I want to be clear about something up front: I understand why his critique resonates. I really do. When electricity prices spiked during the 2022 energy crisis and people saw news stories about trading firms posting record profits, the optics were terrible. Energy trading is complex, often opaque, and involves financial instruments that most people have never heard of. When your electricity bill doubles and you read that some trader made a fortune on the same market dynamics that made your bill more expensive, the leech metaphor does not feel like exaggeration. It feels like an accurate description of predatory behavior.

Moreover, our industry has frankly earned some of this skepticism through our own failures. Energy traders have been terrible at explaining what we actually do. We retreat into technical jargon when questioned. We get defensive rather than educational. We have allowed a narrative to take hold in which energy trading is portrayed as a zero-sum game where our profits necessarily come at the expense of consumers. And we have not done enough to distinguish the productive functions that most trading serves from the genuinely problematic behavior that a small minority of market participants engage in. When European regulators identify over 100 suspicious transactions potentially involving market manipulation, those cases receive extensive media coverage. The millions of legitimate transactions that enable renewable energy integration and cross-border coordination go unnoticed.

So I am not writing this essay to dismiss concerns about energy markets or to claim that everything is fine. Some of the criticism is legitimate. Market design matters enormously, and poorly designed markets can absolutely harm consumers. Market power remains a persistent problem in many jurisdictions. The distributional effects of liberalization have been uneven, with large industrial consumers typically benefiting more than households. And yes, some market participants do behave badly, which is precisely why we have regulatory frameworks like REMIT to police misconduct.

What I want to do instead is explain what energy trading actually accomplishes when markets are reasonably well designed. I want to show why these markets exist in the first place, what functions traders perform, and what the empirical evidence tells us about whether liberalized electricity markets improve overall welfare compared to the alternatives. My argument is not that markets are perfect or that regulation is unnecessary. It is well-regulated energy trading that provides essential services that make electricity systems more efficient, enable renewable energy integration, and generate substantial net benefits for consumers. The best available evidence suggests that European market integration results in welfare gains of 34 to 43 billion euros annually. Those are not my figures or industry claims. They come from the EU Agency for the Cooperation of Energy Regulators, synthesizing peer-reviewed research.

The politician I had this discussion with is not an anti-market ideologue. He has an economics degree and worked as a business journalist for many years. He is educated and thoughtful. But like many people, his intuition about energy trading is shaped more by the visible spectacle of profits during the 2022 crisis than by an understanding of the underlying mechanisms. My goal is to make those mechanisms clearer to people who share his skepticism. If, after reading this, you still believe energy markets are fundamentally extractive rather than productive, at least you will understand what you are rejecting.

Let me start with some context about where these markets came from and why we transitioned away from the system that preceded them.

The World Before Markets: What We Left Behind

To understand why electricity markets exist, you need to understand what came before them. For most of the 20th century, electricity in Europe and much of the world was provided by vertically integrated state monopolies. A single entity, typically government-owned, controlled everything from power generation to transmission networks to distribution to retail sales. These utilities operated under what economists call command and control planning. They would forecast demand, build enough generation capacity to meet that demand plus a safety margin, invest in transmission and distribution infrastructure, and set tariffs that regulators deemed acceptable.

This system had some real advantages. It provided universal service. It enabled long-term planning and investment. It avoided the coordination problems that can arise when multiple entities control different parts of the supply chain. And for much of its existence, it delivered reliable electricity at what seemed like reasonable prices. The engineers running these utilities were often competent and committed to their public service mission.

But by the 1970s and 1980s, the problems with this model had become increasingly apparent. The fundamental issue was that monopolies face systematically distorted incentives. Without competitive pressure, there was limited motivation to control costs. Without price signals, there was no efficient mechanism for allocating resources across time and space. Without the possibility of failure and exit, there was no natural mechanism for kicking out poor performers.

The empirical consequences were substantial. European countries routinely maintained generation capacity 20 to 30 percent above peak demand because each nation pursued self-sufficiency. This was enormously expensive. Power plants are among the most capital-intensive infrastructure investments in any economy. Building redundant capacity that sits idle most of the time imposes massive costs that ultimately get passed to consumers (and taxpayers). When I say redundant, I mean that neighboring countries would each build enough generation to cover their own worst-case scenarios independently, even though meteorological conditions and demand patterns are not perfectly correlated across borders. If countries could share capacity, they could achieve the same reliability with far less total investment.

The lack of price signals created additional distortions. In a monopoly system, electricity was typically sold at average tariffs that did not reflect the actual cost of supply at different times or locations. This meant consumers had no reason to shift demand away from peak periods when supply was expensive. It meant no incentive for demand response. And it meant the utility had to build enough capacity to meet peak demand even if that peak only occurred for a handful of hours per year. In a market system, prices rise during scarcity, which both incentivizes conservation and rewards investments in additional capacity. In the monopoly system, those price signals simply did not exist.

Cross-subsidies were pervasive. Industrial users were often charged more than the cost of serving them in order to keep residential rates politically acceptable. Urban customers subsidized rural electrification. Some regions subsidized others. These cross-subsidies might have been driven by legitimate distributional concerns, but they were rarely transparent, and they distorted investment decisions. They also made it nearly impossible to evaluate the actual economic performance of the system because true costs were obscured.

The inefficiency was not just theoretical. When economists later went back and did detailed cost-benefit analyses comparing actual performance under monopoly to modeled performance under competition, they found substantial productivity gaps. When the UK restructured its electricity sector starting in 1990, subsequent analysis by Newbery and Pollitt found that costs fell by approximately 5 percent in generation and transmission. Distribution costs fell about 10 percent. Labor productivity increased dramatically as overstaffing was reduced. Plant availability improved as operators faced stronger incentives to keep facilities running.

Denmark, before liberalization, illustrated many of these problems. Limited interconnection with neighboring countries meant we could not make use of Norwegian hydropower when wind generation was low, or sell surplus wind power to Germany when generation exceeded domestic demand. This made integrating variable renewable energy far more expensive than it needed to be. You essentially had to maintain fossil fuel backup capacity equal to your entire renewable production capacity because you had no way to access flexibility from neighboring systems. From a climate perspective, this was enormously wasteful.

