New York State is focusing on Extended Producer responsibility to get materials out of the waste stream. But the state is ignoring the most obvious way to reach high rates of diversion, eliminate incineration of garbage. Continue reading
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A recent study in the journal Safety Science suggested that the most vulnerable parts of the grid were the smallest, like neighborhood substations.
“That’s a bunch of hooey,” says Seth Blumsack, Hines’s colleague at Penn State.
Hines and Blumsack’s recent study, published in the journal Chaos on Sept. 28, found just the opposite. Drawing on real-world data from the Eastern U.S. power grid and accounting for the two most important laws of physics governing the flow of electricity, they show that “the most vulnerable locations are the ones that have most flow through them,” Hines says. Think highly connected transformers and major power-generating stations. Score one point for common sense.
And score one point for distributed generation.
Unlike many cities, Portland, Maine, has forged ahead with a significant energy efficiency plan without federal stimulus dollars. Simply borrowing money through bonding to investing in energy saving improvements, the city will – over 20 years – reduce operating costs by $700,000 per year and shrink its carbon footprint by 30 percent.
PORTLAND — The City Council agreed Monday night to borrow as much as $11 million for energy improvement projects in 30 municipal and 15 school buildings throughout Portland…Councilor David Marshall said the energy conservation measures will enable the city to reduce its carbon footprint by more than 30 percent.
…Ameresco [a Massachusetts-based consulting firm] has said that the projects will save about $700,000 a year in utility costs, and by the end of the 20-year bond period will pay back the cost of the work and interest on the bond.
In by far the most exhaustive and detailed study to date, the National Renewable Energy Laboratory (NREL) found that solar homes sold 20% faster, for 17% more than the equivalent non-solar homes, across several subdivisions built by different California builders.
The study looked at a number of housing developments where the homes were otherwise identical except for the solar energy systems.
Also interesting was that buyers were more interested in solar when it was-preinstalled:
If solar was already on the house, and factored into the price already, buyers were more likely to pick a house with solar. But if it was just one more decision to be made at the point of purchase, the decision got shelved.
I heard this week that foundations collectively spent as much as $300 million in the failed attempt to pass comprehensive climate legislation during the last session in Congress. Someone sarcastically remarked that we should have just burned the money for energy instead.
But would it have been worth it? A short analysis follows:
Assume that the $300 million was dispersed in $1 bills. Each dollar bill weighs 1 gram and is 75% cotton and 25% linen. Finding the energy content of a dollar was not easy (even though many conservatives accuse government of spending money on worthless research, apparently no one is literally burning through cash). As a substitute, we used the figure of 7,500 Btu per pound for cotton linters.
Our $300 million equals 300 million grams of dollars, which is 660,800 pounds of dollars, or 330 tons.
At 7,500 Btu per pound, burning $300 million nets us 4.96 billion Btus. And at 3,413 Btus per kilowatt-hour (generously assuming 100% conversion efficiency compared to typical power plant efficiencies of 30-35%), we get 1.45 million kilowatt-hours of electricity. It’s net-zero carbon dioxide emissions, because during its growth, the cotton plant took up all the carbon dioxide emitted during combustion. For comparison, 1.45 million kWhs from coal-fired electricity emits about 1,450 tons of carbon dioxide.
So, if we burn $300 million for electricity instead of passing climate legislation…
- …we can power 145 homes for a year (at 10,000 kWh per year)
- …offset 1,315 tonnes of carbon dioxide (0.00002% of annual U.S. emissions)…
- …at a cost of $228,000 per ton.
Conservatives take note: it’s far cheaper to get carbon dioxide emission reductions (under $100 per ton!) to pass comprehensive climate legislation than to burn $300 million.
Update: this analysis is not meant to imply that we shouldn’t fight for climate policy, but that the failure (like burning the money) is costly.
It’s been a common argument against feed-in tariffs that federal law preempts states from establishing prices for renewable energy above the utility’s avoided cost (a figure meant to represent what it what otherwise cost the utility to get the same amount of electricity from another source, typically a natural gas-fired power plant). The FERC ruling in mid-October changes everything, allowing states to set the avoided cost rate based on the renewable energy technology in question.
From the ruling, as shown on wind-works.org:
“. . . Avoided cost rates may also ‘differentiate among qualifying facilities using various technologies on the basis of the supply characteristics of the different technologies’. . .”
“. . . We find that the concept of a multi-tiered avoided cost rate structure can be consistent with the avoided cost rate requirements set forth in PURPA and our regulations. Both section 210 of PURPA and our regulations define avoided costs in terms of costs that the electric utility avoids by virtue of purchasing from the QF. The question, then, is what costs the electric utility is avoiding. Under the Commission’s regulations, a state may determine that capacity is being avoided, and so may rely on the cost of such avoided capacity to determine the avoided cost rate. Further, in determining the avoided cost rate, just as a state may take into account the cost of the next marginal unit of generation, so as well the state may take into account obligations imposed by the state that, for example, utilities purchase energy from particular sources of energy or for a long duration.51 Therefore, the CPUC may take into account actual procurement requirements, and resulting costs, imposed on utilities in California. . .” [emphasis added]
The FERC ruling does specify one difference between a U.S. state-based FIT and those in Europe or Ontario – the state must specify the amount of each renewable energy technology it wants, as well as the price (e.g. 100 megawatts of solar PV that is under 10 kilowatts).
There’s also a very nice, plain English explanation of the impact of the FERC ruling from Jen Gleason at Environmental Law Alliance Worldwide.
When we released our report on community solar power last month, we expected a few comments on the grades we gave to the nine featured community solar projects. We also generated a really robust conversation about the location (on buildings or on the ground) of community solar PV projects and made a disheartening discovery about the cost of roof repairs when a solar PV array is present.
