Tag: electricity markets

Supreme Court: EPA Can’t Cap Greenhouse Gas Emissions From Power Plants

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The Supreme Court just decided “the most closely watched environmental case in decades,” West Virginia v. U.S. Environmental Protection Agency. In the 6-3, opinion, the Court holds that the EPA cannot use Clean Air Act §111(d) to set power-sector-wide greenhouse gas emissions standards for state power plants. The Court also explains that the Major Questions Doctrine is crucial to this analysis and reflects both “separation of powers principles and a practical understanding of legislative intent.”

A Justice Gorsuch concurrence, joined by Justice Alito, lays out their view of history and application of clear statements doctrines and the major questions doctrine specifically. Justice Kagan wrote a dissenting opinion, joined by Justice Breyer and Justice Sotomayor.

The opinion can be found here: https://www.supremecourt.gov/opinions/21pdf/20-1530_n758.pdf

As a reminder, here is a summary of how the case got to the court from a blog post and webinar I did last December, in anticipation of the Supreme Court argument:

Under the Clean Air Act, the Environmental Protection Agency regulates greenhouse gas emissions from various sources including new cars and new industrial sources. But a large proportion of the country’s greenhouse gas emissions come from existing sources, such as the nation’s coal and natural gas power plants, which provide over half of American electricity.

In 2015, the Obama administration issued a regulation for existing fossil fuel power plants under Clean Air Act §111(d), which allows the EPA to “establish a procedure” for each state to adopt “standards of performance” for existing sources of air pollutants. The administration called this rule the “Clean Power Plan.” It was controversial, in part, because it went beyond asking states to make their existing power plants run more efficiently. Instead, it went “beyond the fenceline” of the power plant to encourage non-fossil sources of electricity such as wind and solar power and shrink the fossil-fuel power sector.

The Clean Power Plan never went into effect because the Supreme Court stayed its implementation on February 9, 2016. The D.C. Circuit heard more than 7 hours of argument on the validity of the Clean Power Plan but never ruled on it because the Trump administration repealed it and replaced it with its own rule, which it called the “Affordable Clean Energy Rule,” and was limited to promoting efficiency measures at existing fossil fuel plants. The D.C. Circuit then heard 9 more hours of argument on this new rule, before striking it down on January 19, 2021. The court held that EPA’s authority was not so limited.

The Supreme Court granted certiorari to decide whether Clean Air Act §111(d) gives “the EPA authority not only to impose standards based on technology and methods that can be applied at and achieved by that existing source, but also allows the agency to develop industry-wide systems like cap-and-trade regimes.” The case is an important sequel in the Court’s lines of cases on how much deference executive agencies should receive to decide major questions of policy and whether Congress might authorize dramatic agency action from relatively obscure provisions—hiding an elephant in a mousehole.

The opinion can be found here: https://www.supremecourt.gov/opinions/21pdf/20-1530_n758.pdf

The Supreme Court emphasized that “the only interpretive question before” it was “narrow”: “whether the ‘best system of emission reduction’ identified by EPA in the Clean Power Plan was within the authority granted to the Agency in Section 111(d) of the Clean Air Act.” Some had thought it might explicitly limit the Chevron doctrine or return to the non-delegation doctrine. This is a narrower ruling, but may rule out some of the more aggressive steps the Biden administration might have considered to reduce sector-wide greenhouse gas emissions in areas such as utilities, refineries, and oil and gas development.

Energy Tradeoffs Podcast #30 – Rhodes & Meehan

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This week’s EnergyTradeoffs.com podcast episode features David Spence interviewing Joshua Rhodes & Colin Meehan about their research on “Keeping the Lights on in a High Renewables Grid.”

Josh & Colin explain the concept of grid “inertia” and why it is so important for grid stability. The grid must always maintain the same frequency and inertia steadies this frequency when a power plant suddenly goes offline. They explain that wind and solar power do not provide the same inertia as conventional plants but describe ways of making the grid flexible to accommodate high levels of renewable power nevertheless.

Josh & Colin also describes how renewable power sources can provide “fast frequency response” as a substitute for inertia. But they explain that doing so would require reducing power output from these sources, which might require modifying markets to pay for ancillary services that maintain the grid’s frequency.

The discussion builds on one of Josh’s recent articles: “Evaluating rotational inertia as a component of grid reliability with high penetrations of variable renewable energy,” which was published last year in the journal Energy.

