FERC and the Supreme Court, Part Two: Court Decides Hughes v. Talen Energy Marketing, Clarifying Lines Between Federal and State Jurisdiction Over Electric Power Markets
As the Supreme Court has recently explained, under the Federal Power Act (“FPA”), “no electricity transaction can proceed unless it is regulable by someone.” The FPA empowers the Federal Energy Regulatory Commission (“FERC”) to oversee “the transmission of electric energy in interstate commerce” as well as “the sale of electric energy at wholesale in interstate commerce.” The states get everything else. The boundaries between state and federal jurisdiction might therefore seem clear enough. And for many decades, they were. More recently, though, these jurisdictional lines have become blurred: FERC’s attempts to increase competition in wholesale markets have bled into retail sales, and state actions to encourage additional generating capacity have likewise impacted wholesale markets.
Recently we reviewed FERC v. Electric Power Supply Association (“EPSA”) and discussed the then-pending Hughes v. Talen Energy Marketing, LLC, two Supreme Court cases that shed light on the often difficult-to-draw lines between state and federal jurisdiction over electric power markets. In EPSA, the Court addressed the limits of FERC’s ability to impact retail sales. There, the Court upheld FERC’s demand-response rules, which require wholesale market operators to receive bids from power consumers willing to forego the use of specified amounts of electricity and treat them similar to bids from traditional generators. In doing so, the Court rejected arguments that FERC impermissibly strayed into state territory by regulating retail rates. In Hughes, decided on April 19, 2016, the Court addressed the other side of the coin. Agreeing with the Fourth Circuit, the Court held that a Maryland program, designed to encourage the construction of a new generating facility in that state, impermissibly strayed into FERC territory by setting wholesale rates.
While EPSA and Hughes clarify the boundaries between state and federal regulation of electric power, both cases recognize that in this era of the interconnected grid, there is inevitably a great deal of overlap. At least for now, the Court seems to have settled on a pragmatic approach. So long as FERC rules are nominally directed at wholesale markets and do not expressly set retail rates, the courts will sustain FERC actions that impact retail rates, even significantly. Similarly, states are free to act in any number of ways to encourage new generating capacity—including via subsidies that necessarily impact wholesale markets—so long as they do not expressly interfere with wholesale sales or rates.
1. Changing Regulatory Roles
Prior to the FPA, state public utility commissions regulated all aspects of the electric utilities that served their states. Over time, generating facilities grew larger, long-distance transmission infrastructure was erected, and interstate sales became more common. The Supreme Court, though, eventually held that the Commerce Clause prohibited state and local regulators from regulating many interstate transactions, including interstate wholesale sales. The FPA was enacted to fill this regulatory gap.
The FPA tasks FERC with regulating, among other things “the sale of electric energy at wholesale in interstate commerce.” The Act, though, does not grant FERC authority to regulate all power sales. Specifically, while FERC has jurisdiction over interstate wholesale power sales, its authority does not extend to “any other sale of electric energy.” Thus, the regulation of intrastate wholesale and all retail sales of electricity are left to the states. The states, too, have authority “over in-state ‘facilities used for the generation of electric energy.’”
2. Wholesale Auctions
Today, FERC ensures lawful wholesale pricing in significant part by facilitating competition. To this end, it has encouraged the creation of regional entities that manage portions of the grid in many parts of the nation, conducting competitive auctions that set wholesale power prices.
A “capacity auction” is designed to ensure that electricity generation will meet future demand. In a capacity auction, the grid operator predicts future demand, and assigns shares of that demand to the load-serving entities (“LSEs”)—entities that purchase wholesale power and resell it to retail consumers—participating in the auction. Power generators and other owners of capacity then submit bids to meet this demand. The grid operator accepts these bids, from lowest to highest, until the projected demand is satisfied. If a capacity owner’s bid is accepted, it is said to have “cleared” the auction. LSEs are then required to purchase their assigned shares of power.
Capacity owners that have cleared the market are not paid the amount of their accepted bid. Instead, all LSEs pay—and all clearing capacity bidders receive—the price of the highest accepted bid. This is referred to as the “clearing price.” By way of example, if three capacity owners submit bids at $10/MW, $20/MW and $30/MW, respectively, and the operator accepts all three bids, each generator will be paid $30/MW. A capacity owner content to receive whatever the clearing price may be, then, has every incentive to submit a bid of $0. Such bidders are commonly referred to as “price takers.”
Not all capacity owners, however, are permitted to act as price takers. Relevant here, FERC’s Minimum Offer Price Rule requires new generators to submit their initial bids at a price set by the grid operator unless they can demonstrate that this price exceeds their actual costs. These new generators, though, are not stuck submitting minimum bids for long: once a capacity owner has submitted a clearing bid, it can thereafter submit as low a bid as it chooses. New generators, moreover, may be able to take advantage of the New Entry Price Adjustment (“NEPA”) rule, which guarantees stable prices for three years.
