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November 5, 2024

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PJM: Grid Performed Well During January Winter Storm

PJM last week said the grid maintained reliability through nearly a week of harsh winter conditions during the winter storm that blanketed much of the nation during mid-January. 

Dave Souder, PJM executive director of system operations, told the Jan. 24 meeting of the Markets and Reliability Committee that the grid was at its most strained Jan. 17, which saw a peak load of 134,777 MW and some emergency procedures implemented to mitigate transmission constraints. Cold weather alerts were in place from Jan. 14-17 and Jan. 19-22. 

Comparisons to December 2022’s Winter Storm Elliott dominated the discussion, with PJM making the case that several market and operational improvements bolstered performance. Souder said the RTO drew on its experience with generation performance during cold weather to take more action before the storm arrived. Dispatchers manually committed thousands of additional megawatts through the day-ahead market to give long-lead units time to come online and combustion turbines that have had trouble procuring gas in the past additional notice to firm up their fuel. 

Conservative operations were in place between Jan. 13 and 17 to provide dispatchers with greater flexibility to keep long-lead resources online when they’d otherwise be released on economics. 

“We took a risk-based unit commitment approach,” Souder said. 

PJM’s Brian Chmielewski said transmission congestion also peaked on Jan. 17, with 19 constraints reaching the $2,000/MWh transmission constraint penalty factor (TCPF). Heavy load interchange and congestion drove system marginal prices to the $500/MWh range Jan. 17 and 18. 

Vitol Vice President of Regulatory Affairs Jason Barker questioned if price spikes on the mornings of Jan. 16, 17 and 18 were driven by PJM load or exports to neighboring regions, saying that the timing appears to align with the MISO morning peak. PJM representatives were unable to confirm the observation, but agreed to examine event data.

Souder said additional information will be presented at next month’s Market Implementation and Operating committee meetings, scheduled for Feb. 7 and 8, respectively. 

The rate of generation outages was around a third of the peak during Elliott at 16,119 MW offline Jan. 16 versus 46,124 MW on forced outage Dec. 24, 2022. Souder said the gas fleet’s performance in particular was much stronger this month; though pipeline capacity restrictions were in place throughout the storm, there were few compressor station or gas well failures, and pipeline operators coordinated with PJM to improve forecasting. 

Generators that did experience disruptions impacting their output also made use of PJM’s newly implemented temporary exception process to report their diminished output. One of the challenges PJM highlighted following Elliott was a significant number of generators not reporting issues to the RTO until dispatchers attempted to bring them online. 

Independent Market Monitor Joe Bowring told RTO Insider that PJM took a “very conservative” approach to the storm and relied on a forecast that turned out to be much more accurate than that for Elliott. While he applauded the performance of PJM operators in keeping the grid online through their actions, he said that a stronger market design would commit generators based on economics. 

“The operators made the system work, and we’re happy they did, but when we think of the bigger picture, markets were not relied on,” he said. 

He argued that the need to manually commit resources during the storm highlighted the need for ongoing stakeholder discussions over the reserve market design to focus on how to include market parameters that reflect a need for short-term reserves. He contrasted the need for reserves that can operate through a storm lasting a few days to the decision to increase the synchronized reserve requirement by 30% last May. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.) 

“You don’t need more reserves year-round; you needed them for a couple days last week,” he said. 

Several stakeholders questioned the cost of $28 million in uplift payments to generators committed under conservative operations, arguing that costs should be built into the market, while others said the current market structure provides dispatchers with flexibility to commit units as they may be needed in real time. 

Gregory Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said that both uplift payments and exports during strained conditions are worrying, but in this instance PJM’s actions appear to be warranted because of the concern that generators wouldn’t be able to perform during a holiday weekend winter storm — the same scenario PJM found itself in during Elliott. In this case, the holiday was Martin Luther King Jr. Day, instead of Christmas in 2022. 

The storm brought a new record-high peak load of 34,524 MW in the Tennessee Valley Authority region Jan. 17, and other PJM neighbors also saw high loads, leading the RTO to export 12,131 MW, the equivalent of nearly 10% of its own load. 

Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), questioned whether the large amount of exports signal that other regions are leaning on the RTO for reliability at the same time that it has been recommending reducing projected reliability benefit of imports reflected in the capacity benefit of ties (CBOT) value. The package of market changes PJM proposed in the Critical Issue Fast Path process last year would have set the CBOT to zero, but the Board of Managers did not include that component in its proposal now pending before FERC. (See PJM Board Releases Outline of Capacity Market Changes.) 

