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November 20, 2024

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ERCOT’s Vegas Makes His Case for PCM

AUSTIN, Texas — ERCOT CEO Pablo Vegas has laid down his markers to redesign the market, framing the Texas regulators’ preferred design construct as a reliability product that will “incentivize development and preservation of dispatchable generation.”

Vegas told his Board of Directors Feb. 28 that the performance credit mechanism (PCM) — which would retroactively reward dispatchable generation that meet performance criteria during the tightest grid periods with incentive payments — addresses the grid operator’s resource adequacy and operational flexibility challenges.

Vegas said ERCOT needs more dispatchable energy, pointing to a chart that showed demand has grown steadily since 2000. (Vegas likes to say Texas adds a city the size of Corpus Christi — population 317,773 in 2021 — every year.) ERCOT’s peak load cracked the 80-GW threshold last year, a more than 5-GW jump in three years.

Thermal contributions (ERCOT) Content.jpgERCOT projects thermal contributions to remain steady while renewables increase. | ERCOT

 

Some 27 GW of thermal, or dispatchable, generation in the grid operator’s footprint has been shuttered since 2000. During that time, more than 52 GW of renewable energy has been added; almost as much thermal generation has been added, but it nets out to 24 GW of thermal resources when retirements are taken into consideration.

“We’re now getting to a place where the peak demands require the availability of renewables in order to meet the energy needs of Texas and that’s going to continue to grow into the renewable space,” Vegas told the board. “The reality is, we cannot always predict and plan for when renewables will be available. We can’t control when the wind blows and when the sun shines. With both a correlation of extreme peak and very low performance on renewables, then we can be in an area of risk of significant risks.”

Renewable energy’s growth and its potential swings in availability on any given day create operational risks to the grid, Vegas said.

“The more energy that we carry with renewables as the fleet of renewables have been growing meaningfully across the state of Texas, the risk associated with a real time operations grows at the same time,” he said. 

Vegas allowed that renewables offer a “tremendous service” as a low-cost energy source, while also filling the demand gap on high-demand days or when fossil generation outages are up. He said the challenge in ERCOT’s energy-only market is that it allows “the zero cost of those renewables to suppress pricing in the overall market.” 

“What that has done is it made it very difficult for dispatchable generators to recover a more significant cost profile to build these large power plants, and they don’t have any federal subsidies to help them do that. It makes it difficult for them to make investments in the state,” Vegas said. “We have to fix the market so that we continue to support the long-term reliability of the grid and look to the future and feel confident that we’ll always be able to meet the needs of Texans, regardless of what’s happening.”

The PCM adds a new revenue stream from generators separate from the energy and ancillary services markets, Vegas said, “specifically created to incentivize generators that can perform when needed and can do so when the grid is tight.” (See Texas PUC’s Market Redesign Dominates ERCOT Market Summit.)

ERCOT expects the PCM to increase total energy costs by $460 million a year, adding a “modest” 2 to 3% to customers’ bills. It has projected implementation will take up to four years and cost between $2 million and $4 million.

Critics say the cost could be much higher.

A report released last week by Bates White Economic Consulting for several industrial consumer groups contends the construct will costs billions “without a meaningful improvement in reliability.” The study reviewed consultant E3’s evaluation of the alternative market options, including the PCM, a dispatchable reliability reserve service (DRRS) and a direct procurement mechanism that could be deployed as a last resort should a dispatchable resources’ shortfall be identified in the future.

The Bates White assessment concluded that a DRRS ancillary service will provide additional market signals sufficient to incentivize new dispatchable generation at a fraction of the PCM’s cost. The latter would create a “tortuously complicated system” that adds costs without improving reliability, the report said.

Bates White said ERCOT’s immediate reliability challenge is to ensure operational flexibility to accommodate continuing additions of intermittent renewable generation. It said the energy and ancillary services markets are the appropriate focus for ensuring flexible and cost-effective operations.

