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August 20, 2024

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California PUC Orders 4 GW of New Resources for Reliability

The California Public Utilities Commission on Thursday ordered load-serving entities under its jurisdiction to procure an additional 4 GW of clean energy resources by 2027, adding to the record-setting 11.5 GW of procurements it ordered less than two years ago to bolster reliability and meet environmental goals.

“This additional procurement is necessary as electric demand is projected to further increase in the coming years and the accelerating impacts of climate change are creating new demands on our electric resource mix,” CPUC President Alice Reynolds said.

The additional procurement is part of the state’s massive buildup in renewable and zero-emitting resources as it tries to meet its 100% clean energy mandate by 2045 while avoiding repeats of the energy emergencies it experienced during the past three summers, including the rolling blackouts of August 2020. (See Calif. Must Triple Capacity to Reach 100% Clean Energy.)

The proposed decision adopted Thursday includes electricity resource portfolios for CAISO to use in its 2023/24 transmission planning process. The ISO updates its 10-year transmission plan annually.

The CPUC’s base-case portfolio anticipates the state will need 69 GW of new resources by 2033 and another 16 GW of new resources by 2035 to meet its environmental goals while maintaining reliability.

The additional 85 GW would be “on top of the existing resource mix on the electric grid of approximately 75 GW. This is more than a doubling of nameplate capacity on the system within 12 years,” the decision by Administrative Law Judge Julie Fitch says.

The base-case scenario includes 39 GW of solar and 28 GW of battery storage by 2035. It projects adding 3,900 MW of in-state wind, 4,800 MW of out-of-state wind and 4,700 MW of offshore wind in Northern and Central California.

The decision also recommends that CAISO study a 75 GW sensitivity portfolio that would add 13.4 GW of offshore wind. The portfolio “is designed to refine and update transmission capability and upgrade assumptions relevant to offshore wind resources,” it says.

In June 2021, the CPUC ordered load-serving entities — including Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to procure 11.5 GW of new clean-energy resources by 2026. It was the largest single procurement order in state history and followed a series of smaller procurement orders that began in 2019 and increased after the 2020 blackouts. (See CPUC Orders Additional 11.5 GW but No Gas.)

“This additional procurement for 2026 and 2027 is required for several reasons … [including] updated load forecasting from the California Energy Commission that suggests that electricity demand is increasing and will continue to increase compared to when [the 11.5 GW was ordered],” Fitch wrote in Thursday’s order.

She also cited the “increasing and accelerating impacts of climate change,” the “likelihood of some additional fossil-fueled generation resource retirements that were not anticipated at the time” and the “likelihood that some delays beyond 2026 in the procurement of long lead-time resources required by [the June 2021 decision] will be necessary.”

The latest decision postponed the procurement of long lead-time resources such as geothermal and long-duration storage from 2026 to 2028.

A number of parties to the most-recent proceeding expressed concerns that ordering another 4 GW could undermine the CPUC’s efforts to develop a “programmatic” approach to resource planning and keep the CPUC “stuck in a cycle of ad hoc, interim procurement orders,” the decision noted.

“A programmatic approach means moving beyond the CPUC’s current energy resource procurement order-by-order approach and setting rolling, ongoing requirements for LSEs [load serving entities] to meet,” the CPUC said in a fact sheet on the effort, called the Reliable and Clean Power Procurement Program.

The CPUC said it had to address reliability concerns before that program is ready.

“As much as we would like to agree … that we should focus on development of a programmatic approach to procurement, we also are convinced that we cannot wait for that larger process to be complete before ordering additional procurement,” the proposed decision said. “In 2022, the electric system came very close to running out of resources, and it actually did run out in 2020. The system is much closer to a supply and demand balance than is comfortable for reliability purposes.”

Tight supply and high prices in summer, “coupled with the lengthy lead time needed for the development of new resources, persuade us that we need to order new procurement now so that the LSEs can have sufficient time to contract for and develop the resources in a timely and cost-effective fashion.”

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ERCOT Technical Advisory Committee Briefs: Feb. 20, 2023

Staff Proposing Bridging Solutions to ERCOT’s Long-term Market Redesign

ERCOT staff have prepared a draft of its early thoughts on a bridge solution to Texas regulators’ preferred market design, which is not expected to be implemented for at least three years.

Kenan Ögelman, ERCOT vice president of commercial operations, told the Technical Advisory Committee during its Monday meeting that staff will bring some proposed recommendations to the Board of Directors’ Reliability and Markets Committee meeting Feb. 27.

