Power to the Few: How Europe's Electricity Markets Remain Locked in the Grip of National Champions

In March 2023, the European Commission tabled its most ambitious electricity market reform in a generation. The trigger was plain enough: wholesale power prices that had spiked above €1,000 per megawatt-hour during the energy crisis, profits at incumbent generators that ballooned far beyond their cost exposure, and tens of millions of households that could not afford to keep the lights and heating on. Yet behind the crisis response lay a structural problem that predated Russia's invasion of Ukraine by decades — the persistent concentration of market power among a small number of nationally dominant utilities that EU liberalization directives were supposed to dismantle starting in 2003.

The Numbers Behind the Oligopoly

The standard tool for measuring market concentration is the Herfindahl-Hirschman Index (HHI), which sums the squared market shares of all firms in an industry. An HHI below 1,500 indicates a competitive market; between 1,500 and 2,500, moderate concentration; above 2,500, high concentration. In U.S. antitrust enforcement, a merger that pushes an industry's HHI above 2,500 typically triggers a challenge from the Department of Justice [1].

By this measure, most EU national electricity markets remain highly concentrated. According to Eurostat and ACER monitoring data, as of 2023–2024 only seven out of 21 surveyed EU countries had household electricity market HHI scores below the 2,000 threshold — meaning the majority of national markets exceed the level that would raise red flags in other industries [1][2].

The concentration is starkest at the generation level. Électricité de France (EDF), now fully renationalized after a 2022 buyout of minority shareholders, accounts for approximately 70% of French electricity production, overwhelmingly through its fleet of 56 nuclear reactors [3][4]. In Germany, the Federal Cartel Office (Bundeskartellamt) found in November 2024 — for the fifth consecutive reporting period — that RWE holds a dominant market position, producing over 26% of total German generation and owning plants deemed "indispensable" when wind and solar output drops [5][6]. In Spain, Endesa, Iberdrola, and Naturgy together control approximately 90% of the national electricity market, with Endesa alone holding around 45% of the regulated supply segment [7]. Italy's market is somewhat more fragmented, with Enel leading at roughly 19% of generation, though it remains the single largest player by a significant margin [8]. Poland's largest generator, PGE (Polska Grupa Energetyczna), holds around 17% of national generation capacity [2].

Source: ACER/Eurostat/National Regulators

Data as of Dec 1, 2024CSV

How Liberalization Stalled

The EU's first Electricity Directive of 1996 and the subsequent Second Energy Package of 2003 were explicitly designed to break up vertically integrated monopolies, introduce third-party access to transmission networks, and allow consumers to choose their supplier [9]. The Third Energy Package of 2009 went further, requiring the "unbundling" of transmission system operators from generation and supply businesses.

On paper, the reforms succeeded: every EU member state now has multiple licensed electricity suppliers, and industrial customers have formal choice. In practice, the degree of real competition varies enormously. The persistence of dominant positions is rooted in several structural features.

State ownership and political entrenchment. France fully renationalized EDF in 2023 at a cost of roughly €9.7 billion. The French government holds 100% of EDF, Poland's treasury controls PGE, and even in Germany, several municipal utilities (Stadtwerke) and state-owned entities maintain large generation portfolios [3][10]. Governments that own incumbents face an inherent conflict: they are simultaneously regulators, competition enforcers, and beneficiaries of monopoly rents.

Vertical integration below the transmission level. While high-voltage transmission has been formally unbundled across the EU, distribution networks and retail supply often remain under the same corporate roof as generation. EDF controls both the dominant generation fleet and roughly 60% of French power retail sales [4]. In Spain, Endesa's integrated structure — generation, distribution, and retail — gives it advantages in customer acquisition that standalone retailers cannot match [7].

Permitting and grid connection barriers. New market entrants consistently cite opaque grid connection procedures, multi-year permitting timelines for generation projects, and lack of transparency in capacity allocation as barriers that favor incumbents with existing assets and regulatory relationships [9][11].

The Price Consumers Pay

European electricity is expensive by global standards, and the gap is growing. In the second half of 2025, the EU average household electricity price stood at €0.2896 per kilowatt-hour, with Germany at €0.3869/kWh and Ireland at €0.4042/kWh — the continent's most costly [12]. For industrial consumers, EU electricity prices in 2025 averaged more than double U.S. levels and nearly 50% above those in China, raising alarms about the competitiveness of European manufacturing [13][14].

Source: Eurostat

Data as of Dec 1, 2025CSV

Disentangling the causes of high prices is contentious. The EU's marginal pricing system — in which the most expensive generator needed to meet demand sets the price for all producers — means that gas-fired plants, subject to volatile fuel costs and the EU Emissions Trading System carbon price, frequently determine the wholesale clearing price even though they supply a diminishing share of actual generation [15]. Grid fees, taxes, and levies account for roughly 29% of household bills and 18% of industrial bills [12].

