Germany has chosen to transform its energy system within a few decades—an ambition that has evoked equal admiration and confusion. Has Europe’s largest economy embarked on a rational path to an energy future that will make it the bellwether for global acceptance of renewables, or will the complex array of current challenges encumber its grand transformation?

A comprehensive legislative package passed by Germany’s federal cabinet and its bicameral legislature (comprising the Bundesrat, the federal council, and the Bundestag, the federal parliament) in the summer following Japan’s Fukushima nuclear catastrophe in 2011 adopted 120 individual measures previously proposed in a 2010-unveiled “Energy Concept” and laid the groundwork for Germany to set its energy supply system on a new footing by the middle of the century.

The transition to a new energy era—described by the German term Energiewende —will be a “Herculean task,” German Chancellor Angela Merkel has admitted, bigger, perhaps, than efforts to bridge the infrastructure development gap following German reunification. But if the transition is successful, Germany could model how an export-oriented industrial nation staking its future on a high share of renewables can be globally competitive. If it stalls, the nation with the world’s fourth-largest economy by nominal gross domestic product could flounder economically, miring grandiose ambitions in the European Union (EU)—and around the world—to combat climate change with renewables.

Making an Energy Transition

The goals of the transition are certainly “ambitious” for Germany, an industrial heavyweight, but they are “clear,” Federal Minister of Economics and Technology Philip Rösler contends in a recent policy brochure. Along with a complete withdrawal from nuclear power by 2022, the country will strive to replace 80% of electricity generated today by conventional sources with renewables by 2050 and shave energy consumption by a fifth. Complex hurdles will have to be overcome, Rösler acknowledges. “[The transition] goes hand in hand with the necessary grids, power stations and storage technologies, and therefore involves the development of a completely new energy system,” he says. And the only way to achieve it without putting an “undue burden” on businesses and consumers and to ensure long-term acceptance of the transition is to prioritize “technology-neutral, market-oriented, and cost-effective instruments.”

It helps that Germany has been on a sustainability trajectory for awhile, some industry observers point out. The term Energiewende was coined three decades ago, in response to the oil shocks of the 1970s, by Öko-Institut, an ecological think tank that defined the transition as “growth and prosperity without oil or uranium.” That idea took root in political discourse during the 1980s, and in 1991, the first feed-in-tariff (FIT) policy backing renewables was introduced. After it was revised and extended in 2000, Germany enacted the Renewable Energy Sources Act ( Erneuerbare-Energien-Gesetz, or EEG)—the policy that perhaps most forcefully drives Germany’s post-Fukushima energy transition.

Nuclear’s Slow Death

In 2000, under then-Chancellor Gerhard Schröder, Germany’s first center-left coalition of Social Democrats (SDP) and the Green Party implemented a nuclear phase-out with the passage of Atomausstieg, a controversial policy change that stymied nuclear generators’ unlimited lifetime licenses and strong legal guarantees. Under that law, the country’s 19 then-operational nuclear plants were allotted a specific amount of electricity (2,623 billion kWh, or an average of 32 years) of lifetime production that they could feed to the grid before mandatory shutdown. It allowed those hefty allowances to be sold or transferred to other power plants for a profit, however, ameliorating protests from nuclear generators—particularly newly born E.ON, which amassed ownership of 12 of the 19 reactors after the merger of Germany’s biggest utilities, Veba and Viag. The industry-government compromise also included a government commitment not to introduce any “one-sided” taxation measures.

Just a decade later, in an attempt to lay the groundwork for future German energy policy to mitigate climate change, and—as a global recession raged—to reap a portion of tremendous profits utilities said they would earn if reactor lifetimes were extended from the average 32 years to 60 years (as in the U.S.), the coalition government of Chancellor Angela Merkel agreed to levy a €2.3 billion annual tax on the country’s four nuclear owners—RWE, E.ON, EnBW, and Vattenfall Europe. In return they got permission to operate reactors on average 12 years beyond 2021. The tax was to be used to subsidize renewables until at least 2016.

Merkel—a former environment minister in the mid-1990s under conservative Chancellor Helmut Kohl—was in September 2010 the head of a grand center-right coalition government that included her own liberal-conservative Christian Democratic Union (CDU), the Christian Social Union (CSU), and the business-friendly Free Democratic Party (FDP). She had then called the reactor lifetime extension compromise “a reasonable technical solution,” noting that at the time, nuclear power accounted for about 22.6% of net electricity consumption. Merkel’s assessment that the renewable sector was not capable of filling the energy gap if Germany was entirely rid of nuclear power was directly in line with the coalition’s newly unveiled “Energy Concept”—the ambitious energy policy with a 40-year trajectory that called for, by 2050, greenhouse gas cuts of at least 80%, increasing renewables to 80% in electricity supply, and a 50% reduction in primary energy consumption compared to 2008 levels.

The Pushback

Then the natural and nuclear disaster at Fukushima happened. In the whirlwind of events following the Japanese catastrophe in March 2011, Merkel’s government reversed its stance on nuclear power and, citing safety concerns, immediately instituted a three-month moratorium on all nuclear plant operation for safety checks. Merkel later decreed that seven of Germany’s plants, which began operation in 1980 or earlier (and later, another one already in long-term shutdown), would be shuttered (Figure 1).

1. A nuclear snub. In 2010, Germany’s nuclear fleet comprised 17 operating reactors (six boiling water reactors and 11 pressurized water reactors, all built by Siemens-KWU), the last of which began commercial operations in 1989. After Fukushima, the government shuttered eight reactors, and the remaining nine are scheduled to close by the end of 2022. Sources: POWER, World Nuclear Association

In June 2011, the cabinet and parliament passed a set of six laws and one ordinance—the so-called “Energy Package”—that adopted 120 individual measures of the 2010 “Energy Concept” and cemented a plan to permanently decommission all 17 of the nation’s reactors by 2022—without abolishing the nuclear fuel tax agreed to in September 2010.

