ERCOT’s final resource adequacy assessment for the summer indicates the grid operator will have “sufficient” installed capacity to meet expected record demand during the next few months.
However, Public Utility Commission of Texas Chair Peter Lake chose to highlight the lack of dispatchable — or thermal — generation to meet that demand. During a press conference Wednesday to provide what has become an annual public update before the summer, Lake used the modifier “on-demand dispatchable” 10 times when referring to power, generation or generators.
For the first time this summer, he said, ERCOT’s data shows demand will exceed “on-demand dispatchable power.”
“So, we will be relying on renewables to keep the lights on during the hottest days of summer,” Lake said.
Ironically, the Texas Legislature has moved bills during the current session that add costs and requirements for renewables. Lawmakers have instead focused on legislation designed to incent the construction of more thermal generation. (See Texas Legislature Moves Bills Remaking the ERCOT Market.)
Lake said that between 2008 and 2020, Texas’ population increased by 24% while the state’s “on-demand dispatchable power supply” grew by only 1.5%. He said demand continues to grow with the state adding the equivalent of the population of Oakland, Calif., (433,823 residents as of 2021, according to the U.S. Census Bureau and other sources) and their “devices” requiring electricity every year.
Oakland has replaced Corpus Christi, Texas, (population: 317,863), which Lake and ERCOT CEO Pablo Vegas used in the example last year.
“The increase in demand for electricity is outpacing the supply of on-demand dispatchable power in this new reality,” Lake said. “Our risk goes up as the sun goes down because it’s still hot at 9 p.m. Our solar generation is all gone, so at that point in the day we will be relying on wind generation on our hottest days. We may not have enough on-demand dispatchable generation to cover the gap between when the sun sets and we lose the solar, and when our wind generation picks up.”
According to ERCOT’s seasonal assessment of resource adequacy (SARA), which assumes typical summer grid conditions, the ISO has enough capacity to meet a summer peak of 82.7 GW. That would smash the current record of 80.04 GW, set last July.
The report says more than 97 GW of summer-rated resources are expected to be available for the summer peak. That includes 65.1 GW of thermal resources, a slight increase from last summer’s 63.5 GW number. The grid operator expects to have on hand another 10.4 GW of summer-rated wind resources and 12.3 GW of solar.
The SARA’s most severe risk scenario assumes a high peak load, extreme unplanned thermal plant outages, and extreme low wind power production. However, Vegas said that probability is less than 1%.
Noting that most of the new capacity added since last summer comes from renewables, Vegas said ERCOT could see more tighter hours than last summer and after the traditional 5 p.m. peak load hour. Scarcity conditions are more likely around 9 p.m., after the sun sets and before wind picks up.
Lake said there were at least 12 days last summer when ERCOT experienced tight conditions between 8 p.m. and 10 p.m. He said less than 20% of all wind turbines were generating, despite data showing “on our hottest days we need 50% of all the windmills generating power at 9 p.m.”
“To help mitigate these risks, we’re going to continue to operate the grid conservatively as we have been doing,” Vegas said. “That means bringing generating resources online earlier to mitigate any sudden changes in generation or demand. We plan to operate a reliable and resilient grid this summer.”
Help for Ramping
The grid operator also will launch a new ancillary service on June 8, ERCOT contingency reserve service, that will address the rapid ramps that can occur when renewable resources are operating.
“The urgency to move forward with meaningful electric market reforms that will incentivize the development of dispatchable generation remains extremely high,” Vegas said. “I’ve described many of the tools that we have to deal with the real-time operational challenges that we have, but these do not substitute for significant market reforms that will incentivize the development of new dispatchable generation and to help preserve older generation until it can be replaced.”
ERCOT also released its semi-annual capacity, demand and reserves report (CDR) for the next 10 years. The report provides forecasted planning reserve margins (PRMs) for the summer and winter peak load seasons, forecasting a 2024 summer PRM of 33.9%. That’s a six-percentage point drop from the November CDR.
The grid operator defines the PRM as the percentage of resource capacity greater than firm demand and available to cover uncertainty in future demand, generator availability and new resource supply. Firm demand accounts for load reductions available through interruptible load programs and incremental load reductions from rooftop solar systems that are not accounted for in the load-forecast models.
According to the report, demand will exceed 85 GW next summer and peak at 71.5 GW during the 2024-25 winter.
The Brattle Group released a study Tuesday that found virtual power plants (VPPs) are cheaper than other currently viable options for resource adequacy, namely storage and natural gas peaking plants.
“Real Reliability: The Virtue of Virtual Power” was prepared for Google (NASDAQ:GOOGL). It found that using distributed energy resources including rooftop solar, smart thermostats (which Google makes), smart water heaters, electric vehicles and batteries also provide additional benefits that the alternatives do not.
The last decade saw utilities spend $120 billion on resource adequacy investments, which was dominated by coal, but saw battery storage rise rapidly in the last few years.
“Electrification, coal retirements and dependence on resources with limited capacity value (wind, solar) will continue to result in a persistent need to maintain sufficient system ‘resource adequacy’ by adding new dispatchable capacity,” the study said.
VPPs involve customers allowing their DERs to be controlled by their utility or a third-party aggregation firm, which then operate them in a way to provide the grid benefits, such as cutting demand during peak hours. That allows the power system to be expanded and operated at a lower cost, reliability to be maintained and emissions cut while the benefits are shared among customers, the aggregator and/or utility, and society at large, the report said.
DER ownership is expected to grow substantially in the next decade with smart thermostats on 34% of homes by 2030 compared to 10% today; rooftop solar growing to 83 GW from 27 GW; light-duty electric vehicles growing to 26 million from 3 million; and behind-the-meter batteries growing to 27 GW from just 2 GW today. That comes on top of friendly policies such as the Inflation Reduction Act, with its promotion of electrification and efficiency, and FERC Order 2222, which requires all organized markets to open up to DER aggregations.
Demand response programs have operated like VPPs for decades in some regions, but many firms are setting up new ones that leverage the expansion of DER technologies in recent years. Portland General Electric is setting up a 4-MW behind-the-meter battery VPP involving more than 500 customers; CPower has introduced a smart thermostat-based VPP to participate in PJM; and ERCOT has set up an 80-MW VPP pilot targeting a variety of end uses.
