How to Liberate Electric Power
Within hours of being sworn in on January 20, President Donald Trump declared that America is in the midst of an energy emergency. The theme of his subsequent executive order, "Unleashing American Energy," is on point, even if brazen executive actions are not the answer. The proper way to unleash America's energy potential is to unshackle the most potent economic force known to humanity: the invisible hand.
Liberating electricity supply is more important than ever. After two decades in hibernation, demand for power has surged, with over 80% of that growth stemming from data centers, manufacturing, and cryptomining. This should come as welcome news, but ballooning electricity costs and worries over shortages are prompting questions over whether the United States has enough juice to win an industrial race.
Temporary price increases are normal for a demand shock in any market: Those signals guide markets to correct the supply-demand imbalance. But because public policy suppresses essential market signals, the U.S. power industry is not well equipped to recalibrate.
The energy problem is not a physics problem: Ample steel and magnets exist to produce enough electrons to go around. Nor is it an economics problem: Capital markets are hungry to finance power infrastructure. Our problem is largely one of government failure. And overcoming that failure requires a clear sense of the distinct elements of our electricity challenge.
In particular, policymakers need to understand the nature of power-demand growth, advance competitive markets for power supply, improve regulatory effectiveness for power delivery, and cut red tape for all forms of power-system infrastructure.
ASSESSING DEMAND
The United States has about 1,200 gigawatts of generation capacity, with one gigawatt being roughly the output of a conventional nuclear reactor. A May 2024 assessment by the Brattle Group estimated that, by 2030, America's power demand would jump 79 gigawatts. Unlike previous demand-growth eras, this one is heavily skewed toward demand from large facilities: Brattle estimated that 45% of demand growth would come from heavy industry, 20% from data centers, 15% from cryptomining, 11% from transportation, and 9% from building electrification.
Expectations of the magnitude and nature of new demand are evolving rapidly, rendering demand forecasts outdated almost as soon as they are published. Mere months after the Brattle report was released, forecasts became especially bullish on data-center demand. S&P Global's conservative estimates projected 50 gigawatts of demand growth in the sector by 2028 — triple the level Brattle expected by 2030. In December 2024, the Department of Energy found that, thanks to artificial-intelligence workloads, data centers may consume 7-12% of U.S. power as soon as 2028. (They consumed 4% in 2023.)
When predicting the impact of rising demand on such things as electricity rates, reliability, and emissions, consumption volume is less important than the location and timing of demand. Power systems are generally designed to meet peak demand; the majority of the time, they operate using vast reserves. In fact, over 90% of the time, the power generated far exceeds demand. Transmission lines, which get congested like roadways, incurred half their congestion costs during just 5% of the time in recent years. Thus, power-consumption growth of, say, 1% during peak times in locations with no infrastructure slack would require additional supply infrastructure, while 4% growth during off-peak times in locations with ample infrastructure slack would boost the use of infrastructure without requiring more of it.
Similarly, power consumption's indirect emissions are highly sensitive to location, often varying by an order of magnitude across different consumption points within a single state. They are also far lower when demand matches variances in supply. This is especially true of renewable energy, whose output can change in a matter of minutes.
The significance of location relative to consumption volume explains why cryptomining, which can change operations and location rather easily, creates modest grid stresses relative to its robust consumption size. Cryptominers act like sponges, situating operations near abundant supplies and soaking up excess wind and solar power when available, then curtailing their demand when supply is scarce.
The big question today is how flexible AI and new manufacturing operations will be in terms of location, and to what extent decisions on where to build them will account for energy and environmental effects. To date, data centers have been rather inflexible in location, but new thinking and AI applications may change that.
Compared to traditional consumers, companies leading the power-demand surge are unique in several ways. For one, their use of power is often exceptionally sensitive to grid reliability. This makes them more willing to pay for on-site generation, either for primary or back-up purposes. The more power new sources of demand can supply on their own, the less strain they place on the central grid.
