The electricity sector is the second-largest source of greenhouse gas emissions in the U.S. economy.
Nonetheless, even with clear and compelling evidence of the dangers of anthropogenic climate change,
the United States has enacted very little comprehensive national policy to address power-sector emissions of greenhouse gases.
In the absence of congressional action, states have taken the lead, developing increasingly ambitious goals for greenhouse gas reduction and the proliferation of renewable energy resources.
State authority to regulate electricity, however, is limited by the Commerce Clause
and the New Deal–era Federal Power Act (FPA), which apportions jurisdiction between federal and state actors.
Traditionally, courts have read the FPA to establish a scheme of dual federalism, favoring broad authority for the Federal Energy Regulatory Commission (FERC) at the expense of state influence.
In the past two years, three major events have occurred at the confluence of renewable energy policy, state action on climate change, and the role of the states in energy regulation. First, in a series of cases, the Supreme Court has upended its traditional construction of the FPA, reaffirming broad federal authority over the power sector but potentially giving state regulators more leeway to influence the spread of renewable energy.
Second, California and New York have enacted among the most aggressive renewable energy mandates in the United States, ambitiously attempting to obtain fifty percent of their electricity from renewable sources by 2030.
Finally, Donald Trump has become President of the United States—bringing with him a cabinet replete with fossil fuel advocates and climate change skeptics—signaling a continuation, if not an intensification, of renewable energy inaction in Washington.
States like California and New York will therefore remain at the vanguard of renewable energy policy in the United States for the foreseeable future. Their authority under the FPA will remain central to renewable energy’s success.
This Note examines, through the lens of state policymakers in New York and California, the effect of the new FPA jurisprudence on the ability of states to reach aggressive renewable energy goals without a comprehensive federal policy. The Court’s recent decisions suggest a new analytical framework for policies that straddle what was once a sharp federal–state jurisdictional divide. This Note builds on existing literature that has analyzed such interstitial policies in the past, exploring whether changes in the doctrine will remove obstacles in states’ paths.
Part I of this Note describes the structure of the interstate electrical power sector and traces the history of federal jurisdiction—and preemption of state authority—in the field of energy regulation. It ends with a discussion of the new Supreme Court jurisprudence on the federal–state jurisdictional boundary. Part II introduces new and exceptionally aggressive state goals in pursuit of a renewable power sector, discusses the preemption challenges that tools supporting those policies have faced under prior constructions of the FPA, and considers whether the new jurisprudence can resolve those challenges. Finally, Part III proposes that FERC can and should use the new jurisprudence to unlock latent cooperative federalism principles in the language of the FPA. It then explores how state regulators can work with—and potentially against—their federal counterparts to ensure the viability of their states’ clean energy goals. The Note concludes that although the Supreme Court has probably saved several important state policy tools from preemption, states will remain dependent on FERC’s cooperation to meet their increasingly ambitious renewable energy and emissions standards.
I. Energy Federalism from the Federal Power Act to Today
This Part contextualizes the Supreme Court’s new approach to questions of federalism in the electricity sector. Section I.A describes the electricity grid and the basic operation of electricity markets, providing a brief background to inform the law and policy discussions that follow. Section I.B discusses the origins of federal regulation of the industry, how courts have traditionally interpreted the scope of federal authority, and how changing electricity infrastructure has challenged these interpretations. Section I.C discusses the most recent jurisprudence on energy federalism and how it departs from the traditional jurisdictional analysis.
A. Electricity, Electricity: An Overview of Electrical Power in the United States
In the United States, electricity travels from producers to end users via a massive interstate network collectively known as the electric power grid (“the grid”).
The grid comprises four central components: generation, transmission, distribution, and load.
Generation plants produce power—by burning fuel, sustaining controlled nuclear fission, or harnessing renewable natural processes—and then inject the resulting electricity into the long-range transmission system.
The high-voltage lines of the transmission system carry electricity to smaller regions, where short-range networks called the distribution system deliver it to end users.
Most residential and commercial customers receive power from the distribution network. In the prototypical model, generators sell their electricity to load-serving entities (LSEs) at wholesale—sale for resale
—over the transmission system. LSEs then sell that electricity at retail—sale to end users—over the distribution system.
Structures for the ownership and management of generation, transmission, and distribution resources vary across the United States. Traditionally, vertically integrated utilities owned all power infrastructure and passed their costs to users through regulated rates approved by state public utility commissions (PUCs).
Twenty states still implement some form of this model.
In most of the country, covering two-thirds of total electricity traded in the United States,
transmission remains a regulated natural monopoly, but wholesale electricity rates are set through competitive auctions managed by one of six organizations, called independent system operators (ISOs) or regional transmission organizations (RTOs).
In wholesale energy markets, the various generators within the ISO or RTO region offer a set quantity of energy at a set rate for each unit of time during the day. The ISO or RTO then organizes these offers into a “supply stack,” the priority order in which the operator will “dispatch” each generator, usually on the basis of cost.
All generators dispatched at a given moment receive the same rate as the highest-priced generator currently operating.
ISOs and RTOs operate markets like these for a number of grid services, including energy, installed capacity, and ancillary services.
Notably, many transactions in ISO and RTO regions occur through bilateral contracting, in which LSEs negotiate with independent generators to purchase a specified quantity of energy at an agreed-upon rate over a particular period of time.
Two regulatory bodies share authority over these electricity sales: FERC at the federal level and PUCs at the state level.
Among other responsibilities, these agencies set rates (directly or through markets) for the entities that operate generation, transmission, and distribution infrastructure. The apportionment of jurisdiction between these regulatory bodies is the primary subject of this Note.
B. Power over Power: The Development of Energy Federalism
Congress passed the Federal Power Act in 1935 to regulate interstate electricity sales.
It began as a gap-filling measure, designed only to occupy the regulatory void in which states could not provide for just and reasonable electricity rates. Over time, however, the Supreme Court has construed the Act to give federal regulators increasingly broad authority at the expense of state jurisdiction. This section outlines the statutory origins, and traces the judicial constructions, of federal energy regulation in the United States.
1. Attleboro and the FPA: The Origins of Federal Regulation of the Electricity Industry. — Extensive federal regulation of the power sector began in 1935 when Congress passed Part II of the Federal Power Act.
Before 1935, generation, transmission, and distribution services—whether the electricity was sold at wholesale or retail—were subject either to state and municipal oversight or to no authority at all.
The states’ right to act as sole regulators, however, came to an end in Public Utilities Commission of Rhode Island v. Attleboro Steam & Electric Co.
In Attleboro, a Rhode Island power company sold electricity to a Massachusetts utility at a rate filed with the Rhode Island Public Utilities Commission.
When the Commission allowed the seller to raise its rate, the buyer sued.
The case reached the U.S. Supreme Court, which invalidated Rhode Island’s authority to regulate the interstate transaction.
The Court held that under the Commerce Clause of the U.S. Constitution, such interstate regulation “can only be attained by the exercise of the power vested in Congress.”
This holding produced a condition known as the “Attleboro gap,” a regulatory vacuum allowing unfettered latitude to businesses moving electricity across state lines, a commercial space that Congress had not chosen to—and states no longer could—regulate.
Congress enacted the FPA to close this gap.
The Act charged the Federal Power Commission (FPC)—now FERC
—with ensuring that “[a]ll rates and charges . . . for or in connection with the transmission or sale of electric energy . . . and all rules and regulations affecting or pertaining to such rates or charges shall be just and reasonable.”
Congress authorized the FPC to exercise this power over “the transmission of electric energy in interstate commerce and . . . the sale of electric energy at wholesale in interstate commerce,” but it withheld federal jurisdiction to regulate “any other sale of electric energy.”
In particular, the statute preserved state jurisdiction “over facilities used for the generation of electric energy or over facilities used in local distribution or only for the transmission of electric energy in intrastate commerce.”
The FPA therefore draws jurisdictional distinctions along several axes: transaction type (wholesale vs. retail), service type (transmission vs. generation and distribution), and geography (interstate vs. intrastate commerce).
