Introduction
One of the Trump Administration’s priorities during its first year has been the rollback of federal actions to address climate change. In addition to reconsidering several critical domestic regulations,
President Trump announced on June 1, 2017, his intention to withdraw the United States from the Paris Accord
—the landmark international agreement on climate change signed by 195 parties.
Shortly after this announcement, U.S. states struck back in an aggressive demonstration of their resurgent place in climate policy. In a letter titled “We Are Still In,” several states declared that “[i]n the absence of leadership from Washington,” they would “work[] together to take forceful action and to ensure that the U.S. remains a global leader in reducing emissions.”
States are backing up this promise with escalating state laws aimed at “decarbonization”—that is, the process of ending reliance on energy sources that emit carbon pollution.
Leading states have passed legislation to reduce carbon emissions in their jurisdictions 80% by 2050, with a focus on reducing carbon pollution from electricity.
These are ambitious goals, likely to require the replacement of significant infrastructure at substantial expense.
And yet, in setting policies to achieve these goals, no state has adopted a purely market-based system that aims to reduce emissions at the lowest cost above all other goals.
Instead, states have crafted schemes that help them manage the contours, aims, and consequences of decarbonization. These state policies include requirements that utilities buy certain amounts and types of renewable energy, incentives for communities to build their own solar farms, payments to aging (and appealingly carbon-free) nuclear power plants to keep them from retiring, and complete redesign of state electricity law.
These various policies combine decarbonization with aims ranging from job creation and economic development to income redistribution, urban revitalization, open-space preservation, and the continuation of traditional livelihoods.
There is, however, a potential downside to this rich set of state climate policies. As state ambitions ramp up, complications with this state-by-state approach to decarbonizing electricity become more apparent. States share jurisdiction over electricity with the Federal Energy Regulatory Commission (FERC).
In most of the country, states have ceded partial control over electricity supply to regional electricity-market operators, which are “hybrid” quasi-private, quasi-governmental entities, comprised of industry members functioning under FERC oversight.
These electricity markets are designed to select least-cost sources of electricity; they do not “price in” carbon or otherwise favor carbon-free generation sources.
Consequently, many allege that state incentives and payment schemes targeted at particular low-carbon technologies interfere with the smooth functioning of these regional markets.
Now, faced with a growing number of divergent state policies, several regional market operators have accepted that electricity markets may need to play a more active role in decarbonization.
One key question under discussion is whether it is time to redesign electricity markets to achieve states’ decarbonization goals.
Such proposals gained momentum in May 2017 when FERC convened a conference to consider their feasibility and desirability.
In her opening remarks, then-acting FERC Chair Cheryl LaFleur identified these potential reforms as “the most critical issue [the agency was] confronting.”
Since that time, debates have intensified regarding how much of a challenge renewable energy presents to electricity markets and how best to manage the shifting composition of electricity-market resources.
There is obvious appeal to using electricity markets to achieve state climate change goals. Integrating these goals into markets could lower the cost of decarbonizing energy, while eliminating the risk that accreting state policies might distort the functioning of electricity markets. For this reason, many stakeholders that often find themselves on opposite sides of energy policy debates have expressed support for integrating state climate policies into regional electricity markets.
It can thus feel almost reflexively reactionary for anyone who supports rapid decarbonization to resist such efforts.
Nevertheless, this Article argues that states should exercise caution in ceding control over decarbonization too quickly or thoroughly to regional electricity markets. This argument is grounded in comparative institutional competencies
and the importance of preserving state centrality in decisionmaking over decarbonization.
In short, states do a disservice to current and future residents if they cede the shape of decarbonization policy to market insiders and experts rather than subject these policy decisions to wider democratic inquiry, debate, and decisionmaking.
Although conversations about electricity markets and decarbonization can quickly alienate all but the most technocratic insiders, decarbonization is far more than a technical project. Decarbonization policies will determine how our society extracts, owns, sites, manages, moves, consumes, and conserves electricity in the future. Given electricity’s centrality to modern life, such policies have the potential to radically alter political and economic power, as well as to shape the future of American landscapes, communities, and daily living arrangements.
Decarbonization is thus a profoundly social project.
In crafting multifaceted, nuanced decarbonization policies, states are demonstrating their understanding of this fact. State climate policies reflect state preferences about how they decarbonize, instead of just whether they decarbonize. These diverse public preferences would be lost in the integration of state policy aims into regional electricity markets. This Article identifies three particular risks electricity markets present in this regard. The first is the loss of transparent, government-driven decisionmaking on the trajectory of decarbonization. Electricity markets are governed through quasi-private, immensely technocratic, and largely opaque processes
—hardly the space in which we should center debates over the shape of decarbonization. The second risk is one of homogenization to the lowest common denominator. Electricity-market design limits the tools with which states can respond to decarbonization, requiring states to homogenize their preferences. In practice, such homogenization is likely to water down more ambitious state policies to achieve the near-consensus buy-in of states and stakeholders required in regional electricity-market governance.
The final risk to electricity-market integration of state climate policies stems from the Supreme Court’s 2016 decision in Hughes v. Talen Energy Marketing, LLC.
There, the Supreme Court placed limits on states’ abilities to adopt policies that regulate electricity in ways too closely linked to federally overseen markets.
Although Hughes left open significant questions regarding how much overlap there can be between regional-market functions and state policy aims, it creates legal risk around any state decision to cede decarbonization goals to the markets.
Once a state gives control over a particular function—like decarbonization—to its regional market, it may diminish the set of tools that it can use at the state level to accomplish the same policy aim.
Articulating these reasons for caution does not mean that states should resist all efforts to integrate decarbonization aims into regional electricity markets. Instead, these risks point to a series of conclusions about when market integration of state climate policies is advisable and how it might best proceed. First, states might prefer using regional electricity markets as a climate tool when their objective is the cheapest decarbonization possible, without regard for what resources the market selects or where these resources are located. In contrast, if a state has resource preferences, distributional goals, or other objectives related to how decarbonization proceeds, markets will prove inapt tools. For these states, market integration may prove advisable only if the particular market reform selected allows states leeway to adjust their preferences and factor them into the market design.
Second, the regional politics of decarbonization should inform state decisions. U.S. states diverge considerably in the ambition of their climate policies, from states pledging to go “100% renewable” to states focused on perpetuating U.S. coal consumption.
As this Article explains, the structure of U.S. electricity law leaves regional market entities without the authority to mandate that recalcitrant states adopt more aggressive climate policies.
Nevertheless, perhaps there is still some bargaining power inherent in the regional market construct, such that states aggressive on climate change might use market solutions to coax along less willing regional neighbors. The greater the likelihood of such persuasion succeeding, the more appealing a market-based solution should be.
Finally, the appeal of integrating state policies into regional markets might shift over time as courts flesh out the boundaries of the Hughes decision and related cases.
Because of these variables at play, the question of how to manage the intersection of state policies and regional electricity markets is likely to be a dynamic and region-specific one. Nevertheless, there is value in understanding at the outset of these conversations the risks that the marketization of state climate policies presents to the multifaceted project of decarbonization. Only states ready to relinquish control over their decarbonization trajectory in exchange for cost effectiveness should embrace market integration proposals as they stand now.
Most scholarly analysis of these proposed electricity-market reforms has focused on the jurisdictional questions they present. Regional electricity-market operators are constrained by the Federal Power Act’s mandate that federally overseen markets ensure “just and reasonable” rates.
Whether integrating decarbonization goals falls within this mandate is a thorny legal question, and many prominent energy law scholars are puzzling through this jurisdictional morass.
Less explored, however, is the question of whether states should want regional markets to perform this service, legality aside. Often, energy law scholars approach such questions over state versus regional market control through the lens of federalism—asking whether FERC or the states are better positioned to take the lead.
This Article frames these debates differently, highlighting the ways in which they implicate long-standing institutional design choices between complex, heavily managed market constructs and more direct regulatory control by states.
Framing the issue in this way lends relevance to a separate genre of scholarship, focused on questions of how markets, public policy, and values intersect.
Drawing from this literature, the Article illuminates the ways in which decarbonization is a normative societal project—one with contested visions and outcomes. Decarbonization might radically redistribute wealth and power in U.S. society, or it might largely maintain the status quo while shifting only behind-the-scenes fuel choices.
State policies reflect and embody this contest while regional markets present a homogenizing and privatizing force that narrows the room in which to debate the many shapes a decarbonized society might take.
This Article proceeds in four parts. Part I gives an overview of regional electricity markets, state climate change policies, and their intersections. Part II explores the nature of the project of decarbonization, illustrating how state climate policies embody diverse preferences and values that reflect an understanding of the significant choices at hand. Part III shows how electricity-market redesign might eliminate these democratically determined value choices embedded in state climate policies, laying out the challenges that result from using the peculiar governance structures of electricity markets to carry out decarbonization. Part IV presents lessons derived from this analysis for when states might prefer or resist market integration of their decarbonization goals.
I. The Current Mesh and Clash of Regional Electricity Markets and State Climate Policies
To understand the debates about decarbonization roiling electricity regulation, one has to begin with a foundation in the structure of electricity policy and electricity markets. This Part provides an overview of regional electricity markets, state climate policies, and their potentially troubling intersections.
A. Electricity Markets
Electricity governance in the United States is a patchwork affair, taking on various forms across states and regions that defy quick summation.
This patchwork quality stems from the Federal Power Act of 1935, which divides jurisdiction over electricity in the United States. The federal government—acting via FERC—has jurisdiction over “the sale of [electric] energy at wholesale,” which comprises sales from electricity generators to the utilities that own the transmission and distribution grid that carries that electricity to end-use consumers.
States retain control over “retail sales” of electricity—sales that these utilities make to consumers.
From 1935 until the 1990s, FERC had a fairly straightforward role in electricity regulation. Most utilities owned their own generation resources that they used to supply their retail customers, such that there were relatively few “wholesale transactions” of electricity to regulate.
