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October 10, 2024

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First Nations Oppose NECEC; Accuse Hydro-Québec of Energy Injustices

Members of the Herring Pond Wampanoag Tribe and the Penobscot Nation last week gave heartfelt explanations for why developers should not build transmission lines to bring Hydro-Québec’s power to New England, saying the utility’s projects have devastated tribal communities.

Lokotah Sanborn, a Penobscot artist and advocate | Maine Youth for Climate Justice.

The hydroelectric power plants in Québec are “projects based on theft and destruction” that halted food supply to communities reliant on the land for hunting and rivers for fish, said Lokotah Sanborn, a Penobscot artist and advocate in Maine.

The severing of the rivers in Québec, the flooding of the forests and the tear of a transmission line through coastal pine barrens in Maine fragments the “spiritual and cultural ties to our homeland,” Melissa Ferretti, chair and president of the Herring Pond Wampanoag Tribe in Massachusetts, said during a webinar co-hosted by Maine Youth for Climate Justice (MYCJ) and the Sierra Club.

Maine residents will vote on a referendum in November that will determine the future of Hydro-Québec and Avangrid’s (NYSE:AGR) proposed New England Clean Energy Connect (NECEC), a $1.2 billion project that would include 145 miles of new transmission in the state. Approval of the ballot measure would put the project before the state legislature, requiring a two-thirds majority in both houses for the project to proceed.

The project also faces potential litigation. A coalition of First Nations in Québec said in July it will file suit if necessary against the provincial government to stop construction of the NECEC line. The Lac Simon, Kitcisakik and Abitiwinni (Anishnabeg Nation), Wemotaci (Atilamekw Nation) and Pessamit (Innu Nation), representing about 7,000 people, claim that more than a third of the dam system providing electricity for the project is on lands the First Nations never ceded to the province.

‘Cultural Genocide’

Hydro-Québec represents half the hydro capacity in Canada and 60% of the country’s power. The company operates more than 60 hydropower generating stations and 28 reservoirs, with 550 dikes and dams across Québec. The utility has flooded 308 million acres of boreal forests since the 1970s to create reservoirs for its dams, according to Hydro-Québec spokesperson Lynn St. Laurent. The James Bay Project, in a region inhabited by Cree and Inuit north of Montreal, covers 68,000 square miles, an area larger than Florida.

Hydro-Québec says the James Bay and Northern Québec Agreement, signed by the governments of Québec and Canada, granted the Cree and Inuit Nations hunting, fishing and trapping rights in the territory, as well as financial compensation for certain services and mitigation measures. But tribes say hunting and fishing in these areas is no longer possible because the hydroelectric projects have shifted the migratory patterns for key game animals and make it difficult for fish to travel up the river to spawn.

Indigenous communities are losing their ability to maintain their culture, Ferretti said during the webinar.

Indigenous-communities-and-hydropower-(Hydro-Quebec)-Content.jpgIndigenous communities and hydropower projects in Quebec | Hydro-Québec
“Indigenous communities are the most likely to be targeted by these energy projects,” she added, recalling the teachings she grew up with, of living off the land and cutting up freshly caught fish for dinner.

“Food in the store is too expensive,” Carlton Richards, a member of the Cree Nation, said in a video to MYCJ. He said the actions of Hydro-Québec and other hydroelectricity companies contribute to the “cultural genocide of Indigenous peoples.”

Lucien Wabanonik, a Lac Simon Anishnabe Nation councilor, wrote in a letter to the Sun Journal of Lewiston, Maine, that the agreements are “the product of coercion into forced agreements with minimal compensation.”

The Innu, whose Nitassinan homeland is the eastern portion of the Québec-Labrador Peninsula, say the water diversion from dikes and dams in the region flooded their hunting land and lowered the water levels of the rivers where they fish.

In July, Hydro-Québec signed an agreement creating a $57.6 million fund to be managed by the Innu of Ekuanitshit “to address Ekuanitshit’s preoccupations” regarding changes made to the Romaine hydro development project. The agreement includes the possibility of awarding direct contracts to Innu businesses related to the Romaine complex.

Last year, the Innu sued Hydro-Québec and Churchill Falls Corp. for $4 billion over the hydro project at Churchill Falls in central Labrador, the second largest hydroelectric underground power station in  Canada, comprising 88 dikes and a 72,000-square-km reservoir. Hydro-Québec purchases more than 5,400 MW of Churchill Falls’ output.

A spokesperson for Hydro-Québec said that the company was limiting its comment on the matter while it is pending before the court. But the company insisted its projects “involve Indigenous representatives during the design stage of a project.” The company has a team of 150 environmental advisers from a “breadth of fields — biologists, anthropologists, sociologists, archeologists, geographers and more — along with 75 community relations advisers dedicated to improving our engagement across the province.”

“Our relationship with First Nations is not perfect,” the spokesperson said. “In certain areas it remains challenging, particularly where communities carry decades-old scars for a variety of reasons.”

New Projects?

In addition to NECEC, which would deliver Hydro-Québec’s power to New England, the utility also plans to send increased power to New York City through two transmission line projects selected last month, including the Champlain Hudson Power Express (CHPE). (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)

Although Hydro-Québec says it will not need to build new dams and reservoirs to meet the increased demand from the U.S., “there is heavy concern that construction will begin on another proposed project known as Gull Island” in Labrador, Julian Felvinci, a member of the Maine Sierra Club Grassroots Network, said during the webinar. “That would be an even bigger dam [than Muskrat Falls in Newfoundland-Labrador] size-wise and capacity-wise,” at 232 km of reservoir area.

The North American Megadam Resistance Alliance cited a report conducted for it by NorthBridge Energy Partners that concluded Hydro-Québec’s export commitments would rise from 33.7 TWh to as much as 55.88 TWh as a result of its NECEC and CHPE commitments.

“Hydro-Québec [HQ] cannot meet the requirements for the NECEC and CHPE demand solely from existing generation facilities under the existing status quo conditions (including service of existing export volumes),” the report said. “The surplus generating capability and spillage cited by HQ and politicians as being capable of supporting these exports are highly variable and insufficient. Either HQ will have to back down existing export volumes, or build new hydro facilities, or resort to a combination of both strategies.”

A report by Energyzt Advisors for the Independent Power Producers of New York came to a similar conclusion. “Under average water conditions, the most likely scenario is that Hydro-Québec would simply divert energy from other exports into CHPE. Under dry conditions, Hydro-Québec would have to purchase energy from other markets to meet its contractual obligations,” it said.

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Estate of GreenHat’s Kittell Lobbies FERC to End Enforcement Action

The estate of one of the owners of GreenHat Energy moved that FERC drop its enforcement action and investigate two of its employees after it emerged last week that Office of Enforcement lawyers violated regulations related to the electricity market manipulation case (IN18-9).

Lawyers for the estate of Andrew Kittell, one of three owners of GreenHat, made the filing on Tuesday, arguing that a series of emails between Enforcement’s Division of Investigations (DOI) lawyers Thomas Olson and Steven Tabackman were “not only unlawful, but deceptive.” FERC released the emails Friday after Olson, who is part of the litigation staff in the GreenHat proceeding, disclosed them to Enforcement management.

