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November 1, 2024

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Glick Bids Farewell to FERC

WASHINGTON — FERC Chair Richard Glick said Thursday that he will leave the commission when the 117th Congress adjourns, likely by the end of the year, ending five years as a federal energy regulator.

President Biden nominated Glick for a second term in May, but Sen. Joe Manchin (D-W.Va.), chair of the Senate Energy and Natural Resources Committee, has refused to hold a confirmation hearing for him. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)

Glick’s term ended June 30, but if they are not nominated for another term, FERC commissioners are allowed to continue serving past the end of their current terms until a replacement is confirmed or until the current Congress adjourns sine die. (Congress’ adjournment is typically before the end of the calendar year, though it could be in session until noon on Jan. 3.)

Given how late it is in the year and how long the confirmation process takes in the Senate, “I think it’s pretty clear there’s not a path forward anymore” for his nomination, Glick said at the commission’s last open meeting of the year.

Richard Glick and his binder of grievances (FERC) Alt FI.jpgFERC Chair Richard Glick jokingly refers to his “binder of grievances.” | FERC

 

Although Glick remains the nominee until the end of Congress, he told reporters after the meeting that he has already declined to be nominated again next year.

“I’m still a candidate out there, but just given the timetable and the time it takes to move a nominee forward, I don’t really foresee” being confirmed this year, Glick said in a press conference after the meeting. “I have notified [the White House] that I’m not interested in coming back, in large part because I know this [nomination] process pretty well. Even under the best of circumstances, I know it would take a number of months. I can’t do that to my family; I can’t do that to myself, for that matter.”

And unless something unexpected happens, Glick added, “Sen. Manchin is still going to be chair of the Energy Committee. I don’t know why things might be different next year versus this year, so I think it’s better that they [the administration] move on.”

Manchin was angered earlier this year by the commission’s proposal to consider greenhouse gas emissions in natural gas infrastructure certificates.

Glick did not participate in several orders that were part of the meeting’s consent agenda: two that involved MISO (ER22-477-002 and ER22-995-001, both of which had not been published as of press time), and one that involved utilities in the WestConnect transmission planning region (ER22-1105). Last month he did not participate in an order that involved PJM (ER22-2110).

Glick told reporters he recused himself from these orders because once it became clear to him that he would not be confirmed, he had expressed interest in an available job. Though he did not end up getting the job — nor had he even formally applied — under FERC’s ethics rules, “you not only have to recuse when you’re negotiating … you also have to recuse afterward during a ‘cooling-off’ period,” he said.

When asked if he had any work lined up for after he leaves, Glick joked, “Not unless you know something.”

“You know, people say this all the time: ‘I’m leaving the job to spend more time with my family!’” he said during the meeting, citing the demands of the commission that often require working late Fridays and weekends and taking late-night phone calls. “But that’s what I intend to do, and I really look forward to it.”

Fierce, but (Mostly) Collegial, Debates

Glick was nominated by President Donald Trump and joined the commission in November 2017. Biden, upon becoming president in 2021, named Glick chair to replace Republican Commissioner James Danly.

His tenure at the commission — both as a commissioner in the Democratic minority, and as chair with a majority — was marked by a fierce divide along party lines. Glick wrote scathing dissents to the Republican majority’s decisions in many high-profile dockets and butted heads with Chairman Neil Chatterjee and Commissioner Bernard McNamee. He was then on the receiving end of many equally scathing dissents from Danly — sometimes joined by fellow Republican Commissioner Mark Christie — when he was chair.

Chatterjee and Glick did find common ground, however, on several notable issues, such as Orders 841 and 2222 — which directed RTOs and ISOs to open their markets to energy storage and distributed energy resource aggregations, respectively. And since leaving the commission, Chatterjee has often called Glick his friend. Though he frequently issues separate concurrences noting his concerns, Christie has also sided with the Democratic majority often.

In contrast, Glick and Danly’s debates have not just played out in concurrences and dissents, but also at open meetings, normally tightly scripted affairs. Glick once compared Danly to a Chicken Little-like Paul Revere; during the same meeting, Danly said Glick was being snide. (See FERC Rejection of Weymouth Rehearing Leads to More Barbs.)

James Danly Richard Glick (FERC) Content.jpgFERC Commissioner James Danly, who famously clashed with Chairman Richard Glick over the past five years, praised the chairman for being “unfailingly gracious.” | FERC

 

At the close of Thursday’s meeting, both commissioners somewhat sheepishly acknowledged the tension.

“And now we come to Commissioner Danly,” Glick said after praising his other three colleagues. “It’s an understatement to say we’ve had our difference of opinions. And we’ve certainly said some harsh things about each other. … But we’ve kept our lines of communications open. In our conversations, we’ve kept things civil. … And I think it’s very important on a going-forward basis that even when there’s differences in opinion … it’s important to keep those lines of communications open and figure out where you can work together and how you can work together.”