Energiewende was officially under way, giving the power-intensive nation just over a decade to increase renewable generation from 17%, as it stood then, to 35%. Saying the country’s grid would remain “controllable,” the Federal Network Agency ( Bundesnetzagentur) urged states to approve more than a dozen new coal and gas plants and transmission upgrades over the next several years.

In the aftermath of the nuclear moratorium, the country’s four major nuclear plant operators called foul, loudly. Robbed of allowances to produce the considerable remaining gigawatt-hours awarded by the Schröder government, RWE head Jürgen Grossmann called the phase-out decision a gross breach of property rights. E.ON’s CEO Johannes Teyssen warned of substantial financial losses, and Vattenfall CEO Oystein Loseth demanded “fair compensation” for losses as a result of the decision, based on “writing off” the plants, cancelled upgrades scheduled after September 2010, and decommissioning costs.

The utilities have turned to the courts and since won some crucial victories. Challenges that the nuclear fuel tax—which amounted to €1.5 billion by January 2013 within two years—could not qualify as a consumption tax were granted by the Hamburg Tax Court in September 2011, leading to refunds of €74 million for E.ON and €96 million for RWE. The federal government, however, later contested the tax court’s ruling and resumed collection of the tax, prompting the Hamburg court to rule more definitively that the German tax on nuclear fuel was simply “to siphon off the profits of the nuclear plant operators.” The Constitutional Court is now reviewing the case.

The German government is meanwhile struggling to fend off generator requests for more than €30 billion in compensation for confiscation of generating rights and costs associated with closure of the eight reactors. In February 2013, the administrative court for the German state of Hesse found the state ministry had no legal grounds when it ordered, on decree from the Merkel administration, shutdown of RWE’s Biblis A and B reactors. Damages are set to be decided in upcoming civil court proceedings.

A Renewable Lifeline

In 2011 critics denounced the decision to phase out nuclear and replace it with renewables as a “moral imperative” rather than an economic one. An assortment of think tanks warned of a “cost-tsunami” that was about to hit Germany and increase industrial operating costs by nearly a fifth in the country that already had one of the highest power prices in the EU. Meanwhile, the term “green-paradox” was coined and went viral, expressing a much-maligned support for renewables that had little impact on carbon emission mitigation.

But against the backdrop of the decade-long nuclear contests, the FIT system (as established by the EEG in 1991) that obligated supply companies to purchase wind, solar, and biomass power and then pass costs to consumers was fueling tremendous growth of renewables. Between 2000 and 2010—under a looming urgency to secure energy supplies posed by the Schröder nuclear phaseout—the share of renewables in Germany’s power profile soared from 6.4% (37 TWh) to 17% (103 TWh), and installed nameplate capacities surged by almost 500%, from 12 GW to 56 GW. Photovoltaics (PV) fared the best, buoyed by the highest FIT of all technologies, with an average compensation of 47¢/kWh in 2010, bringing in a total €3.9 billion that year.

According to government statistics, the closure of the eight reactors in March 2011 prompted another mammoth wave of new renewables installations. The share of renewable capacity in the total generation mix increased from 34% at the end of 2010 to a stunning 41% in July 2012 (Figure 2). Comparatively, the total amount of power generated by renewables was 115.2 TWh (Figure 3), or about 20.9% of the nation’s 551.4 TWh. About 91.2 TWh was eligible for remuneration under the EEG.

2. Capacity on the German power grid. As of July 2012, Germany’s total installed generation capacity of 67.5 GW was characterized by 30.5 GW of net nominal solar power capacity, followed by wind power at 29.3 GW. The two renewable sources soar well ahead of hard coal’s 20.5 GW, the third-highest installed capacity. More nonrenewable energy sources (a total of 101.182 MW) were installed than renewable sources (71.181 MW), however. Sources: Federal Network Agency, Federal Cartel Office

3. Net total power generated in 2011. Of a total 551.4 TWh generated by German power plants in 2011, renewable energy sources (in dark green) generated 115.2 TWh, or about 21%. Nonrenewable energy sources generated the remaining 435.2 TWh, led by brown coal (21%), and followed by nuclear power (17%), hard coal (14%), and natural gas (11%). Sources: Federal Network Agency, Federal Cartel Office

That may all be poised to change, however. This year, a renewable surcharge on private consumer electricity bills rose to a record 5.28¢/kWh, up 50% from 2012, 3.530¢/kWh in 2011, and 2.407¢/kWh in 2010. Meanwhile, the differential cost between the compensation agreed to under the EEG and the revenue from selling renewable electricity supplied to the grid has risen from €0.9 billion in 2000 to roughly €13 billion in 2011. Reports estimate that the average German household currently pays €180 ($242) per year to subsidize renewable energy, highlighting that no upper limit on Germany’s subsidies for renewables has been set.

Responding to a renewed outcry about the burden of the EEG on consumers, Environment Minister Peter Altmaier and Economics Minister Rösler proposed a short-term amendment of the EEG to rein in runaway costs, attempting to put a lid on the surcharge at 5.28¢ through 2014 and limiting its rise to 2.5% per year beginning in 2015.

Critically, the measure includes a €1.2 billion saving measure that would see FITs for new renewables (with the exception of PV) commissioned after August 2013 that would be equal to the market value of electricity for the first five months after commissioning and slashes FITs for onshore wind power to 8¢/kWh (compared to the current 8.8¢/kWh). For all other existing plants commissioned before August 2013, a 1.5% flat-rate reduction will apply in 2014 and is limited to that year.

