Negative prices are a correct signal representing the system’s scarcity of downward flexibility, but also result from a market distortion caused by renewable support mechanisms. In the worst case, these withhold active market participation, as in Germany, with its feed-in- tariff coupled with a stringent curtailment policy. In the best case, these result in negative bids under their marginal production cost to recover lost subsidies, as in Belgium. Day-Ahead, Intra-Day and Real-Time. This post – the first of a two part review – considers the theoretical basis of negative power prices in mainland Europe whilst the second takes a quantitative look at the UK market.

Introduction

Over the last few years, European wholesale electricity markets have shown a manifold increase the instances of negative prices , as have the day- ahead, intra-day, and real-time balancing markets. This corresponds with an excess of electrical energy in the system resulting in a situation where generators are willing to pay to inject electrical energy and consumers are willing to be paid to take it off. This phenomenon is caused by (1) the limited storability of electricity, (2) the low elasticity of electricity demand, and (3) the technical constraints of operating power systems. In a system where the real-time balance between demand and supply is a prerequisite for system stability, the large-scale integration of variable generation sources such as wind and solar power poses a considerable challenge. This variability, also referred to as intermittency, refers to the limited controllability and predictability due to the nature of their resources.

The amount of installed renewable capacity varies across European member states. In Germany, Belgium, and France, wind accounted for respectively 8.5 percent, 3.7 percent and 3.4 percent in terms of average electric energy penetration. However, lessons can be drawn from leading countries such as Denmark (30.0 percent), Portugal (20.4 percent), Spain (18.2 percent) and Ireland (15.6 percent). For solar power integration, Germany, Belgium, and France, achieved a respective 5.1 percent, 1.9 percent and 0.8 percent in terms of average electric energy penetration. Leading countries in Europe are Italy (5.7 percent), Germany (5.1 percent), and Spain (4.3 percent). In terms of power ratios, these shares may account for maximum penetration levels exceeding 100 percent of the minimum demand.

The increasing share of renewable energy sources for electricity (RES-E), such as wind and solar photovoltaic power (PV), impact wholesale electricity prices. Due to their negligible marginal cost, and the present subsidy schemes based on production support, they push expensive generation technologies, such as gas-fired power plants, out of the market and lower the electricity prices in periods with high RES-E in-feed, while increasing price volatility. Today, observations show that high renewable generation during low demand periods lead to negative electricity price spikes in Central Western European electricity markets such as Germany, France, and Belgium. These negative prices represent the challenge of power systems to cope with high renewable electricity injections.

Historically, system operators, regulators, and policy-makers were mainly concerned about upward adequacy, i.e. the ability of power systems to meet peak demand and avoid demand shedding. This topic remains relevant today, especially where power systems face decommissioning of older power plants, in countries that have decided to phase out their nuclear power, while existing units with high marginal cost (such as gas-fired generating units) face problems maintaining their profitability. In combination with RES-E variability, this leads to an increased risk for periodical shortages. As startling as the risk of upwards price spikes has been the emergence of strong downwards drivers on European power markets

A second blog post will shortly look take a quantitative look at this effect in the UK power market, and firstly, this post presents a review of the current situation and attempts to explain the occurrence of negative prices in the German, French, and Belgian day-ahead, intra-day, and balancing market.

Day-ahead Markets

Due to the technical nature of power systems, the majority of electricity trade is conducted up to one day before delivery. Thereafter, market positions are scheduled with the transmission system operator (TSO), which can conduct the necessary security checks and real-time operation. The day-ahead market, generally facilitated by power exchanges, allows market players to adapt their positions according to their system expectations. Positions are taken for the next day, resulting in scheduled production and consumption programs. In the power exchange, the hourly price is determined by means of the intersection of the demand and the supply curve. In the below diagram, it can be seen how the supply curve is represented by a merit order of generation technologies, representing their marginal generation cost. Usually, but depending on the actual fuel costs, these generation technologies are categorized as baseload (e.g. nuclear and coal-fired power plants), mid-load (e.g. combined-cycle gas turbines) and peak load (e.g. open-cycle gas turbines, diesel engines). European day-ahead markets have undergone a coupling process which allows arbitrage between different regions or countries by means of implicit auctioning of cross-border transmission capacity. This creates price convergence between the different areas as long as there is sufficient cross-border transmission capacity.

