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    Gas and Germany’s energy transition [NGW Magazine]


With coal and nuclear fast coming offline, Germany will need more gas to support its renewables expansion and keep the lights on when there is no wind and sun. [NGW Magazine Volume 6, Issue 4]

by: Andreas Walstad

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Natural Gas & LNG News, Europe, Top Stories, Insights, Premium, NGW Magazine Articles, Volume 6, Issue 4, Energy Transition, Germany

Gas and Germany’s energy transition [NGW Magazine]

The share of gas in Germany’s power generation mix has been rising steadily over the past few years, from less than 10% in 2015 to 16% in 2020 according to Eurostat data and estimates from think tanks Ember and Agora Energiewende.

As nuclear and gradually also coal is phased out, the share of gas is expected to continue to rise.

Germany will close its last nuclear power plants by late next year, which means around 8 GW of capacity will go off the grid. Moreover, 9 GW or more of hard coal power plants will be shut by 2023 in line with the country’s coal phase-out law, according to networks regulator Bundesnetzagentur. So far capacity totalling 5 GW has already closed or been earmarked for closure following an auction in December last year.

The auction saw plants built as recently as 2014 and 2015 – RWE's 800-MW Westfalen unit E and Vattenfall's 1.5-GW Moorburg combined heat and power plant respectively – successfully bid for compensation to exit the market. Swedish state utility Vattenfall wrote down the value of the Moorburg plant by around SKr 9 ($1.1)bn last year.

Only around 2 GW of new gas-fired capacity is expected to come online between now and end-2023, according to the regulator. That figure includes Steag’s new 600-MW CCGT in the Ruhr area which is expected to start operations in 2022.

Renewables capacity from wind and solar is expanding. On windy days, renewables have been generating close to 80% of electricity in Germany, as seen in August last year. Yet the roll out of new wind capacity may not be happening fast enough for Germany to be on track for its target of reaching 65% renewables in the electricity mix by 2030, up from around 45% now.

In 2020, only 240 MW of new offshore wind capacity was added in Germany, 870 MW less than in 2019, according to data from the Fraunhofer. Analysts at the research centre say 2 GW/yr of new offshore wind capacity is needed to reach Germany’s targets. Under 1.50 GW of onshore wind was added, while 5 GW/yr is needed.

Moreover, on dark, cold and windless days, Germany may be heading for a power deficit. Natural gas will be needed as back-up as electricity imports from neighbouring countries will not always be available in full.

“Germany is running into a situation that when there is no wind we will rely on electricity imports. On some cold winter days with minimal production from solar or wind the shortfall in capacity can be around 7 GW, according to TSO forecasts for 2022, Frontier Economics’ associate director Christoph Gatzen told NGW

“The question is what we do if France and other neighbouring countries also have a supply shortage on the same day. We will need natural gas to back up renewable electricity in the medium term and in the longer term some form of clean gas. Molecules will be needed, we cannot rely on batteries or demand-side anagement alone.”

Utilities brace for transition

One key question is how German utilities are repositioning themselves to tackle the energy transition. Moody’s senior credit officer Knut Slatten said German utilities differ a lot in terms of decarbonisation strategies.

“E.ON has through the asset swap with RWE become more of a network company with roughly three quarters of pre-tax profits (Ebitda) emanating from their network operations. Similarly, EnBW has around half of Ebitda coming from regulated grid activities,” said Slatten.

He noted that most European utilities, including in Germany, have significantly reduced their exposure to merchant power prices thanks to diversification.

“Most companies now see it as a strategic priority to increase exposure to renewables in the context of the current policy framework and supporting a strong development pipeline. Having said that, prices in renewables auctions are coming down while projects typically come with a substantial amount of capital expenditure and entail risk. Natural gas will continue to be around as a fuel for an interim period,” Slatten said.

Options to replace coal

The phase out of coal in Germany coincides with a sharp upturn in prices for EU carbon allowances which is eating into the profit margins of coal-fired plants. If gas continues to see healthier profit margins than coal, the coal phase out could be completed well before the 2038 deadline.

Fortum’s German subsidiary Uniper commissioned its 1.1-GW Datteln 4 hard coal plant in May last year, but has pledged to close all its older coal-fired plants in Germany in Germany – totalling 2.9 GW of capacity – by 2025. The company’s bid to close the 875-MW Heyden plant was accepted in last December’s auction.