ERCOT plans to hold at least two workshops with stakeholders in March to solicit feedback and other alternatives. The board, responding to a directive from the Public Utility Commission, is expected to approve a final bridge recommendation during its April meeting.

Kenan Ogelman (ERCOT) Content.jpgKenan Ögelman, ERCOT |

ERCOT

“We would very much like to hear from interested stakeholders on what we have,” Ögelman said. “I might have to pivot on what I just said, depending on the feedback that I get, so I just want to put that caveat out there.”

ERCOT on Wednesday filed several bridging solutions in the R&M’s background materials. They include a manually settled performance credit mechanism (PCM), mirroring the market mechanism the PUC has recommended to state lawmakers for their consideration. (See Texas PUC Submits Reliability Plan to Legislature.)

The PCM rewards generators in ERCOT’s energy-only market with credits based on their performance during a determined number of scarcity hours. Those credits must either be bought by load-serving entities or exchanged between them and generators in a voluntary forward market.

Staff say the manual PCM could be brought online late this year or early next year and that it has mechanisms that preserve both existing generation and new resources. They suggest the markets would gain experience with the “proposed future state.” However, the solution doesn’t create an obligation for LSEs to contract, and there would be no forward market; the performance credits’ value would be determined by ERCOT.

ERCOT is also proposing procuring more ancillary services and making payments to more market resources; modifying the operating reserve demand curve to achieve a one-in-10 loss-of-load expectation in 2026; deploy a backstop reserve service that secures a preset capacity amount based on bids; and capacity contracts to bring retired generators back to life.

The various options fall within three categories: solutions that address new investment and maintaining existing resources; those that address existing resources; and those that address new investment.

System Admin Fee up for Increase

Staff told stakeholders to expect an increase in the system administration fee next year, a message that was first relayed during last August’s board meeting. However, Controller Richard Scheel declined to provide an idea of how large the increase will be from the current 55.5 cents/MWh rate that has been in place since 2016.

“I hesitate to comment on the magnitude publicly before I discuss it with the board,” he said.

Scheel plans to take the same message to the Finance and Audit Committee’s Feb. 27 meeting. He’ll return to the committee and the board in April with proposed numbers.

Stakeholders had asked staff to provide them with more advance notice of admin fee increases during the 2016-2017 budget cycle. Lower Colorado River Authority’s Emily Jolly reminded Scheel that TAC’s ask included an idea of the magnitude of any increase.

“Telling our folks back at our shops that there’s going to be an increase and not being able to give them more detail is a little bit challenging,” she said.

Scheel said the final number is still under development. “We’re happy to talk about that more at the April meeting.”

Staff also said they have a path to restart the real-time co-optimization project, which has been on hold since mid-2021. They are evaluating the program’s scope and any gaps and overlaps in RTC-related protocols during the past two years.

Staff plan to complete a prospective budget and schedule for consideration by the June board meeting. The project still has a $51.6 million budget line item and a three-and-a-half-year timeline, but a new impact analysis will be conducted.

Members Approve 2023 Goals

The committee approved its goals for 2023 and those of the Retail Market Subcommittee as part of the combination ballot. TAC’s 19 goals include two late additions to review market design changes and improvements made since the February 2021 winter storm, and to support ERCOT staff in identifying, developing and implementing bridging solutions.

Members approved the ballot 28-0. It included two nodal protocol revision requests (NPRRs) and a single change to the Retail Market Guide that, if approved by the board, would:

  • NPRR1158: eliminate the weatherization-inspection fee’s sunset date and changes its invoicing period from a quarterly to a semiannual basis.
  • NPRR1159: provide 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 would add language establishing the mechanism that opt-in MOUs or cooperatives 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.
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California Energy Commission Explores Complexity of Vehicle-to-grid Connections

Interest is growing in bidirectional charging from vehicle batteries, but utilities and homeowners have different perspectives on the technology, speakers said during a webinar exploring the challenges of the systems.

Utilities are interested in vehicle-to-grid (V2G) charging, in which energy stored in the battery of an EV such as a school bus is harnessed to enhance grid reliability.

But homeowners are more interested in vehicle-to-home (V2H) charging, in which they can use their electric vehicles as a backup energy source for their homes in case of an outage, a Pacific Gas and Electric (NYSE:PCG) official said.

“We’ve seen vehicle-to-home be kind of a bit more of the leading reason why customers get into the V2X space,” said Chris Moris, principal for grid innovation at PG&E.

