Europe’s Energy Markets: If It Ain’t Broke, Don’t Fix It

Abstract

The Draghi Report offers a critical assessment of Europe’s energy markets, with particular focus on electricity and natural gas: price dynamics are primarily the result of poorly designed climate policies and structural inefficiencies in energy market regulation and design. This article focuses on Draghi’s observations on energy markets and argues that, while the report makes a compelling case for removing the root causes of high energy prices, rightly emphasising the relevance of high energy prices for the competitiveness of European firms, its discussion of the root causes thereof is not always backed by the available evidence, and some of the proposed solutions are unlikely to result in lower prices. A more coherent policy framework that focuses on setting clear environmental goals, while allowing market mechanisms to determine the optimal technological pathways, would better balance sustainability with economic efficiency and long-term competitiveness.

Introduction

The Draghi Report (DR) identifies high energy prices as one main component of the European Union’s lagging competitiveness:

Even though energy prices have fallen considerably from their peaks, EU companies still face electricity prices that are 2–3 times those in the US. Natural gas prices paid are 4–5 times higher. This price gap is primarily driven by Europe’s lack of natural resources, but also by fundamental issues with our common energy market. Market rules prevent industries and households from capturing the full benefits of clean energy in their bills. High taxes and rents captured by financial traders raise energy costs for our economy. (Draghi, 2024a: 6)</EXT>

While speaking of energy at large, the DR focuses on natural gas and electricity, largely ignoring oil despite its accounting for 37.8% of the EU’s gross inland consumption of energy in 2023.^[1] The DR also overlooks coal, which accounts for 9.7% of the EU’s gross inland consumption of energy and 11.7% of the EU’s total electricity generation. The DR’s particular focus may be because oil products are traded in global markets, with no significant price differences among the various regions and industries (except for differences in the tax burden); while natural gas prices are a driver of electricity prices, and both severely affect the competitiveness of energy-intensive, trade-exposed (EITE) businesses, a central concern in the DR.

The DR proposes two broad sets of interventions to address the problem of high energy prices: policies that are aimed at reducing the cost of the energy system (i.e., natural gas and electricity) and policies that are aimed at reducing the share of these costs borne by energy-intensive industries (Zachmann, 2024). In identifying the underlying causes of high energy prices, the DR finds three main drivers:

• the impact of ill-designed climate policies, which result in unnecessarily high costs and/or fail to transfer the benefits of decarbonisation to end-users;
• misconduct or abuses in the electricity and natural gas markets;
• faults in the foundational design of these markets.

The proposed policy solutions are consistent with the above diagnosis. At a very high level:

[1] Unless otherwise specified, data concerning the EU’s energy balance is from the EU energy statistical pocketbook and country datasheets, available at https://energy.ec.europa.eu/data-and-analysis/eu-energy-statistical-pocketbook-and-country-datasheets_en (last update 25 April 2025, accessed on 1 July 2025).

The proposed policy solutions are consistent with the above diagnosis. At a very high level:

Draghi’s main cost-reduction policy is to substantially strengthen the EU single market. In this respect, he makes quite bold proposals, including a move from decentralized to central operation of cross-border electricity flows and Europeanisation of the regulatory oversight of electricity sectors, for example by putting in place a single EU energy trading rulebook. (Zachmann, 2024)

However, some of the proposed solutions do not simply remove the existing barriers from the internal market, for example by promoting more intense cross-border trades of energy; they entail greater and more systematic EU intervention in market functioning and, in some instances, even a radical reform of the underlying rules.

This article does not address Draghi’s proposal on how to update climate policies: Andersen and Brøns-Petersen address this issue elsewhere in this volume. Rather, this article focuses on the report’s proposals concerning the functioning of natural gas and electricity markets. It takes as a given not only Europe’s climate targets of cutting greenhouse gases emissions by 55% below 1990 levels by 2030 and reaching net zero by 2050, but also the targets concerning the renewable share of final energy consumption (which is set to grow from 23% in 2022 to at least 42.5% in 2030)^[1] and energy efficiency (the EU final energy consumption should decline by at least 11.7% by 2030, compared with 2020 projections for 2030, corresponding to a primary energy consumption target of 992.5 million tonnes of oil equivalent (Mtoe) and a final energy consumption target of 763 Mtoe by 2030).^[2] The former is particularly relevant because power generation is the industry where renewable technologies can be deployed most cost-effectively, in contrast to other sectors where low-carbon substitutes are not readily available or affordable. The latter target is also relevant, albeit indirectly, because electrification is a major instrument to achieve greater overall energy efficiency and lower emissions (Sioshansi, 2025).

