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November 16, 2024

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Washington’s 1st Cap-and-Trade Auction Nets Nearly $300M

Washington’s first cap-and-trade auction pulled in nearly $300 million in revenue, according to a summary report issued by the state’s Department of Ecology Tuesday.

All 6,185,222 allowances offered in the Feb. 28 auction were sold, clearing at a settlement price of $48.50. That was well above the floor price of $22.20 and “in the range” of an independent analysis commissioned last summer, the agency said in a statement after results were released.  Each allowance entitles a holder to emit one ton of greenhouse gases.

The auction summary showed that 56 companies, utilities and public institutions bid into the auction, but it did not indicate which bidders were successful. 

The Ecology Department is required to provide a final revenue report by March 28.

“This is truly historic for Washington and for the global movement toward a low-carbon future,” Gov. Jay Inslee said in the statement. “This cap-and-invest system is crucial to our approach to addressing climate change, and we are very encouraged to see this program starting off so well.”

“With the cap-and-invest program now fully underway, we can begin providing critical support for reducing emissions in our state and helping communities deal with and prepare for the effects of climate change,” said Ecology Director Laura Watson. 

Washington’s Democrat-controlled legislature in 2021 passed the law establishing the nation’s second cap-and-trade program — behind California — along party lines. Last year state agencies hammered out regulations to put that law into effect. 

The Feb. 28 auction was the first of four quarterly auctions to be held this year by the Ecology Department. 

In January, Washington officials told the state Senate Transportation Committee that the cap-and-trade auctions could raise almost $1.5 billion through fiscal 2024 and reiterated their view that a new low-carbon fuel standard will raise gas taxes by about one penny per gallon. (See Washington Estimates $1.5B in Cap-and-Trade Revenue Through 2024.) 

Later this legislative session, the state Senate and House plan to allocate revenue from the first cap-and-trade auction. The Ecology Department estimates $484 million in cap-and-trade revenue will be raised in fiscal year 2023 (July 1, 2023 to June 30, 2024) and $957 million in FY 2024.

The revenue from the auctions is expected to shrink over time as the number of emission allowances is reduced. Estimates are considered less reliable as they are projected farther into the future. The agency currently estimates $901 million in revenue for FY 2025, $730 million in FY 2026 and $592 million in FY 2027.

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MISO Reports Loss of Control Room Capabilities

MISO said it experienced a “complete loss of monitoring or control capability” at its control center last week, setting off short-lived energy imbalances.

According to the grid operator, the March 1 incident lasted about 41 minutes. It said it was administering routine quarterly maintenance on its energy management system (EMS) at midnight to update modeling. However, “issues with the update” sent incorrect dispatch signals to generation through the RTO’s automatic generation control tool.

MISO said the glitch led to an imbalance in its balancing authority and a Balancing Authority ACE Limit (BAAL) event. It said its area control error (ACE) reached as high as 2,000 MW, resulting in a 17-minute BAAL event.

The ACE then swung as low as -4,285 MW, resulting in a second BAAL event for 11 minutes, MISO said. It said it used “backup tools and processes” to regain the control room’s monitoring and control capability.

The grid operator said it reported the disturbance to the Department of Energy through the agency’s electric emergency incident and disturbance report (form DOE-417), which is used to collect information on incidents and emergencies. 

MISO said its backup plan included reverting temporarily to its earlier December model. It said the model worked as intended.

“We were able to address the incident in less than 15 minutes and move to our new model within a couple of hours, spokesperson Brandon Morris said in an emailed statement to RTO Insider. “We are reviewing the situation and will improve the processes under our new model manager and EMS systems.”

MISO is working to deploy a new EMS and a one-stop model manager that will serve as a single record for maintaining members’ modeling information. The RTO said it experiences redundant data entry and review because it lacks a unified modeling process for reliability, markets and planning. (See MISO Pivots to Models, Market Engines in New Platform Replacement.)

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DERs in Wholesale Markets Still Years Away

FERC has been working through compliance filings on Order 2222, but none of the ISOs or RTOs have yet to have aggregations of distributed energy resources actually participate in their markets.

The commission defines DERs as any resource located on the distribution system or behind a customer meter, or any subsystem thereof, said David Kathan, a former FERC staffer who worked on the issue and now runs his own consulting firm. Speaking on a webinar hosted Wednesday by the United States Energy Association, Kathan listed rooftop solar, community solar, electric vehicles, cogeneration facilities, distributed storage, demand response and others as potential DERs.