These firms are also far greener than the typical energy consumer. Many have voluntarily committed to procuring at least 90% carbon-free energy by 2030. Though load growth and massive supply constraints have forced many to recalculate their commitments, and the political climate has prompted a backlash against corporate environmental, social, and governance (ESG) measures, the corporate sustainability movement is not backtracking; it's simply recalibrating. In fact, financial firms expect corporations to expand their sustainability measures under the Trump administration while also behaving more cautiously.
Fascinatingly, the amount these firms are willing to pay to avoid carbon emissions often exceeds the social cost of carbon. This suggests that the sector driving power-demand growth is voluntarily internalizing the climate-change externality — a true greening of the invisible hand.
These demand-driving firms also worry about being "good grid citizens" when it comes to their impact on other electricity consumers, presumably to retain a social license to operate. This is a rather novel development: In the past, large power consumers were notorious for pursuing sweetheart deals with utilities without concern for shifting costs onto other electricity consumers. Today, technology companies appear especially sensitive to bad press about how their thirst for energy imposes higher costs on others. As a result, they're often willing to shoulder a greater share of grid costs and have initiated collaborative efforts like the Electricity Customer Alliance to advance reforms that benefit all customers. Nonetheless, prospects for a consumer kumbaya to address rising energy demand remain as uncertain as the demand forecasts themselves.
On the energy-demand front, one theme reigns supreme: uncertainty. New demand volume might exceed forecasts and be less flexible than expected. Alternatively, most of the demand predicted could fail to materialize, and what emerges might prove more flexible than forecasters anticipate. Large-scale data-center providers are skeptical of utility forecasts of data-center demand, which discount AI efficiency gains and double-count prospective data-center developments. Similarly, futures markets do not suggest that investors foresee the same level of demand that utilities are forecasting.
The point is not to debate whose numbers are correct; it is rather to appreciate that power-demand growth involves huge unknowns across four critical dimensions: size, location, operational flexibility, and consumer preferences. This calls for institutions with a track record of allocating resources efficiently when uncertainty is high and consumers are diverse. In short, it calls for markets.
PRODUCING POWER
Network industries are notorious for creating market failures that frustrate laissez-faire economic policy. Nevertheless, the partial deregulation of transportation, telecommunications, natural gas, and others have been huge economic successes. The electricity industry remains the last fully regulated public utility.
Historically, the invisible hand was a laughable notion in the power industry. The prevailing view was that power generation, transmission, and distribution combined to form a natural monopoly, and the least-costly service was presumed to take the form of a single, vertically integrated utility. Accordingly, state governments granted exclusive rights to one company to serve customers in a particular area.
In states where the monopoly model dominates, state governments determine utility costs and set reasonable rates of return on capital. This cost-of-service regulation encourages utilities to overspend on capital investments and develop business models that prioritize favorable regulatory treatment over the preferences of their captive customers. To justify overcapitalized assets, they often inflate demand forecasts. Predictably, the power industry has a long history of overestimating demand growth, resulting in excess infrastructure.
For the monopoly model to work, regulators have to be well informed and genuinely motivated to correct for utilities' perverse incentives — which requires, among other things, scrutinizing their demand forecasts. In theory, if economic conditions are predictable and consumer preferences are homogeneous, regulators can allocate resources efficiently by choosing the right level and type of supply arrangements to provide uniform customer service. Unsurprisingly, this is not what transpires.
Even when acting in good faith, regulators find the perverse economic incentives daunting to manage. Travis Kavulla, former head of the Montana Public Service Commission, explains that the "barometer for whether an investment is wise for a utility is not capital productivity, but whether expenditures will be disallowed by the regulator. This seldom occurs." And this doesn't speak to the problems with less-than-good-faith regulators, as regulatory capture and cronyism are rampant in a system where firms' instrumental interests lie in securing favorable regulatory treatment.
