In 2016, the Illinois Legislature and New York Public Service Commission (PSC) enacted nearly identical policies to induce economically struggling nuclear power plants to continue operating. Competing power generation companies filed suits in federal district courts, arguing that the states’ policies are preempted by the Federal Power Act (FPA) and violate the dormant Commerce Clause. Both courts dismissed all claims, and the generators have appealed those decisions to the Seventh and Second Circuit Courts of Appeal, respectively. Decisions are expected in the first half of 2018.
The disputes over the states’ Zero Emission Credits (ZECs) for nuclear plants are just the latest controversies about the roles of states and the federal government in overseeing the electricity industry. Recent federalism cases highlight the incongruity of applying the New-Deal-era FPA to today’s dynamic and evolving industry. Fossil-fuels proponents have also seized on the increasing overlap between state regulation of the generation resource mix and interstate power markets to argue that state clean energy policies overstep the limits of state authority that the dormant Commerce Clause establishes.
The ZEC cases are particularly significant for delineating the boundaries of authority between state and federal regulators. States designed the policies to adhere to the limits of state authority outlined in a trio of Supreme Court energy federalism cases decided in 2015–2016. This bounty of new case law has delighted energy law scholars and inspired voluminous interpretations, but only three federal courts have applied their holdings to electricity regulation cases. Decisions by the Second and Seventh Circuits on ZECs could set precedent that defines the industry’s governance for decades.
These decisions may also be consequential for the future of state climate action. A broad ruling against the states could invite litigation about state renewable portfolio standards and emission allowance programs, such as the Regional Greenhouse Gas Initiative cap-and-trade program that covers power generators in nine Northeastern states. If these well-established, market-based programs are found to be incompatible with federal regulation, states might retreat to “command-and-control”-type policies that entirely ignore the interstate nature of the electric grid and today’s power markets. This result would likely leave consumers, and the environment, worse off. On the flip side, decisions upholding the ZEC policies would implicitly affirm the legality of an array of long-standing state clean energy policies that have never been challenged on preemption grounds. It would also bolster the legal defensibility of more recent policies, such as Maryland’s offshore wind credit program, and could encourage states to enact new clean energy policies.
This article argues that the FPA does not preempt ZECs. These programs adapt traditional state authority over power generation and utility portfolios to today’s restructured electric grid. Courts should reject plaintiffs’ requests to enlarge the scope of FERC’s exclusive authority over wholesale rates and should conclude that ZECs, like other state clean energy programs, do not conflict with FERC’s regulatory regime.
This article begins by briefly recapping the evolution of state and federal roles in regulating the electric industry. After introducing the structure and purpose of state ZEC policies, the paper argues that they are not preempted by the text of the FPA or the Supreme Court’s most recent decision about FPA preemption, Hughes v. Talen. Finally, the paper rejects conflict preemption claims because FERC has the authority and expertise to reconcile state ZEC policies with its wholesale market regulation.
Although beyond the scope of this article, it is important to mention that courts might not decide the preemption issue at all. Both states argue that under the 2015 Supreme Court decision Armstrong v. Exceptional Child Center, the FPA precludes private preemption challenges. If courts accept this argument, private parties would not be able to bring FPA preemption challenges to federal courts.
Prior to the 1980s, investor-owned utilities generated three-quarters of the nation’s power. These utilities are subject to extensive state regulation pursuant to century-old public utility laws. Under this industry structure, utilities built plants in their own monopoly service territories to meet local consumer demand. Utilities financed power plant construction with securities approved by state regulators and earned a regulated rate of return on these investments through state-regulated retail rates. State regulators thus enjoyed substantial control over power plant construction and operation.
Through the 1950s, regulation of power generation was relatively uncontroversial. Consumers paid less for power the more they used, as utilities captured economies of scale. To the extent that utilities had excess generating capacity beyond what they needed to serve local consumers, they could trade power with neighboring utilities. These residual wholesale sales were under the exclusive jurisdiction of federal regulators pursuant to the FPA. Enacted in 1935, the statute filled a regulatory gap by providing FERC with jurisdiction over wholesale sales in interstate commerce, but explicitly reserves to states jurisdiction over matters that they had been actively regulating, including “generation facilities.”
By the 1970s, several factors combined to transform the electric power industry from a long-run decreasing cost industry into a long-run increasing cost industry. Oil and natural gas price spikes and billions of dollars in cost overruns for nuclear power plants contributed to massive consumer rate increases and underscored the economic significance of fuel choices. With heightened political attention on the industry, state regulators became increasingly interventionist. One regulatory response was requiring utilities to engage in “integrated resource planning.” Rather than meeting all demand with utility-constructed power plants, regulators and utilities endeavored to build an efficient portfolio of demand- and supply-side resources that included wholesale power purchases and energy-saving programs. Integrated resource planning expanded the scope of state regulation to include the portfolio of resources that the utility was drawing from to provide electric service.