The FPA, as interpreted by FERC and the courts, remains the primary basis for federal control over the electricity industry.
2. The Bright Line and the Filed Rate Doctrine: Judicial Constructions of the Federalist Balance from 1935 to 2015. — The FPA’s passage refocused judicial analysis of state regulation over the power sector. Whereas the permissibility of state regulation had previously turned only on whether the regulatory action violated the Commerce Clause,
the principal question after 1935 was whether the FPA preempted state regulation under the Supremacy Clause.
The Supreme Court, initially careful to limit federal incursion into potential zones of state regulation, gradually expanded this federal jurisdiction, increasingly preempting state regulation.
In the earliest cases interpreting the FPA, the Court recognized the Act as granting the federal government no more than the authority over wholesale rates that the Constitution denies to the states.
In Connecticut Light & Power Co. v. Federal Power Commission, it studied the FPA’s legislative history, noting that a commissioner of the FPC (which had drafted the Act) had testified before Congress that “[t]he new title . . . is designed to . . . fill the gap in the present State regulation of electric utilities. It is conceived entirely as a supplement to, and not a substitution for, State regulation.”
The Court also cited House and Senate reports averring that the bill “takes no authority from State commissions”
and that it is intended to “extend . . . regulation to those matters which cannot be regulated by the States and to assist the States in the exercise of their regulatory powers, but not to impair or diminish the powers of any State commission.”
Finding this “[l]egislative history . . . illuminating as to the congressional purpose,”
the majority declared that the FPA withheld federal jurisdiction over all local distribution facilities that states could have regulated between Attleboro and the Act’s passage, even if they traded in power that had traveled across state lines before being transferred for local distribution.
The Court recognized that generation, transmission, distribution, and load are technically sufficiently interdependent to bring “the whole enterprise . . . within the reach of the commerce power of Congress” and that there may even be advantages to regulating across the entire field of potential federal jurisdiction.
Nonetheless, the Court determined that Congress had purposefully cabined the Commission’s authority to preserve state control over the industry, drawing a line between transmission and distribution irrespective of the “interstate” character of the electricity itself.
This analysis developed into what would remain the prevailing doctrine until 2016: that the Act had apportioned jurisdiction among the state and federal governments by drawing a “bright line” between wholesale and retail electricity sales.
The Court articulated the bright line test most famously in Federal Power Commission v. Southern California Edison Co., often called “the ‘Colton’ Case”
or “City of Colton.”
In that case, the utility Southern California Edison, which operated only in California but received power from the Hoover and Davis hydroelectric dams in Arizona and Nevada, contracted to supply the city of Colton with all of its required electricity.
Colton then resold the electricity to residential, commercial, and industrial customers.
After initially allowing the California PUC to regulate the Edison–Colton sale, the FPC asserted jurisdiction over the transaction in 1958.
The FPC claimed authority on the basis that Edison sold electricity from the interstate grid for resale, placing it within the Commission’s statutory jurisdiction.
On review, the federal court of appeals tried to overcome this formalistic jurisdictional claim on the grounds that the Commerce Clause permitted state regulation of the Edison–Colton sale, which occurred wholly within California and had little impact on the national market.
The court reasoned that since § 201(a) of the FPA declared that “[f]ederal regulation . . . [is] to extend only to those matters which are not subject to regulation by the States,” the FPC had no authority when the Commerce Clause permitted state regulation.
To rule out Commerce Clause concerns, the appellate court considered factors particular to the sale, including that the only other states conceivably prejudiced by California’s authority already received federal protection in the form of Interior Department control over the Hoover and Davis dams.
A unanimous Supreme Court rejected this context-heavy reading of the FPA. Instead, Justice Brennan wrote, “Congress meant to draw a bright line easily ascertained, between state and federal jurisdiction.”
The Court determined that the FPA’s role as a gap-filling measure did not actually protect every pre-Attleboro power of state PUCs from federal preemption.
Under this construction, an example of dual federalism,
all wholesale transactions—including even the slightest amount of electricity produced out of state, no matter how minor the interstate element and its effects on interstate commerce—fell to the FPC. Likewise, even interstate retail sales fell within state jurisdiction.
The bright line test is therefore highly formalistic, concerned only with whether the regulator acted on the wholesale or retail market while ignoring the subjective interstate effects of the transaction at hand.
Although the FPA can reach only those wholesale transactions that occur in interstate commerce,
the Supreme Court has construed “interstate commerce” quite broadly. In Federal Power Commission v. Florida Power & Light Co., the Court held that the FPA granted federal jurisdiction over Florida Power & Light (FP&L), a utility with no electrical connections to out-of-state power companies.
That FP&L interconnected with other utilities that did trade power across state lines was sufficient to find interstate activity, even without the certainty that FP&L ever transferred power to other utilities at the same time that those utilities were transferring power out of state.
The decision brought any wholesale transaction on any part of the transmission grid within federal jurisdiction.
The FPA’s bright line did not preempt only state regulation of the interstate wholesale market. It also limited state regulatory authority over retail sales, which lie firmly on the state side of the bright line, through a line of jurisprudence known as the “filed rate” doctrine.
When FERC approves the rate at which a utility purchases electricity at wholesale, a state PUC may not set a lower retail rate that makes a utility unable to recoup costs incurred in wholesale transactions.
The filed rate doctrine requires state deference not only to FERC-approved rates but also to the allocation of differently priced wholesale power among utilities, which “directly affects” the resulting cost of electricity.
The Court has repeatedly reaffirmed the filed rate doctrine, including twice in the era of restructured markets.
3. Blurring the Bright Line: Restructured Markets Complicate the Federalist Balance. — The basic balance established under the New Deal–era FPA functioned smoothly for several decades as utilities and ratepayers benefited from steady growth and economies of scale.
In the late 1960s and early 1970s, however, increasing operation costs, inflation throughout the economy, failed investments in nuclear power, and the 1973 oil crisis resulted in sharp utility price hikes that chilled demand for electricity and threatened utilities’ abilities to recover their investments through retail rates.
Utilities could no longer drive down prices with economies of scale, revealing that cost reductions from rapidly advancing technology had masked inefficient investments driven by a cost-of-service rate system that rewarded overbuilding.
These stark circumstances, combined with increasing interest in environmentally sustainable generation, led to calls for political intervention.
That intervention came in the form of the Public Utility Regulatory Policies Act of 1978 (PURPA).
Among other provisions, PURPA required utilities to begin purchasing power from small cogeneration and renewable energy generators—termed “qualifying” facilities (QFs)—at a rate not to exceed “the incremental cost to the electric utility of alternative electric energy,” what is now universally called the utility’s “avoided cost.”
Importantly, Congress built PURPA around a theory of cooperative federalism; the statute gives FERC responsibility for verifying a facility’s status as a QF and state PUCs—which in all other circumstances may not set wholesale rates
—broad authority to define avoided costs for the utilities in their jurisdictions.
Most states chose to award QF contracts under PURPA through competitive bidding.
By guaranteeing a market for QFs, PURPA facilitated the entry of new non-utility generators (NUGs) into an electricity infrastructure dominated by massive, vertically integrated utilities. These nontraditional producers were wildly successful; by the 1990s, NUGs constituted almost ten percent of total generation.
The success of NUGs under PURPA demonstrated that, in the face of utility inefficiency and declining economies of scale, consumers could benefit from a competitive market of independent generators.
As a result of PURPA’s success, statutory development in the late twentieth and early twenty-first centuries has largely been motivated by the project of restructuring the energy sector to facilitate greater competition. In 1992, Congress passed the Energy Policy Act (EPAct),
which exempted independent generators offering electricity on the wholesale market (even those not qualifying as QFs) from burdensome statutory restrictions and authorized FERC to require utilities to open their transmission lines to these independent wholesale generators.
FERC took Congress up on its invitation to open up the grid,
and subsequent orders have only further encouraged deregulation and restructuring.
The ultimate result of this movement toward competition is the patchwork of competitive and vertically integrated market regions that exists today.
