Eversource will take a fourth-quarter 2023 impairment of up to $1.6 billion due to the ongoing struggles of its offshore wind joint ventures with Ørsted.
New England’s largest utility disclosed the news Jan. 8 in an 8-K filing with the SEC.
Also Jan. 8, Eversource said it is continuing its long-running effort to exit offshore wind development altogether and is in advanced negotiations with the selected buyer. It described the unnamed potential buyer as “a leading global private infrastructure investor,” but offered no insight on the likelihood of negotiations succeeding.
Eversource and Ørsted have two joint ventures: one for South Fork Wind, one for Revolution Wind and Sunrise Wind. Separately, Eversource holds a tax equity investment in South Fork.
South Fork is under construction and recently became the first utility-scale offshore wind project to send power to the U.S. grid. The partners also have committed to building Revolution.
But they have said they cannot build Sunrise under the terms of their contract with New York state. New York in November allowed them, and other renewables developers struggling with financial pressures, to cancel their contracts and rebid.
Ørsted and Eversource are considering whether to submit a new bid for Sunrise, and if so, how much that new bid should ask for, and what chances of success that bid might have. Based on this, Eversource expects to record an after-tax, other-than-temporary impairment of $600 million to $700 million for Sunrise.
Meanwhile, in the fourth quarter, both joint ventures revised their projections to reflect the higher cost of building the three wind farms and, as a result, substantially reduced their fair value. Consequently, Eversource expects to record an after-tax, other-than-temporary impairment of $800 million to $900 million for the three projects.
Previously, Eversource reported a second-quarter 2023 impairment of $400 million ($331 million after taxes) and Ørsted reported more than $4 billion in impairments in the first three quarters of 2023, both due to offshore wind.
The U.S. offshore wind industry has been struggling for more than a year now, as developers who locked in the value of their projects’ electricity saw the cost of building those projects soar amid high interest rates, spiking inflation and supply chain shortages.
In late 2023, Ørsted’s Ocean Wind 1 and 2 became the first contracted offshore wind project in the United States to be canceled. Three others canceled power purchase agreements and went into limbo in 2023, and a fourth followed early this year.
In a news release Jan. 8, Eversource CEO Joe Nolan cited those pressures: “Offshore wind projects continue to experience major supply chain disruption and inflationary challenges in the early stage of this growing industry in the U.S., and this impairment is an unfortunate reflection of the current market conditions we are facing. Eversource remains focused on advancing the efforts to decarbonize the energy sector and accelerate electrification with much-needed investments in transmission and other clean energy infrastructure through our regulated utilities.”
In its 8-K filing Jan. 8, Eversource offered one positive update: It is now very confident that construction of an onshore substation will qualify for a 10% investment tax credit adder that was factored into the sale price negotiated with the potential buyer. That is worth nearly $400 million.
A long shadow was cast over 2023 by the final days of the preceding year as the December 2022 winter storm, known as Elliott, brought the PJM grid to the brink, ushering in a year of stakeholder discussions to shore up the issues that the storm revealed.
While the RTO avoided the widespread outages seen in other regions during the storm, 46 GW of generation went on forced outage — prompting control room operators to issue a voltage-reduction alert and prepare for the possibility that load shedding might be required. Once the dust had cleared and the performance shortfalls for underperforming generators had been calculated, market sellers faced $1.8 billion in penalties.
In the months following the storm, PJM and stakeholders discussed concerns that capacity market structures had only narrowly avoided outages and the penalties meant to incentivize performance might prove punitive to the point of causing a surge in retirements and deceleration in new entry.
The largest set of changes drafted this year are a pair of filings pending before FERC, encompassing components of proposals stakeholders drafted through the Critical Issue Fast Path (CIFP) process the PJM Board of Managers launched in February. The proposed market design would leave much of the Reliability Pricing Model (RPM) design intact while revising the Capacity Performance construct, market seller offer cap (MSOC) calculation, risk modeling and generation accreditation. (See “PJM Steams Ahead with CIFP Filing Timeline After FERC Deficiency Notices,” PJM MIC Briefs: Dec. 6, 2023.)
The first of the two proposals (ER24-98) would effectively lower the maximum CP penalties a resource can face in a year by basing the penalty calculation on the Base Residual Auction (BRA) clearing price, rather than the net cost of new entry (CONE). It would also limit bonus payments, which are derived from penalty payments, to capacity resources, making energy-only generation ineligible.
The filing would also revise the MSOC calculation to allow generators to include more cost of risk in their offers even when their net avoidable-cost rate (ACR) is zero or negative.
The second filing (ER24-99) includes accrediting all resources under a marginal effective load-carrying capability (ELCC) framework, which PJM said would reflect the actual capacity value that resources provide. The filing also would increase the granularity of risk modeling, tighten testing requirements for capacity resources and revise components of the fixed resource requirement (FRR) framework to align with the RPM.
After the commission issued deficiency notices on both filings in November, PJM said it believes there remains a pathway to receiving approval for the market changes in time for them to be implemented for the 2025/26 BRA, which is scheduled to be conducted in June. The notices reset the 60-day timeline for the commission to issue an order on the proposals to two months after PJM’s responses; for ER24-98 that means an order by Feb. 6, and by Jan. 30 for ER24-99.
Throughout the four CIFP phases, PJM and stakeholders developed 20 proposals ranging from revising the CP penalty structure to major reworks of the capacity market, such as shifting to a seasonal construct or paying resources for each hour they are able to offer their capacity into the energy market. None of the packages ultimately received a recommendation from the Members Committee in an Aug. 23 vote. (See PJM Stakeholders Vote Against All CIFP Proposals.)
The board also sought to reduce the risks generators face in the capacity market by tightening the triggers to initiate a performance assessment interval (PAI), which the RTO argued in the CIFP filings would maintain an incentive to perform even with a lower maximum annual penalty. The commission approved PJM’s request on July 28. (See FERC Approves PJM Change to Emergency Triggers.)