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Energy Tradeoffs Podcast #21 – Joshua Macey

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This week’s EnergyTradeoffs.com podcast episode features Cornell’s Joshua Macey talking with David Spence about his research on “Renewables and Reliability in Competitive Wholesale Electricity Markets.”

In the interview, Joshua explains why electric power providers in competitive markets are relying more and more on capacity markets, which pay them just for being available to provide power, and less on energy markets, which pay them only when they are actually providing power. He critiques the way that interstate grid operators and the Federal Energy Regulatory Commission have implemented these capacity markets, arguing that current rules discriminate against renewable resources such as wind and solar power.

The discussion builds on Joshua’s forthcoming University of Pennsylvania Law Review article with Jackson Salovaara, “Rate Regulation Redux.”

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Energy Tradeoffs Podcast #18 – Ari Peskoe

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This Thursday’s EnergyTradeoffs.com podcast episode features Harvard Law School’s Ari Peskoe talking with David Spence about his research on “Reliability, Decarbonization & Federal-State Conflict Over Electricity Markets.”

Ari and David talk about restructured power markets and struggles over the extent of federal and state authority to ensure that there are enough power plants and that electricity remains reliable. And Ari explains his work on a brief of electricity law scholars that defended states’ authority to adopt “zero emissions credits” that support nuclear power.

This discussion also builds on Ari’s recent paper, which is titled, “Easing Jurisdictional Tensions by Integrating Public Policy in Wholesale Electricity Markets.”

As an aside, my favorite part of the podcast comes near the start, when David offers the funny-because-it’s-true observation that “Ari is a Twitter public servant” because he “provides a lot of public goods on Twitter.”

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Energy Tradeoffs Podcast #15 – William Boyd

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Today’s EnergyTradeoffs.com podcast episode features UCLA’s William Boyd talking with David Spence about his research on “‘Public’ Utility: Steering Markets Toward Public Ends“.

In the interview, William explains his critique of FERC’s approach to price formation in natural gas markets and electricity auctions. William argues that markets cannot be insulated from politics and that the policy choices that often dominate cost-of-service ratemaking can emerge in restructured energy markets as well.

The discussion builds on two of William’s recent articles: “Public Utility and the Low Carbon Future,” and “Just Price, Public Utility and the Long History of Economic Regulation in America.”

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Guest Blog: Joshua Macey on “Rate Regulation Redux”

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  • Guest blogger Joshua Macey is here to discuss his new paper on how electricity regulators and grid operators are responding to increased solar and wind power, and how their interventions raise old questions that were supposed to be resolved by electricity deregulation. You can also hear an Energy Tradeoffs interview with Joshua about his piece here.

In Rate Regulation Redux, forthcoming in the University of Pennsylvania Law Review, Jackson Salovaara and I consider whether the American system for compensating electric power generators can accommodate high levels of renewables. We find that the current market structure is ill-suited to a high-renewables world. Regulators and grid operators (grid operators are the utilities that manage the power grid), it seems, are aware of the challenges renewables pose. However, instead of developing a payment system that would preserve competition in the energy sector and allow renewables to enter the market, regulators have begun an ad hoc process of reregulation that raises rates, leads to excess capacity, and prevents renewables from competing with traditional energy sources.

For most of the twentieth century, FERC treated electricity as a natural monopoly. To ensure that suppliers met demand, regulators gave utilities exclusive franchises over their service territories and permitted them to charge rates sufficient to cover their costs. In exchange, generators agreed to provide electricity to customers in their territories and cap prices. For years, this system provided reliable electricity. Nonetheless, critics complained that it limited consumer choice, failed to promote innovation, rewarded utilities for overinvesting in supply, and reduced incentives to retire uneconomic generators.

In the 1990s, FERC began to encourage a “market-based” approach to promote competition and control costs. Under this “restructured” model, which has been adopted in two-thirds of the country, an independent grid operator determines demand for electricity, solicits bids from generators, and clears enough bids to meet demand. The grid operator clears bids starting with the lowest bid but ultimately pays every generator the price bid by the highest clearing bidder. In this system, generators bid at their marginal cost. If a generator bids below its marginal cost, it risks having to provide electricity even when it would lose money in doing so. Above-marginal cost bids risk failing to clear when it would be profitable for the generator to operate.