Electricity supply and demand curves with renewable power
Electricity supply and demand curves with and without renewable power

We can see how the expected demand impacts the price of electricity. A low demand does not require the activation of the more expensive power plants and results in a lower price. Similarly, when a certain injection of RES-E is predicted with an almost zero marginal cost, the supply curve is shifted to the right, lowering the electricity prices. This is referred to as the merit-order effect, resulting in average and absolute price reductions.

Due to the technical constraints of power systems, the supply curve looks different in reality. Base-load generation technologies, e.g. older nuclear power plants, may not be designed for short-term output variations (referred to as inflexible base load). For technical or economic reasons, these power plants are inclined to bid their generation at negative price in order to avoid temporarily output reductions. Furthermore, part of the conventional power plants has to remain on-line for security reasons, such as providing reserve capacity, contracted by the TSO (referred to as must-run generation). This issue becomes even more important with the increasing share of RES-E facing prediction errors and additional reserve capacity requirements. This results in negative price bids, in order to guarantee their on-line status. Furthermore, RES which actively participate in the market, e.g. by means of the green certificate mechanism, bid negative prices due to the presence of support mechanisms. They are only willing to reduce output when the negative electricity price falls below the production support. In addition, part of the operation of RES is market-price insensitive due to stringent renewable curtailment policies, e.g. Germany, or control difficulties, e.g. local PV generation in Belgium, and is therefore treated as negative demand shifting the demand curve to the left.

 

Supply and demand curves with inflexible generation
Supply and demand curves with inflexible generation

The Balancing Market

In European power systems, real-time deviations from the scheduled market positions are dealt with by means of the balancing market. Historically, such deviations included unplanned power plant outages and unexpected demand variations. With the increasing penetration of variable RES-E, also prediction errors result in an additional demand for balancing actions. Due to the importance for system security, this market is coordinated by the TSO. It contracts reserve capacity in advance, mainly from conventional power plants, which can be quickly activated upward or downward to cover real-time system imbalances. In principle, a minimum amount is contracted by means of long-term contracts in order to keep a minimum capacity available. In some countries, for example, Belgium, market players can offer additional capacity by means of short-term contracts, which are closed one day before real-time. Together, this results in a merit order representing the activation cost of reserve capacity.

When activating upward reserves, for the situation in which the system faces a power shortage (negative imbalance), this results in a positive marginal price (MP) on the reserve market, and the TSO pays the Balancing Service Provider (BSP). This activation price covers, inter alia, the fuel cost of increasing the output of the power plant. The cost of activation is then transferred to the responsible market players, referred to as balancing responsible parties (BRPs). BRPs facing short positions, reinforcing the system imbalance, pay the marginal price to the TSO. Vice versa, BRPs with a long position, restoring the system imbalance, receive the marginal price from the TSO. This mechanism incentives market players to maintain their portfolio in balance, as well as to reduce the net system imbalance.