The intellectual and political momentum for reform built gradually through the 1980s (Remember Thatcher and Reagan? :-) ). Chile restructured its electricity sector in 1982, creating what would become the longest-running example of comprehensive market liberalization. The results there were quite impressive. Prices fell 30 percent in real terms over the subsequent two decades. Installed capacity grew steadily. Labor productivity in the energy industry increased by a factor of five to six. Energy losses in distribution fell by 71 percent as private operators had incentives to reduce technical and commercial losses that state monopolies had tolerated.

The UK followed in 1990 with the privatization and restructuring of the Central Electricity Generating Board. The Nordic countries began creating a regional wholesale market in the early 1990s, which became operational as Nord Pool in 1996. This was the world’s first multinational power exchange. The European Union, driven by its broader single market project, began pushing for electricity market liberalization through a series of directives starting in 1996.

The economic logic was straightforward. Electricity is not fundamentally different from other goods and services in ways that make competition impossible. Generation is a competitive activity. Different technologies, different fuel sources, different locations, and different operators can compete to supply power. Retail is also potentially competitive. Different suppliers can offer different contract terms, different pricing structures, and different levels of service. The parts of the system that are natural monopolies, primarily transmission and distribution networks, could be separated and regulated while competitive segments were opened to market forces.

But here is the critical thing that often gets lost in discussions about market liberalization: creating competitive markets requires far more than just breaking up monopolies and telling firms to compete. You need institutions that enable coordination. You need transparent price formation. You need mechanisms for managing transmission constraints. You need systems for maintaining reliability when no single entity controls the entire supply chain. And crucially, you need market participants willing to trade continuously, providing liquidity and enabling all the other functions markets are supposed to perform.

This is where energy traders enter the picture. We did not create electricity markets. Policymakers created electricity markets for reasons having nothing to do with enriching traders. They created markets because the monopoly alternative had become economically untenable. But once you have markets, you need people to make them work. That is the role I want to explain.

What Energy Traders Actually Do

When people hear the term energy trader, they often imagine something like the stereotype of a Wall Street stock trader: someone making aggressive bets on price movements, trying to outwit other market participants, extracting profits through superior information or faster execution. And while some of that happens in energy markets, it misses the more fundamental and mundane functions that trading serves. The vast majority of energy trading is not about making dramatic speculative bets. It is about providing services that enable markets to function continuously and efficiently.

Let me explain the three core functions that energy traders perform, using concrete examples to illustrate how each one works and why it matters.

1. Liquidity Provision: Keeping Markets Operational Around the Clock

The first and most basic function is liquidity provision. This means standing ready to buy or sell electricity at publicly quoted prices throughout the day and night. It sounds simple, but it solves a real coordination problem.

Power plants need to sell electricity. Consumers and retailers need to buy it. But they do not naturally find each other at the exact moment a transaction needs to occur. A wind farm operator might need to adjust its position at 2 am when forecast models show wind speeds will be lower than expected in six hours. An industrial facility might decide at noon to increase production tomorrow and therefore needs to buy additional power. A utility serving residential customers needs to continuously balance its portfolio as actual demand deviates from forecasts.

Without liquidity providers, each of these entities would need to find a specific counterparty willing to trade at that exact moment and negotiate terms bilaterally. This is time-consuming, expensive, and often impossible on short notice. The transaction costs would be enormous. Liquidity providers solve this by maintaining inventories of contracts and continuously posting bid and ask prices. If you need to buy power for delivery tomorrow afternoon, you can execute that trade immediately at the prevailing market price rather than spending hours trying to find someone willing to sell to you.

The compensation for providing this service comes from the bid-ask spread. A trader might offer to buy a particular contract at 50 euros per megawatt hour and simultaneously offer to sell it at 50.20 euros per megawatt hour. That 20 cent spread is the margin for providing immediacy (not needing to wait). It covers the risk of holding inventory, the cost of capital, and the operational expenses of maintaining trading infrastructure and staffing desks around the clock.

Consider what happens in the intraday market, which operates continuously up until shortly before actual delivery. Suppose a wind farm receives an updated forecast at 2 pm showing that wind speeds will be significantly lower than expected when power is delivered at 6 pm. The wind farm needs to reduce its sold position because it will not be able to generate as much as it has already committed to deliver. Simultaneously, some other market participant, perhaps a conventional power plant, needs to increase its generation to fill the gap.

In a liquid market, the wind farm can execute this adjustment in seconds. It logs into the trading platform, sees current prices, and sells the contract it needs to offset its position. The transaction is immediate and the price is transparent. In an illiquid market without active traders providing continuous quotes, the wind farm might need to start calling potential counterparties, explaining its situation, and negotiating terms. By the time a deal is reached, the market might have moved significantly. The wind farm bears both price risk and execution risk. And if it cannot find a counterparty quickly enough and ends up out of balance when delivery occurs, it faces potentially severe imbalance penalties from the system operator.

Liquidity provision makes these adjustments routine rather than crisis driven. This becomes especially important as variable renewable energy increases as a share of total generation, because forecast errors are inevitable and the ability to adjust positions quickly and cheaply is essential for system stability.

2. Arbitrage: Creating Price Convergence Across Space and Time

The second core function is arbitrage, or more precisely, spatial price convergence trading. Finance purists define arbitrage strictly as riskless profit opportunities, but in energy markets, we use the term more broadly to describe buying where prices are low and selling where prices are high, even though transmission constraints and execution timing introduce some risk. The economic result of this activity is that it moves electricity from where it is abundant to where it is scarce, and in doing so, it equalizes prices across locations.

Here is a concrete example. Suppose it is a particularly windy day in Denmark, so wind generation is high and electricity prices in the Danish bidding zones are low, say 40 euros per megawatt hour. Meanwhile, in Germany, wind generation is normal, and conventional fossil generation is setting the marginal price at 75 euros per megawatt hour. This price difference creates an arbitrage opportunity, assuming transmission capacity is available on the interconnector between Denmark and Germany.