The state-firm relationship under the monopoly-utility model manifests in an interconnected power system comprised of fragmented, centrally planned fiefdoms run by entities with perverse incentives and access to far more information than their regulators. This arrangement did not play out favorably for consumers in the last era of major demand growth.
As industrialization, urbanization, and electricity-dependent technological advancements swept the country during the 20th century, power demand surged. By the 1980s, utilities had imposed high costs on customers and accumulated unnecessary assets in excess of demand. Cost overruns associated with utility megaprojects, especially nuclear plants, were the last straw for many. Meanwhile, economists concluded that power-generation and retail-supply services were not natural monopolies. At the behest of industrial customers, state governments began passing laws to make wholesale power generation and retail services competitive markets — a process that came to be known as "restructuring."
As intended, the introduction of competition into the energy-supply market during the 1990s overhauled incentives, pivoted the locus of investment decisions, and shifted risk allocation from captive customers to private investors. Fossil-fuel and nuclear power plants rapidly improved their efficiency. The nuclear plants that were sold to competitive suppliers drove innovations that reduced reactor outages, creating $2.5 billion in economic value and reducing carbon-dioxide emissions by roughly 40 million metric tons annually.
Yet in the late '90s and early 2000s, the industry overestimated demand growth. The resulting excess was worst in monopoly-utility states, saddling captive customers with stranded costs. In restructured states, competitive suppliers managed risk more prudently, and those who overinvested faced the music from their creditors, with shareholders — not customers — absorbing the losses.
Regrettably, the California energy crisis of 2000-2001 froze the restructuring movement, which has progressed little since then. Economists identified poor implementation, not the normal operation of restructured markets, as the culprit. Nonetheless, the crisis crystallized the fact that electricity presents complex market failures — including immense network externalities, information asymmetries, transaction costs, and dynamic market power — that surpass those of other network industries in scale.
Electricity economics favor regional-scale transactions across millions of users. And because large-scale storage remains uneconomical, operating such a system efficiently requires instantaneous, system-wide balancing of production and demand. That is a profoundly difficult task.
For these reasons, complete laissez-faire electricity competition is impossible at scale. Capturing the benefits of competition requires complex institutions to implement detailed market-design rules that facilitate competition (as opposed to substituting for it, which is the case under the monopoly model). Electricity markets, therefore, use the visible hand of market design to enable the invisible hand to work.
To implement market-design rules, regulators in the late '90s approved the creation of regional market administrators known as "independent system operators" or "regional transmission organizations." Their highly designed markets have borne the brunt of extended controversy, as no single set of market rules has settled stakeholders. Restructuring has also been criticized by market fundamentalists as impure, yet they offer no economical alternative. Today's electricity markets are less organic than most commercial environments, but they appear to be the best available option.
THE MARKET ADVANTAGE
Competitive suppliers have clearly outperformed monopoly utilities on a variety of measures.
Last decade, for instance, competitive suppliers seized on the natural-gas revolution, driving innovations in high-efficiency gas plants and deploying them in earnest where they provided the best value and had access to inexpensive fuel. This was the main force pushing coal plants into retirement, which reduced both costs and emissions. As the technical lead on the first Trump administration's grid-reliability study observed, "competition worked as intended, driving inefficient, high-cost generation out of the market."
By contrast, monopoly utilities often chose to retain uneconomical coal plants and invested in expensive pollution controls to boost the book value of their assets. This was not unexpected: Monopolies have a long record of lobbying for higher-cost environmental rules (most famously when they opposed the 1990 market-based Clean Air Act amendments) so that they can maximize their regulated-rate base. In the late 2000s, they convinced regulators to second-guess the gas revolution and approve nuclear- and coal-powered gasification plants to hedge gas-price risk. The floundering of four projects alone — Plant Vogtle, V. C. Summer, Edwardsport, and the Kemper plant — has cost captive consumers over $40 billion more than necessary. Only one plant, Vogtle, is operational in the mode it was promised — and it's the poster child for the vices of risk socialization. For consumers, it's megaproject déjà vu.
