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November 14, 2024

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.]

NERC Standards Committee Organizes for New Year

At its first meeting of 2024, NERC’s Standards Committee on Jan. 17 appointed several new members to serve on its Executive Committee for the year and moved forward on several standards projects.

The EC includes by default the chair and vice chair — Todd Bennett of Associated Electric Cooperative Inc. and Troy Brumfield of American Transmission Co., respectively — and three other SC members, each representing a different industry segment from each other or the officers. Its role, as defined in the SC’s charter, is to meet between full SC meetings “when necessary … to conduct committee business,” as well as to help set the agenda for SC meetings and “provide advice and guidance to subcommittee chairs.”

To bring the EC to its full complement, committee members voted to add Patti Metro of the National Rural Electric Cooperative Association, Terri Pyle of OGE Energy and Venona Greaff of Occidental Petroleum, who served on the EC last year.

Following the EC election, committee members voted to approve revisions to four documents affecting the standards development process. These changes affected the drafting team nomination form, drafting team reference manual and reliability standard acceptance criteria. In addition, members agreed to create a new document governing “questions for [drafting teams] to use when reviewing SAR [standard authorization request] forms and reliability standards forms.”

The changes were developed at the recommendation of NERC’s Standards Process Stakeholder Engagement Group, which the ERO’s Board of Trustees appointed in 2022 to identify ways the standards process could be made to move more quickly while still being responsive to industry concerns. Updates include clarifying language and “limiting references to the American National Standards Institute,” in keeping with recent changes to NERC’s rules of procedure. (See FERC Approves NERC Standards Process Changes.)

Standards Actions Approved

Committee members went on to approve a slate of actions related to ongoing standards projects.

First the committee agreed to accept the revised SAR for Project 2023-06 (CIP-014 risk assessment refinement). NERC began the project last year after the ERO promised FERC it would examine its Critical Infrastructure Protection (CIP) standards in light of ongoing incidents of violence against grid assets. (See NERC Says Changes Coming to Physical Security Standards.) The revised SAR defines the goal of the project as modifying the risk assessment requirements within CIP-014-3 to specify “acceptable approaches to the risk assessment.”

Next, members agreed to post proposed reliability standard BAL-007-1 (page 129 in the agenda) for a 45-day formal comment and ballot period. The standard was produced by Project 2022-03 (Energy assurance with energy-constrained resources), which is intended to require registered entities to “perform energy reliability assessments to evaluate energy assurance and develop corrective action plan(s) to address identified risks.”

Finally, the committee agreed to appoint three replacement members to the team overseeing Project 2023-04 (Modifications to CIP-003). This was the first standards item in the agenda, but Bennett agreed to move it to the end because several members did not receive the email with the proposed team members before the meeting. The new members will replace several who left the project last year, including the chair.

Feds Update Solar Development Roadmap in West

The Department of the Interior is proposing to designate 22 million acres of public land in the West as suitable for solar development. 

The roadmap announced Jan. 17 is an update of the 2012 Western Solar Plan and is intended to make permitting faster and easier. 

An estimated 700,000 acres of land for potential solar development is needed to help meet the Biden administration’s goals of a 100% clean energy grid by 2035, the U.S. Bureau of Land Management said.  

The 2012 Western Solar Plan identified areas with high solar potential and low resource conflicts in order to guide responsible solar development. It looked at land in Arizona, California, Colorado, Nevada, New Mexico and Utah. The update adds Idaho, Montana, Oregon, Washington and Wyoming.  

The draft analysis of the “Utility-Scale Solar Energy Programmatic Environmental Impact Statement” would further streamline the permitting process, steering developers toward sites with fewer potential conflicts with other land users, less environmental impact, greater access to transmission lines and higher solar potential. 

The update also reflects a dozen years of technological, societal and economic changes. 

The draft and its appendices are available on BLM’s website. Public comment will be accepted through April 18 and will help shape the Final Programmatic Environmental Impact Statement and Record of Decision. 

“This is a big deal,” acting Deputy Interior Secretary Laura Daniel-Davis told reporters during a conference call Wednesday, “and it’s the first time in more than a decade that the plan has been updated.” 

It will make permitting faster, easier and more consistent, she said. 

“Simply put, the updated Western Solar Plan will create the foundation for solar development and conservation on public land into the future,” Daniel-Davis said. 

“The proposal complements other regulatory updates in progress, including BLM’s pending Renewable Energy Rule, which will help incentivize renewable energy development on our public land” through fee reductions of up to 80%, she added. (See BLM Seeks to Slash Fees for Solar, Wind on Public Land.) 

BLM Director Tracy Stone-Manning said the clean energy portfolio on public land has been growing in the past three years, during which BLM has approved 47 renewable projects rated at 11.24 GW.  

BLM is now processing 67 clean energy projects rated at more than 37 GW, Stone-Manning said, and is in early review of more than 195 applications plus 97 site testing requests. 

