MISO’s Market Subcommittee likely will devote some time this year to discussing either a multiday gas purchase requirement or a multiday gas unit commitment process for use during extreme cold.
The RTO’s Steering Committee tasked the Market Subcommittee with consideration of the topic during a Feb. 6 teleconference. The issue was originally brought to the Steering Committee by member MidAmerican Energy.
In a written request, MidAmerican Energy’s Dennis Kimm said MISO should either introduce a multiday unit commitment process or adopt a requirement that natural gas generators buy fuel when weather is forecast that will send gas and electricity demand soaring. Kimm said the multiday commitments or natural gas procurements should not be used during normal operations.
Kimm said generators “undertake a significant economic risk in executing purchases for fuel and capacity without a guarantee that the generator will be dispatched.” He wrote that uncertainty regarding MISO dispatch “can act to discourage participation in the natural gas marketplace during times of greatest liquidity.”
MISO reported experiencing gas supply challenges, resulting in reduced generator availability, during the mid-January cold front that played out over a holiday weekend.
Kimm said some advance notice from MISO on what it plans to call up would “increase flexibility for natural gas-fired generators to obtain fuel and better situate the electric industry to adequately plan and prepare to deliver reliable service” during extreme cold.
But Executive Director of Market Operations J.T. Smith seemed unconvinced multiday commitments would improve natural gas generators’ performance issues during cold spells. He said a more successful approach would include better offers that reflect true capabilities, take into account lead times and consider temperatures and fuel procurement.
Smith said he understands generation owners want certainty, but there’s a “hesitancy from the membership” to provide true startup times and realistic availability of their generation in the market because it would harm their capacity accreditation values.
Smith said during cold snaps — including the latest widespread mid-January deep freeze — “we don’t get offers from our generators that reflect true availability.”
Smith said the optimization in MISO’s day-ahead market already gives owners and operators the signals to make commitment decisions days ahead of a weather event.
“In my mind, the multiday market already exists,” Smith said, adding he was “not so sure the problem” could be solved through MISO developing a new commitment model or fuel purchase requirement.
“Give me a valid offer of your true availability capabilities first,” he said.
Smith also said the topic likely contains resource adequacy implications that may need to be hashed out at the Resource Adequacy Subcommittee, in addition to the Market Subcommittee.
MISO has waded into the battle over who will build the Iowa portions of its long-range transmission projects two months after a court found the state’s right-of-first-refusal law unconstitutional.
The RTO filed an amicus brief in the case, asking the Polk County District Court to lift an injunction that halted regulatory permitting for long-range transmission plan (LRTP) lines that incumbent developers ITC Midwest, MidAmerican Energy and Cedar Falls Utilities elected to build under the ROFR law (CVCV060840).
The District Court in December struck down Iowa’s ROFR law and prohibited regulatory permitting on Iowa’s portion of five of MISO’s LRTP projects in which incumbent developers had benefited from the law. The ruling cast doubt on $2.6 billion in already approved LRTP projects located at least partly in Iowa. (See Iowa ROFR Law Overturned, Throwing Multiple MISO LRTP Projects into Uncertainty.)
Since then, competitive developer LS Power has asked the court to reverse MISO’s assignment of the Iowa projects to the incumbent developers after the ROFR was deemed unconstitutional. LS Power challenged the ROFR’s validity in the first place, arguing it was shut out of the bidding process.
MISO said while it doesn’t take a position on the legitimacy of the ROFR, it is asking the court to reconsider the injunction against permitting, given that the planned lines are needed for the sake of grid reliability. The grid operator also argued the District Court’s interference with the line development is improper because FERC is best situated to handle who is allowed to build the lines pursuant to the MISO tariff.
MISO said it has a “strong and substantial interest” in making sure the LRTP projects in Iowa are built by the 2028-2030 time frame. The RTO said while the four- to six-year span seems like a long time, 345-kV line construction is a lengthy process that requires “timely permitting” to achieve targeted in-service dates. It emphasized that benefits stemming from its $10 billion LRTP portfolio will cover costs and save billions more in reliability advantages and access to new generation across the Midwest. MISO added that the LRTP lines’ benefits are premised on the lines operating as a whole.
“The injunction in question in this case, if sustained, would stand as an obstacle to timely completion of much-needed transmission to serve not only Iowa but the region as a whole,” MISO wrote to the court in its Feb. 6 brief. “MISO strongly urges this court to revisit its prior decision regarding the subject injunction in light of these factors and circumstances to avoid potentially ruinous practical public policy consequences.”
MISO said if the injunction is allowed to stand, current and future long-range transmission planning will be put at risk.
‘Impermissibly Intrudes’
The grid operator also said the court’s December injunction “impermissibly intrudes on the FERC’s exclusive authority over the transmission of electric energy in interstate commerce under the Federal Power Act.” It said the court “should not disrupt the timely completion of these projects in pursuit of a remedy that only FERC may grant” and added that only FERC has the authority to interpret the MISO tariff.
