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July 22, 2024

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Oceantic Recaps Glum 2023, is Optimistic for OSW in 2024

The industry gyrations of 2023 have put near-term U.S. offshore wind goals out of reach, but the sector will rebound, its trade organization reports. 

The Oceantic Network issued its “2024 U.S. Offshore Wind Market Report” on Feb. 20. 

Looking back, it concludes the first-ever flow of electricity from a utility-scale project to the U.S. mainland, while a landmark moment, was one of the few bright spots in 2023.  

The U.S. market began the year with 17.6 GW of slated offshore wind capacity, but developers terminated contracts for 51% of that amount and sought financial support for another 24% amid soaring coasts and supply chain constraints.  

This had a chilling effect on the nascent domestic supply chain and industrial infrastructure that must develop if the U.S. offshore wind industry is to grow to maturity, benefiting the U.S. economy and environment at a sustainable cost to ratepayers and taxpayers. 

The delays, price hikes and other fallout continue as states and developers try to regain the momentum of the early 2020s.  

Officials have been putting a resolute face on the situation or sidestepping questions about their aspirational timelines, but Oceantic was blunt in its report:
 President Biden’s goal of 30 GW of offshore wind installed by 2030 is now out of reach, it said. 

Oceantic remains optimistic about the industry’s prospects, however, and sees its recovery already beginning. 

As she announced release of the report to Oceantic’s 600-plus members, CEO Liz Burdock said: 

“Global economic challenges hindered our progress in 2023, bringing uncertainty to this new and growing market. However, with each step back, we’ve seen the industry press forward and are seeing a transformation in market fundamentals. New power contracts that are resistant to broader economic pressures are being executed and states like New York, New Jersey and Massachusetts remain dedicated to offshore wind development and investing in a domestic supply chain. In 2024, we are seeing the market rebound with interest rates and inflation falling along with new supply chain capacity.” 

The fundamental strengths of the U.S. market remain unchanged, the report says. It’s the details that have been scrambled. 

Signs For Concern, Optimism

To strain a metaphor, the U.S. offshore wind industry has a chicken-and-egg problem — but with chickens that cost hundreds of millions of dollars apiece and eggs that take years to hatch. 

To generate economies of scale and lasting momentum, the industry needs certainty that someone will build its components and provide the machinery to install them. To commit to that, manufacturers need certainty that a given project will be built, or at least financed.  

There were failures on both sides of the equation in 2023: Multiple offshore wind projects were put on indefinite pause and multiple supply chain bottlenecks appeared. 

Completion delays on a new installation vessel were a big part of Ørsted’s decision to end Ocean Wind I and II, the first and so far only outright cancellation in the present era of U.S. offshore wind development. 

Oceantic’s report highlights multiple failures in the past year and multiple signs of optimism for the years ahead, including: 

    • Federally permitted projects jumped from 0.93 to 8.3 GW in 2023 and could reach 14 GW by the end of 2024. 
    • States are pressing to replace canceled contracts and could reach 20 to 25 GW under contract by the start of 2025, which would be a rebound from the 17.6-GW peak before cancellations started. 
    • Domestic manufacturing has begun, including underwater export cable and the first-ever U.S.-built offshore substation. 
    • The first-ever wind energy auction in the Gulf of Mexico was a flop in 2023, generating limited interest and minimal revenue. Three or more auctions could be held in 2024. 
    • Multistate collaboration has begun even as individual states inevitably compete with others for limited resources. Three regional clusters — Connecticut-Massachusetts-Rhode Island, New Jersey-New York and Maryland-North Carolina-Virginia — are working together in some capacity. 
    • Some investors may choose to remain on the sidelines to await the results of the 2024 elections, which could have a significant impact on federal support for offshore wind development. Others might see an inviting market. 
    • The manufacturing and shipbuilding sectors are seeing multiple positive signals in 2024, including falling interest rates, stabilizing prices, issuance of tax credit guidance and multiple large state offshore wind solicitations being underway. 
    • Installation timelines have been significantly delayed; market analysts project only 14 to 16 GW of installation by 2030. 
    • Inflationary pressures are unlikely to ease any time soon but may not get worse in 2024. 
    • Compensation is rising: The awarded strike price in the 2023 solicitation was 28% higher on average than the 2021 awards in New York and 40% higher in New Jersey. 
    • The U.S. Department of Energy issued its Atlantic Offshore Wind Transmission Action Plan in 2023, addressing one of the most pressing needs for the entire endeavor: Getting those new megawatts to market. 
    • In late 2023, South Fork Wind became the first utility-scale offshore wind farm to send power to the U.S. grid. Vineyard Wind soon followed. South Fork expects to wrap construction next month. Vineyard is larger and will take longer. Installation work is set to begin this year on Revolution Wind and Coastal Virginia Offshore Wind. 
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Wash. Lawmakers Propose Credits to Defray Cap-and-invest Costs

Washington legislators are proposing to give the state’s utilities $150 million to be rebated back to residents to help them defray costs associated with the state’s cap-and-invest program.  

