The Law of the Mid-Transition

Alison Gocke* May, 2026

To address climate change, our energy systems need to transition from fossil fuels to clean energy resources. There is a tendency to think this transition will occur in a linear, seamless progression: We will move from the (old) fossil fuel system at Time A to a (new) clean energy system at Time B. But this belies the reality that an energy transition involves not just building a new energy system, but also unwinding an old one. Crucially, both processes will take time. That means there will be a significant period in which both energy systems coexist.

In the engineering literature, this period is called “the mid-transition.” Identifying the mid-transition is important because it poses unique design challenges: An engineer would design an energy system based on fossil fuels one way, a system based on clean energy resources a second way, and a system based on a mix of both an entirely different, third way.

This Article identifies and analyzes a similar phenomenon in the law—what it calls the “legal mid-transition.” In the context of the energy transition, the legal mid-transition describes the period when two different legal frameworks—one designed for the (old) fossil fuel system and one designed for a (new) clean energy system—coexist. This unique period resembles neither the law as it existed prior to the transition nor the law as it will come to be after the transition. It also poses distinct challenges. During this time, our energy laws are bifurcated and unstable, making it more difficult to ensure safe, reliable, and affordable energy services. The system is also at risk of “maladaptations,” or legal responses that address the challenges of the legal mid-transition in the short term but, in the long term, stall the law in the mid-transition. Additionally, the period is prone to “accountability problems,” or the concern that failures that occur during this period will be incorrectly attributed to the new clean energy laws, leading to misguided efforts to roll back the energy transition.

How we respond to the challenges of the legal mid-transition may be the difference between a successful energy transition and no transition at all. This Article uses the energy transition to develop a granular model of the legal mid-transition. It then uses insights from this model to propose solutions designed to respond to the specific challenges of this period. But the model is not intended to be confined to the energy transition. The legal mid-transition describes the phenomenon of legal change more broadly. Particularly at a time when much of the law is in flux, the framework developed here can be used by scholars to analyze legal transitions in other fields that present similar dynamics.

Introduction

To the world we dream about
And the one we live in now
—Hadestown, Livin’ It Up On Top¹

As the time horizon for avoiding the worst effects of climate change shrinks,² the need to transition our energy systems from ones based on fossil fuels to ones based on zero-carbon resources has become the most pressing challenge in energy law. There may be a natural tendency to think this transition—which is often referred to as the “clean energy transition” or the “energy transition”³—will follow a straightforward, linear progression as our energy systems move from the (old) fossil fuel-based regime at Time A to a (new) clean energy-based regime at Time B. But that misses a key insight: The energy transition involves not just the building of a new energy system, but also the winding down of the old system.⁴ Moreover, both processes take time and will occur simultaneously. Thus, the energy transition will involve a significant period (likely several decades) in which both the old and new systems coexist.⁵

Two engineering professors, Emily Grubert and Sara Hastings-Simon, recently identified this period of overlapping energy systems and labeled it the “mid-transition.”⁶ Recognizing the mid-transition is important because it poses unique design challenges: From an engineering perspective, one would design an energy system based entirely on fossil fuels one way; a system based entirely on zero-carbon resources another way; and a system based partially on both resource types a completely different, third way.⁷

Drawing from this insight, this Article argues that a similar phenomenon exists in the law—what it calls the “legal mid-transition.” In the context of the energy transition, the legal mid-transition describes the period when two different legal frameworks—one designed for the (old) fossil fuel system, and one designed for the (new) clean energy system—coexist. This period is unique; the coexistence of the two laws constrains the operation of both in ways that are not true of either the period prior to or following the transition.

Additionally, the simultaneous presence of two legal frameworks has significant consequences for both the operation of the overall law and the ultimate success of the energy transition. During this time when both old and new legal frameworks coexist, our energy laws are bifurcated and unstable, making it more difficult for them to serve the basic purposes for which they were designed—namely, to provide safe, reliable, and affordable energy services. This threat to the basic function of our energy laws increases the risk that legal actors will engage in what I call “maladaptations,” or legal or regulatory responses that are intended, in the short term, to respond to some of the challenges associated with the mid-transition period but which, in the long term, ultimately stall the law in the mid-transition. Moreover, during this period, the legal system is prone to what I call “accountability problems,” or the issue that it will be difficult to determine which legal framework is responsible for any failures that occur, resulting in the possibility that these failures will be incorrectly attributed solely to the new clean energy laws and will engender misguided efforts to roll back the energy transition.

This Article uses the example of the energy transition to develop the model of the legal mid-transition and its features. But the insights from the energy example highlight a feature of legal change more broadly. To date, the scholarship on legal transitions has focused primarily on the new law-to-be: how new legal regimes are enacted and the mechanisms and conditions required for legal change to be successful.⁸ To be sure, the literature acknowledges that once new legal regimes are enacted, there may still be difficult problems or puzzles “on the ground” that remain from the old regime,⁹ like what to do with regulated industries whose compliance burdens have suddenly changed,¹⁰ how to deal with loyalists from the old regime and the harms they caused,¹¹ or how backlash from supporters of the old regime can influence the course of the law going forward.¹² But this literature is not primarily concerned with what to do with the old laws themselves; these accounts tend to presume that once a new legal regime has been enacted, the detritus of the old laws has been and can be swept away, like a light switch that can be turned off.

In contrast, this Article contends that the continuing presence of the old legal regime simultaneous with the introduction of the new legal regime is an important, and more common, feature of legal change than has previously been acknowledged.

The first step in exploring this theory of legal change is to develop a granular model that describes it. Thus, the primary aim of this Article is to build out a robust schema of the legal mid-transition in the context of a particular legal transition—the energy transition. Viewing the energy transition through the lens of the legal mid-transition reveals significant and underappreciated challenges of this transition and demonstrates the value of the analytical framework. Later scholarship can then be devoted to analyzing and applying this model to transitions in other legal fields.

The Article focuses on two specific areas of energy law: (1) the laws governing the distribution of natural gas for retail consumption, and (2) the laws governing the long-term supply of wholesale electricity and resource adequacy. In both examples, assuming consensus around a broader goal of decarbonization,¹³ it is generally presumed that achievement of that goal will require a new legal or regulatory regime. In the natural gas example, for instance, new legal frameworks will be required to support a zero-carbon alternative for residential and commercial energy services that are currently provided by natural gas, like home space and water heating.¹⁴ Similarly, in the wholesale electricity context, new laws or regulations will be needed to ensure a long-term supply of zero-carbon resources that is adequate to satisfy electricity demand.¹⁵

What is less often discussed or recognized is the idea that simply instituting these new legal frameworks will not be sufficient to achieve decarbonization goals; the old legal frameworks will also have to be simultaneously unwound. For instance, in the natural gas example, the continuing legal duty of natural gas utilities to provide service to their customers means that the residential gas distribution system cannot be dismantled unless there is an alternative, zero-carbon distribution system in place. At the same time, the zero-carbon distribution alternative cannot be put in place unless there are legal changes to the gas utilities’ service obligations. Solving this problem requires simultaneously amending the old natural gas regulatory structure and designing a new zero-carbon regulatory structure, with the alterations made on one side necessarily influencing the trajectory of the other.¹⁶

Similarly, in the wholesale electricity example, in some parts of the country, existing regulatory frameworks known as “capacity markets” ensure that a sufficient supply of primarily fossil fuel-based resources exists to satisfy long-term electricity demand. Because they were designed for fossil fuel resources, these capacity markets will have to be altered—or fundamentally rethought—in order to accommodate a zero-carbon resource mix. But these markets cannot simply be dismantled if they provide necessary support for critical fossil fuel resources that are supplying electricity while clean energy resources are still coming online; and, paradoxically, these clean energy resources face significant challenges coming online so long as the capacity markets designed for fossil fuel resources remain in place. Solving this catch-22 requires simultaneously coordinating the drawdown of the old capacity market framework and the introduction of new regulatory frameworks designed to accommodate zero-carbon resources, again with the alterations made on one side necessarily influencing the trajectory of the other.¹⁷

In each of these examples, managing this period of bidirectional movement in the law will be difficult. If it is not done properly, we risk undermining the ability of our energy laws to ensure affordable, reliable, and safe energy services.¹⁸ Additionally, both of these contexts pose serious risks of maladaptation, as legal solutions intended to address some of the short-term problems of the mid-transition period—like the affordability of residential energy services or the reliability of the electricity grid—may prevent the new legal frameworks from coming to fruition.¹⁹ Finally, disruptions to energy services or the high cost of energy provisioning during this period could lead the public erroneously to blame the new clean energy laws, undercutting support for the clean energy transition.²⁰

Viewed in this light, the most important climate policy is not the laws that are designed for the future, but the responses of policymakers, regulators, and other actors to the laws that exist right now.

This Article develops the model of the legal mid-transition in four Parts. Part I lays the groundwork by describing the legal model in greater detail, as well as recent energy law scholarship that has identified some of the trends that this Article organizes under the legal mid-transition framework. Part II presents the mid-transition framework for the two legal systems at issue here: the laws governing the distribution of natural gas and the laws governing wholesale electricity supply and resource adequacy. This Part explains the “old” and “new” laws relevant to these two examples. It also teases out the constraints that the old and new laws impose on each other through their coexistence. Part III turns to the unique challenges posed by this mid-transition. This Part discusses how the overlapping laws make it more difficult to ensure that the basic requirements of our energy regulations are met during this period. It also explains the concepts of legal maladaptations and accountability problems and how they apply in the energy transition. Part IV canvasses possible solutions to these problems. In particular, three types of legal or policy responses could help manage the mid-transition: (1) “linking solutions,” or solutions that tie the wind-down of the old laws to the implementation of the new laws; (2) “gap solutions,” or solutions that are reliant on the existence of neither the old nor new legal systems and are instead intended to be temporary solutions that last only during the overlap; and (3) “leapfrogging solutions,” or solutions that are designed for the post-transition period and are successfully able to leapfrog over the challenges of the mid-transition. For illustrative purposes, this Article suggests several existing or emerging policies that fit into each of these categories.

I. Laying the Groundwork for the Legal Mid-Transition

At a high level, the primary contribution of the legal mid-transition framework is twofold: (1) to recognize that some legal transitions are just as much about unwinding old laws as they are about building out new ones, and that these events have to happen simultaneously; and (2) to recognize that the period during which legal change of this sort is occurring is a unique one, and therefore requires separate treatment and analysis by legal scholars.

This Part describes the legal mid-transition in greater detail. The first Section develops more fully its key elements and features. The second Section turns to recent articles in energy and environmental law that have identified trends in the law similar to the ones discussed in this paper. Although these articles do not discuss these trends in the language used here, the Article nonetheless argues that what other energy and environmental law scholars have been observing in the field is evidence of the legal mid-transition.

A. Identifying the Mid-Transition

The legal mid-transition describes a period in which the overarching legal system is distinct from both the old legal regime that preceded it and the new legal regime that will come to succeed it. During this period, the legal system is in flux, with remnants of the old laws maintaining relevance even as legal actors may be winding down those laws, and elements of the new laws coming into place even as the final form of the new legal regime may not yet be known. The overlapping presence of these laws influences and constrains them both.²¹

Moreover, consistent with the mid-transition model developed by Grubert and Hastings-Simon, the legal mid-transition involves the identification of certain unique challenges that exist neither before nor after the transitional period. These challenges or features of the legal mid-transition are threefold. First, because of the coexisting and incompatible presences of the old and new laws, ensuring that the basic purposes of the overall legal or regulatory framework are met during this period will be more difficult than in either the pre- or post-transition period.²² Here, when I refer to the “overall legal or regulatory framework,” I am talking about the law in a broader sense than a single legal rule or principle—more along the lines of a legal field, landscape, or context.²³ I assume that there is some degree of continuity across the legal transition—that both before and after the transition, there is some body of, say, “energy law” that maintains some basic purpose throughout the transition—even if the more specific substance of that law will vary as a result of the transition. This basic purpose will be a foundational one that essentially all actors agree is the goal of the overarching legal framework. For instance, in the energy law context, that basic purpose consists of providing reliable, affordable, and universal energy services. In other contexts, the basic purpose may be even more abstract, like rule of law values that ensure stability and certainty in the legal regime. Regardless, because the old and new laws will be simultaneously unwound and built out during the mid-transition, it will be more difficult for the basic purpose of the overall legal framework to be satisfied during this period.²⁴

Second, because the mid-transition period is one of flux where neither the new nor the old laws are entirely stable, the period is prone to “maladaptations.”²⁵ In the engineering context, Grubert and Hastings-Simon define such maladaptations as engineering solutions that seem to stabilize the energy system in the short term but lock in reliance on fossil fuel resources in the long term.²⁶ In the legal context, these maladaptations are legal or regulatory solutions that are ostensibly designed to address problems associated with the mid-transition but which instead slow or frustrate exit from it. Note that these maladaptations may be motivated by either good-faith concerns about the problems of the mid-transition period or self-serving concerns about the transition itself. For instance, actors who have some interest in maintaining the old legal regime may propose maladaptations that appear, on the surface, to be remedial, but are in fact efforts to stop the transition from occurring.²⁷ Alternatively, maladaptations may arise from well-intended efforts by regulators to manage the law during a particularly unstable period.