“I just don’t think the average consumer, when they buy an electric vehicle, they’re really thinking about the electric grid,” Moris said. “They’re thinking more about the reliability, how I can power my home.”

Moris was one of the speakers during a Feb. 8 webinar hosted by the California Energy Commission (CEC) and ElaadNL, an EV charging innovation center led by a coalition of Dutch grid operators. The collaboration between the CEC and ElaadNL is an outgrowth of a partnership between California and the Netherlands to work on climate goals.

Much of the focus of the webinar was grid codes: technical specifications regarding connections to the electrical grid.

“For many of you who need to connect to the electricity grid for charging infrastructure, you may think, ‘Well, how hard can it be?’” said webinar speaker Lonneke Driessen, director of standardization at ElaadNL.

But ElaadNL is increasingly getting feedback about the challenging and diverse grid codes, Driessen said, and “they may become an impediment to the rapid adoption of V2G.”

ElaadNL is working to “harmonize” grid codes as part of a three-year European project called SCALE (Smart Charging Alignment for Europe), aimed at advancing smart charging infrastructure and facilitating the mass deployment of electric vehicles.

V2G ‘Stalemate’

Another webinar speaker, Jeffrey Lu with the CEC’s vehicle-grid integration unit, discussed the potential for breaking through a “stalemate” related to grid codes and V2G charging.

In California, Rule 21 covers requirements for smart inverters used in vehicle-to-grid charging.

While Rule 21 includes a standard from the Institute of Electrical and Electronics Engineers, IEEE 2030.5, as its default, “the EV and charging industries have not adopted this communication protocol,” Lu said in his presentation. Instead, the industries have been using the Open Charge Point Protocol (OCPP) and ISO 15118 for communications between the charging equipment and the network, and the charging equipment and the vehicle, respectively.

The use of OCPP and ISO 15118 doesn’t prevent V2G in California in direct-current systems, which are typical when the inverter is part of the charging equipment. But the charger manufacturers may face additional certification burdens if using those standards, CEC’s Fuels and Transportation Division told NetZero Insider.

The situation is even more complicated for alternating current (AC) V2G systems, which are used when the inverter is on-board the vehicle. Rule 21 does not currently allow AC vehicle-to-grid charging, CEC said, and a certification pathway under discussion may require IEEE 2030.5, which the EV industry hasn’t adopted.

But Lu said during the webinar that efforts are underway to update OCPP and ISO 15118, which may help them meet Rule 21 requirements.

“These updates to OCPP and ISO 15118, paired with regulatory acceptance, can help to break through a V2G stalemate,” Lu said, describing his comment as a proposal for industry to explore.

In addition, Lu said, “the updates to globally aligned protocols may support greater V2G adoption, implementation and economies of scale.”

Cost Challenges

Moris at PG&E said vehicle-to-home charging presents additional challenges because the system can switch from on-grid operation to off-grid — or islanded — mode. He said the company is conducting pilot tests to study the island-transition issue.

“There’s this unique point in time where there’s a transition between on-grid to off-grid,” Moris said. “And that’s an area where our distribution planners need to see a little bit more on how that safely happens and how that energization works.”

In one pilot study, in partnership with General Motors and Ford, six homes were equipped with vehicle-to-home charging systems. Among five of the homes, the cost to install the systems ranged from about $10,000 to $18,000. Charging equipment accounted for 20% to 30% of the total cost; remaining costs were for wiring and panel upgrades.

For the sixth home, trench work was required, which brought the total cost to $58,000. That’s an issue that could crop up for other homes with 100-amp service, Moris said. Collaboration among utilities, car manufacturers and charging vendors is needed to bring V2H costs down, he added.

Moris also proposed that automakers and EV charging vendors collaborate to create lab space where interoperability can be tested. In addition, Moris said, pathways should be explored in which V2G capability is available by default.

“What would it mean for every car to support V2G out of the gate?” he said.

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PJM Whitepaper to Highlight Future RA Concerns

The pace of capacity being installed on PJM’s grid may not keep up with the rate of retirements and accelerating load growth over the next eight years, according to a white paper PJM plans to release Friday.

“There is a concern that we may not be replacing the exiting generation at the rate needed to maintain resource adequacy,” PJM’s Scott Benner told the Markets and Reliability Committee during a presentation on the white paper’s findings.

About 40 GW of generation in the RTO is forecast to retire by 2030, representing 21% of currently installed generation. The white paper lays out two scenarios for the development of additional capacity over the same period, with a conservative estimate at just over 15 GW installed and a more optimistic forecast seeing nearly 31 GW of development.

