Search
`
October 31, 2024

MISO Holds Steady in Mid-Jan. Storm with Help from Wind

MISO dodged the need for emergency procedures during a mid-January cold blast that brought consecutive days of subzero temperatures to the Midwest. 

And both MISO and the Independent Market Monitor credit the wind fleet with playing a key role in keeping the system reliable.  

MISO likely achieved its systemwide winter peak of 106 GW as the arctic air dragged on Jan. 17.   

At a Jan. 18 Market Subcommittee meeting, MISO’s Tim Aliff said the South region set a new wintertime peak of 32.3 GW on Jan. 17, unseating the previous 31.8-GW record set in late 2022. That day, Baton Rouge bottomed out at 19 F, outstripping the day’s previous record of 20 F set in 1905. Other Louisiana cities logged record low temperatures for the day, toppling previous records set either nearly 120 years or more than 50 years ago.  

MISO enacted a cold weather alert and conservative operations beginning Jan. 13 and lifted them Jan. 18 and Jan. 17, respectively. The grid operator never was forced to escalate instructions to a maximum generation alert or warning as cold gripped the entire footprint.   

Aliff said MISO experienced “robust reserve margins” during the storm that varied between 14-19 GW and were generally available within four hours or less. He said thermal generation performed well throughout the event, with up to 2 GW of derates, compared to the approximately 10 GW in derates that occurred in late 2022 during Winter Storm Elliott.  

Wind generation also made healthy contributions during the storm, Aliff said, varying between 12-20 GW.  

Potomac Economics’ Carrie Milton, representing MISO’s Independent Market Monitor, said the week’s weather qualified as an extreme event that the Monitor analyzes in seasonal assessments for emergency potential. Milton said high wind output kept MISO out of emergency conditions; the Monitor had predicted ahead of the season that MISO would require emergency actions if it experienced nearly identical conditions to the storm.  

“We got a lot of support from wind, much higher than [unforced capacity] values,” Milton said. She said there were fewer instances of cold weather cutoffs and icing among the wind fleet than the Monitor anticipated.   

MISO will deliver a more comprehensive picture of its operations during the event at the Jan. 25 Reliability Subcommittee meeting. 

FERC Partly Grants Challenges to AEP Rates

FERC on Jan. 18 partly granted two formal challenges against AEP utilities arguing that benefits from filing consolidated tax returns were not properly reflected in the utilities’ 2021 formula rates in SPP and PJM.

The challenge to the rates filed by AEP subsidiaries in SPP — AEP Oklahoma Transmission and AEP Southwestern Transmission — argued that AEP’s calculation of accumulated deferred income taxes (ADIT) inflated the annual transmission revenue requirement (ATRR) in its 2021 rates by around $22 million. That complaint also argued that AEP incorrectly designated several expenses as falling into the ADIT bucket, increasing the net operating losses that can be used to offset income in future tax years.

The SPP challenge was jointly submitted by Arkansas Electric Cooperative Corp., East Texas Electric Cooperative, Northeast Texas Electric Cooperative and Golden Spread Electric Cooperative. (ER17-405, ER18-194.)

In PJM, several electric cooperatives submitted a challenge arguing that the ADIT calculation inflated the ATRR by $55.9 million.

The PJM challenge was jointly filed by American Municipal Power, Blue Ridge Power Agency, Indiana Municipal Power Agency, Mishawaka Utilities, Old Dominion Electric Cooperative and Wabash Valley Power Association against rates detailed in the annual update submitted by AEP Appalachian Transmission, AEP Indiana Michigan Transmission, AEP Kentucky Transmission, AEP Ohio Transmission and AEP West Virginia Transmission.

FERC’s Jan. 18 order found that AEP’s approach of including net operating loss carryforward ADIT as deferred tax inputs to its rate base did not pass the “benefits and burdens” test, which requires that tax benefits resulting from expenses paid by ratepayers be assigned to those ratepayers. The commission found that by not accounting for the benefits of filing consolidated tax returns in the net operating loss carryforward, AEP had calculated inflated ADIT input adjustments that resulted in higher transmission rates.