Danly, who served as FERC general counsel before he became a commissioner, told Glick that he “breathed a massive sigh of relief and gratitude when you appointed Matt [Christiansen] general counsel. You know, when I was GC, he created a great deal of work for me with all the dissents, and I think the score is almost settled at this point.”

He also affirmed “that it is true that we have wrangled a lot and disagreed a lot. … It has been more than five years that we have been fighting over substance, and we both have the scars to prove that. …

“When you read the press accounts — ‘Glick, Danly Spar on…’ — sure, we are, but in reality we have quite a bit of collegiality,” Danly said. He also praised Glick’s graciousness in helping him with “problems or resource needs” and for being accommodating given the “vast number of orders we have to push through.”

Glick concluded his remarks at the meeting by expressing gratitude for “five exciting and engaging years.”

“I can honestly say that we have not had one boring day at the commission. Not at all boring. These days, it’s inextricably linked to … the transition that’s underway to the way we produce, the way we consume and the way we transport energy. It’s, from a technological standpoint, amazing. The speed at which we’re moving forward is amazing. And from a societal perspective — whether it be from an economic perspective to the United States, or just in terms of the environment — it’s just tremendous.”

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NYSERDA Gets Funding Boost as Energy Transition Continues

The New York State Energy Research and Development Authority is getting a funding boost to hire more people as it administers the state’s Clean Energy Standard program, but not as large a hike as it had sought.

The state Public Service Commission on Thursday approved a $33.4 million administrative budget for NYSERDA for next year. The agency will use part of the increase to hire more people to manage the renewable energy contracts that are continuing to increase in number and complexity in the wake of the state’s Climate Leadership and Community Protection Act.

The budget for 2022 is $30.2 million.

NYSERDA had sought $38.8 million for 2023 and authorization to add 19 full-time equivalents to the 22.5 FTEs currently working on CES administration. Its petition drew supportive comments from several clean energy and environmental advocacy groups and no comments in opposition.

However, Department of Public Service staff pared back the request, eliminating five of the prospective hires and $4.1 million in spending on technical services. Staff said the reduced budget request would strike a balance between the ratepayers who are footing the bill and the growing demands placed on NYSERDA.

PSC Chair Rory Christian said the CES is the tool by which New York will reach its statutory requirements for decreasing emissions and increasing renewable energy deployments.

“What we see here today highlights how far we’ve come since 2016,” he said. “Adoption of the NYSERDA administrative budget today will enable the continued growth of renewable generation in New York state.”

Commissioner Tracey A. Edwards went a step further, saying that she would have supported the original $38.4 million and that the PSC should not micromanage NYSERDA.

“We can cut the legs off and really make sure that this doesn’t work by not giving it proper funding,” she said.

Commissioner John B. Howard came at the issue from a different angle. NYSERDA is not funded through the state budget process and its staff are not subject to civil service requirements, nor represented by a union, he said. The PSC provides the primary oversight and needs to do a better job of it, he said.

“Given that NYSERDA will issue hundreds of billions of dollars’ worth of contracts as part of the CLCPA mandates, it is time for greater oversight of NYSERDA, not just from DPS, but I believe from the comptroller’s office as well,” Howard said.

He clarified he was not criticizing NYSERDA but calling for transparency, because New Yorkers footing the bill for decarbonization need to see the money being spent wisely. Having said that, he voted in favor of the budget, because the increases would be covered by NYSERDA’s surplus funds, rather than new money from ratepayers, he said.

The lone vote against the budget came from Commissioner Diane Burman, who said the cuts to the original budget request were not deep enough and there was not sufficient explanation of the benefits to the ratepayers who fund NYSERDA.

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Manchin Permitting Bill Falls Short in Senate

The Senate on Thursday night rejected Sen. Joe Manchin’s (D-W.Va.) bid to tag his controversial permitting bill to the National Defense Authorization Act (NDAA).

Needing 60 votes to append his bill to the NDAA, Manchin won only a 47-47 tie, despite an endorsement Thursday morning from President Biden, who said it would “cut Americans’ energy bills, promote U.S. energy security, and boost our ability to get energy projects built and connected to the grid.”

Roger Marshall (C-SPAN) Content.jpgSen. Roger Marshall (R-Kan.) speaks against Manchin amendment. | C-SPAN

The Building American Energy Security Act of 2022, which would accelerate permitting of energy and mineral infrastructure projects, faced opposition from Democrats — who saw it as a concession to the oil and gas industry — and Republicans upset with Manchin’s vote for the Inflation Reduction Act. (See Manchin Presses Permitting Proposal Excluded from Defense Bill.)

It also faced opposition from state regulators upset by provisions increasing federal transmission siting authority. “States are not the problem,” the National Association of Regulatory Utility Commissioners said in a letter. “Rather, existing federal law and policies have been the biggest barrier to infrastructure rollout.”

