In the clean energy community, collaborative meetings often reveal a unity around goals (maximizing clean energy production and use) but a disagreement over the means. It’s not that people oppose distributed generation, but rather they see it as a secondary approach to meeting long-term clean energy goals. The following conversation is typical: Advocate 1: Cheap… Continue reading
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About John Farrell
John Farrell directs the Energy Self-Reliant States and Communities program at the Institute for Local Self-Reliance and he focuses on energy policy developments that best expand the benefits of local ownership and dispersed generation of renewable energy. More
Update 4/6/11: Adam responds on a listserv; his comment is added below.
Adam Browning of Vote Solar writes about a recent study of the peer pressure effect of solar PV adoption. The linked study notes that for every 1 percent increase in the number of installations in a single ZIP code, there’s a commensurate 1 percent decrease in the amount of time until the next solar installation. As he writes, “solar is contagious!”
I’m a data lover, so I thought it would be interesting to see what this looks like over time. If you start with a neighborhood with 25 solar installations, where it was 100 days between the 24th and 25th installation, this peer pressure effect will reduce the time between installations to just 10 days by the 250th PV project. (see chart)
Of course, this process takes a while to unfold. In fact, if solar PV was being installed only once every 100 days at the outset, the peer pressure effect will take over 15 years to reduce the time between neighborhood installs to 10 days.
The second line on the chart (red) looks at the change if you start with 25 solar installations but with a time between installs of just 30 days. By the 250th PV project, the time between installs has dropped to 3 days. And because the lag time between installations started so much lower, the 10-fold drop in lag time takes less than 5 years.
The basic formula – written another way – seems to be that a 10-fold increase in local solar installations will result in a 10-fold drop in the time between installations. This will hold true through the second iteration, as well. In the neighborhood with an initial 100-day lag between installations, it will take another 15 years for the lag to drop to 1 day from 10 days, reaching this level when there are 2,500 local PV projects installed.
Perhaps I can amend Adam’s statement: solar is contagious, but it’s not yet very virulent.
Update (Adam’s reply): I would note that the current strain (solar expensivus) is not a virulent as future strain (solar cheapus). Minnesotans are expected to have low resistance — we are talking major epidemic levels of contagion.
Note: If only the experience cost curve for solar PV worked at the neighborhood level, since it typically shows a halving of installed cost for every 10-fold increase in total installed solar capacity (worldwide)!
The large transmission authority serving the upper midwest – the Midwest Independent System Operator – has plans for new high-voltage transmission lines leading from windy states like the Dakotas to places like Michigan. The purpose is to bring renewable energy from big western wind farms to places East.
Some of these places – like Michigan – would rather do it themselves.
The initial list of projects in the MISO region has an estimated cost of $4.8 billion. But MISO has pointed to additional projects over the next several years that could total between $16 billion and $20 billion. Michigan’s share of $16 billion worth of projects would be about $640 million annually. And most of these funds would be sent out of the state.
…This would happen even though Michigan already has its own state law requiring that 10 percent of its power must be generated using alternative sources by 2015. And all of that renewable-source energy must be generated within Michigan — which means electricity consumers likely won’t be buying or using power generated in other states.
The article doesn’t even get into the meat of the issue: that renewable electricity imports may be marginally cheaper than wind and solar power in Michigan, but that the economic impact of locally developed projects doesn’t show up on electricity bills.
Michigan isn’t alone in their desire for self-reliance. Ten East Coast governors signed a letter to members of Congress to protest visions for a new nationwide network of transmission that would have them importing Midwest wind at the expense of domestically built renewable energy. And the Canadian province of Ontario developed a comprehensive clean energy program with a requirement that all renewable energy and a majority of the actual components of new renewable energy facilities come from inside Ontario.
It may seem counter-intuitive that citizens would prefer more expensive electricity, but when weighed against the economic opportunity of local ownership and development, perhaps it’s no surprise.