Finally, the legal mid-transition is prone to what I call “accountability problems.” Grubert and Hastings-Simon observe that the technical failures of the energy system during the mid-transition period could erode public support for broader decarbonization goals.²⁸ They note that people’s perceptions that “the existing system is still essentially functional”—even as the harms associated with greenhouse gas emissions increase and there is “increasing awareness that existing systems are not resilient to climate change and extreme weather”—could lead the public to blame new zero-carbon technologies for any problems that arise during the mid-transition.²⁹ Similarly, in the legal context, in a situation where two legal frameworks coexist, both of which are designed to satisfy the same basic purposes, it is difficult to determine which law is responsible for any failures that occur.³⁰ This inability to identify which law or legal framework to hold accountable results in the possibility that these failures will be incorrectly attributed solely to the new legal system and will lead to misguided efforts to roll back the new laws.

As noted, this view of legal transitions as involving bidirectional flow in the law is different from the conventional one, which tends to define legal change according to the new laws or legal developments that are both its product and primary indicia.³¹ One prominent exception to this occurs in the field of administrative law. In administrative law, various doctrines govern agencies’ ability to repeal old laws or regulations.³² Recently, these doctrines (and others) have begun to take on a new light, as administrative law scholars have explored the increasingly common trend of incoming presidential administrations’ efforts to undo the legal agendas of their predecessors.³³ Cristina Rodríguez’s work on “regime change,” in particular, represents the closest analogy to the conceptual framework developed here.³⁴

Rodríguez defines regime change as “the replacement within the executive branch of one set of constitutional, interpretive, philosophical, and policy commitments with another.”³⁵ Crucially, Rodríguez recognizes that this replacement involves not just the creation of a new presidential regime but also the dismantling of the prior administration’s regime.³⁶ Rodríguez documents a variety of methods by which an incoming presidential administration might undo the policies of their predecessor, including by shifting positions before the Supreme Court, requesting that ongoing court cases be held in abeyance, suspending or repealing agency regulations, rescinding enforcement memoranda, and issuing executive orders intended to undo past executive actions.³⁷

The notion of the legal mid-transition developed here is both broader and narrower than Rodríguez’s conception of legal change. It is broader because I do not intend it to be confined to the kind of legal change that happens within the context of presidential transitions.³⁸ Thus, the legal mid-transition framework may apply to transitions that occur within state and local legislatures, obscure state-level administrative bodies, or the doctrines of state and federal courts. At the same time, the legal mid-transition is narrower than Rodríguez’s conception because, while when I speak of the “old” and “new laws” that characterize the mid-transition, I mean “law” in a relatively capacious sense, I still intend a fairly formal definition of law as a legal rule or principle established by some law-making body: for example, legislation passed by a legislature, a regulation promulgated by an administrative agency, or a legal doctrine announced by a court. Thus, for instance, it would be possible for a legal mid-transition to occur entirely within an administrative context, where a single administrative body is responsible for both unwinding old regulations and instituting new regulations all under the same static statutory authority.³⁹ But, Rodríguez’s definition of regime change as encompassing the replacement of personnel and ideological commitments would fall outside of the “laws” of the legal mid-transition (even if they may still carry causal importance for the mid-transition phenomenon).⁴⁰ At bottom, although Rodríguez’s project differs in significant ways from mine, it is still a useful comparator for ways of thinking about how laws are dismantled as part of a broader project of legal change, as well as evidence for the slow recognition by legal scholars of the importance of accounting for unraveling laws in our understandings of transitions.

The model of the legal mid-transition, with the three features articulated here, is potentially descriptive of a variety of transitional moments in the law. To develop this model with greater clarity, I will focus, as Grubert and Hastings-Simon do, on the energy context, as a granular example of this broader theory of legal change. The model that is developed here can then be used by others to analyze legal change and legal transitions in other fields.

B. Signs of the Mid-Transition in Energy Law

Additionally, viewing current legal scholarship through the mid-transition lens reveals an important, and previously unacknowledged, pattern in the energy and environmental law literature: Recently, scholars in this field have written a series of articles that—in some cases explicitly, in other cases not—take as their thesis that the presence of “old” laws or regulatory frameworks is in some way undermining efforts to mitigate climate change or to respond to its effects.

For instance, Heather Payne, Elizabeth Stein, and Justin Gundlach have all written about how the continued presence of old natural gas utilities cannot be squared with efforts to decarbonize, and therefore the laws supporting them must be unwound if climate change is to be addressed.⁴¹ Josh Macey has written about how old tools of public utility regulation that have outlived their initial purpose—what he calls “zombie energy laws”—are instead being used by monopolistic utilities to protect themselves against the threat of competition from new clean energy companies.⁴² Mark Nevitt has written about how old legal frameworks—some of which are associated with utility regulation, others of which come from the fields of property, tort, and constitutional law—may inhibit federal, state, and local efforts to respond to the effects of climate change, including initiatives to adapt to climate change.⁴³ Multiple energy law scholars have argued that electricity capacity markets designed for incumbent fossil fuel resources are interfering with state-level efforts to introduce clean energy technologies onto the electricity grid.⁴⁴ And Alexandra Klass, Josh Macey, Shelley Welton, and Hannah Wiseman have written a series of pieces on how old conceptions of grid reliability may undermine the transition to a clean electricity grid.⁴⁵

In a few cases, these scholars have recognized some similarities between the ideas motivating their pieces—particularly when the pieces have addressed the same or similar topics, like the governance of the electricity grid⁴⁶—but for the most part the fact that these scholars have all lighted upon the same generalizable phenomenon across all of these areas of the field has gone unnoticed and unmentioned.

Under the legal mid-transition framework, these observations are not mere coincidences but are rather important evidence of one of the primary components of the mid-transition: the continued presence of old laws or legal regimes that constrain the introduction of the new legal regime.

Moreover, in some cases, these scholars have identified additional details with respect to precisely how these old laws are interfering with efforts to decarbonize that are consistent with the features of the legal mid-transition enumerated above. For instance, in the context of the natural gas utility, Stein and Gundlach have observed that the unwinding of the natural gas utility raises questions about how to continue to provide safe and reliable energy services during the decommissioning period.⁴⁷ This goes to one of the essential features of the mid-transition: the challenge of ensuring that the basic purposes of the legal system are satisfied.⁴⁸ Additionally, in the context of the electricity capacity markets, energy law scholars have observed both that these capacity markets tend to disfavor new, state-supported clean energy technologies, and that one of the primary regulatory responses to the clash of these capacity markets with clean energy technologies has been proposals to exclude these technologies from participating in the capacity markets altogether.⁴⁹ As explained in greater detail below, this kind of regulatory response would qualify as a “maladaptation,” where problems resulting from the overlap between the old and new laws result in policies that further prop up the old legal regime and therefore stall or inhibit the transition.⁵⁰ Finally, in the context of regulating the reliability of the electricity grid, scholars have observed that outdated notions of reliability can result in the boosting of conventional fossil fuel resources, which can actually pose a threat to grid reliability (incidentally, another example of a “maladaptation”), but when power losses occur as a result of these fossil fuel resources, clean energy technologies and the policies supporting them are paradoxically blamed for the losses.⁵¹ Again, as discussed more below, this confusion would be an example of an “accountability problem,” where members of the public—uncertain of which of multiple legal regimes to hold accountable for failures—tend to blame the new laws.⁵²

None of these scholars frame their analyses in the language of the legal mid-transition. Indeed, to the extent that these scholars rely on some broader analytical framework to describe their on-the-ground observations, they seem to turn implicitly to rough notions of regulatory capture, or the manipulation of extant laws by self-interested industries.⁵³ Theories of regulatory capture are compatible with the legal mid-transition framework; indeed, they are one of the explanations for the presence of maladaptations. But the legal mid-transition also creates room for a wider variety of explanations for the dynamics at play here, including the possibility that transitions of this kind are simply challenging to implement. Of course, the scholars discussed here do not elaborate on how their observations fit into a broader theoretical framework with respect to the path of the energy transition or the phenomenon of legal change—that is the task of this Article. Nonetheless, the fact that these scholars have identified trends in the energy and environmental law fields that are consistent with the legal mid-transition framework lends support to the idea that this model is both an accurate and useful description of the current transition in energy law.

To further prove this last point, the Article now turns to a more comprehensive description of how the legal mid-transition framework works in the context of specific areas of energy law, drawing from both some of the scholarly work summarized above and on-the-ground examples of the energy transition.

II. The Laws of the Mid-Transition

This Part introduces and explains the Article’s two primary examples of the legal mid-transition in the context of the clean energy transition: the laws governing the local distribution and sale of natural gas and the laws governing electricity resource adequacy. For each example, the Section first describes the “old” and “new” laws of the system, corresponding to the old fossil fuel system and the new clean energy system. The Section then discusses how the coexistence of the old and new legal systems constrains both. This analysis reveals an important discovery: The overlap of the new and old laws tends to result in a phenomenon of redundancy and compartmentalization.

A. The Laws of Natural Gas Distribution

More than half of American homes use natural gas for space heating, water heating, cooking, and clothes drying.⁵⁴ Natural gas is also one of the primary sources of energy used by commercial buildings in the United States.⁵⁵ Together, this direct consumption of natural gas is responsible for a significant portion of our domestic greenhouse gas emissions: Consumption of natural gas by the residential and commercial sectors accounted for around 78 percent of their direct carbon dioxide emissions in 2022,⁵⁶ and these direct emissions made up approximately 13 percent of total U.S. greenhouse gas emissions for that year.⁵⁷ As a result, any effort to move towards a zero-carbon energy system would require either eliminating direct consumption of natural gas or capturing its associated emissions.⁵⁸

Reducing or eliminating residential and commercial use of natural gas, in turn, would require changing the laws that currently support its local distribution and sale. In most jurisdictions, these laws follow a traditional model of public utility regulation. Thus, the “old” legal framework that will have to be altered or phased out is relatively clear. What will replace that framework, the “new” legal framework, is less certain, although policymakers and regulators have proposed several different models, some of which are being tested in small pilots throughout the country. Regardless of which new legal framework is eventually settled upon, the dismantling of the old legal framework will depend on and will happen coincident with the introduction of the new legal framework.

1. Law of the Old System: The Natural Gas Utility

Most residential and commercial consumers in the United States receive natural gas from a natural gas utility. Under this model, natural gas utilities (typically private companies⁵⁹) are given a monopoly by the state to provide natural gas to end-use consumers in a defined geographical area. In return for this monopoly protection, the state (often in the form of a state agency known as a public utility commission) regulates the utilities’ rates and terms and conditions of service. For instance, under traditional public utility regulation, the utility is authorized to charge only “just and reasonable” rates for its service; the utility is required to provide service to any customer within its geographic area (often referred to as the “obligation” or “duty to serve”); the utility must provide service on equal terms to all of its customers (often known as the “undue discrimination” standard); and the utility is required to provide “safe and adequate” service.⁶⁰

There are several features of this regulatory regime that are important to the discussion here. The first is the utility’s “duty to serve.” This duty encompasses several different concepts, including: (1) the utility’s obligation to continue to provide service to customers once service has begun;⁶¹ (2) the utility’s obligation to extend service to prospective customers within its territory upon request, even if doing so would be uneconomic for the utility;⁶² and (3) the utility’s inability to discontinue service on its system unless the utility can demonstrate a compelling reason for abandonment (e.g., a lack of demand on the system or severe economic loss).⁶³ Additionally, depending on state law, the duty to serve may be defined as the obligation to provide a particular kind of service (e.g., natural gas service),⁶⁴ or may be described in more general terms such as the duty to “furnish and maintain adequate, efficient, safe, and reasonable service.”⁶⁵ Altogether, the duty to serve can be thought of as an obligation on the part of the gas utility to provide service to all current and prospective customers within its territory, and to continue doing so as long as there is some minimal demand on the system.