AEP argued that the benefits of filing consolidated tax returns do not result from a burden to ratepayers and therefore should not be assigned to them.

The challenge to rates filed by AEP’s SPP subsidiaries disputed several expenses the utility included in Account 928, which is meant to record regulatory commission expenses. The commission denied the challenge in part, finding that in most cases, AEP had properly explained the expenses, but required compliance filings within 60 days to provide more detail on others, such as the use of the allocation of fees to transmission using a gross plant allocator.

The challenge to the AEP subsidiaries in PJM argued that the utilities also improperly included ADIT assets in its rate base that were the result of over-recovered ratepayer funds. The commission granted the challenge, finding that “because the underlying refund amounts associated with the ADIT asset recorded in Account 190 are not included in rate base, the associated ADIT asset and excess or deficient ADIT should not be included either. The related ADIT must be excluded if the associated refund amounts are excluded from rate base.”

The commission’s order required AEP to submit a compliance filing within 60 days that details the calculations for the formula rate billings in the 2020 and 2021 annual updates and issue refunds for any improperly collected revenues. It also directed AEP to submit a compliance filing explaining how it includes ADIT related to contributions in aid of construction (CIAC) in its formula rate.

NERC Submits IBR Work Plan to FERC

NERC laid out its plan for developing standards to improve the reliability of inverter-based resources, primarily wind and solar generation facilities, in a filing with FERC on Jan. 18 in response to Order 901, issued by the commission in October (RM22-12). 

The ERO’s work plan is meant “to provide a detailed roadmap to guide the effective and orderly development of reliability standards addressing IBR issues through 2026” in accordance with Order 901, NERC said in its filing. The order directed NERC to develop rules addressing IBR data-sharing, model validation, planning and operational studies, and performance standards, and submit the standards in annual tranches over the next three years starting in 2024. (See FERC Orders Reliability Rules for Inverter-Based Resources.) 

FERC gave NERC 30 days to submit a standards development and implementation plan for informational purposes. The commission recognized in its order that the ERO had “already expended considerable effort” thinking about its approach to IBR-related standards; FERC therefore felt it was “not … necessary to approve NERC’s final work plan.” 

The plan “contemplates a broad, cross-functional effort” involving ERO staff and industry stakeholders working together to identify gaps in current reliability standards, review NERC’s ongoing standards development projects, suggest new projects as needed, and “provide additional support and analysis” as development continues. 

The organization identified four key milestones to be completed over the next three years, the first of which is the submission of the work plan itself. The remaining targets comprise the filing of reliability standards to address the following requirements: 

    • Performance requirements and post-event performance validation for registered IBRs (2024); 
    • Data-sharing and model validation for all IBRs (2025); and 
    • Planning and operational studies requirements for all IBRs (2026). 

The standards associated with each milestone are to be filed by Nov. 4 of the respective year. NERC plans to assign projects under the 2024 milestone the highest priority; projects addressing the other two milestones “will be elevated in priority to assure timely completion” as the earlier projects are finished. 

NERC identified three active projects as “essential for meeting [Order 901] directives” relating to the first milestone: Project 2021-04 (Modifications to PRC-002 – Phase II), Project 2020-02 (Modifications to PRC-024) and Project 2023-02 (Analysis and mitigation of bulk electric system IBR performance issues). The plan noted that these projects “may require some small adjustment to assure a timely completion,” and that the teams will need to coordinate throughout the year. 

Additional goals for NERC in 2024 include identifying and defining, “from a technological standpoint,” the terms that will likely be used in the standards developed to address FERC’s directives, such as “inverter-based resource” and “distributed energy resource.” Establishing consistent technical understandings of these terms will reduce the need to harmonize the efforts of the various standard drafting teams working on similar topics, it said. 