Aurora Energy Research’s Oliver Kerr said during a recent conference that the firm’s analysis found the PCM would be “fairly costly,” ranging from $3 billion to $5 billion across various scenarios.

During the latest legislative hearing on ERCOT’s market design before the House State Affairs Committee last week, Texas Industrial Energy Consumers’ Katie Coleman said the PCM means higher costs “without any guarantee we’ll get anything in return.” The construct will simply shift money from consumers to generators, she said.

ERCOT staff is keeping close tabs on the Texas Legislature, where the PCM proposal continues to run into headwinds. The Public Utility Commission recommended the design to the lawmakers in January but will defer to them on the final design.

At the PUC’s direction, ERCOT staff is soliciting input from stakeholders on a proposed bridging mechanism that would retain existing resources and attract new generation until the final market design is developed. The options include a manually settled PCM, procuring more ancillary services, tweaking the operating reserve demand curve, and a backstop reliability service, previously offered by the PUC, to set aside capacity that is only dispatched during scarcity conditions.

“We’re going to look at what options we can do today to continue to operate the grid as reliably as we have and what can we do to try to send signals to the market, potentially to start developing resources today,” Vegas said.

During a first workshop on the bridging construct Friday, Kenan Ögelman, who oversees the ERCOT market’s design and its commercial operations, asked for stakeholder involvement in the process.

“My goal is to have some kind of matrix summarizing the feedback that we received from you such that there is an easy way for board members to tabulate and figure out where there might be some stakeholder consensus,” he said. “Certainly, I want to recommend something that has some broad stakeholder consensus and that meets the commission’s objective.”

A second workshop is scheduled March 15, during which staff will provide feedback on the comments it has received and seek further discussion on each option. ERCOT plans to bring a final bridging solution to the board for its consideration and approval April 18.

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FERC Approves Transmission Incentives for Dayton Power

FERC on Friday granted two sets of incentives to Dayton Power and Light (NYSE:AES) for transmission upgrades across Ohio (ER23-762).

The 18 projects approved for incentives amount to about $226.4 million, which Dayton stated in its filings represents an approximately 41% increase in its gross transmission plant in service. The company argued that granting its application would allow it to smooth rate changes over time and strike a balance between maintaining its credit quality and reasonable rates for customers.

The work includes upgrades to the Marysville substation, expanding the West Manchester substation, and constructing new substations and 138-kV lines between several substations in the Lewisburg, Madison and Amsterdam areas.

The construction work in progress (CWIP) incentive would help control risk during construction, Dayton said, while the abandoned plant incentive would provide risk mitigation for events outside the utility’s control that cause the abandonment of the project, including PJM canceling projects in its Regional Transmission Expansion Plan (RTEP); state and local permitting requirements that prevent siting and federal; or state environmental permitting requirements.

“The record indicates that the cost for completing these projects will put pressure on Dayton’s finances. Granting the CWIP incentive will help to ease this pressure by providing upfront certainty, improved cash flow and reduced interest expense as Dayton proceeds with these projects,” the commission wrote in its order.

“We agree with Dayton that these projects face substantial risks outside of Dayton’s control. … We find that the risk of project cancellation is particularly acute when, as Dayton notes, Dayton has not yet obtained all the needed permits and local approvals to proceed with building these projects.”

The commission granted approval outright for six projects that have already been incorporated into the RTEP or approved by the Ohio Power Siting Board, while the remaining projects received conditional approval with the stipulation that Dayton submit compliance filings within 30 days of siting board approval or RTEP inclusion.

FERC rejected a protest from Public Citizen arguing that incentives should not continue to be granted “on an ad hoc basis” as the commission is considering revising their use through a Notice of Proposed Rulemaking. The organization also contended that the incentives are meant to be granted when necessary to encourage new transmission investments and that Dayton has not demonstrated that there are substantial risks to justify their approval, particularly given changes to siting and federal financing through the Infrastructure Investment and Jobs Act. (See “Construction Work in Progress,” FERC Issues 1st Proposal out of Transmission Proceeding.)