The rising cost of producing power motivated some utilities to regionalize the industry. For example, in the early 1970s, utilities in New England and the mid-Atlantic integrated their systems to economically optimize power plant dispatch across the region. Their goal was to reduce each utility’s need for new capacity and minimize overall operating expenses. Across the country, utilities formed joint ventures to construct new power plants, particularly nuclear-powered facilities, that were sized to meet regional demand rather than just the needs of a single utility’s consumers. While states retained exclusive jurisdiction over the siting and construction of these regional facilities, FERC and state regulators each had authority over certain aspects of the plants’ financing.
By the early 2000s, reforms at the state and federal levels led to the creation of independent power producers, non-utility companies that own and operate power plants and rely on FERC-regulated wholesale rates, rather than state-regulated retail rates, for revenue. These generators typically sell their power at wholesale either through contracts with utilities or through FERC-regulated regional markets. Through a series of orders in the late 1980s and 1990s, FERC facilitated the creation of these interstate power markets. FERC-regulated regional market operators (RTOs or ISOs such as PJM and New York ISO) use auctions to efficiently dispatch regional generators and demand-side resources and keep the grid in balance. FERC approves all market rules and adjudicates disputes about rules and their implementation. This role provides FERC with substantial influence over the price of power.
Meanwhile, approximately a dozen states, including New York and Illinois, broke apart their vertically integrated utilities in the late 1990s and early 2000s. This industry restructuring separated power generation from its delivery by requiring or incentivizing utilities to sell their power plants to corporate affiliates or independent companies. State restructuring laws seeded the new FERC-regulated interstate markets with consumer demand and non-utility power suppliers. “Wires-only” utilities, which remained under the supervision of state utility regulators, had to procure power through wholesale markets to meet the demand of their ratepayers.
As the scope of interstate markets expanded, and power generators increasingly earned revenue from FERC-regulated markets rather than state-set retail rates, state regulators lost considerable leverage over power plant investments. But states did not cede control over utility portfolios. To the contrary, both restructured and traditionally regulated states enacted renewable portfolio standards (RPS) that require utilities to demonstrate that a certain amount of the energy they sell to consumers is derived from renewable power. In most states, utilities comply by acquiring Renewable Energy Credits (RECs), certificates that represent the environmental attributes of a quantity of electricity. Renewable energy generators earn revenue from FERC-regulated wholesale sales and through sales of state-created credits. By requiring utilities to purchase RECs from renewable generators, states incentivized the construction of new generation capacity that met their environmental and energy supply policy goals.
Utilities’ REC purchases complement energy transactions on the restructured grid. A utility buying energy from a market operator purchases undifferentiated energy, not energy from a specific generator. RECs serve an accounting function, allowing utilities (and other consumers) to take credit for renewable energy generation even though they are not actually consuming it or purchasing it directly from the generator. Although state RPS laws are relatively new in the context of the one-hundred-year history of state utility regulation, they are an integral piece of the governance structure of today’s electric grid. By creating a commodity that represents the environmental attributes of electric power, states are able to use a market-based mechanism to exercise control over utility portfolios and influence the mix of resources selling energy at wholesale.
While wholesale power markets have transformed from residual utility-to-utility sales regulated on a cost-of-service basis to regional auction markets governed by RTO/ISOs’ complex and voluminous rules, FERC’s statutory authority is largely unchanged. The core provisions of the FPA, largely intact since they were passed by Congress in 1935, require FERC to ensure that wholesale rates are “just and reasonable” and not “unduly discriminatory.” The Supreme Court has recently explained that FERC “undertakes to ensure ‘just and reasonable’ wholesale rates by enhancing competition—attempting . . . ‘to break down regulatory and economic barriers that hinder a free market in wholesale electricity.’”
When FERC acts to improve the wholesale market, it has “expansive” authority and may account for a range of industry practices that “directly affect” wholesale rates. While courts are reluctant to cut off FERC’s jurisdiction, recent Supreme Court decisions also recognize that the FPA is a “collaborative federalism statute[that] envisions a federal-state relationship marked by interdependence.” Under the FPA, “federal and state powers [are] ‘complementary’” and “marked by interdependence” States “may regulate within the domain Congress assigned to them even when their laws incidentally affect areas within FERC’s domain.” When they do, it is “squarely within FERC’s jurisdiction” to “approv[e wholesale market] rules that prevent the state’s choices from adversely affecting wholesale  rates.”
In August 2016, the New York PSC enacted a ZEC program to benefit economically struggling nuclear plants. According to the PSC, low wholesale power prices challenge the financial viability of nuclear plants and could lead to their premature retirement. The PSC concluded that the ZEC program “is the best way for the State to preserve the nuclear units’ [emission-free] environmental attributes while staying within the State’s jurisdictional boundaries.”
New York’s ZEC program is identical in structure to RPS programs. The PSC’s order designates nuclear power plants that generate ZECs, sets the ZEC price, and requires a state agency to procure ZECs from those facilities for twelve years. Each New York utility must purchase ZECs from the state agency in proportion to its share of total electric sales. The PSC pegged the ZEC price to the social cost of carbon, as calculated by an Obama-era federal government interagency working group. The PSC can adjust the price downward in contract years three through twelve if wholesale power and capacity prices in New York are projected to increase above a reference value.