MISO said while LS Power can argue that it was deprived of the opportunity to bid on the lines’ construction and suffered economic harm due to the ROFR law, “whatever harm LS Power may potentially suffer is not as severe, concrete and particularized as the harm energy users, energy providers, MISO and its affiliates may suffer.”
FERC, MISO argued, is in the best position to assess competing claims to the lines’ construction, weigh how changes and delays to the lines will impact all parties, and order remedies. The RTO said LS Power already has “an effective federal remedy” through FERC and is free to argue before the commission that MISO’s assignment of the Iowa LRTP projects to the incumbents violated its tariff in light of the unconstitutionality holding.
“The public policy interests at stake, the balance of the harms as between the parties involved (and as to MISO), in the context of the nature and gravity of the vital regional utility grid issues at stake, make this matter ideal for judicial reconsideration as requested,” MISO wrote.
At a Feb. 7 MISO Advisory Committee meeting, Clean Grid Alliance’s Beth Soholt said she believed the Iowa ROFR ruling affects more than just the Iowa line segments in the first LRTP portfolio.
Soholt said the delays and uncertainty could bleed over to impede progress on MISO’s second LRTP portfolio, which is in the works.
“I think it’s very important for MISO to be [as] transparent as possible about the impacts and what that does to the study process of follow-on lines. … It’s a really major thing if we start having cascading timing issues. A lot of states are counting on these transmission buildouts,” Soholt said.
MISO Deputy General Counsel Kristina Tridico said the RTO will contemplate the most appropriate venue to share new information on the status of the Iowa projects with stakeholders.
Tridico said MISO will defer to the court’s decisions on the matter and understands the court’s actions stand to affect the planning and timely completion of LRTP lines. She said the RTO hopes to convey the importance of the LRTP lines in its brief.
FERC on Feb. 6 rejected a PJM proposal to rework the role of performance penalties in its capacity market and how the associated risks can be reflected in seller offers (ER24-98).
The filing was one of two the RTO made in October after the conclusion of the Critical Issue Fast Path (CIFP) process, largely focused on market issues highlighted by December 2022’s Winter Storm Elliott and PJM’s February 2023 “4R’s Report.” The commission approved the second filing last week, greenlighting changes to how PJM measures reliabilities risks, accredits capacity resources and verifies generators’ ability to operate throughout the delivery year (ER24-99). (See FERC Approves 1st PJM Proposal out of CIFP.)
In splitting the changes the Board of Managers sought to make after the CIFP process into two filings, PJM Senior Counsel Chen Lu said staff sought to ensure that components that relied on each other were accepted or rejected as a package and to avoid potentially riskier elements from sinking the entire proposal.
At the heart of the filing was how market sellers can represent the risks they face in taking on a capacity obligation through the Capacity Performance quantified risk (CPQR) component of their capacity offers; how those values are reviewed by the Independent Market Monitor and PJM; and under what circumstances generators can be assigned penalties for underperforming or receive bonuses for overperforming.
During the Market Implementation Committee’s meeting Feb. 7, PJM’s Skyler Marzewski said the RTO does not plan to seek a delay of the 2025/26 Base Residual Auction scheduled to be conducted in June. Both CIFP filings were intended to be effective for the auction, and Marzewksi laid out a timeline for when PJM plans to seek endorsement of several manual changes to implement the proposal approved in ER24-99.
FERC’s Order
FERC said that PJM had not provided enough detail around how it planned to implement the changes and sought to give the RTO guidance on changes that might be beneficial if it sought to refile the proposal.
In rejecting PJM’s plan to largely redefine the market seller offer cap (MSOC) based on CPQR and costs incurred to avoid those risks, FERC said that the proposal failed to define what qualifies as the sort of incremental cost that a generator could include in its offer versus actions that generation owners would have taken in the absence of a capacity commitment.
“PJM does not include in its pleadings or proposed tariff provisions a defining principle to identify and differentiate costs incurred only in the absence of a capacity obligation compared to costs incurred in whole or in part for some other purpose, such as to enhance EAS [energy and ancillary services] revenues,” the commission wrote. “PJM’s proposal seems to require PJM to employ a subjective assessment as to the intentions underlying complex investment decisions of sellers participating in a variety of markets, i.e., the capacity, energy and ancillary services markets, and bilateral transactions.”
The commission also said it saw merit in PJM’s proposal to create a standardized calculation for CPQR that incorporates unit-specific parameters that market sellers could accept or substitute with their own determination. But without FERC, the Independent Market Monitor and stakeholders having access to the proprietary model it sought to utilize, it would not be possible to understand what a valid CPQR value would be, it said.
“Though we have found that PJM has not provided sufficient detail to understand how the model components would be implemented in its proposed standardized CPQR formula, using a probabilistic model with unit-specific data would ensure a CPQR value that is specific to that resource and its risk profile,” FERC said.
