Electricity market

• 1. Introduction

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  The electricity market hides in plain sight. Every time a light flicks on, a transaction has already taken place somewhere up the wire, one that might have been priced, cleared, and settled in the span of five minutes. The subject is the electricity market itself: a system enabling the exchange of electrical energy through an electrical grid, and one of the most economically unusual markets ever designed.

  Peak electricity prices can reach one hundred times the off-peak price. That gap dwarfs even the most aggressive seasonal hotel pricing, which rarely exceeds three to four times the off-season rate. No commodity market quite behaves this way. What makes electricity so strange, how did the industry go from unregulated producer-to-customer sales in the late nineteenth century to the sprawling, multi-layered trading architecture of today, and why have deregulated markets struggled to solve what economists call the missing money problem? Those are the questions this documentary will explore.

• 2. The World Before Competition

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  By the 1950s, the structure of electricity supply had diverged sharply across countries. France, Italy, the Republic of Ireland, and Greece each ran a single nationwide government-owned vertically integrated company. The United Kingdom split the job differently: a government-owned Central Electricity Generating Board handled generation and transmission, while fourteen separate electricity boards managed distribution. Germany paired a small number of regional integrated companies with municipal distribution. Japan divided its territory among ten regional vertically integrated monopolies. Norway handled supply mostly at the level of individual municipalities.

  The United States went its own complex way. Hawaii operated with only privately owned utilities; Nebraska had only publicly owned ones. The Tennessee Valley Authority, the country's largest generation company at the time, was federally owned. The Los Angeles Department of Water and Power answered to the city. Regulation in the US tended to favor municipal-level and cooperative ownership, producing a patchwork that no single description could capture.

  For all their differences, these arrangements shared certain features. Almost none relied on competitive markets. There were no formal wholesale markets. Customers had no ability to choose their supplier. Retail tariffs almost entirely relied on volumetric pricing based on monthly meter readings, and fixed cost recovery was bundled into the per-kilowatt-hour price. Richard L. Schmalensee later labeled this the historical regime, a world where nearly all generation sources could be considered dispatchable and the concept of variable renewable energy had not yet become a practical concern.

• 3. The Deregulation Turn

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  Chile moved first. The law of 1982 codified changes that had already started in 1979, making Chile a pioneer in electricity deregulation. Only a few years later, Paul Joskow and Richard Schmalensee published their influential work "Markets for Power: An Analysis of Electrical Utility Deregulation" in 1983, helping to popularize the new market approach in the United States. At the same time, the UK's Energy Act of 1983 made provisions for common carriage in electricity networks, enabling electricity boards and very large customers to choose their supplier, an arrangement analogous to what the US called wheeling.

  The intellectual framing behind deregulation was stark: it meant transforming electricity from a public service, comparable to sewerage, into a tradable good, comparable to crude oil. Around the turn of the twenty-first century, several countries restructured their electric power industries, replacing the vertically integrated and tightly regulated traditional market with mechanisms for competitive generation, transmission, distribution, and retailing.

  As of the 2020s, the traditional market model remains common in large parts of the United States and Canada, while the reformed, competitive model has spread across much of Europe, Australasia, and parts of Latin America. The California electricity crisis and the Enron debacle in 2000 and 2001 slowed the pace of change and in some regions pushed regulation back, but that reversal has been widely regarded as temporary against a longer-term drift toward more open markets.

• 4. How Electricity Gets Priced

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  Electricity is available on demand, but achieving that reliability requires a physical balancing act that has no close equivalent in other commodity markets. Supply must match demand very closely at every moment despite continuous variation on both sides. The only safety margins are often the kinetic energy stored in the physically rotating machinery of synchronous generators and turbines. If supply and demand fall out of step, generators either speed up or slow down, causing the utility frequency to drift. Whether the grid runs at 50 hertz or 60 hertz depends on the region, and the frequency cannot deviate far from its target. Equipment throughout the grid can be destroyed by out-of-bounds frequency and will automatically disconnect to protect itself, which can trigger a blackout.

  This physical reality shapes how markets clear. In a double auction, the operator aggregates both supply bids and demand bids for each time interval, and the clearing price sits at the intersection of the resulting supply and demand curves. Nord Pool uses this approach. In a single reverse auction, only supply bids are aggregated and the cheapest combination is dispatched.

  Two payment approaches determine what winning bidders actually receive. Under pay-as-bid, each successful bidder receives exactly the price in its bid, an arrangement used by the UK and Nord Pool's intra-day market. Under pay-as-clear pricing, also called marginal pricing, all participants receive the price of the highest successful bid. Pay-as-clear is far more common and is generally considered more transparent, because a new entrant already knows the market price and can estimate profitability from its own marginal cost alone. Under pay-as-bid, the bidder must also estimate what other players have bid, which gives large, well-resourced players a structural advantage.

• 5. Centralized Versus Decentralized Markets

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  PJM Interconnection, the Midwest Independent System Operator, the California Independent System Operator, and ISO New England all operate centralized day-ahead markets with nodal pricing, as does ERCOT in Texas. The United States, in other words, went heavily centralized. Europe moved the other direction. Nord Pool, Germany, Great Britain since 2001, and Ireland since 2018 are all decentralized, using zonal rather than nodal pricing.

