November 15, 2024

Lordstown Motors Production Line Down at Least Until April

The electric vehicle manufacturer that once aimed to be the first to offer an electric pickup truck solely to commercial customers is now uncertain whether it will resume production following a second recall to address supply chain and parts quality issues while facing continued financial stress.

Edward Hightower, CEO of Ohio-based Lordstown Motors (NASDAQ:RIDE), told analysts Monday during the company’s call to discuss fourth-quarter and full-year 2022 earnings results that the company is seeking another partner in addition to Taiwanese-based FoxConn Technology Group, an international contract manufacturer.

At issue is the creation of a network of suppliers manufacturing the myriad electrical and mechanical parts not only for the current pickup truck, the Endurance, but also for new vehicles that Foxconn and Lordstown are now beginning to design.

Lordstown announced its first recall and decision to shut down its assembly line on Feb. 23 over an issue in an electrical system component that the company determined could lead to a loss of power while driving. (See Lordstown Motors Recalls Endurance Electric Truck.)

Hightower said the company issued the second recall after a parts supplier said a component in the truck’s brake assembly did not meet specifications. It is now involved in a lengthy root-cause analysis with its suppliers to prevent future problems.

“Our team has also worked closely with our supplier network to root-cause the other post-launch quality issues and develop and implement corrective actions, which have included part quality corrections, part design modifications, retrofits and software updates,” he explained.

And he underscored the importance of finding another partner to make improvements to the Endurance and begin mass production of the vehicle.

“While we continue to pursue partnership opportunities, should we not identify a partner in the coming months, we may decide to pause commercial production of the Endurance until a partner is identified,” he said.

Foxconn has already invested hundreds of millions of dollars in Lordstown, initially agreeing to buy the 25-year-old sprawling former General Motors assembly plant from it in November 2021 for $230 million. A year later, Foxconn invested another $170 million, purchasing about 19% of the company’s shares and gaining two seats on its board of directors. (See Lordstown Motors Gives 2 Board Seats to Foxconn.)

The joint venture did not begin to produce the Endurance until late 2022. So far it has only built 48 trucks and sold only three in the fourth quarter of 2022.

Lordstown ended 2022 with $221.7 million in cash and short-term investments, about $57 million (34%) higher than expected, the company said in a release accompanying the results.

“We expect to end the first quarter of 2023 with $150 [million] to $170 million in cash and short-term investments, excluding any additional Foxconn funding, other equity sales or contingent liabilities.”

Experts Discuss ‘Public’ Part of PSPS

VANCOUVER, British Columbia — Utilities shared ways to narrow the impact of public safety power shutoffs (PSPS) — and convince customers of the need for them — at the Western Interstate Energy Board’s Winter Wildfire Meeting last week.

The practice of PSPS — preemptively shutting down power lines to prevent ignition of wildfires — originated with utilities in California but has since spread across the West as a way to mitigate the risk of catastrophic wildfires in the face of climate change.

When Portland General Electric (PGE) initiated its first PSPS in Oregon’s Mount Hood corridor in September 2020, area residents understood the need for the utility’s preemptive measure because they were already feeling the impact of fires burning elsewhere in the state, said PGE Director of Wildfire Resiliency and Mitigation Bill Messner.

“That worked really well in the sense that we did turn off the power, but it also worked really well with the community because they saw smoke and they saw flames, so I think you can put the correlation really quickly together,” Messner said.

The massive wildfires ignited over Labor Day weekend 2020 and burned about 1.2 million acres of dense forest in normally temperate Western Oregon. The fires killed 11 people, destroyed more than 4,000 homes, leveled entire communities and spread within 25 miles of the city of Portland. Portland-based PacifiCorp already has paid out settlements for its role in starting at least one of the fires, but PGE’s equipment was not implicated in any of them.

In 2020, PGE had just one PSPS zone within its 4,000-square mile territory. By last year, the number of zones had grown to 10, including the heavily forested West Hills area in Portland. All 10 were subject to shutoffs at various times last September in the face of high winds and low humidity at the tail end of a dry summer.

“We actually added some other preventative outage areas as we were learning more about what was happening, and we were being proactive in other areas,” Messner said. “I think ‘just be agile’ is probably one of the biggest learnings that you have to have in this space.”

The utility learned another lesson from the unexpected timing of outages, which sometimes had to be initiated at night. “We were turning off power at two in the morning,” Messner said. “Well, sending messages at two in the morning when someone is sleeping is not very helpful.”

Despite the recent history of wildfire, some Oregon electricity customers are unconvinced about the need for PSPS, Messner said. Some of that confusion might stem from how utilities communicate with the public about the reasons for the policy.

“I think one of our challenges … is that we have several utilities in Oregon. Are we using the same words? Are we saying the same thing? Or are we causing confusion with our attempt to not cause confusion?” Messner said. To improve the company’s communication around PSPS, PGE has created the position of “customer manager” within its incident management team, who is tasked with gathering feedback from customers and improving the utility’s communication with them.

Claire Halbrook, director at California-based consultant Gridworks, said effective communication around PSPS requires “teams of people,” which can be challenging to assemble for just one season.

“So where are these resources going to come from if they’re only needed for part of the year? What are they going to be doing for the remainder of the year? Or are we trying to pull people from their day jobs to do this during wildfire season? And what are the disruptions to those teams and normal course of business?” said Halbrook, who previously worked for Pacific Gas and Electric.

Halbrook emphasized the importance of working with impacted communities to ensure essential services remain energized during a PSPS.

“I also would encourage surveying large customers to see who already has backup generation, and how much of their own load it can serve,” she said. “A big thing we did at PG&E in 2020 was work with many of our local hospitals to ensure that they had backup generation and to provide additional support if needed.”

“The communities that are most vulnerable are often the least resourced to engage with us,” said Oregon Public Utility Commission member Letha Tawney, the panel’s moderator.

“Absolutely,” Halbrook said. “I think we’re asking a lot of our communities to engage with utilities on a variety of fronts around emergency management and other topics. [It’s important to make sure the utilities are] providing them the information and resources they need in an easy way, [and] key contacts within your organization [that] they could reach out to with questions. And engaging in education and listening to their questions and concerns is going to be really important.”