Competitive markets managed gas risk far more economically. Over the last decade, they used financial instruments and physical investments to lead the expansion of cost-effective renewable energy. Even when markets guessed wrong, consumers fared better than they would have under monopolies. For instance, one competitive supplier pursued the development of a nuclear plant known as the South Texas Project. When the market shifted unfavorably, the supplier pulled the plug at under $500 million in sunk costs, which were borne by shareholders, not consumers.
The market advantage in evaluating risk was evident when the planning context included meager demand growth and a simple choice between different types of conventional power plants, as it did before 2015. Now that unconventional resources like renewable energy and some energy-storage methods are economical but imperfect substitutes for conventional plants, an enormous information asymmetry between utilities and state regulators has developed, as gauging the prudence of monopoly investments in such resources has taken a step-function increase in complexity. As a result, the centrally planned fiefdoms of the Midwest, which have pursued renewables ambitiously, face the highest expected reliability risk in the country. In 2019, the threat of severe overcapitalization of unconventional resources prompted the national large-electricity-consumer group, the Electricity Consumers Resource Council, to issue a notice to its members warning of the risk.
Markets, on the other hand, are well positioned to evaluate risk in a context that includes a mix of conventional and unconventional resources. Only thoroughly restructured markets have shown signs of unleashing meaningful participation in demand.
A great case study is the nation's largest electricity region, the PJM Interconnection, which stretches from Chicago through the Mid-Atlantic. PJM is composed of competitive suppliers and monopoly utilities, making it an excellent natural experiment. From 2020 to 2025, the competitive market for resource investment fetched annual prices ranging from $29 to $140 per megawatt-day, compared to monopoly-utility costs typically in the $450-$500 per-megawatt-day range. The last annual auction reflected newfound demand growth combined with supply constraints, which drove prices up to $270 per megawatt-day. This has created a sufficient market signal for new investment and delayed resource retirements, all at a steep discount to monopoly costs.
The latest price increase has attracted ire, and some of this is deserved. PJM has its share of problems with market design and governance. Yet rather than allowing PJM to resolve these issues by adjusting market rules, state legislators in Ohio and Pennsylvania are entertaining the utility lobby's request to re-regulate power generation. Sage leaders should instead listen to consumer groups like the Ohio Manufacturers' Association (OMA) and double down on commitments to protect and improve markets.
Large-energy-consumer groups like the OMA have been at the forefront of the push to protect and expand markets. They have successfully aided efforts to extend wholesale electricity markets, which now serve roughly three-quarters of the nation's electricity demand. Retail competition, on the other hand, has stagnated. In effect, most of the country has migrated to a hybrid paradigm of regional wholesale markets comprised of retail monopoly utilities.
This is not true restructuring. Large consumers like the Louisiana Energy Users Group are pushing to give consumers market access, where they can choose their supplier. Even when they fail, incremental progress sometimes emerges. For example, Indiana industrials pushed for retail choice but settled for utilities' agreeing to put more utility-resource needs out for competitive bid.
True to the spirit of being "good grid citizens," many large consumers have also advocated market-oriented reforms that would benefit all consumer classes. Last decade, Nevada's casinos and resorts led the Energy Choice Initiative, rooted in the belief that "other consumers should have similar freedom of choice." Recently in Virginia, small and large businesses banded together to expand consumer choice. Competitive pathways are especially important in power-hungry states like Virginia, home to Data Center Alley, because they lower total costs, emissions, and the burden on consumers not responsible for significant growth in demand.
At the same time, monopoly utilities are seeking to build new power plants at a major premium to meet large energy consumers' growing needs. They usually recover those costs by dividing them among all of their customers. Giving large consumers access to the market to purchase power would lift the burden on other consumers, who would otherwise foot an inflated bill for the increased demand.