No changes are planned for PV, experts point out, because existing policy mechanisms contain a volume-responsive degression model designed to keep annual PV installations within a target “corridor” of 2.5 GW to 3.5 GW. PV rates change on a monthly basis, and as of October 2012, degression is adjusted every three months based on the amount of PV capacity installed during the prior 12-month period. Exceeding the target corridor sets off a standard decrease that starts at 1% per month. This means, technically, the FIT price could decrease by a maximum of 29% or increase by up to 6% over a 12-month period. And it’s working: Following a record 7.5 GW of new PV installations in 2011, new installations fell three months in a row at the end of 2012—though last year still saw another record of 7.6 GW in new PV installations (Germany’s FIT-eligible PV total in January 2013 was 32.7 GW). The 2012 record means solar FITs will see a 2.2% reduction each month from February to April 2013.

Although stakeholders seem to agree that surging power prices could capsize Energiewende, the proposal has been met with skepticism by industry and lambasted by environmental groups, which say it would massively unsettle investors.

Experts, meanwhile have largely dismissed the move by the two ministers as a ploy to score points for conservatives running in the upcoming Sept. 22 federal elections. “Altmaier’s plan is both, at best half-cooked, but also clever. It does not address important topics such as the further integration of renewables into the German/European energy system, the future design of the electricity market or adverse distribution effects,” wrote Frankfurt-based Deutsche Bank in a note to investors in March. In light of the current SDP/Green majority in the Bundesrat, moreover, “it is doubtful whether the ruling CDU/CSU/FDP coalition will be able to find the necessary majorities for this proposal. In addition, the constitutionality particularly of the proposed 1.5% reduction of feed-in tariffs for existing plants in 2014 will surely be questioned,” Dr. Matthias Lang, an energy lawyer at Bird & Bird LLP in Düsseldorf and author of the “German Energy Blog,” said in February.

Lang noted that the umbrella organization of German industry (BDI) had also presented a proposal to check rising EEG surcharges. Among five measures it proposes are those that abolish compensation that renewable generators receive per the EEG if grid operators must curtail renewables input that stem from grid bottlenecks. It also calls for a strong signal on the EU level for proper functioning of the European Emissions Trading System (EU-ETS) and a new market-oriented electricity market design on the federal level and in the states.

The current system resulted in conventional power plants, particularly gas-fired generators, that were increasingly unprofitable, the BDI asserted. Federal figures estimate that of a total 172.4 GW of Germany’s installed capacity, about 2.7 GW of non-intermittent generation capacity is in cold reserve status—mostly in the north. This capacity is unable to relieve the increasingly tense supply situation in the south, but could become operational within six months.

A Cloudy Outlook

Permanent shutdown of the eight nuclear reactors in March 2011 resulted in an immediate “loss” of about 32.5 TWh of nuclear generation in 2011 and, experts estimate, could result in a loss of 41 TWh over 2012 and 2013. Reduced nuclear generation as a result of the moratorium was compensated for mostly by increased renewables generation (5 TWh) and a significant reduction in net exports (6 TWh). Between July 2011 and June 2012, however, data show a gradual adapting of the demand and supply balance to the new situation: By mid-2012, renewable generation reached 11 TWh—a level projected to be reached this year—and net exports increased again to 2010 levels. At the same time, electricity demand did not increase.

Renewable generation is expected to surge to between 231 TWh and 283 TWh by 2025 under separate scenarios from the federal ministries of Environment and Economy. More ambitious political targets from the federal states, explained partly by different expectations for the growth of onshore wind power, project renewable generation could reach 315 TWh as early as 2020 (Figure 4). If these projections are achieved by 2020, technically, renewables could exceed the roughly 140 TWh generated by Germany’s operational nuclear fleet in 2010.

4. Comparison of renewable generation projections through 2025. Scenario studies commissioned by the federal ministries of Environment (BMU) and Economy (BMWi), and one from a German grid operator project that renewable generation will range between 199 TWh and 315 TWh by 2020. Compared with 2011, when renewables generated about 115.2 TWh, that represents a 72% to 173% increase. Sources: POWER, Federal Network Agency, DENA, BMU, BMWi

A bevy of studies since 2011 examining the effect of the nuclear phaseout on power generation, cost, emissions, and security of supply in Germany concede that Germany’s best chances of replacing its nuclear power capacity while meeting long-term climate protection targets (and most studies conclude that it is possible) will require substantially decreased exports to the Netherlands and Austria, increased imports from France and the Czech Republic, a grid expansion, and increased reliance (about 21 GW) on coal and gas plants.

As evidenced over the two winters since the announced nuclear phaseout, Germany’s supply issues will be most critical in the winter, when France typically relies on imports from Germany (because it relies on power for domestic heating). But it will likely also rely on imports to meet certain demand conditions, analyses from the European Network of Transmission System Operators (ENTSO-E) and research firm Prognos show. A number of scenario analyses forecast tight generation capacity in the southern regions, where most of the phased-out nuclear power is concentrated, and suggest excess power from the north should be rerouted to the south—a recommendation strongly advocated by the Federal Network Agency and ministries involved with the transition.

The Grid Dilemma

In the immediate aftermath of eliminating nearly 5 GW of secured generation capacity in the southern German region alone following Fukushima, the Federal Network Agency, in conjunction with German transmission system operators, warned that failure of key network equipment or a major power plant—caused by potential overloading of transmission routes and by voltage control in the southern region—could critically jeopardize security and reliability of the German power supply. But when asked to decide by parliament by August 2011 whether one of the decommissioned reactors should be designated as a “cold reserve” plant to ensure security, the Federal Network Agency claimed that even with the disturbances it had warned about, system security in the transmission network could be guaranteed—if a variety of measures were taken into account.