Commissioner Mark Christie also expressed reservations with the approval in a concurrence, stating that he believes Dayton has met the existing requirements to qualify, but that he believes that FERC needs to re-examine the incentives offered to developers.

“In my concurrences to prior orders … I questioned, among other concerns, whether the commission’s determination of whether ‘substantial challenges and risks’ exist when granting the abandoned plant incentive and other incentives has become nothing more than a check-the-box exercise,” he said, pointing to his concurrence in the granting of incentives to NextEra Energy (ER22-1886).

Christie had likened the granting of incentives before a project’s completion to turning customers into a bank for developers, with consumers expected to loan money through formula rates while also paying the utility a profit. The abandoned plant incentives approved for Dayton also would make ratepayers the “insurer of last resort.”

“Just as consumers receive no interest for the money they effectively loan transmission developers through CWIP, they receive no premiums for the insurance they provide through the abandoned plant incentive if the project is never built,” Christie wrote in concurrence to Friday’s order. “And if the CWIP incentive is a de facto loan and the abandoned plant incentive is de facto insurance — both provided by consumers — then the RTO participation adder, which increases the transmission owner’s [return on equity] above the market cost of equity capital, is an involuntary gift from consumers.”

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NJ Opens Third OSW Solicitation Seeking 4 GW+

New Jersey’s Board of Public Utilities (BPU) voted to open the state’s third offshore wind solicitation Monday with a goal of doubling the state’s wind capacity, paying little heed to the opposition to already approved wind projects along the Jersey Shore.

The unanimous vote launched a solicitation period that will conclude at 5 p.m. on June 23, in what BPU President Joseph L. Fiordaliso said confidently would be “another step forward in making New Jersey the supply chain for offshore wind along the eastern seaboard.”

“There are forces out there who don’t want us to do this. But we’re going to do it,” Fiordaliso said. “Renewables are the wave of the future. And New Jersey, I’m proud to say, is leading the way.”

The solicitation guidance document seeks projects totaling 1.2 GW to 4 GW and adds that the BPU may award projects above or below the target. Applicants must submit a completed application form and an explanation of their project and investment in it, as well as an in-depth analysis of its economic impact on the state. Unlike earlier solicitations, applicants are also required to submit proposals for creating infrastructure to tie their projects and others in the ocean to the grid in New Jersey.

The BPU expects to award projects in the solicitation in the fourth quarter of this year and have them up and running by 2030.  

Seeking Competition

The solicitation comes nearly four years after the board approved its first offshore wind project, the 1.1 GW Ocean Wind, and two years after the approvals of Ocean Wind 2, with a capacity of 1,148 MW, and Atlantic Shores, with a capacity of 1,510 MW. (See NJ Awards Two Offshore Wind Projects).

The three projects, which total 3,758 MW, already are moving ahead. But Ocean Wind 1, because it is the state’s first offshore wind project, has faced the most opposition. Opponents include residents concerned about its impact on their ocean view, the commercial fishing sector, which worries that the turbines will reduce their access to fishing areas, and tourism interests fearful that the sight of wind turbines ten or more miles off the coast will deter visitors.

Most recently, local government officials have cited a spate of nine or so dead whales washing up on New Jersey as a sign that pre-construction sonic testing is potentially having a negative impact on marine life, although federal officials at the Marine Mammal Commission say there is no link in the deaths to any offshore wind work. Some opponents, and the New Jersey Division of Rate Counsel, have urged the state to slow the pace of OSW projects until environmental and other studies are finished, and the true impact of the turbines is known.