Not Just a Western Issue

Tawney asked the panelists what steps utilities are taking to mitigate the impact of PSPS when fire risk is high.

“I think we learned a lot from PG&E,” Messner said. “I mean, to be frank, when they first started this, they were turning the power off at the substation, right? So there were hundreds of thousands of customers being impacted — and then having to deal with communication challenges about that.” From that experience, PGE learned to narrow the impact of outages from a switching standpoint, he said.

PGE in the past three years has sharply increased the number of weather stations it relies on for monitoring conditions across its service territory, Messner said. During the September 2020 event, the utility relied only on weather data from Portland International Airport at the northern edge of the city. Now it gathers information from about 50 different weather stations and solar-powered surveillance cameras to make more pinpointed decisions.

“I don’t think you can underestimate the importance of the mapping and modeling,” said Mike Bartel, vice president of operations at Alberta, Canada, transmission operator AltaLink. “Every time we go around looking at refinements, it either scares me that the model may not be right, and we’re focused in the wrong places, or it gives me lots of confidence because I’ve got a number of weather experts and forestry experts telling me we’re focused in the right places.”

Bartel also pointed to the need to have “boots on the ground” validating conditions, especially on a transmission right of way, to avoid overreacting to information from a weather station that might be located three miles away.

“At this point in time, every utility across the West needs to know which of its lines are at risk, [and] under what conditions,” Halbrook said. “Are these transmission lines, distribution lines, both? Where along the line is there potential for risk? What are all of the customers that are served by that line that will be impacted if it’s shut off? What is the driver of the risks?”

Pointing to recent wildfires in Florida, Messner said he thinks states across the U.S. — not just the West — will one day face the need to implement PSPS on their grids.

“I think climate change is going to come all the way through … so any state that thinks that this is not going to be a tool they need to have in their tool chests, I think they’re mistaken,” he said.

Advocates’ Report Slams Hydrogen as Heating Fuel

A group pressing Massachusetts’ transition to carbon-free fuels is trying to head off consideration of hydrogen as a wide-scale replacement for natural gas.

Producing green hydrogen in quantities sufficient to supply all the structures now heated with gas would consume all the clean electricity that offshore wind is projected to supply to Massachusetts, according to a report released Monday by Gas Transition Allies, a coalition of more than two dozen organizations, advocates and researchers.

Decarbonizing the power grid and ramping up green hydrogen production would be impossible to do simultaneously by 2050 or even longer, the report concludes.

The report is the latest dispatch in an ongoing competition between environmental advocates and natural gas delivery companies to shape policy and opinion as Massachusetts moves to a net-zero future.

The Massachusetts Department of Public Utilities has drawn comments from all sides of the debate in its investigation (20-80) of the role of natural gas local distribution companies as the state moves toward its 2050 climate goals.

Green hydrogen is the subject of research and development on multiple fronts. It holds promise because it does not produce greenhouse gas emissions when burned, but the cost of production currently is not economical for many purposes.

Also, if the electricity used to produce hydrogen is generated by burning fossil fuels, the climate-protection benefit of hydrogen produced is negated.

This is at the heart of the new report, “Impact of Green Hydrogen Production on the Availability of Clean Electricity for the Grid.”

Key points include:

  • 3.2 GW of offshore wind capacity is predicted to be available for Massachusetts by 2030.
  • Replacing 100% of natural gas in all Massachusetts structures that now use it as a heating fuel with an 80/20 blend of natural gas and green hydrogen would require 3.9 GW of nameplate offshore wind capacity.
  • An 80/20 blend would result in only a small emissions reduction that falls far short of state mandates.
  • Replacing natural gas with 100% green hydrogen would require 19.7 GW of offshore wind power, plus an enormous expenditure on hydrogen-compatible equipment and infrastructure.
  • Electric heat pumps are a better option — 3.7 times more efficient than hydrogen boilers.

The report bases its calculations on a series of assumptions about the power output of offshore wind turbines and power demand of hydrogen electrolyzers. Some of the data points will likely improve, given the amount of effort being poured into research and development.

For example, the report assumes 43 kWh of electricity will be needed to produce 1 kg of hydrogen, which is low by current standards. But the U.S. Department of Energy in 2021 launched one of its Energy Earthshots, seeking to cut the cost of clean hydrogen production by 80%.

‘Inherent Flexibility’

Two of the natural gas LDCs that will be directly affected by Massachusetts policy decisions told NetZero Insider on Monday they continue to see hydrogen as a potential path to net zero.

Unitil (NYSE:UTL) spokesperson Alec O’Meara said the company was still reviewing the report. He added:

“Regarding hydrogen in general, we very much believe fully endorsing or ruling out any one specific energy solution would be premature at this time. Unitil is a firm supporter of the commonwealth’s stated emission goals, and as a company we are continuing to explore the potential of a wide number of different renewable natural gas options, including hydrogen.”

National Grid (NYSE:NGG) spokesperson Christine Milligan said the company is firmly committed to its net-zero goal, pursuing it through energy-efficiency programs, offshore wind, EV charging programs and, eventually, hydrogen.

“Green hydrogen is currently being demonstrated around the world as a renewable carrier and a means for long-term storage of renewable power. Its inherent flexibility means it can be used synergistically with solar and wind and, if used for heating, might reduce the potential for renewable power curtailments like those seen already in California,” she said.

“With billions of dollars in federal support for clean hydrogen coming through the IRA [Inflation Reduction Act] and IIJA [Infrastructure Investment and Jobs Act], green hydrogen is going to get much more affordable and more abundant in coming decades. We feel it can play a very important role in helping meet our decarbonization goals and has a range of use cases.”

‘Not Well-suited’ for Local Distribution

Other proponents and opponents of green hydrogen have made their points regularly, in Massachusetts and elsewhere.

At a recent press briefing, environmental advocates decried the possible use of hydrogen in New England, calling it inefficient, explosive and leak-prone. 

“There are roles for hydrogen, in hard to decarbonize sectors,” said Steven Hamburg, chief scientist at the Environmental Defense Fund. “But hydrogen is not well-suited for thinking about applications in an urban environment for local distribution-related services like what we do with natural gas.” 

