The European energy system is feeling increasing strain from the effects of the energy transition. New regulatory and business models are urgently needed, in particular to cope with the increasing share of variable energy sources. Pieter Boot of the Netherlands Environment Assessment Agency (PBL) and Jacques de Jong of the Clingendael International Energy Programme (CIEP) offer six practical suggestions to prepare our energy system for a low-carbon future. They warn that if we fail to fix our energy market design, “the EU’s whole energy transition will be put at risk”.

The effects of the energy transition are increasingly felt in the European energy system. Above all in Germany which is leading the way with its Energiewende. The two largest German utility companies, Eon and RWE, have both announced major strategic reorientations to adapt to the new realities. At the same time, German policymakers and regulators face great challenges to ensure that the German energy system will not collapse under the weight of the growing share of variable energy sources. Other European countries will soon face similar issues.

As long as the share of wind and solar power in the system is limited, their fluctuating output can be leveled out with existing non-variable capacity. But when the shares of variable sources reaches more than 20-25%, it becomes more and more difficult to run back-up capacity profitably for a (sometimes very) limited amount of time. Profitable operations are possibly only if prices are allowed to peak.

This changes the risk profile of non-variable capacity, especially when there is a risk that high prices in the wholesale market may be capped by regulators. As a result, a change takes place in what drives investment in the market: the role of the wholesale market as a driver of investment is challenged. Instead, support schemes for renewables become more important. This  in turn may impact the ability to maintain system adequacies in a cost-effective and reliable way.

New market structure

Actually it is possible to distinguish two different functions of the wholesale power market. As coordinating mechanism for daily operations, it is still performing reasonably well. In this case the dispatching of generators is based upon short-term marginal costs. But as a driver for long-term investment the wholesale market is losing out  to renewable energy support schemes or capacity remuneration schemes.

The new market structure has three broad consequences that may not yet be sufficiently appreciated by market participants and policymakers.

• Many observers expect that subsidies for renewable energy can be abolished in the future as solar and wind become more competitive. However, as wholesale prices are decreasing faster than production costs and may decrease further, especially at times when there is a large amount of renewable power being generated, it may not be possible to end subsidies.
• Network costs will increase as networks will have to be further stretched out, and operational costs will increase.
• Generation adequacy will not remain guaranteed as investor incentives for new plants will be insufficient for capital-intensive new technologies.

So what should be done to address these problems? We offer six practical ideas that can help to make our energy system cope with the new realities.