Critics of market concentration argue that dominant generators exploit their position precisely during stress episodes. The Bundeskartellamt's 2024 report noted that RWE can "systematically predict when its plants are essential to meeting energy demand and therefore could in theory drive up prices" [5]. The International Energy Agency found that renewable generators in the EU earned windfall profits during the 2021–2023 crisis because the marginal pricing mechanism paid them gas-linked prices despite their near-zero fuel costs [16].

Defenders of the current market design counter that marginal pricing is the most efficient dispatch mechanism available, and that high prices during scarcity are a feature, not a bug — they signal the need for investment in new capacity [15]. Eurelectric, the European power industry association, has argued that marginal pricing ensures that "the cheapest plants run first" and that alternatives would distort investment signals [15].

Energy Poverty and the Windfall Profits Debate

The human cost of the price spike was severe. Approximately 42 million people across the EU — 9.3% of the population — were unable to keep their homes adequately warm in 2022, a figure that rose to 10.6% in 2023 before easing to 9.2% in 2024 [17][18]. In Bulgaria, Greece, Portugal, and Lithuania, more than 20% of the population reported inadequate heating [17].

Source: Eurostat/EESC

Data as of Dec 1, 2024CSV

In October 2022, the European Council passed an emergency intervention imposing a temporary solidarity contribution on fossil fuel producers and capping inframarginal electricity revenue at €180 per megawatt-hour, a measure projected to raise approximately €117 billion annually for redistribution to consumers [19]. Several member states implemented national variants. Yet the measures were temporary, and their effectiveness was uneven: some countries returned revenues as lump-sum payments, others as bill subsidies, and enforcement varied widely [20].

The windfall-profits episode crystallized a deeper question: did generators' excess earnings during the crisis reflect genuine scarcity rents — the textbook signal to build more capacity — or the exercise of market power by firms that faced little competitive pressure? The answer likely differs by market. In France, where EDF's nuclear fleet has near-zero marginal cost, the company reported significant surplus revenue until the government imposed a clawback mechanism. In Germany, RWE's coal and gas plants set prices during peak hours, generating margins well above their long-run costs [5][16].

Greenpeace estimated that the largest windfall profits in the EU accrued in Germany, France, Spain, and Italy, with above-average margin expansion in fossil fuel segments [21]. The Tax Foundation documented that by 2024, at least 16 EU member states had introduced some form of windfall profit tax on energy companies, though most were structured as temporary surcharges rather than permanent structural changes [20].

The Case for Big Utilities

Not everyone views high concentration as a market failure. A counterargument, grounded in engineering and investment logic, holds that large vertically integrated utilities provide services that competitive fragmentation structurally cannot deliver.

Grid stability and system balancing. Electricity is unique among commodities: supply and demand must balance in real time, second by second, or the grid collapses. Large utilities with diversified generation portfolios — nuclear, hydro, gas, and increasingly renewables — can manage this balancing internally, reducing reliance on volatile spot markets. Smaller, specialized generators cannot provide the same depth of ancillary services [22].

Long-term investment. Nuclear plants take a decade or more to build and cost billions of euros. Offshore wind farms require front-loaded capital of €3–5 billion per project. Only firms with large balance sheets and patient capital — often backed by state ownership — can finance these assets. Fragmenting the industry risks leaving no entity large enough to underwrite the energy transition's capital requirements [22][23].

Cautionary tales from deregulation. The California electricity crisis of 2000–2001 and the Texas grid failure of February 2021 are frequently cited as evidence of what happens when markets are designed around thin competitive margins without adequate capacity reserves. In both cases, inadequate generation reserves, market manipulation (California) and weatherization failures (Texas) led to catastrophic blackouts. Proponents of the European model argue that large, regulated incumbents provide a buffer against such outcomes [22].

The counterargument has limits. France's EDF accumulated over €60 billion in debt partly because the state used regulated tariffs to suppress consumer prices while under-investing in reactor maintenance, leading to an extended period of low nuclear availability in 2022 that worsened the very crisis it was supposed to prevent [3]. The benefits of scale come with the risk that political interference substitutes for market discipline.

The Reform Agenda — and Its Opponents

The EU's 2023 Electricity Market Reform, formally adopted in mid-2024, represents the most significant update to the bloc's electricity market rules since the Third Energy Package [24]. Its key provisions include:

Mandatory contracts for difference (CfDs). From 2027, all new public investments in renewable and nuclear generation must use two-way CfDs, in which governments guarantee a floor price to investors but claw back revenues when market prices exceed the strike price. This mechanism is designed to insulate consumers from price spikes while maintaining investment incentives [24][25].