A trader sees this price difference and executes two simultaneous transactions: buys electricity in Denmark at 40 euros and sells electricity in Germany at 75 euros. The trader earns 35 euros per megawatt hour on this spread. But notice what happens to prices as a result of this activity. Buying in Denmark increases demand there, which pushes Danish prices up. Selling in Germany increases supply there, which pushes German prices down. As long as the price difference persists and transmission capacity remains available, traders will continue this arbitrage. Eventually, prices converge to something closer to equilibrium, maybe both ending up around 57 or 58 euros per megawatt hour.

This is not extractive. Danish generators benefit because the price they receive rises from 40 to 58 euros. German consumers benefit because the price they pay falls from 75 to 58 euros. The trader earns a profit, but it’s smaller than the combined benefit to the Danish generators and German consumers. Total welfare increases. The electricity that would have been wasted or curtailed in Denmark because local demand couldn’t absorb it now flows to Germany, where it displaces more expensive fossil generation.

This arbitrage function is especially important in the European context, where you have multiple countries with different generation mixes, different weather patterns, and different demand profiles all connected through an increasingly integrated transmission network. Norwegian hydropower is extremely valuable for balancing when wind generation is low elsewhere. French nuclear provides stable baseload. German industrial demand creates large concentrated consumption centers. Spanish solar generation peaks in the afternoon. Arbitrage coordinates all of this by creating price signals that guide flows across borders.

The United States has a somewhat different but related mechanism worth mentioning because it shows how arbitrage profits can signal infrastructure needs. In many US wholesale markets, traders can buy point to point transmission rights, basically financial contracts that pay out based on congestion between two locations. If a particular transmission path is frequently congested, meaning that price differences persist because physical capacity is insufficient, then the financial transmission rights for that path become valuable. Traders who correctly forecast where congestion will occur can profit by holding these rights. But here is the key insight: those profits are a market signal showing where transmission infrastructure investment is needed. Persistent price differences that generate trading profits reveal bottlenecks in the physical network. System planners can use this information to prioritize transmission expansion projects.

This is arbitrage serving an information function. The profits are not just private returns to traders. They are signals about the underlying physical system that help guide efficient investment. When arbitrage profits are high and persistent between two regions, it means moving power between those regions creates real value, which suggests infrastructure should be built to make that flow easier.

3. Risk Management: Enabling Investment in Renewable Energy

The third core function, and arguably the most important from a social welfare perspective, is risk management. Electricity prices are volatile. They vary hour to hour (and now quarter by quarter) based on weather, demand patterns, fuel costs, and generator outages. For a wind farm developer trying to get financing for a new project, this price volatility creates a serious problem.

Imagine you are a renewable energy developer approaching a bank for a loan to build a wind farm. The bank’s first question is about revenue projections. How much electricity will you generate, and what price will you receive? You can estimate generation reasonably well based on historical wind data for the site, though there’s still uncertainty. But you have basically no ability to predict what electricity prices will be five or ten years in the future. Those prices depend on fossil fuel costs, how much additional renewable capacity gets built, policy changes, tech developments, and many other factors.

The bank looks at this uncertainty and sees unacceptable risk. It either declines the loan entirely or demands a much higher interest rate to compensate for the revenue uncertainty. That higher cost of capital makes the project economically marginal. Many projects that would be socially valuable, meaning they would generate electricity at lower cost than alternatives, don’t get built because of financing constraints driven by price risk.

This is where risk management through trading becomes crucial. A trader can offer the wind farm developer a power purchase agreement with a fixed price for the electricity generated over a long period, say ten or fifteen years. The developer now has revenue certainty. It can take that contract to the bank and say, here is guaranteed income for the life of the loan. The bank is much more willing to lend, and it offers better terms because the revenue risk has been eliminated.

But where did the risk go? The trader took it on. The trader is now exposed to electricity price fluctuations. If market prices end up lower than the fixed PPA price, the trader loses money because it must pay the wind farm the fixed rate but can only sell the power at a lower market price. If prices end up higher than the PPA price, the trader profits. The trader manages this risk through portfolio diversification, hedging with financial instruments, and sophisticated forecasting. Basically, the trader is better equipped to bear price risk than the wind farm developer is, both because traders specialize in risk management and because they can spread risks across many projects and geographies.

The social benefit here is huge. According to research on European electricity markets, the existence of liquid forward and futures markets that enable this kind of risk transfer has been crucial for renewable energy deployment. Without these hedging mechanisms, the cost of capital for renewable projects would be much higher, which would slow the energy transition and increase its ultimate cost. ACER estimates that cross border trading enabled by these risk management tools contributes to the 34 to 43 billion euros in annual effiency gains I mentioned earlier, precisely because it enables more renewable investment at lower cost.

It is also worth noting that risk management is a two way street. Just as generators need to hedge against low prices, consumers and utilities need to hedge against high prices. An industrial facility with high electricity consumption might want price certainty to manage its budget and stay competitive. A utility serving residential customers wants to avoid the political disaster that results from a sudden spike in retail electricity bills. Traders help with these hedges too, standing ready to take the other side of contracts that transfer risk from those who cannot easily bear it to those who can.

This hedging function existed in theory under the old monopoly system, but it was handled through implicit cross subsidies and regulatory mechanisms rather than explicit markets. And critically, it was much less efficient. A state owned utility might absorb some price risk on behalf of generators and consumers, but it did so without transparent pricing, without competition to ensure efficiency, and ultimately with taxpayers bearing the cost when things went wrong. The market based approach makes risk transfer explicit, prices it competitively, and puts it with those best positioned to manage it.

These three functions (liquidity provision, arbitrage, and risk management) are not exotic financial engineering. They are basic market making activities that exist in virtually every well functioning market for commodities or financial assets. Energy traders are doing for electricity what market makers do in stock markets, what dealers do in bond markets, and what commodity traders do in agricultural markets. The profits earned from these activities are compensation for services provided, not value pulled from a zero sum game.

Empirical Evidence: Do Markets Actually Work?