The proposals come after Washington last year grappled with some of the highest gasoline prices in the country, which cap-and-invest opponents attributed to the rollout of the program early last year. (See Cap-and-invest to Loom Large in Wash. Legislative Session.)  

Democratic legislative leaders in both chambers unveiled similar $150 million clean energy credit programs Feb. 19 in two supplemental 2023-2025 budget proposals that must be reconciled before the current legislative session ends March 7.  

If the funding is approved, the money will go to utilities, which have increased rates partly due to expenses stemming from the cap-and-invest program, then credited back to utility customers.  

In the Senate, Ways and Means Committee Chair June Robinson (D) and Sen. Joe Nguyen (D) said lawmakers will have to hash out details related to the size of individual credits and the income thresholds for eligibility to receive them.  Robinson speculated the credits would likely be distributed to residents in the fall. 

Lawmakers in the House have proposed a one-time $200 credit to eligible households in September. 

The credit programs have been proposed ahead of a looming referendum to be held in November on whether to repeal the cap-and-invest program.  

In December, Gov. Jay Inslee (D) asked the Legislature to establish a rebate program for lower- and middle-income residents to counteract the higher-than-expected gasoline prices being linked to cap-and-invest. Inslee called for a one-time $200 credit applied to the utility bills of roughly 750,000 low- and moderate-income households. Rep. April Connors (R) introduced a bill similar to the governor’s request, but it never received a committee hearing. 

‘Really Suspicious’

At a Feb. 20 press briefing, Washington GOP leaders criticized the timing of the proposed rebate, characterizing it as an election ploy by the Democrats. The Republicans contended the rebate will occur prior to the election with no legislative guarantees of future rebates if voters repeal the cap-and-invest program in November. 

“Let’s be candid on how much $200 will help …  It’s not much … It’s a little like electioneering,” said Senate Minority Leader John Braun (R).  

House Minority Leader Drew Stokesbary (R) echoed that view, saying the timing of rebate “is really suspicious.” 

“I wonder how Representative Stokesbary will pay for [the rebates] if we revoke the Climate Commitment Act,” House Majority Leader Joe Fitzgibbon (D) said at a later briefing by Democrats.  

Democratic leaders also responded to Republican criticism of Sen. Marko Liias (D), chair of the Senate Transportation Committee, who said repealing the cap-and-invest program will hurt the state’s transportation budget. GOP leaders countered that the transportation budget is independent of the cap-and-invest program. 

But Senate Majority Leader Andy Billig (D) noted the cap-and-invest program pays for transportation expenses such as free transit for residents under 18 and some of the conversions of the state’s diesel ferries to hybrid electric vessels, programs the Democrats do not want to revoke.  

If the cap-and-invest revenue is eliminated, the limited transportation budget will have to pay for transit and some ferry finances currently supported by the Climate Commitment Act, Billig said.  

“We will have to reprioritize everything in transportation,” he said. 

Liias noted that cap-and-invest money is paying for roughly one-third of the supplemental transportation budget that the Legislature is currently assembling.  

Washington raised about $1.8 billion in its 2023 cap-and invest auctions, money the Legislature is allocating toward clean energy development and programs that mitigate the impacts of climate change, particularly in disadvantaged communities. The Inslee administration is predicting the auctions will raise another $941 million in the first six months of 2024. 

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EEI Briefs Wall Street on Business and Policy Goals for 2024 and Beyond

The Edison Electric Institute’s senior executives briefed Wall Street on Feb. 20 on the state of the utility industry and some of the policies it supports. 

The briefing was the first for EEI CEO Dan Brouillette, who joked that many in the audience were expecting former CEO Tom Kuhn, who retired at the end of 2023. Brouillette came to EEI from Sempra Energy after serving as energy secretary under President Donald Trump. As a staffer in Congress, he helped write the Energy Policy Act of 2005. 

“This is an exciting industry,” Brouillette said. “And there’s never been a more exciting time to be a part of it. What is happening today, I think, is truly transformational. We talk a lot about the energy transition; we talk about the changing generation sources. There’s even more to it than that.” 

EEI members make up 5% of the economy, which Brouillette called the “first 5%” because they contribute to all the other sectors. The utility sector is seeing growth for the first time in years, he said, with residential customers using electricity more and more for heating and transport, and new demand from commercial and industrial customers as data centers expand because of artificial intelligence, battery manufacturing, microchip factories and reindustrialization. 

“There are challenges ahead for the next several years,” said Philip Moeller, EEI executive vice president of regulatory affairs. “But it’s a pretty good challenge to have, when you’re looking at the kind of growth that a lot of our member companies are looking at.” 

New England, the Midwest and the West have been facing resource adequacy issues in recent years, but with the rapid growth in demand recently, most of the country needs to build more infrastructure to keep pace, he added. 