The second feature relevant here is the utility’s obligation to provide “safe and adequate” service. This provision could be thought of as supplementing the utility’s duty to serve: The utility is obligated not just to provide service but also to provide a certain minimum level of service.⁶⁶ Again, this will vary depending on state law, but in the context of a natural gas utility, the law may specify certain minimum physical characteristics like the heating value of gas.⁶⁷ Additionally, all natural gas utilities must comply with certain minimum safety standards, including quality and maximum viable pressure standards for local gas pipelines.⁶⁸ Importantly, the gas distribution system is interconnected, so a leaky or aging pipe on one part of the utility’s system—or changes in consumption patterns, including drops in consumption—can affect pressure across its distribution system, potentially posing safety risks. Thus, gas utilities are obligated to ensure that their entire distribution system is safe regardless of what level of service is being provided.

Finally, the last component relevant for this discussion is the state’s regulation of utilities’ rates. Rate regulation can be thought of as involving the balancing of utility and ratepayer interests: The state regulates utilities’ rates to ensure that utilities do not use their monopoly power to extract exorbitant rates from their customers, on the one hand, and to ensure that utilities earn sufficient revenues to operate their business, on the other.⁶⁹ Consistent with this approach, a “just and reasonable” rate for a local gas utility is usually one that allows the utility to recover its costs of providing service plus some reasonable rate of return.⁷⁰ Because the capital costs of constructing a gas distribution system can be quite high, these costs are often amortized over the period of the infrastructure’s useful life (usually estimated at several decades). Thus, when a gas consumer pays their gas bill, they are often paying for some portion of the fixed costs associated with the construction of the gas infrastructure, as well as the variable costs associated with operating and maintaining that infrastructure, with the assumption that over a sufficient period of time the utility will eventually recover the costs of its investment.⁷¹

2. Law of the New System: The Electric or Heat Utility

We do not yet know exactly what the law of the “new” system will look like, in part because we do not yet know what technology will replace the services that are currently provided by natural gas. Nonetheless, two possibilities have appeared in those areas of the country that are at the forefront of efforts to reduce reliance on natural gas: full electrification and a networked heat system.⁷² The first possibility should be relatively intuitive for readers. Many Americans already rely on electricity to provide some portion of their energy services; full electrification would entail shifting those parts of residential and commercial energy consumption that currently rely on natural gas to electricity. The second possibility is also not new but less common. Networked heat systems involve a system of insulated underground pipes that circulate heat to generate both heating and cooling services, typically through geothermal technology.⁷³ Networked heat systems could supplement space and water heating and cooling currently provided by natural gas.⁷⁴

These new energy technologies could be provided to consumers through a variety of different regulatory models.⁷⁵ For purposes of the discussion here, it does not much matter which model is used. Regardless, the “new” legal framework is likely to exhibit at least two features: first, a reimagined duty to serve, and second, the building out of a significant amount of new distribution-side infrastructure to support that service.

On the first point, it is likely that, whatever the “new” electric or heat utility looks like, the utility will be subject to a duty to serve akin to the one that currently governs natural gas utilities.⁷⁶ That is, the utility will be responsible for providing safe and adequate service to all customers within its geographic area. The primary difference will be the type of service: It may involve electric service, or heat service, or it may be defined more generally as “energy services.”

Additionally, to support this reimagined duty to serve, the utility will have to build out a significant amount of new distribution-side infrastructure. For the electric utility, that could entail extending electric distribution lines to communities that do not already have them; upgrading existing electric distribution lines to support additional capacity on those lines; and, possibly, engaging in “behind-the-meter” electrification of homes and buildings, which would involve exchanging natural gas appliances for electrified options. For the heat utility, that would entail building out a system of networked heat lines and, again, possibly retrofitting home and building heating and cooling systems to adapt them to the new technology.

3. The Legal Mid-Transition: Coexistence and Constraint

For both the old and new legal systems, the most difficult period to manage will likely be the period of legal mid-transition, when the old system is not yet fully phased out and the new system is not yet fully online. Importantly, these difficulties arise not just because of the phasing out or phasing in of each system considered in isolation, but because of the simultaneous presence of both legal systems operating together. The two legal systems impose constraints on each other: The continued presence of the old law of the natural gas utility influences and meaningfully restricts the introduction of the new law of the electric/heat utility, and (in some cases) vice versa. This dynamic can be seen with respect to the three legal features of the natural gas utility discussed above—the duty to serve, the duty to provide safe and adequate service, and rate regulation.

First, with respect to the duty to serve, this legal obligation on the part of the gas utility means that if a customer within its service territory requests service, the utility cannot deny that request for service, even if the utility is simultaneously trying to reduce its reliance on natural gas.⁷⁷ The implication of this is that a natural gas utility’s service territory cannot be converted to the new heat or electric utility unless every customer within the relevant service territory agrees to be placed on the new utility system (or, put differently, all customers agree not to request gas service). The conversion of the system can happen only if there is a 100 percent participation rate in the transition.

In segments of the country where this conversion process has begun, utilities and regulators have identified the natural gas utility’s duty to serve as constraining their ability to introduce the new legal system.⁷⁸ For instance, in California, one of the state’s largest gas distribution utilities (which is actually a combined electric/gas utility), Pacific Gas and Electric (PG&E), has begun dismantling parts of its natural gas distribution system to comply with the state’s decarbonization goals.⁷⁹ As part of this decommissioning program, known as its “Alternative Energy Program,” PG&E has converted 105 customers to full electrification and decommissioned 4.4 miles of gas distribution pipelines and 22 miles of gas transmission lines, avoiding what would have been expensive maintenance and repair of gas lines.⁸⁰ While PG&E notes the success of this program, it has also raised concerns that the model is limited by the utility’s duty to serve. PG&E has pointed out that each “AEP” project tends to convert only five or fewer customers because the “gas utility’s obligation to serve lead[s] to the possibility of a single customer to halt an otherwise economically promising electrification project by declining to participate.”⁸¹ PG&E has observed that “[e]ven at this small scale and with offering generous customer rebates,” its AEP program “has a success rate of approximately 40 percent of customers opting to electrify.”⁸² The utility has reported to regulators that unless its obligation to serve is modified, “significant portions of the gas system would need to remain” in service through 2045.⁸³

One way to address this concern would be to amend the law to remove the natural gas utility’s existing obligation to serve. But legislators will almost certainly not agree to that amendment unless there is the simultaneous creation of a new obligation to serve—in other words, the legislative enactment of the “reimagined” duty to serve described above. Alternatively, depending on the state law, regulators might be able to act without legislative involvement by reinterpreting the natural gas utility’s existing obligation to serve to be one that can be satisfied through the provision of an alternative energy service.⁸⁴ Indeed, we have already seen some states enact legislation authorizing the modification of the gas utility’s duty to serve conditional upon the simultaneous introduction of a reimagined duty to serve that would be satisfied through alternative service provision.⁸⁵

Both the limitations of the natural gas utility’s existing duty to serve and the introduction of the reimagined duty to serve demonstrate the constraints that the new and old laws pose on each other. In the first case, the continuing presence of the old natural gas duty to serve limits the ability of the new electric or heat utility to come online: The latter is hampered so long as the former still exists. In the second case, the absence of the reimagined duty to serve impedes the unraveling of the old natural gas duty to serve: The latter cannot be undone unless and until the former is sufficiently in place.

Moreover, the old natural gas utility’s duty to provide safe and adequate service overlapping with the introduction of the new heat/electric utility creates what might be thought of as a further obligation for redundancy during the period of the mid-transition. Under its duty to provide safe and adequate service, the natural gas utility is obligated to continue providing service to those customers who have not yet been moved onto the new energy system. Because of the interconnected nature of the natural gas system, this may mean that the natural gas utility will have to maintain a significant part of its distribution system in its existing state, even as the number of customers on the system decreases, simply to preserve minimum safety and service standards. For instance, a study commissioned by the California Energy Commission to find viable places for targeted decommission of PG&E’s natural gas distribution system determined that if projects were screened so that they (1) were limited to areas of the gas utility’s system that were not already designated for pipeline repair or replacement in the short term (presumably to address safety or maintenance concerns), and (2) satisfied certain hydraulic feasibility standards (i.e., did not strand customers outside of the project’s footprint or negatively affect gas system reliability or pressure for the remaining gas customers), then only approximately 5–10 percent of the utility’s gas distribution main miles qualified for decommissioning.⁸⁶

This analysis suggests that the decommissioning of the natural gas distribution system may look less like a gradual replacement of the old natural gas system with the new electric/heat utility system and more like a period in which two almost-full-scale distribution systems exist simultaneously, with the old system dismantled only once virtually all customers have been switched over to the new system. If that conclusion is correct, then the presence of the old law is yet again shaping the introduction of the new law. The old natural gas utility’s continuing obligation to provide safe and adequate service requires not just the perpetuation of a substantial part of the old natural gas distribution system, but also that the new electric/heat utility be essentially fully built out before the old infrastructure can be entirely dismantled.

Furthermore, the continuing rate regulation of the old natural gas utility constrains the way that costs can be allocated between the two systems during this period of redundancy. As the above discussion suggests, the obligation for redundancy ensures that all customers have some kind of energy service during the period in which the old natural gas utility is being phased out and the new electric/heat utility is being phased in. But the presence of rate regulation of the gas utility means that the old law compartmentalizes the responsibility to pay for this redundancy. Under rate regulation of the gas utility, only those who consume natural gas help pay for the costs of the natural gas system. And, perhaps even more importantly, when former natural gas customers exit the gas system for the new electric/heat utility, under the old legal framework, they are no longer on the hook for the costs associated with the gas distribution system. Thus, rate regulation of the gas utility forces us to think about cost allocation as segmented between the old gas system and the new electric/heat utility system, even as both systems are required by the presence of the other during this transitional period.

Altogether, the overlapping presence of the old and new laws imposes important constraints on both legal systems. The old duty to serve means that the new electric/heat utility cannot be introduced until the old natural gas utility is wound down, and the reimagined duty to serve means that the old natural gas utility cannot be wound down until the new electric/heat utility is sufficiently built up to provide the required service. The old duty to provide safe and adequate service means that the new electric/heat distribution system will have to be essentially fully built out before the old natural gas distribution system can be decommissioned, thus creating a kind of additional obligation for redundancy during this period of overlap. And the old system of rate regulation of the natural gas utility means that the costs for maintaining this redundancy are by default allocated such that users who exit the natural gas system are no longer responsible for paying for it, even when the presence of both the old natural gas system and the new electric/heat system plays an important role in service provision for all customers during this period.

These constraints exist only when the two legal frameworks coexist. Once the law transitions fully to the new electric/heat utility, the regulatory puzzles and challenges associated with this period of overlap will no longer apply. Thus, as in the engineering context, there is a moment during the energy transition of natural gas distribution in which the “old” and the “new” laws will overlap and produce unique configurations. This moment is the legal mid-transition.

B. The Laws of Resource Adequacy

Another aspect of our energy systems that will have to change in the face of decarbonization goals is our electricity sector. Our electricity sector was responsible for producing 25 percent of our domestic greenhouse gas emissions as of 2022, mostly from the burning of fossil fuels to generate electricity.⁸⁷ Additionally, plans to decarbonize other sectors of our economy often rely on converting those sectors to electricity generated from zero-carbon sources.⁸⁸ To achieve a substantial reduction in our greenhouse gas emissions, then, our electricity grid would have to shift from one that is based primarily on fossil fuels to one that, in the long term, is served primarily by renewable and zero-carbon resources.