Noting that the drop in temperatures was most severe in the ComEd zone, AEP Energy Director of RTO Operations Brock Ondayko said more detailed analysis on generation outages by zone could provide more information about any incremental improvements made in generator performance in subzero temperatures. 

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New York PSC Seeks Rehearing of RTO Adder for Offshore Tx Project

The New York Public Service Commission on Jan. 25 requested a rehearing of FERC’s December order granting a 50-basis-point RTO participation adder for the Propel NY Energy transmission project (ER24-232).

Propel — a $2.7 billion, 345-kV joint venture between New York Transco and the New York Power Authority — was selected from NYISO’s public policy transmission needs (PPTN) assessment to deliver at least 3,000 MW from offshore wind farms near the Long Island coast.

NY Transco petitioned FERC for transmission incentives, including a cost-containment mechanism, a base return on equity of 10.7% with a 150-basis-point risk adder, 100% coverage for abandoned plant and construction work in progress, and a 50-basis-point RTO participation adder. The commission approved these requests, but it reduced the risk incentive to 75 basis points and suspended the proposed base ROE pending hearing and settlement judge procedures. (See FERC Approves Incentives for NY OSW Transmission.)

However, the PSC said in its protest that the RTO adder is “neither necessary nor warranted” and “harms New York consumers” who will be “required to overpay to encourage a voluntary conduct on the part of the developer where the conduct sought to be incentivized is already required.”

FERC granted the adder with the condition that the developer continue its “membership in NYISO and transfer … operational control of the project to NYISO once it has been placed in service.”

But the PSC argued that the adder, typically used to incentivize voluntary participation, is redundant for Propel NY, as NY Transco’s involvement with NYISO is a regulatory requirement, not a discretionary choice. The adder “gives the developer an unjustified windfall while unnecessarily increasing costs to New Yorkers,” it said.

To support its position, the PSC cited FERC’s ruling last month that Pacific Gas and Electric was not eligible for an RTO adder in CAISO (ER24-96). (See Citing California Law, FERC Rejects PG&E Request for RTO Adder.) It said the two cases “are analogous.”

The PSC, along with New York City and Multiple Intervenors, had opposed NY Transco’s requested ROE and incentives. They complained that the 10.7% ROE was inflated and argued that NY Transco failed to demonstrate any special project risks.

The first settlement conference over the ROE is scheduled for Jan. 31.

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Virginia State Corporation Commission Finally Gets All Seats Filled

The Virginia State Corporation Commission (SCC) has a full complement of commissioners after the Virginia General Assembly approved two new members last week.

The legislature picked Kelsey Bagot, a former staffer of FERC Commissioner Mark Christie who was working at NextEra Energy, and Sam Towell, who is associate general counsel for Smithfield Foods and previously worked for the state attorney general.

“Kelsey is an excellent choice by the Virginia General Assembly for the State Corporation Commission,” Christie said in an interview Jan. 26. “As a former commissioner on the State Corporation Commission, I know that Kelsey brings exactly the qualities and the dedication to serving the public that the Virginia Commission needs and that the people of Virginia deserve.”

The two new members join Jehmal Hudson, who has been the only member of the state regulator since former Chair Judith Jagdmann stepped down in 2022.

The issues with staffing the SCC go back to when Jimmy Dimitri stepped down in 2018 and the legislature failed to find a long-term replacement for him. Dimitri has, however, been able to come back and help move needed business with Hudson in recent months because the body requires two votes for a quorum. The general assembly, which has seen its chambers flip between Republicans and Democrats multiple times in recent years, likewise had been unable to find a long-term replacement for Christie, who served on the SCC for nearly 17 years before joining FERC in 2020.

“I’m very, very happy that finally, after three years, all three seats are filled with permanent appointments, permanent elections, and they’re all three quality people,” Christie said. “The State Corporation Commission of Virginia is the most important state agency in Virginia that most people have never heard of.”

The SCC oversees energy, as well as large swaths of the state economy, including all insurance (it helps set up the state marketplace for health insurance under Obamacare), banking, securities, retail franchises and railroads. It also is the state’s central filing office for corporations, limited partnerships and LLCs.

“I think it’s the outstanding regulatory agency in America at the state level, based on the history and based on the broad jurisdiction,” Christie said.

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CAISO Considers Replacement of RA Incentive Program

CAISO staff and stakeholders are looking to re-evaluate the ISO’s Resource Adequacy Availability Incentive Mechanism (RAAIM) and explore whether it should be replaced with a new program relying on an unforced capacity (UCAP) construct to ensure sufficient RA capacity.  