The benefits of competition are on display. Restructured states cultivate a commercial readiness to respond to surging energy demand through creative financial and physical arrangements. This became especially evident beginning in 2022, when large consumers sought not merely to dabble with conventional renewable-energy credits that offset the emissions of power consumption on paper, but to pursue "around the clock" carbon-free energy. The market responded with premium clean-energy products like time- and location-based energy-attribute certificates. This move has created an ecosystem consisting of a healthy mix of renewables combined with more reliable supply sources, like energy storage and high-efficiency gas, to offset the rapid fluctuations in renewables' energy output.
Over the past year, the most fashionable development has been the rise of data centers' nuclear appetite. And once again, competitive suppliers were first to respond. To name the headliners, Amazon inked a deal with Talen Energy, Microsoft partnered with Constellation Energy to reopen the Three Mile Island facility, Google announced an agreement with Kairos Power to purchase power from multiple small modular reactors, and Meta announced requests for proposals for a whopping 1-4 gigawatts of nuclear power.
The increase in data-center deals is highly concentrated in restructured areas, namely PJM and Texas, and often takes creative forms to avoid years of red-tape-induced delays. Commercial activity — like exploring semi-autonomous industrial parks or private-use networks — is amassing at the grid edge. If governments fail to expedite project approvals in regional markets, more of this will occur.
The capital market delineates the starkly divergent financial motivations of competitive versus monopoly business models to power new demand. In 2024, share prices of leading competitive suppliers jumped 30-80%, while utilities' share prices remained flat. Competitive suppliers have emerged as the saviors of power-hungry industries.
Utilities, meanwhile, have begun offering some special rates that are ostensibly tailored to the characteristics of large energy customers. But these have been slow, risky, obtuse, and unscalable compared to market products' expedience and customizability. A 2023 report by the Analysis Group provided clear evidence that retail choice increased consumer options, produced a varied array of products to match heterogeneous consumer preferences, and delivered long-run cost reductions.
The economic and environmental merits of restructuring are compelling, but policymakers often remain unconvinced. The complexity of electricity markets creates a literacy gap between market operators and regulators, and with it a vulnerability to fall victim to incumbent-utility talking points rather than considering the advice of independent experts or the interests of consumers. Utilities are now arguing for re-regulation in places like Pennsylvania by falsely claiming that markets cannot attract enough investment. The truth is that supply is lagging primarily because of non-market problems, like bureaucratic approval delays.
Perhaps the greatest myth in the power industry is that restructuring failed because electricity rates are higher in restructured states than in monopoly states. This misunderstanding is a classic case of misdiagnosing causal relationships. Restructured states, most of which are in the Northeast, have disproportionately high cost drivers that are unrelated to restructuring — these include higher fuel costs, higher land values, increased environmental-compliance demands, more clean-energy mandates, higher taxes, more stringent permitting restrictions, and greater labor costs than monopoly states, on average. The restructuring-relevant portion of consumers' bills — that is, energy-supply cost — has generally increased in monopoly states and decreased in competitive ones.
DELIVERING POWER
The invisible hand holds sway, albeit very unevenly, in U.S. electricity supply. But it is painfully absent in most facets of electricity transmission and distribution, or T&D. It is in this "wires" segment of the industry that the biggest cost problem resides.
Such can be seen in spending increases over the last two decades. Whereas annual capital spending on power generation nationwide remained relatively steady from 2003 to 2023, it tripled for transmission systems. Meanwhile, distribution spending increased 160%, constituting the bulk of electricity costs over that same period.
Distribution systems are regulated exclusively by the states. There is little hope of changing this state of affairs, as the natural-monopoly argument for local wires companies is fairly compelling. The most radical yet achievable idea may be to periodically put the distribution-utility franchise out for competitive bid. Absent such reform, thorough regulatory oversight of power distribution is the only option.