“If we just keep going with the status quo, with gas utilities continuing to pretend there’s a path to keep the pipes running indefinitely, we’re going to have a utility death spiral where people who can afford to leave the system do. People who can’t leave … are going to be stuck holding the bag and paying ever higher costs,” said Caitlin Peale Sloan, a vice president at the Conservation Law Foundation. 

At a recent meeting, ISO-NE board chair Cheryl LaFleur questioned the wisdom of replacing gas systems with hydrogen. 

“As far as hydrogen as a complete substitute for gas … that’s a much more expensive system to retrofit than to retrofit the lines to power plants,” LaFleur said. 

Poll Shows Michigan Voters Split on EVs

LANSING, Mich. — Michigan officials and the Big Three automakers are making massive efforts to transition to electric vehicles, but a new public poll shows almost half of Michigan voters oppose the shift, and more than 60% said they would not consider buying an EV in their next purchase.

Of the 600 voters asked, 46.4% supported the overall shift toward EVs, while 44.4% opposed the move, the poll showed.

The poll, conducted in mid-February by the Glengariff Group of Lansing and commissioned by the Detroit Regional Chamber, also showed that more than 44% of the 600 likely voters polled thought the push toward EVs was being driven primary by government regulations and incentives. Just 18% of those polled thought consumer demand was driving the push toward EVs. The poll has a margin of error of 4%.

Both the industry and state are pushing a shift to EVs. Ford Motor (NYSE: F), for example, is preparing to spend $3.5 billion to build a large plant to produce EV batteries near the tourist city of Marshall in Calhoun County. The state is committing to spend some $1.6 billion in incentives to lure the plant, which is expected to employ 2,500 people.

In addition, the state’s Mi Healthy Climate Plan calls for a major increase in EV usage by 2040, including converting 100% of the state’s light-duty vehicle fleet to EVs by 2035.

But the poll shows that support for EVs in Michigan depends on a variety of factors, including the region the respondent lives in, their age and especially their political leanings.

The poll showed voters living in the Metro Detroit area, where the economy remains strongly centered on the auto industry, support the shift to EVs by 53.3% to 32.4%. Those living outside the Detroit area oppose the shift on a basis 40.2% to 50.6%.

The poll also showed that 51.2% of voters between 18 and 29 years old would consider buying an EV, but 74.7% of those older than 65 would not consider buying an EV.

And 56.6% of voters considering themselves strong Democrats said they will consider buying an EV, but 83.9% of those who are strong Republicans said they would not consider buying an EV.

Of those opposing a shift to EVs, 19.6% said the state’s electric grid could not support the vehicles, another 18.4% said the shift would be too expensive and 13.3% said Michigan’s infrastructure could not support the shift to EVs.

Glengariff Group President Richard Czuba said the poll showed voters are getting caught up in the “culture wars.”

“I don’t think we should be shocked to see this, but I do think it’s a challenge for the automakers simply because you’ve got half of the population saying they won’t even consider this,” he said.

Vistra Pays more than $3 Billion for Energy Harbor

Vistra (NYSE: VST) said Monday it will buy Energy Harbor and combine the two firms’ nuclear plants, renewable facilities and retail businesses into a new subsidiary called “Vistra Vision.”

Vistra is paying $3 billion and assuming $430 million in debt, while Energy Harbor’s two biggest shareholders, Nuveen and Avenue Capital, will continue to own 15% of Vistra Vision. Vistra’s fossil assets, which total 24,000 MW of natural gas units and 8,400 MW of coal, will be in a separate subsidiary called “Vistra Tradition.” The deal needs to be approved by the Department of Justice, FERC and the Nuclear Regulatory Commission; Vistra expects it will close later this year.

“Through this creative transaction we will combine Vistra’s nuclear, retail, renewables and battery storage assets with Energy Harbor’s nuclear and retail assets to create one of the largest clean energy businesses in the country,” Vistra CEO Jim Burke said on a conference call with analysts.

Energy Harbor, which was spun off from FirstEnergy (NYSE:FE), owns three nuclear plants in Ohio and Pennsylvania and has a competitive retail power business serving 1 million customers in PJM and MISO. That will be matched with Vistra’s Comanche Peak nuclear plant in Texas, its renewable and storage projects around the country, and its retail business in Texas and other states.

Vistra Vision will have a about 7,800 MW zero-carbon generation, about 5 million retail customers and access to a pipeline of 1,100 MW of additional renewables projects. It would be the second largest operator of nuclear plants in the country with six reactors across its four plants.

With the country navigating a transition to cleaner energy, nuclear provides the unique capability of being both carbon free and available around the clock to serve demand, Burke said.

“The nuclear production tax credit provides significant downside protection while maintaining the ability to capture upside through market volatility and … hedging forward,” Burke said.

The federal PTC for nuclear, part of last year’s Inflation Reduction Act, will effectively give the firm’s four nuclear reactors an earnings floor. It provides revenue support when a nuclear plant’s “gross receipts” are below $43.75/MWh and can contribute up to $15/MWh when gross receipts drop to $25/MWh.

Power prices were much higher when Vistra first considered the deal last summer because of spiking natural gas, but Burke said his firm is doubtful that prices can go much lower and does not expect cheap natural gas, or resulting power prices, to stick around long.

“Our returns on our PTC case are not that much further below the returns that we actually modeled for this,” Burke said. “And we think we’re modeling closer to the downside of the opportunity with still a lot of upside opportunity, depending on how gas and power … behave from this point forward.”

While Vistra Tradition would be home to the firm’s fossil assets, Burke said that Vistra Vision would use its generation to firm up supplies for retail customers as needed.

Keeping the traditional generation around also gives the firm a larger scale, which could help it invest in new technologies as they become viable, he said.

“We’ve got some opportunities with sites to do things with future nuclear technologies, potentially even at existing coal sites and sites that we’re retiring,” Burke said.

The firm’s coal plants are eventually going to retire, but Burke expects the natural gas generators will be needed for a long time to come.

Separating the two businesses gives investors and customers more visibility into the clean energy assets that Vistra has, Burke said, conceding that it might eventually make sense to split the two businesses completely.

“But right now, these are both scaled businesses with some interdependencies, and so I think we’re going to focus on running this in an integrated fashion for a while,” he added.

