Renewables move into the mainstream

For more than two decades the European power markets have been exposed to a raft of fundamental changes driven by national privatisation programmes and European Union (EU) regulation, including:
? Introduction of competition to break previously monopolistic structures, allowing customers to choose their suppliers;
? Ring-fencing and spin-offs of transmission and distribution businesses by traditional utilities stripping out the stable part of their future cash flows;
? Europe’s “20-20-20” commitment, i.e., by 2020 reducing energy consumption as well as greenhouse gas emissions by 20 percent and generating at least 20 percent energy from renewable sources (translating to around 35 percent of renewable power);
? Market distortion by introducing emission costs, subsidies, grants, tax breaks and other support mechanisms (around 170 different renewable energy subsidy programmes are estimated to exist in Europe and there is little harmonisation between markets);
? Renewable power is posing an existential threat to fossil-fuelled power generators; and
? Some countries’ decision to phase out nuclear capacity following the Fukushima disaster.

Internationally, global energy market trends are having a big impact on Europe’s power generation mix. Cheap US shale gas has displaced coal as fuel in the US pushes cheap coal into Europe at times of low emission cost. Most long-term European gas contracts, unlike in the US, are linked to oil, leading to European gas trading at multiples of US gas and imported coal. As a result, coal-fired plants are profitable despite low power prices, while gas plants are loss-making.

As a consequence, traditional utilities have lost more than 50 percent of their value. According to an article in The Economist dated 12 October 2013, the market capitalisation of the top 20 European energy utilities was roughly €1 trillion in 2008; within five years their valuation had fallen by more than €500 billion, more than European bank shares lost in the same period.

So what have investors learned?


Germany, Europe’s biggest power market with around a quarter of electricity produced from renewables, sees a significant impact not only on wholesale power prices but also on supply patterns. Intermittent wind and solar capacity is expected to rise above 70 gigawatts (GW) in Germany in the first half of 2014 (compared with current peak load of circa 75GW).

Under the German Renewable Energy Act, qualifying renewable energy plants have dispatch priority and receive a 20-year, fixed-price feed-in tariff which is ultimately paid for by end consumers of power (with certain exemptions being granted to energy-intensive industries). Hence, renewables have an incentive to generate power whenever the resources allow them to do so, independent of market price signals.

Despite Germany’s nuclear decommissioning programme, power prices exhibited a downward trend over the last few years. This is driven by renewable’s zero short-term marginal cost of production (wind and solar plants have no fuel costs and comparatively minor operating costs) which means more expensive fossil-fuelled power plants are pushed out of the merit order allowing the market to clear at a lower price. In addition, German electricity consumption in 2013 fell for the third year in a row and for 2013 is 1.8 percent less than in 2012.

According to Platts, German day-ahead, over-the-counter base-load power prices averaged €37.51/MWh (megawatt hour) in 2013. These price levels do not even cover fuel cost for gas-fired plants, an asset type key to generating peak power and to providing back-up services. In addition to lower market prices, periods when conventional power plants are required to run has also shrunk, – a double impact of lower volumes sold at lower prices. However, to be able to safeguard important system reliability given the intermittent characteristics of wind and solar, flexible and controllable power generation assets as well as large-scale storage are needed.

Supply patterns have also shifted fundamentally: solar plants are typically producing during peak demand hours and a significant share of peak demand can be supplied at zero marginal cost on sunny days. In a perfect scenario, i.e., a sunny and windy working day, only comparatively little additional capacity is required to meet peak demand, reducing the difference between peak and off-peak prices. At certain hours, peak prices have even been below night-time prices or gone negative in extreme cases (i.e., consumers being paid for accepting delivery).

While the dampening effect on peak prices may be an attractive side-effect of solar power production, it further limits the earnings potential of flexible generation assets which previously targeted periods of higher peak prices to earn their returns despite lower utilisation. Alongside gas-fired generation assets, even pumped-storage hydro plants are struggling.

So it seems that renewable power’s ‘winner’s curse’ is the fact that in the current market design, it is eroding its own market if renewable assets were compensated by merchant prices. Therefore, the market design desperately needs to be changed to avoid additional increases in retail power prices (currently around 7x the wholesale price) and ensure security of supply by providing compensation for system-critical fossil generation assets.


Across Europe, significant power generation over-capacity appears to exist. According to the European Network of Transmission System Operators for Electricity (ENTSO-E), the 2013 European load estimate is circa 542GW as of April 2013. The corresponding “net generating capacity” estimate is 997GW including unavailable capacity (e.g., non-usable capacity, outages, overhauls and reserves). Adjusted “reliable available capacity” still amounts to 641GW, leaving a safe reserve margin of 18 percent.

However, these numbers don’t tell you whether assets are in the right locations, if their supply patterns concur with demand, and if they can run economically.

According to an IHS analysis in May 2013, about 130GW of European gas plants (60 percent of Europe’s total installed gas-fired generation) are currently not recovering their fixed costs and are at risk of closure by 2016.

The changing structure of Europe’s power generation mix stretches the limitations of existing transmission and distribution infrastructure. Traditionally, power plants were centralised, large assets, their locations carefully selected with respect to grid considerations and demand pockets. Renewable plants tend to be small in size and decentralised. Good natural resources (i.e., irradiation and wind) don’t always coincide with locations of major electricity demand.

On a local level, networks need to be modified to adapt to renewable generation patterns and, internationally, physical interconnector capacities have to be increased to avoid bottlenecks and allow for improved European supply-demand balancing. In addition, storage solutions are required to bridge the timing mismatch between supply and demand.


Industrial consumers already have a long tradition of generating their own power and are now increasingly adding renewable capacity to their portfolio. BMW is supplying about a quarter of the power used at its Leipzig plant from wind generation assets. DIHK Chambers of Commerce and Industry estimate that 10 percent of German companies had their own power capacity in 2012, increasing to 16 percent in 2013. The forecasted share is circa 23 percent.

Within auto-production, there is certainly a role for unsubsidised renewable power. Different technologies are already at “grid parity” – the key question is what reference power price is relevant for different users. Solar photovoltaic plants without feed-in tariffs make economic sense for retail consumers and, depending on the size, even commercial consumers in Germany. German retail power prices are close to €300/MWh, more than twice the feed-in tariff for small photovoltaic plants.


There is no such thing as standalone renewables any longer. The ‘old’ investment theses no longer apply to either conventional or renewable energy. Renewables are part of the mainstream and, therefore, investors must have experience of both areas to be able to make the right investment decision.

Over-reliance on subsidies, in combination with wind and irradiation forecasts, will be yesterday’s investment proposition in the renewable space while new business models and regulatory structures have to be established when considering investments in ‘conventional’ asset classes.

Regulatory understanding and expertise across both renewable and traditional energy asset classes will be key when considering any investment in the European energy sector. The market will move to more fundamental drivers as changing regulation tries to introduce auction-based mechanisms to replace subsidy structures; but before considering an investment, clarity, visibility and reliability of the regulatory regime are vital.

Wherever you are in Europe, and whatever the uptake domestically has been, the tipping point is here.

Erich Becker is a partner at Zouk Capital, the London-based growth capital and infrastructure investment firm