Member utilities have gotten creative in how they approach regulators on how to meet the new demand, bringing in large new customers like data centers to explain what is driving the need, EEI Chief Strategy Officer Brian Wolff said. 

“They are starting to get the rhythm of taking those customers in with them to be able to explain what the need is,” Wolff said. “Because as you know, regulators are first and foremost about customer affordability. So, they’ve really got to be able to make the case for that, and there’s nothing better than hearing from somebody else in the community about how important that is.” 

EEI is expecting several final rules from federal agencies, especially EPA, to come out this spring, well before the end of President Joe Biden’s term, as they want to avoid the possibility of the next Congress overturning them through the Congressional Review Act, General Counsel Emily Sanford Fisher said. The rules include an update to the Mercury and Air Toxics Standard, which the industry has already exceeded, she said, along with the effluent limit guidelines on water pollution and another rule on coal combustion residuals. 

But the big item coming out of EPA is its new rule on carbon emissions from power plants under Clean Air Act Section 111(d). Fisher said EPA successfully implementing the carbon rules affordably and reliably will require it to be flexible in when plants retire, with the transition to clean energy moving faster some years than others depending on the grid’s reliability needs. 

That would ensure “that we don’t need to make big control investments in units that will either accelerate their retirement in ways that are unhelpful from a reliability perspective or encourage folks to run those like into the 2040s to recover their investments,” Fisher said. “There’s a happy medium there, and I hope we can land that plane.” 

Fisher expects the final rule to use either carbon capture and storage or clean hydrogen as the requirement for clean power plants, both of which offer the industry-needed 24/7 clean energy production. 

“We need that 24/7 clean to balance the grid and to address reliability, and the fact that those technologies aren’t available at cost and scale right now is actually one of the contributors to our concerns about resource adequacy,” Fisher said. “If we had more of those technologies available to us, I think some of those concerns would be lessened.” 

The industry has wanted to see new permitting laws to help make it easier to build out the infrastructure subsidized by the Inflation Reduction Act and Infrastructure Investment and Jobs Act, but Wolff said not to expect anything until at least a lame duck session after the November elections. 

“If we’re not really moving to agree to fund the war in Ukraine, you can imagine how the rest of the oxygen has left the Congress with regards to getting something actually done,” Wolff said. “And at the end of the day, whether you’re a Republican in the House or a Republican in the Senate, you don’t want Joe Biden to be signing one more piece of legislation into law.” 

While many Republicans have called for the repeal of the IRA and IIJA, Brouillette said he doubted either would go away entirely if the GOP wins in November. Money from both is flowing to red states, where it often is easier to get a permit to build infrastructure. 

“So of course, the money is going to continue to flow to places like that,” Brouillette said. “What that means, obviously, is that there’ll be support for those programs in Congress going forward.” 

Some of the programs the law funds, like hydrogen, have been important to the industry and others for years, so they are unlikely to be swept away in a Republican electoral wave. Likely changes could come if Republicans are in charge of the appropriations process for some of the long-term programs under the laws that will need to have future funding approved. 

“If Republicans take both the House and the Senate and the White House, you’ll see some changes,” Brouillette said. “But I would dare say that those changes will be largely at the margins, not at the heart of what was passed in the IRA.”

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RMI Report: GETs Could Speed Renewable Development, Save Consumers Billions

An RMI study into the applicability of grid-enhancing technologies (GETs) on the PJM grid found they could save consumers hundreds of millions of dollars a year and speed renewable development when used as an alternative to reconductoring and rebuilding lines. 

“With growing demand for electricity to power our lives and an influx of clean energy projects under development, the U.S. grid needs to expand, fast. Grid-enhancing technologies can be deployed in a matter of months and offer a multifaceted solution — they unlock greater efficiency on the grid, keep electricity rates down and enhance reliability throughout the energy transition,” Katie Siegner, RMI electric sector expert, said in an announcement of the study. The study was funded by Amazon and included analysis by Quanta Technology. 

The study, released Feb. 15, looked at how dynamic line ratings (DLRs), topology optimization (TO) and advanced power flow controls (PFCs) could be used in the analysis PJM conducts to determine network upgrades required for generation interconnection requests. It modeled the feasibility of using the technologies for projects in the PJM interconnection queue and compared costs to reconductor or rebuild lines to GET alternatives. 

Some of the greatest cost-saving potential came from PFCs, which modulate the reactance on a line to redirect power from congested lines to those with available capacity. The study identified 69 transmission overloads that could be addressed by flow controllers, with the potential to reduce interconnection costs for associated projects by $523 million over reconductoring or rebuilding lines. PFCs are limited to circumstances where there would be multiple paths for power to flow and are best suited for transmission under 550 kV. 

The study found DLRs were applicable to 49 overloads and could reduce costs by $504.5 million by increasing line ratings under favorable conditions. The technology uses sensors and existing data about installed infrastructure to change line ratings based on how factors such as wind speed, air temperatures and conductor sag can affect the amount of power a line can handle before overheating. Although overall summer line capacity could be increased by 17% over current static ratings, the study acknowledges dynamic ratings vary with the weather and therefore are more suited to making energy deliverable than bringing new capacity online. 

