Vol. 97, No. 4

Decommodifying Electricity

William Boyd*
Energy, Markets
Articles

Electricity markets are struggling. Unprecedented energy price shocks, a deeply entrenched cost-of-living crisis, and the imperatives of decarbonization are challenging the ability of current market arrangements to deliver clean, affordable electricity at the scale and pace necessary to avoid widespread climate disruption. Over the last several years, mass protests around the world have put a vision of electricity as a primary social good and system of provisioning squarely on the public agenda for the first time in a generation. Regulators have responded with emergency packages of support and longer-term efforts to rethink and reform the basic design of electricity markets. In all of this, it is increasingly clear that the forty-year global experiment with neoliberal electricity has failed to deliver on even the most basic metrics and, more importantly, is no longer fit for purpose as electricity becomes the chief instrument of decarbonization for most economies around the world. This Article explains how and why electricity markets have failed and offers a series of prescriptions for where we go from here. The Article starts with a brief global history of neoliberal electricity that shows how the project of privatization and restructuring emerged and spread around the world and the consequences this entailed. It then discusses how these markets have struggled with persistent problems of market power, chronic underinvestment, high prices, and an inability to support renewable energy at scale. Finally, the Article offers some provisional thoughts on what an alternative, decommodified approach to electricity might look like as the clean energy transition accelerates, focusing specifically on the relationship between capital and infrastructure, the need for “social ratemaking” to ensure access and affordability, and the potential for a more cooperative approach to balancing the system as intermittent renewables come to dominate the supply of electricity. The Article draws on recent work in law and political economy as well as some of its precursors in legal realism and institutional economics. It also engages with a specific set of questions and concerns that have long preoccupied the fields of public utility and regulated industries law but have recently been revived and updated in the context of a new cross-sectoral approach to economic regulation known as networks, platforms, and utilities law. The key objective is to understand how law, politics, and economics have together structured distributional struggles over the design and maintenance of electricity markets and how they might be recombined in new ways to realize a vision of electricity as a key system of provisioning and vital infrastructure for the clean energy future.

INTRODUCTION

In the summer of 2022, during the most severe energy crisis in half a century, grassroots organizers launched a new campaign across the United Kingdom known as “Don’t Pay UK.” The goal was simple and audacious: recruit one million households from across the country to join an “energy strike”—a mass movement to stop paying energy bills.¹ Drawing inspiration from the successful resistance to Margaret Thatcher’s regressive “poll tax” proposal in the late 1980s and tapping into the growing rage across the country over a deeply entrenched cost-of-living crisis, Don’t Pay UK was betting that if a large enough number of households simply refused to pay their energy bills, suppliers and the government would be forced to respond.²

As of early 2023, more than 250,000 people had signed up; well short of the one million household goal, but a substantial number with thousands engaged in a series of direct public protests, burning their energy bills and demanding action from the government.³ Together with similar campaigns focused on ending fuel poverty, Don’t Pay UK emerged directly out of the energy and economic crisis in the UK that had reached extreme levels by the second half of 2022. Indeed, by late summer 2022, some seven million households were estimated to be behind on their energy bills, and more than four million had been placed on prepayment meters, which, as the name suggests, require customers to constantly feed special meters in order to keep the lights on.⁴ Although the government stepped in with an “Energy Price Guarantee” in September 2022 that capped “typical” household energy bills at £2,500 per year (about $3,000 U.S. dollars), households were still paying double what they had paid the previous winter.⁵ The price shocks of 2022 also squeezed retail providers who were unable to pass along the full costs to their customers. By July 2022, twenty-nine retail providers had failed, requiring expensive government bailouts and the transfer of 2.4 million customers to other providers.⁶

Don’t Pay UK made three essential demands: (1) a reversal of energy utility price increases; (2) an end to the enforcement of prepayment meters; and (3) a social energy tariff that would ensure basic service for low-income households.⁷ In essence, they wanted a just or fair price for energy and an end to the thirty-plus-year experiment with liberalized markets that had failed to deliver reliable and affordable electricity.⁸ Although the energy strike never happened, Don’t Pay UK succeeded in forcing the Government to respond with a package of support for households as well as a broad initiative to rethink and reform energy markets.⁹ More importantly, Don’t Pay UK, along with other campaigns like it around the world, has put a vision of energy as a primary social good and system of provisioning squarely on the policy agenda for the first time in at least a generation. The fact that this occurred in the UK is also notable because the UK was one of the first countries to privatize and restructure its electricity sector and has sometimes been held out as the “gold standard” for such efforts.¹⁰

Of course, the energy crisis of the early 2020s was hardly contained to Great Britain. Across Europe and around the world, energy price shocks have decimated household budgets and created substantial economic challenges for businesses and governments. The International Energy Agency has called it the first truly global energy crisis of the twenty-first century, and one has to go back half a century to the oil shocks of the 1970s to find precedent for the impact on domestic politics and world order.¹¹ Protests over high energy prices rocked cities in Germany, Italy, Spain, and other European countries during the summer and fall of 2022, leading governments to respond with very large aid packages intended to protect businesses and households from the full impact of the price shocks.¹² The amount of spending by European governments is staggering, close to 7% of GDP in some cases.¹³ One report from June 2023 found that total spending across the EU block was around $700 billion, close to what these governments spent on COVID-19 pandemic relief.¹⁴ Such numbers, of course, mask the uneven levels of spending across the EU member states, with some countries such as Germany spending far more than others, raising more than a few eyebrows among those who recall Germany’s previous lectures to fellow member states on the virtues of austerity and fiscal responsibility.¹⁵ For governments in the Global South, of course, such spending is pure fantasy given much more limited fiscal capacity and a looming sovereign debt crisis.¹⁶

Although the U.S. did not experience the extreme price shocks affecting Europe and the UK, the substantial increase in exports of liquefied natural gas to Europe to compensate for the loss of Russian gas did lead to significantly higher prices for both natural gas and electricity across the country. In California and New England, for example, customers experienced “European style” price increases during the winter of 2022–23.¹⁷ For households in many parts of the country, utility bills more than doubled during the early 2020s, leaving more than twenty million households unable to pay their bills.¹⁸ This has been compounded by the expiration of utility shutoff moratoria during the pandemic, which led to a new round of shutoffs and an army of collections agents chasing down unpaid bills.¹⁹ Even before the pandemic, close to a third of U.S. households suffered from chronic energy insecurity—often forced to choose between paying for food or paying for utilities.²⁰ It is, needless to say, a damning indictment on any register.

While it has been common to explain these price shocks of the last two years as a supply problem that started in the second half of 2021 and was greatly exacerbated by the Russian invasion of Ukraine, such a view misses important questions about market design and the distinctive ways of price making at the center of natural gas and electricity markets.²¹ For electricity in particular, the current crisis has raised fundamental questions about the forty-year project of neoliberal electricity and the viability of current electricity market designs. Prices, in short, have become disconnected from the actual cost of providing electricity, raising basic questions of fairness. As EU President Ursula von der Leyen stated in her September 2022 State of the European Union, “the current electricity market design . . . is not doing justice to consumers anymore.”²² Similar concerns have been raised by UK government officials and by at least one sitting Federal Energy Regulatory Commission (“FERC”) commissioner.²³

At the center of these concerns is the uniform or single-clearing price auction design used in most electricity markets. As the name suggests, the single-clearing price design sets clearing prices based on the price of the last increment of generation needed to meet demand. All sellers who submit offers below the clearing price receive the clearing price, regardless of their original offer price. This means that when very expensive generators are necessary to meet demand, clearing prices can rise to extreme levels, and all the generators who submitted successful bids will receive that high clearing price regardless of their actual costs. Thus, when natural gas prices rose to unprecedented levels following the Russian invasion of Ukraine, electricity prices followed because natural gas power plants were on the margin setting the clearing price in the electricity markets. These high clearing prices, in turn, delivered substantial windfalls to non-gas generators and caused enormous pain for retail customers.²⁴

The single-clearing price design also means that prices in these markets can fluctuate dramatically and are often completely detached from the overall costs of providing electricity. In Texas, for example, a state that has long prided itself on having one of the best designed electricity markets in the world, spot market prices have fluctuated from negative prices—typically at night when demand is low and vast amounts of wind energy are on the system—to $9,000 per megawatt-hour (“MWh”), which was the price cap set by the state’s scarcity pricing mechanism for periods of peak demand.²⁵ Although this kind of volatility might seem exceptional, it is actually hard wired into the logic of these markets and reflects the multi-decade effort to make electricity into a commodity.²⁶ While that might be good for traders and others who can profit from volatility, it is most assuredly not good for consumers. It is also not good for efforts to create the stable, long-term investment climate needed to scale up decarbonization. In fact, current electricity market designs are incompatible with a future dominated by renewables.²⁷ Virtually all of these markets were built on the assumption that fossil fuel generators such as natural gas plants with positive short-run marginal costs (that is, fuel costs) would set the clearing price. A renewables-dominated electricity system does not work under such a market design for the simple reason that renewable electricity such as wind and solar do not have any short-run marginal costs. The uncertainty that this creates for renewables projects in terms of their ability to recover their fixed capital costs is one reason why virtually all renewables in markets around the world are compensated through some form of long-term contract with price terms that make them indifferent to market clearing prices.²⁸

Electricity markets have also failed to deliver on the one metric for which they were supposed to be vastly superior to regulation: lower prices for consumers. Indeed, even as efficiencies have improved and wholesale costs have declined across these markets, retail prices have increased as generators and electricity providers have been able to capture the gains in performance while also pursuing substantial price markups, demonstrating the stubborn fact of market power in electricity.²⁹ This exercise of market power, moreover, has not been limited to periods of scarcity, when generation capacity is most constrained, but appears to be pervasive in these markets.³⁰ Notwithstanding the claims (and hopes) of the proponents of deregulation that the new electricity markets would be contestable, they have remained concentrated on the supply side, which has translated into ongoing pricing power for wholesale generators.³¹

In sum, the electricity markets that were adopted in the U.S. and around the world over the last several decades have not been able to deliver savings to consumers. They have not been able to ensure security of supply, and they are not delivering renewable energy and other clean energy assets at the scale that is needed. While these markets have led to improved performance and efficiency for some existing assets, it is no longer feasible or appropriate to view the power sector as simply another legacy infrastructure industry in need of market discipline. It is now the chief instrument of decarbonization for most economies in the world, a project that entails a very different set of technologies with very different cost structures than those used as the basis for designing these markets in the 1980s and 1990s and one that will also involve much more extensive use of electricity in everyday life.

Put another way, given the radical shifts in the goals, underlying technologies, and cost structures of the power sector, it is increasingly clear that electricity markets are no longer fit for purpose. The vast subsidies available for renewable energy, clean energy manufacturing, and electric vehicles (among others) in the Inflation Reduction Act (“IRA”) do not change this in any fundamental way. If anything, the IRA’s core strategy of de-risking private investment in clean energy through tax credits accepts the status quo of markets and builds on the financialized approach to renewable energy that has dominated U.S. federal renewables policy since the early 1990s.³² To be sure, the IRA’s direct pay and transferability provisions do open up possibilities for alternative forms of project finance and ownership, including by governments and non-profit entities.³³ But the main thrust of the legislation is to lure private capital into clean energy by reducing the risk of investment, leaving the basic design and regulation of electricity markets intact. Thus, while the legislation is unprecedented in the scale and scope of investment that it could generate, and while it may well be the case that the IRA is the best that clean energy advocates could have hoped for given the demands of budget reconciliation and the highly polarized nature of our politics, it does beg the question whether other approaches will be needed in addition to the IRA to channel investment into new clean energy assets at the scale and pace required to decarbonize the power sector and electrify large segments of the economy. It also poses the broader question of what this heavy reliance on markets and the private sector means for the overall governance of electricity as a system of provisioning and vital infrastructure for everyday life.

One alternative that has been advanced by critics of the IRA’s de-risking strategy is the so-called Big Green State marked by predominantly public investment and public ownership of clean energy assets.³⁴ This was part of the impulse behind some versions of the Green New Deal in the United States and the so-called European Green Deal.³⁵ To be sure, there is precedent for significant state ownership of electricity in the nationalized systems that prevailed in the UK and many European countries after World War II, across much of the Global South after independence, as well as in the United States with its large public hydropower projects, regional experiments such as the Tennessee Valley Authority, and municipally owned utilities. Despite the enthusiasm on the left for extensive public ownership, however, it seems at best aspirational in the current U.S. political environment, notwithstanding important ongoing efforts to build on and promote more public investment and ownership across the electricity sector.

But there is another alternative that has not received much attention in the current debate: U.S.-style public utility regulation with its reliance on cost-of-service rate making for regulated investor-owned utilities (“IOUs”). This model, which still operates in various ways across some parts of the United States, has long provided a vehicle for channeling large amounts of capital into physical assets as well as a platform for important experiments with new rate designs to socialize costs and to improve access and affordability.³⁶ Without question, the basic public utility model in the U.S. has had its share of challenges, leading to intense criticism and repeated calls for reform and even wholesale abandonment. But in the current moment, given the need to significantly ramp-up investments in long-lived physical assets and secure a low cost of capital, it seems important to revisit the public utility model and ask what role it might play in the ongoing effort to decarbonize the power sector and electrify much of the rest of the economy.³⁷

To say, then, that the forty-year experiment with electricity markets has failed is hardly a sufficient rejoinder to the question of what is to be done in the face of the looming climate crisis and the pressing need to address the twin challenges of investment and affordability at the heart of the clean energy transition. Before we turn to the question of where we might be headed, however, it is critical to understand how and why these markets emerged in the first place, and the nature of their failures. Put simply, we need to understand the multi-decade effort to make electricity into a commodity before we can understand the different ways in which it can be and already is being decommodified.