PJM sought to provide more certainty of the costs that market participants could include in their CPQR submissions by introducing a third-party review process where sellers could include a review by a qualified, independent party and include that as documentation in support of their submissions. The commission found that the existing tariff language already supports that process and that the proposal would create a requirement that PJM and the Monitor accept the results of that outside review. FERC also raised questions of how PJM would define the qualifications that the third party must possess and how to ensure independence from the market seller whose offer it is reviewing.
“In other words, it would require PJM to automatically accept any third-party consultant justification regardless of reasonableness. We find that such a requirement would not be just and reasonable because it would delegate responsibility that belongs to PJM and the Market Monitor to third parties. The commission has found it is inconsistent with the principles of mitigation to allow sellers with market power to determine their own costs without review.”
FERC rejected PJM’s proposal to allow it to calculate an alternative MSOC using the information submitted by the market seller if the RTO determined that the one submitted after the review process conducted by the Monitor did not conform to the tariff. The tariff only empowers PJM to accept or reject the offer cap submitted by market sellers, which the RTO argued leaves its hands tied when it agrees with parts of an offer, but not the entirety.
The Monitor argued that granting PJM the ability to calculate its own offer cap would impinge on its prerogative in reviewing offers for market power, a position the commission cited in denying the filing. FERC pointed to Order 719 in finding that external monitors have the expertise and means to identify and mitigate market power and provides them with the sole authority to make market power determinations.
“We share commenters’ concerns that under PJM’s proposal, the Market Monitor would not be able to provide meaningful feedback because PJM would replace the Market Monitor’s role in calculating offer caps, which could undermine the Market Monitor’s duty to ensure competitive markets,” it said.
The proposal also would have created a new exception generation owners could claim to avoid being assigned Capacity Performance (CP) penalties by exempting generators not dispatched during a performance assessment interval (PAI) on a market-based offer that exceeded their cost-based offer. PJM argued that resources following dispatch instructions should not be penalized, but the commission sided with protests arguing that the change would allow generators to avoid being subject to CP by submitting offers that are unlikely to be committed.
“We agree with the Market Monitor that, with respect to nonperformance charges, there is no meaningful difference between resources that choose to submit market-based offers using relatively less flexible parameters than their cost-based offer or market-based parameter-limited offer, and those that choose to submit market-based offers using relatively higher economic parameters than their cost-based offers. Both strategies would constitute a capacity resource failing to meet its obligation to perform during an emergency and, therefore, require appropriate penalties,” the commission wrote.
FERC also rejected PJM’s proposal to limit eligibility for CP bonus payments, which are paid out from the pool of penalties collected following PAIs, to committed capacity resources. It pointed to comments from the PJM Industrial Customer Coalition, which said that about 40% of the overperformance seen during Winter Storm Elliott came from market sellers lacking a capacity commitment. Making such resources ineligible would remove an incentive for all resources to be prepared to operate during emergencies and limit the solutions available to maintain reliability during stressed system conditions.
Clements Partially Dissents
In a partial dissent, Commissioner Allison Clements said she agreed with the bulk of the order but disputed the majority’s reading of Order 719 in relation to PJM’s proposal.
Rather than making market power determinations, she said that the changes would have given PJM flexibility in considering whether an offer complies with the tariff, arguing that the “Monitor plays an important but circumscribed and advisory role under PJM’s offer cap rules.”
Clements also disagreed with the majority in rejecting PJM’s request to eliminate the physical replacement option for fixed resource requirement (FRR) entities that underperform. Instead of incurring financial penalties, such entities can choose to procure additional capacity for one year. PJM argued the option lacks the teeth of immediate financial penalties by deferring the costs and results in a smaller economic impact.
Clements wrote that PJM’s difficulty incentivizing resources to perform during extreme weather makes it reasonable to create FRR penalties that are more in line with those used in the Reliability Pricing Model.
Legislators in five states in PJM have filed similar bills that would require regulated utilities to submit all of their stakeholder votes publicly with state regulators.
Illinois, Maryland, Pennsylvania, Virginia and West Virginia have all introduced bills in the effort, which is supported by the National Caucus of Environmental Legislators (NCEL) and the Citizens Utility Board (CUB) of Illinois.
“My colleagues and I, across the PJM region, know that decisions made at PJM affect our ratepayers, the reliability of our electric grid and our transition to clean energy,” Charkoudian said. “These are all issues we are working on at the state level, and PJM’s rules have the ability to either support or hamper our ability to address these issues. This bill will go a long way to establishing transparency to support our ability to engage with PJM on these crucial issues.”
While PJM’s meetings are open to the public, so many are held that state regulators and consumer groups cannot track all of them, Clara Summers, manager of CUB’s Consumers for a Better Grid campaign, said in an interview.