Topology optimization could reduce the cost to alleviate 72 overloads by $273 million by using software to determine alternate grid configurations that reroute power around constraints, such as opening or closing breakers automatically. 

The report states GETs can significantly reduce the amount of time to make the necessary grid adjustments to bring new generation online, addressing concerns PJM has raised about the balance of deactivations and new resource entry, as well as reducing energy costs by speeding development of low-cost renewables. It estimates ratepayers could save $1.1 billion in annual production costs by 2033 against a $0.1 billion installation cost for GETs. 

“These findings make a compelling case for more widespread deployment of GETs in PJM, where today there are only a handful of pilots and proposed projects. PJM and its stakeholders have an opportunity to spur broader uptake of these technologies by leveraging the growing proof points, modeling tools and changing regulatory landscape that are driving GETs adoption,” the study said. 

It calls for PJM and utilities to train staff in GET deployment and for regulators to draft new guidance and oversight for their usage, arguing adoption in the U.S. is behind Europe due to a lack of understanding and few incentives to seek cheaper transmission options. Generation developers also can benefit from evaluating GETs as an alternative to PJM’s recommended network upgrades for their projects. 

There have been some inroads for DLR usage in PJM, in which a pilot program to install the technology on PPL’s Juniata-Cumberland line resulted in line capacity increasing 18% under normal conditions and 10% under emergency conditions, Joseph Lookup, PJM’s director of asset management, told RTO Insider last year. (See Grid-enhancing Technologies Poised for Growth with Federal Funds.) 

Speaking in the announcement of the study, Alexina Jackson, AES vice president of strategic development, said it presents an opportunity for greater understanding of how new technologies can benefit the grid. 

“There are numerous market-ready technologies that can optimize our electrical grid and accelerate the future our customers need. Realizing how to model the functionality and quantify the benefits of these technologies is a barrier to the implementation of grid-enhancing technologies,” she said. 

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Fossil Retirements to Slow Briefly as Solar and Storage Proliferate

The U.S. Energy Information Administration reports that fossil fuel generation retirements will slow in 2024 and that solar and storage will dominate capacity additions. 

The two forecasts represent a pause and an acceleration, respectively, of recent trends. 

EIA said Feb. 20 that operators plan to retire 5.2 GW of capacity this year, most of it coal- or natural gas-burning plants. Coal retirements alone totaled 22.3 GW in the past two years and are expected to total 10.9 GW in 2025. 

EIA said Feb. 15 that developers and power plant owners plan to add 62.8 GW of new utility-scale capacity in 2024. Almost all scheduled additions are emissions-free power sources, including a record 36.4 GW of solar. That would nearly double the 2023 total of 18.4 of new solar, which itself was a record. 

Retirements 

Fossil fuel generation has been retiring rapidly, so much so that some grid operators have begun issuing warnings about potential capacity shortfalls. (See NYISO to Keep Gas Peakers Online to Solve NYC Reliability Need and PJM Requests 2nd Talen Generator Delay Retirement.) 

The 5.2 GW scheduled for retirement in 2024 would be the least since 2008 and would be down 62% from 2023, when 13.5 GW was retired. Forecast for retirement in 2024 are plants totaling 2.4 GW of natural gas, 2.3 GW of coal, 450 MW of petroleum and 20 MW of other power sources. 

The largest gas retirement will be the last six units (1,413 MW) at the Mystic Generating Station outside Boston, one of the nation’s oldest power plants. The other large gas retirement scheduled is TVA’s Johnsonville station (754 MW). 

The largest coal retirements will be Seminole Electric Cooperative’s Unit 1 in Florida and Homer City Generating Station’s Unit 1 in Pennsylvania, both 626 MW. 

Almost all of the petroleum-fired capacity retirement will be at TVA’s Allen plant, which has 20 old combustion turbine units totaling 427 MW. 

Construction 

EIA forecasts heavy growth in renewable energy development in 2024 — particularly in photovoltaics, which is outstripping other generating resources as supply chain challenges and trade restrictions ease. 

The planned additions break down to 36.4 GW of solar, 14.3 GW of battery storage, 8.2 GW of wind, 2.5 GW of natural gas and 1.1 GW of nuclear, plus about 200 MW from other sources. 

Slightly more than half the nation’s 2024 utility-scale solar construction is planned in three states: Texas (35%), California (10%) and Florida (6%). Elsewhere, the nation’s largest single solar project — the Gemini facility in Nevada, with 690 MW of solar capacity and 380 MW of battery storage — will start to come online this year. 

Battery construction also could set a record: 14.3 GW of grid-scale storage capacity added in 2024 would nearly double the installed capacity nationwide, which stood at 15.5 GW at the start of this year. The heaviest battery development is expected to be in the states with the heaviest solar development: Texas (6.4 GW) and California (5.2 GW). 

