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November 18, 2024

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Former Lordstown Motors CEO Sells Shares Before Dismal Q1 Earns

Electric vehicle manufacturer Lordstown Motors (NASDAQGS:RIDE) last week reported a first-quarter loss of nearly $172 million and warned investors of “substantial doubt regarding our ability to continue as a going concern.”

An ongoing dispute with its partner and major funder, Taiwanese-based Foxconn Technology Group, regarding additional investment in the company erupted just days before the release of the quarterly results, sending the company’s share price from 52 cents at the end of April to a low of 26 cents last week. The share price closed Monday at 37 cents. 

Throughout the quarter, former CEO Stephen Burns continued to sell his stock in the company, according to a document Lordstown filed with the Securities and Exchange Commission at the close of business Friday.

The filing reported Burns had sold off nearly 10 million shares during the quarter as the share price fell below $1 and now owns nearly 17 million shares, down from the 46 million shares he owned in 2020, when Lordstown merged with special-purpose acquisition company DiamondPeak Holdings to raise substantial new funding.

Burns resigned as CEO in June 2021 after an investigation revealed that he and other company executives lied about the number of preorders Lordstown had for its electric pickup truck.

In another SEC filing last week, Foxconn agreed that it cannot legally walk away from its current funding agreement with Lordstown as the automaker warned Foxconn was preparing to do. (See Lordstown Motors Warns of Bankruptcy in Contract Funding Feud.)

The dispute with Foxconn erupted after Nasdaq removed Lordstown from its main trading chart when the automaker’s share price fell below $1. The company has floated a plan to do a “reverse stock split” in hopes investors will approve it at the company’s annual meeting.

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PJM Hears from White House Official on Security

CAMBRIDGE, Md. — A top White House security official urged participants in PJM’s General Session to engage in closer collaboration with RTOs, infrastructure owners and law enforcement at all levels as cyber and physical security threats morph.

“We need to think about how in this changing environment we can enhance our resilience — not just on the grid, but other critical infrastructure sectors,” said Caitlin Durkovich, deputy homeland security adviser for resilience and response.

The growing prevalence of renewable resources on the grid and new transmission technologies will increase the use of networked devices on the grid, which Durkovich said will bring new capabilities but also potentially create vulnerabilities for attackers to exploit.

Part of expanding grid security at all levels will involve a “Madison Avenue campaign” to educate the public, critical communities in particular, about the infrastructure they rely on. By increasing people’s ability to be more self-sufficient, she said first responders can focus on the most important aspects of their response to an emergency, be it a security issue or related to the impacts of climate change.

“It is a remarkable engineering feat, especially as you think about the number of … dependencies and interdependencies,” Durkovich said of the electric grid. “I think we’re at a point where we have to do a better job of helping Americans understand … the increasing threats that we’re dealing with.”

The Biden administration is currently working on updating the 2013 Presidential Policy Directive 21, which defines the responsibilities of government agencies and private companies in maintaining the security of critical sectors, as well as creating bridges for collaboration. The 2021 cyberattack on Colonial Pipeline was an instructive moment for the Department of Homeland Security, which Durkovich said has been working to create new communications infrastructure to allow for tighter collaboration between infrastructure owners and law enforcement. (See Glick Touts Gas Pipeline Reliability Organization Before Congress.)

In addition to strengthening security guidelines, she recommended that companies reach out to state and local law enforcement to identify ways of collaborating. Many of those agencies have received federal security funding and are also in the process of expanding their own practices or creating new programs, which could benefit from knowledge about the infrastructure within their jurisdictions. Recent attacks on substations have also highlighted the need for enhancing physical security, and Durkovich recommended companies reach out to report any suspicious activity.

RTO Panelists Discuss Experiences

A panel of top officials from CAISO, MISO, ISO-NE, NYISO and SPP discussed their experiences navigating the clean energy transition and how they’ve addressed challenges that would be familiar to PJM stakeholders, including how to accredit burgeoning renewable energy, resource adequacy concerns, and the siting and cost allocation for the transmission needed to interconnect intermittent resources.

Melissa Seymour, MISO vice president of external affairs, said the RTO has seen a dramatic evolution from a fairly homogenous grid powered by dispatchable coal resources to a more balanced and diverse fleet. Looking at the projects that are expected to be built in the coming years, however, she said it’s likely to become dominated by resources with limited ability to be dispatched. The margin between the accredited capacity on MISO’s grid versus installed capacity is expanding, along with the number of unforeseen outages, which she said pose a growing reliability risk.

SPP Vice President of Engineering David Kelley said that as wind resources began to proliferate in the RTO, it didn’t require the generators be dispatchable, requiring significant retrofits years later. PJM stakeholders recently endorsed a proposal addressing renewable dispatch, providing more transparency and expanding existing wind rules to solar resources. (See “Renewable Dispatch,” PJM MRC Briefs: April 26, 2023.)

In New England, coal and oil generation have fallen from accounting for 40% of ISO-NE’s generation to single digits, though oil still accounted for nearly a third of the energy supplied during the December 2022 winter storm. Director of External Affairs Eric Johnson said natural gas now supplies about 45% of the RTO’s energy, but there is a disconnect between the short-term commitments wholesale powers markets utilize for generators and the long-term investments needed to support the fuel infrastructure for those resources.

Constructing adequate transmission to meet localized load is proving to be particularly difficult for NYISO. Vice President of Market Structures Rana Mukerji said there is limited transmission going into New York City and opposition upstate to building more to connect to more plentiful renewables.