Before backing the project, Commissioner Robert Gordon noted the vigorous bidding war for offshore wind contracts in the New York-New Jersey Bight when it was held in February 2022; it resulted in combined bids totaling $4.37 billion. He said he is “very hopeful … that we will see many more applicants entering the market and promoting a more competitive market for offshore wind in New Jersey.” (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)

“What we are seeing today is yet another concrete piece of evidence of New Jersey’s long-term commitment to offshore wind,” he said. He added that the board’s solicitation document should persuade anyone “of our commitment to protecting both the ratepayers and the marine ecosystems off our coast.”

Disappearing Promises

In contrast, Commissioner Dianne Solomon, who also voted to open the solicitation, expressed reservations, especially the potential cost to ratepayers.

“It appears that with every solicitation promises are made that somehow disappear or we learn of increases in costs above and beyond that which we relied upon making our initial awards,” she said. “Now, I certainly understand within an enterprise of the scope and size of offshore wind, that there are bound to be challenges and changes. … But folks are relying on us to make prudent decisions that will forever impact the cost of energy here in New Jersey, not to mention the landscape and waters of our coastline.”

Solomon, noted that the solicitation allows the BPU to award a very large volume of new wind capacity, or none at all. “It is my hope that before the board approves the next project, we will have answers to the valid questions raised,” she said.

Fiordaliso, speaking after Solomon, said that in cooperation with the New Jersey Department of Environmental Protection, “we’re going to ensure the fact that the commercial fishing industry is protected, that the marine wildlife is protected. And that it’s going to be a boon economically for the state of New Jersey.”

He said that critics expressed similar concerns about the cost of solar power at the start of the century, when the state vigorously developed that sector, and the “cost of solar has greatly diminished.”

Submitting Small and Large Projects

Gov. Phil Murphy in September increased the state’s OSW target capacity from 7.5 GW by 2035 to 11 GW by 2040. A board award of 4 GW in the third solicitation would take the state to approved capacity of 7.58 GW. The state expects to hold three more solicitations, each for 1,200 MW, starting in 2023 and finishing in 2030.

Applicants must state the price ($/MWh) of Offshore Wind Renewable Energy Certificates (ORECs) at which they would complete their proposed project. The OREC price reflects project costs including equipment, construction, financing, operations and maintenance, and taxes, offset by any state or federal tax credits and other subsidies or grants.

The BPU is encouraging applicants to make several submissions, including at least one that will generate only 1.2 GW of energy, and others detailing larger projects.

The submissions must also detail the developers “proposed investment in New Jersey offshore wind infrastructure, supply chain, labor force development, other in-state investments, and how the proposed investment furthers the development of New Jersey as a regional hub for offshore wind.”

The document also demonstrates the state’s desire to maximize economic development, urging applicants to use the state’s infrastructure, such as the New Jersey Wind Port under construction in Salem County.

 “Applicants can further demonstrate commitment to in-state economic development by including incremental supply chain infrastructure as part of the proposed project(s). The state values the opportunity for new Tier 1 manufacturing facilities, specifically for full-scale manufacturing of blades or towers at the New Jersey Wind Port.”

Environmental groups welcomed the solicitation. The state branch of the Sierra Club released a statement, which also was supported by Environment New Jersey, saying the solicitation puts New Jersey at the “vanguard of a new clean, renewable energy industry that will drive workforce development and economic prosperity, shoreline protection, and marine and wildlife preservation.”

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NYISO Previews Capacity Accreditation Modeling Work

NYISO last week briefed the Installed Capacity/Market Issues Working Group on its efforts to improve capacity accreditation by modeling natural gas constraints, special-case resources (SCRs) and correlated derates.

The three projects are intended to produce more accurate capacity accreditation factors and capacity accreditation resource class (CARC) calculations, as well as capture metrics not represented in installed reserve margins (IRMs) and locational capacity requirements (LCRs) in resource adequacy models. (See “Capacity Accreditation Kickoff,” NYISO Presses Onward with DER Revisions; Stakeholders Struggle to Keep up.)