I have explained the theoretical functions that energy trading serves. But theory is not enough. We need to look at what actually happened when countries restructured their electricity sectors. Did markets deliver the promised benefits? Are consumers better off? The empirical record is more nuanced than either enthusiastic market advocates or skeptical critics typically acknowledge.

Let me start with the good news, because there is substantial evidence that well-designed electricity markets generate significant welfare gains. And remember those markets need traders for them to work as intended.

European Market Integration: Substantial Documented Benefits

The most comprehensive and recent estimates come from the European Union’s Agency for the Cooperation of Energy Regulators, which synthesizes research from multiple sources to assess the benefits of cross-border electricity trading. Their 2022 assessment estimates that European market integration delivered 34 billion euros in efficiency gains in 2021 alone. Projections suggest this could reach 40 to 43 billion euros annually by 2030 as integration deepens.

These are not trivial numbers. To put them in perspective, 34 billion euros is roughly equivalent to the entire annual electricity expenditure of a country like Belgium. These gains come from several sources. First, integration allows countries to share generation capacity rather than each maintaining independent reserves, which reduces total capital requirements. Second, it enables the exploitation of geographic diversity in renewable resources. When wind generation is high in Denmark and low in Spain, power flows north to south. When the situation reverses, flows go the other direction. This geographic smoothing reduces the need for backup fossil generation. Third, it creates more liquid and competitive markets, which tends to reduce markups and improve operational efficiency.

Research by Newbery, Strbac, and Viehoff estimates that coupling interconnectors across European markets yields benefits as high as 3.9 billion euros annually, with about one quarter coming from day-ahead market coupling and roughly one third from shared balancing reserves. The ability to share reserves is particularly valuable because it means countries do not each need to maintain spinning reserves sufficient for their worst-case generator outage. Instead, they can pool reserves across a larger area where outages are not perfectly correlated.

A 2018 study in Oxford Economic Papers by Grossi and several coauthors examined spillover effects from German energy policy on neighboring countries. Germany’s nuclear phaseout following Fukushima triggered electricity price increases of up to 25 percent in neighboring countries, costing France alone an estimated 3.15 billion euros annually. But Germany’s simultaneous expansion of renewable generation reduced prices by about 0.16 percent per percentage point increase in renewable share, creating approximately 2.9 billion euros in annual savings for neighboring countries. The integration of European markets meant these policy changes had cross-border effects, both positive and negative. Without market integration and the trading that enables it, countries would have been far more insulated but also far less efficient.

The degree of market integration varies substantially across Europe. A 2018 analysis found integration levels ranging from 16 percent in Poland to 94 percent in the Czech Republic, with most countries falling somewhere in between. Even partial integration appears to generate benefits, though fuller integration would yield more.

The Nordic Experience: Thirty Years of Regional Markets

The Nordic electricity market deserves particular attention because it represents the longest-running example of multinational electricity market integration. Nord Pool began operations in the mid-1990s and has now facilitated trading across Norway, Sweden, Finland, Denmark, and the Baltic states for nearly three decades.

Early research by Hjalmarsson in 2000 examined whether the Nordic market operated competitively and concluded that the hypothesis of perfect competition could not be rejected during his sample period. This was an important finding because it suggested the market was functioning more or less as designed, with prices reflecting underlying supply and demand rather than being distorted by the exercise of market power.

More recent analysis paints a slightly more complicated picture. Tangerås and Mauritzen (2018) used detailed bidding data from 2011 to 2013 and found an average price cost margin of approximately 4 percent. They reject the hypothesis of perfect competition in all their statistical specifications. The interpretation is that some market power exists, likely due to transmission constraints that create local monopolies in certain price areas at certain times. A 4 percent markup is not huge, but it does indicate room for improvement in market design and competition.

What the Nordic experience demonstrates most clearly is that regional market integration can be sustained over long periods with mixed public and private ownership. Norwegian hydropower is largely state-owned. Swedish nuclear and hydro have mixed ownership. Danish wind has substantial private participation. This diversity of ownership structures coexists within a common market framework. The implication is that full privatization is not a prerequisite for competitive markets, which contradicts some of the more ideological claims made by early liberalization advocates.

The Nordic market has maintained relatively low and stable prices compared to many other European regions, though this partly reflects the region’s abundant hydro and nuclear baseload capacity rather than purely being a triumph of market design. Still, the ability to coordinate across different generation types and national systems represents a real achievement. When Norway experiences dry years and hydro reservoir levels are low, the region can import from Continental Europe. When reservoirs are full, Norway exports. This flexibility has value that would not exist without trading across borders.

Chile: Four Decades of Sustained Success

Outside Europe, Chile provides perhaps the most compelling long-term evidence. Chile restructured its electricity sector in 1982, making it the oldest comprehensive market reform in the world. The results over four decades have been impressive by almost any metric.

Prices fell 30 percent in real terms between 1992 and 2002. Installed capacity grew steadily at over 4 percent annually in the main interconnected system and over 10 percent annually in the northern mining region. Labor productivity increased dramatically. In generation, productivity rose from 6.3 gigawatt hours per worker to 35 gigawatt hours per worker. In distribution, it went from 1.4 gigawatt hours per worker to 14.1 gigawatt hours per worker. These are not marginal improvements. They represent fundamental gains in operational efficiency.

Energy losses in distribution, which had been nearly 20 percent under the state monopoly, fell to under 6 percent as private distribution companies had strong incentives to reduce both technical losses from infrastructure problems and commercial losses from theft and non payment. Rural electrification expanded from 38 percent to 86 percent of the population.

What explains Chile’s sustained success? Several factors appear important. First, strong property rights protection and a stable regulatory framework gave investors confidence to make long term capital commitments. Second, the market design included cost based bidding requirements that limited the ability of generators to exercise market power. Third, roles were clearly separated between the system operator, generators, distributors, and the regulator. Fourth, contracts between generators and large consumers were allowed and encouraged, which provided revenue stability without requiring capacity markets. The Chilean model is not directly transferable to other contexts, but it demonstrates that market-based systems can work well over extended periods when fundamentally designed correctly.