She spoke also of BLM’s deep and continuing responsibility to balance the Biden administration’s economic and clean energy goals with the need for preservation of resources and respect for stakeholders. 

BLM worked with the National Renewable Energy Laboratory and Argonne National Laboratory to calculate that approximately 700,000 acres in the West would be needed to meet Biden’s clean energy goals. The proposed designation is 22 million acres, or approximately 31 times more than needed, which will provide needed flexibility. 

BLM prepared five alternatives; its preferred alternative, No. 3, would exclude areas in the 11 states that are more than 10 miles from existing or planned transmission lines carrying at least 100 kV and exclude areas that have a slope greater than 10%. 

Alternative No. 3 would exclude 140 million acres in the 11 states and invite solar applications on 22 million acres, ranging from 106,458 acres in Washington to 6.99 million acres in Nevada. 

Wash. Bill Seeks Increased Monitoring of Petroleum Sector

OLYMPIA, Wash. — A Washington bill to create a new agency to monitor activity in the state’s petroleum market details five pages of information the body would have to collect from oil companies.

That’s too much data for a new state agency to collect and digest, representatives of oil industry representatives argued during a Jan. 17 hearing of the Washington Senate’s Energy, Environment and Technology Committee to introduce Senate Bill 6052.

But environmental groups contended that an oil industry transparency law is greatly needed.

The bill sponsored by Sen. Joe Nguyen (D) would create a Division of Petroleum Market Oversight under the umbrella of the Washington Utilities and Transportation Commission. Modeled after a new California office, the proposed agency would collect a massive amount of financial and industrial data from various branches of the oil industry in the state, including five refineries and a complex supply chain.

A Senate report describing the bill outlines the scope of information to be collected from oil producers, storage facilities, middlemen and transporters. The proposed agency’s purpose is to analyze the data to ensure the public is not being gouged at the gas pump.

“It has incredibly complex reporting requirements for an agency that does not exist,” said Peter Godlewski, government affairs director at the Association of Washington Business (AWB), which opposes the bill.

The agency would have subpoena power and would confidentially refer suspected legal violations to the Washington Attorney General’s office. It would also report its observations and conclusions to the governor’s office, other state agencies and the Legislature.

“I have concerns on how you determine price-fixing,” said Sen. Drew MacEwen, the committee’s ranking Republican.

‘Sunshine for Consumers’

Gov. Jay Inslee called for the bill following the political and economic fallout from the state’s introduction of a cap-and-invest program, which went into effect last year. Critics of the program, which is administered by Washington’s Department of Ecology, have blamed it for the state having some of the highest gasoline prices in the country. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)

Inslee has challenged those critics, contending the oil industry has used confusion around the program to hike gas prices in excess of the costs to comply with the program, padding their profits. (See Inslee Challenges Cap-and-trade Role in High Wash. Gas Prices.)

Meanwhile, headed for the ballot next November is a public referendum to repeal the cap-and-invest program, against the wishes of the Democratic-controlled Legislature.

Washington’s gas prices have been among the highest in the nation since last summer, including a week as the highest. But during the Jan. 17 hearing, Nguyen cited AAA figures showing that Washington’s gas prices have been among the five highest in the nation since the 1970s for various economic and geographic reasons.

“This [bill] provides sunshine for consumers. … It makes [oil companies] show their math,” Clifford Traisman, lobbyist for Washington Conservation Action, said at the hearing. Leah Missik, senior policy manager at Climate Solutions, added that Washington needs to know what profits are earned at the different stages of the oil supply chain, from imports to the gas pump.

“Why does [the gas price] fluctuate so dramatically? … At the end of the day, we don’t know why,” said Matthew Hepner, an official with the International Brotherhood of Electrical Workers, which supports the bill.

‘Hellscape’

In opposing the bill, the Western States Petroleum Association (WSPA) and AWB expressed concerns about the complexity and scale of the proposed agency’s tasks and fears about sensitive information being leaked to the public.

“This Is highly sensitive data. If released, it will affect the market,” said Greg Hanon, who represents the WSPA, whose members include four of Washington’s five refineries. Jessica Spiegal, WSPA’s Northwest Region senior director, said: “It makes more sense to find out how Ecology got it wrong on the cap-and-trade program.”

Relying on Ecology Department calculations, Inslee and Democratic leaders said in 2021 that cap-and invest would add a few pennies per gallon. Instead, prices have been up 21 to 50 cents, depending on who’s calculating. That miscalculation is a key factor in today’s political controversy over the program.

Sen. Liz Lovelett (D) asked two AWB lobbyists at the hearing how making sensitive data public would hurt the oil companies and the market.

“It is unclear what type of hellscape this would unleash,” Lovelett said. The lobbyists said they would have to get back to her with answers.

Representatives from companies operating in the supply chain between oil refineries and gas stations opposed Nguyen’s bill because they contend some definitions in it are hazy.