In December 2016, the Illinois Legislature passed essentially the same ZEC program. Illinois’ ZEC price is also based on the social cost of carbon and can be adjusted downward if projected energy and capacity prices in the FERC-regulated PJM and MISO markets exceed a reference value.
Both ZEC programs were part of broader efforts to reduce greenhouse gas emissions from the states’ power mixes. In New York, the PSC’s order also increased the state’s RPS to 50 percent renewable energy by 2030. According to the PSC, “the independent renewable resource and ZEC obligations . . . each contribute uniquely to serving the long-term goal of achieving a largely de-carbonized energy system by the middle of the century.” New York ZECs are intended “to avoid backsliding in the State’s efforts to reduce carbon emissions.” The Illinois legislation, known as the Future Energy Jobs Act, increased that state’s RPS target, expanded utility energy efficiency mandates, and created a new solar energy program.
Shortly after the programs were enacted, coalitions of electric generators filed lawsuits in federal district courts in New York and Illinois. The suits allege two Constitutional infirmities with the ZEC programs. First, they assert that the FPA preempts ZECs because they intrude on FERC’s exclusive field of wholesale ratemaking and conflict with FERC’s market-based regulatory regime. Second, they claim that by selecting only in-state plants to receive ZECs, the states are impermissibly discriminating against out-of-state businesses and burdening interstate markets in violation of the dormant Commerce Clause.
Both courts dismissed all claims on the merits and on procedural grounds. Below, I argue that courts should reject preemption claims on appeal.
The Supreme Court has repeatedly stated that FERC has exclusive jurisdiction over rates for electric energy sold at wholesale in interstate commerce. The FPA “‘leaves no room either for direct state regulation of the prices of interstate wholesales’ or for regulation that ‘would indirectly achieve the same result.’” A court will preempt any state action that it finds intrudes on this exclusive federal field.
Many aspects of power generation – such as plant siting and operations and environmental standards – are clearly within state authority and beyond the reach of FERC. But state restructuring laws complicated the jurisdictional picture. By moving power sales entirely out of the retail rate construct and forcing plants to sell at wholesale, states linked power generation to wholesale sales. In restructured states, traditional areas of state concern necessarily implicate FERC-jurisdictional wholesale sales.
For instance, in 2017 the Second Circuit rejected a field preemption challenge to a Connecticut law that requires utilities to solicit proposals for new renewable generation and sign contracts with winning bidders. Because Connecticut is restructured, utilities must contract for power, including for renewable power mandated by state law. The Second Circuit panel concluded that it is “settled law” that states may “specify the sizes and types of generators that may bid” in to a utility procurement for wholesale energy, despite the direct effects those choices have on the resulting FERC-regulated wholesale contracts and the indirect effects those contracts may have on rates in FERC-regulated interstate markets.
While states can mandate that utilities contract for power from specified generation technologies, no court has decided whether states may offer financial incentives to generators themselves. By requiring utilities to purchase RECs from eligible generators, RPS laws provide renewable generators with revenue on top of what they earn from FERC-jurisdictional wholesale sales. But RPS laws have never been challenged on preemption grounds.
ZEC opponents attack the RPS policy structure and argue that it is preempted based on a straightforward reading of the FPA. Section 205 is one of the core provisions of the FPA. It stipulates that “[a]ll rates and charges made, demanded, or received . . . for or in connection with the . . . 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.” The plaintiffs argue that because an eligible nuclear generator sells a ZEC to the state for each megawatt-hour of energy it generates and sells at wholesale, ZECs are payments “received” by nuclear generators “in connection with” their wholesale sales of electric energy. Plaintiffs reason that ZECs are therefore under FERC’s exclusive jurisdiction, and the state programs must be preempted.
Plaintiffs’ proposed expansion of FERC’s exclusive authority has no limiting principle that would prevent FERC’s exclusive jurisdiction from similarly swallowing up RECs. Although no court has ever ruled precisely on this issue, FERC itself has held that it does not have exclusive jurisdiction over all REC sales. In 2012, FERC determined that when RECs are sold “independent[ly] of a wholesale electric energy transaction . . . the charge for the  RECs is not a charge in connection with a wholesale sale of electricity.” Both the Illinois and New York district courts were reluctant to disturb FERC’s finding. The Illinois court found that “FERC’s conclusion that it is possible to unbundle an environmental attribute credit from the sale of electricity without stepping on FERC’s toes is persuasive when applied to ZECs.”
Classifying state-created ZECs or RECs as FERC-jurisdictional payments would inject uncertainty into REC markets and invite litigation about RPS laws. It could also force FERC to regulate REC sales, and it might frustrate FERC’s ongoing efforts to harmonize its market regulation with state policies that select cleaner generation. Destabilizing how states and FERC have understood this key jurisdictional issue would be inconsistent with how the Supreme Court has interpreted the FPA.
In a 2002 decision about a FERC order that enabled the creation of today’s wholesale markets, the Court held that FERC “had discretion to decline to assert  jurisdiction [over certain transactions], in part because of the complicated nature of the jurisdictional issues.” The Court concluded that FERC had made a “statutorily permissible policy choice” to limit the scope of its authority, even though it arguably could have asserted jurisdiction over certain state-regulated transactions. That principle applies with equal force here. Even if FERC could assert jurisdiction over RECs and ZECs, the FPA does not compel it to do so.