The United States: Efficiency Gains Not Passed Through to Consumers

The US experience with electricity restructuring is considerably more mixed and provides important cautionary lessons. Some states restructured their electricity sectors in the 1990s and early 2000s. Others maintained traditional regulated monopolies. This variation creates a natural experiment that researchers have exploited to estimate the causal effects of restructuring.

The most methodologically rigorous recent study is by MacKay and Mercadal, published in 2022, which uses difference in differences techniques comparing restructured utilities to those that remained regulated. Their findings are sobering. They estimate annual consumer welfare losses averaging 8.7 billion dollars over the period from 2000 to 2016. Retail electricity prices increased by 6.4 percent on average in restructured states compared to what would have occurred under continued regulation, despite the fact that marginal costs of generation actually declined.

What explains this paradox of rising prices despite falling costs? The answer is markups. Wholesale markups increased by 14.7 dollars per megawatt hour on average, with over 60 percent of the total markup increase occurring at the wholesale rather than retail level. Market concentration remained high in most restructured markets. Entry of new competitors was limited. Incumbent generators were able to exercise market power, capturing the efficiency gains as increased profits rather than passing them through to consumers as lower prices.

This finding is crucial because it shows that restructuring alone is insufficient. If you break up a vertically integrated monopoly but do not create sufficient horizontal competition in generation, you may simply replace a regulated monopoly with an unregulated oligopoly. The latter can be worse for consumers because the oligopoly has both the incentive and ability to raise prices above competitive levels without regulatory constraint.

The state level variation is substantial. California saw retail price increases exceeding 20 percent following restructuring. Illinois saw prices decline by over 12 percent. Pennsylvania experienced modest declines of around 3.5 percent. This heterogeneity suggests that implementation details matter enormously.

Other US research has documented real operational improvements from restructuring. Davis and Wolfram found that nuclear plant output increased by approximately 10 percentage points following deregulation as operators faced stronger incentives to maximize availability. Cicala’s work shows that deregulated plants reduced procurement costs for fuel and improved dispatch efficiency. These are genuine efficiency gains. The problem is that in the absence of adequate competition, those gains accrued primarily to producers rather than consumers.

The Price Question: Methodological Challenges and Ambiguous Results

One of the most politically salient questions about electricity market liberalization is whether it reduces prices. The empirical literature on this question has evolved significantly as econometric methods have improved, and the most careful recent work suggests the answer is more ambiguous than earlier studies claimed.

Early research using simple panel data methods often found that liberalization was associated with lower prices. But these studies suffered from a fundamental identification problem. Countries or states with high electricity prices are more likely to pursue liberalization precisely because the political pressure for reform is greater when prices are high. This endogeneity makes it extremely difficult to isolate the causal effect of liberalization. Even if liberalization had no impact on prices whatsoever, you might still observe price convergence between liberalized and non-liberalized regions due to mean reversion or other concurrent reforms. The apparent price reductions found in early studies were likely artifacts of inadequate econometric specification rather than evidence of liberalization’s benefits.

Hyland’s 2016 paper in Utilities Policy represents an important methodological advance. He uses dynamic panel data techniques with generalized method of moments estimation, specifically designed to address endogeneity. Once this bias is corrected, he finds that restructuring has no statistically significant impact on industrial electricity prices. The apparent price reductions found in earlier studies were artifacts of inadequate econometric specification.

This finding is reinforced by Del Río, Fernández Sainz, and Martinez de Alegria’s 2019 analysis of EU industrial prices from 2003 to 2013, also published in Utilities Policy. They conclude that electricity market reform has not resulted in price reductions for industrial users. Among various reform measures, only third party access to transmission networks appears associated with lower prices, while some reform dimensions are actually associated with price increases.

The picture for residential consumers is similarly mixed. Amenta, Aronica, and Stagnaro, writing in Utilities Policy in 2022, find a nonlinear relationship where partial liberalization correlates with lower prices but full liberalization shows no statistically significant effect. This is a puzzling finding that suggests the benefits may come primarily from introducing some competition rather than from complete market opening.

Country specific studies reveal substantial heterogeneity. Bojnec and Križaj’s analysis of Slovenia finds that liberalization increased electricity prices for both industrial and household consumers. Bacchiocchi, Florio, and Taveggia identify asymmetric effects between older EU member states and new member states, with the latter experiencing significant price increases in relatively short periods following reforms.

Perhaps most provocatively, Fiorio and Florio’s comprehensive study covering thirty years of data from 1978 to 2007 across EU countries, published in Energy Economics, finds that public ownership is associated with lower consumer prices after controlling for market opening and other factors. Privatization does not result in lower prices for consumers. This contradicts the conventional wisdom from the British style reform paradigm that assumed privatization was essential for efficiency.

The methodologically rigorous conclusion appears to be that liberalization’s effect on prices is highly context dependent and often statistically indistinguishable from zero once proper econometric techniques account for endogeneity and selection bias. Where prices do fall, it is typically because reform successfully created competitive market structures with adequate numbers of competitors and limited market power. Where prices rise or remain flat, it is usually because market concentration remained high or because efficiency gains were captured by producers rather than passed through to consumers.

The 2022 Energy Crisis: A Natural Experiment

The energy crisis that began in 2022 following Russia’s invasion of Ukraine provides a recent “natural experiment” that sheds light on how electricity markets respond to extreme shocks. Wholesale electricity prices across Europe spiked dramatically as natural gas prices surged. In many countries, retail electricity prices doubled or even tripled.

Critics pointed to record profits at some energy trading firms as evidence that speculation and profiteering were driving the crisis. But the data tells a different story. The price spikes were driven by fundamental supply constraints in natural gas markets, not by manipulation or excessive speculation. As gas prices rose, gas-fired power plants that often set the marginal price in electricity markets required higher electricity prices to cover their increased fuel costs. This is exactly how marginal cost pricing is supposed to work.

The critical evidence comes from what happened when gas markets normalized. Danish electricity prices fell 60 to 61 percent from 2022 to 2023 as gas prices declined. If speculation rather than fundamentals were driving prices, you would not expect such a tight correlation between input costs and electricity prices. The price movements reflected underlying physical realities about fuel availability and generation costs.