In cases in which one utility sold wholesale power to another, FERC fulfilled its duty to ensure “just and reasonable” rates
by requiring utilities to prefile the rates they intended to charge for FERC-jurisdictional sales.
At the same time, states had their own public utility commissions (PUCs) to regulate the rates that utilities could charge end-use customers.
Thus, there was relatively little difference in the character of regulation at the state and federal levels—in either case, commissions oversaw regulated monopoly entities.
In the 1990s, Congress and FERC—following on the heels of deregulation in other major sectors, including airlines, trucking, communications, and railroads—took significant steps to promote market constructs within federal electricity regulation.
The first move in this direction was a requirement that utilities allow other utilities to utilize their transmission lines at nondiscriminatory rates.
Around the same time, many states required their utilities to sell off generation assets so that the same company would no longer comprise both the supply and demand side of electricity transactions.
With these two changes in place, the stage was set for the birth of electricity markets—exchanges in which generators could bid in offers to sell electricity and utilities could seek out the lowest-priced sources of electricity to supply their customers.
In 1999, FERC issued Order 2000, which encouraged—but did not require—states and utilities to form regional electricity-management organizations, called either “Regional Transmission Organizations” (RTOs) or “Independent System Operators” (ISOs).
These entities would be “independent grid management organizations” in charge of managing the transmission grid and running electricity markets to procure and dispatch least-cost electricity across the region.
Some states and their utilities opted in; others declined—hence the patchwork nature of the present system. Today, seven RTOs serve around two-thirds of the U.S. population.
These RTOs range in size from single-state (for example, those that serve New York or California) to fifteen-state (for example, MISO, the RTO serving the upper Midwest).
FERC oversees all of these regional entities except for that of Texas, whose RTO has no interstate transmission connections to bring it within federal jurisdiction.
As a general matter, states outside of these regions continue to exercise substantially more direct oversight of generation resources.
In RTO regions, FERC has stepped away from direct policy oversight of wholesale electricity prices toward using markets as a tool to ensure just and reasonable prices. In these regions, generators can sell power either through bilateral contracts or through centralized electricity markets administered by RTOs.
These are hardly “free” markets, though. FERC and the RTOs oversee these markets through a complex set of rules and agreements that establish what can be bought and sold, by whom, and how.
Some regions—in particular, regions in the East—have chosen to administer separate “capacity markets” to ensure that enough new generation is built to serve future needs.
In these markets, generators
bid in a promise to have available for the market a certain amount of generating capacity three years in the future, and the region procures enough future capacity to meet future projected demand.
In theory at least, these markets ensure long-term reliability by providing generators a second potential stream of revenue—in addition to earnings from the energy market—around which to make investment decisions.
In both energy and capacity markets, RTOs run an auction process to determine which energy resources to purchase. Generators bid in at the price they would accept, and the RTO then “stacks” these bids, “first accepting the lowest bids and then moving up and accepting higher bids until all demand [for electricity] is satisfied.”
All accepted bids are then paid the highest bid that “cleared” the auction.
This “stacking” process creates incentives for generators to bid as low as they can afford to ensure that their generation clears the market and gets paid.
In focusing solely on bid prices, the markets remain “agnostic as to resource and fuel types, so they do not favor one technology over another.”
Because of the efficiencies presumed to flow from this market design, FERC has declared prices established by these markets to be presumptively “just and reasonable,” such that participation in the market takes the place of the traditional requirement to file rates with FERC.
The fact that FERC’s “wholesale” jurisdiction now revolves largely around regionally administered electricity markets
means that states deciding whether to join RTOs face a choice between these unusual markets and more traditional regulation.
States can either continue to manage their electricity supply through government oversight and planning, or they can place their faith in regionally administered markets to deliver reliable, affordable power. States that have opted to place their faith in markets have done so believing “that it would benefit consumers by leading to lower costs and lower prices in both the short run and the long run.”
Now, however, many of the states that chose to participate in regional markets have become increasingly aware of the limits of these markets when it comes to achieving goals beyond least-cost electricity.
Particularly with respect to climate change, which the markets do not factor into their dispatch algorithms, states have had to take matters into their own hands.
B. State Climate Policies
Leading states have approached the challenge of regulating climate change with a level of commitment far beyond what would be predicted by any sort of rational-choice calculus.
Even as the federal government retreats on climate change,
certain states are responding bullishly. Most notably, California, New York, Massachusetts, Connecticut, Minnesota, New Jersey, Vermont, and Oregon have passed laws or promulgated executive orders that establish state greenhouse gas reduction targets of between 75% and 80% by 2050.
Twenty states in total have greenhouse gas targets,
and every state has some policies in place to reduce carbon emissions.
Policy strategies span an enormous gamut. States are using cap-and-trade programs;
renewable-energy procurement requirements;
rebates and tax incentives for individuals, businesses, and communities;
and novel electricity pricing schemes.
In some instances, they are also considering overhauling the utility business model and the way they regulate utilities.
A complete canvass of these state policies would occupy the remaining space of this Article, without contributing anything novel.
Instead, this section examines three popular state climate policies that have been the most controversial for the ways in which they intersect with regional electricity markets: renewable portfolio standards, direct procurement orders, and “zero-emissions credits” for nuclear generators.
Renewable Portfolio Standards (RPSs) are one of the most popular state tools for promoting low-carbon energy sources. Twenty-nine states currently have an RPS in place.
These laws require
utilities in the state to source a certain percentage of the electricity that they sell from renewable sources by a certain date.
This approach enables utilities to seek out the cheapest renewable energy available to satisfy the state mandate.
Typically, states track compliance with their RPS by issuing “Renewable Energy Credits” (RECs) to renewable energy generators, which utilities then purchase to prove that the requisite share of their energy has come from renewable sources.
RECs thus help create a more liquid market for renewable energy by allowing the “renewable” attribute to be sold separately from the underlying energy.
In the most ambitious states, RPSs require a substantial percentage of renewables: In New York and California, this percentage is 50% by 2030; in Vermont, 75% by 2032.
In 2015, Hawaii adopted a 100% target by 2045.
In total, state RPS policies have driven more than half the growth in U.S. renewable energy generation to date and are expected to drive another 50% growth in the sector by 2030—making them an enormously important state climate policy.
Each state RPS defines qualifying renewable resources in its own way, sometimes by enumerating a list,
and other times more conceptually. For example, Vermont’s definition of renewables includes any “technology that relies on a resource that is being consumed at a harvest rate at or below its natural regeneration rate.”
Some states use these schemes to express more idiosyncratic preferences tailored to local conditions.
Maryland, for instance, includes electricity produced from chicken manure in its RPS, while North Carolina includes electricity from hog waste.
Numerous states also establish “tiers” or “carve-outs” within their RPSs, which mandate a certain amount of the overall requirement to come from particular resource types. Twenty-two of the twenty-nine states with RPSs have a carve-out relating either to solar energy or “distributed generation”—a term used to describe small-scale generating resources located at or near the site of consumption.
In some states, legislatures have created additional procurement processes for certain clean-energy resources above and beyond the RPS.
For example, in 2016, Massachusetts passed “An Act Relative to Energy Diversity,” which requires utilities in the state to enter into long-term contracts for 1,600 megawatts of offshore wind energy.
The state has also joined California in mandating that utilities acquire a certain amount of energy-storage resources.
Several other northeastern states also have special procurement processes for additional renewable resources.
Finally, there is perhaps the most controversial policy of them all: state support for particular nuclear plants at risk of retiring. New York pioneered this strategy with its Public Service Commission’s 2016 decision to provide payments, per megawatt hour, to three nuclear units in New York State that it determined were at risk of retiring without state aid.
The state awards these units “Zero-Emission Credits” (ZECs) for each megawatt hour of energy they produce through the year 2029.
New York utilities are required to purchase these ZECs, with their price determined by the “Social Cost of Carbon”—a figure calculated by the Obama Administration.
The ZEC price for the first two years of the program is around $17.50 per megawatt hour; after that time, the ZEC price may decline based on forecasted prices in wholesale markets.
Several states have either followed or are considering following similar courses. Illinois adopted a ZEC program in December 2016, which looks quite similar to New York’s.
Both states have quickly faced lawsuits challenging the legality of the programs under the Federal Power Act’s framework of shared federal–state jurisdiction.
The lawsuits have not, however, deterred Connecticut, Ohio, Pennsylvania, and New Jersey from seeking to enact similar programs.
Altogether, the suite of policies that states have amassed to meet their decarbonization goals is both impressive and eclectic—to some delightfully so; to others, frustratingly so.
In the next Part, this Article analyzes and defends these diverse climate policies and the preferences they represent. First, though, it is helpful to understand the problems that detractors believe these state policies present to regional electricity markets.
C. Tensions at the Intersection
State climate policies and regional electricity markets have coexisted—and indeed, grown together—for around two decades.
Why the recent fuss? Regional market operator PJM—an RTO that spans the mid-Atlantic—offers perhaps the most parsimonious explanation for the present spate of concern: “Subsidies are contagious.”
By “subsidies,” PJM is referencing the myriad state policies detailed above that help promote various clean-energy resources. As this quote suggests, regional electricity-market operators are nervous about the proliferation of these state-level, resource-specific policies as a means to achieve ambitious climate-mitigation goals.
The first common complaint about these state policies is that payments to specific zero-carbon resources unfairly suppress market prices. For example, plaintiffs suing to contest the legality of New York’s ZEC program explain their concerns as follows: Providing existing nuclear units an out-of-market ZEC payment enables these nuclear plants to lower the price at which they bid into the market.
Then, the clearing price of the entire market is lowered such that other plants that do not receive subsidies either fail to clear the auctions or clear at a lower price. Consequently, the argument goes, “the ZEC program . . . distorts the functioning of the FERC-regulated energy and capacity markets.”
Similar complaints extend to other state support policies, such as RPS and specific procurement policies, which some believe “cause a similar type of harm to . . . markets.”