In May, the commission issued a show-cause order to GreenHat and its owners with $229 million in potential civil penalties over the company’s 890 million MWh default of its financial transmission rights portfolio in PJM in 2018. (See GreenHat Energy, Owners Face $229M FERC Fine.)

In a report released as part of the order, Enforcement staff alleged that GreenHat’s owners violated the Federal Power Act and PJM’s tariff and Operating Agreement by engaging in a “manipulative scheme” in the FTR market. The order directed the participants to demonstrate why GreenHat should not be assessed a civil penalty of $179 million and owners John Bartholomew and Kevin Ziegenhorn assessed civil penalties of $25 million each. GreenHat, Bartholomew, Ziegenhorn and the estate of Kittell were also required to explain why they should not have to disgorge $13.1 million in unjust profits, plus interest.

“As we already have shown, the merits case against the estate is fatally flawed,” Kittell’s lawyers said. “Enforcement’s conduct is disturbing. And the only remaining purpose the commission might have for continuing this matter — stripping Andrew Kittell’s widow and two children of their limited remaining assets, when it is this investigation that took Andrew’s life — is a distastefully misguided use of the commission’s enforcement powers.”

In July, the estate told FERC that Kittell, 50, killed himself by jumping off the San Diego-Coronado Bridge in California on Jan. 6. His death had been made public in April when his obituary was published, but the cause of death had been unknown.

FERC Emails

Olson notified the commission that he received emails through his personal Gmail accounts on Sept. 17 and 18 from Tabackman, who was serving as decisional staff in the GreenHat case. The two were discussing a pair of U.S. Supreme Court case decisions that Tabackman believed could strengthen FERC’s case.

Tabackman urged Olson not to reveal where he received the information on the cases, saying, “You never heard that here.”

Olson questioned Tabackman if he sent information on 1940’s U.S. v. Summerlin and 2006’s Marshall v. Marshall with the GreenHat case in mind, “or something else?”

Tabackman responded, “Yes — you should be familiar with them — though you should not mention how you came upon them.”

Olson received another email from Tabackman on Sept. 18, which referenced his work with the decisional team, and he realized the emails “constituted a violation of the commission’s separation-of-functions regulation.”

The regulation does not allow any employee assigned to work on an Enforcement proceeding or assist in a trial “to participate or advise as to the findings, conclusion or decision, except as a witness or counsel in public proceedings.”

FERC on Friday also removed Tabackman as a counsel of record in its federal court case.

Kittell Estate and FERC Response

In its motion Tuesday, the Kittell estate argued that the commission should drop all Enforcement action against it, ban Tabackman and Olson from any future involvement in the investigation and “order other offices within the commission to investigate what happened.”

“Tabackman and Olson both knew at the time they were on opposite sides of the wall,” Kittell’s lawyers said “They used Gmail instead of official FERC email to avoid detection. They used words that confirm deceptive intent.”

The estate also cited its reply in August to the show-cause order, arguing that Enforcement officials made statements that “sought to intentionally deceive the commission about the mathematical fact that the bilateral trades actually reduced the size of the default, thus benefiting PJM stakeholders.”

“Normally a litigant responds when facing allegations that it filed an intentionally deceptive pleading,” Kittell’s lawyers said. “But Enforcement never did, conceding our point. While everyone owes a duty of candor to the commission, that duty is even higher for the commission’s own lawyers. That duty was breached here.”

On Wednesday, litigation staff responded to the motion by the Kittell estate, saying Enforcement “followed proper procedure” through the disclosure of the emails. “This, and not termination of the proceeding or removal of litigation staff members, is the appropriate remedy for this violation,” they said.

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NC Compromise Energy Bill Passes Senate, Heads Back to House

A compromise energy bill that could reshape North Carolina’s energy industry passed the state Senate on Wednesday and will now return to the House of Representatives, which passed an earlier version. Approved by a voice vote, H951 authorizes the state’s Utilities Commission to “take all reasonable steps to achieve a 70% reduction” in carbon emissions over 2005 levels by 2030 and net-zero emissions by 2050.

The commission would be responsible for formulating a plan, updated every two years, that would ensure a least-cost, technology-agnostic portfolio of resources to ensure affordability and reliability, Newton told the Agriculture, Energy and Environment Committee. It would also be able to establish performance-based regulation (PBR) that would link utility profits to specific, measurable performance goals, while also decoupling profits from power consumption by residential customers.

Rolled out by Gov. Roy Cooper (D) and a small bipartisan group of lawmakers on Friday, the bill is a slimmed-down and tightened-up version of the original H951 introduced in the House in June. The result of closed-door negotiations between Duke Energy (NYSE:DUK) and Republican lawmakers, the bill was widely criticized for promoting natural gas as a replacement for coal and undercutting the authority of the Utilities Commission, provisions that would benefit Duke and open the door to big rate increases. (See NC Republicans Roll Bill to Close Coal Plants, Add Renewables.)

Cooper praised the revisions as setting “a clean energy course for North Carolina’s future that is better for the economy, better for the environment and better for the pocketbooks of everyday North Carolinians.” It could also significantly improve on his own initial carbon emission reduction goal of 40% by 2025, set in 2018’s Executive Order 80.

“Bipartisanship is at the heart of this bill,” Sen. Paul Newton (R) said on Tuesday, as he shepherded the bill through two Senate committee hearings. “This is a policy bill first and foremost, focused on achieving carbon reductions at least cost and in a way that maintains our grid’s reliability. We know renewables cannot do it alone. … It will take diversification of fuel sources to achieve this goal.”

At the same time, he noted that the bill gives the commission some wiggle room on meeting the emission deadlines if it “determines that reliability or least cost would be compromised by meeting these goals. In other words, we’re giving them room to do the right thing at the right time, even if it means we’ll reduce more carbon at less cost beyond the deadlines in this bill,” Newton said.

Such loopholes raised concerns among some clean energy and environmental advocates, who saw the bill as an improvement on the original but still needing stronger protections for utility customers and a wider range of emission-cutting policies. Maggie Shober, director of utility reform at the Southern Alliance for Clean Energy, pointed to a PBR provision that would give utilities environmental incentives but only based on existing environmental standards, which could result in “utility profit windfalls for doing the bare minimum.”

A statement from the Southern Environmental Law Center called for “provisions to provide bill payment assistance and comprehensive energy-efficiency programs for low-income customers.”

PBR and PURPA

The bill essentially sailed through a one-hour hearing before the Senate Agriculture, Energy and Environment Committee on Tuesday afternoon, followed by an even quicker approval from the Senate Finance Committee. In both instances, lawmakers did raise questions about the bill’s impact on low- and moderate-income customers, which Newton answered with a list of consumer protections.

For example, he said, the bill sets a 4% cap on utility rate increases, allows utilities to offer on-bill financing for residential energy-efficiency improvements and provides for “securitization” of Duke’s retiring coal plants, under which the utility would recover only 50% of a plant’s costs.

“So, we’re protecting customers,” Newton said. “It brings the rates down lower than they would have been to securitize some of this net book value that’s left in these plants that we’re telling them to shut down, even though they have economic life left.”