Given the rather large and longstanding literatures on commodification and decommodification in law and social science, it is important to specify here the way that this Article uses these concepts.³⁸ At a general level, the effort to make electricity into a commodity can be seen as an effort to replace existing non-market modes of governing a key system of provisioning with a privatized, market-governed system of coordination.³⁹ More specifically, the entire effort was expressly conceived and directed at making electricity into a commodity like natural gas, oil, or other bulk commodities, with a mix of forward and spot markets, and a pricing system built around marginal cost. There were two important components to this effort that are important to keep in mind. First, on the upstream, wholesale side of the industry, the vertically integrated structures of existing state-owned and heavily regulated systems were unbundled and replaced with competition among private, unregulated generators through a mix of long-term forward markets and short-term spot markets. These markets were explicitly designed to operate in a manner like those prevailing in other commodity markets, with the single-clearing price in the auctions intended to capture the short-run marginal cost of producing the last increment of supply needed to meet demand. Although the effort has never been completely realized, in part given the distinctive challenges of electricity, the establishment of wholesale markets for electricity does represent a remarkable socio-technical achievement. Second, on the downstream, retail side of the industry, the goal was to replace the previous model of dedicated customers paying flat rates to regulated monopoly providers based on average costs with competition among retail providers and dynamic retail rates that would transmit the clearing prices in the wholesale markets directly to retail customers, thereby allowing the price system to deploy true marginal cost pricing all the way through to the end users. For reasons discussed in more detail below, this effort has also been partial and incomplete. The key point for now, though, is to underscore that the basic idea at the center of both wholesale and retail electricity restructuring was to create markets that would allow for the exchange of electricity between producers and consumers via pricing mechanisms based on marginal costs.

The Article proceeds in three parts. First, it provides a brief global genealogy of “neoliberal electricity” that shows how the project of privatization and restructuring emerged and spread around the world, focusing on the intellectual, technical, and political histories that came together to support the move to electricity markets. The goal here is to show how various neoliberal experiments sought to turn electricity into a commodity and the consequences this brought forth. Second, the Article demonstrates how these efforts to create markets for electricity have struggled with persistent challenges of market power, chronic underinvestment, high prices, and an inability to support renewable energy at scale. The main takeaway here is that these markets have failed on multiple grounds and are no longer viable as electricity becomes the main instrument of decarbonization in most economies around the world and as more and more aspects of everyday life are electrified. Third, the Article articulates some of the features of what an alternative, decommodified approach to electricity might look like as the clean energy transition accelerates, focusing specifically on the relationship between capital and infrastructure and the possibilities (old and new) for driving investment and cost recovery, the need for “social ratemaking” to ensure access and affordability, and the potential for a more cooperative approach to balancing the system as intermittent renewables come to dominate the supply of electricity.

The Article draws inspiration from recent work traveling under the rubric of law and political economy as well as some of its precursors in legal realism and the old institutional economics.⁴⁰ It also focuses specifically on a set of questions and concerns that have long preoccupied the fields of public utility and regulated industries law but have recently been revived and updated in the context of a new cross-sectoral approach to economic regulation known as networks, platforms, and utilities (“NPU”) law.⁴¹ The key concern is to understand not so much how law regulates economic actors but how it structures industries and shapes markets; that is, how it constitutes distributional struggles over the design, maintenance, and restructuring of economic institutions and, specifically, those governing key infrastructures and systems of provisioning.⁴² Much of this work, particularly in law and political economy, has focused on critiques of neoliberalism, and much of it has been domestic in orientation. This Article joins in the critique of neoliberalism, as manifest in the move to privatize and deregulate electricity over the last forty years, but it does so in a broader global context that seeks to properly situate the project of neoliberal electricity in all of its world-making ambitions. It also attempts to go beyond critique and offers some normative arguments regarding a new set of institutional arrangements for the coming age of electricity.⁴³

I. NEOLIBERAL ELECTRICITY: A SHORT HISTORY

The move to restructure and liberalize both state-owned and heavily regulated electricity systems reflected a confluence of factors taking shape across multiple countries starting in the 1980s. The story played out differently in different places, given that the electricity sector, like other network industries, has always been place-bound and heavily domestic in orientation. But electricity, and neoliberal electricity in particular, has a global history that is important to understand as the industry transitions to a low-carbon future.

Recognizing that this history can be told in different ways, this Part focuses on three major strands that came together in the making of neoliberal electricity. First, a powerful and sustained economic critique directed at state-owned and heavily regulated public utility systems hit full stride in the 1970s and 1980s and provided an intellectual call-to-arms for efforts to privatize and liberalize electricity markets. Second, a series of innovations in mechanism design, operations research, and experimental economics provided the basic rules and techniques used to build the auctions that operate at the center of these markets. Third, domestic political developments that often reached to the very highest levels of government opened new policy horizons for ambitious market experiments in leading jurisdictions.

A. Intellectual Commitments

Two important intellectual developments underwrote the move to privatize and restructure electricity. First, the powerful and sustained critique of economic regulation and state ownership that took shape during the 1970s provided the theoretical and normative case for the move to competitive markets. Second, the rich tradition of thinking about the challenges of marginal cost pricing for public utilities, and electricity in particular, led to a reconceptualization of the role of prices in the sector and their relationship to investment, cost recovery, and consumer behavior.

1. Economic Critiques

The standard critique of economic regulation advanced by economists and public choice theorists starting in the early 1970s has been well rehearsed.⁴⁴ Boiled down to its essentials, the critique consisted of three main points. First, the whole category of natural monopoly was unstable and incoherent and not a proper basis for regulation.⁴⁵ Second, Public Utility Commissions (“PUCs”) were all too often captured by the industries they were supposed to regulate.⁴⁶ Third, cost-of-service rate making created incentives for regulated firms to overinvest in physical assets and overcharge ratepayers.⁴⁷ The combined effect of these critiques was simple and devastating: regulation did more harm than good.⁴⁸

While the economic critique focused mainly on U.S. public utility regulation, it shared many of the basic commitments that animated the growing skepticism toward nationalized industries in the UK and other countries. These critiques of state ownership often rested on relatively simple complaints that state-owned enterprises were bloated and inefficient, but they drew upon a deeper hostility to planning and a conviction that unfettered markets were essential to a free society.⁴⁹ Without the discipline of competition, performance suffered, innovation was stunted, service was poor, the public paid too much, and individuals would never realize their full economic potential.⁵⁰

As powerful as these criticisms were, however, they did not provide an obvious blueprint for restructuring.⁵¹ In fact, the real “theory” of restructuring that underwrote liberalized electricity markets came not from the Chicago school or the enemies of state ownership but from work on contestable markets.⁵² As the name suggests, contestable markets posited that as long as firms could enter and exit a market with relative ease to compete with the incumbents, this would discipline the prices charged by the incumbents even if no competing firm ever actually decided to enter and compete.⁵³ Put another way, as long as the market was contestable, prices could be expected to track those one would expect to see in a competitive market.⁵⁴ Thus, instead of focusing on the number of firms and the structure of the market, contestable market theory directed attention to barriers to entry and, even more importantly, barriers to exit, which together determined whether a particular market, even one marked by only a few firms, was contestable.⁵⁵ And the key to understanding barriers to exit, the proponents argued, was sunk costs.⁵⁶ Even if a firm could enter the market easily, if it had to make large investments that could not be easily recouped, it would be far less likely to enter in the first place.⁵⁷

These insights were powerful and well-timed, providing further grounds on which to indict various forms of economic regulation and state ownership while also offering clear guidance for restructuring.⁵⁸ For starters, contestable market theory highlighted the fact that regulation often made things worse precisely because it erected new or additional barriers to entry.⁵⁹ Here the monopoly franchise for public utilities in the United States was often held out as Exhibit A.⁶⁰ More generally, contestable market theory suggested that vertically integrated industries—whether regulated or state owned—could be unbundled, allowing certain segments to be subjected to competition. Finally, for those segments that did entail high sunk costs—pipeline infrastructure, transmission systems, and local distribution networks—moving toward an open access, common carrier model that would maintain regulation but require all firms to have access to the basic infrastructure on the same rates, terms, and conditions would avoid some of the problems of regulation while further enhancing the contestability of linked markets.⁶¹ Taken together, these elements provided the blueprint for unbundling generation from transmission and distribution, imposing new open-access requirements on transmission, and opening up the wholesale generation market to competition.⁶² The working assumption was that the new wholesale power markets would be sufficiently contestable to ensure competitive prices, an assumption that, as we will see, proved overly optimistic.

2. Marginal Cost Pricing

Any effort to create new markets for electricity, however, also had to sort out complex issues of price formation. Given the engineering complexities of electric power systems (namely, the fact that the system operated as one big machine that had to be perfectly balanced in real time), highly inelastic demand, and the inability to store electricity, the transactional and pricing aspects of any new market would need to be carefully orchestrated.⁶³ Realizing the efficiencies that markets promised, in other words, required a solution to the problem of marginal cost pricing that had preoccupied economists, engineers, and regulators for more than a century.

The idea of marginal cost pricing for public infrastructure is often traced back to the mid-nineteenth-century work of Jules Dupuit and other French engineer-economists working in the French civil service.⁶⁴ Among other things, Dupuit and his colleagues were looking for ways to assess the relative value of different infrastructure investments—roads, bridges, canals, railroads—so as to better allocate resources and maximize welfare.⁶⁵ In the process, they identified some of the key challenges confronting efforts to develop efficient pricing for large infrastructure and public utilities.⁶⁶

Among the most important issues raised by this work involved setting prices for industries marked by declining costs. If prices were set at short-run marginal costs in these industries, firms would be unable to recover their fixed costs.⁶⁷ In an important 1938 article, Harold Hotelling took this problem head-on arguing that the best way to maximize “the general welfare” with respect to infrastructure investments marked by declining costs was for the government to use taxes on income, inheritances, and land to pay for the fixed (overhead) costs of the physical assets and to charge the public a price that was set at marginal cost, which in the case of most infrastructure would be very low or even zero.⁶⁸ According to Hotelling, two groups would be likely to object to such a scheme: the wealthy and land speculators.⁶⁹ But any losses they incurred would be more than offset by the benefits accruing to the public at large.⁷⁰

Hotelling’s intervention, which explicitly invoked Dupuit’s earlier work, gave rise to a vigorous debate among economists during the 1940s and 1950s about the merits of marginal cost pricing in industries with declining costs—an episode that Ronald Coase referred to as “the marginal cost controversy.”⁷¹ In Coase’s view, Hotelling’s proposed solution of using tax revenues to pay for the fixed costs of infrastructure and public utility was misguided because it would create a “maldistribution of the factors of production” across the economy, an unwelcome “redistribution of income” among different classes, and “other harmful effects.”⁷² Most fundamentally, tax-based subsidies would deny the possibility of any sort of “market test” to determine whether the proposed investment was “worthwhile.”⁷³ A better solution, Coase argued, was to use a multipart pricing scheme that included separate charges for the marginal cost of producing the good or service and for the cost of delivering it—an approach that was already well developed in public utility pricing.⁷⁴

At roughly the same time that Coase and others were debating the merits of marginal cost pricing, another group of French engineer-economists working at Electricité de France (“EDF”) (the most prominent of whom was Marcel Boiteux) were developing their own version of marginal cost pricing in their effort to rebuild the French electricity system after World War II.⁷⁵ In particular, Boiteux and his colleagues were interested in incorporating marginal costs into the rates charged for electricity in a manner that would allow them to build a national electricity system that contained an appropriate mix of thermal and hydroelectric power plants in the face of rapidly growing demand.⁷⁶ According to Boiteux, prices were not simply signals but rather tools to realize an investment policy.⁷⁷ Peak-load prices that reflected the system’s marginal cost could thus be used to help mold and shape the “load curve” (a term of art for electricity demand over the course of the day or the year), thereby allowing for the efficient investment of capital into certain kinds of physical assets as determined by system planners.⁷⁸ The price system, in other words, was subordinated to, and made to work on behalf of, the need for infrastructure to support the national objective of building an electric power system based on a particular mix of assets.⁷⁹

Notwithstanding Boiteux’s efforts to ground the discussion of marginal cost pricing in the context of national planning and investment policy, however, the concept of marginal cost pricing came to be viewed over time in a more detached, generic sense as the basis for maximizing allocative efficiency in state-owned and rate-regulated public utilities.⁸⁰ The goal, as William Vickrey put it in the early 1970s, was “responsive pricing,” which would allow prices to track costs and thereby lead to more efficient allocation of capital across the industry.⁸¹ Vickrey did recognize that the move to “responsive pricing” of public utility services was ultimately a political choice that “would constitute a fairly radical departure from current practices in utility pricing,” at least in the United States.⁸² But in his view, it would be “well worth the considerable effort that [would] be needed to put it into practice” given “the very substantial improvements in economic efficiency” that would be gained.⁸³ Indeed, responsive pricing was as close as one could hope to get to the virtues of a “free market” in industries marked by “heavy fixed costs and economies of scale.”⁸⁴

During the early 1970s, as electricity rates increased across the United States for the first time in decades, several public utility commissions began to explore the possible use of marginal cost pricing as a basis for retail rates.⁸⁵ Environmental groups also began to push PUCs in this direction based on their conviction that the prevailing practice of declining block rates (that is, the more you use the less it costs) undermined efforts to promote conservation and efficiency and that marginal cost pricing would reduce the amount of new generation that needed to be built by shaving peaks and possibly even reducing overall demand.⁸⁶ In 1974, the Wisconsin Public Service Commission issued a landmark order that embraced marginal cost pricing as a key principle in rate design.⁸⁷ In New York, Alfred Kahn, who had just become chair of the New York Public Service Commission, opened a “generic” rate investigation to develop principles and methods for marginal cost pricing.⁸⁸ After thirty-five days of hearings, the New York Commission issued an order concluding that marginal costs provided a “reasonable basis for electric rate structures,” and directed the state’s electric utilities to consider how “to translate marginal cost analyses into rates.”⁸⁹ These efforts received a further boost in 1978 with passage of the Public Utility Regulatory Policy Act (“PURPA”), which implicitly endorsed the concept of marginal cost pricing and directed state PUCs to consider new rate designs based on time-of-use.⁹⁰