Long-term electricity supply on the modern electricity grid is governed by a concept known as “resource adequacy.” Resource adequacy is the idea that there is a sufficient supply of electricity on the grid to satisfy demand at all times.⁸⁹ Resource adequacy is crucial for any grid. If electricity supply does not match demand instantaneously and at all times, then the frequency of the grid can fall outside of a very narrow acceptable range, leading to equipment failure and the risk of system-wide blackouts.⁹⁰ The laws governing resource adequacy, in turn, ensure that this balance is met over the long term.

Resource adequacy, however, has traditionally been conceived of and regulated in a way that fits fossil fuel resources. Specifically, resource adequacy has often been tied to a grid’s “capacity,” or the total amount of electricity that all power plants connected to the grid could theoretically generate, if those plants were operating at their maximum output.⁹¹ Thinking about resource adequacy in terms of capacity arguably makes sense in the context of a fossil fuel-based grid, because power plants that burn fossil fuels tend to be limited only by their fuel supply and their operational efficiency (at least theoretically—this is proving less true in practice, for reasons discussed below). But clean energy resources operate differently. For resources like wind and solar plants, their electricity supply depends on whether the sun is shining and the wind is blowing when electricity is needed, not their theoretical maximum output in the abstract. On a zero-carbon grid, resource adequacy is more a question of resource availability than resource capacity.

Thus, assuming a broader goal of decarbonization, our resource adequacy laws will have to be reconceptualized to suit a clean energy grid, so that they are incentivizing availability as opposed to capacity. Much like the natural gas example, however, the introduction of a new resource adequacy framework will happen while our old resource adequacy framework is still in place. The continued existence of the old framework during this period constrains and inhibits the introduction of the new zero-carbon grid.

1. Law of the Old System: Reserve Margins and Capacity Markets

In the United States, there is no one entity in charge of regulating resource adequacy. Technically, the Federal Power Act gives the Federal Energy Regulatory Commission (FERC), an independent federal agency, ultimate authority over ensuring that our electricity grid is reliable.⁹² Resource adequacy is a component, although not the sole criterion, of grid reliability.⁹³ But FERC delegates the authority for developing and enforcing resource adequacy standards to a private, nonprofit entity known as the North American Electric Reliability Corporation (NERC).⁹⁴ NERC, in turn, calculates resource adequacy standards for much of the electricity grid and uses those standards to conduct regular assessments.⁹⁵ But, in a rather convoluted and circuitous way, NERC delegates ultimate responsibility for developing and enforcing resource adequacy standards to a mix of state public utility commissions; electric utilities; and regional, private, nonprofit entities known as Regional Transmission Organizations (RTOs) or Independent System Operators (ISOs).⁹⁶

Despite this regulatory hodgepodge, our current resource adequacy laws can be generalized into two components: (1) the standards used to assess resource adequacy, which are roughly the same across the United States and are based on a concept known as a “reserve margin”; and (2) the mechanisms for implementing those standards, which vary depending on the region of the country, but one prominent form of which is known as a “capacity market.” Notably, both components were designed with a primarily fossil fuel-based grid in mind and are nice illustrations of how our existing resource adequacy laws will have to change in light of decarbonization.

First, to understand what reserve margins are and how they are intended to work requires a brief description of the electricity grid. The grid is broadly made up of three segments: (1) generation, or the mix of resources that supply electricity; (2) transmission, or the large, high-voltage lines that transport electricity across long distances; and (3) distribution, or the smaller, lower-voltage lines that carry electricity into people’s homes.⁹⁷ Traditionally, our electricity grid has relied on a standard set of resources to generate electricity. This has included a combination of “baseload” resources and “peaker plants.” Baseload resources are large, centralized power plants that generate a constant supply of electricity throughout the year to satisfy the minimum demand on the system. Peaker plants are smaller, fast-ramping plants that can be turned on and off as needed to satisfy periods of fluctuating demand, including the several days throughout the year (typically the hottest summer days or the coldest winter days) when demand on the grid reaches its maximum, or “peak.”⁹⁸ Historically, fossil-fuel plants have often made up a significant portion of both baseload and peaker plants; coal plants represent a classic baseload resource and natural gas plants represent a classic peaker plant.⁹⁹

On this kind of grid, ensuring a sufficient long-term supply of electricity—or, put differently, ensuring resource adequacy—has typically been thought to mean ensuring that there will be a sufficient supply of both baseload and peaker plants to satisfy the future peak demand on the system, taking into account risks of possible outages or unexpected spikes in demand. Thus, in most parts of the country, resource adequacy is measured based on the probability that electricity service will be lost due to insufficient capacity on the grid.¹⁰⁰ A typical acceptable level of such outages is one day of outage in a ten-year period.¹⁰¹ Grid planners convert this one-day-in-ten-years standard to a target for an overall amount of capacity.¹⁰² The resultant value is known as a “reserve margin,” which identifies the amount of capacity that an electricity grid would need—above the amount the grid is already expected to need to satisfy projected peak demand—to meet the one-day-in-ten-years standard.¹⁰³ Essentially all of the state or regional entities in charge of enforcing resource adequacy on the grid (a) rely on reserve margins to assess resource adequacy and (b) use a variety of regulatory mechanisms to ensure that their territories contain sufficient capacity to satisfy the reserve margin standard.¹⁰⁴

In many parts of the country, “capacity markets” are the regulatory mechanism enforcing the reserve-margin concept of resource adequacy. In these heavily regulated marketplaces, promises to make available electricity supply at some point in the future are bought and sold.¹⁰⁵ Capacity markets are designed and operated by RTOs and ISOs, subject to regulatory oversight by FERC.¹⁰⁶ The structure and regulation of RTOs and ISOs are quite complicated;¹⁰⁷ for our purposes here, it is sufficient to know that RTOs and ISOs were introduced in the 1990s and 2000s by FERC and some states to permit the competitive procurement of the wholesale electricity supply.¹⁰⁸ To that end, RTOs and ISOs operate short-term markets for the supply of electricity, often known as “energy markets,” where generators sell their electricity in real time, and utilities buy that electricity in order to resell it to their end-use customers.¹⁰⁹ But, for a variety of reasons, these short-term markets often do not provide enough revenue for generators to stay in business over the long term—particularly for those peaker plants that operate inconsistently throughout the year.¹¹⁰ Thus, some RTOs and ISOs also operate capacity markets, which are intended to provide an additional source of revenue for power plants to ensure that they are built—and will stay in business—to satisfy electricity demand in the future.¹¹¹

Capacity markets work as follows. The electric generators within a region submit bids offering to make their generation available at some point in the future.¹¹² The market operator in the region (the RTO or ISO) collects these bids and orders them from the lowest price bid to the highest price bid.¹¹³ The market operator also calculates an expected future demand curve for the region, which is based in part on the region’s reserve margin.¹¹⁴ The market operator then selects the bids, starting with the lowest price bid and moving progressively higher, until the expected demand curve is satisfied. The last bid selected, the marginal bidder, sets the “clearing price” for the market: All the generators whose bids were selected, including the marginal bidder, will receive this price for their offered capacity.¹¹⁵ In some RTOs and ISOs (particularly along the East Coast), the market operator then requires all electric utilities within the region to purchase an amount of capacity based on their proportional contribution to overall system demand—utilities in these RTOs/ISOs are not permitted to opt out of the capacity market.¹¹⁶ Additionally, to ensure generators follow through on their promises to make their generation available, generators may be obligated to pay a “non-performance” penalty if they fail to be available at the promised future time.¹¹⁷

There are a few design aspects of capacity markets that are worth highlighting for the discussion here. First, capacity markets are mechanisms for enforcing the reserve margin concept of resource adequacy. By setting the demand curve based on the region’s reserve margin and requiring utilities to purchase an amount of overall capacity consistent with that demand curve, the capacity market is intended to ensure that the reserve margin standard is achieved through a competitive bidding process.

Second, capacity markets tend to contain some embedded assumptions about how plant “capacity” ought to be defined and valued. For example, in the description above, the capacity market treats generators’ capacity as fungible, atomized units: Each generator bids individually, with the relevant information being its capacity and price, and units are stacked up until maximum demand is reached.¹¹⁸ The market does not take into account interactive relationships between resources, the possibility that a generator’s future ability to produce electricity might vary based on considerations like time of year or weather, or the possibility that generators might provide other valuable attributes like flexibility or fast-ramping capabilities.

These features and embedded assumptions are consistent with the historical, primarily fossil fuel-based electricity grid. On this kind of grid, it has made sense to think of resource adequacy as being primarily about reserve margins, and therefore about an enforcement mechanism that prioritizes obtaining enough capacity to meet those reserve margins. Additionally, that capacity has typically been composed of fossil fuel-based baseload resources and peaker plants, which have generally fit the atomized, fungible model described above. The whole idea behind baseload and peaker plants is that their capacity can be simply stacked on top of each other to reach peak demand. Reserve margins and capacity markets thus are designed for a particular kind of fossil fuel-based electricity grid.

2. Law of the New System: Subsidies, Availability, and Capacity Market Replacements

As we shift to a primarily renewable or zero-carbon grid, ensuring an adequate long-term supply of electricity resources to satisfy demand will still be an important concept, but the way that we think about it and the mechanisms for implementing it will be different. As in the natural gas distribution example, it is not entirely clear at this moment what will come to replace our old resource adequacy laws. Nonetheless, the laws of this new grid will likely include at least three things. First, at least in the short term, building out this new grid has involved laws subsidizing or, in some cases, mandating the construction of new renewable or zero-carbon resources. Second, over the longer term, there will have to be a reconceptualization of resource adequacy away from an emphasis on reserve margins and towards a notion of resource availability. Third, although this is the least certain aspect of the law of the new grid, it is likely that capacity markets as they are currently conceived will have to be replaced by some other regulatory construct to ensure sufficient long-term supply of zero-carbon resources.

Taking the subsidies piece first: If we are evaluating the laws that govern the long-term supply of renewable and zero-carbon electricity on the grid, we must include in that category the significant state and federal laws that have subsidized—and, in some cases, mandated—the construction and maintenance of renewable and zero-carbon resources.¹¹⁹ These laws have existed for several decades.¹²⁰ Most prominently, they have taken the form of state-level renewable portfolio standards or clean electricity standards,¹²¹ as well as federal tax credits and subsidies for clean energy resources like those in the Inflation Reduction Act.¹²² Overall, more than half of the states have adopted some version of a requirement or voluntary goal for the procurement or construction of renewable or clean energy resources.¹²³ These state laws are estimated to be responsible for almost half of all growth in renewable energy generation and capacity since 2000; and current state-level targets would require an additional nine hundred terawatts of clean electricity by 2050.¹²⁴ Additionally, tax credits from the Inflation Reduction Act were estimated to result in an average of fifty-eight gigawatts of wind and solar deployment annually from 2021 to 2035, more than double what was seen prior to the passage of the Act.¹²⁵ Of course, these numbers are likely to change given the passage of the One Big Beautiful Bill Act in 2025, which amended or repealed many of the Inflation Reduction Act’s energy tax credits and subsidies.¹²⁶ Nonetheless, it is clear that state- and federal-level subsidies have played a significant role in spurring renewable and zero-carbon electricity capacity, and at least some of these laws will likely continue to play an important role in building out the new clean energy grid. What remains to be seen is whether they should be considered short- or medium-term laws of the new grid, or permanent fixtures of the post-transition period.