Power purchase agreements (PPAs). The reform encourages long-term bilateral contracts between generators and large consumers, reducing exposure to spot market volatility. European PPA volumes reached 13.1 gigawatts in 2025 [26].

Consumer protection. New rules require electricity suppliers to offer fixed-price contracts and strengthen protections for vulnerable consumers, including a prohibition on disconnecting households during energy emergencies [24].

Capacity market oversight. ACER gains enhanced authority to monitor capacity mechanisms, which several member states use to subsidize backup generation but which critics argue entrench incumbents [2][24].

The legislative process revealed deep divisions. France pushed hard for CfDs that would cover nuclear power — preserving the model under which EDF operates — while Germany, the Netherlands, and Nordic countries defended the primacy of short-term marginal pricing and resisted measures they viewed as re-regulation [24][25]. Several Eastern European member states with state-owned utilities sought broad exemptions for existing generation assets. The final text represented a compromise: CfDs are mandatory for new public support but voluntary for existing plants and private investments [25].

Implementation timelines stretch to 2027 and beyond, and the reform's effectiveness depends entirely on member-state transposition — the same mechanism that allowed the 2003 liberalization directives to be diluted in practice.

Renewables: Breaking the Oligopoly, or Reproducing It?

The energy transition offers the theoretical possibility of disrupting incumbent market power. Wind turbines and solar panels can be deployed by a wider range of actors — community cooperatives, municipal utilities, corporate offtakers — than nuclear or large thermal plants. Renewables accounted for 35% of EU power generation in 2024, up from under 20% a decade earlier [2].

In practice, the picture is more mixed. The same incumbents that dominate conventional generation are acquiring renewable assets at scale. Iberdrola has become one of the world's largest renewable energy companies, with a market capitalization exceeding $158 billion in 2025 and a strategic reallocation of 60% of its 2024–2026 capital expenditure toward regulated grid assets [27]. EDF, Enel, and RWE have all made large renewable investments, and their existing grid connections, balance sheet strength, and regulatory relationships give them advantages in competitive auctions for offshore wind and battery storage contracts [26][28].

Offshore wind is particularly susceptible to concentration. Projects require multi-billion-euro investments, complex permitting across maritime jurisdictions, and long-term grid connection agreements — all of which favor large incumbents. The EU's offshore wind pipeline, targeting 60 GW of installed capacity by 2030, is dominated by a small number of developers: Ørsted, Vattenfall, Iberdrola, EDF, and RWE account for the majority of awarded contracts [28][29].

Battery storage, by contrast, shows signs of a more competitive landscape. Nearly 12 GW of battery energy storage capacity was contracted under flexibility purchase agreements in Europe in 2025 — triple the 2024 figure — with a broader range of developers and financial investors participating [26]. Whether this emerging sector will consolidate as it matures remains an open question.

The transition also creates new dependencies. As ACER's 2025 monitoring report documented, rising grid congestion management costs — reaching €4 billion in 2023 — reflect the infrastructure bottleneck created by connecting dispersed renewable generation to demand centers [2]. Transmission system operators, which are separate from generation companies under unbundling rules, estimate that €150 billion in new lines is required by 2030 [2]. The companies best positioned to navigate this congested system are, again, the large incumbents with diverse portfolios and flexible generation to offer when renewables underperform — as demonstrated during the December 2024 "Dunkelflaute" episode in Germany, when low wind and solar output pushed prices close to €1,000/MWh [2].

What Would Real Competition Look Like?

The EU's electricity markets sit in an uncomfortable middle ground: too liberalized for the coherent state planning that France's nuclear program once exemplified, but not competitive enough to deliver the consumer benefits that liberalization promised. Household prices remain among the highest in the developed world [12][14]. Industrial competitiveness is eroding relative to the U.S. and China [13]. And the incumbents that were supposed to face competitive pressure have, in most markets, maintained or even strengthened their positions.

Genuine reform would require member states to confront the contradictions in their own policies. Governments cannot simultaneously own dominant utilities, set regulated tariffs that suppress competition, block new entrants through permitting delays, and then blame "the market" for high prices. The 2024 reform package is a step, but its reliance on voluntary CfD adoption for existing assets and member-state transposition means that the same political dynamics that blunted previous liberalization efforts remain in play.

The energy transition adds urgency. If the shift from fossil fuels to renewables merely replaces one set of oligopolists with the same firms operating wind farms and battery storage instead of coal plants and gas turbines, Europe will have decarbonized its electricity without democratizing it. The coming decade will determine whether the continent's electricity markets serve consumers or continue to serve the handful of companies — and the governments that own them — that have controlled European power for a century.