Search
`
November 16, 2024

Posted on

BOEM Sets Central Atlantic OSW Auction for August

The federal government will auction two lease areas along the Central Atlantic coast for wind energy projects with a potential of up to 6.3 GW of emissions-free power generation. 

The June 28 announcement by the Bureau of Ocean Energy Management had been expected, and the prospect has drawn interest — 17 companies have been qualified to participate in the Aug. 14 auction. 

This auction is the first in a series of a dozen offshore wind lease sales tentatively scheduled by BOEM through the end of 2028. Next up are a Gulf of Mexico wind energy auction targeted for September and auctions in the Gulf of Maine and off the coast of Oregon targeted for October. 

BOEM’s Central Atlantic region — from Delaware to North Carolina — includes the largest U.S. wind farm announced to date: Dominion’s 2.6-GW Coastal Virginia Offshore Wind, now under construction.  

But planning for additional development has run into conflict due to concerns that massive wind turbines would be incompatible with military and NASA operations in the area. 

BOEM announced eight possible wind areas totaling 1.7 million acres in November 2022. That was winnowed down to three, two of which will be offered in this auction: A-2 (101,433 acres off the mouth of Delaware Bay) and C-1 (176,505 areas off the mouth of Chesapeake Bay).  

The third, Area B-1 (78,285 acres off Ocean City, the only one of the three off the Maryland coast), may be offered in a future auction. 

This has limited the options for Maryland as it tries to reach its goal of 8.5 GW of offshore wind installed by 2031.  

The state lost Skipjack Wind from its portfolio in January, after Ørsted decided it would not proceed to construction under the existing offtake agreement. In May, the state allowed the one offshore wind developer still under contract, US Wind, to seek increased compensation for its projects. 

In December, after it concluded it could not offer B-1 at auction, BOEM committed to helping Maryland reach its goals. The two formalized that agreement with a memorandum of understanding June 7. 

Trade group Oceantic Network welcomed the June 28 auction announcement but said additional seabed acreage for offshore wind development is critical for the region and for Maryland in particular: “We encourage BOEM and Maryland to continue their work in identifying new areas to help meet regional targets,” CEO Liz Burdock said in a prepared statement. 

The Central Atlantic auction announcement comes amid a regulatory transition for BOEM: Its new Renewable Energy Modernization Rule will take effect July 15, by which time the terms of the auction already will have been set. 

Before the Central Atlantic auction takes place, details such as timing of lease terms and formulas for calculating operating fees will be revised according to the new rule. 

Posted on

Bp Says It is Still Evaluating Beacon Wind

Oil supermajor bp said it is still evaluating its options for Beacon Wind, the offshore wind plan it withdrew from New York’s renewable development queue early this year. 

Reuters reported June 27 that CEO Murray Auchincloss had taken steps to refocus bp on oil and gas, pausing new offshore wind development and instituting a hiring freeze. 

It was a sharp reversal from the transition away from fossil fuels begun by his predecessor, Reuters said. And it followed a decision by the subsidiary of another oil supermajor, Shell, to divest its 50% share of the SouthCoast Wind proposal off the New England coast. 

NetZero Insider asked bp about the impact of Auchincloss’ decision on its proposals in New York: Beacon Wind, a two-phase wind farm on a 128,811-acre tract off the southeast end of Long Island, and the Astoria Gateway for Renewable Energy, a converter station for the power generated by Beacon.  

The Gateway would be built on the northwest end of Long Island, in a New York City neighborhood where a gas turbine peaker plant once stood. 

A U.S.-based bp spokesperson indicated no decision has been made on the New York plans: “We are pursuing a disciplined, value-driven development approach to the Beacon Wind and Astoria Gateway for Renewable Energy projects, which includes taking the necessary time to fully evaluate the initial design plans. This will enable us to continue advancing the developments and deliver the highest value to local communities and bp.” 

The company website lists offshore wind plans in Germany, Japan, South Korea, the United Kingdom and the U.S., Beacon.

Beacon Wind was a product of the 50-50 partnership between bp and Equinor, the Norwegian oil and gas producer making a hard push into renewables. 

The two had secured a contract from New York for the 1,230-MW Beacon Wind 1 in New York’s 2020 solicitation and unsuccessfully bid the 1,360-MW Beacon Wind 2 into New York’s 2022 solicitation. 

Beacon Wind 1 became one of the many offshore wind casualties in 2023 and early 2024, when the majority of projects along the Northeast coast were canceled outright or canceled offtake agreements. Amid soaring costs, it had become financially untenable to proceed to construction with revenue agreements locked in years earlier. 

Equinor and bp also held New York contracts for Empire Wind 1 and 2, and decided to cancel them, as well. 

Amid the fallout, the two companies dissolved their partnership. 

As part of the split, Beacon and Astoria went to bp. Empire went to Equinor, which continued to actively develop the proposal. 