The new rules add a requirement that a primary reserve shortage be in place paired with any of the following: a voltage reduction warning and reduction of noncritical plant load; manual load dump warning; maximum generation emergency action; or curtailment of nonessential building load.
In directing that the filing be made, the board chose half of a proposal endorsed by the MC in May, rejecting a stakeholder call for a reduction in the nonperformance penalties by basing the calculation on the BRA clearing price. While the annual stop-loss would be tied to capacity prices under the CIFP filing, the penalty rate would continue to be derived from net CONE. (See PJM Board Rejects Lowering Capacity Performance Penalties.)
Settlement Reduces Elliott Penalties
While discussions on how to change PJM’s markets went on throughout the year, market sellers that underperformed during Elliott negotiated with PJM to reach a settlement to reduce the $1.8 billion in penalties they faced.
An agreement was reached in October to reduce the total sum to $1.25 billion, and FERC granted its blessing last month, resolving the bulk of the 15 complaints filed against PJM over its assessment and application of the penalties. (See FERC Approves Settlement Reducing PJM Penalties for Elliott Underperformance.)
In a concurrent order, FERC rejected a complaint from Energy Harbor arguing that PJM had not properly accounted for a maintenance outage that partially reduced the output of its Sammis generator. The RTO argued that the generator also experienced a forced outage that could account for the entirety of the facility’s performance shortfall and therefore the maintenance outage was not an excuse for its underperformance.
The commission is still considering a second complaint not fully resolved by the settlement, an argument from the East Kentucky Power Cooperative (EKPC) that basing the penalty rate and annual stop-loss on net CONE, rather than the BRA clearing price, results in the potential for penalties being higher than the revenues a resource can earn in the market and is not just and reasonable.
PJM also sought to reduce the financial shock of the penalties by creating a new payment option that allows the penalties to be paid over the course of nine months, rather than by the end of the delivery year, at the cost of being subject to interest. Penalty payments are due by the end of the delivery year in which they are assessed under the standard schedule. The commission approved the alternative on April 7, and about 30% of market sellers saddled with penalties chose the longer timeline. (See “FERC Approves Alternative Billing Schedule,” PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)
New Stakeholder Groups Continue Reliability Discussions
Stakeholders have also launched three groups to investigate further changes to PJM’s markets and planning processes aimed at reducing reliability risks posed by shocks to the grid, such as winter storms, and the balance between generation deactivations, new resource entry and load growth.
The RCSTF was created with a wide-ranging issue charge intended to address any deficiencies stakeholders identify in the near, intermediate and long terms. The areas the group is tasked with investigating include reserve performance and penalties for not meeting obligations when called upon; ensuring that market offers reflect actual resource capability and fuel procurement; how reserves are deployed and in what quantity; requirements for a resource to provide reserves; and how to incentivize resource flexibility. Thus far the group has been focused on education provided by PJM and the Independent Market Monitor around how reserve resources fit into the RTO’s markets.
The DESTF is charged with considering changes to the timeline on which generators are required to notify PJM of their intent to deactivate and how generators that agree to retire past their desired offline date are compensated under reliability-must-run (RMR) contracts. During discussions around the task force’s creation, PJM and the Monitor said that the number of large generators deactivating is likely to accelerate over the coming years and that the RTO’s mechanisms for replacing the energy provided by retiring resources would function better with additional notice. Generation owners are only required to provide 90 days’ notice of their intent to cease operations.
The task force began the interest identification process during its Dec. 8 meeting, with stakeholders detailing goals of ensuring that deactivation notices provide adequate time for solutions to be implemented and compensation is provided for all services resources provide.
PJM has been forming a proposal during LTRTP meetings to create a 15-year planning horizon that would forecast the future balance between load and generation under three scenarios: a base case focused on reliability needs and near-term solutions that can resolve them, and two looking at state legislation and objectives that may affect load — such as electrification — and generation, such as environmental policies prompting deactivations or renewable development.
New Generation Interconnection Process Intended to Clear Projects Faster
PJM has completed the process of sorting 616 generation interconnection requests into two transitional queues, one of the first steps in the transition from a first-come, first-served serialized study process to the clustered approach FERC approved in December 2022. (See FERC Approves PJM Plan to Speed Interconnection Queue.)
In a Dec. 21 announcement of the milestone, PJM said the projects were evenly split between the expedited process, or “fast lane,” and first transition cycle (TC1). The fast lane is designed to allow projects requiring relatively smaller grid upgrades to be approved quicker, with final documentation expected through this year. Studies of projects in TC1 may be complete in 2025.
PJM said it anticipates studies being completed on about 300 projects in 2024, allowing 26,000 MW of nameplate capacity to move another step closer to construction. By mid-2025, it expects an additional 46,000 MW to have completed the new process.
The transition to the new study process began in mid-July when PJM opened a 60-day window for projects to meet readiness requirements, namely showing that they have site control and making deposits towards the study costs. The system of increasingly large deposits and requirements on developers as they move through the study process is meant to reduce the number of speculative projects to allow PJM staff to focus on those most likely to reach commercial operation.
Half of the 72 GW in projects expected to have their studies completed through 2025 are solar, growing to 65% when solar-and-storage hybrids are included. Standalone solar makes up a further 12.7% of project proposals, followed by offshore wind at 8.2% and onshore wind at 6.1%. Merchant transmission contributes another 5.7%, and 1,647 MW of natural gas adds 2.3%.
The amount of time to get a signed generation interconnection agreement has been cited as one of the key hurdles in bringing more capacity online, one of the challenges PJM identified in its February “4R’s” white paper. The report stated that the pace of new generation development is not set to keep pace with load growth, particularly from data centers, and generation deactivations. (See PJM Whitepaper to Highlight Future RA Concerns.)