MISO has sought to address transmission needs by implementing long-term planning using its Multi-Value Project system. It is planning four tranches of transmission, with the first round approved in July 2022 with 18 projects. (See MISO Finalizes Long-range Tx Cost Sharing Plan.)

Johnson said ISO-NE has also experienced many of those challenges, presenting roadblocks to clean energy projects proposed by individual states. The RTO is exploring what can be done to reconductor or otherwise improve lines in existing rights of way and has found that many constraints can be resolved while avoiding siting new projects.

Casey Roberts of the Sierra Club questioned how the RTOs plan to manage the transition to clean energy and retirement of fossil fuels. Mukerji said it will require long-term storage capability beyond four intervals, which is not currently available technologically or economically in many cases.

Kelley said the December storm showed the need for forecasting to go beyond drawing off historical data to find ways of evaluating needs during rarely seen conditions, such as a sharp temperature drop on a holiday. The RTO created an Uncertainty Response Team in 2018, incorporating experienced staff from several departments tasked with identifying new risks and solutions.

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Public Interest, Environmental Groups Urge Transparency at PJM

CAMBRIDGE, Md. — Consumer advocates, environmental groups and a Maryland lawmaker last week all urged PJM to become more transparent in its decision making.

Maryland legislators often find their energy policies are stymied at the RTO level and struggle to identify why, Lorig Charkoudian, a Democratic member of the state’s House of Delegates, said during a meeting of PJM’s Public Interest and Environmental Organizations User Group on May 3.

Charkoudian was sponsor of HB 1186, a bill that would require state utilities to submit annual reports detailing any recorded votes they make at an RTO and explain how each vote benefits the public interest. The bill passed the House 100-35 in March but was not brought to a vote before the Senate prior to conclusion of the legislative session and would require reintroduction for further consideration. (See Maryland Bill Would Require Utilities to Report Votes at PJM.)

Charkoudian said the complexity of PJM’s operations and decisions makes transparency doubly important, as many of her constituents don’t understand what the RTO is and how it impacts the legislation they have pressed their elected officials to enact.

“A lot of what I have to do is then explain to them how an RTO works, which is interesting to do in a community town hall,” she said.

States’ confidence in organized markets comes from the ability of RTOs to predict and forecast, making it difficult for Charkoudian to understand how PJM didn’t predict a future in which a high volume of renewable resources would enter the interconnection queue, requiring a faster pace of processing requests to keep up, she said.

As Maryland pursues stronger clean energy policies, including the passage of the Promoting Offshore Wind Energy Resources (POWER) Act (SB 781) last month, Charkoudian said closer collaboration with PJM will be necessary. (See Md. Legislature Sends POWER Act to Governor’s Desk.)

“Our overall experience with PJM is [that] we pass laws and those laws can’t be enacted because of PJM interconnection queues,” she said.

Tyson Slocum, director of Public Citizen’s Energy Program, said public confidence in PJM has been undermined by the RTO’s recent fast-track processes for generators attempting to lower capacity performance penalties, closed-door discussions about the Independent Market Monitor contract and Base Residual Auctions (BRAs) being rerun with minimal stakeholder feedback. (See “Capacity Performance Penalties,” PJM MRC Briefs: April 26, 2023)

“This creates a credibility problem with PJM, and when you lose credibility you start to lose confidence in the markets … and I’d say that’s where we are with PJM,” he said. “… The more light that is shown on your deliberations, it will relieve those questions about whether special interests are driving your decision making.”

PJM CEO Manu Asthana said the RTO holds more than 400 meetings each year, the vast majority of which are open to the public, and it publishes records of the votes taken at the Members Committee, broken down by how each sector and individual member voted.

“Transparency is important, [and] it does lead to credibility, and we think we are extremely transparent,” he said.

PJM Board of Managers member Charles Robinson said it’s critical that all stakeholders be able to engage with the board to promote transparency and accountability, though it may not be possible to always involve simultaneous access. He said the board plans to release a written summary of the feedback it has received on the possibility of a review of the Monitor contract.

Consumer Advocates Question Transmission, Capacity Costs

Gregory Poulos, of the Consumer Advocates of the PJM States (CAPS), said PJM must be more transparent about transmission costs, which have been steadily rising, according to his presentation, and are likely to go higher as transmission plays a major role in making renewable generation deliverable in efforts to meet states’ clean energy goals.

Following recent meetings of the Transmission Expansion Advisory Committee (TEAC), Poulos said he was rebuffed after reaching out to transmission owners that presented supplemental projects and asking how they developed estimated project costs and solution budgets. Given the lack of cost information being presented to the TEAC and the short timeframe for presenting solutions, there’s little opportunity for stakeholder engagement, he said.

“These are really self-approved projects, and that’s not to say if they’re good or bad. I don’t have the information to know if they’re good or bad,” he said.

T. David Wand, an attorney with the New Jersey Division of Rate Counsel, said the December 2022 winter storm demonstrated that generators may not be able to deliver the capacity they’ve been paid for, undermining the foundations of the capacity market.

“How do we ensure performance? Without performance, it’s hard to have confidence that the capacity market is serving its intended purpose,” he said.

Wand said that when the capacity performance (CP) structure was created to incentivize performance, the Rate Counsel and other advocates expressed concern that risk penalties would be built into capacity bids, a reality that has come to pass, costing consumers millions of dollars.