Despite enthusiastic support from economists and other utility reform advocates, however, none of these efforts made much of an impact on existing residential rate structures across the country.⁹¹ Aside from some modest experiments with time-of-use rates and peak-load pricing in a handful of states, most residential customers continued to pay flat rates based on historical average costs.⁹² Part of the reason for this was because of the complexity of trying to design rate structures that would reflect marginal costs while also meeting revenue requirements for utilities.⁹³ Part of it also stemmed from older commitments to using historical average costs, which were easier to calculate and verify based on uniform accounting.⁹⁴

But the concept of marginal cost pricing did have an important impact on the whole approach to public utility pricing that fed into larger concerns about the sector and the need for restructuring.⁹⁵ By elevating efficiency concerns, particularly during a moment when prices were rising and regulators were struggling to make sense of a new macroeconomic environment, marginal cost pricing worked to displace and discredit some of the longstanding redistributive aims of public utility.⁹⁶ In particular, it made visible the cross-subsidies that had long operated in the shadows of flat rates based on historical average costs.⁹⁷ It also provided a foil to the efforts by consumer groups and others during the 1970s to adopt “lifeline rates” for poor customers, a topic that we will return to in Part III below.⁹⁸ Alfred Kahn, in fact, was notable in his hostility to the whole idea of lifeline rates, which he dismissed as “social ratemaking” and antithetical to any economically responsible approach to setting rates.⁹⁹

Finally, although much of the discussion of marginal cost pricing had taken place in the context of state-owned and regulated systems (and was largely directed at establishing more efficient rate structures within these systems), there was an important sense in which it reinforced the case for markets. In fact, if designed correctly, competitive spot markets for electricity might provide a solution to the challenge of translating marginal costs into rates precisely because the new markets would provide a robust, granular price signal that reflected the changing costs of generation across time as well as the specific physical constraints of the transmission system.¹⁰⁰ Making this work in practice turned out to be an enormously complicated technical and computational problem given the peculiar nature of electricity networks and their variability over space and time.¹⁰¹ In the U.S., a system of locational marginal pricing (“LMP”) was developed during the 1990s to translate the theory of short-term spot pricing into a workable approach that could capture both the changing cost of supply at particular locations and the additional costs of transmission congestion on the network.¹⁰² LMP has subsequently been adopted by all of the wholesale markets in the U.S. as well as several foreign markets. Translating these short-term wholesale spot market prices into dynamic, real-time prices for retail customers, however, has not been widely adopted in the United States, in part because states still retain jurisdiction over retail prices and in part because of lack of interest from customers. As discussed in Part II, this has significantly limited the ability of supply and demand to mutually adjust in real time and undermined the ability of electricity markets to deliver the full benefits of marginal cost pricing.

B. Market Devices

Translating these broad commitments to competition and marginal cost pricing into an actual market in the real world was, of course, easier said than done. The main challenge involved creating a package of rules, devices, and institutions capable of formatting the interaction of supply and demand in a manner that would consistently generate prices that reflected marginal costs.¹⁰³ Because electricity networks operate as a single integrated machine, where supply and demand must be balanced in real time, this required centralized systems operations that would embed any sort of market arrangement within the basic engineering requirements of the grid.¹⁰⁴

Here again the basic approach grew out of the experience with vertically integrated systems. Indeed, grid managers in the regulated and state-owned utilities had long used a system of least cost economic dispatch to ensure that the entire system was run as efficiently as possible subject to the basic engineering constraints of the grid.¹⁰⁵ Generating units were ranked in merit order depending on their costs and dispatched from low cost to high until demand was satisfied. In these vertically integrated systems, the fixed and variable costs of each generating unit were known and could be used as a basis for dispatch decisions. Control of the system thus proceeded based on extensive knowledge of how all the parts fit together.¹⁰⁶

Finding a “market device” that could replicate this across a fleet of competitive generators where the costs were not known was no small task.¹⁰⁷ Two main challenges confronted the effort. First, the basic design of these markets and their associated activity rules needed to ensure that generators would not be rewarded for offering to sell at inflated prices. Put another way, generator bidding needed to be constrained by a set of rules that would encourage them to submit bids at their actual marginal cost. This was not, as we will see, a simple question of market structure, and the effort to ensure a consistent pattern of honest bidding across these markets has proved to be quite challenging. Second, generators needed sufficient revenues to cover their total costs (that is, both fixed and variable costs) and needed to have sufficient confidence that they would be able to do so going forward to make new investments. Any new market arrangements thus needed to produce sufficient economic rents to maintain enough capacity to meet peak demand and to stimulate enough new investment so that the system would be able to satisfy future demand. This too would prove to be quite challenging.

1. Honest Bidding

For spot markets, the challenge was to create a market mechanism that could consistently generate prices that reflected marginal costs and to avoid gaming by generators. Put another way, the challenge was to make generators behave like honest bidders. As it turned out, economists working in the fields of auction theory had been thinking about a related set of problems since the early 1960s. In 1961, a decade after his initial interventions in the area of public utility pricing, William Vickrey demonstrated that the “incentive properties” of specific auction designs could be used to elicit truthful information from bidders in their bidding strategies.¹⁰⁸ In effect, by separating the price-as-bid from the price received (the clearing price), bidders in a sufficiently competitive market had no incentive to make inflated bids.¹⁰⁹ Although Vickrey’s paper was ignored for the better part of a decade, its key insight would become central to efforts in coming decades to adopt specific auction formats to encourage certain forms of behavior.¹¹⁰

More generally, as the field of mechanism design gained traction within economics, a new generation of market designers worked to translate the insights of Vickrey and others into the design of actual markets.¹¹¹ In the UK, economist Sally Hunt and her colleagues convinced the government to use a single-price auction format for the UK’s mandatory short-term electricity market.¹¹² In California, Robert Wilson made use of Vickrey’s insights to explain how different auction designs and activity rules could be used to create what he called a “mode of competition” for electricity markets that would suppress gaming and force market participants to reveal truthful information in their bidding strategies.¹¹³ As one of the key architects of the new California market, Wilson recognized that a uniform or single-price auction design wrapped in detailed activity rules would provide the honest bidding outcome that Vickrey had hypothesized decades earlier.¹¹⁴

The basic design of the single-clearing price auction was quite simple. Generator bids would be stacked in ascending order from lowest price to highest. Load serving entities would likewise submit offers to buy at various prices, arranged from lowest to highest, although because of the highly inelastic nature of electricity demand the demand curve was essentially fixed. The last increment of generation needed to meet demand would set the clearing price. All generators that submitted bids below that price would receive the clearing price. All load serving entities that submitted offers above the clearing price would pay the clearing price. As long as there was no market power and as long as individual bidders did not know the bidding strategies of their competitors, they had no incentive to bid above marginal cost. By submitting bids at their short-run marginal costs, they maximized their chances of being dispatched without losing money in the short term.¹¹⁵ And if the clearing price ended up being higher than their marginal costs, they would receive the difference as inframarginal rents.

It was a brilliant solution to a vexing problem that illustrated the significant changes underway in economics as a discipline and the vast new domains opened up by mechanism design. Rather than trying to understand how markets work or why economic agents behave in certain ways, the proponents of mechanism design sought to intervene directly in the economy and build specific kinds of markets with specific rules and institutions that would then elicit the behavior of market participants that theory indicated was optimal.¹¹⁶

2. Rent Machines

The other challenge facing electricity market design was how to ensure that generators received sufficient revenues to maintain enough generating capacity over time. This was particularly challenging in capital-intensive industries where prices needed to cover fixed costs and provide sufficient incentive for future investment. In the electricity sector, moreover, the problem was further compounded by the inability to store electricity at scale, highly inelastic demand, and the need to balance the system in real time—all of which created special vulnerabilities to market power during conditions of scarcity.

The uniform or single-price auction design offered a possible solution here as well. In effect, the inframarginal rents available to lower cost (inframarginal) generators would cover at least some of their fixed costs and, if consistently high enough, would signal the need for new investment. By operating as rent machines, in other words, the auctions would drive investment toward the lowest cost generation technologies while solving the revenue problem. This had two components: the modest inframarginal rents available to lower cost generators during normal operating periods and the very large rents available during periods of peak demand (perhaps only a few days per year) when prices were very high. The latter scarcity pricing effect was generally viewed as the major source of profits to encourage longer term investment.

But given highly inelastic demand and the fact that electricity is a necessity, market operators were uncomfortable with the extremely high prices that might occur during periods of peak demand when the system is operating at capacity. Allowing prices to go as high as they could during these periods would effectively destroy the market.¹¹⁷ The solution here was to adopt price caps that would kick in during periods of scarcity. Currently, these range from $1,000 MWh in most of the organized electricity markets in the U.S. to $9,000 in the Electric Reliability Council of Texas (“ERCOT”) market (a cap that was reduced to $5,000 per MWh after Winter Storm Uri and has since been thrown into doubt by a 2023 court decision).¹¹⁸ For comparison, the average annual wholesale prices in many of these markets have historically been around $40 to $50 per MWh.¹¹⁹

Opponents of price caps have argued that the effort to limit the extraordinary rents available during periods of scarcity has undermined incentives for future investment. This is sometimes referred to as the “missing money problem,” which in turn has led generators to push for all manner of additional out-of-market payments, capacity remuneration mechanisms, and new products intended to provide additional compensation to ensure adequate investment and maintain enough capacity to meet peak demand.¹²⁰ As discussed in more detail below, it is fair to say that none of these markets have solved the capacity problem, and it is a problem that becomes significantly harder in a system dominated by intermittent, non-dispatchable renewable energy.

* * *

The intellectual case for electricity markets and the technical aspects of their design were necessary but not sufficient by themselves to deliver actual electricity markets in the real world. In effect, they provided crucial building blocks for the larger political effort to abandon the state-owned and heavily regulated electricity systems that had prevailed for most of the twentieth century. This political effort was, as noted, part of a global project that was deeply rooted in the broader rise of neoliberalism on both sides of the Atlantic and grew directly out of the crisis of the 1970s.

C. Political Histories

The mutually reinforcing energy and economic crises of the 1970s provided fertile ground for the neoliberal critique of regulation and state ownership. Within electricity, the exhaustion of economies of scale in thermal power generation by the late 1960s combined with high fuel prices stemming from the oil shocks of the 1970s strained the system and undermined support for regulation.¹²¹ In the U.S., declining real prices abruptly gave way to significant price increases as PUCs were inundated with new rate cases brought by utilities seeking higher rates.¹²² These facts, combined with a Keynesian welfare state that seemed exhausted and inadequate in the face of high inflation and low growth, prepared the ground for a series of experiments around the world to privatize and restructure the electricity sector—a set of developments that we turn to now.

1. Chile

As with most things neoliberal, the first efforts to privatize electricity and subject it to market competition took place in Chile under the Pinochet dictatorship during the early 1980s.¹²³ With its potent mix of Chicago economics and authoritarianism, Chile provided an ideal laboratory for neoliberal experiments.¹²⁴ The power sector was an obvious target, as it had been under state ownership for decades and was viewed as strategic for the development of other industries.¹²⁵

One of the main architects of the Chilean experiment, Sebastian Bernstein, had spent time in France studying the theory and practice of marginal cost pricing developed by Marcel Boiteux and others. Rather than use marginal cost pricing as a tool for improving efficiency within a state-owned system, however, Bernstein and his colleagues recognized that marginal cost pricing could also be used in a market context.¹²⁶ Two overarching goals animated the basic approach: the use of markets to ensure “the correct allocation of resources” and the assignment of the state to a “subsidiary role.”¹²⁷ This required, in Bernstein’s view, “deconcentrating, decentralizing, and privatizing the activities and property of the energy companies” previously owned by the state, combined with “state support to the more deprived sectors of the population through direct subsidies, without distorting the prices of goods and services,” and a strict prohibition on state performance of any “entrepreneurial activities” unless they “cannot or will not be carried out by the private sector.”¹²⁸ In the reformed electricity sector, “pricing” provided the “mechanism to attain the objectives of global efficiency and state subsidiarity.”¹²⁹

Enacted in 1982, the Chilean Electricity Law unbundled and privatized state-owned generation, created new distribution companies, and explicitly required the use of marginal cost pricing: “[T]ransfers of energy between electric power generating companies operating in synchronism with an electric system . . . shall be priced according to the short-term marginal costs of the electric system.”¹³⁰ These prices would be calculated through an “economic load dispatching centre” that was structured as a “generators’ club” with minimal government oversight and involvement.¹³¹

The two large state-owned electricity companies, Chilectra and Endesa, which generated 13.4% and 64.1% respectively of Chile’s electricity, were unbundled into seven generation companies and eight distribution companies.¹³² The hope was that more private companies would enter the market and enhance competition. In fact, just the opposite occurred. During the late 1980s, Endesa purchased three of its former spin-offs and by 1990 was supplying 52.1% of Chile’s electricity generation.¹³³ By 1995, Chile’s leading distribution holding company, Enersis, had acquired a controlling ownership share in Endesa.¹³⁴ Four years later, Spain’s largest electricity company, also named Endesa, acquired a controlling interest in Enersis.¹³⁵ Spanish Endesa then used its control over Enersis to fight off an effort by Duke Energy to acquire a majority stake in Chilean Endesa.¹³⁶ Spanish Endesa, moreover, was controlled by the Spanish government through a so-called golden share arrangement until 2005, when the European Court of Justice forced it to relinquish control in accordance with EU competition law.¹³⁷

By the early 2000s, then, two decades after it launched its experiment to privatize and liberalize its electricity sector, Chile faced a highly concentrated sector with its largest companies controlled by a foreign company that was itself controlled by the government of Spain.¹³⁸ It seems unlikely that this was the result that Sebastian Bernstein and other architects of the Chilean experiment anticipated in the early 1980s, but it is not, as we will see in the UK case, a story that was unique to Chile.