EBA Addresses ‘Zeitgeist’ of Western Regionalization

SAN FRANCISCO — CAISO had just won approval from its Board of Governors last month for a day-ahead extension of its Western Energy Imbalance Market when a state lawmaker introduced a bill a week later to allow the ISO to become an RTO, CEO Elliot Mainzer recalled Thursday in his keynote address at the Energy Bar Association Western Chapter’s annual meeting.

Elliott Mainzer 2023-03-02 (RTO Insider LLC) FI.jpgCAISO CEO Elliot Mainzer | © RTO Insider LLC

“Some of us thought, ‘Oh boy, we just got EDAM [the extended-day ahead market] done. Wouldn’t it be nice to have a little bit of time just to let that play out and let that evolve?’” Mainzer said. But the “zeitgeist in the West” is one of rapidly evolving efforts to organize the region’s balkanized electricity sector into markets and programs that could lead to RTOs, he said. (“Zeitgeist” is a German word meaning “the spirit of the times.”)

The measure introduced Feb. 8, Assembly Bill 538, by Assemblymember Christopher Holden would allow CAISO to develop a plan for governance independent of California’s governor and legislature, with a governing body that could include members from other states. (See Lawmaker Introduces Bill to Turn CAISO into RTO.)

“The reality is that … outside of California, I think a lot of people who are thinking about making significant additional investments either in the day-ahead market or even beyond … want to see a pathway to independent governance for the ISO,” Mainzer said. “And I think they need to see that as a way to get them comfortable staying with [CAISO and the Western EIM] and continuing to invest and grow with our organization as it evolves.”

Mainzer’s remarks in his keynote address were part of a discussion at the meeting about efforts by CAISO, SPP, the Western Power Pool (WPP) and others to assemble the West’s 39 balancing authorities into mutually beneficial organizations for resource adequacy, transmission planning and market transactions.

About 100 energy lawyers gathered at the historic Westin St. Francis hotel on San Francisco’s Union Square for the chapter’s first in-person meeting since the COVID-19 pandemic began three years ago.

WRAP and EDAM 

Sarah Edmonds 2023-03-02 (RTO Insider LLC) FI.jpgWPP CEO Sarah Edmonds | © RTO Insider LLC

In a panel on resource adequacy, WPP Executive Director Sarah Edmonds described FERC’s recent approval of the group’s Western Resource Adequacy Program, a West-wide RA effort with 18 participants and three more expected to join. (See FERC Approves Western Resource Adequacy Program.)

The order allows the WRAP to move forward with a binding phase of its program, which would hold members accountable for failing to meet their resource requirements as part of the RA pool.

“We are currently working to identify what season WRAP goes binding,” Edmonds said. “The tariff that [FERC] approved allows flexibility for the region to determine which season, winter or summer, between now and 2028, [that] we’re going to select.”

CAISO and SPP executives described their efforts to organize markets in a panel on Western regionalization, while a strategic planner for Arizona’s Salt River Project offered the views of one potential market participant.

Anna McKenna, CAISO’s vice president of market policy and performance, highlighted the success of the Western EIM (WEIM), which has generated $3.4 billion in participant benefits since it began in 2014. The performance of the market, which has dealt only in real-time transactions, is the ISO’s main selling point for utilities to join the EDAM, which would encompass the much larger day-ahead market.

EBA Regionalization Panel 2023-03-02 (RTO Insider LLC) Alt FI.jpgA panel on Western regionalization included (from left) Tony Braun, attorney; Anna McKenna, CAISO; Josh Robertson, Salt River Project; and Paul Suskie, SPP. | © RTO Insider LLC

 

The WEIM has 19 members, including some of the West’s largest utilities such as PacifiCorp and the Bonneville Power Administration. After three new members join this year, it will encompass roughly 80% of load in the Western Interconnection.

“It’s been extraordinarily fruitful for all of us,” McKenna said.

Adding a day-ahead market would leverage the WEIM’s success by allowing Western entities to coordinate their diverse resources — hydropower, solar, wind and thermal generation — into the day-ahead time frame, “which of course, as you can imagine, really unleashes an extraordinary amount of opportunity for our diversity to be really optimized across those footprints.”

A study commissioned by CAISO found the EDAM could produce $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection. (See West Could Save $1.2B a Year in CAISO EDAM.)

The CAISO board and the WEIM Governing Body approved the EDAM on Feb. 1. It still requires FERC approval. The ISO is developing a tariff for stakeholder review and hopes to submit it to FERC later this year.

“With all the attorneys in this room, you guys can’t wait to get your hands on that. It’s coming,” McKenna said to laughter. “One thing I’d like to do is invite you all to really participate closely in that process because one of the benefits we get is your legal input and insights on the documentation we put out there. So please do participate.”

RTO West, Markets+

SPP is planning to offer its own day-ahead energy imbalance market as part of Markets+, a program currently in development, said Paul Suskie, SPP’s general counsel and executive vice president of regulatory policy.

SPP is also planning RTO West, a Western version of its Eastern Interconnection RTO. Nine entities have committed in writing to joining the RTO, including three regions of the Western Area Power Administration and utilities in Colorado and Wyoming.

Markets+ has signed funding agreements with eight Western entities for the program’s first phase, in which stakeholders will help draft tariff language and outline a governance plan. (See related story, SPP Moving Quickly on Markets+’s Development.)

Suskie said SPP plans to apply its governance model — with an independent board, a committee of state regulators and stakeholder groups that develop and vet policy proposals — to Markets+.

“It’s a very effective process [that] … empowers organizations and people to get in the room discussing … issues, to develop the actual tariff language and vote on [what] is ultimately filed at FERC. So, when we make a filing at FERC, it’s language that has been vetted, voted on, debated and amended through the stakeholder process.”

Suskie said he thinks FERC will approve RTO West before Markets+ because the RTO model is more familiar than the novel Markets+ design.

‘Towards an RTO’

The Salt River Project, a participant in the WEIM and one of the utilities that signed a funding agreement for Markets+, wants to “see two really good [day-ahead] market options come forward” from SPP and CAISO to determine which would benefit its customers most, said Josh Robertson, the utility’s director of energy market strategy.

The utility favors an incremental approach to market development, and a day-ahead market is already a big step compared to a real-time market, Robertson said.

“EDAM, potentially the next step, might be enough,” he said. “We don’t know. We might be good with that. But we do value the possibility of moving forward with an RTO, and seeing a pathway towards an RTO will be an important aspect in terms of our eventual decision-making and our engagement,” Robertson said.