Brattle’s analysis focused on four commercially proven technologies: smart thermostats, smart water heating, managed charging for EVs and behind-the-meter battery-enabled DR. It compared the costs of providing 400 MW of resource adequacy from VPPs made of those technologies to a utility-scale battery and a natural gas peaking plant.
The different plants were studied in the same utility system where 400 MW produced about 7% of the peak demand and half the generation was made up of renewable power. Brattle designed the model utility to represent some challenging requirements for the VPP, like needing to offer resource adequacy during many hours in both the winter and summer. The resources all had to perform 63 hours a year and seven hours during one peak summer day.
VPPs can curtail load during the highest demand hours and shift it to lower hours, while any smart water heaters in the aggregation are capable of producing ancillary services. The VPPs also cut greenhouse gas emissions and delay the need for transmission and distribution upgrades, with the batteries able to provide backup generation during distribution outages.
“The VPP could provide resource adequacy at a net utility system cost that is only roughly 40% of the net cost of a gas peaker and 60% of the net cost of a battery,” the study said.
RMI has estimated that 60 GW of VPPs could be deployed across the country by 2030 and that would meet future resource adequacy needs at a cost that is $15 billion to $35 billion lower than the alternatives.
“Decarbonization and resilience benefits are incremental to those resource cost savings,” said the study. “Consumers would experience an additional $20 billion in societal benefits over that 10-year period.”
Utilities are pushing back against a proposed rule by the New Jersey Board of Public Utilities (BPU) that would prevent them from owning or operating projects in the agency’s planned permanent community solar program.
But the BPU’s plan has the backing of the state’s Division of Rate Counsel.
The topic emerged as a prominent source of contention in an April 24 BPU hearing seeking stakeholder feedback on the latest draft of the rules, which state that electric distribution companies (EDCs) “are not allowed to develop, own or operate community solar projects.”
New Jersey Utilities Association CEO Richard Henning said he was “surprised and disappointed” at the BPU’s position and expressed the view — shared by representatives of two utilities, Atlantic City Electric and PSEG — that EDCs have valuable experience and expertise to contribute to the community solar sector.
“To have the electric utilities on the sidelines makes no sense,” Henning said. “They have the resources, the program management, the infrastructure to handle organizing and implementing community solar projects like no other.”
Speakers also raised questions about the impact of making program eligibility dependent on a project obtaining an EDC connection study and encouraged the BPU to broaden the types of projects eligible in the program.
Several speakers urged the agency to rethink a rule that prohibits a developer from co-locating two projects on the same property or contiguous properties. They said that complicated projects, such as those on brownfields or a landfill, are more expensive, and combining two projects can increase the capacity and financial reward enough to make the project feasible.
Serving LMI Customers
The draft rules outline a permanent program in which the BPU would approve community solar projects totaling at least 225 MW in each of the first two years, starting this year, and at least 150 MW in subsequent years. Projects can be no larger than 5 MW and will be allocated by the BPU on a first come, first served basis. (See NJ Proposes Modest Community Solar Capacity Hike.)
State officials consider the two community solar pilots a major success and believe the program will play a key role in the state reaching its goal of 32 GW of solar by 2050, about 34% of the state’s generating capacity.
In both pilot programs, the BPU approved projects through a competitive solicitation process, awarding 45 projects totaling 76 MW in 2019 and 105 projects totaling 165 MW in 2021. So far, 25 community solar projects totaling 47.7 MW have been completed and are up and running, according to BPU figures.
Aaron Karp, an attorney for PSEG, said the state’s Clean Energy Act clearly requires the BPU to “set forth standards for projects owned by electric public utilities” and other entities in the permanent community solar program. Moreover, he said, the utility has a long history of “partnering” with low- and moderate-income (LMI) customers and is “uniquely suited to effectively leverage those relationships to ensure that LMI customers can participate in community solar.”
“Utility ownership will not only help the state meet its lofty but important solar goals, but it will also ensure the participation of low- to moderate-income customers,” he said, urging the board to revise its prohibition on EDC project ownership and operation.
Offering comments “on behalf” of Atlantic City Electric, Jocelyn Tyler, manager for DER interconnection at parent company Pepco Holdings, said the utility has gathered “lessons learned” by working to connect community solar projects. That experience, and the fact that “utility-owned solar has seen success in many states,” should warrant the BPU rethinking its position, she said.
“Utility ownership of community solar will lead to increased deployment of renewable energy, benefiting LMI customers, increasing grid resilience and reliability” and help manage peak load stress, “all of which are objectives of the program,” she said.
BPU staff, in an explanation accompanying the latest draft, said EDC ownership or operation is “unnecessary” given that the two community solar pilot programs were heavily oversubscribed, demonstrating “strong interest” in developing community solar by non-EDC entities.
“Staff therefore believes that there is no reason to transfer the risks and costs associated with developing a community solar project from non-EDC entities to the ratepayers, nor for EDCs to have a potential competitive advantage in project ownership,” the BPU staff said.
The experience of the pilot “demonstrates both the strong interest in developing community solar by non-EDC entities (both private developers and public entities) as well as their ability to design projects that serve a broad diversity of customers,” the staff explanation said.
Rethinking Acceptable Projects
Sarah Steindel, staff attorney with the Division of Rate Counsel, said her agency supported the BPU’s position on EDCs. But switching to another topic, she added that the ratepayer advocate would like the regulator to rethink its limitation on where community solar can be located. The draft proposal limits projects to four types: rooftops, carports and canopies over impervious surfaces, contaminated sites and landfills, and man-made bodies of water.
“We would caution the board on limiting the sites to rooftops and so forth,” Steindel said. “This conflicts with the stated goal in the straw proposal of providing maximum benefits at the lowest cost because it tends to increase the amount of subsidies required or reduce the benefits that go to subscribers, or both.”
Eric Millard, chief commercial officer at CS Energy in Edison, N.J., also advocated for a wider variety of project types beyond the “restrictive” selection outlined in the draft. “The draft effectively restricts the siting of community solar projects to areas in the state that have large rooftops or contaminated sites, and that’s a pretty small subset of New Jersey,” he said.
“We think that community solar projects should be allowed in commercial and industrial zoned parcels,” where solar is allowed under land use laws, he said. In addition, he added, the BPU should add “contaminated agricultural land” to the definition of brownfield sites suitable for community solar projects.