Developers at a Solar Focus conference in November said the prospect of a project proposed today not having its study initiated until 2026, and the in-service date being as far out as 2030, has made grid-connected projects a hard sell. When looking to site solar projects in the PJM footprint, Steve Swern of Sol Systems said, multiple strategies are considered, including bypassing the queue by approaching utilities to connect to their distribution grids. (See Solar Developers Sing Mid-Atlantic Interconnection Blues.)
PJM has argued that the issues slowing renewable development go beyond the interconnection queue, stating that about 40 GW of projects have cleared the queue but have yet to be built, often because of issues with siting and permitting, procurement timelines and financing.
During a Dec. 24 Interconnection Process Subcommittee meeting, PJM’s Jonathan Thompson said projects that have been placed in the expedited queue following the completion of their readiness studies can still be shifted to TC1 if the short-circuit, stability or feasibility analyses determine that the project will require grid upgrades larger than $5 million.
Thompson told stakeholders that PJM will carry over the study deposits developers have already made to cover the initial deposits under the new process, but additional deposits will be required further into the process.
PJM also introduced the Queue Scope tool, which allows users to explore the potential transmission upgrades needed to construct a generator at specific locations and how it might impact grid congestion.
Data Center Growth, Deactivations Create Need for New Transmission
One of the largest transmission buildouts PJM has seen was given the greenlight by the board last year to address 11,000 MW in generation deactivations and about 7,500 MW of new data center load in Northern Virginia, highlighting the potential impacts of the challenges that the new stakeholder groups intend to address. (See FERC Approves PJM RTEP Projects over State Protests.)
The estimated $5 billion package of transmission projects the board approved on Dec. 11 would build lines spanning Maryland, Pennsylvania, Virginia and West Virginia, with a particular focus on bringing power into so-called Data Center Alley, around Dulles Airport in Virginia, and into Baltimore, where the retirement of the Brandon Shores generator poses reliability risks. The Brandon Shores retirement also prompted the $796 million Grid Solutions Package as part of the Regional Transmission Expansion Plan projects the board approved in July. PJM expects to update stakeholders on the status of RMR discussions with Talen Energy, owner of Brandon Shores, in the coming months.
State consumer advocates said both the December and July RTEP approvals highlighted flaws with PJM’s planning processes, which they argue leave inadequate time for stakeholders and the public to understand and comment on the final projects before they are brought to the board. Dozens of residents from regions the transmission lines would pass through objected to the proposal, citing disruption of historic communities, agricultural land and nature preserves; the inclusion of greenfield components rather than utilizing existing rights of way; the cost to ratepayers; and the possibility that the project would support load growth through 2028 but prove insufficient should Data Center Alley continue to grow.
A pocket of data centers is also driving $579.5 million in transmission upgrades in Ohio, with an estimated consumption of about 3,000 MW. Unlike the projects in Virginia, the Ohio projects would affect infrastructure below the 500-kV threshold to initiate the competitive process for soliciting proposal designs. (See “Data Center Growth in Ohio Contributing to Nearly $600 Million in Transmission Upgrades,” PJM PC/TEAC Briefs: May. 9, 2023.)
EPA on Jan. 8 announced $965 million in grants to purchase almost 2,700 electric buses in 37 states and Washington, D.C. as part of its Clean School Bus Program.
The program, established by the Infrastructure Investment and Jobs Act of 2021, will dispense $5 billion through fiscal year 2026 through rebates and grants. EPA awarded about $875 million in rebates in 2022 for replacing diesel buses with either battery electric, propane or compressed natural gas (CNG) models. (See EPA Awards US School Districts Nearly $1B for Clean Buses.) This week marked the second round of funding.
The new buses will reduce both greenhouse gas emissions and particulate matter that can cause asthma and other maladies. “Every school day, 25 million children ride our nation’s largest form of mass transit: the school bus,” Vice President Kamala Harris said in a statement. “The vast majority of those buses run on diesel, exposing students, teachers and bus drivers to toxic air pollution.”
According to the agency’s data on the awards, 95% of the funds will go toward new battery-powered buses: Of the 2,737 buses to be purchased, only 62 will be propane, and none will be CNG.
EPA said it selected 67 applicants, and that buses will go to 280 school districts, representing about 7 million students. Many of the awardees are districts and county school systems themselves, while others are bus providers and manufacturers acting on schools’ behalf. First Student, which bills itself as the “leading school transportation provider in North America” will receive the largest award — about $140 million for 366 battery electric buses across the country.
First Student CEO John Kenning said the grants will help the company meet its commitment to transition 30,000 diesel buses to electric power by 2035.
Among school districts, the largest awards of about $20 million for 50 buses each went to Boston, Miami, Los Angeles, Chicago, Clayton County, Ga. (south of Atlanta), DeKalb County, Ga. (east of Atlanta), and Beaverton, Ore. (west of Portland).
EPA noted that it will take applications until Jan. 31 for the next round of funding. Awards are expected to be announced in April. It did not say when the next round of grants or the third round of rebates would begin.
Deployment Delays
According to a report by Canary Media last month, awardees of the first round of rebates have been slow to deploy their new buses. According to World Resources Institute data, as of Dec. 29, of the more than 6,000 buses that fleet operators and school districts have committed to, only 1,862 are operating, making up 0.4% of the entire U.S. fleet.
Canary cited installing charging infrastructure — not covered by the rebates — as one of the challenges for districts. Another is needed upgrades to distribution infrastructure by electric utilities, which was the primary concern of EPA’s Office of Inspector General in a report released Dec. 27.
The IG concluded that there were no significant supply chain issues or production delays impacting EPA’s efforts to disburse electric bus funds. “However, the agency may be unable to effectively manage and achieve the program mission unless local utility companies can meet increasing power supply demands for electric school buses.”