New York recently awarded Empire Wind 1 a new contract at a much higher strike price. Equinor expects to “mature” Empire Wind 2 and rebid it into a future solicitation. 

After the split, Equinor also took sole ownership of the partners’ lease of the South Brooklyn Marine Terminal. It is now converting the site to an offshore wind hub for Empire and for future projects other companies envision off the Northeast coast. The contractor, Skanska, has said the contract is valued at $861 million. 

Posted on

Supreme Court Ends Chevron Deference to Administrative Agencies

The U.S. Supreme Court on June 28 overturned the doctrine of deference to federal agencies in interpreting statutes when issuing rules, ending 40 years of legal precedent and putting into question numerous existing agency rules, including those from FERC.

In a 6-3 decision, with Chief Justice John Roberts writing the majority opinion, the court said that the doctrine, known as Chevron deference after the 1984 case Chevron v. Natural Resources Defense Council, cannot be squared with the Administrative Procedure Act (APA), in which Congress said that the reviewing court — not the administrative agency in a case — is to “decide all relevant questions of law.”

“Chevron cannot be reconciled with the APA by presuming that statutory ambiguities are implicit delegations to agencies,” the court said. “That presumption does not approximate reality. A statutory ambiguity does not necessarily reflect a congressional intent that an agency, as opposed to a court, resolve the resulting interpretive question. Many or perhaps most statutory ambiguities may be unintentional.”

The ruling came in the case of Loper Bright Enterprises v. Raimondo, which dealt with requirements from the Department of Commerce that commercial herring fishers pay for federal employees on their ships to monitor their catch to prevent overfishing. (See Supreme Court Hears Oral Arguments on Overturning Chevron.)

The department’s National Marine Fisheries Service (NMFS) based its rule on the Magnuson-Stevens Fishery Conservation and Management Act of 1976. Loper Bright Enterprises, a New Jersey-based herring fishing company operating off New England, challenged the agency’s authority under the law to issue such a rule, arguing that the statute’s wording was ambiguous.

Under Chevron, if congressional intent in the wording of a law was ambiguous, courts would defer to agencies’ rules as long as they found they had reasonably interpreted Congress’ intent.

While Magnuson-Stevens explicitly authorized fees on industry for federal monitoring of foreign and Pacific Ocean fisheries, it did not do so for those in the Atlantic Ocean. The D.C. Circuit Court of Appeals found in favor of NMFS in 2022 under Chevron.

But the Supreme Court said Chevron’s presumption is misguided because agencies do not have special competence in resolving statutory ambiguities; courts do.

“Even when an ambiguity happens to implicate a technical matter, it does not follow that Congress has taken the power to authoritatively interpret the statute from the courts and given it to the agency,” the court said. “Congress expects courts to handle technical statutory questions, and courts did so without issue in agency cases before Chevron.”

Until Chevron, courts would only defer to agencies’ expertise for “fact-bound determinations” that did not involve statutory interpretation. When the APA was enacted in 1946, Congress specifically said that when agency actions are appealed, “the reviewing court shall decide all relevant questions law,” without any deferential standard for courts to use.

Thus, Chevron requires a court to ignore, not follow, “the reading the court would have reached” had it exercised its independent judgment as required by the APA, the Supreme Court said.

When it comes to deferring to an agency’s technical expertise, Roberts wrote that it does not follow that Congress has taken the power to authoritatively interpret the relevant statute from the courts and given it to the agency. Congress expects courts to handle technical statutory questions.

“Courts, after all, do not decide such questions blindly,” Roberts said. “The parties and amici in such cases are steeped in the subject matter, and reviewing courts have the benefit of their perspectives. In an agency case in particular, the court will go about its task with the agency’s ‘body of experience and informed judgment,’ among other information, at its disposal.”

The court also said that stare decisis is overcome because Chevron has proved fundamentally misguided by reshaping judicial review of agency action without grappling with the APA. “Chevron was a judicial invention that required judges to disregard their statutory duties.”

Justices Clarence Thomas and Neil Gorsuch wrote individual concurring opinions.

Thomas joined the majority’s opinion in full, but he wrote “separately to underscore a more fundamental problem: Chevron deference also violates our Constitution’s separation of powers. … It curbs the judicial power afforded to courts, and simultaneously expands agencies’ executive power beyond constitutional limits.”

“Today, the court places a tombstone on Chevron no one can miss,” Gorsuch wrote. “In doing so, the court returns judges to interpretive rules that have guided federal courts since the nation’s founding.”

Liberal Justices Dissent

Justice Elena Kagan wrote the dissenting opinion, on which she was joined by Justices Sonia Sotomayor and Ketanji Brown Jackson.

