Who Will Pay for Electricity Infrastructure Investments?

American public discourse has rather suddenly become electric. A confluence of factors in technology, policy, and economy has rendered energy availability and affordability a pressing debate. Several trends have pushed these issues to the fore. On one hand is the imperative of meeting growing energy demand at any cost, driven in part by the intriguing prospects of AI. Another strain of technologists wants to deploy new options for the electric system, promising sundry benefits. One example is the arrival of cost-effective batteries making electricity storage viable, which could potentially lead to less need for expensive but infrequently used generation capacity. Customers, especially residential ones, are deeply concerned about rising bills. Swings in policy undermine long-term investment incentives, with maximalist and divergent platforms pushed through by narrow margins. Adding to the boil is the prevailing insistence that all this and more must be done yesterday. Utilities and others who manage the electricity grid are caught in the crossfire, trying to determine how best to deliver a growing amount of reliable, affordable power.

Through it all, the common thread underlying each element is the infrastructure—generators, wires, transformers, and other gear—that keep the lights on. Some advocate for their favorite kit or defame their most loathed competitor, while many commentators hardly understand the complicated machinery that comprises U.S. electric grids. Informed and careful thinking is needed because today’s decisions have profound and longevous effects. The deeper issue is simpler: while everyone agrees that an electricity buildout is needed, everybody thinks somebody else should pay for it.

The main forcing factor is load growth. For nearly fifteen years, there was little aggregate growth in electricity demand, but now the intermission is over and expectations of growing demand have returned. To deliver that energy reliably, investments are needed across the system in generation, transmission, and distribution. The problem is sufficiently complex that a single solution, such as adding only generation or transmission, is not viable. The fragmented nature of the U.S. electric system complicates the problem. End users will ultimately pay for those investments, but many avenues are possible and cost-shifting is a key strategy for the interested parties.

Contextualizing the American Energy Buildup

Understanding how we got here is crucial for developing an appropriate strategy to address today’s challenge. The grid has been built and expanded over the course of many decades, matching the steady growth in demand. During the twentieth century, utilities could undertake ambitious, long-term projects and let customers grow into them. Public utility commissions signed off on these plans, rolling the cost of long-term investments into the rate base and charging customers to recover the outlays. Then, for over a decade, the aggregate growth stopped. After the Great Recession, aggregate electricity consumption in the United States hardly changed. Underlying shifts were not uniform, as some states never saw a stagnation in electricity consumption. Texas and Florida stand out as states that have seen and supported continually growing demand. More states, however, saw declines: California, Illinois, Kentucky, and Missouri foremost among them.

The aggregate trend hides some important intensive changes. Since the Great Recession, manufacturing became more energy efficient, with output growing despite lower electricity use. That trend can continue as profit-maximizing manufacturers seek to make the most efficient use of costly energy inputs. Another part of the manufacturing story is a pivot by the sector toward relatively inexpensive and abundant natural gas. But these shifts have been made and are unlikely to continue. The portions of the manufacturing sector that were convertible have largely been accounted for, and those that remain have good reasons to resist further fuel shifting.

In addition to manufacturing, there have been substantial efficiency gains in other areas. One notable area is in lighting. Switching illumination to more energy-efficient technologies like light-emitting diodes (LEDs) has led to substantial reductions in the amount of energy needed to provide the same level of illumination. Here, like the manufacturing shift to natural gas, the conversions have already been made, and one can expect few reductions in load growth from this quarter. These shifts underscore the one-off nature of the period of limited load growth that we experienced and are now realizing is over. While the above gains managed to offset the effects of population and economic growth, they will not reliably continue.

Over this period with limited sales growth, it should come as no surprise that infrastructure investment has been weak. Two explanations are immediately obvious. The first is that if the system is providing a stable amount of final sales, there is little motivation to expand. The second is that infrastructure is ultimately paid for by ratepayers, whether directly by accumulated revenues or through financing dependent on collateral from future sales. If sales are constant, there is no scope to pay for expanding the system. Now, however, there is tremendous momentum to expand the system, hence the present energy friction.

The current fear about energy infrastructure investment is that it will increase system costs. It most certainly will. Only the introduction of new, cheaper technologies can reduce the cost of provision. It is heroic to presume that expanding the system with currently available technologies is going to capture unrealized economies of scale and lower costs for all users; that prescription implies that our current system is massively inefficient. We will have to incur substantial costs; the challenge is who will pay for the system upgrades.