As one or more RTOs emerge in the West, independent governance will be key to SRP and others joining, he said, echoing Mainzer’s keynote remarks.

“It’s just really important that these markets have a transparent, independent governance process,” Robertson said. “We don’t want a single entity, region [or] state … to be able to drive the decision-making here. It really needs to be independent and transparent.”

West Must Fight Wildfire with Fire, Forest Scientists Say

VANCOUVER, British Columbia — Scott Stephens, professor of fire science at the University of California, Berkeley, last week offered an unexpected piece of advice for Western U.S. states and Canadian provinces that face a rising danger of catastrophic wildfires.

“Don’t do what California did,” Stephens said Wednesday during the opening panel of the Western Interstate Energy Board’s (WIEB) Winter Wildfire Meeting.

Scott Stephens (University of California Berkeley) FI.jpgScott Stephens | University of California, Berkeley

At the core of Stephens’ advice was a seemingly paradoxical message that would be reinforced by other panelists throughout the conference: that the growing wildfire threat in the West is as much a product of a century of strict fire-suppression practices than of climate change.

Stephens opened his presentation with a picture showing the aftermath of the 2021 Dixie Fire, the second largest wildfire in California history, which scorched more than 963,000 acres and destroyed several small communities over that summer. California’s Department of Forestry and Fire Protection later pinned the source of the fire on a Pacific Gas and Electric distribution line that was struck by a tree. (See Cal Fire Finds PG&E Started Massive Dixie Fire.)

“The Dixie Fire was horrendous. It is a disaster times 10,” he said. “I’ve been in that thing [burn area] for about three weeks in June of last year to see some of the effects. It literally is something that can make you cry: the damage to the forest ecosystem; [it] burned down the town of Greenville. There’s so many connotations to this that we’ve got to do better.”

‘This is a Disaster’

For Stephens, doing better means looking back to a time before the displacement of indigenous peoples, who for centuries engaged in the practice of controlled burns to maintain forest health and prevent large-scale wildfires that could threaten their living spaces.

Stephens pointed to a study from 1924 that described California’s pine forests as “broken, patchy, understocked stands, worn down by the attrition of repeated light fires.” The ground contained little surface fuel, and extensive crown fires — in which the fire moves from treetop to treetop rather than along the forest floor — were “almost unknown,” the researchers found.

But since that time, federal and state policy has aimed to discourage the spread of any fires, even those occurring naturally. That has fostered the development of denser forests where trees increasingly compete for space, compromising the health of many of the oldest, most fire-resistant trees, and creating fuel load to feed the fast-moving and highly destructive crown fires that have plagued California in recent years. On top of that, many of the largest trees most resistant to burning have been harvested for lumber.

A 2022 study cited by Stephens found that in 1911, 73 to 85% of California’s mixed conifer forests were in a condition of “free” or “partial” competition among trees. By 2011, 82 to 93% of those forests were in “full occupancy” or “imminent mortality.”

“This is a disaster,” he said. “If you have a forest ecosystem going into climate change with those characteristics, you better just hold on, because that forest is not resilient.”

Stephens said the increasing number of unhealthy, fallen trees on the forest floor translates into heavy fuel loads that make it impossible to predict how fires will behave once they start. He noted that the 2020 Creek Fire in the Sierra National Forest, which burned nearly 380,000 acres, occurred under normal wind, temperature and humidity conditions. The fire was not driven by wind but by dead wood on the ground, and its movement defied models designed to predict how it would spread.

“This was actually kind of scary, both for our managers [and] utilities … because it tells us that not a single model in the United States is able to predict what these fires can do under the worst conditions,” he said.

Stephens finds hope in a different approach to forest management that draws on the historical practices of indigenous peoples. For more than a year he’s been participating in the Stewardship Project, which he described as a “50/50 partnership” among tribes and “Western science” across the Western U.S. The project aims to address issues such as a tribal right to steward forests, regulatory reform around fire-management practices and workforce development to manage woodlands.

“What we’re trying to do is come up with some policy recommendations for the federal government,” said Stephens, who sits on the Wildland Fire Mitigation and Management Commission, created by the Infrastructure Investment and Jobs Act of 2021.

He recommends that policymakers allow forest managers to adopt practices that include prescribed burns when conditions permit, as well as “restoration thinning,” which would entail mechanical removals that focus on what should be left behind to create a more resilient forest — based on tree species, sizes and spatial patterns — rather than what should be taken out. And although some tree removals might end up in sawmills, economic harvesting of timber would not be a priority.

‘Era of Megafires’

“When Scott comes here and tells me, ‘Don’t do what we did,’ it makes me nervous because we keep watching to learn from California and to help us track where we’re going and the attempts that we’re making to be proactive in this same space,” said Lori Daniels, a professor in the Department of Forest and Conservation Sciences at the University of British Columbia.

About 95% of British Columbia’s land is publicly owned, and the province contains about 235.8 million acres of forest, of which nearly 59.3 million are actively managed. Roughly 494,000 acres are harvested annually, although that number has declined in recent years, according to Daniels.

Daniels said the province has already adopted a timber harvesting policy that is “meant to emulate what fire used to do on our landscapes.”

The province experiences about 1,700 fires a year, with lightning causing 60% and humans the other 40%. About 94% of all fires are quickly extinguished.

“So the only fires that we have experienced in our lifetime are the top 6% that burned under extreme weather, heat, drought [and] wind and escaped all our modern technologies to put out fires. So we have this really biased view of what fire is,” she said.

As in California, fire-suppression practices over the past century have resulted in denser forests that are now fueling larger wildfires in British Columbia in recent years. While the province has experienced some large burns in the past (about 1.7 million acres in 1920 and 2.1 million acres in 1958), recent years have seen fires growing even bigger. In both 2017 and 2018, it saw burns exceeding 2.9 million acres. During the Pacific Northwest heat wave of summer 2021, temperatures in the village of Lytton hit a record-shattering 121.3 degrees Fahrenheit on June 29. The next day, a fast-moving wildfire swept through the area, destroying 90% of the village and killing two people.

“It’s the cumulative impacts of both extreme weather [and] these land-use changes that have been building up over a century,” Daniels said, adding that we live in an “era of megafires.”

