Build Public Renewables, Again

Sandeep Vaheesan* April, 2025

The Price Is Wrong: Why Capitalism Won’t Save the Planet. By Brett Christophers. New York and London: Verso. 2024. Pp. viii, 379. $29.95.

Introduction

Economic geographer Brett Christophers¹ paints a fine-grained picture of political economic life. But like Georges Seurat, Christophers’s pointillist command of specifics does not blind him to the big picture. Quite the contrary, The Price Is Wrong: Why Capitalism Won’t Save the Planet persuasively argues that, under current institutional arrangements, the private sector is not equipped to decarbonize the power system—the single biggest task for arresting further climate change. Technological innovation has steadily decreased renewable energy facilities’ construction costs; in some ways, the economic barrier to renewable energy investment entry is as low as it’s ever been. Christophers, however, forcefully rejects complacency in the face of these technological advances. According to Christophers, private investment in renewable energy remains, and will likely remain, inadequate because a critical ingredient is missing—stable and substantial profits.

Christophers arrives at this conclusion by digging into the guts of electricity markets. Take the United States, this Review’s focus, as one example of a country with an almost bewildering variety of power sector governance models. In the United States, private electric utilities operate under one of two modes of regulation.² In most of the American Southeast and West, a single utility owns and operates generation, transmission, and distribution facilities for a given area:³ In exchange for a publicly recognized monopoly, a state agency—commonly called a public service commission—sets the utility’s rates based on the cost of service.⁴ Until the late twentieth century, most American utilities operated this way.⁵ But in the 1990s and 2000s, California, the Northeast, the Mid-Atlantic, much of the Midwest, and Texas restructured their power sectors to effectively separate generation from the transmission and distribution functions.⁶ They turned power generation and wholesaling of electricity into a competitive market.⁷ Rivalry among generators, not public administration, serves to discipline rates—or so the theory goes.⁸

Christophers finds the competitive market segment currently insufficient to stimulate investment in renewable technologies, such as solar and wind.⁹ He homes in on a critical feature of these markets: the wholesale pricing mechanism. Under competitive market conditions, marginal production costs set the price for all generators. These marginal production costs are set by the most expensive unit necessary to meet the final increment of electricity demand in a given period.¹⁰ In an increasingly renewable system, however, the marginal cost of power will often be zero because, once a plant is up and running, turning the wind or sun into electricity has practically no cost.¹¹ Who would fund a wind farm that will often make no money?

Christophers documents many renewable energy projects running aground in the face of these economic prospects. Paradoxically, renewable energy in the United States has thrived in areas with volatile wholesale market rates but has hardly penetrated regions that offer stable, cost-based rates.¹² Christophers provides a partial explanation: the federal government offers tax credits for renewable energy projects, and environmentally conscious tech companies are eager to buy clean electricity through long-term contracts. But, in writing a book that is laudably global, he doesn’t dig further into this curiosity of the American electricity landscape.

Christophers makes a persuasive case—with some important caveats addressed below—that private-sector renewable energy is a nonstarter without generous public support. Even the federal government’s investment and production tax credits have not been enough. Instead of further opening the public treasury to private developers, Christophers endorses another way: direct public investment. Why not decarbonize directly instead of through tax and regulatory kludges? Christophers finds support in New York’s Build Public Renewables Act of 2023, which authorizes the state-owned New York Power Authority to build large-scale renewable energy projects (pp. 376–78). This public approach has a venerable history in the United States. In the 1930s, 1940s, and 1950s, the federal government constructed dams on rivers across the country, including the Columbia, Missouri, Sacramento, and Tennessee, to produce clean hydroelectricity.¹³ Dams such as the Grand Coulee and Hoover and institutions such as the Tennessee Valley Authority are with us today. Christophers thinks it is time to build public renewables again.

In Part I, I examine the two governance systems for private electric utilities: (1) monopolistic service with cost-based rates fixed by public regulators, and (2) market-based rates set through competition among generators to serve wholesale customers. Part II examines Christophers’s target: market-based rates tied to electricity generation’s marginal costs. He traces the inadequate investment in renewable energy in the United States and elsewhere to this pricing system, which often fails to yield the profits necessary to support private development of solar and wind energy. Part III challenges Christophers’s thesis by identifying and attempting to diagnose a paradox: renewable energy investment in the United States has thrived in states that have adopted market-based pricing for electricity, while it has stagnated in states with cost-based rates that are more conducive to investment. Part IV reviews and endorses Christophers’s recommendation for escaping the pitfalls of private-led investment in clean energy: public investment and ownership. Public power has a rich history in the United States and is a promising path to decarbonization.

