Despite widespread rumors in North America that Germany was abandoning its system of Advanced Renewable Tariffs, the country’s upper chamber of parliament, the Bundesrat, approved the latest revision of its pioneering Renewable Energy Sources Act [PDF] on July 8, 2011.

The action follows approval by Germany’s House of Commons, the Bundestag, on June 30, 2011.

The new version of the law first introduced in Germany in 2000 will go into effect Jan. 1, 2012.

Approval of the latest revisions of the Renewable Energy Sources Act, the Erneuerbare-Energien-Gesetz (EEG) in German, is significant because it follows the nuclear accident at Fukishima, Japan and the debate in Germany about the future of nuclear power.

The 30-year long debate on nuclear in Germany was settled earlier this summer when parliament decisively voted to quit nuclear power by 2022.

Germany is currently ruled by a coalition of the Conservative (CDU/CSU), and the neoliberal (FDP) parties.

Thus, the vote on revisions to the Renewable Energy Sources Act for 2012 follows the decision to quit nuclear power and further expand the role of renewable energy in the electricity sector.

The revisions for 2012 were part of regularly scheduled periodic revisions. Previous revisions occurred in 2004 and 2009.

The 2012 EEG sets a minimum requirement of not less than 35 percent of renewable energy in electricity supply by 2020, not less than 50 percent by 2030 and not less than 65 percent by 2040 and not less than 80 percent by 2050.

However, the law actually sets a target of between 35 and 40 percent of supply within the next decade. This conforms to a decision made by the Ministry of Environment in 2010. See “Germany Ups Renewable Target — Again.”

Rather than reducing its commitment to expanding renewable energy, Germany has codified a more aggressive target than in the previous law.

Final interpretation of the complex 204-page law will be issued by the Ministry of the Environment, the BMU, later this summer.

Some key provisions of the 2012 EEG include

• Raising biomass tariffs nearly 30 percent from €0.11/kWh ($0.16/kWh) to €0.14/kWh ($0.20/kWh) for plants less than 150 kW in size.
• Increasing geothermal tariffs more than 50 percent from €0.16/kWh ($0.22/kWh) for small projects to €0.25/kWh ($0.36/kWh) for all projects.
• Increasing offshore wind tariffs 15 percent from €0.13/kWh ($0.19/kWh) to €0.15/kWh ($0.21/kWh).
• Increasing the “starter” bonus for offshore wind nearly 25 percent from €0.15/kWh ($0.21/kWh) to €0.19/kWh ($0.27/kWh).
• Maintaining the 2011 degression for solar photovoltaics (solar PV) into 2012.
• Maintaining the tariffs for wind energy on land, including the repowering bonus.

Significantly, parliament again stated its support for the rapid development of solar PV in Germany. The 2012 EEG continued the current policy of regulating solar PV development within a “growth corridor” of 3,500 MW per year.

If Germany maintains growth of solar PV of 3,500 MW per year it will remain the world’s largest solar market for the foreseeable future. Both the government and the industry expect solar PV capacity to exceed 50,000 MW by 2020.

Solar PV growth will be regulated by adjustments in the annual degression rate of 9 percent. If the growth exceeds the target, the degression is increased. If growth is less than the target, the degression is decreased.

In addition, the 2012 EEG continues the German reference yield system for wind energy both on shore and off shore. The system is designed to ensure that not only wind energy at windy sites can be developed but also wind energy at less windy sites as well. The system has proven successful. Today, nearly 60 percent of all wind energy in Germany is developed in the less windy interior of the country, taking development pressure off the windy North Sea cost.

See “Tables of Feed-In Tariffs Worldwide” for details on the 2012 EEG as well as updated feed-in tariffs on Britain’s Renewable Heat Incentive.

When it comes to certain things — luxury cars, beer, chocolate — we should just acknowledge that the Germans did it better than us first. This teutonic skill extends to solar power, where a tariff system ensures Germans pay less for solar energy than we do. But that doesn’t mean we can’t copy them, and if we do, comparatively sunny places like California stand to gain even more than cloudy Deutschland.

Newly installed solar photovoltaic (PV) projects in California were paid an average of approximately $0.34 per kilowatt-hour (kWh) last year, according to a privately commissioned study. Germans paid substantially less, taking into consideration the amount of solar energy their country receives.

Germans paid an average of $0.38/kWh for the first six months of 2011, according to data from the country’s grid manager, the Bundesnetzagentur.

If the Golden State applied German feed-in tariffs to solar PV under its bright, clear sky, Californians would only pay the equivalent of $0.24/kWh.

Data on the cost of German feed-in tariffs is from publicly available sources and is adjusted for California’s sunnier climate relative to cloudy Germany.

Unfortunately, data on the total cost of solar PV in California is more difficult to analyze, as it derives from numerous sources.

The study on California’s solar program, by private consultant Robert Freehling, examined the cost of the California Solar Initiative, federal tax credits, depreciation deductions, and the value of electricity offset from net-metering. Freehling is an expert in the arcane world of California renewable energy policy.

California Solar Initiative

The California Solar Initiative (CSI) is one of the state’s premier renewable energy programs, even though it only governs solar PV. CSI issues an up-front payment, or “rebate,” for residential solar systems and a payment per kWh for commercial systems, from a pool of money collected from ratepayers. The CSI funds are being rapidly depleted and in 2011, most of the funds for the program will be exhausted.

Because payments under the CSI, federal tax credits, and depreciation deductions necessary for investments in solar PV in the U.S. are all of short duration, it was necessary for Freehling to prorate these benefits over the typical 20-year life of a solar system. Only by prorating these benefits over 20 years and including the value of the electricity offset from net-metering was he able to estimate the total cost of electricity per kWh.

The average value of rebates under the CSI program in 2010 was $0.058/kWh. Residential customers were paid the least. They received $0.05/kWh while non-governmental and governmental organizations received as much as $0.09/kWh.

One unique feature of the CSI program, unlike many other such programs in the U.S., is that it makes special provisions for nonprofits and governmental agencies.