This process of restructuring rendered the “bright line” between state and federal jurisdiction increasingly difficult to resolve, as many scholars have noted.
Deregulation has brought about a vast increase in the quantity of electricity sold at wholesale and in interstate commerce.
The electricity regulatory environment has changed so much as to be nearly unrecognizable to the one that bore the FPA and most of the jurisprudence reinforcing it, a fact the Court itself observed in its last major FPA jurisdiction case before 2016.
Nonetheless, before the Supreme Court’s 2016 term, the retail–wholesale split remained the prevailing division of regulatory authority over the power sector.
C. Separate Spheres Collide: FERC v. EPSA and Hughes v. Talen Energy Marketing
In early 2016, the Supreme Court decided two cases—FERC v. Electric Power Supply Association (EPSA)
and Hughes v. Talen Energy Marketing, LLC
—that diverged from the Court’s traditional bright line approach to energy federalism. In EPSA, the Court held that FERC’s jurisdiction under the FPA extended to a program substantially affecting retail markets, the traditional bailiwick of the states.
In Hughes, it held that state attempts to encourage new generation through a wholesale capacity market were preempted under the FPA.
Like previous FPA jurisprudence, each case extended or confirmed federal authority. Unlike previous jurisprudence, however, each case also forwent a strict bright line analysis, trading the traditional formalist jurisdictional test for a functionalist evaluation.
1. FERC v. EPSA. — EPSA concerned FERC’s assertion of authority over a program called demand response, a process whereby businesses called aggregators organize energy consumers willing to reduce consumption during times of peak electricity demand and bid this reduction offer into the wholesale electricity market.
Consumers set a price they would accept to reduce their consumption (notably, from the retail market) by a set amount.
This reduction en masse liberates generators to serve other load, yielding the same effect as producing additional electricity without engaging inefficient, expensive, or carbon-intensive resources.
To promote the adoption of such programs, FERC required wholesale market operators to incorporate demand response bids into their market auctions,
and subsequently required market operators to pay the same price to both generators producing electricity and demand response aggregators offering to reduce electrical consumption during the same period.
Notably, FERC allowed market operators to refuse demand response bids if the relevant state PUC had banned demand response.
EPSA, an industry group representing electric power producers, challenged FERC’s authority to regulate wholesale compensation for demand response bids, claiming that FERC’s regulation of a consumer-focused program “effectively” regulates retail prices and “lure[s]” retail customers into wholesale markets.
The Court disagreed and held that the FPA authorizes FERC to regulate wholesale demand response.
In so deciding, the majority made three determinations. First, it found that demand response falls within FERC’s authority under the FPA to regulate “rules and regulations affecting or pertaining to” wholesale rates.
Recognizing that authorizing FERC to regulate anything affecting wholesale rates would give the federal regulator near-infinite breadth,
EPSA adopted a test from the D.C. Circuit, “limiting FERC’s ‘affecting’ jurisdiction to rules or practices that ‘directly affect the [wholesale] rate.’”
It nonetheless found FERC’s demand response requirements to have such a direct effect.
Second, the Court held that the order did not violate the FPA’s bar on regulating retail energy sales—despite substantial effects on retail transactions—acknowledging that “the wholesale and retail markets in electricity . . . are not hermetically sealed from each other.”
“[W]hatever the effects at the retail level,” the Court observed, “every aspect of the regulatory plan happens exclusively on the wholesale market and governs exclusively that market’s rules.”
Pressing the point further, the Court adopted a test from the recent Natural Gas Act case Oneok, Inc. v. Learjet, Inc., which counsels examining the “target at which the state law aims in determining whether” a state law (properly) regulates retail rates or (improperly) regulates wholesale rates.
All of FERC’s justifications for regulating demand response focused on improving the wholesale market.
Pressing the point still further, the Court highlighted FERC’s “notable solicitude” to the states in allowing them to opt out of demand response programs entirely.
The majority explicitly endorsed the wholesale demand response orders as “a program of cooperative federalism, in which the States retain the last word.”
Finally, the Court reinforced its decision by referencing the FPA’s original purpose to “eliminate vacuums of authority over the electricity markets.”
Both the majority and EPSA recognized that state PUCs clearly could not regulate demand response bids in wholesale markets.
As a result, if FERC lacked authority over these bids, no regulator would have such authority, and wholesale demand response—a policy that Congress had explicitly encouraged—would simply be impossible.
EPSA does not read like a bright line opinion. In fact, the phrase “bright line” appears nowhere in its pages. Rather than the formalistic language of separate spheres, EPSA repeatedly refers to the inextricable linkages between wholesale and retail markets that are not “hermetically sealed.”
Instead of citing prohibitions on case-by-case analysis
and decrying “exceptions . . . for particular uses,”
EPSA examines the “target” of FERC’s regulation.
Perhaps most tellingly, the case explicitly endorses a program of cooperative federalism under the same New Deal–era FPA provisions once construed to impart exclusive federal jurisdiction.
Scholars have already begun to recognize the momentousness of EPSA’s departure from the Court’s prior jurisprudence.
Demand response seemingly straddles the once-bright line (customers reduce their consumption in the retail market and then bid that reduction into the wholesale market) and EPSA signals the Court’s preparedness to adapt its understanding of the FPA to further policies presenting similar questions.
Most critical discussions have read EPSA, along with Oneok, to signal the dissolution of the strict bright line approach.
2. Hughes v. Talen Energy Marketing. — In Hughes v. Talen Energy Marketing, LLC,
decided just a few months after EPSA, the Court resolved one element of the federal–state boundary under EPSA’s new functionalist framework.
Hughes concerns attempts by the state of Maryland to encourage new in-state generation in response to concerns that there was insufficient generation available to serve local customers during times of heavy congestion.
Believing that a long-term reliable contract would most effectively encourage the construction of generation, the PUC solicited proposals for a new power plant, accepted one plant’s rate proposal, and required LSEs to enter into twenty-year contracts with the facility at the rates specified.
The “contract for differences” was conditioned on the new facility’s successfully selling its capacity at wholesale auction, although it would essentially trade its revenue from that auction to LSEs for the contract price.
Competitors of the facility benefitting from Maryland’s program challenged the state’s scheme as intrusive on FERC’s exclusive jurisdiction over wholesale electricity markets.
The Court agreed, holding that Maryland’s incentive program effectively sets a wholesale rate determined outside of the market FERC designated as the appropriate mechanism to ensure “just and reasonable” rates, violating the Supremacy Clause.
Despite relying on preemption doctrine, the Court took great pains to narrow its holding in Hughes.
It based its preemption analysis on the fact that the generator did not transfer its capacity to another party in the process of contracting for a rate different than the one available on the wholesale market—with the result that it had no incentive to bid its capacity efficiently—in direct contravention of the market design approved by FERC.
The Court declined to hold that FERC’s authority preempts any state policies with the potential to affect wholesale rates.
Instead, the Court concluded by very deliberately limiting its holding, even seeming to encourage states to continue incentivizing generation according to their policy preferences:
Our holding is limited: We reject Maryland’s program only because it disregards an interstate wholesale rate required by FERC. We therefore . . . do not address 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 re-regulation of the energy sector. Nothing in this opinion should be read to foreclose Maryland and other States from encouraging production of new or clean generation through measures “untethered to a generator’s wholesale market participation.” So long as a State does not condition payment of funds on capacity clearing the auction, the State’s program would not suffer from the fatal defect that renders Maryland’s program unacceptable.
This new jurisprudence signals a vastly different role for the states in power regulation, seemingly replacing a “separate spheres” conception of federalism with a tolerance for—and even encouragement of—concurrent jurisdiction.
The Court in Hughes recognized that “[s]tates, of course, may regulate within the domain Congress assigned to them even when their laws incidentally affect areas within FERC’s domain.”
This statement is essentially the converse of the one in EPSA that countenances federal regulations with substantial repercussions in the sphere of regulation generally left to the states. Taken together, EPSA and Hughes suggest that both federal and state regulators have wide latitude to regulate in the gaps where the bright line has broken down. This interpretation is bolstered by the Court’s citation to Oneok, counseling an examination of the “target at which the state law aims.”