“Generators did not complain when they received these [capacity payments] and saw no penalties. It was always known that penalties would happen and excusals would not be allowed,” he said.

Asthana said CP includes significant penalties that provide an incentive to perform and credited the CP program with contributing to years without any significant issues in the PJM markets. Nonetheless, PJM can still make improvements, such as exploring whether gas resources are over-accredited for winter operations.

While those improvements are being considered, Asthana said, it’s important to not cause generators to retire prematurely.

Poulos questioned whether that way of thinking represents a shift in priorities — from guaranteeing reliability to a focus on reducing penalties to hold onto existing generation.

“Are we going from performance and reliability as the No. 1 issue and goal to [a situation in which] we have resources that are too big to fail even though they’re not performing,” he said.

Advocates Defend Monitor

Ankush Nayar, of the D.C. Office of the People’s Counsel, said some stakeholder factions are “clamoring” for changes to the Monitor contract. Those critics want to allow others to compete for the contract, currently held by Monitoring Analytics, and they seek greater access to the Monitor’s data. (See PJM Stakeholders Discuss Monitor Contract Review.)

Nayar said states have confidence in the way that Monitoring Analytics’ Joseph Bowring has performed as PJM’s IMM. Mandating data access could undermine the independence that allows Bowring to continue his work, while putting an auditor in place would be “overkill,” he said. Rather than issuing an RFP for new applicants, Nayar said he’d prefer to see the contract revised, to maintain continuity.

PJM board member David Mills said the board has “the utmost respect for Monitoring Analytics,” and that its proposed review of the contract doesn’t seek to reduce the independence or strength of the Monitor but instead seeks to address stakeholder comments and concerns.

Environmental Groups Seek More Renewable Development

Environmental groups pushed PJM to ensure that its markets and operations were structured to support the growth of clean energy, arguing that the grid operator has lagged behind other RTOs in the volume of wind and solar cleared in recent auctions.

Casey Roberts of the Sierra Club said PJM’s February report on resource retirements and load growth — the “4R” study — ignored the role played by capacity market signals and offered a lopsided perspective on how state policies impact resource adequacy by not noting the impact of incentives to increase the pace of renewable resource development. She said the report has been cited in proceedings seeking to delay the retirement of coal plants and referenced a May 1 letter from the PJM board stating that retirements unforeseen by the study have already been filed.

“In our view, retirement of facilities like that is a good thing … rather than raising false alarms of the need to slow down retirements,” she said.

Tom Rutigliano, of the Natural Resources Defense Council, said the issues identified in the 4R study are the same as those being addressed by stakeholder initiatives to improve the capacity market, which is where resource adequacy concerns should be focused. Rutigliano thinks capacity market price signals are being impacted by over-accreditation of gas resources that are not accounting for fuel supply issues.

“PJM probably has several gigawatts of phantom capacity from gas plants that can’t deliver. Fixing that is the first step to preventing excessive requirements,” Rutigliano said.

Asthana said PJM’s interconnection queue has been advancing significant volumes of renewables, including some projects that require minimal network upgrades. However, few of those have been completed over the past year due to issues such as siting and supply chain challenges.

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PJM CEO, Panelists Address Reliability During Annual Meeting

CAMBRIDGE, Md. — Opening PJM’s Annual Meeting on May 1, CEO Manu Asthana said organized markets and planning have continued to stand the test of time, but challenges lie ahead as stakeholders wrestle with a possible overhaul to the capacity market to address future resource adequacy concerns, in part sparked by the impact of the December 2022 winter storm.

“Just within PJM we estimate our markets … bring in $4 billion in value each year to customers and producers. I know there’s a lot of rhetoric lately about RTOs and organized markets, and I just want to say RTOs and organized markets are” efficient and transparent, Asthana told the Members Committee at the meeting.

Though this is not the first time PJM has experienced a major energy transition, pointing to the shift from coal to natural gas for generation, Asthana said the clean energy transition presents a new, global challenge that will require the RTO to continue to evolve.

The need to interconnect more renewable energy could be exacerbated by a significant number of generation retirements that are expected through 2030, Asthana said, referencing PJM’s February Resource Retirements, Replacements & Risks (4R) report, as reserve margins are expected to shrink because of electrification and data center load growth.

The winter storm, also known as “Elliott,” underlined many of those concerns, leading PJM’s Board of Managers to initiate a Critical Issue Fast Path (CIFP) process in February to gather stakeholder proposals for the board to consider later this year. That process is currently in the second of four phases. (See PJM Stakeholders Refine CIFP Capacity Market Proposals.)

Though the storm was within the studied conditions that could be expected within PJM, Asthana said it was concerning that emergency procedures were required to meet load during the storm, and it’s necessary to now think about what can be done differently to not get as close to the edge next time.

“The question is, did our Capacity Performance [CP] rules work as intended? … I think it’s important that we look at that and think about that,” he said.

Last year’s FERC approval of a new system for handling interconnection requests — allowing PJM to work through its queue backlog quicker — will go a long way toward navigating the transition, Asthana said. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

“That complicated piece of work is a big deal for us. It is a big deal from a reliability perspective. It is a big deal from an energy transition perspective. It is a big deal from the perspective of helping our states and our members reach their energy transition goals,” he said.

