In less than a month, solar energy projects will see the stimulus-funded cash grant in lieu of the 30 percent tax credit expire. The change back to tax-credit-financed projects provides a revealing look at the disadvantages of energy incentives based … Read More
When discussing centralized v. decentralized solar power, there’s an inevitable comparison between solar thermal electric power and solar photovoltaic (PV). But the fact is that solar thermal power – or concentrating solar power (CSP) – can also be done in … Read More
Martifer Solar, a subsidiary of Martifer SGPS, alongside Silverado Power, signed today Power Purchase Agreements (PPAs) with Southern California Edison, for 113 MW solar projects.
These 113 MW consist of nine PV projects within close proximity to major utility lines in Southern California. These projects, expected to be concluded in 2013, are primarily located in Los Angeles County and will allow an energy supply to thousands of homes via a 20-year contract with Southern California Edison. [emphasis added]
Last week I briefly reviewed IREC’s new (almost) Best Practices for Community Solar and Wind Generation. Craig Morris provided another review this week that provides a very good perspective.
For one, Craig notes that there’s an unhealthy focus on net metering to the exclusion of other policies (like feed-in tariffs) that can provide a higher value for community projects. I think he illustrates one of the biggest problems with continuing to rely on net metering for distributed renewable energy projects:
Generally, under net-metering the utility company gets your “excess” solar power for free, say, at the end of the calendar year – solar power that offset the most expensive power on the spot market during times of peak demand in the early afternoon during the summer. You give that to your utility for free under net-metering. [emphasis added]
The report also misses a chance to highlight the global best practices for community renewables, or even the best practices in the U.S.:
Perhaps unsurprisingly, when IREC went looking for best practices, it did not look at leading global markets, but stayed within the confines of US borders. The study is typical of US analyses in that respect (see this report at Renewables International). Clearly, the dominant global policy to incentivize renewables is feed-in tariffs, especially in ramping up community projects. IREC even ignores FITs within the US, comparing policies in Massachusetts, California, and Maine, for instance, while Vermont, which has successful, but rather limited feed-in tariff scheme, is mentioned only in terms of its “group billing program.”
Craig also notes the glaring issue of ownership. The IREC report defines community ownership as “direct ownership, third-party ownership, and utility ownership.”
Which begs the question of what kind of “community” system can be owned by a utility. Certainly in Germany, a community system is by definition one owned by the community.
IREC goes on to state a preference for utility ownership, an idea I find appalling. As I noted in my review, utility-owned community solar projects have often asked community participants to pay more for electricity, at a time when most people going solar are making a return on investment.
Overall, I think I agree with Craig’s conclusion:
Given the current policy framework in the US, the report is probably useful. For instance, it discusses how community projects can avoid having to pay income tax on the power generated and how federal tax credits can be utilized. In other respects, IREC’s thinking is clearly still bound to net-metering; if you switch to feed-in tariffs, for instance, the question of “demand charges,” which seems to be an important issue for IREC, becomes completely irrelevant. In effect, the proposals basically show how progress could be made within the current legal framework without any major changes.
IREC’s report provides a good perspective of how to advance community renewables under a “business as usual” policy framework. If you agree that we might be able to find better policy, however, you might want to read [shameless promotion alert] Community Solar Power: Obstacles and Opportunities instead.
It’s rarely mentioned that a home with a solar array still gets most of its electricity from the grid. In fact, without storage, a typical home solar array might only serve one-third of a home’s electricity use, even if the … Read More
Yesterday, the Interstate Renewable Energy Council (IREC) released their model program rules for community renewable energy projects [pdf]. IREC’s new model rules consider many of the basic issues facing community renewables programs. These include: renewable system size, interconnection, eligibility for … Read More
IN this environmentally conscious college town, thousands of bicyclists commute each day through a carefully cultivated urban forest whose canopy shields riders and their homes from the harsh sun of this state’s Central Valley.
The intensity of that sunshine also makes Davis an attractive place to generate clean green energy from rooftop solar panels. And therein lies a conundrum. Tapping the power of the sun can also mean cutting down some of those trees.
Enter community solar. Individuals can invest in a nearby, common solar PV installation, saving kilowatt-hours and trees.
But the article provides some poor examples: the Sacremento Municipal Utility District’s Solar Shares and SunSmart in St. George, UT. In the case of the former, participants pay extra for their solar power. In the case of the latter, participants pay extra for solar and – worse – pay up front for 20 years of more expensive power.