Americans for a Clean Energy Grid, the American Council on Renewable Energy, the International Brotherhood of Electrical Workers, the Solar Energy Industries Association and Third Way issued a statement supporting the transmission provisions.

“A comprehensive approach to advancing new transmission investment is long overdue and urgently needed,” the groups said. “While it is not comprehensive, we believe the transmission portion of the Building American Energy Security Act of 2022, as updated last week, will make incremental, yet meaningful, progress.”

Vote on Manchin amendment (C-SPAN) Content.jpgSenate votes on Manchin permitting bill. | C-SPAN

 

Manchin gave an impassioned 11-minute speech on the Senate floor before the vote. Afterward, he issued a statement putting the blame for the bill’s failure on Republicans.

“Once again, Mitch McConnell and Republican leadership have put their own political agenda above the needs of the American people,” he said.

“As frustrating as the political games of Washington are, I will not give up,” he added.

Among the “yes” votes were five Republicans. Nine Democrats and Independent Bernie Sanders of Vermont voted “no.” Six Republicans abstained.

The $858 billion NDAA passed later Thursday evening on an 83-11 vote.

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California PUC Adopts Contested Net Metering Plan

The California Public Utilities Commission on Thursday adopted a controversial proposal to revise the state’s net-metering scheme for rooftop solar arrays, including by reducing bill credits for new solar owners and incentivizing battery installations.

“We are launching the solar and storage industry into the future so that it can support the modern grid,” CPUC President Alice Reynolds said in a statement issued after the vote. “The new tariff promotes solar systems and battery storage with a focus on equity and advances the new clean energy technologies we need to meet our climate goals and help ensure grid reliability.”

The vote came after months of wrangling over the plan, which was originally proposed a year ago, then postponed amid public outcry and rewritten to mollify homeowners angry about the possibility of losing their solar subsidies.

The modified proposal, approved by a unanimous vote Thursday, says it tries to balance the “multiple requirements of the Public Utilities Code and the needs of the electric grid, the environment, participating ratepayers, as well as all other ratepayers.”

It will not change the credits paid to current rooftop solar owners for excess electricity they export to the grid. The state’s investor-owned utilities compensate those homeowners at full retail electricity rates, which are much higher than the current costs of utility-scale solar.

The subsidies shift the costs of solar panels from ratepayers who can afford them to those who cannot, Pacific Gas and Electric (NYSE:PCG) and other IOUs argued. The “cost shift” amounts to $3 billion to $4 billion a year, the utilities estimated.

The generous payments to those who install PV panels are credited with making California the nation’s leader in rooftop solar over the past 25 years.

“Since 1997, California has supported the rooftop solar market through its NEM tariffs, which have enabled 1.5 million customers to install more than 12,000 MW of renewable generation,” the CPUC said in a news release last month.

The CPUC’s previous net energy metering proposal, issued in December 2021, would have slashed NEM bill credits by more than half and possibly up to 80%, including for homeowners who installed solar panels prior to the plan’s adoption. (See California PUC Proposes New Net Metering Plan.)

Under the revised plan, future rooftop solar owners will be compensated differently from existing customers through “an improved version of net billing, with a retail export compensation rate aligned with the value that behind-the-meter energy generation systems provide to the grid and retail import rates that encourage electrification and adoption of solar systems paired with storage,” the decision says.

“The successor tariff applies electrification retail import rates, with high differentials between winter off-peak and summer on-peak rates, to new residential solar and storage customers instead of the time-of-use rates in the current tariff,” it says. “The successor tariff also replaces retail rate compensation for exported energy with Avoided Cost Calculator values that vary according to grid needs.”

A fact sheet that accompanied the proposed decision when it was released in November said the new rate structure will encourage customers to install battery storage so they can store solar electricity generated in the daytime and sell it to the grid on hot summer evenings, when prices are higher and the state needs it most for reliability.

Strained grid conditions in the past three summers occurred during heat waves when solar ramped down in the evening but demand remained high from air conditioning use.

The state legislature approved $900 million in funding this year to spur adoption of rooftop solar and battery storage, including $630 million for lower-income households. Those who install solar or solar coupled with storage in the next five years will receive extra payments.

“Customers lock in these extra bill credits for nine years,” the CPUC said in the fact sheet.

The solar industry will benefit by selling more storage along with solar arrays, it said.

The adopted plan removed a controversial provision contained in the December proposal to impose an $8/kWh grid charge on solar customers’ bills, averaging about $48 per month for residential customers.

The CPUC estimated that under the new plan, residential customers installing solar will save an average of $100 a month on their electricity bills, and those installing solar panels and batteries will save $136 a month or more.

“With these savings … customers will fully pay off their solar systems in just nine years or less,” the CPUC said in the fact sheet.

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FERC Moves to Implement New Backstop Transmission Siting Authority

FERC on Thursday approved a Notice of Proposed Rulemaking that would pave the way for overriding state regulators’ rejections of certain transmission projects (RM22-7).