Moderating a Jan. 16 meeting of the ISO’s Resource Adequacy Design and Modeling Working Group, Jeff McDonald, vice president at Concentric Energy Advisors, said the potential ineffectiveness of RAAIM was a prominent topic in past RA meetings of the group and in submitted comments.  

A UCAP construct, which seeks to procure the most reliable resources by factoring their historical lack of availability into their capacity value, has been offered as an alternative to RAAIM, although stakeholders questioned if the two programs were similar enough to replace one another or if they could operate in tandem.  

“My view is that these two issues can be conceptually separated,” said Alva Svoboda, principal of market design integration at Pacific Gas and Electric. “RAAIM is an issue of how one deals with failures operationally to deliver what has been promised and UCAP can be considered simply as an improved approach to calculating what resources should be eligible to contribute in the RA plan.”  

Implemented in 2016, RAAIM is a bid-based mechanism designed to incentivize resources providing RA capacity to meet their must-offer obligations (MOO) and provide substitute capacity should they go on forced outage. Resources are penalized for not meeting their MOO and rewarded when they do.  

Stakeholders raised concerns about RAAIM shortly after its implementation. In January 2018, CAISO submitted a tariff amendment to FERC requesting modification of the program after identifying a series of issues and problematic outcomes related to it. The ISO found the methodology overweighted the availability of flexible RA capacity compared with generic RA because it treated each availability assessment hour (AAH) as equal, despite differences in RA types.  

The ISO also found that RAAIM was designed in such a way that resources could be led to designate a minimal flex RA megawatt amount with a maximum hourly amount to minimize penalties, reducing incentives to provide capacity at other times. As a result, staff modified the program to treat each megawatt equally within each AAH and to evaluate generic and flex RA separately, among other modifications.  

While FERC approved the modifications, stakeholders still raised concerns about the effectiveness of RAAIM and whether it could be replaced with UCAP.  

RAAIM, UCAP — or Both?

At the Jan. 16 meeting, Lauren Carr, senior market policy analyst at CalCCA, disagreed with Svoboda that the two programs were conceptually distinct.  

“If we have UCAP in place, it is a replacement for RAAIM, and it wouldn’t make sense to have both,” Carr said. “The purpose of RAAIM is to incent substitution when resources aren’t available to follow their must-offer obligation, and if you’re accounting for forced outages up front through UCAP, it wouldn’t make sense to have substitution rules for forced outages.”  

Doug Boccignone, a principal at Flynn Resource Consultants, added that he thought RAAIM was redundant and feared having both programs could lead to double counting of resource contributions for both awards and penalties.  

“I’m questioning whether you’d need additional incentives beyond the long-term UCAP incentive and the short-term incentive to bid your resources and get compensated for them in the market,” Boccignone said. “If you are taking into account reasonable expectation for the resource … you’ve already taken into account forced outages. And if a unit goes on outage, it would be a double penalty to make them go get replacement capacity for that resource you were [already] counting.”  

Svoboda disagreed, saying that having both programs would not lead to double counting because they operate under different time frames and decision processes.  

“The risk of double payment or over-penalizing is better addressed by getting the prices right and requirements right than by throwing the sticks on the table and trying to redesign from scratch,” he said.  

But meeting participants largely agreed that the ISO should reevaluate RAAIM before deciding about UCAP.  

“I think the re-evaluation of RAAIM is one of those low-hanging fruits that will be easy for the ISO to potentially change some of the layouts of the RA construct and the incentivization to show resources,” Nick Burki, senior integrated resource planner with City of Anaheim Public Utilities, said.  

The RA Working Group’s next meeting is set for Feb. 13.  

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Ørsted Cancels Skipjack Wind Agreement with Maryland

Ørsted has canceled its Skipjack Wind agreement with Maryland but will continue preparations to build the 966-MW offshore wind farm in hopes of securing a better deal. 

In its announcement Jan. 25, the company cited the same factors that have caused so much pain for the U.S. offshore sector since late 2022: inflation, interest rates and supply chain constraints. 

Ørsted said the offshore renewable energy credit (OREC) price that it previously negotiated with Maryland is too low now to be commercially viable.  

Even as a global leader in the offshore wind industry, the Danish firm has been hit hard by the sector’s growing pains in the United States, reporting billions of dollars in cost impairments on project delays and cost escalation. 

Other developers have canceled OREC contracts and power purchase agreements along the Northeast U.S. coast in the past year, but none went as far as Ørsted did in October, when it outright canceled the 2.24-GW Ocean Wind 1 and 2 projects off the New Jersey coast. 

But Ørsted is moving forward elsewhere.  

It and Eversource are nearing completion of South Fork Wind and preparing to start construction of Revolution Wind. 