While recognizing Newton’s efforts, Sen. Don Davis (D), speaking before the vote on Wednesday, made an impassioned plea for lawmakers to do more to protect low-income residents from rate hikes and potential power shut-offs.

“Everyone here that’s been involved in this legislation, I’m begging you that as you vote in support of this bill today … when you press the button today, and when we go out to laud how wonderful this is, that we still have in the back of our minds a commitment of coming back, a true commitment, a genuine commitment of coming back to try to do something to help the least of those amongst us,” Davis said.

Other key provisions in the bill:

      • Solar procurements would be split, with 45% coming from power purchase agreements with third parties and 55% utility-owned. These requirements would also apply to procurements of solar plus storage and any solar “procured in connection with any voluntary customer program.” The bill also calls for competitive procurement of 2,660 MW of renewable energy allocated over a 45-month period.
      • Multiyear rate plans are part of the bill’s PBR provisions, allowing Duke to file a rate case only once every three years, after which it could raise rates up to 4% without Utilities Commission approval. Utilities will have to apply for PBR incentives and multiyear plans, and the commission can approve, modify or reject the applications. The bill includes a list of considerations for PBR approval, including whether a utility’s plan will encourage peak load reduction, energy efficiency and deployment of distributed energy resources, while also reducing energy costs for low-income consumers and supporting equity in contracting.
      • Solar projects originally built under contracts mandated by the federal Public Utility Regulatory Policies Act will have the option of renegotiating and extending their contracts with utilities for another 10 years, albeit at a lower rate. Under PURPA, utilities are required to offer contracts at a standard price to qualified facilities, which in North Carolina were originally sized at 5 MW and below. The state passed a bill (H589) in 2017 that reduced the maximum size of projects down to 1 MW and shortened the contract length from 15 to 10 years.

Rep. John Szoka (R), who was a sponsor of the original House bill, says he supports the revisions, noting that the current bill’s PBR and PURPA provisions are taken from the original.

“What we were trying to do was to continue what we’ve started in 589 to keep a downward pressure on energy costs for the state,” Szoka said in a phone interview with NetZero Insider. The original bill may have been too prescriptive, he said, but it brought out the proposed legislation’s good points and opponents’ objections, “so when it got to the Senate, I believe, it was easier for them to deal directly with the governor and come up with something that was agreeable.”

He expects the bill to pass in the House with a “very good majority.”

“My belief is the lower-cost forms of energy, which today are renewable, will eventually win out,” Szoka said. “It might be one of those deals where solar and modular nuclear end up getting more market share than they would have, had we stayed with a more prescriptive approach.”

Could All-source be Least-cost?

Underlying the bill’s mandate for least-cost resources is an assumption that natural gas will continue to be competitive with the falling costs of solar, wind and storage. Opponents speaking at both hearings on Tuesday warned that renewable procurement would translate to higher electric rates.

However, the Utilities Commission is now studying technology-neutral, all-source procurements that could help accelerate coal retirements in the state and replace that generation with a portfolio of cheaper, cleaner resources optimized to improve system efficiency and savings. Advocates are similarly pushing Duke to adopt all-source procurements in its next integrated resource plan. (See NCUC Debates Best Path for Duke Coal Retirements.)

At a two-day technical conference on Thursday and Friday, Commissioner Dan Clodfelter quizzed Duke executives on the utility’s procurement practices versus an all-source approach.

“As I hear it, you are defining need in a more discreet, ‘componentized’ way and looking at procurements relative to components or elements in that need,” he said. “And what I hear the other party’s advocating for is that we should define what they call ‘total system need,’ and then you should seek procurement of a portfolio of resources that in the aggregate will satisfy that total system need.”

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PJM Requests Rehearing of MSOC Change

PJM on Monday requested a rehearing and clarification of FERC’s order to replace its market seller offer cap (MSOC), arguing that the commission’s decision to side with the RTO’s Independent Market Monitor may lead to over-mitigation of the market (EL19-47).

FERC on Sept. 2 approved the Monitor’s unit-specific avoidable-cost rate (ACR) proposal and required PJM to revise its tariff. That followed FERC’s order in March requiring PJM to revise the MSOC to prevent sellers from exercising market power in the capacity market, having been convinced by the Monitor’s arguments. (See FERC Backs PJM IMM on Market Power Claim.)

In its request, PJM said it “remains concerned” that the unit-specific review of all resources “may prove to be a significant overreach” to address concerns raised by the commission.

“The harm of over-mitigation under a unit-specific ACR approach is real and will inhibit the ability of capacity market sellers to base their offers on their respective cost estimates and assumptions about what is likely to occur three years in the future,” PJM said. “This is because each capacity market seller’s evaluation of risk relating to actual costs and revenues varies for various resources … and it is not appropriate for PJM or the Market Monitor to substitute their assessment of the risks for the capacity market seller’s demonstrable assessment of the risks.”

Because unit-specific reviews involve applying criteria that can “engender significant debate” and “charges of subjectivity” in the application of its components, PJM said disputes will “likely arise” under the revised MSOC because of disagreements over “sufficient support for the valuation of various risks in the unit-specific net ACR calculation.”

“In fact, all of the unit-specific offer caps requested to date for the upcoming BRA [Base Residual Auction] have already been rejected by the Market Monitor,” PJM said. “Thus, contrary to the commission’s finding, the concerns that the Market Monitor will not entertain alternative expectations of risk is not speculative. These disputes will ultimately prove disruptive to the [capacity] auction process given that they will likely end up at the commission — with limited time for resolution before the auction window opens.”

It noted that FERC had acknowledged in its order that replacing the existing MSOC with a unit-specific net ACR “will likely create more work for the Market Monitor and sellers by requiring the individual review of a higher number of capacity offers.” The commission had relied on the Monitor’s position “that its staff would be capable of any additional review resulting from its own offer cap proposal” to determine the new approach would not prove to be excessively burdensome.

But FERC failed to note that the RTO is ultimately responsible for making final determinations on all requested unit-specific ACRs, PJM argued, and it never indicated the reviews could be completed within the 25-day period allotted under the tariff to review the requests. The RTO said the larger volume of unit-specific requests expected under a net ACR approach would make reviews even more difficult. PJM “repeatedly expressed concerns of the administrative burdens” that would result from setting the MSOC at a capacity resource’s net ACR, it said.

The RTO also said the commission may have “inadvertently included default gross ACR values for demand resources and energy efficiency resources” in the tariff changes it ordered, which would make those resources subject to the MSOC and in conflict with an exemption elsewhere in the tariff.

“The current ACR calculation is not designed with demand resources or energy efficiency resources in mind,” PJM said. “Specifically, since avoidable costs are the costs that a demand resource or energy efficiency resource would not inquire absent the load curtailment or shift, the relevant input would be the cost for such load curtailment or shift. However, such costs are difficult to calculate since the cost of curtailment varies by industry, time and individual customer needs.”

Last month, PJM requested a delay of the BRA for the 2023/24 delivery year by almost two months, citing the commission’s Sept. 2 order. The RTO said the auction delay was necessary to give capacity market sellers and the Monitor a “realistic opportunity” to appeal the RTO’s final decisions on unit-specific offer cap requests resulting from the MSOC rules change. (See PJM Proposing 2-Month Capacity Auction Delay.)