The report noted that charging sites for 25 or more buses often require a new transformer — equipment that currently is backlogged.
In a separate report released the same day, the Inspector General criticized EPA for failing to verify information submitted in applications for federal funding, which it said “led to third parties submitting applications on behalf of unwitting school districts, applicants not being forthright or transparent, entities self-certifying applications without having corroborating supporting documentation, and entities being awarded funds and violating program requirements.”
The report noted that EPA focused on whether the supply chain, an issue hampering other clean energy industries, would delay deployment, holding meetings throughout 2022 with bus manufacturers who expressed confidence they could meet demand. The IG agreed with the agency’s finding that production would not be an issue. It found that manufacturers have hired new workers and at least one built a new plant to meet demand.
But EPA did not require applicants in the first round of funding to coordinate with their utilities to see if their systems could handle the new demand for electricity, the IG said. It did note that for the third round of rebates, EPA has required applicants to submit a Utility Partnership Agreement “to verify that the school district’s electric utility provider is aware of the school district’s rebate application.”
“The EPA needs to ensure that utilities have constructed and connected charging stations in a timely manner so that school districts’ school bus fleets … are functional,” the IG wrote.
The regional assessment of six potential projects in the New York Bight is an effort to improve efficiency and smooth the path toward the Biden administration’s goal of 30 GW of offshore wind installed by 2030.
The Bureau of Ocean Energy Management (BOEM) announced Jan. 8 that the draft programmatic environmental impact statement (PEIS) would be published in the Federal Register on Jan. 12, at which point a public comment period will begin.
A cluster of lease areas on the Outer Continental Shelf from Cape Cod, Mass., to Cape May, N.J., has been the focus of early efforts to build wind power in the United States.
There are many unknowns because there is virtually no operational experience with offshore wind in this hemisphere. BOEM has been preparing environmental impact statements — exhaustive reviews taking many months to complete and filling many hundreds of pages — for each project individually.
The PEIS announced Jan. 8 is different: Rather than a single project, it covers six lease areas totaling nearly a half-million acres stretching 75 nautical miles north-to-south in the New York Bight. The PEIS paves the way for future individual reviews.
In its conclusions, however, the PEIS is similar to the other environmental impact statements BOEM has prepared for the individual wind projects off the Northeast coast. It presents a range of possible positive and negative effects from the six projects individually, as a group of six and cumulatively with all the other offshore wind development proposed for the region.
As with most of the offshore impact statements, the predictions are a bit nebulous: maybe a minor impact, maybe a major impact, perhaps beneficial, perhaps detrimental.
The PEIS does firmly predict that all the wind farms in the New York Bight would have a major detrimental impact on ships approaching the Port of New York and other vessel traffic, cultural resources, and scientific research and surveys.
This last impact has been flagged as a problem. Not only are the effects of offshore wind development not fully understood at this point, but also, the construction itself will impair the ability to track those impacts.
But protecting the ocean remains a primary stated goal of BOEM as it carries out the administration’s directives.
BOEM Director Elizabeth Klein said in a news release Jan. 8: “We look forward to receiving additional public comment to inform this first-ever regional environmental review of offshore wind energy development on multiple leases. We are confident that this comprehensive approach can create efficiencies for future project-specific wind energy reviews in a manner that protects the ocean environment and marine life.”
The wind lease numbers covered in the PEIS, and the associated project or leaseholder names, are OCS-A 0537, Bluepoint Wind; OCS-A 0538, Attentive Energy; OCS-A 0539, Community Offshore Wind; OCS-A 0541, Atlantic Shores Offshore Wind Bight; OCS-A 0542, Leading Light Wind; and OCS-A 0544, Excelsior Wind.
The six areas hold the combined potential for as much as 7 GW of electric generation.
They are in relatively close proximity to the Empire Wind projects, the canceled Ocean Wind projects, and the Atlantic Shores projects, all of which are closer to the New Jersey and New York coasts.
With heating electrification set to spur a transformative shift away from the gas distribution system and potentially more than double Massachusetts’ annual peak electricity demand, the state’s Department of Public Utilities (DPU) has launched an inquiry into affordability for gas and electric ratepayers.
The new docket (DPU 24-15) will consider improvements to the state’s affordability programs for low- and moderate-income ratepayers.
“We need to take action now to address the challenges people bear in paying their utility bills, especially as Massachusetts transitions away from volatile fossil fuels,” said DPU Chair James Van Nostrand in a press release. “Our investigation will look at the different models that exist to reduce the burden so many of our residents face in making ends meet.”
The state’s utilities currently offer 25% rate discounts for low-income gas customers and discounts that range by utility from 32% to 42% for qualifying electric ratepayers. The utilities also offer bill forgiveness programs for eligible low-income customers.
In the new inquiry, DPU is requesting public comments to help weigh the benefits of different affordability approaches, including whether programs should be specifically designed to help environmental justice communities and neighborhoods that host a “disproportionate burden of energy infrastructure.”
“The department is creating this opportunity to hear from many voices about how it can direct changes that will lower the energy burden for low- and moderate-income residents so that people are less likely to make choices between paying utility bills and covering other essential costs,” said DPU Commissioner Staci Rubin.
As electrification spurs an influx of major investments in new generation and grid infrastructure, residents could face significantly elevated energy costs. The region also will need to cope with the continued costs associated with maintaining the gas system while customers transition to electrified heating.
Eversource and National Grid, the state’s two largest electric utilities, projected their peak loads to increase by about 150% and 130%, respectively, by 2050. (See Mass. Utilities Submit Grid Modernization Drafts.)
“This clean energy transition is going to potentially be very expensive,” Van Nostrand said at an event in December. “Given the urgency of addressing climate change, I don’t think we can slow down. … But we definitely need to take measures to address affordability.”