European regulators conducted extensive investigations looking for evidence of market manipulation during this period. REMIT enforcement identified 102 suspicious transactions among millions executed. That is not zero, and those cases should be investigated. But it is a tiny fraction of total market activity and does not suggest that manipulation was a significant driver of the price crisis.

What the crisis did reveal was the value of market integration for managing extreme events. France experienced a nuclear generation crisis in 2022 when numerous reactors were offline simultaneously for maintenance and safety concerns. This created an 81 terawatt-hour shortfall. France shifted from being a major electricity exporter to a significant importer. The ability to import from neighboring countries through integrated markets, facilitated by trading, prevented what could have been catastrophic blackouts. Without those markets and the traders providing liquidity and coordination, the physical management of this crisis would have been far more difficult.

What the Evidence Actually Shows

Synthesizing this empirical literature, several conclusions emerge. First, well designed electricity markets with adequate competition can deliver substantial welfare gains. The European market integration benefits of 34 to 43 billion euros annually are real and represent meaningful improvements in efficiency and consumer welfare. The Nordic experience over three decades and Chile’s four decade track record demonstrate that market based systems can be sustained successfully over long periods.

Second, the benefits are highly conditional on market design and structure. Markets with insufficient competition, inadequate regulation, or poor institutional frameworks can perform worse than the monopolies they replaced. The US experience shows that restructuring without creating adequate competition allows producers to capture efficiency gains as increased profits rather than passing them through to consumers as lower prices.

Third, claims that liberalization reliably reduces prices are not well supported by the most rigorous econometric evidence. Once you properly account for issues like endogeneity and selection effects, price impacts are often statistically insignificant or even positive. It is not important that you understand what endogenity and selection effects are, but the main point is that where prices do decline, it is because specific design features created genuine competition, not because liberalization automatically generates lower prices.

Fourth, operational efficiency gains from liberalization are real and well documented. Nuclear plant availability increased. Dispatch efficiency improved. Labor productivity rose substantially. Redundant generation capacity was eliminated. These efficiency improvements are valuable even when they do not fully translate into lower consumer prices, because they reduce the real resource costs of providing electricity.

Fifth, distributional effects matter and are often uneven. Large industrial consumers typically benefit more than residential consumers because they can negotiate better contracts, respond to price signals, and access competitive markets more easily. The removal of cross subsidies that existed under monopoly systems means some consumer groups, particularly residential users who were previously subsidized, may face higher prices even when overall system efficiency improves.

The evidence supports a conditional defense of electricity markets. They are not panaceas. They require sophisticated design, strong regulatory oversight, adequate competition, and sustained political commitment. When those conditions are met, they deliver measurable benefits. When those conditions are absent, they can fail spectacularly. The challenge for policymakers is creating and maintaining the institutional prerequisites for market success rather than assuming that competition alone will solve all problems.

Where Critics Have a Point: Legitimate Concerns

I have presented evidence that energy trading serves valuable functions and that well designed markets can improve consumer welfare. But intellectual honesty requires acknowledging where critics of electricity markets and trading have legitimate grounds for concern. There are real problems with how many liberalized electricity markets operate, and dismissing these concerns as ignorance or ideology would be both inaccurate and counterproductive.

Market Power Remains a Persistent Problem

The assumption underlying market liberalization is that competition will discipline pricing and ensure efficiency gains flow to consumers. But competition requires a sufficient number of independent competitors, and many electricity markets remain highly concentrated even decades after restructuring.

The research I cited earlier by Tangerås and Mauritzen on Nordic markets found price cost margins of approximately 4 percent and rejected the hypothesis of perfect competition. This is in one of the world’s most successful regional electricity markets. If market power persists there, it certainly exists in less well-designed markets. Transmission constraints create local monopolies where a single generator or small group of generators can influence prices because electricity cannot flow freely from other regions. Even in markets with apparent structural competition at the system level, congestion can fragment the market geographically.

The US evidence is even more concerning. MacKay and Mercadal document that market concentration remained high following restructuring, with limited entry of new competitors. Wholesale markups increased by nearly 15 dollars per megawatt hour on average, and over 60 percent of total markup increases occurred at the wholesale level. This is market power being exercised at scale. The efficiency gains from better plant operations were captured by generators as increased profits rather than being passed through to consumers.

The implication is that restructuring electricity sectors without adequate horizontal competition can make consumers worse off. You replace a regulated monopoly that at least faces regulatory oversight with an unregulated oligopoly that has both the incentive and ability to raise prices above competitive levels. This is not a theoretical concern. It is what actually happened in multiple US states.

The Missing Money Problem is Real

One of the most intellectually honest debates in electricity market design concerns what economists call the missing money problem. The issue arises from a fundamental tension between short run efficiency and long run investment incentives.

In a well functioning energy only market, prices should rise to very high levels during scarcity events when demand approaches available supply. These price spikes serve two functions. They incentivize demand reduction, helping to balance the system. And they provide revenue to generators that compensates them for maintaining capacity that is only needed during peak periods.

But extreme price spikes are politically toxic. When wholesale electricity prices reach thousands of euros per megawatt hour during a few hours of scarcity, the public outcry is immediate and intense. Politicians are then tempted to respond by imposing price caps. These caps would protect consumers from extreme bills during scarcity events, which is understandable. But they also eliminate the revenue peaks that would incentivize investment in generation capacity.

The result is that energy only markets systematically fail to attract sufficient investment in generation capacity, particularly peaking plants that only operate during high demand periods. Joskow and Tirole’s theoretical work demonstrates that if you solve the short run market power problem through price caps, you simultaneously create a long run investment problem. There is no way to have both protected consumers during scarcity and sufficient investment incentives in a pure energy only market when political constraints prevent truly scarcity pricing.

European policymakers have effectively conceded this point. Five EU member states representing approximately 40 percent of EU electricity demand now operate capacity remuneration mechanisms. These are explicit payments to generators for maintaining available capacity, separate from energy payments. The EU’s 2024 Electricity Market Design Reform removed language describing capacity mechanisms as temporary measures. They are now recognized as structural elements of market design rather than temporary patches for market failures.