Brenner said while 46 GW left the market over the past eight years, the period saw sharp growth in natural gas resources that made up for lost coal generation. Natural gas installations are expected to drop off after 2023, with renewables only picking up a share of the slack. 

“We’re blessed in PJM to have an abundant natural gas supply, but there’s a concern over the next 10 years that we won’t have that backstop to cover the retirements,” Brenner said.

PJM Vice President of Market Services Stu Bresler said staff have been looking at the future supply-demand balance since October, when CEO Manu Asthana shared concerns about the pace of retirements and development at the 2022 Annual Meeting of Members. (See “PJM CEO Manu Asthana Warns of Potential Generation Shortfalls,” PJM MRC Briefs: Oct. 24, 2022.)

“We cannot take the reliability that we enjoy in our region for granted through this energy transition; we have to take concrete steps to ensure that it will continue,” Asthana said before the Markets and Reliability Committee on Oct. 24.

The development forecasts combine analysis of projects in PJM’s queue with analysis conducted by S&P Global. The conservative scenario assumes that about 5% of projects that enter the interconnection queue reach commercial operation, while the more optimistic estimate assumes more projects enter service. Of the 40 GW expected to retire, Benner said coal would account for about 60% and natural gas 30%.

State clean energy policies are expected to drive about 24 GW of the retirements, with PJM’s analysis assuming that owners will choose to retire facilities rather than make the upgrades required to comply with new regulations and laws.

The retirements are expected to accompany a growth of demand from data centers and the electrification of vehicles and buildings. Benner said those trends could collide later this decade, causing installed generation to fall below the 14% reserve margin unless the rate of new resources accelerates.

“With the expected retirements and rates of replacements, there’s a risk that we move into a higher rate of demand response usage in around 2027,” he said.

Carl Johnson, of the PJM Public Power Coalition, said the RTO must implement firm and transparent rules to avoid reliability problems and creating a scenario where reliability must-run (RMR) contracts are seen as a solution.

“We’re going to need some sort of reliability backstop that isn’t the current RMR rules,” he said.

Noting that Benner’s presentation pointed to the Resource Adequacy Senior Task Force as one of the forums to discuss market changes to continue the conversation, David “Scarp” Scarpignato of Calpine said the task force has already been mired in intractable discussions, and PJM may need to take a more active role in addressing the issues it’s highlighted.

“PJM might have to exert even more leadership than you already have to push this forward … because I’m not sure the stakeholders are going to reach consensus,” he said.

Abe Silverman, of the New Jersey Board of Public Utilities, said he was glad to see that development of new generation is being treated as an equal priority to the issue of retirements. States and companies with clean energy goals have significant demand for renewable resources and obstacles limiting their entry to the market, including the interconnection queue, should be treated as part of the solution, he said.

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DOE Announces $2.5B for Carbon Capture Projects

The Department of Energy is targeting the dirtiest and hardest-to-decarbonize electric power and industrial plants with $2.52 billion in funding for “transformative carbon capture systems and carbon transport and storage technologies,” according to an agency announcement on Thursday.

The dollars from the Infrastructure Investment and Jobs Act will go to two programs, both focused on advancing carbon capture technologies that are at or moving toward commercial scale.

The Carbon Capture Demonstration Projects Program will get the lion’s share of the money — $1.7 billion — for approximately six projects that demonstrate commercial-scale, and readily replicable, carbon-capture and sequestration (CCS) projects.

According to the funding announcement, at least two of the projects will be at new or existing coal-fired generation plants. Another two will be sited at new or existing natural gas plants, and the final two at new or existing industrial facilities, such as cement, iron or steel plants.

“Proposed projects must demonstrate as part of the application and during the award at least 90% CO2 capture efficiency over baseline emissions and a path to achieve even greater CO2 capture efficiencies for power and industrial operation,” the announcement says. The awards will come with a 50% cost-share requirement.

Letters of intent for the funding must be received by March 28, with final applications due May 23.

The Carbon-Capture Large-Scale Pilots program will offer a more modest $820 million for 10 projects that will de-risk “transformational carbon capture technologies and [catalyze] significant follow-on investments for commercial-scale demonstrations” in both the electric power and industrial sectors.

The term “large-scale” here means projects that are not yet commercialized but are large enough to validate the technology and “demonstrate the interaction between major components so that control philosophies for a new process can be developed and enable the technology to advance from large-scale pilot project application to commercial-scale demonstration or application.”