Uniper has also joined the race for renewable hydrogen production using electrolysis technology. The company has teamed up with the Port of Rotterdam Authority to investigate the possibilities of large-scale production of green hydrogen at the Maasvlakte area in Rotterdam. A 100-MW plant could be operational by 2025, and the capacity could be expanded to 500 MW.

However, the company also wants to clean up electricity production from its 3.3-GW fleet of gas-fired plants. Fortum said in a recent investor presentation that its output from gas-fired power had tripled after it took a majority stake in Uniper last year. Fortum’s desire to establish an image as a clean electricity provider means it is also looking into using clean fuels in power generation and investing in carbon capture technologies.

The aim is to decarbonise its power plant fleet – including Uniper’s – by 2035. The company has teamed up with Siemens and General Electric to study the use of hydrogen-ready gas turbines. Wartsila is also developing hydrogen engines for electricity generation.

As for conventional CCGTs, the investment climate in Germany looks bleak without a capacity remuneration scheme to mitigate price risks.

“It is difficult to make a business case for CCGT or open-cycle gas turbine investment in a world with a lot of political uncertainty around future electricity demand developments, such as the heat and transport sector,” said Gatzen. “We would either need a wider capacity market like in France, further strategic reserves or allow very high peak prices in these scarce hours. Peak prices are not explicitly capped in Germany, but the competition authority may start asking questions if prices hit the roof.”

Converting existing coal-fired plants to run on natural gas and clean fuels is also an option. German utility EnBW says it wants to exit coal-fired power by 2035, but that it may conver the plants to run on natural gas in the coming years and then switch to carbon-free green gases or hydrogen after 2035. The company owns around 3.6 GW of hard coal plants and 875 MW of lignite power plants.

Swedish state Vattenfall is also replacing coal with natural gas in the medium term with the possibility of switching to hydrogen later on. In June last year it commissioned a combined heat and power plant in Berlin as part of its mission to replace coal. RWE has also said natural gas and hydrogen will play a role in reaching carbon neutrality by 2040.

UK market counts the cost of thin margins

The early January freeze afforded some financial relief for UK combined-cycle gas turbines (CCGT), analysts have said. These plants made the vast majority of the offers to supply power on the balancing mechanism, when National Grid is most distressed and so pays the most. It shelled out £100mn for a relatively small amount of electricity, according to trader Hartree Solutions February 10.

Day-ahead prices reached £1000 ($1380)/MWh or higher on seven separate occasions including January 11-14, while imbalance prices reached a record high of £4,000/MWh. CCGTs accounted for 3.96 GWh, or 93.5% of the total, according to Cornwall Insight January 9.

Withholding output for the balancing mechanism is a gamble, according to Hartree, as there might be no need for it on the day while pre-selling the power at least ensures some income. It identified “just a handful” of stations that cashed in, including the SSE owned Keadby, the EPH owned Langage, the EDF owned West Burton units, the Uniper owned Connahs Quay units, and the Drax owned Rye House and Drax-5 coal unit.

Cornwall said: “There is the potential for such fluctuations in power prices to become more frequent in the near-future as older dispatchable generation assets retire and the share of weather-dependent renewable generation increases, whilst the flexibility and response markets – which will help to smooth out any issues – continue to develop in terms of scale and sophistication,"

Hartree drew the same conclusions: “January painted a stark picture of the UK’s challenges as it seeks to decarbonise its electricity. With weather forecasts pointing to further cold weather across Europe for February, the potential for extreme pricing is not yet over this winter,” it said.

Hartree said the events were a “perfect storm of peak winter demand, low wind generation and delays to supplies from the continent” and that more of the same was possible, given the start to February.

Scarcity pricing is a part of the market design and ensures that the cost to the country of a blackout is correctly priced into imbalance prices. The cost of a blackout is estimated at an equivalent of £6,000/MWh, so bringing generation on at prices lower than this to avoid a blackout is the better financial option for the country, Hartree said.

Thermal generators also have less opportunity to recover their costs, most of which are fixed, owing to the build-out of renewables. Calon Energy for example went into administration in the autumn as it was unable to pay its debts, owing to conditions in the UK market, including the UK net-zero carbon ambitions.

William Powell