The article is structured as follows. The next section summarises the main points regarding the DR’s diagnosis of the underlying causes of high energy prices and the proposed solutions thereof. The third and fourth sections deal, respectively, with natural gas and electricity markets. In both these sections, Draghi’s assertions concerning the market’s malfunctioning and the suggested reforms will be addressed. Natural gas markets come logically before electricity markets because, under the existing price formation mechanism (the so-called system marginal price), the price of natural gas has a significant influence on the price of electricity. The final section summarises and concludes.

Draghi’s analysis

The DR starts from the observation that European consumers, particularly energy-intensive industries, have historically paid higher prices for natural gas and power than their foreign competitors, with the gap widening during the energy crisis of 2021–2023 (Figure 1). Moreover, price differences between Member States are large and have grown during the same time span, creating a competitiveness issue both between the EU and its trading partners and within the EU: ‘The spread between the highest and the lowest energy [electricity] prices in EU Member States doubled in 2022 and rose again by 15% in 2023’ (Draghi, 2024b: 5). Gas prices have also become more volatile during the crisis, resulting in increased volatility of power prices, too.

High and volatile prices have an especially strong impact on the EU as it is a net importer of natural gas (as well as oil); therefore, this constitutes a ‘major drag on resources in the EU’ that ‘could be better used by the EU to invest in infrastructures, innovation, education, and other areas’ (Draghi, 2024b: 7). This latter point will not be explored in detail in this article. However, it is important to note that imports do not inherently impoverish a country or reduce its GDP. When a country imports goods or services, it typically does so because those products can be produced more efficiently, at lower cost, or with higher quality abroad than domestically. By importing such goods, the country can allocate its resources more effectively, focusing on industries where it holds a comparative advantage. Therefore, it is not at all clear that the EU becomes poorer by relying on imported energy, especially if domestic alternatives are significantly more expensive (Krugman, 1998; Wolla, 2018; Shepard & Pratson, 2022).

The DR identifies eight root causes of high energy prices: 1) the EU’s dependency on gas imports and exposure to spot markets; 2) marginal gas and coal power prices, impacting electricity prices; 3) underdeveloped long-term contract solutions (such as power purchase agreements markets), hindering benefits from increased rollout of renewable energy sources (RES); 4) higher carbon costs than other regions in the world; 5) higher volatility and non-transparent financial markets for energy; 6) a possible increase in physical network bottlenecks during the energy transition; 7) a lengthy and uncertain permitting process for new power supply and grids; and 8) higher and non-homogeneous taxation and subsidies.

This article focuses on ‘root causes’ 1–3. The remaining ones generally reflect either non-controversial opinions, quasi-truisms, or both. For example, physical bottlenecks in power networks do contribute to price differentials between Member States almost by definition; it is also self-evident that removing bottlenecks would allow for more efficient use of existing or planned assets. It is not obvious, though, to what extent the optimal degree of infrastructural development would pay off: the removal of physical bottlenecks is subject to the law of diminishing returns, so there may well be a point after which the benefits of larger interconnections become lower than the costs. This is, however, an empirical issue, and that is precisely the reason why new infrastructural projects are usually subject to cost–benefit analyses (Cretì & Fontini, 2019). The hidden costs of red tape are well studied in the literature, both in general (Libman, 2022) and in the energy sector (Ruge, 2022; Daniele et al., 2023). Finally, energy taxation and subsidisation in the EU are widely heterogeneous, contributing both to the failure to reflect the costs of consumption or production negative externalities and to huge disparities between Member States (Booth & Stagnaro, 2022). High carbon prices (root cause 4) are not necessarily a bug in the system: they may be a feature therein, depending on the emissions reduction target. Whether or not current carbon prices are consistent with the stated targets goes beyond the goals of this article; the broader role of carbon pricing in the context of the energy transition in dealt with in the article by Andersen and Brøns-Petersen. Finally, root cause 5 is mainly about extending the same conduct and prudential rules that cover financial intermediaries (whether or not they participate in energy markets) to other market participants in such markets that, as of today, have no such obligation. Discussing these aspects goes well beyond the scope of this article; a few considerations, though, will be made concerning the role of derivatives markets and trading hubs in ensuring energy security and a smooth price discovery process.