Perhaps the most contested element of this narrative is the normative claim that the market is “distorted” and “harmed,” rather than merely altered, by these kinds of state policies. An alternative view is that it is perfectly legitimate for states to support certain resources and that such support does not render these resources’ market bids “uneconomic.”
To the contrary, this view holds, state support policies are permissible judgment calls by states that exist at “the heart of their historic jurisdiction over generation resources.”
If they affect market prices, so be it—there’s nothing necessarily wrong with that. Indeed, subsidies to fossil fuels have long affected their relative competitiveness in ways that the market has not accounted for.
Moving beyond these semantics—and the substantially different views they represent of the relative hierarchy of market functioning and state policy goals—can be challenging. Complaints about state clean-energy policies lowering market prices often feel like their own protectionist effort to insulate carbon-heavy resources from necessary change. But the most compelling version of this argument looks further down the road than mere market “distortion.” That longer-term argument proceeds like this: States decided to join regional electricity markets to have these markets competitively select least-cost electricity and generating capacity. Going forward, states plan to continue to rely on these markets to send signals about whether and when to invest in new generating capacity in any particular region. But if state policies in support of certain resources lower the prices those markets are sending to everyone else, then it may well be the case that non-policy-supported generators—in particular, natural gas generators
—no longer see value in building new plants.
This result, in and of itself, might be exactly what states desire: Their policies push out existing, carbon-emitting resources by supporting certain zero-carbon resources. But here’s where PJM’s worry about subsidies’ contagiousness comes into play: Renewable energy, nuclear energy, and natural gas have different attributes that lead them not to be perfectly interchangeable electricity sources. Solar and wind energy are available only when the sun is shining or the wind is blowing, respectively. Nuclear power cannot be turned on and off quickly—meaning that it is not very useful in balancing out the variability in solar and wind.
Natural gas and hydropower, by contrast, are capable of quickly “ramping” up and down, such that they act as flexible complements to these variable resources.
Electricity storage can play a similar role in “smoothing” out electricity supply.
These divergent characteristics underpin the “contagion” worry. As renewable energy comes to play a larger role in the grid, states may realize that they need a certain amount of natural gas, electricity storage, or some other new resource to keep their decarbonizing grid running smoothly and efficiently.
In this case, if the market is incapable of supporting such resources, states may end up having to also design subsidy programs for these resources.
Eventually, the market might be so poor at sending competitive price signals that the only way for any resource to remain viable
would be to obtain state subsidies.
Such a result would ultimately amount to creeping, accidental re-regulation of the electricity sector and abandonment of the gains states intended to obtain from regional electricity markets.
Whether this potentiality presents an imminent threat remains a matter of debate. For the moment, the worry is particularly acute in the eastern RTOs that rely on regional forward capacity markets as the primary way to ensure resource adequacy (that is, enough electricity going forward to keep the lights on). In these regions, states have largely required utilities to sell off their generation assets, such that corporations building generators do not have the benefit of a captive monopoly rate base
to help pay for new plants.
Instead, these generators rely exclusively on payments from electricity markets as the way to recoup their investments, such that a depression in market prices threatens their survival to a greater extent than in other markets.
Although state reregulation of the electricity sector is sometimes held out as a plausible solution to these challenges, no state pursuing aggressive decarbonization expresses reregulation as its aim.
Instead, states wish to remain a part of regional electricity markets while also accomplishing their decarbonization goals.
Accordingly, the key question becomes how to balance the aims of these policies with the risks they present to electricity-market functionality. Before taking up this question in Parts III and IV, the next Part argues that the answer to this question requires a deeper understanding of the nature of the project of decarbonization—an understanding that has largely been lacking in conversations to date.
II. What Should We Ask of Decarbonization? Preferences Beyond Least Cost
At one level, decarbonization is a technical challenge. To combat climate change, the amount of carbon released in the production of electricity must be dramatically reduced. Leading studies suggest that adequately mitigating climate change—that is, minimizing the possibility of planetary catastrophe—will require “deep decarbonization” of developed country economies.
“Deep decarbonization” in this context describes decarbonization efforts of around 80% by 2050—precisely the aim embraced by leading U.S. states.
Several recent projects have fleshed out the technological changes necessary to accomplish this transformation. These projects yield answers along the following lines: “The carbon intensity of electricity will need to be reduced by a startling 97%.”
To do so, “[p]etroleum, coal, and natural gas [must] play a much smaller role in the primary energy supply,” and “wind, solar, biomass, and nuclear [must] become the dominant share of primary energy supply.”
These changes will, of course, “profoundly transform the U.S. energy economy.”
A more interesting and open question, though, is how—and how much—these major infrastructure changes will reverberate throughout the American economy and American society.
A. Two Visions of the Decarbonized Future
It can be difficult to trace the ways in which discrete energy-infrastructure decisions affect larger social and political structures. It is often only in hindsight, after the gradual accretion of decades of such decisions, that we can understand how energy policies interrelate to larger questions of social structure and economic and political power.
But part of this Article’s argument is that it is important to appreciate up front—as best we can—the expansive effects that our choices around how to decarbonize the energy system are likely to have.
In an attempt to develop an appreciation of decarbonization’s potentially widespread ramifications, this section asks the reader to consider two divergent pathways to deep decarbonization. The first emerges from a recent, personal conversation with an acquaintance who works for a major environmental not-for-profit that will remain undisclosed.
He explained that, frustrated with recent backsliding on climate change in the United States, his organization was quietly assembling a group of the major fossil fuel companies in an attempt to devise a response to climate change that would ensure that the companies maintained their dominant role in the economy. That is to say, this group hoped to draft legislation related to decarbonization that would do as little as possible to shake up market shares, or political power, within the energy industry or beyond. In this group’s view, accepting a policy actively designed to forestall any significant distributional shifts is the surest way to achieve rapid deep decarbonization.
If this pathway were taken, the major political and economic players in the decarbonized future might not look so different from those of today—many of the changes would play out behind the scenes of the electricity grid. All of us would get used to landscapes dotted by major utility-scale wind farms, nuclear power plants, solar arrays, and transmission lines, owned by companies like Exxon and BP.
Companies would build whichever combination of these resources proved most profitable to them. The price of electricity would likely rise, but companies such as General Electric would provide new technologies to help control electricity demand—technologies that would be available to those who could afford them.
Now, consider a second, quite different pathway that a country or state could take toward decarbonization. This pathway emerges from the thesis of journalist Naomi Klein’s 2014 book This Changes Everything.
In her view, the reason that the world has made so little progress on climate change is that “the Right is Right”: Addressing climate change requires actions that “directly challenge our reigning economic paradigm” and “spell extinction for the richest and most powerful industry the world has ever known—the oil and gas industry.”
She doubts that any significant solution can be forged through cooperation with major corporations, citing the poor record of this strategy to date.
Instead, she sees the challenge of climate change as an opportunity to forge new grassroots alliances that link climate change to community health and that demand more democratic decisionmaking and local economic power.
Climate change, in this view, “could be the catalyst to attack inequality at its core.”
If this pathway toward decarbonization were pursued, there might be an efflorescence of city movements to reclaim their electricity grids from private ownership.
Communities would collectively invest in locally sited solar and wind farms, deciding to pay more to support local clean energy and local jobs. Consumption of energy and other goods might fall as the country pursued low-growth economic policies that focused on delivering free time instead of material accumulation, in an effort to spread fewer resources more broadly.
Significant lifestyle changes might be required, including reduced consumption of meat and dairy, less car ownership, and fewer airplane trips.
It is hard to get much further apart than these two visions of the decarbonized future—one based entirely on political expediency and maintenance of the economic order; the other based on a vision of using the project of decarbonization to radically restructure political and social relations. Their coexistence hints at the range of possibilities that decarbonization holds for power structures, community character, and daily life. No matter how we approach it, decarbonization will shape more than just physical infrastructure, making it a social project as much as a technical one.
There is considerably more to be said about the many contours of the “social project” of decarbonization, but much of it will have to wait for future work. This Article does not attempt to explore the range of potential considerations or solutions in their entirety, nor does it make any judgment about the most viable or desirable version of this social project. For the present argument, it is enough to understand that decarbonization is, inexorably, more than just a technical challenge. Discussions around its trajectory implicate choices and values that extend far beyond what technologies are available at what costs.
The question then becomes: Who determines what additional values are relevant? The sections that follow contend that state politics present a better avenue for this determination than quasi-private, regional electricity markets.
B. State Policies as Reflections of the Social Project of Decarbonization
Although no state has embraced a vision of decarbonization near either extreme described above, state responses to climate change similarly evince an understanding of the significant political and value choices bound up in decarbonization policy.
Take, for example, state variations in RPSs, which demonstrate preferences for certain resources that are either locally abundant (for example, Maryland’s chicken manure) or particularly desirable, but less economically competitive (for example, rooftop solar carve-outs).
In both of these instances, states have chosen to promote certain aims beyond “mere decarbonization”—that is, the lowest-cost decarbonization achievable.
By including chicken manure in its RPS, Maryland provided a potential additional stream of revenue to the state’s many poultry farmers, while diverting nitrogen-rich poultry manure from running off into the Chesapeake Bay—a body of water that has faced significant problems of nitrogen overloading.
By including solar and distributed generation carve-outs, states have prioritized controlling both the type and scale of their clean-energy build-out. A policy preference for distributed generation ensures that renewable energy built in a state will not all occur in large-scale, utility- or developer-led projects that consume open space. Instead, some of it will be located on the roofs and in the yards of state residents, providing them additional income streams and creating opportunities for new businesses to emerge in the electricity sphere.
A built-in preference for solar serves a different end: It ensures that all of a state’s renewable energy will not come from the cheapest source—frequently wind—but instead that state policy will work to promote multiple renewable energy technologies.