Second, while resource adequacy will still be an important concept on the new grid in the long term, it will require reconceptualization in light of the different set of challenges that a zero-carbon grid faces. Resource adequacy rules on the new grid will have to focus on resource availability and resource portfolios as opposed to capacity and reserve margins. This is because an electricity grid that runs primarily on renewable or zero-carbon resources is less likely to rely on baseload power and peaker plants and more likely to rely on “variable” resources. Variable resources are those whose output varies depending upon the circumstances—like the time of day, the weather, and the season.¹²⁷ Classic examples include wind and solar power: Wind turbines generate electricity only when the wind is blowing, and solar plants generate electricity only when the sun is shining. A less common but equally important example is batteries: Under existing technologies, batteries can generate electricity only when they have been able to charge on the grid and only for so long as their storage capacity permits.¹²⁸ Even resources that have traditionally been thought of as providing a predictable amount of capacity are proving to be more variable in practice than initially understood. A natural gas plant’s performance, for instance, depends significantly on the weather: During cold spells, natural gas plants are more likely to freeze or experience supply constraints, causing plant failures that can prove catastrophic during extreme weather events.¹²⁹ Extreme weather events might also make other resources typically thought to produce consistent amounts of electricity—like hydropower plants—variable in practice.¹³⁰

On a primarily renewable or zero-carbon grid, then, the concern with resource adequacy is not one of capacity but of availability. The notion of “peak demand”—or the few days out of the year when demand is the highest—is less useful on a grid that is energy-limited. The most difficult times to ensure availability are not when overall demand on the system is highest, but rather when high levels of demand coincide with periods when electricity is least likely to be available, e.g., in the evenings, when solar power is offline and electricity consumption increases as people return home from work.¹³¹ The ability of the grid to satisfy demand, then, is not limited by the overall amount of capacity that exists to supply it, but rather the amount of energy that will actually be able to be generated to satisfy demand at any given point in time.¹³²

Thus, ensuring resource adequacy on the new grid will likely involve creating portfolios of resources that can satisfy demand at any given time, rather than adding up the capacity of individual plants to satisfy a reserve margin based on peak demand.¹³³ Grid planners will have to incentivize bundles of resources that complement each other—for instance, combining solar and battery storage on the grid increases the ability of both resources to supply electricity¹³⁴—and discourage overreliance on single sets of resources, which can result in diminishing returns in terms of both availability¹³⁵ and the risks of failure during outages.¹³⁶ Additionally, thinking about resources in terms of portfolios opens up the crucial need to incorporate nontraditional, nongeneration resources into the mix. This includes new transmission lines that enable consumers to draw from a geographically diverse array of resources; demand-side programs and technologies that allow consumers to reduce their consumption in response to supply shortages; or “virtual power plants” that aggregate together many small-scale resources like rooftop solar panels or electric vehicles.¹³⁷

Finally, under this new resource adequacy paradigm, it is likely that capacity markets as they are currently constructed will no longer exist. At the most basic level, a regulatory mechanism intended to provide additional revenue to baseload and peaker plants to ensure that an administratively-calculated reserve margin is satisfied will no longer be relevant.¹³⁸ It is possible that some of the design aspects of capacity markets could be changed to accommodate the resource availability/portfolio approach to variable resources.¹³⁹ But, at the end of the day, designing a well-functioning capacity market (where promises to make available a specified amount of capacity in the future are exchanged) for variable resources (where it is inherently difficult to know what amount of capacity will be available in the future) is quite challenging. As some scholars have put it, trying to fit variable resources like wind and solar power into a capacity market is like trying to fit a square peg into a round hole.¹⁴⁰

It is not yet clear what will replace the capacity market. Some have suggested other kinds of market designs that may be better suited to a zero-carbon grid.¹⁴¹ Others have pointed out that not all RTOs and ISOs use mandatory capacity markets to enforce resource adequacy standards, relying instead on a mix of scarcity pricing, long-term bilateral contracting, self-supply, and voluntary markets, and thus we might see consolidation around these other enforcement mechanisms.¹⁴² Still others have observed that the political economy of renewables is such that competitive wholesale marketplaces may not be the ideal model for managing electricity supply and demand.¹⁴³ At this point, it is difficult to know what resource adequacy enforcement mechanisms will look like on the electricity grid in twenty or thirty years, but it is likely that they will bear little resemblance to today’s mandatory capacity markets.

3. The Legal Mid-Transition: Coexistence and Constraint

As in the case of the natural gas distribution example, the most difficult period to manage resource adequacy on the electricity grid will be the period of legal mid-transition. The two legal systems impose constraints on each other: the continued presence of the old resource adequacy laws influences and meaningfully restricts the introduction of the new zero-carbon grid and its new resource adequacy laws. This dynamic can be seen most acutely within the context of the mandatory capacity markets. So long as old capacity market rules remain in place, even as new resource adequacy laws are being introduced, capacity markets are naturally going to favor the capacity produced by conventional fossil fuel generators, and discount or miss the contributions of zero-carbon resources to resource adequacy due to the mismatch between resource capacity and resource availability. Further, to the extent that these fossil fuel resources are not actually required to maintain resource adequacy standards, the old resource adequacy laws could perpetuate the existence of the old fossil fuel grid beyond the point at which it is actually needed, simultaneously inhibiting the introduction of the new grid.

Indeed, this is precisely the dynamic we have seen play out in the eastern RTOs and ISOs over the last decade or so, a dynamic that is the subject of much of the recent energy law scholarship discussed in Part I.¹⁴⁴ Until recently, the capacity markets in these regions maintained design parameters that clearly favored conventional fossil fuel resources over zero-carbon resources. In PJM, the mid-Atlantic RTO that includes thirteen states and the District of Columbia, the capacity market included rules (1) requiring resources in the region to bid into the market three years ahead of when their energy would actually be needed, without regard to the time of year;¹⁴⁵ (2) calculating resources’ individual capacity based on a comparison to the resource’s theoretical maximum output, with fossil fuel resources rated more highly than renewable resources;¹⁴⁶ and (3) treating each resource individually without regard to the mix of resources that would be available on the grid or the resource’s marginal contribution to the resource adequacy of that mix.¹⁴⁷ Not surprisingly, from 2007 to 2017, nearly all of the new capacity that cleared the PJM capacity market consisted of natural gas plants¹⁴⁸—the cheapest fossil fuel resource that performed well under these metrics.¹⁴⁹

This did not mean that renewable or zero-carbon resources were not built in the PJM region during this period. Quite the contrary; over the same time horizon, several states within PJM had adopted new resource adequacy laws in the form of state renewable portfolio standards that required their utilities to secure around 15 percent of their electricity from renewable or zero-carbon resources by 2017.¹⁵⁰ But because of the design parameters within the PJM capacity market—as well as additional market rules introduced by PJM during this time—the renewable generation that utilities secured to satisfy their state renewable portfolio obligations was not able to count towards those utilities’ resource adequacy obligations as enforced through the capacity markets.¹⁵¹ These utilities were thus obligated to continue to pay for fossil fuel capacity within the PJM capacity market, even as those utilities were also required to procure renewable or zero-carbon resources, when it was not clear that this double capacity was actually needed to support resource adequacy.¹⁵²

We saw a different manifestation of a similar problem in PJM’s capacity markets in the summer of 2024. Over the prior year, PJM had reformed some of its capacity market rules—particularly how it calculates an individual resource’s contribution to the system’s overall capacity needs—to try to better value variable resources in the capacity market.¹⁵³ But PJM’s capacity market reforms reflected tinkering at the edges of the capacity market problem. They did not address the broader issue that thinking about resource adequacy as a matter of capacity alone is no longer sufficient, and that addressing resource adequacy on the new grid requires a portfolio approach that includes nontraditional resources like new transmission infrastructure.¹⁵⁴

As a result, in the summer of 2024, the old resource adequacy framework of PJM collided yet again with the new resource adequacy laws of the new grid. In part due to the subsidies provided by the Inflation Reduction Act, the 2022–2023 period saw a flood of new clean energy resources seeking to connect to the electricity grid within the PJM region.¹⁵⁵ But because PJM had not made any significant changes to its transmission interconnection process to reflect the requirements of the new zero-carbon grid, much of this new clean energy capacity got stuck in a Kafkaesque application process to actually hook up to the PJM grid.¹⁵⁶ Meanwhile, PJM ran its 2024 summer capacity auction as planned—asking all resources that were already hooked up to the grid to bid in their ability to provide electricity three years into the future—with no mechanism to account for the vast clean energy resources that were waiting in line and might be able to provide electricity in the future. As a result, the PJM capacity market continued to provide a stream of revenue for fossil fuel resources, despite attempts to incentivize clean energy generation. The 2024 summer capacity market yielded $14.7 billion in market payments to existing generators, with fossil fuel resources comprising more than 60 percent of that generating capacity.¹⁵⁷ In the meantime, the total amount of capacity that was sitting in PJM’s interconnection line waiting to be processed was almost double the amount ultimately secured through the 2024 summer capacity market, and virtually all of this capacity consisted of clean energy resources.¹⁵⁸

Of course, not all of this clean energy capacity may be available to provide electricity in the future; and at least some of the capacity that cleared PJM’s 2024 summer capacity auction will likely be needed to satisfy future demand. But the incident shows how, yet again, the continued presence of PJM’s old approach to resource adequacy is (a) failing to account for new resource adequacy laws that contribute to ensuring sufficient electricity supply to satisfy demand in the future, (b) maintaining a resource adequacy enforcement mechanism that is unlikely to reflect true resource adequacy needs on the grid, and (c) inhibiting the introduction of the new zero-carbon grid and perpetuating the existence of the old fossil fuel grid.

Taking a step back, the coexistence of PJM’s old resource adequacy laws with the new laws of the zero-carbon grid produces a redundancy and compartmentalization phenomenon akin to that seen in the natural gas distribution context. That is to say, in the resource adequacy context, the coexistence of the old and new laws creates a fossil fuel-based track for resource adequacy (in the capacity markets) and a clean energy-based track for resource adequacy (in the state and federal laws supporting clean energy resources), with each track being paid for through separate mechanisms. Unlike in the natural gas distribution example, however, this two-track approach threatens overall resource adequacy (for reasons discussed further in Part III), rather than ensures that, for instance, the duty to provide safe and adequate service is maintained throughout the transition. As a result, figuring out how to integrate these two tracks—or put more broadly, how to wind down the old resource adequacy laws at the same time that the new resource adequacy laws are introduced—while maintaining overall resource adequacy on the grid is the challenge of the legal mid-transition in the electricity context.

III. The Challenges of the Mid-Transition

Managing the bidirectional flow of the law during the period of the legal mid-transition poses unique challenges in both the gas distribution and wholesale electricity contexts. As described above, the wind-down of the laws associated with the “old” fossil fuel-based energy system will have to happen in concert with and is contingent upon the introduction of the laws for the “new” clean energy system. Furthermore, during this time when some laws are phasing out and some laws are phasing in, additional challenges with respect to the broader regulation and management of our energy systems arise. First, the simultaneous phasing out and phasing in can make it more difficult to ensure energy provisioning is safe, reliable, and affordable. Second, because this period poses unique challenges to safety, reliability, and affordability, regulators will be pushed to respond and may do so in a maladaptive way. That is, regulators (or other parties) may propose solutions that address the basic requirements of energy regulation in the short term but, in the long term, stall the law in the mid-transition phase. Finally, this period of overlapping legal regimes carries a significant risk of offloading blame for failures onto the laws of the new system, undermining support for the energy transition itself.

A. Ensuring the Basic Requirements of Energy Regulation

During the mid-transition period, when two different regulatory models exist to satisfy the basic requirements of the legal regime, coordination across these two regulatory models will be difficult. In particular, the tendency during this period for the law to produce redundant or parallel energy systems, and to compartmentalize legal treatment of the costs of these two systems, makes guaranteeing the safe, reliable, and affordable provisioning of energy services uniquely challenging.

1. The Laws of Natural Gas Distribution

Take, for example, the natural gas distribution utility. As Part II describes, the need to ensure safe and adequate service already produces the need to maintain redundant energy distribution systems during this period. Moreover, maintaining safe, reliable, and affordable services as the gas system is being wound down and the new electric/heat alternative is simultaneously being built out is especially challenging. These challenges are essentially three-fold. First, the ongoing maintenance of the gas utility will require financial investment even as the system is ultimately slated for closure. Second, the simultaneous build-out of the electric/heat alternative means that the significant upfront costs of constructing this system will have to be expended while the gas utility is still being maintained. Third, the rate regulation of the gas utility means that the law already compartmentalizes the costs associated with these two systems to some degree, thus placing the burden of paying for the maintenance of the gas utility on the customers who remain on the gas system. This compartmentalized cost allocation frustrates all three requirements of safety, reliability, and affordability.