The DR’s analysis of high energy prices concludes that markets do not work. Specifically, regarding the gas market, Draghi argues that competing importers will inevitably pay higher prices than a unified monopsony:

As net importers of gas, Japan and Korea share similarities with the EU, yet notable differences exist. In Korea, the state-owned Korea Gas Corporation (KOGAS) retains a de facto monopoly, importing approximately 90% of the country’s LNG [liquefied natural gas], helping in principle to bargain on imports and to minimise costs generated along the value chain. In Japan, the state-owned Japan Organization for Metals and Energy Security (JOGMEC) invests in the upstream production of fossil fuels and minerals worldwide. JOGMEC provides equity capital and liability insurance to Japanese companies for upstream projects and LNG-receiving terminals, ensuring in principle secure access to energy at prices nearer production cost. (Draghi 2024b: 8)

In addition, European importers are excessively dependent on spot markets; moreover, long-term contracts are often indexed to spot markets, thereby increasing their direct and indirect impacts on prices. Finally, the DR claims that ‘there is significant concentration at position and trading venue level and that concentration increased in 2024’ (Draghi, 2024b: 12); that is, a small number of traders hold a large share of the total positions in the market (concentration at position level) and most of the trading takes place on a small number of exchanges or platforms (concentration at trading venue level). According to the DR, this may have further inflated gas prices.

With regard to electricity markets, the DR argues that the system marginal price – used to set equilibrium prices in the day-ahead markets (see below) – unduly amplifies the impact of high gas prices on electricity prices. Under this pricing mechanism, the electricity price at any given moment is determined by the marginal cost of generation, that is, the variable cost incurred by the marginal generator to meet demand. According to the DR, ‘natural gas was the price-setter 63% of the time in 2022, despite being only 20% share in the electricity mix’ (Draghi, 2024b: 9). The lack of cheaper infra-marginal sources and more diversified generation explains the high price of electricity (Draghi, 2024b: 10). Similar to gas markets, the DR indicates that the electricity market is overly dependent on spot prices.

The DR suggests several reforms that are intended to result in structurally lowering energy prices. Both the alleged causes and the proposed solutions are summarised in Table 1. Draghi seems convinced that, in both electricity and natural gas markets, deep changes should be implemented (even though the proposed solutions are somewhat less ambitious than the root causes would imply): on the one hand, he suggests that gas markets are inherently uncompetitive, so competition between suppliers and importers should be replaced by joint procurement by the EU, by more strictly regulating the markets, or by nudging market agents to shift towards more long-term contracts (or a combination thereof); on the other hand, he seems to believe that implementing the energy transition will result in lower power prices, but for these benefits to be transferred downstream governments need to step in by promoting (again) more long-term contracts between energy originators and off-takers (especially large, energy-intensive firms) or between originators and some public counterparts.

Table 1. Root causes of high energy prices and solutions proposed in the Draghi Report

The following sections discuss both the underlying analysis and the proposed solutions.

In 2021–2023, the price of natural gas reached unprecedented levels, peaking above €300/megawatt hour (MWh) in August 2022, in comparison with a long-term historical average in the range of €15–€25/MWh. Prices have normalised somewhat since 2023, settling in the range of €30–€50/MWh (much lower than the peaks but still significantly higher than the pre-crisis norm) (Molnar & Zeniewski, 2025; Fulwood, 2024). The DR argues that 1) internal competition among gas importers drives gas prices above acceptable levels, 2) gas trading hubs (most importantly the Title Transfer Facility, TTF) may be either manipulated or scarcely representative of the underlying fundamentals, and 3) gas exchanges are too exposed to spot prices. Hence, the proposed solutions hinge on reinforcing joint procurement of gas, moving away from spot purchases or from spot-linked contracts, and more strictly regulating trading hubs to prevent opportunistic behaviours.