Wind energy is the outlier in the report. Wind capacity addition has slowed after record construction of 14 GW-plus in both 2020 and 2021. The big news in U.S. wind energy in 2024 is likely to be the Vineyard Wind (800 MW) and South Fork Wind (130 MW) projects, the nation’s first utility-scale offshore wind farms. Both are nearing completion off the Northeast coast. 

The 2.5 GW of natural gas additions planned in 2024 is the lowest total in a quarter-century. Also notable: 79% of the gas capacity added in 2024 will be simple-cycle turbines, which can start up and ramp up or down relatively quickly to support the grid at times of fluctuating demand or faltering supply from wind and solar generation. This will be the first year since 2001 the slower but more efficient combined-cycle turbine technology did not account for most capacity additions. 

EIA forecasts a relatively small amount of fossil fuel generation retirements in 2024. | EIA

Finally, start-up of the fourth reactor at the Vogtle nuclear plant in Georgia, originally scheduled for 2023, now is slated for 2024. 

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NJ Launches Electric School Bus Program With Bidirectional Incentives

New Jersey is encouraging school districts to consider “bidirectional” charging systems that use electric school buses for energy storage under the state’s new $45 million three-year pilot program to put electric school buses in 18 school districts. 

The Legislature in December approved funding for the electric school bus program, 18 months after Gov. Phil Murphy (D) signed legislation enacting the pilot. The state Department of Environmental Protection (DEP) opened the program application process Feb. 1 and in recent weeks has held three webinars to guide potential participants through the application process. The deadline for applications is May 17. (See: New Jersey Senate Advances Electric School Bus Pilot Program.) 

The last webinar Feb. 14 provided a deep dive on bidirectional charging, outlining the benefits and incentives available for vendors and school districts that draw on bus batteries to power school buildings at certain times of day. 

New Jersey does not allow electric buses to send electricity directly to the grid. But the program offers up to $50,000 in additional support for projects that use a “vehicle-to-building” (V2B) strategy. According to the project solicitation guidelines, these incentives are “intended to both encourage projects which increase electric grid resilience and to add value to electric school bus investments.” 

Speaking at the Feb. 14 webinar, Gilbert Botham, a senior economic advisor for the DEP, said using buses as storage would enable the districts to cut the cost of powering its buildings. Districts could charge the bus batteries during cheaper overnight hours and use the power during the late afternoon or evening, when the building otherwise would be drawing electricity from the grid at higher rates, he said. 

“Your electricity bill from the utility should go down due to the decreased demand” in power from the grid because the bus battery is meeting the need, he said. After dropping off the final students in the afternoon, the electric bus may be at 30% charge, he said, adding that “you can use that last 30% to arbitrage down to zero and then charge overnight on cheap electricity.” 

Studies show electricity usage peaks in Northeastern states about 6 p.m. and drops off dramatically by midnight. 

“In the case of an emergency, you can actually use your electric school bus. It’s a giant rolling battery,” Phillip Burgoyne-Allen, an associate with the electric school bus initiative at the World Resources Institute (WRI), said at the DEP’s first hearing Feb. 1. 

“If there’s a large power outage for an extended period of time, you can use that bus battery to help charge a gymnasium or cafeteria or some other emergency shelter,” he said. 

Feasibility Testing

School districts, or vendors working with them, can apply under New Jersey’s program for financial support to lease or buy between two and 24 new electric buses ― either a 44-seat C-type bus or 70-seat D-type bus ― with a range of at least 90 miles. Applicants could receive $270,000 for a bus purchase and accompanying Level 2 charging station installation, and $290,000 for a bus and direct current fast charger (DCFC), with an additional subsidy of $30,000 if the district is in an overburdened community. 

The program incentive rises to $320,000 for a bus purchase and an accompanying bidirectional charging system that is capable not only of charging the bus but of sending electricity in the other direction so the bus effectively can be used as a storage facility. 

A single entity can apply for funding for 16 buses under the main program, and another eight buses under the bidirectional charging pilot. 

Projects that are funded as bidirectional pilots must use the technology at least six days a year. These are defined in the program guidelines as “uptime days” in which the electric bus is plugged into the charging station by, at latest, 5 p.m. with bidirectional functionality enabled until midnight of that calendar day. 

The school district can receive additional incentives if the bus is available for uptime days beyond the six required, with $5,000 awarded for two additional days in the first year of the program, $5,000 awarded for four additional days in the second year and $10,000 for an additional six days in the third year. 

School buses are particularly attractive for such a strategy due to the lengthy summer holidays and spring and winter breaks in which they often sit idle. 

Botham said the incentive structure is designed to give the DEP insight into the usefulness of bus batteries as storage. 

“We have to make sure that we get data from these buses,” he said. “That is one of the biggest things … that we are really wanting to understand: Is this possible? How is this possible? And what data can we derive from this to help the state understand the feasibility of this technology?” 