“When utilities vote at PJM, the outcome of those votes impact our clean energy transition; they impact our reliability and the cost of electricity,” Summers said. “So, these bills are about introducing better transparency and better accountability for how those utilities are voting on these issues that affect our electric markets and transmission.”
With hundreds of meetings a year that can last hours and do not always produce records of how individual firms voted, making sure utilities are open about how they are voting will ensure states that their policies are being respected, she added.
PJM itself did not weigh in on the substance of the bills, but it said its stakeholder process is transparent.
“The PJM stakeholder process and the various stakeholder meetings, approximately 450 meetings, are open to the media and the public, with agendas and minutes posted on our website,” the RTO said in a statement.
Unlike the major committees — the Markets and Reliability Committee and the Members Committee — the lower committees allow firms’ individual affiliates to vote. Some firms, like American Electric Power and FirstEnergy, have so many affiliates that on their own, their votes can outweigh the combined votes of the participating consumer advocates, Summers said. “That increases their potential for impacting which proposals get voted on to advance.”
To win approval, rule changes need a majority in the lower committees and a two-thirds sector-weighted majority at the MRC and MC. PJM provides summaries of votes by sector at the major committees and details how individual members voted at the Members Committee.
Both Summers and Ava Gallo, NCEL’s climate and energy manager, said one reason states have become more interested in the PJM process is the drama around the now-defunct extended minimum offer price rule (MOPR-Ex). During the Trump administration in 2018, FERC controversially ordered the RTO to expand its bidding floor in the capacity market to all new state-subsidized resources; the rule had previously only applied to new gas-fired resources. (See FERC Extends PJM MOPR to State Subsidies.)
Politics among the PJM states is diverse, but Gallo said that while West Virginia and Illinois might differ sharply on energy policy, they both value transparency.
“NCEL is proud to help organize these state legislators across the PJM region,” Gallo said. “We know that legislators work tirelessly to ensure their constituents have affordable, reliable and clean electricity. States are stronger together, and this legislation can help ensure that utilities across the region are also working towards these same goals.”
The West Virginia legislation comes almost a year after its Public Service Commission filed a complaint at FERC alleging it had been improperly blocked from the PJM Liaison Committee, whose meetings are limited to members and the RTO’s Board of Managers. (See W.Va. PSC Files Complaint over PJM Meeting Policy.)
In the still-pending complaint proceeding (EL23-45), PJM responded that the committee was created so stakeholders could have direct communication with its board outside of the normal stakeholder process and that the board has closed-door meetings with state regulators under a deal it signed with the Organization of PJM States Inc.
“In West Virginia, people’s electric rates have gone up faster than any other state,” state Del. Evan Hansen (D) said. “We need our electric utilities to explain how their secret votes at PJM are in the public interest.”
Participants in NERC’s Member Representatives Committee suggested improvements to the onboarding process for new entrants and greater engagement with industry organizations in their responses to Board Chair Ken DeFontes’ call for stakeholder input, published Feb. 6.
DeFontes asked for the MRC’s input last month ahead of the Board of Trustees and MRC meetings to be held next week. In addition to seeking feedback on the board’s planned agenda items, the chair requested responses to three specific questions:
How can NERC facilitate engagement by new industry participants?
How can NERC encourage incumbent players to continue engaging in the ERO stakeholder process and ensure their contributions are effective?
How can NERC promote improved alignment between subject matter experts, trade associations, industry leadership, the MRC and NERC?
Multiple respondents brought up issues with NERC’s onboarding process. Electricity Canada, a trade group representing Canadian electric utilities, cited the ERO Enterprise’s “complexity” as “a barrier to onboarding new entrants,” despite acknowledging NERC’s efforts to provide documentation for its resources. The group suggested the ERO create a dedicated section on its website for bringing newcomers up to speed, in addition to offering “introductory courses on NERC fundamentals” that can be tailored to more specific topics.
The Edison Electric Institute echoed Electricity Canada’s thoughts but advised that any introductory courses should include in-person learning sessions rather than being limited to prerecorded webinars and slide decks. EEI explained that webinars “lack dialogue and opportunities for interaction,” and new participants would benefit from discussions with their more experienced colleagues.
A group of federal utilities and power marketing administrations said NERC should “learn more about the new entrants,” including their corporate goals and the regulatory structures under which they operate. The ISO/RTO Council (IRC) added that NERC’s onboarding materials should address each responsible entity’s “role and responsibilities within the broader NERC community.”
Regarding the ERO’s engagement with existing participants, several entities raised concerns about the volume of projects underway at NERC. A collective letter from members of the cooperative sector noted that “there continues to be significant requests for industry comments on reliability standards, guidelines, and data requests.”
The cooperative members said the high level of activity can “become burdensome” for industry and warned that projects may be “pushed through the approval process to satisfy a FERC rulemaking.” They asked for “more robust” communications from NERC to help industry grasp the benefits and impacts of proposed standards, with outreach tailored to specific sectors.