3. Bilateral Contracts
In addition to wholesale auctions, FERC also helps to ensure lawful wholesale pricing by regulating bilateral contracts between LSEs and generators. In a bilateral contract, an LSE agrees to purchase electricity from a generator at a given price, time, and amount. FERC may then review the rate’s reasonableness. Bilateral contracting, though, will not necessarily remove the LSE from wholesale auctions. Instead, an LSE that holds a contractual right to a given amount of electricity at a given time simply enters the wholesale market, at least in part, as a capacity owner.
Say, for example, an LSE is assigned a 100 MW share of future demand, and has a bilateral contract to purchase 40 MW at $40/MW. If the clearing price is $50/MW, the LSE must still pay the operator $5,000 (the clearing price multiplied by the LSE’s share). But, because the capacity-owning LSE is itself paid $50/MW for the 40 MW of capacity it sells at the auction, the LSE in effect pays only $3,000 at auction. In this scenario, then, the LSE pays $1,600 under the bilateral contract and $3,000 at auction, saving $400 compared to what it would have paid without the bilateral contract. Were the clearing price to come in below the bilateral contract price, though, the LSE would lose money on the deal. All of this, of course, depends on the LSE’s capacity bid clearing the auction. Because the LSE must pay the contract price no matter the auction result, it has every incentive to act as a price taker, submitting a $0 bid to ensure it clears the auction.
Hughes v. Talen Energy Marketing
The capacity auctions just described are designed to ensure adequate supply to meet future demand. State regulators, however, do not always believe they are sufficient to encourage new generation within their borders. Hughes v. Talen Energy Marketing involved Maryland’s attempt to spur new in-state power generation.
Maryland began by asking FERC to extend the NEPA period to ten years. When FERC refused, the state took a different approach. The Maryland program operated roughly as follows. The state solicited bids to construct a new power plant at a specified location; in return, Maryland would require its LSEs to enter into a 20-year “contract for differences” with the winning bidder (ultimately Commercial Power Ventures, Maryland, or “CPV”). This contract set the wholesale rates CPV would be paid for a 20-year period.
The Maryland contract for differences departed from the bilateral contracts described above in that it did not transfer ownership of capacity from the generator to the LSE. Thus, CPV—not the Maryland LSEs—would sell the newly constructed capacity in the wholesale auction. The contract, though, was tied to the federal auction in important ways. In short, if CPV cleared the auction and the clearing price was less than the contract price, the Maryland LSEs would pay it the difference. Conversely, if CPV cleared the auction and the clearing price exceeded the contract price, CPV would pay the LSEs the difference. If CPV failed to clear the auction, though, it received nothing. As a result, CPV’s incentive was to submit the lowest possible auction bid, regardless of its actual costs or the price it expected to receive at auction.
2. Decisions Below
CVP’s competitors brought suit, claiming that Maryland’s approach unlawfully suppressed wholesale market prices, and thus their own revenue. In the competitors’ view, the Maryland program encouraged CPV to submit bids that did not reflect its actual cost of producing power, thereby artificially driving down the market. They argued that the Maryland contract was unlawful under the theories of both field preemption (states cannot regulate where the federal government fully occupies a regulatory field) and conflict preemption (states cannot regulate in a way that impedes a federal regulatory scheme). Finding that Maryland’s approach effectively set the price CPV received for interstate wholesale power sales, the district court held that the state impermissibly strayed onto the field occupied exclusively by FERC. In PPL EnergyPlus, LLC v. Nazarian, the Fourth Circuit affirmed, adding that conflict preemption similarly doomed the Maryland plan.
With respect to field preemption, the appeals court held that the Maryland program was “field preempted because it functionally set the rate that CPV receive[d] for its sales in the [wholesale] auction.” Significant to the court was the fact that contract payments were conditional on CPV entering and clearing the wholesale auction. This, the court found, meant that the payments “plainly qualify as compensation for interstate sales at wholesale, not simply for CPV’s construction of a plant.” Moreover, the state’s actions “ensured . . . that CPV receives a fixed sum for every unit of capability and energy” it sold in the wholesale auction. As a result, the “[t]he scheme thus effectively supplant[ed] the rate generated by the auction with an alternative rate preferred by the state.”
Still, the Fourth Circuit stopped short of holding that the FPA prohibits all state subsidization of new generating capacity. Specifically, the court did “not express an opinion on other state efforts to encourage new generation,” and explained that “it goes without saying that not every state statute that has some indirect effect on wholesale rates is preempted.” But the Maryland program’s effect “on matters within FERC’s exclusive jurisdiction is neither indirect nor incidental. Rather, [it] strikes at the heart of the agency’s statutory power to establish rates for the sale of electric energy in interstate commerce. …”
The Fourth Circuit also found the Maryland program to be conflict preempted because it (a) set CPV’s wholesale rate and (b) guaranteed it a fixed price for more than NEPA’s three-year period. While the court again noted that “not every state regulation that incidentally affects federal markets is preempted,” it found the Maryland program “a bridge too far.”