For the remaining milestones, NERC said “additional gap analyses” will be needed to incorporate currently active projects into the work. NERC’s standards development staff will work with the organization’s engineering teams and the Reliability and Security Technical Committee to identify the appropriate projects and determine what additional projects may be needed to address FERC’s objectives. 

NM Regulators to Explore Findings on Day-Ahead Market at RTO Workshop

The New Mexico Public Regulation Commission will dive into a report on the financial implications of a Western day-ahead electricity market during a workshop Jan. 25. 

The workshop is part of the PRC’s research into the pros and cons of utility participation in a regional day-ahead market or RTO. The PRC plans to develop “guiding principles” for utilities to consider in deciding whether to participate. 

During the workshop, the regulators will hear a presentation from Energy+Environmental Economics on the cost-benefit study, which E3 prepared for the Western Markets Exploratory Group. WMEG is a coalition of transmission-owning entities covering most of the Western Interconnection. (See Study Shows Uneven Benefits for Calif., Rest of West in Single Market.) 

E3 also conducted additional economic analysis for individual WMEG members. Results for two New Mexico utilities — Public Service Company of New Mexico (PNM) and El Paso Electric (EPE) — will be shared during the workshop. 

Commissioner Gabriel Aguilera said there are several issues to consider in an RTO or day-ahead market decision, including transparency, seams and reliability. 

But from a regulator’s perspective, the most important questions are “will the market design lead to financial benefits to ratepayers?” and “will the benefits outweigh the costs?” Aguilera told RTO Insider. 

The commission doesn’t currently have a timeline for finalizing its guiding principles, but Aguilera acknowledged the need to act quickly. 

PNM has said it expects to decide this year on joining a regional day-ahead market. The two options are CAISO’s extended day-ahead market (EDAM) or SPP’s Markets+ offering. 

In December, FERC approved the tariff for EDAM. And SPP expects to file a Markets+ tariff with FERC early this year. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM and IMIP Approves SPP Markets+ Governance Tariff Language.) 

The upcoming meeting is a follow-up to a workshop in September that featured presentations from PNM, EPE and Southwestern Public Service Co. (See New Mexico Contemplates Organized Market Choice.) PNM and EPE will give an update during the upcoming meeting, according to the agenda. 

Aguilera said the commission is seeking as much input as possible. 

The workshop will begin at 2 p.m. MST. Those who wish to comment may attend in-person or via Zoom. 

To attend the meeting via Zoom, email public.comment@prc.nm.gov or call (505) 490-7910. The deadline to sign up for public comment is 5 p.m. Jan. 24, or 5 p.m. Jan. 19 for those who want to participate in the meeting’s question-and-answer session. 

The meeting will also be streamed on the PRC’s YouTube channel. 

Diablo Canyon Secures $1.1B DOE Award to Support Operations

Pacific Gas and Electric’s Diablo Canyon Power Plant will be the first recipient of federal funds being made available to shore up operations at U.S. nuclear plants that face imminent closure.

The Department of Energy on Jan. 17 awarded the California utility $1.1 billion to help maintain operations at the 2,200-MW nuclear plant, whose two units had been slated for closure in 2024 and 2025.

DOE is providing the money through the Civil Nuclear Credit (CNC) Program, established in 2022 with $6 billion from the Infrastructure Investment and Jobs Act (IIJA) to head off the shutdown of nuclear plants from economic factors. Under the terms of the program, applicants must commit to “best efforts” to use uranium produced in the U.S. and seek to rely on domestic providers of other services.

PG&E is the first plant operator to win money under the first funding cycle of the CNC program. The utility will receive credits in installments paid over four years, “with the amount of the annual payment to be adjusted based on a number of factors, including actual costs incurred to extend the operation of the Diablo Canyon Power Plant,” according to DOE.

The first payment is scheduled for 2025 and will be based on the plant’s operations over 2023/24.