To address the high costs associated with the distribution side of electricity T&D, state lawmakers should increase transparency in utilities' planning and operation of distribution systems. Conducting hosting-capacity analyses, for example, would shed light on the headroom available in distribution-system segments before triggering expensive upgrades to meet new demand. Such analyses would send market signals to firms that construct distributed energy resources, like electric-vehicle charging stations, encouraging them to build where the distribution system is most robust.
Tackling the costs of electricity transmission is not so simple. Transmission systems are byzantine quagmires that straddle state and federal jurisdiction. Nearly all transmission is centrally planned by utilities or independent regional planners, with projects receiving cost-of-service rates. States generally have jurisdiction over transmission planning in localities, while the federal government has jurisdiction over interstate transmission planning. States also have primary jurisdiction over all transmission siting and applicable permitting within their borders. Local authorities play a pronounced role here, too. Thus, transmission development follows a piecemeal and haphazard pattern, ignoring large economies of scale.
The elephant in the room is the vertically integrated utility. These utilities have an incentive to stifle efficient power transmission, which insulates their fiefdoms and justifies overcapitalization of their transmission and generation infrastructure. A paper published in the National Bureau of Economic Research monetized the problem, finding that expanding efficient transmission in 2022 would have saved consumers billions while reducing incumbent utilities' net revenues by $1.3 billion. Entergy, a vertically integrated utility, recently acted on this incentive by undercutting the development of a $100 million transmission line to justify building a new billion-dollar power plant.
Starting from scratch, an efficient energy-transmission system would maximize the potential of the invisible hand to expand transmission voluntarily. This worked well for natural gas: Deregulatory efforts unbundled the nationwide industry into several segments, allowing upstream producers and downstream consumers to voluntarily enter into agreements with pipeline developers. By contrast, only one-third of states have restructured their electricity utilities along these lines.
Nevertheless, voluntary transmission has room to run. The market value of transmission projects is artificially low because rules render firms ineligible for compensation for providing key grid services — a problem the Federal Energy Regulatory Commission (FERC) has neglected to address. Even with fixes, however, wonky network effects make it impossible to capture all transmission benefits in market products. Mandatory transmission planning is a secondary necessity for improving transmission efficiency in restructured areas; it is the primary necessity in those that remain vertically integrated.
In 2011, FERC made regional transmission planning mandatory while intending to establish interregional planning down the line. Yet the commission never made it to the interregional-planning stage. Instead, it was forced to remedy deficiencies in regional transmission planning — namely that it was done reactively, used inconsistent methodologies to account for benefits, and allowed pervasive exemptions to the commission's regional rule. FERC addressed the first two of these issues in 2024 via Order 1920, which made regional planning proactive and improved benefits accounting. It has yet to address the third.
To date, regionally planned transmission has been a success story. It is conducted by independent entities, harnesses economies of scale, uses cost-benefit criteria, and puts identified needs out for competitive bid. This modest role for the invisible hand saves up to 40% on costs, and with anticipated transmission expansion, consumer groups see it saving over $270 billion. Regional planning has yielded projects with impressive benefit-cost ratios, and consumer groups are generally pleased.
The problem is that only a sliver of transmission development occurs this way. Because FERC never fixed the exemptions under the 2011 rule, utilities have been allowed to unilaterally initiate exempt projects that follow no economic guidelines.
Today, 90% of transmission development is centrally planned by monopoly utilities without any sort of economic justification. It is the cost-of-service model without the regulatory compact. This problem is rooted in monopoly-utility fiefdoms. Ari Peskoe, a leading electricity-policy scholar, described the "utility transmission syndicate" as having had "overriding control over transmission in [its] monopoly service territories" while investor-owned utilities "exploited nearby non-profit utilities and regionalized their dominance through collusive agreements with each other that obstructed competition and cartelized infrastructure development."