Additional Rehearing Requests

Several other stakeholders also requested rehearing on Monday.

Exelon (NASDAQ:EXC) and Public Service Enterprise Group (NYSE:PEG) said in a joint filing that FERC’s order “employed a machete, slashing off the default MSOC” instead of using a “scalpel to fix the discrete problem” of recalibrating the number of expected performance hours.

“In selecting this remedy, the commission never found the broader Capacity Performance framework, including the opportunity cost-based default MSOC, to be unjust and unreasonable,” the companies said.

Vistra (NYSE:VST) said the commission’s order “contains at least three fatal market design flaws”: it was “based on the erroneous assumption that the marginal offer must be reviewed in all circumstances”; it “adopts technology-specific default offer caps that assume resources face zero risk associated with their PJM capacity supply obligations”; and it “unduly limits the costs a resource owner can include in a resource’s offer.”

“Each of those flaws, standing alone, renders the commission’s replacement rate unjust and unreasonable,” Vistra said.

A joint filing by Calpine, LS Power, Talen Energy, the Electric Power Supply Association and the PJM Power Providers Group said a rehearing is required because the commission “failed to properly consider the alternatives” and instead “adopted an MSOC that fails to properly reflect the risks and costs imposed on suppliers and is at odds with PJM’s Capacity Performance structure.”

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Crops, Wildlife Suffering Under Wash. Drought

Global warming has led to decreased crop yields and increased disease in some wildlife in Washington, state lawmakers heard last week.

Washington agriculture and wildlife experts briefed the Joint Legislative Committee on Water Supply During Drought on Sept. 29 on the ripple effects from a nearly statewide drought that Gov. Jay Inslee blames on climate change. The joint committee only meets during years in which a drought is declared by the state government.

The committee has been receiving briefings as it ponders how to prepare for potential future droughts, which legislators worry could happen as soon as 2022. “This year caught us by surprise. … We didn’t have funding for our agencies … We need to prepare for the next drought, and there will be one, I’m afraid,” said committee chair Sen. Judy Warnick (R).

This year’s March-August temperatures were the third warmest in Washington history — 2.1 degrees Fahrenheit above average, said Karin Bumbaco, an assistant state climatologist. This period was also the second driest on record at 7.15 inches of rain. Fifteen of Washington’s 39 counties posted their driest conditions ever. An unusually hot spell in June was extra damaging, she said.

Increased heat led to higher temperatures in the state’s streams and rivers, which speed up the metabolisms in fish, leading to their consuming more calories, said Megan Kernan, water policy section manager for the Washington Department of Fish and Wildlife. The increased water temperatures also decrease oxygen levels in streams.

The warmer temperatures increase the chances of the region’s fish being struck with the sometimes-fatal Ichthyophthirius multifiliis — also known as “Ich” or “white spot” disease.

“We see a lot more sick fish when the water temperatures get warmer, “Kernan said.

She also noted that drying wetlands have led to more cases of sometimes-fatal epizootic hemorrhagic disease and bluetongue affecting deer. Spread by biting insects, bluetongue causes a deer’s tongue to swell, while also causing ulcers, sores, painful hooves, lameness and reproductive problems. Epizootic hemorrhagic disease causes extensive hemorrhages. 

Jaclyn Hancock, a hydrogeologist with the Washington Department of Agriculture, said 2021’s predictions for the state’s dryland wheat harvest will be the lowest since 1997. The state is predicting a harvest of 93.26 million bushels compared to an average of 152.2 million bushels for the five previous years. “We’re concerned about 2022,” she said. 

Other projections are:

  • Harvested peas are predicted at 1,200 pounds per acre this year, compared with 3,000 pounds per acre in 2020. 
  • The lentil harvest should yield 920 pounds per acre, compared with 1,300 pounds per acre last year.
  • Harvested garbanzo beans are predicted to be 680 pounds per acre this year, compared to 1,780 pounds per acre in 2020. 

She noted water and forage for livestock had to be trucked into the region. “That’s very expensive,” Hancock said. 

The Roza Irrigation District snakes along the Yakima River’s shoreline in Central Washington, which is home to numerous vineyards and many other crops. Scott Revell, executive director of the Roza district, observed that the extra heat is expect to reduce 2021’s wine grape and juice grape yields by 20-40%.  Hop yields are also down. The sizes of harvested apples have also shrunk, Revell said.

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Quarter of Energy Sector Vulnerable to Ransomware, Report Says

One in four major U.S. energy companies — including 17% of the largest electric utilities — are “highly susceptible to a ransomware attack,” according to a report issued this week by cybersecurity firm Black Kite.

The 2021 Ransomware Risk Pulse: Energy Sector report presents the results of Black Kite’s survey of the 150 largest energy companies by market cap in the U.S.; included in the report are 29 electric utilities and 58 and 63 companies in the oil and gas industries, respectively. Black Kite assigned a rating to each company based on its proprietary ransomware susceptibility index (RSI), a number between 0 and 1 broadly determining how susceptible the company and its third parties are to an attack.

RSI ratings are based on a combination of publicly available information and data gathered on the dark web. Factors that can damage a company’s score include leaked credentials, use of older software versions with unpatched vulnerabilities, open remote desktop protocol ports and misconfigured email systems.

Ransomware-specific assessments are relatively new for Black Kite, which started offering the service earlier this year in response to concerns from clients about their own vulnerability to ransomware, and that of their vendors and suppliers even more so. Bob Maley, Black Kite’s chief security officer, told ERO Insider that ratings systems that give overall cybersecurity grades may not take into account vulnerabilities to specific risks.

“Grades are a good overall view of cyber hygiene, but they don’t always indicate where the highest risk is,” Maley said. “And what we’ve discovered through this process is that … some companies that have very good cyber hygiene [but] are highly susceptible to ransomware.”

Major Vulnerabilities Evident Across Sector

Black Kite found that 25% of all the companies surveyed had an RSI of 0.6 or more, which the company considers critical. An RSI of 0.4 to 0.59 is considered average, and a low RSI is 0.39 or below.

The electricity industry fared relatively well compared to the natural gas and oil industries, with 17% of surveyed electric utilities returning a critical RSI compared to 28% of oil companies and 25% of natural gas companies. Companies with a low RSI did not make up the majority of any industry, though oil came closest with about 24 of 58 companies, compared to 11 of 29 electric utilities and 16 of 63 gas companies.

Average overall cybersecurity rating of U.S. energy sector companies, September 2020 to September 2021 | Black Kite

The RSI ratings stand out in contrast with the “relatively decent cyber posture” of the energy industry, with Black Kite’s overall average cyber hygiene rating of companies mostly hovering around 75% for the last 12 months. Many of the companies with high RSIs demonstrated technical grades of 80% or above, while some of the companies with the lowest RSIs also had the lowest technical grades, apparently confirming Black Kite’s assertion that ransomware vulnerability is not necessarily correlated with overall cyber proficiency.

Examining specific vulnerabilities provides a better indication of the sector’s areas for improvement. Credential access is a particular concern: Black Kite found at least one leaked credential within the last 90 days from 77% of U.S. energy companies, an especially sensitive area given that the ransomware attack on Colonial Pipeline this May — which led the company to shut down its entire network — originated with a leaked password for the company’s virtual private network.