Congress originally gave FERC this backstop siting authority for transmission projects in Department of Energy-designated National Interest Transmission Corridors as part of the Energy Policy Act of 2005. But the 4th U.S. Circuit Court of Appeals ruled this only applied to those projects that state regulators did not act on, not to those that states denied (Piedmont Environmental Council v. FERC (2009)).

A provision in last year’s Infrastructure Investment and Jobs Act essentially overturned that ruling, expanding FERC’s backstop authority over state-rejected projects. The NOPR is intended to implement that provision.

“The NOPR clarifies the commission’s siting authority by expressly stating that the commission may issue a permit for the construction or modification of electric transmission facilities in DOE-designated national corridors if a state has denied an application to site transmission facilities,” Abigail Christoph, an attorney-adviser in the Office of General Counsel’s, said in a presentation at FERC’s open meeting Thursday.

E-1 panel (FERC) Content.jpgAbigail Christoph and Kim Smaczniak, of the FERC Office of General Counsel, and Enakpodia Agbedia, of FERC’s Office of Electric Reliability, brief FERC commissioners on the NOPR. | FERC

 

It would also allow developers to begin prefiling proceedings for their projects with FERC while its state applications are pending, instead of waiting for one year after they submit them.

“This change will allow applicants to simultaneously pursue approval before a state and the commission if they so choose,” Christoph said.

Transmission wonks generally consider federal backstop siting authority necessary for building large, interregional projects, as just one state can unilaterally kill a multistate project if it rejects its developer’s application. It is a deeply unpopular concept with state regulators, however.

FERC acknowledged this in the NOPR by proposing several rule changes aimed at ensuring a thorough process if a developer requests that it override a state’s rejection.

The commission would create a new applicant “code of conduct” for how potential permit holders engage with landowners. It would also require three “resource reports” be included in applications: on environmental justice, tribal resources, and air quality and environmental noise.

Republicans Tentatively Approve

All five FERC commissioners voted to approve the NOPR, but they didn’t agree on whether it will actually help build out any transmission projects.

“Infrastructure is extremely difficult to site in the United States,” Chair Richard Glick said. “It’s something that, as a country, we need to come to grasp with, especially in regards to transmission. … We have to get it done as a country, and I think this is a step in the right direction.”

Fellow Democratic Commissioner Allison Clements pointed to the provisions that add new requirements for engaging with landowners and other stakeholders as helpful to getting projects done and avoiding litigation.

“It’s really hard to build infrastructure because that impacts people. So let’s find ways to bring people into the conversation early on and get satisfactory outcomes,” she said.

But Republican Commissioner Mark Christie challenged both the premise of the new rules — that states are blocking transmission buildout in a meaningful way — and their function.

“This narrative that’s being pushed — that the states are standing in the way of critically needed infrastructure — is a false narrative,” Christie said.

He noted that the transmission rate base around the country has almost tripled in the last 10 years.

“The states are not standing in the way of critically needed transmission projects. The states are by and large approving them. If the states need anything, they need more authority to vet projects, not less,” he said.

Christie also said the rule changes would not be a “magic bullet” that results in more transmission. Instead, he said, they would create multiple lines of attack for litigation opposing new transmission lines.

“The first time FERC overturns a state after the state has said ‘no,’ once the state has held its own formal process and said ‘no’ either on the route or the need or the prudence of cost … that’s going to be litigated 16 ways from Sunday,” he said.

Still, Christie said he would approve the NOPR, though he said he wanted to hear from state regulators and consumer advocates.

“I question the purpose of fidelity to the IIJA in a NOPR that has what I think in many cases are unnecessarily burdensome requirements, but … I solicit comments on that,” Commissioner James Danly said.

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NERC Warns of Ongoing Extreme Weather Risks

The coming decade will be marked by “extraordinary reliability challenges and opportunities” amid rapid changes in the climate and the North American electric grid, NERC staff said while introducing the organization’s Long-Term Reliability Assessment (LTRA) on Thursday.

“Year after year, we’ve seen extreme weather leading to increased reliability events. … It’s clear that the bulk power system is impacted by extreme weather more than it ever has,” John Moura, NERC’s director of reliability assessment and performance analysis, said at a media event accompanying the report’s release. “So, as we transition our system so rapidly, it’s vitally important that we’re planning and operating a [BPS] that can be resilient to the extreme weather we’re seeing.”

NERC produces the LTRA every year in coordination with the regional entities to assess North American resource adequacy and identify trends, emerging, issues and potential risks during the coming 10 years. This year’s report found most of the continent as either high-risk — meaning energy shortfalls may occur at normal peak conditions in one or more years — or elevated, in which case reserves meet normal resource adequacy criteria but severe heat or cold could lead to shortfalls.