I. Two Modes of Industrial Governance

A brief detour into the United States’ utility regulatory structure and its history provides helpful context for Christophers’s argument. Today, the United States governs the private power industry in two main ways. First, in the Southeast and most of the West, vertically integrated utilities function as publicly regulated monopolies and sell power at cost-based rates. These rates cover capital and variable costs and provide a reasonable return on the former.¹⁴ This model, refined during the New Deal, dates back more than a century. Second, in other parts of the nation, policymakers separated the industry into generation and wires (transmission and distribution) businesses: generators sell wholesale electricity at market-based rates to utilities, who then resell it to residential and commercial customers.¹⁵ This system is a product of federal and state reforms that began in the late 1970s.

A. Regulated Monopoly and Cost-Based Rates

In most of the Western and Southeastern United States, publicly regulated private monopolies provide electric service to customers.¹⁶ These companies—such as Georgia Power and Portland General Electric in Oregon—own generation, transmission, and distribution assets. In other words, they are vertically integrated.¹⁷ Since electricity production and distribution’s technical features favor scale, the industry was historically governed as a “natural monopoly.”¹⁸ States accepted and validated this assumption. In exchange for their legal or effective monopoly status, utilities must comply with a set of rules imposed by their state public service commissions, including regulation of rates.¹⁹

Regulators set rates based on the cost of service. Under federal law, utilities are required to comply with specified accounting standards. These standards permit regulators to determine the cost of service based on fuel, labor, and investments in fixed assets.²⁰ Cost-based rates allow utilities to recover their expenses while earning a reasonable rate of return on prudently incurred capital investments,²¹ called their “rate base” in regulatory parlance.²² The rate of return is tied to both equity financing costs—used or raised to fund construction costs for generation, transmission, and distribution facilities—and debt costs.²³ Following federal and state regulators’ adoption of original cost valuation in the 1940s and 1950s,²⁴ the rate of return, particularly the cost of equity, became the most hotly contested issue between commission staff and the utility.²⁵ Adding to the debate, the Supreme Court captured the essence of the regulatory system in 1944, writing that it “involves a balancing of the investor and the consumer interests” by setting rates that neither burden consumers nor discourage investment.²⁶

The federal government and states divide regulatory authority over the power industry. The Federal Energy Regulatory Commission (FERC) regulates interstate wholesaling and electricity transmission rates, while states regulate retail rates.²⁷ State regulatory authority started in the early twentieth century, when New York and Wisconsin enacted power regulation statutes to stabilize the nascent industry and to meet and co-opt popular demand for public ownership in the sector.²⁸ Through the Federal Power Act of 1935, Congress charged the Federal Power Commission (the predecessor of FERC) with ensuring wholesale and transmission rates are “just and reasonable.”²⁹ In interpreting the new federal “just and reasonable” standard, the Supreme Court began offering public-utility regulators substantial discretion over their ratemaking methods—consequently, federal and state agencies are not obligated to use cost-based rates.³⁰

B. Regulated Competition and Marginal-Cost Pricing

Recent policy changes have partially undone the regulated monopoly model. In California and much of the Midwest, Northeast, and Texas, electricity is sold in organized wholesale power markets.³¹ The growth of small generation plants and cogeneration facilities following the Public Utilities Regulatory Policies Act of 1978 (PURPA) convinced many lawmakers that power generation does not have natural monopoly features.³² These new power-generation players showed that electricity could be efficiently produced by firms that owned only a few smaller plants.³³ At least for power generation, many legislators and regulators abandoned monopoly and public regulation and embraced market entry and business rivalry.³⁴

PURPA responded to popular and scholarly disenchantment with cost-of-service regulation. Critics including consumer advocates, economists, and environmentalists, contended that state public service commissions failed to maintain “just and reasonable” rates in the inflationary environment of the 1970s;³⁵ encouraged overinvestment in capital assets;³⁶ and failed to give due importance to the environmental costs of power generation.³⁷

Many historians, economists, and policymakers refer to this regulatory transformation as “deregulation.”³⁸ That term, however, is a bit of a misnomer. These new arrangements are the product of institutional reconstruction and the creation of new regulatory bodies—but are not de facto regulation abolition. Given new assumptions about the power generation business, FERC aggressively reinterpreted its mandate to maintain “just and reasonable” rates by permitting generators that lacked market power to sell wholesale at “market-based rates.”³⁹ FERC would still evaluate the justness and reasonableness of rates after the fact, but it no longer required the prospective filings of rates that a regulated utility would charge wholesale customers.