Again, the focus will be on coal and natural gas power plants and industrial facilities, and the award can be used for up to 70% of project costs. The Office of Clean Energy Demonstrations will oversee both programs.

Concept papers for the funding will be due April 5, with full applications due June 21.

“Drastically cutting emissions across our economy through next-generation carbon management technologies is a critical component of President Biden’s strategy to combat the climate crisis and achieve our ambitious clean energy goals,” Energy Secretary Jennifer Granholm said in the DOE announcement. “By focusing on some of the most challenging, carbon-intensive sectors and heavy industrial processes, today’s investment will ensure America is on a path to reach net-zero emissions by 2050.” 

Other Carbon Capture Funding 

The White House and DOE continue to roll out IIJA funding, signaling the administration’s focus on implementing its clean energy and greenhouse gas emission reduction initiatives at speed and scale. The CCS announcement comes hard on the heels of Wednesday’s announcements of new initiatives aimed at expanding offshore wind. (See Interior Proposes 1st Lease for Offshore Wind in Gulf of Mexico and DOE Launches West Coast OSW Transmission Study.)

The carbon capture industry has already been buoyed by earlier funding announcements from the IIJA, focused mostly on demonstration projects, and the Inflation Reduction Act, which contains generous tax credits for such projects.

The IIJA funding includes $3.5 billion for four regional direct air capture hubs, each of which will have to capture, store or utilize one million metric tons of CO2 per year. The IRA contained significant increases in the 45Q tax credits, which specifically benefit CCS. For example, the credit for carbon captured from power or industrial plants and stored in underground salt caverns rose from $50/metric ton to $85/metric ton, and the credit for direct air capture jumped from $50 to $130/metric ton.

Coming on top of this support, Thursday’s announcement “is significant not just for the size of the investment, but for the impact it will have on further advancing the development and deployment of carbon management technologies in both heavy industry and power sectors,” Jessie Stolark, executive director of the Carbon Capture Coalition, said in a statement to NetZero Insider. “Testing, demonstrating and safely deploying new emissions reduction technologies in heavy industry sectors, such as steel, cement and concrete as well as the power sector are not optional if we are to meet climate targets.”

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Dragos: Cyber Landscape Remained Volatile in 2022

The cyber threat landscape in 2022 included new malware targeting the electric industry with “breakthrough escalation in capabilities,” in addition to an increase in energy sector-targeting threat activity in general, possibly linked to tensions between Russia and the EU, cybersecurity firm Dragos said in its annual Year in Review report released last week.

However, while attacks against targets in Europe — particularly Ukraine — escalated following Russia’s invasion of that country in February, cyber incidents involving U.S. energy utilities were “primarily focused on reconnaissance,” Dragos said. This ran counter to fears that the Russo-Ukrainian War could become the prelude to a broader cyber offensive against Western countries that support Ukraine. (See Experts Warn Cyberwar Still Possible.)

The biggest news for Dragos on the malware front last year was the introduction of Pipedream, a framework for attacks on industrial control systems (ICS) disclosed by Dragos in April. (See Dragos Warns Malware Developers Building Skills Fast.) Pipedream’s developers, a newly identified threat group dubbed “Chernovite” by Dragos, intended the tool to “attack industrial infrastructure,” the firm said.

Dragos added that it has “high confidence” that Chernovite represented a state-backed actor with “disruptive or destructive” goals, though in keeping with its usual practice, it has not connected the group with a specific nation.

Ransomware incidents (Dragos) Content.jpgRansomware incidents by sector | Dragos

 

Although it was discovered before being deployed in the wild, Pipedream sparked concern across the cybersecurity community because of the unprecedented level of sophistication it displayed. Pipedream’s modular nature meant it could be easily modified to attack many manufacturers and equipment types and could impact companies in a wide range of industrial sectors.

Dragos’ report compared the new tool to Havex, a malware variant discovered in 2013 that targeted victims in the U.S. and Europe. Like Pipedream, Havex could be used across multiple industries; Dragos called it “the [cybersecurity] industry’s first glimpse into the potential cross-industry impact an adversary could have by taking advantage of a standard protocol.”

“Havex’s campaign goal was espionage, and … the adversary gathered data on networks from companies in the energy, aviation and pharmaceutical sectors, to name a few,” Dragos said. “While we can never know whether Chernovite looked at Havex when designing Pipedream, we do know that Pipedream takes that cross-industry ability to the next level [with] the ability to target thousands of devices across critical industries.”