In contrast to products such as the COVID-19 vaccines, which were successfully negotiated and procured by the European Commission on behalf of the Member States, natural gas is traded by professional market participants, including producers, importers, (large) consumers, and financial intermediaries. The demand for natural gas is highly uncertain, unlike vaccine demand, which was directly set by the European Commission and national governments in control of their healthcare systems. Gas demand depends on several factors: overall economic performance (a stronger economy typically increases consumption); the relative price of alternative energy sources; investment in capital assets such as renewables or energy-efficient appliances (which reduce gas usage); and climate variability, typically measured by heating degree days (HDDs), with colder winters increasing demand. To manage these complexities, traders have developed sophisticated risk management strategies. Over time, they have shifted from long-term contracts to spot market purchases. Among the remaining long-term contracts, pricing has evolved from being indexed to a basket of non-gas commodities (such as various types of crude oil and petroleum products) to being tied directly to gas hub prices. Historically, in the absence of spot markets, European importers signed long-term contracts with foreign producers, such as those in North Africa or Russia, at fixed starting prices, which were later adjusted based on indices linked to other energy products. As a result, gas prices were influenced by unrelated market dynamics rather than supply–demand fundamentals. While this pricing model still exists in some contracts (particularly with North African suppliers), the development of gas exchanges such as the TTF enabled long-term contracts to be indexed to market-based gas prices, aligning them more closely with actual market conditions.

The European Commission has long promoted this shift as a means of fostering competition in the domestic gas market. The DR itself acknowledges that, by shifting the indexation of long-term contracts away from oil and other products towards natural gas spot prices, Europeans have reaped significant benefits. According to the International Energy Agency (IEA), as the DR observed, ‘the European Union saved USD 70 billion over a decade because its imports were gradually priced away from oil and towards TTF’ (Draghi, 2024b: 27). The savings occurred because natural gas prices – both in spot markets and in spot-indexed long-term contracts – began to reflect actual gas supply and demand conditions. This decoupled gas prices from oil and petroleum product prices, which were influenced by scarcity specific to those separate markets. As the IEA explains, ‘[o]ver the past decade, the EU built up significant capacity to import gas via pipelines or as LNG. The shift towards spot market pricing allowed the EU to benefit from low prices for LNG imports during periods of ample supply’ (Zeniewski, 2021). Nonetheless, prices in the US – as reflected by the main gas trading hub, Henry Hub – have remained consistently lower than in the EU and other regions. This reflects both the abundance of North American gas production and the region’s limited capacity for exports.

During the energy crisis, the gap between Europe’s TTF and the United States’ Henry Hub widened, so that:

[e]ven accounting for the costs of transporting LNG to Europe, the price was still around half the price of European gas. This shows that the cost premium linked to spot indexation is around half of production and transport cost pricing. This margin accrues mostly to large energy companies and commodity traders [that] manage the transport of gas from the US to Europe. (Draghi, 2024b: 27)

Hence, the DR suggests that, ‘to reduce the EU’s exposure to the volatile spot market and leverage potential downward pressures on prices, it would be beneficial to promote the signing of long-term contracts by European companies which incorporate pricing formulas reflecting less spot indexation’ and ‘support joint purchasing via procurement’ (Draghi, 2024b: 27).

These proposals rely on two main assumptions: on the one hand, the alleged failure of the TTF and other gas hubs to reflect the ‘true costs’ of gas supply; and on the other hand, the alleged failure of competing gas importers to secure ‘fair’ prices from producing entities. To address the first problem, the DR recommends better regulating the TTF and pricing gas away from the TTF; it is the same logic underlying some of the emergency measures that were introduced in 2022, most notably a gas price cap that would be triggered if specific circumstances and price levels were in effect for a prolonged period. To address the second problem, it recommends reforming the existing aggregation platform, called AggregateEU.

Despite the assertions in the DR, the available evidence does not seem to suggest that the TTF mispriced gas. For example, several papers have found that TTF sweep price variations reflected new information as it became available in a rapidly changing and uncertain environment (Goodel et al., 2023; Bortolotti, De Giorgio, & Paltrinieri, 2022). Precautionary regulations that have imposed a 90% minimum storage level by the beginning of the heating season since 2022 have contributed to pushing prices up, potentially introducing perverse incentives to over-rely on stored gas rather than on fresh imports (De Giorgio, 2023). In this context, the price cap had little (if any) effect (Goodell et al., 2024), whereas the TTF emerged as a mature and liquid benchmark. The benchmark Dutch TTF is far and away the leading European traded gas hub, used by many more market participants than any other hub; has a very high traded products score, with far greater total traded volumes than all the other hubs put together; has the highest Tradability Index score[;] and finally, by far the greatest churn rate. TTF total traded volumes represent 82.9 per cent of total European traded gas volumes, and its churn rate [i.e. the ratio of the total volume of gas traded at the TTF hub to the volume of physical gas actually consumed, a common measure of market liquidity] calculated against the much greater physical consumption figure of the countries including and bordering the Netherlands, has risen considerably for the second year running and is now 45.9 times, easily becoming for the first time a ‘very liquid’ benchmark hub. The TTF churn against all Europe’s gas consumption is a very impressive 20.3 times. TTF is being used to price spot LNG cargoes and has become an investment asset class in its own right. (Heather, 2025: iv)

