Germany has made enormous investments in renewable energy. So why isn’t it on target to meet its ambitious greenhouse gas emissions goals?
When the first German law to incentivize renewable energy (RE) came into effect in 1991, even its most ardent supporters could not have imagined that 25 years later RE would provide Germany with 195.9 terawatt hours of power—almost a third of the nation’s gross electricity consumption. Germany’s Energiewende, with its successive and increasingly generous RE legislation, made this unprecedented achievement possible.
The formal goal of the Energiewende (best translated as “energy turnaround”) is to reduce Germany’s greenhouse gas (GHG) emissions by 80% to 95% from 1990 levels by 2050 without relying on nuclear power and while maintaining secure and affordable energy access. This ambitious goal is to be achieved by following two strategic pathways: promoting the deployment of RE so that it provides at least 60% of the nation’s gross final energy consumption by 2050 and increasing energy efficiency to reduce gross final primary energy consumption by half from 2008 levels by 2050. The core energy-system-wide targets are, in turn, divided into quantitative sub-targets for the electricity, industrial heating, and transport sectors.
In 2004, Jürgen Trittin, the German Minister of Environment, declared that support for RE would cost the average German household no more than one scoop of ice cream per month. “The transformation of our energy system is not only feasible, it also pays off,” stated a later Minister of Environment, Norbert Röttgen, in 2012, based on a feasibility study for reducing carbon emissions by up to 95% without relying on nuclear power.
Despite such optimistic statements, Germany’s energy transition is coming at a very high cost to energy consumers and to the German utility industry. Energy systems are complex amalgams of technologies, institutions, markets, regulations, and social arrangements. Nations have little experience intervening in such socio-technical systems to steer them in desired new directions over specified periods. To date, the Energiewende offers strong lessons about the unintended consequences of such interventions, but whether Germany can meet its goals of creating a clean, affordable energy system remains unknown.
Up with renewables
The backbone of the Energiewende is a succession of interrelated laws and regulations aimed at deregulation of energy markets, deployment of REs, support of combined heat and power production for industry, and establishment of a carbon emission trading system. Other policy instruments include measures to increase energy efficiency in buildings; stimulate more intensive deployment of electric vehicles; import RE from European, Middle-Eastern, and North-African countries; and begin to explore and implement visions of a future hydrogen economy. The costs of the Energiewende are primarily being paid directly by energy consumers. This is a significant policy change from previous German energy programs (mostly for the deployment of hydroelectric, nuclear, and fossil-fuel power projects), which were typically financed from general government funds.
The raft of intertwined and interdependent legislation and policies comprising the Energiewende has appropriately been termed an “integrated energy and climate program.” But, as we will see, the consequences of this complexity means that individual policies cannot be understood in isolation and often have consequences that go far beyond those that were intended.
No other instrument from the convoluted Energiewende policy toolbox has contributed more to Germany’s impressive results in ramping up RE production than the successive RE acts, known as the EEGs (Erneuerbare Energien Gesetz), of 2000, 2004, 2009, 2012, and 2014, with the next EEG coming online in January 2017. Each EEG defines the conditions for incentivizing and connecting RE facilities to the grid, as well as the level of feed-in tariff (FIT) for each RE source—wind (on- and offshore); solar (rooftop and large-scale); biomass (liquid, solid, and gas); geothermal; and so on.
The EEG requires grid operators (the electric utilities) to connect, on demand, any RE facility to their grid, and to do so in a way that minimizes the connection cost for the facility owner. RE facility owners then receive from the grid operators generous payments based on the feed-in tariff for each kilowatt-hour of electricity fed into the power grid. The relevant FIT for any given RE site is fixed over 20 years and corresponds to the payment level valid at the moment of the facility’s initial operation. Moreover, because the FITs enacted by each EEG go down over time, the sooner RE owners can bring a facility online, the higher the FIT over the fixed 20-year period. In this way, rapid RE deployment is further incentivized. The EEGs also reduce the risks of RE ownership: even if the grid operator shuts down a renewable facility due to grid instability problems, the FIT has to be paid, as if there were no interruption.