Jake Springer, mid-Atlantic policy director for Nexamp, a Boston-based solar developer, cited the difficulty of pursuing contaminated sites as a reason for the BPU to reconsider its prohibition on co-locating projects on the same site. In cases such as landfill or brownfield development, co-location can provide a “tremendous benefit to making those projects cost effective,” he said.
Under any circumstance, “there’s an argument to be made that those types of projects are disadvantaged relative to others, such as rooftop projects, where the permitting requirements are less,” Springer said. “The ability to co-locate up to 10 MW [on a site], as under the pilot, would allow a number of brownfield and landfill projects to go forward.”
Making a similar point, Lyle Rawlings, president of Mid-Atlantic Solar & Storage Industries Association, suggested the BPU could allow developers to seek a waiver from the prohibition based on a project’s “public benefits” or ability to help the state reach its “policy priorities.”
Evaluating Project Maturity
Several speakers also questioned whether the state could reach those priorities and the community solar sector could flourish with the program structure outlined in the draft — especially aspects of the criteria of “maturity” needed for a project to be accepted into the program.
BPU officials say the criteria is designed to ensure that under the first come, first served system, only those projects ready to advance — and likely to be implemented — will be allocated valuable capacity in the program.
Joe Henri, of Atlanta-based solar developer Dimension Renewable Energy, welcomed the BPU’s plan to select projects on a first come basis method, while ensuring their quality and readiness by requiring them to meet certain “maturity” measures. Among them would be a requirement that the developer demonstrate the project will be able to connect to the grid by showing that it has an interconnection study completed and the EDC is ready to sign off on the project.
However, Henri said, that will be problematic in the short term because of the current lengthy delays projects face in connecting to the grid and planned reforms to improve the situation are moving slowly.
“Unfortunately, those rules probably aren’t going to be completely in place and completely clarified until late this year or early next year,” he said. He said it would be ideal for the EDC to sign off on a project before it is selected, but that does not usually occur until late in the proves, so an “interim” milestone that shows the project has the requisite maturity needed, he said.
Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, added that the proposal to assess a project’s maturity by whether the EDC has completed a connection study will not only put great pressure on utilities, but will also make them “gatekeepers to this process,” giving them considerable power in deciding which projects go forward. The draft proposal suggests that requirement for projects greater than 1 MW, and smaller projects must only show they have submitted to the EDC an “interconnection agreement.”
“So that this puts the ball in the utilities court completely for making the decision on who wins and who loses based upon the first come, first served” selection structure,” he said. “To that end, we think it’s important that the industry understand how the EDCs will work through this significant surge in workload [and] the protocols and priorities that they may establish in conducting this work.”
COLONIE, N.Y. — Boosted by new tax credits and growing momentum toward decarbonizing buildings, the 2023 NY-GEO Conference last week was nearly standing-room only, with a record number of attendees.
And the room to stand was limited by all the exhibitors on hand at the geothermal heat pump expo last week, some of them wedged into any available space in the corridors.
Geothermal systems have among the lowest operating costs of any heating/cooling system, but for decades, many potential buyers have been turned away by their high upfront costs.
With local, state and federal policy promotion of the technology, and with IRA tax credits to sharply reduce the installation costs, the industry has turned a corner, one speaker after another declared.
Jens Ponikau, president of the NY-GEO board of directors, recalled being excited to have 62 attendees at the first conference eight years ago and see it grow steadily to 400 last year. More than 700 people registered to attend the 2023 edition.
“Never in my wildest dreams would I have imagined where this technology has gone,” he said.
The industry does still face headwinds, notably a shortage of contractors to drill the bores that act as a source of heat in the winter and repository of heat in the summer. But with structures being one of the largest sources of greenhouse gas emissions, building decarbonization is central to the climate mitigation programs being planned and implemented in New York and elsewhere.
Scott Walsh, director of development for Lendlease, spoke about 1 Java Street, the 790,000-square-foot mixed-use complex it is building on the Brooklyn waterfront. The all-electric building is a significant undertaking, not least because of its geothermal system. Construction crews had to choreograph foundation pile-driving with drilling of 320 vertical bores for the system. (A one-family house typically needs only a single vertical underground loop.)
“It was Santa’s Workshop on our site, to say the least,” Walsh said.
The geothermal climate control system at 1 Java will be larger than any other residential installation in the state, and by serving multiple structures, it is akin to the district community systems that the New York State Energy Research and Development Authority is guiding through a pilot process.
Donovan Gordon, NYSERDA’s director of clean heating and cooling, said the various pilot projects are a good mix of upstate and downstate, and are advancing through the review process. He urged NY-GEO to keep the momentum going by doing good work; people need to trust that ground-source heat pumps will deliver on their promise, he said.
“If we’re selling this product, let’s make sure that it’s reliable and they can count on it when they really need it,” Gordon said.
And then we need to let the world know it, he said.
“One thing I learned very early on is that in order for geothermal to succeed, we need a champion. So, we want to identify who the champions are — certainly at the municipal level; the developer level; the building owner level; wherever we can — and help them so they can really push the cause and get things done within their community.”
Daniel Ellis of Comfortworks said the shortage of drilling contractors notwithstanding, the ground-source heat pump industry is in an excellent position in 2023.
“It takes three things to make the market really fly,” he said. “You have to have high energy costs; you have to have some form of incentive; and you have to have an economy where things are being built and renovated. Right now, I think we’re at a pretty good situation. Anything could change in a heartbeat, economy-wise or whatever, but we have all the things lined up.”
Continual Effort
A plenary discussion was titled “Worst to First,” a reference to the economics of geothermal heat and government support for it as a means of decarbonizing buildings.
The discussion’s moderator said this was a bit of an exaggeration: Geothermal was never really worst, and there still are a few things to unpack in the IRA before it can be first.
But worst to first describes the ups and downs of an industry campaign that started in the Carter administration and has continued with dashed hopes, false starts and steady lobbying to gain recognition and subsidies for geothermal as a legitimate way to save money and the planet.
What could have been a seminal moment for the industry came and went 30 years ago, when the EPA report “Space Conditioning: The Next Frontier” declared electric ground-source heat pumps the cleanest, most efficient means of interior temperature control.
Through politics, legislative horse trading and apparent clerical errors, geothermal became one of the “orphan technologies” excluded from subsidy programs, along with small wind, fuel cells and microturbines, Geothermal Exchange Organization President Ryan Dougherty said.
Things began to look up in 2018, when federal incentives were reinstated, but persistent lobbying — right up to and after passage of the IRA in 2022 — finally turned the page for geothermal, he said.