A delightful infographic from 1BOG, residential solar aggregators who are driving down the cost of solar PV across America.
They also note that the cleanup cost for the oil spill – $32 billion – would buy enough solar to power all of Los Angeles county for 30 years, for less than 15 percent of what Los Angeleos are expected to pay through 2040.
Using the tax code to support wind and solar power significantly increases their cost. I wrote about this problem last year because project developers were selling their federal tax credits to third parties at 50 to 70 cents on the dollar.
Along these lines, the Bipartisan Policy Center released a study [last week] showing that simply handing cash to clean energy developers is twice — yes, twice — as effective as supporting them through tax credits. [emphasis added]
The problem is that all but the largest renewable energy developers or buyers can’t capture the full value of the federal tax credits. So, prior to the economic collapse, a number of enterprising investment banks (and others) started buying up tax credits to reduce their tax bills.
This was great for big banks, but lousy for taxpayers and electric ratepayers. In fact, using tax credits instead of cash grants for wind and solar projects increased the cost per kilowatt-hour produced by 18 and 27 percent, respectively. (Wait, why not 50 percent? Because even though the tax credit is only half as good as cash, the cash payment only covers up to 30 percent of a wind or solar project’s costs. So cash in lieu of tax credits can only improve that portion of a project’s finances.)
Seen another way, if the $4 billion spent on renewable tax incentives in 2007 had been given as cash instead, it could have leveraged 3,400 MW of additional wind power and 52 MW of additional solar power. This would have increased incremental installed wind capacity in 2007 by 64%, and installed solar capacity by 25%.
The increased costs come from higher prices that utilities pay for wind and solar power (and pass on to consumers) as well as the the cost to taxpayers of passing half of the tax credit value to investment bank shareholders instead of wind and solar projects.
The problem isn’t solved, but has simply been postponed.
When the economy tanked, so did profits (and tax liability) for big banks. Wind and solar producers had no one to buy their tax credits and the entire industry was in danger of collapsing. The adjacent chart illustrates the idiocy of relying on the tax code for energy policy.
Congress stepped in with a temporary fix, allowing project developers to receive a cash grant in lieu of the tax credit. The temporary cash grant (currently extended through 2011) kept the wind and solar industry running during the recession and has saved taxpayers and ratepayers billions of dollars.
It’s also helped level the playing field, allowing for local ownership of wind and solar projects, rather than requiring complex tax equity partnerships. It’s meant more revenue from wind and solar staying in the local community. And this means a larger, stronger constituency for renewable energy.
The cash grant option will expire at the end of 2011, but hopefully the climate hawks and fiscal hawks in Congress will take note: we can support wind and solar at half the price with smarter policy.
Hat tip to David Roberts at Grist for the study link.
A new study released in February adds evidence that utility grids can handle high levels of renewable energy penetration. The latest study examined adding 500 MW of wind to the electric grid on the Hawaiian island of Oahu (home to Honolulu). The result would be a grid with 25% of the energy coming from wind and solar power.
Results of this study suggest that 400 MW of off-island wind energy and 100 MW of on-island wind energy can be integrated into the Oahu electrical system while maintaining system reliability. Integrating this wind energy, along with 100 MW of solar PV, will eliminate the need to burn approximately 2.8 million barrels of low sulfur fuel oil and 132,000 tons of coal each year. The combined supply from the wind and solar PV plants will comprise just over 25% of Oahu’s projected electricity demand. [emphasis added]
By its nature, the wind and solar power will be largely distributed generation, although much of the wind power reaching Oahu would arrive via undersea transmission. Regardless, it’s a promising opportunity for Hawaiian energy self-reliance.