“Preserving the nation’s nuclear fleet is critical not only to reaching America’s clean energy goals, but also to ensuring that homes and businesses across the country have reliable energy,” Maria Robinson, director of DOE’s Grid Deployment Office, said in a statement about the award. “Today’s announcement demonstrates the [Biden] administration’s commitment to domestic nuclear energy by preserving existing generation while we continue to support a stronger nuclear power industry.”

Located on the West Coast near Avila Beach, Calif., the 2,200-MW Diablo Canyon plant provides about 9% of California’s in-state generation and 15% of its emissions-free energy.

The plant had been scheduled to close in stages starting this year, largely in response to concerns about its vulnerability to earthquakes. Those concerns increased sharply in the aftermath of the 2011 major accident and radiation release at the Fukushima Daiichi nuclear plant, which was caused by an earthquake and ensuing tsunami.

But since California’s rolling blackouts of 2020, state officials — including Gov. Gavin Newsom — have expressed growing worries about how to maintain grid reliability without the plant as the state works to meet ambitious targets to reduce its economywide carbon emissions. In 2022, Newsom signed Senate Bill 846, which directed the California Public Utilities Commission to authorize an extension for Diablo Canyon by December 2023.

The CPUC last month voted 3-0 to keep Units 1 and 2 at the plant running until 2029 and 2030, respectively. In approving the extension, the commission said it would continue to evaluate whether the cost of continued operation becomes “too high to justify incurring,” as outlined in SB 846. (See California PUC Votes to Extend Diablo Canyon Nuclear Plant 5 Years.)

PG&E is still awaiting approval for an extension to its operating license from the U.S. Nuclear Regulatory Commission after filing a renewal application last November.

Phillips: FERC to Issue Transmission Rule in ‘Very Near Future’

FERC Chair Willie Phillips on Jan. 18 expressed confidence that the commission will approve its Notice of Proposed Rulemaking on transmission planning and cost allocation this year (RM21-17). 

Speaking at the commission’s first open meeting of the year, Phillips’ remarks came just days after nearly half the Democrats in Congress urged FERC to complete its work on the NOPR. (See related story, Congressional Democrats Urge FERC to Complete Transmission Rule.) 

“We stand on the cusp of some significant milestones this year at FERC,” Phillips said at the open meeting. “Building upon the foundation that we set last year including Order No. 2023 from last July, a landmark rule that will help streamline our interconnection queue process, we are poised to address critical aspects of regional transmission planning and cost allocation in the coming months. The importance of these upcoming actions on transmission cannot be overstated.” 

The NOPR’s provisions will ensure the grid is robust and reliable, and the collective expertise at FERC will lead to a final rule that helps expand the grid and stands the test of time, he added. The NOPR, issued in April 2022, would direct transmission providers to revise their planning processes to identify infrastructure needs on a long-term, forward-looking basis and propose a list of benefits on which they would base their selections of proposed projects to meet those needs. 

Phillips said he is confident that the current three-member commission could vote out the NOPR soon. 

“I look forward to working on and voting on these important items in the very near future,” Phillips said. “There’s nothing that I know, that I can see, that can make me believe that we can’t get this work done. It’s too important for the American people.” 

FERC was holding its meeting after D.C. saw its first major snowfall in several years that was part of a winter storm system that stretched across much of the country. The weather stressed the grid, but it did not break as it had in previous storms such as December 2022’s Elliott or February 2021’s Uri. 

“This event underscores the need for more transmission capacity,” Phillips said. “SPP imported a record 6.8 GW from neighboring regions, surpassing the amount that was imported during Winter Storm Uri. But it’s only mid-January. We’ve got a little bit more winter that’s going to come through here, so we cannot rest. We have to remain vigilant.” 

Another aspect of transmission policy is increasing interregional transfer capability, which is being examined by NERC in a study that was mandated by Congress.  

