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October 31, 2024

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Group Says Inslee, Dems Knew About Cap-and-invest Impact

A Seattle-based conservative think tank says Gov. Jay Inslee (D) knew nearly a decade ago that Washington’s cap-and-invest program — launched in 2021— would dramatically increase gasoline prices in the state. 

In 2021, Inslee and other Democrats contended that cap-and-invest — which went into effect Jan. 1, 2023 — would increase gas prices by “pennies on a gallon.” In reality, prices at the pump have increased 21-50 cents per gallon, depending on how the calculations are done. 

In a press release issued Jan. 4, the Washington Policy Center (WPC), a “free market” think tank opposed to the cap-and-invest program, noted that one of Inslee’s staff members briefed the Washington Senate’s Environment, Energy and Technology Committee in 2014, predicting that a cap-and-trade program could raise gas prices by 44 cents per gallon.  

“It has been obvious the governor and his administration knew they were lying,” Todd Myers, the WPC’s environmental director, said in the press release. 

Asked by NetZero Insider whether it was appropriate to compare 2014 and 2021 calculations on different incarnations of cap-and-trade, Myers emailed in reply: “The physics and math haven’t changed. Gasoline still emits 19.6 pounds of CO2 per gallon.”  

Myers argued that the two incarnations of the program are the same, but Democrats in the Washington Legislature made significant changes and compromises in the cap-and-invest legislation in 2020 and 2021 to get enough votes to pass the program. 

At a Jan. 4 press conference in Olympia, Inslee pointed to the challenge of predicting the movement of gasoline prices. The Washington Department of Ecology, which administers cap-and-invest, came up with the “pennies per gallon” estimate partly based on estimates from California’s cap-and-trade program. 

“Ecology made a good faith effort. It’s like a weather report — hard to predict,” Inslee said. 

The governor said the state’s experts predicted lower gasoline price increases because they expected allowance auction prices to be similar to California’s when it began its program in 2012. Auction prices have been a factor in setting gas prices. 

Washington’s quarterly settlement prices in 2023 — $48.50 to $63.03 per metric ton of emissions — were much higher than what state experts predicted in 2021. By comparison, California’s allowance prices started at $10 in 2012 and rose to slightly above $36 in 2023. 

A reason for California’s lower auction prices is that Washington is trimming carbon emissions at roughly twice the rate as the Golden State over the next decade before flattening out, according to observers. That translates to Washington having fewer allowances to auction off than California, driving up prices in the Evergreen State.  

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New Jersey Backs Geothermal Study, EV Charger Bills

New Jersey lawmakers gave final passage to bills Monday to study geothermal heat pump systems, promote electric vehicle charger installation and require clarification of the status of a residential solar system when a house is sold. 

The Senate voted 35-1 for a bill, A5442, that would direct the New Jersey Board of Public Utilities (BPU) to study the “feasibility, marketability and costs of implementing large-scale geothermal heat pump systems in the state,” and to consider creating a pilot program to evaluate their use. The Assembly approved the bill 76-1 in June. 

Each of the bills passed Monday go to Gov. Phil Murphy (D), who has until Jan. 16 to sign, or not, his office said. 

Part of the geothermal study would look at whether a financial incentive system, or other strategies such as public-private partnerships, financial investments or university involvement would, “encourage and incentivize the development and successful deployment of geothermal energy and large-scale geothermal heat pump systems.” 

The study would evaluate the costs and savings to ratepayers, government entities, electric public utilities and the state.  

Although there are 3,400 geothermal heat pump systems in operation, and a major “geo-exchange” project is coming online at Princeton University, geothermal has not been a priority for New Jersey even as it has aggressively pursued other clean energy sources, such as wind and solar.  

Advocates say geothermal projects can heat or cool air and hot water extremely efficiently by harnessing the temperature of the earth below the surface. But the up-front costs can be high, requiring deep excavation and space to bury pipes underground. (See New Jersey Moves to Embrace Geothermal Heat Pumps.) 

Clean Energy EV Charging

The Senate also gave final approval to a bill, A4794, that would set up a program to develop clean energy electric vehicle (EV) charging depots with energy supplied by one or more distributed energy resources. The bill, which passed 24-9 in the Senate, passed out of the Assembly 62-12 in June. 

The bill would require the BPU, Department of Environmental Protection (DEP) and Economic Development Authority (EDA) to issue a request for proposal (RFP) seeking entities to set up demonstration depot projects in six locations around the state. The bill makes each project eligible for $2 million in unspecified “assistance.” 