Vote Solar recently teamed up with COSEIA to collect and evaluate the current state of [solar] permitting in 34 local jurisdictions throughout the state. Survey says? In practice, solar permitting requirements vary widely from one jurisdiction to the next due to different permitting plan review processes and other extraneous fees. This has resulted in piecemeal local permitting practices that are often costly, complex, non-transparent and time-intensive. The process is arduous for solar installers and increases costs to consumers. Among the 34 cities and counties surveyed, Breckenridge, Colorado Springs, and Denver are doing permits on the fast and cheap. On the slower, more expensive end are Arapahoe County, Aurora and Commerce City…
The findings reinforce the need for Colorado’s juridications to adopt standardized, streamlined solar permitting practices. The Colorado Fair Permit Act (HB 11-1199) has passed out of the House on a 64-1 vote and now moves on to the Senate. Stay tuned!
Solar permitting remains a looming cost barrier to distributed solar, so it’s great to see that Vote Solar’s Project:Permit is gaining traction.
A proposed revision to the United Kingdom’s feed-in tariff program may have created an uproar, but it may also help spread the economic benefits of solar more widely.
The proposed changes, announced last week, would reduce solar payments for large solar projects (50 kilowatts and larger) by 50 percent or more, but leave payments for smaller projects largely intact. The following tables illustrate:
The new tariffs will help redistribute more of the feed-in tariff (FIT) program revenue to smaller projects. The most likely manner is simply by giving less money per kilowatt-hour (kWh) to the large projects, leaving more for the small projects. The following charts will illustrate.
Let’s assume that under the old FIT scheme, each project size tranche provided 25% of the solar PV projects under the program (see pie chart).
However, since a 2 MW project produces many more kWh than a 3 kW project, the revenues will skew heavily toward the larger projects. For the sake of simplicity, I assumed that the midpoint of each size tranche was a representative project and that they all produced the same kWh per kilowatt of capacity.
The revenue distribution can be seen in the second pie chart:
Essentially, all the FIT Program revenue was going to the largest projects. Even if three-quarters of projects were under 4 kW, they would still only represent 3 percent of program revenue, with 93 percent accruing to the projects over 100 kW.
Under the new FIT scheme, the prices paid to larger solar PV projects are sharply reduced. With projects evenly distributed between the now six size tranches, much less of the program revenue goes to large projects.
The projects under 100 kW have roughly tripled their share, from 3 percent to 10 percent of revenues.
Of course, the lower prices for large solar projects could have another impact: killing large solar projects completely. Let’s assume that the new prices for projects over 50 kW (that experienced the steepest revenue decline) are simply too low and that all development ceases.
The first pie chart shows the project allocation in the FIT program without any projects over 50 kW. As described, we have an even distribution (# of projects) between the smallest three size categories, and no projects 50 kW or above.
The next chart shows the revenue allocation of the FIT program under this assumption. Now, nearly 30 percent of program revenue accrues to projects 10 kW and smaller.
If we assume that instead of an even allocation of projects, we have an even allocation of capacity between the size tranches (e.g. 30 MW, 30 MW, 30 MW), then the revenues would be split evenly between the remaining size categories and two-thirds of the solar FIT program would be flowing to solar projects 10 kW and smaller.
While it’s unlikely that the government plans to eliminate the large solar PV market with its price revisions, the overall effect is likely to be a transfer of program revenues to smaller projects. The advantage in this strategy is that these revenues will be spread over a much larger number of projects and project owners, creating a larger constituency for supporting solar power and solar power policies.
Vote Solar reports that Ohio utility First Energy is claiming for the second straight year that it can’t meet the state’s solar carve out.
First Energy Corp – which is parent company to Toledo Edison, Ohio Edison and Cleveland Electric Illuminating - reports that they were unable to find enough solar renewable energy credits in Ohio needed to satisfy their 2010 benchmark for solar energy. First Energy has filed for force majeure for the second year in a row claiming that it was a circumstance beyond their control, a legal ‘act of God’, that prevented the company from buying the needed SRECs….it’s awfully suspect that an Act of God would occur twice in a row.