This system promotes competition and keeps short-run costs low, but it is ill-equipped to integrate significant volumes of renewables. Generators that are dispatched infrequently or operate on the margin cannot make a profit or recover their costs. These plants are known as “peaking plants” and operate a few times in a year when demand is high (often on the hottest days of the summer or the coldest days of the winter when Americans consume a lot of electricity). Without them, grid operators would not be able to meet peak demand.

In theory, peaking plants would be able to make enough money to operate. While generators bid their variable costs almost all of the time, that assumption does not apply to peaking plants that bid only when demand is high. In most circumstances, a generator risks losing out on profitable bids if it submits a bid above its marginal costs. Because peakers are the last plants to be dispatched, they do not need to worry that they will be outbid because there are no plants available to outbid them. They can therefore submit bids that significantly exceed their marginal costs. As a result, peaking plants can drive prices to levels that would allow them to recover their fixed costs and make a profit despite the fact that they operate only a few times a year

However, a system that relies entirely on energy markets can lead to rampant market manipulation and excessive price volatility. Peaking plants have market power. Because they are the last units dispatched, if they do not operate, there will not be enough electricity to meet demand (these incentives contributed to the California energy crisis in the beginning of the twenty-first century). Peaking plants can therefore drive prices to extremely high levels. To avoid these problems, every regulator in the United States sets a ceiling on its energy market’s clearing price.

Unfortunately, a system that imposes price caps on energy markets is ill-equipped to integrate significant volumes of renewables. Renewables have a different cost structure than other generators. While the marginal costs for most generators are above zero, wind and solar facilities have very low operating costs. As renewables provide an increasing percentage of electricity, they suppress revenues for all generators. Imagine if four generators had been providing electricity to a region. Two bid $20 MWh, one bid $40 MWh, and one bid $50 MWh. All four generators were paid $50 MWh. If, however, a solar plant replaces the $50 MWh generator and offers $0 MWh, it will reduce revenues for all generators. That is because it will drive out the $50 MWh generator, making the $40 MWh generator the clearing bid, which means that every generator would be paid $40 MWh.

The challenge with this system is that as renewables suppress prices, energy markets become increasingly reliant on price spikes to ensure that all generators receive sufficient revenue. But if regulators do not increase price caps, then energy prices will not increase enough during scarcity to allow generators to make enough money to continue to operate.

There are a few possible solutions to this problem. One would be to increase price caps, but no regulator (with the possible exception of Texas) has expressed a willingness to let spot market prices rise enough to allow generators to recover their costs. Regulators have been reluctant to allow prices to rise to extremely high levels out of fear that doing so would encourage market manipulation. 

Another option is to develop other markets that would ensure that crucial generators are able to survive. To date, most regulators seem inclined to adopt this approach. Unfortunately, the markets regulators are developing do not allow meaningful competition between energy sources and instead prevent renewables from competing with traditional generators. For example, grid operators in the east coast have begun to rely on capacity markets, which pay generators for being available to provide electricity instead of for actually providing electricity, to make sure that generators receive enough revenue to continue operating. The problem with this this system is that capacity markets do not actually reward generators for providing the services the grid needs. Not all electricity has the same value. Generators that can turn on and off quickly, that can provide electricity when it is most needed, and that provide electricity to areas that are resource-constrained should be rewarded for providing these services. Energy markets are uniquely effective because they reward generators that provide electricity where and when it is really needed. Capacity markets fail to do this. To make sure that the “right” generators are being compensated in capacity markets, some grid operators have taken steps to make it more difficult for some types of generators (often renewables and nuclear) to enter capacity markets.

Equally problematically, it is difficult for generators to exit the market once they clear a capacity markets. Generators that clear capacity markets commit to operating for a period of time (often three years). During that period, they are not permitted to exit the market unless they receive regulatory approval to do so. Thus, customers are often stuck paying for dirty electricity that is no longer necessary for the grid.

Worse still, grid operators have begun to rely on “reliability-must-run” (RMR) agreements to provide even more competition to the generators that are perceived to be critical to grid reliability. When capacity markets are not able to retain generators perceived to be critical to grid reliability, grid operators have simply bailed individual generators, and they have done so without any kind of competitive bidding procedure.