The intensive deployment of RE resulting from incentives created by the EEG has put more power into the electricity market and wholesale prices over the past decade have fallen from about 60-80 euros (€) per megawatt hour (MWh) to €20-30/MWh. Yet household and small industrial consumers experienced the opposite trend because they still had to pay for the rising EEG feed-in tariffs that incentivized and subsidized all the new RE capacity that has continually been coming online. The consumer contribution, a surcharge on top of their regular electricity bills to cover the added costs of RE power generation, has risen with the successive EEGs from about 0.2 cents per kilowatt hour (kWh) in 2000, to 6.88 cents/kWh in 2017. The total electricity-related Energiewende costs for 2016 are estimated at €34.1 billion, of which €22.9 billion (67.1%) represents the EEG costs. For household consumers and small industrial consumers, this means that more than half of their 2016 electricity bills reflect the costs of the Energiewende.
Why have energy consumers had to foot the rising electricity bills even as the market price of electricity was dropping? First, the costs imposed by the Energiewende far outweighed the falling prices on the wholesale markets. Second, to preserve Germany’s economic health, which to a large extent depends on exports of industrial goods, the government shielded energy-intensive manufacturing processes, such as chemical, aluminum, paper, and glass production, from EEG-related charges to keep manufacturing companies from migrating to countries with cheaper energy, or simply to protect them from economic failure due to the high price of electricity. As a result, about 40% of the nation’s electricity is used by industries that are largely protected from contributing to the Energiewende costs—expenses that therefore must be borne by other energy users.
Down with nukes
If the EEGs have introduced significant price distortions onto the German energy scene, a second major policy change—the phasing out of nuclear power—makes the role of REs even more complex. After passing into law the first regulations for promoting RE and combined industrial heat and power, former German Chancellor Gerhard Schröder’s first administration signed in June 2000 a nuclear phase-out agreement with the German utility industry. The political motivation for the phase out was not climate change, but the antinuclear position of the Green party, which at the time was part of Schröder’s ruling coalition. Thus, the phase out was accompanied by policies that protected the use of cheap domestic lignite and subsidized domestic hard coal—the most carbon-intensive fossil fuels—in order to protect jobs, reduce energy imports, and help preserve energy security as Germany moved away from nukes.
This political and policy calculus soon evolved as climate change became an increasingly important policy priority. Current German Chancellor Angela Merkel’s first administration decided in 2007 to merge Germany’s energy and climate policies in an integrated action plan meant to reduce GHG emissions by 36.6% from 1990 levels by 2020. Three years later, Chancellor Merkel’s second government set the current decarbonization goals of at least 80% emissions reductions by 2050 and presented the first integrated road map to carbon neutrality. To achieve this ambitious target, the road map included a postponement of Schröder’s nuclear phase out by extending the life span for the existing German nuclear facilities by up to 14 years. The rationale behind this change in the policy was that nuclear technologies are nearly carbon-free, have a high energy intensity, cover about 60% of Germany’s base-load power, and can not only help meet higher decarbonization rates, but also make up for the lack of affordable electricity storage facilities needed to make up for intermittent power generation from renewable sources.
Only six months later, after the March 11, 2011, nuclear accident in Fukushima, Japan, and in the wake of fast-spreading antinuclear protests, Chancellor Merkel changed Germany’s policy course again. Driven this time by the fear of losing her political legitimacy, she decided to decommission all German nuclear power plants by 2022, without renouncing Germany’s ambitious 2050 GHG reduction targets.
Intermittent sun and wind
With nuclear power no longer a part of Germany’s energy future, the country’s aggressive decarbonization goals now had to be achieved through even more rapid deployment of REs, and that is the course the nation has been pursuing. But the rising share of intermittent RE sources—solar and wind—creates several technical, economic, and ecological problems.
Most important, as intermittent RE sources increasingly come onto the grid, the ratio of electricity generated to installed capacity goes down. For example, fossil and nuclear plants are able to reach about 8,000 “full load hours” per year (the amount of electricity actually generated in a year, divided by the installed capacity). The average full load hours in Germany for onshore wind is about 2,000 hours, and for solar it is about 800 hours. So the more that electricity is generated by intermittent sources, the more the full load hours decline.