MISO, Ontario at High Risk

MISO and NPCC-Ontario led the high-risk areas, with projected shortfalls for each region exceeding 1,000 MW. Most urgent is the 1,300 MW in MISO, where NERC now expects the reserve margin to fall below the reference margin level beginning next year — a year earlier than the prediction from last year’s LTRA. Mark Olson, NERC’s manager of reliability assessments, explained in Thursday’s call that generation retirements in MISO are “outpacing the new resource additions, and not keeping up with resource adequacy criteria.”

Shortfalls are expected to begin in NPCC-Ontario as early as 2025, with the anticipated reserve margin (ARM) dropping below the reference margin level by 1,700 MW in that year and 2026, driven by “planned retirements and lengthy outages for nuclear units undergoing refurbishment.”

Five-year projected reserve (NERC) Content.jpgFive-year projected reserves for MISO (left) and NPCC. | NERC

 

Regarding the nuclear outages, NERC observed that Ontario Power Generation has proposed to extend the operation of Pickering Nuclear Generating Station, which is currently expected to retire in 2025, through September 2026. The LTRA’s ARM for NPCC-Ontario was calculated under the assumption this proposal would be approved by Canada’s Nuclear Safety Commission.

The last high-risk area is California. Although the state now seems set to avoid the shortfall that last year’s LTRA predicted would begin in 2026, thanks to added capacity, NERC noted it “remains dependent on electricity imports to manage periods of extreme electricity demand or low resource output.” A probability assessment for 2024 showed that while most months show a low risk of load loss and unserved energy in the state, August and September had high risks of more than two hours of load loss due to warm temperatures and “potentially volatile electricity demand.”

Olson said California’s Diablo Canyon nuclear plant was not included in the LTRA due to uncertainty around its continued operation, but that it “would certainly help alleviate risk.” The 2.2 GW plant was scheduled to close by 2025, but the state this year determined that its baseline contribution was essential for reliability, and the Department of Energy last month awarded PG&E $1.1 billion to help keep it in operation. (See DOE Grants PG&E $1B for Diablo Canyon Extension.)

Variable Generation a Continuing Concern

Areas at elevated risk include the U.S. Northwest and Southwest, SPP, Texas and New England. In those regions, capacity should be sufficient to meet normal peak demand; however, conditions under NERC’s 90/10 forecast — which has a 10% chance of being exceeded — could lead to outages.

Tier 1 and 2 planned resources (NERC) Content.jpgTier 1 and 2 planned resources projected through 2032. | NERC

For Texas, the report noted that “ERCOT’s winter peak load varies substantially … between the coldest temperatures of an average year and a more extreme year.” Although changes by state regulators, ERCOT and generator owners since the winter storm of February 2021 should reduce the risk of disruption, NERC said the state still has cause for concern.

The biggest risk for New England continues to be dependence on natural gas for electricity and the risk of gas supply bottlenecks due to increased heating demand in severe cold. The report reminded readers that stored backup fuels are “critical” to ensuring grid reliability.

WECC and SPP face risks due to high demand and variable output, highlighting an ongoing issue in the BPS. As in previous years, projections for planned resources for the next decade show that wind, solar and gas “are the overwhelmingly predominant generation types in the planning horizon.”

Michelle Bloodworth, CEO of coal industry advocate America’s Power, said in a press release that the increasing presence of weather-dependent resources in the electric grid is worrying. She called for utilities not to abandon conventional generation sources without a better understanding of how to maintain reliability.

“We remain deeply concerned that the grid is being forced to rely on less dependable electricity sources in the future because of coal retirements. We strongly urge the Federal Energy Regulatory Commission and grid operators to act as quickly as possible to value all reliability attributes,” Bloodworth said. “In addition, we urge utility commissioners to pause coal retirements until grid operators have identified and valued all reliability attributes.”

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FERC Restarts Hearing on La Paloma Interconnection Dispute

FERC on Thursday restarted a paper hearing in a dispute over a revised interconnection agreement that would reduce the transmission capacity provided to a 20-year-old gas-fired power plant located in California’s Central Valley.

The dispute involves CAISO, Pacific Gas and Electric (NYSE:PCG) and CXA La Paloma, owner of the La Paloma Generating Plant in Kern County, Calif. (ER21-2592).

La Paloma, which entered service in 2003, struggled financially over the last decade as low-priced renewable resources depressed wholesale electricity markets.

After failing to win an expanded reliability must-run designation from CAISO, the plant declared bankruptcy in 2016, citing rising debt, a difficult regulatory environment and mounting compliance obligations under California’s cap-and-trade program.

The ISO refused to authorize a partial closure of the plant, and a new owner acquired the facility in 2018.

La Paloma’s original large generator interconnection agreement (LGIA), which FERC approved in 2001, provided the plant with 1,160 MW of interconnection capacity in the CAISO system. When the LGIA expired in August 2021, PG&E proposed a replacement agreement that would reduce La Paloma’s interconnection capacity to 1,062 MW, which CAISO asserted had been the maximum net generating capacity demonstrated at the plant’s point of interconnection.