Representatives of the merchant electricity generator sector said NERC’s practice of allowing entities to register in multiple segments, and therefore cast multiple votes, gives too much power to members that can qualify in multiple segments. For example, the writers observed that segment 5 — electric generators — “allows participation by merchant generators; renewable resources; municipalities, cooperatives and vertically integrated utilities that hold generation.”
“There was a recent vote where the merchant generators and renewable developers overwhelmingly opposed a proposed standard, yet a majority of the segment representatives voted for the standard,” the merchants said. “Presumably these multisegment entities coordinated voting across segments.” The writers suggested that this potential power imbalance might discourage entities from participating.
Reliability, Transparency
Members urged NERC to focus on its leading role in the community of electric reliability, with members from the electricity marketer sector suggesting the ERO improve industry alignment by prioritizing “targeted areas with the greatest impact for improving reliability.”
The IRC pointed out that the power grid’s generation mix is changing rapidly, and not all new resources will be subject to NERC’s reliability standards. Their response suggested that NERC “engage with applicable regulatory entities” to promote awareness of these resources’ potential reliability impacts.
Representatives of the North American Generator Forum repeated these calls for communication, recommending that NERC reach out to trade associations and other industry participants frequently and “facilitate calls and/or virtual meetings” to promote the exchange of information. EEI also emphasized the importance of transparency, noting that “the ability to develop robust solutions in a timely manner is impaired when industry and NERC do not have the same understanding of the underlying problem.”
“It is critical that the problem statement for risks that need to be addressed through standards projects or other activities is clear and well understood by the industry,” EEI said. “Investing more time up front explaining and soliciting broad stakeholder feedback on an issue, and subsequently on the proposed solution, should result in better alignment, less rework and a more efficient process.”
CAISO’s Western Energy Imbalance Market has yielded $5.05 billion in benefits for its members since its inception in 2014, continuing the positive trend of growth tied to an expanding Western footprint, according to the ISO’s fourth-quarter benefits report released Jan. 31.
“This level of economic benefits are a very good representation of the value and effectiveness of the WEIM market to meet supply and demand across the wide footprint,” Guillermo Bautista Alderete, director of market performance and advanced analytics for the ISO’s Department of Market Monitoring, said at a Feb. 6 WEIM Governing Body meeting.
Q4 2023 produced a total of $391.82 million in cost savings for WEIM participants, accrued from having additional entities join the market in 2023, which now stands at 22 balancing areas representing nearly 80% of the demand for electricity in the Western Interconnection.
The Balancing of Authority of Northern California saw the largest share of benefits last quarter at $73.24 million, with PacifiCorp second at $50.46.
CAISO said economic transfers within the WEIM were “substantial” in Q4. The ISO itself had the highest volume of net exports, at 1,403,521 MWh, followed by the Salt River Project (629,470 MWh) and PacifiCorp East (538,108 MWh). Powerex was the largest net importer at 1,266,745 MWh, followed by CAISO with 735,579 MWh.
CAISO also led in the volume of wheel-through transfers, at 1,140,739 MWh, followed by Arizona Power at 379,452 MWh.
WEIM also continued to provide emissions benefits due to its ability to enable transfers that prevent renewable output from being curtailed. According to the report, the total avoided renewable curtailment by volume reached 49,880 MWh, displacing an estimated 21,349 metric tons of CO2 in Q4. Avoided curtailment since 2015 yielded a reduction of 925,568 equivalent tons of CO2.
“The environmental benefits of the WEIM are very compelling, really helping to bend the cost curve for many,” CAISO CEO Elliot Mainzer said during the Feb. 6 meeting. “We see an increasingly volatile system that’s impacted by extreme weather and new resource development. That wide-area capability of the WEIM will continue to produce these tangible economic and environmental benefits.”
Extreme Weather at Play
January’s extreme cold snap in the Pacific Northwest demonstrated the WEIM’s ability to deliver reliability, CAISO officials said at the meeting. During that weather event, California balancing authority areas were able to transfer energy to Northwest areas struggling to meet demand.
“The market’s performance in 2023 shows how widespread cooperation among entities in the Western Interconnection reduces consumer costs and quickly sends energy where it’s most needed during stressed weather conditions,” Mainzer said. “The value of that broad transmission connectivity and resource diversity across the West as a reliability support mechanism continues to come into sharper focus.”
A report analyzing how CAISO responded to extreme weather conditions in the Northwest in January is slated for the week of Feb. 19, Mainzer said.
The world’s leading offshore wind developer announced it is pulling out of some smaller markets but reiterated its commitment to construction and operation in U.S. waters.
In its 2023 earnings report, issued Feb. 7, Ørsted also downgraded its growth projection, announced hundreds of job cuts and said its bottom line was a $2.91 billion net loss in 2023. More than $1 billion of the loss was because of offshore wind project cancellation costs.