PJM’s State Agreement Approach (SAA) has also proven itself to be a valuable tool for states to work with the RTO to meet their clean energy goals, he said. New Jersey received FERC approval for the cost allocation portion of its first SAA process to construct the transmission necessary to interconnect 7,500 MW of offshore wind. The state announced a second SAA process with the goal of developing 11 GW of offshore wind capacity by 2040. (See NJ BPU Backs Plan for 2nd Grid Upgrade Process with PJM.)

MC Chair David “Scarp” Scarpignato said Elliott was both an accomplishment for PJM and a struggle: The RTO kept the lights on while managing to provide aid to surrounding regions, but it laid bare unforeseen reliability issues. While a sudden emergency hasn’t occurred recently, it remains a real risk, and stakeholders must consider changes to price signals, a “circuit breaker” system for limiting extended periods of high pricing and the market seller offer cap, he said.

“Last year, the defining accomplishment or struggle for PJM at large was Elliott and how well our market reliability procedures and rules worked,” he said. “We, collectively, did keep the lights on.”

Panel Discusses Future Reliability Landscape

Independent Market Monitor Joe Bowring and PJM administrators shared how they’re working to maintain reliability through the clean energy transition through state, market, operations and planning initiatives.

Asim Haque, PJM vice president of state policy and member services, outlined the series of “Energy Transition in PJM” reports the RTO is publishing, detailing the challenges presented by the transition and possible solutions. The first iteration, “Reliability in PJM: Today and Tomorrow,” was released in March 2021, while the 4R study earlier this year was the most recent. He categorized the identified reliability concerns as immediate, largely pertaining to Elliott; near term, relating to resource adequacy in the latter portion of this decade; and upcoming, which includes essential reliability services.

“We do believe we are relatively well positioned today, but we are concerned this position may not hold for the not too distant future … so we feel some sense of urgency to act to maintain reliability,” Haque said.

In visiting state legislatures, he found that each have their own priorities but are all bound together by a desire for reliability. He recounted telling states that regardless of their individual goals, it is a reality that PJM’s interconnection queue is primarily composed of renewable resources, and planning the future of the grid will have to reflect that.

“The finding that most directly impacts reliability as we transition to greater renewable penetration is the conclusion that we will continue to need our thermal resources and the essential reliability services they provide in order to preserve reliability until a replacement technology for these resources is deployable at scale,” he said.

Senior Vice President of Operations Mike Bryson said there have been multiple retirements announced since the 4R study that weren’t anticipated during the document’s drafting, and some scenarios for this summer are showing operating reserve shortages this summer for the first time he can remember. The reliability-must-run (RMR) system is one potential area for improvement, as he believes there may be a more significant need for those contracts in the future.

Bowring said increasing reliance on RMR agreements could create an incentive to retire, and they should be used with caution. Bryson said they offer a benefit in allowing some flexibility in addressing policy retirements that could impact reliability, an area that cannot be met through market changes.

Ensuring the right types of reserve products and all necessary characteristics are being captured in offers and procured is critical to provide dispatchers assurance that when they call on resources, they will receive what has been committed, said Vice President of Market Design and Economics Adam Keech. The transition provides an opportunity to use markets to shape the grid of the future, focusing on flexibility and providing incentives as a proactive solution.

“Now is the time to use the markets proactively to send the right signal, so we attract the right resources we need,” he said.

Bowring said Elliott showed the flaws of having energy market incentives manifest in the capacity market and that extreme prices and penalties can have a destructive effect. He cautioned against creating new cost-of-service constructs as a reaction to the storm, saying that wouldn’t promote reliability; market solutions should be sought instead.

Vice President of Planning Ken Seiler said PJM is potentially on track to complete interconnection studies on projects with a nameplate capacity equal to resources expected to retire in the coming years, but much of that new generation is intermittent, which will push the RTO to change how it acts under various system conditions.

The first-come-first-serve interconnection model approved by FERC last year allows PJM to transfer the capacity interconnection rights of generators that complete the study process and receive an interconnection service agreement (ISA) but do not complete construction within a year. Seiler said PJM has seen a large number of projects that receive ISAs but haven’t entered construction.

Stakeholders Approve New Terms for 3 Board Members

The MC voted to reseat three board members whose terms expired: Jeanine Johnson, Margaret Loebl and Charles Robinson.

The committee also elected Vickie VanZandt to continue filling the remaining year left on the term previously held by Sarah Rogers, who retired in September 2022.

Johnson brings a background in cybersecurity and product design to the PJM board, to which she was elected in 2021, according to PJM’s biographies of the candidates. She was shortlisted as Entrepreneur of the Year by the Women in IT Awards for co-founding a company commercializing a product to create drinking water.

Loebl has held officer positions in finance at several companies, most recently serving as executive vice president and CFO at AgroFresh Solutions, and has worked with the board of companies on acquisitions, strategy, controls infrastructure and risk management, according to her biography. She was elected to the board in 2020.

First elected in 2011, Robinson serves as general counsel for the Regents of the University of California and was previously general counsel for CAISO. He has also served as a senior attorney for several companies, including Packard Bell and Raychem Corp.

President of VanZandt Electric Transmission Consulting, VanZandt was appointed to the board in 2022. She previously served as the senior vice president and chief engineer of transmission services for the Bonneville Power Administration and served on the ISO-NE Board of Directors.

States Argue Board Didn’t Consult Membership on Auction Delay

The MC voted to approve the minutes of its special meeting held April 4, but five states objected to them because they stated that PJM provided an update on the Base Residual Auction schedule and consulted with membership on delaying upcoming auctions.