“But it’s not like flipping a light switch,” Dougherty said. “We’re still in many ways building back.”
A geothermal heat pump system is an expensive upfront investment that will yield immediate dividends for GHG reduction but take years or decades to provide return on investment for the building owner, depending on the cost of fossil fuels and electricity. It is also just one piece of a much larger bill spread over the next few decades. How much the energy transition will cost and how that cost will be allocated is still unknown.
And if the transition is to be anything close to complete or equitable, someone must pick up the tab for the Americans who cannot afford big increases in taxes or utility rates or housing costs.
One session of 2023 NY-GEO was titled “Who Will Pay for Building Electrification,” but it centered more on “Who Must NOT Pay”: the imperative that low- and middle-income residents not be stuck with the bill. It was suggested that all the money being spent to maintain and expand gas utility infrastructure be spent instead on electrifying housing, but no one noted that ratepayers presumably would bear the cost either way.
Then there is the housing itself: About 45% of New York state’s housing stock consists of rental units whose residents have limited ability to make upgrades and whose owners have little incentive to do the work, absent the carrot and stick of government regulation.
In New York City, 67% of the housing is rented and the poverty rate is significantly higher than the rest of the state and nation. An apartment on the Brooklyn waterfront can run $5,000/month. Market-rate units in Lendlease’s high-tech no-carbon complex at 1 Java will go for $7,000 to $10,000/month, CNBC reported last week.
“We have some big challenges because New York has some very old building stock,” said Jessica Azulay, executive director of the Alliance for a Green Economy. “A lot of these older houses are in dire need of repairs, upgrades, weatherization and electrical work before they can electrify.”
Annie Carforo of WE ACT for Environmental Justice related a pilot project that replaced gas stoves with electric induction ranges in 10 apartments in a housing authority building in New York’s poorest county. Everyone loved them, and nitrogen oxide levels dropped 35% in the air in those 10 apartments. But the project had to be fanned out horizontally across the building; the electrical circuitry could support only two induction ranges per vertical stack of apartments in the six-story structure.
Challenges like these are multiplied across the 177,000 units of the New York City Housing Authority, which reports it has a $40 billion backlog of deferred maintenance after decades of funding cuts.
“That is going to be a barrier to doing a lot of this electrification work,” Carforo said. Government funding streams for doing this work are siloed and inflexible, she added.
Drill, Baby, Drill
Outside the meeting rooms at 2023 NY-GEO, NetZero Insider spoke to exhibitors representing a sales company, an installation contractor, a utility, and an inventor and manufacturer. Each offered a distinct perspective, but all gave an upbeat appraisal of the prospects for geothermal heating and cooling.
“I used to come to these events to find moral support!” said Jonathan Tham, administrator of PSEG Long Island’s Home Comfort Program. “There’s definitely a larger interest [now]. I’ve been in this field for more than 30 years. It used to be that I would have to go and sell green environmental technology; now they’re coming to us. But that’s been the case for the last five years; the awareness is there. …
“We’ve changed from thinking about energy efficiency in terms of dollars to carbon. We’re basically saying we don’t want any emissions.”
Tham promotes air-source and ground-source heat pumps with equal enthusiasm. The biggest obstacles to adoption, particularly for ground-source heat pumps, remain the high cost of installation and the limited availability of contractors to do the work, he said.
Aztech Geothermal Service Manager Austin Gross said government incentives are important to continued adoption of the technology. Their cancellation several years ago choked off consumer interest in his company, which is based near Albany and works almost entirely on residential projects.
Incentives were restored and later enhanced by the IRA.
“It’s backed us out of the corner; it’s given us a lot more breathing room to at least be competitive with conventional systems,” Gross said.
Aztech contracts its bore drilling, and like many others during the conference, Gross flagged the shortage of drillers as a problem. Not only are there not enough to begin with, many shy away from drilling geothermal systems. They have enough business drilling water wells that they need not bother with what is a familiar process but an unfamiliar application.
“It’s an entirely new market for a lot of drillers to be able to step into,” he said.
Energy Catalyst Technologies grew out of a young engineer’s frustration at the lack of options to convert his home to geothermal heat. Like many houses in the Northeast, it is an older building with a hydronic heating system — hot water running through pipes — that would be expensive and disruptive to replace.
“A lot of times in a home with radiators — like our own — someone will come by and say, ‘Rip out all the radiators, and let’s put in some air ducts, mini splits or something like that,’” said Marketing Director Emily Desmarais.
So, founder Matthew Desmarais designed a double hybrid heat pump, warming hot water and circulating it through the radiators in winter. In the summer, it generates hot water for domestic use and can double as an air conditioning system for the first floor with a relatively small amount of ductwork, if the basement is unfinished.
Now four years old and out of the startup phase, Energy Catalyst is hoping to grow with the geothermal industry.
Tim Houle of Stark Tech was showing off a water furnace ground-source heat pump at the expo. He sees momentum in the industry, with ground-source heat pumps now getting consideration against their less expensive air-source counterparts or against fossil-fuel systems because of incentives to bring the cost down.
“We’ve been doing it forever; now it’s more of a desired technology,” he said.
Stark works on the commercial scale — schools, office buildings, industrial sites and really, really large houses. The motivation for such conversions ranges from a desire to go carbon-free, to a desire to publicly promote oneself as carbon-free, to simply getting away from expensive oil heat.
There is also a desire or need to get ahead of regulations, Houle said, as a growing number of jurisdictions are mandating that buildings go carbon-free.
New York is poised to be the latest.
As 2023 NY-GEO wound down Thursday, Gov. Kathy Hochul announced a conceptual agreement on the state’s long-overdue 2023-2024 budget. Among the welter of critical policy issues baked into the spending plan is a ban on fossil fuel systems in new construction. (See related story, NY to Begin Banning Gas in new Construction in 2026.)
New York is on track to be the first state in the nation to ban fossil fuel in new buildings.
State leaders are also expanding the role of the New York Power Authority, the nation’s largest state-owned utility, and set a 2030 retirement deadline for NYPA’s gas-fired peaker power plants.
These and a vast array of other important policy decisions — ranging from marijuana to mental health to the minimum wage — are baked into the 2023/24 state budget agreement, which was due March 31 and finally hashed out late last week.