“I’ve been meeting with Jim Robb, the CEO of NERC,” Phillips said. “My understanding is that they’re not waiting. … They’ve already hired folks to work on the study, and that it may not take the full 18 months. We are working on these two projects in parallel so that when NERC concludes its study, FERC is ready to act immediately.” 

Phillips also mentioned that the commission is working to implement its updated backstop siting authority under the National Interest Electric Transmission Corridor process. 

Another Federal Lawsuit Seeks to Invalidate OSW Approvals

A coalition of offshore wind opponents is suing federal agencies and officials, seeking to overturn their approval of the South Fork Wind and Revolution Wind projects. 

The “putative” approval violated nine federal acts, the plaintiffs argue, and in so doing, undercut the statutory and regulatory requirements put in place to protect the nation’s natural resources, industries and people. 

It is the latest in a series of legal challenges to the first wave of what is envisioned to be dozens of wind farms off the Northeast coast. So far, none of the complaints have been successful in thwarting offshore wind’s progress in U.S. waters.  

In fact, the Ørsted-Eversource partnership is nearing completion of South Fork and preparing to begin construction of Revolution. 

Case 1:24-cv-00141 was filed Jan. 16 in U.S. District Court in the District of Columbia.  

Topping the list of plaintiffs is Green Oceans, a Rhode Island nonprofit opposed to “industrialization of our coastal waters.” Named as defendants are the U.S. Department of the Interior, Bureau of Ocean Energy Management, National Marine Fisheries Service, Army Corps of Engineers and the leaders of those entities. 

“In authorizing these projects,” the plaintiffs write, “defendants failed to comply with numerous statutes and their implementing regulations: [the] Administrative Procedure Act, National Environmental Policy Act, Endangered Species Act, Marine Mammal Protection Act, Migratory Bird Treaty Act, Coastal Zone Management Act, National Historic Preservation Act, Outer Continental Shelf Lands Act and Clean Water Act.” 

There currently are 42 MW of installed offshore wind capacity in the United States, but Mid-Atlantic and Northeast states have combined goals of more than 50 GW. The Biden administration wants to get at least 30 GW operational by 2030. 

The legal paperwork lays out a familiar complaint — in rushing to create an offshore wind industry, developers and governmental entities risk harming ocean ecosystems. (See Report Flags Gap in Scientific Knowledge of OSW Effects.) 

“Green Oceans aims to prevent irreversible damage to the marine ecosystem and Rhode Island communities,” the legal paperwork states. 

Another plaintiff is Responsible Offshore Development Alliance, a D.C. nonprofit representing the fishing industry.  

In 2022, RODA filed a federal lawsuit against Interior, BOEM and others, alleging they had violated numerous environmental protection statutes in approving Vineyard Wind 1, another wind project off the southern New England coast. 

The judge hearing Case 1:22-cv-11172 dismissed RODA’s complaint against Vineyard in October, and RODA in December filed an appeal.  

Like South Fork, Vineyard 1 is nearing completion. 

RODA told NetZero Insider in mid-2023 that start or even completion of construction does not render these types of challenges moot — if the complainants win their case, a judge still could order redress ranging right up to halting construction or ceasing operation. 

South Fork Wind is a smaller, 12-turbine project with a nameplate capacity of 132 MW. It fed its first electricity to the New York grid Dec. 6 and reported Jan. 18 that the sixth turbine had begun generating power. 

Revolution Wind has a nameplate capacity of 704 MW — 300 MW designated for Connecticut and 404 MW for Rhode Island. Offshore components are being fabricated, construction of onshore electrical infrastructure is underway and offshore construction is planned to begin later this year. 

(See related NetZero Insider coverage: Lawsuit Against Vineyard Wind over Threat to Whales Tossed; Judge Dismisses Groundwater Lawsuit Against South Fork Wind; Lawsuits Mount Over NJ OSW Projects as Opposition Digs In; Opponents to NJ OSW Project Sue BOEM to Stop Project.) 