Although EPSA and Hughes signal a massive shift in how the Court handles the jurisdictional divide in the FPA, the state of the doctrine after these two cases is not entirely clear. Both cases hold for federal jurisdiction: EPSA upholds a federal program against the putative authority of the states, and Hughes invalidates a state program as preempted under the FPA. And yet, in acknowledging the grid’s interconnectedness and the resulting necessity of cooperative federalism, each also suggests an expanded zone of influence for the states. EPSA signals a departure from the bright line analysis that has consistently expanded the scope of federal preemption. Hughes supported federal preemption, but only narrowly and through the same functionalist lens developed in Oneok and carried through in EPSA. The cases still draw on the language of “wholesale”
—as the statute plainly dictates that they must—but the test has lost its ring of formalism. After all, even in invalidating a state policy, Hughes ends with a direct invitation to the states to continue innovating.
Part II will examine the extent to which this invitation rings true.
II. Reinforcing the Front Line, Not the Bright Line: The Effect of EPSA and Hughes on Aggressive Clean Energy Mandates in California and New York
In his dissent to the decision in New State Ice Co. v. Liebmann, Justice Brandeis famously remarked that “[i]t is one of the happy incidents of the federal system that a single courageous state may . . . serve as a laboratory; and try novel social and economic experiments without risk to the rest of the country.”
Scholars have explored this view of states as “laboratories of democracy,”
in many different spheres of law.
In few areas, however, has state leadership been more important than in renewable energy.
With no comprehensive renewable energy policy on the federal level, states have effectively led the charge in encouraging the construction and use of renewable resources.
In many cases, this state leadership in alternative energy policy was born of frustration with federal inaction.
At the turn of the twenty-first century, the George W. Bush Administration and its contemporary Congress elected not to pursue an aggressive climate policy, deprioritizing carbon dioxide reduction in the power sector and abandoning negotiations on the Kyoto Protocol.
In response, states like California, New York, and Massachusetts developed renewable energy policies—most notably renewable portfolio standards (RPSs)
—under both Democratic and Republican governors.
Environmentally conscious energy policymaking on the state level—and congressional stagnation on the federal level—continued into the Obama Administration. Currently, twenty-nine states, Washington, D.C., and three U.S. territories have enacted RPSs,
which are only one of several policy tools for carbon reduction.
Although most scholars support more robust federal action (like the adoption of a national RPS), many also see state leadership as a positive development in light of the immense difficulty of national intervention.
As the prospect of broad federal action on climate change and renewable power dwindles,
states will only become more critical to clean energy development in the United States.
This Part examines how the new energy federalism jurisprudence discussed in Part I will facilitate—or hamper—the policy tools necessary for states to remain an effective vanguard in renewable energy policy. To conduct this analysis, this Part looks to California and New York—arguably the states with the most aggressive renewable energy and greenhouse gas mitigation policies—as models.
Section II.A describes California’s and New York’s ambitious renewable energy and carbon reduction mandates. Section II.B isolates four policy tools—each essential or important to meeting these mandates—that straddle the traditional boundaries between federal and state jurisdiction, evaluating the effect of the new jurisprudence on their viability and potential effectiveness.
A. A Renewable Power Surge: California’s and New York’s Aggressive Renewable Energy and Carbon Reduction Mandates
California and New York have demonstrated exceptional leadership in promoting renewable energy. This section discusses their new, aggressive RPS and greenhouse gas reduction targets, and sketches the policy tools that will be necessary to advance those aims.
1. California’s Renewable Portfolio Standard. — California has consistently demonstrated extraordinary commitment to establishing a clean electricity sector. By 2014, it was the only state to have adopted all five of what Professor Steven Ferrey identifies as the primary legal mechanisms for renewable energy and low-carbon development.
Since late 2015, California has doubled down on its commitment, continuing to set what are arguably the country’s most aggressive legally binding clean energy requirements.
On October 7, 2015, Governor Jerry Brown signed Senate Bill 350, mandating that California procure fifty percent of its electricity from renewable sources by 2030.
On September 8, 2016, Governor Brown signed Senate Bill 32, similarly aggressive legislation that requires the state to reduce greenhouse gas emissions forty percent below 1990 levels by 2030.
Although this bill affects all sectors that emit greenhouse gases, its mandates will fall heavily on electric utilities, which accounted for twenty percent of California’s total greenhouse gas emissions in 2014.
When California first introduced its updated “50 by 30” RPS, it identified several potential tools to reach its target.
These included special requirements that utilities procure electricity from clean and efficient sources, similar requirements to encourage demand response, increased coordination with surrounding U.S. states and the Mexican state of Baja California, and a clean energy standard limiting the greenhouse gas emissions associated with any electrical energy sold in California.
Since California receives power from the interstate grid, the latter tool would apply to electricity sold in California from both in- and out-of-state sources.
The RPS statute also highlighted the importance of distributed generation (the integration of customer-sited generation into the distribution grid), requiring the PUC to consider its use
and using its deployment as an indication of whether a utility failing to comply with the RPS has made sufficient attempts to do so.
These broad sketches are not exhaustive; further policy choices will likely emerge once the PUC has completed a series of studies mandated under SB 350.
It is already possible, however, to predict at least some conclusions of those studies. A paper by Jeffery Greenblatt of Lawrence Berkeley National Laboratory indicates that meeting California’s ambitious goals will be achievable, if at all,
only if the state phases out imported power from coal plants, makes extensive use of distributed generation, increases energy storage capacity, and electrifies significant parts of the transportation and building sectors.
2. New York’s Clean Energy Standard. — In August 2016, New York joined California in setting an enforceable mandate to obtain fifty percent of electricity from renewables by 2030.
The so-called Clean Energy Standard (CES) is New York’s first binding mandate, but it enters into force on the heels of other sweeping climate and energy goals within the state.
New York has folded the CES into an ongoing energy policy strategy overhaul called Reforming the Energy Vision (REV), which aims to rethink and reorganize utility models to better incorporate renewable generation into the wholesale and retail grids.
REV is structured primarily around the increased use of distributed generation.
Like California, New York has established carbon emissions reduction goals in addition to its RPS, including a forty percent reduction from 1990 levels by 2030 and an 80 percent reduction by 2050.
New York’s “50 by 30” order acknowledges that achieving its ambitious goal will require more than simply mandating that load-serving entities acquire a certain percentage of their power from renewable sources.
The order emphasizes that to actually meet the mandate, utilities and other power providers must procure significant new renewable resources, including “a mixture of technologies and combinations that are not fully developed at this time.”
The order further recognizes that accomplishing the renewable generation and carbon-mitigation objectives while maintaining grid reliability will require the increased use of demand response and storage.
In light of these determinations, the order mandates a triennial review process to determine, among other things, the effectiveness of compliance mechanisms and fuel diversity.
B. Federalism Challenges on the Horizon: EPSA, Hughes, and State Policy Tools
New York’s and California’s objectives are unprecedented in their aggressiveness, and each state is still finalizing its roadmap to achieve them. Both still have significant planning ahead of them, with established procedures for adjustment along the way.
This section examines four policies
central to New York’s and California’s nascent renewable energy goals that, like demand response in EPSA,
blur the traditional bright line between wholesale transmission and retail distribution. It discusses preemption challenges that have plagued these policies in the past and evaluates the degree to which the Court’s most recent jurisprudence has resolved those questions—or created new ones.
1. Distributed Generation and Net Metering. — New York and California have both expressed a clear interest in meeting their renewable energy goals through distributed generation.
Both states support distributed generation through a policy called net metering, currently the dominant method of compensating distributed resources.
Under a net metering scheme, customers with onsite generation or storage can both draw electricity from and feed excess electricity to the distribution grid. At the end of the billing period, the utility charges the customer only for its net use of electricity.
This method of compensation is a form of subsidy, since the customer effectively receives the retail rate—usually two to six times higher than the wholesale rate an independent generator on the transmission system would receive—for electricity “sold” to the grid.
