With the federal Energy Policy Act of 2005, Congress gave broad powers to the Department of Energy and the Federal Energy Regulatory Commission (FERC) to identify “congested” transmission corridors in order to prioritize new high-voltage transmission development and to provide higher financial returns to transmission development companies. The decision created a lot of controversy, since… Continue reading
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As long as the penetration of PV on the grid is low, the utility should have no trouble maintaining power quality as the output from PV systems fluctuate. However, even if overall PV penetration levels in a region are low, it is possible to have local “hot spots” where penetration on a single distribution circuit is very high. In this case utilities have concerns that power quality will suffer on that distribution circuit due to the high penetration of PV. [Kauai Island Utility Cooperative] KIUC is testing that hypothesis to the extreme with its 1.2 MW solar farm, by supplying 100% of a distribution circuit with PV during the day. [emphasis added]
Now for the good news: as the utility monitors the distribution circuit on sunny days and cloudy days, with the PV system turned on and the PV system turned off, they are seeing very little difference in the voltage levels, harmonics, and overall power quality between the different scenarios. These preliminary results suggest that utilities could go to very high levels of PV penetration in localized areas without causing problems for the grid. KIUC is continuing to monitor the system, but the initial results look very positive for the PV industry. [emphasis added]
A month ago, I compared the fuel cell Bloom Box to distributed solar PV. I’m not linking the posts, because I’ve updated my cost models for both technologies thanks to some good input from others. The revised analysis follows.
Update 3/15/11: The data in the text was accurate, but I had a labeling error in the chart. It’s fixed now.
The Bloom Box provides a plug-and-play approach to on-site electricity, using natural gas-powered fuel cells to provide stable, on-demand power. While it competes favorably with solar PV, its cost is competitive in just a few states with high electricity prices.
Bloom Box v. Grid
Only three states (New York, Connecticut, and Hawaii) have average retail electricity prices for the commercial sector higher than the break-even price (14.7 cents) for the Bloom Box’s electricity (with natural gas at $9 per million BTU), assuming the user is able to use federal tax incentives and accelerated depreciation. A number of states (including New York, New Jersey, and California) also have state rebates for fuel cells. The following map illustrates the states where the Bloom Box breakeven price is equal to or lower than the retail electricity price for commercial users. (In blue states, the Bloom Box competes with only federal incentives; in green states, it competes with additional state incentives.)
The number of states where Bloom Boxes would make economic sense would be higher, but a recent story from Greentech Media noting that the oft cited price for a Bloom Box ($700,000-800,000) was incorrect. Instead, the unit retails for $1,250,000 with a 10-year warranty, essential because the fuel cells will require replacement at least once in that span.
Bloom Box v. Distributed Solar PV
The Bloom Box performs well compared to distributed solar PV, especially in less sunny climates. At $5 per watt, a competitive price for commercial scale installations, solar PV in sunny Phoenix and Los Angeles costs 12.3 and 14.1 cents per kilowatt hour, respectively; in New York City, solar PV costs 17.5 cents. (all prices include federal tax and depreciation incentives). Six of the 16 largest metropolitan areas (with a cumulative population of 36 million) have solar PV prices lower than the Bloom Box price, although not by a lot.
The Bloom Box and solar differ in one significant way, however. The Bloom Box produces electricity on demand and round the clock, whereas a solar PV project only produces electricity during daylight hours.
When comparing the Bloom Box to a solar PV power plant with varying storage capacities, the Bloom Box is more cost-effective, even in sunny regions.
However, even this quantitative analysis leaves out a number of additional considerations: If the goal is to provide stable, baseload power, then the PV system would need longer storage (at least in winter months with fewer daylight hours). This is especially true if the power plant is an off-grid application.
If the goal is instead to offset grid electricity, especially peak power, then the PV system may make more sense. It produces power during peak hours (when prices are higher), and even a small amount of storage capacity would be sufficient to smooth out variability during the day (e.g. periods of clouds), as well as to extend production into the high-priced, late afternoon peak period.
Additionally, the operations cost for the Bloom Box will fluctuate with fuel prices, and there are more carbon emissions associated with a fuel cell operating on natural gas than with a solar PV array (zero).
Bloom Box Financing
Bloom is emulating the creative financing tools of the solar market with a power purchase alternative to buying the fuel cells. Businesses sign a 10-year power purchase agreement at a discount to their current electricity rates and Bloom handles installation, maintenance, fuel purchasing, etc. The service mimics a popular strategy for installing solar PV on residential and commercial rooftops. Bloom purportedly offers a 5 to 20 percent discount to California’s 14-cent per kilowatt-hour average commercial electricity price, so the power purchase arrangement would likely only work in states with comparable or higher electricity rates.