At least one depot would be required to be located in the area covered by each of the state’s four electric utilities, and the bill directs the agencies to favor projects that result in the installation of direct current fast chargers (DCFCs) and creates opportunities for charging medium- and heavy-duty vehicles and fleets. 

Other criteria set out in the bill that would make certain depot locations preferable to others include those located on brown fields, those that are publicly accessible or can serve public-serving fleets, and those that charge private fleets that serve overburdened communities. Also identified as preferable in the bill are projects that manage a charging program at peak periods or minimize demand charge peak. 

The Assembly also sent to the governor with a 31-2 vote a second bill, A4715, designed to make EV charging stations more accessible.   

The bill requires that any charging station that receives financial assistance from the BPU, DEP, Department of Transportation or any other state agency be operational at least 97% of the time. It also requires the state agencies to monitor compliance with the law and enforce it.  

The bill, which passed the Assembly with a 53-23 vote Monday, secured Senate approval by 35-1 in June.  

Easing Community Solar Accessibility

A third bill, S3234, given final approval by the Senate in a 36-0 vote, seeks to inject transparency into the status of a solar system mounted on a single-family home when it is sold. 

The bill, which the Assembly backed 78-0 in June, requires the contract with the purchaser to include the name and contact information of the developer that installed the system. It also requires the contract to “contain clear and precise language regarding if the owner selling the home is transferring the lease of the panels to a new residence or to the buyer of the home contracted for sale.”  

If the lease is going to be transferred to the new property owner, the name and details of the developer that installed the panels must be disclosed. 

Property owners who misrepresent or make false claims about the company that installed the solar system or who transfers the responsibility of a leased solar system to the buyer can face a penalty of up to $1,000 under the law. 

The legislative approval followed the signing by Murphy on Thursday of a bill, S3123, that will make it easier for ratepayers — especially low-income subscribers — to sign up to receive energy from projects developed in the state’s community solar program.  

The bill’s passage followed the enactment by the BPU of a permanent Community Solar program on Aug. 16, after two rounds of pilot programs that attracted extensive developer interest. (See NJ Opens Community Solar and Nuclear Support Programs.) 

The bill sets out similar annual capacity targets to the BPU program: 225 MW each year in the first two years and 150 MW each year after. It also allows low- and moderate-income residential customers to self-attest to their modest incomes in the application process to become a Community Solar subscriber. 

The state program requires that 51% of the subscribers to a Community Solar program have a low or moderate income. Developers have for a while argued that many eligible ratepayers either do not have the documentation required to prove their income level or are reluctant to divulge personal details, which made it difficult for them to reach the subscriber targets. 

“The Community Solar Energy Program isn’t just about achieving our clean energy goals — it is also about enabling households that ordinarily would not be able to reap the benefits of solar power to do so, such as renters or families whose homes cannot support solar panels,” said state Sen. Linda Greenstein (D-Cranbury), a sponsor of the bill. “Families that choose to participate can annually save hundreds on their utility bills, and with the Governor’s signature, those savings will be felt by thousands more across New Jersey.” 

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Eversource Takes Hit of up to $1.6B on Offshore Wind

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.

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PJM Tackled Market Changes and Transmission Expansion in 2023

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 Deactivation Enhancements Senior Task Force and Reserve Certainty Senior Task Force were both formed by the Markets and Reliability Committee in September, and the Long-Term Regional Transmission Planning Workshop began its work in July. (See PJM MRC/MC Briefs: Sept. 20, 2023.) 

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.) 

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EPA Awards $965M in Grants from Clean School Bus Program

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.  

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Impacts of Six Potential OSW Projects Previewed

Federal regulators have issued their first-ever environmental impact evaluation of multiple offshore wind lease areas.

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.

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Mass. DPU Launches Affordability Inquiry

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.”

Stakeholder comments are due March 1.

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Vitol to Pay $2.3M for CAISO Market Manipulation

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. 

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Report Details CAISO Response to Partial Solar Eclipse

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. 

In a preeclipse technical bulletin issued in late August, CAISO expressed concern about the steep ramp-up of solar generation that was expected as the eclipse waned. (See CAISO Sheds Light on October Solar Eclipse Preparations.) 

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. 

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NuScale Refocusing from R&D to Commercialization

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.