In May 2012, at the German Energy Agency’s (DENA’s) behest, the nation’s four grid operators (TSOs)—50Hertz, Amprion, TenneT TSO, and TransnetBW—drew up a joint network development plan identifying necessary expansions to help transmit power from the North and Baltic Sea, where many offshore wind parks are being planned and built, to industrialized areas in southern and western Germany. Assuming wind power was the primary driver of the expansion and increased from 27 GW in 2012 to 51 GW by 2020, at minimum, 4,400 km of existing lines would need to be optimized and 3,800 km of power lines (1,700 km of new alternating current and 2,100 km of new direct current) would need to be built. This could cost in the vicinity of €20 billion over the next decade, the TSOs said.

The urgency of an accelerated grid expansion has been underlined several times since last May by individual grid operators—as well as by the Federal Grid Agency, which warned that nuclear plant closures had brought the nation’s transmission grids “to the edge of their resilience.” Over the past two years, the network has seen several near-misses, the most worrisome among them the periods between Christmas and New Year’s Eve in 2011 and in the midst of a February 2012 cold spell. And this March, 50Hertz revealed in its full-year results for 2012 that it had to curtail generation from renewable power producers (the last tactic to maintain reliability after reducing generation from conventional plants) to avoid oversupply on 77 days last year—almost double the 45 days in 2011.

The government has responded by making grid expansion a priority. The TSOs’ so-called “Grid Development Plan” forms the basis of the “Federal Requirement Plan for Transmission Networks,” which identifies as “urgent” under the German Energy Act a total of 36 projects, including three north-to-south electricity highways and 21 projects that traverse state or country borders. The cabinet in December 2012 agreed to fast-track construction (within four years) of 2,800 km of new power lines and upgrade of 2,900 km by designating, with approval from the country’s 16 federal states, the Federal Grid Agency as the only competent planning authority and allocating legal disputes concerning the expansion to a single federal administrative court. The plan will cost, without accounting for costs of underground cables, about €10 billion, the government claims.

Meanwhile, distribution grids, which connect smaller renewables installations and conventional power stations, will also require considerable expansion and modernization, the scale of which will depend on specific tasks assigned to the nation’s 800-plus distribution grid operators when developing smart grids. With liberalization of the electricity market and expansion of renewable sources, distribution grid mandates have mounted, requiring, for example, that operators ensure their grids remain stable despite increased levels of intermittent generation.

Yet progress has all but stopped. An evaluation of TSO data from October 2012 shows a large portion of the planned power lines prioritized to be newly built or upgraded much earlier, under the 2009 Power Grid Expansion Act (EnLAG), have been stalled by delays (Figure 5): Of the total 1,834 km of extra-high-voltage power lines, just 214 km (nearly 12%) have been completed. During 2012, only 35 km were expected to be added. This year could see the much-needed completion of a key line that could secure system reliability in the greater Hamburg region and all of northern Germany, which is absorbing the impact of decommissioning the closed Krümmel and Brunsbüttel nuclear reactors.

5. Super-charged ambitions. As this October 2012 map from the Federal Network Agency shows, of 1,834 kilometers (km) of Germany’s extra-high-voltage lines that are on the fast track to be newly built or upgraded under the 2009 Power Grid Expansion Act, just 215 km—about 12%—have been completed. In 2012, only 35 km were expected to be added. Germany’s existing extra-high-voltage grid of 17,610 km is webbed over its 16 federal states. The grid is overseen by the four transmission system operators whose areas are shown here. Source: Federal Network Agency

Security of Supply

Directly tackling unpredictability in supply to the grid from renewables, the government is enforcing a number of measures, including passage of an ordinance that requires nearly 400,000 older PV systems over 10 kW to be upgraded to avoid simultaneous shutdown when a frequency of 50.2 Hz is exceeded. Reaching a frequency of 50.2 Hz is unusual—but it could happen, experts say, especially in situations where electricity production is higher than demand due to a grid disturbance. In November 2006, frequencies reached 50.2 Hz in Germany when power failed first in Cologne, Germany, before shutting down across parts of France, Italy, Spain, and Austria and cutting power to 15 million people across the rest of Europe.

Major power consumers are also able to make loads available to grid operators for load reduction and shutdowns, to provide TSOs with an added means of balancing electricity fluctuations. “The Ordinance on interruptible loads has opened up new possibilities for developing load management potential,” the Economics Ministry said in a statement. And the Federal Network Agency and grid operators had reportedly contracted adequate reserve capacities for winter months, increasing from about 1 GW in 2011 to about 2.6 GW earlier this year.

Efforts are also under way to upgrade distribution grids to accommodate smart grid technologies and prepare for a high percentage of renewables. The Economics and Environment ministries recently completed a €140 million four-year study in six pilot regions, testing information and communication technologies, including smart grids in rural areas and virtual power plants (a list of the projects is available at http://bit.ly/11k3hgH). The “E-Energy” program reportedly demonstrated that the energy consumption of private households could be reduced by up to 10% using intelligent systems and appropriate incentive mechanisms.

On the generation side, the government has boosted incentives for investment in combined heat and power generation. To enhance reliability, it has also established liability rules for delays and disruption to the connection of offshore wind parks. A tremendous amount of offshore wind—from 100 MW to 13,000 MW—is expected to play a major role in Energiewende through 2050.

Grid operator TenneT, which bought the 11,000-km-long grid network from E.ON in 2011 and has been tasked with connecting all wind parks in the North Sea, has warned of looming bottlenecks stemming from “major difficulties in planning and building progress.” Showing symptoms suffered generally by the global offshore wind sector, growth of Germany’s offshore wind market has been stunted as participants “reached the limits of their resources,” facing “severe problems with financing,” TenneT said. German politicians blame the Dutch company for the repeated delays, however, saying TenneT apparently lacks both the right management and necessary equity capital to establish urgently needed connections to the wind farms owned by major utilities like RWE and E.ON.

