Act: Inspiration

Why German Coal Power is Falling Fast in 2019

July 26, 2019

Germany generated significantly less electricity from coal-fired power stations in the first half of 2019, with output down by more than a fifth compared to a year earlier.

Generation from brown coal (lignite) was down by 14 terawatt hours (TWh, 21%) and hard coal was down by 8TWh (24%). With gas generation only increasing moderately (3TWh), the German power sector’s emissions fell by 20m tonnes of CO2 (MtCO2, 19%).

This dramatic shift in Germany’s power sector comes as the Federal Ministry for Economic Affairs and Energy (BMWi) recently outlined its plan for a complete coal phaseout no later than 2038, in line with the recommendations of the country’s coal commission.

The BMWi plan would include auctions for compensation payments to hard coal plants shutting down early, even though many of these plants have been sitting idle for large parts of 2019 to date.

In this article, I look at why German coal generation is becoming less profitable as a result of much higher carbon prices, against a backdrop of continued increases in renewable generation.

Generation change

The EU’s largest economy is also its most polluting, with Germany accounting for roughly a third of all electricity-related CO2 emissions in the bloc. Around half of EU electricity generation from brown coal (lignite) takes place in Germany, as well as a quarter of the total for hard coal.

(Lignite is a soft brown coal formed from compressed peat. It has higher water content than hard coal and so causes much higher CO2 emissions per unit of energy when it is burnt.)

After years of steady output, German electricity generation from coal has been falling fast in 2019. Hard coal output had already seen declines over the past few years, as the chart below shows (black line), whereas brown coal generation (brown) had been resilient until much more recently.

Monthly electricity generation from lignite (brown line) and hard coal (black), terawatt hours, from January 2010 through the end of June 2019. Source: Energy Charts. Chart by Carbon Brief using Highcharts.

In the first half of 2019, hard coal generation is 8TWh (24%) lower than a year earlier, while lignite is down 14TWh (21%) – with coal down 22TWh (22%) in total and 44TWh (36%) over five years.

The gap left by coal-fired electricity has been largely filled by renewables, with output from German windfarms up by 11TWh (19%) and solar up by 1TWh (6%) in the first half of 2019, while demand fell by 9TWh (3%) and gas generation only increased by 3TWh (16%). The shift means wind is on track to become the single largest source of electricity in Germany this year, overtaking lignite.

In total, these changes mean that emissions from Germany’s electricity sector were down 20MtCO2 (around 19%) in the first half of the year, compared to the same period in 2018.

The German environment ministry has previously projected a 32% reduction in power sector emissions by 2020, compared to 1990 levels. The rapid falls this year mean this estimate is likely to be exceeded.

If savings continue at a similar rate in the second half of 2019, then emissions from the sector would fall by 40MtCO2. This is equivalent to 3 percentage points towards Germany’s now abandoned 40% emissions reduction target for 2020, which is nevertheless still likely to be missed.

Idle capacity

Notably, the decline in coal generation in 2019 has happened without any major power station closures. According to Energy Charts, a website maintained by the Fraunhofer Institute for Solar Energy Systems, the installed hard coal capacity is 23.7 gigawatts (GW, red line in the chart, below), but maximum output this year has not exceeded 17.4GW (blue line) and has stayed below 11.2GW since March.

Monthly electricity generation from lignite (brown line) and hard coal (black), terawatt hours, from January 2010 through the end of June 2019. Source: Energy Charts. Chart by Carbon Brief using Highcharts.

This low utilisation means Germany’s hard coal fleet, even at maximum output, has been running well below half its installed capacity since March. In the first half of the year overall, the fleet averaged 25% of its potential output. Similarly, lignite plants have averaged just 57% of their potential output in the same period – albeit with large differences between individual power stations.

A number of lignite plants have stopped generating over the past few years and are being kept open as “reserve” capacity in case of shortages. Some 2.7GW will gradually be moved into the reserve during 2016-2019, leaving 18.5GW operating in the German electricity market. While important, however, this can only explain a small part of the decline in lignite output since last year.

Most of this idleness can be attributed to renewables generating more electricity and the fact that many gas-fired power plants are now cheaper than their coal competitors, due to lower gas prices and higher carbon costs on the EU Emissions Trading System (EU ETS).

This highlights the fact that CO2 emissions from coal can be reduced without closing down coal-fired power stations – and that coal capacity does not automatically translate into emissions.

Reducing operation through a higher price on carbon instead of actively shutting down plants could even be more effective from an economic point of view, since it would reduce emissions without necessitating compensation payments for forced retirements. The UK carbon price floor has been a significant contributor to the country’s success in phasing out of coal, for example, helping keep remaining coal plants idle, with more than half the hours this year seeing no coal generation at all.

Market prices

The recent decline for hard coal generation has also come despite falling fuel prices. In April of this year, the cost of emitting CO2 (red line) overtook the cost of buying hard coal for a typical power plant (grey), as the chart below shows. This switch is also a result of a surge in EU carbon prices since reforms were agreed in late 2017.

Contributions from fuel (grey line) and CO2 permits (red) to total running costs to generate a unit of electricity at a typical hard coal power plant (blue), excluding operations, maintenance, fixed costs and investments in lifetime extensions. Source: Authors calculations based on data from SysPower. Chart by Carbon Brief using Highcharts.