Some of the energy and environmental provisions are potentially far-reaching and impactful. But what seemed to capture the public eye most was something that Gov. Kathy Hochul never even proposed: a ban on gas stoves.
No such ban is in the final budget bill, either. But the budget provisions will have the same effect: If a developer cannot run a gas line into the building, there is no point in putting a gas stove there.
Fossil fuel systems will be banned in new construction of fewer than eight stories starting Dec. 31, 2025, with an exception for commercial and industrial buildings greater than 100,000 square feet. The ban extends to all new construction on Jan. 1, 2029.
Backup power systems are exempted from the ban, as are manufactured homes, critical infrastructure, buildings with uses as varied as car washes and crematoriums, and places where decarbonization is technically or physically impossible. An exemption also can be granted if the grid is deemed unable to support increased power demand.
There is no opt-out provision for municipalities.
Fossil fuel systems in buildings built before the two deadlines can continue to be used, repaired and replaced.
Missing from the final budget are provisions of NY HEAT, or New York Home Energy Affordable Transition Act, which would limit expansion of natural gas distribution infrastructure in the state and actively encourage its orderly shrinkage to spare New Yorkers billions of dollars in costs to build and maintain it.
NYPA’s New Roles
Big changes are coming for NYPA.
Hochul this year proposed multiple expansions of NYPA’s role along the same framework as the Build Public Renewables Act (BPRA), a proposal that originated in the legislature and failed to advance in 2022.
Progressives championed the BPRA as a way to democratize energy and scorned the governor’s proposal as “BPRA Lite.” Multiple observers said this week that the version that emerged from budget negotiations was close to the original BPRA.
Under these provisions NYPA is:
authorized and directed to develop, own, operate and improve renewable energy projects alone or through public-private partnerships;
required to execute project labor agreements, enforce apprenticeship requirements and, if possible, include domestic content requirements on any renewable energy projects it undertakes, then staff the project with union labor once complete, with hiring preference to workers displaced by the energy transition;
authorized and directed to establish a renewable energy access and bill credit program for low- and middle-income electric customers in disadvantaged communities, using credits generated by one of its renewable projects;
directed to produce a plan to retire its seven small gas-fired peaker plants downstate before 2031. (Hochul had originally proposed a 2035 deadline. The requirement is waived if the plants are needed for emergency power service or grid reliability);
directed to provide the state Department of Labor up to $25 million a year for workforce training; and
directed to develop decarbonization plans for the 15 state-owned structures with the highest greenhouse gas emissions.
Reaction
Like most budgets, the 2023-2024 edition was an exercise in horse trading. Nobody got everything they wanted, and almost everybody is vowing to fight for what they can salvage before the part-time legislature adjourns for the season.
Reactions Tuesday often referred to the imperative to keep lobbying for change and to the win-lose nature of the budget provisions.
Decarbonizing state buildings is incredibly “important and meaningful,” he said, a chance for state government to lead by example and also experience for itself the costs and challenges of the mandates it is imposing.
But putting NYPA in competition with the private sector will boost costs for its customers, he said.
Missing, Donohue said, are any meaningful details of the cap-and-invest program Hochul is pursuing and funding for research and development of the power sources to replace natural gas-fired plants, which state law mandates be retired by 2040.
Some other reactions:
Alex DeGolia, director of U.S. climate at the Environmental Defense Fund: “Gov Hochul and state leaders have positioned the state for progress on climate action, but it is just the start of the urgent work that’s needed to achieve the state’s climate goals and secure the strongest possible future for New York communities. It is enormously important that state leaders follow these actions with next steps to make the clean energy transition affordable, equitable and just for working families across New York.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York: “ACE NY was opposed to BPRA, but this latest development means that NYPA will be in the mix with clean energy developers. The renewable energy industry will continue to focus on getting wind and solar projects built. Our climate goals in New York must become construction goals for family-sustaining jobs, economic development, and energy resiliency.”
The Marcellus Drilling News website: “NY State has Fallen — Gas Stoves & Peaker Plants Banned in Budget.”
Public Power NY Coalition: “The passage of the Build Public Renewables Act is a historic victory that will improve the lives of New Yorkers and be a model of how to rapidly ramp up the production of renewable energy for the country. Unfortunately, Governor Hochul and her handpicked NYPA interim CEO Justin Driscoll vehemently opposed provisions that would make NYPA more accountable to New Yorkers and were able to strip them from the version of the bill included in the budget. Driscoll has proven he is not the leader NYPA needs, and we will mobilize the powerful movement that passed this bill to oppose his confirmation.”
Lisa Dix, New York director of the Building Decarbonization Coalition: “We applaud Gov. Hochul and the New York State Legislature for their leadership in passing the first-of-its-kind statewide requirement to achieve zero-emissions in new buildings as early as 2026. Despite these steps forward, the legislature’s work is not done. After months of high energy bills, downstate New Yorkers are facing double-digit rate hikes driven, in part, by costly gas pipeline investments. While the Legislature’s allocation of $200 million for short-term utility bill relief for low-income New Yorkers is a necessary short-term Band-Aid that begs for a long-term solution. The Legislature can deliver long-term affordability this session by passing the NY Home Energy Affordable Transition (HEAT) Act.”
Renewable Heat Now! on its website said the celebratory moment is soured by the missing provisions of NY HEAT and the fact that building decarbonization deadlines start in 2026, not earlier. “Delays and Exemptions are Disappointing,” it posted. “Exclusion of NY HEAT Act Demonstrates Gov. Hochul’s Lack of Commitment to Climate Plan.”
Gas utility National Fuel Gas Company did not return a request for comment, but its homepage prominently features the message: “Tell Albany lawmakers: NO natural gas bans.”
A federal jury in Chicago on Tuesday found former Commonwealth Edison (NASDAQ:EXC) CEO Anne Pramaggiore guilty of bribery in connection with a multiyear conspiracy to pay former Illinois House Speaker Michael Madigan (D) for passage of legislation favorable to the utility.
Also found guilty were former ComEd lobbyist and Madigan associate Michael McClain, former ComEd Vice President John Hooker and former ComEd consultant Jay Doherty.
The four were charged with nine counts of conspiracy to bribe Madigan in exchange for his help in passing bills that set certain rate charges that could not be debated before the Illinois Commerce Commission and produced millions of dollars of profits for the company over several years.