The issue has also prompted calls for the creation of a national grid company with public investment, and many—among them, power companies and pro-industry politicians—recognize its possible benefits. If grid owners that oversee the country’s four grid zones—which suffer different line prices and individual control stations and control centers—were combined, both administrative costs and electricity prices could be slashed, say executives at E.ON.

A Desperate Need for Storage

Germany also must deal with a huge temporal power surplus, extremely large load gradients, and long “calms”—periods of low wind, typically experienced in the winter. Holger Gassner, head of markets and political affairs at RWE Innogy GmbH, estimates that in 2050, a 10-day span when wind farms generate less than 10% of capacity would require 313 times the current pumped storage capacity to bridge the “calm.”

In its first crucial step to address this predicament, the government in the summer of 2011 defined grid fee exemptions for electrical energy storage facilities and existing pumped storage; it later attempted to improve policy conditions for investments in pumped storage plants. As have other industry observers, Jens Hobolm of the European Center for Economic Research and Strategy Consulting points out that pumped storage potential in neighboring Scandinavian reservoirs is 2,300 times that available in Germany, where 30 pumped storage plants have a capacity of 6.8 GW; when magazines are fully loaded, they can run for 4 to 8 hours and produce a total of 0.04 TWh.

Noting that surplus electricity—to the tune of 38 TWh by 2050—reserve power, and ancillary services would be Germany’s foremost challenges over latter period of the transition, Hobolm suggests 7 GW to 12 GW of new interconnectors between Germany, Norway, and Sweden, of mutual economic benefit, could be built so that about 10 TWh to 20 TWh (26% to 52%) of Germany’s surplus electricity could be stored there.

That front, too, is seeing progress. In March, Norwegian and Dutch power grid operators, Statnett and TenneT, along with German development bank KfW, announced plans to build NORD.LINK, a 1,400-MW high-voltage undersea connection. A final decision wouldn’t be made until 2014, though developers have announced planning of a second €2 billion link, NorGer, that could possibly materialize within a decade.

Meanwhile, it has been suggested that until at least 2020, storage capacities in the Alps could help store surplus PV electricity from southern Germany. But, notwithstanding the time and cost required to build new pumped storage capacity, several experts have warned that the role Scandinavia can play in such a scenario is unclear. Norway, for example, holds hydro reservoirs of 84 TWh—half of all Europe’s hydro storage capacity—and already acts as a “green battery” for Denmark and the Netherlands. Hydro storage expansion would need political action on Norway’s current electricity policy that far exceeds 2020 and would have to consider a multitude of technical, economic, and environmental implications.

Carbon Commitments and a Dash to Coal

One of the EU’s core member states, Germany has been at the forefront of the continent’s efforts to curb carbon emissions, spearheading the European energy and climate package in 2007 under the German EU presidency. The so-called “20-20-20” package called for greenhouse gas reductions of at least 20% of 1990 levels by 2020, increasing use of renewables to 20% of total energy production by 2020, and cutting energy consumption by 20% of projected 2020 levels by improving energy efficiency. Yet Germany’s own climate targets, driven by environmental movements in the Green Party, are more ambitious than the EU’s: a 40% reduction of greenhouse gas emissions by 2020 and 80% to 95% in 2050.

Though Energiewende was designed to complement those goals, Germany’s carbon dioxide (CO₂) emissions are on the rise, as the Environment Ministry noted this February, increasing 1.6% (932 million tonnes of CO₂ equivalent per year). The ministry, which brushed off the increase, saying the nation had “comfortably” met its Kyoto Protocol targets, coming in 193 million tonnes per year under its target by the commitment date in 2012, pegged the increase on unusually cold weather and heightened use of coal. Had shuttered nuclear reactors operated as planned, critics pointed out, and Energiewende not been instituted, Germany could have reduced its carbon emissions to an all-time low of 897 million tonnes per year.

But Germany needs coal, experts say. In the two years since the nuclear moratorium, the nation has urgently needed new baseload power plants to shoulder the country’s annual peak load of 80 GW. Only about 12 GW of the nation’s reliably available capacity of 160 GW is currently met by renewables, which includes wind power to a minor extent, and is mostly hydropower. “How great this need for conventional power plant capacity actually is depends on a number of variables,” says the Economics Ministry, adding that “it is… very difficult to put a figure on the power plant capacity needed.” The future expansion of renewable energy plants, the possibility of using an interregional system to balance fluctuating supply and demand in the electricity market, and the continued development of storage technologies are just some of the factors that come into play, it adds.

Environmental and citizen groups have launched numerous legal challenges, and successfully stalled development of several coal projects. Meanwhile, rejection of a draft bill to allow pumping of CO₂ underground into former gas storage facilities in 2011 has slowed plans for carbon capture and storage and derailed government plans to curb carbon emissions that way. Vattenfall in December 2011 shelved demonstration of an oxy-combustion carbon capture technology at Jänschwalde in Brandenburg, and no efforts have been made to restart it.

A common complaint from industry stakeholders is that a regulatory framework for the conventional power plant market has to be redesigned. An amendment of the German Energy Act that became effective in January provides only for the possibility to postpone planned shutdowns of power plants to improve the security of supply, but incentives for new state-of-the-art power plants that can balance the fluctuating input of renewables still have to be set.

That hasn’t deterred conventional hard coal–fired power plants from increasing their share of power production to 19.1% in 2012 (jumping from 18.5% in 2011). Lignite-fired plants remain the most important power producers in Germany, increasing their share in the electricity mix to 25.6% (from 24.6% in 2011). And until 2015, most of Germany’s new-build conventional power plant capacity will be coal-based, analysts say, pointing at a project pipeline of 8 GW of new coal-fired capacity compared with 1 GW of new gas-fired installations.