Although both California and New York have considered revising their net metering policies, both states will continue to implement the scheme described above for the time being.
Like demand response, distributed generation and net metering straddle the traditional bright line between federal and state jurisdiction.
The same customers who purchase electricity from the distribution grid at retail appear to sell electricity back to the same grid at wholesale, breaking down the customary notion of the distribution market as an enclave of retail transactions and, by extension, state control. With the “bright line” gone, opponents of distributed generation—probably utilities or generators losing business to residential solar—could argue that states should be preempted under the FPA from setting the (technically wholesale) rate, whether states choose to pay distributed generators the retail rate or some other compensation. Under this logic, states could set the relevant wholesale rate only if distributed generators qualified as QFs under PURPA.
Even then, this rate would be limited to the relevant utility’s avoided cost for energy, which is significantly less than the retail rate.
Nevertheless, FERC has consistently disclaimed jurisdiction over net metering compensation schemes.
In a pair of administrative adjudications, FERC determined that transferring customer-sited power to the retail grid under a net metering scheme does not constitute a “sale” subject to federal jurisdiction as long as energy consumed exceeds energy fed into the grid within a single billing period.
Under this conception, the customer’s contributions to the distribution system merely offset consumption and net to a single unidirectional retail sale.
Before EPSA, however, the days of FERC’s repudiating authority over these net sales appeared numbered. A pair of D.C. Circuit cases in 2010 and 2012 held that FERC could not define the converse of net metering—allowing generation facilities that export energy at wholesale to subtract their retail consumption of grid energy from their wholesale energy production as long as they export more than they consume during a “netting” period determined by FERC—as a single net transaction instead of a series of individual sales on two different markets.
It is highly plausible that a court would find the same with respect to net metering, were the question presented.
The primary question, therefore, is whether EPSA and Hughes reinforce state authority over net metering rates.
In all likelihood, the precedent set by EPSA will reinforce this state authority, or at least save FERC’s jurisdictional disclaimer. EPSA’s adoption of the “target” test from Oneok suggests that “the how and the why” of state regulation plays a significant role in its permissibility when the regulated activity does not fall cleanly within federal or state jurisdiction.
Net metering policies operate on the distribution grid to advance a particular type and location of generation and to influence retail customers—by all accounts the traditional domain of the states.
Of course, the target test was not enough to save Maryland’s policy in Hughes—also aimed at the type and location of generation—which the Court found to directly defy a wholesale market rate.
Crucially, however, the Maryland PUC offered a rate contrary to the one set by a wholesale market that FERC recognized explicitly and regulated heavily.
FERC makes no comparable effort to recognize or regulate a wholesale market for generation on the distribution system. As a result, there are no federal rates for state PUCs to defy.
Further, if states lacked jurisdiction to regulate net metering, FERC’s disavowal of—and apparent lack of interest in asserting—such authority could create a regulatory gap, a specter totally absent from Hughes.
EPSA reinforced that the FPA abhors a vacuum.
In EPSA, preserving a useful policy required FERC to regulate arguably retail activity. To preserve a similar policy here, states must maintain authority over the arguably wholesale component of net metering.
Even if a court were to find unmistakable federal jurisdiction over net metering, EPSA would probably preserve the ability of PUCs to set rates in line with state policies as long as they have FERC’s (implicit or explicit)
blessing to do so.
By endorsing cooperative federalism in demand response, EPSA strongly suggests that FERC’s deference to state policy choices—at least in the interstices between the traditional spheres of federal and state jurisdiction—is appropriate even where FERC could arguably preempt those choices.
2. Feed-in Tariffs. — Feed-in tariffs (FITs) are policy instruments that require utilities to purchase renewable energy over an extended period of time at a guaranteed (usually above-market) rate, often the sum of the market rate for electricity and a uniform or technology-specific premium.
Feed-in tariffs, popular in Europe,
are often considered alternatives (rather than complements) to RPS and CES policies.
Nonetheless, there is significant evidence that FITs are more effective incentives for renewable power than RPSs alone.
To the extent that the two policies can work compatibly,
their combination will be important—if not central—to renewable energy procurement goals as aggressive as California’s and New York’s.
In 2012, California adopted a FIT called the ReMAT geared toward small distributed generation,
and the New York Public Service Commission has considered a (FIT-like) bundled energy and REC plan, although it has not called it a FIT.
The Commission acknowledged in its “50 by 30” order that investor concerns have the potential to limit the state’s renewable energy goals, even with a mandatory RPS in place.
If New York’s new clean energy procurement does not meet its intended schedule, it could implement a FIT or FIT-like program, pursuant to its triennial review process, to alleviate the investor anxiety it has already identified.
Like net metering, FITs do not fit comfortably on one side of the bright line. They deal primarily with procuring generation—a responsibility traditionally left to the states
—but they do so by compensating generators for their wholesale contributions to the grid. Also like net metering, state FIT programs have faced administrative challenge in the past and emerged with only a partial solution from FERC. Before its adoption of the ReMAT, California operated a differently structured FIT requiring utilities to purchase electricity from combined heat and power generators—without regard to QF status under PURPA
—at a price determined by the California PUC.
In implementing the FIT, the PUC sought a declaratory order from FERC that the FPA and PURPA did not preempt the tariff structure, arguing in part that the environmental concerns motivating the regulation should override arguments in favor of preemption.
FERC’s response was mixed. It held firmly against California’s assertion that the PUC could define an offer price for non-QF generators on environmental or other grounds, finding that California’s FIT impermissibly set a wholesale rate and was therefore preempted by the FPA.
FERC did allow, however, that insofar as the desired generation qualifies as a QF under PURPA, California maintains broad authority to determine the avoided cost at which it must be compensated.
In a clarifying order, FERC held that California may, consistent with PURPA, adopt a “multi-tiered avoided cost rate structure” that sets the required rate not at the lowest possible avoided cost but at the avoided cost of sourcing electricity from similar (in this case, renewable) sources, as long as state rules require utilities to procure electricity from “generators with certain characteristics.”
This facilitates the central aim of a FIT—providing otherwise less-competitive renewables with a competitive rate. ReMAT is the result of California’s attempt to comply with FERC’s rulings.
Recent scholarship has argued that FERC’s position is a boon for states attempting to create FITs and RPSs in tandem.
It is, however, a limited boon. States must constrain their policies to QFs under PURPA and may set avoided cost rates tailored to renewable energy only under specific state policies. For California and New York, these limitations probably do not present significant challenges; both states intend to encourage the kind of small generation that can qualify for PURPA and already have expansive RPSs.
Further, EPSA likely supports FERC’s broad grant of rate-setting authority to the states with respect to QFs. Although the actual grant of state authority over QF compensation comes from PURPA (which the Court has long acknowledged embodies cooperative federalism)
and not the core of the FPA, the Court’s strong endorsement of cooperative federalism in the latter reinforces its application to the former.
Likewise, Hughes does not counsel for preemption. Unlike the large power plant in Hughes, QFs under PURPA need not clear a capacity auction to run;
they therefore have no incentive or ability to distort a carefully regulated competitive market as the Hughes court feared.
3. FIT-Like Incentives for New Generation to Join Wholesale Markets. — With the assistance of favorable administrative interpretations of PURPA, states have significant authority to incentivize renewable QF generators through FITs valued at the avoided cost for renewable generation. In the wake of EPSA and Hughes, however, the question remains how states can encourage non-QF generation to enter the wholesale capacity and energy markets in which the majority of electricity is traded.
California and New York both have ISO-operated energy and capacity markets,
and both states have stressed the need for significant new renewable generation capacity to meet their “50 by 30” goals.
Although Hughes bars states from requiring utilities to guarantee generators a wholesale energy rate other than the one FERC deems “just and reasonable,” its limited holding did not necessarily preempt “other measures States might employ to encourage . . . new or clean generation.”
In fact, in addition to the means explicitly listed in the opinion (such as tax incentives, direct subsidies, and land grants), Hughes may have hinted at a very strong method by which states like New York and California could entice utility-scale renewables into their capacity and energy markets: mandated bilateral contracting.