More important, the overall performance of the Chilean electricity sector over the last forty years has been uneven at best. In effect, privatization led to significant concentration in the ownership of generation assets and very limited gains for consumers, while the new market actors captured large profits.¹³⁹ Over the course of the 1990s and early 2000s, Chile’s electricity sector underwent several major crises resulting in extremely high prices, forcing the Government to intervene to address the problems.¹⁴⁰ The most extensive reforms came in 2015, when the Government introduced a new “tariff equity law” for retail consumers and embraced a series of reforms that sought to integrate concerns about sustainability and affordability into the dominant market-based approach.¹⁴¹ Four years later, in response to the widespread social unrest that focused directly on Chile’s staggering levels of inequality and a deepening cost-of-living crisis for many Chileans, the Government canceled a proposed 9.2% price increase and froze retail prices for most consumers.¹⁴² Since that time, local electricity distribution companies have faced mounting debts and a growing liquidity crisis.¹⁴³ In 2022, the price freeze was extended under a new law that creates a tariff stabilization fund managed by the Government that will be used to reimburse generating companies for the difference between the amounts charged by the distribution companies to retail customers and the amount payable to the generating companies for electricity supply under existing regulated power purchase agreements.¹⁴⁴

Chile’s liberalized electricity markets have also struggled to promote renewable energy—despite the country’s vast solar, wind, and hydropower resources. Indeed, although hydropower had long provided a substantial share of Chile’s electricity, by the early 2000s, electricity produced from fossil fuels (coal, oil, and natural gas) accounted for the majority of generation.¹⁴⁵ Protests over several large hydropower projects and growing concerns over climate change led to a renewed focus on so-called non-conventional renewable energy (wind, solar, biofuels, and geothermal).¹⁴⁶ In 2008, the Government adopted a new Law of Renewable Energy, which it amended in 2013 and further amplified in 2015 as part of a broader energy policy agenda for 2050.¹⁴⁷ In essence, these laws established a new framework for renewable energy built around quotas for distribution companies and public and private auctions for long-term power purchase agreements.¹⁴⁸ The overall effect was substantial growth in Chile’s renewable energy, particularly solar energy, up through the early 2020s.¹⁴⁹ By 2023, however, the system was in crisis, with multiple renewables developers canceling contracts or exiting projects because of insufficient revenues.¹⁵⁰ Several factors contributed to the crisis, including the general inflation and supply chain constraints that affected the renewables industry everywhere. But much of this was also a product of the increasing dysfunction of the Chilean electricity market, given the imbalances created by the retail price freeze despite rising wholesale costs, a lack of transmission capacity that has led to increased congestion and curtailments of renewables, and the inability of the electricity auctions to deliver sufficient revenues to renewables projects—all of which has led to a growing chorus of calls for bailouts in the short term and a fundamental redesign of Chile’s electricity markets over the longer term.¹⁵¹

2. UK

While Chile was the first country to move toward privatizing and liberalizing its electricity sector, the UK launched the first truly comprehensive experiment and was arguably the most influential.¹⁵² During the second half of the 1980s, Margaret Thatcher’s government worked to open up the UK electricity sector as part of a broader effort to reform the energy sector.¹⁵³ The goal was to privatize formerly state-owned enterprises and to unbundle generation from transmission and distribution in order to create competitive markets for wholesale electricity. It was, as one observer put it, “[t]he biggest and most radical project” of all in the Thatcher government’s efforts to “roll back the state” and remake the British economy.¹⁵⁴

As in many European countries, electricity supply in the United Kingdom had been provided through state-owned monopolies for most of the post-WWII period.¹⁵⁵ Throughout this time, there was a general consensus across the political spectrum that electricity was a strategic sector and that state ownership was in the national interest.¹⁵⁶ Electricity was also viewed as part of an overall package of public services that played a prominent role in the British welfare state.¹⁵⁷ Over time, coal fired electricity came to dominate the system, in part because of the power of the coal mining unions.¹⁵⁸ But the state-owned Central Electricity Generating Board (“CEGB”) also built and operated nuclear plants and maintained a large in-house engineering program.¹⁵⁹ The whole set up was boring, dull, and gray—overbuilt in places and overly reliant on coal in the eyes of some—but it was a public system that provided reliable and affordable electricity to everyone.¹⁶⁰

Debates over the performance and proper management of the state-owned industries occurred throughout the 1960s, culminating in a 1967 government White Paper that set specific economic performance targets and adopted marginal cost pricing as official policy.¹⁶¹ Over the next decade, a series of assessments pointed with increasing urgency to the inefficiencies of state-owned enterprises and the need for reform as the UK sought to navigate the economic crisis of the 1970s and a challenging macroeconomic environment.¹⁶²

In 1979, the incoming Thatcher government signaled a shift in approach, and over the next decade pursued a deliberate strategy to privatize and liberalize natural gas and electricity as part of its broader privatization effort.¹⁶³ Nigel Lawson was put in charge of energy and much of the original vision that motivated the effort was summed up by his quip that “the business of Government is not the government of business.”¹⁶⁴ In an important 1982 speech on energy, Lawson indicated in no uncertain terms where the conservatives were going:

I do not see the government’s task as being to try and plan the future shape of energy production and consumption. It is not even primarily to try to balance UK demand and supply for energy. Our task is rather to set a framework which will ensure that the market operates in the energy sector with a minimum of distortion and energy is produced and consumed efficiently.¹⁶⁵

Lawson turned to a small group of free market economists inside and outside the government to lead the effort.¹⁶⁶ Chief among them was Stephen Littlechild, an economics professor at Birmingham University and devoted follower of Friedrich Hayek and Austrian economics.¹⁶⁷ Littlechild was also quite familiar with principles of marginal cost pricing; his 1969 Ph.D. dissertation used linear programming and game theory to investigate marginal cost pricing in regulated and state-owned industries.¹⁶⁸ Over the next two decades, Littlechild emerged as an outspoken critic of the failures of state ownership and planning.¹⁶⁹ In 1981, he published a manifesto on “denationalization” urging the Thatcher government to complete the task of privatization that it had begun.¹⁷⁰ “[T]he real task,” he noted, “is not to control the industries but to control the government itself.”¹⁷¹ And the way to do that was to sell off as many of the state-owned industries as possible and subject them to market forces.¹⁷² “What the Post Office needs,” he argued, “is an imaginative asset stripper.”¹⁷³

During the second half of the 1980s, Littlechild and his colleagues worked to develop and pursue a comprehensive overhaul of the electricity industry built around privatization, unbundling, and market competition.¹⁷⁴ A 1988 government White Paper, Privatizing Electricity, provided the basic blueprint that was then incorporated into legislation the following year.¹⁷⁵ Although it did not go as far as Littlechild hoped, the new law was quite a radical departure from the past. The old Central Electricity Generating Board would be divided into two private generating companies (National Power and PowerGen), a separate transmission company (National Grid), and a group of twelve regional distribution companies that would together own the holding company that governed National Grid.¹⁷⁶ The two new private generating companies, National Power and PowerGen, together controlled close to 80% of the generating capacity of the country, leading some to worry (correctly) that any new market would be subject to significant market power.¹⁷⁷ The reason for sticking with two large companies was because the government had hoped that the larger of the two would be able to take ownership of the country’s nuclear power plants and that the other company needed to be sufficiently large to compete.¹⁷⁸ When the government decided that nuclear was too risky and too expensive to put in the mix, it was apparently too late to go back and create more private generating companies.¹⁷⁹ In effect, the government assumed that the lure of large profits would quickly take care of the problem by encouraging entry, particularly of new combined-cycle natural gas plants.¹⁸⁰ As long as these markets were contestable, in other words, any problems of market power would be short lived.

Thatcher, of course, also recognized that privatization and liberalization of electricity markets gave her a tool to discipline labor and, specifically, to break the powerful coal mining unions’ grip on the national economy.¹⁸¹ Privatization and the so-called dash-for-gas after the discovery of large natural gas fields in the North Sea operated in this respect as a proxy in a larger fight between capital and labor with the state coming down firmly on the side of capital.¹⁸² To that end, neoliberal electricity proved to be singularly effective, decimating the coal mining labor force as new combined-cycle gas-fired generation replaced older coal burning plants.¹⁸³ By 1990, the number of coal miners had fallen from nearly 200,000 in 1985 to about 70,000.¹⁸⁴ Eight years later, the total stood at less than 10,000.¹⁸⁵

In an effort to ensure marginal cost pricing, the UK market design also established a new mandatory Electricity Pool that would operate as a centralized day-ahead market (priced on half-hour increments) that would determine the merit order for dispatching generation and the wholesale spot price of electricity.¹⁸⁶ The Pool used the basic single-clearing price auction format with the last increment of generation needed to meet load setting the System Marginal Price.¹⁸⁷ The basic approach (and software) used to rank generators as a basis for economic dispatch was the same as had been used previously by the CEGB, except that the generators were now free to submit bids made up of various “price components” as opposed to actual cost information.¹⁸⁸

From the beginning, however, the Pool struggled with problems of market power.¹⁸⁹ With two big generators controlling the vast majority of generating capacity, clearing prices tended to be much higher than marginal cost pricing would suggest.¹⁹⁰ According to one early study, the proponents of privatization had “seriously underestimated” the exercise of market power in the Pool and the impacts on consumers.¹⁹¹ Thus, over the first three years of the Pool, annual average Pool prices increased by more than 30% in real terms, even as fuel prices declined and the country struggled through a recession.¹⁹²

None of this should have been surprising. The basic design of the Pool allowed two generating companies controlling close to 80% of generation capacity and almost all of the price-setting marginal plants to participate in a new market for electricity based on software that they were intimately familiar with.¹⁹³ Instead of using objective facts about the costs of their various generation units to establish the system marginal cost and merit order for dispatch, they were now free to submit prices based on a complex set of factors that were not tied to costs in any transparent or objective way.¹⁹⁴

To be sure, the new generating companies did have incentives to improve performance, something they delivered on with great success.¹⁹⁵ The problem, however, was that the gains in performance were captured as profits for the generating companies rather than as lower costs for consumers.¹⁹⁶ One study from 1997 found, in fact, that despite the improvements in efficiency UK consumers were worse off than they would have been under the old CEGB regime.¹⁹⁷

The new electricity market, in short, was not a contestable market.¹⁹⁸ Even when entry did materialize, moreover, the single-price auction combined with the complexity of price formation provided ample opportunities for the incumbents to exercise market power across a range of different strategies.¹⁹⁹ Put crudely, asset stripping had succeeded in creating exceptional profit opportunities for the new private electricity companies, while delivering little if any value to customers.

During the 1990s, as their profits soared, the new private electricity companies collectively laid off roughly half of their workforce while bestowing massive dividends on their shareholders.²⁰⁰ With a capital markets environment that was increasingly conducive to corporate acquisitions, the prospect of large profits was not lost on outsiders. Starting in the mid 1990s, various foreign companies, first from America and then from France and Germany, began buying assets and companies to gain a foothold in the lucrative UK electricity market. Politicians and regulators stood by and watched (they “simply let it happen,” as Dieter Helm observed), without thinking through the long-term implications.²⁰¹

Meanwhile the government had become thoroughly disenchanted with the single-clearing price design of the Pool in the face of persistently high wholesale prices, publishing an extensive set of reviews in 1998 and announcing that the Pool would be replaced with the so-called New Electricity Trading Arrangements (“NETA”).²⁰² After several years of work, NETA went live in 2001 and was built around a system of decentralized bilateral contracting, an auction-based market for short-term balancing that would be based on a discriminatory “pay-as-bid” format rather than the single- or uniform- clearing price design of the Pool, and heavier reliance on financial instruments for hedging.²⁰³ In many ways, NETA turned out to be even more complex than the Pool and, if anything, pushed companies to further consolidate and, where possible, integrate backwards and forwards in order to hedge against the additional uncertainty.²⁰⁴

By the mid-2000s, then, fifteen years into the experiment with privatization, the UK electricity sector was dominated by large, vertically integrated firms, many of them foreign owned (and some state owned).²⁰⁵ Indeed, one of the great ironies of the UK experiment is that the buyers of many of the formerly state-owned power sector assets were large state-owned enterprises from the continent such as Électricité de France.²⁰⁶ Without question, this was not the result that Margaret Thatcher and her lieutenants imagined when they embarked on privatization in the 1980s. In less than a generation, the UK had transferred a large part of its vital infrastructure, and along with it the right to tax the British public for the use of that infrastructure, to a wholly owned subsidiary of the French government.²⁰⁷

Perhaps even more concerning was the fact that the new markets did not seem to be creating sufficient incentives for new investment, especially in renewables. In response, the Government launched another Electricity Market Reform (“EMR”) package in 2013 with the goal of ensuring security of supply and ramping up support for renewables.²⁰⁸ On security of supply, the EMR provided for new capacity payments that would be paid for firm generation, following the pattern in most electricity markets of establishing new capacity remuneration mechanisms to address underinvestment.²⁰⁹ On renewables, the EMR created a new government-owned entity, the Low Carbon Contracts Company, that would enter into fifteen-year contracts with renewables projects.²¹⁰ These new contracts would be based on a “contracts for difference” price term that made the renewables projects indifferent to prevailing market prices.²¹¹ This was deemed essential to providing the long-term predictability needed to drive investment in renewables.²¹² In effect, renewable energy projects were now operating entirely outside of the formal electricity market and enjoyed the benefit of the state as a counterparty for long-term contracts with guaranteed prices.²¹³

Although the EMR represented a retreat from markets as an instrument for achieving the UK’s ambitious and legally binding decarbonization targets, it left the struggling retail electricity sector largely untouched. Under the UK’s approach to liberalized electricity markets, retail competition in electricity had been phased in over the course of the 1990s, with the residential market opened to competition in 1998.²¹⁴ By the 2010s, however, it was clear that most residential customers were not actively engaged in choosing their retail providers, that the retail supplier market was highly concentrated, and that poor and vulnerable customers had fewer choices and typically paid more than wealthier customers.²¹⁵ An investigation by the Competition and Markets Authority in 2016, for example, found that the concentrated retail electricity sector (dominated by the so-called Big Six) combined with widespread customer disengagement led to excessive prices and reduced quality of service.²¹⁶ Customers on prepayment meters (around 15% of all electricity customers by 2015) also paid higher prices than those on standard tariffs.²¹⁷ As wholesale prices continued to rise throughout the 2010s, more and more customers ended up behind on their bills, many of whom were placed on prepayment meters, often installed without their consent.²¹⁸ By 2018, the government regulator Ofgem reported that there were 4.4 million residential electricity customers on prepayment meters across the UK and that the cheapest prepayment plans were “significantly more expensive” than the standard plans based on credit (where customers are billed for their use after the fact).²¹⁹

Thus, by the time of the Russian invasion of Ukraine in early 2022, the system was already in crisis, with millions of customers behind on their bills and millions more on prepayment meters struggling to keep the lights on.²²⁰ Chronic underinvestment after years of asset sweating combined with financial engineering attached to dubious takeovers had left the system exhausted and unable to deliver affordable, reliable electricity. As prices spiked to unimaginable levels in the second half of 2022 (after steadily rising for more than a decade), the public backlash forced a succession of Conservative governments to take extraordinary measures to protect households and launch yet another effort to reform the electricity market.²²¹ For the first time in a generation, grassroots campaigns such as Don’t Pay UK focused directly on the cost of energy and its place in a broader cost-of-living crisis, underscoring the failure of neoliberal electricity to deliver stable and affordable electricity for the public.