In New York last week, the partners canceled their OREC contract for Sunrise Wind and promptly re-bid the project into the latest solicitation, presumably at significantly higher cost — which essentially is what Ørsted wants to do with Skipjack. 

The company said as it looks for that opportunity it will continue to move Skipjack through the development and permitting process and submit an updated construction and operations plan to the U.S. Bureau of Ocean Energy Management.  

“As we explore the best path forward for Skipjack Wind, we anticipate several opportunities and will evaluate each as it becomes available,” Ørsted Americas CEO David Hardy said in a news release. “We’ll continue to advance Skipjack Wind’s development milestones, including its construction and operations plan.” 

Skipjack would stand off the Delaware coast, but it would feed into the Maryland grid. It has been part of Maryland’s emissions-reduction strategy and would equal 11% of the state’s 8.5-GW 2031 offshore wind target. 

Democratic Gov. Wes Moore’s office summed up the situation in a prepared statement:  

“Governor Moore is disappointed by the news of Ørsted’s repositioning of the Skipjack Wind project, an effort that has the capacity to impact the lives of so many Marylanders. However, he will continue to work with legislators, Maryland’s federal partners, offshore wind developers and advocates that see Maryland’s potential in order to build a system to help Maryland reach the state’s goal of 100% clean energy by 2035.”  

Maryland Public Service Commission Chair Frederick Hoover offered a similar response Friday: “Yesterday’s news from Ørsted is disappointing — the Skipjack project was an important component in advancing Maryland’s clean energy goals. However, the Commission remains optimistic about the future of the offshore wind industry in Maryland, and would note that the US Wind project continues to move through the federal approval process.” 

Maryland awarded ORECs to US Wind for its MarWin and Momentum Wind projects, which total approximately 1,100 MW and are progressing through federal review. (See Draft Environmental Statement Prepared for Maryland OSW.) Additional portions of US Wind’s lease area off the Delaware/Maryland coast are designated for potential future development. 

There are some constraints on offshore wind development near the DelMarVa peninsula, however, due to extensive military and space launch activity in the region. (See BOEM to Auction Wind Energy Areas in Central Atlantic.) 

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Feds Issue Strategy to Protect Right Whale Amid OSW Push

Federal regulators have finalized their strategy to protect a critically endangered whale species as they expedite development of coastal waters for wind energy generation.

The “North Atlantic Right Whale and Offshore Wind Strategy” provides guidance to federal agencies and their partners on how best to promote recovery of the species and other marine life.

The Bureau of Ocean Energy Management and the National Oceanic and Atmospheric Administration’s National Marine Fisheries Service released the strategy Jan. 25.

It follows three main tracks: support tools for mitigation and decision making; research and monitoring; and collaboration, communication and outreach.

Immediate steps include avoiding leasing that may impact whale habitat and issuing guidance to developers on how best to ensure noise does not reach potentially harmful levels.

BOEM and NOAA Fisheries also are directing nearly $100 million of Inflation Reduction Act funds toward conservation of the North Atlantic Right Whale (NARW), which is near extinction. The NARW population is estimated at only 360, with fewer than 70 females of reproductive age.

These efforts seek to untangle a chain of causes and effects: Fossil-fired power generation is blamed for climate change; climate change is blamed for the NARW’s decline; emissions-free offshore wind power is intended to help replace fossil fuel and ease climate change; construction and operation of offshore wind turbines could further harm the NARW.

“Right whales are endangered and climate change is impacting every aspect of their survival — from changing ocean habitat [and] prey availability … [to] migratory patterns — making the transition to cleaner, renewable energy critically important,” NOAA Fisheries Assistant Administrator Janet Coit said in a news release. “Working together on this strategy leverages the best available scientific information to inform offshore wind management decisions while conserving and recovering the species.”

The strategy is a nonbinding advisory document, rather than a directive or rule. It is intended to be updated as more information becomes available.

Save the Whales

Whales have become a center of attention in the offshore wind development debate because an unusual mortality event for the NARW, minke whale and humpback whale along the Atlantic coast has coincided with increasing offshore wind testing and construction activity there.

Officials blame fishing gear entanglement and vessel strikes for most of these whale deaths, but opponents have seized on the timing to blame offshore wind.

A smoking gun for some opponents has been NOAA Fisheries’ use of the word “take” in the Incidental Harassment Authorizations it issues for wind projects.

In that usage, “take” means to harass — to disturb or slightly injure.

But in other contexts — such as NOAA Fisheries’ “Atlantic Large Whale Take Reduction Plan” — the word “take” can mean to seriously injure or kill.

