Understanding Deregulated Electricity Markets

Do markets in electricity reduce prices for consumers? This fascinating 2024 paper by MacKay and Mercadal tries to answer the question by looking at evidence across a 20-year period from US electricity markets. What makes the US particularly interesting is that it offers a kind of natural experiment. Some US states deregulated and introduced free markets for buying and selling electricity; others did not and retained vertically integrated utilities under rate of return regulation. This allows the authors to ask the following question: did consumers in the states that introduced electricity markets experience lower prices compared to consumers in states that didn't? The attached paper gives a somewhat surprising answer: over the period studied by the authors, generation costs fell but retail prices rose in deregulated states compared to regulated ones. You would expect generation costs to fall with deregulation because competition between generators in the market sharpens the incentive to reduce costs (compared to a utility under rate of return regulation). But the paper finds that the reduction in costs was not passed on to consumers. Instead, the increase in production efficiency was more than offset by an increase in the wholesale margins charged by generators and by increases in other non-wholesale costs (such as networks). The paper’s lead explanation of this result is that the US wholesale markets are not perfectly competitive. So generators in deregulated markets were able to exploit their market power to increase their margins. Alternatively or additionally, deregulation may have increased risks to generators which were priced in to the wholesale market. A third contributing factor could be that unbundling generation from transmission led to poorer co-ordination between the two, thereby increasing non-wholesale costs such as networks and balancing costs. What can we read across from this to the British case? Possibly that: (a) Markets do not necessarily lead to lower electricity prices for consumers - we need to pay attention to how upstream costs are actually translated into wholesale and retail prices taking account of real-world market imperfections and market power; (b) The separation of generation and transmission through unbundling enables greater competitive pressure to be applied to generators (with the potential for improved production efficiency) but at the expense of proper co-ordination with transmission infrastructure. In a steady state power system, this probably doesn't matter too much. In an expanding power system, it probably matters a lot more; and (c) market reforms can lead to inefficient pricing if they result in a poor allocation of risk between market participants and consumers.

Listening to the debate on locational pricing in the UK, you’d think it was a radical experiment: untested, risky, potentially destabilising. In reality, it’s a standard feature of well-functioning power markets around the world — already in use in Italy, the Nordics, Australia, and most of the US. And the direction of travel is clear: OECD countries are moving toward greater locational granularity, not away from it. Independent studies in the UK, Germany, and the Netherlands all point to the same conclusion: ✅ Massive consumer savings ✅ Better grid utilisation ✅ More efficient investment signals So why the big debate? Perhaps because these gains come from reducing implicit rents embedded in uniform national pricing — rents that currently accrue to a small number of well-organised producer interests. To be clear, some of these concerns are entirely legitimate: ✔ Investors need regulatory stability ✔ Assets were built in good faith ✔ Sudden changes can erode trust in the UK energy sector So it's important that reform is handled sensitively - whether that means phase-ins, grandfathering, or transitional compensation. But these concerns can’t justify freezing an inefficient system. Because the cost of inaction is enormous. Independent analysis for Ofgem suggests £31 billion in benefits from zonal reform in GB. A similar study for Germany suggested €7.3 billion/year in avoided congestion and grid costs. Both are independent reports commissioned by government/regulators. Locational pricing isn’t radical. It's essential for economic competitiveness. And I doubt many officials need convincing. But the risk for the government is that the constituencies that stand to gain — consumers, flexible resources, demand-side innovators — are either too dispersed or not yet large enough to be heard properly. #LocationalPricing #ElectricityMarkets #EnergyReform #RegulatoryPolicy #ZonalPricing #EnergyTransition #ConsumerBenefit #ElectricityMarketReform #LocationalSignals #GridEfficiency #EnergyPolicy #RegulatoryStability #PowerMarkets #ZonalPricing #ConsumerBenefit