The delicate nature of preemption under the FPA reinforces the principle that courts should tread lightly. In Hughes, Justice Sotomayor’s concurrence explains that courts evaluating FPA preemption claims “must be careful not to confuse the ‘congressionally designed interplay between state and federal regulation’ for impermissible tension that requires preemption under the Supremacy Clause.” Although sales of ZECs and RECs may affect FERC-regulated wholesale rates, those effects do not necessarily transform state-created credits into FERC-jurisdictional products sold “in connection with” wholesale energy. As the Court explained decades ago in a decision about the companion Natural Gas Act, “the breadth and complexity of [FERC’s] responsibilities demand that it be given every reasonable opportunity to formulate methods of regulation appropriate for the solution of its intensely practical difficulties.” In this case, courts should defer to FERC’s determination that when state-created credits are sold separately from their associated energy, as ZECs are, they are outside the scope of FERC’s authority.
Plaintiffs’ novel reading of the FPA, if accepted, would frustrate FERC’s long-standing efforts to accommodate state RPSs. For example, in February 2017, FERC drew a distinction between its “responsib[ility] for maintaining well-functioning markets” and state “jurisdiction over . . . renewable resource targets and renewable portfolio standards.” In that order, FERC found that an ISO New England tariff provision that exempted renewable resources from certain bidding rules “balances [FERC’s] responsibility to promote economically-efficient prices, while accommodating states’ ability to pursue legitimate policy objectives.” This sort of technical judgment about squaring wholesale market rules with state clean energy policies is at the heart of FERC’s regulatory mission. As the Supreme Court has explained, FERC “must be permitted . . . to adapt [its] rules and policies to the demands of changing circumstances.” Courts should reject ZEC opponents’ efforts to prevent FERC from harmonizing its regulation of interstate markets with state policies that advance legitimate environmental goals.
Plaintiffs also argue that the states’ ZEC programs are preempted because they are “indistinguishable” from the program that the Supreme Court preempted in Hughes. In his companion article, Joel Eisen crafts a preemption test based in part on a phrase in Hughes that suggests state programs may not be “tethered” to wholesale markets. Neither argument provides a basis for preempting ZECs.
In Hughes, the Court held that the FPA preempted a Maryland Public Service Commission Order. The relevant order was the result of Maryland’s multi-year effort to induce construction of a new natural gas power plant. State regulators solicited proposals from developers and then ordered each utility to sign a contract-for-differences with the plant. Under the contracts, the utilities paid the plant the difference between PJM prices for energy and capacity and prices set by the developer and approved by the state, so long as the plant bid into and cleared the PJM market. The effect of these contracts was to guarantee the plant selling its entire output to PJM that it would receive the price the state set, regardless of FERC-regulated PJM rates.
The Court concluded that the state-mandated contracts “operate within the [FERC-regulated] auction.” The contracts traded nothing of value between the parties, but rather mandated that utilities and the plant exchange money based on PJM prices. The Court’s rationale is somewhat confusingly explained in the opinion’s last paragraph:
We reject Maryland’s program only because it disregards an interstate wholesale rate required by FERC. . . 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.” Brief for Respondents 40. 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.
In the first sentence, the Court finds fault “only” with the state’s “disregard” for the FERC-regulated rate. The final sentence, however, ignores that the state program supplants the wholesale rate and concludes that the contracts’ “fatal defect” is the requirement that the plant clear the FERC-regulated auction. Although all three federal courts that have interpreted Hughes have concluded that the a “fatal defect” language is controlling, any remaining ambiguity in the Court’s final paragraph is irrelevant for ZECs because they trip neither of the Court’s concerns.
First, ZECs (and RECs) do not “disregard an interstate wholesale rate required by FERC.” ZECs represent the environmental attributes of power, which an economically rational market should value, but FERC-regulated markets do not. By pricing ZECs based on the social cost of carbon, the states are approximating the actual benefits of the program (as best we can measure them). This price does not ignore or supplant the FERC-regulated price for power or capacity; it pays for an entirely separate product.
Second, the ZEC programs do not “condition payment of funds” on nuclear plants selling through any particular market. There simply is no such provision in the programs’ rules. Plaintiffs argue that the bid-and-clear condition is embedded in FERC-approved market rules that require plants to sell to wholesale market operators, thus obviating the needs for New York and Illinois to specify that condition. But the law of preemption is about state action, and it would flip the doctrine on its head to conclude that a state program can be preempted by a complementary (and not conflicting) Federal regulation. Indeed, the Hughes Court identified the state’s clearing requirement as the program’s “fatal defect.”
Eisen argues that the district courts were incorrect to read this language literally. But for Maryland, this bid-and-clear requirement was critical for the cost-effectiveness of its program. The state-mandated contracts contemplated that the plant would earn the vast majority of its revenue by selling to PJM. Utilities (and by extension ratepayers) would then pay what was expected to be relatively a small amount to true-up any difference between the plant’s PJM revenues and the state-approved contract price. Had the contracts not included the bid-and-clear requirement, utilities could have been on the hook for the entire contract price. The “clearing” requirement was fundamental to the state’s scheme of replacing the FERC-regulated rate with a state-determined price. No such concern exists with regard to ZECs, whose prices are capped at the social cost of carbon.