Congress and FERC recognized that transmission was a major obstacle to wholesale market competition. Utilities that owned generation and transmission facilities—with the latter still accepted as a natural monopoly—could use their control of the grid to exclude rival independent generators either by denying them transmission access or charging them discriminatorily high rates.⁴⁰ In response, the Energy Policy Act of 1992 authorized FERC to remedy discriminatory grid practices on a case-by-case basis.⁴¹ In 1996, FERC, relying on its older statutory powers, went further and issued Order 888 to mandate open access over the transmission grid.⁴²

Many state governments undertook major sectoral reforms of their own. To reduce the incentive for discriminatory grid management practices, states encouraged transmission owners to sell off generation assets or functionally separate their transmission and generation businesses.⁴³ To bolster open access to the grid, some states, as well as FERC, nudged utilities to join regional transmission organizations (RTO) that would implement planning procedures and control, though not own, transmission facilities.⁴⁴ Regulators also tasked these nonprofit, quasi-public corporations with managing the power spot markets.⁴⁵ RTOs—such as the California Independent System Operator, New York Independent System Operation, Midcontinent Independent System Operator, and the PJM Interconnection which covers the Mid-Atlantic and parts of the Midwest—are important actors in the current power industry.⁴⁶ Some of these RTOs grew out of power pools that had been formed in the early twentieth century by neighboring utilities to share generation and transmission assets, while others are entirely new organizations.⁴⁷

This brings us back to Christophers’s critique. Spot markets are a core feature of RTO areas and the principal focus of The Price Is Wrong. Rather than tying rates to service costs, these markets price power based on marginal cost principles (p. 167). The highest-cost generator’s bid sets the price for all generators, regardless of their production costs. Generators that offer bids higher than this set price are not dispatched and cannot sell energy.⁴⁸ For mainstream economists, marginal-cost pricing achieves the optimal allocation of resources, at least in the short run.⁴⁹

To understand how competitive power spot markets operate, consider the following example: Four merchant generators—entities that do not own transmission nor have captive customers—operate in a single market. This power market has 500 megawatts (MW) of demand in an hour, or 500 megawatt-hours (MWh) of energy. Bidding at their marginal cost of production:

Merchant generator 1 offers to sell 250 MW of power at $5/MWh;
Merchant generator 2 offers 100 MW at $15/MWh;
Merchant generator 3 offers 150 MW at $40/MWh; and
Merchant generator 4 offers 200 MW at $60/MWh.

The RTO ranks the bids from lowest to highest and determines that merchant generators 1, 2, and 3 can meet demand in the hour. Merchant generator 3 is on the margin and sets the market price at $40/MWh. Merchant generators 1, 2, and 3 are paid $40/MWh to supply power in that period. Since merchant generator 4’s bid is above the market-clearing price, it is rejected. It does not run, and it does not make money.

Under neoclassical textbook principles, generators in a competitive wholesale market should bid their marginal cost (p. 167). If they bid less, they stand to lose money. If they bid more, they risk RTO rejection. But if generators have market power because they are essential for meeting demand, they can submit bids above their marginal cost of production and still be dispatched (p. 367).

II. The Perils of Marginal-Cost Pricing

Professor Christophers primarily targets marginal-cost pricing. He documents how this pricing model has proliferated with resounding support from academic and applied economists. Whether in California, Canada, or China, some amount of power is sold through organized spot markets in which the marginal generator sets the price for everyone who buys and sells power through this channel.⁵⁰ Christophers convincingly establishes that these markets do not support long-term investment.⁵¹ Hence, the price is wrong: it is often too low to ensure a profitable return. The growth of renewable energy only compounds preexisting problems in market design.

Power generation is a capital-intensive industry. New power plants can cost hundreds of millions of dollars or more. The third and fourth units at the Vogtle nuclear power plant near Augusta, Georgia cost $31 billion to construct.⁵² Despite the declining costs of renewables relative to other kinds of electricity generation, they still have substantial upfront costs. When fully finished, the Mammoth Solar farm in Northern Indiana will have a capacity of 1,300 MW—capable of generating enough power for more than 200,000 homes⁵³—and is expected to cost $1.5 billion to build.⁵⁴ A combination of retained earnings, debt, and equity fund these upfront costs, which need to be recovered—and then some—to make the investment worthwhile for project developers and financers.

As Christophers explains, marginal-cost pricing poses a serious problem: If generators bid their marginal costs (the cost needed to make an additional increment of power), they are only accounting for the costs of labor and fuel.⁵⁵ What about the upfront fixed construction costs, which sometimes amount to billions of dollars? Generators not on the margin will pocket the difference between their own marginal cost and the market price. Over time, they may make enough money to pay off the original financial obligations incurred to build their plant(s).