Ransomware risk of U.S. energy companies vs. overall cybersecurity ratings | Black Kite

Email security is also an area of high vulnerability; despite the fact that email is the “most common channel leveraged during ransomware deployment,” Black Kite found that 74% of U.S. energy companies still have not properly configured their email services to prevent email spoofing. This means that attackers can easily pose as employees’ coworkers or managers to trick them into exposing sensitive information they would not normally provide to outsiders.

U.S. regulators responded to the Colonial hack and other recent ransomware attacks with heightened cybersecurity requirements, which Maley acknowledged could help improve the sector’s baseline for cyber hygiene. (See TSA Issues New Pipeline Cybersecurity Requirements.) But he warned that given the fluid nature of the cyber threat landscape and the inevitable delays in implementation of new standards, attempts to regulate the sector into safety are ultimately a losing proposition.

“From a high level view, [those things] make a lot of sense. But when I take off the regulatory glasses and put on the bad actor glasses, [they] don’t concern me at all,” Maley said. “The way bad actors work is, they will try something, and as long as it’s working … they will continue to do it. They’ll continue to profit off that. But when it stops — they’re very smart, [and] they’ll find other avenues.

“I think it’s more about how do leaders of companies get that mentality of … ‘how are the bad actors going to get into us today?’” he continued. “Not what checklists they’ve done or which auditor certification they’ve acquired. … And it is a daily basis because it can change very quickly.”

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Western Utilities to Explore Market Options

A loose coalition of the West’s largest utilities said Tuesday that they are discussing ways to work together on “new market services” such as transmission expansion and day-ahead energy sales, while leaving open the possibility of forming or joining a Western RTO.

The Western Markets Exploratory Group (WMEG) began holding early-stage talks this summer, the utilities said in a joint statement. It includes Xcel Energy-Colorado, Arizona Public Service, PacifiCorp, NV Energy, Idaho Power, Salt River Project and six other utilities in the Pacific Northwest, Rocky Mountain states and Desert Southwest.

“We are excited to join with the other companies to explore creating new ways of sharing resources to better serve our customers with affordable and reliable power,” Alice Jackson, president of Xcel Energy-Colorado, said in the statement. “We believe that a Western energy market is key to transforming the electricity system throughout the West, integrating more renewables onto the system, while reducing costs and maintaining reliability.”

The discussions are geared toward “long-term solutions to improve market efficiencies in the West,” the statement said. “That includes incorporating lessons learned from existing regional markets as well as other efforts across the West.”

Many of the exploratory group’s members participate in CAISO’s Western Energy Imbalance Market (WEIM) or plan to join the interstate real-time trading market in the next two years.

Xcel’s Public Service Company of Colorado (PSCo), Platte River Power Authority and Black Hills Energy, all members of the working group, had planned to join the WEIM but paused those plans in June to explore other options. (See Xcel Delays Joining EIM to Examine Options.)

The move followed a decision by Colorado Springs Utilities (CSU) to exit a joint-dispatch agreement with the three other Colorado utilities to join the WEIM. CSU instead opted to join SPP’s Western Energy Imbalance Service (WEIS), with the intention of becoming a full RTO member.

The exploratory group said its efforts, expected to continue for several years, won’t affect the energy imbalance markets anytime soon.

“WMEG’s discussions will not impact participation in or evaluation of those markets in the short-term, as the group is focused on long-term market solutions,” Tuesday’s statement said.

Asked if the effort could lead to an RTO, Xcel spokeswoman Julie Borgen said, “the Western Markets Exploratory Group agrees on some core principles, including that any market or potential RTO that it would join or establish must outweigh the costs, and provide more value than the existing [SPP and CAISO energy imbalance models].”

“It’s essential that the companies involved are able to meet their state and local carbon reduction targets, while also maintaining reliable, affordable service for customers,” Borgen said.

A Western RTO?

Reaction to the WMEG announcement focused on the need for a Western RTO rather than piecemeal approaches.

“The West needs and deserves an RTO,” Vijay Satyal, Western Resource Advocates’ regional energy markets manager, told RTO Insider. Satyal said he hoped the coming together of private and public utilities from across the West would lead toward that goal. However, “if this announcement is a rushed measure to show something is happening and doesn’t reflect public interest goals, that can create a bigger concern for everybody,” he said.

The West’s market is split between CAISO and the rest of the West, leading to market inefficiencies and a lack of coordination, he said.

The WMEG shows utilities are “aligning to agree to come to the table for a long-term market solution, but that’s not enough,” Satyal said. “What we need is a market in the West that is a full RTO, one that is automated, transparent and has a fair governance structure that promotes clean energy and a decarbonized grid of the future.”

In addition, he said, an RTO would “create a centralized situational awareness of the larger grid that can ultimately enhance grid reliability.”

Advanced Energy Economy Managing Director Amisha Rai said in a statement Tuesday that “it’s good to see the utilities publicly acknowledge the benefits of regional markets and collaboration, but as described, this announcement by utilities falls short of the urgency of the moment.”

“The stakes are too high for slow and small steps,” Rai said. “An RTO is needed to achieve truly reliable, affordable and expanded clean energy in the region. Utilities and state leaders should not delay any longer in moving away from the status quo toward real, meaningful change.”

Momentum for a Western RTO had been building this year. While two-thirds of the nation’s electricity load participates in organized wholesale markets, the West remains a collection of 38 balancing authorities with limited cooperation.

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The development of a single RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion a year in energy costs by 2030, according to findings from a state-led study funded by the U.S. Department of Energy. (See Study Shows RTO Could Save West $2B Yearly by 2030.)

The study also found that a full Western RTO would be more effective at reducing renewable resource curtailments and CO2 emissions than under other configurations in which the region is broken up into two separate markets.

Citing potential benefits, Colorado and Nevada passed bills in June requiring transmission owners to join an RTO by 2030.

And FERC Chairman Richard Glick called for a Western RTO along with a growing number of policymakers, public interest groups and industry leaders. (See Glick Says West Should ‘Finish the Job’ on RTO.)

Glick said at a FERC technical conference in June that “the time is right for the states, the region’s utilities and other key stakeholders to go ahead and finish the job” and form an organized market in the West.

Prior efforts to form a CAISO-led RTO failed because California politicians refused to cede authority over CAISO, a state public benefit corporation, and because other Western states were leery of joining a California-controlled RTO.

SPP and CAISO Comment

SPP has been pitching its benefits as the would-be leader of a Western RTO. Members of its WEIS have signaled interest in joining an SPP-led RTO, CEO Barbara Sugg told WECC’s Board of Directors in June. SPP’s proposed Western RTO would provide a day-ahead market and regional transmission planning, she said. (See SPP CEO Pitches WECC on Western Benefits.)

SPP signed an agreement in August to operate Northwest Power Pool’s resource adequacy (RA) program in the Western Interconnection, working with NWPP and its RA participants to help develop, implement and operate the program. (See SPP to Operate NWPP’s Resource Adequacy Program.)

Responding to a request for comment on the WMEG, SPP said it “believes there is vast potential for continued market development in the West. We launched the Western Energy Imbalance Service market in the West this year, and we’ve been responding to interest from additional Western entities about their specific needs in a market offering.”