Overall, the “power-in-a-box” concept can serve commercial and industrial enterprises with round-the-clock power needs very well and it’s a promising start for distributed electricity production from fuel cells. As prices for both technologies fall, the Bloom Box fuel cell and solar PV power plant will be complementary components of a distributed grid.
Grid parity is an approaching target for distributed solar power, and can be helped along with smarter electricity pricing policy.
Consider a residential solar PV system installed in Los Angeles. A local buying group negotiated a price of $4.78 per Watt for the solar modules and installation, a price that averages out to 23.1 cents per kilowatt-hour over the 25 year life of the system.* With the federal tax credit, that cost drops to 17.9 cents. Since the average electricity price in Los Angeles is 11.5 cents (according to NREL’s PV Watts v2), solar doesn’t compete.
Or does it?
In Los Angeles, there are three sets of electricity prices. From October to May, all pricing plans have a flat rate per kWh and total consumption. During peak season (June to September), however, the utility offers two different pricing plans: time-of use pricing and tiered pricing. Time-of-use pricing offers lower rates – 10.8 cents – during late evening and early morning hours, but costs as much as 22 cents per kWh during peak hours. Prices fluctuate by the hour. Tiered pricing offers the same, flat rate at any hour of the day, but as total consumption increases the rate does as well. For monthly consumption of 350 kWh or less, the price is 13.2 cents. From 350 to 1,050 kWh, the price is 14.7 cents. Above 1,050 kWh, each unit of electricity costs 18.1 cents.
The following chart illustrates the difficulty in determining whether solar has reached “grid parity” (e.g. the same price as electricity from the grid). For some marginal prices, solar PV is cheaper than grid electricity when coupled with the federal tax credit.
Over the course of the year, solar is not less than grid electricity. A very rough calculation of the expected time of day production of a solar array in Los Angeles finds that the average value of a solar-produced kWh is 15.1 cents over a year. That suggests that solar power is not yet at grid parity, even with time-of-use pricing.
There are other considerations, as well.
For one, we ignored additional incentives for solar power, including federal accelerated depreciation (for commercially-owned systems) as well as state and utility incentive programs. These programs substitute taxpayer dollars for ratepayer ones, making the cost of solar to the grid lower.
We also didn’t confront the complicated issues involving a grid connected solar PV system. Net metering is the rule that governs on-site power generation and it allows self-generators to roll their electricity meter backward as they generate electricity, but there are limits. Users typically only get a credit for the energy charges on their bill, and not for fixed charges utilities apply to recover the costs of grid maintenance (and associated taxes and fees). Producing more than is consumed on-site can mean giving free electrons to the utility company. So even if a solar array could produce all the electricity consumed on-site, the billing arrangement would not allow the customer to zero out their electricity bill.
Where Can Distributed Solar Compete?
Based on our own analysis, solar PV at $5 per Watt (with solely the federal tax credit) could not match average grid electricity prices in any of the sixteen largest metropolitan areas in the United States. With accelerated depreciation – an incentive only available to commercial operations – solar PV in San Francisco and Los Angeles (representing 21 million Americans) could compete with average grid prices near $4 per Watt installed cost.
Under a time-of-use pricing plan (where prices could be 30% higher during solar hours, as in Los Angeles), 40 million Americans would live in regions where solar PV could compete with grid prices at $5 per Watt with both federal incentives.
With solar at $4 per Watt, Californians would only need the tax credit (not depreciation) for grid parity with time-of-use rates. Adding in the depreciation bonus would increase the number to over 62 million Americans.
Distributed solar is nearing a cost-effectiveness threshold, when it will suddenly become an economic opportunity for millions of Americans.
*Note: for regular readers, we changed and improved our levelized price model (in response to some comments on our cross-post to Renewable Energy World).
Craig Morris has a thorough discussion of why feed-in tariffs (CLEAN Contracts) and other renewable energy policies are still necessary even when renewables get to grid parity. It’s a direct response to an earlier piece on Renewable Energy World claiming that the best strategy for solar is to get off incentives.
First, he notes that there’s a pervasive myth that feed-in tariffs have failed:
In fact, every gigawatt market in the world for PV was driven by feed-in tariffs. Mints is right that some of these markets have gone bust, but do the other markets (like Germany) that haven’t gone bust not show us how to do it right? I can’t say that of other PV policies (think of the US or pre-FIT Britain).
Can we agree that solar feed-in tariffs have not failed in “most” countries – and that no non-solar FIT market has undergone boom-and-bust anywhere? A more accurate description would be that feed-in tariffs are the only policy that has led to major success stories for solar, but that some incompetent governments threw in the towel when they saw the price tag.