3. California and the U.S.

A decade after the Thatcher Government launched their efforts to privatize the UK electricity sector, California took the lead in the United States to restructure and liberalize electricity under Republican Governor Pete Wilson, who was eager to prove his pro-market bona fides as he prepared for a possible Presidential run.²²² Reacting to a growing chorus of concerns about California’s deteriorating “business climate,” Wilson was apparently intrigued by the idea of unleashing the forces of competition to reduce the price of electricity in a state that had some of the highest prices in the country.²²³ These high prices stemmed in part from excessive spending by utilities, including on some very expensive nuclear power plants, but they also reflected California’s decision to mandate generous long-term contracts for renewable power under PURPA, which in turn provided a crucial basis for the development of the wind industry in California and beyond.²²⁴

In the mid-1990s, Wilson appointed UC Davis Law Professor Daniel Fessler as President of the state Public Utilities Commission and charged him with leading the effort.²²⁵ Fessler, who had no background or experience in electricity, was a committed free marketeer and an unabashed anglophile.²²⁶ After a trip to the UK as part of a delegation of electricity industry leaders and regulators from California, during which they met with Lawson, Littlechild, and Margaret Thatcher, Fessler came back committed to the idea of harnessing the price system to create a new market for electricity in the Golden State.²²⁷ All of which found support from longstanding proponents of deregulation and a growing push by economists to embrace markets for electric power.²²⁸

The California Public Utilities Commission (“CPUC”) took the lead, issuing background documents and instituting a proceeding to develop a blueprint for deregulation.²²⁹ Not to be outdone, the California legislature passed new legislation (A.B. 1890) in 1996 that established the basic legal framework for deregulation.²³⁰ Under the legislation, the state’s three large IOUs would divest 50% of their fossil fuel generation and would receive payments for their remaining stranded costs.²³¹ Going forward, they were prohibited from signing long-term contracts for power and forced to buy all of their power needs in the state’s new spot market for electricity.²³² Retail electricity rates were also reduced by 10% and frozen for four years or until the utilities had recovered their stranded costs.²³³

Contrary to what some might have expected, the incumbent utilities initially favored restructuring, presumably because they would be free to play a more active role in deregulated electricity markets in the U.S. and abroad and because of the generous treatment they received for their stranded assets and divested generation.²³⁴ Traders such as Enron, of course, were also heavily in favor of restructuring and saw the California market as an opportunity to further dominate the emerging markets for electricity and natural gas across the United States.²³⁵ The state’s large industrial and agricultural customers always weighed strongly in favor of restructuring.²³⁶

The basic market design was similar to the Pool in the UK. A new FERC regulated entity, the California Power Exchange (“Cal PX”), would run the wholesale day-ahead spot market, while the California Independent System Operator (“CAISO”) would manage the real-time and ancillary services markets to ensure overall system reliability.²³⁷ As noted, Robert Wilson was one of the key architects of the new markets, all of which used the single-clearing price design.²³⁸

The market went live in 1998 and for the first couple of years it functioned without major problems.²³⁹ Starting in the summer of 2000, however, prices in the spot market increased by more than 1,000% and continued at very high levels into the next year.²⁴⁰ Because of the retail rate freeze, however, the utilities could not pass along their higher costs and there was no real demand response. And without long-term contracts, they were unable to hedge their exposure to spot market prices. Forced to buy high and sell low, the utilities faced deepening credit problems. Pacific Gas & Electric (“PG&E”), the state’s largest utility, filed for bankruptcy in April 2001 and Southern California Edison was forced into quasi-receivership with the state’s PUC. Rolling blackouts were common, while manipulation of gas and electricity markets reached “epidemic” levels according to FERC.²⁴¹ Overall, Californians paid an estimated $40 billion in excess energy costs during the crisis.²⁴² Litigation to recover these costs is ongoing, more than twenty years later.²⁴³

Most explanations for the crisis have highlighted bad market design, a naive and ineffective federal regulator, and widespread gaming and manipulation by traders such as Enron.²⁴⁴ All of that in combination with hot and dry conditions across the western United States, which cut back on imports of power into California, and a general lack of new generation capacity in the state, made for a perfect storm of market dysfunction.

But a big part of that market dysfunction also stemmed from the widespread exercise of market power by new merchant generators who withheld generation during crucial periods of scarcity, allowing them to drive the single-clearing price to very high levels.²⁴⁵ Under the original restructuring plan, when the IOUs divested the bulk of their generation capacity, five main companies each ended up with between six and eight percent of total generation capacity.²⁴⁶ While that might not sound like much, during periods of peak demand, when essentially all of the available generation capacity was needed to meet load, these generators could wield enormous influence over the clearing price by simply withholding marginal generating units.²⁴⁷ Here again, an overreliance on the theory of contestable markets, combined with the failure to recognize the intense gaming that the single-clearing price design created, led to major problems.²⁴⁸

In the wake of the California crisis, other states that had been actively pursuing deregulation pulled back, leaving the U.S. with a fragmented regulatory landscape with three major regulatory models in use across the country.²⁴⁹ Nevertheless, the basic model of wholesale electricity markets that was first attempted in California has survived with various adjustments.²⁵⁰ Today, about two-thirds of U.S. electricity consumers receive their power through organized wholesale power markets run by Independent System Operators (“ISOs”) or Regional Transmission Organizations (“RTOs”), although some of these markets, such as the Midcontinent Independent System Operator (“MISO”) and the Southwest Power Pool (“SPP”), are still dominated by vertically integrated utilities that self-schedule the bulk of their generation resources through the markets.

4. A Global Project?

Notwithstanding the failures of these early experiments in Chile, the UK, and California, electricity liberalization spread around the world during the 1990s and 2000s, from Australia and New Zealand to Scandinavia, South Africa, and Turkey.²⁵¹ In perhaps the biggest experiment of all, moreover, the EU succeeded after almost two decades of work in establishing a single electricity market for the region starting in the late 2010s.²⁵²

Like other examples of “fast policy” that have become common features of neoliberal globalization, electricity market reform was pushed by a network of academics, experts, consultants, and corporate actors eager to move into new markets.²⁵³ Leading theorists proposed a standard set of “textbook” reforms that, if followed, would deliver competitive wholesale markets and unleash vast gains for energy consumers.²⁵⁴ The World Bank, along with other development institutions, also pushed power sector reform, sometimes as a condition for loans, as part of a broader effort to get countries in the global south to open up their economies to outside investment.²⁵⁵

The overall success of this effort has been mixed at best. While performance and efficiency have improved in some cases, the savings appear to have been captured largely if not entirely by private companies rather than customers.²⁵⁶ Investment in new capacity has also failed to keep pace with demand, leading to limited reserve capacity in some markets. Poor customers have also been relegated to an inferior status, often stuck with higher cost, strict prepayment plans.²⁵⁷ And many (if not most) of these markets have struggled in the face of extreme price shocks, in part because of their reliance on the single-price auction design. All of which has led to a growing chorus of calls for an overhaul of the existing market arrangements, especially in the face of the increasing urgency of decarbonization. As noted, reform efforts are underway in the UK and the EU as well as in Australia, and at least one sitting FERC commissioner and various state regulators are actively pushing market reform in the United States.

D. Inversions

The overarching goal of neoliberal electricity was to subordinate electricity to the magic of the price system. Rather than use prices as tools to drive particular types of investment across the system based on established objectives, the neoliberals believed that an unfettered price mechanism would deliver the system people actually wanted. It was, in essence, an inversion of the relationship between infrastructure and the price system that earlier state-owned and regulated systems had embraced, where rates were set at a level sufficient to recover long-term average costs in order to pay for ongoing investment.

The engineers that built these earlier systems understood that different generating technologies with different characteristics and cost structures allowed them to play different roles in the overall system, and that the system had to be planned accordingly. Prices or rates could be used as tools to drive particular investments and shape load in a manner that would deliver the right mix of assets.

The neoliberals, by contrast, did not seem to care as much about specific technologies or cost structures. In their view, the market would sort all of that out. Neoliberals in fact often took pride in being agnostic about technologies and fuel sources, embracing the mythical notion that market arrangements could somehow be designed to operate in a neutral manner.²⁵⁸ The result was a system built around short-term spot markets that created incentives to sweat assets without any sense of how all the pieces fit together.

The new electricity markets also moved decisively away from any sort of redistributive goals. Previous commitments to the idea that electricity was a primary social good or a key system of provisioning in service to the public interest was anathema to the neoliberal vision. With marginal cost pricing, existing cross subsidies were more visible and became much easier to attack. Although never fully realized, the goal of sending real-time price signals to individual consumers endeavored to demolish the idea that electricity should be viewed as a collective undertaking. In the world of neoliberal electricity, everyone would have to pay their own way.

In the wake of multiple crises and market meltdowns, the proponents of neoliberal electricity have sometimes claimed that the real problem has always been the distortions introduced by politics and regulation, as if somehow the design of new markets could be kept pure as it worked its way through the political process.²⁵⁹ But, of course, there is no basis for ever concluding that market design can be fully insulated from politics and it is naïve and disingenuous—especially coming from those who accept and celebrate the basic insights of public choice theory—to expect that rent seeking behavior either does not apply or can somehow be controlled in the complex and all too often highly opaque world of market design.²⁶⁰

II. MARKET CRISES AND STRUGGLES OVER PRICE MAKING

The early 2020s have been brutal for electricity markets. Coming out of the pandemic, markets were already strained by supply chain problems, especially in natural gas. With the Russian invasion of Ukraine, those stresses became extreme as natural gas prices in Europe and the UK spiked to unimaginable levels, up more than 800% at the peak of the crisis.²⁶¹ These extreme price shocks rippled around the world and led to a structural realignment of global gas markets, with U.S. suppliers reaping extraordinary profits.²⁶²

Extreme prices for natural gas translated into very high prices for electricity, particularly in markets built around the single-price auction given that natural gas generation was on the margin setting the price. As consumers and government officials saw this play out in real time, they began asking why low-cost, non-gas generators should be receiving the same price as gas generators when their costs had not changed, triggering deep intuitions about just or fair pricing.²⁶³ As European Commission President Ursula van der Leyen observed, it was clear to everyone that these markets were “no longer doing justice to consumers anymore.”²⁶⁴ In response, those governments with sufficient fiscal capacity took emergency measures to protect households from price shocks and launched a series of longer-term market reform efforts.²⁶⁵ In some cases, such as Australia, authorities were forced to suspend operation of the electricity market entirely.²⁶⁶

What is remarkable about these recent price shocks is that the specific ways of price making operating at the heart of these markets have been made visible to policymakers and publics seemingly for the first time. Instead of simply accepting prices as facts that emerge from markets, the recent crisis has revealed that prices are, as Robert Lee Hale and others emphasized many years ago, relationships, and that those relationships can sometimes be coercive.²⁶⁷ Viewed in this way, prices and the ways of price making that generate them are never simply facts or technical artefacts, but rather ongoing objects of struggle.²⁶⁸

Understanding how these struggles are playing out and the stakes involved requires getting into the details of these markets and the main problems they have confronted since their inception. This Part focuses on four such problems: the pervasive nature of market power, security of supply, price rationing, and decarbonization. Versions of these problems have emerged in virtually all of the electricity markets and have sometimes become acute during moments of crisis. Governments have responded in various ways, all too often adopting piecemeal, ad hoc reforms that tend to operate more as palliative short-term measures rather than as long-term structural solutions. Absent a major overhaul of the basic structure of these markets, these problems will not be resolved. They are, in effect, embedded in the logic of neoliberal electricity and the distinctive ways of price making that allow these markets to function.

A. Market Power

Market power has been a significant and persistent problem in virtually all restructured electricity markets.²⁶⁹ The assumption that these markets would be contestable once barriers to entry had been removed proved to be overly optimistic and insufficiently attentive to the special challenges facing electricity markets, especially during periods of peak demand.²⁷⁰ This has resulted in substantial wealth transfers from consumers to producers.²⁷¹

The single-price auction exacerbates the problem of market power for the simple reason that it endows the market clearing price with special significance.²⁷² When generation capacity is constrained and scarcity pricing prevails, the prospect of windfall profits for inframarginal generators improves dramatically because of the single-price design. This is one reason why these clearing prices become objects of gaming and manipulation by traders and financial institutions.²⁷³ It is also why wholesale generators have employed various strategies to drive clearing prices higher, such as withholding particular generating units during periods of scarcity.²⁷⁴ This was, as noted, a particular problem during the early years of the UK Pool as well as during the California crisis, and it can be very difficult to police against.²⁷⁵

Regulators around the world have generally approached the problem of market power in electricity markets through various ex ante mitigation measures, ongoing monitoring and investigation, and ex post enforcement.²⁷⁶ Typically, the U.S. market operators have taken an ex ante approach, adopting various structure- and conduct-based approaches that seek to prevent the exercise of market power.²⁷⁷ The UK, Australian, and EU markets, in contrast, have adopted a more ex post approach.²⁷⁸ The overall trend seems to be toward more elaborate approaches based on a growing recognition that the standard antitrust approach to market structure does not work for electricity markets given their distinctive characteristics.