The Marine Mammal Protection Act specifies two types of harassment: Level A has the potential to cause nonserious injury, and Level B has the potential to disrupt behavioral patterns but not directly cause injury.

Serious injury or death of any species listed in a harassment authorization is explicitly not authorized.

But in a lengthy document, that distinction can be missed by those who want to protect whales or ignored by those who want to thwart offshore wind.

This can lead to accusations that a project is officially allowed to kill a specific number of whales.

In one recent example, NOAA Fisheries on Nov. 20 issued a 42-page letter of authorization for incidental take of marine mammals through acoustic disturbance during construction of Revolution Wind off the Rhode Island coast.

This included a Level B take of up to 44 NARWs in any one year and up to 56 NARWs over a five-year period. No Level A take is authorized.

The authorized Level B take is lower for three other whales — 18 sei, seven sperm and three blue whales per year — but much higher for other creatures: 304 minke whales, 2,303 gray seals and 8,084 common dolphins.

Limited Level A harassment is authorized for certain whale species: 21 minke, nine humpback, five sei and four fin.

The letter of authorization also spells out protective measures. Active visual and passive acoustic monitoring for any NARW presence must be maintained during pile driving, for example, and work must be halted immediately if a NARW is detected, unless a shutdown would create imminent risk to human safety or project integrity.

The newly published strategy includes a map indicating that Revolution and several other planned wind farms south of the Massachusetts-Rhode Island coast stand near the densest concentration of NARW activity observed from 2010 to 2019.

Revolution’s harassment authorization reflects this.

By comparison, the NARW is a less frequent visitor to the area off the New Jersey coast where the now-canceled Ocean Wind 1 would have been built.

Ocean Wind 1 would have been up to 50% larger than Revolution Wind.

But NOAA Fisheries authorized a Level B take of only seven NARWs per year for Ocean Wind 1, compared with 44 for Revolution Wind.

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CPUC Fines PG&E $45M for 2021 Dixie Fire

California regulators approved a $45 million penalty against Pacific Gas and Electric on Jan. 25 for the utility’s role in the 2021 Dixie Fire, the second-largest wildfire in state history.

The California Public Utilities Commission voted 3-2 to approve the penalty as part of a settlement negotiated between PG&E and the commission’s Safety and Enforcement Division (SED).

The penalty includes a $2.5 million fine that will be paid to the state’s general fund. PG&E will pay another $2.5 million to tribes whose land was impacted by the fire.

In addition, the utility agreed to spend $40 million to transition to electronic recordkeeping for inspections of overhead and underground distribution equipment. PG&E has agreed to not seek recovery of the $40 million through customer rates.

As part of the settlement, PG&E denied any fault in connection with the Dixie Fire, which was sparked by a tree falling on one of the utility’s distribution lines in the Sierra Nevada foothills.

5-county Blaze

The Dixie Fire started July 13, 2021, when a Douglas fir tree fell onto PG&E distribution lines, a Cal Fire investigation determined. The fire spread across 963,309 acres in five Northern California counties and destroyed about 1,300 structures.

The proposed settlement went to the commission for a vote Nov. 30. But two commissioners — Darcie Houck and Genevieve Shiroma — said they needed more information, and the vote was postponed.

Following the Nov. 30 meeting, SED provided written responses to the commissioners’ questions.

But during the Jan. 25 meeting, Houck and Shiroma said they weren’t satisfied with the answers. They voted against approving the settlement agreement.

Houck questioned whether the relief provided by the settlement was enough given the magnitude of the fire.

“In light of the enormous impact this fire had on the state of California and the five counties impacted, the relief that is being proposed here, based on the information and reports we have today, I still believe is inadequate,” Houck said.

Houck also said she was worried about the impact of the agreement in a future cost-recovery proceeding. Under terms of the agreement, PG&E retains the right to pursue recovery of costs associated with the Dixie Fire.

“There’s still a concern about how the information and the fact that the settlement was there with no admission of fault would be looked at when we’re looking at things like cost recovery,” she said.

Role of Recordkeeping

Several of Houck’s questions during the Nov. 30 meeting were related to the $40 million for electronic inspection records. She asked for more specifics on what information would be digitized and how that would improve safety.

In its written response, SED said digitization “is important for speed and efficiency at the commission and across other agencies responsible for wildfire safety.”

“The continued and accelerated improvement of inspection processes by PG&E pursuant to the [agreement] will support public safety and facilitate commission oversight,” SED wrote.

Commissioner John Reynolds, who voted in favor of the $45 million settlement, emphasized the importance of digitizing records during the Jan. 25 meeting.