Nontaxable entities cannot use the 30 percent federal tax credits. Accordingly, the CSI issues a higher payment for nonprofits and governmental agencies to compensate for their inability to use the federal tax credits.

However, Freehling concluded that “in 2010 the benefit of this higher rebate was lost due to the higher price paid for solar projects by government and nonprofit entities.”

Federal subsidies

In addition to the CSI, a state program, residential and commercial solar projects in California qualify for federal tax credits and depreciation deductions. The costs of these subsidies are borne by all U.S. taxpayers, not just those living in California.

Last year, the value of the 30 percent federal tax credit was as high as $0.096/kWh for residential customers and $0.071/kWh for commercial customers, according to Freehling’s study. Nonprofits and other nontaxable entities received no benefit from the federal tax credit.

Freehling estimated that commercial projects received an additional benefit worth $0.07/kWh from accelerated depreciation.

Net-metering value

Net-metering is not a direct payment, nor is it a tax deduction. Net-metering is the ability to offset electricity consumption. Its value is that of the electricity offset.

The value of being able to “spin your meter backwards” varies widely across the state and by customer.

California is among the few states that use a “reverse block” rate structure that requires consumers to pay a higher price per kilowatt-hour the more electricity they consume. Many states and Canadian provinces use the archaic “declining block” rate structure that charges less per kilowatt-hour the more electricity a customer consumes.

Thus, in California, the value of net-metering is much higher for “energy hogs” who use the most electricity, and least to frugal consumers who conserve electricity. The value, reported Freehling, can vary from a low of $0.08/kWh for low-income consumers to as much as $0.38/kWh for those using the most electricity. The average value of net-metering across the state was substantial — $0.18/kWh — accounting for more than half of overall payments.

“Frugal customers that only pay 12 cents/kWh for all their electricity,” said Freehling, “will get little benefit from installing solar projects on their homes, while energy hogs that use three or more times the average amount of electricity will get the most benefit because the solar will be valued at nearly 30 to 40 cents/kWh.”

Average payments for solar PV in California in 2010 total $0.34/kWh for a system with a 20-year life, though total payments ranged from a low of $0.27/kWh for nonprofits and governmental entities to a high of nearly $0.38/kWh for commercial projects.

Germany’s feed-in tariffs

Freehling’s report did not specifically examine Germany’s feed-in tariffs for solar PV. However, data on the cost of the German program is much more readily available than data on solar PV installed in California.

There are no tax credits, rebates, grants, or other subsidies in the German program. There is no net-metering, though there is a small program that attempts to approximate a similar result that has not proven popular. There may also be depreciation deductions.

The posted tariffs vary from a high of $0.41/kWh for rooftop systems less than 30 kW to a low of $0.30/kWh for systems mounted on the ground at, for example, brownfield sites.

German tariffs are based on the cost of generation plus a reasonable profit. If German tariffs were applied directly to California without adjustment to the state’s greater solar intensity, the tariffs would pay more than necessary and result in windfall profits.

German tariffs in California

To compare Germany’s solar PV tariffs to those that would be appropriate in California, it is necessary to reduce the tariffs by an amount equivalent to the difference in the solar resource.

The solar resource in California is not uniform across the entire state. The rainy north coast, for example, has much less insolation than the blisteringly hot San Joaquin Valley. Any solar feed-in tariff program for California would have to take these differences into account.

Nevertheless, for the sake of a simple comparison, we can assume that a simple solar feed-in tariff for California would be about 64 percent of that currently paid in Germany.

Thus, German solar tariffs today applied to California would range from a low of $0.20/kWh for groundmounted systems on brownfield sites to nearly $0.27/kWh
for rooftop systems less than 30 kilowatts.

Average cost of German solar feed-in tariffs in 2011

According to data from the Bundesnetzagentur, Germany installed 717 megawatts (MW) of solar PV from January through April 2011. The average weighted payments per kilowatt-hour under the German program were $0.38/kWh. Under California conditions, these payments would be equivalent to $0.24/kWh.

Germans pay less than Californians

A comparison between Freehling’s data on the total cost of solar PV in California and data from public sources in Germany shows that Californians are paying substantially more for solar PV than Germans, despite claims to the contrary.

Excluding the benefits of the depreciation deduction to California investors in solar PV, Germans are paying $0.03/kWh less for installations by nonprofits and government agencies than Californians, and nearly $0.07/kWh less for commercial projects.

Overall, Germany paid $0.07/kWh or 23 percent less for the 717 MW installed in the first part of 2011 than California paid for 200 MW of solar PV in 2010.

Germans have cut solar rates 50 percent since 2004

Germany launched its Renewable Energy Sources Act in 2000. Included in the act was provision for a solar feed-in tariff. It was a simple tariff without size differentiation.

From the year 2000, when total installed solar PV capacity across all of Germany was only 90 MW, capacity grew steadily to 1,000 MW by 2004. However, this growth was insufficient to renewable energy advocates in Germany’s House of Commons, the Bundestag. During the scheduled revisions of the Renewable Energy Sources Act in 2004, tariffs for solar PV were increased and differentiated by size. The revisions also included annual decreases in the tariffs (degression) of from 5 percent to 6.5 percent per year.

Since 2004, Germany has revised its tariffs for solar PV several times. Today, solar PV tariffs in Germany are about one-half those of 2004.

Germany has effectively reached parity for groundmounted solar PV with the residential retail rate, though it has been at grid parity for wind energy for more than a decade.

German costs fell faster than U.S. costs

In contrast to the experience in Germany, Lawrence Berkeley National Laboratory (LBL) found that during the period from 2004 through 2009, the installed cost of solar PV in the U.S. dropped only 10 percent. In “Tracking the Sun III: The Installed Cost of Photovoltaics in the U.S. from 1998-2009” [PDF], LBL also found that the installed cost of residential solar PV in Germany was 61 percent of that in the U.S. That is, Germans were paying 40 percent less to install solar PV on their homes than Americans were.

Based on German experience, it could be argued that California, and the U.S. as a whole, would have proceeded much more quickly toward grid parity for solar PV — and saved taxpayers and ratepayers money — by simply adopting the German feed-in tariffs and letting the industry drive down costs for solar PV on both continents.