The DPU chair added that “affordability and energy burden is a huge concern as people migrate away from a natural gas system toward electric heat pumps — you’re going to have the same level of fixed costs recovered through fewer therms.”
In early December, the DPU issued a ruling on a multiyear investigation into the future of the state’s natural gas system, calling for “a significant increase in the use of electrified and decarbonized heating technologies.” The DPU largely rejected gas utility calls to rely in part on alternative fuels like renewable natural gas. (See Massachusetts Moves to Limit New Gas Infrastructure.)
The ruling declined to endorse specific alternative cost recovery mechanisms for potentially stranded gas assets, saying it will address that issue in a future order. The order also called for additional programs to support low-income ratepayers in the clean energy transition.
Along with enhancements to the state’s existing affordability programs, the DPU’s affordability inquiry specifically mentioned the possibility of percentage-of-income payment plans (PIPPs), which would prevent energy bills from exceeding a certain portion of income. PIPPs have been implemented in states including California, Virginia, Connecticut and Maine.
The DPU also will consider comments on program cost recovery, as well as the “role of energy-efficiency programs, consumption reduction, investment in residential loan programs for photovoltaic and battery installations, and targeted educational programs in addressing energy affordability.”
FERC on Jan. 4 approved $2.3 million in penalties against Vitol and one of its traders for manipulating CAISO‘s market in 2013 to limit losses stemming from the energy and commodities company’s congestion revenue rights position (IN14-4).
Under the agreement negotiated by FERC’s Office of Enforcement (OE), Vitol will pay the U.S. Treasury Department $2,225,000. The trader, Federico Corteggiano, who helped CAISO develop its CRR software and had previously engaged in similar manipulation while at Deutsche Bank, was fined $75,000. Houston-based Vitol is part of a global commodities trading holding company based in Geneva, Switzerland.
The proceeding began in early 2014 when OE initiated an investigation into Vitol’s October 2013 trading activity in CAISO.
FERC staff alleged that during a five-day period, Vitol sold physical power at a loss of about $4,500 in CAISO’s day-ahead market to eliminate CRR losses of up to $1.2 million, according to a 2019 show cause order. (See FERC Proposes $6.8 Million Fine for CAISO Market Manipulation.)
During the 2013 incident, Corteggiano purchased CRRs on the Cragview node, where CAISO transfers power from the PacifiCorp-West balancing authority area in far Northern California. He discovered he could cut Vitol’s losses on export congestion on the partially derated Cascade intertie by importing physical power.
“Corteggiano knew that he could likely eliminate the problematic export congestion for that week by importing physical power in the day-ahead market at Cragview,” the 2019 report reads. “Working with other Vitol employees, Corteggiano arranged to buy [5 MW of] physical power in the Pacific Northwest and successfully offered it for import at Cragview. Vitol’s imports over the Cascade intertie achieved their intended purpose, preventing export congestion from occurring during the period of Vitol’s imports…”
FERC determined that, by allowing itself to lose money on the imports, Vitol was “able to eliminate the export congestion and thereby avoid the far larger financial losses they otherwise would have incurred on the CRRs at Cragview.” FERC staff in 2019 recommended that Vitol pay $6 million and Corteggiano pay $800,000 in penalties, in addition to returning the $1.2 million in CRR savings. The proceeding then moved to a federal district court, where OE and the defendants engaged in negotiations and agreed to the terms of the Jan. 4 settlement.
Vitol and Corteggiano “neither admit nor deny the alleged violation,” and the current agreement settling the dispute orders the company to make payments within 10 days after the commission issued the order.
According to OE’s FY 2023 report, FERC approved 12 settlement agreements totaling around $48.8 million, saying that market manipulation and fraud create losses that are ultimately shouldered by consumers.
The partial solar eclipse of Oct. 14, 2023, knocked 4,500 MW of solar generation off the CAISO grid — about 1,000 MW more than the solar-power reduction seen during the August 2017 total eclipse, according to a recent report.
The result was expected given the increase since 2017 in grid-scale solar, which accounted for 16,500 MW in 2023 compared with 10,000 MW in 2017.
“The growth in solar generation since 2017 exacerbated the eclipse’s effects,” CAISO said in the report, which details system and market performance during the Oct. 14 event.
The Oct. 14 eclipse lasted from about 8 a.m. to 11 a.m. in California, with a maximum impact around 9:30 a.m. As output from behind-the-meter rooftop solar dropped, load grew by 2,064 MW from 8:25 a.m. to 9:20 a.m., peaking at about 21,000 MW, the report said.
Similar to the response in August 2017, CAISO called on other resources to make up for the loss of solar generation on Oct. 14, including gas-fired plants, hydropower and imports. (See Grid Operators Manage Solar Eclipse.)
But the Oct. 14 response included a sizable contribution from storage resources, which supplied about 1,500 MW of capacity in real-time. Storage resources also boosted regulation capacity.
“Battery storage resources, which have increased dramatically in the ISO in the past three years, played a role in offsetting the eclipse’s effects,” the report said.
Another difference between the 2017 and 2023 eclipses is that participation in CAISO’s Western Energy Imbalance Market (WEIM) has grown, from four entities in addition to CAISO in August 2017 to more than 20 entities in 2023. WEIM participants have access to a greater diversity of energy supply.
“During the eclipse, the WEIM proved to be an effective mechanism to manage conditions throughout its Western footprint by determining optimal transfers in its areas when those transfers were needed most,” CAISO said in its report.
The CAISO grid remained stable during the eclipse, and system operations returned to normal soon after it was over. (See Eclipse Barely Dims CAISO Operations.)
Steep Ramp-Up
During the partial, or annular, eclipse on Oct. 14, the moon obscured the sun by 65% to 90% within WEIM territory. Because the eclipse was on a Saturday, load was lighter than it might have been on a weekday.
The total eclipse of Aug. 21, 2017, was on a Monday and lasted from about 9 a.m. to noon in California.