Much of the fiscal distress stems from Ørsted’s troubles in the northeastern United States.
In late 2023, it became the first developer to cancel a major, mature U.S. project when it spiked Ocean Wind 1 and 2 and took billions in impairments.
In early 2024, it canceled the Maryland offtake contract for Skipjack Wind and moved to cancel the New York offtake contract for Sunrise Wind, resulting in additional costs and delays. But it continues to develop both projects and is seeking a new contract for Sunrise.
The developments prompted Ørsted to undertake a comprehensive offshore portfolio review, the results of which were reflected in Feb. 7’s announcements.
The board of directors set a goal of 35-38 GW of installed offshore capacity by 2030; it now has approximately 23 GW installed, and previously had aspired to reach 50 GW by 2030.
The challenges of 2023 also led Ørsted to suspended stock dividends for fiscal years 2023-25 and report a $2.91 billion loss in 2023, compared with a $2.17 billion profit in 2022.
It remains committed to the U.S. offshore wind sector, particularly off the Northeast coast, but will exit the market in Norway, Spain and Portugal; will deprioritize development in Japan; and is planning to trim development efforts in floating wind and P2X — the use of offshore wind energy to generate other forms of energy, such as green hydrogen.
As a result, the company expects to reduce its global workforce by 600 to 800 people.
Looking forward, Ørsted said it’s exploring options for divesting the federal leases off the New Jersey coast for the Ocean Wind projects.
The company said it is revising its project operating model to include better contingency planning, with more proactive planning for backup supply chain capacity; securing all critical local permits before making a final investment decision; ensuring greater flexibility on project timelines and commissioning dates; and conducting more reviews of projects as they progress, both by internal peers and external sources.
Other Financials
Other companies in the offshore wind space also have released financial results in the past week. The reports have provided additional insight into the problems the sector is facing.
For example, in its fourth-quarter/full-year earnings call Jan. 23, General Electric placed its 2023 offshore wind loss at roughly $1.1 billion.
In its 10-K filing Feb. 2, General Electric predicted global growth in the offshore wind industry in coming decades but near-term challenges due to companies trying to increase output and reduce cost.
For its own offshore business, GE said it continues to experience pressure related to product and project cost estimates. It’s attempting to counter this, but timeline changes and other adverse developments could result in further losses beyond what it currently estimates.
For the year ending Dec. 31, offshore project losses increased by $400 million, GE said, and launching or ramping up new platforms such as the Haliade-X offshore wind turbine will create additional operational risks.
In other reports:
Equinor said Feb. 7 its net income dropped 59% from $28.74 billion in 2022 to $11.9 billion in 2023. Its renewables sector recorded a $757 million net loss in 2023, compared with an $84 million net loss in 2022, which it attributed in part to the $300 million third-quarter impairment it took on its U.S. Northeast offshore wind projects, as well as higher development and operating costs elsewhere.
Bp took a $600 million pretax impairment charge in the fourth quarter of 2023 because of restructuring of its U.S. projects, raising the full-year cost to $1.14 billion. Bp and Equinor are dissolving their offshore partnership, which had four separate wind farms in development. They have terminated the New York offtake contracts for Empire Wind 2 and Beacon Wind 1 and effectively terminated the contract for Empire Wind 1.
Siemens Energy issued its first-quarter 2024 report Feb. 7, titling the release “Solid start to the year, turnaround of wind business remains focus.” But that referred to onshore wind, where Siemens has run into quality control problems. The company said orders were slightly higher but revenue lower in the offshore business in the first quarter of 2024 compared with 2023 amid rising product costs and ramp-up challenges.
Vestas said Feb. 7 that it returned to profitability in 2023 and recorded a record order intake — 18.4 GW — in both onshore and offshore equipment, especially in the U.S. 2023 offshore revenue was down from 2022 but that was more than offset by onshore increases. Looking forward, it expects the offshore market to show a compound annual growth rate of 20 to 25% in 2023-30, with growth accelerating after 2025. That is a downgrade from a year earlier, when Vestas predicted 35 to 40% growth from 2022-25.
A task force formed in the wake of significant fires at three grid-scale battery energy storage systems has recommended new safety protocols for the facilities in New York state.
The 15 draft recommendations published Feb. 6 are open now for comment by the public and industry stakeholders. The final versions will be considered by the New York State Code Council for inclusion in the Fire Code of New York State and in other fire safety standards that apply to energy storage facilities.
The three fires came in two months in mid-2023, each larger than the one before. Fires in lithium-ion battery energy storage systems (BESS) are hard to extinguish and can emit toxic smoke, but an extensive review found no sign of environmental damage or public health risks in the aftermath of these three. Nor were any injuries reported. (See Analysis Shows No Contamination from NY BESS Fires.)
Public perception was perhaps the biggest casualty of the fires, becoming a friction point for New York’s clean energy ambitions, which will require many gigawatt-hours of installed storage to backstop intermittent renewables. (See Battery Storage Developers Bump Against Perception of Risk.)