Negotiations between PG&E and La Paloma failed to produce a replacement, and in December 2021, FERC accepted the utility’s unexecuted agreement, then suspended it for a nominal period, saying it needed more information to determine the reasonableness of the agreement “regarding the amount of interconnection service that should be reflected in the replacement interconnection agreement.”

The December 2021 order established a paper hearing, which the commission held in abeyance to allow a settlement judge to help negotiate the dispute. In June, the chief administrative law judge overseeing the matter terminated settlement procedures, saying the parties had reached an impasse.

In its order Thursday, the commission asked the parties to address several points in preparation for the hearing. It:

  • directed CAISO to explain which tariffs or manuals, if any, govern the renegotiation of an expiring LGIA, as well as which documents govern “a decrease to the interconnection capacity provided under an expiring generator interconnection agreement, and explain under which conditions interconnection service capacity may be decreased from the amount specified in the expiring generator interconnection agreement.”
  • asked why 1,062 MW was selected for the proposed replacement interconnection agreement, given that La Paloma’s participating generator agreement states the plant has 1,022 MW of generating capacity; the CAISO master file for the plant shows it has a generating capacity of 1,066 MW; the project’s peak output in recent years has not exceeded 1,061.3 MWh in any given hour; and the plant’s average peak output since 2018 has been 988.95 MW.
  • asked La Paloma to provide evidence for its own claims about the capacity and output of the plant.
  • directed CAISO to explain whether it conducted PMax testing — which determines the maximum megawatt level that a resource is capable of sustaining — and site visits to the plant during the replacement interconnection agreement negotiations, in line with the ISO’s stated practice.

The commission also directed La Paloma to provide documentation supporting its request that the ISO and PG&E compensate the plant for the 98 MW of interconnection capacity the replacement agreement would return to the CAISO system.

Initial briefs from the three parties are due 60 days from Thursday’s order.

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FERC Orders NERC Review on Physical Security

Reacting to recent sabotage events, FERC ordered NERC Thursday to report within 120 days on the effectiveness of its existing physical security reliability standards and determine whether improvements are needed (RD23-2).

The commission acted in response to the Dec. 3 gunfire attack on two Duke Energy (NYSE:DUK) substations in North Carolina, which left 45,000 customers without power for as long as four days. Shots also were fired near Duke’s Wateree Hydro Station in Ridgeway, S.C., last week. (See Duke Completes Power Restoration After NC Substation Attack.)

“In light of the increasing number of recent reports of physical attacks on our nation’s infrastructure, it is important that we fully and clearly review the effectiveness of our existing physical security standard to determine whether additional improvements are necessary to safeguard the bulk power system,” FERC Chairman Richard Glick said.

FERC’s existing physical security reliability standard (CIP-014-3), approved in 2014, requires transmission owners to perform periodic risk assessments to identify transmission stations and substations whose loss or damage could result in instability, uncontrolled separation or cascading outages. The standard also applies to primary control centers overseeing such facilities.

Transmission owners and operators must evaluate potential vulnerabilities of a physical attack to each of those assets and develop and implement physical security plans to protect them. It requires TOs to have an unaffiliated third party verify the risk assessments and security plans.

The commission directed NERC to assess the effectiveness of the current standard in light of the recent attacks, including evaluations of the adequacy of the applicability criteria and required risk assessments. NERC also must determine whether a minimum level of physical security protections should be required for all BPS transmission stations, substations and primary control centers.

Glick said the North Carolina attacks, and news reports of incidents in the Northwest and elsewhere, “reminds us that we need to take physical security into account just like cybersecurity.”

“We don’t want to get out in front of the FBI [which is investigating the North Carolina incident] and we don’t know exactly what [the attackers’] motives were or what or what actually happened. … But in the meantime, I think it’s a good idea … to reassess our existing security standards, and whether changes need to be made.”

Glick also noted that some incidents occur at electric facilities below the bulk power system, which are subject to state regulation. “So we need to work with our state colleagues as well to make sure that we’re prepared; they’re prepared; and we all do as much as we can to make sure that the grid is as secure as possible.”

Commissioner Mark Christie said common distribution transformers are “vulnerable to a drunk with a gun and an attitude and … we have a lot of incidents of that. [The loss of a transformer] knocks out a block or two — a substation, several tens of thousands of people.”

Christie said he expects NERC to recommend upgrades to the standard, such as requiring high-definition cameras at substations. “That’s gonna be really costly,” he said, adding that he hoped the Department of Energy will provide support from the $15 billion in grid resilience funding from the Infrastructure Investment and Jobs Act.

“I hope this does not flow through to ratepayers,” he said.

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Northeastern States Plan OSW Compensation Fund for Fisheries

Nine Northeastern and Mid-Atlantic states are seeking input from fisheries and other stakeholders on a plan to create a compensation fund for commercial and for-hire recreational fishing businesses that suffer economic damage from the development of offshore wind projects.