“Modernizing records related to the condition of PG&E’s assets may not sound exciting to the public,” he said. “But better information about the condition of electrical assets is vital to improving inspection and preventive maintenance procedures, which are bread-and-butter wildfire safety activities.”

Commissioners also noted that PG&E has taken steps to reduce wildfire risk since the Dixie Fire.

CPUC President Alice Busching Reynolds said the utility now has a system that shuts down distribution lines when it detects a fault, such as one caused by a tree falling on the line.

In a release issued after the vote, the CPUC said it has “taken many actions to hold PG&E accountable for safely serving its customers.”

Those include a $150 million penalty for the 2020 Zogg Fire, a $1 million penalty for the 2019 Easy Fire and a $125 million penalty for the 2019 Kincade Fire.

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Offshore Wind Reset Complete in New York

The churn in New York’s offshore wind industry reached a crescendo Jan. 25, with ownership changes, contract cancellations and new proposals announced. 

The cancellations effectively reset the state’s offshore development pipeline almost to zero, albeit briefly, as thousands of new megawatts are in advanced negotiations, and bids for thousands more were submitted this week. 

The day’s highlight reel went like this: 

    • Ørsted announced plans to buy out Eversource’s 50% stake in Sunrise Wind if the project goes forward. 
    • Equinor and bp announced they are dividing up their joint projects, with Equinor taking full ownership of Empire Wind and bp taking full ownership of Beacon Wind. 
    • Ørsted and Eversource pulled out of their offtake contract with the state for Sunrise and submitted a new bid on an updated version of the proposal. 
    • Equinor and bp, which previously cancelled their Empire Wind 2 contract, also now have canceled Empire Wind 1. They submitted a rebid for Empire 1 but are holding off on Empire 2. 
    • Equinor and bp also reached a deal to cancel the state contract for Beacon Wind 1. They did not indicate what would become of that project, or of Beacon Wind 2, which had not been awarded a contract. In its news release, bp said only that it would independently pursue future U.S. offshore wind opportunities.  
    • Finally, the National Grid Ventures-RWE joint venture Community Offshore Wind — which the state chose in late 2023 for a 1.3-GW offtake contract — announced Jan. 25 it had submitted a proposal for a second 1.3-GW offshore wind farm. 

The afternoon of Jan. 25 was the deadline for proposals in New York’s fourth offshore wind solicitation. Details were not immediately available, except for the limited information from those developers that chose to publicize it. 

Attempting A Rebound

Renewable energy development in New York reached a crisis point in 2023, as long-running review and permitting processes combined with soaring costs to make previously contracted proposals unprofitable and unable to proceed to construction.  

Offshore wind was the most visible example because of the huge sums of money involved, but onshore wind and solar had similar financial pressures. 

New York declined in October to provide more money to those projects, triggering mass cancellations. (See NY Rejects Inflation Adjustment for Renewable Projects.) 

With Sunrise, Empire and Beacon (combined capacity 4,230 MW) now gone, the only offshore project with a New York contract is South Fork Wind, which is nearing completion but will produce a maximum of only 132 MW. 

New York has scrambled to rebound from this potentially disastrous setback to its clean energy goals. (See New York Scrambles to Maintain Momentum in Energy Transition.) 

In late October, it announced provisional contracts for three offshore projects totaling 4 GW and 22 onshore projects totaling 2.4 GW. The three offshore wind proposals — Attentive Energy One, Community Offshore Wind and Excelsior Wind — then went to final contract negotiations. (See NY Announces Renewable Energy Projects Totaling 6.4 GW.) 

The state also announced expedited solicitations for new projects and allowed developers to rebid existing proposals at higher cost if they first canceled their earlier contracts. (See New York Issues Expedited Renewable Energy Solicitations.) 

The deadline for offshore bids was 3 p.m. on Jan. 25. 

The deadline for large-scale onshore bids is 3 p.m. on Jan. 31. Sixty-eight onshore renewable projects totaling more than 5.6 GW were submitted by the prequalification deadline, Dec. 28. Sixty of those were existing projects whose developers canceled their previous contracts. 

Churn Continues

Ørsted and Eversource have suffered amid the offshore wind industry’s growing pains in the United States. Both have recorded billions in impairments, and Eversource has been searching for more than a year for a buyer for its share of the venture. 

Ørsted’s takeover of Sunrise is conditioned on the 924-MW wind farm plan being chosen for an offtake contract and on regulatory approvals. But Sunrise is a rare commodity in a struggling market — a mature project with supplier and labor agreements in place, state approvals in hand and final federal approval anticipated later this year.  

Construction could be completed by 2026 if it is chosen in the solicitation that closed Jan. 25, Ørsted said. 