Morris also notes that the price tag is another myth – feed-in tariffs are a less expensive policy tool than most others:
Mints writes, “Here’s the golden rule of incentives: they are expensive, and someone has to pay the bill.” Actually, it’s photovoltaics that’s expensive, not feed-in tariffs. Studies have repeatedly found that feed-in tariffs are the least expensive way to promote renewables.
The bigger issue is that getting to grid parity is not an end in itself:
FITs for wind and biomass have generally always been below the retail power rate, so why should anything change when solar is no longer the exception? As Mints herself points out, conventional energy sectors also continue to be subsidized. Why should the situation ever be any different for photovoltaics?
Morris goes on to describe how solar below the retail rate will create a massive rush to solar that will actually make electricity more expensive (as solar installers take a larger cut of the favorable economics and increased solar capacity scales down baseload fossil fuel power plants during peak hours). Instead:
But what we probably need over the long run are feed-in tariffs that pay for power production from intermittent sources (especially solar and wind) with a fluctuating premium based on power demand; when renewable power production approaches or exceeds demand too often, the premium will not be paid, and investments in such technologies will not pay for themselves as quickly. The floating cap will find itself, so to speak.
The Germans have already adopted such a policy, called “own generation“. And a few U.S. states – where solar is already cheaper than peak electricity prices – will need a similar policy innovation.
Photo credit: David Parsons (NREL PIX)
A new report about electric grid deregulation in Texas shows (yet again) that deregulation of electricity leads to much higher ratepayer costs:
In 2009, the report found 93 percent of Texans served by deregulated electric companies were charged above the national average. By comparison, 81 percent of customers outside deregulation paid less.
A 2007 story in USA Today examined state electricity deregulation policies and also found that they hadn’t ended well for ratepayers:
While average prices rose 21% in regulated states from 2002 to 2006, they leapt 36% in deregulated states where rate caps expired, according to a study by Ken Rose, senior fellow at the Institute of Public Utilities at Michigan State University.
Texas apparently didn’t learn the lesson from its hometown team and deregulation poster boy – Enron – which manipulated California’s deregulated market to precipitate the 2000-01 California electricity crisis.
Updated 3 PM: Preliminary numbers had suggested that Southern California Edison’s distributed rooftop solar PV purchase would be among the most cost-effective solar projects in the world, and data released yesterday confirmed that:
Southern California Edison has selected 250 MW worth of solar bids from companies able to produce solar electricity for 20 years for less money annually than the 20 year levelized cost of energy of a combined-cycle natural gas turbine power plant.
SCE’s bidding process for smaller renewable projects is smart. These small projects do not face the multi-year bureaucratic delays for extensive reviews, like most utility-scale solar, so each small unit can be built as quickly as normal commercial rooftop solar projects. They are made up of multiple distributed solar installations of under 20 MW, which in combination total a power plant-sized 250 MW.
…The requirement is that the renewable energy has to be priced to cost no more than the Market Price Referent (MPR) – which is an annual calculation of the 20 year levelized cost of energy of a combined cycle gas turbine.
The MPR has recently been around 11 cents per kilowatt-hour, so the solar PV projects will produce electricity for less than the retail rate in southern California. There’s indication of enormous distributed PV demand, because SCE received bids for up to 2,500 MW of projects, but only accepted 250 MW.
Can a state with a renewable energy mandate require green jobs to stay at home? Litigation has made states into tepid defenders of their job rights, but states have the legal ground to go great lengths to keep more of the economic development from their renewable energy industry inside their borders.
No renewable energy mandate passed a state legislature without the promise of thousands of new jobs, but many states have shared the recent experience of Massachusetts: the state’s largest solar manufacturing plant announced that it is moving production to China. Evergreen Solar is moving despite the state’s commitment of $44 million in subsidies to support the plant and its manufacturing jobs. The state is losing out on manufacturing jobs despite its citizens’ commitment to (if necessary) pay more for electricity from renewable sources.
In contrast, last week I wrote about Ontario’s clean energy program, well on its way to 5,000 megawatts of new renewable energy production and supporting over 40,000 new jobs. Over 20 new manufacturing plants have been announced. The keystone of this program is a ‘buy local’ rule that requires wind and solar power projects who want the province’s attractive power payments to be constructed with at least 60 percent of their materials ‘made in Ontario.’ Ontarians are getting cleaner electricity and significant economic development for their clean energy commitment.
U.S. states can do much more to secure the economic benefits of their clean energy mandates, even if they can’t copy Ontario’s law verbatim (see our recent report on Ontario’s program for more on the international trade controversy).