“We look forward to the possibility of expanding our Western market and having further discussions with these entities and others about how SPP can assist utilities in achieving clean energy goals while providing reliable, affordable energy to customers,” the RTO said.

CAISO is renewing its effort to expand the WEIM from a real-time to a day-ahead market with a stakeholder meeting scheduled for Oct. 13. It had put the plans on hold last year amid heat waves and blackouts. (See Heat Waves, Blackouts Slow Western EIM Expansion.)

CAISO CEO Elliot Mainzer said that “with the continued expansion of the Western EIM and our planned Extended Day-Ahead Market Forum on Oct. 13, we are heartened to see the growing interest in regional market development represented by the Western Markets Exploratory Group (WMEG).”

“At the ISO, we will continue to advance pragmatic, actionable market enhancements that optimize transmission and resource diversity across the widest geographical footprint possible and enable our many partners to continue to evolve together toward a fully integrated Western electricity market,” Mainzer said.

Tom Kleckner contributed to this story.

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FERC Approves $2.2 Million Penalty for PG&E

Pacific Gas and Electric (NYSE:PCG) will have to pay $2.2 million to WECC for violations of NERC reliability standards, along with other mitigating activities, according to a settlement approved by FERC last week (NP21-26).

NERC submitted the settlement to FERC in a Notice of Penalty (NOP) in August, along with a spreadsheet NOP detailing settlements that WECC reached with Farmington Electric Utility System, the U.S. Bureau of Reclamation and Southern California Edison (SCE) (NYSE:EIX) (NP21-28).

The settlement with Farmington carries a $49,000 penalty, while SCE settled for an $85,000 penalty. WECC did not assess a monetary penalty for the violation by the Bureau of Reclamation, citing a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal governmental entities.

In addition, NERC disclosed that it had also submitted a settlement to FERC involving one or more violations of the Critical Infrastructure Protection (CIP) standards (NP21-27), though it did not publicly reveal details of the violations in accordance with an agreement with the commission last year. (See FERC, NERC to End CIP Violation Disclosures.) FERC on Thursday indicated that it would not review the settlements, including the CIP violations, letting the penalties stand.

More than a Decade of Facility Misratings

PG&E’s penalty stems from violations of five standards:

      • FAC-009-1 — Establish and communicate facility ratings (This standard was in effect when the violations began; the effective standard now is FAC-008-5 — Facility ratings.)
      • FAC-501-WECC-1 — Transmission maintenance (since replaced by FAC-501-WECC-2)
      • PRC-005-6 — Protection system, automatic reclosing, and sudden pressure relaying maintenance
      • PRC-005-1a — Transmission and generation protection system maintenance and testing (replaced by PRC-005-1.1b)
      • PRC-004-5(i) — Protection system misoperation identification and concern (now PRC-004-6)

WECC discovered the FAC-009-1 violations during a compliance audit in 2018, but the issues were determined to have begun at least 11 years earlier. The regional entity found that the utility’s facility ratings for more than 1,000 generation and transmission facilities across its entire footprint were missing the current carrying series elements, making it impossible for PG&E to determine the most limiting element for each facility. As a result, the calculation of system operating limits for each facility were inaccurate.

The shortcomings already existed in 2007 when the standard took effect and were never corrected in the years before WECC’s compliance audit. The RE identified the root cause of the violation as “poorly defined management and guidance regarding how to maintain a comprehensive facility ratings program,” with a contributing cause being the lack of a process for maintaining the facility ratings database.

WECC determined that the risk posed by PG&E’s violation was “serious and substantial,” with the potential for equipment damage or failure, unplanned or cascading outages, and other serious issues across the utility’s 18,000 miles of transmission lines and 8,000 MW of generation facilities. Mitigation was ongoing at the time of WECC’s filing; steps to be completed by March 2022 include:

      • updating WECC on a quarterly basis regarding facilities status;
      • performing a document review, identifying gaps and generating a report for all facilities;
      • updating facility ratings guidance documents; and
      • developing and implementing an asset register for electric transmission.

Inspections Skipped for Years

The violation of FAC-501-WECC-1 concerns requirement R3, which requires transmission owners to “implement and follow their” transmission maintenance and inspection plan (TMIP). PG&E reported to WECC on Dec. 5, 2018, that it was in potential noncompliance with the requirement after discovering that 10 towers on two parallel 500-kV transmission lines had not been visually inspected as the TMIP required in 2014, 2017 and 2018.

WECC found that the utility had exhibited “less than adequate process design” for carrying out the TMIP, noting that while a supervisor had noted that the towers were not inspected in 2014 or 2017 because of various factors such as agriculture work in the vicinity, the same person had failed to ensure that the inspections were carried out later when these were no longer an issue.

According to PG&E, all 10 affected towers had been inspected by the time of its report, which WECC later verified. The RE determined that the violation posed a “serious and substantial risk” to the bulk power system, though acknowledged that the towers “showed no signs of degradation” and did not contribute to any incidents or fires while the violation was occurring.

PG&E’s mitigation measures were completed by March 3, 2020. Actions taken by the utility include rearranging its inspection schedule to account for the issues that previously interfered with the inspections and modifying its processes to better account for situations where inspections cannot be performed as scheduled.

Wrong Battery Baseline Used

The PRC-005-6 violations were also self-reported: PG&E notified WECC in January 2018 and April 2019 that it was potentially in noncompliance with requirement R3 of the standard, which mandates that utilities “that [utilize] time-based maintenance program(s) shall maintain [their] protection system, automatic reclosing and sudden pressure relaying components … in accordance with the minimum maintenance activities and maximum maintenance intervals” prescribed in the standard. WECC determined that the self-reports stemmed from the same issue and consolidated them in the settlement.

The first report originated during an internal compliance review on Oct. 20, 2017, when PG&E determined that it did not use the correct values in a battery resistance test conducted the previous year. If it had used the correct values, the battery bank would have failed the test. When it discovered the mistake, the utility reviewed its testing for the previous year and found that it had used the wrong baseline to verify 58 battery banks across its footprint.

In the second case, PG&E found that it had not completed maintenance and testing activities for four electromechanical relays at one substation since December 2012. The tests were required every six years, and while a test had been scheduled for January 2018, it was not completed because of “storms and operational concerns.” As a result, the utility had been in violation of the standard since December 2018.

The violation began on Jan. 15, 2016, when PG&E failed to verify the battery banks using the correct baseline, and ended on Jan. 24, 2019, when the utility completed the corrected tests on all affected batteries. PG&E completed testing the substation relays in the intervening time as well.

Additional mitigation activities by the utility included conducting spot checks of battery records across its footprint and revising the battery maintenance program “to clarify roles and responsibilities for all battery testing and review activities.” It also “added system protection and testing personnel to the quarterly transmission outage planning meetings” in order to prevent future mix-ups with maintenance and testing activities.

Software Migration Delays Relay Testing

PG&E’s violation of PRC-005-1a relates to requirement R2, which states that utilities must “provide documentation of [their] protection system maintenance and testing program and the implementation of that program to its regional reliability program on request (within 30 calendar days).”