Balancing markets are still organized nationally, but first integration steps are taken by means of exchanging reserve capacity, and netting imbalances. Although main principles are similar, specific implementation aspects vary between different countries In this section, the Belgian balancing market is taken as a reference as its market design based on single marginal pricing market design results in cost-reflectiveness of reserve capacity activation. In an attempt to harmonise frequency control, the European Network of Transmission System Operators for Electricity (ENTSO-E) introduced three general types of reserve capacity, i.e. frequency containment reserves (FCR), frequency restoration reserves (FRR), and replacement reserves (RR) (De Vos, 2013). The FCR is a very fast automatic reserve to contain the frequency drop. Costs are socialised by means of the grid tariff and therefore not subject to the imbalance settlement mechanism. The FRR is a fast automatic or manual reserve to restore the frequency to its nominal value and restore the balance within the control zone. Their activation cost is the basis for imbalance settlement. The RR is a slow reserve replacing the FRR, but is not implemented in Belgium. In Belgium, the system imbalance is netted with other control zones (e.g. Germany, the Netherlands, etc.) by means of International Grid Cooperation and Control (IGCC). Upward fast-response FRR (automatic, aFRR) include contracted and possible free bids from power plants. The slower-response FRR (manual, mFRR) contain contracted and free bids from power plants, contracted bids from interruptible demand, contracted bids from resources on the distribution level (as of 2014), and a non-guaranteed emergency capacity from other TSOs.

In contrast to the upward reserve, the downward activation price can be positive or negative. Usually, the price is negative and refers to a payment of the BSP towards the TSO. This is explained by the fuel savings following the output reduction of a power plant. Consequently, in a system facing excess generation, BRPs facing long positions, reinforcing the system imbalance, receive the marginal price to the TSO. Vice versa, BRPs with a short position, restoring the system imbalance, pay the marginal price from the TSO. However, market players may also bid positive activation prices, i.e. be willing to be paid for the activation. This may compensate inflexible power plants facing expensive ramping down due to their technical characteristics. Furthermore, this might be required to cover the costs when forcing the power plant to remain on line. Finally, renewable power plants, when allowed to actively participate in providing reserve capacity, e.g. Belgium, bid positive prices in order to compensate for lost production support, e.g. green certificates. In this case, the imbalance settlement tariff becomes negative and money flows represented in Figure 3 (right) are reversed. In Belgium, downward reserve capacity is provided by means of the IGCC mechanism, automatic and manual FRR based on free bids and inter-TSO emergency reserves (Elia System Operator, 2014).

The reservation and activation of reserve capacity are referred to as the procurement side of the balancing market, i.e. the reserve market. Reservation costs are included in the transmission tariffs and activation costs are transferred to the responsible market players by means of the imbalance settlement mechanism. In 2012, a one-price settlement system was introduced in Belgium. This represents the settlement side of the balancing market, resulting in a price quoted on this market every quarter of an hour. This price is based on the marginal activation cost, which is in principle equal for BRPs facing a positive or downward imbalance. However, an additional component is added when facing system large imbalances, pulling apart the marginal decremental price (MDP) and marginal incremental price (MIP), providing an additional incentive for BRPs to balance their position. Although the price is unknown in real time, estimates can be made from the real-time system imbalance, the available capacity and marginal price published by the TSO. BRPs can thus actively adapt their positions in order to minimize their imbalance volume or cost.

Negative prices in Belgium
Negative prices in Belgium

Intra-day market

In European power systems, market players can adapt their positions intra-day, based on updated market expectations. This allows them to avoid the price risk of the balancing market, which is particularly useful for variable RES-E, relying on higher forecast accuracy closer to real time. This market is well represented in European power exchanges, matching bids and offers on a continuous basis. In general, intra-day markets follow the same economic principles as day-ahead markets, although liquidity may be lower and prices more volatile. This is explained by technical limitations of generating units to alter their injections closer to real- time. A trend towards European market integration is present, which is expected to help increase the market liquidity.

Prices in the intra-day market are expected to be strongly related to price expectations in the real-time balancing market. According to economic theory, low future price expectations, resulting from expected excess supply, move the current supply curve to the right, resulting in a lower market price. In other words, as an expected excess of electrical energy is likely to result in low or even negative price in the balancing market, market players facing an expected excess are inclined to trade their excess energy intra-day. This allows them to avoid the risk for lower prices on the balancing market when expecting stringent real-time system conditions. However, this action pushes intra-day market prices down, potentially into negative values. Consequently, the intra-day price is strongly indirectly impacted by the balancing price drivers, the expected prediction error, and the available flexibility resulting from the scheduling of power plants based on the expected demand.