Traditionally, U.S. states have limited their economic development policy to subsidy programs, offering grants, loans, and tax breaks to manufacturers to locate within the state. Businesses let states bid against one another for scarce jobs. The result is a repeat of Massachusetts’ experience with Evergreen Solar. Manufacturers accept subsidies and then leave when it suits their bottom line.
Some states have tried more. Ohio and Illinois require part of their renewable energy standard to be meet with in-state projects. Other states provide greater credit toward compliance with their renewable energy standard for in-state projects. One state, Washington, offers multipliers to a state tax credit for projects with “made in Washington” parts.
Massachusetts tried to require its utilities to sign long-term contracts with in-state renewable energy suppliers, but the state backed down in the face of a lawsuit from renewable energy supplier TransCanada.
No state has gone as far as Ontario to require local purchasing of components, partly because more robust policies to require in-state development have often been threatened with lawsuits under the Supreme Court’s Dormant Commerce Clause.
The linchpin to a commerce clause dispute is whether the law in question discriminates against out-of-state economic interests and, in particular, whether it burdens them while benefitting in-state interests. Enacted in a U.S. state, Ontario’s buy local requirement would likely trigger than discrimination clause, requiring the state to prove that the law “advances a legitimate local purpose that cannot be adequately served by reasonable nondiscriminatory alternatives.” (Source: Richard Lehfeldt, Woody N. Peterson, and David T. Schur. Commerce Clause Conflict. (Public Utilities Fortnightly, December 2010)). Success in this situation is rare, and yet clean energy economic development may meet the requirements. A recent article in Public Utilities Fortnightly magazine on the Massachusetts case highlights how states could move beyond jobs subsidies:
First, be explicit about the incentives being offered for in-state investment. In particular, “The opportunity to enter into a long-term PPA should be one of the benefits offered to successful bidders as part of the state’s development initiative, not the starting point.” In fact, the article notes, this is exactly what happens in regulated electricity markets, where the state provides a utility franchise and the exclusive right to build and rate-base new power generation. The PPA follows from the commitment to local development.
The state must also be explicit about the functional difference between a power plant developed in-state as opposed to out-of-state, with specifics about the technology and the site. For example, redeveloping a brownfield site in state is much more valuable than simply importing clean electricity.
Finally, states have legitimate environmental objectives for in-state power generation. “A state that seeks new in-state renewable power plants may increase its reserve margins, improve its air quality, displace fossil-fuel based generation, avoid transmission congestion charges that may apply, and may also avoid or defer the need to build new transmission lines.” All of these are “legitimate local purpose[s] that cannot be adequately served by reasonable nondiscriminatory alternatives.”
In other words, under the strict discrimination clause there is room for states to favor local development. But there are also several nondiscriminatory strategies that can also pass legal muster.
States that favor in-state production without placing an “excessive burden” on out-of state entities have nondiscriminatory policies. There are several illustrations of this at work. In Minnesota, an ethanol producer incentive provided 15 cents per gallon of ethanol produced in-state and nothing for out-of-state suppliers, who were still allowed to sell in Minnesota. The state of Washington provides a significant multiplier to its solar PV incentives for domestically produced inverters and solar modules.
If U.S. states fear the legal conflict over a discriminatory clean energy policy, they could instead emulate Turkey. Turkey provides renewable energy producers a standard offer, long-term CLEAN contract for anyone who builds in the country, but they provide bonus payments for renewable energy projects that are “made in Turkey.” These payments increase the per kWh contract anywhere from 32% to 146%, depending on the renewable technology.
Over thirty states have committed themselves to renewable energy and potentially higher electricity costs. In exchange, states should consider their legal authority to keep those jobs within state borders and to the economic advantage of its citizens.
Overruling a utility challenge, the Federal Energy Regulatory Commission (FERC) affirmed today that states have the right to set prices for mandated renewable energy purchases and that these prices may vary by technology:
“[W]here a state requires a utility to procure energy from generators with certain characteristics,” the state may set the wholesale rate (known as ‘avoided cost’) for that specific type of energy. Id. at para. 30. Therefore, a state can require utilities to purchase electricity generated from differentiated technologies (wind, solar, wave, etc.) and set the rate for purchases from each of these generators.
Photo credit: Flickr user KeithBurtis
The batteries and the solar cells themselves are something like shock absorbers for the grid. If drivers want to charge up their cars during peak periods on the grid, the charging station’s batteries will meet part of that demand so that the impact on the grid is milder. Likewise, the solar cells will chip in with some energy, lessening the load on the grid.
“If with new technologies we can control these resources on the distribution side, we can eliminate the need for potentially very expensive upgrades to the distribution system,” said James A. Ellis, the senior manager for transportation and infrastructure at the T.V.A.’s Technology Innovation Organization.