On the morning of Oct. 14, solar production reached 7,731 MW before the eclipse slashed it to 3,231 MW, a drop of 4,500 MW. During the August 2017 eclipse, solar generation fell by 3,547 MW, from 6,392 MW to 2,845 MW.
From 9:30 a.m. to 11 a.m. on Oct. 14, the average ramp-up was 71 MW per minute, compared to 8 MW per minute over the same time during a non-eclipse, full-sun day. Between 9:30 a.m. and 10:20 a.m., the post-eclipse ramp-up was even steeper at 131 MW per minute.
Solar curtailment was negligible from 9 a.m. to 10 a.m., then spiked between 10 a.m. and noon before returning to normal levels.
CAISO noted that parts of California were cloudy on the morning of Oct. 14, lessening eclipse impacts compared to modeling based on clear-sky conditions.
Extensive Preparation
In addition to its pre-eclipse technical bulletin and modeling of expected impacts, CAISO reached out to WEIM participants and other entities ahead of time.
According to the new report, other preparations included:
Charging storage resources ahead of time;
Additional procurement of day-ahead commitment capacity;
Additional procurement for regulation; and
Tighter control bands to balance the system in real time.
CAISO increased its volume of exceptional dispatches in the hours before the eclipse to make sure battery resources had sufficient state of charge and that other generating resources were available to provide ramping capacity.
CAISO released the eclipse performance report last month and discussed findings during a Dec. 14 market performance and planning forum.
Lessons learned from the Oct. 14 event can be applied to the next eclipse: a total solar eclipse on April 8, CAISO staff said during the forum.
The total eclipse path through the U.S. will extend from Texas to Maine, with fewer impacts expected on the West Coast.
NuScale Power Corp. on Jan. 8 announced a change in focus from research to commercialization, with a resulting 28% reduction in its full-time workforce.
The developer of small modular reactor (SMR) technology said the strategic shift would yield an annual savings of $50 million to $60 million, minus approximately $3 million in personnel severance costs this quarter.
The announcement came two months to the day after NuScale reported cancellation of the Carbon Free Power Project, which was to be the company’s first operational SMR in the United States. (See Pioneering NuScale Small Modular Reactor Project Canceled.)
The pioneering effort was a collaboration between NuScale and Utah Associated Municipal Power Systems. It called for six 77-MW modules at the U.S. Department of Energy’s Idaho National Laboratory, the first of them targeted to come online in 2029. However, it appeared unlikely to gain sufficient subscription to be viable.
NuScale CEO John Hopkins said during a Nov. 8 conference call with industry analysts that the effort and expense the Oregon-based company had poured into the project was not lost, but an investment that will benefit future customers.
He said in a Jan. 8 news release that NuScale was making the workforce reductions and strategic changes to better position itself commercially, financially and strategically.
“Our U.S. Nuclear Regulatory-approved, industry-leading SMR technology is already many years ahead of the competition,” he said. “Today, commercialization of our SMR technology is our key objective, which includes near-term deployment and manufacturing.”
He said the company workforce would shrink by 154 full-time employees, or 28% of the 556-person workforce cited in NuScale’s 10-K annual report filed in March 2023.
NuScale’s 50-MW power module in January 2020 became the first SMR design certified by the U.S. Nuclear Regulatory Commission.
SMRs hold promise as a cleaner replacement for fossil fuel generation and a less expensive alternative to traditional nuclear reactors. Numerous cost, safety and regulatory hurdles still must be cleared before that potential is achieved.
The organizations charged with leading New York’s energy transition enter 2024 trying to build on momentum generated in the past year while recovering from its disappointments.
The state celebrated its first offshore wind generation and the first coordinated grid planning process while adding 6.4 GW of new renewable energy contracts.
But it also suffered some notable setbacks, as financial pressures endangered many of the renewable projects that had been contracted but not yet constructed. And the federal government passed over New York as it was allocating multibillion-dollar funding packages for hydrogen hubs.
And as the addition of renewable generation threatens to fall behind fossil plant retirements, NYISO issued increasingly dire warnings about capacity shortfall while the Public Service Commission opened a discussion on expanding the definition of “zero emissions” resources beyond wind, solar and storage. (See NY Renewable Portfolio May Come up Short on Getting to Net Zero.)
But state leaders remain committed in word and deed to the clean energy transition and to the generation and transmission projects that will make it a reality.
The Climate Leadership and Community Protection Act (CLCPA) mandates that New York reduce its emissions to 85% below 1990 levels by 2050 and achieve 70% renewable electricity by 2030 and 100% zero-emission electricity by 2040.
Below, NetZero Insider and RTO Insider outline what’s on the horizon in 2024 for NYISO and the three agencies central to the state’s climate efforts.
Public Service Commission
PSC Chair Rory Christian said the additional megawatts of power New York will need to meet its electrification goals mean transmission development is paramount. And it is well underway, with billions of dollars authorized for line construction.
“I don’t imagine we’ll have a lot of transmission items coming to us in 2024, but the process is a multiyear, ongoing thing, and we’ll be heavily involved in moving that forward,” he said.
He flagged New York’s first-ever coordinated grid planning process — approved by the PSC in August as a way to increase the speed and control the cost of building transmission — as one of the most significant achievements of 2023.
Also important were proactive transmission projects planned to meet future demand.
“Ensuring that those assets are built out affordably and expeditiously, that’s going to pay huge dividends in the long run,” Christian said.
“A lot of the work that we do is long-term. We issue an order, and the fruition of that may be years in the making. I look at this transmission work — I think we’re over $6 billion at this point in transmission investments that we’ve authorized this year — as probably the single most significant of the actions that we have taken.”
The Champlain Hudson Power Express, which was proposed in 2010, finally began underground construction in 2023 and promises to deliver up to 1,250 MW of emissions-free power to New York City starting in 2026.