Aside from Chernovite, and another newly identified threat actor dubbed “Bentonite” that targets governments and the manufacturing and maritime oil and gas networks, Dragos identified a number of other known threat groups as still active last year. These include Kostovite, which has demonstrated “skilled lateral movement and initial access operations into ICS/OT [operational technology] environments” in U.S. energy companies, and Kamacite, which has been linked to the 2015 and 2016 attacks on Ukraine’s power grid.

Electrum, another group involved in the 2016 Ukraine attacks, was back last year as well. In a fresh attack on Ukraine, the group deployed a malware that Dragos has labeled Industroyer2, a variant of the tool used in 2016. However, unlike the earlier attack, last year’s hack was apparently foiled before any outages were caused. (See E-ISAC Warns of Escalating Russian Cyber Threats.)

Ransomware on the Rise

While North America was relatively free of ICS attacks during 2022, ransomware was another story. Dragos said it “tracked 605 ransomware attacks against industrial organizations [worldwide in] 2022, an increase of 87%” over the prior year. Of these, 247, or about 41%, affected organizations in North America.

The vast majority of global ransomware incidents occurred in the manufacturing sector, with 437 attacks. Energy accounted for 29 incidents, with seven attributed to engineering and utilities.

Attacks in the energy sector included a compromise of unspecified companies reported in October by the Electricity Information Sharing and Analysis Center, resulting in the exfiltration of data that could “allow a capable adversary to dynamically model electricity systems.” According to Dragos, however, no outages are known to have occurred because of this data extraction.

The ransomware sector was marked last year by the apparent collapse of the Conti cybercrime gang in May, after its attack on the government of Costa Rica led the U.S. State Department to announce a reward for any information about the group’s leadership and affiliates. (See Dragos: Ransomware ‘More Impactful’ in Q2.)

However, the disappearance of Conti was accompanied by the rise of other groups such as Black Batista, which attacked U.S. agricultural equipment manufacturer AGCO in May; Dragos said it is possible that personnel from Conti may have joined Black Batista or other groups.

Dragos attributed about 28% of ransomware incidents last year to the Lockbit group, which released an updated version of its eponymous ransomware-as-a-service software that included features such as anti-detection mechanisms and the ability to disable Microsoft Defender Antivirus. The firm said it had “moderate confidence” that Lockbit “will pose a threat to industrial operations into 2023.”

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Lordstown Motors Recalls Endurance Electric Truck

Lordstown Motors (NASDAQ:RIDE) on Thursday announced it had stopped production of its battery-electric pickup truck, the Endurance, and would voluntarily recall those already sold to address an electrical connection issue that could result in a loss of propulsion while driving.

The recall affects 19 vehicles that are being driven either by customers or by company employees, Lordstown said in a statement and simultaneous filing with the U.S. Securities and Exchange Commission.

Judging from the company’s explanation that it is working with its entire supplier network to address the problem, the potential malfunction may not be as simple as one malfunctioning part.

“While our experienced team has made significant progress in addressing the underlying component and vehicle subsystem issues affecting the Endurance build schedule, we remain committed to doing the right thing by our customers and to resolve potential issues before resuming production and customer shipments,” CEO Edward Hightower said in the statement.

“The team is diligently working with suppliers on the root-cause analysis of each issue and potential solutions, which in some cases may include part design modifications, retrofits, and software updates,” the company said.

“In this regard, LMC has filed paperwork with the National Highway Traffic Safety Administration to voluntarily recall the Endurance to address a specific electrical connection issue that could result in a loss of propulsion while driving. Lordstown is working with its supplier network to implement a corrective action that the company believes will address this issue.”

The company expects to provide a detailed update on the problem during its 2022 earnings call with analysts on March 6, it said.

The company did not begin production of its truck until last fall after a yearlong delay because of supply chain problems. (See Startup EV Makers Inching Toward Profitable Production.)

The company’s share price fell 11.38% on Thursday, closing at $1.09. During the last 52 weeks, the share price has been no higher than $1.47. It was as high as $29.01 on Sept. 14, 2020.

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Avangrid Pushes Forward on NECEC, Offshore Wind, PNM Merger

Avangrid (NYSE:AGR) announced Wednesday that its net income increased 16% in 2022 over 2021 but projected flat financials in 2023.

In a conference call with industry analysts, CEO Pedro Azagra said the company’s priorities this year are closing its merger with PNM Resources (NYSE:PNM), negotiating settlements in its utility rate cases and ensuring the economic viability of its New England Clean Energy Connect (NECEC) transmission project.

He said Avangrid remains committed to the Commonwealth Wind project off the Massachusetts coast and is still working on it, even after moving to terminate the power purchase agreements it agreed to.