Consumer groups are livid over this woeful arrangement. They see demand growth and other factors driving a doubling of transmission expansion, and fear the impact on cost if regulators fail to impose economic discipline. In December 2024, a large consumer-group coalition filed a complaint with FERC calling for a major reduction in exempt projects and enhancement of robust independent planning. Though "economic planning" is a four-letter word to many economists, it is critical to remember that the transmission status quo is uneconomic planning. Where competition is unworkable — namely in local T&D systems — there is no choice but for state regulators to intervene.
When the invisible hand is prohibited, economic regulation must follow effective governance principles. Failure on this front stifles speedy, cost-effective accommodation of demand growth. Such growth is often geographically concentrated in industrial and data-center areas. Customers in these demand pockets are frustrated by local monopoly utilities, and for good reason: Some utilities impose moratoria on new customers or accommodate them on ludicrous terms only.
A prime example is Columbus, Ohio. The local utility, American Electric Power, placed a moratorium on new customers based on an exaggerated demand forecast. It then called for new customers to front payment, on open-ended financial terms, for an expensive upgrade on a 7-to-10-year timeline. Thus far, the state regulator has not effectively required the utility to evaluate more expeditious and lower-cost solutions, nor has it scrutinized the utility's inflated demand forecast.
The top T&D priority for federal and state regulators alike must be making existing systems more efficient. Adopting just a subset of efficiency technologies could save customers over $5 billion annually. Despite massive promise, transmission owners do not readily adopt low-cost technologies as they would in a competitive market. A FERC order in 2021 partially addressed this problem, but it was challenged by utilities, who now resist further reforms. Moving forward, policymakers would be wise to heed the priorities of those paying for the infrastructure: consumers.
STREAMLINING THE ADMINISTRATIVE STATE
The pernicious deficiencies of the modern administrative state hardly require an introduction. Nevertheless, they acutely distress the power industry in underappreciated ways that are often buried in technocratic minutiae.
Administrative suffocation outright bars many power supply and delivery projects; those that survive the process face exorbitant delays. Though there is no silver bullet for unleashing American electricity supply and delivery, there is silver buckshot. The primary fixes reside in dozens of distinct policies at the state and federal levels.
The federal to-do list is shorter than the state list, but just as potent. The primary federal barrier for power-plant proposals is the approval process that builders must submit to in order to connect to regional grids. This is necessary, as it evaluates the impact that new power plants will have on the wires network. But it is also unnecessarily inefficient. Depending on the region, the process can take around five years to complete. At fault are antiquated rules — vestiges of the era of vertical integration, when utilities constructed a small number of large power plants. Nowadays, a high volume of smaller competitive power plants seek connection against the backdrop of an increasingly unprepared, heavily saturated wires network.
In 2023, FERC updated generator-interconnection regulations by a unanimous bipartisan vote. These updates will help, but they fail to tackle the bulk of necessary reforms. FERC could adopt the remaining reforms on its own, or it could work with regional stakeholders to expedite theirs. The last Congress introduced legislation, backed by consumer groups, to force FERC to do the former. Whispers have grown in the early days of the new Congress that such an effort may resume.
Even when markets find creative solutions to avoid red tape, they stumble into other versions of it. When technology companies began developing data centers on site at competitive power plants to avoid delays associated with buying power through the backlogged regional network, they soon discovered that they needed regulatory approval to modify a power plant's existing interconnection service agreement. FERC rejected a first-of-its-kind agreement between Talen Energy and Amazon last fall, though not out of malicious intent; it was simply upholding bureaucratic precedent. Nonetheless, the decision cast shade on the outlook for future co-location proposals. It also caught the capital market by surprise, devaluing companies by billions of dollars overnight.
In addition to obstacles with electricity regulators, a litany of environmental rules obstruct the power infrastructure. The Environmental Protection Agency's (EPA) power-plant rule likely chilled investment in natural-gas plants. Permitting under the National Environmental Policy Act now takes nearly five years on average, and ironically, the affected projects are overwhelmingly clean-energy related. Other legacy environmental statutes, like the Endangered Species Act and the Clean Water Act, cement the paradox of environmental rules' preventing a transition to clean energy. A rather niche but memorable example was the discovery of a rare species of bee that caused environmental regulators to block Meta's plans to pursue a nuclear development.