Direct procurement policies for particular resources serve a similar purpose: They signal a commitment to developing a certain local clean-energy industry. Massachusetts politicians celebrated the state’s 2016 legislation mandating offshore wind on this ground, proclaiming, for example: “What we have here, as opposed to an amorphous bill of clean energy generally or greenhouse gases generally, is a specific technology—an offshore wind economy—that we’re hoping to jump start and we have real incentives in place to make that happen.”
New York tells a similar story about its ZEC program for nuclear energy. The New York Public Service Commission asserts that without support for nuclear, it would be exceedingly difficult for the state to accomplish its RPS goal of 50% renewables by 2030.
Although nuclear power does not count towards this 50% goal, “[i]f the nuclear plants were to retire before the renewable build-out occurs, the resulting gap in the state’s power supply would lead to a surge in [greenhouse gas] emissions as fossil-fuel-fired generators fill that gap.”
Accordingly, the Commission has designed the ZEC as a time-limited measure to assist the state in meeting its long-term decarbonization targets.
It also decided to provide nuclear energy a fixed level of support, pegged to predicted wholesale market prices, rather than allow it to receive the fluctuating, often more generous prices awarded to renewables.
Illinois is even more explicitly far-reaching in the aims of its ZEC program: The title of its governing legislation is the “Future Energy Jobs Bill,” and leaders in the state have touted the ZEC program for its job-preserving potential.
Each of these policies reflects decisions by state actors—either the legislature or the commission in charge of electricity—to pursue courses of decarbonization that focus on goals beyond the most efficient removal of carbon.
They want their decarbonization policies to also create new local industries and jobs, provide new ways for consumers to produce energy close to home, solve contemporaneous environmental challenges, preserve open space and utilize abandoned lots or existing structures, and stabilize energy prices and air emissions during a period of dramatic transition.
C. Is It All Just Rent Seeking?
It is not difficult to conjure up a public-choice-minded skeptic’s swift reaction to my argument: social project? These state policies are all just examples of successful rent seeking, in which certain powerful industries are benefitting to the detriment of the people of the state!
A proponent of the rent-seeking hypothesis might suggest that most of the state policies detailed in this Article are deviations from the most efficient way to decarbonize, which would be to simply put a price on carbon.
These deviations might be the result of successful lobbying on the part of particular clean-energy industries—including nuclear, wind, and solar—which have secured for themselves premium prices for their particular type of clean energy at the expense of ratepayers, who are largely unorganized, politically powerless players in these debates.
It is certainly important not to be naïve about the motivations behind state climate policies. To respond to these concerns, this section makes two brief points. First, this Article’s argument does not turn on a rejection of public choice theory or on proof that harmful rent seeking is absent from state climate policy. Public debate and public churn about the aims and methods of decarbonization are valuable even if they sometimes result in certain industries getting a boost. Unjustified rent seeking can be (and is being
) contested through the courts and in the theater of public debate. In contrast, utilizing RTO governance structures and energy markets as the locus for debating, hashing out, and implementing decarbonization policy shunts these debates to much more private, inaccessible quarters—without eliminating the distinct possibility of rent seeking also occurring in those forums.
Second, it is not clear that state decarbonization policy preferences can easily be shrugged aside as examples of problematic rent seeking. To be sure, some of these state policies appear to favor certain industries. But in the case of the most dominant state policy, RPS, it is more fledgling solar and wind developers who stand to benefit most—at the expense of established fossil fuel companies. That’s hardly a predictable outcome under a public choice explanation of the companies most likely to hold sway with government. The same holds true for numerous other state policies that work against incumbent utility interests.
The case of ZEC programs for nuclear may seem to better conform to a classic public choice account of a large corporation persuading lawmakers to give it special treatment. Even there, though, the supporters of the policy defy simplistic explanation—the ZEC program divided the environmental community, with many groups coming out in support of it.
This division suggests that many saw ZECs as productively serving decarbonization goals.
Moreover, even accepting that some rent seeking may be at work in these policies, it might not be bad rent seeking.
Scholars have posited several ways in which policy mechanisms that favor certain groups may produce more efficacious or efficient outcomes than neutral policies. Professor Eric Biber has made the case that when it comes to climate change, state policies that build interest-group support may create “political momentum” that prevents backsliding and allows for a gradual ratcheting up of the ambition of climate policies.
Similarly, Professor Zach Liscow and Quentin Karpilow argue that when government’s goal is to encourage innovation—as it is in the realm of decarbonization—state policies that “specifically encourage cleantech” may be more efficient than technology-neutral policies like a carbon tax.
As a separate justification, Professors William Boyd and Ann Carlson have made a federalism-based, “laboratories of democracy”–type argument for why we should want states to experiment with different ways to decarbonize.
These scholars advance pragmatic arguments as to why state policies that favor certain pathways to decarbonization might make political or economic sense.
This Article’s argument is broader: Any apparent rent seeking in these policies may be justified as a way to fulfill values related to decarbonization that go beyond efficiency.
When states establish climate change policies, they are—at least in part—channeling value judgments about how decarbonization should proceed.
Emerging research suggests that the public has distinct preferences and value judgments related to decarbonization. In response to surveys and deliberative polls, individuals have expressed several values beyond pure economic efficiency they consider important in energy systems change, including “not wasting;” environmental protection; stability, reliability, and affordability; autonomy and freedom; and social justice and fairness.
These diverse values lead people to have strong preferences for certain technologies over others;
a concern for low-income protections and bill stability over “affordability” as a general metric;
skepticism about market mechanisms over regulatory approaches;
and a desire to “be heard” on energy system preferences.
Many of these same preferences emerge in state decarbonization policies—for example, in concerns over who is benefited and who is burdened by particular policies, in the widespread tendency to favor the promotion of renewable energy above nuclear energy, and in many states’ particular emphasis on individuals’ ability to choose their own energy supply. State policies on decarbonization, then, can be seen as attempts to capture the “messy, pluralistic, and pragmatic” goals associated with the social project of decarbonization and to give voice to community judgments regarding the desired shape of our future decarbonized society.
Responding to and incorporating these preferences helps a state maintain broad citizen support for its decarbonization initiatives. Without this support, passing the laws necessary to reach “deep decarbonization” levels of carbon mitigation will be all the more difficult.
Of course, there is no guarantee that state policies are accurately channeling residents’ preferences in these regards.
Indeed, I have argued elsewhere that energy law should pay more attention to how citizen preferences are generated, understood, and incorporated into decisionmaking around decarbonization.
Nevertheless, one need not have perfect faith in state democracies
in order to accept the central argument of this Article, which is one of comparative institutional competence.
The choices currently on the table for states pursuing decarbonization are either (1) maintain robust state public policies as a way to establish the contours of decarbonizing electricity or (2) transfer central responsibility for ensuring decarbonization to regional electricity markets. The next Part describes why regional electricity markets are a troublesome mechanism for accomplishing the social project of decarbonization.
III. Electricity-Market Redesign to Accomplish the Project of Decarbonization
Almost every academic (myself included) prefers that policies to address climate change include some sort of national carbon tax or cap-and-trade scheme.
Putting a price on carbon is theoretically appealing because of its potential breadth, simplicity, and efficiency.
Most states with robust decarbonization policies also support some sort of national carbon-pricing scheme, particularly one that would allow them to pursue additional side policies to address their citizens’ decarbonization preferences.
Despite its theoretical appeal, however, such a scheme is a political pipe dream in the near term.
In its place, proponents have advanced the idea of addressing decarbonization within regional electricity markets as a compromise measure. Although covering less of the country and less of the economy than a federal carbon price, including decarbonization aims in electricity markets still holds some advantages over state-by-state efforts. The many parties in favor of using markets to achieve decarbonization goals argue that market incorporation represents the most feasible way, in the current political climate, to efficiently decarbonize.
At the same time, they suggest, incorporating state climate goals into markets would help control the purported damage that variegated state climate policies do to regional electricity markets.
This Part first describes leading proposals for how to achieve state climate goals through RTO markets and the governance processes these proposals would have to go through. It then advances three reasons why the compromise measure of achieving decarbonization through electricity markets is a risky substitute for robust, democratically determined action on climate change. In brief, these reasons are that (1) procedurally, given RTO governance structures, using these market constructs to achieve climate goals would remove decisions over decarbonization further from the public view and democratic oversight; (2) substantively, incorporating climate goals into regional electricity markets would homogenize and water down state preferences; and (3) recent Supreme Court precedent creates a risk that once states cede control over decarbonization to an RTO, they may give away some ability to adopt supplementary policies to strengthen or shape the trajectory of their decarbonization efforts.
A. Proposed Market Reforms to Achieve State Policies
Stakeholders have proposed two predominant reforms to incorporate state climate aims into regional electricity markets. The first is for electricity markets to create their own carbon-pricing systems, analogous to a carbon tax. Thus, for example, certain stakeholders in New England’s RTO have proposed the following scheme:
Under a carbon pricing system, each electricity producer would pay an emissions fee in direct proportion to the amount of carbon (in tons) its generation facilities emit. The carbon emissions price (that is, the fee per ton emitted) could be fixed, be a set price schedule that increases over time, or be dynamically adjusted based on aggregate performance over time to satisfy specific carbon reduction objectives.
PJM—the mid-Atlantic RTO—has proposed a similar scheme, suggesting a carbon-pricing system might also be pursued by a subset of the region interested in a carbon price, should the entire region prove unable to reach agreement.
And New York’s RTO has also come out in favor of a carbon-pricing scheme in that single-state market.
New York’s proposal focuses on using the (now-defunct, federal
) “social cost of carbon” to create a “carbon adder” for each generator based on its carbon emissions.
“This fee would be added to the prices generators bid into the wholesale electricity market and those adjusted prices used by NYISO to determine the dispatch order.”
A separate set of proposals focuses on using RTOs to run centralized, market-based procurement processes specifically for clean energy. Thus, for example, an RTO might create a “Forward Clean Energy Market,” in which the market operator would solicit contracts for future commitments of low- or no-carbon resources in an annual auction.