Plaintiffs and Eisen also argue that the states’ ZEC price formula is a basis for preemption under Hughes. Both states set the price initially at the social cost of carbon. New York adjusts the price downward if forecasted energy and capacity prices in a particular New York market region increase above $39. Illinois similarly adjusts the price downward if a composite of forecasted energy prices and actual capacity prices in two regional markets exceeds $31.40. Plaintiffs assert that the ZEC price “varies in almost exactly the same manner that the contracts for differences in Hughes operated, shrinking as rates rise and growing as rates thereafter fall, to make up the difference between supposedly inadequate wholesale market rates and the rate [the state] thinks the generators should receive.” Eisen views the price adjustment as an impermissible “tether” between the state’s policy and FERC-regulated rates.
Resting preemption entirely on these adjustments would lead to an odd result. This argument concedes the legality of the ZEC program initially when the ZEC price is set at the social cost of carbon, and would find the program invalid only if FERC-regulated market prices increase above the reference values ($39 or $31.40). Under this theory, a state would be allowed to price an environmental credit based on the social cost of carbon (or some other metric), but forbidden from reducing that price if the beneficiary of the credits earns greater revenue due to higher wholesale power prices.
These credit price adjustments are distinguishable from the contracts in Hughes. Unlike Maryland’s contract price, the ZEC adjustments are not tied to actual revenue earned by any specific plant. Rather, the ZEC formulas account for a general forecasted increase in wholesale market prices without calculating the precise revenue effect for each ZEC-eligible plant. The ZEC price adjustments therefore do not “disregard an interstate wholesale rate.” Rather, the adjustments account for wholesale market conditions by reducing the price of the credit without changing any generator’s compensation for FERC-jurisdictional energy or capacity.
These adjustments are consistent with how a few states cap REC prices. Many RPSs allow utilities to pay alternative compliance payments (ACP) in lieu of surrendering RECs. ACPs are typically set by statute, can be adjusted by regulators, and set a ceiling for REC prices used for compliance in that state. States have various adjustment methodologies, and many tie ACPs to REC prices or inflation, but some account for wholesale market conditions. For example, Oregon law requires regulators to set an annual ACP based in part on the cost of renewable energy and rates in Oregon utilities’ wholesale contracts. New Jersey accounts for “changing conditions in the environment, the energy industry and markets.”
As a practical matter, ZECs and RECs are both “tethered” to wholesale rates. For ZECs, the price adjustment is embedded administratively in the price formula. For RECs, the tether is explicit when ACPs are based on wholesale rates and otherwise implicit. States created RECs when renewable energy was significantly more expensive. RECs were intended in part to make up the difference between a developer’s costs and the revenues it would earn from wholesale energy and capacity sales. RECs and ZECs both provide revenue to resources that would otherwise be uneconomic. In addition, as New York regulators note in the order creating ZECs, REC prices are expected to vary inversely with wholesale market rates – when energy prices are low, REC prices tend to be high and vice-versa.
The ZEC price adjustment thus mimics how REC prices change in response to wholesale rates. Preempting ZECs due to the adjustment would tell states that they may not explicitly account for wholesale market conditions but may continue to do so implicitly by setting ACPs and establishing utility demand for credits. Other indirect mechanisms, such as credit price adjustments based on in-state utility costs for wholesale power purchases, may be sufficiently attenuated from wholesale rates and rooted in consumer protection. Ultimately, preempting a credit price adjustment as an impermissible “tether” overlooks the interconnectedness of state and federal regulation and would invite litigation about other state policies.
Plaintiffs allege that the states’ ZEC programs are invalid under conflict preemption principles. In general, courts find conflict preemption when a state law “stands as an obstacle to the accomplishment and execution of the [Congress’] full purposes and objectives.” Plaintiffs complain that by keeping otherwise uneconomic plants in the market, ZECs frustrate FERC’s efforts to set rates through competitive markets and distort FERC-approved just and reasonable rates.
Courts should reject this theory that market effects provide a basis for preemption. As the Third Circuit held in a case about a New Jersey program that was nearly identical to the program at issue in Hughes, “the law of supply-and-demand is not the law of preemption. When a state regulates within its sphere of authority, the regulation’s incidental effect on interstate commerce does not render the regulation invalid.” Numerous state policies, ranging from clean energy mandates to taxes, have effects on interstate power markets. Whether any of these policies “conflict” with FERC’s markets is best addressed in the first instance by FERC, rather than a federal court.
Plaintiffs’ primary concern about the ZECs’ effects is that they will suppress capacity market prices. FERC has explained that “competitive offers [in a capacity market] are expected to reflect going-forward costs as adjusted for revenues that are consistent with revenues earned in competitive markets.” Because ZEC-eligible plants will earn revenue from ZEC sales, they may submit lower offers into the capacity market than they otherwise would. These lower offers may then result in lower market-clearing prices received by all sellers.