Alone among the state’s refiners in not opposing the bill was bp America, which previously left the WSPA because it disagreed with the association’s opposition to some carbon-reduction measures.

Tom Wolf, a lobbyist for bp, said the company is fine with the concept behind the bill, but would like to see some tweaks to it. He also urged Washington to delay the bill for at least a year to give the state a chance to study the record of California’s program, which is only six months old.

Nguyen said his bill still needs work to address cybersecurity and confidentiality issues and clean up some of its definitions.

ISO-NE Details Resource Modeling Plans for Capacity Accreditation

ISO-NE provided stakeholders with additional detail on its plans for modeling capacity demand and resource reliability attributes as the RTO and stakeholders continued work on the resource capacity accreditation (RCA) project at the NEPOOL Reliability Committee meeting Jan. 16. 

“Improvements are required to the Resource Adequacy Assessment (RAA) used currently to calculate capacity requirements (demand) and develop resource-specific accreditation values,” said Fei Zeng, ISO-NE technical manager. 

ISO-NE is working to improve the RAA modeling to better assess the risks and severity of loss-of-load events, and how different resources would affect system reliability during these periods. The RTO is trying to better capture resource reliability performance under different weather and system loading conditions, and with different resource mixes. 

The RAA resource modeling includes specific cases focused on season risk, resource accreditation, and system and zonal capacity requirements. 

ISO-NE has outlined four different modeling options for different resource types: thermal modeling based on seasonal qualified capacity and outage rate; profile modeling based on an “hourly expected performance profile;” storage modeling based on expected energy limitations; and perfect capacity modeling, based on seasonal qualified capacity. 

At the January RC meeting, Zeng detailed which modeling options would be used for different resource types: 

    • Thermal model: nuclear, coal, fuel cell, nonintermittent hydro, imports, tie benefits, and (from March to November) gas and oil resources. 
    • Profile model: active and passive demand resources, and intermittent resources like solar, wind and landfill gas. 
    • Storage model: battery storage and pumped hydro. 
    • Perfect capacity model: distributed energy capacity resources and co-located generators that function as a single capacity resource. 

For peak winter months, ISO-NE is proposing to take a more varied approach to modeling oil, gas and dual-fuel resources, instead of just using the thermal model, which would apply to them in all other months. 

From December through February, gas resources would be modeled as a single fleet using the profile model, intended to account for gas network limitations and demand from local gas distribution companies.  

A regression model is used to establish a relationship between the amount of daily gas available to generation and temperature conditions based on historical data,” Zeng said. “The daily available gas will be apportioned to each hour during the day based on historical hourly gas generation patterns and the representative heat rate of the gas fleet.” 

For oil resources, ISO-NE proposes using the thermal model for residual fuel oil (RFO) resources in all RAA cases and for distillate fuel oil (DFO) resources in the accreditation and capacity RAA cases.  

For the RAA seasonal risk assessment, ISO-NE would model DFO resources as an “aggregate energy storage resource with a limited amount of energy available during a two-week period.” 

Zeng noted that DFO resources have smaller storage tanks than RFO resources, causing them to exhaust their stored fuel more quickly and require more frequent replenishment. Because of variability in tank sizes and replenishment strategies, “DFO resource risks are better captured on a fleet level,” Zeng said.  

The two-week DFO energy constraint would be based on data from the past five winters. 

Fuel Requirements

To compare the reliability benefits of different types of resources that rely on a limited supply of energy, ISO-NE proposes creating a “daily operating hours requirement” (DOHR), which would equal the number of hours per day a resource must be able to operate at its seasonal capacity rating during peak winter months. Resources that can’t meet this requirement would have their qualified capacity derated.  

The RTO would use RAA results to calculate the daily operating requirement and would update the requirement at each capacity auction. ISO-NE also is considering a winter peak seasonal operating hours requirement (SOHR) and a fuel storage hours requirement (FSHR) for stored fuel resources. The calculation of SOHR and FSHR would consider RAA results and historical weather data.  

FSHR would be calculated by “multiplying the DOHR by the number of days in a winter cold snap,” said Alex Mattfolk of Levitan & Associates (LAI), which is working as a consultant for ISO-NE on the project. For this calculation, the consulting firm has determined that modeling a four-day cold snap would cover more than 99% of days. 

The seasonal requirement would be determined by multiplying the DOHR by the number of days cold enough to significantly stress the grid. LAI determined that 11 days would cover over 99% of days.  

Operationally Limited Resources

Mattfolk also presented on the firm’s proposal for “operationally limited resources” — gas plants that typically are unable to run on cold days due to “physical and/or operational constraints on gas delivery.” These resources would not be credited with any qualified capacity.  

LAI proposes to flag operationally limited resources based on historical performance during cold periods. Flagged resources could appeal their designation by providing evidence the gas constraint no longer applies or that the lack of operations was due to some unrelated factor.