This model would, in essence, amalgamate the various state RPSs in a region and attempt to satisfy them all at the same time and at the lowest cost. Such a scheme would also guarantee renewables a certain amount of revenue into the future, helping to create the certainty necessary to obtain project financing.
Proponents of these reforms include many clean-energy as well as fossil-fuel generators,
well-regarded market analysts,
and several states and environmental groups.
There is an obvious reason for this broad-based support: Pricing carbon into electricity markets should help to achieve electricity-sector carbon-emissions reductions more efficiently, since a market price drives innovation and doesn’t predetermine winners.
Similarly, having a market scheme procure all of a region’s renewable-energy demand would be a more efficient way to meet state RPSs than having each state’s utilities go it alone.
As a substantive matter, then, the argument for subsuming state climate policies into markets is relatively straightforward: It offers a more efficient way to accomplish state public policy aims while keeping electricity prices as “just and reasonable” as possible. Relatedly, it avoids the need to constantly guard against potential market distortions caused by state public policies, thus maintaining predictable, well-functioning competitive markets.
Despite widespread support, these proposals are not without challenges. One of these is legal—it is not clear that federally overseen electricity markets have the mandate to include environmental considerations within their dispatch models. As noted in the introduction, many excellent legal minds are engaged in this analysis.
A second challenge is less strictly legal in nature, although it implicates jurisdictional frictions. It is relatively clear what states might gain from integrating climate policies into regional electricity markets. But no action is without tradeoffs. What, then, do they stand to lose? The remainder of this Part tackles this question.
B. How a Stakeholder Proposal Becomes a Tariff Provision: The Intricacies of RTO Governance
To enact a regional decarbonization mechanism, a proposal would first have to clear complex RTO and FERC governance processes. RTOs are “Frankenstein like”
hybridized creatures, singular in their structure.
These organizations operate as not-for-profit corporations, governed by a board of directors and overseen by FERC.
Functionally, RTOs manage the day-to-day transfer of electricity across utility transmission lines, as well as coordinate electricity markets.
They exist only in those areas in which utilities have voluntarily ceded operational control of their transmission assets after obtaining the approval of their home states to do so.
Tariffs, by-laws, and operating agreements dictate the terms of RTO operations and governance, and the RTO board must file proposed changes in these documents with FERC for its approval.
In determining whether to approve an RTO’s proposed changes, FERC evaluates whether they will further “just and reasonable” rates and avoid “unduly discriminatory or preferential” practices, after hearing from interested parties through a notice-and-comment procedure.
Before a board can make such a request to FERC, any proposal must go through internal RTO-governance processes.
RTO boards solicit the opinions and expertise of stakeholders principally through topic-specific committees.
These committees ostensibly allow all stakeholders—persons with an interest in the market rules—to have their views considered.
But only “members” receive voting privileges.
Members are predominantly transmission-owning utilities, generators, and other energy-market participants with financial stakes in market outcomes.
Membership rules vary by RTO, but generally becoming a member requires establishing an interest in the operations of the market and paying annual membership dues.
Members are grouped by their interest in the markets, with weighted votes established by group.
Typically, a proposal for reform must obtain a super-majority vote by the members of a committee before it is recommended for the RTO board’s consideration.
RTOs also have structures in place for states to provide input into regional electricity-market governance. Most notably, this influence occurs via “regional state committees” comprised of state representatives (typically utility commissioners) from the states within the RTO’s territory.
These committees supply feedback to RTO boards of directors on proposed tariff changes, which the boards take into account in deciding whether to recommend any changes to FERC. Such committees do not, however, have any formalized role in the RTO process—a source of consternation for some, given how important RTO governance is for state policy outcomes.
Despite these channels of input and influence, RTO boards remain “independent.”
Thus, a board need not formally follow either members’ majority preferences or state wishes. When it submits its final decisions to FERC, however, an RTO board frequently explains major deviations from members’ recommendations.
In practice, then, it is substantially easier for a board to establish that a proposed change is “just and reasonable” if a substantial proportion of its members—and its members’ states—so agree.
Members, states, or other stakeholders that continue to disagree with an RTO proposal can protest the changes during FERC’s vetting process or ultimately through a lawsuit.
These protests can also be backed up by the more drastic measure of deciding to leave the RTO (in the case of member utilities)
or requiring their utilities to leave the RTO (in the case of states).
Any decision by an RTO to incorporate decarbonization objectives into market operations would occur through the process outlined above: An RTO board would determine—by a requisite margin of votes—that such changes would help to ensure “just and reasonable rates” and would file a petition with FERC to have such changes approved. FERC would then have the ultimate decision on whether including decarbonization in RTO market rules would in fact be “just and reasonable.”
The remainder of this Part discusses the pathologies that might emerge from using this decisionmaking structure to achieve decarbonization aims.
C. Resulting Challenges for RTO Control of Decarbonization
Several characteristics of RTOs make them imperfect sites for decisions on the shape of decarbonization policies. This section details three particular flaws that should give states pause in ceding control over decarbonization policy to their RTOs: (1) RTO governance presents a diminished space for deliberative, democratic decisionmaking, as compared to state politics; (2) RTO-governance structures create a tendency for policies to become homogenized and watered down when adopted at the regional level; and (3) the jurisdictional frictions created by Hughes pose a risk that states may diminish their own tools for controlling decarbonization if they cede the same functions to their RTOs.
1. A Loss of Public Procedure. — The first challenge of RTO control over decarbonization policies has to do with RTOs’ governance structure, and in particular, the relative sway of various stakeholders and members within RTO governance. Many suspect that stakeholders with assets managed by the RTO—that is, transmission owners—have outsized influence, given that they can wield the threat of leaving the RTO should they be dissatisfied with a change in the governing rules.
Similarly, although “membership” is not limited to these asset holders, weighted voting by membership sector can stack the deck against public interest organizations or those without a strong foothold in the industry.
Moreover, even if the stakeholder-committee processes were viewed as fair, participation in them would still be challenging. In a recent study that interviewed numerous participants in RTO governance, the tenor of many responses was along the following lines: To participate successfully, “you have to be a combination of an economist and a math wizard.”
Others observed that the sheer quantity of stakeholder meetings at RTOs makes it impossible for smaller, less resourced organizations to participate.
These challenges point to the first key risk of shunting decarbonization policy into RTOs: They offer considerably less transparent, only quasi-public frameworks in which to make these critically important decisions. Although RTO-governance processes nominally give boards independent decisionmaking power (a structure that itself already lessens public accountability), their membership rules and the weight that FERC gives to stakeholder opinions—both as a matter of law and practice—dampen this independence.
Thus, if RTOs take over decarbonization policymaking, it will not be elected public officials or their appointed bureaucrats, but private companies, who will hold much of the power to determine the shape of these efforts.
Having expressed these concerns about stakeholder governance, it is important to acknowledge some limits on the extent to which private companies would shape RTO-led decarbonization efforts, particularly on the front end. No RTO is likely to proceed with decarbonization efforts without support from participating states, at least in the current legal and political climate.
States hold this sway because of another feature of RTOs: their explicit disengagement from creating new “policy.”
RTO representatives maintain: “We are a taker of policy not a maker of policy. . . . We don’t create policy. We attempt to interpret policy as handed to us.”
Because RTOs eschew any role in determining what the “public interest” is, states retain what Professor Christina Simeone has described as “an incredible amount of power and influence” in shaping the interaction of public policies and markets.
RTOs disclaim this policymaking function for both political and legal reasons. Politically, it would be substantially harder to convince states to let their utilities join or remain in RTOs if membership meant ceding state policymaking authority to this quasi-private entity. As a legal matter, imagine if an RTO were to include any sort of decarbonization requirement—such as a carbon price—that caused a state’s utilities to pay extra for electricity. For states in which state decarbonization policy supported this change, a “just and reasonable” finding would be understandable—as noted above, pricing carbon in the market would likely help the state accomplish its aims at the lowest price possible. In contrast, for any state that did not have a policy in place that supported this extra payment, a carbon price might well be “unjust and unreasonable” because it would force the residents of the state to pay more for reasons unsupported by any state or federal policy.
Accordingly, any state that did not believe its underlying decarbonization policies justified its utilities’ increased costs for wholesale power would have a strong legal claim to advance in front of FERC and the federal judiciary.
There is, in sum, a byzantine set of dynamics facing RTO efforts to integrate state decarbonization aims. RTOs would be unlikely to request such changes in their tariffs unless both stakeholder committees—via super-majority vote—and all states in a region endorsed the request. FERC, similarly, would be unlikely to approve the request if any state felt it unfairly required its customers to pay for more decarbonization than state law mandated. Not only would all of these negotiations occur deeper in the shadows than does state climate change policymaking, but this de facto near-consensus procedural requirement would also likely have troubling substantive impacts, discussed in the following section.
2. Homogenization and the Watering Down of Preferences. — The second challenge with using RTOs to achieve state decarbonization aims is that their structure and legal mandate leaves them with a diminished set of policy tools as compared to states. Accordingly, the use of these markets to achieve state goals would likely entail both homogenization and watering down of state preferences.
The more drastic homogenizing force would come from imposition of a carbon price, which would require substantial regional agreement across a range of topics. The entire theory behind a carbon-pricing scheme is that it eliminates aims beyond the cheapest decarbonization achievable.
Away would go state preferences for particular types of clean energy, particular locations or scales, or broad-based inclusion or redistribution as a part of decarbonization policy (except to the extent that states continued to pursue these goals through separate, state-specific side policies).
Moreover, states would also have to homogenize their timing and targets for decarbonization. In order for a carbon price to work, there would likely have to be a single price throughout a region.
Setting this price would be challenging, given the divergent state decarbonization targets that exist in multistate regions.
To reach region-wide agreement on a price, states with higher targets would either have to accept a price that would not fully satisfy their decarbonization goals, or find a way to refund revenues from the regional carbon-pricing scheme to those neighbor-states that otherwise feel that they would be “overpaying” (a politically contentious work-around, to be sure).