Avangrid plans to submit an economically viable bid on that project in the state’s next offshore wind solicitation, Azagra added, and is working through the legal and economic challenges that face some of its other projects.

NECEC, first proposed in 2017, would bring Quebec hydropower to New England. After multiple challenges, the project won key court victories in 2022. (See NECEC Scores Another Victory in Maine’s Highest Court.)

But legal issues remain unresolved, Azagra said.

“Also, we have to review the economics just to be sure we get recovery of the costs we have incurred,” he said.

“With the delay caused by the unprecedented action by our opponents, we continue to look at restarting construction as soon as possible,” said Catherine Stempien, CEO of Avangrid Networks. “And with that restart of construction, we’re negotiating with all of our vendors to make sure we can optimize the construction schedule as well as the pricing. We’re doing that in the background as we’re proceeding with the legal matters.”

An analyst asked whether the financial review centers on the cost of construction of the line or on the revenue that will be derived from it.

“We are working on both sides,” Azagra said.

Turning to utility revenues, Avangrid reported that it had settled its rate case for Berkshire Gas in Massachusetts in 2022; expects its settlement negotiations for New York State Electric and Gas and Rochester Gas and Electric in New York to yield new rates in May; expects new rates for Central Maine Power in Maine by July; and expects rates for United Illuminating in Connecticut to be settled by September.

Avangrid also said its proposed acquisition of the largest energy utility in New Mexico is still in play, despite being shot down by that state’s Public Regulation Commission in December. (See NM Regulators Reject Avangrid-PNM Merger.)

Since that vote, Avangrid and PNM have extended their merger agreement and the elected commissioners have been replaced by appointees. Azagra expects that to make a difference.

“The new commissioners are each highly experienced individuals with deep knowledge of the challenges and opportunities the energy transition will bring, as well as the central role of utilities in enabling that transition,” he said.

During the call, Azagra spoke repeatedly about the economic pressures of the past year. He said Avangrid renegotiated PPAs for 780 MW of onshore wind in 2022 and, when it could not renegotiate the PPAs for the 1,232-MW Commonwealth offshore project, moved to dismiss them. (See Avangrid Seeks to Terminate Commonwealth Wind PPAs.) 

“Let me be clear: While we are terminating our PPAs for Commonwealth Wind, we remain fully committed to our offshore business. We are on track to bring the first large-scale project to successful completion,” he said, referring to the 806-MW Vineyard Wind I, now under construction and expected to start generating electricity later this year. “This is not a question of commitment or capabilities, but rather of a unique economic situation.

“Unfortunately, the impact of historic inflation, sharp interest rate increases, supply chain bottlenecks and existence of a price cap prevent us from moving Commonwealth Wind forward under viable economic conditions,” Azagra said. So Avangrid will submit a new bid to the state of Massachusetts in May, he added.

Asked by an analyst if Avangrid had confidence in the viability of such a bid amid continued economic pressures, Azagra said he did.

“Because of the work we have already done in the last more than three years, we’re probably as best positioned as we can to have [certainty] to make a new bid for this project because we continue working in the project, and we are committed to delivering this project.”

He noted that offshore projects in other states have included price indexing and said that given the multiyear time frame, an ability to make price adjustments needs to be considered for Commonwealth.

Unaudited financials show Avangrid ended 2022 with $901 million in adjusted net income on $7.92 billion in operating revenue, up from $780 million and $6.97 billion in 2021. That works out to $2.33/share in 2022 and $2.18 in 2021.

For 2023, it is projecting $850 million to $915 million in adjusted net income, or $2.20 to $2.35/share.

Additional discussion by the company about its projects and its finances is contained within its 10-K annual report, also published Wednesday.

Avangrid stock closed at $41.01/share in heavier-than-average trading, a 1.6% increase from Tuesday’s close.

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NYISO CEO Delivers ‘State of the Grid’ to Management Committee

NYISO CEO Rich Dewey used Wednesday’s Management Committee meeting to brief stakeholders on “the state of the grid” and the ISO’s priorities going forward.

“NYISO is excited about 2023 but is cognizant of the unprecedented challenges” arising from the Climate Leadership and Community Protection Act (CLCPA), which moves New York through “an unprecedented energy transition,” Dewey said.

Dewey said the ISO is focused on effectively transitioning the state’s grid from high-polluting and high-emitting resources to new renewables without compromising reliability. He also listed as priorities: ensuring projects such as the Long Island offshore wind solicitation remain on schedule; improving the interconnection process with more transparency and expediency; and fine-tuning market mechanisms to be more responsive during the transition.