The evolution of the U.S. approach to market power mitigation is instructive in this regard. In the early years of restructuring, FERC essentially imported the basic approach to market power that it had been using in experiments with so-called market-based rates for bilateral sales of electricity in the late 1980s and early 1990s.²⁷⁹ Drawing on antitrust conceptions of market structure, the Commission developed ex ante screens to determine whether a firm possessed market power.²⁸⁰ If the firm passed these screens, the Commission would grant it market-based rate authority—that is, the authority to go out into the market and sell power at market-based rates rather than on the basis of pre-approved tariffs.²⁸¹ Various appellate decisions held that FERC’s market-based rate program was consistent with the Federal Power Act, on the theory that competition would provide the discipline needed to ensure that rates (prices) would be just and reasonable.²⁸² Notably, the Supreme Court has never addressed the question of whether market-based rates are consistent with the Federal Power Act.²⁸³

While the system of market-based rates was designed for a world of bilateral contracts, it took on additional importance with the move to restructure wholesale markets in the late 1990s and early 2000s.²⁸⁴ Merchant generators and electricity traders such as Enron were all required to secure market-based rate authority before they could participate in the new wholesale power auctions.²⁸⁵ Needless to say, FERC’s general assumption that this would ensure that these markets would be competitive proved to be mistaken.²⁸⁶

Over time, the RTO and ISO markets themselves have also adopted increasingly elaborate mechanisms to mitigate and remedy the exercise of market power. These include automatic “structural” approaches, where the offer prices of large generators deemed to have potential market power are automatically replaced with default reference prices, as well as behavioral approaches (sometimes called conduct and impact approaches), where the market monitor reviews and replaces offer prices found to be non-competitive with default reference prices.²⁸⁷ FERC also has substantial civil penalty authority that it can use to enforce against market manipulation and conduct that produces prices that are unjust and unreasonable.²⁸⁸

In contrast to the U.S. approach, other markets around the world have taken a less proactive approach to market power and tend to rely more on ex post monitoring and enforcement as well as referrals to competition authorities.²⁸⁹ In some cases, such as the UK in the late 1990s, this led to a new round of mandatory divestments by large generators as well as various market reform initiatives.²⁹⁰ In others, it led to prohibitions on certain acquisitions and ongoing investigations.²⁹¹

The bottom line here is that restructured electricity markets have never been sufficiently contestable to control the exercise of market power. Given the capital intensity of new generation combined with long lead times and general uncertainty regarding consistent dispatch in the markets (uncertainty that increases as the share of intermittent, non-dispatchable generation increases), there are significant barriers to entry and exit that undermine contestability. And because privatization and restructuring often failed to create a sufficiently competitive market structure at the outset, in part because of an overreliance on the theory of contestable markets, the problem of market power has turned out to be pervasive.²⁹² In electricity, as many observers have noted, extreme inelasticity of demand combined with the lack of storage and the need to balance the system in real time creates opportunities for individual firms with limited market share to set prices above marginal costs.

These problems with market power have been borne out repeatedly in the experience of electricity markets, particularly during periods of scarcity. Indeed, because scarcity pricing delivers very large rents to inframarginal generators, incumbent generators have a strong incentive to maintain the system as close to the edge as possible. When compounded by larger structural crises or extreme events, the basic mechanism of scarcity pricing in these markets can result in extremely high prices and very large windfalls for inframarginal generators. During the recent price shocks in Europe, for example, one scholar estimated that non-gas generators received some 400 billion EURs in windfall profits as a result of the very high clearing prices for natural gas generators.²⁹³ To mitigate this, EU member states considered several responses, including windfall taxes on generator profits, a new lower reference price for natural gas that would set the marginal electricity price, and permission to member states to introduce price caps for inframarginal generators.²⁹⁴

But it would be a mistake to conclude that market power only exists during periods of scarcity and that short-term measures directed at limiting or clawing back some of the windfalls constitutes an adequate response . In fact, experience in the UK and recent studies investigating market power in the United States indicate that price markups have been far more pervasive across time, even as costs have declined, and that these price markups affect both short-term auctions and the long-term bilateral contracts that are increasingly common in all of these markets.²⁹⁵ Moreover, it is also important to recognize that most of the generators and traders in most of the markets actually have very specific, detailed information on the cost structures all of the other generators in the market as well as a very good understanding of overall demand and system constraints.²⁹⁶ Needless to say, this complicates the Hayekian premise that these markets are necessary to aggregate knowledge from a diffuse set of actors, much less that there is sufficient competition to allow prices to play their proper coordinating function.

B. Security of Supply

Notwithstanding the pervasive fact of market power (and the additional profits that accrue to those with market power), all of these markets have also struggled to produce sufficient incentives for new investment. This might seem paradoxical if there are in fact substantial rents available in these markets for generators able to exercise market power. Part of this goes back to the challenges of entry (and exit) in these markets—the capital intensity of new generation, the long lead times, the volatility of spot market prices, and regulatory uncertainty—all of which have worked against contestability. Part of it also likely stems from specific mechanisms, such as price caps, that have been adopted by market operators to mitigate against market power and protect consumers. This has created what some economists have referred to as a “missing money” problem in the markets, which refers to the limits on inframarginal rents available during periods of scarcity that, if available to inframarginal generators, would in theory be sufficient to encourage new investment.²⁹⁷ More generally, the entire purpose of privatization and restructuring was to correct for the overbuilding that was supposedly endemic under state-owned and regulated cost-of-service systems. In fact, the new electricity markets have never been oriented toward promoting investment, but rather were focused from the start on “sweating” existing assets.²⁹⁸ The whole point of shifting the risk of investment from ratepayers to investors was to mitigate against overinvestment and waste and improve performance of existing assets, something that the markets have clearly delivered upon.²⁹⁹

The irony (and the tragedy) here is that underinvestment is actually a much more serious problem than overinvestment when it comes to systems of provisioning for necessities. When electricity grids do not have sufficient reserve capacity to meet peak demand, significant disruptions can result. These problems can become acute during extreme events, with very serious consequences. During Winter Storm Uri in Texas, when temperatures in South Texas were lower than they were in Alaska in February, close to half of the state’s generation capacity was offline because of a lack of investment in winterization and insufficient reserve capacity.³⁰⁰ This was true across all sources of generation, and the system came very close to total collapse as a result.³⁰¹ More than two hundred people died during that crisis.³⁰²

To be sure, market regulators have long recognized the problem of underinvestment and have gone to great lengths to encourage new investment.³⁰³ The so-called missing money problem has been a near constant refrain among market boosters.³⁰⁴ This has led to all manner of contrivances such as capacity markets, capacity payments, reliability must-run contracts, and outright mandates and subsidies for new generation. While some of these efforts have succeeded in driving new investment, it would be hard to describe the current mix of policies and programs to promote investment in new capacity as rational or well designed. Much of it in fact looks like bad cost-of-service regulation that has created ample opportunities for new rent seeking behavior.³⁰⁵

The larger lesson here is that an overbuilt system is actually much better for consumers than a system that is slightly underbuilt or even one that is operating right on the edge of full capacity. When it comes to vital infrastructure, asset sweating is generally not a good strategy. And even if there was a time when asset sweating made sense for the electricity sector, this is decidedly not the case today as the sector enters a new phase of substantial investment.

C. Price Rationing

The neoliberal vision of competitive electricity markets depended ultimately upon the ability to transmit real-time prices in the wholesale markets all the way through to consumers in the retail markets. If consumers could see and respond to the actual wholesale cost of electricity as it fluctuated in real time, they would be able to adjust their demand accordingly and the system would be optimized. This form of price rationing provided a way to manage load, as Boiteux and others recognized in the 1950s, and was the only way to fully realize the allocative efficiency that comes with marginal cost pricing.³⁰⁶

The problem is that most retail customers in most markets do not want to take service on these terms. When given the choice, most residential customers in most markets seem to prefer stable, flat rates as evidenced by the general lack of switching in retail markets that allow it.³⁰⁷ This is especially true for the elderly and others who spend a lot of time at home and have limited options for shifting their demand over time.³⁰⁸ To be sure, an increasing (but still quite small) number of residential retail customers in the U.S. and elsewhere have started to take service under a system of time-varying rates—an option that is much easier with new advanced metering infrastructure.³⁰⁹ And commercial and industrial customers have long opted for time-varying rates because of their sensitivity to costs and ability to shift load.³¹⁰ In some states such as California and Massachusetts, moreover, certain classes of residential customers are being defaulted into time-varying rates.³¹¹

There are a range of options here—from simple time-of-use block rates to various forms of peak pricing to fully-dynamic real-time pricing, and there is a large and growing literature evaluating the relative advantages of each.³¹² The catch is that the more closely retail prices track wholesale prices, the more volatile and unpredictable customers’ bills become. This is, of course, also the basis for the opportunities that such pricing programs entail—allowing customers to adjust their demand in response to price signals over the course of a day, month, or season. But the assumptions about consumer behavior that underwrite much of the thinking about these policies seem to be rather crude and unrealistic. How many people actually want to be energy day traders for a few dollars a day (at most)?

More importantly, dynamic retail pricing can also turn out to be a disaster when wholesale prices reach extreme levels. To take a rather dramatic recent example, in Texas during Winter Storm Uri, many of the customers who ended up with extremely high bills used a retail provider called Griddy to procure their power. For a monthly fee of $9.99, Griddy provided its customers with retail electricity at a price that mirrored the wholesale cost of electricity established by the auctions in the Texas electricity market.³¹³ As one of the purest forms of dynamic marginal cost pricing of electricity that one could find, Griddy sought to put into practice what Alfred Kahn and other proponents of marginal cost pricing had long sought—a system where supply and demand could mutually adjust based on real-time price signals.

In February 2021, however, the Texas grid was pushed to the breaking point and wholesale prices were allowed to rise to the market operator’s $9,000/MWh price cap for several days.³¹⁴ Given the arctic conditions across the state, of course, most customers had little choice but to keep using their electricity as long as it was available. This left thousands of customers facing astronomical bills and financial distress (one Griddy customer reported a bill of $16,752).³¹⁵ Griddy, of course, went out of business (after urging its customers to switch suppliers) and the government had to come to the rescue.³¹⁶ The Texas Public Utility Commission issued orders blocking retail providers from sending bills or disconnecting customers, while the Texas Legislature promptly banned the use of dynamic real-time pricing plans like the one offered by Griddy.³¹⁷ Some Texas politicians even called for federal relief for Texan’s utility bills.³¹⁸

Various commentators have also argued that real time pricing would have helped avert the California electricity crisis in 2000–01, given that the retail rate freeze instituted as part of the restructuring legislation undermined any possibility of demand response and forced utilities to buy high and sell low.³¹⁹ There is surely some truth to this, but it is difficult to gauge how much of a difference it would have made. In fact, widespread use of responsive pricing during the California crisis would likely have transferred the costs of market power and market manipulation to rate payers in the short term rather than over the longer term. And it would surely have hurt those most dependent on electricity, such as the elderly and the infirm.

The key lesson here is that an overreliance on responsive pricing for necessities can quickly become coercive during periods of great need, raising important political and ethical questions about the overall governance of key systems of provisioning. Even the proponents of responsive pricing have recognized this. As William Vickrey put it more than fifty years ago, “the main difficulty with responsive pricing is likely to be not mechanical or economic, but political. The medieval notion of the just price as an ethical norm, with its implication that the price of a commodity or service that is nominally in some sense the same and should not vary according to the circumstances of the moment, has a strong appeal even today.”³²⁰ Indeed it does.

But perhaps the most extreme manifestation of price rationing in electricity is the widespread use of prepayment meters that have been such a prominent part of retail electricity in the UK and other markets around the world over the last decade.³²¹ Retail providers, not surprisingly, strongly favor the use of prepayment meters precisely because they put responsibility on individual households and provide a means to extract additional fees from the poor.³²² Indeed, various government reports have found that customers on prepayment meters typically pay higher prices than those on standard tariffs and have fewer options to switch among providers.³²³ The widespread use of prepayment meters in the midst of the recent energy crisis, as noted, became one of the major points of contention for grassroots campaigns such as Don’t Pay UK.³²⁴

What seems to be increasingly clear from these developments is that many customers do not view electricity as a commodity. Rather, they (we) tend to view it as part of the basic infrastructure of everyday life and many of us prefer a stable, predictable monthly bill. This is especially true for older customers, low-income customers, and others who are confined to their homes because of illness or, say, a pandemic. So, while it may be true that more price-mediated demand response can make the power grid more responsive and help to balance supply and demand, we need to think long and hard about safeguards and protections during extreme events for certain classes of customers and should proceed carefully as we start defaulting customers into systems of variable rates as California, Massachusetts, and other states are doing.³²⁵ Prices for electricity, like the prices for other essential services, are more than just signals, and the ways in which we decide to make prices for these essential services (that is, the ways in which we design and use regulation and markets to generate prices) have serious implications for people and their ability to get on with their lives.

As we enter the age of electricity, moreover, price rationing makes even less sense than in the past. Going forward, we actually want people to use more electricity, not less; that is, we want them to replace their gas-fired cooking and heating and their internal combustion vehicles with electricity. That means we need to find ways to make electricity cheaper and more stable over time so that we can accelerate the process of decarbonization through electrification. Although well-designed time-varying rates clearly have an important role to play in shifting load and balancing the system as we ramp up electrification, it seems unlikely that most customers will be able to constantly adjust their demand in response to constantly changing price signals. Any viable decarbonization strategy will need to include rate designs that spread costs over time and across customers while ensuring access to affordable electricity for everyone.

D. Decarbonization

There has long been an implicit assumption in much of the energy policy literature that because wind and solar are now the cheapest sources of electricity generation, investment will inevitably flow to these technologies relative to others. Subsidies and supports have been and will continue to be important, the argument goes, but now that renewables have won the war on costs, markets are the best way to translate these cost advantages into deployment at scale. The rapid growth of renewables in general and solar energy in particular are often taken as evidence of this.