But this doesn’t address the generators that are commonly on the margins. These “peaker” plants, usually ones that use natural gas as fuel, are making just enough money to cover the short-term costs of generating power. They may run for fewer than 100 hours in an entire year, at times when demand for power is very high.⁵⁶ These periods include hot summer days when businesses and homes run their air conditioners at full blast and frigid winter evenings in places where many households have electric heating.

Because capacity to store electricity is still limited, peaking units are critical to consistent system reliability. A utility or RTO must have a reserve margin, or generation capacity greater than peak demand, of around 15 percent.⁵⁷ Reserve margins ensure that peak demand can be met even if one or more power plants or transmission facilities suffer an outage.⁵⁸

Peaking units are often cheap to build. They have much lower fixed costs but higher marginal costs relative to “baseload” plants that run all the time.⁵⁹ Low upfront costs come at the expense of less-efficient operational design. But peaking units still have fixed costs that need to be recouped and plant construction creditors who need to be repaid. Will these generators make enough money to do so, or will they face what commentators call a “missing money” problem?⁶⁰ Although high prices burden customers and draw the ire of consumer advocates and politicians, Christophers notes that in the absence of public support, some pricing power is necessary to attract and sustain investment in power generation, especially for plants on the margins (p. 202). The price can be too low because profits must be assured.

Christophers explains that the missing money question has been addressed through either wishful thinking or additional revenue streams for generators provided by the creation of additional markets (p. 67). In Texas, regulators believed that periods of generation scarcity would contribute to very high spot-market prices. At these times, the market operator would allow prices to rise as high as $9,000/MWh to encourage customers to conserve energy (pp. 154, 309–10). High prices would have a supply-side benefit too: Generators, including peakers, would theoretically make enough to recover their fixed costs (pp. 309–10). But such circumstances may not occur for years, if ever. Until Winter Storm Uri in 2021, natural gas peaking plants in the state consistently failed to make enough money to cover their upfront costs.⁶¹ As such, many operators decided to shut down their plants instead of unprofitably staying in the market.⁶² The result was an ever-more precarious system balance, with reserve margins declining from more than 30 percent in the mid-1990s to just 8.6 percent in 2019.⁶³

Winter Storm Uri inflicted massive harm on Texas and killed at least 246 people,⁶⁴ but the event provided a necessary financial windfall for many generation owners. The high prices that resulted from home heating demand and outages at many generation plants replaced a decade of revenue drought with a flood of money.⁶⁵ The system strain caused by the storm supplied revenues that had been missing for a decade. The episode showed the absurdity of Texas’s basic market design: Generators, living in the hope of a catastrophic weather event or something similar to deliver a necessary bounty, went years without making enough revenue. And of course, they recovered these rewards at the massive social cost of hundreds dying from lack of heat in their homes.

Elsewhere, market operators and regulators chose not to rely on faith and confronted the missing money problem head on. For instance, in New England, New York, and PJM, RTOs, with FERC’s blessing, established capacity markets in addition to existing power spot markets.⁶⁶ These markets enable generators to make money both by selling energy and offering capacity in the future. In other words, they are paid to produce power today and to build or maintain power generating capacity years down the road. Capacity markets can be an important source of revenue and profits. In PJM in 2021, coal- and gas-fired power plants earned most of their revenue selling capacity, not energy.⁶⁷

Because of its market design, PJM appears to have the opposite problem of Texas. According to a 2020 estimate, the market was projected to have reserve margins—superfluous spare capacity that customers ultimately pay for in their bills—of 70 percent in 2024.⁶⁸ What we see in the Texas and PJM case studies suggests that wholesale market prices are consistently outside what the Supreme Court called the “zone of reasonableness”⁶⁹ by being either too low or too high.

The cost-of-service system seems rational in comparison. Whatever its demerits, cost-of-service regulation accepts that power generation is capital intensive and needs stable, remunerative rates to be sustainable. By comparison, market-based rates, on top of often being too low, are notoriously volatile. Christophers examines prices on two days in the Scandinavian wholesale market and reports: “On 21 August, the day-ahead price was €38 per MWh; on 22 August, it was €372. Can there be any other product, anywhere in the world, subject to such volatile price movements?” (p. 172). A review of American wholesale markets similarly indicates that dramatic price fluctuations are the rule, not the exception.⁷⁰ Given that the market price is sometimes set by nuclear plants with low marginal costs and other times set by expensive gas peaker plants, rapid price movements should not come as a surprise. But such volatility is hardly conducive to sinking billions of dollars into a project that will operate thirty years or more. At a minimum, these dramatic price fluctuations raise financing costs.⁷¹