1. Improve the functioning of intraday and balancing markets. Price signals should be strengthened in intraday and balancing operations in order to make system operations more effective and efficient. This should be done by, among other things, enhancing demand side integration and operating reserve demand curves. When markets would be allowed to be operating close to near-time closures for final balancing, this would also make markets become much faster. These signals should apply cross-border and all market parties, whether generators or consumers, should operate in such a way that system costs are fairly allocated to the parties causing these costs. This would mean, among other things, that all generators of variable renewable energy are obliged to take full program-responsibility. In addition, demand side response should be fully integrated in the  balancing system. If price capping is deemed to be necessary, it should not occur up to a level of say €15,000/MWh.
2. Establish a carbon price tunnel. Strengthening the EU Emission Trading Scheme (ETS) is the most straightforward option to improve the functioning of the energy system. The EU proposal for a Market Stability Reserve will temporarily increase the carbon price, but will not make a difference in the longer term as withdrawn emission rights will sooner or later return to the market. Nor will increasing the linear reduction factor to 2.2% per year in the period 2021-30 help sufficiently to switch power plants from coal to gas. To enable such a switch and to decrease subsidies for clean investments, it would make sense to establish a carbon ‘price tunnel’. A guaranteed minimum (and eventually also a maximum) price could be introduced if allowances would be auctioned only when a pre-defined floor price would have been attained. With a policy commitment to sell allowances if the price ceiling is reached, and to buy them if the floor price is reached, the current cap-and-trade instrument would change into a tailored combination of a quantity and price instrument.
3. Introduce emission performance standards. As a substantial strengthening of the ETS may not be feasible in the near term, a second-best regulatory option should be considered, namely the introduction of emission performance standards for power plants. This has already been done in several countries: in the US, the UK (where emission performance standards serve as back-stop for new coal plants) and the Netherlands, which has introduced stricter licensing conditions for early closures of old coal plants. Such combinations of market-based instruments and specific case-by-case regulatory instruments have to be considered if a substantial increase of the CO2 price is not expected. Although such instruments may hinder the functioning of the ETS to some extent, eventually they could lead to a further reduction of carbon emissions from fossil-fuel based power plants and lead to a better and more efficient use of remaining carbon budgets. And although these measures may lead to some increase of wholesale prices, subsidies will decrease as well.
4. Introduce tailor-made solutions for risk-hedging via long-term coordination mechanisms. Investor confidence is key in bringing new technologies on line with high capital investment and low operational costs such as solar and wind energy. Regulatory risk is usually seen as the most important disincentive, so new risk-hedging approaches should be introduced. One approach could be to introduce new and innovative long-term coordination mechanisms which would enable investors to come together with financiers and public entities or other interested (industrial or cooperative) consumer groups. This could be done for specific technologies, such as the Contracts for differences as applied in the UK, or on a plant-specific basis as applied in Finland and in discussion in some eastern EU-member states.  The recent State Aid Guidelines from the EU offer a comprehensive set of conditions for such an approach. They include rules for allowing renewable energy subsidies as a premium in addition to market prices and stipulate that renewable energy suppliers be subjected to standard balancing responsibilities. These guidelines also set relevant boundaries for introducing a system of capacity payments as a last resort measure, for instance when relevant regional adequacy assessments have been made and a capacity remuneration scheme is to be applied in a non-discriminatory way.
5. Reconsider the grid-generation paradigm. As the role of both high-voltage and distribution grids becomes more and more important in a power system based on variable renewable energy, the prevailing “grids-follow-generation” paradigm needs to be reconsidered. This applies both to grid planning and to tarification methodologies. New methodologies should be introduced to incentivize grid users and operators to find the optimal balance in cost-benefit allocation from a social welfare perspective. This would also allow consideration of alternative energy carriers such as natural gas, hydrogen, steam, and low-temperature water substituting for or being added to “just” electrons.
6. Develop policies in a regional context. No national policy solutions will be adequate in the context of the continuing EU energy market integration process. Cross-border solutions are called for. However, policy solutions at the EU level tend to lead to sub-optimal compromise solutions. Hence, policy development and implementation should be following regional approaches, which take into account physically and commercially interconnected markets. Such approaches already exist in Scandinavia and in the Penta-plus context in which the Benelux, France, Germany, Austria and Switzerland are working together on extending their operations on market-coupling. A new approach could be to develop the 2030 energy and climate packages in these regional contexts. All these efforts however, should always be based on the ground-rules and boundary conditions set by the EU Internal Market, such as the recent Guidelines on State Aid.

These measures should be considered by the EU as it comes to implement the “2030 package” agreed to last year. The development of an “Energy Union” may offer further opportunities to adapt the EU’s energy market design. If we fail to take adequate measures, the whole transition towards a low-carbon energy system may be put at risk.

Editor’s Note

Pieter Boot is head of the department of Climate, Air and Energy at PBL Netherlands Environmental Assessment Agency. He is also fellow of the Clingendael International Energy Programme in The Hague.  Previously, he held positions at the International Energy Agency as Director Sustainable Energy Policy and Technology, at the ministry of Economic Affairs as deputy Director-General Energy and at other ministries in the Netherlands. He has a PhD in Economics.

Jacques de Jong is a former Dutch energy policy maker and energy regulator and now works as senior fellow at the Clingendael International Energy Programme.

This article is based on the recent CIEP/PBL paper “Reflections on coordination mechanisms for accommodating Increasing Amounts of Wind and Solar in the Power Market”.