The board is required to consult with stakeholders prior to making any Federal Powers Act Section 205 filing under the RTO’s tariff. PJM made a Section 205 filing to delay future auctions following the meeting on April 11 (ER23-1609).

“The board members weren’t present to have that discussion, so it was kind of a misrepresentation of what that meeting would entail,” said Gregory Poulos, of the Consumer Advocates of the PJM States. He added that the objecting states didn’t believe that it constituted an adequate consultation.

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PJM MRC Endorses Proposal to Reduce Performance Penalties

The Markets and Reliability Committee on Thursday endorsed a proposal to reduce penalties for generators that don’t meet their capacity obligations during performance assessment intervals (PAIs).

The package, made by American Municipal Power, redefines the penalty rate and the stop loss limit — the maximum a generator can be penalized in a year — to both be based on the Base Residual Auction (BRA) clearing price. It would also reduce the circumstances under which PJM can declare a PAI.

Both the penalty rate ($3,177/MWh) and stop loss ($142,952/MW-year) are currently based on the net cost of new entry (CONE). AMP’s proposal would reduce them to $394/MWh and $17,744/MW-year, respectively. The change would be effective through the 2024/25 delivery year. (See “Capacity Performance Penalties,” PJM MRC Briefs: April 26, 2023.)

The AMP proposal was one of three before the MRC during a May 4 special meeting, with LS Power and the Independent Market Monitor also making presentations. The subject was brought before the MRC by LS Power through the quick fix process, allowing the issue charge and problem statement to be considered simultaneously with the proposed rule changes. The Members Committee is set to consider endorsement of the AMP solution on May 11.

The LS Power proposal retained the $3,177/MWh status quo PAI charge rate but set the stop loss limit to twice the BRA clearing price, or $23,659/MW-year. All three proposals included the same PAI trigger.

Monitor Joe Bowring said LS Power’s proposal would result in the annual limit being reached very quickly, defeating the purpose of the penalties. The IMM’s proposal used the same penalty rate as AMP and the same stop-loss formula as LS Power. It did not receive a vote because AMP’s plan was approved.

According to the sector-weighted vote report, the Electric Distribution sector unanimously opposed the LS Power proposal, which was voted on first, but gave full support to the AMP solution. The Transmission Owner and End Use Customers sectors also gave majority opposition to the LS Power package and supported AMP.

During a May 1 special MRC meeting, LS Power’s Marji Philips said her company’s proposal was a compromise between PJM’s desire to have a higher penalty rate and the goal of many stakeholders of limiting when PAIs can be called and lowering the annual penalty cap. Philips said she would support any of the three options over the status quo, arguing that generators wouldn’t invest in PJM if they were subject to a penalty rate that could wipe out years of capacity market revenues.

PJM General Counsel Chris O’Hara said the RTO strongly preferred the LS Power proposal, largely because it has the highest penalty rate of the three.

“We feel that from an economic perspective and from a legal challenge perspective that if we are going to do something for these two years, we are much more comfortable leaving the penalty rate where it is,” he said during the May 4 meeting.

Reviewing penalty claims from the December 2022 winter storm, he said the capacity performance construct appears to have properly incentivized many generators to make investments to support their capacity obligations. In many cases, circumstances out of generators’ control impacted their ability to perform, he added, saying it makes a case for reducing the stop loss limit.

American Electric Power’s Brock Ondayko said a filing at FERC seeking to modify the stop loss limit would likely run into challenges that it constitutes retroactive ratemaking. He said generators expected to overperform their capacity obligation may have made offers based on the assumption that they were likely to receive a certain amount in bonuses in a year.

Vitol’s Jason Barker said reducing the penalty rate or stop loss limit effectively shifts the performance risk from a financial risk faced by generators to a reliability risk across PJM. Rather than a separate process addressing penalties for upcoming delivery years, he encouraged stakeholders to vote against all three and instead seek a solution through the ongoing critical issues fast path (CIFP) process. If an interim solution were to go forward, he said one limited to just modifying the PAI trigger would be preferable. (See PJM Stakeholders Refine CIFP Capacity Market Proposals.)

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California Faces Challenges Connecting 156 GW to Grid

Participants in a California Energy Commission workshop last week wrestled with the question of how the state can interconnect huge quantities of new storage and generation resources to its transmission grid in the next two decades to meet its climate goals.

State statutes require load-serving entities in California to serve retail customers with 90% carbon-free electricity by 2035 and 100% by 2045, while reducing greenhouse gas emissions to 40% below 1990 levels by 2030 and 85% below 1990 levels by 2045.  

“The punchline, of course, is that we need 86,000 MW added to our grid in 12 years,” said Sharon Eddy, executive director of the Large-scale Solar Association. “We need another 70,000 MW in the 10 years after that” to meet the 100% clean energy goal established by Senate Bill 100 in 2018. “This is unprecedented.”

The state’s transmission system needs major upgrades and additions in a relatively short timeframe to handle so much new capacity, panelists said in the workshop.  

“Our current transmission grid can’t accommodate an additional 86,000 MW without new lines, new poles, new substations, and we need it quickly,” Eddy said.

“Everyone is running into the fact that we just didn’t plan early enough to build out the transmission system,” she said. “The challenge isn’t that we have too many projects vying for too little grid space, it’s that our entire system and our planning processes weren’t set up to handle this kind of accelerated growth.”