This dynamic would create a pull toward a “lowest-common-denominator” level of carbon pricing—which would be bad both for states keen on rapid decarbonization and for free-riding states that want to see their neighbors carry more of the burden of achieving decarbonization.
A less drastic homogenization of state climate policies might occur in the case of a Forward Clean Energy Market. In this model, states could control their overall level of desired renewable procurement and pass this information on to the market operator.
But such a scheme would still require, at a minimum, agreement on qualifying resources. To be sure, the scheme could be designed to allow states to make requests for certain types, as well as amounts, of renewable power.
The more the market was segmented by resource type, however, the less benefit it would provide in the form of an interstate, least-cost auction.
Accordingly, a Forward Clean Energy Market would also create pressure to homogenize resource preferences in order to reap the benefits of creating a regional auction.
The homogenizing forces described here present two distinct lines of concern. The first springs from theories of democratic experimentalism.
Because decarbonization is in the early stages of what looks to be a long, expensive, transformative slog, perhaps it is best at this stage to allow multiple models to flourish, instead of subsuming state policies into regional markets. Former FERC Chair Norman Bay adopted this position in a concurrence authored right before his resignation, in which he celebrated state decarbonization policies for their experimental character.
And Professors Ann Carlson and William Boyd have made a thoughtful case regarding the national decarbonization benefits that such state experiments can produce.
This classic “laboratories of democracy” line of argument is compelling, but it captures only part of the challenge that states face as they consider regionalizing their decarbonization efforts through RTOs. In this context, the choice is not simply between the state, regional, or federal scale as the locus of policymaking. Instead, choosing between the state and regional scale also implicates a fundamental choice between electricity markets or regulation as the fundamental driver of decarbonization. States that turn RPSs or carbon pricing over to RTOs must be willing to allow RTO governance to dictate the terms of these policies going forward. To relinquish control to a regional electricity market is thus to authorize a diminishment in the suite of tools and scope of control available to publicly manage decarbonization.
3. The Risk of Aggrandizing Market Control. — There is an obvious objection to the argument made in the previous subsection: Why assume that if states were to give regional markets some control over achieving climate change goals, they could not continue to shape decarbonization’s trajectory through complementary side policies if necessary? This argument relates to an argument economists often make about the risks of mixing policy aims: Why not let markets take care of decarbonization as cheaply as possible and then let states craft separate policies to accomplish their additional aims? Wouldn’t this be better than letting states design these inefficient, multifaceted policies that attempt to mash together the goals of decarbonization with social justice and economic growth?
The response to this argument again revolves around the pathologies of electricity markets, and in particular, the way these markets operate under shared state and federal jurisdiction.
In brief, the challenge is this: Once a state cedes policy objectives to its regional electricity market, the state may suffer limits on its ability to craft supplementary policies or to reclaim the objectives if it does not like the results the market produces.
This argument no doubt appears strange at first blush. Why should a state lose its ability to reclaim control over public-policy objectives, if it only voluntarily gives the market control over these objectives in the first place? The complicating factor is a recent line of Supreme Court jurisprudence interpreting the state–federal boundary in electricity law, which updates the longstanding principle that “[s]tates may not regulate in areas where FERC has properly exercised its jurisdiction to determine just and reasonable wholesale rates.”
Of particular relevance is the Supreme Court’s 2016 decision in Hughes v. Talen Energy Marketing, LLC, which considered a subsidy scheme devised by Maryland to incentivize power plants to build in the state.
Although Maryland’s RTO, PJM, ran a capacity market to ensure future resource adequacy throughout the region,
Maryland was frustrated that the market was not incentivizing any generation to locate in congested areas of the state, where electricity prices were higher than average.
To attract new investment, Maryland “solicited proposals from various companies for construction of a new gas-fired power plant at a particular location.”
It then entered into a “contract for differences” with the winning bidder, in which it guaranteed the winner a certain price for any capacity it supplied that also cleared the PJM capacity market auction.
The Supreme Court had no trouble finding that this scheme violated the Supremacy Clause of the Constitution, as Maryland’s program “set[] an interstate wholesale rate” and thus “invade[d] FERC’s regulatory turf” under the Federal Power Act.
In so holding, the Court was careful to point out that states “of course” maintain authority to “encourage construction of new in-state generation.”
The particular problem with Maryland’s scheme, though, was that the payments to the generator were “conditioned on [its] capacity clearing the auction,” such that they were too closely linked to interstate wholesale prices.
In contrast, the Court passed no judgment on “the permissibility of various other measures States might employ to encourage development of new or clean generation, including tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or reregulation of the energy sector.”
Particularly given this explicit disclaimer, it is hard to know exactly what Hughes portends for the host of policies that states have designed to decarbonize electricity.
There is now a profusion of litigation challenging state clean-energy policies under Hughes’ logic. Both Illinois and New York are in the middle of litigation over the legality of their ZEC programs.
Connecticut, Massachusetts, and Rhode Island have all faced similar attacks against their procurement policies for specific clean-energy resources.
Whether these policies will ultimately prove acceptable will come down to how circuit and district courts interpret and apply the standards articulated in Hughes.
And courts will have to integrate the Hughes precedent with two other recent Supreme Court cases dealing with similar topics: OneOK v. Learjet, Inc.
and FERC v. Electric Power Supply Ass’n.
The Court’s 2016 decision in Electric Power Supply Ass’n affirmed FERC’s jurisdiction over any practice “directly affecting” wholesale rates, striking down states’ arguments that FERC had overreached its jurisdiction.
The year before, in OneOK, the Court clarified that field preemption of state energy law should turn on an analysis of the purpose of the state regulation, such that courts should examine “the target at which the state law aims in determining whether that law is pre-empted.”
For present purposes, the fallout of Hughes and related precedents is that there might be substantial consequences to ceding new powers to regional electricity markets. Hughes made clear that because Maryland had granted PJM the right to control resource adequacy in the region by running a capacity market, the state lost some of its ability to concurrently strive to achieve the same goals. In contrast, right now RTOs claim no control over decarbonization. Quite the contrary: They specifically decry any obligation in this regard. But what if states were to grant their electricity-market operator control over decarbonization? Then, under the logic of Hughes and OneOK, states might be preempted from tying any state policies too closely to whatever market construct for decarbonization the RTO devised. In particular, states would have to be careful not to impermissibly “tether” their policies or prices for clean energy to the results of regional clean-energy or carbon markets.
To be sure, even if a state decided to allow decarbonization to proceed through its RTO, many traditional state methods of encouraging decarbonization would likely not be threatened—including tax breaks, financial incentives, and straightforward subsidies. Although part of the picture, these methods have not emerged as the predominant tools that states use to regulate climate. Instead, the most important state policies are those that proceed through rate regulation, including RPSs, ZECs, regional carbon prices, procurement mandates, and ratepayer support of certain technologies.
There is a reason that these policies predominate: They are funded not through general taxation but through the rate base. They are, in other words, a form of covert “taxation by regulation,”
which serves as a more politically feasible way to meet decarbonization aims than direct taxation.
Under the Hughes framework, these popular forms of “carbon taxation by regulation” would be particularly threatened by RTO jurisdiction over decarbonization. Regional carbon-pricing and state procurement schemes would be at risk if they were designed in ways that pegged their pricing to market outcomes.
Even Renewable Portfolio Standards—the central mechanism of state clean-energy policy to date—might prove vulnerable under an expansive interpretation of Hughes, should a state wish to pursue an RPS design that differs from a regional clean-energy procurement market.
A hypothetical example helps illustrate these concerns. Consider the case in which a state wishes to promote a particular type of renewable resource in the state that its RPS is inadequately incentivizing—say, offshore wind. Right now, in order to promote more offshore wind, a state would be free to offer that generator a long-term premium on top of REC prices that fluctuates based on how much the generator is able to earn from the REC market.
The state might find this particular method for promoting certain renewables quite attractive, as it would create long-term investor certainty without complicating the state’s RPS or causing residents to overpay.
But if renewables procurement were to become RTO administered and FERC jurisdictional (through proposals such as a regional clean-energy market), it is unclear whether such a scheme would survive. It might, under the logic of Hughes and OneOK, be too closely tethered in purpose or effect to the newly FERC-jurisdictional clean-energy market.
Less hypothetically, consider New York’s current study of adopting a single-state RTO carbon adder. There, regulators have proposed that a market carbon price and the state REC program can and should operate simultaneously.
To facilitate this dual scheme, an August 2017 study by the Brattle Group proposed that “[f]uture REC contracts could be structured so that the price adjusts automatically with changes in carbon prices, mitigating regulatory uncertainty associated with a carbon charge.”
Again, under the logic of Hughes, it is not clear that such tethering would be permissible.
Of course, the risks that Hughes and related decisions pose remain largely inchoate. As such, it is hard to know how to factor them into pressing decisions on decarbonization policy and markets. This Article’s final section clarifies how states might integrate these developing risks into decisionmaking about the future of their climate change policies.
IV. Implications for Current Electricity-Law Debates
So far, this Article has explored some dangers in using regional electricity markets as a tool to accomplish the “social project” of decarbonization. At the same time, the Article does not intend to give short shrift to these markets’ potency as a potential least-cost solution or as a bargaining tool in interstate climate negotiations. To evaluate these tradeoffs, section IV.A first lays out some variables to help states assess whether regional electricity-market integration of decarbonization objectives is in their best interest. Sections IV.B and IV.C then briefly explore options for regionalizing climate policy outside RTOs and how markets might adapt to accommodate such schemes. Finally, section IV.D examines what this Article’s argument portends for laggard states, as opposed to states taking the lead on climate change.
A. Deciding Whether to Regionalize Through Electricity Markets
The limitations and pathologies of regional electricity markets identified in this Article suggest that states should assess three variables in deciding whether to aggressively pursue the integration of climate goals into these markets: (1) the relative priority of advancing least-cost solutions; (2) the evolution of legal doctrine surrounding federal–state jurisdiction over electricity policy; and (3) regional politics.