New England States Delay Offshore Wind Solicitations

Connecticut, Massachusetts and Rhode Island have agreed to delay their coordinated offshore wind solicitations by about two months to give time for additional certainty around Inflation Reduction Act (IRA) federal tax credits.

The delay will push the due date for bids from Jan. 31 to March 27, with projects now set to be selected by Aug. 7.

“Extending the schedule for our current solicitation creates additional time for developers to react to the possibility of further guidance from the IRS regarding key tax credits available to offshore wind projects,” Massachusetts Department of Energy Resources (DOER) external affairs manager Lauren Diggin said in a statement.

“We know the importance of capturing all available savings for Massachusetts customers, and federal tax credits are essential to lowering the price of offshore wind for our ratepayers and improving project viability for offshore wind developers,” Diggin added.

In November, the Treasury Department released a notice of proposed rulemaking (NOPR) for IRA changes to the Investment Tax Credit that would increase the credits available to clean energy developers. (See Treasury Department NOPR Seeks to Clarify IRA’s ITC Rules.)

Comments on the NOPR are due Jan. 22, with a public hearing scheduled for Feb. 20. Massachusetts is working with other states to submit comments on the proposed regulations, the state’s Department of Energy Resources (DOER) wrote in its notice of the delay.

Delaying the solicitation “is crucial to encourage the most cost-effective bids for the benefit of Massachusetts ratepayers,” the DOER wrote.

The delay will affect both single- and multi-state bids. Connecticut, Massachusetts and Rhode Island agreed in the fall to coordinate their offshore wind solicitations to leverage their collective buying power and regional supply chains. (See Mass., RI, Conn. Sign Coordination Agreement for OSW Procurement.)

The two-month delay to get more information on the ITC also could provide perspective on the trajectory of inflation and interest rates.

While the procurements will allow for indexed bids to account for unforeseen changes to interest rates or inflation, some in the region have expressed concern that soliciting bids amid continued macroeconomic pressures could result in more expensive projects.

“Bidding a lot of megawatts while inflation is still raging risks resulting in inflated prices that consumers will pay,” Massachusetts state Sen. Mike Barrett (D), co-chair of the legislature’s Joint Committee on Telecommunications, Utilities and Energy, told NetZero Insider in an interview in early January. “If you wait six months and the Federal Reserve has lowered interest rates three or four times, you are then looking out on a vastly altered set of expectations.”

Supreme Court Hears Oral Arguments on Overturning Chevron

The Supreme Court heard more than three hours of oral arguments Jan. 17 in a case that conservatives hope will reduce the authority of federal regulatory agencies and that the Biden administration warned could cause a “convulsive shock to the legal system.”

At stake is the Chevron doctrine, the result of a 1984 Supreme Court ruling (Chevron U.S.A. v. Natural Resources Defense Council) in which the court set out a two-step process for judicial review of administrative actions: The court must first decide if Congress had spoken on the issue. If so, its intent must be followed. If the statute’s meaning is unclear, and the agency action was reasonable, the court should defer to the agency rather than imposing its preference. 

The challenge — Relentless, Inc., v. the Department of Commerce and Loper Bright Enterprises v. Gina Raimondo, Secretary of Commerce — asks the court to overturn a Commerce Department rule requiring herring fishermen to pay for monitors hired to enforce rules against overfishing.  

The question presented to the court is whether it “should overrule Chevron or at least clarify that statutory silence concerning controversial powers expressly but narrowly granted elsewhere in the statute does not constitute an ambiguity requiring deference to the agency.” 

It’s clear that at least some of the court’s conservative majority want to narrow, if not reverse Chevron 

Justice Neil Gorsuch urged his colleagues to take action in a 2022 dissent, writing that Chevron “deserves a tombstone no one can miss.” (Ironically, Gorsuch’s mother, Anne, headed EPA during the Reagan administration, when Chevron was handed down — a ruling that upheld the agency’s relaxation of pollution rules.) 