This represents an admission that pure energy markets are insufficient for reliability. You need additional mechanisms beyond energy pricing to ensure adequate generation capacity. Critics who argued that liberalized markets would struggle to maintain reliability without additional interventions have been partially vindicated. The question is no longer whether capacity mechanisms are needed but rather what form they should take and how to design them efficiently.

Distributional Effects Are Genuinely Uneven

Market liberalization produces winners and losers, and the distribution of gains and losses matters both economically and politically. The evidence clearly shows that large industrial consumers benefit more from liberalization than residential consumers.

Industrial users can negotiate customized contracts with generators or retailers. They have sophisticated procurement operations that can evaluate offers and switch suppliers. They can respond to real time price signals by adjusting production schedules. They can relocate facilities to jurisdictions with favorable electricity prices. And they were typically the first customer class granted access to competitive markets during phased liberalization.

Residential consumers face very different circumstances. They have high switching costs because evaluating different retail offers is time consuming and confusing. They have low price elasticity because electricity is essential and most households cannot easily adjust consumption in response to price changes. They face information asymmetries because they lack the expertise to evaluate complex tariff structures. And they have essentially no ability to hedge price risk.

The removal of cross subsidies that existed under monopoly regulation means some households now pay cost reflective prices that are higher than the subsidized rates they previously enjoyed. From an economic efficiency perspective, cost reflective pricing is desirable because it creates accurate incentives. But from a distributional perspective, it means lower income households that were previously subsidized now face higher bills even if overall system efficiency has improved.

This creates genuine political economy challenges. A reform that improves aggregate welfare but harms a large voting bloc is difficult to sustain politically. The fact that the gains are diffuse and often invisible while the losses are concentrated and highly visible makes this even more challenging. When your electricity bill increases 20 percent, you notice. When the counterfactual is that it would have increased 25 percent without market integration, you have no way to observe that.

Industry Communication Has Been Inadequate

I need to acknowledge that our industry deserves substantial blame for public misunderstanding about what energy trading does and why it matters. We have been defensive rather than educational. We retreat into technical jargon when questioned. We have allowed critics to define the narrative, casting traders as parasitic speculators rather than explaining the coordination functions we perform.

During the 2022 energy crisis, when trading firms reported strong profits while consumers struggled with high bills, our industry response was tone deaf. We pointed to market fundamentals and gas supply constraints, which were accurate explanations. But we failed to communicate empathy for people facing real hardship. We failed to distinguish clearly between legitimate trading activities that enable market function and the small minority of genuinely problematic behavior. And we failed to explain proactively how trading contributes to the renewable energy transition that most Europeans support.

The result is that when politicians call us leeches, the accusation resonates because we have not built public understanding of what we actually do. This is a failure of communication and engagement that the industry needs to address. We cannot expect the public to understand complex market mechanisms if we are unwilling to explain them in accessible terms. And we cannot expect political support for market based systems if we only engage with policymakers when regulations threaten our business models.

The solution is not just better public relations. It is genuine transparency about our activities, honest acknowledgment of where markets fall short, and constructive engagement with efforts to improve market design and strengthen regulation. If we want the benefits of operating in liberalized markets, we have an obligation to help those markets function well and to help the public understand why they exist.

Conclusion: A Conditional Defense

I began this essay by describing a LinkedIn exchange with a Danish politician who called energy traders leeches. I said I understood why that characterization resonates with people, especially after the 2022 energy crisis when trading profits were visible while consumers struggled with high bills. Having worked through the theory, evidence, and legitimate criticisms, I want to return to that conversation and explain why I still believe his characterization is wrong, even if his skepticism is understandable.

Energy traders provide three essential services. We maintain continuous liquidity that enables markets to function around the clock. We perform arbitrage that moves electricity from regions with surplus to regions with deficit, creating price convergence that benefits both. And we enable risk management that makes renewable energy projects financeable by absorbing price uncertainty that developers and their lenders can’t bear. These aren’t exotic financial manipulations disconnected from the real economy. They’re coordination functions that allow complex electricity systems with high renewable penetration to operate reliably and efficiently.

The empirical evidence supports this view, with important caveats. European market integration saves consumers an estimated 34 to 43 billion euros annually. The Nordic market has worked successfully for three decades. Chile shows that well designed markets can deliver sustained benefits over four decades. These are not trivial accomplishments, and they wouldn’t be possible without active trading.

But the evidence also shows that markets can fail when poorly designed. The US experience shows that restructuring without adequate competition allows producers to capture efficiency gains as increased profits rather than passing them through to consumers. Market power remains a persistent problem even in relatively successful markets. Capacity mechanisms have become necessary because pure energy markets can’t solve the missing money problem under political constraints on scarcity pricing. And distributional effects are genuinely uneven, with residential consumers often benefiting less than industrial users.

So my defense of energy trading is explicitly conditional. When markets are well designed with sufficient competition, strong regulatory oversight, appropriate capacity mechanisms, and sustained political commitment, trading improves welfare. When those conditions are absent, markets can perform worse than the regulated monopolies they replaced. The challenge is creating and maintaining the institutional prerequisites for success.

The politician suggested that energy traders operating internationally are extracting value from foreign consumers. Even if his premise were correct, which I have argued it is not, Danish firms earning profits abroad and paying Danish taxes would still benefit Denmark. But the deeper error is the zero sum thinking. Trading is not value extraction. It is coordination that increases total welfare by more than the profits traders earn.

The industry has communicated this poorly. We have been defensive and jargon heavy when we should have been educational and accessible. We have not sufficiently separated productive trading from the genuinely problematic behavior that a small minority engages in. And we have not adequately explained how trading enables the renewable energy transition that most Europeans support.

The transition to a decarbonized electricity system requires sophisticated markets and active trading. Variable renewable generation creates coordination challenges that simply cannot be solved through command and control planning. You need price signals, you need liquidity, you need risk management, and you need continuous arbitrage across time and space. Those functions require traders.