What’s next for California?

As the CSI program winds down, the question becomes, “What should California do next?”

During the 2010 campaign, Gov. Jerry Brown said he wants to develop 12,000 MW of distributed generation with feed-in tariffs. If he carries through on his campaign promise, then California’s solar program may morph into just one of many components of a comprehensive feed-in tariff program for multiple technologies.

And if Congress carries through on its threats at belt-tightening, future solar tax credits could be at risk.

California may be wise to create a renewable energy program that’s not only adaptable to future federal action but also more fair to all Californians. The state could, for example, create two feed-in tariff tracks — one for those who can use federal tax credits and another for those who can’t use federal tax credits, or choose not to.

Should Congress eventually axe solar subsidies, California homeowners, farmers, and businesses could then simply use the feed-in tariff track not dependent on federal tax credits.

Adopting German solar PV tariffs in California

California has an international reputation for an overly bureaucratic and cumbersome regulatory process. The state’s Public Utility Commission (PUC) has still not implemented SB32, the California solar industry’s attempt at moving toward a simple feed-in tariff in the state that was signed into law in the fall of 2009.

While interminable hearings on SB32 drag on, the PUC has instead launched another bidding scheme masquerading as a feed-in tariff.

Governor Brown could short-circuit the PUC’s administrative apparatus and simply declare that as part of the state’s new feed-in tariff program for distributed generation, California would simply adopt German tariffs, adjusted for the Golden State’s better solar resource. He could do so on the grounds that the German tariffs are cheaper and more fair to all Californians than the current hodgepodge of programs.

Feed-in tariffs, or fixed payments for the electricity generated by wind turbines, solar panels, and biogas power plants, have pushed Germany to world leadership in renewable energy development, most of which is in small distributed applications.

However, Germany is in the “also ran” category in geothermal energy, tying Ethiopia for the amount of capacity installed. Even France, a country not known as a hotbed of renewable energy development, has more than twice the installed geothermal generating capacity as Germany.

In the year 2000, Germany introduced a system of differentiated feed-in tariffs to pay for renewable energy generation. The policy pays one price for wind energy, another for solar energy, and so on. It also differentiates its renewable tariffs by project size and, in the case of wind energy, by resource intensity.

Germany currently uses feed-in tariffs to pay for electricity generated by geothermal power plants.

Existing geothermal status

Following feed-in tariff revisions in 2009, Germany implemented geothermal tariffs for two project size classes: those less than 10 megawatts (MW) and those greater than 10 MW. However, these tariffs are the base rates only. Germany offers substantial bonus payments for when the projects are completed, how the technology is used, or the type of technology employed.

From only 220 kilowatts (kW) in 2003, installed capacity has risen to 7.5 MW in 2010. In 2010 geothermal power plants generated 27 million kilowatt-hours (kWh), still only 0.03 percent of Germany’s consumption of more than 600 tetrawatt-hours per year.

The German Renewable Energy Federation (Bundesverband Erneuerbare Energie or BEE) expects that by 2020, Germany will have installed 625 MW of new geothermal power plants or nearly two orders of magnitude more than that today. Even so, such a fleet will still only be capable of generating somewhat less than 1 percent of electricity consumption.

To reach the level expected by BEE and the government, the pace of development will have to be significantly increased. Thus, Germany is on the verge of a substantial revision of its feed-in tariffs for geothermal generation.

German geothermal costs

The president of the Geothermal Business Forum, Erwin Knapek, says geothermal generation to date has cost from €0.18/kWh ($0.25/kWh) to €0.28/kWh ($0.40/kWh) with plants averaging about €0.21/kWh ($0.30/kWh).

Knapek, former mayor of Unterhaching, a city south of Munich and the home of one of Bavaria’s few operating geothermal power plants, recommended to Germany’s conservative government that they scrap a subsidy covering 30 percent of drilling costs and suggested instead that the government simply raise the tariff. While this doesn’t reduce exploration risk, a big concern to geothermal developers worldwide, it does make the payment more attractive if the wells are successful. The conservative coalition government of the Christian Democrats-Christian Social Union and the neoliberal party appears to have accepted this suggestion.

For project developers, says Knapek, this simplified payment reduces bureaucracy as well as reduces the policy risk that the government will scrap exploration subsidies. In contrast to the policy risk posed by elimination of federal subsidies with each budget review, payments from feed-in tariffs and the policy they represent are much more stable in Germany and accepted across party lines.

While the Ministry for the Environment and Nuclear Safety (BMU) and the Merkel cabinet have recommended that the 30 percent exploration subsidy be continued, Germany’s upper chamber, the Bundesrat, appears disinclined to agree and early indications are the subsidy will not be extended. The Bundesrat will vote in early July.

If the feed-in tariff revisions are accepted by both chambers of the German parliament (the Bundestag and the Bundesrat), the new tariffs will go into effect at the beginning of 2012.

Proposed new geothermal tariffs

The revision of the geothermal tariffs is part of the normally scheduled revisions of all tariffs. The last revision was in 2009.

To inform the parliamentary policy debate, studies on the experience of each technology’s growth during the previous period are undertaken and a report on this experience is published by BMU. The most recent “experience report” [PDF] was delivered to the Bundestag at the end of May.

The report contains information on the cost and performance of each technology. Here are just a few items gleaned from the section on geothermal energy:

• Projects operating in Germany deliver a 90 percent capacity factor,
• Drilling costs account for about one-half of total project costs,
• New projects cost €10,900/kW ($15,500/kW),
• Most German projects are developed at intermediate temperatures,
• Higher temperature sites in Bavaria can produce electricity for €0.20/kWh ($0.29/kWh), and
• Lower temperature sites, more typical of elsewhere in Germany, need €0.27/kWh ($0.39/kWh).

The report also shows how much is being typically spent by ratepayers on each size tranche within each technology.