Load management and solar were the dominant DERs from 2015 to 2020, and they are expected to continue growing at a healthy clip but will be joined by additional resources ramping up deployments this decade such as EVs and storage, Kathan said.

Hawaii is ahead of most states on renewable deployments with a goal of getting to 100% renewables by 2045, and DERs will play a key role there, he said.

“I know Hawaii is not exactly, you know, the normal state in the United States; it’s islands,” Kathan said. “It has a different set of resources and challenges. And they like to call themselves a postcard for the future.”

Across the entire state, DERs could make up 15% of electricity by 2045, but they could be as high as 23% on the island of Maui. It is important for grid operators to have visibility into those resources, but that requires changes to how they have operated in the past.

“Many DERs, especially behind-the-meter resources, are too small to participate in wholesale markets,” Kathan said. “Most RTOs and ISOs have set a minimum offer size requirement of at least 100 kW.”

Individual DERs often do not have the capability, nor the interest, to participate in the markets, but they are happy to have aggregators do much of the work so they can get paid, he added.

“At present, no DER aggregations participate in wholesale markets … and will mostly have to wait until implementation of 2222 by the RTOs and ISOs,” Kathan said. “Most plan for effective dates for their participation between 2024 and 2026.”

MISO has proposed an implementation date of 2030, but that is still pending FERC approval. CAISO enacted its DER aggregation rules back in 2016, and many of the elements it set up then informed Order 2222. But even there, no DERs have participated in the wholesale markets yet.

“It is not necessarily a problem with the rules, and more having to do with issues that are still not resolved at the state level,” said Kathan. “And in particular, whether various resources, like DERs and demand response, are able to see resource adequacy credits has been a major issue on why there has not been as much participation.”

Getting the rollout of DERs and how they work on the grid right is going to be important when it comes to decarbonization efforts, said Omar José Guerra Fernández, of the National Renewable Energy Laboratory.

Much of the discussion has been on how to decarbonize the power sector, “but then we also need to decarbonize the industrial transportation and building sectors,” said Guerra Fernández. “And, in my opinion, this is the place where the DER group will play a significant role.”

DERs will help ensure that cars are charged up when the grid is producing clean power, providing a key cross-sectoral role in decarbonization, he added. It will also help decarbonize the building sector in ways that central station renewables are not capable of by adding distributed generation, heat pumps and other technologies that can ensure buildings do not produce greenhouse gases.

“DERs are a variety of technology that will allow us to do this cross-sectoral integration of the energy systems to help achieve net zero by 2050, or maybe before,” Guerra Fernández said.

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North Carolina Regulators Face Questions on Holiday Outages

North Carolina lawmakers on Tuesday peppered state utility regulators with questions about widespread outages stemming from a winter storm over the December holidays.  

Duke Energy had to resort to rotating outages for the first time in its history on Dec. 24 to avoid even worse impacts as Winter Storm Elliott brought historic cold weather and extremely high demand, impacting about 500,000 — or 15% — of the utility’s customers.

The North Carolina Utilities Commission has been looking into the outages, but its investigation is still ongoing, Chair Charlotte Mitchell said during a hearing the state House of Representatives’ Energy and Public Utilities Committee.

The cold weather had been expected and utilities were planning to meet associated demand, but “the temperature dropped more rapidly than the weather forecasts were anticipating,” causing “problems for the utilities,” Mitchell said.

The rapid drop in temperature meant that the utilities’ load forecasts were off by 10% and that unexpected demand contributed to the outages.

“There had been no history of a temperature drop like the one that was experienced during that period of time,” Mitchell said. “So, the model was off, and to the extent that the model is the predicate for … the planning of generation resources to meet load there, there was sort of a problem.”

On top of that, the extreme cold impacted generation. Despite the NCUC’s focus on winterization for more than a decade, some units were knocked offline during the extreme cold.

Rep. Larry Strickland (R) asked whether regional markets, such as PJM, performed any better during the cold snap over the holidays.

“It’s tough to say whether it fared better,” NCUC Public Staff Executive Director Christopher Ayers said. “I can tell you PJM came very, very close to rolling blackouts. But they, to my understanding, did not experience rolling blackouts.”

Dominion Energy’s territory in northeastern North Carolina requires Ayers, the state’s consumer advocate, to follow PJM; he noted the RTO lost up to 23% of its generation and is in the process of “fining” generators who did not perform under its capacity performance mechanism.

“Is it possible that integrating the grid more closely with surrounding states could help prevent blackouts in North Carolina?” Strickland asked. “Shouldn’t we study this further to find out?”