In classic political fashion, the answer to that question has thus far been “not me but thee.” Following the tradition of “users pay,” a salient answer might see firms investing heavily in AI bearing the lion’s share of the cost. Prominent firms like Google, Meta, Microsoft, and OpenAI are seen as creating the load problem. Some of those firms are historically valuable, so obviously, in the minds of many, they are fattened calves to sacrifice. Never mind that AI may not play out along the lines of the most optimistic projections, or that an ultimate dominant player may not be today’s incumbent behemoth. Many data centers have nothing at all to do with AI, providing a wide range of services from web hosting or cloud computing to cryptocurrency mining. Most data centers are relatively small, though the public imagination latches onto the largest hyperscaled facilities.

This has been the basis of the Trump administration’s proposal to “bring generation with you.”¹ The notion that hyperscalers are going to supplant an entrenched industry like electric utilities is rather heroic. Neither party wants that to happen. If tech firms wanted to be in the electricity business, they’ve had plenty of opportunity to opt into a capital-intensive and heavily regulated, low-margin business. But they haven’t and probably won’t. Hyperscalers want to buy energy and the reliability that the U.S. grid delivers. By the same token, utilities look at the disruptive landscape of technology and hail the importance of reliability.

Segments and Issues in the Current Energy Landscape

In a rare contemporary instance of grade deflation, the most recent annual ASCE infrastructure assessment awarded a D+ to American energy infrastructure.² The low grade is misleading, however, as it relies heavily on earlier analyses geared toward policy aspirations for emissions reduction and electric transitions within the transportation system. Now, in an environment facing growing demand after an about-face in policy priorities, the current U.S. energy infrastructure deserves a closer look.

Capital expenditures by utilities are one important indicator of investment in the electricity system. The Edison Electric Institute (EEI), the trade association of investor-owned utilities that serve about 70 percent of U.S. customers, reports planned and actual capital expenditures each year.³ One worried about chronic underinvestment in electric infrastructure might expect to see a hole in capital investment, but the data reveal a different story. Nominal expenditures increased each year since 2014, even though they fell slightly short of the projections in nine of the ten most recent years. In real terms, the increase in investment appears more modest, which reflects the recent history of inflation and rising infrastructure costs. There is no compelling evidence of a glaring deficiency in aggregate capital expenditures for the load being served.

Capital allocations in the EEI data are divided between the traditional generation, transmission, and distribution segments, as well as gas-related investments such as pipeline capacity necessary to integrate natural gas into the electric system. The allocation of investment across different parts of the supply chain deserves close consideration, as all are necessary to ensure the effective functioning of the system. There is not a reductive solution to just switch from one type of investment to another. For example, building new generation assets alone will not lead to a functional future grid. Generation is the most volatile category from year to year, peaking at 35 percent of total planned investment in 2016 before receding to 24 percent in 2021–22 and then bouncing back to 30 percent in 2025.

Each type of electricity infrastructure has its own particular issues. First, consider investment in integrating natural gas into the electric system. The advent of shale and the inexpensive and abundant natural gas dividend it pays is a windfall. This ability to capitalize on low-cost gas depends on investment in the pipelines and power plants that provide flexibility and capacity to the overall system. Replacing coal with natural gas as the backbone of the U.S. electric system requires expenditures on pipelines, laterals, and additional capacity.

Generation investment attracts outsized attention and discussion for good reason as at least three interesting changes have occurred in recent years. High-profile incentives for renewable generation, whether through investment or production tax credits, are something of a litmus test for how commentators feel about electricity investment.⁴ Partly due to these incentives, wind and more recently solar have accounted for the largest share of new capacity additions.⁵ Inverter-based resources, such as solar and wind, have the advantage of having no fuel cost or variation in that cost. Low utilization rates relative to many baseload generators, however, underscore the importance of comparing not just the capital cost of headline capacity but also the expenditure for effective generation.