Ørsted and Eversource also are a known commodity, currently completing South Fork and starting work on Revolution Wind, a Connecticut-Rhode Island project. 

Ørsted Americas CEO David Hardy said: “Following a thorough risk review of our U.S. portfolio, we’re comfortable with taking full ownership of Sunrise Wind if the project is awarded in New York 4. This transaction is a value-accretive opportunity for Ørsted and the best path forward for the project.” 

The price tag of the buyout was not disclosed. 

Eversource would remain contracted to lead onshore construction of Sunrise. 

Meanwhile, Equinor and bp also have had financial problems trying to move forward with offshore development.  

Along with the offshore assets, they are divvying up their onshore efforts: 

Equinor will take over bp’s 50% interest in the lease for the South Brooklyn Marine Terminal, which is planned for development as a hub for offshore wind activity in the New York Bight. 

And bp will take Equinor’s 50% interest in the Astoria Gateway for Renewable Energy site, which will host a converter station where electricity from offshore wind will be connected to the New York grid. 

Their agreements are cash neutral. 

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FERC, NRC Examine State of the Nuclear Industry

FERC and the Nuclear Regulatory Commission convened a joint meeting Jan. 25 to examine issues of common interest, including the rollout of advanced reactors and grid reliability.

FERC Commissioner Mark Christie said nuclear power has two advantages.

“No. 1, it’s carbon free, and that’s great,” Christie said. “No. 2, it runs all the time. Not two weeks, but two months, three months, six months — it runs all the time. So that’s great. So basically, any future where you want to have … reliable power and reduce carbon emissions, it’s got to include nuclear.”

The future of the technology seems to be centered on small modular reactors, he added. The NRC is expecting 25 applications involving SMRs in the next five years, said Andrea Kock, deputy office director for engineering for the agency’s Office of Nuclear Reactor Regulation.

“Those are potential applicants that have come to us and stated that they intend to submit an application, and it spans technologies from things that look a lot like what we currently have, but smaller, to some really advanced designs,” Kock said.

The regulator has resolved more than 35 technical and policy issues and issued more than 60 guidance documents to support those reviews, Kock said. NRC is also using a graded approach that will focus on the most significant safety issues.

“The NRC is doing things differently to yield timely and cost-effective reviews without compromising on safety,” she added.

FERC Commissioner Allison Clements asked about the impact of the recent decision by NuScale Power and Utah Associated Municipal Power Systems to end the development of the SMR-based Carbon Free Power Project in Idaho. (See Pioneering NuScale Small Modular Reactor Canceled.)

Kock said the NRC is still reviewing that reactor design to allow it to be used by another project in the future if it winds up being approved.

SMRs and even smaller “microreactors,” which adapt the technology used to fuel submarines and aircraft carriers to civilian uses, present new issues the NRC has encountered before, Kock said. Such reactors will be built in a central factory and transported to where they are used, presenting novel regulatory issues, she added.

The smaller reactors also bring up questions about how much staff is needed to safely operate them, with many designed to be much more passive than traditional nuclear plants, Kock said.

Another issue is how to keep existing plants running as the country transitions to a greener grid, leading FERC Chair Willie Phillips to ask about California’s quest to keep the Diablo Canyon nuclear plant running and what factors policymakers should consider to keep existing plants online. (See Diablo Canyon Secures $1.1B DOE Award to Support Operations.)

One factor influencing the decision is how much energy a plant is producing, said David Ortiz, director of FERC’s Office of Electric Reliability.

“Nuclear plants are essentially energy resources because they’re on all the time,” Ortiz said.

“The next [factor] is the services that those provide,” he said, noting that the impact on voltage control is the transmission system support function that planners typically assess when a nuclear plant seeks to retire,

It will be important to study more than just voltage in the future because retirements can lead to other system issues, he added.

NRC is expecting to field a significant number of license renewal applications that would extend plant operations to 80 years, in part because of federal support for existing nuclear under the Inflation Reduction Act with the Civil Nuclear Credit Program, Kock said. (See DOE Opens IIJA Nuclear Credit Program to Recently Closed Plants.)

“We’ve received interest in the potential restart of the Palisades plant in Michigan, which is now looking to restart by August of 2025,” she said.

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Reports Detail Causes, Impact of Local Opposition to Renewables

Two new reports quantify the local opposition renewable energy developers are facing with many of their U.S. projects and offer insight on how to address it.

The first-of-its-kind Berkeley National Laboratory’s report, “Survey of Utility-Scale Wind and Solar Developers,” finds that a third of siting applications submitted by developers in the past five years have been canceled and about half have been delayed by at least six months, in many cases because of local pushback.