In our view, these interventions resurrect many of the principles of rate regulation. Under that approach, regulators gave generators a rate of return intended to make sure that the electricity companies would be able to meet all of a region’s electricity needs. In exchange, power companies provided service at agreed-upon rates. Today, regulators have begun identifying the generators that the grid needs, making sure those generators receive enough money to operate, and preventing them from retiring prematurely. Rather than rely on market forces to determine which generators operate, regulators shield preferred generators from competition in order to ensure that those generators are financially viable. And these generators are required to provide the services the grid needs.

A superior option, which we endorse in the paper, is to design a system based on long-term contracts that would impose penalties on generators that fail to perform as promised. Some of the problems with capacity markets are that they do not compensate generators that provide the services that the grid needs, they prevent generators from competing with each other, and they make it difficult for uneconomic and superfluous generators to exit the market.

Regulators and grid operators want to ensure that there is enough capacity to provide electricity to consumers throughout the year. A bidding process would allow utilities to purchase the electricity that they need. Utilities would have an incentive to keep cost down because doing so would allow them to lower their own costs. And, by penalizing generators that fail to provide services they agreed committed to, this approach would preserve short-term price signals that create incentives for generators to provide electricity where and when it is needed.

FERC’s Demand Response Strategy Hits a Snag: D.C. Circuit Vacates Order 745 in Electric Power Supply Association v. FERC

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  • I am delighted to welcome guest blogger Sharon Jacobs. Sharon was my colleague at Harvard Law School and will be an Associate Professor at Colorado Law beginning this summer.  Sharon’s scholarship focuses on administrative, energy and environmental law and she has a forthcoming article on federalism and demand response programs, so she is the perfect person to discuss the D.C. Circuit’s recent decision in Electric Power Supply Association v. FERC, which invalidated a federal order designed to encourage demand response. -James Coleman

By Sharon B. Jacobs

It is a poorly kept secret that D.C. Circuit judges do not exactly clamor to be assigned Federal Energy Regulatory Commission (FERC) cases. The notable exception is now-Senior Judge Stephen Williams, who loves them. His grasp of the intricacies of energy regulation is unparalleled on any court in the country. It is unfortunate, therefore, that Judge Williams was not assigned to the D.C. Circuit panel that recently handed down Electric Power Supply Association v. FERC. In a 2-1 opinion authored by Judge Janice Rogers Brown and joined by Judge Laurence Silberman, the panel vacated FERC’s final rule on compensation for demand response resources in wholesale energy markets. Judge Harry Edwards offered a well-reasoned and ultimately more persuasive dissent.

Demand response is the reduction of electricity use in response to a price signal. In other words, customers are paid not to consume energy. Demand response has been called the sale of “negawatts,” although the phrase is an imperfect description of the actual transaction. Where demand response bids are accepted, market administrators need not purchase as much generation (supply) to meet aggregate demand. Because the cost of electricity goes up as demand increases, especially at times of peak consumption, demand response can lead to significant savings.

Electricity markets are divided into two spheres: retail (sales to end-use customers) and wholesale (sales for resale). For the most part, states regulate the former, while FERC controls the latter. FERC’s demand response strategy affects both markets. In an earlier order, FERC allowed aggregating companies to bid retail customers’ demand response commitments directly into wholesale markets. In the rule challenged in this case, Order 745, FERC sought to further eliminate barriers to demand response participation in wholesale markets by requiring market administrators to pay demand resources the “locational marginal price” or “LMP” for each megawatt not consumed. The locational marginal price is the same price that generators receive when they bid their megawatts of power into wholesale markets. It reflects the value of energy at a specific location at the time of delivery. PJM, the market administrator for the mid-Atlantic region, explains that the LMP fluctuates like taxi fares—lighter electricity traffic yields a lower, steadier fare, whereas congestion on the wires causes the fare to rise. FERC included a caveat in its rule: demand response resources would only receive the LMP when their participation in wholesale markets would be cost effective, as determined by a specified “net benefits” test.

The bulk of the opinion concerned a threshold question: whether FERC acted within the scope of its jurisdiction under the Federal Power Act when it established compensation and other rules for retail demand response resources participating in wholesale markets. Under the Act, FERC has clear jurisdiction over rates for wholesale sales of electric energy in interstate commerce as well as rules, regulations and practices affecting those rates. FERC argued that it could set wholesale rates and other rules for demand response in wholesale markets because they were practices “directly affecting” wholesale sales. The panel majority disagreed, instead characterizing what FERC did as indirect regulation of the retail market for electricity.