German geothermal development uses what the industry terms low-temperature resources. Unlike the more well known geothermal fields at Larderello, Italy or the Geysers in California that use relatively conventional power plant design, low-temperature geothermal resources, like those in Germany, France, and Switzerland, require more complex, and costly, “binary” technology.

To simplify construction and reduce costs, binary geothermal power plants have become standardized and are built in a series of small modules from 1 MW to 7 MW. The average size of binary geothermal power plants worldwide is about 2.5 MW per unit according to a reference textbook by engineering professor Ronald DiPippo. The modules are then clustered at one site.

If past experience is any guide, these clusters of small generators will be connected at the distribution level. Projects in Germany are typically found in small, distributed applications on the outskirts of cities, towns, and villages.

For example, one 3 MW geothermal plant was built on the southern edge of Landau in Rheinland-Pfalz in 2007 and another 3.4 MW plant was installed in the city of Unterhaching south of Munich in 2009.

Both geothermal plants are about the same size as modern wind turbines. However, geothermal power plants operate more often at full capacity than wind turbines. BMU assumes in its report that a geothermal power plant will typically generate 8,000 kWh/kW of installed capacity (a capacity factor of about 90 percent), whereas the average generation of wind turbines in Germany is about 2,000 kWh/kW. Thus, a geothermal power plant in Germany operating as designed should generate
four times more electricity than a wind turbine for the same generating capacity.

As yet the plant at Unterhaching hasn’t reached the level of performance expected of a mature plant. Unterhaching generated 4 million kWh in 2009 and 11 million kWh in 2010.

In the conclusion of its report, BMU recommends simplifying the geothermal tariff structure by eliminating separate size tranches. Most current projects, the report says, are less than 10 MW. Thus, the proposed new tariff replaces the previous two tranches with only one. Further, the BMU has incorporated the bonus for projects installed prior to 2016, and the bonus for district heating into the single tariff. They have maintained and increased the bonus for using enhanced geothermal using hot, dry rock.

BMU recommends raising the geothermal tariff nearly €0.10/kWh ($0.14/kWh) above that in 2011 to €0.25/kWh ($0.36/kWh).

Germany’s proposed new geothermal tariffs, if implemented, will put it on a par with France and Switzerland where existing tariffs range from €0.20/kWh ($0.30/kWh) to €0.30/kWh ($0.40/kWh).

The conservative German government has issued a 14-page document [PDF] outlining how Germany can close all of its nuclear reactors by 2017 — sooner than the government’s official proposal of 2022 — and still keep the lights on.

The report, and the timing of its release, indicates the intense political debate within and without the ruling coalition of Angela Merkel’s Christian Democrats and her junior partner the neoliberal Free Democrats. As noted by Craig Morris for Renewables International, the report was issued by an agency within the German Ministry of the Environment, but it was not “commissioned” by the ministry itself. This subtlety would be lost on all but the most avid political junkies.

The ministry is led by the up-and-coming conservative party member Norbert Röttgen, who distanced himself from the report but did not prevent its publication. The report will surely be used by the opposition parties in arguing that the exit from nuclear can be quicker than the Merkel government is proposing.

Ironically, the conservative Merkel government has proposed essentially the exit policy planned by the previous red-green government of Social Democrats and the Greens. Merkel’s conservative party rose to power in part on a platform of extending the operation of the existing reactors. Her policy reversal is historic not only in Germany, but worldwide.

Critics of the reversal have charged that:

• Germany will suffer power outages;
• Germany will import nuclear power from other countries, notably France; and
• Germany will build massive new coal plants to make up the shortfall.

The analysis by the German environment agency specifically examined these issues. It concluded that Germany can close the reactors within five years and do so:

• without power outages;
• without importing nuclear power from other countries;
• without building new coal plants; and
• with only a modest increase in the cost of electricity.

The agency says that Germany can close the nuclear plants by faster development of its renewable sources of energy and the construction of 5,000 megawatts of new natural-gas-fired generation. The new gas-fired generation will give the grid the needed flexibility in meeting demand while also preserving Germany’s commitment to reducing its carbon dioxide emissions.

To the surprise of many critics of Germany’s renewable energy program, the country is not a net importer of electricity. In recent years, Germany has been a net exporter of generation.

The study found that electricity imports to Germany are based on price and not on any shortage of supply and that this will continue as the reactors are taken off-line. That is, Germany buys electricity on the liberalized market when it is cheaper than generating the electricity from its own fossil-fired power plants.

The German Environment Agency estimates that a rapid exit from nuclear will cost ratepayers only $0.009 to $0.01 per kilowatt-hour. This increase, it says, is less than the price swings of natural gas and coal during the past year.

Interestingly, the higher market price for electricity will reduce the cost of Germany’s renewable energy program by decreasing the differential between the market price of electricity and the average cost of feed-in tariffs for renewable energy.

For further reading, see the Heinrich Böll Foundation’s “No Nukes, No Problem?” by Arne Jungjohann and Wilson Rickerson.

The world’s beleaguered nuclear industry continues to take a battering. The “nuclear renaissance” juggernaut that once seemed unstoppable now appears dead in its tracks.

The cabinet of Germany’s conservative government on Monday voted to take the country out of nuclear permanently by 2022. Not to be outdone on the right, the country’s opposition parties say that’s not fast enough.

The conservative party in the state of Bavaria has gone even further and says that while it was first in German nuclear power, it will now be first in exiting nuclear. Bavaria, known as the “Texas of Germany” for its conservatism, gets more than 50 percent of its electricity from nuclear energy.

But it’s the sheer cost of nuclear that may overwhelm any industry “renaissance.”

Little data exists on the actual cost of new nuclear generation. Rumors persist in Ontario, Canada, that the government’s delay in building its promised new reactors was due to “sticker shock” after receiving costly proposals. Whatever the reason for delay, the actual costs of the proposals are being hidden from public view.

So policy discussions are often dependent on studies of nuclear’s cost by organizations with a particular axe to grind.