The very same plaintiffs that filed lawsuits in federal courts have also filed complaints at FERC asking it to ensure that capacity market rules protect against this outcome. Plaintiffs’ conflict preemption claim would short-circuit FERC’s processes. FERC has authority to address potential market distortion and has considerable expertise and discretion in determining how to do so. Courts should decline to address this argument, and only rule on a conflict preemption claim if plaintiffs allege that the states’ policies conflict with FERC’s eventual orders on ZECs.
Zero Emission Credits are consistent with state authority over utility portfolios and do not intrude on FERC’s jurisdiction over interstate power sales. Many state programs shape the mix of resources on the grid by providing incentives for clean power or adding costs to pollution. By design, these programs, including ZECs, affect FERC-jurisdictional rates. But the law of preemption is not an economic test. These incidental effects do not constitute state regulation of wholesale sales. To the extent that ZECs have adverse consequences on wholesale markets, FERC has the technical expertise and legal authority to address them.
* Ari Peskoe is the Director of Electricity Law Initiative at Harvard Law School’s Environmental and Energy Law Program. Many thanks to Jim Rossi, my co-author on an amicus brief about Zero Emission Credits available at https://statepowerproject.files.wordpress.com/2017/02/electricity-regulation-scholars-brief-webposting.pdf.
 Coal. for Competitive Elec. v. Zibelman, 272 F. Supp. 3d 554 (S.D.N.Y. 2017), appeal docketed, No. 17-2654 (2d Cir. Aug. 25, 2017); Vill. of Old Mill Creek v. Star, No. 17 CV 1163, 2017 WL 3008289 (N.D. Ill.), appeal docketed, No. 17-2445 (7th Cir. July 18, 2017).
 See Coal. for Competitive Elec., 272 F. Supp. 3d 554.; see also Elec. Power Supply Ass’n v. Star, No. 17 CV 1163, 2017 WL 3008289, appeal docketed, No. 17-2455 (7th Cir. July 18, 2017).
 See, e.g., Conn. Light & Power Co. v. Fed. Power Comm’n, 324 U.S. 515 (1945); Fed. Power Comm’n v. S. Cal. Edison Co., 376 U.S. 205 (1964); Pac. Gas & Elec. Co. v. State Energy Res. Conservation & Dev. Comm’n, 461 U.S. 190 (1983); New York v. F.E.R.C., 535 U.S. 1 (2002).
 F.E.R.C. v. Elec. Power Supply Ass’n, 136 S. Ct. 760 (2016); see Hughes v. Talen Energy Mktg., LLC, 136 S. Ct. 1288 (2016).
 See, e.g., Energy & Env’t Legal Inst. v. Epel, 793 F.3d 1169 (10th Cir. 2015); North Dakota v. Heydinger, 825 F.3d 912 (8th Cir. 2016).
 See, e.g., Jim Rossi, The Brave New Path of Energy Federalism, 95 Tex. L. Rev. 399 (2016); Joel B. Eisen, Duel Electricity Federalism is Dead, But How Dead, and What Replaces It? 8 Geo. Wash. J. of Energy and Envtl. L. 3 (2017); Amy L. Stein, Regulating Reliability, 54 Hous. L. Rev. 1191 (2017); Matthew R. Christiansen, FERC v. EPSA: Functionalism and the Electricity Industry of the Future, 68 Stan. L. Rev. Online 100 (2016); Steven Ferrey, The Medium is the Message, 35 Va. Envtl. L. J. 213 (2017); Ari Peskoe, Easing Jurisdictional Tensions by Integrating Public Policy in Wholesale Electricity Markets, 38 Energy L. J. 1 (2017).
 See Allco Finance Ltd. v. Klee, 861 F.3d 82 (2d Cir.), cert. denied, 138 S. Ct. 926 (2018); see also Coal. for Competitive Elec., 272 F. Supp. 3d 554; Vill. of Old Mill Creek v. Star, No. 17 CV 1163, 2017 WL 3008289 (N.D. Ill.), appeal docketed, No. 17-2445 (7th Cir. July 18, 2017).
 See Md. Pub.Serv. Comm’n, Order No. 88192, Case No. 9431 (2017).
 See Armstrong v. Exceptional Child Ctr., 135 S. Ct. 1378, 1387–88 (2015).
 Government-owned and rural cooperatives generated the remainder. Richard Hirsh, Power Loss 279 fig.A-2 (1999).
 One notable exception was whether the Federal government should own and operate power plants that make wholesale sales. See Ashwander v. Tenn. Valley Auth., 297 U.S. 288 (1936); see also Tenn. Elec. Power Co. v. Tenn. Valley Auth., 306 U.S. 118 (1939).
 Hirsh, supra note 10, at 48 fig.2.1; see Carolyn Brancato, New Approaches to Current Problems in Electric Utility Rate Design, 2 Colum. J. Envtl. L. 40 (1975).
 16 U.S.C. § 824(b) (2015).
 See Brancato, supra note 12, at 40–41 ; see Paul L. Joskow, Regulatory Failure, Regulatory Reform, and Structural Change in the Electrical Power Industry, Brookings Papers on Econ. Activity 125, 136–39 (1989).