Chevron was a “cornerstone of administrative law” for 40 years, Kagan wrote. If Congress’ intent was clear in the law, that was how the court based its decision, and the agency’s view made no difference. The doctrine covered the situations when Congress left an ambiguity or gap in the law.

“The answer Chevron gives is that it should usually be the agency, within the bounds of reasonableness,” Kagan said. “That rule has formed the backdrop against which Congress, courts and agencies — as well as regulated parties and the public — all have operated for decades. It has been applied in thousands of judicial decisions. It has become part of the warp and woof of modern government, supporting regulatory efforts of all kinds — to name a few, keeping air and water clean, food and drugs safe, and financial markets honest.”

Congress cannot write perfectly complete regulatory statutes, Kagan said. “It knows that those statutes will inevitably contain ambiguities that some other actor will have to resolve, and gaps that some other actor will have to fill. And it would usually prefer that actor to be the responsible agency, not a court.”

Agencies have scientific and technical subject matter expertise that courts lack, and some decisions demand a detailed understanding of interdependent regulatory programs that agencies know “inside-out,” Kagan said.

“In one fell swoop, the majority today gives itself exclusive power over every open issue — no matter how expertise-driven or policy-laden — involving the meaning of regulatory law,” Kagan said. “As if it did not have enough on its plate, the majority turns itself into the country’s administrative czar.”

Reactions to the Decision

It is unclear how much the end of Chevron will impact FERC, but at the Energy Bar Association’s meeting in April, the general counsels for the commission and the Department of Energy both argued they would be able to defend their regulations without it. (See Energy Lawyers Debate the Impact of Losing Chevron Deference.)

Republicans and some industry groups welcomed the court’s decision, while Democrats and clean energy groups decried the decision.

“In overruling Chevron, the Trump MAGA Supreme Court has once again sided with powerful special interests and giant corporations against the middle class and American families,” Senate Majority Leader Chuck Schumer (D-N.Y.) said. “Their headlong rush to overturn 40 years of precedent and impose their own radical views is appalling.”

Minority Leader Mitch McConnell (R-Ky.) said the decision makes clear that no federal agency can co-opt Congress’ authority to make the law.

“Congress’ willingness to outsource legislative responsibilities to the most unaccountable corners of the executive branch weakened both its own Article I powers and the link between the American people and a responsive federal government,” McConnell said. “The days of federal agencies filling in the legislative blanks are rightly over.”

U.S. Chamber of Commerce CEO Suzanne Clark said that the decision will help create a more predictable and stable regulatory environment.

“The Supreme Court’s previous deference rule allowed each new presidential administration to advance their political agendas through flip-flopping regulations and not provide consistent rules of the road for businesses to navigate, plan and invest in the future,” Clark said. “The Chamber will continue to urge courts to faithfully interpret statutes that govern federal agencies and to ensure federal agencies act in a reasonable and lawful manner.”

Advanced Energy United CEO Heather O’Neill argued just the opposite, saying it was incumbent on Congress to ensure the decision does not undo decades of progress in the energy transition.

“While the march to clean energy will continue, today’s Supreme Court decision to radically overturn 40 years of judicial precedent is a blow for effective and efficient government,” she said. “Technology and regulation go hand-in-hand in making America a prosperous, safe and clean place in which to live. Overturning the so-called Chevron doctrine will invite chaos, inefficiency and added cost to everyday people.”

White House Press Secretary Karine Jean-Pierre said the ruling is “another deeply troubling decision that takes our country backwards.”

President Joe Biden “has directed his legal team to work with the Department of Justice and other agency counsel to review today’s decision carefully and ensure that our administration is doing everything we can to continue to deploy the extraordinary expertise of the federal workforce to keep Americans safe and ensure communities thrive and prosper,” she said.

Posted on

FERC Orders Further Cold Weather Standard Modifications

NERC will go back to work on another revision to its most recent cold weather standard after FERC on June 27 accepted EOP-012-2 (Extreme cold weather preparedness and operations) while ordering additional “targeted modifications” to be completed by next March (RD24-5). 

The approval of EOP-012-2 brings to an end what FERC Chair Willie Phillips called the “second round on this particular standard” at the commission’s monthly open meeting. Phillips commended NERC for its efforts to improve the grid’s resilience to cold weather impacts while observing that there is still a lot of work left to achieve the goals in the commission’s cold weather preparedness dashboard. 

“The standard … has helped close some ongoing reliability gaps and address many of the outstanding commission recommendations on winterization,” Phillips said. “Nevertheless, I would be remiss not to note that there are still changes that need to be made to help the standard reach its full potential.” 

NERC’s Board of Trustees approved EOP-012-2 in February. The standard’s 12-month development period began after FERC accepted its predecessor EOP-012-1 last year. 

The first version, which has yet to take effect, outlined several measures for generator owners to implement to prevent their units from freezing during extreme cold weather events, along with situations in which GOs would need to submit corrective action plans. However, FERC said the standard should be further revised to clarify language and enhance some of its requirements. 