 

Negative German spot prices
Negative German spot prices

Conclusions

The theoretical framework shows how day-ahead prices are driven towards negative values when facing low demand and high renewable generation expectations. This is due to operational constraints of the power system, as well as current support mechanisms for wind and PV. Market observations show that negative price events occur only rarely, which can be explained due to the market coupling and acceptable flexibility of the power system on a day ahead basis.

In contrast, negative prices occur frequently on the balancing market. The theoretical framework teaches how prices become negative when facing unexpected renewable generation excess in periods with low demand. This is explained by the same drivers as in the day-ahead markets, but reinforced in the balancing market where available flexibility is much lower due to its real-time nature. In addition, balancing market design is much less developed, with limited market integration and products allowing participation of alternative market players. Intra-day market prices are closely related to balancing market expectations. However, these markets still suffer from limited liquidity, mainly due to the lack of regional integration.

It is concluded that negative electricity prices are a correct signal representing the scarcity for downward flexibility of the system. However, these are currently also the result of a market distortion caused by renewable support mechanisms. In the worst case, these withhold active market participation, as illustrated in Germany with its feed-in-tariff coupled with a stringent curtailment policy. In the best case, these result in negative bids under their marginal production cost to recover lost subsidies, as illustrated in Belgium. Some policy analysts argue that this might motivate new flexibility services to enter the market. On the other hand, the artificial nature is to be taken into account as changes in the support mechanism design may have a large impact on the price, and thus the business case of these technologies.

Volatile, and negative electricity prices correctly represent the need for downward flexibility, which needs to be resolved by trade, demand response, storage, conventional flexibility, and active participation of renewable energy. This may require supporting policy measures, but specific attention is to be paid to the balancing market design. This is increasingly impacted by the variability of RES, while facing market design flaws to adequately deal with large shares of RES. These include the limited market integration the limited cost-reflectivity and transparency of imbalance settlement design, and reserve capacity products which are inaccessible to new flexibility providers

References
  1. Discussion Papers. German Institute for Economic Research, DIW Berlin, No. 1162.
    Brandsta¨tt, C., Brunekreeft, G., Jahnke, K., 2011. How to deal with negative power price spikes? Flexible volun- tary curtailment agreements for large-scale integration of wind. Energy Policy 39, 3732–3740, http:// dx.doi.org/10.1016/ j.enpol.2011.03.082
  2. Negative Wholesale Electricity Prices in the German, French and Belgian Day-Ahead, Intra-Day and Real-Time Markets – De Voos (2015)
  3. Pros and cons of exposing renewables   to   electricity   market risks – a comparison of the market integration approaches in Germany, Spain, and the UK. Energy Policy 36, 3646–3661, http://dx.doi.org/10.1016/j.enpol.2008.06.022
  4. Wind power in the Danish liberalised power market – policy measures, price impact and investor incentives. Energy Policy 36, 3940–3947, http://dx.doi.org/10.1016/j.enpol.2008.07.024
  5. APX, Belpex, EPEX SPOT – Joint Statement on negative prices in Belgium and France on 16 June 2013, http://www.belpex.be/
  6. http://www.renewablesinternational.net/german-wind-solar-push-power-prices-way-down-on-sunday/150/537/73470/
  7. https://www.epexspot.com/en/market-data/dayaheadauction/chart/auction-chart/2016-01-30/DE

2 COMMENTS

  1. Great article Patrick.

    Thanks for the useful insights. Though the partial re-sizing of government subsidies to renewable generation (e.g. UK), this is a quite interesting topic, particularly when coupled with increasing focus on downstream energy efficiency.

    Best regards
    Mirko

    • Thanks Mirko and you’re quite right that it is an interesting time to be in the energy markets. The next 5 to 10 years are going to as dynamic and challenging as the last ten; energy policy in Germany, UK generators closing and where is the new capacity?, French energy mix will come under review….

I'd love to hear what your thoughts are...please feel free to leave a reply