First, the ongoing maintenance of the gas utility means that this system will require financial investment even as the system is ultimately slated for closure. The expenses associated with maintaining this system can generally be placed into two buckets. First, the gas utilities have already spent a significant amount of money building out the existing gas distribution system, with the expectation that the costs of paying for that system would be paid back by gas customers over a multidecade time horizon. Although gas customers have already repaid some of those costs, there is still a significant portion that remains, which one study currently estimates at around $150–$180 billion nationally.¹⁵⁹ Second, if the gas utility is to be maintained during the transition to the electric/heat alternative, then ongoing maintenance costs to ensure the safe and reliable operation of the gas distribution system will also have to be paid. Again, these maintenance costs are likely to be significant. In California alone, gas utilities are projected to spend $43 billion over the next twenty years to replace aging gas mains.¹⁶⁰ Indeed, as time progresses, expenditures related to safety and reliability are expected to dominate utilities’ capital investments.¹⁶¹

Second, the simultaneous build-out of the electric/heat alternative means that the significant upfront costs of constructing this system will have to be paid for while the gas utility is still being maintained. Over the long term, it is possible that the electric/heat utility alternative will result in an overall decrease in ratepayers’ energy bills as compared to business as usual.¹⁶² But the upfront costs associated with building out this new system—in particular, retrofitting buildings to accommodate the new electric/heat alternative—are likely to be significant.¹⁶³

Third, the compartmentalization of the gas system from the new electric/heat alternative means that, under existing law, only those who consume gas are responsible for paying for the costs of the gas system. This cost allocation not only makes the affordable provisioning of energy to gas customers during this period especially difficult but also threatens the safety and reliability of the gas system. Under the standard public utility model, the significant costs of maintaining a natural gas distribution system are eased somewhat by distributing those costs amongst a large and expanding consumer base: Each additional consumer helps reduce the average fixed costs paid by every consumer on the system. On a natural gas distribution system that is being unwound, however, the opposite forces are at play. A shrinking customer base is being asked to pay for an increasing proportion of the costs. Indeed, some studies have predicted that without regulatory intervention, gas customers’ costs could increase by as much as 71 percent over a twenty-year period as customers leave the old system for the electric/heat alternative.¹⁶⁴ Moreover, utilities and regulators predict that those customers who are likely to leave the gas utility first will be the higher-income customers who are more willing and able to weather the transition. That means that the customers who are most likely to remain behind are the ones who will be least able to shoulder the increasing per-customer costs of the gas system.¹⁶⁵ Obviously, this scenario—of a declining gas utility system whose costs are increasingly composed of expenditures related to safety and reliability, and are increasingly paid for by low-income customers who cannot afford the additional cost burden—threatens to undermine all three of the basic requirements of energy regulation.

Further, the compartmentalization of the gas and electric/heat systems during this period makes taking advantage of potential cost savings that could result from the transition more complicated. In a study identifying viable places for PG&E’s targeted decommissioning of its natural gas distribution system, researchers determined that, in many cases, the total benefits of decommissioning exceed its total costs¹⁶⁶—mostly as a result of the avoided costs of maintaining the existing pipeline infrastructure.¹⁶⁷ Indeed, the researchers estimated that in California, up to $20 billion in future pipeline replacement costs could be avoided through targeted decommissioning.¹⁶⁸ But researchers found that the impact of the targeted decommissioning varied significantly from an individual customer perspective. Although decommissioning and electrification provided net benefits from a systemwide perspective, examining individual electrifying customers revealed that these customers experienced a per-customer upfront electrification cost that exceeded the benefits they were expected to receive.¹⁶⁹ One response to this could be allocating some of the cost savings from avoided maintenance of the gas system to these customers, which would make decommissioning net beneficial for everyone.¹⁷⁰ On the other hand, these savings could instead be allocated to the remaining gas customers on the system, who are otherwise likely to experience significant gas cost increases.¹⁷¹ Thus, the researchers identified a tension between the affordability of energy services for gas customers and electrifying customers during the mid-transition—a tension that is produced when these two systems are compartmentalized.

2. The Laws of Resource Adequacy

Similar challenges with respect to ensuring the safe, reliable, and affordable provisioning of energy services on redundant and compartmentalized systems also appear in the electricity context. This can be seen in the PJM electricity grid example. As discussed in Part II, during the legal mid-transition, PJM’s capacity market framework tends to procure fossil fuel generation under the old resource adequacy laws, and state and federal renewable and zero-carbon subsidies tend to procure clean energy resources under the new resource adequacy laws. Assuming these two frameworks are not integrated together, and instead operate in parallel, their uncoordinated coexistence poses a threat to both reliability and affordability in the PJM region.

First, as noted, PJM’s capacity market tends to procure a significant amount of gas-fired power plants because they are the cheapest resources that fit the notion of “capacity” valued by the market. The resources that these gas-fired power plants tend to beat out in the market are other, more expensive fossil fuel resources—like coal plants and combined cycle turbines. In fact, cheap natural gas plants have lowered prices in the PJM capacity market to such a degree that they are making it uneconomic for these more expensive fossil fuel resources to operate.¹⁷² Indeed, PJM’s market monitor has predicted that up to fifty-eight gigawatts of existing generation capacity could retire between now and 2030, with the majority of that capacity retiring because it is no longer economic,¹⁷³ and the majority of that retiring capacity consisting of coal plants and combined cycle turbines.¹⁷⁴ Already, in 2024, more than 50 percent of the installed capacity within PJM’s capacity market consisted of natural gas plants,¹⁷⁵ up from around 30 percent in 2014.¹⁷⁶

As it turns out, this pattern of procuring mostly natural gas plants to satisfy capacity requirements is worrisome from a reliability perspective. Natural gas plants tend to be vulnerable to equipment and supply failures during extreme cold weather, which can be dangerous if natural gas plants make up a significant portion of supply on a grid.¹⁷⁷ Indeed, in the last decade alone, PJM has experienced two severe cold snaps that saw almost a quarter of generation on the PJM grid fail, with, in the first instance, more than 40 percent, and in the second instance, more than 70 percent of that failed generation consisting of natural gas plants.¹⁷⁸ During both of these events, grid operators had to resort to emergency measures to keep the lights on.¹⁷⁹ Only in its most recent changes to its methods for valuing capacity in the market has PJM started to recognize the risk that this procurement of primarily gas-fired plants poses to the region’s reliability.¹⁸⁰

Moreover, this problem is not solved simply by introducing new resource adequacy laws supporting the construction of zero-carbon resources without any effort to integrate or coordinate the two resource adequacy systems. First, the failure to integrate the two systems can render these zero-carbon resources unable to compete in the PJM capacity market, resulting in essentially no change to the market outcomes (i.e., the market will continue to pay primarily natural gas plants to stay open). Second, the failure to integrate these two systems can also result in the more fundamental inability of these new resources to even connect to the electricity grid—as seen most recently in PJM’s interconnection morass—meaning that these resources cannot generate electricity to satisfy demand during periods of need, much less count towards PJM’s capacity requirements. Third, even if these resources are ultimately connected to the grid, there is no guarantee that they will fill in the reliability gaps PJM’s existing resource mix creates or ensure reliability on their own. If, for instance, the state or federal laws resulted in the construction of only a significant amount of solar generation, this solar power would be unlikely to supply power at the times it is most needed. Relatedly, solar power on its own, without an additional portfolio of resources that can help supply electricity during the evening, is also insufficient to ensure reliability. Indeed, the problems of correlated outages and seasonal and hourly variability are precisely the reason why resource adequacy frameworks must shift from a focus on capacity to a focus on availability.

If these two different resource tracks are not integrated, then consumers are at risk of paying more for capacity without any assurance that those higher prices bring them greater reliability. The most recent capacity market auction conducted by PJM in 2024 resulted in $14.7 billion in payments to incumbent generators. Ultimately, electricity ratepayers in the PJM region will pay for these costs. Although it is difficult to predict what the impact of these costs will be for individual ratepayers, some have estimated that they could lead to electricity bill increases of 10 to 20 percent in the PJM region.¹⁸¹ Maryland—a state located within PJM—estimated that PJM’s 2024 capacity auction will result in an additional $504 million in capacity costs for certain Maryland electricity customers as compared to the prior year, which translates into an average electricity bill increase for Maryland residential customers of $16 per month.¹⁸² Over the same period, Maryland ratepayers were also helping pay for the renewable and clean energy subsidies that were being provided by the Inflation Reduction Act. But the failure to integrate these two frameworks means that Maryland ratepayers are likely paying more than they ought to for capacity.¹⁸³

These examples demonstrate how the coexistence of two legal systems—with two parallel energy provisioning systems compartmentalized by the law—can complicate the satisfaction of the basic requirements of energy regulation. As the electricity example also demonstrates, the response of regulators to these challenges can exacerbate or compound these problems—a problem that this section turns to next.

B. Maladaptations

The legal mid-transition is a period in which the risks of maladaptive legal or regulatory responses are high. As explained above, it is likely that, during this period, regulators will face unique challenges in ensuring that the basic requirements of the system are met. Concerns about safety, reliability, or affordability may prompt regulators or other actors to respond with solutions intended to preserve the stability and integrity of the system during the transition. These maladaptations might be the product of good-faith concerns about the unique challenges of the legal mid-transition period, but they could also be opportunistic or self-interested responses of industries or individuals who are likely to be negatively impacted by the transition. Thus, it will be particularly important for regulators during this period to scrutinize all solutions proposed to ensure that they will not ultimately undermine exit from the mid-transition, even if they look appealing in the short term. Notably, one feature that may help identify and reveal maladaptive responses is legal or regulatory solutions that perpetuate the redundant and compartmentalized approach to the law that appears during the legal mid-transition, rather than solutions that attempt to integrate the legal systems.

Consider, for instance, the response of Massachusetts’s gas utilities to the state’s regulatory proceeding evaluating the future of the utilities in light of the state’s aggressive decarbonization goals.¹⁸⁴ In that proceeding, the gas utilities put forth a possible decarbonization pathway in which the gas system would be maintained as part of a hybrid system, where customers would adopt technologies that enabled them to rely on electricity most of the time but could use a gas back-up as needed.¹⁸⁵ The utilities argued that this hybrid approach would alleviate some of the mid-transition period’s affordability pressures because it would reduce investments in the electric system.¹⁸⁶ They also argued that it would provide reliability benefits for customers during the cold winter months by providing dual fuel options.¹⁸⁷ But while studies did indicate that such a hybrid approach could reduce costs and greenhouse-gas emissions in the short term,¹⁸⁸ these cost savings were predicted to disappear over the long term, and the continued greenhouse gas emissions associated with the hybrid system would make it difficult for the state to meet its decarbonization goals.¹⁸⁹ As the Massachusetts Attorney General pointed out, although a hybrid approach could “provide significant GHG reductions by 2030, a hybrid strategy alone makes achieving net zero in 2050 more difficult and expensive for all customers” because “[r]eliance on a hybrid strategy requires continued maintenance of redundant heating and fuel distribution systems.”¹⁹⁰ The Department of Public Utilities ultimately rejected the gas utilities’ requested support for the hybrid approach, acknowledging that while it could provide benefits in the short term, it was an “impractical” solution for the long term.¹⁹¹

Similar maladaptive solutions have cropped up repeatedly in the context of resource adequacy laws, with less pushback from the actors that oversee these regulatory frameworks. In 2014, following a polar vortex that resulted in significant plant outages on the PJM grid (more than 40 percent of which were natural gas plants), PJM adopted new capacity market rules designed to require generators to comply with stricter capacity standards to reduce the likelihood of future plant failures.¹⁹² These new rules instituted “pay-for-performance” metrics that paid generators that cleared the capacity markets more if those generators ended up performing well during periods of peak demand and penalized them more if they failed to be available during those times.¹⁹³ Higher enforcement penalties can theoretically be helpful in improving reliability by ensuring generators follow through on the promises they make in the capacity market auction.¹⁹⁴ But in this case, the rules also penalized renewable and zero-carbon resources. Because these resources have variable hourly and seasonal generation, they were placed on a separate payment track that prevented them from receiving the higher performance payments and capped their total overall contribution to the PJM capacity market.¹⁹⁵ Eventually, these resources would have been phased out of participation in the capacity market altogether unless they could cobble together capacity values equal to those designated for conventional fossil fuel resources.¹⁹⁶ Under this framework, the old and new resource adequacy laws could not have been reconciled, leaving the two parallel systems—and the reliability and affordability problems associated with that—in place.