The missing money problem and volatility should have forced a serious reckoning with the restructuring of the electric industry. However, the problems of wholesale power markets never seem to spur questions about their basic wisdom. Instead, proponents believe they are always just one market away from achieving their utopia.⁷²

Renewable energy’s emergence has only compounded the existing infirmities of wholesale power markets. Indeed, that is the principal theme of Christophers’s book. Solar and wind projects produce power at zero marginal cost.⁷³ If high-cost peaking plants set the spot-market price of power most of the time, the renewable energy plant owners can make substantial profits—specifically the difference between their zero marginal cost of production and the wholesale price. But this won’t be the case as renewables account for a larger fraction of generation, eventually becoming the marginal units themselves. In a theoretical all-renewable system, power in spot markets would sell for nothing at all hours of the day (p. 168), meaning that lower marginal costs can translate to lower prices and profits (p. 167). But while the sunshine and breezes are free, solar and wind energy projects are not. As the Mammoth example shows, they are expensive to build. If power sells for nothing, these projects cannot recover their fixed costs, let alone make a profit. Further, capacity markets offer little help for these renewable projects. Unlike coal, gas, hydro, and nuclear plants, solar and wind projects that lack on-site energy storage are not “dispatchable,” meaning they cannot be turned on as needed: the sun doesn’t always shine, and the wind doesn’t always blow. Accordingly, they are not eligible to participate in most capacity markets (p. 67).

Christophers shows that many renewable power projects are running aground in wholesale power markets. Banks and energy developers do not want to fund or undertake unprofitable renewable energy projects. Here, he highlights a critical distinction that commentators often erase in popular and technocratic debate. The cost of building solar and wind farms has declined substantially.⁷⁴ But that doesn’t mean they have become more profitable to pursue under market-based rate systems (p. 204). Their zero marginal costs can translate to lower prices, cannibalizing the cost advantages of renewable energy and transferring the benefits mostly, or entirely, to wholesale market customers (p. 226). The traditional regulatory model—in which public service commissions direct utilities to build cost minimizing systems⁷⁵—can offer a different outcome. Utilities and customers can split lower costs to encourage investment.

As renewable generation plants capture market share, and are on the margin more often today than in the past, zero-price periods have become more common in wholesale power markets.⁷⁶ Developers, and especially financiers, have become skittish as low prices expose projects as not “bankable,” or attractive to fund (pp. 176–77). Christophers cites projects that seemed impressive and inspiring in scale and vision but died on the logic of profit and loss (pp. 133–34). The price is doubly wrong: not only are renewable power prices often too low, but it is profit, rather than price, that predicts whether these projects succeed.

Although Christophers asserts that wholesale markets were not constructed with renewable energy in mind (p. 352), he is too charitable to the market designers. These markets, as the longstanding missing money problem reveals, were poorly structured from the beginning. Zero-marginal-cost renewable energy only accentuated their existing defects. Power generation has been capital intensive since its inception (pp. 133–34). Renewable energy’s fixed costs only differs from fossil fuel generation in degree, not kind. Market designers were blind to this technical reality.

III. The Paradox of Renewable Energy Investment in the United States

Because The Price Is Wrong is admirably global in scope, the book has gaps on specific national experiences. For students of the American energy system, one will likely stand out: Christophers does not fully confront and explain the renewable energy paradox in the United States.

Renewable energy capacity and output have grown significantly in the United States. Specifically, utility-scale solar and wind power generation grew dramatically between 2012 and 2022, with these two sources accounting for 14 percent of total power generation in 2022.⁷⁷ Based on my earlier discussion, a reader might reasonably believe that renewable energy has thrived under cost-of-service regulation in places like Colorado, Florida, and Georgia and made little headway in restructured California and Texas. The reality is almost the exact opposite. Wind, and increasingly solar have done better in Texas’s “Wild West” wholesale electricity market than almost anywhere else.⁷⁸

Christophers offers a partial answer to this paradox. In the United States, Congress awarded investment and production tax credits to solar and wind developers, which offered important subsidies but not price stability (a distinction that will be discussed momentarily) (p. 334). In the Inflation Reduction Act (IRA), Congress extended these federal aids through 2032 and made them available as effective grants to tax-exempt entities, such as state agencies and rural electric cooperatives.⁷⁹ Under the IRA, a solar project developer can claim an investment tax credit equal to 30 percent of construction costs while a wind developer can receive a production tax credit of $0.0275 per kilowatt-hour of energy produced.⁸⁰ For a large project, these credits can be worth tens of millions of dollars.