  In a centralized market, the transmission system operator collects start-up costs, no-load costs, and marginal production costs for every unit of generation, then makes all commitment and dispatch decisions well before delivery. This allows the operator to account for the full configuration of the transmission network and is especially useful for scheduling plants with long ramp-up times. The trade-off is opacity: market-clearing algorithms are sometimes NP-complete, must run in as little as five to sixty minutes, and are hard to replicate independently, which requires participants to trust the operator even when a decision to accept or reject a bid appears entirely arbitrary.

  Decentralized markets let generation companies choose how to meet their day-ahead commitments, using any unit at their disposal or even paying another company to deliver the energy. This portfolio-based bidding allows for intra-day corrections as weather forecasts improve, which helps integrate renewables. Because the operator's powers are more limited, the question of whether the operator owns transmission capacity becomes less pressing; European countries outside the UK generally permit it.

  Locational marginal pricing reflects the cost of supplying one additional kilowatt-hour at a specific node on the network. When a transmission constraint binds, prices on either side of that constraint separate, producing what are called congestion rents. This can be politically difficult when consumers in the same territory but on different nodes end up paying different prices, which is why some US markets use a modified generator nodal pricing model: generators are paid the nodal prices, but the cost passed to end users is averaged across the territory.

• 6. The Missing Money Problem

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  When deregulation arrived in the United States, the market had excess generating capacity, which confirmed a longstanding suspicion that regulated prices had incentivized generators to overinvest. The initial hope was that competitive revenue streams would sustain ongoing investment in capacity. That hope did not materialize.

  Faced with the abuse of market power, all US wholesale markets introduced price caps on what generators could charge. In many cases those caps were set well below the true value of lost load during shortages. The consequence was the missing money problem: capping revenue during relatively rare shortage events leaves generators without enough income to justify building the reserve infrastructure that is only needed during those same shortages. The problem of overinvestment was replaced by underinvestment, and grid reliability deteriorated. By 2018, capacity payments in the US had risen to cover as high as 47% of a new generating unit's revenue. European markets followed a similar path in the 2010s.

  MacKay and Mercadal, in a large-scale analysis of the US market between 1994 and 2016, confirmed Schmalensee's finding that restructuring lowered wholesale costs, but reached the opposite conclusion on prices: deregulated utilities realized significantly higher prices, driven by higher markups and double extraction of the profit margin by the two vertically separated companies. Schmalensee himself concluded that the process of determining compensation for new capacity in the US, while structurally similar to integrated resource planning, is less transparent and provides less certainty due to frequent rule changes, making an efficiency gain in this area unlikely.

• 7. Capacity Markets and Reform

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  ISO New England held its first Forward Capacity Auction in 2008, three years after officially becoming a regional transmission organization. The auction ran on a descending-clock model: the price started high and fell in successive rounds until resources willing to sell at the clearing price met the installed capacity requirement. All resources clearing the auction received the same rate.

  Starting in late 2022, ISO New England began studying alternative structures, weighing whether to adopt a seasonal market to reflect the fact that some resources have weather-dependent capacity and that peak demand differs between summer and winter. In November 2023, the ISO filed with the Federal Energy Regulatory Commission to delay the nineteenth forward capacity auction, which had been scheduled for February 2025. After consulting independent advisors, it filed again in 2024 to push the auction back by two years, to 2027. FERC granted the delay on the 20th of May 2024.

  In late 2025, ISO New England filed its first set of tariff changes for the reformed market, shifting the auction to take place immediately before the commitment period rather than three years ahead. FERC accepted those changes on the 30th of March. The last auction under the old rules, covering the June 2027 to May 2028 commitment period, took place on the 5th of February 2024 and procured 31,556 megawatts of capacity at a final clearing price of $3.58 per kilowatt-month. The second tariff filing, addressing seasonal accreditation, is expected in the fourth quarter of 2026.

• 8. Retail Markets and Future Pressures

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  A retail electricity market exists when end-use customers can choose their supplier from competing retailers. In many markets, consumers pay a fixed price rather than one that tracks the real-time wholesale price, which means they have no financial incentive to shift consumption away from periods of peak demand. The California electricity crisis of 2001 illustrated what can go wrong: flawed regulation left incumbent retailers exposed to high spot prices without the ability to hedge against them. In the UK, the retailer Independent Energy, carrying a large customer base, went bankrupt when it could not collect payments from its customers.

  Research on competitive retail markets in the United States found that the effects are mixed across states, but that lower prices generally appeared in states with high customer participation and higher prices in states with little participation. Larger commercial customers, who can shift the timing of their consumption to take advantage of time-of-use pricing and who have access to hedging instruments, embraced the competitive retail model. Acceptance among residential customers was minimal.

  Due to high gas prices stemming from the 2022 Russia-European Union gas dispute, the EU in late 2022 capped non-gas power prices at 180 euros per megawatt hour, and the UK was considering its own price cap. Some economists argued that an EU-wide cap risked triggering a spiral of higher import prices and higher subsidies. Rather than the traditional merit order based purely on cost, some proposals have suggested ramping down plants that cause the greatest health damage first when excess generation needs to be curtailed, a reflection of the growing pressure to align market design with both emissions reduction goals and public health.