In 2015, the installed RE capacity was slightly higher than the conventional capacity (97.4 gigawatts [GW] compared with 96.7 GW). The current conventional power plant pool is already sufficient to cover the entire energy demand without relying at all on RE. However, given the priority of RE feed-in, and a “power back-up” ordinance that prevents conventional power plant owners from phasing out uneconomic sites if they are necessary for grid stability, utilities are forced to run their power plants inefficiently and to generate significantly less electricity than they technically could. Despite these imposed operational inefficiencies, conventional plants still generate more than twice as much power as RE facilities can produce with nearly the same installed capacity.
One way to think about this problem is that for every megawatt (MW) of conventional base-load capacity generated by fossil or nuclear fuel, you’d need 10 MW in solar power or 4 MW in wind. Yet this RE capacity would ensure only that one could generate the same amount of power as conventional sources over one year and not that one could supply the power when demand is high. For example, on a sunny and windy holiday, when demand is low, the generated power would exceed by far the demand, but on cold, windless nights, when demand is high, it would be rather impossible to meet demand.
The more intermittent power is fed into the grid, the more difficult it becomes to ensure a reliable and stable grid operation, especially because there is no affordable technology for storing electricity at a large scale. Wind and solar intermittencies are currently leveled by conventional power plants, most of which are coal-burning. The alternative is pumped water storage—reservoirs that can provide hydroelectric power on demand—which is very expensive (yet cheaper than other storage technologies), with an estimated cost of 7.7 cents/kWh. Approximately 9,000 pumped-storage facilities would be needed to level the discontinuities generated by wind and solar energy in 2015. Currently there are 36.
Another consequence related to the intensive deployment of RE and the lack of appropriate storage facilities is that electricity prices have become negative in periods of low demand and high RE feed-in—that is, companies ended up having to pay users to consume electricity. The reason is that gas power is too expensive and coal power is not flexible enough to compensate intermittencies at the hourly-scale pace in which they appear. It typically takes about eight hours to run a coal power plant completely down and another eight hours to bring it up to capacity generation again. Yet coal power is still too important for the stability of the grid to be phased out, so these plants continue operation during the relatively short RE peaks where prices actually go negative on the wholesale power exchange.
Gaming the system
Intermittency is not the only difficulty created by the Energiewende. A significant if less publically known set of problems is related to the ability of actors in the energy system—especially large ones—to take advantage of loopholes and improperly specified rules, even if they know that such “gray” areas will be eliminated by policy makers as soon as they become aware of them. For example, one way that the EEGs generate revenue to support the costs of the Energiewende is through the surcharge on electricity consumption for all end uses (apart from exempted industries). But to further incentivize energy traders to increase the share of RE in their portfolio, EEG2009 allows traders with at least 50% RE power in their portfolio to deliver 100% of their electricity without the EEG surcharge. Traders dutifully designed portfolios with exactly 50% RE and 50% conventional power, reduced their electricity prices slightly, and kept the difference, thus enriching themselves while returning only minimal savings to their customers.
The RE acts also exempted companies that produced their own power from paying EEG surcharges. The resulting loophole allowed companies to lease a power plant (usually one that burned fossil fuel), produce their own electricity, and share the savings in EEG costs with the power plant’s owner.
Yet another example of the perverse incentives of the Energiewende is the booming business in small lignite boilers. To avoid disproportionate bureaucratic burdens for relatively small heat-generating facilities, boilers with a thermal capacity under 20 MW are not subjected to the emissions trading law, so operators of such boilers do not have to purchase allowances for their carbon emissions. This rule led to a flourishing business in 19.9 MW lignite boilers because lignite is the cheapest fuel—even though it is also the one with the highest carbon content.
Such unintended consequences should not be surprising given the daunting complexities of the Energiewende and related efforts to steer the German energy system toward a clean energy future. Since the 1990s, such efforts include the ratification of the Kyoto protocol, the implementation of the European Emissions Trading System, the liberalization and deregulation of electricity markets, the adoption of successive support schemes for RE deployment, and the creation of complex mechanisms for promoting energy efficiency and enforcing clean air regulations—all superimposed on the major geopolitical changes of German reunification in 1990 and the founding of the European Union in 1992. While trying to remain up-to-date with the steadily changing and increasingly complex regulatory framework, diverse actors in the energy arena have faced soaring energy costs, an increasing dependence on intermittent power sources, severe energy transmission and storage problems, forced electricity exports, negative electricity prices, and loopholes that motivate actors to take legal free rides on the backs of less favored, or less creative, players in the energy system.