The main reason for new coal plants: pure economics. According to early November 2012 estimates from research firm Bloomberg New Energy Finance, German utilities were set to lose an average €11.70/MW but gain €14.22/MW when they combusted coal. Another looming policy change fueling the rush to burn more coal over gas is that in 2016, an EU directive will become effective that will force utilities to either close coal-fired plants that do not meet new environmental standards or install costly pollution control devices.

Of 13 coal plants proposed since 2007, two plants had come online by November 2012: Vattenfall’s €2.2 billion, 675-MW lignite-fired Boxberg plant in Saxony, and RWE’s €2.6 billion, 2.2-GW BoA 2&3 in North Rhine–Westphalia. Eight others were under construction, all fired by hard coal. These include E.ON’s 1.1-GW Datteln plant in North Rhine–Westphalia and Vattenfall’s innovative heat and power 1.6-GW Hamburg-Moorburg plant. Both are expected to begin operations in 2014. Three others are in the planning phase: two lignite plants and a hard coal plant.

Particularly noteworthy is that many plants in Germany’s new coal-fired fleet are designed for flexibility. RWE’s August 2012–commissioned BoA 2&3 (Figure 6) near Cologne, for example, has rapid-response capabilities. Each lignite-fired unit can modify its output by 500 MW in just 15 minutes, the utility says. The plant also uniquely stores its pulverized coal in a silo to more easily control how much is fed to the boiler. That enables it to power down to as little as 10% of its maximum output. Other companies are exploring manufacturing boiler walls with thinner, special steel alloys that can withstand rapid and extreme changes in temperature occurring when a plant’s output is adjusted up or down.

6. A coal irony. The European Union’s carbon emissions have been on the rise since the global recession two years ago, despite mandates to cut them to 80% of 1990 levels by 2020 and the prevalence of its emissions trading scheme. Germany will start up 5.3 GW of new coal capacity this year alone as its utilities bank on coal’s cost advantage over more-expensive oil-indexed natural gas. New plants—such as RWE’s BoA 2&3 (shown here), a 2.2-MW lignite-fired plant commissioned in August 2012 in Grevenbroich-Neurath near Cologne—will feature advanced technology. These twin units are reportedly able to offset the intermittency of renewables by modifying output by 500 MW within 15 minutes. Courtesy: RWE

A Gas Daze

A new fleet of power plants fired by natural gas may have better fit the jagged generation gap left by the nuclear phaseout, given gas power’s reduced carbon emissions and flexibility to balance feed-in variations. But last year, cheap coal imports and low carbon trading prices negatively impacted spark spreads and squeezed natural gas–fired power plants to the margins or out of the merit order.

Locked into expensive oil-indexed gas supply contracts while still gradually negotiating discounts from producers such as Norway’s Statoil and Russia’s Gazprom, gas generators are seeing adverse market conditions that are driving down negative profit margins. Some are already mothballing or considering decommissioning existing gas plants in Germany.

E.ON, which spent €400 million just three years ago to build its state-of-the-art Irsching 5 unit, an 847-MW advanced combined cycle power plant near Ingolstadt, is looking to close the plant because last year it operated less than 25% of the time it was designed for. “If the plant keeps putting up red figures, it makes little sense to keep it operational,” an E.ON spokeswoman said. “No decision has been taken to date,” as the plant’s operators were still in negotiations with the Bavarian government and the grid operator TenneT, she said. In March, meanwhile, Norwegian generator Statkraft put into cold reserve its 510-MW Robert Frank plant (Figure 7) in Landesbergen after grid operator TenneT classified it as “non-system relevant.”

7. A gas suspension. Though gas power is seen as more efficient and environmentally friendly than coal as a complement to renewable power in Germany, market conditions have made it uneconomical for generators like Statkraft to operate older gas plants. The Norwegian firm in March put its 510-MW gas-fired Robert Frank plant (shown here) in Landesbergen, Lower Saxony, into cold reserve. Formerly owned by E.ON, the 1962-built combined cycle plant with a net efficiency of 43% was the first large gas power station in Germany. Courtesy: Statkraft

“Unfortunately, the market perspectives for gas-to-power in Germany have continued to deteriorate over the past twelve months,” Dr. Jürgen Tzschoppe, senior vice president of continental energy at Statkraft explained in a statement. “Based on the current market status, it is not possible to operate the plant economically. And we cannot justify keeping a reserve unit in the portfolio while the efficient [combined cycle] power plants in Knapsack… and Herdecke are hardly running.” Statkraft, which is building another “ultra-modern” combined cycle gas and steam turbine plant at Knapsack, would “need to seriously look into the market design… yet to be created,” Tzschoppe said.

The effect on utilities with a high thermal power exposure has been devastating. RWE and E.ON have, for example, seen depressed gas businesses for three years even though European spot gas prices have fallen. And the outlook looks “bleak,” Josef Pospisil, head of utilities and transport at Fitch Ratings told reporters at a briefing in March. “It’s a fairly weak fundamental picture, one of weak demand, slight capacity increases, and unpredictable politics,” he said. Anti-coal politics could possibly generate a fundamental shift, but radical reforms are not expected this year, before the Sept. 22 national elections, he pointed out.

Germany’s ability to produce power from unconventional gas remains uncertain. Shale gas drilling has been a headline-making and contentious political subject that features prominently in the rhetoric of politicians seeking votes, and Merkel’s government in February unveiled a new draft law that permits development of the unconventional fossil fuel through fracking, albeit with conditions. These include environmental safeguards that outlaw fracking in protected areas and near drinking wells—an area estimated to cover about 14% of German territory.