A State Electricity Market Is Not A Walk In The Park I spoke and listened at the Lagos Energy Summit last month and listened to the The Electricity Hub's 105th Power Dialogue discussing the 2023 Electricity Act while between advisory meetings and work deliverables. One thing that has struck me consistently from engaging investors, regulators, policy shapers & other stakeholders is how easy many think it will be to design and operate these new ecosystems. While, the passage of Nigeria’s 2023 Electricity Act was a much-needed, progressive shift, I need to be honest - this is not going to be a walk in the park. Designing and operating a commercially viable, technically sound, investor-attractive and politically sustainable state electricity market is hard work. Very hard work. State Electricity Regulatory Commissions (SERCs) will face layered challenges: 1. Macro risks: FX volatility, inflation, rising cost of imported equipment — all threatening the viability of tariffs and long-term returns. 2. Commercial pressure: Cost-reflective tariffs are essential, but collection remains weak, and many areas are plagued with energy theft and low willingness to pay. 3. Political interference: Governors who want to win elections may block tariff reviews, delay tough decisions, and undermine regulatory independence. If it can happen at the Federal level..... 4. Capacity gaps: Regulation is not just policy — it’s systems, people, models, enforcement, and institutional culture. Many states are starting from scratch. 5. Demand-side viability: Not every state has the industrial or commercial base to justify full electricity market autonomy. Some will struggle to find bankable off-takers or anchor loads. Let’s also be clear: all states are not created equal. Lagos, Edo, and Enugu are moving fast and showing promise. But even for them, this has not and will not be easy. For other states with limited revenue bases, poor planning institutions, and weak energy demand, setting up a full-blown electricity regulator may be overkill — or worse, a vanity project. If we're serious about making this work, a few things are non-negotiable: a. SERCs must be independent — insulated from the political calendar and budget cycles. b. Clear tariff methodology — site-specific, transparent, cost-based. c. Focus on project prep — bankable load mapping, risk allocation, and clear licensing. d. Strong dispute resolution systems — to avoid tariff cases clogging up the courts. e. Avoid vague policy signals — investors need clarity, not aspiration. That said, this can work. With collaboration, technical support, and discipline, we can build something that delivers value. But we must be clear-eyed: this will take time, resolve, and political maturity. The law is a good step. Execution & delivery, as always, is the hard part. Let's go!!! Photo: hanging out earlier in the week with Emmanuel Ekwueme, PhD, of ICE Solar. Refining assumptions and set up for huge growth. Great guy.

🚀 Reforming Australia’s energy markets: A $19 billion DER opportunity 💰 My submission to the National Electricity Market (#NEM) Wholesale Market Review, prepared for Solar Citizens, outlines how outdated rules and market design are stifling $19 billion in net benefits from distributed energy resources (#DER) by 2040. As pv magazine Australia highlights, this isn’t just about rooftop solar—it’s about redesigning markets to prioritise DER as critical infrastructure for affordability, reliability, and decarbonisation. DER—including solar, batteries, EVs, and flexible demand—could deliver: $11 billion in avoided network costs (poles, wires, substations), and $8 billion in reduced large-scale generation/storage needs. 20% of contingency FCAS raise is already provided by aggregated DER today. Yet current market rules and network revenue regulation: * Impose 1MW bid minimums, reducing competition * Lock households and SMEs out of the wholesale demand response mechanism * Let networks prioritise costly infrastructure over DER solutions * Include no minimum demand equivalent of the RERT (emergency peak supply), and * Are not designed for a majority renewable electricity system. See my submission for the details of this series of principles to support the participation of aggregated DER in markets: * Market design should be prepared from first principles * Value resilience to extreme weather events in reliability * Consider how greater deployment of SAPS and microgrids could be facilitated * Ensure fair and non-discriminatory access for all forms of aggregation to all markets and regulatory procurement * Ensure equitable, fair compensation * Facilitate robust competition, especially through the lowest reasonable minimum bid sizes *Establish the best way to manage minimum demand * Enable value stacking to maximise benefits Ensuring fair and inclusive consumer participation: * Voluntary consumer participation * Tiered participation options * Ensure appropriate consumer protections, including transparency about benefit splits Technical and regulatory enablers of #ADER: * Create open data and open communication protocols, use open-source software, make detailed network data available and allow third party access to real-time smart meter data with consumers’ permission * Implement Dynamic Operating Envelopes * Upgrade Market Systems #EnergyPolicy #RooftopSolar #NEMReform #aggregatedDER Integrate To Zero, IEEFA Australia, The Superpower Institute, UTS Institute for Sustainable Futures, NSW Decarbonisation Innovation Hub, Blunomy, Tim Nelson, Paula Conboy, NACD.DC GAICD