Inside the Energiewende there was no economic branch harder hit by these successive waves of induced complexity and change than the utility sector. Deregulation of the electricity market in the late 1990s triggered a strong consolidation wave; mergers among the nine largest German regional utilities led to the four big energy corporations that dominate Germany’s utility sector today. This consolidation phase was followed by a period of diversification and international expansion triggered by the EEGs and other Energiewende laws. National utilities became global energy companies almost overnight, investing in new facilities and companies in Germany and other countries and generally changing their focus from domestic to international markets.
At first, utilities ignored government efforts to encourage RE deployment; later, they began to lobby against them, as they realized that managing the problem of intermittency would be both technically difficult and expensive, and that hard assets such as coal and nuclear plants were being rendered worthless. Yet, utilities soon came to recognize that the EEGs offered a comfortable pathway to making profits without taking entrepreneurial risks. By 2008, the major utilities began massively investing in RE and by 2014 they began to split their companies into “bad” traditional fossil and nuclear energy businesses that could not make a profit, and “good” entities that invested in REs.
The Energiewende’s focus on RE feed-in forced utilities to run their power plants inefficiently and to generate significantly less electricity than they technically could. Meanwhile, the nondiscriminatory grid access rules created by the EEGs subjected utilities to increased competition and significant loss of market share as new players were enticed into the Energiewende arena and small, flexible entrepreneurs developed new business ideas that exploited market niches in the decentralized power generation realm. Electricity prices for industrial consumers and households significantly dropped in early deregulation stages, reaching their lowest level in 2000, and rising again under the generous schemes for the deployment of RE that became effective between 2000 and 2014.
Despite all efforts by the big utilities to improve their position in the market, the spread between revenues and earnings steadily increased and the sector shed nearly a quarter of its employees between 1998 and 2013. Shares of RWE, Germany’s largest utility in 2000, rose rapidly through 2007 and have since lost about 90% of their value; Eon, currently Europe’s largest utility, lost about 80% of its share value in the same interval.
Given the increased dependence on intermittent wind and solar energy, regional utility grids became increasingly difficult to operate. The grid business is strongly regulated, allowing only small predetermined margins, so the utilities lost their interest in operating transmission grids and sold significant shares of this business to compensate for losses triggered by the Energiewende. The tremendous decommissioning costs for nuclear power plants, coupled with the unsolved problem of nuclear waste disposal, added still more to the costs that the utilities had to bear and this once powerful sector was pushed to the brink of dissolution. In their desperate effort to survive, the big utilities defined new ways of working, organized and reorganized their activities, sold assets, changed the core of their business, and, finally, switched their focus to “intelligent” technologies, demand-side management, and energy services, but such efforts have done little to stabilize their long-term prospects. Today, the German utilities, especially those such as Eon and RWE that still operate major fossil and nuclear plants, lack the financial means to develop new business models, adjust to the continually changing policy frame, satisfy their stockholders, and actively shape the Energiewende. Indeed, on April 25, 2015, some 15,000 utility employees working in lignite extraction, fuel manufacturing, and coal power plant operation demonstrated in front of Chancellor Merkel’s office to get attention for their plight. But unless wholesale energy prices rise significantly, and soon, the future solvency of these major companies remains in doubt.
Is the Energiewende on track?
On the face of it, what amounts to an unintended sacrifice of the utility industry might seem like the necessary price to pay for creating a new clean energy system. Indeed, on May 15, 2016, Germany met almost its entire electricity demand with RE. These impressive results in the renewable electricity realm have attracted international attention and recognition. Numerous individuals and organizations, including Al Gore, Paul Krugman, and Greenpeace, share the optimistic view that Germany is now demonstrating that a totally decarbonized economy is both technically feasible and affordable.
But it is by no means clear that the addition of huge new RE capacity to the German electricity grid is translating into the desired outcome of reduced carbon emissions. As I have shown, the situation in the power sector is extraordinarily complex and the addition of RE capacity does not in any straightforward way displace fossil-based electricity; indeed, in some cases it has led to the increased use of cheap fossil fuels. Moreover, emissions are not determined by the power sector alone; RE deployment lags behind targeted deployment levels in the two other major energy sectors, transport and heat, making it difficult to meet the targeted RE share of the gross final energy consumption without adding yet another layer of regulation.