Renewables are not the only generation asset attracting investment. A second important change is the “dash to gas.”⁶ Much has been made of the replacement of coal with natural gas as the backbone of the electric generating system.⁷ The share of net generation by coal, which was 50 percent as recently as 2001, has now shrunk to less than 18 percent and is still falling. By contrast, natural gas has grown to 40 percent of the national net generation.⁸ Gas-fired generation is needed to provide both baseload and peaking capacity—producing electricity all of the time and at times when it is needed most, respectively—so that depreciated assets can be sustainably replaced. The increasing efficiency of combined cycle plants that capture and reuse the heat from combustion has helped to improve efficiency. These investments have replaced many retiring coal plants, accounting for significant U.S. emissions reductions.⁹ By comparison, the marginal contribution of renewable generation is a rounding error.

The third and most interesting dimension of U.S. generation assets is the rapid rise of battery storage as an effective and economical addition to the system. Adding large-scale storage assets to the system is potentially revolutionary. Electricity markets must clear continuously as system operators carefully balance the amount of power generated with the demand from businesses and individuals. That means that capacity must be built and sit idle for much of the year so that it will be ready to serve the highest loads, which might come during an especially hot summer afternoon or cold winter morning. Paying for capacity that is only used 250 out of 8,760 hours each year proves to be expensive. If battery storage can be used to store excess generation from, say, solar or wind and then discharge the energy when demand is high and other generators are dropping out, then it may be possible to avoid building and maintaining dedicated capacity for high demand hours. Widespread battery storage is a new opportunity that is attracting substantial investment, and early indications show that it is providing new and valuable functionality to the system. Arguments about generation are some of the most bitter, but each technology has its advantages and shortcomings. Indeed, the generation mix need not look the same in all regions. All technologies can help meet growing demand.

Generation alone is worthless without wires to deliver energy. Transmission capacity remains a pressing and immediate issue. Transmission lines are the ties that bind the electric grid together, and expanding the transmission network offers the prospect of greater gains from trade. One example of a transmission opportunity might entail the moving of electricity from wind-rich areas in low-demand, early morning hours to cities further east where load has picked up as people begin their day. This could raise prices that sometimes fall into negative territory in windy generating regions while simultaneously reducing price pressure where the load is in demand. The owners of transmission assets stand to gain for connecting these willing sellers and buyers. More capacity is needed while billions of dollars of gains lie unrealized elsewhere.¹⁰

Increasing competition lowers the value of scarce transmission capacity. Allowing more competition in transmission means that some occupant transmission owners will make less money.¹¹ Those occupant owners have an incentive to try to block new competitors. Furthermore, regulatory fragmentation adds to the costs of expanding transmission. The biggest potential gains are from long links, such as from New Mexico to California, but those investments have many vested interests stacked against them. Connecting two utilities requires each to be willing. Even if this is the case, there remains an ascending hierarchy of other counterparties: third-party utilities, balancing authorities, system operators, and so on, to say nothing of the many directly affected landowners along a given route. The only group to win is the lawyers, who enjoy the multilateral conversations at their accustomed hourly rate. Project costs escalate and the gains from transmission begin to look small. Vesting rights to prevent projects from being completed leads to fewer projects being completed.

The Federal Energy Regulatory Commission (FERC) recognizes these difficulties baked into the transmission landscape and has made efforts in recent years to promote regional cooperation and planning on the broader system.¹² Yet the FERC applies a stringent standard to avoid stranded costs of constructing excess transmission. Nobody should be surprised that this stringency has produced a world in which we find ourselves short on transmission. Easing the standard for merchant transmission would match the deference shown to gas transmission plans. Those efforts are not helped by the Trump administration’s decision to withdraw funding support for a new long-distance transmission project that was nearly ready to proceed from Kansas to Chicago.¹³

Even though they attract less attention than generation and long-distance transmission investments, distribution systems are equally important for two reasons. First, distribution wires are the natural monopoly that justifies regulation in the public utility structure. It would be inefficient to invest in multiple distribution systems, but it is important to prevent the owner of the distribution system from extracting all value through exorbitant fees. Second, distribution connections are the margin at which load growth requires infrastructure. The physical connection of new loads requires continual investment. Public utilities have an obligation to serve at nondiscriminatory rates. New customers, whether residential, commercial, or industrial, almost always require investments in distribution. When these services fall short, the fallout can be costly and even dangerous.