541 Interconnection Requests

CAISO adopted what it called a “more strategic and proactive approach” to interconnections in its 2022/23 transmission plan, which identified 46 transmission projects costing $9.3 billion that California needs by 2032 to incorporate more than 40 GW of renewable resources. (See CAISO Retools Transmission Plan for Reliability, Renewables.)

Future transmission plans will have to address portfolios from the California Public Utilities Commission (CPUC) that call for adding 70 GW of new resources by 2033 and 86 GW by 2035, CAISO said.

The 2022/23 transmission plan broke with tradition by analyzing projected resource additions within 14 transmission interconnection zones. CAISO said the “zonal” approach will allow it to deal more efficiently with interconnection requests, which it previously evaluated in annual cluster studies.

Interconnection requests to CAISO have soared in the last three years, from 155 in 2020, to 373 in 2021, to 541 this year, in clusters 13, 14 and 15, respectively. This year’s requests totaled 354 GW on top of the 180 GW already in its queue, including 18 GW of requests for a single substation, CAISO said.

Performing cluster studies on “such a huge volume is inefficient and provides less meaningful study results,” said Neil Millar, CAISO vice president of infrastructure and operations planning. “This clearly calls on us to take action and move forward with more substantive, transformative changes, better prioritizing where we’re putting our energies.”

The ISO’s new zonal approach targets “energy rich zones” with current or anticipated transmission connections where CAISO wants utilities and resource developers to focus their efforts, Millar said.   

“We’re talking about volumes being required in next year’s transmission plan of over 7,000 MW of installed capacity to be added to the grid each year for the foreseeable future,” Millar said. “The challenge would be to maintain that pace year over year, which our current processes were not designed around.”

Transmission-owning utilities such as Pacific Gas and Electric also have been inundated with interconnection requests.

“For many years up to cluster 13, the number of applications never exceeded more than 70 and [involved] less than 20,000 MW,” said Marco Rios, PG&E’s manager of transmission planning. “That wasn’t the case in cluster 14, where we received 185 applications and over 46,000 megawatts of generation just in the PG&E system. That makes the study process very, very difficult.”

PG&E used to have a high withdraw rate, but fewer developers are withdrawing their projects from the queue, compounding the problem, he said.

‘Promising if Arcane’

The afternoon sessions of the all-day workshop dealt with possible solutions.  

Representatives of wind, solar and storage trade organizations urged CAISO to revise its generation deliverability study methodology.

Nancy Rader, executive director of the California Wind Energy Association, called it a “very promising if arcane topic.”

“Reforming that methodology could really accelerate generator interconnections and make more efficient use of our existing grid and every additional transmission project that we build,” Rader said.

The ISO launched a stakeholder initiative in December to review its deliverability methodology, she said.  

“CAISO uses this methodology to determine what reliability upgrades are needed for an interconnection customer to obtain deliverability capacity … which is what generators need to qualify under the CPUC’s resource adequacy program,” Rader said. “The point of the methodology is to ensure that a project will be able to deliver its generation to load when it’s needed.

“The prospect of reforming this methodology is exciting because it could immediately address the current lack of available [deliverability] capacity” on transmission lines, she said. “Without it, projects can’t qualify for RA and generally won’t be commercially viable. And so, in our view, the available capacity appears to be insufficient to meet the state’s mid-decade and certainly our longer term SB 100 goals. And that will remain the case until new transmission is planned and built and that’s about 10 years off…”

CAISO currently uses a more restrictive methodology for assessing deliverability capacity than other RTOs, Rader said. Adopting less stringent criteria such as that used by PJM and MISO could “free up more than 10 GW of capacity immediately across the CAISO grid in areas … where the grid is strong,” she said.

“Capacity is a function of the assumptions used in the CAISO’s deliverability study methodology, and in our view those assumptions are unnecessarily conservative,” she said. “Reforming those assumptions consistent with those used by PJM and MISO could dramatically expand [deliverability] capacity. And that capacity would immediately become available at no cost.

“So, we really might have a big free lunch here,” she said.

Rader said she and others were looking forward to discussing the issues in CAISO’s upcoming stakeholder process.

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Constellation CEO: Nuclear PTC Could Extend Reactors’ Life to 80 Years

The Inflation Reduction Act’s production tax credits for nuclear could boost Constellation Energy Group’s (NASDAQ:CEG) profits by $100 million annually beginning in 2024 and help extend the life of its reactors to 80 years, CEO Joseph Dominguez said during the company’s 2023 first quarter earnings call on Thursday.

Nuclear represents about 86% of the terawatt-hours of power Exelon’s spin-off independent power producer generates for its customers, according to the company website. The PTC, which could provide up to $15/MWh for plants not already receiving state support, “provides downside commodity risk protection … while ensuring that our plants remain economic and reliable,” Dominguez said.

“Other provisions in the IRA create unique growth opportunities, like increasing the output from our nuclear plants through upgrades and hydrogen [production],” he said. “And finally, it gives us the opportunity to extend  the time horizon of our fleet to 80 years. … No other clean energy assets can run this long without being replaced.”

The company began producing zero-carbon hydrogen at its Nine Mile Point nuclear plant in Oswego, N.Y., in March. The 1-MW hydrogen production facility was a joint demonstration project of Constellation and the Department of Energy. (See Megawatt-scale Demonstration Project Yields First Pink Hydrogen.)