EOP-012-2 underwent three formal comment and ballot periods before finally receiving the blessing of industry in January. (See Industry Approves New Cold Weather Standard in Final Vote.) NERC’s Board of Trustees had warned that it might have to step in to approve the standard if it looked like the ERO might miss FERC’s deadline — an authority it possesses under section 321 of NERC’s Rules of Procedure — but the successful ballot averted this possibility. 

FERC called the new standard an “improvement” to EOP-012-1 but said “some elements … are not fully responsive to the commission’s February 2023 order.” While it did not agree with the ISO/RTO Council’s request to remand EOP-012-2 to NERC for further revisions — which FERC observed would leave EOP-012-1 to go into effect Oct. 1 “despite its ambiguities and other identified issues” — the commission did identify some remaining shortcomings that still need to be overcome. 

FERC’s order directs NERC to submit another revised standard within nine months that: 

    • ensures that the standard’s generator cold weather constraint declaration criteria “are objective and sufficiently detailed” so that entities understand the requirements. NERC is to remove phrases such as “reasonable [or] unreasonable costs” and “good business practices” in favor of “objective, unambiguous and auditable terms.” 
    • allows NERC to evaluate and confirm the validity of cold weather constraints invoked by generator owners “to ensure that such declaration cannot be used to avoid” compliance with the standard or corrective action plans. 
    • shortens and clarify implementation timelines and deadlines for corrective action plans. 
    • ensures that any extension of a corrective action plan deadline beyond the maximum time frame provided by the standard is preapproved by NERC, and that GOs inform relevant entities of resulting extreme cold weather operating limits. 
    • implements more frequent reviews of generator cold weather constraint declarations to ensure the declaration is still valid. 

Noting the urgency FERC has “repeatedly expressed” for implementing cold weather standards, and the fact that the above directives are meant to “fully address issues identified in the commission’s prior February 2023 order,” FERC mandated that the ERO complete revisions to the standard within nine months. 

In a statement, NERC said it “appreciates FERC’s focus on reliability matters and will continue to work toward assuring the reliability and security” of the electric grid. 

Posted on

RI Sets 600-MW Energy Storage Target

Rhode Island is the latest state to set targets for energy storage system construction.

Gov. Dan McKee (D) signed the Energy Storage Systems Act into law June 26. It directs the state Public Utilities Commission to adopt a framework for adoption of tariffs to apply to grid-connected energy storage systems, and the Rhode Island Infrastructure Bank to develop programs and distribute money to help achieve the goals of the act.

It sets a series of targets for installation of storage over the next decade: 90 MW installed by Dec. 31, 2026; 195 MW by the end of 2028; and 600 MW by the end of 2033.

On a per-capita basis, the numbers are much larger than they might appear.

New York’s target is 6 GW — the most of any state, and 10 times higher than Rhode Island’s new target. But New York has nearly 18 times more residents than Rhode Island.

Rhode Island also has the lowest electricity consumption per capita of any state, according to the U.S. Energy Information Administration.

The legislation (2024-S 2499A, 2024-H 7811aa) cleared both houses of the General Assembly by wide margins.

“This bill sets concrete goals and action plans to build a resilient grid that can accommodate the green energy transition that is happening now,” Senate Judiciary Committee Chair Dawn Euer (D) said in a June 13 press release. “This is just one of many actions we will need to meet our diverse energy goals and ensure that Rhode Island keeps its commitment to a carbon-neutral future.”

Advanced Energy United cheered McKee’s signature.

“Energy storage is flexible, reliable, affordable and will be a game changer for Rhode Island’s power grid,” said Kat Burnham, the group’s Rhode Island lead. “Investing in energy storage technologies will drive economic development and job creation in the clean energy sector.”

In its March 2024 energy storage policy update, law firm Morgan Lewis listed 11 states with codified energy storage targets: California, Oregon, Nevada, Illinois, Virginia, New Jersey, New York, Connecticut, Massachusetts, Maine and Maryland.

Some states have a long way to go to reach their goals. The U.S. Energy Information Administration reported that as of November 2023, there were three categories: California (7,302 MW), Texas (3,167 MW) and the other 48 states (3,500 MW combined).

But EIA predicted 2024 would be a busy year for storage installation, if all plans in place come together on schedule.

Wood Mackenzie earlier this month reported 1,265 MW of storage was deployed nationwide in the first quarter of 2024, much more than the first quarter of 2023 but much less than the fourth quarter of 2023.

Rhode Island’s first utility-scale battery energy storage — a 3 MW system serving the Pascoag Utility District — went online July 7, 2022.