More recently, in response to the high prices in PJM’s summer 2024 capacity market auction, we have seen renewed calls for regulators to double down on the old resource adequacy framework. Some have pointed to the high prices as evidence that there is a supply crisis in PJM and that incumbent resources should not be permitted to retire unless they can be replaced by a resource that matches their capacity value on a one-to-one basis.¹⁹⁷ Perhaps most notably, the President and CEO of America’s Power, a trade group that advocates on behalf of the United States’ coal fleet, recently argued that the capacity market’s high prices signal that regulators should not permit existing generation resources to retire “until replacement capacity is in operation,” and that this replacement capacity “should have at least the same accredited capacity and reliability attributes as the retiring capacity.”¹⁹⁸ This approach would obviously disfavor new renewables and other variable resources, many of which are not yet operational because of PJM’s jammed interconnection queues, and many of which likely do not have the same one-to-one capacity value as conventional fossil fuel resources, though they nonetheless provide important resource adequacy services for the grid. Granting the likelihood that at least some amount of existing generation will be needed in the short term to satisfy electricity demand while the new zero-carbon grid comes online, the proposal to require a one-to-one capacity match for retiring and replacement resources both misses the problems with the old capacity-based approach to resource adequacy and fundamentally undermines the transition to a new resource adequacy framework. The point is not to replicate the old resource adequacy approach on the new zero-carbon grid, but rather to change the way that resource adequacy is understood to more accurately reflect resource and reliability needs on an evolving grid.

In each of these instances, professed concerns with reliability on the PJM grid motivate regulatory responses that serve to perpetuate the bifurcated and compartmentalized approach to resource adequacy within PJM, simultaneously propping up older generation resources through PJM’s capacity market and excluding new renewable or zero-carbon resources from that forum. The consequence is to undermine the transition to a new resource adequacy approach for a new zero-carbon grid in the long term.

C. Accountability Problems

An additional challenge of the legal mid-transition is the problem of blurred lines of accountability. Under a simplified description of politically-accountable or responsive lawmaking, policymakers are held accountable for their actions through the consequences of their policies on the ground. If a new law is passed or a new regulation is implemented that results in broadly negative consequences, the general public can hold policymakers to account by pressuring them to amend or repeal the bad law.¹⁹⁹ This description relies on the general public being able to identify the negative consequences with the policy that produces them. While that identification in general may not be as straightforward as this simplified description would suggest,²⁰⁰ it is particularly challenging in situations in which not one, but two, legal systems coexist, both of which are intended to satisfy some broader, shared regulatory goal.

In the context of the energy mid-transition, if the basic requirements of safe, affordable, and reliable energy provisioning are not met in a given instance—as is more likely to be the case during this period—then it will be more difficult to determine which legal framework is responsible for the failure than would be the case fully before or after the transition. Indeed, the failure may be due to the overlap itself: In many cases, it is the coexistence of the two legal frameworks that creates the threat to the basic requirements of the legal regime. During this period, then, it will be particularly difficult for consumers and the general public to determine which legal system to blame for the problems that arise. Further, because decarbonization policies and the laws of the new system will necessarily have been promulgated most recently, it could be the case that consumers and the general public simply assume that these new laws alone are at fault for any issues that appear during the legal mid-transition. This misattribution could lead the public erroneously to pressure policymakers to walk back the new laws or even the broader decarbonization goals, thus undermining support for the clean energy transition itself.

Consider, for instance, the legal mid-transition in the context of natural gas distribution laws. As the mid-transition progresses, assuming the existing regulatory framework stays the same, natural gas customers are likely to experience an increase in their natural gas bills. As explained above, these rate increases are a feature of the old natural gas utility laws: The old rate regulation framework requires only current gas customers to pay for the costs of the gas system, which means that as customers leave the gas utility, the customers who remain on the gas system will have to pay a greater proportion of the costs of that system. Importantly, the laws of the new electric/heat alternative are only tangentially connected to these gas rate increases. Arguably, by creating an alternative energy distribution system for which former gas customers can exit the gas system, the laws of the new electric/heat alternative enable the decline in the gas system’s customer base, which results in the increased gas rates. But the same phenomenon would occur even if the new laws were not introduced, and instead consumers voluntarily decided to exit the natural gas utility for purely preference-based reasons. In other words, it is the structure of the old laws themselves that is responsible for the rate increases, and there is nothing inherent in decarbonization policies or in the laws of the new electric/heat alternative that requires increasing gas prices. Nonetheless, it seems plausible that customers will blame decarbonization alone for the gas cost increases.²⁰¹ If that is the case, then broader public support for decarbonization could collapse.

A similar problem could occur in the wholesale electricity context. As noted, assuming no effort to integrate the old and new resource adequacy laws, the wholesale electricity system is likely to experience reliability and affordability concerns during the legal mid-transition. A concrete example of this is the higher electricity bill that some ratepayers in the PJM region are expected to see this year because of the most recent PJM capacity market auction. The reasons for these cost increases are, in some ways, quite convoluted.²⁰² Nonetheless, each of these complicated and technical reasons for the price spike boils down to the fundamental point that PJM has failed to integrate new renewable and zero-carbon resources onto the grid in a variety of different ways, which essentially means that older, more expensive conventional generation is being paid to stay online to satisfy PJM’s capacity standards.

Crucially, for purposes of the accountability point, renewable or zero-carbon resources are not the primary cause of these higher costs in PJM. In fact, in parts of the country where we have seen grid operators do a better job of integrating new zero-carbon resources onto their grids—notably, in parts of the country where capacity markets are nonexistent—these resources are estimated to have lowered wholesale electricity costs.²⁰³ Nonetheless, it would not be surprising if ratepayers within PJM attribute these electricity rate increases to state or federal subsidies for renewable or zero-carbon technologies, or broader decarbonization goals.²⁰⁴ If that is the case, then political momentum for state or federal subsidies for clean energy resources, or even decarbonization itself, could decrease.

In both natural gas distribution and wholesale electricity, it is the old laws themselves, or the coexistence of the old and new laws, that poses a threat to safe, reliable, and affordable energy services. Yet consumers or the general public may blame the new laws alone, or broader decarbonization goals, for these threats. Moreover, because these price increases are likely to be seen in essential goods like consumers’ gas and electricity bills, the political risks associated with these costs could be especially significant.

But this pattern is not inevitable. Effective management of the legal mid-transition by regulators and policymakers could, in the context of natural gas distribution, allocate costs more equitably to reduce the burden of increasing gas prices, or, in the context of wholesale electricity, better integrate the two resource adequacy frameworks to reduce the reliability and affordability challenges of the parallel systems. In those circumstances, the public may be more willing to tolerate relatively smaller bumps in the road to get to the post-transition period. If that is true, then it is ultimately the failure of regulators to manage the challenges of the legal mid-transition that could lead to a loss of political support for decarbonization. This realization ought to illuminate the importance of the legal mid-transition period. It may very well be that the most important thing to focus on with respect to decarbonization and the clean energy transition is not the substance of the new laws that are designed to support a new, zero-carbon energy system, but rather the decisions made by regulators and policymakers as to how to wind down the old laws and introduce these new laws in a managed and integrated manner. In other words, the most important climate policy may not be the laws that are designed for the future but the responses of policymakers, regulators, and other actors to the laws that exist right now.

The Article turns next to possible solutions policymakers or regulators could adopt to smooth the challenges of the legal mid-transition.

IV. The Solutions of the Mid-Transition

It is the redundancy and compartmentalization of the legal mid-transition that produces its challenges. It follows that the solutions to the legal mid-transition ought to target the redundancy and compartmentalization aspects of this period. That is to say, if the parallel legal systems can be integrated or translated into each other during this time of legal overlap and evolution, then the threats to the basic requirements of the broader legal system that flow from the transitional moment might be reduced. That reduction might permit the legal mid-transition to happen more smoothly, paving the way for the ultimate exit from the mid-transition period.

With that in mind, this Part canvasses possible integration- or translation-oriented solutions for the mid-transition. These solutions can be grouped into three categories: linking solutions, gap solutions, and leapfrogging solutions. The Sections below describe these categories in greater detail and give examples of legal responses that might fit into each of them. The examples are not intended to be definitive or exclusive; legal or regulatory responses might fit into more than one of these categories, and a much longer list of possible responses might be generated for each of these categories. Other categories of solutions might also be imaginable. The point of the discussion here is not to offer silver bullets, but rather to give some illustrative ways of thinking about solutions to the legal mid-transition problem that address the underlying issue of redundant and compartmentalized regulatory frameworks.

A. Linking Solutions

Linking solutions are regulatory or legal responses that link, tie together, or otherwise try to integrate the redundant and compartmentalized legal systems that form during the mid-transition period. They can range from small interventions in individual decision points to larger reworkings of the regulatory model. Regardless of the scale, their aim is to force regulators and relevant entities to think about both the old and new laws together in order to avoid the myopic approach that results in maladaptations, where the parallel and redundant systems are perpetuated.

For instance, in the natural gas distribution context, linking solutions could be solutions that tie together the wind-down of the old laws of the natural gas distribution utility and the new laws of the electric/heat alternative. One example of this that has been discussed already is the linking of the winding down of the old natural gas utility’s duty to serve to the introduction of the reimagined duty to serve for the electric/heat alternative.²⁰⁵ By permitting the old natural gas utility to terminate its service to existing customers only if an alternative service is available, the linking of the old and new duties to serve ensures that customers are not deprived of safe and reliable energy services during the transitional period. Additionally, some states have extended this solution even further to protect vulnerable consumers during the mid-transition. In California, for instance, state law directs the public utility commission to authorize utilities to engage in targeted decarbonization in neighborhoods that are low-income or historically disadvantaged.²⁰⁶ This prioritization could reduce the number of low-income consumers who remain on the natural gas distribution system during the mid-transition period, which would in turn reduce the disproportionate impact that the transition is otherwise expected to have on these consumers.

Another possible linking solution is the “non-pipeline alternative” analysis. This analysis requires utilities to explore alternatives to gas system upgrades or extensions that would maintain or enhance service levels without requiring additional investment in the gas distribution system. Examples of such alternatives could include energy efficiency initiatives, appliance electrification, demand response programs, and targeted electrification or thermal heat network planning for certain neighborhoods.²⁰⁷ Some state public utility commissions have made non-pipeline alternative analyses a precondition for utilities to receive approval to engage in new investments in the gas system. If the utilities cannot prove that a non-pipeline alternative was not feasible, then the utility may not receive permission to move forward with the investment or may not receive recovery for the costs if it engages in the investment.²⁰⁸ By conditioning new gas investments on a finding that the electric/heat alternative (or reduced gas consumption) is not an option, the non-pipeline alternative analysis forces utilities and regulators to think of and evaluate both the old laws and the new laws simultaneously.

A large-scale linking solution in the natural gas distribution example would involve requiring gas and electric utilities to engage in joint planning inside state public utility commission proceedings. Currently, most state-level gas and electric utility proceedings happen within separate dockets inside state public utility commissions. Sometimes, a utility may be a combined gas and electric utility, which might enable some coordination between the gas and electric sides of energy provisioning. But in many cases, there is a separate gas utility and electric utility that provides energy services to customers within a given territory.²⁰⁹ Joint proceedings would create a forum in which these two utilities could share relevant data with each other and with the public utility commission, and identify viable areas and methods for targeted decarbonization.²¹⁰ For example, in Quebec, joint planning has resulted in a “dual energy agreement” in which the separately-owned electric utility has agreed to make compensation payments to the area’s natural gas utility for the benefits that the gas utility is providing during the period in which both the gas and electric systems are providing energy services.²¹¹ These payments have helped cushion the blow to the gas utility and its customers as the gas customer base is shrinking.²¹²

Linking solutions in the context of wholesale electricity may also be feasible, although it will be especially important in this area for regulators or policymakers to ensure the solutions do not unintentionally perpetuate the old resource adequacy laws. For instance, PJM recently changed the methodology it uses to evaluate a resource’s capacity in the capacity market in order to better reflect the resource’s marginal capacity contribution given the existing mix of resources on the PJM grid.²¹³ In some ways, this new capacity accreditation methodology reflects a conceptualization of resource adequacy that is more akin to the resource availability framework of the new resource adequacy laws.²¹⁴ It could therefore be thought of as an effort to translate the new resource adequacy laws into the old resource adequacy system in order to make these two ways of thinking about resource adequacy more compatible. The problem, however, is that this new capacity accreditation methodology still operates within the confines of the existing capacity market. To the extent that this new approach simply perpetuates the existence of the old capacity market, it may actually represent a maladaptation.²¹⁵ That is because, as discussed in Part II, a grid that relies primarily upon zero-carbon resources will likely require something other than capacity markets to ensure long-term resource adequacy. If this regulatory intervention is propping up the capacity market model longer than is actually necessary, with no path out of that model, then it may not be a true linking solution.