Current models do not identify and quantify natural gas constraints; sufficiently align SCR expected performance and obligations with NYISO’s expectations; nor include attributes like functionally unavailable capacity from generators during peak conditions.

NYISO’s work will involve identifying individual gas-only units’ characteristics and partnering with neighboring RTOs to develop methodologies to better identify and quantify gas pipeline constraints.

Currently IRM/LRM models do not properly reflect SCR performance, so these resources cannot be treated as a separate CARC. NYISO will test different ways to stagger zonal SCR activations in the modeling, as initial analyses showed that doing so lowered loss-of-load expectations.

In response to stakeholder questions, the ISO made a point to note that changes to the design of the SCR program itself are not within the scope of the project.

NYISO will also address potentially over-crediting emergency generators that are functionally unavailable during peak times of high temperatures and humidity, a problem identified by Potomac Economics.

That involves evaluating incorporating water temperature and humidity into IRM/LCR models, as well as assessing whether dependable maximum net capability tests should be updated to better reflect resource adequacy values for capacity-limited resources.

DER Aggregation Registration

NYISO also presented stakeholders proposed updates to the distributed energy resource Aggregation Manual, which detail the requirements developers must follow to successfully register as a DER aggregator.

Along with relevant transmission and data paperwork, prospective aggregators must provide two “operational contacts” whom NYISO can contact at any time for operational support.

The ISO plans to begin accepting registration packets by April 28.

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‘What Did We Do to Deserve This?’

The administrative law judges running an information session on the transmission lines for a wind farm proposed off Long Island had to repeatedly remind callers Thursday that the discussion was about the 11 miles of cable under the jurisdiction of the Department of Public Service. Not about a disastrous Ohio train derailment, municipal fiscal management or groundwater contamination at a U.S. Marine Corps base.

The cables for Empire Wind 2 would make landfall in the densely built barrier island community of Long Beach and connect to a substation in nearby Island Park (DPS case number 22-T-0346).

While the moderators struggled to keep the questions within scope, callers on the phone-in session were frustrated by the frequent lack of answers.

DPS staff and Equinor (NYSE:EQNR) officials opened the session with an overview of the review process for the 1.26-GW wind farm proposed by Equinor and BP (NYSE:BP) 15 to 30 miles off Long Beach. The developers began work on the proposal in 2017. They are hoping for federal approvals in early 2024 and state approvals later that year.

It includes three three-core 230-kV HVAC export cables running 7.7 miles in New York state waters; a cable landfall in Long Beach; three single-core export cables running 1.5 miles to a new onshore substation in Island Park; and up to three 345-kV HVAC cables running 1.7 miles from the substation to the point of interconnection — the existing substation at National Grid’s gas-fired E.F. Barrett Generation Station.

The cables would be underwater or underground except for a “cable bridge” crossing a narrow channel of water north of Island Park.

More than 100 people signed in for the virtual presentation. When it was done, several began firing off questions, not about suction hopper dredges or voltages, but about why this was being done to their community, and how bad the effects would be.

One question the residents didn’t ask: What role would the offshore wind turbines play in slowing climate change, which scientific consensus holds is an existential threat to their sea-level community of 35,000 people.

Most written comments submitted so far also have been against the proposal; only one caller Thursday offered support for the project.

Nevertheless, the developer is taking criticism in stride.

“Our projects benefit from input from members of the community in which we work,” Equinor Renewables US spokesperson Lauren Shane told NetZero Insider via email. “We continue to seek, and to receive, feedback from the community in these information sessions as part of our ongoing dialogue with all stakeholders as we progress Empire Wind, a project that will provide renewable energy to over one million New York homes.”

Few Answers

Because of the compartmentalization of the state and federal review processes, some of the questions Thursday did not pertain to the narrow scope of the DPS docket and DPS staff could not answer them. Other questions simply don’t have answers at this point in the process.