Posted on

FERC Accepts NERC ROP Changes, Drops Assessment Proposal

FERC this week accepted a set of proposed changes to NERC’s Rules of Procedure to allow the ERO to register owners and operators of inverter-based resources while ordering a compliance filing clarifying whether its proposal will ensure that all IBRs are registered (RR24-2). 

In addition, the commission withdrew an open proceeding to shorten the ERO’s timeline for its performance assessments from five to three years (RM21-12). 

The ROP changes are the first step in NERC’s three-year plan to satisfy a November 2022 order in which FERC directed the ERO to register IBRs that are not currently required to register with it but that are connected to the grid and, “in the aggregate, have a material impact” on reliable operation. FERC approved NERC’s work plan in May 2023. 

NERC submitted the ROP changes to FERC in March, requesting an expedited review period of 60 days. According to FERC’s order, NERC must finish modifying its registration processes by 12 months after the commission approved its work plan, identify owners and operators of relevant IBRs within 24 months and register them no later than 36 months. 

The changes apply to Appendices 2, 5A and 5B of NERC’s ROP, with the most important updates coming to Appendix 5B. These changes will create a new category of generator owners, Category 2 GOs, comprising entities that own or maintain IBRs that “either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.” 

A similar new category, Category 2 GOPs, will be created for generator operators that operate such equipment. Revisions to Appendices 2 and 5A were proposed to conform to this language. 

In its order, FERC said it was generally satisfied with NERC’s proposal. However, the commission observed that the ROP revisions specifically referred to “inverter-based generating resources,” which might be construed to exclude battery energy storage systems because they store energy rather than generate it. As a result, FERC directed NERC to submit a compliance filing within 60 days explaining whether the ROP changes would apply to owners and operators of BESS resources and, if not, how the ERO plans to include these and any other IBRs that could be excluded. 

In a webinar last month, NERC Vice President of Regulatory Oversight Howard Gugel said the ERO was currently using data from the U.S. Energy Information Administration and other sources to identify IBR candidates for registration. With FERC’s approval granted, NERC can also send a request for information on additional applicable resources to registered entities, starting with balancing authorities and transmission owners. 

Assessment Proposals Faced ERO Skepticism

FERC’s decision to drop its proposal for shortening NERC’s performance assessment timeline comes three years after the commission first floated the idea in 2021.  

At the time, the commission, under Chair James Danly, said a quicker turnaround would “provide better continuity” in FERC’s oversight of the ERO Enterprise and its ability to identify potential performance improvements more quickly. 

The 2021 Notice of Proposed Rulemaking also suggested allowing FERC to request additional information beyond the statutory requirements of the performance assessment; NERC would have to honor any such requests submitted at least 90 days before the assessment’s publication date. In addition, the NOPR would have required the ERO to solicit recommendations from industry stakeholders for improvements to its “operations, activities, oversight and procedures.” 

NERC and the regional entities objected to the proposals despite recognizing the commission’s interest in “effective and efficient communication, coordination and feedback objectives.” (See ERO Enterprise Resists FERC’s Assessment Proposal.) The ERO said a three-year assessment cycle might not allow it to conduct the same level of review that it currently does in its performance assessments.  

NERC also pointed out that it already posts its draft performance assessments for public comment three months prior to submission, which should give stakeholders enough time to submit feedback. Regarding FERC’s proposal for requesting additional specific information, the ERO said it was open to such requests but 90 days was not sufficient notice. 

FERC’s June 27 order acknowledged the ERO’s concerns and concluded that “modifying the periodicity or procedural requirements for the ERO performance assessments is [not] an efficient use of ERO or commission resources.” The commission emphasized that withdrawing the NOPR and terminating the proceeding was an exercise of its own discretion. 

In a statement, NERC acknowledged the end of the proceeding and noted that it is currently preparing its assessment for the 2019-2023 period, a draft of which was posted for comment in April. (See NERC Makes Case for Recertification in Performance Assessment.) 

Posted on

Supreme Court Grants Pause of EPA Good Neighbor Rule

In a 5-4 decision on June 27, the U.S. Supreme Court issued an emergency pause on the implementation of EPA’s “Good Neighbor Plan,” which is aimed at reducing ozone pollution, a key component in the creation of smog.

The plan stems from a 2015 update of ozone air quality standards. Based on these tightened standards, EPA ruled in 2023 that 23 states had not submitted adequate plans to prevent harmful levels of pollution flowing to downwind states.

Lower courts already had temporarily paused the plan’s implementation in 12 states, and the Supreme Court sided with a coalition of Republican-led states, along with industry groups, in its ruling that the EPA likely has not justified the applicability of its plan to a smaller subset of states than initially proposed. (See Supreme Court Skeptical of EPA’s Good Neighbor Plan.)

The legal challengers included Ohio, Indiana and West Virginia, along with Kinder Morgan, the American Forest and Paper Association, and U.S. Steel.