The Biden administration says Chevron is a “bedrock principle of administrative law,” having been cited by federal courts more than 18,000 times, including more than 70 Supreme Court rulings. Supporters, including the Natural Resources Defense Council, say it is needed to ensure the more than 650 federal judges do not issue conflicting rulings that would prevent industry from having regulatory certainty. 

Attorney Roman Martinez, who argued on behalf of fishing company Relentless Inc., contended that Chevron conflicts with the Constitution’s directive that judges “apply their own independent judgment” and eliminates a needed check on executive power. Chevron opponents say it undermines regulatory certainty because it allows agencies to change policies with new administrations. 

Much of the arguments revolved around the practical impact of overturning Chevron. Martinez argued that the doctrine of stare decisis would prevent a flood of relitigation for cases that were settled using the Chevron doctrine.  

Justice Amy Coney Barrett asked whether that would really be the case. 

“So, isn’t it inviting a flood of litigation even if for the moment those holdings stay intact?” she asked. 

Any such arguments would have to overcome the stare decisis test, which would mean showing the agency is “really wrong” and the issue “really practically important,” said Martinez. 

Martinez said the court could revert to the Skidmore standard, which allows a federal court to confer greater or lesser deference based on the agency’s ability to support its position. “We would be very comfortable with Skidmore,” he said. 

But Justice Elena Kagan dismissed “the idea that Skidmore is going to be a backup once you get rid of Chevron.” 

Skidmore has always been nothing,” she said. 

Drug or Dietary Supplement?

Kagan asked Martinez about a couple of examples from Chevron cases in the past, such as whether a new product meant to promote healthy cholesterol levels is a drug or a dietary supplement. 

Martinez said it would depend on the understanding of the text in the relevant statute — a legal question for the courts.  

If the law is ambiguous on that question, should the court make the call without deference to the regulator? Kagan asked. 

“There are going to be hard questions, but I think the court would bring all the traditional tools of construction to bear,” Martinez said. 

Courts are very rarely in the position of having to overturn a decision where an agency thinks the law means one thing, but the court says another, Kagan said. 

“Sometimes there’s a gap. Sometimes there’s a genuine ambiguity. … In that case, I would rather have people at [Health and Human Services] telling me whether this new product was a dietary supplement or a drug.” 

Gorsuch acknowledged that Kagan’s examples were difficult legal questions. 

“One option would be to say it’s ambiguous and, therefore, the agency always wins,” Gorsuch said. “That’s what I understood Chevron to mean, at least coming in here today.” 

Gorsuch and Martinez then got into a back and forth about how regulations can go through some major changes depending on which party is in the White House. 

Chevron really is a reliance-destroying doctrine,” Martinez said. “Imagine if you’re a person or a regulated entity and you’re trying to figure out what the law is. You should be able to rely on the best interpretation of the law and not have to, you know, check the [Code of Federal Regulations] every couple years to see if the law has somehow changed, even though Congress hasn’t acted.” 

Shock to the System

Solicitor General Elizabeth Prelogar said that overturning Chevron would be a shock to the system. 

“The Chevron framework is a bedrock principle of administrative law with deep roots in this court’s jurisprudence,” Prelogar said. “Overruling a precedent is never a small matter, but overruling a precedent as foundational as Chevron should require a truly extraordinary justification, and petitioners don’t have one.” 

Gorsuch, however, said Chevron can lead to plenty of instability. 

“Each new administration can come in and undo the work of a prior one,” Gorsuch said. “[The rules are] all reasonable,” he joked, prompting laughter. “I mean, my goodness, the American people elect them.” 

Prelogar argued that such instances are rare. 

“Agencies themselves build on those regulations as a foundation,” Prelogar said. “There’s no evidence that agencies are out there flip-flopping left and right or doing so on a whim.” 