ERCOT (Electric Reliability Council of Texas) is often described as a “competitive” electricity market, but it is not a truly free market in the classical sense. Here’s why: ⚖️ 1. Government-Defined Market Structure ERCOT is created and regulated by the Texas Legislature and Public Utility Commission of Texas (PUCT). Participation is limited to qualified entities who must comply with detailed rules. This structure is far from an open-access market. 🧩 2. Price Controls and Interventions ERCOT allows prices to fluctuate but imposes caps and floors, such as the $5,000/MWh system-wide offer cap. During crises, administrative price setting can override market forces, distorting natural supply-demand outcomes. 🏛️ 3. Centralized Dispatch ERCOT centrally clears and dispatches generation based on economic and reliability criteria. This replaces decentralized bilateral trades typical in free markets. 🛠️ 4. Limited Customer Choice Large parts of Texas remain served by municipal and cooperative utilities not subject to competition. Customers in those areas cannot choose providers, reducing competitive pressure. 💡 5. Distorted Investment Signals ERCOT operates an energy-only market with no capacity payments. Price volatility is supposed to incentivize investment, but political pressure often leads to regulatory fixes (e.g., ORDC, backstop procurements), interfering with price signals. 🏗️ 6. Isolation and Market Barriers ERCOT is electrically isolated from the rest of the U.S. This limits competition and arbitrage. New entrants also face long interconnection queue delays, reducing ease of market access. 🧾 7. Policy-Driven Outcomes Subsidies (e.g., federal tax credits for renewables) and regulatory redesigns (e.g., Performance Credit Mechanism) shape outcomes by policy—not by market logic—undermining competitive neutrality. In short, ERCOT is a structured, policy-driven market with competitive features, but not a true free market. It blends market-based pricing with top-down rules, price interventions, and limited consumer choice, all of which deviate from the classical definition of a free market. #Texas #Energy #ercot

🔍 Can we trace electricity from a specific generator to a specific consumer? Traditionally, the answer was no — electricity was seen as indistinguishable and untraceable across a meshed power system. But deregulated markets demanded answers. Electricity Tracing 📊⚡ 📄 J. Bialek’s 1996 IEE paper proposed a topological, flow-based tracing method that opened up possibilities for loss allocation, cost-reflective tariffs, and improved grid transparency. ⚙️ Why tracing matters in deregulated systems In vertically integrated utilities, power exchanges were contractual. But deregulation fragmented generation, transmission, and supply. Now, with generators competing and wheeling transactions growing, a transparent way to allocate responsibility for losses and line usage became essential. 💰 For instance, in the UK Pool (1990s), £140M cost), yet losses were charged uniformly. No incentive to minimize them. Bialek’s method offers a fairer, traceable alternative. 🧭 The Proportional Sharing Principle Imagine a node receiving 100 MW: 40% from one line, 60% from another. Bialek assumes all outflows from this node carry the same proportions. Thus, electricity at a node is treated like water in a mixer — impossible to separate, but easy to apportion based on inflows. 🧮 Two algorithms – Two perspectives 1️⃣ Upstream-looking: Traces how much of each generator’s output reaches a specific load. 2️⃣ Downstream-looking: Determines how much of each load’s demand is met by specific generators. Both yield a “road-distance table”: an intuitive view of who supplies whom, and by how much — for both real and reactive power. ⚡ Handling losses The method supports 3 approaches: Lossless model: Averages sending & receiving-end flows. Gross flow tracing: Assumes no losses, inflates demand to match generation. Net flow tracing: Removes losses, reduces generator output. Each version helps in allocating losses to generators or loads. For example, the gross method lets you say: "Load X caused 4.2 MW of loss," or "Generator Y is responsible for 12.3 MW of loss." Losses can even be shared non-linearly (e.g., in proportion to the square of the flow), better reflecting physics (since losses ∝ I²). 🌊 Analogy Think of it like mixing colored water: If you pour 40% blue and 60% red into a tank (no matter how many pipes exit), every pipe carries water that’s 40% blue, 60% red. 💡 Takeaways for modern grids Bialek’s tracing method isn’t just academic. It supports: ✅ Fair cost allocation ✅ Locational pricing ✅ Transparent tariff design ✅ Better incentives for loss minimization As power systems embrace open access, variable renewables, and granular pricing, flow-based tracing becomes a vital tool in the operator’s arsenal. https://lnkd.in/gn9qtVWv