Hey, here’s some data

One exception comes from the California Energy Commission (CEC), a public agency mandated with the task of periodically examining the costs of various electricity-generation technologies that may be used in the state to meet demand. There are four operating nuclear reactors in the state, two each in two locations. There is an additional 900-megawatt reactor that was decommissioned by the Sacramento Municipal Utility District (SMUD) after a plebiscite on June 7, 1989. California is unlikely ever to build another reactor; state law prohibits construction until a permanent waste repository is available.

Nevertheless, the CEC in its most recent Integrated Energy Policy Report examined the cost of electricity from 21 different central-station generation technologies. Such studies, says the CEC, are useful for comparing the relative costs between technologies, though the actual cost of electricity to consumers can be quite different from these hypothetical studies.

The detailed study considered three forms of ownership: merchant plant, investor-owned utility, and publicly owned utility. Merchant plants are built to serve deregulated markets and assume a high degree of market risk. They may not be able to sell all their electricity at any one time if their price is too high. Investor-owned utilities are the traditional private companies serving a regulated market. In California, Pacific Gas & Electric and Southern California Edison are investor-owned. Publicly owned utilities are municipal utilities, like SMUD. Publicly owned utilities pay fewer taxes and have access to lower cost financing than either investor-owned utilities or merchant plants.

The CEC’s 186-page report, “Comparative Costs of California Central Station Electricity Generation” [PDF], found that a 1,000-megawatt pressurized water reactor would generate electricity in 2018 from as little as $0.17 per kilowatt-hour to as much as $0.34 per kilowatt-hour. These results are startling: Most renewable technologies today, even solar photovoltaics (PV), generate electricity for less than that. Only a municipal utility could generate nuclear electricity for less than the cost of solar PV.

Currently, Germany pays between $0.31 and $0.41 per kilowatt-hour for electricity from solar PV, which means that the cost of solar-generated electricity today is equivalent to the cost estimated by the CEC for a nuclear plant beginning operation in 2018. And all observers, even critics, expect the cost of solar PV to continue declining during the next decade.

And what about insurance?

In an unrelated study for the German Renewable Energy Association, consultants found that nuclear reactors are effectively uninsurable. The 157-page report [PDF] by Versicherungsforen Leipzig estimated that the premium necessary to insure a nuclear reactor from accident would cost from $0.20 per kilowatt-hour to a staggering $3.40 per kilowatt-hour.

Thus, the cost to insure a nuclear reactor — at a minimum — would cost as much as the electricity itself from a nuclear plant coming online in California in 2018.

Earlier German studies of the cost for insuring reactors against catastrophic failure found similar results. A 1999 report for the European Commission on the externalities of energy found that the external cost of nuclear power was $2.59 per kilowatt-hour largely due to the cost of insurance.

These studies indicate that the cost of nuclear energy is far higher than proponents have led policymakers to believe.

Renewable energy, even costly solar photovoltaics, begins to look like a bargain to consumers when realistic costs of new nuclear plants come to light.

With the right policies in place, geothermal could play an active role in reaching California’s renewable energy goals.

California recently passed new legislation requiring the state to provide 33 percent of its electricity from renewable energy and newly elected Gov. Jerry Brown (D) signed the bill into law.

Geothermal energy is a renewable resource using the heat of the Earth to generate electricity and heat homes, offices, and factories.

California leads the world in geothermal energy development. However, most of California’s geothermal power plants were built in the 1970s and 1980s. There has been very little geothermal development in the state since Brown was last governor in the early 1980s.

That could change. Candidate Brown prominently talked of introducing a system of feed-in tariffs to spur renewable energy development in California. Brown specifically mentioned developing as much as 12,000 megawatts (MW) of new renewable generating capacity with feed-in tariffs.

In a study for the California Energy Commission (CEC) in 2008, engineering consultant Black & Veatch examined the renewable resources available to meet California’s renewable energy target and the new transmission capacity that would be needed. Included in the consultant’s report, “Renewable Energy Transmission Initiative” (RETI), are detailed estimates of the cost to develop 244 proposed geothermal power plants at sites in California, Nevada, Oregon, Idaho, and British Columbia.

Black & Veatch considered projects as small as eight MW to as large as 1,000 MW.

Distributed geothermal

While many geothermal projects are connected at transmission voltages, they differ from typical central-station plants. Many individual geothermal projects are relatively small. Of the 244 proposed projects in the RETI database, 185, or three-fourths, are less than 20 MW in size. They would, thus, qualify as distributed generation under Brown’s proposed feed-in tariff.

The following analysis arbitrarily sorted the proposed projects into several size categories similar to those found where feed-in tariffs are used to develop geothermal energy:

• Less than 10 MW: 117
• Greater than 10 MW but less than 20 MW: 68
• Greater than 20 MW but less than 25 MW: Nine
• Greater than 25 MW but less than 50 MW: 31
• Greater than 50 MW but less than 100 MW: Nine
• Greater than 100 MW but less than 500 MW: Nine
• Greater than 1000 MW: Two

The bulk of the projects greater than 20 MW are also relatively small. Forty projects, or 16 percent, fall in the size range from 20 MW to 50 MW. Altogether, 90 percent of the proposed geothermal projects in the RETI database are less than 50 MW in size. This is in part artificial and due to state regulations. Power plants less than 50 MW are not regulated by the CEC.

If Brown’s proposed feed-in tariff policy included geothermal projects up to 50 MW, it would encompass most of the geothermal projects in the RETI database.

Projects less than 50 MW would account for 40 percent of all proposed geothermal generating capacity, some 3,300 MW. These plants would produce 40 percent of all potential geothermal generation, about 22 terawatt-hours per year (7 percent of current supply) or 1.7 times more electricity than at present.

Geothermal plants in California currently generate 13 terawatt-hours per year of the nearly 300 terawatt-hours consumed annually.

What geothermal tariffs are needed

The consultants estimated the cost of electricity from the plants under several conditions: Independent Power Producers, municipal utilities, and if the generation was delivered from Canada or Mexico. Within the category of Independent Power Producers (IPP), cost estimates were further subdivided into the cost for IPPs without any federal subsidies, the cost for IPPs with Production Tax Credits (PTC), and the cost for IPPs with Investment Tax Credits (ITC).