Generally, the more integrated a state is in regional markets, the more resources it can call on and access it has to a greater diversity of supply, Ayers said.

“If they don’t have power to send you, then there’s no power to be received,” he added. “So, you know, there’s no easy answer to that, at least from what we have seen in the data that we have looked at.”

PJM was unable to bail out Duke’s utilities in the Carolinas during the cold snap because it was facing the same weather and also ran into supply issues, though it avoided rolling blackouts, Mitchell said.

The cold weather led to inaccuracies in the demand forecasts of other grid operators, including PJM, and while that experience will now be included the historical data feeding future forecasts, Mitchell said factoring in extreme weather is an important issue going forward.

“We are concerned about the divergence and the strain that it causes the system operators when all of this load shows up that they were not anticipating,” Mitchell said. “So, it’s an issue that we — sort of the greater universe of electric utilities, natural gas utilities and regulators — have to study.”

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Emissions Bill Stalls in New Mexico Senate

A net zero bill unveiled by New Mexico lawmakers last week has stumbled, failing to advance out of a Senate committee on Tuesday.

Senate Bill 520, sponsored by Sen. Mimi Stewart (D), calls for the state’s direct greenhouse gas emissions to be reduced to 90% below 2005 levels by 2050. Interim GHG reduction targets in the bill are 50% by 2030 and 75% by 2040.

An earlier version of the bill included a requirement to offset remaining GHG emissions in 2050 and beyond. The bill’s authors decided to leave offsets, and a system for managing them, as a topic for future legislation.

But SB 520 may now be dead after the Senate Conservation Committee failed to advance it. A motion to pass the bill failed on a 4-4 vote. One committee member was absent.

The committee potentially could revive the bill by bringing it back for another vote. New Mexico’s 60-day legislative session ends at noon on March 18.

The committee’s three Republican members voted against the bill and were joined by Sen. Joseph Cervantes (D).

Cervantes criticized the bill for its lack of consequences for not meeting the GHG reduction targets.

“There’s no accountability in here at all,” he said.

“If we really want to do things, let’s do things,” Cervantes said. “Let’s give meaningful standards, and let’s give consequences, and let’s give clear direction.”

Stewart, the bill sponsor, said that even though the bill didn’t have “huge accountability,” it was an important step. SB 520 would codify GHG reduction targets outlined in a 2019 executive order from Gov. Michelle Lujan Grisham. The bill “sets an essential framework for our continued climate action,” Stewart said.

“It tells agencies, and the industries, and the communities about the clarity and the consistency that we’re going to need to plan long-term to meet these goals,” she said.

Sen. David Gallegos (R) expressed concern that the bill’s requirements would cause businesses to leave the state. That could be an issue, especially along the state’s eastern border with Texas, he said.

“If they move to Texas, I don’t think we resolve emissions issues,” Gallegos said.

Clean Future Act

Stewart filed SB 520 on Feb. 16, the last day for introducing legislation The initial version of the bill was essentially a blank placeholder. Net zero language was added in a Senate Conservation Committee substitute version posted last week.

SB 520 is similar to House Bill 6, a net zero-bill that stalled during the 2022 legislative session. (See NM Climate Activists Vow to Try Again on Net Zero Bill.) Both bills are known as the Clean Future Act.

Stewart said various groups had been working with the governor’s office on the bill for nearly the last year. But the efforts broke off due to disagreement among groups. As a result, SB 520 is less comprehensive than it could have been, she said.

In addition to the GHG reduction targets, SB 520 would codify the methane waste rule recently promulgated by the state’s Oil Conservation Division. It would instruct state agencies to apply climate equity principles when developing policies and rules.

There would also be requirements for state agencies to report on GHG emissions from sectors under their control and progress made toward meeting reduction targets.

‘A Real Problem’

Representatives of several conservation groups, including Conservation Voters of New Mexico and Western Resource Advocates, spoke in support of SB 520 during Tuesday’s hearing.

Representatives of groups including the New Mexico Farm and Livestock Bureau, the Independent Petroleum Association of New Mexico and the New Mexico Chamber of Commerce spoke in opposition.

Camilla Feibelman, director of the Sierra Club: Rio Grande Chapter, said after the committee hearing that the vote was a disappointment.

The bill “would have been a strong step forward” and would have laid the groundwork for the New Mexico Environment Department to begin rulemaking to help address climate change, Feibelman told NetZero Insider.

Residents are still recovering from the state’s recent fires and floods, which are a clear illustration of climate change, Feibelman said.

“Failure to move a comprehensive climate bill forward is a real problem,” she said.

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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.