The conspiracy outlined by the U.S. Justice Department and now accepted by the jury included payments of about $1.3 million from the utility to pay contractors favored by Madigan but who did not work, and an arrangement to generate billable hours with a favored law firm that also did no work. ComEd also provided summer jobs for constituents in Chicago Ward 13, where Madigan resided, and the wards of Chicago aldermen allied with the speaker. The scheme also included an appointment of a candidate favored by Madigan to a seat on the company’s board of directors.
John Hooker, lobbyist and former ConEd executive | Chicago Housing Authority
Prosecutors during the trial referred to the payments as a “corruption toll” ComEd paid from 2011 to 2018.
Defense attorneys tried to convince the jury that the efforts of Pramaggiore and the others were just old-fashioned lobbying and not criminal.
A sentencing hearing must still be set. Each defendant faces up to five years in prison.
The guilty verdict came after five days of deliberations following a trial that lasted nearly eight weeks. The four were indicted on Nov. 18, 2020, after an eight-year FBI investigation that included hundreds of hours of wiretapped conversations. (See Ex-ComEd CEO, Officials Charged in Ill. Bribery Scheme.)
The verdict on all nine counts sets the stage for trials in April 2024 on federal racketeering charges filed against Madigan and his confidant McClain. The Justice Department indicted Madigan in March 2021.
Madigan was speaker of the Illinois House of Representatives for 36 years, the longest-serving leader of any legislative body — both federal and state — in the history of the U.S.
Dominion Energy Virginia’s (NYSE:D) new integrated resource plan anticipates continued development of solar, wind and storage and — much to the dismay of environmental groups — 970 MW of new natural gas capacity.
The company on Monday submitted its integrated resource plan to the State Corporation Commission, along with a planned rate cut.
“These plans demonstrate that solar, wind and storage will be the majority of the company’s generation development over the next fifteen years,” the IRP said. “Until new zero-carbon dispatchable generation options are developed or reach commercial viability, gas units are among the most affordable and reliable options for new generation that can quickly adjust output with changes in intermittent output.”
Reactions to the IRP
Gov. Glenn Youngkin (R) said the IRP shows the value of the kind of “all of the above” energy plan he supports.
“Virginia’s economy is growing, and the accelerated electricity demands of Virginia’s industrial users demonstrate the need for a more realistic and judicious approach to power planning,” Youngkin said in a statement. “We support an all-of-the-above approach that embraces the use of innovative generation technologies to bring more capacity online, while also thoughtfully managing the retirement of existing generation capacity to satisfy the growing needs of the commonwealth.”
Demand is projected to grow at 5% per year, which exceeds the expectations from when the 2020 Virginia Clean Economy Act (VCEA) passed. With PJM expecting retirements will outstrip new supplies in the coming years, Youngkin said “it would be a huge mistake” to retire baseload generation without a plan to replace it.
Advanced Energy United criticized the utility and its IRP for going against the intent of the VCEA, which is supported by the trade group’s members.
“We have seen this play from Dominion before. Its latest resource plan is yet another example of this utility picking a forecast that suits its business interests,” AEU Policy Director Kim Jemaine said in a statement. “Dominion chooses a questionable energy load forecast as justification for cherry-picking preferred technologies, preserving existing fossil-fuel facilities and calling for new investment in gas fired resources. In our view, Dominion has not developed a good faith decarbonization plan that fully aligns with the Virginia Clean Economy Act.”
VCEA was already designed to maintain reliability by relying on proven technologies and not requiring the retirement of natural gas until 2045, giving Virginia plenty of time to make the transition to 100% clean energy, Jemaine said. AEU wants Dominion to find ways to maximize the role of efficiency, demand response, smart rate design, rooftop solar and more technologies to rein in increasing demand.
“There are so many reliable and low-cost technology solutions to meet growing electricity demand, but they are largely absent from this new plan,” Jemaine said. “Instead, the utility is planning to preserve — even expand — natural gas-fired generation as a benefit to its shareholders, at unnecessary cost to Virginia consumers. This is a risky bet given volatile gas prices.”
The Integrated Resource Plan
Dominion’s IRP details ways the firm can meet its customers’ growing needs over the next 15 years — not an application to build specific projects, but a long-term planning document based on current technology and market information and projections.
Demand is expected to grow significantly faster over the next 15 years compared to the last as Dominion’s territory in Northern Virginia is home to a rapidly growing data center industry, and its customers are expected to electrify new sources of demand.
The firm’s plan is to continue developing renewable energy as required by the VCEA, while keeping most of its current power stations until the late 2030s.
“This ‘all-of-the-above’ approach ensures we can reliably serve our customers ‘around the clock,’ especially on the hottest and coldest days of the year,” Dominion Energy Virginia President Ed Baine said. “Our plan balances the benefits of renewables with the reliability of ‘on-demand’ power so we can meet the growing needs of our customers.”
The firm offered five long-term “alternative plans” that it said were developed using constraint-based, least-cost planning techniques and proven technologies:
Plan A is a low-cost alternative that will meet applicable carbon regulations and the mandatory Virginia Renewable Portfolio Standard (RPS), but does not meet the VCEA’s targets for solar, wind and energy storage. Dominion does not view it as a true path forward as it fails to meet state policies, but it noted that even without retiring most of its existing units, it still needed to construct significant new resources to meet demand. The utility forecast a net present value (NPV) of $109.7 billion for Plan A.
Alternative B is similar to A, but it meets the VCEA’s procurement goals and adds another 2.9 GW of combustion turbine generation, 19 GW of additional solar, 2.6 GW of additional offshore wind, 600 MW of onshore wind, 5.1 GW of storage, and 1.6 GW of small modular reactors (SMR). Even with the additional generation, Dominion would have to increasingly rely on imports, with plans to buy 4 GW from the market starting 2041 and beyond, requiring additional transmission. (NPV: $127 billion.)
Plan C is similar, but Dominion ignored VCEA requirements for in-state renewables. (NPV: $127 billion.)
Plan D leads to zero emissions as Dominion retires all carbon-emitting generation by the end of 2045. Plan D includes additional procurements to make up that gap with 3.4 GW of incremental solar, 4.6 GW of storage and 3.2 GW of SMRs. (NPV: $140.9 billion.)
Plan E is similar, but like Plan C it ignores the locational requirements of the VCEA. (NPV: $138 billion.)