This analysis considered only IPPs and for only two conditions: without federal subsidies and with the ITC, a federal tax subsidy.

While federal investment subsidies currently exist in the form of the PTC and ITC for many renewable energy technologies, their future is uncertain. The federal government’s growing budget deficit, the cost-cutting mood of Congress, and threats to the bond rating on U.S. federal debt suggests that tax subsidies may not be a secure source of funding. Because geothermal projects take several years to complete, investors are wary of financing projects when the future of tax credits or other “incentives” is questionable.

Geothermal feed-in tariffs worldwide vary from as low as $0.10/kilowatt-hour (kWh) for a 20-year contract in Spain to as much $0.40/kWh for a 20-year contract in Switzerland.

Black & Veatch did not specifically evaluate the feed-in tariffs that would be necessary to fully pay for geothermal generation plus sufficient profit to overcome the risk of developing what is inherently a risky resource.

Feed-in tariffs are typically determined on the cost of generation plus a reasonable profit. Cost-of-energy studies — because of their different objectives — do not necessary reach the same conclusions about price. However, Black & Veatch’s study is the most detailed source of data in the public domain on geothermal energy and its cost and the study can serve as a proxy for what geothermal tariffs may work in the California context.

For IPP projects without access to federal subsidies, tariffs for geothermal projects less than 20 MW in California would need to be comparable to those in Europe: from a low of $0.13/kWh to as much as $0.30/kWh. Tariffs for projects from 20 MW to 50 MW would vary from a low of $0.10/kWh to a high of $0.18/kWh.

Projects that could be developed quickly and take advantage of the federal ITC while it remains available would be significantly less expensive. For projects less than 20 MW, tariffs would vary from a low of about $0.09/kWh to a high of $0.20/kWh. Projects from 20 MW to 50 MW in size would require tariffs in the range from a low of $0.08/kWh to $0.13/kWh

The price necessary for geothermal development in California is comparable to that of other renewable resources. Estimates of the cost of geothermal are comparable to those of wind energy, but geothermal costs less than that for generation from solar photovoltaics.

In contrast to variable renewable resources like wind and solar, geothermal provides base load generation. It is thus a natural compliment to the development of California’s abundant wind and solar resources.

California could add 7 percent of new renewable generation to its supply, and compliment development of its variable renewable resources by including geothermal energy in Brown’s as yet unannounced feed-in tariff policy.

A German wind farm.Photo: Dirk Ingo Franke

The conservative government of Chancellor Angela Merkel, struggling to stay ahead of public attitudes toward nuclear power in the run-up to regional elections, issued its annual report on the contribution of renewable energy to the German energy market in 2010.

Wind turbines, hydroelectric plants, solar cells, and biogas digesters now provide nearly 17 percent of Germany’s electricity.

Meanwhile, the German network agency Bundesnetzagentur issued its final update on the installation of solar photovoltaics (PV) in 2010.

The results are nothing short of startling and will add fuel to the heated debate about how countries such as Japan can meet their electricity needs without reliance on nuclear power.

In the immediate aftermath of the Japanese nuclear accident, Germany’s Merkel closed two reactors permanently, and another five temporarily. She also called on her government to revisit its controversial decision to extend the life of its aging reactors.

The reactors at Fukushima Daiichi are 40 years old and their license to operate had been extended by the Japanese government.

The reports on the rapid growth of renewable energy in Germany may give Merkel’s government the cover it needs to reverse direction on nuclear power, and by doing so reverse its faltering political fortunes.

Germany uses an advanced system of feed-in tariffs to pay for renewable energy generation, and has an aggressive target of meeting 39 percent of its electricity supply with renewable energy by 2020. Its system of advanced renewable tariffs has enabled Germany to exceed its 2010 target of 12.5 percent by a wide margin.

New renewables near 17 percent of electricity supply in 2010: The German Ministry for the Environment and Reactor Safety reports [PDF] that in 2010, renewable energy generated more than 100 TWh (billion kilowatt-hours) of electricity, providing nearly 17 percent of the 600 TWh of supply.

Wind turbines and biomass plants delivered more than 70 percent of renewable generation.

Biogas plants powered with methane from manure alone generated nearly 13 TWh.

In 2010, renewables generated more electricity in Germany than gas-fired power plants — nearly as much as hard coal — and are fast approaching the contribution of nuclear power.

7,400 megawatts (MW) of solar PV installed in one year: Doubling their previous record, the German solar PV industry installed 7,400 MW from nearly one-quarter million individual systems in 2010, according to the final report by the Bundesnetzagentur.

In December alone, Germans installed more than 1,000 MW of solar PV, enough solar capacity to generate 1 TWh of electricity under German conditions. While they represent only half that installed in June 2010, the December installations were 50 percent greater than total solar PV installed in the USA in 2010 and as much as that rumored to have been installed in Japan last year.

Nearly 700 MW from some 100,000 systems were installed in a size range typical of that installed by German homeowners.

An astounding 3,700 MW from more than 135,000 systems were installed in a size range representative of that installed by farmers and other small businesses.

Another 1,700 MW were installed in a size class characteristic of small businesses and large industrial rooftops.

Large, multi-megawatt systems comprised 1,400 MW of capacity or nearly one-fifth of total capacity installed in 2010.

Renewable electricity more than 30 percent of supply on Feb. 7: A further sign that renewable energy has come of age as a commercial generating technology, certainly in Germany, is that penetration of wind and solar reached more than 30 percent of supply on Feb. 7, 2010, according to data posted publicly by Germany’s electricity transmission exchange, EEX.

The exchange posts online the amount of capacity of conventional generation, wind generation, and solar PV generation delivered to the grid by time of day.

On Monday, Feb. 7, 2011, the combined real-time wind and solar generation varied from a high of 32 percent of supply at midnight to a low of 18 percent of supply at sunrise. Solar PV generation delivered more than 8,000 MW for the two-hour period from just before noon until 2:00 p.m., reaching a peak of nearly 8,500 MW at noon. During the same time period, conventional sources contributed 50,000 MW and wind delivered another 10,000 MW to the network.