If the project demonstrates the feasibility of using electric school buses as storage, the state could consider “a second phase of the program which would demonstrate the feasibility of selling electricity from the bus back to the grid during peak demand, creating a fully integrated bidirectional system,” according to the current program guidelines. However, that kind of expansion would require regulatory approval. 

Rapid Impact

The opening of the pilot program follows years of planning, during which environmentalists have argued New Jersey is behind where it needs to be in terms of introducing electric buses, and creating a pilot ― rather than a program ― for electric buses will just delay the state further. (See New Jersey Legislators Back $45 Million EV Bus Bill.) 

According to the most recent figures from WRI, the nationwide count for electric school buses as of June 2023 was 2,277 vehicles ordered, delivered or in operation. 

The corresponding figure for New Jersey is 21 electric school buses ordered, delivered, or in operation, spread across six school districts, Burgoyne-Allen said. School districts have committed to buying another 200 electric buses, and funding of about $20 million has been allocated to electric school bus purchases, he said. 

Electric buses still cost at least three times the $110,000 to $125,000 price of a diesel bus, but WRI, a research and data organization that advocates for electric school bus use, expects the cost of electric buses to decline, especially the battery cost, Burgoyne-Allen said. 

“We anticipate that as the technology improves, as the pricing improves, that these buses are going to be even more competitive with diesel buses on a pricing front,” he said. 

Still, he added, even if a school district gets incentives that cover 90% or 95% of the cost of an electric bus, “coming up with the 5 or 10% can be a challenge.” 

New Jersey’s program allows the state funding to be combined with federal tax credits, which can reach $40,000 for eligible vehicles, the DEP said. 

WRI also is seeing a reduction in the delays that have characterized some school bus purchases in the past, with the wait from order to delivery stretching out a year or 15 months, Burgoyne-Allen said. 

“There have been a lot of supply chain issues,” he said. “But we’re seeing those increasingly get sorted out. We’re seeing manufacturers increasing their production capacity on electric school buses and opening new factories and expanding factories so that they can bring these buses to the road on a faster pace.” 

Once deployed on school routes, the buses can make a rapid impact, Tim Farquer, superintendent of Williamsfield Schools in Illinois, said at New Jersey’s Feb. 1 webinar. His district has operated five school routes with electric buses since November. Over about 23,000 miles of operation, the district has used 21,000 kW of electricity and spent about $500 in fuel costs. Adding power from a district solar array, final costs are well below the $14,000 that would have spent on diesel, Farquer said.  

“We’re getting better numbers than we anticipated,” he said. “We’re just burning a little over one kWh of electricity per mile traveled.” 

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Berkeley Lab Reports Narrowing Income Gap on Residential Solar

The 2023 edition of a federal rooftop solar demographic report finds the median household income of people installing solar systems has decreased but is still well above the median American household income. 

The Clean Energy States Alliance held a webinar Feb. 15 to discuss the data in the report, which is designed as a reference for policy makers and industry stakeholders. 

The Lawrence Berkeley National Laboratory’s “Residential Solar-Adopter Income and Demographic Trends: 2023” is based on address-level data for 3.4 million residential solar systems installed through 2022, covering about 86% of residential systems. 

Key takeaway points from the report:
 

    • The documented income disparities are due in part to the rooftop solar industry concentrating on high-income states. 
    • Residential solar adopters are diverse, but many share a few common traits — they own a single-unit residence, occupy a higher income bracket, hold jobs in the business or finance sector, are middle aged and do not reside in a disadvantaged community. 
    • The differences between solar- and non-solar households are diminishing gradually as the industry reduces prices and expands into lower-income states and disadvantaged communities. The emergence of policies and business models that support broader adoption also helps. 

Researchers found that Americans installing rooftop solar systems most often have higher incomes and own a single-family house. | Lawrence Berkeley National Laboratory

Report co-authors Galen Barbose, Sydney Forrester and Eric O’Shaughnessy explained some of the findings during the webinar. 

Barbose said the income gap between solar and non-solar is not as wide as it initially seems. 

Median household income of solar adopters in 2022 was $117,000, compared with just $69,000 for all U.S. households. 

But the median income was $86,000 for U.S. households that occupy housing they own, which is a better metric, because 94% of rooftop solar installations were on single-family owner-occupied homes. 

Finally, the average owner-occupied income rises to $98,000 nationally once weighted for the number of solar installations in each state. 

That’s not to say everyone with a solar panel on their roof earns a lot of money: In 2022, 43% of solar adopters had household incomes less than $100,000 and 12% reported incomes of less than $50,000. 

“The main takeaway here is that solar adopters come from all parts of the income spectrum,” Barbose said. 

“When thinking about these trends, we like to distinguish between two underlying dynamics that are at play: a broadening of solar markets as solar adoption expands into new parts of the country, as well as a deepening, where even within established markets, we see solar increasingly reaching less affluent households within the region.” 