A final example of a linking solution in the context of wholesale electricity could be a form of a “resource adequacy alternatives” analysis—akin to the “non-pipeline alternatives” analysis described above—for individual generation resources that are kept online because of their reliability attributes.²¹⁶ Pursuant to instructions by FERC, RTOs and ISOs have developed mechanisms outside of the capacity market to keep specific, individual generation resources online if the RTO or ISO determines that retirement of the resource would cause reliability or resource adequacy problems for the electricity grid.²¹⁷ In most instances, these mechanisms result in ratepayers paying to keep an old coal or fossil fuel plant running, often at above-market rates, to satisfy resource adequacy needs.²¹⁸ Several energy law scholars have argued that instead of simply approving the continued operation of these resources at above-market rates, FERC and the RTOs/ISOs ought first to solicit competitive bids to see if anyone could provide similar resource adequacy value for a lower price.²¹⁹ One could imagine a similar policy intervention that conditions continued payment of the incumbent resource on the generator’s proving that no feasible resource adequacy alternative existed, taking into account the portfolio of resource adequacy options that might be available on the new grid (e.g., transmission upgrades, energy efficiency, demand response programs, zero-carbon generation, or virtual power plants). Again, as in the case of the “non-pipeline alternatives” analysis, this kind of inquiry would force regulators and power plant operators to think of and evaluate the old and new resource adequacy laws simultaneously in an effort to encourage integration of the two.

B. Gap Solutions

Gap solutions are temporary legal or regulatory responses that are intended to address the unique challenges of guaranteeing that the basic requirements of the system are met during the legal mid-transition. Unlike linking solutions, they do not solve the fundamental problem of having two bifurcated legal systems during this period. But because they are explicitly designed to be temporary, they do not run the risk of becoming maladaptations and perpetuating the parallel and redundant approach to regulation that exists during mid-transition.

One example of a gap solution in the natural gas distribution context may be temporary financial mechanisms that help reduce the cost impact of rising natural gas rates during the mid-transition period. As noted in the example of Quebec’s “dual energy agreement,” some of these mechanisms might fall into the bucket of linking solutions, like scenarios where electric utilities make payments to gas utilities for the benefits provided by the redundant gas distribution system during the transitional period. We might put into this bucket other cost- and benefit-sharing mechanisms between the electricity and gas systems, like “exit fees” for customers who are leaving the gas system for the electric/heat alternative,²²⁰ or electricity surcharges that are placed on electricity ratepayers’ bills to help pay for some of the gas system’s costs.²²¹ But other financial mechanisms may pull from a broader pool than just electricity ratepayers, including the state and federal tax base.²²² Indeed, allowing at least some of the cost recovery to come from the tax base may be preferable because it would help reduce the inherently regressive effect of rate regulation.²²³ Similarly, public utility commissions will likely have to adopt innovative, temporary rate structures for gas utilities during the mid-transition period that prioritize safety, reliability, and affordability for the remaining gas customers.²²⁴ At the most extreme end, for gas utilities where no viable business option exists in the post-transition future, conversion to a public entity for the wind-down period may be the most rational response for managing cost concerns.²²⁵

On the wholesale electricity side, gap solutions might be policies that support the rapid build-out of transmission infrastructure to help ensure reliability and affordability during the transition period. High-voltage transmission lines lower electricity costs because they allow consumers to access the cheapest electricity generation wherever it might be located.²²⁶ They also improve reliability through expanded access to generation resources—reducing the likelihood that any individual plant outage or extreme weather event will result in broader, systemwide impacts on the grid—and higher quality lines that reduce line losses.²²⁷ Indeed, high-voltage transmission lines are often referred to as the “backbone” of the electricity grid²²⁸ and are valuable regardless of whether the grid is supplied primarily by fossil fuel or zero-carbon resources. Thus, it may seem odd to think of them as a “gap” solution, as transmission infrastructure will continue to be essential before, during, and after the transition.

But treating short term, aggressive policy support for accelerated transmission infrastructure separately from transmission policy in general may help unlock some gap solutions that would be useful during the mid-transition period. Such policies could include a bevy of existing and proposed initiatives for transmission development, like the Inflation Reduction Act’s direct financial support for new transmission infrastructure;²²⁹ rate structures that favor construction of high-priority lines; and fast-tracked permitting processes that allow transmission lines to be sited and built quickly. Thinking of these policies as “temporary” or “gap” solutions—and designing them explicitly as such—may actually be helpful in their realization. For several years now, permitting reforms that could accelerate transmission infrastructure development have stalled in Congress, in part because of concerns that such reforms could gut environmental review laws or concentrate too much authority within the federal government.²³⁰ If a sunset is placed on these reforms, such that, for instance, fast-tracked environmental review is available for projects only during a specified time horizon, or federal agencies are given expanded federal eminent domain authority but only for a short period, some of these policies might be more tolerable for their opponents.

C. Leapfrogging Solutions

The final category of solutions is leapfrogging solutions, or policy or legal interventions that address the challenges of the mid-transition period by jumping straight into the approach of the new laws without having to unwind the old laws. Obviously, this kind of solution works best in those areas where the old regulatory framework does not exist. Given the pervasiveness of the old legal regime, these solutions may not be plausible on a large scale in the United States. Nonetheless, there might be targeted possibilities for leapfrogging where such an approach would help avoid the challenges of having to undo an old regime while building out a new one.

One clear candidate for leapfrogging solutions in the natural gas distribution context is laws or policies that require all new building construction to conform to the electric/heat alternative, thus avoiding the need to unwind natural gas infrastructure in the first place.²³¹ Electrifying a building from scratch is significantly less expensive than retrofitting a building that was initially designed for gas or mixed-fuel use.²³² Recognizing this, some states and localities have adopted policies that encourage or require new construction to be fully electrified, including new building energy efficiency codes or even restrictions on gas hookups for new construction (although municipal regulations targeting gas hookups may be vulnerable to federal preemption challenges²³³).²³⁴ Non-pipeline alternative analyses instituted by state public utility commissions might also qualify as leapfrogging solutions, if they require gas utilities to evaluate electrification options for new construction before authorizing new natural gas connections.²³⁵ Additionally, research suggests that, policy interventions aside, construction costs for new all-electric buildings are less than construction costs for new gas or mixed-fuel buildings.²³⁶ Thus, this approach may take shape even in the absence of laws or policies requiring full electrification.²³⁷ Finally, leapfrogging in the form of full electrification may be an important solution for certain low-income rural communities, especially in New England, where natural gas infrastructure was never built in the first place, and residents instead rely on more expensive diesel or fuel oil to heat their homes.²³⁸

On the wholesale electricity side, one version of a leapfrogging solution may be innovative approaches by utilities, public utility commissions, and consumers to secure “24/7 clean energy” that ensures that all of a consumer’s electricity consumption will be satisfied through zero-carbon resources.²³⁹ These efforts—which often occur outside of the capacity markets—attempt to leapfrog over the winding down of the old fossil fuel grid by directly investing in new renewable or zero-carbon resources that will be available to satisfy consumers’ electricity needs at all times of day throughout the year.²⁴⁰

One such example is the “Clean Transition Tariff” that Google has designed in concert with a Nevada utility currently under consideration by the Public Utilities Commission of Nevada.²⁴¹ The tariff came out of a commitment by Google to run on 24/7 carbon-free electricity on every grid where the company operates by 2030.²⁴² Google could not achieve this goal simply by purchasing electricity from the broader grid because even on grids where renewable or zero-carbon resources make up a significant portion of electricity generation, those resources are still currently backed up by fossil fuel resources that supply electricity during periods when zero-carbon resources are unavailable. Thus, Google entered into an arrangement with a Nevada utility, NV Energy, and a geothermal developer, Fervo Energy, to secure a 24/7, continuous supply of carbon-free electricity. Under this arrangement, Fervo is constructing an advanced geothermal plant that will be able to satisfy Google’s 24/7 clean energy standard. Fervo has executed a long-term contract with NV Energy for the utility to purchase the electricity generated from the geothermal plant. NV Energy then resells that electricity to Google under a separate long-term, fixed rate contract.²⁴³ The geothermal electricity sold by Fervo Energy is more expensive than the electricity that NV Energy would typically procure for its customers; but by entering into a contract in which Google agrees to pay for the additional costs of the geothermal generation, NV Energy promises that its other ratepayers will not be saddled with the costs of the new generation technology.²⁴⁴ At the same time, Google’s contract with NV Energy allows the company to continue to purchase electricity from the broader electricity grid if Google’s electricity consumption exceeds the supply provided by Fervo Energy. Thus, Google retains the benefits of being connected to the grid (access to diverse supply, reliability, redundancy, etc.) while also ensuring that the company can meet its rigorous decarbonization goals. As a commenter put it, the tariff creates a mechanism for large tech companies like Google (which have significant electricity loads, especially with the rise of AI and new data center construction) to “play ‘venture capitalist’” on the electricity grid.²⁴⁵

That said, the clean transition tariff and other proposed tariffs between big technology companies and utilities are not without criticism. A recent report released by Harvard’s Electricity Law Initiative argues that many of these tariffs have been designed in ways that suggest that residential ratepayers could be stuck paying for the significant costs of electricity grid expansion posed by new data center construction, without those ratepayers receiving much or any of the benefits.²⁴⁶ If that is true, then the clean transition tariff version of a leapfrogging solution would be beneficial only in the narrow sense that it might encourage big tech companies to power their new data centers with innovative zero-carbon resources rather than conventional natural gas plants. It is not clear, however, that these tariffs would be net positive for society.

As with each of the solutions discussed above, therefore, regulators looking to support leapfrogging solutions will have to scrutinize them carefully to ensure that they are beneficial for the public interest more broadly, not just some narrow private interest that is advocating for them.

Conclusion

This Article has focused on the example of the legal mid-transition in the context of the energy transition—perhaps the most significant legal transition of our era. But the Article also posits that the model of the legal mid-transition is applicable to legal change in other contexts. This is important not just for scholars who study legal transitions, but for a variety of legal actors and advocates who may be interested in facilitating legal transitions. For the theory of legal change uncovered here suggests that, in some cases, it is not enough simply to envision and attempt to implement new approaches to fields of law and policy where change is desired. It is also necessary to plan how to unwind the existing approaches. In other words, for proponents of legal change, there are two tasks: to build the world-that-might-be, and to manage the world-that-is.²⁴⁷ To neglect either could mean the failure to transition from one to the other.

*Associate Professor of Law, University of Virginia School of Law. This Article is indebted to the work of two people in particular: Emily Grubert, Associate Professor of Sustainable Energy Policy at the University of Notre Dame, and Elizabeth Stein, State Policy Director at the Institute for Policy Integrity at the New York University School of Law. The Article grew out of a workshop hosted by Professor Grubert. Without her groundbreaking scholarship and her efforts to convene interdisciplinary groups of academics, it would not exist. The Article is also the product of many extended conversations with Elizabeth Stein, who helped refine the ideas and examples contained herein. Finally, thanks are owed to the excellent student editors at the Michigan Law Review, in particular Henry Evans, Alex Rochon, Nathaniel Magrath, Heather Foster, and Izzy Tegtmeyer.