As Brett Christophers reminds us, however, this assumption rests on a basic misconception about how capitalism works.³²⁶ Simply put, capital flows not to the lowest cost option but to the one with the highest expected profits.³²⁷ This is part of the reason why large fossil fuel companies continue to invest heavily in fossil fuels rather than renewables. They simply cannot make the same profits in renewables that they make with fossil hydrocarbons.³²⁸ Thus, to assume that renewables will beat gas and coal just because they are cheaper is to ignore the all-important question of whether they are actually more profitable. Without question, cost and profit are sometimes aligned, but that is always an artefact of the system of price making that has been devised rather than some sort of natural fact about markets.

The assumption that low-cost renewables will beat fossil fuels simply because they are cheaper also ignores the distinctive cost structures and capital requirements of the new renewable energy technologies. Because renewables are essentially all capital costs and no variable costs, the cost of financing is all important.³²⁹ It is in the capital markets, therefore, that much of the future cost of renewable energy will be determined.³³⁰

The need for large upfront financing and stable revenues is also why, in virtually all electricity markets, renewable energy is almost always compensated through long-term contracts at fixed prices that make these projects largely indifferent to the prices that emerge from the spot markets.³³¹ Simply put, the inframarginal rents available in the electricity markets have not provided sufficiently reliable revenues to compensate new investment, leading governments to intervene in various ways. In the UK, as noted, since 2013 the government itself has stepped in to act as the counterparty on long-term renewables contracts precisely in order to promote investment and lower the cost of capital.³³² In the EU, member states are also moving toward a system of contracts-for-differences, building on their longstanding use of feed-in-tariffs and other mechanisms to de-risk investment in renewables.³³³ Other countries, including Brazil, Chile, Colombia, and Argentina have adopted similar approaches.³³⁴ And, in the United States, aggressive state Renewable Portfolio Standards, which were adopted initially to protect and promote renewables during the transition to restructured electricity markets, often mandate the use of long-term power purchase agreements, and virtually all renewable energy projects are financed on the basis of such long-term contracts.³³⁵ In important respects, this can be seen as a move back to a form of vertical integration—another sign that short-term spot markets cannot provide the compensation these resources require.³³⁶

Finally, the inability of organized the electricity markets to promote renewables becomes even more acute as the overall share of renewables increases. This is because in a single-price auction built around short-run marginal costs, large-scale presence of renewables will compress and ultimately destroy the clearing price.³³⁷ While this may be viewed as a positive development for those who want to accelerate the retirement of coal, gas, and even nuclear, it also makes it impossible for renewables (or storage for that matter) to receive sufficient compensation through these markets, which then simply reinforces the preference for other forms of long-term remuneration and support.³³⁸

III. DECOMMODIFYING ELECTRICITY

In 2022, for the first time, global investment in clean energy exceeded $1 trillion and matched, also for the first time, global investment in fossil hydrocarbons.³³⁹ Notwithstanding the headwinds of supply chain disruptions, higher interest rates, and geopolitical uncertainty, clean energy investment looks likely to continue growing and will soon be the main driver of global energy investment.³⁴⁰ While there is much to celebrate in these developments, the problem is that current investment levels are still only a fraction of what the world needs to hit its climate targets. In fact, the world needs to be investing at least $4 trillion dollars every year starting now to have a reasonable chance of hitting those targets.³⁴¹ And, needless to say, every dollar invested in new fossil fuel assets creates that much more inertia in a global energy system that is still dominated by fossil fuels.

The continuing shortfall in current levels of investment are often taken as evidence that we need additional interventions by governments to de-risk and turbocharge private sector investment. This was, in part, the thinking behind the Inflation Reduction Act (“IRA”), and it has become an article of faith for many policymakers around the world. The politics of these sorts of subsidies are, of course, much easier than interventions focused on imposing additional costs on emissions, whether through pricing mechanisms or direct regulation. As the EU and the UK ramp up their own subsidies for the green transition, moreover, the existing “rules-based” trading system is being challenged by a newfound faith in industrial policy. But while economists and others might bemoan the inefficiencies of a “subsidy race” among larger emitters, it is not at all clear that a system built around sticks rather than carrots could ever be sufficient to build whole new industries (much less survive politically).

If we focus specifically on the power sector, which, as noted, is the backbone of broader decarbonization efforts, there are two main challenges going forward: (1) how to substantially increase capital investment in clean energy assets and (2) how to ensure access, affordability, and security of supply. The first is an investment challenge and the second is a provisioning challenge. And these two challenges have to be addressed together. Put another way, if we solve the investment problem without also simultaneously solving the access and affordability problem, efforts to accelerate the electrification of everyday life will stall in the face of high prices. This will in turn undermine overall democratic support for the effort, which will then undercut the support for more investment.

As this Article has sought to demonstrate, electricity markets as currently designed cannot deliver on these goals. While the forty-plus year experiment with liberalized electricity markets may have been good at sweating assets, these markets are not capable of driving new investment in the sector at the scale and pace necessary to achieve decarbonization targets while also ensuring access and affordability. In important respects, and as documented above, the move away from markets is already underway. But the process has been largely ad hoc and piecemeal and too many continue to cling to the idea that existing market designs can be tweaked and adjusted to deal with the challenges they face.³⁴² While short-term balancing markets will continue to play an important role in electricity, it is past time to acknowledge the larger shortcomings of neoliberal electricity and embrace new institutional arrangements capable of driving massive new investment while expanding access and affordability.

There are three main components of this. First, instead of focusing on using competition between generators to discipline prices and maximize efficiency, we should focus on tools to secure a low cost of capital for the trillions of dollars of financing for zero emissions electricity generation, storage, and transmission infrastructure that is needed. This requires a fundamental shift in the relationship between capital and infrastructure that has marked the last forty years of neoliberal electricity. That means de-emphasizing competition and the price system to focus more on the best ways to channel large flows of low-cost capital into long-lived physical assets. Second, we need to explicitly embrace new forms of “social ratemaking” that depart from the principles of market pricing to support stable and affordable rates going forward.³⁴³ That will inevitably require new approaches to spreading different components of costs among and between different classes of customers, a task that is made more challenging by the ongoing adoption of distributed generation, distributed storage, and electric vehicles. Third, we need to rethink our approach to balancing—both on the bulk power supply side and on the demand side in favor of a more cooperative approach that recognizes the fact of intermittency and prioritizes arrangements to share reserve capacity and load management responsibilities as we transition to a renewables-dominated future.

A. Capital and Infrastructure

The old idea of public utility in the United States was built in part around efforts to devise a framework that could channel large amounts of capital into new infrastructure based on specific mechanisms of cost recovery. The objective was to make sure that the investments were prudent when made and that the investors would receive a fair return on their capital—a moving target that was tied to the more general conditions in the capital markets.³⁴⁴ Historians have documented that one of the reasons IOUs favored rate regulation through state PUCs was in order to secure a lower cost of capital, which the evidence suggests was at least partly realized.³⁴⁵

During the first three quarters of the twentieth century, this system succeeded in driving substantial capital investment in new infrastructure.³⁴⁶ As utilities built larger and larger plants together with extensive transmission and distribution systems, economies of scale translated into declining real prices for ratepayers. The concern, as noted, was overbuilding and overinvestment in the physical assets that constituted a utility’s rate base—a problem that was compounded by the threat of regulatory capture.³⁴⁷ By the 1970s, with economies of scale in thermal power generation exhausted and in the face of major increases in fuel prices and slowing demand, utilities and their regulators were suddenly confronted with a very different macroeconomic environment that entailed a significantly higher cost of capital.³⁴⁸ This was the beginning of the end of the so-called “public utility consensus,” and the emergence of a new emphasis on deregulation and markets that would go into high gear during the 1980s and 1990s.³⁴⁹

A big part of the move to markets, in fact, was premised on the idea that investment would be disciplined by the forces of competition and the price system rather than the judgments of regulators. Gold plating would be replaced by a focus on performance and efficiency. Assets would be squeezed and sweated, made to work harder, while the risk of new investment would be transferred from ratepayers to investors.

Today, however, the electricity sector is transitioning once again to a phase of high investment. Moreover, the dominant generating technologies and underlying cost structures that mark the current phase put even more of a premium on cost of capital than in the past. As the clean energy transition accelerates, the focus will once again need to be on institutional arrangements that can secure a low cost of capital for long-lived assets.³⁵⁰ Spreading those financing costs over a longer time frame and a larger customer base will in turn provide a critical part of the effort to ensure stable and affordable electricity for customers.

This requires patient capital willing to support high upfront investments in exchange for long-term, stable returns. Doing that, as noted above, means shifting our attention from the remuneration possible in the electricity markets to the capital markets and to the role of government in promoting capital investment in long-lived assets. In the United States, at least, there are three main options for doing this: (1) the use of tax credits and other subsidies to de-risk private investment in new assets; (2) public investment and public ownership of new assets; and (3) public utility regulation.

The big looming question in all of this is whether the new renewable energy and storage assets that will dominate our electricity systems in the future will be owned and managed by private owners intent on charging what the traffic will bear or whether they will be part of a broader collective project that includes diverse forms of public utility—from outright public ownership to various cooperative and community arrangements to a renewed effort to leverage public utility cost-of-service regulation to harness the power of private enterprise and direct it toward public ends.³⁵¹ For the last thirty years, the U.S. has made a very deliberate choice to pursue a privatized and financialized approach to renewable energy, with generous tax credits driving project finance structures that were dominated by banks and financial institutions. The IRA continues this trend, but it also begins to move away from the heavily financialized arrangements of the past through the direct pay and transferability provisions. While it is too early to tell how popular and effective these provisions will be, they do point up the importance of creating a system with a diversity of ownership structures for renewable power that maintain strong public and regulated components. Given the long lead times and financing challenges associated with renewables, especially under current market structures, there is a danger (and a growing body of supporting evidence) that large private equity firms, asset managers, and large clean energy multinationals are increasingly in a position to own the lion’s share of renewable energy generation. While this may be a welcome development for those who are eager to see more private capital flowing into clean energy, we should be careful to remember the painful lessons learned when unregulated private capital takes over vital infrastructure.

But there are alternatives, as Harold Hotelling made clear almost a century ago in his argument in favor of using taxes on land and wealth to pay for the fixed costs of new public infrastructure.³⁵² Although it seems unrealistic to expect full government financing for new infrastructure along the lines of what Hotelling and some contemporary proponents of the Big Green State have advocated for, it is still important to articulate the details of how these new public enterprises would be structured and governed—a task that requires attention not only to past experiences with state-owned enterprises, various public power projects, and municipal utilities, but also one that critically evaluates emerging approaches such as the UK’s Low Carbon Contract Company and similar efforts around the world. Government-backed financing arrangements can also provide cheap long-term capital to various forms of community and cooperative arrangements. And, of course, recent calls for a new public investment authority and efforts in various states to revive public ownership and control over clean energy assets could also serve as examples of a more robust public role in the clean energy transition.³⁵³

As for the IRA and the use of tax credits to de-risk private investment, the key question here is whether the public will get anything in return for the use of public money to drive investment in new assets and infrastructure or whether the new private renewable energy asset owners will capture the majority of the benefits of public support. As noted, the new direct pay provisions under the IRA could be used to support various forms of public ownership of renewable energy, but it seems unlikely that this will scale quickly.

A third option that offers a middle path between public ownership and the pure de-risking approach is U.S. style public utility regulation, which has long served to channel large amounts of low-cost capital into long-lived physical assets.³⁵⁴ Under this approach, public utilities are allowed a guaranteed rate of return on their prudent investments that covers their costs including the cost of capital. The certainty of cost recovery through rates has historically translated into a lower cost of capital. Moreover, under the basic model (which, to be sure, does not always work as intended), once the costs are recovered in rates and the assets are depreciated, they are no longer charging costs to the ratepayers beyond whatever it takes to keep them running, which is very little in the case of wind and solar. Critics will surely rehearse all of the problems and perverse incentives that are embedded in public utility regulation, all of which ultimately depend on how well regulators do their jobs. At the very least, though, it seems important to acknowledge the promise that public utility regulation holds for more public control over the direction of private capital investment and the mechanisms of cost recovery. This seems particularly important for renewable energy, which in many ways is a perfect fit for cost-of-service regulation given the fact that these projects are almost all capital costs, which should make financing and cost-recovery much more straightforward than traditional fossil fuel assets.

The key takeaway in all of this is that we have returned, it seems, to many of the fundamental questions regarding capital and infrastructure that Hotelling and others raised during the middle decades of the 20th century.³⁵⁵ In Hotelling’s view, the “general welfare,” as he called it, was best served when the fixed costs of infrastructure investments were paid from taxes on income, inheritances, and land, which would then allow the public to pay only the short-run marginal costs of using the asset, which in many cases was zero.³⁵⁶ In effect, Hotelling was arguing for using taxes on the wealthy to support public infrastructure, which promised to deliver enormous benefits to the public that far outweighed the costs imposed.³⁵⁷

In some ways, the IRA tax credit provisions could be read as a partial realization of Hotelling’s argument. Substantial tax revenues (albeit in the form of foregone taxes or so-called tax expenditures) are being used to build part of the infrastructure we need for the clean energy transition. The only problem is that we have allowed private financial institutions and large corporations to take the tax credits and own the assets. If anything, then, the current use of public money to de-risk private investment looks like a neoliberal inversion of Hotelling’s argument. In this view, it is a mistake to suggest that the ultimate ownership of the assets does not matter. As the great clean energy buildout proceeds, the critical question is how much rent these asset owners will be able to extract from the public for the use of those assets. Put another way, once these projects are paid off, the owners will continue to extract rents for the use of resources that are essentially free and have been partially financed by public expenditures in the form of tax credits. But only if we let them.