Daniels said British Columbia’s success in extinguishing wildfires has made residents “naive,” thinking they can dial 911 to have firefighters put out any fire.

“Our fear and our desire to protect our lives and homes — and our forests and our livelihoods — from fire has contributed to the problem,” Daniels said, noting the importance of logging to the region’s economy. The province’s forests are still managed with an eye to maintaining timber harvests, which has “homogenized the landscape” and puts the focus on economics rather than forest resilience.

But conditions have changed, she said, and there is now a need to put “pressure on our decision-makers to make it a priority to make the [policy] changes that are needed.”

Key among those changes is the need to “coexist with fire” in the landscape. The province has already moved in that direction, having in 2014 adopted a policy of permitting some fires to burn in locations away from communities when it’s considered safe to do so — allowing “fire back as part of the ecosystem, creating heterogeneity and breaking up those fuels,” Daniels said.

It’s an approach to forest management that New Mexico has also recently adopted, according to Lindsey Quam, deputy state forester and tribal liaison for the New Mexico Energy, Minerals and Natural Resources Department’s Forestry Division, who spoke on a separate panel Thursday.

Quam said that in New Mexico, climate change is bringing higher temperatures and a windy season that starts earlier and lasts longer, “which is drying out our fuels a lot faster,” particularly in the “high country” areas at elevations of about 12,000 feet.

“We’re working outside the norms of what we’re used to, predicting what fire may do; what winds may do; what temperatures may do. How that’s going to impact or affect fuels is getting harder and harder” to predict, Quam said. “Our models can’t keep pace. Our models are working beyond what they were built and designed for, so we don’t have a good prediction in order to know what we may be facing out in the forest.”

‘Fire is not the Enemy’

In response to the changing conditions, in 2020 the New Mexico Forestry Division implemented the Forest Action Plan, a “science-based” plan that uses geospatial analysis to assess threats to the state’s natural and cultural resources. The plan includes 10 strategies, including those related to forest and watershed restoration, fire management and utility rights of way (ROWs). The latter strategy seeks to work with utilities to clear out ROWs to reduce wildfire risk and ignition, providing $1 million in state funds to support those efforts. It also works to incorporate state utility data into the federal Wildland Fire Decision Support System for guidance during wildfires.

Additionally, New Mexico lawmakers in 2021 passed the Prescribed Burning Act, which focuses on encouraging more prescribed burns on the state’s private lands. The law is intended to reduce liability for private landowners and created a program to certify burners.

Lindsey Quam (New Mexico Forestry Division) FI.jpgLindsey Quam | New Mexico Forestry Division

Quam pointed out that recent studies on New Mexico’s Jemez Mountains and Gila National Forest indicate that past fires in those areas were larger but less destructive than present-day burns. He said the research is finding that those fires were purposely set by tribes “to create a defensible space around their living areas.”

“We have to consider that we really need to look at science and what science is telling us and incorporate that into our times, but we also need to incorporate a lot of traditional cultural knowledge as well,” Quam said.

Speaking on a different panel Thursday, Oregon Public Utility Commissioner Letha Tawney said she was struck by the fact that when colonists and “resource extractors” came into the West, they were encountering a land that was being actively managed by the indigenous inhabitants.

“I think we still persist — or I still persist — unwittingly in a very strong sense that there was a pristine wilderness” until the intervention of the past 150 years, Tawney said, but the evidence is clear that European settlers “walked into a landscape that was being actively and quite professionally managed, and had been for probably millennia.”

“Fire is a cycle. Fire is a process. Fire is not the enemy,” said Kit O’Connor, a research ecologist with the U.S. Forest Service.

“Wildfires are treating acres faster than we ever will be able to, so if we’re not using wildfire as part of our equation in solving this problem, then we’re ignoring the biggest tool that we have in front of us,” O’Connor said.

“Sometimes it just feels like hope is out of the sail,” Stephens said. “It’s just like, ‘Wow, what are we going to do? All we’re going to do is basically get beat up.’ That is not necessary. There really is hope to actually do some work that actually can make a difference.”

NY DPS Urges More Funding for EV Make-Ready Program

New York Department of Public Service staff on Wednesday recommended a 58% funding increase for the state’s EV Make-Ready Program for electric vehicle infrastructure.

When it created the program in July 2020, the Public Service Commission stipulated a midpoint review. The DPS’ white paper published Wednesday updates the PSC on the progress made to date and recommends a series of changes for the commission to make.

The recommendations reflect data and feedback gathered in the nearly three years since the order was issued, including through a series of technical conferences with the investor-owned utilities that are carrying out the program — Central Hudson Gas & Electric, Consolidated Edison, National Grid, New York State Electric and Gas, Orange and Rockland Utilities, and Rochester Gas and Electric — and other stakeholders. (See Inflation Hampering Efforts to Expand EV Charging Network in NY.)

Installing charger plugs has proved to be more expensive than was projected in 2020, and analysis has indicated a different mix of direct current fast chargers (DCFC) and Level 2 chargers should be incentivized.

The 2020 order authorized the utilities to spend $701 million in ratepayer money to help reach a buildout target of 53,733 L2 plugs and 1,500 DCFC plugs. Staff are recommending that be changed to $1.11 billion to incentivize buildout of 43,122 L2 plugs and 6,302 DCFC plugs.

Buildout through the Make-Ready Program has also been slower than anticipated.

Only 4% of the original L2 goal and 14% of the original DCFC goal had been completed as the midpoint review was prepared. With the addition of projects committed but not completed, the totals rise to 23% and 42%, respectively.

The pace was such that all six utilities failed to qualify for incentives through the earnings adjustment mechanism specified for L2 chargers, and only National Grid reached the midpoint goal that would qualify it for a DCFC incentive.

The Make-Ready Program supports New York’s landmark Climate Leadership and Community Protection Act of 2019, which mandates a 40% reduction from 1990-level greenhouse gas emissions by 2030 and an 85% reduction by 2050.

The transportation sector is a major source of those emissions. A 2022 New York law mandates that a gradually increasing percentage of passenger vehicles sold in the state be EVs, reaching 100% by 2035. For that to happen, many more publicly available chargers will be needed.