🇺🇸⚡️ After listening to Travis Kavulla dissect America’s electricity markets on Bloomberg's "Odd Lots" podcast, I challenge anyone to continue claiming Europe is more regulated than America 😆 The US electricity system exemplifies how America drowns in complexity whilst pretending otherwise. Travis, who brings unique perspective as both a former Montana utility commissioner and current executive at NRG Energy, describes a regulatory landscape where 50 states maintain different rules, competitive and monopoly markets coexist, and utilities earn returns based on how much capital they deploy rather than outcomes delivered. The framework incentivises utilities to solve every problem with capital investment because they earn returns on capex but not operating expenses. A commissioner must divine future electricity demand, then charge those guesses to captive customers. The system fragments across regulated generation, competitive retail, monopoly transmission, and nodal pricing at thousands of grid points. This structure now collides with AI-driven electricity demand. The US needs to add large amounts of new capacity. Yet the market, shaped by rules from another era, cannot even match supply and demand in a clear, timely way. Meanwhile, China builds its “electrostate” on pragmatic foundations. Adding solar capacity annually equal to America’s total installed base, China treats electricity as programmable infrastructure. Its planning delivers reliable, affordable power for manufacturing and AI development. China produces 60% of global EVs, 70% of batteries, 80% of solar panels! America’s lawyerly culture throws attorneys at regulatory problems, creating an illusion of freedom whilst actual constraints multiply. China’s engineering culture builds infrastructure ahead of demand. American utilities guarantee shareholder returns; Chinese planning guarantees industrial capacity. The consequences extend beyond electricity bills. As America debates whether data centres deserve priority over residential air conditioning, China captures the electric tech stack. Batteries, motors, power electronics flow from Chinese factories whilst American regulators iterate through interconnection studies. This sclerosis costs America its industrial future. The dollar’s reserve status already forces chronic trade deficits that erode manufacturing capacity. Now electricity constraints threaten to strand data centre investments as energy costs rise. Europe’s single insurance market covers 41 countries with one licence. American insurers need 50 separate approvals. It is the same pattern seen in electricity: America multiplies rules while insisting it is light-touch. Yet Silicon Valley sustains the myth of US regulatory superiority, mistaking abundant lawyers for absent rules. The delusion becomes dangerous when competing against an engineering state building tomorrow’s infrastructure today. -- More analysis of our electric future in my newsletter Drift Signal.

Did you know that every UK power generator gets paid the highest price needed that hour - even if their costs are near zero! The UK electricity market operates on a rather interesting system called "marginal cost pricing" which you may find a bit counterintuitive at first glance. Here's how it works: Power stations are arranged in a "merit order" based on their operational costs - from cheapest to most expensive. Wind and solar typically bid at near-zero cost since their fuel is free. Nuclear comes next, followed by gas plants, with "peaking plants" (the ones that kick in only when they need to meet the highest peak demands) at the top of the cost stack. What makes this system unique is that all generators receive the same price, set by the most expensive unit needed to meet demand at any given moment. In the UK, gas power stations set this price 97% of the time, which explains why electricity prices track gas prices so closely. This creates some unique market dynamics. During periods of high demand when we need peaking plants, prices can rise dramatically - there have been instances where generators were paid up to £4,950/MWh during peak demand periods. In such an event, even renewable generators receive this price, despite their much lower operating costs! However, the landscape is evolving. The UK's Contracts for Difference (CfD) scheme is gradually changing this dynamic by offering fixed prices for renewable generation, helping to decouple some electricity prices from gas prices. Understanding these market mechanisms is crucial for anyone involved in energy trading, policy, or investment. The generation stack is the fundamental mechanism which determines electricity prices in our market. #EnergyMarkets #Electricity #RenewableEnergy #CommodityTrading