“Plan D results in the company purchasing over 10.8 GW of capacity and 13 GW of energy in 2045 and beyond, raising concerns about system reliability and energy independence, including reliance on out-of-state capacity to meet customer needs,” the IRP said. “In addition, there is no guarantee that other states will maintain dispatchable generation that will be available for purchase when the company needs incremental power.”
Dominion table showing potential sources of supply under different scenarios | Dominion Energy
All the plans show that a growing capacity and energy need will require a diverse mix of resources and an increased reliance on market purchases, even under normal weather conditions and with few retirements.
Short-term Plan
Because the longer-term plan is full of uncertainties around technology and other issues, the IRP also included a short-term action plan for the next five years. Dominion said it plans to continue developing solar, onshore wind and storage while completing the Coastal Virginia Offshore Wind project on schedule by 2026.
The firm also plans to continue its efforts to get a license extension for the North Anna Nuclear Plant, developing 970 MW of new gas-fired combustion turbines; start development of a “backup” LNG facility to support reliable operations of its natural gas plants, and continue compliance with both North Carolina’s and Virginia’s environmental laws.
The Chesapeake Climate Action Network (CCAN) also panned the IRP. “Included in the IRP is a push for small modular reactors, a new nuclear reactor prototype that costs up to $10 billion each at a nameplate capacity of 300 MW of electricity and is currently operational only on one floating barge in Russia. A solar facility costs 3% as much per megawatt of nameplate capacity,” the group said.
CCAN also criticized Dominion for considering scenarios in which it would abandon the VCEA’s goals. “All iterations of the IRP assume that Virginia will exit the Regional Greenhouse Gas Initiative by 2024, despite a lack of legal authority for Virginia to do so without the approval of the legislature,” it said.
“We should recognize this unholy union between billionaire Governor Youngkin and Dominion for what it is: a corporate profit grab that would bankrupt Virginians and exacerbate climate change,” CCAN’s Virginia Director Victoria Higgins said. “The state can meet demand without compromising our clean energy goals or forcing Virginians to choose between energy and food. Suggesting new fracked gas infrastructure in 2023 is patently absurd.”
Rate Cut
The firm’s rate decrease would save the typical residential customer between $7 and $14/month because of bipartisan legislation that eliminated $350 million in riders while giving the SCC more flexibility to set its rates going forward. (See Virginia Legislature Passes Utility Regulation Bills Backed by Dominion.)
“Earlier this year we promised substantial rate relief for our customers,” Baine said in a statement. “Thanks to bipartisan legislation and broad support from consumer advocates, we are delivering on that promise.”
Dominion also asked to securitize some fuel costs so they will be recovered from customers over a longer term, which will lower monthly bills by another $7 starting July 1. The savings are partially offset by a $2.67 increase to the stand-alone transmission charge that would go into effect September 1 if approved, meaning the typical residential customer would save between $4 and $11 a month.
Electric truck maker Lordstown Motors (NASDAQ:RIDE) warned investors this week that it may seek federal bankruptcy protection following the refusal of major shareholder Foxconn to invest as much as another $117 million in the Ohio company.
“We may need to curtail or cease operations and seek protection by filing a voluntary petition for relief under the Bankruptcy Code,” Lordstown warned investors in a U.S. Securities and Exchange 8-K filing Monday.
The fledgling truck maker’s share price has fallen below $1/share, and it could be delisted from trading.
Monday’s announcement accelerated the decline of Lordstown’s share price, which fell below $1 on March 7 and remained there for 10 days, prompting the Nasdaq to warn on April 19 that it would delist the shares unless the price recovered to more than $1 for 10 consecutive days by Oct. 16.
The company made the Nasdaq’s warning public in an 8-K the same day it received it.
That prompted Foxconn to put the brakes on additional investments until the share price increased, declaring in a letter to the company on April 21 — only publicly revealed in this week’s 8-K — that Lordstown had breached an agreement made in November 2022 obligating Foxconn to invest up to $170 million in share purchases. (See Lordstown Motors Gives 2 Board Seats to Foxconn.)
Foxconn purchased $22.7 million of common stock and $30 million in preferred stock in November, according to Lordstown, and is now obligated to invest another $117.3 million in additional stock, according to the 8-K.
Foxconn, however, argued in its letter that the action by Nasdaq put the company in breach of the agreement; Lordstown replied that Foxconn cannot unilaterally pull out of the agreement.
“The company is in discussions with Foxconn to seek a resolution regarding these matters; however, to date, Foxconn has declined to revoke its invalid termination notice and has failed to confirm that it will proceed with the subsequent common closing or any preferred stock closing,” Lordstown wrote to the SEC. If the additional investments “do not occur, the company will be deprived of critical funding necessary for its operations.”
Foxconn said in a statement Tuesday that it remained open to continuing negotiations with Lordstown.
The two companies have been developing one electric vehicle, the Endurance pickup truck, which they hope to sell to commercial customers. Production of the truck has been repeatedly slowed or stopped by parts shortages and inadequate funding. Fewer than 40 trucks have been fully assembled. A recall in February to replace suspect parts in the few trucks that had been sold did not help the company’s reputation with investors. (See Lordstown Motors Recalls Endurance Electric Truck.)
Monday’s announcement of a possible bankruptcy filing accelerated the decline of the company’s share price, which tumbled to 25 cents midday before rebounding, ending the day at 39 cents. The share price on Tuesday was hovering in the mid-40-cent range. Over the last 52 weeks, the price was as high as $3.73, still a steep decline from a high of $31.40 in September 2020.
Public Service Enterprise Group (NYSE:PEG) should get a boost from New Jersey’s second solicitation for offshore wind transmission upgrades and the state’s deepening embrace of electric vehicles, CEO Ralph A. LaRossa said during a first-quarter earnings call Tuesday.
Of particular benefit to the company could be a recommendation by the state Board of Public Utilities (BPU) that cables running from offshore projects pass through the utility’s 500-kV Deans substation in Northern New Jersey, LaRossa told analysts.
“What it means for us certainly is that if PJM does agree with the Board of Public Utilities and selects that, any of the work inside the fence will be the responsibility of [PSEG utility subsidiary] PSE&G,” he said. “Outside the fence will still follow under that state agreement approach and be competitive solicitation.”
“What I’m encouraged by is the fact that Deans is in our service territory; we know our service territory; and we should be very knowledgeable about the routes to get from the shore to that substation,” he said.