Energy trading is not necessarily sexy (although I do find it very interesting). It is technical, complex, and easy to make a villain of. But it is essential infrastructure for the energy system we are building. That is not ideology. It is what four decades of evidence across multiple continents shows.

Disclaimer:

The views expressed in this essay are my own and do not represent the positions of Aarhus University, BD Energy, or any other organization with which I am affiliated.

References

Section II: The World Before Markets

Newbery, D. M., & Pollitt, M. G. (1997). The restructuring and privatisation of Britain’s CEGB—was it worth it? Journal of Industrial Economics, 45(3), 269-303.

Pollitt, M. G. (2004). Electricity reform in Chile: Lessons for developing countries. Journal of Network Industries, 5(3-4), 221-262.

Section III: What Energy Traders Actually Do

European Union Agency for the Cooperation of Energy Regulators (ACER). (2022). ACER Market Monitoring Report 2021-2022.

Newbery, D., Strbac, G., & Viehoff, I. (2016). The benefits of integrating European electricity markets. Energy Policy, 94, 253-263.

Section IV: Empirical Evidence

European Market Integration:

European Union Agency for the Cooperation of Energy Regulators (ACER). (2022). ACER Market Monitoring Report 2021-2022.

Grossi, L., Heim, S., & Waterson, M. (2018). The impact of the German response to the Fukushima earthquake on the European electricity market. Oxford Economic Papers, 70(4), 1018-1038.

Newbery, D., Strbac, G., & Viehoff, I. (2016). The benefits of integrating European electricity markets. Energy Policy, 94, 253-263.

Zachmann, G., McWilliams, B., Tagliapietra, S., & Fredriksson, G. (2024). The Case for European Electricity Market Integration. Bruegel Policy Contribution.

Nordic Markets:

Hjalmarsson, L. (2000). From club-regulation to market competition in the Swedish electricity sector. In T. P. Tangerås (Ed.), Developments in Swedish Economic Policy (pp. 144-190). Palgrave Macmillan.

Tangerås, T. P., & Mauritzen, J. (2018). Real-time versus day-ahead market power in a hydro-based electricity market. International Journal of Industrial Organization, 59, 169-197.

Amundsen, E. S., Bergman, L., & von der Fehr, N. H. M. (2006). The Nordic electricity market: Robust by design? In F. P. Sioshansi & W. Pfaffenberger (Eds.), Electricity Market Reform: An International Perspective (pp. 145-170). Elsevier.

Chile:

Pollitt, M. G. (2004). Electricity reform in Chile: Lessons for developing countries. Journal of Network Industries, 5(3-4), 221-262.

United States:

MacKay, A., & Mercadal, I. (2022). Deregulation and efficiency: Evidence from U.S. electricity restructuring. Working Paper.

Davis, L. W., & Wolfram, C. (2012). Deregulation, consolidation, and efficiency: Evidence from U.S. nuclear power. American Economic Journal: Applied Economics, 4(4), 194-225.

Cicala, S. (2015). When does regulation distort costs? Lessons from fuel procurement in US electricity generation. American Economic Review, 105(1), 411-444.

Cicala, S. (2022). Imperfect markets versus imperfect regulation in US electricity generation. American Economic Review, 112(2), 409-441.

Mansur, E. T. (2008). Measuring welfare in restructured electricity markets. Review of Economics and Statistics, 90(2), 369-386.

Price Effects:

Hyland, M. (2016). Restructuring European electricity markets: A panel data analysis. Utilities Policy, 38, 33-42.

Del Río, P., Fernández-Sainz, A., & Martínez de Alegría, I. (2019). Do renewable energy policies promote electricity market reform? Empirical evidence for OECD countries and major developing countries. Utilities Policy, 61, 100974.

Amenta, C., Aronica, M., & Stagnaro, C. (2022). Revisiting the relationship between market structure and prices in the EU electricity sector. Utilities Policy, 74, 101326.

Bojnec, Š., & Križaj, A. (2021). Electricity pricing and market power in the Slovenian electricity market. Energy Policy, 157, 112489.

Bacchiocchi, E., Florio, M., & Taveggia, G. (2015). The privatization of European energy utilities and its impact on social welfare. In M. Florio (Ed.), The Economic Performance of Public Enterprises (pp. 237-274). Routledge.

Fiorio, C. V., & Florio, M. (2013). Electricity prices and public ownership: Evidence from the EU15 over thirty years. Energy Economics, 39, 207-213.

Steiner, F. (2000). Regulation, industry structure and performance in the electricity supply industry. OECD Economics Department Working Paper No. 238.

Hattori, T., & Tsutsui, M. (2004). Economic impact of regulatory reforms in the electricity supply industry: A panel data analysis for OECD countries. Energy Policy, 32(6), 823-832.

2022 Energy Crisis:

European Union Agency for the Cooperation of Energy Regulators (ACER). (2024). Annual Report on the Results of Monitoring the Internal Electricity and Natural Gas Markets in 2023.

Section V: Where Critics Have a Point

Tangerås, T. P., & Mauritzen, J. (2018). Real-time versus day-ahead market power in a hydro-based electricity market. International Journal of Industrial Organization, 59, 169-197.

MacKay, A., & Mercadal, I. (2022). Deregulation and efficiency: Evidence from U.S. electricity restructuring. Working Paper.

Joskow, P. L., & Tirole, J. (2007). Reliability and competitive electricity markets. RAND Journal of Economics, 38(1), 60-84.

European Commission. (2024). Electricity Market Design Reform.

General References on Electricity Market Liberalization

Joskow, P. L. (2008). Lessons learned from electricity market liberalization. The Energy Journal, 29(Special Issue 2), 9-42.

Pollitt, M. G. (2019). The European single market in electricity: An economic assessment. Review of Industrial Organization, 55(1), 63-87.

Jamasb, T., & Pollitt, M. (2005). Electricity market reform in the European Union: Review of progress toward liberalization & integration. The Energy Journal, 26(Special Issue), 11-41.

Newbery, D. M. (2018). Economics of Energy. Cambridge University Press.

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