At the end of June 2019, hard coal was trading at just above $50 per tonne. Such low prices are unlikely to be sustained, given it is below the $66/tonne expected by the International Energy Agency (IEA) in its Sustainable Development Scenario, where coal demand drops dramatically worldwide.

With a rebound in coal prices and carbon prices remaining stable – as expected by the forwards markets – hard coal running costs are likely to reach around €50 per megawatt hour (MWh), up from closer to €40/MWh today.

This figure excludes fixed operating costs and investments needed to renew equipment and meet more stringent air pollution rules. A cost of €50/MWh is also around the same level as expected power prices in Germany, meaning margins will be small for the country’s hard coal fleet.

While hard coal use has been falling steadily for years, lignite has seemed less susceptible to the effects of the green transition. This is because lignite plants have lower running costs, using fuel extracted from large surface mines nearby rather than from deep mines that are often overseas.

That position finally changed this year, as increased wind generation, declining demand and lower gas prices resulted in a smaller market for coal. It was further exacerbated by the price of carbon rising from just €5 per tonne of CO2 two years ago to about €28/tCO2 today, which hits lignite particularly hard due to its very high emissions per unit of electricity generated.

The net result is that lignite operators’ margins have been squeezed in recent months, with total revenues across the German fleet (red line in the chart, below) barely covering the costs of carbon (blue) – let alone fuel or other fixed costs such as salaries.

Total revenues from electricity sales (red) and the cost of carbon allowances (blue) for all German lignite plants by month. Source: Author calculations based on data from SysPower and Energy Charts. Chart by Carbon Brief using Highcharts.

This squeeze on lignite profitability has started to produce real consequences for power plant owners. One major utility, EnBW, took its 900 megawatt (MW) Lippendorf S lignite unit out of operation on 15 June 2019, saying that “current framework conditions do not permit economic operation”.

This is a reflection of the substantial shift in lignite profitability over the past two years, shown in the chart, below. In general, lignite power plants have higher output (shown on the y-axis) in hours when electricity prices are high (x-axis). Comparing this distribution in June 2019 (red dots) with the same month in 2017 (blue) shows how much less the plants have been switching on.

Hourly output from German lignite plants (gigawatts) as a function of electricity prices (€/MWh) in June 2017 (blue dots) compared with June 2019 (red). Source: Energy Charts. Chart by Carbon Brief using Highcharts.

Most remarkable is the increase in the “drop-off price” under which lignite plants significantly reduce their output, from about €10/MWh in 2017 to about €30/MWh in 2019. This price is the point below which plants are unable to operate without losing money.

Maximum output has also fallen in 2019 as a few lignite units are permanently offline, while minimum output has been reduced too. The latter is due to plants shutting off completely during extended periods of high renewable generation.

Until recently, lignite plants rarely shut off completely, as periods of uneconomic operation were typically short enough to justify loss-making operation instead of paying the associated costs of switching off and then re-starting the power station. That meant that lignite plants were running more or less continuously outside of planned maintenance.

A few points in the chart above also shows the new dynamic where lignite output remains low even during some periods of high electricity prices. This is due to some plants switching off for economic reasons and being unavailable to fire up quickly during short periods of high prices, when prices are otherwise low.

Carbon futures

Looking ahead, the current market expectation is that lignite revenues will increase slightly over the next few years, with gas prices due to rise and competition from nuclear plants disappearing as Germany completes its phaseout of the technology by 2022.

This means lignite generation could rebound in the short term, as plants are expected to become cheaper to run (brown line in the chart, below) than their gas counterparts (blue line).

Running costs to generate a unit of electricity at a typical gas (blue line), hard coal (black) or lignite power plant (brown), excluding operations, maintenance and life time extensions. Historical figures are shown with a solid line. Projections, in the shaded area, are based on forwards markets. Source: Author calculations using data from SysPower. Chart by Carbon Brief using Highcharts.

Despite this potential rebound, however, the price difference between running a lignite and gas-fired power plant seems set to remain small – whereas, previously, brown coal had a large cost advantage.

This means that the days when lignite running costs were low and power prices (set by gas and hard coal) were high will probably not return. Furthermore, the emergence of subsidy-free renewables are likely to cap long term electricity prices, even in the event of rising gas prices.

The chart above may even overstate the profitability of lignite plants, as it assumes a short-term running cost of just €10/MWh. Longer-term running costs – on top of carbon costs – could be as much as €22/MWh, according to thinktank IEEFA, citing figures from German lignite operator RWE. This still does not factor in costs for upgrades to comply with tighter environmental standards for local air pollution.

With renewable generation set to continue growing rapidly and prospects for carbon prices remaining buoyant, the end for German coal could arrive sooner than expected.


Teaser photo credit: By Martin Falbisoner – Own work, CC BY-SA 4.0

Karsten Capion

Karsten Capion is senior adviser at Danish Energy, the membership body for the Danish energy industry. In August, he will be joining the Danish Council on Climate Change (Klimarådet) as chief analyst. This is broadly equivalent to the UK’s Committee on Climate Change.

Tags: coal power, German electricity generation, renewable energy transition