New York Power Authority
Transmission also figured prominently for the New York Power Authority in 2023. It completed and energized major upgrades of the Smart Path and Central East Energy Connect projects, both of which will help move more power from upstate to downstate, where emissions-free power generation is in short supply.
In 2024, NYPA and its private-sector partners expect to start construction of the 175-mile underground power line that is the heart of Clean Path NY, an $11 billion package of upstate renewable energy projects linked to New York City. In the spring of 2023, a 104-MW wind farm became the first Clean Path generation asset to come online.
Perhaps the most far-reaching development for NYPA in 2023 was a contentious piece of legislation that expanded its role as a renewable energy developer.
NYPA spent the second half of 2023 gathering input on how to approach its new responsibilities and in 2024 will begin planning how to use those new powers, with plans to publish its renewable energy generation strategic plan in 2025. “We are fully engaged in embracing our expanded authority, and the entire organization is galvanized behind our commitment,” NYPA President Justin Driscoll said via email.
Along the way, NYPA will continue with the multiple smaller-scale projects it has been assisting, including high-speed chargers for light-duty vehicles, energy storage, environmental justice, building decarbonization, energy efficiency, distributed energy resources and heavy-duty chargers for electric city buses.
One milestone example in 2023: It cut the ribbon on the first utility-scale battery asset owned by the state, the 20-MW Northern New York Energy Storage Project.
The New York Power Authority’s new Northern New York Energy Storage Project is shown in May 2023. | NYPA
These smaller projects can easily be overshadowed by the high-megawatt, high-dollar projects that command so much attention, but the small projects far outnumber the large-scale projects. Smaller-scale projects also serve to make the energy transition more tangible to people who may never see an industrial-scale wind farm.
NYSERDA
About those wind farms …
2023 will be remembered as the year that planning for multiple offshore wind projects off the Northeast U.S. coast came to a screeching halt, squeezed by contracts that locked in revenue with no provision for an inflation adjustment.
Developers of four New York OSW projects said they could not proceed to construction under their current financial agreements with the state. On Jan. 3, 2024, Empire Wind 2 became the first New York project to cancel its contract. The project itself remains alive, and developers are seeking other ways to move forward with it. (See Empire Wind 2 Cancels OSW Agreement with New York.) Many of New York’s onshore wind and solar projects are in the same predicament. The situation came to a head in June, when developers of 90 projects totaling more than 12 GW sought additional compensation.
The PSC rejected the request in mid-October. That day, Gov. Hochul issued a 10-point plan to accelerate renewable energy development, although the plan was mostly a reaffirmation of existing policies and programs.
The urgency Hochul’s plan promised has been backed up with actions so far: In late October, the governor announced conditional contracts for 6.4 GW of renewable generation. In late November, the New York State Energy Research and Development Authority (NYSERDA) issued an expedited solicitation that will allow developers of those struggling earlier projects to rebid at a higher cost in early 2024.
A NYSERDA spokesperson said awards for offshore wind and Tier 1 onshore renewables projects from the agency’s expedited solicitations are expected in February 2024 and April 2024, respectively.
Also on the 2024 agenda for NYSERDA: expanding the electric school bus fleet; designing a program to distribute $317 million in home energy and electrification rebates; assessing the role of nuclear power, green hydrogen and other zero-emissions technologies in the state’s clean energy transition; continued development of a cap-and-invest program; and helping allocate $400 million in competitive federal solar grants.
In November, the ISO announced it would keep four natural gas peaker plants operational in New York City to address a 446-MW reliability deficit. The units were set to retire in May 2025 to comply with the Department of Environmental Conservation’s 2019 Peaker Rule, which imposes nitrogen oxide emissions limits on fossil fuel plants. (See NYISO to Keep Gas Peakers Online to Solve NYC Reliability Need.)
“From an operations perspective, the resources are not coming in as fast as they were originally planning to, as seen with OSW,” said Rick Gonzales, who recently retired as the ISO’s chief operating officer.
Gonzales was cautious about New York’s progress in meeting CLCPA goals, saying, “so far so good, but it’s very early in the process.” He added, “Legacy fossil fuel resources should not be retired until we have new replacement clean energy resources in place.”
Much of the concern stems from the nearly 3 GW backlog in the ISO’s interconnection queue. To comply with FERC Order 2023, the ISO is planning to move to a clustered study process, with increased penalties for projects that fail to meet milestones and more opportunities for projects to exit the queue without hindering the progress of other queued projects. Stakeholders have expressed concerns over the ISO’s proposed deposit requirements and the length of time to make project decisions. (See NYISO Stakeholders Question Proposed Interconnection Timelines, Deposit Rules.)
On a positive note, the ISO has seen an increase in renewable projects entering its interconnection queue. The 2023 class year began with nearly 100 projects, many renewable — a notable rise from the previous class year, which saw 53 projects, with only 27 being clean energy projects. (See NYISO Begins 2023 Class Year with Nearly 100 Projects.)
The ISO also has been working to increase its demand-side resources (DSRs), such as DERs, which the CLCPA says are vital to providing “a more flexible and resilient grid to address and mitigate the impacts of climate change.”
In December, the ISO announced the state had surpassed 5,000 MW of behind-the-meter solar capacity, halfway to the CLCPA goal of 10,000 MW of distributed solar by 2030.
Over the past year, NYISO has been developing rules to make New York’s markets more accommodating to DSRs.
Some stakeholders, however, have criticized the ISO’s proposals, including its 10-kW minimum requirement for DER aggregation participation and its proposed day-ahead market for some DSRs, as cost prohibitive and counterproductive. (See NYISO Stakeholders Balk at Proposed Day-Ahead Market for Demand Resources.)