It is, for two reasons. First, as we detailed in our 2009 report – Energy Self-Reliant States – Ohio is like many states in having sufficient rooftop space for solar PV to supply 20 percent of the state’s electricity. There’s no shortage of sunshine.
Additionally, it’s far less expensive for the utility to buy solar than to pay the alternative compliance payment. In 2011, utilities must either acquire the necessary solar renewable energy credits (RECs) or pay $400 per megawatt-hour (MWh) that they fail to acquire.
However, a large-scale solar PV system in Ohio with an installed cost of $6 per Watt only needs 22.6 cents per kWh ($226 per MWh) to break even over 25 years (if they use federal incentives). With a long-term contract with a known price for solar RECs (something they have yet to offer), First Energy can surely find a solar developer willing to help them out.
After all, that’s exactly what other Ohio utilities are doing:
First Energy could have followed the example of AEP Ohio, a neighboring utility that has successfully entered into a long term PPA with a 10 MW solar farm and is in development for another 49 MW solar facility as we write. If AEP can do it, so can First Energy.
First Energy’s problems with solar have little to do with God or their state’s solar resources, and everything to do with giving up.
Community ownership may provide the solution for increasing resistance to wind power in the United States.
Wind power has expanded rapidly in recent years, but the new wind farms have a common characteristic: absentee ownership. These large wind farms promise a broad expansion of clean energy production, but not a commensurate expansion in local economic benefits. True, every wind power project will create some jobs and ripple effects in the local economy, but with absentee ownership most project benefits will leave the community (whereas locally owned projects have significantly higher rewards).
Without a say or stake in the turbines remaking their local skyline, communities have raised red flags. The result is more restrictive wind siting policies and opposition to new high-voltage transmission lines that may carry wind power from remote areas to major cities.
The wind industry’s initial reaction to local resistance seems to attempt an end-around, looking for states to pre-empt local siting authority and the federal government to pre-empt state transmission planning authority. Unsurprisingly, such moves win few friends for wind power.
There’s an alternative.
Some wind developers have learned that gaining local acceptance means rewarding not just the landowners who host project turbines, but neighbors who will also be affected by the turbines’ proximity. In the United Kingdom, state policy is requiring wind farms to pay into community funds (perhaps inappropriately, as a tool to offset severe budget cuts). But this policy has two drawbacks. For one, it only buys off the opposition, it doesn’t transform them into wind advocates. Second, it fails to take advantage of a community’s capital and the interest of residents in owning a stake in local wind power, rather than simply observing.
Community wind projects typically find a warmer welcome:
“In local communities, there’s been little to no opposition to wind projects,” said Eric Lantz, a wind policy analyst at the Renewable Energy Laboratory and a co-author of the study. “There’s more pride taken when you’re able to participate with an ownership stake.”
Community ownership not only eliminates most local opposition, but makes locals into stakeholders in the success of wind power. A new 25 megawatt wind project in southwestern Minnesota will feature significant community ownership. Just listen to the heartfelt pride in wind power from these members of a wind power cooperative in the United Kingdom:
Community wind projects are also more likely to reduce demand for long-distance transmission, because gaining local acceptance means wind farms can be built closer to cities and because communities lack the capital to build that largest-scale wind farms. This is a key issue, since there’s yet to be a community-owned transmission line.
While community wind could save the wind industry, it won’t be without some better rules. Community wind projects still require financial acrobatics, largely because the federal incentive for wind power (the Production Tax Credit) can only effectively be used by big banks and investment firms. And utilities tend to favor a few negotiations with large wind projects rather than many negotiations with smaller projects to meet their renewable energy obligations. Laws like Minnesota’s Community-Based Energy Development statute or CLEAN contracts can pave the way for more community-based wind projects.
Wind power is a key element of transforming our electricity system to clean energy and to combatting climate change. But it’s future may hinge on the willingness of the wind industry to embrace community ownership.