As Christophers describes, there is more to the paradox. By entering long-term power purchase agreements (PPA) with renewable energy developers, utility and large corporate customers committed to decades of buying large amounts of renewable energy at fixed prices. With a PPA, a project unviable if reliant on spot-market sales can become bankable (p. 249). In the United States, where the government offers support but not price stabilization, lenders frequently require developers to have a PPA in hand before they seriously contemplate financing a solar or wind farm (p. 244).

What’s in it for the customers who might be able to purchase cheap or even zero-price power on the spot market? Utilities serving residential and commercial customers seek a secure source of electricity, though they are often unwilling to offer stable prices (p. 241). Long-term contracts offer stable long-term power supply, while reliance on the spot market does not. Further, some large industrial customers, especially in the energy-hungry tech sector, want to establish their green credentials.⁸¹ Corporations like Amazon and Google establish green credentials by entering PPAs with renewable energy projects, which secure long-term power supply for their data centers (pp. 242–43).

Christophers recognizes that in recent years, big tech companies have played an especially critical role in renewable energy development (p. 244). They have stepped up their reliance on PPAs while utilities have backed away (pp. 246–47). Christophers writes that in 2022, “Amazon alone, with deals in sixteen different states, was responsible for over 40 percent of the new [renewable energy] capacity” (p. 251). In other words, certain big tech corporations have enabled renewable energy growth in the United States.

Policymakers, and especially big tech customers, allowed renewable energy developers to escape the brutal logic of marginal-cost pricing: Renewable energy could make money through tax credits and PPAs. And here Christophers stresses a critical distinction. Congress offered subsidies while corporate customers, whatever their motives, offered something more: stability. Unlike many other nations, the U.S. government does not offer price stability to renewable energy developers; it instead only offers a supplemental income stream channeled through the tax code (pp. 184, 277). An investment or production tax credit does not offer insulation against volatility in energy prices or construction costs (p. 184). In the United States, PPAs with fixed rates are the principal instrument for providing long-term price stability to renewable energy projects (p. 278).

In areas with wholesale power markets, long-term contracts and stable, profitable prices have allowed some renewable energy developers to thrive. Without these escapes from the punishing prices of wholesale power markets, renewable energy would have likely died on the vine for the reasons Christophers articulates. But there is more to the story that is not covered in the book: Federal tax credits are available everywhere, not just in states that restructured their power sector.⁸² While Christophers offers a broadly negative assessment of industrial restructuring, it may have directly helped renewable energy.

By separating or unbundling the power sector into discrete generation, transmission, and distribution segments, lawmakers in states like California and Texas advanced two ends. First, they promoted fair, non-discriminatory access to the transmission grid. In essence, lawmakers made FERC’s Order 888 open access rule more effective in practice by “quarantining the monopoly.”⁸³ Merchant renewable developers could invest in projects with much greater confidence in California than in Florida because they could count on using the grid to sell their power. Customers like Amazon could rely on the grid to deliver power from generators without transmission lines of their own. Second, restructuring states created a large class of utilities that needed power. California law prodded Pacific Gas & Electric (PG&E) to sell off most of its nonnuclear generation assets.⁸⁴ Now, PG&E needs to purchase power to serve its customers. Post-restructuring, it cannot depend on its own generation assets and must turn to the market. This need created a ready and willing customer base for merchant generators that neither own transmission lines nor have a captive customer base.

In traditionally regulated states, by contrast, merchant generators face major obstacles to building power plants of all kinds. Vertically integrated utilities can explicitly or subtly deny them grid access, notwithstanding FERC’s open access rule, and prevent them from selling power to willing industrial customers. In encouraging the formation of RTOs, FERC acknowledged that Order 888 did not fully remedy the problem of discrimination by transmission owners.⁸⁵ Also, vertically integrated utilities do not have a clear need, or interest, to buy power from merchant generators. Their generation portfolio was not subject to divestitures and is still intact.⁸⁶ And when vertically integrated utilities need to expand capacity, building their own facilities to sell energy at a base rate that would earn a return on investment is more attractive than contracting with a merchant generator. In traditionally regulated states, renewable energy developers face uncertainty over both delivering their power and finding enough customers for it.

Although Christophers correctly identifies that marginal-cost pricing impedes investment, he gives insufficient attention to how the power industry’s separation into generation and transmission segments was likely a boon for renewable energy investment in the United States. These restructuring characteristics gave renewable energy developers confidence in grid access and a large class of customers willing to purchase their power. In other words, the restructuring project itself should be unbundled into constituent parts, with some favorable to renewable energy investment (access to the grid and creation of wholesale market-dependent customers) and others not (spot-market pricing).