There were three major problems with the opinion.  First, the majority found the Federal Power Act’s jurisdictional provisions much clearer than they are in fact.  It applied the normally deferential Chevron test, under which the court will defer to the agency’s reasonable interpretation of an ambiguous statutory provision it is authorized to administer, to FERC’s jurisdictional claims. Though some have argued that allowing the agency to determine the scope of its own jurisdiction when statutory language is ambiguous is analogous to permitting the fox to guard the henhouse, the Supreme Court recently affirmed the propriety of this practice in City of Arlington v. FCC. The Federal Power Act’s grants of jurisdiction did not anticipate demand response and the statute’s application to the phenomenon, as the dissent recognized, is unclear. In other words, the statutory provisions at issue, as applied to demand response, are ambiguous. Thus, the court should have deferred to FERC’s reasonable interpretation of those provisions at Chevron step two.

Second, Judge Brown found that the Federal Power Act foreclosed FERC’s reading because the Commission’s interpretation “has no limiting principle.” In an argument reminiscent of Justice Scalia’s warning in his Massachusetts v. EPA dissent that Frisbees and flatulence could be regulated under EPA’s capacious definition of “air pollutant,” Judge Brown warned that FERC’s interpretation of its “affecting” jurisdiction would authorize it to regulate “steel, fuel, and labor markets.” As the dissent pointed out, however, the limiting principle could not be clearer. Under the D.C. Circuit’s own holding in CAISO v. FERC, FERC may only regulate practices that “directly affect” wholesale rates or are “closely related” to those rates, “not all those remote things beyond the rate structure that might in some sense indirectly or ultimately do so.” As Judge Edwards pointed out in his dissent, this language clearly precludes regulation of “steel, fuel, and labor markets.”

Third, to the extent that the true motivation for the decision was general unease about federal encroachment on traditional areas of state regulatory power, the decision overlooked a key aspect of FERC’s demand response rules that mitigate any unwanted impact on state authority. An earlier FERC order, Order 719, offered state and local regulatory authorities an “opt-out”: those who did not want their retail customers participating in wholesale markets for demand response could prohibit them from doing so via legislation or regulation. Order 745’s pricing scheme was layered on top of this jurisdictional compromise. In Judge Edwards’s words, “[t]his is hardly the stuff of grand agency overreach.”

The most controversial part of Order 745, and the real reason the rule was the subject of such concerted opposition, got the least airtime in the opinion. In what was billed as an alternate holding in Part IV (but felt more like dicta), the panel found that Order 745’s locational marginal pricing scheme was arbitrary and capricious. In under two pages of text, the opinion declined to “delve now into the dispute among experts” yet asserted that the Commission had not “adequately explained how their system results in just compensation.” “If FERC thinks its jurisdictional struggles are its only concern with Order 745,” the opinion cautioned, “it is mistaken.” In a much more nuanced discussion of the Commission’s choice and the deference due to FERC “in light of the highly technical regulatory landscape that is its purview,” Judge Edwards concluded that the Commission provided a “thorough explanation” for selecting the locational marginal price as the appropriate level of compensation. In a nutshell, FERC’s argument was that the compensation level was necessary to overcome barriers to participation by demand response resources in wholesale markets and that it accurately reflected the value demand response provided to those markets.

Prior to this ruling, FERC had been successfully pursuing a policy of what I call, in a forthcoming article, “bypassing federalism”:  working a de facto rather than a de jure reallocation of regulatory power by extending its influence through the expansion of wholesale markets. In the context of demand response, that strategy was undermined by the Commission’s aggressive posture on pricing in Order 745. It was the idea that demand response resources would be paid the LMP for their “negawatts,” thereby competing directly with generation in wholesale markets, that triggered the groundswell of opposition from generation resources. The decision will not go into effect until seven days after the disposition of any motion for rehearing, and FERC is still considering its options as well as the decision’s impact on its rules and related programs. The panel’s decision may yet be reversed by the D.C. Circuit en banc or by the Supreme Court. But, as a policy matter, the Commission might have avoided a direct confrontation over its demand response rules by moving more deliberately on the pricing question.  As I have written elsewhere, for agencies whose regulatory schemes face concerted opposition, discretion is sometimes the better part of valor.