3. Supreme Court Decision
As we had predicted, in Hughes v. Talen Energy Marketing the Supreme Court agreed with the Fourth Circuit that “Maryland’s program sets an interstate wholesale rate, contravening the FPA’s division of authority between state and federal regulators.” Justice Ginsburg delivered the majority opinion in which all but Justice Thomas joined; Justice Thomas concurred in part and in the judgment. As expected, the Court issued a narrow ruling.
While the Court did not expressly state whether it relied on field or conflict preemption, it used language suggesting it believed both doctrines to have been implicated:
FERC has approved the PJM capacity auction as the sole ratesetting mechanism for sales of capacity to PJM, and has deemed the clearing price per se just and reasonable. Doubting FERC’s judgment, Maryland—through the contract for differences—requires CPV to participate in the PJM capacity auction, but guarantees CPV a rate distinct from the clearing price for its interstate sales of capacity to PJM. By adjusting an interstate wholesale rate, Maryland’s program invades FERC’s regulatory turf.
The Court also distinguished the Maryland contract for differences from more common bilateral contracts. To the Court, the difference was subtle but important:
The contract for differences does not transfer ownership of capacity from one party to another outside the auction. Instead, the contract for differences operates within the auction; it mandates that LSEs and CPV exchange money based on the cost of CPV’s capacity sales to PJM.
In the end, the Court issued a narrow ruling: “We reject Maryland’s program only because it disregards an interstate wholesale rate required by FERC.” The Court explained that it did “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.” The Court also emphasized that its decision does not “call into question whether generators and LSEs may enter into long-term financial contracts based on the auction clearing price.” This is because private contracts for differences, unlike Maryland’s, “do not involve state action to the same degree as Maryland’s program, which compels private actors (LSEs) to enter into contracts for differences—like it or not . …”
Most significantly, the Court did not accept the invitation to invalidate the Maryland program on the grounds that “it interferes with the capacity auction’s price signals,” or “counteracts FERC’s refusal to extend the NEPA’s duration.” Instead, the Court concluded that “[s]o 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.”
Like the recent FERC v. EPSA, the Court’s decision in Hughes demonstrates the Supreme Court’s recognition of the interconnected nature of state and federal jurisdiction over electric power sales as well as the Court’s desire to draw jurisdictional lines based on the face of a challenged regulatory program rather than its actual effect on power markets.
In FERC v. EPSA, the Court walked this line by finding that while the FERC demand-response rule at issue affected the retail market, it (a) was expressly directed only at the wholesale market and (b) did not set retail rates. Similarly, in invalidating the Maryland program, the Hughes Court looked not to its practical effects on wholesale markets, but the fact that the Maryland program expressly tied contract payments to the generator entering and clearing the wholesale auction.
At least for now, it appears that when evaluating whether a state or federal power regulator has crossed the line into the other’s turf, courts will look first to the terms of the rule in question. What remains to be seen is whether courts will ultimately permit states to adopt programs that artificially depress wholesale rates, even though they avoid the Maryland program’s flaw of being expressly tied to wholesale markets. The Court in Hughes certainly suggested this possibility, but future litigation on the issue seems inevitable.
 41 Stat. 1063, as amended, 16 U.S.C. §791a et seq.
 FERC v. Electric Power Supply Association, 136 S.Ct 760, 780 (2016).
 16 U.S.C. §824(b)(1).
 136 S.Ct 760 (2016).
 578 U.S. ___ (2016).
 See Michael Dotten and Zachary Kearns, FERC at the Supreme Court: Drawing the Line Between Federal and State Jurisdiction Over Electric Power Markets, Marten Law Environmental News (March 23, 2016), available at http://www.martenlaw.com/newsletter/20160323-ferc-jurisdiction-electric-power-markets#_edn10.
 On April 25, 2016, the Court denied cert petitions in two related cases involving a similar program developed by the state of New Jersey. This leaves in place the decision of the Third Circuit Court of Appeals, which had found the program invalid.
 Public Util. Comm’n of R. I. v. Attleboro Steam & Elec. Co., 273 U.S. 83, 89–90 (1927).
 16 U.S.C. §824(b)(1).
 Hughes, 578 U.S. ___, ___ (slip op., at 2) (quoting 16 U.S.C. §824(b)(1)).
 Id. at 4.
 Id. at 5.
 Id. at 6.
 Id. at 3.
 Id. at 5.
 Id. at 5.
 Id. at 7.
 Id at 7.
 Id. at 8.
 PPL EnergyPlus, LLC v. Nazarian, 753 F.3d 467, 474 (4th Cir. 2014).
 Id. at 476.
 Id. at 478 (citations and quotations omitted).
 Id. (citations omitted).
 Id. at 479.
 Id. at 480.
 Hughes, 578 U.S. ___, ___ (slip op., at 12).
 Id. at 14.
 Id. at 15.
 Id. at 15 n.12.
 Id. at 15 n.13.
 Id. at 15.
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