1. Relative Priority of Least-Cost Solutions. — Much of this Article’s analysis has centered on the ways in which state climate policies evince an understanding of decarbonization as a social project with multifaceted goals. State climate policies illustrate attention to distributional consequences, the risks and externalities associated with various low-carbon technologies, and the ways in which transforming energy can also transform state economies. But leading states are also pursuing ambitious targets, which are likely to cost substantial sums to achieve.
It could be that as implementation progresses, affordability will become the dominant priority for states pursuing decarbonization.
Accordingly, the first question state policymakers considering regional integration might ask is: How important is least-cost decarbonization to state residents, as compared to a more managed decarbonization trajectory that incorporates other goals? The more the scale tilts in favor of affordability as a central criterion, the greater the benefits of regionalization through electricity markets.
Understanding decarbonization as a social project also points to some useful conclusions about what kind of regional market design for decarbonization states might prefer. In particular, a Forward Clean Energy Market in which states can funnel their decarbonization preferences into the market design presents less of a relinquishment of state control than does a region-wide climate price.
Of course, a clean-energy market also presents a less thoroughly efficient solution—again highlighting the importance of prioritizing state aims relating to decarbonization.
One final word regarding temporality is in order. Even if a state finds that a particular market construct for achieving decarbonization might perfectly achieve its aims at time zero, there is a long-term risk to ceding such control to the market. Given the scale of the enterprise of deep decarbonization, a state’s goals and preferences regarding the shape of decarbonization may well evolve over time.
If state aims change such that affordability ceases to be the priority criterion, a state may have limited recourse once it has ceded decarbonization imperatives to the market, other than full-scale market exit.
This temporal constraint appears particularly acute with respect to carbon-pricing schemes, which may “lock in” investments that states do not want their ratepayers to support.
A regional carbon price would likely incentivize near-term investments in new combined-cycle natural gas facilities, which could displace higher-emitting fossil fuel facilities.
But states may not want a carbon-price scheme to help finance construction of these types of facilities, given their inability to contribute to long-term “deep decarbonization” targets.
States weighing market integration should thus carefully evaluate not only short-term goals but also the compatibility of a market scheme with their long-term aims.
2. Evolving Legal Risk. — The second variable that can help shape state decisions regarding decarbonization and electricity markets is that of evolving legal risk. As traced in section III.E, the Hughes decision has opened up a new line of attack on state climate policies. How these cases play out in the coming years should influence decisions about whether to decarbonize through regional markets.
Consider first the outcome in which courts give Hughes its narrowest possible reading. Courts in this instance would hold that Hughes preempts only those state policies that explicitly condition receipt of some benefit on clearing wholesale electricity markets.
In that case, states might feel more confident in ceding some authority over decarbonization to regional electricity markets, because they could assume such shared authority would place limited constraints upon state power. A state in this scenario would likely maintain considerable ability to shape its decarbonization trajectory, so long as complementary state policies were not explicitly conditioned on certain regional decarbonization market outcomes.
Now consider the (in my opinion, less likely
) outcome in which courts use the logic of Hughes to strike down RPSs, nuclear subsidies, and special procurement orders as intruding on federal jurisdiction over regional electricity markets. In that case, states would be faced with a conundrum. On the one hand, states would be left with considerably fewer climate policy options other than using regional electricity markets, since their primary policy levers to date would be impermissible. On the other hand, a decision to cede decarbonization objectives to the market would likely take even more policy options off the table, given that Hughes and its progeny in this scenario would stand for the proposition that states are prohibited from enacting a broad range of policies that too thoroughly impact regional markets. In this case, states would be faced with difficult choices between returning to the drawing board in terms of how to craft state climate policies, or giving in to the pressure to let the markets do their decarbonization work for them.
Finally, consider the emerging middle-ground scenario, in which courts develop a sliding scale for determining which state policies are too closely “tethered” to wholesale markets.
Early indications are that courts are likely to head in this direction. In June 2017, the Second Circuit became the first circuit court to interpret Hughes, ruling on a challenge to Connecticut’s use of its procurement laws to encourage more solar energy.
The plaintiff in that case argued that Connecticut’s procurement scheme should be preempted under the logic of Hughes, since the state was directing its utilities to enter into a specific wholesale contract and therefore interfering with federal jurisdiction over wholesale electricity pricing.
The Second Circuit dodged the direct preemption argument, instead finding that Connecticut’s law did not compel utilities to enter into contracts with the winning bidders of the procurement process.
The court thus left open the question of whether a state scheme that more clearly required utilities to enter into contracts with certain renewable resources would be preempted. Nevertheless, the court took a moment to opine on Hughes, observing that Connecticut’s scheme appears quite different from Maryland’s failed program, given that Connecticut’s program involves traditional bilateral contracts that are in no way conditioned on certain resources clearing the regional capacity auction.
As such, Connecticut’s contracts resemble “precisely what the Hughes court placed outside its limited holding.”
In July 2017, U.S. District Courts for the Northern District of Illinois and the Southern District of New York reached similarly limited conclusions in dismissing lawsuits against Illinois’s and New York’s ZEC programs.
The first opinion to be issued concerned Illinois. Plaintiffs in that case argued, inter alia, that the ZEC program violated the Hughes standard for preemption because it was too closely tied to wholesale prices, since Illinois’s program allowed for the price of ZECs to be adjusted based on predictions of wholesale prices.
The court rejected this argument, reasoning that basing ZEC prices on future projected wholesale prices is not an interference with the wholesale market that rises to the level of Hughes.
The Southern District of New York reached the same conclusion regarding that state’s program. Its opinion emphasized that Hughes was focused on the “impermissible tether” of required participation in the wholesale market and that New York’s ZEC program required nothing of the sort.
Moreover, the court observed, the ZEC program “does not guarantee a certain wholesale price that displaces the market-determined price” but rather simply places a separate value on the environmental attributes of nuclear.
The Illinois and New York decisions have been appealed to the Seventh and Second Circuits, respectively.
These courts are now tasked with drawing a delicate line between schemes that come too close to electricity markets in design or in purpose
and those that stay further away from pegging their schemes to market prices and functions. The fact that this jurisprudence appears to be shaping itself around this inquiry should at least give states pause about ceding control over decarbonization to the markets. In doing so, states risk carving out more room for their policies to become constrained by regional markets’ integration of the project of decarbonization.
3. Regional Politics. — One final variable relevant to state decisionmaking on integrating climate change aims into regional electricity markets is that of regional politics. This Article painted regional electricity-market governance as suffering from pathologies that are likely to yield least-common-denominator solutions.
This potentiality is least problematic in one-state RTOs like New York. That state is more likely to be able to translate its climate goals into a market-based scheme that fully reflects its decarbonization aims—leaving one fewer variable for state regulators there to contend with.
In multistate regions, though, the challenge of watering down is quite real. But even there, perhaps aggressive states might use market integration as a bargaining chip in negotiations with other states that are worried about state climate policies’ destabilizing effects on the regional market. In particular, they might suggest to a recalcitrant state: “Up the ambition of your RPS five percent, or allow the market to use a higher price on carbon, and we will commit to pursuing regional decarbonization through the market.” It is not clear whether laggard states see enough appeal to using electricity markets that such a promise could motivate them to greater action on climate change. But the more states find this outcome plausible, the more appealing using regional electricity markets to decarbonize might be.
B. Thinking Outside the Market: State-Led Climate Policy Regionalization
Much of the appeal of using regional electricity markets to accomplish climate change aims comes from the opportunity they present for capitalizing on the efficiencies of a larger, regional market construct. But if that’s the draw for states, then electricity markets are far from the only method available. Many states have already devised regional solutions through cooperative arrangements that avoid the pathologies of electricity markets.
Two successful examples predominate.
The first is a regional cap-and-trade program, the Regional Greenhouse Gas Initiative (RGGI), which nine northeastern states have been running since 2009.
In this scheme, participating states devised a “memorandum of understanding” that set forth negotiated carbon-reduction targets for each state, along with a plan for each state to adopt legislation approving of the regional scheme.
All states were able to pass such legislation, bringing the scheme into force. Under the program as it is currently run, each generator that emits carbon pollution must purchase enough credits to cover its emissions from a region-wide auction.
RGGI has coexisted for almost ten years alongside the PJM, NYISO, and ISO-New England regional electricity markets with scant complaints regarding market interference. Generators simply factor the cost of RGGI allowances into their expenses, on which they base their bids into regional electricity markets.
Clearly this requirement to at least partially internalize the costs of carbon emissions has an impact on the prices at which these generators offer electricity to the regional markets, but no one argues that it creates a distortionary effect.
RGGI thus stands as proof that it is possible to concoct a regional pricing scheme outside the regional electricity market without causing undue interference.
RGGI is not an unmitigated success—otherwise, many of its participants would hardly now be considering building carbon pricing into their regional electricity markets. RGGI’s main problem, quite simply, is that the caps that states were able to agree upon for RGGI—and the resultant allowance prices—have been too low to accomplish the most ambitious states’ decarbonization goals.
Nevertheless, RGGI has functioned as a base policy upon which states can build the myriad other decarbonization policies discussed in this Article. And RGGI can function in this manner because a regional “memorandum of understanding” creates no risk of wresting away state power to address decarbonization simultaneously at the state level. At the same time, building upon years of trust among states, RGGI has twice succeeded in lowering its program carbon cap, thus raising the cost of allowance prices and strengthening the program’s effects.
RGGI’s structure thus presents an appealing alternative to electricity-market integration for states intent on regionalization.
A second example of regional cooperation on decarbonization outside of electricity markets comes from regional trading of RECs—the renewable energy credits that utilities use to demonstrate compliance with state RPS.
To date, most REC markets are single state—thus creating what many critics have bemoaned as unnecessarily constricted trading pools.
But the New England states have created a regional market for RECs that enlarges the pool of RECs available to create a more stable, fluid market.