The states — Maine, New Hampshire, Massachusetts, Rhode Island, Connecticut, New York, New Jersey, Maryland and Virginia — on Monday issued a request for information (RFI) seeking stakeholder input on the plan to “establish a regional fisheries compensatory mitigation fund administrator.” The RFI aims to secure input from “impacted members of the fishing industry” as well as offshore wind developers, corporate and financial management entities and interested members of the public.

The fund, if it goes ahead, would provide a source of assistance and compensation for fisheries that find their business and income damaged by the construction or operation of the wind projects, said Kris Ohleth, director of the Special Initiative on Offshore Wind, an independent non-profit organization that promotes wind energy and helped organize the interstate collaboration on the issue.

“So, if you are a fisherman who’s fishing, who is home porting in Virginia, and you fish for scallops off the coast of Massachusetts, you are eligible to apply if you can demonstrate that where you fish before is no longer available to you and it’s impacted your revenue,” she said. “That’s the way the states are envisioning it.”

The proposal addresses an issue that has stirred persistent opposition to offshore wind projects along the East Coast, and elsewhere, where commercial fishermen fear that project construction will damage marine wildlife and prevent them from fishing their regular locations. The fishing industry between Maine and South Carolina caught fish valued at $2.1 billion in 2019 and employed about 360,000 people, according to a scoping document put together by the nine states in preparation for the RFI.

In New Jersey, for example, clam industry representatives have expressed concern that the weight of clam dredges, which can weigh 5 to 7 tons when empty, and other nets, combined with unpredictable winds and currents through the turbines, will make it difficult and dangerous for fishing boats to maneuver around them once they are built. (See Fishermen Fear the Impact of NJ Wind Farms.)

In Massachusetts, lobstermen have expressed concern that their livelihood will be threatened by the construction of offshore wind turbines and embedding of power cables into the ocean floor to transmit the wind power. (See Massachusetts Fishermen Brace for Offshore Wind.)

A study by Rutgers University concluded in July that offshore wind projects on the East Coast could cut revenue in the $30 million surf clam industry by 3% to 15%. The study, which was funded by the U.S. Bureau of Ocean Energy Management (BOEM), said the presence of the turbines in the water could mean that some clamming vessels will make fewer trips, go to different — more distant — fishing areas and so harvest fewer clams, cutting their earnings. Those changes could also increase average costs by 1% to 5%, according to the study.

Trust Fund

The idea for a pool grew out of the framework released by BOEM in June, which set a goal of mitigating the impact of offshore wind projects on the fishing industry. The framework recommended that developers provide reimbursement for “for fisheries gear loss and damage resulting” from developer actions.

Seeing the benefits of collaborating and sharing experiences on issues such as permitting challenges, natural resource consideration and scheduling issues, the nine states had earlier written President Biden about the need for a coordinated offshore wind policy. In a June 2021 letter, they offered several recommendations for how the federal government could support states in the development of wind projects, including suggestions to plan from a longer- term perspective.

“The states are really motivated to get this work done,” said Ohleth. But they saw the “less than ideal” experience of the first two offshore wind projects in the U.S. — South Fork off the New York coast and Vineyard Wind off Martha’s Vineyard in Massachusetts — that handled the fisheries mitigation on a project-by-project level.

“In both cases, there was a lot of consternation,” she said. “There was a lot of issues with fishermen not trusting developers, developers not trusting fishermen, and the state is getting stuck in the middle as the arbiters of the deal.”

Ohleth said the question of compensation is always at the forefront of fishermen’s minds and providing an established fund to meet that concern would enable the states and the industry to address deeper questions.

“We’re attempting to take that question off the table,” she said. With that in place, “we can evolve to … higher order conversations about adaptability, about vessel diversification, about fishermen participating in the offshore wind space … It’s too scary for fishermen to think about that until they have their bottom line met.”

Beyond Compensation

The RFI poses a range of questions about the proposed fund and how it should be managed, seeking responses from the public, the commercial and for-hire recreational fishing industry, the renewable energy industry, corporate and financial managers, and others with knowledge of offshore wind energy siting and development. Questions include: What should be the purpose of the fund? How should the administrator handle claims? What kind of appeals process should be in place? And what role should states play in the fund?

The group will receive comments between Dec. 12 and Jan. 31 and expects to start seeking a regional fund administrator for the program in the spring.

The scoping document put together by the nine states says that “because coastal states are reliant on seafood as part of their complex economic portfolios, they are committed to ensuring sustainable seafood and domestic food security be maintained into the future.”

Yet “the junction of OSW and fishing is a complex intersection, where solutions are needed to advance the long-term sustainability of both industries,” the document says.

Compensation is the “last step” that states should consider in seeking to help the fishing industry, the document says. States and their developers should first focus on avoiding an impact on the industry or, if that is not possible, on minimizing or mitigating the effect, the document says. Still, a compensation plan is “vital to ensuring coexistence of robust and dynamic OSW energy and fishing industries,” the document says.