The Larger Context

Germany’s decision to transition to an almost purely renewables-based system by 2050 wasn’t exactly abrupt, as some observers point out. It isn’t a Sonderweg —which suggests Germany is going it alone on the fringe of the continent’s mainstream—as Paul Hockenos, a blogger for a nonpartisan think tank, the German Council on Foreign Relations, argues. At least 11 of the EU’s 27 members have no nuclear power at all, while five others, including Italy, have pledged to phase out nuclear reactors altogether. And 18 EU countries have implemented renewable support policies similar to Germany’s.

Others note that Germany is a nation with nine direct neighbors and imports 100% of its consumed uranium, 98% of its oil, 82% of its natural gas, and 77% of its hard coal—and the bulk of oil and gas imports, about 35% each (more than the EU average), come from Russia. Until 2011, Germany had been a net electricity exporter, sending 58 TWh to its neighbors in 2010. After the eight nuclear reactors were shuttered in March 2011 by order of the government, a series of reports released by the Federal Network Agency analyzing scenarios under different conditions concluded that Germany would be able to generate sufficient power to cover its own electricity needs, but it could no longer support security of the European interconnected grid to the extent it had done previously.

Consequently, in the EU, Germany’s transition is being viewed with suspicion. A frequent critic of the country’s surging power prices is EU Energy Commissioner Günther Oettinger. The former head of the southern German state of Baden-Württemberg has cautioned that Germany is pushing energy sector reforms too fast, pointing out that investments in solar and wind power don’t match the speed of grid extension and storage capacity. And the transition is occurring without regard for a bigger European framework.

The consequences of Germany’s transition will not be limited to Germany, which borders so many other member nations, Oettinger has argued. In the EU, “All member states are aware of the need to transform their energy systems to ensure that they are sustainable in the long run and to enable Europe to reach its 20-20-20 targets. Moreover, they know that they need to act in cooperation. In an integrated market, this is the only way to ensure that the transformation will be a success.

“Let me give you an example: the integration of renewables into the grid will be possible only in a fully integrated and interconnected market. In a fragmented market the necessary investments would not be viable and hence would not take place,” he told IP Journal, a publication of the German Council on Foreign Relations.

Oettinger has reportedly suggested that as a first step toward a pan-European policy, some countries (possibly Germany, France, Belgium, the Netherlands, and Luxemburg, which make up the 2010-launched Central Western Europe market region and is the European hub of power trading) could set up joint market mechanisms and expansion targets for renewables.

But challenges remain before Europe can set up an internal electricity market by 2014, as planned, and one frequently cited hurdle is resolving whether the priority with which renewable electricity has to be purchased and marketed by grid operators under Germany’s EEG is compatible with the European Single Market.

Solutions are also being sought for insidious and unexpected surges of wind power from northern Germany that find a path of least resistance to the power-hungry south through circuitous routes via the grids of neighboring Poland, Hungary, the Czech Republic, and Slovakia. These “loop flows” have been blamed for congestion of cross-border transmission capacity and, worse, pose threats to the network security conditions of Germany’s neighbors, the affected countries’ grid operators said in a March 2012 report. Recently, the German Institute of Applied Ecology (Öko-Institut) said, however, that it could not confirm those findings, noting only that loop flows with Poland exceeded 2.5 GW once, in 2011, when wind production was between 4 GW and 8 GW.

Even so, France and the Netherlands have already installed phase-shifting transformers to redirect electricity by increasing transmission resistance as a defense against loop flows, and the Czech Republic and Poland are reportedly considering the same. As some experts point out, if its neighbors limit flows during power surges, the grid stability problem will be shifted back to Germany.

Seeking Future Solutions

Among Germany’s efforts to secure a reliable and affordable future energy supply is the adoption of a new research program, which has ear-marked funding of roughly €3.5 billion through 2014—75% more than from 2006 to 2009—to support development of sustainable energy technologies. The funds are split among support for nonnuclear energy technologies along the entire energy chain, ranging from high-efficiency production in modern power plants, decentralized energy systems, smart grids, and storage modules to energy usage in energy-optimized buildings and towns as well as efficient industrial processes.

But even these efforts have been opposed by critics, who say that though the technologies or concepts funded are indeed achievable, they are still far from being ready for market. Hampered by excessive costs, their operation could be delayed far beyond the politically desired timeframe due to other deficits, and they won’t play an immediate role in Germany’s energy transformation.

A better investment would have been to open up regenerative energy sources for heating markets instead. “Solar heat and use of the Earth’s warmth should have been advocated more effectively, yet this never came to pass. The use of distant heat from the deep layers of the Earth instead of the absurd unprofitable geothermal power plants would have been far wiser…. Available wind power in this country, where the potential for pump storage is poor, should be used solely to produce hydrogen which can be used in return as fuel or as a chemical commodity,” energy expert Dr. Günther Keil, asserts. The bottom line is that “New installations should be prohibited by law, or left to the laws of the free markets,” he says.

A Costly Rebalancing

Ultimately, reforming and restructuring Germany’s energy sector by the end of the 2030s could cost as much as €1 trillion, Environment Minister Altmaier said in February 2013. Most of these costs are related to renewable FITs, which could total some €680 billion by 2020—and increase if the market price of power falls, he warned.

The cost implications are tremendous for Germany, which has seen costs associated with energy consumption double over the past 12 years. Compared with €59 billion in 2000, energy spending spiked to €124 billion in 2011—an increase of 20% over 2010. The Economics Ministry blames higher energy prices for primary energy resources in the international commodity markets. But power prices, central to the competitiveness of German industry, have also surged, on the back of steadily rising taxes and levies—which today make up almost 40% of the price of industrial electricity. The expedited nuclear phaseout could add another 0.5¢ to 1.5¢/kWh, an enormous burden for power-intensive industries, for whom a price hike of around 1¢/kWh translates into an increase of roughly 20%. The Economics Ministry estimates additional costs for a large aluminum producer with a consumption rate of 4,000 GWh, for example, could surge to €40 million.