In the report, our criteria for solar PV location gave high marks for rooftop solar PV systems because of their use of existing infrastructure, lower marks for ground-mounted systems in brownfields, and the lowest grades for greenfield systems. In one particular case, we gave a ‘C’ grade to the Clean Energy Collective’s project because while it used otherwise unusable land near a sewage treatment plant, it was still ground-mounted.
The response to their ‘C’ grade made us re-evaluate our grading system. On reflection, there are three major considerations for the location of a community solar (or any distributed renewable energy) project.
Location Criteria for Community Solar
- Preservation of Open Space
- Use of Existing Grid Infrastructure
- Lifetime Cost for Participants
The open space issue cannot be ignored, as demonstrated by the opposition to centralized concentrating solar thermal power and solar PV power plants in the Mojave Desert and San Luis Valley in Colorado. Projects that use rooftops will rarely encounter resistance on environmental grounds (although there can be issues with historic districts). From the perspective of open space, there is still a higher value in a rooftop project than a ground-mounted one.
Existing Grid Infrastructure
The issue of existing grid infrastructure is not as clear cut. In general, distributed solar PV projects minimize the need for new grid infrastructure by plugging into the grid at low voltages and in a variety of places.
Rooftop solar would seem to have an advantage in this. With few exceptions, a rooftop solar PV system can easily interconnect through the building’s grid connection. A rooftop solar PV system doesn’t change the capacity required by the local grid connection because net metering limits typically mean that no one installs a system that produces more than the building consumers.
But our error was to assume that ground-mounted systems would not take advantage of existing infrastructure, as well. In fact, the Clean Energy Collective solar project connects to existing infrastructure at an adjacent sewage treatment plant. Several other community solar projects in the report were constructed by utilities and presumably built next to existing substations where the new generation could easily be absorbed into the local grid. In other words, we should have graded this location criteria separately from the open space issue.
The third issue – and one we’d never considered – is that rooftop PV systems may have to be removed and reinstalled if the roof needs replacement or repairs. While PV systems typically lose a small portion of their potential output (< 1%) each year, the systems can operate for decades, far longer than the typical residential or commercial roof (20-25 years in Minnesota). In other words, there’s likely to be one roof replacement during the life of a PV system.
Reinstalling a residential rooftop PV system could cost $6,250 or 25% of the installed cost of the system
In our investigation, we found that moving residential PV systems to accommodate a roof replacement could cost as much as 25% of the initial system cost (and over 35% of the net cost after the application of the 30% federal tax credit). Moving systems on a commercial roof was less expensive, on the order of 15% of initial installed cost (around 25% of the system cost after the tax credit).
The following chart illustrates the range of costs we found relative to an initial installed cost of $5.00 per Watt for commercial and residential PV systems.
But this chart is somewhat disingenuous, because solar PV owners never pay the full installed cost. Instead, there are a slew of tax credits and rebates that reduce this initial price. The next chart shows these roof repair reinstallation costs relative to the net cost after the 30% federal tax credit.
The cost issue is also complicated by various ownership arrangements. If the building owner also owns the array, the cost of moving the PV system is their responsibility. But what if they lease the solar array? Does the leasing company bear the cost of system safety when the roof is repaired or replaced or is it still the responsibility of the building owner? Will that cost be assessed when the roof is repaired or escrowed from the start of the project?
A CEC representative noted, “I guarantee you that a building owner (lessee) will never sign a long term lease that requires them to pay the costs of reinstalling a system after roof repairs, etc.” If CEC’s recently completed 77 kW community solar array had been built on a rooftop and required a move, the cost to its individual investors would likely be around $2,000, increasing the upfront cost for those individuals by nearly 30%. In addition, CEC couldn’t have offered the utility or its customers a 50-year service level agreement.
Conclusion: Location is Complicated
Obviously, there’s much more to the ground v. rooftop issue than meets the eye, from interconnections to roof repairs. Look for a transformation in our Community Solar Report in the next few weeks reflecting on this complex issue.
This initiative was announced in September 2009 with the goal of using 100,000 household-sized combined-heat-and-power gas units to provide grid electricity and home heat. The units would provide enough power to supplant two nuclear power plants. The video about the project was released (in English) just recently:
Traditionally, the reliability of small PV systems’ power output has been a concern for utilities, project developers and grid operators, since all it takes is a few clouds to disrupt the power flow of a small array. But the Berkeley Lab study suggests that when PV plant arrays are spread out over a geographic area, the variability in power output is largely eliminated.
This means that for utilities, the distributed generation of small PV arrays could mean increased efficiency, reduced costs and a quicker path to a cleaner energy portfolio.
There’s been much discussion of whether state-based feed-in tariff policies comply with federal energy law, including PURPA and the Federal Power Act. Fortunately, the brilliant folks at NREL released a report earlier this year providing feed-in tariff policy design options for state policy makers [pdf]. Furthermore, the state of Vermont recently affirmed that their feed-in tariff policy conforms to federal law.
The PSB, the regulatory authority, ruled that no challenger, including DPS, had “demonstrated that the standard offer program is invalid”. Under Vermont law, the PSB has the “obligation to implement statutes passed by the legislature,” it said, and, thus, it was their duty to do so if the law is valid.
Some challengers suggested that the PSB suspend the program while it seeks clarification from FERC. The PSB ruled definitively saying that to seek clarification from FERC; the PSB would be making a determination that the program is invalid. The program is valid, says the PSB, therefore there’s no need to seek clarification.
Good news for a policy that delivers strong support for distributed renewable energy generation.