Out now: our latest piece on marginal pricing and the Merit Order https://lnkd.in/djcRVVmM The electricity markets discussion The policy debate about electricity market design, marginal pricing, and the “Merit Order” has resurfaced in Europe. Policymakers and stakeholders concerned about electricity prices have proposed state interventions into wholesale electricity markets. These interventions resemble the “Iberian Mechanism” and the “Market Split” that were suggested during the energy crisis. This memorandum presents data on electricity price levels, explains the mechanics and merits of marginal pricing, and evaluates the proposed interventions. We are not in an energy crisis The impression that electricity prices have returned to crisis levels is false. At the peak of the energy crisis in 2022, forward electricity prices reached 1,000 €/MWh. Today, they range between 50 €/MWh and 90 €/MWh in most Member States. However, prices are higher in some parts of Europe than in other regions, including the United States. For example, forward prices in Texas are around 50 €/MWh, which is below the level observed in some European markets. This gap is not due to differences in market design — Texas also applies marginal pricing. Rather, the price differential reflects higher natural gas prices in Europe and the fact that Europe prices CO₂ emissions, whereas Texas does not. Marginal pricing works Marginal pricing is the standard mechanism through which prices form in competitive markets — not only in electricity, but also in commodities such as oil, gas, and metals. The “Merit Order curve” is just another name for the “short-term supply curve.” Prices in commodity markets reflect the marginal cost of the last unit needed to meet demand. Electricity markets function in the same way. Revenues earned by generators with lower variable costs are not windfall profits; they are necessary to recover investment costs and fixed costs. This revenue structure is essential to incentivize new capacity and maintain system adequacy. European wholesale electricity markets are functioning as designed, and there is no structural failure that would justify intervention.

In the late 20th century, many countries, particularly in North America and parts of Europe, embarked on a journey towards deregulating their #electricy markets. This shift aimed to introduce competition and reduce consumer prices. However, as we analyze the impacts on #gridstability, it has become clear that the type of market structure—deregulated, regulated, or hybrid—has had significant influence on the reliability and stability of the power grid. The primary motivation behind deregulation was the belief that competition would drive down costs by increasing competition and spur innovation. By breaking up monopolistic utilities, policymakers hoped to create a marketplace where multiple suppliers could compete to provide electricity at lower prices. The rationale was straightforward: a competitive market would incentivize efficiency and foster technological advancements, ultimately benefiting consumers. However, this shift has not come without challenges, particularly concerning grid stability. In a deregulated market, the responsibility for maintaining grid reliability often falls on independent system operators (ISOs) or regional transmission organizations (RTOs). These entities coordinate the flow of electricity but lack direct control over generation resources, which can lead to coordination challenges. The incentive structures in deregulated markets typically focus on short-term profits resulting in underinvestment in long-term infrastructure and reliability measures such as capital intensive, carbon free energy sources like nuclear. Conversely, in regulated markets, utilities are incentivized to maintain stable operations, as their profits are tied to providing reliable service rather than competing on price alone. This structure often allows for better long-term planning and investment in grid stability, as utilities can recover costs associated with maintaining and upgrading infrastructure through regulated rates. Deregulated areas like California now face grid reliability issues due to renewable integration without backup plans, leading to blackouts. Pacific Gas and Electric Company is one of several utilities pushing for innovation across their energy assets to derisk grid stability while moving toward #NetoZero goals. While the deregulation of electricity markets was driven by the pursuit of consumer protection and lower prices, it has also introduced complexities that now jeopardize grid stability. As we move forward, we must ensure that electricity markets not only foster competition but also prioritizes reliability and stability of the grid as we move toward achieving #netzero goals. U.S. Department of Energy (DOE) Federal Energy Regulatory Commission #WIN