Another priority is to “continue to recruit talented, engaged and motivated people” to NYISO and create a “learning environment focused on inclusion for every team member,” Dewey told the committee.

Scott Leuthauser of Hydro-Quebec Energy Services asked for Dewey’s opinion on the Public Service Commission’s recent approval of 62 renewable projects (See NY PSC Approves 62 Tx Upgrades Totaling 3.5 GW.)

Dewey responded that much of New York’s infrastructure and transmission needs were already identified by NYISO, and so the PSC’s recently approved projects are “compatible with what we see as needed and what we’ve been calling for.”

Chris Wentlent, of the Municipal Electric Utilities Association of New York State, asked Dewey what NYISO’s role would be in implementing the cap-and-invest program proposed by Gov. Kathy Hochul. Mark Younger, president of Hudson Energy Economics, asked whether it would be difficult to implement. (See Hochul Highlights Cap and Invest in State of the State Address.)

Dewey said NYISO has already spoken with heads of state agencies about the proposal, and they have “tapped into our expertise” and expressed “a spirit of cooperation and collaboration.” Dewey said he believes “it wouldn’t be a hard lift” to incorporate carbon pricing into NYISO markets but that “the proof will be in the pudding.”

Chris Casey, a senior attorney with the Natural Resources Defense Council, asked if Dewey believed that a cap-and-invest program might dissuade investors from New York.

Dewey responded that incentive programs that accelerate the transition to renewables can drive economic opportunities, but NYISO wants a balanced approach that “doesn’t create counter incentives that prematurely retire resources.”

Casey also inquired about NYISO’s staffing concerns. Dewey noted that vacancy rates in some parts of the organization were once above 10% of staff levels but have since dropped back to the historic norm of 5% because of the ISO attracting top talent in key areas.

DER Revisions

The MC approved NYISO’s proposed revisions to its participation model for DER aggregation, recommending that the Board of Directors approve them as well.

The revisions process had been contentious, but a NYISO statement promising to revisit its unpopular 10-kW minimum for individual resource participation assuaged stakeholders. The ISO’s Michael DeSocio read the statement before staffer Harris Eisenhardt outlined the revisions, which passed without discussion, objections or abstentions.

With FERC approval, the revisions are expected to go into effect in summer, which is also when DER aggregation open enrollment should begin. (See NYISO Promises to Lower DER Minimum Capability in Future.)

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EV Road Usage Charge Bill Floated in Wash. House

Washington Rep. Jake Fey (D) talked Tuesday about his bill to create a road usage fee for electric and hybrid vehicles.

Talking was his main goal — with fellow legislators, interest groups and other stakeholders.

Fey’s House Bill 1832 was more of a conversation starter than a nailed-down piece of legislation. 

“I’m not wedded to any specific detail. This is the start of a discussion,” he said at a hearing on the bill before the House Transportation Committee, which he chairs. “We can’t sit back and pray we’ll have a solution.”

Last year, Gov. Jay Inslee issued a mandate banning the sale of new gasoline-powered cars in the state by 2035, which led to Fey’s proposal of a road usage fee. The measure is designed to replace shrinking state gasoline tax revenue that pays to maintain Washington’s highways. (See Road to Mass EV Adoption Still Unclear in Wash.)

“Gasoline revenues are headed downward and consistently so from year to year,” Fey said. The legislature needs to discuss and hammer out a road usage fee system to counteract those shrinking gas revenues, he said.

HB 1832 proposes to establish a voluntary road usage charge program in 2025 that would levy a 2.5-cent fee for every mile that an electric or hybrid vehicle drives on public roads and highways. The fee would likely be calculated by an instrument connected to an electric vehicle’s odometer, a Transportation Committee memo said. A mandatory mileage fee would be targeted for 2030 under the bill.

Owners of electric and hybrid vehicles in Washington currently pay two annual fees that total $150. Under HB 1832, an owner would have the choice of either paying the $150 or the fees calculated by the odometer readings, which would be capped at the amount of the combined annual fees.

Before Fey suspended the hearing Tuesday, the Washington State Transportation Commission, Seattle Electric Vehicle Association (SEVA) and Seattle-based think tank Climate Solutions testified in favor of the bill, without getting into specifics.

“This is a more equitable system for EVs to pay their fair share of road costs,” SEVA’s Grace Reamer said.

Fey said he plans to reopen the hearing on HB 1832, but no date was set.