In other words, the TTF serves as a representative benchmark that accurately reflects the real supply and demand conditions for gas in the EU. It is the most liquid gas trading hub in Europe and ranks among the most liquid worldwide, to the extent that it has become a global reference point. Based on the available evidence, it is difficult to argue that the TTF misprices gas or is subject to manipulation. While such issues cannot be entirely ruled out, there is no prima facie case to justify pricing gas independently of the TTF. Any allegations of market misbehaviour should be substantiated. Notably, the DR provides neither proof nor even a suggestion that the TTF mispriced gas, whether during typical years or throughout the recent energy crisis.

At the same time, the joint procurement platform launched by the EU did not quite work as expected. The AggregateEU platform was started in 2022 based on the belief that, by aggregating EU demand, it would be possible to buy gas from foreign producers at cheaper prices. The European Commission describes AggregateEU as follows: ‘AggregateEU pools gas demand from EU and Energy Community companies and matches this demand with competitive supply offers. Following the matching of demand with supply, companies can voluntarily conclude purchasing contracts with gas suppliers, either individually or jointly.’^[1] According to the Solidarity Regulation that established the platform, Member States must ensure that entities participating in the platform account for at least 15% of Member States’ gas storage filling targets. Participation, hence, is mandatory: once all the bids have been submitted, the platform matches supply and demand and moves on to the later stage, where the parties are supposed to negotiate the supply contracts. Despite initial scepticism (Barnes, 2023), the platform has been kept in operation. However, its performance has been less than satisfying: according to the European Court of Auditors, 

the volumes requested are equivalent to 50% of EU gas storage capacity, much higher than the compulsory 15% of EU gas storage required by law. This suggest[s] that AggregateEU has generated genuine interest among gas entities. However, we could not determine AggregateEU’s added value in relation to gas trading platforms, nor the market failure that AggregateEU addresses[,] as the divergence in prices across EU gas markets caused by the crisis was already substantially reduced at the time of AggregateEU’s launch. (ECA, 2024: 36–37)

Even less enthusiastic is the evaluation performed by two consultancies, Frontier Economics and Freshfields Bruckhaus Deringer (2024), on behalf of the European Commission. According to the Commission’s consultants, ‘[o]ur main finding is that AggregateEU may have contributed to establishing new commercial relationships, though the extent to which matches with new suppliers resulted in the conclusion of gas supply contracts is unclear’ (Frontier Economics & Freshfields Bruckhaus Deringer, 2024: 7).

Furthermore, based on a survey of stakeholders, the report suggests that ‘AggregateEU may have initially resulted in matches being made with new counterparties on occasion; Except in rare instances, matches were not suitable (e.g. due to missing contractual requirements); and with further tendering rounds, further new matches have typically not been generated’ (Frontier Economics & Freshfields Bruckhaus Deringer, 2024: 62). It follows that ‘[i]t is likely that, faced with high and volatile energy prices, many customers will have expended greater resources on energy trading regardless of whether AggregateEU was introduced. This may have contributed to counterparty discovery, even under a counterfactual in which AggregateEU would not have been in place’ (Frontier Economics & Freshfields Bruckhaus Deringer, 2024: 63).

Simply put, the platform collects supply and demand bids and matches them with each other. However, this matching does not automatically result in a contract being signed; instead, it marks the beginning of a negotiation process. In most cases, these negotiations do not conclude successfully for various reasons. Even when contracts are eventually signed, these agreements would likely have been reached regardless of the platform’s involvement.