The first caller launched into a soliloquy sprinkled with a few questions, including a pointed: “What did we do to deserve this?” Another caller noted that other projects by the same developers — Beacon Wind and Empire Wind 1 — are making landfall at industrial sites in Astoria and Brooklyn and wondered why Empire Wind 2 had to run through dense residential neighborhoods.

That question — why here? — came up several more times and was never really answered.

The closest thing to an explanation came from an Equinor representative who said, without elaboration, that a variety of factors were considered as the project was designed. (In a report posted on the project website, however, the developers did outline the alternatives they considered, citing among other criteria the proximity to the preferred point of interconnection; “sediment dynamics (e.g., erosion)”; wildlife habitats, and “constructability complexities (e.g., long additional water crossings.”)

A summary of other questions and the responses from DPS and Equinor:

What impacts will such a large transmission line have on quality of life, property values and public health? Electromagnetic field modeling shows this project would be well below state standards.

What impact will this have on people who fish for a living or for subsistence? That will be part of the environmental review.

Will the wire run on the north or south side of east Broadway? It’s a corridor at this point in the process; we don’t know yet.

I want to know how close these electromagnetic situations are going to be to my kids … this is nonstop, 24 hours a day, gazillions of volts of electricity. At the moment it’s a corridor; that information will be in the application material.

I don’t mean to be rude but I’m not going through 6,000 pages. I’d like a simple answer: Is it going to be 100 feet from my babies or 50 feet?  At this time that level of information is not available.

I don’t want to be the next Camp Lejeune. Why are you running it through our residential area? I believe the applicant answered before.

The city has been mismanaging our money for decades. Can community benefits payments from the developer go directly to residents rather than the city? That’s beyond the scope of this review.

Will running the HVAC power cables a few feet below the electrified Long Island Rail Road tracks create a derailment risk? The railroad will conduct a rigorous safety review.

What happens if the cables catch fire or explode? Has that risk been evaluated? The project will adhere to all national safety and other standards for cables.

If there is an earthquake or natural disaster, do these things have the potential for blowing up our island? I’m neither a seismologist nor someone versed in that type of disaster. However, we’ll be submitting a detailed fire and safety protocol — later in the process.

This hearing is about the cables, but you can’t answer if a cable goes on fire, if it’s going to blow up and how big of an area that will damage. We don’t have an electrical engineer with us on the line, but I believe that the risk of an underground cable exploding is relatively low.

The information session wrapped at the two-hour mark. Two public comment sessions are planned via WebEx on March 9.

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New York Power Authority Sees ‘Additive’ Role in Decarbonization

Justin Driscoll, acting CEO of the New York Power Authority (NYPA), met with the New York Senate Energy and Telecommunications Committee last week to discuss how the authority’s duties have evolved and the role of new technologies in decarbonization.

Driscoll told the Feb. 28 live-streamed session about NYPA’s growing “statewide footprint” and how NYPA is the “backbone of the [state’s] grid,” operating 16 electricity facilities, including three hydroelectric and several gas-fired generators, as well as more than 1,400 circuit-miles of transmission.

NYPA also is partnering on the Smart Path Connect, a project to rebuild and strengthen about 100 miles of transmission in the North Country and the Mohawk Valley, and the Propel NY Energy project to improve the grid on Long Island, New York City and Westchester County. Other NYPA initiatives are directed at improving transmission cybersecurity and reducing consumer costs, such as ReCharge NY, Driscoll said.

Sen. Mario R. Mattera (R) questioned NYPA’s investments in battery charging stations, asking “why ratepayers should pay for an investment that is already being made by the private sector.”

Driscoll responded that “we need to use all the tools in our toolbox.”

“Given the enormity of what we’re looking to achieve, I believe NYPA and government can play an ancillary role in the energy transition,” he said.

Sen. Mark Walczyk (R) asked for Driscoll’s perspective on NYPA’s role in the future.