Four out of five developers were at least moderately concerned that community opposition will get in the way of decarbonization goals.

“Good Fences Make Good Neighbors,” a collaboration by researchers at Berkeley Lab and Michigan universities, focuses strictly on large-scale solar systems. It is based on 54 interviews with a broad range of stakeholders examining the concerns about these facilities.

Pattern of Delays

The wind and solar survey by three Berkeley Lab researchers drew responses from 123 people at 62 companies that collectively are responsible for about half of U.S. wind and solar development from 2016 to 2023.

Among the findings:

    • Most projects take four to six years from initial public announcement to commercial operation date; about 20% take longer.
    • Local ordinances or zoning regulations, grid interconnection and community opposition are the leading causes of project delays and cancellations in the past five years.
    • Project delays and cancellations are slightly more common for solar than for wind and most often occur during the permitting process.
    • Project cancellations result in average non-recoverable costs of more than $2 million each for solar projects and $7.5 million each for wind.
    • Community opposition to wind and solar is cropping up more frequently and becoming more expensive to address; it delays solar projects 11 months on average and wind projects 14 months; developers expect it to become even more prevalent in the next five years.
    • About 95% of respondents say opposition often is caused by a vocal minority; about half find opposition is driven by outsiders; middle- to high-income communities are more likely to push back on proposals than low-income areas.
    • Less than a third of developers say it is easy to predict opposition, but most agree that larger proposals are more likely to be contentious.
    • Visual impact is the most likely root of community opposition for both solar and wind, followed by impact on community character and property values; additionally, noise is a frequent concern with wind proposals and loss of agricultural land with solar plans.
    • Developers typically begin community engagement after securing site control; most developers find it effective in addressing concerns and reducing opposition and say it results in fewer cancellations; in-person meetings with stakeholders are ranked the most effective means of engagement.
    • Many respondents said earlier engagement might have been a good idea with their most recently canceled project, but a few said earlier engagement allowed more effective opposition to form.
    • The most common design changes in response to community feedback on solar projects are changes to vegetation screening, exclusion of properties and increased setbacks; for wind projects, it is revised turbine placement, increased neighbor compensation and exclusion of properties; for both technologies, increase of community subscription or ownership was the least common change.
    • Community engagement boosted costs approximately $1,100 per megawatt on successful wind projects and $700 on solar.

Building Trust

The report “Good Fences Make Good Neighbors: Stakeholder Perspectives on the Local Benefits and Burdens of Large-Scale Solar Energy Development in the United States” was prepared by the same three researchers from Berkeley Lab and two each from the University of Michigan and Michigan State University.

They note that a rapid increase of solar and wind generation is needed to meet national decarbonization goals and that the Energy Information Administration predicts 63 GW of solar capacity to be installed in 2024 alone.

This effort often relies on residents willing to host these systems, the authors write, and depends heavily on permitting approval by local and state officials and policymakers.

These officials and local residents offer far less support for large-scale solar (LSS) projects than national surveys suggest, the authors say. They interviewed nine developers, 32 people who live near solar facilities, seven government officials and six utility representatives to try to understand why.

They identified eight typical concerns and a set of recommendations to address them:

    • Public meetings have little positive effect on residents’ perceptions of LSS; many people are unaware of the processes and feel left out. Policies should be considered to require developers to engage in one-on-one conversations to identify and address concerns.
    • Residents use the term “developers” as a catchall for builders, owners and operators, leading to confusion and distrust; also, residents should have more opportunity to provide feedback when construction is complete and the facility is online. Officials should better delineate and communicate organizational responsibility over the life of the project.
    • Rural communities may be overwhelmed by a sudden influx of LSS construction workers and their needs. Developers should contract with local businesses to meet the needs of their project and of the community before starting construction.
    • Residents living near LSS projects often are ignored in subscription efforts. Developers should, at a minimum, advertise such opportunities via direct mail and at public meetings.
    • Residents often are unaware of the LSS impact on tax revenues or have a negative impression of it. Officials should tie specific services to the tax benefits or replace tax revenue with predictable, scheduled payments.
    • The visual impact of interconnection infrastructure often is ignored during pre-construction community engagement. Developers should provide detailed renderings of substations and other infrastructure, not just the solar arrays; they should provide tours of nearby LSS sites.
    • Previously developed land in rural areas may not be perceived as more suitable than greenfields for LSS developments. Developers should not assume LSS will be seen as a beneficial use of disturbed land.
    • The costs of not developing solar rarely are a conversation point. Developers and officials should discuss the more permanent infrastructure that could occupy the same land with potentially greater impact on neighbors, such as subdivisions and trailer parks.