To add one final element to the many drivers of renewable investment in the United States, consider this confounding factor. The development of renewable energy in restructured states may also be a story of state-mandated demand. States that pursued restructuring were also more likely to enact renewable portfolio standards (RPS),⁸⁷ which require customer-facing utilities to source an increasing fraction of their electricity from renewable or zero-carbon sources more broadly.⁸⁸ For instance, New York requires a full phaseout of fossil fuel-generated energy by 2040.⁸⁹ By contrast, states in the Southeast—where vertical integration and traditional regulation still prevail—stand out on a map for generally not adopting RPS laws.⁹⁰ Compared to states like California and Texas, Southeastern state regulators do not require the self-generation or purchase of clean energy.⁹¹

IV. A Third Way to Decarbonization

For all his naysaying about wholesale power markets, Christophers eschews hopelessness and pessimism. His basic point is that renewable energy investment here and around the world has been inadequate—a claim made by other scholars and institutions,⁹² including the Intergovernmental Panel on Climate Change.⁹³ In the United States, market restructuring has promoted renewable energy investment, but the pace has been far too slow to stem climate change.

But we have another way that does not rely on private capital: As an alternative to tax credit kludges; continued faith in the social consciousness of Amazon and Google; and prayers for southeastern utilities and public service commissions to take climate change seriously, Christophers endorses public power (pp. 372–73, 377). If governments want to expand renewable energy, they should do it themselves—without the profit mandate or obligations to pay dividends, and with access to lower-cost funds, including direct fiscal appropriations—rather than trying to bring private capital off the sidelines using carrots and sticks. Public power has a venerable history in the United States.⁹⁴

Christophers anchors his optimism in a major 2023 legislative development in New York (p. 378). As part of a budget deal, the legislature enacted the Build Public Renewables Act (BPRA), which empowered the state-owned New York Power Authority (NYPA) to build large-scale renewable facilities.⁹⁵ In 1931, Governor Franklin Delano Roosevelt helped create NYPA to develop the Niagara and St. Lawrence Rivers’ hydroelectric potential and transmit the power across the Empire State.⁹⁶ New York did not build the projects until the 1950s, years after his death, but FDR set in motion the public development of New York’s water power.⁹⁷ Nearly a century later, the legislature charged NYPA with capturing the state’s sunshine and wind and converting it into electric energy on a large scale.⁹⁸

NYPA is part of a rich institutional tradition in the United States. Public power development, by either the federal government or the states, was a pillar of populist and progressive politics in the late nineteenth century and for much of the twentieth. For example, the Reclamation Act of 1902 authorized the federal government to build multipurpose dams in the West to irrigate arid lands, control floods, and generate electricity.⁹⁹ In 1928, Congress authorized construction of the massive Boulder Dam (better known today as the Hoover Dam) to tame the volatile Colorado River; store water for agricultural and domestic uses; and produce large amounts of electricity.¹⁰⁰

The New Deal greatly expanded public participation in the power sector. However, as FDR articulated at a campaign stop in Portland, Oregon, in September 1932, he did not seek to nationalize the power sector if elected president.¹⁰¹ He only offered public takeovers as a last resort—a birch rod in the cupboard—to deal with poorly performing private utilities.¹⁰² Further, at the generation level, Roosevelt wanted to create enough federal hydroelectric projects—specifically on the Colorado, Columbia, St. Lawrence, and Tennessee Rivers—to expand generation capacity and to serve as “yardsticks” that stimulate private power to do better.¹⁰³ In line with Roosevelt’s vision and public power supporters like Senator George Norris,¹⁰⁴ Congress created the Tennessee Valley Authority (TVA) in May 1933 to build dams on the Tennessee River and its tributaries, and develop one of the country’s poorest regions.¹⁰⁵

Unlike the project-level approach of the private energy developers in The Price is Wrong, the TVA applied a regional-systems approach to power development. The TVA sought to maximize power generation in the entire Tennessee River Basin, not simply at each individual dam.¹⁰⁶ Senator Norris, who since the 1920s had proposed a TVA-like authority to own the federal dam and nitrates project at Muscle Shoals, Alabama, imagined harnessing the river and its tributaries as a single resource for Southerners.¹⁰⁷

Uncoordinated project development, which prevails today, has serious costs. In places like West Texas, solar and wind generators must curtail their output because the state does not have enough transmission capacity to move power to energy-hungry cities such as Austin, Dallas, and Houston.¹⁰⁸ Infrastructure bottlenecks waste zero-carbon energy, with curtailed energy accounting for 5 percent of total wind generation and 9 percent of total solar generation in the state in 2022.¹⁰⁹