There is 16,500 MW of solar PV capacity now online in Germany. Solar insolation is weakest in mid-winter, and highest in mid-summer. The solar industry’s Feb. 7 performance bodes well for this coming summer, when solar PV can be expected to break new records.

In other Feb. 7, 2011 observations:

• PV produced 13 percent of supply at noon.
• Wind reached nearly 1/3 of generation at midnight.
• Wind and solar’s combined 18,500 MW at noon met 29 percent of demand.
• PV was producing 1/2 of its nameplate in mid-winter.
• Wind was producing near its total installed capacity.

With the Japanese nuclear calamity fresh in everyone’s mind and upcoming elections staring the government in the face, the success of Germany’s rapid development of renewable energy may give Merkel’s conservative government the flexibility it needs to weather the nuclear crisis. It would not be surprising to find the government proposing an even more aggressive pace of renewable energy development than that seen in 2010.

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”.

Britain, along with the U.S., has been the principal intellectual and political proponent of electricity trading in a de-regulated market as the principal means for developing new generation at what was promised to be the lowest cost to consumers. Similarly, the development of renewable resources in Britain through the RO, and in the U.S. through Renewable Portfolio Standards, was premised on trading in renewable energy certificates and selecting individual projects through an auction or tendering system.

Following the Enron scandals of the late 1990s, electricity trading and de-regulation fell into disrepute. The widespread failure of programs with quota-driven markets, such as in Britain, to reach their renewable energy targets further tarnished the concept. Most jurisdictions with aggressive renewable energy policies long ago moved from quota systems to programs using feed-in tariffs to create dynamic markets for renewable energy.

Of major European countries, only Britain’s RO and Italy’s RPS for wind energy remain. Nearly all other markets have moved to fixed feed-in tariffs for renewable energy. Italy abandoned its RPS for all but wind in the mid 2000s. Britain abandoned its traditional subsidy program for renewables in late 2009.

Italy moved to feed-in tariffs for solar photovoltaics (PV) with its Conto Energia in 2006 and hasn’t looked back. Italy, now the second-largest solar PV market in the world, is expected to install more than 1,000 MW in 2010.

Even Britain, one of the remaining examples of an European RPS program, implemented a comprehensive system of feed-in tariffs in the spring of 2010 for projects up to 5 MW.

Huhne’s proposal follows the coalition’s agreement coming to power of moving the RO to a system of feed-in tariffs. New feed-in tariffs could be in place by 2013, but existing contracts under the RO could be built through 2017. The latter is critical for Britain’s booming offshore wind sector.

However, environmentalists have reacted with alarm to the government’s inclusion of “low carbon” technologies in its proposal. “Low carbon” is code for nuclear power and Carbon Sequestration and Storage or CSS.

Renewable energy advocates have joked for years that nuclear power should be held to the rigors of a feed-in tariff market. Only then, they’ve argued, would policy makers learn the true cost of nuclear, and by extension that of CSS. In Ontario, for example, the rumored cost of new nuclear of $0.20 per kWh makes even solar PV look attractive.

If the government’s program is implemented as proposed, renewable advocates may unfortunately get their wish. University of Birmingham lecturer Dave Toke has publicly warned that the nuclear wolf among the renewable sheep could lead to a massive slaughter as nuclear’s characteristic cost overruns gobble up all funding for “low carbon” technologies.

Toke, an authority on Britain’s complex RO, as well as an earlier failed program, the Non-Fossil Fuel Obligation (NFFO), has issued a call to arms for a robust, German-style feed-in tariff program that isn’t a cover for the nuclear industry.

Ironically, it was the NFFO that former Prime Minister Margaret Thatcher implemented to help Britain’s struggling nuclear industry with ideologically acceptable public support. Since then the British nuclear industry has been privatized and sold off to French and German utilities.

NFFO, an early quota program based on auctions, failed both as a means to support the nuclear industry and renewable energy. Only one-fourth of the renewable contracts won through NFFO auctions were ever built. It was the failure of the NFFO auctions that led Britain down the ultimately unsuccessful RPS path.

Toke’s warnings are taken seriously within Britain’s renewables and environmental community. They have painful memories of the government’s past duplicity on renewable energy, or as Shakespeare said of “perfidious Albion.”

This box of Tim Hortons could cover an entire year of solar PV.Photo: Daniel Nugent

Tim Hortons is a popular Canadian coffee-shop chain found in even the smallest village.

The confidential report comes at a time of heated political debate in the provincial capital of Toronto about the cost of the current government’s Green Energy and Green Economy Act. Ontario’s feed-in tariff program is the most visible — and the most controversial — aspect of the policy.

The report by ClearSky Advisors was prepared for private, and so far unnamed, clients. However, a summary has been released to the media.

ClearSky says that by 2015, Ontario’s solar PV industry will have created 72,000 person-years of jobs.

Ontario plans to close all its coal-fired power plants by 2014. Generation by renewable sources, including solar PV, will be used to offset the coal-fired generation lost.

Program cost minimal

Critics of the program say that feed-in tariffs are the cause of what they claim are increasing electricity costs.

Not so, says ClearSky’s summary. Cost of electricity in the province will increase slightly to a maximum of about one percent of a typical household’s bill, then decline steadily as the initial contracts work their way through the system.

Solar PV is the most expensive of the new renewable energy technologies. Though costs are rapidly declining, generation from solar PV is still several times more costly than that from wind, hydro, or biogas. Thus, feed-in tariffs for solar PV are a lightning rod for critics of renewable energy.

In a previous report, ClearSky estimated that Ontario will install 3,000 megawatts of solar PV in the next five years. During the period studied in this report, ClearSky says Ontario will install a total of 6,000 megawatts of solar PV by 2021. For comparison, California is expected to have a total installed capacity of 800 megawatts and the U.S. 1,700 megawatts of solar PV by the end of 2010.

If ClearSky’s estimates become reality, Ontario will soon become the largest center of solar PV development in North America by a wide margin, and rival European countries, which are currently the leaders in solar generation.