Hotelling, of course, was writing against the backdrop of massive government spending on infrastructure, particularly for large public power projects, and a concerted government effort through initiatives such as the Tennessee Valley Authority and the Rural Electrification Administration (among others) to ensure near-universal access to affordable electricity. To be sure, our world is quite different than the one Hotelling was writing about, but we are clearly at the beginning of another substantial buildout of new infrastructure, where questions of cost recovery, cost of capital, access, and affordability will be front and center. One of the major claims of this Article is that the market-based approach to electricity of the last forty years—that is, the effort to make electricity into a commodity—will not get the job done. Policymakers, market regulators, and even some economists have started to recognize this. But the question of what comes next is still unresolved, notwithstanding the strong tendencies pushing toward a financialized and privatized version of the clean energy future. While there is surely no one right way to decommodify electricity, in all cases it seems critical to think of the new assets being built (and, perhaps, the capital being invested in those assets) as part of a common infrastructure and key system of provisioning for basic needs. In this vision, renewable energy and storage, which will likely be the dominant sources of electricity in a decarbonized future, should be essentially free once the capital costs have been paid. And that should open up a range of possibilities for making electricity widely available at low and stable prices.³⁵⁸

B. Social Ratemaking

A fundamental commitment of Don’t Pay UK was that electricity is too important to be left to a system of markets and price rationing. Their demands for an end to prepayment meters and for a social tariff that would provide a stable, affordable rate structure for all customers reflected a view that electricity is a primary social good (an “essential service,” as Felix Frankfurter once put it) that needs to be made available to everyone on reasonable terms.³⁵⁹ This was, as noted, a basic commitment of many of the nationalized systems of the past, which, despite all of their problems, were directed at providing reliable and affordable electricity to everyone and often explicitly conceived as part of a broader redistributive welfare state.

In the U.S., the older regulated public utility model incorporated some of these commitments, but all too often fell short of the goal of universal access. Expansive federal support for rural electrification, regional experiments such as the Tennessee Valley Authority, and large public power projects were also based on strong public commitments to providing cheap and reliable electricity to all households.³⁶⁰ That work is still not done, despite its increasing urgency.³⁶¹

Access and affordability are important on their own terms, given that electricity is a necessity and increasingly important to everyday life.³⁶² But, they are also critical to a clean energy transition that is built around electrification. As noted, the whole strategy of decarbonization through electrification requires that people use more electricity, not just for the normal activities of the past but also for cooking, heating, and mobility. And one way to get people to use more electricity, especially people with limited budgets, is to make it cheaper for them to do so. Social ratemaking, to use Alfred Kahn’s dismissive phrase, will thus need to be a key feature of the clean energy transition.³⁶³

There is a history here that is worth recalling briefly.³⁶⁴ During the 1970s, at the same time that state PUCs were considering marginal cost pricing as a way of improving efficiency and promoting conservation, consumer and ratepayer advocacy groups were also pushing state PUCs to adopt new rate structures that would cushion the impact of high and rising prices on low-income customers.³⁶⁵ In 1974, the Colorado PUC was the first in the country to adopt a system of “lifeline” rates establishing a minimum block of service at below average costs.³⁶⁶ The California PUC followed in 1975 with a rate case for PG&E that adopted a similar system of lifeline rates providing a cheap initial block of electricity for “essential needs.”³⁶⁷ That same year, the state adopted legislation codifying the concept of lifeline rates and stating explicitly that light and heat were “basic human rights [that] must be made available to all people at low cost for basic minimum quantities.”³⁶⁸ As the name suggested, the overall objective of lifeline rates was to ensure that all customers would have access to a sufficient amount of electricity to meet their basic needs.³⁶⁹ For use beyond that basic amount, rates would increase, following what is known as an inverted rate structure.

Other states followed suit. By the 1980s, more than twenty states in the U.S. had adopted some version of lifeline rates.³⁷⁰ Although some critics argued that the system of lifeline rates departed from cost-based pricing (given that the rates for the initial lifeline block of electricity were typically below average costs) and that they violated the core public utility commitment to non-discrimination between customers, commissions and legislatures had little trouble finding that a baseline amount of electricity to meet essential needs for all customers was in the public interest and consistent with public utility law.³⁷¹ In fact, the inverted rate structure that resulted from the use of lifeline rates, where subsequent blocks of electricity were priced at above average costs to make up for the below average cost of the initial block, corrected for some the cross-subsidies inherent in so-called promotional or declining block rates and were consistent with the energy conservation goals that were increasingly dominating discussions of rate design during and after the energy crisis of the 1970s.³⁷² One of the great advantages of lifeline rates, moreover, was that they did not require any sort of means testing, making them much easier to administer.

But various means-tested programs have been adopted over the years, including direct assistance, reduced billing and rebates, and targeted weatherization and efficiency programs.³⁷³ Most recently, California enacted legislation in 2022 that calls for a new system of progressive income-based fixed charges for utility customers that seeks to reduce the growing burden of system costs on poor households and redistribute some of these costs to wealthier households.³⁷⁴ While the measure has generated an enormous amount of controversy and opposition and while there are important questions regarding implementation, including whether the program will further encourage so-called grid defection by the wealthy, the effort represents an important experiment directed at affordability in the face of rising costs.³⁷⁵

In the UK and elsewhere, there are ongoing debates over the need for “social tariffs,” which provide targeted discount rates for low-income, elderly, and other customer groups.³⁷⁶ As noted in the introduction, this has been one of the main demands of Don’t Pay UK and other similar grassroots groups.³⁷⁷ Various EU member countries have also used a system of cheap initial block rates, similar to lifeline rates in the U.S., as well as rebates, direct transfers, and more holistic approaches such as social housing to ensure affordability.³⁷⁸

This kind of social ratemaking represents a major departure from the commitments of neoliberal electricity and reflects a growing recognition that electricity is too important to be treated as a commodity where everyone is expected to pay their own way. By explicitly structuring rates to support low-income customers, these various programs resurrect earlier redistributionist objectives of ratemaking and serve to reinforce the broad commitment to the public interest that motivated much of the early development of public utility law.³⁷⁹

Going forward, if we approach electricity as a system of provisioning for necessities rather than as a commodity that should be priced at marginal cost, there is a strong argument for a commitment to some form of social ratemaking, perhaps even universal basic service. In a renewables-dominated world, moreover, where financing of new projects has access to a low cost of capital, we should be able to spread these costs across a stable rate structure over long time frames. One can think of this more like a long-term fixed rate mortgage rather than a series of volatile market transactions tied to unpredictable markets. Customers who wish to opt into time-of-use or other forms of dynamic rates should continue to have that option. And regulators will surely continue to experiment with new pricing schemes that will drive certain kinds of investments. California’s new Net Energy Metering framework, for example, shifts the benefits of net metering from distributed generation to distributed storage.³⁸⁰ Although the rooftop solar industry has reacted with outrage at the new rules,³⁸¹ it is important to recognize this effort for what it is: California is using prices to drive investment in behind-the-meter storage because that is what the system currently needs. This is the Boituex vision of using price signals to drive investment toward a particular mix of assets.

With more electric vehicles and distributed energy resources connecting to the grid, questions about how to price electricity for those customers who are able to take advantage of distributed energy and those who are not and how to allocate system costs across these different customer groups will be increasingly important and connected to broader questions of economic policy and social welfare. For the vast majority of customers, however, it seems that simple, stable rates that allow for predictable household expenditures and budgeting are surely preferable to a world of constantly changing price signals.

As the system settles down and the infrastructure gets built out, moreover, responsive pricing may come to matter less. In a world of zero marginal costs, and especially in a world where storage is able to spread zero marginal cost resources across the entire day, short-run costs will ultimately collapse into long-term financing costs. In that world, stable, affordable rates can serve as a stabilizing mechanism for the clean energy transition and the broader economy.³⁸²

C. Cooperative Balancing

A decommodified approach to electricity also entails new thinking about balancing across the system. This is especially important as intermittent renewables such as wind and solar become a larger source of electricity, whether at utility scale or so-called behind-the-meter distributed generation. Because intermittent renewable energy makes everything on the system intermittent, this can make it difficult to finance and recover costs for other assets. In a renewables-dominated world, natural gas plants and batteries are essentially on hold waiting to see when the wind stops blowing or the sun stops shining. In effect, renewable power has been pushing the costs of intermittency onto the rest of the system.³⁸³

There are a variety of solutions here. One obvious approach would be to require all generators to offer firm power all the time.³⁸⁴ That is happening in some power purchase agreements (“PPAs”) and there are proposals to require this in some markets outside of the United States. More transmission providing access to more and different types of renewables across larger geographies can also help. Windy nights in Wyoming and Colorado could be used to complement sunny days in Arizona and California. Storage could also play a major role here, effectively allowing wind and solar to be spread out over the course of the day.

But under any approach, the fact that renewables are intermittent and non-dispatchable will require new approaches to balancing the system. And this needs to happen on both ends of the grid: the bulk power supply side as well as the demand side.

On the bulk power supply side, as intermittent renewables account for a higher and higher portion of supply, broader regional and inter-regional approaches to balancing will become more important. The existing RTO and ISO markets can provide some of this. The Western Energy Imbalance Market and the proposed Southeast Energy Market (“SEEM”) are other examples. While we can debate the pros and cons of different approaches (real-time auctions versus bilateral contracts traded over an exchange), the larger question is whether these arrangements should be viewed as competitive or collaborative.

In their original manifestation, balancing markets grew out of the old tight power pools of the middle decades of the twentieth century, where large vertically-integrated utilities developed cooperative arrangements to share reserves and power so that they could deliver reliable power more cheaply than they could acting alone.³⁸⁵ The entire approach was based on a simple “split-savings” arrangement under which the cooperating utilities shared the savings.³⁸⁶ This system worked because it was built on reciprocity and mutual assistance among similarly situated actors.³⁸⁷ Such an approach may be more difficult in the current environment, with its mix of different regulatory and ownership structures, but the regional balancing authorities and load serving entities of today do have a strong incentive to find new approaches to cooperative balancing. Regional experimentation will be critical, but one could imagine a world of short-term regional energy imbalance markets constructed around principles of joint dispatch and reserve sharing—where different balancing authorities are cooperating with each other based on an agreed set of protocols and prices. The key point here is that the short-term markets would be deployed as tools to help balance the system rather than as arenas for competition and price discovery.

At the inter-regional scale, there are ongoing efforts, including proposed bipartisan legislation, to promote and even require substantial transfer capacity between the big regional systems that make up the U.S. power grid.³⁸⁸ Having access to substantial flows of power from outside the Texas market during Winter Storm Uri, for example, would have made a huge difference.³⁸⁹ As climate disruption intensifies, moreover, more robust transfer capacity across regions can provide crucial resources to make up shortfalls and enhance resilience. Such transfer capacity can also provide much needed assistance during various sorts of market disruptions. Substantial new investments in high voltage transmission connecting key regions across the EU, for example, allowed for large transfers of bulk power across the continent to manage some of the disruptions during the recent energy crisis and ultimately kept the lights on for millions of people despite the rapid and dramatic reduction in natural gas supplies because of the Russian invasion of Ukraine.³⁹⁰ This new transfer capacity was explicitly based on a fundamental commitment to solidarity and mutual assistance among the EU member states that sought to compensate for the significant shortcomings of the market.³⁹¹

On the demand side, ongoing experiments with incentive-based demand-response programs and new rate structures offer promising ways forward for a system that includes demand not simply as a resource to be managed but as an active participant in the balancing of the system. The question here, though, is whether it is possible to think about demand response based on notions of reciprocity and cooperation rather than responsive pricing where each individual customer is left to decide how they will respond to price signals. Given how rapid the demand side is changing amid significant growth of distributed energy resources and electric vehicles, it is impossible to say how this might be organized in practice and whether individuals would ever embrace a more cooperative and collective approach to the electricity system. It is quite possible, maybe even likely, that we are headed in a very different direction where rich households and gated communities can defect entirely from the grid, leaving the rest of us to pay the fees that the owners of the system demand.³⁹² But there are alternatives and there may well be deeper commitments in play here than we realize. In September 2022, during an intense heat wave that pushed California’s electricity system to its limit, the government sent a text message to everyone in the state asking them to step up and reduce their electricity demand over a period of hours.³⁹³ We did it and it worked and for a brief moment we were reminded that the electricity system is in fact a shared, collective infrastructure.

CONCLUSION

The forty-year experiment with electricity markets is coming to an end. Policymakers and regulators around the world now recognize that these markets have been unable to deliver on even the most basic metrics and have launched a series of reform efforts. While there are various reasons for these failures, this Article has demonstrated that they trace back in large part to the basic design of these markets and their distinctive ways of price making. That basic market design, and the broader effort to turn electricity into a commodity, was built around fossil fuel generation and a commitment to harnessing the price system to squeeze as much efficiency out of the system as possible. But that approach no longer makes sense in the face of radical shifts in the goals, underlying technologies, and cost structures of the power sector. It is time to recognize that we are at the beginning of a new age of electricity—one in which electricity is now the chief instrument of decarbonization for most economies around the world and an increasingly critical infrastructure for vast domains of everyday life.

Needless to say, the stakes in all of this are quite high. If we cannot fix electricity, we will surely fail in our effort to fix the climate. Part of that is an investment challenge. But part of it is, as this Article has made clear, a provisioning challenge. Fixing electricity, in other words, means that we also must solve the access and affordability problem at the same time that we dramatically increase investment in new assets and infrastructure. Rapid decarbonization via electrification will not happen unless we can ensure universal access to electricity at stable and affordable rates. Put another way, electricity policy is climate policy. But it is also social policy, and it is no longer possible or prudent to ignore the connections between the two.

97 S. Cal. L. Rev. 937

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William Boyd*

* Professor and Michael J. Klein Chair, UCLA School of Law; Professor, UCLA Institute of the Environment and Sustainability. Drafts of this Article were presented at the second Networks, Platforms, and Utilities Conference at Vanderbilt Law School, the UCLA/Colorado Climate Change Law and Policy Workshop, and the Law and Political Economy Workshop at Harvard Law School. Many thanks to the participants for helpful comments. Special thanks also to Samantha Lusher and Alice Carli for outstanding research assistance, and to the wonderful editors at the Southern California Law Review.