The ISO’s agenda for the upcoming year is packed with projects, including dynamic reserves and capacity accreditation modeling improvements, resetting the demand curve and improving emissions transparency. However, its primary focus will be on improving the interconnection queue and integrating more renewable energy into the grid to address potential near-term reliability shortfalls.
Building on Experience
PSC Chair Christian said absent the extraordinary challenges of the early 2020s — war, disease, inflation, interest rates — projects now struggling through pre-construction development phases would have been able to progress much more easily.
Christian said the land-based renewables the state had previously authorized created a partial template for New York’s first offshore wind projects. In December, South Fork Wind became the nation’s first utility-scale project in federal waters to send power to the mainland grid.
The first turbine blades are attached at the South Fork Wind Project, the first offshore wind farm powering New York. | South Fork Wind
South Fork, in turn, smooths the path for the thousands more megawatts New York wants to generate offshore, Christian said.
“Every single time we do one of these projects, it makes the process easier going forward,” Christian said. “It’s not just the interface with the federal government. It’s everything from the legal agreements, the contractual terms, the procurement documents, the RFPs, the insurance requirement, the bonding.”
Real and Perceived Costs
The high cost of the energy transition — and the allocation of that cost — also comes to fore in a state with some of the highest electricity rates in the nation.
The PSC’s staff in July 2023 tallied $44 billion in spending authorized since passage of the CLCPA in 2019. It offered no estimate how many billions more would be needed.
Christian said he chafes at criticism of the cost of the energy transition.
New York’s electric and gas infrastructure would need major investments even if it were not going through a transition, he said. Business as usual might cost just as much as building clean energy infrastructure, he added, and it would bring none of the societal and environmental benefits.
But there are ways to minimize spending, and the PSC does pursue them, Christian said. He singled out the Brooklyn Queens Demand Management (BQDM) program as an example.
In 2013, Con Edison identified growing demand overload in a central swath of New York City’s two most populous boroughs that could reach 69 MW within five years. The new substation, switching station and feeders needed to meet this demand were estimated to cost $1 billion.
This would become the first case in which the PSC required a utility to attempt to address demand through nontraditional means. In late 2014, the PSC authorized Con Edison to deploy distributed generation and demand-side management to defer installation of the substation, with a budget capped at $200 million.
In its third-quarter 2023 report, Con Edison said expenditures to date stood at $131.3 million and peak-hour load relief had reached 61.2 MW.
“It’s been almost 10 years — that substation is still working just fine,” Christian said. “It may get upgraded at some point — in fact, it likely will. But that saved ratepayers a significant amount of money.”
The other thing BQDM did was buy time for technology development.
“Time is our friend in this scenario in many ways,” Christian said.
“I think about just the advancements we’ve seen in battery storage. They’re now an effective solution, where just 10 years ago they were marginal in many instances. The same applies for advances in charging stations, inverter technology, the list goes on and on.
“I see every reason to be optimistic about the pace of technology going forward in helping address many of the needs that we’re seeing coming up.”
FERC on Jan. 4 ordered Linde Inc. and Northern Indiana Public Service Co. (NIPSCO) to pay a combined $66.7 million in disgorgement and penalties for violating rules related to MISO’s demand response program (IN24-3).
The order approves a consent agreement between Linde and NIPSCO, which requires Linde to pay $48.5 million in disgorgement and $10.5 million in civil penalties and NIPSCO to pay $7.7 million in disgorgement. The order also mandates that Linde complete compliance training to participate in MISO’s markets in the future and outlines steps NIPSCO must take to issue refunds to affected customers.
Linde’s Calumet Area Pipeline Operations Center (CAPOC), located in northwest Indiana and distilling gases such as oxygen and nitrogen for industrial or medical use, was found to have engaged in deceptive practices within MISO’s demand response resource Type 1 (DRR-1) asset program. This resulted in unfair advantages, market price distortions and adverse effects on other market participants and consumers.
MISO operates two demand response programs, including DRR-1, which allows participants to offer load reductions during peak demand periods and receive compensation for reducing their energy use in response to grid needs.
MISO requires DRR-1 participants selling energy to “respond to the transmission provider’s directives to start, shut down or change output levels of resources, in accordance with the terms specified in the offer,” and compensates DRR-1 assets at the LMP for the difference between a unit’s baseline and its actual load.
When MISO accepts DRR-1’s asset load reduction offer, it is called an event day, while other days are called nonevent days. Only on event days are participants expected to actively reduce their load.
Linde was found to have manipulated the DRR-1 program for about five years by artificially inflating its baseline load during nonevent days and then reducing operations during event days, thereby collecting payments based on this discrepancy without changing pre-planned operations when called upon by MISO.
This manipulation created a false impression of significant load reduction at Linde’s CAPOC. In reality, Linde did not reduce its energy or consumption levels. Consequently, Linde was awarded undue payments from MISO, while NIPSCO, which earned an administrative fee equal to 5% of Linde’s DRR-1 revenues because it sponsored Linde’s participation, also received inappropriate payments and was found to be in violation.
The Linde and NIPSCO case mirrors previous incidents in demand response markets.
In October, the Independent Market Monitor for MISO advocated for new rules in the demand response program after uncovering unfair gaming strategies by some market participants. (See IMM Presses MISO for New Rules After DR Market Gaming.)
Similarly, in August, FERC fined Big River Steel, an Arkansas steel mill operator, for its multiyear manipulation of MISO’s demand response programs to obtain undue payments without actual load reduction. (See FERC OKs $21M Settlement in Arkansas Steel Mill’s DR Scheme in MISO.)
FERC’s order not only mandates that Linde and NIPSCO pay their penalties and disgorgement within an unspecified time frame for past violations, but also imposes stringent conditions on Linde for future participation in MISO’s DRR-1 program. Conditions include providing advance notification to MISO of its intentions, demonstrating evidence of compliance training and submitting annual reports on its DRR-1 activities for the next three years.