They have done so through state laws that allow for generators to satisfy state RPS obligations with RECs purchased from any generator in the region that meets the state-specific definition of “renewable,” or similarly, from a renewable generator outside the New England region that can demonstrate that its renewable energy was imported into the region.
In this way, New England already orchestrates regional cooperation on renewable energy.
These programs suggest that regional cooperation can flourish without having to relinquish control to quasi-private governance organizations that are not under state oversight. To be sure, both RGGI and New England’s REC-sharing arrangement carry their own legal risk. Commentators frequently point to the dangers of both the Compact Clause
and the Dormant Commerce Clause
when it comes to programs like these.
These risks are not theoretical—both RGGI and the New England REC program have faced lawsuits on these grounds.
But for now, courts have sided with the states. One New York case brought against RGGI on Compact Clause grounds settled;
another was thrown out on procedural grounds.
New England’s regional REC scheme recently received substantial validation on Dormant Commerce Clause grounds, in the same Second Circuit opinion that upheld the state’s renewables procurement regime.
With these holdings in place, both a regional cap-and-trade program and a regional market for RECs appear to stand on relatively firm legal ground. Of course, it could still come to pass that RPS programs themselves get struck down or that another circuit analyzes regional RECs’ constitutionality differently. But the legal risk inherent in pursuing these types of regional solutions comes for states with an attendant gain—not having to relinquish public control over the course and content of these important decarbonization programs.
C. Designing Markets to Accommodate, Rather than Achieve, State Policies
The problem, of course, with pursuing regional solutions outside markets is that it returns the states to the problem animating current disputes: the fact that extra-market solutions, whether pursued at the regional or state level, may distort and ultimately dismantle electricity markets.
Here, then, a separate set of proposals for how to manage these concerns is salient. While many are deep in exploration of how to use electricity markets to achieve decarbonization, there is a second strand of proposed reforms that would focus on redesigning electricity markets not to subsume state climate policies but merely to accommodate them. Such accommodation would require regional markets to embrace the coexistence of manifold state policies in a way that has not always been the case to date and to intentionally mold their rules to support the continued viability of markets in the face of these state policies.
There are many ideas about how markets might be refined to better accommodate state climate policies, and most proposals tend to be quite technical. The basic idea behind them, though, is this: Regions should identify what current market signals are failing to achieve, and rework the market construct to achieve these aims. That might be through pricing some “attribute” of electricity that markets do not currently value—for example, markets might pay generators for their ability to “ramp” up and down quickly to balance out renewables.
Or, it might be through redesigning capacity markets to pay different prices to state-supported resources—like renewables and nuclear energy—and resources that are unsupported by these policies.
The Department of Energy’s October 2017 proposed “Grid Resiliency Pricing Rule” can be understood as one such attempt to refine market structures
—albeit, in the view of many experts, a poorly designed one. In that notice of proposed rulemaking, the Department asked FERC to consider providing out-of-market payments to “fuel-secure” resources that it believes are undervalued by current regional market-pricing structures.
In particular, this proposed rule would have provided additional compensation to coal and nuclear plants in recognition of the “resiliency” benefits
that substantial on-site storage of fuel can provide.
In January 2018, FERC terminated this proposed rulemaking, explaining that the proposal was legally insufficient because it failed to demonstrate that regions were experiencing any resiliency challenges that resulted in “unjust and unreasonable” RTO tariffs.
In FERC’s termination order, several commissioners sharply critiqued the Department of Energy’s plan for its potential to unravel energy markets. In particular, they suggested that the Department had used the amorphous goal of “resiliency” to justify payments to two favored resources that do not clearly provide grid resiliency benefits, while ignoring other resources that might better provide grid resiliency.
In place of this misguided attempt, the Commission initiated a new rulemaking “to specifically evaluate the resilience of the bulk power system in the regions operated by [RTOs],” as a first step in determining whether there is a real need to redesign markets to respond to resiliency challenges.
Through these new twists, the Department of Energy’s controversial proposal could ultimately prompt regional solutions that strengthen markets while responding to concerns over ever-expanding state resource subsidization. A frank reckoning with exactly what “resilience” services are lacking from the grid and what resources and investments might provide them should help regions determine if there is some “resiliency attribute” that markets currently undervalue and whether there is a market-grounded methodology for rewarding any resources that provide that value.
If pursued in this manner, an RTO’s creation of an additional revenue stream for currently undervalued “resiliency” characteristics could help offset any resilience challenges that state-supported renewables might pose for the grid.
At the same time, such a reform would not undermine state climate change goals and programs by selectively providing payments to the most carbon-polluting resource in the market: coal.
The Department of Energy’s proposed Grid Resilience Pricing Rule thus provides a sort of crossroads that underscores this Article’s argument about why states should be cautious in ceding decarbonization to RTOs. At best, FERC may use the proposed rule as a jumping-off point for redesigning markets in a way that truly helps RTOs better accommodate state climate change policies. If this path is taken, then state and regional policies will cause less friction for markets going forward—rendering robust state decarbonization policies less problematic. At worst, certain RTOs might use the proposed rule as an invitation to create their own subsidy schemes aimed at propping up aging coal and nuclear for reasons unrelated to climate change aims—and in large part, in direct contravention of them.
If this path is pursued, then states will likely be glad not to have even partially ceded the goal of decarbonization to these markets, only to have them work to actively undermine it.
These concerns—that RTOs and their participating states might end up with competing objectives—highlight another potential avenue of reform. Twenty-odd years ago, FERC created RTOs as a grand experiment in new ways to manage electricity.
But we have moved beyond the early, experimental stage of RTOs’ existence. If their initial governance structures turn out not to serve states well, perhaps it is time to consider not only tweaking market design to accommodate state policies but also more dramatically reforming RTO governance itself. There is not enough space in this section to consider the possibilities and practicalities of pursuing these larger reforms, but hopefully the concerns raised here will prompt further inquiries in this vein.
B. But What About the Laggards?
This Article focuses on a conundrum facing states that are leading the way in addressing climate change, arguing that they should cling to the right to shape their decarbonization trajectories. In articulating this argument, this Article has attempted to sketch the ways in which decarbonization is a “social” project, requiring care in crafting its contours rather than merely its end game.
But the primary problem confronting state climate change policy today isn’t the underappreciated “social nature” of decarbonization. The bigger problem is the fact that a good many citizens—and state governments—deny the existence of climate change and refuse to do much of anything to promote decarbonization. Laggard states not only do little to address climate change within their own boundaries but also actively impede efforts at federal climate change policies.
For those who care about action on climate change, then, this Article’s argument that we should leave states to shape their own policies might seem to create a critical downside: Leaving the aims of energy policy to state legislators and regulators means accepting whatever ends they democratically determine, be they climate change goals or coal mine job preservation goals. Such risks are not hypothetical: Ohio has already pursued efforts to provide supplementary ratepayer funds to several coal plants at risk of retirement,
and there is considerable interest under the present Administration in protecting “baseload power” from renewable energy.
This interest may prompt more states to enact policies that seek to support not particular clean-energy sources but particular dirty-energy sources.
Such is these states’ right in a federalist system with no overarching federal climate policy.
This state schism on climate change thus creates a powerful argument in favor of federal action, which could bind all states to achieving progress on decarbonization.
But these arguments are orthogonal to this Article’s inquiry, which is of a narrower scope: Given the fact that no federal climate policy is likely to be forthcoming soon, should states seeking to decarbonize work together through their regional electricity markets to do so?
Using RTOs to address decarbonization simply does not have the same power to pull along laggard states. Because of RTOs’ voluntary membership and stakeholder-governance processes, laggard states would be perfectly capable of blocking any RTO decarbonization proposals that required them to go above and beyond on climate.
And even if a region were to figure out a way to allow certain of its members to pursue decarbonization goals absent full regional participation,
such cooperative action would not stop other states in the region from pursuing policies aimed at propping up carbon-intensive resources.
Accordingly, although state polarization argues for federal action, it does not lend force to proposals to regionalize decarbonization policy through electricity markets.
Conclusion
Scholars, regulators, and market participants all recognize that electricity markets, in their current form, do not incentivize the rapid decarbonization of the electricity sector necessary to respond to climate change, thereby forcing states to act on their own. This realization has provoked conversations at FERC, at RTOs, and among states as to whether these markets should be redesigned to accomplish states’ climate change goals. This Article has questioned the use of redesigned electricity markets as a driver of decarbonization in the United States. In particular, this Article has pointed out the ways in which decarbonizing electricity is a social project that should be managed by politically accountable entities, working through public processes capable of channeling and incorporating numerous goals related to decarbonization.
Those who are committed exclusively to the most rapid decarbonization possible are unlikely to be persuaded by this argument. It is true that in the present political climate, using electricity markets to respond to climate change would be an expedient and efficient pathway forward. Nevertheless, this Article has highlighted the risks that attend expediency. If climate change policy is shunted into these markets rather than left open for public debate, states will have lost a significant amount of control over how decarbonization proceeds. Instead, these decisions will be made in quasi-private governance institutions with complex voting rules and opaque power structures, under murky jurisdictional boundaries that may make it hard for states to assert concordant control.
The technical intricacies inherent in discussions over integrating climate policies and regional electricity markets often drive participants to put aside larger questions regarding the animating forces of climate policy—at great peril. Debates over using electricity markets to accomplish decarbonization should in fact highlight the question of why climate change is a problem in the first place. After all, civilizations have crumbled and species have gone extinct due to climatic changes.
For many, the answer to this question is that the continued peaceful existence of humans on Earth—and the minimization of their suffering—is a worthy aim.
If the project of decarbonization is in service of the continued wellbeing of humanity—and, potentially, species beyond humans
—it must be part of a larger social conversation about how we want to live in communities in the future. These conversations are worth preserving for the public forum, in which debate, dissent, experimentation, and long-term social visions can continue to develop within and alongside decarbonization policies in the coming decades.