Distribution system failures, such as the winter storm that affected Mississippi and Tennessee in January 2026, provide a poignant reminder of the importance of the system.¹⁴ Crisis management usually entails restoring power as soon as possible along the contours of the existing system, but a less urgent timescale can explore other options such as undergrounding or other hardening strategies that may help prevent high-profile failures. Increasing customer bills to support distribution hardening, or even just more aggressive tree trimming, reduces the scope for increases caused by generation or transmission investments.

While EEI gives a snapshot of the investment flowing into infrastructure, it is also worth considering the current accumulated stock. The Bureau of Economic Analysis estimated electric industry capital stock at year-end 2024 to be just over $2 trillion.¹⁵ For context, this was about 75 percent higher than oil and gas extraction (which does not include the value of natural capital in the form of reserves). This capital stock accumulates steadily, without accounting for financial or physical depreciation. By this measure, hundred-year-old transmission lines in California that potentially contribute to wildfires remain on the books as assets when they very well may be liabilities.¹⁶ The logic of “if it ain’t broke, don’t fix it” resonates with utility regulators trying to protect ratepayers, but it comes at the cost of some superannuated assets. Willingly replacing assets earlier increases system costs, but it can reduce other hidden costs, perhaps including legal liability associated with wildfire ignition.

Policy and Investment

Investment is an inherently forward-looking practice, but it is especially relevant and consequential for the longevous elements of the electricity system. Expectations about the value of a particular installation over a long period are crucial; both policy incentives and rhetoric are critical in their formation.

At the federal level, U.S. energy policy has bordered on partisan-induced bipolarity over the preceding decade. The whipsawing of federal posture undermines incentives to make investment decisions immediately. Uncertainty paralyzes decisions, causing delay in hopes that greater clarity will emerge and illuminate a prudent decision. Financial support weakens at the prospect of abbreviated amortization and less than full cost recovery. Economic uncertainty is one thing, but when compounded with policy changes, particularly sudden or unanticipated ones, investors back away. Energy investment has almost certainly been blunted in recent years solely due to policy inconsistency. Naturally, it is very difficult to fully hedge these risks. Market risks can often be managed using market tools, but policy risks require political and lobbying investments that may not offset the risks that are posed. There is a certain irony that governments offer political risk insurance for investments in energy infrastructure abroad but no such safety net exists at home. Only by adopting policy consistency can comparable security in this sector ensue.

In setting objectives to remake the entire energy system, existing assets find their lives foreshortened and may be rendered valueless. Intentional “stranding” of fossil assets is a key feature of climate policy.¹⁷ For investors, concerns about stranding assets cannot be taken lightly. It does not matter if fossil assets are stranded in pursuit of a “keep it in the ground” fossil strategy or renewable assets are stranded in backlash to climate policy.¹⁸ Both are toxic to a stable investment environment. This is an extreme manifestation of uncertainty about the value of a fixed capital asset.

Policy stranding spawns two longer-term effects that are doubly undesirable. One potential hazard is competition between polities, be they local, state, or national. Places regularly compete to attract new investment, and there is a risk that policies undercut one another. This can undermine policy goals, such as when there is a “race to the bottom” to attract dirty industries. A similar cascade can occur as successively stricter policies are imposed in an effort to accelerate change.¹⁹ Climate commitments of increasing ambition, which imply stranding fossil assets, lead to a certain competition between neighbors that are rebranded as a “race to the top” despite the perverse investment incentive that is created.²⁰ A related hazard with stranding is the rent seeking and lobbying of compensation for the value of stranded assets. Faced with the economic loss of premature retirement, asset owners may seek to obtain compensation or other benefits to offset their diminution. This can take the form of grandfathering, lobbying, or other types of rent seeking. Backward-looking score-settling reduces the efficiency of the system.

Climate policy presents an unusual problem in the desired speed of adoption, motivated by achieving ambitious targets. One of the key objectives of the climate movement is to rapidly transition the energy system from fossil fuel to non-emitting sources. The urgency of the policy program meant that long-lived investments, including power plants, needed to be retired prematurely rather than on schedule. Retiring the fossil plants could help achieve emissions reduction targets but at the cost of undercutting future investment incentives (or inviting immediate political blowback). When policy environments are inconsistent, the incentive is to delay investment. Political uncertainty breeds inaction in the private sector. Emphasis on the policy goal of stranding assets leaves every investment decision subject to an additional unwelcome factor of whether the asset will survive to be amortized.