 See Bruce Biewald & Rachel Wilson, Best Practices in Electric Utility Integrated Resource Planning, Synapse Energy Economics (June 2013), http://www.raponline.org/wp-content/uploads/2016/05/rapsynapse-wilsonbiewald-bestpracticesinirp-2013-jun-21.pdf.
 See Our History, ISO-New England, https://www.iso-ne.com/about/what-we-do/history (last visited March 14, 2018); see also PJM/MISO Joint Board–FERC, Statement by Phillip J. Harris, President and CEO of PJM Interconnection 2 (Nov. 21, 2005), https://www.ferc.gov/EventCalendar/Files/20051120152440-Harris,%20PJM.pdf.
 See, e.g., Miss. Power v. Miss. ex rel. Moore, 487 U.S. 354, 357–61 (1988).
 See id. at 357–58.
 Severin Borenstein & James Bushnell, The U.S. Electricity Industry After 20 Years of Restructuring, Energy Institute at Haas 7, 15–16 (May 2015) https://ei.haas.berkeley.edu/research/papers/WP252.pdf.
 Depending on the state law, RECs may instead certify that a quantity of electricity was generated by a specific technology. Ari Peskoe, Emission Rate Credits in the Clean Power Plan, Harvard Environmental Law Program 4 (Oct. 2015), http://environment.law.harvard.edu/wp-content/uploads/2015/08/Emission-Rate-Credits-in-the-Clean-Power-Plan.pdf.
 16 U.S.C. § 824d(a) (1978); 16 U.S.C. § 824e(a) (2005).
 F.E.R.C. v. Elec. Power Supply Ass’n, 136 S. Ct. 760, 768 (2016) (quoting Morgan Stanley Capital Grp. Inc. v. Pub. Util. Dist. No. 1 of Snohomish City, 554 U.S. 527, 536 (2008)).
 Id. at 776; see Joel B. Eisen, FERC’s Expansive Authority to Transform the Electric Grid, 49 U.C. Davis L. Rev. 1783 (2016); see also Rossi, supra note 6; Ari Peskoe, Easing Jurisdictional Tensions by Integrating Public Policy in Wholesale Electricity Markets, 38 Energy L. J. 1 (2017).
 Hughes, 136 S. Ct. at 1300 (Sotomayor, J., concurring); see also Oneok, Inc. v. Learjet, 135 S. Ct. 1591, 1601 (2015) (“Petitioners and the dissent argue that there is, or should be, a clear division between areas of state and federal authority in natural-gas regulation. But that Platonic ideal does not describe the natural gas regulatory world.”).
 Hughes, 136 S. Ct. at 1298.
 N.J. Bd. of Pub. Utils. v. FERC, 744 F.3d 74, 98 (3d Cir. 2014).
 N. Y.Pub. Serv. Comm’n, Order Adopting a Clean Energy Standard, Case 15-E-0302 at 45 (2016).
 Id. at 20.
 Id. at 51.
 20 Ill. Comp. Stat. 3855/1-75 (2017)
 Order Adopting a Clean Energy Standard, supra note 29, at 20.
 Id. at 45.
 16 U.S.C. § 824(b) (2015); Hughes v. Talen Energy Mktg., LLC, 136 S. Ct. 1288, 1291 (2016); Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 966 (1986).
 F.E.R.C. v. Elec. Power Supply Ass’n, 136 S. Ct. 760, 780 (2016) (quoting Northern Natural Gas Co. v. State Corporation Comm’n of Kan., 372 U.S. 84, 91 (1963)).
 See § 824(b) (reserving to states authority over generation facilities).
 Allco Finance Ltd. v. Klee, 861 F.3d 82 (2d Cir.), cert. denied, 138 S. Ct. 926 (2018).
 16 USC 824d(a) (1978).
 Appellants’ Initial Brief at 39–41, Elec. Power Supply Ass’n v. Star, No. 17-2455 (7th Cir. Aug 28, 2017); Appellants Initial Brief at 29–30, Coal. for Competitive Elec.. v. Zibelman, No. 17-2654 (2d Cir. Oct. 13, 2017).
 Reviewing FERC orders on the Public Utility Regulatory Policies Act of 1978 – which requires utilities to purchase energy from certain renewable generators – the Second Circuit concluded that FERC’s orders do “not evince an intent to occupy the relevant field—namely, the regulation of renewable energy credits.” Wheelabrator Lisbon, Inc. v. Conn. Dep’t. of Pub. Util. Control, 531 F.3d 183, 190 (2d Cir. 2008).
 WSPP, Inc., 139 FERC ¶ 61,061 P 24 (2012).
 Vill. of Old Mill Creek v. Star, No. 17 CV 1163, 2017 WL 3008289, at *13 (N.D. Ill.), appeal docketed, No. 17-2445 (7th Cir. July 18, 2017); see also Coal. for Competitive Elec., 272 F. Supp. 3d at 573 (“The death knell for Plaintiffs’ field preemption argument is their failure to distinguish ZECs from RECs . . . If RECs are not preempted . . . then the Court fails to see how ZECs are.”).