The reason for this is that most of the services provided by the platform are also available from commercial suppliers of both gas and market intelligence: ‘there is some risk that public provision could crowd out private offerings. Therefore, policymakers need to balance this risk against their desire to support a quick market development of the products in question’ (Frontier Economics & Freshfields Bruckhaus Deringer, 2024: 83). Despite the cautious wording, it is clear that the platform has fallen short of delivering the expected benefits; consistently, Frontier Economics and Freshfields Bruckhaus Deringer (2024) has been very cautious in recommending that the experiment is not extended to other commodities that might in principle have been subject to forms of demand aggregation, such as hydrogen, biomethane, captured methane or CO₂, and strategic raw materials. The report does not consider the proposal to establish a public counterpart in charge of gas procurement, as suggested by the DR. However, the experience with AggregateEU should sound a note of caution regarding further steps: so far, the platform has not delivered the benefits expected by its proponents, while it has demonstrated at least some of the risks that its opponents had foreseen. In commenting on the DR’s proposals on gas, the Council of European Energy Regulators emphasised that ‘the proposal to reinforce joint procurement could become redundant if the industry indeed shifts more towards long-term sourcing strategies’ (CEER, 2024: 1).

The very point behind the analysis in the DR is that it assumes that gas markets have not worked – because they mispriced natural gas or increased price levels and volatility – but, with the benefit of hindsight, there is no evidence thereof. There is some evidence that gas markets reacted promptly to the changes in market conditions and have now normalised, as has been shown above.

Electricity markets

The DR acknowledges that high natural gas prices are a major driver of high electricity prices. The retail price that consumers (including large industrial consumers, small businesses, and residential customers) pay comprises four main components: 1) the wholesale cost of energy; 2) network and metering costs; 3) other levies, most notably green levies; and 4) taxes. The share of each of these components varies across the Member States (depending on both structural and policy issues) and over time. The DR focuses in particular on component 1 and, to a lesser extent, 2 and 3. It devotes comparatively less attention to component 4, aside from stating that taxes and other levies should be reduced. As Figure 2 shows, on average, energy and supply accounted for 54% of the power bill in 2023, followed by network costs (24%); environmental, renewable, and capacity levies (8%); and VAT (14%) (ACER & CEER, 2024). However, in 2023, some transitional measures introduced in 2021–2022 to mitigate the energy crisis and shield consumers were still in place. As a result, the breakdown may have changed in 2024 and 2025, with a lower share of wholesale prices and a greater share of environmental, renewable, and capacity levies.

The DR focuses on wholesale power prices, that is, the cost that energy suppliers pay to purchase electricity on the open market before adding their own costs and profit margin to sell it to consumers. Wholesale power prices emerge primarily from competitive markets, with prices determined by supply and demand dynamics in day-ahead and intra-day markets, regulated and coordinated at the EU level.

Day-ahead markets (DAMs) are the primary venue for setting electricity prices. Market participants submit bids to buy or sell electricity for each hourly (or sub-hourly) time slot of the following day. The market algorithm ranks supply offers in ascending order of price (forming the ‘merit order curve’) and matches them to expected demand. While demand-side bidding exists, it is often less price-sensitive and actively traded than supply. As the delivery time approaches, intra-day markets allow participants to adjust their positions. Finally, the system operator (i.e., the grid operator) maintains real-time balance between supply and demand in the balancing markets, ensuring the physical stability of the power grid (Cretì & Fontini, 2019).

The single most important determinant of wholesale power prices is the outcome of DAMs (Day Ahead Markets). In this market, once the equilibrium is reached and the equilibrium price is discovered, all accepted bids receive the price of the most expensive accepted offer, that is, the ‘marginal unit’ or the ‘system marginal cost’, as shown in Figure 3. This is not a surprising result: ‘a general result in economics is that to maximise the net surplus from consumption, price should be equal to the marginal cost of production and the marginal surplus from consumption’. Therefore, ‘Under reasonable conditions, there exists a unique equilibrium price such that supply is exactly equal to demand, that is, the quantity produced is exactly equal to the quantity consumed. At this price, the marginal surplus is equal to the price, which is also equal to the marginal cost. The marginal net surplus is equal to zero: the equilibrium leads to the optimum’ (Joskow & Léautier, 2021: 41, 43).