That’s why, the ministry says, the federal government agreed with the 2011 Energy Package to introduce compensatory arrangements for businesses competing at a global level, including measures to offset increases in the price of power stemming from the EU’s carbon emissions trade, and a cap on their renewables allocation charge. Cost reductions in 2012 for some 202 German firms, including steelmakers and those in the chemicals industry, amounted to €440 million. But that measure, too, is under fire: The EU Commission this March launched a formal probe into whether energy price cuts granted to these energy-intensive consumers constitutes a breach of anti-trust rules to the detriment of German consumers because, it says, the reductions are rolled over to ordinary Germans’ power bills.

According to researchers at the Institute of Economic Structures Research GWS, a private consulting firm in Osnabrück that carried out a cost-benefit analysis of the integration of renewables in Germany between 2008 and 2011, the benefits apparently “more or less” outweigh the costs—though, it cautions, several unresolved questions remain. It concludes “there is no sign yet of a final unequivocal judgement about the overall economic costs and benefits” of a renewable energy expansion. One plus would be added jobs: About 382,000 jobs were added last year to the burgeoning renewables sector (about 1% of the workforce), and by 2030—when renewables should make up at least 35% of Germany’s power profile—renewables jobs should increase to 600,000. Renewables also lower the price of power during the middle of the day by significant amounts—but increase household bills via the EEG surcharge, the group said.

Mounting Opposition

Energiewende’ s success is deeply rooted in wide public acceptance, but almost every facet required to ease the transition has been opposed by industry, citizen groups, and environmentalists. A substantial number of citizen action groups— Wutbürger (angry citizens)—have fiercely objected to the construction of new wind parks for noise and aesthetic reasons, for example. Pumped storage projects, high-voltage transmission projects, and carbon storage sites have also been protested, some successfully, as has construction of new advanced technology coal-fired power plants. Renewables, too, have been targeted by ecologists, who, unsettled by the effects of the energy transition across the country, protest clearing of forests for biomass or the conversion of tracts of land for solar and wind farms. That conflict has even driven a wedge within the Greens, splitting the political party that championed the nuclear phaseout in the 1980s and rallied for clean energy through the 1990s into proponents of the transition and stewards of the environment.

Rhetoric supporting a wide range of views backing or opposing facets of Energiewende has heightened and will likely get increasingly shrill until the September election at least. What happens beyond the election is a lot harder to discern.

— Sonal Patel is POWER’s senior writer.

Comments

The big energy companies economic model is directly threatened by the Energiewende! High renewables means fast acting variable response, not base load generation, see The Base Load Fallacy http://www.energyscience.org.au/BP16%20BaseLoad.pdf.

Energiewende’s success is deeply rooted in wide public acceptance."
And who owns 50% of renewable energy in Germany … individuals and farmers and the other 50% has a large proportion of local government ownership with returns better than money in the bank. And local energy cooperatives with a mix of individual, business and government investors are expanding, see Energy Cooperatives Citizens, communities and local economy http://www.dgrv.de/en/cooperatives/newcooperatives/energycooperatives.html.

Of course the returns need to be modulated and they are now that capital costs particularly of photovoltaic are reducing. See 12 Insights on Germany’s Energiewende http://www.agora-energiewende.de/fileadmin/downloads/publikationen/Agora_12_Insights_on_Germanys_Energiewende_web.pdf.

As we move towards high renewables, capacity payments for fast response but little used energy plants (coal, gas - biogas, SNG synthetic natural gas) will probably be needed in the future for the occasional low renewable energy (RE) week and peak demands but will add little cost to the price of energy.

Instead of dumping excess RE as we do now, it will be stored in the least cost and most efficient storage to create a viable energy system. Donc, a much greater role for District Heating, as the European energy demand for building heat is significant and its lower cost than electrical potential storage. So MW sized, high voltage grid heat pumps see Helsinki, in ground low cost inter-seasonal heat ponds with floating insulated covers, see Denmark, 4th generation low temperature distribution 55/25C which works for Passivhaus very low energy demand buildings at medium densities or the low density suburbs of individual houses, see Denmark.. But also all those very low priced RE sources such as the sun, see Marstal, Denmark, hot water aquifers, see Dogger, Paris… see EU JRC Background Report on EU-27 District Heating and Cooling Potentials, Barriers, Best Practice and Measures of Promotion http://setis.ec.europa.eu/system/files/1.DHCpotentials.pdf

Stocking potential electrical energy is expensive eg. pumped hydro, compressed air, cryogenic, flow batteries, lithium batteries, etc. and have relatively short periods of operation so should be used progressively as needed. And there is a lot of future potential from Norway, et al see EU JRC Assessment of the European potential for pumped hydropower energy storage http://setis.ec.europa.eu/system/files/Assessment_European_PHS_potential_online_0.pdf.

The gas grid can easily accommodate more than a month’s energy demand (as does Germany’s) and storage is low cost… salt caverns, old gas fields. So excess RE is electrolysed (or perhaps PEM) to create hydrogen with direct use in fuel cells and storage in the gas grid at 5% (with no changes) or 10 to 15% as hythane (with a change of gas burners required). The hydrogen via the Sabatier reaction (needs CO2 perhaps from biogenic CCS) converted to methane and injected into the low loss gas grid to be used as necessary.

Above all energy efficiency will allow us to do more with less and will drive big savings. See AECB, Less is More http://www.aecb.net/publications/less-is-more-energy-security-after-oil/ but a new economic model that does not rely on abundant low cost energy will be required http://www.sd-commission.org.uk/publications.php?id=914

Note that Denmark will go 100% renewables for all energy use by 2050, see http://www.kemin.dk/en-us/newsandpress/news/2011/sider/energystrategy2050.aspx