 In May 2017, FERC convened a conference on the interaction between RTO markets and state policies. FERC hoped the conference would foster further discussion regarding the development of regional solutions in the Eastern RTOs that “reconcile the competitive market framework with the increasing interest by states to support particular resources or resource attributes.” Notice of Technical Conference, Notice Inviting Post-technical Conference Comments (May 23, 2017) (F.E.R.C. Docket No. AD17-11-000).
 New York v. F.E.R.C., 535 U.S. 1, 28 (2002).
 Id. (quoting Transmission Access Policy Study Grp. v. FERC, 225 F.3d 667, 694–95 (D.C. Cir. 2000).
 Hughes v. Talen Energy Mktg., LLC, 136 S. Ct. 1288, 1300 (quoting Nw. Cent. Pipeline Corp. v. State Corp., Comm’n of Kan., 489 U.S. 493, 518 (1989)).
 In re Permian Basin Area Rate Cases, 390 U.S. 747, 790 (1968).
 See, e.g., California Indep. Sys. Operator, 119 FERC ¶ 61,061 at P 86 (2007); California Indep. Sys. Operator, 118 FERC ¶ 61,226 at PP 6, 14 (2007); Int’l Transmission Co., 120 FERC ¶ 61,220 at PP 23–25 (2007); S. California Edison, 121 FERC ¶ 61168 at PP 3, 6, concurrences (2007); New York Indep. Sys. Operator, 122 FERC ¶ 61,211 at P 112 (2008); Order No. 1000, 136 FERC ¶ 61,051 at P 81 (2011); Midcontinent Indep. Sys. Operator, 133 FERC ¶ 61,221 at P 190 (2010); Order No. 764, 139 FERC ¶ 61,246 at PP 19–21 (2012); Order No. 792, 145 FERC ¶ 61,159 at P 25 (2013); New York Pub. Serv. Comm’n. v. New York Indep. Sys. Operator, 153 FERC ¶ 61,022 at P 51 (2015).
 ISO New England, 158 FERC ¶ 61,138 at P 9 (2017).
 Id. at P 68; see also New York Indep. Sys. Operator, 122 FERC ¶ 61,211 at P 112 (2008); New York Pub. Serv. Comm’n. v. New York Indep. Sys. Operator, 153 FERC ¶ 61,022 at P 51 (2015).
 In re Permian Basin Area Rate Cases, 390 U.S. at 784.
 Appellants’ Initial Brief at 41–51 , Elec. Power Supply Ass’n v. Star, No. 17-2455, (7th Cir. Aug 28, 2017); Appellants Initial Brief at 30–40, Coal. for Competitive Elec. v. Zibelman, No. 17-2654, (2d Cir. Oct. 13, 2017).
 Joel B. Eisen, The New (Clear?) Electricity Federalism: Federal Preemption of States’ “Zero Emissions Credit” Programs, 44 Ecology L.Q. Currents (2018).
 Hughes v. Talen Energy Mktg., LLC, 136 S. Ct. 1288, 1299 (2016)
 See Allco Finance Ltd. v. Klee, 861 F.3d 82, 100 (2d Cir.), cert. denied, 138 S. Ct. 926 (2018); Coal. for Competitive Elec. v. Zibelman, 272 F. Supp. 3d 554, 571 (S.D.N.Y. 2017), appeal docketed, No. 17-2654 (2d Cir. Aug. 25, 2017); Vill. of Old Mill Creek v. Star, No. 17 CV 1163, 2017 WL 3008289, at *13 (N.D. Ill.), appeal docketed, No. 17-2445 (7th Cir. July 18, 2017).
 Eisen, supra note 54.
 PPL Energyplus, LLC v. Nazarian, 974 F. Supp. 2d 790, 822 (D.Md. 2013).
 Appellants Initial Brief at 38, Coal. for Competitive Elec. v. Zibelman, No. 17-2654, (2d Cir. Oct. 13, 2017).
 Eisen, supra note 54.
 Or. Rev. Stat. § 469A.180 (2007).
 N.J.A.C. § 14:8-2.10 (2017).
 Order Adopting a Clean Energy Standard, supra note 29, at 127.
 Galen Barbose, U.S. Renewable Portfolio Standards: 2017 Annual Status Report 30 (Jul. 2017) (“REC prices are a function of ACP rates and current/expected supply-demand balance.”).
 See OneOK, Inc. v. Learjet, 135 S. Ct. 1591, 1601 (2015) (“Petitioners and the dissent argue that there is, or should be, a clear division between areas of state and federal authority in natural-gas regulation. But that Platonic ideal does not describe the natural gas regulatory world.”).
 Hines v. Davidowitz, 312 U.S. 52, 66‒68 (1941).
 PPL Energyplus v. Solomon, 766 F.3d 241, 255 (3d Cir. 2014) (citing Nw. Cent. Pipeline v. State Corp. Comm’n of Kansas, 489 U.S. 493, 514 (1989)).
 See FERC Dockets No. EL16-49-000; EL13-62-000.
Copyright 2018 Ari Peskoe. All rights reserved.