Although FDR ultimately abandoned Senator Norris’s plan to build a “Tennessee Valley Authority for the entire country,”¹¹⁰ the federal government did pursue a major dam construction program across most of the nation. The Army Corps of Engineers and the Bureau of Reclamation constructed the large Bonneville and Grand Coulee Dams, respectively, on the Columbia River.¹¹¹ Grand Coulee is still the largest power plant in the nation.¹¹² Congress created the Bonneville Power Administration to market power from the two dams and build and operate a regional grid for the Pacific Northwest.¹¹³ In California, the Bureau of Reclamation developed the Central Valley Project to irrigate arid land and generate electricity.¹¹⁴ The federal government, through the Public Works Administration, also aided state power development, awarding grants and loans to undertakings like the Lower Colorado River Authority in Texas and the Santee Cooper Project in South Carolina.¹¹⁵

Massive federal investment in the power sector helped transform American life. After the New Deal, abundant, low-cost electricity raised living standards in both cities, where most households had electric lighting but few of the appliances we take for granted today, and rural areas, where electricity was once mostly absent.¹¹⁶ In 1935, only about one-in-ten American farmers had electricity.¹¹⁷

Whereas 1920s private power executives were skeptical of residential power use and dismissive of the rural market, the New Dealers believed homes and farms were an untapped market.¹¹⁸ TVA Director David Lilienthal and Bonneville Power Administrator J.D. Ross argued that lower rates would increase domestic power consumption.¹¹⁹ They were right. In Tupelo, Mississippi, low-cost TVA power and lower retail rates doubled average household power consumption in just over one year.¹²⁰ Visiting the city in 1934, Roosevelt hailed the residents’ electrified modern living and pledged to replicate this development across the nation.¹²¹

Considering this history, Christophers’s belief in initiatives like New York’s BPRA is hardly naive. If anything, he should have expressed more confidence about the prospects of public-led decarbonization. Federal investment in power generation in the mid-twentieth century modernized American life. The New Dealers did not use tax credits to entice private utilities to do better. They directly invested in power generation and transmission and compelled private power to improve or face public displacement. They relied on public investment and institutional competition to achieve their ends.¹²²

Today’s energy needs demand a redux and perfection of what has already been done. The federal government dammed the mighty Columbia and brought abundant power to the poor Tennessee Valley as part of the New Deal. But new, large dams are untenable because they dislocate communities and destroy fish stocks, among other social harms.¹²³ Yet, this history illustrates that the U.S. government is capable of launching and leading social transformation. Given the history of dam construction across the nation, the federal government can surely develop the capability to dot the land with solar and wind farms, large batteries, and pumped storage projects—and build transmission lines from coast to coast as part of a Green New Deal.¹²⁴ Drawing on George Norris’s dream, the time for public renewables for the entire nation has come. This public system would both complement and discipline the dominant investor-owned utilities and private power developers.

Conclusion

The Price Is Wrong should make defenders of electric industry restructuring think twice. Wholesale power markets cannot deliver the sustained, large-scale investment in renewable energy needed to avert even more serious climate change. While American power markets have delivered some renewable energy investment—primarily via federal government tax credits and corporate customers’ PPAs—Christophers’s key contention remains true: Wholesale power markets structurally do not offer the stable and handsome profits necessary to bring private capital off the sidelines. Even tax incentives that accelerate decarbonization are not enough.¹²⁵ The level of clean energy investment pales in comparison to the scale and urgency of the climate crisis.

Granting subsidies through the tax code and trusting the social consciousness of large corporations are ad hoc solutions to an extraordinary and systemic problem. Instead of continuing down this path, policymakers should recognize the profound defects of wholesale power markets. The entry of renewable energy into these markets is a testament to liberal fiscal aid and a few energy-hungry tech sector customers’ willingness to commit to long-term PPAs and burnish their green images. But even more generous financial support in several European nations has not stimulated adequate investment in renewable energy. Why throw public money at private capital while giving up public control and without achieving the desired results? If we want renewable energy, we should not try to cajole and entice fickle financiers and corporate executives to do the right thing. We, through our elected government, should do it ourselves.

* Legal Director, Open Markets Institute. The author thanks Anita Jain, Ben Kodres-O’Brien, Brian Callaci, Luke Herrine, and Matt Buck for valuable input on a draft of the Review. He is the author of the book entitled Democracy in Power: A History of Electrification in the United States (2024), which was published by the University of Chicago Press in December 2024.