In Hughes, Maryland argued that its incentive policy should not be preempted because its contract for differences was indistinguishable from a (permissible) bilateral contract for capacity, in which an LSE contractually engages a generator’s capacity and bids it into the auction as its own.
Resolving the point against Maryland, the Court identified only one material difference between the circumstances in Hughes and a bilateral transaction: that the contract for differences allowed the generator to bid its own capacity rather than transferring capacity ownership to LSEs, removing the generator’s incentive to send useful price signals.
What the Court did not identify as a material difference is that a traditional bilateral transaction is the product of arm’s length negotiation, whereas Maryland’s contract was forced on the utilities.
This suggests that a bilateral contract for a long-term (and possibly above-market)
wholesale transaction—even one the state requires utilities to enter—may be a legally feasible means of procuring “new or clean” generation. Even if the LSE-as-buyer sustains a loss (by paying an above-market rate in a bilateral capacity transaction but receiving the market rate when bidding that capacity into the auction), it is undoubtedly the state PUC with the authority to allow the LSE to recover those losses in the retail market.
Granted, such a bilateral transaction would occur at wholesale and would therefore require FERC’s certification as a just and reasonable rate,
but if FERC deemed a mandated purchase in line with state authority to be the basis of a just and reasonable rate—particularly given states’ “traditional authority over . . . in-state generation”
—then it could theoretically allow such bilateral transactions to occur. Rather than being entirely preempted as it might have been before EPSA and Hughes, such a strategy may now rely—as must net metering and feed-in tariffs—on cooperative federalism. The legitimacy of state-mandated bilateral contracting therefore makes sense not only as a literal interpretation of Hughes but also as a practical way of upholding FERC’s regulatory authority. Maryland’s scheme bypassed FERC’s rate-regulation scheme by guaranteeing a rate that FERC had no chance to review (either directly or through a market mechanism). Conversely, mandated bilateral contracting would not bypass FERC review, as contracts could go forward only with FERC’s approval.
If the above-described scheme is indeed workable, it could be operationalized like a feed-in tariff layered over an RPS.
States could mandate that LSEs enter bilateral contracts with renewable generators at the market rate for capacity plus a premium based on the market rate for RECs.
FERC has already suggested that such a rate is appropriate for setting avoided cost under PURPA;
there is no reason to believe that, given the choice, it would not approve such a rate as just and reasonable.
Admittedly, this sort of mandate—which not only requires utilities to contract for renewable energy but also sets a price—stretches the new doctrine to its limits, but weaker forms are also possible. Instead of setting a particular rate, states could merely require utilities to contract with certain renewable energy providers at a bargained-for rate, or—in its weakest form—require utilities to negotiate with renewable energy providers without a requirement to buy. Connecticut has tried both of these weaker-form strategies, and the resulting judicial and administrative precedents (both pre- and post-EPSA) signal hope for both types of policy.
In 2013, Connecticut’s legislature authorized the state Department of Energy and Environmental Protection to solicit proposals for renewable energy projects and to direct utilities in the state to enter bilateral contracts with selected projects.
The Department did so, and a power producer that did not submit a winning proposal sued in federal court.
Writing before the decision in EPSA, the district court held that Connecticut’s actions did not impermissibly set an interstate rate; instead it permissibly regulated retail utilities within the State’s jurisdiction.
When the Second Circuit determined that the issue was not ripe for judicial determination because FERC had not considered it, the challenger brought the issue before the Commission.
FERC did not rule on the merits of the challenger’s claims, but it did issue a Notice of Intent Not to Act, declining to invalidate the mandate.
After EPSA, such findings of nonpreemption are even more defensible, especially since FERC did not appear keen to pursue preemption even before the rigid scheme of dual federalism fell.
Connecticut authorized a similar mandate in 2015, but this time included new language absolving utilities of any responsibility to accept renewable generators’ bids.
As a whole, the policy merely required that the utilities consider and negotiate with certain renewable power producers. In June 2017, the Second Circuit, citing heavily to EPSA and Hughes, upheld that policy’s validity under the FPA.
The panel found that this weakest form of mandated bilateral contracting neither set a wholesale rate nor—since either party could terminate the contract at will—compelled utilities to enter wholesale transactions (it purposefully did not rule on whether such compulsion would render the scheme impermissible).
The panel also identified numerous differences between Connecticut’s statute and the scheme invalidated in Hughes, finding the former to be “precisely what the Hughes court placed outside its limited holding.”
In sum, there is a statutory basis for a spectrum of mandatory bilateral contracting policies, and fairly compelling judicial and administrative support for at least part of that spectrum. But, as the Allco court noted, any bilateral contract at wholesale remains “subject to FERC review for justness and reasonableness,”
and any scheme reliant on such contracts therefore remains reliant on FERC.
4. Restrictions on Out-of-State Power. — California’s and New York’s RPSs and emissions laws, in accordance with the norm for RPS standards generally, are goals not for in-state capacity but rather for in-state consumption.
But California and New York both import power from utilities in neighboring states.
In crafting their respective cap-and-trade policies more than ten years ago, both states realized that their ambitious policies could be offset by “leakage,” in which less costly, non–carbon-controlled power makes its way into the state from neighboring jurisdictions.
As a result, states like California and New York need ways to limit the carbon content of their imported power to meet their goals.
Constitutionally, that is easier said than done. Policies restricting the flow of energy from outside states have recently faced preemption challenges, even in the wake of EPSA and Hughes. In the recent case North Dakota v. Heydinger, the Eighth Circuit Court of Appeals invalidated a Minnesota statute limiting the importation of power from coal-fired power plants in neighboring states.
In addition to proscribing the construction of new large carbon-emitting energy facilities, the statute in question barred actors within the state from “import[ing] or commit[ing] to import from outside the state power from a new large energy facility that would contribute to statewide power sector carbon dioxide emissions,” and from “enter[ing] into a new long-term power purchase agreement that would increase statewide power sector carbon dioxide emissions.”
The statute defined “power sector carbon dioxide emissions” to include emissions from the generation of all power consumed in Minnesota, even if generated elsewhere.
The panel unanimously struck down the law but could not agree on a single basis, suggesting that restrictions on out-of-state power may face challenges on multiple fronts. Writing for the panel but taking a minority position, Judge Loken found the statute preempted by the Commerce Clause.
Noting that electricity flows freely throughout the interstate grid, and certainly in the subsection balanced by the Midwest ISO (MISO), Judge Loken found it impossible for Minnesota to successfully prevent the importation of electricity from out-of-state carbon-intensive generators unless those generators were excluded from the grid anywhere within MISO.
He therefore found the law to control transactions wholly outside of Minnesota, an impermissible imposition on the Commerce Clause.
Judges Murphy and Colloton, by contrast, found the statute preempted by the FPA.
They found that in barring bilateral transactions with out-of-state power plants, the statute directly regulated wholesale transactions in interstate commerce, which remain squarely within federal jurisdiction under Hughes.
The decision could apply to greenhouse gas laws (limiting importation of carbon-heavy generation) and RPSs (limiting importation of non-renewables), although it is unlikely to be the final say. Judge Loken’s Commerce Clause holding was convincingly rebutted by Judge Murphy’s concurrence,
and commentators have contrasted
his decision with the one in Energy & Environment Legal Institute v. Epel, in which a Tenth Circuit panel (that included now-Justice Gorsuch) upheld a Colorado twenty percent RPS—and therefore the exclusion of some carbon-intensive energy from Colorado’s energy market—against Commerce Clause challenges.
Heydinger’s FPA preemption holding, too, is unconvincing. Citing to Hughes, Judge Colloton contended that “[b]ecause a State may not regulate wholesale rates, it follows that a State may not impose a complete ban on wholesale sales, effectively forbidding the parties to arrive at any mutually agreeable price.”
This holding, however, ignores important aspects of both Hughes and EPSA. Hughes’s holding was limited to the proposition that state PUCs could not set a wholesale rate different from FERC’s market rate—it said nothing about blocking a class of sales entirely.