“The clean hydrogen generation system operating at Nine Mile Point uses 1.25 MW of zero-carbon energy per hour to produce 560 kg of clean hydrogen per day, more than enough to meet the plant’s operational hydrogen use” to cool the facility, according to a company press release on the project.

Constellation also said it will invest $900 million through 2025 to develop and scale commercial clean hydrogen production using nuclear power.

Marking just over a year since its separation from Exelon, Constellation reported first-quarter GAAP net income of $96 million versus $106 million in the first quarter of 2022. Adjusted (non-GAAP) EBITDA was $658 million, down from $866 million.

The lower 2023 figures were partially caused by higher energy prices in 2022 and increased refueling outages and labor costs as Constellation has been increasing staff, said Daniel L. Eggers, executive vice president and chief financial officer.

Dominguez was nonetheless upbeat about the quarter’s results, saying the company expects “we will end the year comfortably in the top half of our guidance range” of $2.9 billion to $3.3 billion.

It declared a dividend of 28.2 cents/share in the first quarter, about twice the payout in the first quarter of 2022.

The Nuclear Edge

While Constellation is now separate from Exelon, which reported its first-quarter results one day earlier, both companies are positioning themselves as key players in the U.S. energy transition, providing carbon-free power to a broad range of residential and commercial customers. (See Exelon CEO: Energy Transition ‘Requires Investments,’ Rate Increases.)

With its large nuclear fleet — 12 plants with 21 reactors — and smaller amounts of solar and wind, Constellation boasts that it is currently producing 90% of its power from carbon-free sources. All of the generation it owns will be 100% carbon-free by 2040, it says.

Dominguez said the company provided 11% of the country’s clean power in 2022, serves 25% of the competitive commercial and industrial market and numbers 75% of the Fortune 100 among its commercial customers.

He also stressed nuclear’s reliability in the face of the increasing number and severity of extreme weather events.

With electric generation shifting toward more intermittent renewables, anyone participating in retail or wholesale markets has “to ask yourself really three basic questions,” Dominguez said. “Do I have physical generation? Is it the kind of physical generation that is going to show up in extreme events? And do I have the financial balance sheet to deal with negative outcomes?”

How the PTC Will Work

The nuclear PTC does not kick in until 2024, when Constellation anticipates four of its 12 plants will be eligible for the credit: Calvert Cliffs in Maryland, LaSalle in Illinois, and Limerick and Peach Bottom in Pennsylvania.

Payoff Dynamics (Constellation Energy) Content.jpgThe IRA’s production tax credit for nuclear will help Constellation top up its revenues from nuclear plants not already receiving state subsidies. For example, if the company is getting $35/MWh at a plant, the PTC will add $7/MWh to ensure a total of $42/MWh. | Constellation Energy

The credit is designed to ensure nuclear owners are getting around $40/MWh for their power, with the amount of the credit a specific plant gets hinging  on market prices. The credit phases in at $25/MWh and phases out at $43.75/MWh, Constellation said.

In a hypothetical example, the company assumes prices at $35/MWh, with the PTC then kicking in $7/MWh, to ensure a total of $42/MWh.

In such a situation, Eggers said, “The PTC is functioning as it should, stepping in to provide downside protection.”

Dominguez was confident that IRA tax credits would not be lost in any deal over the debt ceiling now being debated between the White House and congressional Republicans.

“We just see that as — it’s hard to use the word ‘normal’ — the political back-and-forth that’s occurring,” he said. “I don’t think there’s any prospect that President Biden is going to cut or gut the IRA to deal with this issue.”

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Coalition Promotes US-Canadian Offshore Transmission Link

An industry coalition is promoting the concept of underwater transmission linking New England and Nova Scotia with each other via wind farms off their respective coasts.

The shared infrastructure, they say, would help both regions meet their climate-protection goals in the coming decades.

The New England-Maritimes Offshore Energy Corridor last week released a report on the concept prepared by risk-management company DNV and electric consulting firm Power Advisory.

It is not a business case for building such a power line; it was intended to show its potential benefits, rather than quantify them.

But the benefits would be spread among multiple parties, the report’s authors write, so for a proposal to attract investment, they must be quantified and recognized in the cost-allocation process.

The long, windy coast of New England is expected to play a critical part in that region’s clean energy drive, with Massachusetts alone targeting 5,600 MW by 2027 and other states hoping developers will install thousands more megawatts.

Nova Scotia’s provincial government wants to offer leases for 5 GW of OSW between 2025 and 2030 to support its budding green hydrogen industry.

Transmission between the two sets of offshore wind arrays could both enhance grid reliability and provide economic benefits, the authors said. Nova Scotia turbines could export to ISO-NE during high-priced hours, and wind turbines in the Gulf of Maine could export to Nova Scotia to reduce curtailment.

Weighing against this are multiple challenges: the multijurisdictional permitting of such a line, its non-traditional value proposition and its significant cost: High-level price estimates range from $6.4 billion to $8.3 billion (USD).

Government financial support would be needed. Meanwhile, the floating turbine technology that would be required in the deep water of the Gulf of Maine is still being developed, and the supply chain to manufacture its components is facing yearslong delays.

