customers can examine their average current cost of electricity, and choose to switch over with relatively low risk if given an equal or better offer by the PPA.
In California, where the market for commercial PV systems is the largest, the average cost per kWh of electricity was sold for $0.1097 in January 2008. However, Navigant Consulting estimates that the top 25% of kWhs are sold for $0.15 and above and the top 5% of kWhs are sold for $0.17 and above. Thus, for a solar company that can make a profit and meet or beat those prices, potential market penetration can be substantial.
Furthermore, in July this year, utility company Southern California Edison proposed a 20% rate hike for its electricity consumers. If electricity were to move higher by this amount, a whole new batch of customers could be sold solar at save cash.
While angst over the extension of the ITC in 2008 has reached a peak, investors and industry participants with long-term perspectives should be able to do well in the US PV downstream industry.
Andrew Kinross is associate director at Navigant Consulting