Typically, the marginal unit is a gas-fired power plant or another form of flexible generation. As a result, electricity prices – given the current composition of Europe’s power generation fleet – are heavily influenced by natural gas prices. In addition, power generators that emit carbon (for example, by burning natural gas or coal) are required to purchase carbon allowances equivalent to their emissions, as mandated by the EU Emissions Trading System. Consequently, carbon prices also contribute to the overall cost of electricity, particularly its wholesale price.

The DR suggests three channels to reduce power prices: 

• Decouple the remuneration of RES and nuclear from fossil-fuel generation though long-term contracts (Draghi, 2024b: 35–36);
• Increase the share of low (marginal) cost renewable generators (Draghi, 2024b: 36–37);
• Lower and level the energy taxation playing field and the strategic use of taxation measures to reduce the cost of energy (Draghi, 2024b: 38).

Draghi (2024a: 44) goes so far as to call for the complete decoupling of electricity and gas prices. While some elaborated proposals to achieve these results have been published in the literature (Fabra, 2022; Frangioni & Lacalandra, 2024), these have been generally evaluated as either too complex to implement, self-defeating, or both (Schlecht et al., 2022; Zachmann et al., 2023). A review paper on the subject found that

in all the papers supporting the split market idea [i.e. decoupling of electricity and gas prices], there is the presumption that government or an electricity market regulator will be able to implement the considerable additional institutional requirements that are needed to make the split market work – these include preventing arbitrage and trade across the diverging supply contracts, maintaining the required entry and prevention of entry conditions, assuring the flow of symmetric information to consumers and producers, integrating the generation contracts with the transmission and distribution system, and monitoring the performance and success of the proposed changes. None of the proposals analyze the regulatory issues involved and none of the proposals recognizes or quantifies any regulatory costs of implementation, which are likely to be considerable. (Weyman-Jones, 2023)

A thorough analysis by the EU’s Agency for the Cooperation of Energy Regulators (ACER) found no evidence of structural faults in the electricity market design (ACER, 2022). According to CEER (2024: 3), ‘the broad consensus [is] that marginal pricing is the most efficient method for auction-based markets like day-ahead and intraday trading’.

The DR does not propose a comprehensive reform of the system marginal price as a solution to high electricity prices. Instead, it advocates for a broader use of long-term contracts between energy consumers and renewable energy producers. These contracts can involve either public or private counterparties. When the state is involved, they are typically structured as contracts for difference (CfDs) – mechanisms where the government guarantees a fixed price for electricity and pays or receives the difference if the market price deviates. When the counterparty is a private entity, the agreements are known as power purchase agreements (PPAs) – long-term contracts where a buyer agrees to purchase electricity from a producer at a predetermined price, providing revenue certainty for renewable projects.

The underlying rationale is that, by signing these contracts, the low cost of renewable energy can be passed on to final consumers (in the case of PPAs) or to the state (in the case of CfDs) while also providing stable revenues for green investors – thereby facilitating the financing of new renewable energy projects. Offering indirect support for PPAs – for example, through public guarantees that mitigate counterparty risk – can be a sound policy measure, as long as it promotes private investment in new renewable capacity and ensures that the energy produced is consumed (typically by large industrial users), effectively displacing fossil-fuel use for the same end (Stagnaro et al., 2025).

CfDs, however, present a different case. While they can be effective in minimising the public cost of supporting renewable energy deployment, they may also introduce market distortions, particularly when the volume of subsidised energy becomes substantial, as is already the case. In 2020, an average of 22.7% of total electricity produced in Europe received some form of renewable energy support, and that share has likely increased since (CEER, 2023; see Figure 4).

If CfDs become the prevailing source of financing for renewable energies – by shifting price risks from investors to the government – then the dispatch and investment decisions of generation assets may be affected. For example, since a CfD sets the price at which energy is sold, investors may be incentivised to maximise production. However, this does not necessarily mean that social welfare is maximised. Suppose excess renewable production drives prices down close to zero, or even below. In that case, the support system effectively transfers valuable resources to producers who do not create social value (otherwise energy prices would remain positive and well above zero). This is essentially equivalent to a direct subsidy. Several proposals have been made to reduce the potential distortions caused by CfDs (Zachmann & Heussaff, 2023; Schlecht, Maurer, & Hirth, 2024). Even if some issues are addressed, as the volume of CfD-supported energy grows, these contracts may still contribute to increasing system costs and ultimately lead to higher, rather than lower, prices for end consumers.