Median income for solar households dropped from $140,000 in 2010 to $117,000 in 2022. Over the same period, the percentage of rooftop solar adopters living in designated disadvantaged communities doubled from 11% to 22%. 

One shortcoming of the data is that it cites mid-2023 income, rather than income at the time the solar panels were installed. It also does not account for ownership transfer: Some residents of solar-equipped houses bought those houses well after the panels were installed, so their income and other demographics had no bearing on the decision to install solar. 

Forrester drilled down on three pronounced trends in the report:  

Each of the successively higher income brackets presented had successively larger photovoltaic systems on average, successively higher rates of battery storage installed on site, and successively higher rates of ownership of the equipment, rather than leases or power-purchase agreements with a third-party owner. 

In states other than California, median system size was 7.2 kW for households with annual income less than $50,000, gradually increasing to 9.2 kW for those with annual incomes above $200,000. This can be due to the higher cost of larger systems, the larger roof area often available in more expensive homes and the higher electrical demand often seen in higher-income households, Forrester said. 

(California is a category unto itself, a high-income state that accounts for 42% of the installed systems analyzed nationwide in the report. It is not an accurate snapshot of America.) 

O’Shaughnessy said the lower rate of solar adoption by lower-income households often reflects not a lack of interest in solar but a lack of money to pay for it. 

Berkeley Lab analyzed this issue a few years ago, he said. 

Looking at the incentives offered to low- and moderate-income (LMI) households, researchers found evidence “that not surprisingly, incentives do work. The catch there is that LMI incentives tend to be very small. So, it’s not really a scalable solution,” O’Shaughnessy said. 

“Leasing or third-party ownership, a model that allows homeowners to adopt solar with no or little money down, the evidence suggests that was probably the biggest factor that opened up the market to LMI households,” he said. “That is also a policy decision — not every state allows third-party ownership.” 

O’Shaughnessy added: “We continue to look at questions of why there is lots of low-income adoption in certain places, not others.”  

Data for the report were gathered from the U.S. Census Bureau; the U.S. Bureau of Labor Statistics; the White House Council on Environmental Quality’s Climate and Economic Justice Screening Tool; Berkeley’s own Tracking the Sun database; BuildZoom and Ohm Analytics; and an Experian ConsumerView dataset purchased for the project. 

Berkeley Lab’s online portal allows public analysis of the demographic data. 

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FERC Approves Rate Incentives for NJ OSW Transmission

FERC on Feb. 15 approved four rate incentives to Mid-Atlantic Offshore Development (MAOD) for its component of the approximately $1 billion in transmission to serve offshore wind in New Jersey under the State Agreement Approach (SAA) with PJM (EL23-101). 

The company, a joint venture between Shell New Energies US and EDF-RE Offshore Development, received approval to receive the RTO participation, regulatory asset, abandoned plant and hypothetical capital structure incentives. MAOD is tasked with constructing the new 230-kV Larrabee Collector substation and HVDC converter stations for $193.6 million, nearly a fifth of the total SAA project cost. (See New Jersey Launches OSW Infrastructure Solicitation.) 

The company’s request was protested by the Long Island Commercial Fishing Association and New Jersey ratepayers, who argued that it did not meet the Order 679 requirement that there be a connection between the incentives sought and the investments being made. They posited that Ørsted’s cancellation of the Ocean Wind 1 and 2 projects and economic assistance requested by Atlantic Shores Offshore Wind signal that the generation the transmission is designed to serve might not be built.

The commission rejected the protests, stating the SAA projects are meant to support New Jersey’s offshore wind development goals, not any three of the planned projects, and therefore may move forward even if those projects are not built. 

“Denying incentives because of the actions of third-party developers that may negatively impact the project would be inconsistent with the commission’s interpretation and implementation of Section 219,” the commission wrote, citing the Federal Power Act section requiring transmission incentives supporting capital investment. 

The company sought the regulatory asset and hypothetical capital structure incentives because of its status as a first-time, nonincumbent transmission developer without existing rates that can offset development costs. Establishing a regulatory asset would allow startup and development costs not capitalized to be recovered once rates are initiated after the project’s completion; the commission said approving a 50% debt and 50% equity capital structure would establish financial principles that nonincumbents lack. 

Approval of the 50-point RTO participation adder was conditioned on it being applied to a base return on equity that is later shown to be just and reasonable. 

The order also greenlit the abandoned plant incentive to provide 100% recovery of costs if the project is abandoned for reasons outside of the developer’s control. MAOD cited environmental, policy, siting and land acquisition risks the project faces, as well as risks inherent in it being one component of the larger SAA project involving numerous other developers. 

Commissioner Mark Christie concurred with the majority’s order, reiterating his concern that in many cases, the commission has a “check the box” approach to approving incentives; in this case, however, he said they’re warranted on the basis they’re in support of New Jersey’s policy goals and the associated costs would be allocated to the state’s ratepayers. 