“At the time the Make-Ready order was issued, the commission was confident that the electrification of the transportation sector would help attain the goals of the CLCPA,” DPS staff wrote. “In the three years since the Make-Ready order was issued, it has only become clearer to DPS staff that the electrification of the transportation sector is paramount to the achievement of the goals of the CLPCA.”

The following recommendations by the DPS staff are among those included in the white paper:

  • Continue to limit administrative costs to 15% of the original program incentive budget in the 2020 order.
  • Budget $25 million for micromobility charging, for devices such as electric bicycles, skateboards and scooters, and earmark $20 million of that for the New York City area.
  • Boost the budget for the medium- and heavy-duty vehicle make-ready pilot program from $24 million to $54 million.
  • Shrink the eligibility radius for the enhanced funding offered for siting L2 chargers in disadvantaged communities, so that wealthier surrounding communities do not benefit.
  • Seek continued input to shape a workforce development program focusing on disadvantaged communities.
  • Direct the Technical Standards Working Group to identify barriers to vehicle-to-grid integration and propose solutions.
  • Convene a technical conference to streamline the collection of charger site data, which is critical to achieving the goals of the Make-Ready Program but has proved challenging to carry out.
  • Seek additional shareholder input and analyze it before modifying or expanding the transit electrification efforts authorized in the 2020 order.
  • Do not move forward with consideration of a make-ready program for installation in private residences, because brisk EV sales suggest such incentivization is not necessary.

PJM Stakeholders Seeking More Detail from Board on Reliability Fast Path

PJM stakeholders are requesting that the Board of Managers provide more information about its initiation of a fast-track process to address reliability concerns, which it announced in a letter published last month.

“This is not giving us any clear direction … and I think that we’re going to waste a lot of time if we don’t get some clear direction,” Paul Sotkiewicz, president of E-Cubed Policy Associates, said during the Feb. 28 meeting of the Resource Adequacy Senior Task Force.

The board released the letter Feb. 24 in response to “numerous data points suggesting that grid operators may face challenges in maintaining reliability during the transition,” as shown in a white paper released by PJM the same day detailing an imbalance between future resource development and retirements through the rest of the decade. (See PJM Board Initiates Fast-track Process to Address Reliability.)

Invoking the Critical Issue Fast Path (CIFP) stakeholder process, the board identified a set of key work areas it would like to see addressed by proposals for it to consider and potentially send to FERC by Oct. 1.

The four primary areas the board identified include revising the Capacity Performance (CP) model and ensuring any penalty risks can be accounted for in capacity offers; improving resource accreditation to ensure that reliability contributions are accounted for and compensated; enhancing risk modeling to improve understanding of winter risk and correlated outages; synchronization between the Reliability Pricing Model and the fixed resource requirement rules to ensure that supply and demand are held to comparable standards.

Steve Lieberman of American Municipal Power said the letter is eliciting a lot of questions from stakeholders and it would be beneficial for representatives of the board to attend one of the upcoming Markets and Reliability Committee meetings to set the grounds of what they’re looking for in a solution package.

“If we’re going to be jumping through hoops for the next six [or] seven months, let’s make sure we’re jumping through the right hoops,” he said during the RASTF meeting.

Vice President of Market Design Adam Keech said PJM’s understanding of the board’s intent with the letter was to avoid steering stakeholders in the direction of a specific solution, but to identify areas of importance that a solution must address.

“I think this is the scope we have to work with, and it was written for this reason,” he said.

Going through the work areas, Keech noted that many of them have long been under discussion by stakeholders before giving PJM’s interpretation of each of them. Regarding any changes to the CP construct, he said the board believes any risk generators face from penalties should be reflected in their market seller offer cap.

“I see the board saying ‘review CP’ in terms of Winter Storm Elliott and the market seller offer cap,” he said. In the wake of the December 2022 storm, PJM announced that generators could face $1 billion to $2 billion in CP penalties, which has prompted many generators to say they are not adequately able to incorporate the risk of future penalties in their capacity offers. (See PJM Weighs Options for Winter Storm Elliott Follow-up.)

Keech said PJM believes the board wants to incorporate growing risk during winter months into the calculation of reliability requirements.

He also said PJM is likely to pursue a marginal accreditation framework for its effective load-carrying capability method, whereas it currently uses an average, though he acknowledged stakeholders can opt to move in a different direction.

Part of the board’s letter noted that it is interested in exploring if any changes made can be implemented before the 2027/28 Base Residual Auction. But state consumer advocates said any delays to future capacity auctions could interfere with states that procure their own capacity.

“I know that is a concern for at least some of the auctions: further delays and how that affects state auctions,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States.

David “Scarp” Scarpignato said he would like to see additional information about the impact auction delays could have on states at future meetings. He also encouraged PJM to create a framework for presenting the particulars of any proposals that may come forth in an easier-to-read format than the matrix that is typically used, predicting that the process of drafting packages is likely to be “unwieldy.”

“I don’t think someone is going to be able to read a 100-line matrix and understand what it’s saying,” he said.

PJM’s Dave Anders gave an overview of a target roadmap for drafting and voting on packages, with first reads anticipated in June and votes at the MRC and Members Committee in August and September, respectively. Anders and Keech told the task force that the RTO plans to present a draft problem statement, issue charge and proposal, with a target posting date of March 13.

The Market Implementation Committee will continue the discussion of potential auction delays during its March 8 meeting, as well as at the March 15 RASTF.

ERCOT Board of Directors Briefs: Feb. 27-28, 2023

Wind Energy Plays Key Role During December Storm

AUSTIN, Texas — ERCOT staff reported to the grid operator’s Board of Directors last week that despite “not insignificant” forced outages during the December winter storm, it set a new winter demand record and supported “reliable execution throughout event.”

Fossil fuel outages from fuel restrictions and cold weather spiked in the early-morning hours of Dec. 23, knocking more than 14 GW of generation offline at one point. Fortunately for ERCOT, wind resources, the early fall guys during the deadly February 2021 storm, helped fill the gap with about 30 GW of energy at times during the night Dec. 22-23.

“This is a great example of the dependency we have on renewables, because for part of the 22nd and the 23rd, we were in renewable territory,” Director John Swainson said during the board’s Feb. 28 meeting. “If the wind had stopped blowing, we would have been in deep [expletive].”