The opponents contended that the emissions-prevention measures required by the plan are contingent on the states included in the plan, and therefore the exemption of one or more of the states invalidates the cost-benefit analysis the rule was based on.

Responding to this argument, EPA said the plan’s requirements are independent of the other states included.

Justice Neil Gorsuch — joined by Chief Justice John Roberts and Justices Brett Kavanaugh, Clarence Thomas and Samuel Alito — wrote that a stay on the plan is warranted because its opponents “are likely to prevail on their argument that EPA’s final rule was not ‘reasonably explained.’”

“EPA did not address whether or why the same emissions-control measures it mandated would continue to further the [Federal Implementation Plan’s] stated purpose of maximizing cost-effective air-quality improvement if fewer states remained in the plan,” Gorsuch wrote, adding that the 12 states already excluded from the plan account for most of its targeted emissions.

Justice Amy Coney Barrett broke with her fellow conservatives on the court to author the dissent, supported by the court’s three liberal justices. She said the majority based its decision on “an underdeveloped theory that is unlikely to succeed on the merits.”

Barrett noted that none of the 23 states proposed to take any action to reduce ozone emissions to comply with the 2015 regulations, and because no state has been permanently exempted from the plan, it “may yet apply to all 23 original states.”

She added that the Good Neighbor Plan does consider differences between states when establishing state-specific emissions budgets; that EPA relied on national data when setting the rule’s emissions limits; and that the agency “did not depend on the number of states in the plan.”

Fossil fuel and industry groups applauded the decision, arguing that the plan would hurt grid reliability and increase electricity costs in the affected states by driving coal plants into retirement.

“We are pleased that the court recognized the immediate and irreparable harm this rule would do to utilities and ratepayers,” Michelle Bloodworth, CEO of the coal lobbying group America’s Power, said in a statement.

Bloodworth called the rule “yet another example of EPA overreach,” and expressed her hope the courts will permanently strike down the rule.

Jim Matheson, CEO of the National Rural Electric Cooperative Association, said the decision “directly speaks to the gravity of EPA’s unlawful ozone transport rule which directly threatens the American economy and way of life.”

Meanwhile, climate and environmental advocacy groups said the court’s ruling will have major climate and public health consequences.

Conservation Law Foundation President Bradley Campbell told RTO Insider that the rule is “another example of the Supreme Court’s new majority using its ‘emergency powers’ to obstruct EPA rules it doesn’t like.”

“This is going to directly impact the health and life expectancy of communities in downwind states that historically have been overburdened by pollution,” Campbell said. “It’s clear that the new Supreme Court majority is going to use every tool at its disposal either to overturn or at least significantly delay new EPA protections and safeguards, and that’s going to result in a lot more illness and premature death.”

The decision comes as the Supreme Court appears poised to overturn or significantly roll back the Chevron doctrine, which directs courts to defer to the reasonable judgment of regulatory agencies in the absence of clear direction from Congress. (See Supreme Court Hears Oral Arguments on Overturning Chevron and Energy Lawyers Debate the Impact of Losing the Chevron Deference.)

Posted on

FERC ANOPR Seeks to Move the Ball Forward on Dynamic Line Ratings

FERC is moving forward on its examination of dynamic line ratings (DLRs), with the issuance of an Advance Notice of Proposed Rulemaking (ANOPR) on June 27 indicating the commission is considering requiring the transmission industry to adopt the technology (RM24-6). 

DLR technology uses the latest weather forecasts and monitors other conditions — such as sunlight and wind speed — to more accurately reflect transmission line ratings, allowing for more efficient power flow and reducing congestion. 

“Our success in ensuring reliability and operability of our nation’s transmission grid requires work on many fronts,” FERC Chair Willie Phillips said in a statement. “Last month, we took the major step of issuing Order No. 1920 to determine how to plan and pay for transmission facilities that our nation will need. Today, we are looking to wring efficiencies out of the grid so we can make the best and most efficient use of what we already have.” 

The ANOPR reflects public comments FERC received from a Notice of Inquiry issued in early 2022 alongside Order 881 that required transmission line ratings to reflect ambient air temperatures. (See FERC Opens Inquiry on Dynamic Line Ratings.) 

FERC will collect more information on DLRs based on specific questions it asks in the ANOPR before potentially moving forward with a proposed rule. Comments are due 90 days after the ANOPR’s publication in the Federal Register, and replies are due 30 days after that. 

Despite its earlier work, some implementation issues for DLRs still need to be worked out, Phillips said at a press conference that followed FERC’s monthly open meeting. 

“We look forward to moving as quickly as possible … to get a final rule in place,” Phillips said. “We can’t just build our way to where we need to go. We have to get as much as we can out of our existing system if we have any hope to not just reach goals, but to also serve our consumers reliably.” 

The factors that can change a line’s capacity include solar heating, cloud cover, wind speed and direction. The ANOPR asks whether hourly solar conditions should be reflected in all transmission line ratings and how to determine which lines would benefit from reflecting hourly wind conditions. 

The ANOPR had not been published as of press time. But a FERC fact sheet noted that reflecting hourly solar conditions would not require utilities to install any equipment to monitor them. But it “would go beyond the simple day/night considerations in Order No. 881 by requiring hourly forecasts of solar intensity and cloud cover events.” 

Wind conditions have the highest impact on line temperature out of any weather condition, but reflecting them does require the installation of sensors and communication equipment. “Recognizing this potential added cost, the ANOPR specifies that transmission providers could be required to reflect wind conditions in ratings only on lines that … are heavily congested and located in geographic areas with windy conditions,” FERC said. It seeks information on how congestion levels and environmental factors could identify the lines that would most benefit from better monitoring wind conditions. 

It also seeks comment on new methods for measuring congestion and other related data. 

Commissioner Allison Clements said that not implementing DLRs leaves significant benefits and cost savings on the table. 

“This has been a long time coming,” Clements said. “We first voted on DLR issues in December 2021. That’s nearly three years to move the ball forward several yards — with most of the field yet to cover. Best case, we are looking at another year for the NOPR and then a final rule, plus compliance and implementation after that. All of this emphasizes the need for good, thoughtful comments in response to this ANOPR, which sets up a promising framework.” 

LineVision, which makes the sensors that are sometimes required by DLRs, welcomed the ANOPR. 

“With demand spiking, extreme weather intensifying and increasing congestion straining overall grid capacity, today’s decision by FERC to initiate a rulemaking will help to ensure that dynamic line ratings become an even more critical tool in the toolbox to achieve a commonsense solution: squeezing all the capacity that we can out of our existing grid,” LineVision Vice President of Policy Hilary Pearson said in a statement. “We appreciate FERC’s continued leadership in advancing transmission line ratings solutions and pursuing criteria for DLR to help support just and reasonable rates.” 

Advanced Energy United also welcomed the proposal. 

“Transmission operators aren’t maximizing the potential of our power lines, leading to unnecessarily high energy costs for consumers,” Managing Director Caitlin Marquis said. “Dynamic line ratings are one of the most cost-effective tools we have for getting more out of our existing power grid infrastructure.” 

Clements’ Last Meeting

The meeting marked Clements’ last as a commissioner; her term ends June 30. 

She said she was particularly proud of the commission’s recent major orders: 1920 on long-term transmission planning and cost allocation and 2023 on generator interconnection rules. Also, she was glad to help set up the Office of Public Participation. 

“At this moment in time, when facts on the ground are changing so quickly, it is difficult to regulate at the pace necessary to keep up,” Clements said. “I urge the new commission to lean in and take a proactive approach to reliably and affordably adapting to the energy transition that is underway. Regulation will fail if it is deemed ‘ideological’ to try and skate where the puck is going. More than any time in our memory, the commission’s regulations must be nimble in the face of a changing energy system and new threats.” 

New Commissioner David Rosner sat in on the meeting, though he did not vote on any items because he had not had enough time to properly review them since being sworn in. His taking office means FERC is at no risk of losing a quorum once Clements leaves. He will soon be joined by Judy Chang and Lindsay See once they are sworn in. 

Posted on

FERC Approves Sloped Demand Curve in MISO Capacity Market

After two requests for more information and nine months, FERC has greenlit MISO’s plan to exchange its current, vertical curve for sloped demand curves in its seasonal capacity auctions (ER23-2977).

FERC said use of a downward-sloping curve in MISO should “reduce volatility in auction clearing prices, increase the stability of the capacity revenue stream over time and render capacity investments less risky, thereby encouraging greater investment and at a lower financing cost.” The commission pointed out that it has approved similar sloped curves in the PJM, NYISO and ISO-NE capacity markets.

“We find that using the proposed sloped demand curve will result in capacity price signals that reflect the marginal reliability impact of incremental capacity additions, provide better incentives for efficient resource entry and exit and, as a result, improve resource adequacy and economic efficiency across the MISO footprint,” the commission said in an order issued at its monthly open meeting June 27.

MISO CEO John Bear announced the approval during the Board of Directors’ meeting the same day in Eagan, Minn., to applause from stakeholders.

FERC addressed arguments from Midwestern transmission-dependent utilities and the Mississippi Public Service Commission that it foreclosed on the possibility for a sloped demand curve when it consistently found in previous orders that the RTO’s vertical curve was just and reasonable.

FERC said that its past orders finding the vertical curve sufficient did not mean that it would not entertain a proposal from MISO to change the design of the curve.

Prior to its approval, the commission twice said it needed more information before it could judge the plan. (See MISO’s Sloped Demand Curve Plan Draws 2nd Deficiency Letter.) Both times, the commission focused on MISO’s proposal to remove its annual price cap for auction clearing prices as part of the move to sloped demand curves. It said it required more explanation for the RTO’s proposal to eliminate the yearly cap.

The commission ultimately found that it is appropriate under the sloped demand curve for clearing prices to reach as high as four times the cost to build new generation. It said MISO is free to scrap its current annual price cap of 1.75 times the cost of new entry (CONE) for local resource zones (LRZs).

MISO has said that once it implements the sloped curves, the total annual price for an LRZ could reach as high as four times CONE, depending on whether capacity shortages occur in all four seasons of the auction. The RTO didn’t explicitly list an annual price cap in its new tariff language, telling FERC it isn’t necessary because its plan limits clearing prices to seasonal CONE values. It also said there’s only a small chance a zone would experience shortage conditions in all four seasons, and if that occurred, the more than $1,300/MW-day prices that ensue would properly reflect an “extreme” situation.

This year’s CONE value averages $330/MW-day. MISO has said its sloped demand curves won’t allow prices to automatically jump to CONE values for small capacity shortages below reserve requirements, unlike the current, unyielding vertical demand curve.

FERC agreed that sloped curves will result in a more nuanced pricing of shortages, rendering an annual price cap no longer necessary.

“Given that the sloped demand curve more accurately reflects the value of the increase or decrease in reliability of one additional (or one fewer) megawatt of capacity, under a small megawatt shortfall scenario, the auction clearing price will increase more gradually than it would with a vertical demand curve, and the capacity price will not rise to CONE unless MISO is experiencing a severe capacity shortage,” the commission reasoned.

It agreed with MISO that sloped curves will moderate pricing extremes and produce more “graduated and meaningful” price signals.

Commissioner Allison Clements wrote a concurrence to express a longstanding concern with the design of MISO’s seasonal capacity auction. She said that while downward-sloping demand curves in the auctions are a sound idea, she remains apprehensive over MISO appearing to allow sellers to compress their full annual costs into the seasonal offers they make.

Clements said that in the 2023 order accepting MISO’s seasonal auction design, the RTO’s testimony appeared to contradict its tariff language that seasonal offers may include only costs associated with providing capacity for that season. (See FERC Affirms MISO’s Seasonal Auctions, Accreditation.)

“My concern at the time was that if sellers can include their full annual costs into each and every seasonal offer, and they clear multiple seasons, they could receive in excess — potentially up to two, three or four times — their actual costs of providing capacity,” Clements wrote. “This risk is a direct result of MISO’s choice to conduct the four seasonal auctions for each delivery year simultaneously.”

Clements ended by asking MISO to consider conducting its auctions sequentially.

In a statement to RTO Insider, MISO said while offers generally are cleared on a seasonal basis in the auction, there may be “a situation where a unit clears one season but still needs to recover its full cost.” MISO noted that its Independent Market Monitor reviews all offers to make sure they’re appropriate.

“The sloped demand curve and seasonal construct are designed to work together to provide the right market signals to address the growing complexity of the system,” MISO said.

Posted on

AEP Selects Industry Veteran as Next CEO

American Electric Power, one of the nation’s largest utilities, said June 26 its Board of Directors has selected industry insider Bill Fehrman as its president and CEO, effective Aug. 1. 

Fehrman replaces Julie Sloat, who parted ways with AEP in February after just a year in the top job. Former Xcel CEO and AEP board member Ben Fowke, who has been running the company on an interim basis since then, will serve as a senior adviser during the transition. (See Interim CEO Fowke Explains AEP Leadership Change.) 

AEP’s new leader brings decades of industry experience. As infrastructure services company Centuri Holdings’ CEO, he helped launch the organization as a public company. Before that, he led Berkshire Hathaway Energy, MidAmerican Energy, PacifiCorp Energy and the Nebraska Public Power District. 

Fehrman said in a statement he was honored to join a “renowned industry leader” during the energy transition’s “pivotal time.” 

“AEP has built a strong foundation with a long history of solid operational and financial results and a focus on customers,” he said. “I see incredible potential in this company, and I look forward to working with the best-in-class team at AEP to continue delivering safe, reliable and affordable service to customers and advancing our long-term growth strategy.” 

“Bill is an accomplished leader and industry veteran with a proven ability to drive operational excellence, produce strong financial results and deliver for customers and stakeholders,” board Chair Sara Martinez Tucker said. “His expertise and unique perspectives will help AEP implement new solutions as we build the energy system of the future to power our communities.” 

AEP has 5.6 million customers in 11 states and several RTO markets. The Columbus, Ohio-based company says it plans to invest $43 billion over the next five years to make the electric grid cleaner and more reliable. It plans to reduce carbon dioxide emissions 80% from 2005 levels by 2030 and to achieve net zero by 2045.