Driscoll said that NYPA’s role is “additive” to what is currently going on in the private sector.

Sen. John Mannion (D) asked whether NYPA was investigating nuclear energy, particularly small modular reactors (SMR).

Driscoll said New York would not be a national leader in nuclear development but that NYPA has interest in the potential deployment of SMR and is following development of the technology.

Mattera asked whether green hydrogen has a future in the state.

“Hydrogen will certainly play a big role,” Driscoll said. “But the question in the industry is really what is the right role.

“It is too early to say whether hydrogen will play a role in the power sector,” Driscoll said, adding there are “big use cases in the heavy industry sector, particularly cement manufacturing or public transportation.”

The discussion on hydrogen follows previous Senate hearings at which senators expressed an openness to innovative technologies.

Sen. Kevin S. Parker (D), chair of the committee, said New Yorkers “are struggling with high cost of heating their homes, lighting their homes, and we need to find ways to address that.”

Parker told Mattera that he supports emerging technologies, such as hydrogen, and that he “doesn’t think we are in different places,” but it is simply a “question of how we get from point A to point B.”

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Megawatt-scale Demonstration Project Yields First Pink Hydrogen

A central New York nuclear power plant is the first in the nation to generate its own hydrogen, Constellation Energy Group (NASDAQ:CEG) and the U.S. Department of Energy announced Tuesday.

The agency and company shared costs on the project at the Nine Mile Point Nuclear Plant, which is one of four DOE hydrogen demonstration projects underway at reactors.

The hydrogen generation system went online in February, several months after its projected late-2022 startup. It produces 560 kilograms of hydrogen per day with an hourly 1.25-MW draw on the 1,907-MW output of Nine Mile’s two reactors.

Hydrogen is used on site for cooling, and previously was trucked in, but Constellation said the output of the new system exceeds the needs at Nine Mile.

Nine Mile is simultaneously working with the New York State Energy Research and Development Authority on a demonstration project that will use hydrogen fuel cell technology to provide long-duration energy storage and is targeted to be operational in 2025.

Hydrogen, which burns without producing greenhouse gas emissions, is potentially a key tool in fighting climate change. It could serve as a form of energy storage and is viewed as an alternate power source for industries and applications that otherwise would be hard to decarbonize.

But the cost of production currently is a barrier to wider use. DOE made reducing that cost by 80%, to $1/kilogram, the central goal of the first of its Energy Earthshots in 2021.

Interest is keen in green hydrogen — derived from renewable energy sources — because generating greenhouse emissions to generate hydrogen limits the net benefit.

So-called pink hydrogen is produced with emissions-free nuclear power and, in some processes, with the excess heat generated by nuclear fission.

Reactors at Nine Mile, Davis-Besse in Ohio and Palo Verde in Arizona are testing low-temperature electrolysis systems. The fourth demonstration project, at Prairie Island Nuclear Generating Plant in Minnesota, is testing a high-temperature electrolysis process that is regarded as more efficient.

DOE provided a $5.8 million grant to the Nine Mile project, which uses a proton exchange membrane made by Nel Hydrogen.

Constellation said the demonstration project could pave the way for large-scale deployments at its other clean-energy facilities.

Constellation has told investors it plans $900 million in capital investments to develop commercial hydrogen production, which it hopes to begin in 2026. It projects a 250-MW hydrogen facility could produce about 33,450 metric tons of hydrogen, more than 90% of which it expects to sell via long-term off-take agreements.

“Hydrogen will be an indispensable tool in solving the climate crisis, and Nine Mile Point is going to show the world that nuclear power is the most efficient and cost-effective way to make it from a carbon-free resource,” Constellation CEO Joe Dominguez said in a news release. “In partnership with DOE and others, we see this technology creating a pathway to decarbonizing industries that remain heavily reliant on fossil fuels, while creating clean-energy jobs and strengthening domestic energy security.”