Numerous municipalities statewide proposed or enacted BESS moratoria as 2023 went on.
After the third fire, Gov. Kathy Hochul (D) formed the Inter-Agency Fire Safety Working Group to examine the incidents and BESS safety standards. In late December, the group issued its initial analysis of the toxic effects of the fires.
The fire code recommendations announced Feb. 6 were the next step. They’re intended to apply to lithium-ion grid-scale BESS exceeding 600 kWh of capacity.
The working group’s continuing efforts include negotiations with the battery manufacturers and utilities to obtain root cause analysis reports for the three fires and perform inspections of all operational BESS above 300 kW in New York.
BESS safety industry experts are part of the working group. The BESS industry itself is not. Its input will come now, during comment on the draft recommendations.
The New York Battery and Energy Storage Technology Consortium told NetZero Insider via email: “NY-BEST is pleased that the State Inter-Agency Battery Safety Working Group has released its thoughtful draft recommendations and is soliciting feedback and additional input from industry subject matter experts. The energy storage industry appreciates the significant efforts of the state’s working group and we share the state’s interest in ensuring that battery energy storage is deployed safely throughout the state. We look forward to leveraging our expertise to assist the state in developing final recommendations that achieve our shared goal of making New York a leader in safe deployment of battery energy storage.”
The Alliance for Clean Energy New York also was not ready to comment Feb, 6on the recommendations themselves. It said: “In the coming days, we plan to review closely the 15 draft recommendations proposed by the working group and look forward to submitting comments and working with the New York State Code Council to ensure that the installation and operation of BESS facilities continues in a safe manner.”
The Recommendations
The Working Group noted in conclusion that the most critical issues it identified could be addressed by better enforcement and adherence to the existing code.
It offered the 15 recommendations as ways to improve the regulatory framework for BESS in New York. They are:
Require industry-funded independent peer reviews for all projects.
Expand the requirement for explosion control to include BESS cabinets in addition to rooms, areas, and walk-in units; additionally, provide design requirements or language for what constitutes a “passable” system.
Require that qualified personnel are available for dispatch within 15 minutes and able to arrive on scene within four hours to provide support to local emergency responders.
Extend safety signage requirements beyond the BESS unit itself to include perimeter fences or security barriers and include a map of the site, BESS enclosures and associated equipment.
Update the Fire Code to ensure that Battery Management System data is monitored by a 24/7 staffed Network Operations Center. Critical failure notifications should be immediately communicated to the site owner/operator to take corrective actions as necessary.
Update the Fire Code to incorporate requirements for closed-circuit television systems, specifying their intended use as both a continuous monitoring tool and a post-event analysis resource.
Remove the Fire Code exemption for BESS projects owned or operated by electrical utilities to ensure that all projects comply with the Fire Code.
Include a requirement for an Emergency Response Plan and annual local first responder training for every BESS installation.
Include a Fire Code requirement for monitoring of fire detection systems by a central station service alarm system to ensure timely, proper notification to the local fire department in the event of a fire alarm.
Mandate the installation of fire stops for all BESS enclosure penetrations to prevent the propagation of fires from one BESS unit to another through these pathways.
Introduce a new provision in the Fire Code mandating industry-funded special inspections for BESS installations to ensure thorough safety and compliance.
Include “cabinets” in all Fire Code requirements that pertain to rooms, areas or walk-in units, except for fire suppression requirements, as they may be inappropriate for cabinets.
The WG concluded that the Fire Code may not be the appropriate place to require a Root Cause Analysis.
Establish guidance for water supply, including whether water is appropriate for different technologies, in an emergency response to a BESS fire and determining if more specific requirements are necessary.
Recommend that the Code Council have further discussions around clearance distances of oil-insulated transformers from BESS.
Leaders of nine states have agreed to pursue greater adoption of heat pumps by their combined 93 million residents.
A memorandum of understanding announced Feb. 7 sets a goal of heat pump technology comprising 65% of residential heating, cooling and water heating equipment sales by 2030 and 90% by 2040. That compares with a present-day market share of roughly 25% in the nine states.
California, Colorado, Maine, Maryland, Massachusetts, New Jersey, New York, Oregon and Rhode Island signed onto the MOU. It builds on a September announcement by the U.S. Climate Alliance in which 25 governors set a 2030 goal of 20 million heat pumps operating in their states. (See Climate Alliance Seeks to Boost Heat Pump Sales.)
The nine states agreed to lead by example and promote zero-emission technologies in state-owned buildings. They also will seek to direct at least 40% of efficiency and electrification investments toward low-income households that pay a large percentage of their income for energy costs, and to communities that historically have experienced high air pollution levels.
NESCAUM noted that buildings are a leading source of greenhouse gas emissions. In the nine participating states, buildings emit 173 million metric tons of carbon dioxide per year, plus much smaller quantities of nitrogen oxides, fine particulate matter and other substances blamed for health problems.