Justice Ketanji Brown Jackson said that such changes are inherent in the democratic form of government, where presidents are elected based in part on voters’ preferred policy determinations. 

“I guess my concern is, I suppose judicial policymaking is very stable, but precisely because we are not accountable to the people and have lifetime appointments,” Jackson said. “So, if we have gaps and ambiguities in statutes and the judiciary is coming in to fill them, I suppose we would have a … separation of powers concern related to judicial policymaking.” 

Chief Justice John Roberts asked Martinez how pertinent the Chevron issue was because the Supreme Court rarely uses the precedent in its opinions, having last done so in 2016. 

Martinez said the lower courts use it and that the two fishery cases show the main issue with its application. 

“They’re essentially getting to a point where they don’t really have to figure out the best answer. … Instead of asking what does the statute mean, they can ask a different threshold question, which is, is this statute ambiguous enough that we should just, you know, let the agency do the work for us?” Martinez said. 

Conflicting Rulings

The challenge drew more than 70 friend-of-the-court briefs, mostly from conservative-leaning organizations. The New York Times reported this week that the lawyers representing one set of plaintiffs, who are working pro bono, also work for Americans for Prosperity, an anti-regulatory group funded by Charles Koch, the chairman of Koch Industries. 

In its amicus brief, the NRDC noted that it supports Chevron even though it was the losing plaintiff in the case that produced the precedent.  

The cases that produced Chevron stemmed from 1977 Clean Air Act amendments that required large new stationary sources located in the nation’s most polluted areas to use the most stringent emission controls.  

In 1980, EPA issued a regulation that applied these requirements whenever a large new industrial unit, such as a boiler or blast furnace, was added. Under Anne Gorsuch, EPA reversed its position and allowed states to avoid the requirements by redefining “source” as an entire industrial plant. 

The change, which became known as the “bubble concept,” meant that most large new industrial projects were exempt from the new requirements. 

The D.C. Circuit Court of Appeals ruled three times on the matter, with two panels reaching opposite conclusions about the “bubble concept” before the court, in an opinion by Ruth Bader Ginsburg, overturned the EPA rule. The Supreme Court overruled the Ginsburg ruling, holding that EPA’s plant-wide definition of the term “source” was a “permissible construction of the statute.” 

“NRDC could well win more cases if Chevron is overruled,” the group wrote the court. “After all, NRDC challenges more agency actions than we defend, and agency interpretations generally fare better under Chevron than they do without it.” 

LS Power Purchasing 810-MW Combined Cycle Generator in Pa.

LS Power has entered into an agreement with Platinum Equity to purchase the 810-MW gas-fired Hunterstown Generating Station in Adams County, Pa.

“Hunterstown will join LS Power’s fleet of flexible gas-fired generation, a portfolio of assets with the dynamic ramping attributes critical to a successful clean energy transition,” LS Power Generation President Nathan Hanson said Jan. 16 in an announcement of the transaction, which is expected to close in the second quarter of this year.

Located in PJM’s Met-Ed region, the combined cycle generator is configured with three combustion turbines and a steam turbine. LS Power could not be reached for comment.

LS Power CEO Paul Segal said natural gas generators will continue to be necessary to maintain grid reliability as demand accelerates.

“In order to decarbonize the electric grid in a reliable, affordable and responsible manner, we will need to continue utilizing efficient, flexible gas-fired generation, for which our fleet is well positioned, to help accelerate the clean energy transition by managing the intermittency of renewables,” Segal said.

In a separate announcement of the deal, Platinum co-President Louis Samson said the facility has been a strong source of revenue for the private equity firm. Platinum acquired Hunterstown from NRG Energy in 2018 for $520 million.

“Hunterstown is an outstanding asset that has benefited from meaningful investment under our watch and has performed well operationally during our ownership,” Samson said.

The financial details of the transaction were not disclosed in either company’s announcement.

[Editor’s Note: An earlier version of this article included a stock photo that was not the Hunterstown plant.]