Technology as a key issue

Flexible power production (no more baseload)

Already, it is clear that intermittent solar and wind power will eventually cut deeply into baseload power. Energy experts have been aware that baseload power is incompatible with intermittent renewables for years. To complement renewables, we will need dispatchable power plants that can ramp up and down relatively quickly. Such plants more closely resemble today’s medium and peak load (such as gas turbines) than the baseload (such as nuclear plants, which do not ramp easily). To pay for such reserve generating capacity, the power market will need to be redesigned, however, which is why Germany is now increasingly talking about a capacity market and a strategic power reserve. No plans have been finalized as of 2017. Instead, a "winter reserve" with a different capacity each year (2017/18: 10.4 gigawatts) is created. This reserve is essentially a capacity market.

The "winter reserve" is expected to be expanded from 2.5 to 4 gigawatts. The winter reserve covers power plants that are not needed except in emergency cases, generally when power demand peaks during the heating season. These plants receive compensation for their standby services but are prohibited from selling power otherwise.

What do you do when the sun is not shining and no wind is blowing? Outside Germany, it is often said that conventional power plants will be needed as bridge technologies as we switch to renewables this century. In particular, there is talk about the need for baseload power, which fluctuating wind turbines and solar panels cannot provide. Germany already gets so much of its power from wind and solar that it has a different viewpoint. To the surprise of many foreign onlookers, Germans realize that baseload power demand will soon be a thing of the past. What is needed is flexible, quickly dispatchable power generation, not baseload. The difference is easy to understand if we consider central power stations, such as coal and nuclear plants. Ideally, these plants are switched on and run near full capacity until they need servicing. Nuclear plants in particular do not easily ramp up and down within a matter of hours, and attempts to do so are bad for the bottom line in two ways: first, fixed costs remain the same, with only fuel costs being slightly reduced, so the cost of power from the plant increases; and second, the plants themselves undergo thermal fatigue, which can shorten their overall service lives.

For Germany's four biggest power companies, this new situation represents quite a dilemma. They set up their generating capacity based on the assumption that they would be able to sell power at a great markup during times of peak consumption. Now, power consumption remains unchanged and still peaks at above 70 megawatts on certain days, but solar and wind push back conventional power production into the lower 40s – roughly the level of baseload power that big power corporations are set up to cover. Just a decade ago, these power companies still belittled wind and solar power as niche technologies that would never be able to make up a big chunk of power supply; now, solar and wind power are increasingly making these firms unprofitable.

In 2015, German utility E.On split into two companies: one for renewables and new services, and one for conventional energy. Wholly owned by the Swedish state, the utility Vattenfall has also announced plans to step away from its coal assets in Germany, but the motivation is political, not financial; the Swedish government elected in 2014 wants the firm to be as clean abroad as it is at home. The state government of Baden-Württemberg ownes utility EnBW, which now pursues a “greener” strategy. The utility RWE also split into two companies. RWE has too much lignite (more than a third of its power generation), which remains relatively profitable on the German power market. In contrast, E.On has only six percent lignite; a third of its power generation came from oil and gas in 2015. E.On is the firm affected most by the nuclear phase-out; RWE, the most affected utility by talks of a gradual coal phase-out. Most of these utilities mainly invest in renewables abroad - RWE in the UK, E.On in the UK and the United States - where these investments do not conflict with their existing assets.

Unintended outcome: renewables push back natural gas

This outcome is partly intentional and partly unintentional. The unintentional part is that renewables are making investments in natural gas turbines unattractive by replacing the medium load, meaning that natural gas turbines do not run for as many hours a year. Essentially, Germany needs to have a dispatchable installed capacity at the level of its peak demand for the year, which is currently around 80 gigawatts and occurs on winter evenings – when the sun does not shine. A large part of that 80 gigawatts therefore needs to be built as dispatchable gas turbines. This option is generally considered the best technically as it requires no additional infrastructure and would allow electricity to be stored seasonally. German researchers have estimated that the storage capacity in the country's current natural gas lines can contain enough gas to meet the country's power demands for four months.

Though this option seems the best in terms of technology, it faces a financial challenge: wholesale power prices are now so low on the power exchange that investments in additional generating capacity would not be profitable. Not only are Germany's four biggest power firms abandoning plans to set up new gas turbines; there have also been rumors that some of the existing turbines might be taken off-line because they are no longer running for enough hours per year. However, in 2016, the profitability of gas turbines improved somewhat, so a renaissance of power from natural gas may yet be coming.

While this outcome was predictable, the situation has come about much faster than most proponents of renewables expected, especially in light of the extremely fast growth of photovoltaics from 2010 to 2012, when 7.5 gigawatts were installed annually. If the German PV market had continued to grow at the level of those three years (in 2014, only 1.9 gigawatts was installed; in 2015, only 1.4 gigawatts), the country would eventually have had more than 150 percent of peak demand in the summer, when demand peaks at between 60 and 70 gigawatts during the week and as little as 50 gigawatts of the weekend. One German researcher’s "dental chart" shows what the effect would be if "only" 70 gigawatts of PV is installed by 2020 (keep in mind that the government's official target is 52 gigawatts by 2020).

This chart has no baseload power at all; the gray area now represents medium and peak load. Clearly, Germany will need a fleet of very flexible, dispatchable power generators that can ramp up every day from around ten gigawatts to 50 gigawatts or more within just a few hours. The country does not have this much flexible generating capacity at present, and all current plans for new power plants are now in question given the new market conditions of lower wholesale prices. From 2010 to 2016, wholesale power prices on the German power exchange fell by roughly half. One main reason is the rise of solar power in particular: because most of it is generated around noon-time, demand for peak power at midday has been greatly offset.

One possible remedy currently being discussed is capacity payments. Here, owners of quickly dispatchable generators would be paid not only by the kilowatt-hour generated, but also by the kilowatt kept on standby. In 2015, the German government resolved to keep the capacity payments small by increasing the “winter reserve” from 2.5 to 4.0 gigawatts, but that volume rose to 10.4 gigawatts for the winter of 2017/18. Germany has more than 100 gigawatts of dispatchable generation capacity.