PG&E reported on May 6, 2020, that it had not maintained and tested five protection system relays at two substations within defined intervals. The issue arose from an error when the utility was transferring its relay settings to a new database in 2017; PG&E discovered in 2019 that the settings for the five relays were never entered into the new database. As a result, testing on these relays had been overlooked since 2012.

At the time of WECC’s filing, the violation was still ongoing because PG&E was performing an extent-of-condition evaluation to determine if any other relays had not been migrated appropriately. Remediation activities completed at the time included performing additional field validations of physical assets and generating a job aid “outlining the requirements for reviewing and approving test reports”; additional work to be completed included maintaining and testing the affected relays and continuing to “provide period progress [updates] on extent of condition evaluation.”

Oversight in Misoperation Process

Finally, the infringement of PRC-004-5(i) — specifically requirement R5, mandating development of corrective action plans (CAPs) for misoperations of protection system components — was reported by PG&E on May 22, 2020.

The utility notified WECC that on April 12, 2019, a transformer bank at a substation tripped out-of-section because a protection system misoperation, resulting in an interruption to another transformer in the same substation. PG&E submitted a report to its CAP program documenting corrective actions and developed a CAP for the misoperation within 120 calendar days, as required by the standard.

In addition, the utility determined that the CAP “was not applicable to its other protection systems” after reviewing all of its misoperations since 1999. However, this determination was not done until April 16, 2020, more than a year after the misoperation; the standard requires that such a conclusion be reached no more than 60 days after the event, putting PG&E in violation for the intervening time.

WECC determined that the violation posed a moderate risk, but it noted that the utility had committed similar infringements on six other occasions by failing to evaluate a CAP’s applicability to other protection systems than those involved in the initial misoperations. The RE observed that “such failure could have resulted in additional misoperations” leading to more serious issues like the loss of a transformer.

PG&E’s mitigation plan included providing refresher training to protection system personnel regarding PRC-004 requirements and performing an extent of condition review to find any other potential issues. The utility reported on March 4 that it had completed its mitigation plan; at the time of filing WECC was reviewing PG&E’s certification.

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Hydrogen: ‘Holy Grail’ or Rabbit Hole?

The gulf between the promise of hydrogen and the technology to make enough of it to help safely decarbonize power grids, industry and transportation in just a few decades is a challenge just now coming into public focus.

The outline of the potential dilemma emerged quickly during the Sept. 30 Future of Green Hydrogen webinar organized by the Environmental Business Council of New England

The virtual conference featured a policy and economic analyst, a hydrogen safety expert and a university researcher focusing on hydrogen as a potential pipeline fuel.

Speakers represented companies already investing in hydrogen technologies, including Toyota, (NYSE: TM), National Grid (NYSE: NGG) and Plug Power (NASDAQ: PLUG), who described their efforts to harness hydrogen’s potential.   

Paul Hibbard, principal at the Analysis Group, said green hydrogen has the potential to be “the Holy Grail of civilization,” as nations urgently work to reduce carbon emissions to net zero by 2050.

“It’s not going to be easy,” Hibbard stressed. “The transition timelines that we’re talking about are completely inconceivable relative to the pace of change that we’re used to in the sector. And the technological solutions for decarbonization are not readily apparent.” 

“Why are we focusing on hydrogen? In my view, being completely honest — and it’s not the sort of thing you want to say in public — it’s because it looks like a fossil fuel. When you think of all the potential decarbonization solutions that are being discussed, a lot of them don’t really look like the world we currently live in. Hydrogen absolutely does.”

Hibbard said a lot of the decarbonization will be based on electrifying automobiles and trucking, switching to heat pumps for heating and cooling in new construction, and moving toward a “potential trade-out of existing heating technologies” in existing homes and buildings.

“When you look at what the states are proposing and what’s in the pipeline from a decarbonization perspective in the electric sector … [you see] rapid increases in the demand for electricity on the one hand and changing the shape of electricity demand on the other as the sector acts as something of a sponge for greenhouse gases and transportation and building sectors,” he said. 

In other words, that decarbonization scenario relies heavily on the electric grid, and one based primarily on renewable generation.  And that’s the problem.

“That will significantly change the demand profile, and within 10 years the New York-New England region will become a winter peaking system, meaning power demand will peak when solar generation is out of the picture.” Offshore wind and imported Canadian hydropower and storage would be crucial in this scenario, he added.

The harder question to answer, Hillard said, will be whether the regional grid could meet the growing demand “without some form of thermal generation to back it up,” such as gas turbines burning hydrogen or fuel cells generating power by combining hydrogen with oxygen in ambient air. 

Safety First

Then there is the question of learning how to handle hydrogen safely.   

Nick Barilo, executive director of the Center for Hydrogen Safety at the American Institute of Chemical Engineers, said hydrogen as a general use fuel poses significant problems.

Citing accidents over the decades, including the Challenger space shuttle explosion in 1986, Barilo said the industry has developed strong safety protocols but that the public has no experience with hydrogen and plenty of misconceptions.

“Some of the things that we have run into so far are apathy, fear and the general misconception that it’s just like any other flammable gas,” he said.

But hydrogen has no color, is flammable at a wider range of temperatures and lower concentrations than methane and propane, and burns with a pale blue flame that is hard to detect, said Barilo.

Another problem that many may be unaware of, he said, is that the industry does not yet have a good “odorant” to add to hydrogen as it did to natural gas decades ago.

“The key for safety … [is] that it’s like any other flammable gas. You need to identify and eliminate those hazards and find mitigation measures,” Barilo said. “System integrity is critical. It’s a small molecule so that becomes even more important. Proper ventilation is a key to safety. And then managing discharges, detecting, and isolating leaks and not the least of which is training personnel. … There are a lot of things to think about.”

Devinder Mahajan, director of Stony Brook University’s Institute of Gas Innovation and Technology, said “there is a pretty solid foundation to move to hydrogen power … using methane in the mix.” 

Mixing green hydrogen with methane, presumably to feed gas turbines, “basically addresses the intermittency of power generation from renewables,” he said. 

The major challenge will be developing the technologies to lower the cost of producing hydrogen through electrolysis and then moving the gas to where it is needed.

Using the nation’s existing gas lines is one of the keys to an economical transition away from methane to hydrogen, said Mahajan. 

“Do we just abandon this $1 trillion infrastructure that is already in place by not using any gas or can we repurpose this infrastructure for hydrogen?  I think that is the question, and I think there is a fairly simple no-brainer answer. Why would you abandon a $1 trillion infrastructure that the public paid for, and just say let’s go on to something else that we don’t know anything about?”

As for hydrogen’s destructive impact on existing natural gas lines, Mahajan said federal labs and his institute have been working on detection technologies to enable utilities and pipeline companies to develop an early enough warning of such leaks to make a “business decision” about using an existing line.

No Silver Bullet

One company with some experience moving hydrogen is National Grid, which sees hydrogen as a “zero-carbon energy carrier” rather than a fuel.

“The decarbonization train is leaving the station, and hydrogen is definitely one of the engines,” said Christopher Cavanagh, and engineer with National Grid.

“We have a high degree of confidence that hydrogen can be safely blended with natural gas today. There may be changes, and we’re trying to figure out what exactly those are now. And we are not the only ones proposing this. 