“As load shot through our forecast, we needed another [6,000] or 7,000 MW,” Texas Public Utility Commission Chair Peter Lake said.

Stoic Energy principal Doug Lewin — who follows ERCOT and, among other data, its forced outages — told RTO Insider that about 25 GW of capacity was offline at some time between Dec 22 and 24. ERCOT went into the event with 6 GW already offline, despite the lack of snow and ice, he said.

The grid operator’s data included 655 individual outages at 348 units, peaking at close to 20 GW during the storm. Initially, 127 outages were considered weather or fuel supplyrelated, with a high of almost 4.5 GW. Outages or derates at 97 units were considered weather related (35 were wind), and another 30 were caused by fuel issues; 23 of the latter were at gas units.

John Swainson 2023-02-28 (RTO Insider LLC) FI.jpgERCOT Director John Swainson | © RTO Insider LLC

Almost 1.5 GW of large flexible loads, such as data centers and bitcoin miners, responded to market prices and curtailed their usage. ERCOT also deployed a total of about 2.5 GW of firm fuel supply service to make up for gas restrictions in North Texas.

Like other grid operators during the storm, ERCOT underestimated the drop in temperatures and its effect on load. In the days before the storm, staff had projected demand would almost reach 70 GW. Instead, it peaked at 73.9 GW on Dec. 23, more than 4 GW than the official record peak set during the 2021 storm and its load shed.

“It was a fairly successful event from a risk perspective. It was also one of the coldest events that we’ve seen in the last 15 years,” said Dan Woodfin, vice president of system operations, referencing the more recent storm. “The key message here is that this under-forecast didn’t have any impact on reliability because pretty much all the generation was all buying, and so we were prepared for much higher load than what actually occurred.”

Woodfin said national weather models underestimated “how quickly and how deep” the storm arrived in Texas. Dec. 22-23’s load-weighted daily minimum temperatures of 13.4 and 16.3 degrees Fahrenheit during the December event were lower than all but two of the 2021 storm’s days.

He said the load-forecast models “overplayed” the demand reduction from businesses shutting down for the holiday weekend and were unable to rely on historic data without load shed for the temperatures. Staff have since identified lessons learned and begun improving the forecast models with a focus on extreme cold events, Woodfin said.

ERCOT is still investigating the forced outages’ root causes.

Carrie Bivens, ERCOT’s Independent Market Monitor, attributed prices that peaked at $4,500/MWh on Dec. 22 to the normal economic dispatch of energy storage resources.

“It was fairly significant pricing event,” she said. “The reason the prices were high is price-setting resources were energy storage resources during that time. They typically have high opportunity costs and high offers, and they were mostly setting the price during that time.”

She said the issue was an example of a case in which real-time co-optimization would have had an effect. The IMM has for several years pushed the market tool’s implementation, which is currently sidelined by the state’s market redesign efforts.

Vegas Applauds Sunset Review

ERCOT CEO Pablo Vegas told the board that the grid operator supports recommendations made following a review by the state’s Sunset Advisory Commission.

“Fundamentally, I think some of the changes can be summarized as improvements to communication, making sure that when we communicate information and reports; … that we’re clear [and] transparent, and we take out the engineering jargon,” he said, “and that what we’re recommending needs to happen in order to always keep reliability at the forefront.”

The commission, which also simultaneously reviewed the PUC and the Office of Public Utility Counsel because of their interrelated responsibilities, recommended:

  • process changes so ERCOT can restrict the commissioners’ presence during executive sessions and to better define the sessions;
  • adding a second commissioner to the ERCOT board as a non-voting member;
  • requiring ERCOT to send a biannual industry report to the legislature;
  • directing ERCOT and the PUC to re-evaluate the grid operator’s performance metrics and create a public communication guidance document; and
  • ordering ERCOT to include appropriate budgetary funding for “qualified” economic planning staff.

Under state law, ERCOT, the PUC and OPUC, as do all state agencies, undergo regular sunset reviews to assess their continued need and their programs’ efficiency. The Legislature will consider the sunset commission’s recommendations when the report is filed and make final decisions before its session ends May 29.

Directors Approve Rule Changes

The board approved seven nodal protocol revision requests (NPRRs) and single changes to the Planning Guide (PGRR) and Retail Market Guide (RMGRR) previously endorsed by the Technical Advisory Committee:

  • NPRR1144: provides a limited exception to the requirement that loads included in an ERCOT-polled settlement metering facility’s netting arrangement only be connected to the grid through the facility’s metering point(s). The exception would allow no more than 500 kW of auxiliary load connected to a station service transformer be connected to a transmission or distribution service provider’s (TSP/DSP) facilities through a separately metered point using an open transition load transfer switch listed for emergency use.
  • NPRR1147: sets fast frequency response’s ancillary service offer floor 1 cent/MW lower than other responsive reserve services categories to allow fast frequency response’s procurement up to the current limit, without proration with other categories.
  • NPRR1149: charges qualified scheduling entities (QSEs) an ancillary service failed quantity if their supply responsibility is not met in real time by their portfolio’s resources, based on a comparison of their real-time telemetry.
  • NPRR1151: eliminates the protocol requirement that the Protocol Revision Subcommittee hold at least one meeting per month.
  • NPRR1153: adds two existing fees (public information request labor and ERCOT training) to the grid operator’s fee schedule; creates a $500 registration fee for resource entities, TSPs and DSPs, and subordinate QSEs; deletes the system administration fee’s current value and the map sales fee; and restructures existing fees for generator interconnection or modification, full interconnection study applications and wide-area networks.
  • NPRR1158: eliminates the weatherization-inspection fee’s sunset date and changes its invoicing period from a quarterly to a semiannual basis.
  • NPRR1159: provides needed references to the Retail Market Guide accounting for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas. The change is aligned with RMGRR171, which adds language establishing the mechanism that opt-in munis or co-ops without an affiliated provider of last resort (POLR) that have not delegated authority to designate POLRs to the PUC would follow to provide their initial POLR allocation methodology; and updates and confirms such allocation methodology.
  • PGRR102: requires resource entities and interconnecting entities to provide operations dynamic model quality test results that demonstrate appropriate performance for submitted operations dynamic models, and makes non-substantive clarifying changes.

The board also approved: