Property Assessed Clean Energy (PACE) financing, a promising tool to advance energy efficiency, was blocked nationwide by the opposition of the Federal Housing Finance Agency. In this post we get a status report from Renewable Funding’s, Cisco DeVries, on what’s happening in the courts with various parties suing the FHFA. He also gives us an update on what’s happening on the on the ground with PACE financing for the commercial sector which is alive and expanding.
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Before the holidays we posted a chart illustrating the average cost of solar by state, highlighting Minnesota’s claim to the most expensive solar PV in the nation. The data came from the brilliant report, Tracking the Sun III: The Installed Cost of Photovoltaics in the U.S. from 1998-2009 (large pdf).
But are solar costs high in some states simply because the market is small? The answer seems to be no.
The following chart illustrates the average cost of solar PV by state, mapped against the total installed capacity (in megawatts) from 2007-09. California is omitted because its 1600 MW of new capacity dwarfs other state markets; Colorado, Hawaii, and North Carolina were not included in the original dataset. The markers for Oregon and Connecticut were shaded blue and red, respectively, to help distinguish them from surrounding states.
What’s clear from the data is that there seems to be little relationship between market size and average installed costs. Texas installed 16 MW at an average cost of $7.00 over the three years analyzed, whereas New York and Nevada had costs 25% higher in markets five times the size. And five states with markets 10 MW and smaller had costs ranging from $7.60 (New Hampshire) to $9.10 per Watt (Minnesota). The largest markets in New Jersey and California tie for 5th lowest cost, 10% more expensive than the least expensive market despite being (in California’s case) two orders of magnitude larger.
The data leave a lot of questions. Why don’t larger markets uniformly have lower prices? Why is there such large variation in costs in smaller solar market states? And how does state solar policy matter, when there is no correlation between the total value of state incentives and the before-incentive installed cost of solar?
Update 1/20/11: a cacophony of different permitting rules may be partially responsible. The solar industry estimates that permitting costs add $2,500 to each solar installation.
Southern California Edison recently canceled a 663 MW power purchase agreement for a Stirling dish powered concentrating solar power plant. It’s the latest blow for centralized solar as the economics have continued to favor decentralized solar. There were other issues, too:
Stirling and Tessera…also needed millions in equity investments and big honking loans from the government and others.
When modular, decentralized solar PV is easy to finance and less expensive than centralized solar thermal electricity, the decentralized power is going to win.
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In a potentially precedent-setting move for the English-speaking world, Great Britain’s ruling coalition proposes abandoning its long-running experiment with so-called “market reforms” of the 1990s. Included in the proposal released by Chris Huhne, Energy and Climate Change Secretary December 16, 2010, is wholesale revision of the country’s Renewable Obligation, the British version of Renewable Portfolio Standards (RPS).
While the renewable targets will remain, the government proposes abandoning the mechanism for reaching the targets, the Renewables Obligation (RO). Instead the coalition government of the Conservative and Liberal parties proposes implementing a system of feed-in tariffs for “low carbon generation”.
The California Public Utility Commission officially launched its Renewable Auction Mechanism (RAM)* last week, to spur more development in renewable energy projects smaller than 20 megawatts.
The good and bad news is summarized quite well by the FIT Coalition, with the good news being:
- A strong focus on the < 20 MW market segment, also known as Wholesale Distributed Generation if the project connects to the distribution grid.
- Recognizes value of “locational benefits,” rewarding projects that site close to load to avoid unnecessary transmission expenditures – “(massive capital expenditures, decade-long build-outs, and significant line and congestion loses)”
- Requires utilities to provide specific grid details to help developers select project sites before they commit.
Points 1 and 2 highlight an increasingly recognized issue: meeting the near-term benchmarks in state renewable energy standards may be impossible if states rely on centralized, transmission-dependent projects. Sub-20-megawatt projects can quickly sum to large quantities of renewable energy, capture most economies of scale, and come online much faster that large, centralized projects.