Renewable energies contribute to reducing wholesale power prices, but they may impose additional costs to the system – such as managing variability and financing investments in grids and storage infrastructure (as the DR recognises; see also ECA, 2025). Whether the net effect is positive or negative is an empirical question, not a theoretical one, and the answer may vary depending on the characteristics of individual Member States. Therefore, simply increasing the share of renewable electricity does not guarantee a fall in retail prices. Moreover, support policies that incentivise renewable growth, without considering the specific context of new installations, may add incentive costs on top of variability-induced system costs. This explains why, despite declining costs of renewable technologies, the overall cost of direct and indirect support policies has risen. Consistent with the DR’s recommendations, policymakers should consider shifting the cost of green levies and similar measures from electricity bills to general taxation (Lo Schiavo & Stagnaro, 2025). However, increasing these costs – whether funded through general taxation or electricity tariffs – is unlikely to reduce energy prices or boost the competitiveness of European industry. Instead, energy and climate policies should be designed to minimise the costs of the energy transition while advancing other key political goals, such as energy security. Achieving this requires opening markets and removing internal barriers that hinder the proper functioning of the EU’s internal gas and electricity markets. High energy prices in the EU are more plausibly the result of government and policy failures, rather than inherent market failures.

Conclusion

The DR correctly identifies high energy costs as a major source of competitiveness disadvantage for European firms. According to the report, these high prices stem from multiple causes that should be addressed through a broad set of reforms. Some proposals are uncontroversial, such as streamlining licensing procedures and reducing energy taxes (even though these are easier said than done). Others are less straightforward.

Notably, much of the DR’s analysis appears to rely on an unproven assumption: that natural gas and electricity markets are structurally flawed. To address perceived issues in gas markets, the DR recommends measures such as joint EU-level procurement, a shift from spot purchases to long-term contracting, and tighter regulation of major trading hubs, especially the TTF. Regarding electricity markets, the report calls for reforms to price-setting mechanisms and endorses tools such as PPAs and CfDs to achieve a ‘decoupling’ of renewable energy prices from natural gas. It also assumes that increasing the share of renewables will automatically lower prices.

This article has critically assessed both Draghi’s diagnosis and the proposed solutions. The diagnosis lacks empirical grounding – indeed, available evidence shows that natural gas and electricity markets have responded to changes in the fundamentals largely as the economic theory would predict. Moreover, some of the proposed solutions risk being ineffective or even counterproductive. This is especially true where government intervention introduces unnecessary costs, as may be the case with joint gas procurement or the over-subsidisation of renewable energy via CfDs.

One possible explanation for the DR’s failure to accurately diagnose the causes of high energy prices lies in its strong anchoring to the exceptional circumstances of the 2022 energy crisis. Several claims remain unsubstantiated: for example, there is little evidence that natural gas and electricity markets malfunctioned in 2022. Rather, unprecedented prices during that period prompted a series of emergency measures (ACER, 2023), which were arguably justified by temporary conditions – most notably, the uncertainty surrounding Europe’s ability to meet its gas demand amid fears of physical scarcity. Today, those conditions have changed significantly. The EU is less dependent on gas (with total consumption dropping from over 400 billion cubic metres (bcm) in 2021 to about 330 bcm in 2023), supply sources are more diversified (Russian imports fell from 150.2 bcm in 2021 to 51.7 bcm in 2024), and liquefied natural gas imports reached over 100 bcm in 2024, nearly 45% of which came from the US.^[1] Meanwhile, renewable sources are playing a growing role, accounting for 24.5% of total energy consumption in 2023.

To be sure, Europe’s electricity and gas markets are not free of problems. Policy contradictions, such as import duties on foreign-made solar panels that raise the cost of photovoltaics, can undermine clean energy goals. Excessive subsidies, particularly legacy incentives for early-stage renewables, may still inflate electricity prices. And anti-competitive behaviour by market participants remains a concern that national competition authorities must address. However, these issues do not originate from the core market mechanisms themselves, such as gas trading hubs or the system marginal price in electricity markets. On the contrary, the evidence suggests that excessive policy intervention explains much of Europe’s high energy costs.

[1] https://ec.europa.eu/eurostat/statistics-explained/index.php?title=Natural_gas_supply_statistics

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