“Our experience with hydrogen has been pretty substantial. We produced hydrogen as part of our synthetic natural gas production during the energy crunch in the ’70s and ’80s,” said Cavanagh. 

The most important question, he said, is how green hydrogen will be sourced.  “We’re going to produce hydrogen onsite in a distributed manner, from either onsite renewables or from purchased renewable power.

“New York state is supporting that, but it’s also supporting new centralized hydrogen production facilities,” he added.

Plug Power, a N.Y.-based fuel cell company that also builds hydrolysis equipment to make hydrogen, announced in February that it would build a plant in western New York to produced 45 metric tons of liquefied green hydrogen a day. 

Swarna Arza, vice president and operations general manager at Plug Power, said her company’s vision for the future is one “where we create the energy, we store the energy, and then when we have a downtime, we can use that same energy … and create the electricity that can substitute for any intermittent energy sources like wind.” She said Plug Power’s hydrolysis technology under development produces significantly more hydrogen than standard hydrolysis equipment. 

Plug Power is working with Toyota on a hydrogen project in California, Arza said. 

Refueling a hydrogen fuel cell car takes 5 minutes. | Toyota

Toyota, unlike major U.S. automakers, is already producing and selling fuel cell cars. In the U.S., Toyota’s Mirai fuel cell model is available in California, where 52 hydrogen refueling stations have been built.  Refueling time is five minutes.

Jacquelyn Birdsall, a senior engineering manager with Toyota’s fuel cell integration group, said the company’s goal is to reduce the CO2 emissions of its fleet 90% by 2050 compared to 2010 levels and that fuel cells vehicles are part of the strategy to accomplish that.

“Toyota believes in what we call a portfolio of solutions. I think that you’ve heard this from other members [today] as well. There’s not really one silver bullet; there’s not one great solution. It takes a combination of all [technologies].  
 
 “For us, that means hybrid, plug in hybrid, battery electric and fuel cell electric, she said.

Toyota’s progress at moving from gasoline to electric vehicles might be seen as an example of the road ahead for the massive electrification goals of industrial nations around the world. It will be expensive and take time.

Birdsall pointed to the Prius hybrid as a starting point. Introduced in 1997, Prius sales were initially slow, taking 10 years for the first one million sales. Today, Toyota sells 1.5 million hybrids annually around the globe.

“We sell more electrified vehicles than the rest of the auto industry combined,” she said. Toyota and Kenworth built 10 heavy-duty fuel cell trucks for use in California ports. | Toyota

Sales of Toyota’s Mirai, first introduced in 2014 and updated this year, have been slow. And the company more recently built 10 fuel cell electric Class 8 heavy-duty semi-trucks with Kenworth, each equipped with a 560-horsepower electric motor, Birdsall said. The trucks can haul 80,000 pounds and have a 300-mile range between fill-ups. They are in operation around the ports in Los Angeles.  

“We use about 10 times the amount of hydrogen in a truck that we do in a light-duty vehicle. So that increase in the fuel demand is driving down the cost of the hydrogen,” Birdsall said.

“However, in order to get the cost of the trucks themselves down, we need the volume of the fuel cell stacks, which comes from the light-duty market. So, we need to sell the light-duty vehicles as well to build more hydrogen … fuel cell stacks to drive down the cost of the technology itself.”

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California Can Get By Without More Gas, Energy Commission Says

The California Energy Commission adopted a midterm reliability analysis Thursday that determined the state can meet its 2023-2026 capacity needs without adding more gas generation but warned that extreme weather and the state’s dependence on battery storage could prove problematic.

“The analysis concludes that, given the assumptions, it appears that sufficient capacity has been ordered for midterm reliability from 2023 through 2026,” Liz Gill, advisor to CEC Vice Chair Siva Gunda, told commissioners. “However, additional retirements [of aging natural gas plants] would increase the likelihood of system reliability challenges.”

The analysis did not “capture the frequency and dispersion of extreme climate events” or the higher demand from electrification of the transportation and building sectors, Gill said. The CEC is working to include those factors in future analyses, she said.

The second conclusion of the analysis was that “a portfolio of zero-emitting resources can provide the equivalent system reliability compared to fossil fuel resources,” but lithium-ion battery performance must be monitored as storage plays a larger role, she said.

The vote on the midterm reliability analysis followed two CEC workshops on Aug. 30 that examined the role of natural gas in the energy mix through 2026 as the state’s last nuclear plant retires, older gas plants close, and the grid relies more heavily on renewables and storage. (See CEC Looks at Gas for Midterm Reliability.)

The CEC’s demand forecasts inform procurement decisions by the California Public Utilities Commission.

In June, the CPUC ordered utilities to procure an additional 11.5 GW of capacity by mid-decade but intentionally left open the question of whether more gas generation is needed. (See CPUC Orders Additional 11.5 GW but No Gas.)

A proposed decision by a CPUC administrative law judge said the state needed up to 1,500 MW in additional gas capacity, but CPUC commissioners rejected that component amid a public outcry. (See CPUC Proposes Adding 11.5 GW of New Resources.)

“The revised [proposed decision] that we’re voting on today removes the requirement to procure any fossil resources, and instead our staff will work with the Energy Commission staff to conduct additional analysis over the next few months about the need for fossil resources for reliability purposes,” CPUC Commissioner Clifford Rechtschaffen said at the time. “The results of this analysis from our staff and the Energy Commission will help inform our next procurement decision, which we will debate about later this year.”

Thursday’s analysis found the CPUC’s 11.5 GW no-gas procurement order was sufficient to ensure reliability through 2026. Under the order, the state is expected to add 10 GW of four-hour battery storage, 8.3 GW of solar capacity, 2.5 GW of wind, 1.2 GW of geothermal power and 1 GW of long-duration storage.

Concerns have been raised that the international supply chain for battery production might not support the projected growth, Gill said. The analysis applied a one-year delay to 20% of new battery resources and found that it did not undermine reliability, she said.

Battery Performance

The analysis also raised the issue of battery performance, including charging and outages.

Battery outage rates need more analysis as the technology is deployed, Gill said.

A Sept. 4 outage at Vistra Energy’s Moss Landing Energy Storage Facility, the world’s largest battery array at 400 MW, pointed to one potential flaw in lithium-ion batteries: overheating. Initially the incident was blamed on high heat and fire, but Vistra said in a Sept. 30 statement that it has so far found no evidence of batteries exceeding acceptable temperature limits when its sprinklers went off, damaging a small percentage of units.

The CEC projects a 12,000 MW increase in battery storage from 2022 to 2026. | California Energy Commission

Limitations on imports, solar and hydropower could affect charging conditions, Gill said.

The analysis looked at scenarios in which imports were limited by up to 5,600 MW, hydropower was limited to average minimum generation during non-peak hours, and solar was reduced by 15% to 45% to reflect cloudy or smoky conditions.

The CEC analysts found there was sufficient capacity on the grid until both imports and hydropower were constrained and solar output dropped by 45%.

“Given the extreme nature of this scenario, staff has determined that it does not appear energy sufficiency will be a limiting factor to system reliability in the next five years,” Gill said.