More jobs from solar PV than coal or nuclear

The Green Energy Act was in part justified by the job-creation potential in Ontario’s industrial sector, which was hard hit by the collapse of North America’s auto manufacturers.

Implementation of the province’s feed-in tariff program by the Ontario Power Authority includes a controversial domestic content provision. In effect, a substantial portion of any solar system installed in Ontario must be manufactured in the province.

ClearSky’s summary suggests that this policy may in fact work as intended at creating new jobs. The report says solar PV creates 12 times more jobs than nuclear per kilowatt-hour of electricity generated and 15 times more than coal.

More jobs per dollar invested

ClearSky calculates that while investment in solar PV results in 30 percent to 40 percent as much electricity as investment in conventional sources, the investment in solar PV pays dividends in job creation. According to ClearSky’s summary, investment in solar PV creates 2.4 to 6.4 times more jobs than a similar investment in conventional sources.

Ontario solar PV billion dollar market

At the current pace of development and with the limitations of a weak, antiquated grid in mind, ClearSky projects that between 2010 and 2015, Ontario’s burgeoning solar industry will attract nearly $7.8 billion (USD) in private capital.

Clean generation saves ratepayers 20 percent

On Oct. 17, 2010 the Ontario government announced a rebate of 10 percent on ratepayers’ electricity bills to compensate for what it calls the “Clean Energy Benefit” of the Green Energy Act. The rebate will be paid for from tax revenue.

In a posting on their website, “Why Ontario’s Clean Energy Benefit Makes Sense — Sort Of,” ClearSky argues that the rapid development of clean sources of generation to replace the existing coal-fired plants saves taxpayers money by eliminating coal’s social and environmental costs.

The posting has revised interest in a long-forgotten report on the cost of coal-fired generation. The 2005 report, Cost Benefit Analysis: Replacing Ontario’s Coal-Fired Electricity Generation [PDF], tallied the then social cost of electricity from the province’s nuclear-powered and fossil-fired fleet of generators. The report says Ontario’s coal-fired power plants cost Ontario nearly $0.127 (USD) per kilowatt hour in environmental and social impacts.

According to ClearSky, new renewable generation under the Green Energy Act’s feed-in tariffs saves ratepayers the equivalent of 20 percent on their electricity bills. Thus, they reluctantly say, the province’s Clean Energy Benefit does appear justified and could be even higher.

While ClearSky’s market analysis won’t settle the debate on the future of Ontario’s electricity system, it clearly shows that the province is headed toward becoming a leader in renewable energy development, and especially in the creation of a solar PV industry.

The city of Toronto looking out onto Lake Ontario.Photo: Christopher Chan

When completed, Ontario will have the largest installed base of community-owned renewable generation in North America, surpassing community ownership of renewable generation in Minnesota. Nearly one-third of the capacity will be built by Ontario’s aboriginal population.

Within a few years, Ontario will have the largest installation of community-owned renewable resources outside Denmark and Germany.

In an Oct. 12, 2010 report, OPA said that it has signed contracts for 264 megawatts of community-owned projects, and another 120 megawatts of projects owned by Ontario’s aboriginal peoples. The contracts represent 16 percent of Ontario’s 2,500 megawatts of feed-in tariff contracts to date.

No other jurisdiction in North America has made such a concerted effort as Ontario has to guarantee that a portion of the new renewable generating capacity to be built will be owned by its own citizens and native peoples through the province’s innovative feed-in tariff program.

This is in addition to Ontario’s microFIT program (a small renewable energy project program under the umbrella of feed-in tariff programs), which assures connection for homeowners and farmers wanting to generate electricity with solar panels for sale to the grid. There are 20,000 applications for microFIT contracts.

Until the Ontario program, Minnesota led North America in developing community-owned wind generation. In a recent analysis by the Institute for Local Self-Reliance‘s John Farrell, there are 239 megawatts of community-owned projects operating and under construction in Minnesota, or about 10 percent of the 2,500 megawatts installed in the state.

Nearly all of Minnesota’s community-owned wind generation was installed under its Community-Based Energy Development (CBED) program. Minnesota’s CBED and its forerunner were the state’s version of an early feed-in tariff.

Feed-in tariff policy enables farmers, community groups, Native Americans, and Native Canadians to participate directly in the development of their own renewable resources, on an equal footing with commercial power producers.

One-half of all wind generation in Germany, or more than 12,000 megawatts, is owned by local investors. The percentage of local ownership is even higher in Denmark and the Netherlands.

Nova Scotia begins hearings Nov. 8, 2010 on the province’s community feed-in tariff program. The Nova Scotia Utility and Review Board will determine feed-in tariffs for large and small wind, biomass, and tidal power that will go into effect on April 4, 2011. Projects in the 100 megawatt program are set aside for Nova Scotians.

One prime example of a community-initiated project resulting from Ontario’s feed-in tariff program is the $55 million Pukwis project only 80 km (50 miles) north of downtown Toronto. Early next year, the Chippewas of Georgina Island will start construction on a 20 megawatt, ten-turbine project on the island in Lake Simcoe, the first phase of a 54 MW-development. The Pukwis community wind project will be the first aboriginal- and community-owned wind project in Canada and possibly in North America.

The Pukwis wind farm is made possible by the provincial feed-in tariff program, which includes a $0.015/kilowatt-hour bonus payment for projects owned by Ontario’s First Nations and Métis, and a $0.01/kilowatt-hour bonus payment for community-owned projects. The provincial program also pays $0.135/kilowatt-hour for all the generation from the wind turbines.

Pukwis, the Ojibwa word for whirlwind, is a joint venture between the Chippewas of Georgina Island and the Pukwis Energy Co-operative, which will sell shares to local investors in the Greater Toronto Area.

The Ontario Sustainable Energy Association, the principal Canadian advocate for community ownership of renewable generation, will be hosting its annual Community Power conference Nov. 14-17, 2010 at the Metro Toronto Convention Centre. The conference is set to celebrate 100 years of community power in Ontario and includes a specific track for aboriginal project development like that of the Chippewas on Georgina Island.