In our recent report – Community Solar Power: Obstacles and Opportunities – we provide a case study of nine operational community solar projects – five of them provide a payback on investment rather than asking a premium price for clean power.
Community solar can save trees, but it can also save participants money.
For two years, solar and wind energy producers seeking federal incentives have been able to take cash grants in lieu of tax credits. The stimulus act program helped keep the renewable energy industry afloat as the credit crunch and economic downturn dried up the market for reselling tax credits to banks and other investors with large tax bills.
The cash grant program is set to sunset at the end of this year, but solar and wind energy advocates are hoping it will be extended, for good reason:
In fact, the tax credits were always an awkward tool, some argue. Rhone Resch, the head of the Solar Energy Industries Association, said that many of the companies doing the installations were not making a profit either, so these tax credits were sold as “tax equity,” a secondary market, at a loss of 30 to 50 cents on the dollar to the seller. [emphasis added]
The tax credits were worth 30% of a project’s value, so the transaction costs of reselling the credits meant that renewable energy projects without sufficient internal tax liability were 13 to 21% more expensive than projects that could use the credits themselves.
This is dumb policy. Ratepayers pay a higher price for renewable energy because incentives filter through the tax code instead of the general fund.
But the cash grant v. tax credit issue is just one symptom of a larger disease affecting American renewable energy policy. Transaction costs are increasing the cost of renewable energy in nearly every state with a renewable portfolio standard (RPS).
Under most state RPS policies, utilities put out requests for proposal to acquire renewable energy to meet the state mandates. These solicitations attract thousands of developers who all have to front their project development costs. But in California, for example, 90% of projects don’t make the utilities’ shortlist for the solicitation, stranding over $100 million in development costs.
Some of those projects may eventually get online, but most of that money is flushed because the U.S. prefers to let utilities act as gatekeepers to clean energy rather than open the market to any potential producer. It’s not the only way.
There’s a renewable energy policy that’s responsible for 75% of the world’s solar and half its wind power. It has the lowest transaction costs because there’s no fiddling with the tax code and no parasitic costs from auctions or solicitations. Instead, utilities are required to interconnect and take the power from any developed renewable energy project, and to provide a price sufficient to provide a reasonable return on investment (just like the utilities enjoy in rate regulated states).
The policy is funded entirely through the electricity system, so renewable energy doesn’t have to compete with other budget priorities.
It’s called a feed-in tariff.
The U.S. can extend the cash grant program, but it merely treats a symptom of the disease. A better policy awaits.
I had a conversation with a wind developer yesterday and was talking about the difference between putting together large projects (over 80 MW) compared to distributed generation wind projects (80 MW and under). I mentioned that we have a deep interest in understanding the economies of scale of renewable energy projects and he replied, “economies of scale are bullshit.” He noted that large wind projects require significant development costs that smaller projects don’t encounter (including many more landowner negotiations and permits) and that installation and maintenance services are sufficiently widespread for any sized project to find services.
It’s not entirely true that bigger projects have no economies of scale, but these two charts illustrate the larger point: Most economies of scale in solar PV and wind power are captured at a relatively small size.
The first chart is from the California Solar Statistics website, and draws on data from over 70,000 solar PV installations in California since 2005.
Clearly, solar PV installations of 10 kW have captured more of the economies of scale for solar PV. Costs may fall slightly for much larger projects, but the smaller number of projects makes it hard to see trends (interesting note: there seem to be as many > 100 kW solar projects costing over $10 per Watt as there are under $8 per Watt).
The second chart comes from the 2009 Wind Technologies Market Report by Ryan Wiser and Mark Bolinger (which is a must-read).
The wind data is even more striking, with the lowest average project cost found in the projects with just a handful of turbines (5-20 MW of capacity), with costs steadily rising for larger projects. Certainly there’s an advantage to having more than one turbine, but less so for growing the project much larger than 10 turbines.
This data should inform renewable energy policy. If modest-scale, distributed renewable energy projects capture most (or all) economies of scale, then the opportunity to place these projects close to load may reduce the need for new, long-distance, high-voltage transmission lines. It means more renewable energy can come online faster and with fewer political battles.
These smaller-scale projects are also the appropriate size for local ownership (which provides twice the jobs and 1-3 times the economic impact of absentee ownership), allowing more the economic benefits of renewable energy development to accrue to the host community.