PSE&G was among 13 developers that submitted 80 proposals in the state’s first solicitation, made under the FERC State Agreement Approach rules, which resulted in last October’s awarding of contracts totaling $1.07 billion. PSEG submitted several proposals, some with Danish OSW developer Ørsted, which is developing two of the three approved projects off the Jersey shore under the name Coastal Wind Link. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
Despite PSEG’s anticipation that it could see up to $3 billion in business from the solicitation, the BPU awarded the utility only two small contracts totaling $40.3 million. (See PSEG Sees Potential $3B OSW Transmission Spending.)
LaRossa said he was “very happy” the utility had upgraded its transmission network because BPU’s recommendation to use Deans indicated “that our transmission system is robust enough to take that injection of offshore wind generation into it.”
“Our engineering team has done a really nice job of readying the system for what might come, and here it is,” he said.
One analyst on the call noted that a major part of the business awarded in the first solicitation went to FirstEnergy’s Jersey Central Power and Light, which was contracted to build a new substation next to its existing Larrabee substation. The analyst suggested that might happen with PSEG and its Deans substation.
But LaRossa said only that the work already done has improved the utility’s “readiness” for the future.
Growing EV Use
LaRossa said the utility also is “developing proposals to help support and advance” New Jersey’s updated and expanded clean energy policy, which PSEG expects will be primarily implemented by the BPU. The utility is paying particularly close attention to three climate change-related executive orders signed by Gov. Phil Murphy in February, including one to bring about electrification of 400,000 homes by 2035 and to require all electricity sold in the state to be derived from clean sources by the same year.
Another measure would end the sale of gas-powered cars and light-duty trucks by 2035.
LaRossa said the company is seeing signs that the state is turning to EVs.
“We are starting to see some new business requests come in,” he said. “We see it in some of the Garden State Parkway rest stops. We’re seeing it in the New Jersey Turnpike rest stops. We’re seeing it in some of the large commercial organizations that were just granted approval by the BPU, that will install the charging infrastructure.”
“We’re going to keep an eye on that and see about what kind of capital is required for each one of those installations on a standalone basis to help us in projection going forward. But it’s just the start,” he said.
LaRossa added that he expects more information will become available over the next 12 months as the company deploys more advanced metering infrastructure, which uses smart meters to collect and communicate energy use data, and as “we start to see folks connect their EVs.”
He said he was “really excited” by the apparent interest in EVs, especially after the BPU on April 24 announced the recipients of the first round of grants under its Electric Vehicle Tourism Program and opened a second round of grant applications. The program provides funding to support the installation of EV charging stations at tourist sites around the state. In the first round it awarded $755,000 to 16 applicants who together will install 43 chargers.
Cash Flow from Nuclear
LaRossa said PSEG is looking to evaluate how it might boost the capacity of its three South Jersey nuclear plants in the second half of this decade.
Asked by an analyst about the future of the nuclear fleet, LaRossa said, “We want to and expect to keep those assets in our portfolio. I don’t see any scenario that we’ve been presented with that would make us waver from that.
“They are a great cash flow. They’ve been run really, really well. And they continue to be run really well,” he said. “And so, when you have that operating excellence, combined with the cash flow, it does create a very unique utility-like revenue stream for us that we think differentiates us from some of our peers.”
Company officials said they are awaiting direction from the U.S. Treasury Department about how to handle different aspects of the nuclear Production Tax Credit (PTC) approved under the Inflation Reduction Act. When that becomes clear, the utility can work out how that will affect the economics of its three plants and the future of the subsidies they receive under the state’s Zero-Emission Certificate program. (See NJ Nukes Awarded $300 Million in ZECs.)
“One of the things that we were saying that was so, so important is that we have a long-term solution for nuclear,” said PSEG CFO Dan Cregg.
He said the company was “happy” that the PTC created a long-term solution for profitably operating nuclear plants.
Earnings
PSEG reported first-quarter net income of $1,287 million, ($2.58/share) compared to a loss of $2 million ($0.01/share) for the first quarter of 2022. Non-GAAP operating earnings for the first quarter were $695 million ($1.39/share) compared with non-GAAP earnings of $672 million ($1.33/share).
LaRossa said the results show the company “delivered solid operating and financial performance to begin the year, and we are on track to achieve our full-year 2023 non-GAAP Operating Earnings guidance.
“We are executing our plan to grow PSEG while also increasing its predictability,” he said.
VALLEY FORGE, Pa. — PJM stakeholders provided feedback to the Board of Managers on a potential review of the Independent Market Monitor contract during the Markets and Reliability Committee meeting Wednesday.
Manager David Mills said the current deliberations are focused on the structure of the contract, not the performance of the current contract holder, Monitoring Analytics, nor whether the company will continue to hold the contract.
“It’s been quite some time since these documents were reviewed, and in that time, PJM has had a significant amount of turnover on the board,” Mills said. “This is not a performance review or referendum on Monitoring Analytics.”
Paul Sotkiewicz, president of E-Cubed Policy Associates, pushed for the board to consider issuing a request for proposals.
“If it turns out Monitoring Analytics is the best outfit to do this, that’s great … but I do think this should be open to a competitive process,” he said.
Vitol’s Jason Barker said the contract states that the PJM board has the responsibility to evaluate the Monitor’s performance, but it doesn’t provide any measure to benchmark against. He advocated for a third party to be retained to look at topics such as whether Monitor comments are pertinent and influence the outcome of FERC orders, and the impact of Monitor participation in the stakeholder process.
“We encourage the board not only to retain this provision … but also to use it,” he said.
Susan Bruce, of the PJM Industrial Customer Coalition (ICC), said the cost of market manipulation in PJM’s market is high and customers are willing to pay for a monitor who can push for stronger competition. While she said discussion of the Monitor’s role is appreciated, she cautioned against holding an RFP, saying that continuity is critical to the IMM’s work.
“There’s a place here for history and understanding how the markets work,” she said.
The topic of reviewing the contract was first raised in the board’s Competitive Market Committee. Mills, the committee’s chair, reiterated the board’s commitment to a monitor empowered to curtail market manipulation.
“None of this is intended to tear apart or destroy the foundation of a strong market monitor,” he said.
The board had previously solicited stakeholder input through the Liaison Committee and last month at the Organization of PJM States Inc.’s meeting, where Mills said comments addressed data access, intellectual property rights for proprietary software and calculations used by the Monitor, and how the contract handles succession.
Mills said the board plans to provide a public written summary of the comments it has received this month.