Multiple variables will bear on how these outputs change amid greater use of heat pumps, and there is not a ready estimate of what a 65% or 90% market share would accomplish by way of reduction, said Emily Levin, a NESCAUM senior policy adviser.
She told NetZero Insider that small-scale residential installations are the subject of the MOU because controlling temperatures in larger residential and commercial structures with heat pumps is a more complicated proposition, and the technology is evolving.
The MOU is not legally binding, and it is designed to sidestep the controversies that often attach to proposed fossil fuel bans or electrification mandates.
Levin said there is not one single path to 65% market share; each state will develop its own strategy, and each strategy likely will have multiple tracks.
“I think we see it being all of the above and looking a little different in every state,” she said. “There will likely be new policy measures in the mix.”
But almost all of the residences that will exist in 2030 and 2040 already have been built. So any meaningful drive to building decarbonization will need to specifically target existing structures. A mix of incentives, tax credits and practical assistance is offered to make this happen.
“We’re seeing a range of policies emerging to tackle existing buildings,” Levin said.
There are potential sticking points on the path to 65% market share.
A larger workforce skilled in heat pump technology needs to be trained, for example. Levin said these efforts are underway. The skillsets in the traditional HVAC industry are not entirely different, but there is a learning curve in the move to electrification.
Grid capacity is also a consideration, she said, but there are strategies that could mitigate heat pumps’ demand for electric power in regions that previously relied on fossil fuels for heat.
There also could be pushback from industries that rely on existing technology and see electrification as an existential threat. Some proposals have turned into battles.
NESCAUM hopes this effort will be perceived more positively and has enlisted HVAC industry stakeholders in the push for the MOU.
The New Jersey Board of Public Utilities (BPU) has initiated a second state agreement approach (SAA) process with PJM to build the transmission needed to connect 3,500 MW of offshore wind with the RTO’s grid.
In a Feb. 5 announcement of the SAA, BPU President Christine Guhl-Sadovy said the first agreement in 2022 — also the first for PJM — made the state a national leader in developing offshore wind, putting it on track to construct 4,890 MW.
In addition to resources being developed through PJM’s traditional generation interconnection queue, the second SAA will allow the state to meet Gov. Phil Murphy’s goal of installing 11 GW of offshore wind by 2040. PJM and the BPU jointly filed the SAA with FERC on Feb. 2 (ER24-1187).
“We believe that a coordinated and planned approach could result in more efficient and cost-effective transmission solutions, significantly reducing the risks of permitting and construction delays and protecting ratepayers with cost containment options,” Guhl-Sadovy said in a statement. “This approach helps minimize environmental impacts associated with onshore and potentially offshore upgrades. We look forward to further evaluation and planning, as a result of SAA 2.0.”
PJM CEO Manu Asthana said New Jersey’s use of the SAA process shows the promise it holds for states with policy goals that required developing new generation.
“The continued collaboration between PJM and New Jersey through the State Agreement Approach underscores PJM’s commitment to reliably and cost-effectively facilitating states’ renewable energy policy goals,” Asthana said in the announcement. “PJM’s competitive planning process allows for creative solutions to complex infrastructure challenges. New Jersey has been a leader in this approach and can be a template for other states pursuing their individual energy policies.”
New Jersey has pushed ahead with solicitations for offshore wind infrastructure since approving the $1.1 billion in transmission projects PJM recommended through the first SAA round, but hit a snag when developer Ørsted canceled its two Ocean Wind projects in November. (See New Jersey Launches OSW Infrastructure Solicitation.)
Speaking at a Feb. 6 PJM Transmission Expansion Advisory Committee meeting, PJM’s Susan McGill said the RTO plans to run the SAA planning process parallel to the 2024 Regional Transmission Expansion Plan (RTEP), with the goal of opening competitive solicitation windows for both in July. Doing so would allow PJM to select project components that meet both future reliability needs and New Jersey’s interconnection request in the most cost-effective manner and on a timeline that allows the BPU to consider project approval in the second quarter of next year.
McGill encouraged developers to draft proposals that address needs identified in both windows and submit them to each window, which would allow PJM to ensure it is selecting the best match of components.
“We will look at it from every angle to make sure we are only building what’s needed,” she said.
McGill said PJM will also give further thought to a stakeholder question about whether this approach could result in transmission owners who submit projects having to pay twice the fees to have a proposal considered for both windows.
Several stakeholders raised concerns that having two competitive windows open at once could strain the resources of PJM and transmission owners. They suggested that better ideas might be submitted if the RTO conducted the processes on a staggered timeline.
PJM’s Sami Abdulsalam said the RTO considered delaying one of the windows but said there are time constraints on when each needs to be finished. Completing one without knowing what proposals will be made for the other could result in overlap and projects having to be canceled, he said.