While it might seem tempting to view policy uncertainty as a figment of climate concerns, there is not a partisan monopoly on perverse investment incentives. The Right and Left have shown equal willingness to stifle energy initiatives in recent years. President Trump has taken a hard stance against windmills, acting to upend projects that are nearly complete. One would be forgiven for worrying that the next step is to tear down those projects that are. After years of effort and millions of dollars invested, the prospect of imminent additional generation for high-price New England and the broader Northeast is welcome. Trying to cancel projects so near the finish line introduces doubt in the minds of every board making a final investment decision.

Without clarity of vision, the idea of stranding assets you don’t like can lead to an unhealthy policy race that undermines incentives to make any long-lived investments. When that kind of race focuses on a particular class of infrastructure, such as electric generators, then it is not surprising that other classes of assets such as electric transmission are relatively overlooked. Building transmission to connect coal-fired generation from coalfields in Appalachia or the Powder River Basin is useless if we need transmission to connect wind in Iowa, geothermal in Nevada, or solar in Arizona.

A second set of policy issues relevant to electricity infrastructure investment is the U.S. experience with restructuring, moving away from the traditional regulated utility model and toward a system more reliant on market incentives. Encouraged by successful deregulation in natural gas as well as other industries such as railroads and trucking, electricity restructuring efforts took off in the mid-1990s. This meant replacing internal decisions by regulated monopolies with market forces, to the delight of free market devotees. These deregulatory actions gained momentum for a few years, spawning a handful of regional transmission organizations and even achieving full retail choice for customers in some states. The California electricity crisis of 2000 robbed the momentum from restructuring, as the potential for price volatility became clear and the subsequent political reaction was swift.

In the intervening decades, economists and others have worked to design incentives for systems to imitate services a traditional utility would provide of its own accord through sufficient capacity or other types of ancillary services needed to keep the grid functioning smoothly. Some point to outcomes in these markets, such as increasing prices in PJM capacity markets, as indications that insufficient investment has been made. Others believe that the same outcomes provide a clear signal to investors of what specific types of infrastructure are needed (in that case, dispatchable generation capacity).

The upshot of restructuring is that the financing model for infrastructure investment is more complicated and nuanced than previously. Before restructuring, electricity infrastructure investment was determined by regulated utilities’ internal decisions. Now, the landscape includes merchant power producers and others with different business models than public utilities. This shift has important implications but is not an insurmountable barrier.

As a prominent example, consider nuclear power plants. A total of 135 have been built in the United States, each one by a traditional rate-regulated utility. This emerging dynamic has allowed utilities to bank future power sales into construction capital under the oversight of rate regulation. Today, there are two commercial nuclear power plants under construction, both by non-utility private firms (TerraPower in Wyoming and Kairos in Tennessee). While neither project is completed, it does suggest that institutional changes are not prohibitive to the kinds of investments that are needed to expand the electric system. The regulatory framework of electricity is fragmented between state regulatory commissions with relatively weak federal oversight from the FERC. A dizzying balkanization of system operators, balancing authorities, individual utilities, and a wide variety of customers complicates decision-making and underscores the value of innovative institutional arrangements, such as private nuclear generation.

Shifting away from nuclear, Texas is a state that has succeeded in building expansive electricity infrastructure. It has been successful in all of the industry segments: generation, transmission, and distribution. It has thoroughly and reliably integrated natural gas and has also built both wind and solar generation in record amounts. Texas is a leading state in deployment of battery storage, where it complements the renewables and helps make that power production more flexible and valuable. Texas is also a bright spot for success in transmission planning and construction. Thanks to the leadership and vision of the state legislature, a series of long-distance transmission lines in the state were identified and built to connect relatively clean and inexpensive renewables in the rural western and northern part of the state to demand centers in the center. A second planned transmission effort is now underway to deliver more energy to oil and gas-producing regions. Texas has also been an attractive place for data centers, which have compounded demand growth that never really went away in the state.

Texas has structural advantages, but there are important policy lessons as well. It has experienced strong demand growth, promising buyers for new sources that can be developed and connected. Much of the state and a vast majority of its population is served by the Electric Reliability Council of Texas (ercot), a restructured and non-FERC jurisdictional system operator. It provides clear market incentives in the energy market without having to engage in distant oversight for transmission investments within the footprint. But it is important to acknowledge the role that government played in authorizing the study and construction of new transmission. The contrast with California, which authorized a very similar transmission study, but not construction, is instructive. Even with a strong governmental push, it took several years to go from ideas to completed lines. If the most aggressive load forecasts are accurate, there is no time to be wasted in starting the expansion process.