From bees to bureaucrats, government machinations are the antithesis of "speed to market," the commercial tagline of new power demand. And the news only gets worse below the national level. Surprisingly to many administrative-state detractors, the power industry's woes increasingly emanate not from Uncle Sam, but from state and local governments.
State and local restrictions on electricity infrastructure run the gamut from moratoria on certain fuels to prohibitive permitting and siting practices. Wind and solar infrastructure have faced rapidly rising obstacles — the number of restrictive local ordinances alone increased over 1,000% in roughly a decade. Natural-gas plants and pipelines experienced a generally favorable permitting climate in the 2010s, but in the early 2020s, progressive states began issuing more selective or blanket denials of gas infrastructure projects. Meanwhile, transmission siting has become even more fragmented, suppressing expansion below expected critical-need levels and shifting the composition of expansion toward costlier projects.
The only positive state trend, it seems, is nuclear. Though 12 states have legacy laws restricting or prohibiting nuclear-plant siting, six have recently modified or repealed nuclear moratoria. Some regions are affected more than others. For example, it is hard to build anything in the Northeast — including infrastructure for the technologies that those states have mandated.
In all, state permitting and siting restrictions urgently need an about-face. Permitting should be tied to specific harms, not politics and speculative notions of harm. This would remedy a common trend in which restrictions are increasingly untethered from the harms that permitting is supposed to protect against. Better mechanisms of obtaining project information should improve permitting and siting bodies, which often are understaffed and ground their decisions in limited or incorrect information regarding project benefits and costs. An appeals process would also help vindicate liberty by protecting individual property rights and reducing the risk of unaffected parties vetoing project development, which has become commonplace.
POWERING THE FUTURE
President Trump's urgency to unleash American energy is well founded. Doing so well will require a series of judicious surgical strikes, not capricious emergency interventions, that are guided by two principles.
The first principle is to reject overreliance on central planning. Prognosticators have a knack for being wrong, and energy forecasts are notoriously inaccurate. The only certainty we have is that demand for power will grow.
The second principle is to unshackle the invisible hand where possible. Power supply should be left to market forces. Competition should be used to deliver more electricity, and effective economic regulation should cover the rest.
Decision-making authority regarding technical policies few outside the industry have heard of resides mostly with state lawmakers. States vary in their readiness for the imminent growth in electricity demand. The model state lawmakers should follow on this front is Texas.
The Lone Star state has electrified the invisible hand better than any other. It boasts the most robustly restructured electricity market, the smoothest interconnection process, and relatively efficient permitting and siting laws. As a result, Texas leads the country in wind, solar, and energy-storage additions while coming second in gas to PJM. It has also rapidly retired outmoded plants. Energy customers are flocking to the state, which finds itself with the largest demand-growth projections in the country. Texas has also demonstrated how economic freedom and emissions reductions align, earning Newsweek's title of the greenest state in 2024.
Delightfully, proponents of liberty have never had more in common with environmental interests. Discouragingly, whatever progress these alliances can make, the culture war can quickly undo.
This tension was on display when the bipartisan Energy Permitting Reform Act made a run late last Congress. The bill would have alleviated several permitting and transmission problems while giving grid-reliability authorities more input on EPA rules. Analyses found it a win-win for the economy and the environment. As such, it was supported by principled free-market groups, energy consumers, and results-oriented environmental groups. It was predictably opposed by incumbent utilities, but also by tribal conservatives opposed to transmission and symbolic environmentalists opposed to permitting reform.
Overcoming these deformations of electricity policy must be a priority. Dull as it may seem, the mundane is the sublime. Defeating entrenched interests is a slog, but a union of pragmatic conservative, environmental, and consumer voices is gaining steam. Should it prevail, liberty will fuel America's next industrial revolution.