But Christie also disputed the order’s wording in finding that MAOD’s request met the Order 679 requirement that projects seeking incentives undergo “a fair and open regional planning process that considers and evaluates reliability and/or congestion.” He argued PJM didn’t review whether the project would improve reliability or economics and that the project instead was evaluated by the New Jersey Board of Public Utilities using its own criteria. Nonetheless, he agreed the incentives are appropriate given the costs and benefits are allocated to one state. 

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PJM Seeks Waiver to Postpone 2025/26 Capacity Auction

PJM on Feb. 12 submitted a waiver request asking FERC to delay the 2025/26 Base Residual Auction by 35 days, which would bump the commencement to July 17. 

The RTO argued the delay would allow a more “orderly administration” of the auction and additional stakeholder education on how effective load-carrying capability (ELCC) values will be calculated under the process FERC approved last month. (See FERC Approves 1st PJM Proposal out of CIFP.) 

“Such education would provide market participants with greater confidence that their respective accredited UCAP [unforced capacity] values are accurate and consistent with the approved marginal ELCC methodology,” the request states.  

During the Jan. 16 meeting of the Planning Committee, Adam Keech, PJM vice president of market design and economics, told stakeholders the RTO plans to release class average accreditation values in the coming weeks.  

Keech also said PJM has shifted the pre-auction activities schedule by 10 days in support of stakeholder education, with an additional special session of the PC scheduled for Feb. 21 for that purpose. 

The auction originally was scheduled to begin June 12. 

PJM requested expedited commission action by Feb. 26, one day before the pre-auction deadline for market participants to submit unit-specific offer caps and inform the RTO of whether they intend to use the fixed resource requirement alternative to the Reliability Pricing Model. 

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PPL CEO Talks Energy Transition on Q4 Earnings Call

PPL Corp. CEO Vincent Sorgi on Feb. 16 touted his company’s plans to prepare its utility subsidiaries for a changing grid.  

“Looking ahead, we remain laser focused on creating the utilities of the future to advance the clean energy transition reliably, affordably and sustainably for our customers,” Sorgi said during an earnings call. “And throughout PPL, we’re driven to create long-term value for both our customers and shareowners.ˮ 

The company reported annual earnings of $740 million, which were down slightly from 2022 in the face of milder temperatures, more storms and a more challenging economy in 2023. 

PPL owns utilities in Pennsylvania, Kentucky and Rhode Island, and Sorgi reported “constructive regulatory outcomes” in the latter two. Kentucky regulators approved $2 billion in spending on generation, while the Rhode Island Public Utilities Commission approved PPL’s first infrastructure safety and reliability plan since the company purchased Rhode Island Energy from National Grid in 2022. 

“In addition, we received the green light to deploy advanced metering functionality across Rhode Island as we lay a foundation for a smarter, more resilient, more reliable and more dynamic electric grid capable of supporting the state’s leading climate goals,” Sorgi said. 

PPL is planning to invest $14.3 billion in capital spending from 2024 to 2027, which will strengthen reliability and resiliency while enabling more clean energy and keeping a lid on costs for customers, Sorgi said. That will translate into rate-base growth of 6.3% annually, compared with 5.7% last year. 

The company does not plan to file any rate cases this year, though it might go to the Pennsylvania Public Utility Commission for a waiver request “in the near future” to accelerate the replacement of aging infrastructure at PPL Electric Utilities, Sorgi said. 

PPL’s long-term plans are to continue hardening its transmission and distribution systems against climate change, improving its cybersecurity and rolling out advanced grid technology. 

“It means expanding our industry-leading use of technology, including smart grids, automation, data analytics, AI and technologies that haven’t even been invented yet to build a self-healing grid,” Sorgi said. “It means investing in R&D to drive innovation to advanced technologies that can be scaled safely, reliably and affordably to meet our customers evolving energy needs.” 

The company plans to expand its transmission system and add grid-enhancing technologies (GETS) to existing lines to connect more renewables and improve reliability. It also expects to invest in its distribution system to manage two-way power flows as more distributed energy resources are connected. 

The broader energy transition is going to require significant investments from the entire sector, Sorgi said. 

“The industry and others are projecting a 200 to 300% increase in electricity demand, which will require additions of reliable generation unless we see unprecedented amounts of energy conservation,” he said. “At the same time, aging fossil fuel plants in this country are being retired very rapidly, without replacements of reliable dispatchable generation capacity.” 

Sorgi said the math does not add up, with fossil fuel plants representing 50% of the total generation capacity in the country and some of the needed replacement technologies not ready. The power industry tends to take 40 years to commercialize new technology, but that is not good enough now, he said. 

“We need to cut that time frame in half, at least, to meet net zero-by-2050 targets, especially as we think about the big four new potential technologies: nuclear [small modular reactors], carbon capture and sequestration, long-duration energy storage and hydrogen,” Sorgi said. “In the meantime, we need to leverage commercially viable resources that exist today to reduce our carbon footprint while maintaining reliability.” 

For now, the industry will need to continue using natural gas plants to balance renewables and keep the lights on, he added.