“This accomplishment tangibly demonstrates that our nation’s existing reactor fleet can produce clean hydrogen today,” Kathryn Huff, assistant DOE secretary for nuclear energy, said in a news release. “DOE is proud to support cost-shared projects like this to deliver affordable clean hydrogen. The investments we’re starting to make now through the Bipartisan Infrastructure Law and Inflation Reduction Act will even further expand the hydrogen market to create new economic and environmental benefits for nuclear energy.”

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CIP Standards Dominated ERO 2022 Enforcement Activities

Last year saw “significant progress” for the ERO Enterprise’s Compliance Monitoring and Enforcement Program (CMEP) and Organization Registration and Certification Program (ORCP), NERC said in the programs’ Annual Report released last month.

The annual reports, released each February, are intended to help NERC and the regional entities track their progress “aligning CMEP and ORCP activities across the ERO Enterprise,” along with identifying trends in resolving violations of NERC’s reliability standards. Starting this year, NERC plans to supplement the annual report with a mid-year report released in August.

According to the report, REs processed 383 instances of noncompliance assessed at either moderate or serious risk last year. This represents a five-year record, although it totals only six more violations than were filed the previous year.

While total noncompliances rose slightly in 2022, the number of repeat violations reported fell. Repeat noncompliance in the report was divided into incidents involving compliance history — referring to “a relevant prior violation of the same or similar reliability standard and requirement” — and aggravation history, defined as “a prior violation that stemmed from similar actions or conduct.”

Noncompliance Standards (NERC) Content.jpgThe 10 standards that accounted for the highest number of noncompliances assessed as moderate or serious risk in 2022. | NERC

Cases with compliance history fell to 198 last year, from 216 in 2021, while the number of cases with aggravation history dropped more both proportionately and in absolute terms, declining from 83 to 54. NERC pointed out that aggravation history averaged around 19% of all moderate and serious noncompliance cases over the last five years.

NERC’s Critical Infrastructure Protection (CIP) standards accounted for seven of the top 10 most violated standards in 2022, just as they did in 2020 and 2021, according to last year’s report. CIP-007-6 (Cybersecurity — systems security management) garnered the most violations with 108, nearly twice as many as the next most cited standard, CIP-010-4 (Cybersecurity — configuration change management and vulnerability assessments). CIP-004-6 (Cybersecurity — personnel and training) came next, with 37 infringements; the same three standards, in the same order, represented the most violations in 2020 and 2021 as well.

The ERO noted that it achieved “substantial reductions” in the volume of unprocessed noncompliance issues last year, having processed “nearly 70% of its open noncompliance from 2019 and earlier and nearly 50% of its noncompliance from 2021 and earlier.” At the end of 2022, out of NERC’s 2,903 open cases, 1,608 — about 55% — were submitted in 2022; the oldest open cases were from 2017, but this represented only three of the total.

Nine in 10 noncompliance issues reported in 2022 were discovered internally, more than at any time in the last five years. The remaining 10% were found either through compliance audits or spot-checks.

Along with enforcement figures, the ERO also included other highlights from last year such as the ongoing implementation of the Align software tool for processing audits, investigations, and other compliance activities, and the ERO Secure Evidence Locker.

Release 4 of Align deployed in the second quarter of the year, with release 4.1 and 4.5 following in the third and fourth quarters respectively. The January issue of NERC’s Align newsletter said release 4.5 is “the final release planned under the current business case,” though the software will continue to be updated under a governance model adopted last year.

The report also listed the CMEP and ORCP priorities for 2023. These include continuing to deliver enhancements to Align, focusing on efficient resolution of noncompliance, tracking completion of registered entities’ compliance oversight plans, and pursuing consistency efforts on penalties, mitigation, training exercises, documentation, and risk assessments.

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Lordstown Motors Production Line Down at Least Until April

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

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

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

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

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

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

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

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

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

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

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

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