It seems that emissions reductions have for the most part been driven by entirely different forces than the Energiewende so far.
Current trends show a much slower reduction in carbon emissions than is needed to even come close to meeting the minimum target of 80% reduction by 2050. More perplexingly, the contribution of the power sector itself to reductions so far is quite minimal. Indeed, it seems that emissions reductions have for the most part been driven by entirely different forces than the Energiewende so far. Germany’s GHG emissions have decreased by 27% since 1990, yet more than the half of this decline was achieved before the European Union ratified the Kyoto Protocol, before the first regulations to mitigate climate change became effective, and before the sophisticated European cap-and-trade system was established. These pre-Kyoto achievements were primarily related to the deliberate selection of 1990 as the reference for measuring emission reductions, since it marked the beginning of eastern Germany’s economic breakdown and consequent reduction in energy use in the wake of reunification. Early voluntary commitments to climate mitigation by several industrial branches also contributed to the pre-Kyoto carbon reductions, but these were based mostly on substitution of natural gas for coal and oil. The global economic recession that started in 2008 also contributed to lower energy use and thus reduced emissions.
The post-Kyoto measures have led to relatively little mitigation in the intervening years. In fact, between 2009 and 2014, as 44,425 MW of RE capacity was added to the German power system, emissions increased. This occurred, in part, because zero-carbon nuclear facilities had to be replaced with carbon-intensive coal and gas plants. At the same time, all of the new RE capacity helped to drive down wholesale electricity prices. The European Emissions Trading System, which was supposed to be a market tool for reducing GHG emissions, proved instead to be a playing field for speculators hoping to profit from boom-and-bust cycles. And bust has been much more the norm as the emission trading rules and the rapid deployment of RE led to reduced production of fossil energy and a consequent glut of carbon allowances, whose value declined from above €20/ton of carbon dioxide emitted in 2008 to less than €3/ton in 2013 to just above €4/ton at the end of 2016. These very low allowance prices sent the wrong signals to the market and ended up making lignite and hard coal economically attractive, thus further contributing to the absolute increase of carbon emissions.
To date, then, the Energiewende’s record is mixed, but very troubling. On the plus side is continued public support and a very impressive ramping up of RE capacity. But on the deficit side of the ledger are exploding energy costs, failed policy tools such as the German and European Union trading schemes, and hard-hit institutional actors—above all the major utilities, which increasingly look as though they have been consciously sacrificed to help Germany to meet its ambitious GHG emission targets. But these targets are not being met.
The major challenge for Energiewende-like programs is to integrate intermittent sources of power into existing energy systems. But despite all efforts to convert excess electrical power to hydrogen, methane, heat, or other storable commodities, and despite all progress made in battery research, storing the electricity necessary to solve Germany’s intermittency problem remains technologically, economically, and politically out of reach.
An optimist might declare that the very fact that Germany’s electricity grid has not collapsed must mean that the intermittency problem is well on the way to being solved. In reality, collapse has been averted only through two mechanisms that run directly counter to the goals of the Energiewende. First, the intermittency balancing problems on cloudy and windless days could be managed only because utilities backed up intermittencies by running fossil power plants—and running them in ways that were uneconomic and especially bad for the environment. Second, Germany’s electricity generation on windy and sunny days exceeded, often by far, the grid’s balancing abilities, forcing the power surplus into adjacent grids, and obliging other countries to compensate for German intermittencies, which can lead to disturbances and additional costs in the other grids. Thus, these solutions are neither economically sustainable nor carbon-free. In the absence of nuclear power, Germany’s transition to a low-carbon energy system depends on its ability to store enough cleanly—and affordably—generated electricity to compensate for the intermittencies created by the massive introduction of REs. Until this problem is solved, the Energiewende will remain, above all, a testimony to the unintended consequences that result from well-meaning intervention by Dichter und Denker—poets and thinkers—into complex social and technological systems.
Christine Sturm served until 2016 in several management positions inside the renewable energy arm of RWE, one of Germany’s largest utility groups.
The most important information about Germany’s energy transition can be found on the website of the Federal Ministry for Economic Affairs and Energy, at www.bmwi.de. Many pieces are available in English.
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