Looking Forward

A popular sentiment of the day holds that the United States is currently experiencing an AI bubble, not entirely different from technological ebullience surrounding other emerging general purpose technologies like the internet, restructured telecommunications, and even railroads. Energy has emerged as a limiting factor for the rapid buildout envisioned by industry insiders and some policymakers. Even in the unlikely event that AI turns out not to be the next big thing, renewed load growth is a challenge that will require more generation and more transmission. That realization reinforces calls to expand electric infrastructure. We should and we will. But in doing so, we should be careful to avoid overbuilding the capacity in ways that will impose a burden on future ratepayers.

Questions about electricity infrastructure come down to who decides what, when, and where, and who pays. The most likely answers to those questions are occupant utilities and merchant firms. Transmission investments will benefit from better signals at the government level. Governors and state utility commissions are already aware of these issues and have been engaged. Here, the Department of Energy could be more helpful, notably in supporting additional transmission. The recent allocation of federal loans to Southern Company to finance buildout of natural gas generation—one of the most bankable forms of infrastructure—was a missed opportunity.²¹ In examples such as this, government can crowd out private funding. These funds could and would be better applied to projects or counterparties that the private market is less willing to support, including new technologies or other less bankable projects.

Looking forward, two important things to consider are the immediate state of global energy markets and the certainty of load growth. The closure of the Strait of Hormuz has delivered a long-awaited and long-pondered shock to global fuel markets. The propagation of the shock continues as inventories are depleted, cargoes in transit arrive, and hopes for a speedy and conclusive resolution evaporate. It is true that most Hormuz flows do not come directly to the United States, with much greater volumes flowing to Asia and Europe. But that does not insulate the United States from this shock despite wishful thinking to the contrary. The longer the shock continues, the greater scope there is for meaningful impact.

Reliance on natural gas has grown in the U.S. electric system at the same time U.S. LNG exports play a pivotal swing role in global markets. With Qatari LNG exports stranded by a Hormuz closure and damaged by attacks, global price effects are transmitted directly to U.S. exporters, who are currently enjoying windfall gains. Limited capacity provides a short-term buffer to domestic U.S. prices. But investment already underway will approximately double U.S. LNG export capacity. While that is good news for global buyers, it opens the door wider for global price shocks to affect domestic prices. While making no predictions regarding Hormuz, the relevant investment question becomes how the U.S. system is positioned to respond to future global shocks. Investment flowed to increase natural gas delivery to LNG export points, mostly along the Gulf Coast. Investment has not similarly integrated different parts of the country, leaving exposure to price spikes. As stated above, New England is the most glaring example, but the Southeast and Pacific coast face similar issues. With multiple producing regions across the country, these challenges are surmountable, but the delay in identifying and alleviating local shortfalls exposes those areas and their electric ratepayers to global gas price risk. These issues are likely secondary to liquid fuel impacts in the event of extended Hormuz disruption, which will also require capital investment to resolve.

Projections about the future are inherently uncertain. This is particularly true when so much of load growth, crucial for affording new electricity infrastructure, depends on AI, which may or may not be exponentially adopted or transformative. Similarly, speculation that reshored manufacturing will restore industrial electricity demand in places where it disappeared is sustained through optimistic announcements, but there is not yet concordant construction underway to justify the gaudiest load growth estimates.

Infrastructure is part of a broader debate about energy and climate, where commercial, regulatory, legal, and technical factors collide. Because of the long life of these assets, contemporary investment choices can have deeply consequential implications, which only intensifies energy debates. Misallocating investment can lead to long-term financial burdens or chronically fragile physical systems. In addition to policy debates, choices about infrastructure are complicated by extenuating factors, including new technologies, increasing incidence of physical shocks over time, and uncertainty about the timing, magnitude, and location of load growth. With all of these swirling uncertainties, it is imperative that industry and government coalesce around a singularity of vision and purpose in refining and expanding our electricity infrastructure.

This article originally appeared in American Affairs Volume X, Number 2 (Summer 2026): 24–37.

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Notes