The difference is one of kind, not of degree; courts should be wary of extending a holding as purposely narrow as Hughes’s so far. Even more importantly, EPSA explicitly endorsed the right of states to ban demand response within their jurisdictions even after finding that FERC—not state PUCs—has authority over wholesale demand response rates.
Nevertheless, Heydinger demonstrates that courts—on multiple bases—may find regulations affecting power produced out of state preempted. As a solution, Professor James Coleman has proposed that FERC review any “exported”
state regulation to determine whether it should be preempted.
Professor Coleman suggests that Congress instruct FERC to make this review.
But consistent with EPSA and Hughes, FERC can probably develop such a program even in the absence of Congressional intervention. These recent cases not only endorse a program of cooperative federalism but also take a functionalist approach to the jurisdictional divide, weighing the factors counseling in each direction rather than simply asking on which side of a bright line a particular action falls.
As a result, a program that evaluates whether an “exported” regulation truly does prejudice out-of-state actors is directly in line with the new jurisprudence.
Taken in aggregate, all four policies, which straddle the traditional bright line, benefit from the new and more flexible jurisprudence set down in EPSA and Hughes. Those cases preserve or extend the ability of states like California and New York to employ net metering, FITs, mandatory bilateral contracts, and restrictions on out-of-state power in at least some capacity. States’ enhanced abilities to enact these policies, however, appear closely tied to cooperative federalism and, by extension, FERC’s interpretations of the FPA and PURPA. Part III examines the relationship between FERC and the states and its effect on how much states will actually benefit from the Supreme Court’s new constructions.
III. FERC and the States: Operationalizing Cooperative Federalism in Energy Policy
Part II evaluated current and anticipated elements of California’s and New York’s ambitious state renewable energy goals, determining that the most aggressive policies will likely require significant collaboration with FERC to move forward and that EPSA and Hughes lay the groundwork for that cooperation. This Part explores that cooperation in more detail, dissecting its statutory underpinnings and evaluating its success under different policy scenarios. Section III.A discusses how the text of the FPA lends itself to this cooperative federalism and advocates for the broadest possible reading available to FERC under the most recent jurisprudence. Section III.B explores the approaches states like California and New York should—and will be able to—take under sympathetic and unsympathetic federal regulation. Section III.C contextualizes the overall effect of the new jurisprudence on state policies.
A. The Words Remain the Same: Cooperative Federalism and the Language of the FPA
The above discussions of cooperative-federalism approaches to net metering, feed-in tariffs, mandated bilateral contracting, and exported regulation each rely on a conception of FERC not as the exclusive arbiter of wholesale rates, but rather as the final such arbiter. In each case, FERC has allowed—or could theoretically allow—the states a degree of freedom in setting or affecting a rate that is arguably within FERC’s jurisdiction over wholesale rates. EPSA clearly condoned such an approach, in part by reasoning from the FPA’s policy motives.
The question FERC will have to answer going forward is whether the language of the FPA can support cooperative federalism and solicitude for state policies as plainly as its legislative history does (and, if so, how extensively). As surprising as it is given its judicial history, the FPA does seem to support a construction of collaboration among federal and state regulators, even on its face. After all, the same Senate report the Court recognized in Connecticut Light & Power as saying the FPA extended only to “those matters which cannot be regulated by the States” also expressed a purpose “to assist the States in the exercise of their regulatory powers,” suggesting that Congress meant for the boundaries separating state and federal jurisdiction to be porous.
Likewise, by the terms of the statute, FERC’s jurisdiction does not exclude states from acting within FERC’s domain if the Commerce Clause otherwise permits it. To the contrary, the only hard limits on jurisdiction in the FPA are those that limit FERC:
The provisions of this subchapter shall apply to the transmission of electric energy in interstate commerce and to the sale of electric energy at wholesale in interstate commerce, but . . . shall not apply to any other sale of electric energy . . . . The Commission shall have jurisdiction over all facilities for such transmission or sale of electric energy, but shall not have jurisdiction . . . over facilities used for the generation of electric energy or over facilities used in local distribution or only for the transmission of electric energy in intrastate commerce, or over facilities for the transmission of electric energy consumed wholly by the transmitter.
The word exclusive never appears; nor is it plainly implied. Furthermore, in requiring FERC to ensure just and reasonable wholesale rates, the FPA does not prohibit state or other regulators from proposing or otherwise influencing rates before FERC ensures their reasonableness:
All rates and charges made, demanded, or received by any public utility for or in connection with the transmission or sale of electric energy subject to the jurisdiction of the Commission, and all rules and regulations affecting or pertaining to such rates or charges shall be just and reasonable, and any such rate or charge that is not just and reasonable is hereby declared to be unlawful.
To the contrary, the statute requires that FERC monitor all rules and regulations affecting or pertaining to jurisdictional rates. For over eighty years, the Court apparently read this language to field preempt state authority over those rates and ensure a clean slate on which FERC may inscribe its orders.
But it lends itself just as (if not more) readily to the conclusion that states and FERC have some common jurisdiction and, where states have already regulated within that concurrent jurisdiction, FERC may choose to accept those regulations as just and reasonable.
As indicated above,
Hughes can be read to support this extremely broad conception of PUC-as-regulator and FERC-as-reviewer.
In Hughes, the FPA preempted Maryland’s policy not merely because FERC oversaw a wholesale market to set the “just and reasonable” rate, but rather because FERC had taken great pains—in the form of market regulatory policies—to calibrate the market to its policy goals.
The Court interpreted this extensive policing as FERC’s imposing an exclusive regime that would be frustrated by state interference.
Hughes is not incompatible, however, with the conclusion that FERC could explicitly allow states to set a price different from the market price.
If read narrowly—and the language of Hughes very clearly invites a narrow reading
—Hughes stands only for the proposition that in the absence of a clear statement from FERC, careful regulation of a market mechanism will be interpreted to impart exclusivity. If FERC were to indicate that its regulated market is not the exclusive mechanism for ensuring a just and reasonable wholesale rate, nothing in Hughes prevents states from participating in alternative mechanisms.
Other parts of the statute also point to a role for state agents in otherwise FERC-jurisdictional activity. Notably, a little-used FPA provision provides for state PUC commissioners to hear interstate cases alongside or even instead of FERC commissioners.
Although the provision does not grant the states any independent rate-setting or policy authority, it does provide further evidence within the confines of the FPA’s language that the statute endorses cooperative federalism.
FERC should embrace the opportunity EPSA and Hughes provide to broadly interpret the FPA and allow states to set rates and enact policies to support state-level clean energy policies wherever those actions do not directly conflict with FERC’s aims. FERC has endorsed cooperative federalism schemes in the past only cautiously (for example, endorsing net metering not as a collaborative venture but as a mechanism beyond its jurisdiction).
EPSA and Hughes empower FERC to approve state policies through open recognition of concurrent jurisdiction. The following section proposes a means for FERC and the states to maximize this new leeway.
B. Approaching Federalism Challenges Under Opposite Policy Scenarios
Given the short timetable with which California and New York plan to achieve their renewable mandates, they cannot afford to wait for clarifying jurisprudence or congressional action. Against background assumptions of stagnant congressional policy and no further jurisprudence from the Court, this section considers potential routes for the states to work with FERC under a friendly and unfriendly Commission.
1. Committed States and a Friendly FERC. — As discussed in sections II.B and III.A, the new jurisprudence presents new opportunities for cooperative federalism under the FPA, granting the states a first crack at regulation
—provided that they are not preempted by the Commerce Clause
—if it would not interfere with FERC’s preferred regulatory scheme.
The success of each of the policies described in section II.B seems to rely heavily on FERC’s intervention on behalf of state PUCs. In all four policy areas, past state efforts have been challenged and had either no solution or a solution dependent on FERC action and approval.
Since their positions are fairly precarious,
state PUCs ought to coordinate with FERC immediately in order to begin the process of obtaining favorable orders and to insulate themselves from legal challenges.