Point 3 is huge, as well, because it finally addresses a market failure where distributed energy project developers could not get information about grid “sweet spots” for plugging in smaller scale renewable energy without significant infrastructure upgrades. It’s an issue too rarely discussed, with a rare exception being our 2008 report on Minnesota’s potential to meet its state RPS without significant new high-voltage transmission lines (backed by two state-sponsored studies).
The bad news is that the CPUC missed several opportunities to maximize the potential for distributed generation:
- It allows participation by transmission-connected projects, which will not carry the same advantages as distribution-connected projects – “producing energy close to load and avoiding the significant costs, timeframes, and environmental issues associated with transmission.”
- It institutes a lop-sided playing field that will favor well-established companies and larger projects.
- It perpetuates the high failure rate of solicitation programs: “In general, California’s solicitation-based RPS programs result in more than 95% of the bid capacity to be rejected by the utilities or to be abandoned by developers in the end due to underbidding.” These rejections lead to enormous stranded development costs, as much as $100 million in one solicitation.
Despite the bad news, it’s a promising “pilot” program that will support 1 gigawatt of distributed renewable energy. Let’s hope it improves with time.
*And folks suggest feed-in tariff is a lousy policy name…Speaking of which, a number of media stories indicate that this is California’s take on a “feed-in tariff.” That’s like saying like soccer is Europe’s take on American football. One is an auction, the other is a standard contract with prices based on the cost of generation.
Photo credit: alforque on Flickr
There’s no better illustration of the value of distributed renewable energy than the U.S. military. In Iraq, the 50,000 U.S. troops (as of August 2010) use 600 million gallons of fuel per year at a cost of dozens of lives of U.S. soldiers who die protecting fuel convoys and financial cost of nearly $27 billion for fuel and security ($45 per gallon!). New distributed renewable energy systems can help combat brigades reduce fuel consumption, saving lives and money.
One Marine company – Company I, Third Battalion, Fifth Marines – field-tested the Ground Renewable Expeditionary ENergy System (GREENS) system in August 2010 and found that it saved 8 gallons of fuel per day for each of the company’s 150 men. Complemented with other renewable energy systems, the Marines powered their combat operations center without using the diesel generator for eight days.
The renewable technology that will power Company I costs about $50,000 to $70,000; a single diesel generator costs several thousand dollars. But when it costs hundreds of dollars to get each gallon of traditional fuel to base camps in Afghanistan, the investment is quickly defrayed.”
It takes approximately 200 GREENS (1,600 kilowatts of solar modules with battery storage for 300 Watts of continuous power) to replace a single 60 kilowatt diesel generator, but it saved the Marine company 1,200 gallons of fuel per day. In Iraq, that fuel would have cost $45 per gallon, including transportation and security costs. That’s a savings of $54,000 in a single day. If priced at $70,000 each, the 200 GREENS will pay back in 260 days, less than 9 months.
If every U.S. company serving in Iraq made use of GREENS, it would reduce fuel consumption by U.S. troops by 25%, saving 146 million gallons of fuel and $6.5 billion per year.
There are benefits besides saved fuel and money. Marines appreciated that the solar-powered base systems are quiet, and also don’t require constant refueling. The no-fuel requirement also benefits security, as 72 U.S. soldiers died protecting convoys in Iraq in 2009.
The military provides a great illustration of the utility and cost-effectiveness of distributed generation, and one that should inform state-side strategies for energy deployment.
Last week was a tough one for distributed solar markets in several states, as a remarkable number of renewable energy incentive programs hit their budget or capacity caps, or are shrinking in scope: San Diego Gas & Electric’s allocation of non-residential solar incentives under the California Solar Initiative ran out. The Los Angeles municipal utility… Continue reading
From page 19 of the brilliant report, Tracking the Sun III: The Installed Cost of Photovoltaics in the U.S. from 1998-2009 (large pdf).
It’s worth noting that this has nothing to do with the state’s solar resources. This is the upfront cost to install the modules. The difference in cost of solar electricity is likely even more severe since many of the least expensive states also have better sun.