It adds that “experience to date with siting and development of OSW energy in the region indicates that a standardized framework is necessary to ensure compensation in addressing aggregated adverse economic effects on fisheries equitably and efficiently.”

The scoping document says the administrator would consider both revenue losses and the additional costs paid by fishing interests because of the wind projects. The revenue losses could include displacement of the interests from their fishing area; the transition from highly productive to less productive fishing grounds; reduced fish catch in lease areas; and the devaluation of fishing businesses.

Additional costs could include: the need to acquire new or modified gear, including navigational equipment; extended transit times to get to new fishing areas; increased insurance costs and higher dockage and offloading fees due to competition for “limited space in ports and harbors.”

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Entergy Strengthens its Emissions-Reduction Goals

Entergy has fleshed out its interim goal of emission reductions by adding interim benchmarks and a definitive goal for 2050.

According to the company’s latest climate report released last month, Entergy plans to reach net-zero greenhouse gas emissions from all electric and natural gas operations across its businesses by 2050. It aims to reduce owned and purchased emissions 50% from 2000 levels by 2030 and to have 50% carbon-free power generation capacity by 2030.

The utility’s 2030 goals did not previously include a carbon-free capacity component and power purchases in its 50% utility-only, carbon-reduction goal. Entergy said it added the provisos because its planning models showed that it was on track to outperform its current goal.

It said it now expects to reach the current 2030 interim goal of reducing its CO2 emission rate by 50% from its 2000 baseline several years early. “[We] are evolving this goal to include purchased power,” Entergy said in the report.

The New Orleans-based company had only said it would strive for net-zero emissions in an addendum to its first climate report in 2019.

Entergy’s goal is to reduce “emissions as low as possible and minimize our need to neutralize any residual emissions while still maintaining the reliability and affordability of our products, even as our customer base and demand for clean energy grows.”

Pathway to net-zero (Entergy) Content.jpgEntergy’s illustrative pathway to net-zero compared to other climate warming scenarios | Entergy

 

The utility said 2030’s carbon-free capacity will be supplied by nuclear, solar, wind, hydropower and energy storage. It did not specify a definitive supply plan for 2050, saying its assumptions and risks will change over time.

Entergy completed the report’s modeling before passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act. It said the modeling doesn’t account for the laws’ potential acceleration of technological advancements and emissions goals.

However, Entergy noted that the laws are “expected to help us define our path to net-zero with more certainty, as well as enabling new and innovative solutions.”

Rick Johnson, the company’s director of sustainability, discussed the updated plan Monday during an Entergy Regional State Committee Working Group meeting.

He said while an uptick in demand might slow Entergy’s emissions reductions, the utility is poised under several scenarios to limit its greenhouse gases in line with either a 2-degree or 1.5-degree Celsius total warming.

“We’re going to continue to compare our path … to climate science to avoid the worst impacts,” Johnson said. Entergy foresees “substantial growth in demand from electrification” that could lead to up to 60% more energy production by 2050, Johnson said, noting load growth could “put upward pressure on our absolute emissions.”

“Some stakeholders might not be happy with individual company progress,” he said. But he added that Entergy’s subsidiaries are a linchpin in its region’s decarbonization efforts.

Johnson said Entergy is discussing whether to purchase carbon offsets but will likely only use them if it becomes necessary to counteract its remaining emissions.

“If we got to 2050, and we’re short, yes, we’ll look for high-quality, permanent instruments to neutralize those residuals,” he said.

Johnson said he doesn’t know when Entergy might next revise or update its climate goals, expressing hope that “this will go down to a lower number, but that’s difficult to guarantee 28 years out.”

Entergy needs clean, dispatchable generation including small modular nuclear reactors, advanced nuclear options, clean hydrogen, and long-duration storage to reach its overall emissions commitment, he said. Entergy believes some of those technologies may become commercially viable before 2035.

Going forward, any newly built Entergy gas facility will be hydrogen-capable and able to be retrofitted to exclusively burn hydrogen, Johnson said. He said Entergy’s two newest natural gas plants, the St. Charles and Montgomery power stations can co-fire up to 30% hydrogen.

Johnson added that Entergy Louisiana and Entergy New Orleans recently signed a memorandum of understanding with Diamond Offshore Wind to explore the feasibility of connecting offshore wind generation in the Gulf of Mexico to the grid. He also pointed to Entergy’s recent agreement with Holtec International to evaluate installing small modular reactors in the Entergy service area.

Entergy will need some long-term transmission projects to prop up a clean energy future, Johnson said. He said Entergy “supports MISO’s efforts to develop its initial proposal” for long-range transmission projects (LRTPs) and added that it will need to be confident that the projects have “demonstrable benefits that exceed the costs” and that costs are allocated in a fair manner.

MISO has mounted a series of four LRTP planning cycles but doesn’t anticipate assessing Entergy’s needs in MISO South until the third iteration. (See MISO Staff Preview New LRTP Projects with Board.)