To start, states should ask FERC to release updated guidance on its already permissive policies on net metering and FITs. Given the broad interpretation to which the language of the FPA—bolstered by EPSA and Hughes—lends itself,
FERC may reinterpret its organic statute to allow states more freedom in compensating net metering participants and incentivizing non-QF participation in wholesale markets. As noted above, FERC currently facilitates state net metering with a tenuous disclaimer of jurisdiction.
Under EPSA and Hughes, it can amend its position to continue disclaiming jurisdiction but to maintain that, in the alternative, it may delegate its putative net metering authority to states under the FPA. At a minimum, FERC should facilitate the state policies described in section II.B using the methods discussed therein.
Furthermore, California and New York in particular should seek FERC approval to take a greater role in setting ISO market rules. California’s transmission system is balanced by the California ISO and New York’s by the New York ISO—the only two ISOs in FERC jurisdiction that cover only one state.
As a result, the two states’ PUCs could request FERC’s permission to operate FITs or other renewable energy procurement tools directly through the wholesale markets.
The market does not encompass any additional states with policy objections, and the state PUC is apparently willing to pass higher wholesale costs on to its customers at retail. FERC has, in multiple contexts, expressed willingness to consider state policy goals in planning wholesale markets.
If it is willing to order utilities engaging in resource planning to consider state policy goals, it stands to reason that it would indulge those goals itself when there are no interstate conflicts within the regulated region.
States in multi-state ISO regions may not be able to integrate their policies as firmly into wholesale markets as California and New York, but they may still be able to enjoy a lesser degree of increased participation under the same scheme of FERC solicitude. Professor Jim Rossi and Thomas Hutton have proposed a model of “clean energy floors” under the FPA.
Under such a program, state standards may be more aggressive (but not more lax) than federal standards.
The states in an ISO region could adopt such a scheme, establishing a baseline policy to which all agree (such as a low FIT that all customers in the region are willing to bear) and incorporating it into wholesale markets. More ambitious states could develop their own policies outside of the ISO’s or RTO’s capacity and energy markets, presumably through bilateral contracts incorporating FIT-like payments or out-of-state energy restrictions subject to FERC’s assent.
2. An Unsympathetic FERC. — Under a broad interpretation of the FPA
and a friendly federal regulator,
EPSA’s and Hughes’s principles of cooperative federalism and concurrent jurisdiction can go a long way in supporting state renewable energy and carbon emissions goals. But there is no guarantee of a friendly federal regulator. Since August 2017, a majority of FERC commissioners have been Trump appointees.
Although President Trump has not been actively hostile to state renewable energy goals, his appointments to other high-ranking government positions have included climate skeptics and fossil-fuel supporters.
It is highly unlikely that he or Congress would prioritize renewable policy in making further appointments to FERC.
Under this scenario, policies that rest on FERC’s solicitude to the states may fall into jeopardy if FERC changes its lenient interpretations or otherwise fails to promote cooperative federalism in future orders. The PURPA tiered-rate structure that bolsters FITs and the treatment of net metering as a non-wholesale transaction already rely on FERC, and other policies like capacity-market-based procurement and regulations on out-of-state electricity may have serious difficulty getting off the ground without FERC’s attention.
Importantly, reducing—or refusing to extend—solicitude to the states would not necessarily run counter to FERC’s established mandate. Above all, FERC promotes reliability.
FERC has indicated that fulfilling its mission involves three key goals, among them the promotion of “safe, reliable, secure, and efficient infrastructure.”
If a new set of FERC commissioners perceives that renewable generation challenges the reliability of the grid, FERC could revoke its interpretations benefitting the states on the grounds that they promote variable resources the grid cannot reliably absorb.
This would not be a new or extreme position. When Tony Clark, a former Republican FERC commissioner, stepped down from his position in January 2016, he warned that the Clean Power Plan
—which would have reduced carbon emissions thirty-two percent by 2030 (a significantly less stringent goal than New York’s or California’s)—would strain grid reliability.
It is likely that Trump’s appointees will make the same determination, if not a more extreme one. If this prediction proves accurate, the Commission could halt all federal support for the nation’s most aggressive clean energy plans for fear of the reliability impacts on major economies like California and New York, and the already-congested energy corridors they occupy.
A FERC majority with little regard for climate change mitigation goals and a conservative approach to preserving grid reliability is unlikely to actively support any of the policies described in section II.B. An unfriendly regulator therefore poses a clear challenge to states with aggressive renewables mandates that rely heavily on distributed generation and the procurement of new renewable technology. Major support programs for these goals, like net metering and FITs, depend on FERC’s solicitude.
Without it, meeting state goals on time is likely to be all but impossible.
Short of forming interstate compacts
or isolating their transmission lines from the national grid—almost certainly more difficult, time-consuming, and expensive than waiting for political change—states would have little choice but to attempt to meet their renewable generation and carbon reduction goals without relying heavily on the policies described in section II.B.
That said, states would not be entirely without options. Without FERC’s support, states may still adopt relatively diluted forms of at least two of the policies described above. In particular, states could adopt the weakest version of mandated bilateral contracting: requiring utilities merely to negotiate with renewable generation. The principles present in Hughes, and the Second Circuit’s recognition of those principles, indicate that policy’s potential to survive federalism challenges. Furthermore, prevailing doctrine suggests that FERC will probably have to approve any rates that result, even if politically indisposed to renewable energy.
States outside of the Eighth Circuit may also continue to restrict the importation of carbon-intensive electricity in hopes that other Circuits will interpret the Court’s new jurisprudence differently.
Even within the Eighth Circuit, states could try to craft their policies around Heydinger’s holding by, for example, giving greater retail rate incentives to utilities that trade in only clean energy.
States may also choose to focus on policies other than those described in II.B. The Court’s decision to apply Oneok’s target test to energy federalism questions suggests that states could pass regulations that decarbonize the electricity sector only indirectly,
like extremely stringent generation emissions mandates, without invading FERC’s turf. Finally, states could employ the policies explicitly left open by Hughes, focusing on subsidies and tax incentives rather than market-based policies like those described in section III.B.
These mitigating solutions, however, are second-best. Only FERC’s support can unlock the full potential of the new latitude the Court has afforded the states.
C. Policies in Context: Where Cooperative Federalism Leaves California and New York
In light of the analyses in section II.B and the counterfactual scenarios in section III.B, the Supreme Court’s new readings of the FPA seem to vindicate FERC’s extant cooperative federalism orders and invite further solicitude to state policies when such latitude will not threaten FERC’s duty to set just and reasonable rates. They do not, however, appear to extend significant new rights to the states to act over FERC’s objections. Scholars and subject matter experts such as Professor Rossi and Jon Wellinghoff (a former FERC chairman) have celebrated this opportunity for state regulation “adjacent” to FERC’s policy priorities.
By their lights, the cooperative model endorsed by EPSA “invites policy experimentation, without fixing a sphere of authority for state regulators that lays [sic] beyond the FPA’s reach.”
They see the federal backstop as an advantage, a way of protecting “competitive, efficient, and reliable interstate power markets.”
States like California and New York, however, will likely see the caveat of federal oversight as a detriment, at least as long as climate skeptics dominate the White House and Congress.
The short-term legacy of EPSA and Hughes for states engaged in intensive renewable energy and carbon mitigation goals is therefore one of cautious optimism, presenting opportunities to incentivize renewable energy with a plethora of policy tools but also the serious prospect of disappointment in the eventuality of an uncooperative federal regulator.
EPSA and Hughes represent a massive shift in the Supreme Court’s construction of state and federal jurisdiction under the FPA, favoring functionalism and cooperative federalism where the Court once imposed formalism and dual sovereignty. In opening the door to cooperative federalism, this new jurisprudence invigorates the renewable resource procurement and carbon mitigation policies of states like California and New York, which will rely on tools facilitated by cooperative federalism to meet their ambitious goals. Four tools in particular—net metering, feed-in tariffs, mandatory bilateral contracting, and limitations on out-of-state power—now have significant legal ground to stand on. But the door is merely ajar—without FERC’s support, many of the tools the Court has made accessible to the states will remain just out of reach.