NEMOEC comprises:

      • Atlantic Canada Offshore Development, a joint venture of Copenhagen Investment Partners and Shell Canada to explore the potential for OSW in Canada’s Maritime provinces;
      • hydrogen and ammonia developer Bear Head Energy, a subsidiary of BAES Infrastructure;
      • Ireland-based renewable energy developer and operator DP Energy;
      • floating wind developer Hexicon;
      • transmission line developer Grid United;
      • Canadian power producer Northland Power; and
      • floating offshore wind developer TotalEnergies SBE US, a partnership between TotalEnergies and the Simply Blue Group.
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Climate Advocates Ask FERC to Reject ISO-NE Capacity Results

Environmental activists asked FERC on Friday to reject the results of ISO-NE’s Forward Capacity Auction 17, saying continued payments to fossil fuel generators is a risk to ratepayers and the climate.

The March 6 auction for the 2026/27 procurement period saw a slight increase in non-emitting generation obligations but still resulted in over three-quarters of the total obligations going to fossil fuel generation. (See FCA 17 Shows Clean Energy Boost, Endgame for Coal in New England.)

ISO-NE filed the results on March 21, asking the commission to find them just and reasonable and in accordance with the RTO’s tariff (ER23-1435).

More than 160 individuals and organizations wrote comments opposing the auction’s results. No Coal No Gas, a New Hampshire-based campaign to end fossil fuels that recently elected an activist slate of candidates to the Consumer Liaison Group’s (CLG) Coordinating Committee, coordinated the effort to reject the results. (See Climate Activists Take Over Small Piece of ISO-NE.)

“Based on blatantly inaccurate assumptions about the capacity, reliability and sustainability of fossil fuel-powered generators, the FCA 17 results not only violate ISO-NE’s mandate, but also call into question the legitimacy of the [Forward Capacity Market] as a whole,” the group wrote in its comments. “Thus, the arguments made in No Coal No Gas’s protests and comments are directly relevant to whether the ISO-NE followed its tariff when it conducted FCA 17.”

The group noted that the Merrimack Station did not win a capacity supply obligation, saying it was “grateful that our utility bills will not be used to subsidize coal as of June 2026.”

But it lamented that the auction “awards hundreds of millions of ratepayer dollars to keep the oldest, dirtiest, least economical fossil fuel-powered generators online for use as peaker plants. By propping up these failing fossil fuel-powered generators as standby peaker plants and sending bonus payments to base load generators, ISO-NE is preventing a just transition on our dime, and we call on FERC to intervene.”

The organization highlighted a 2019 white paper commissioned by the Sustainable FERC Project that found that capacity markets like those run by ISO-NE “have built-in biases against renewable energy.”

Commenters also criticized the structure of ISO-NE, arguing that the Forward Capacity Auction is part of a broader bias within the RTO favoring existing fossil fuel generators and providers.

“The current status quo financial subsidies and broken rules of ISO’s transmission grid has created a state of high ratepayer financial and physical vulnerability,” wrote Nathan Phillips, a Boston University ecology professor and one of the recently elected members of the CLG coordinating committee. “ISO-NE’s corporate arm, NEPOOL, is set up so that ratepayers are only one-sixth of the stakeholder groups involved in the grid.”

The Berkshire Environmental Action Team also filed comments in opposition, saying ISO-NE should “also aggressively prioritize demand response and other efficiency programs, and engage ratepayers in programs designed to reduce demand during peak events on the grid.”  

Several companies with a financial stake in the auction — including Eversource, National Grid, Calpine, Dominion and Constellation — filed motions to intervene in the proceedings, though none filed comments.

ISO-NE has requested FERC rule on the auction results with an effective date of July 19.

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Wash. Allocates Millions from Cap-and-Trade Fund

A new pumped storage site, an undetermined number of solar farms and agrivoltaic ventures are among the projects for which Washington is allocating $300 million.

Washington’s first cap-and-trade carbon allowances auction in February raised $300 million for the state’s coffers. (See Washington Confirms $300M Take for 1st Cap-and-Trade Auction.)

Near the end of the legislative session last month, Washington lawmakers divided the $300 million into 188 individual appropriations. Highlights include:

  • $10.7 million to develop agrivoltaic projects, the mingling of solar farms with growing crops and grazing livestock. Washington currently has a small agrivoltaic project operating on the Colville Indian Reservation near the Grand Coulee Dam. In May 2022, the Yakima County government approved BayWa r.e.’s 94-MW Black Rock agrivoltaic solar farm, expected to be completed next year.  
  • $39 million will go to developing solar farms.
  • $40.9 million to help local government add climate planning to their urban growth planning. The Legislature recently passed House Bill 1181, which adds climate considerations to city and county land-use planning.
  • $600,000 to help site new pumped storage projects. The Legislature recently passed HB 1216, which directs the Washington State University Energy Program to develop a pumped storage siting process. Washington has one pumped storage project in the works, which is controversial because part of it would be on land that the Yakama Indian Nation considers culturally sacred.
  • $20 million to help the state’s fledgling hydrogen industry. Washington, Oregon, Idaho and Montana have combined forces to seek at least $1 billion in federal money to create a regional hydrogen hub. Another $3 million will be allocated to build hydrogen vehicle refueling infrastructure. 
  • $50 million for climate change projects for the state’s tribes.
  • $15 million to capture methane rising at the state’s landfills.
  • $50 million to install solar panels on public buildings. 
  • $1.4 million to deal with childhood asthma problems related to jet fumes from SeaTac International Airport between Seattle and Tacoma. 
  • $36 million to build charging infrastructure for electric vehicles.
  • $30 million to build a hybrid electric ferry. Another $180 million is allocated to overhaul ferry docks and terminals to handle electric ferries.

The next quarterly auction is set for May 30.