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OIL & GAS: The U.S. Energy Department approves a $189 million loan to build a real-time laser monitoring network to track methane emissions from oil and gas facilities in Colorado, New Mexico and other states. (Reuters)
ALSO: New Mexico regulators agree to plug and reclaim a Texas company’s 300 idle oil and gas wells and allow the operator to reimburse the state over the next several decades. (KOAT 7)
NATURAL GAS: New Mexico regulators begin hearings on a controversial proposed natural gas storage facility in Rio Rancho. (Santa Fe New Mexican)
NUCLEAR:
CLIMATE:
SOLAR:
TRANSPORTATION: A proposal to establish a half-cent sales tax to fund road repairs, carpool lanes and expanded public transit in San Diego County qualifies for the Nov. 5 ballot. (San Diego Union-Tribune)
CARBON CAPTURE: A California county proposes charging companies a per-acre fee for sequestering captured carbon. (Bakersfield Californian)
COMMENTARY:
The following story is the first in a series produced in collaboration with KAXE/KBXE, an independent, nonprofit community radio station that tells the stories of northern Minnesota.
World leaders in Dubai this week are concluding the latest United Nations conference on climate change, where experts and advocates repeated urgent pleas for governments to phase out fossil fuels and transition to clean energy.
In Minnesota, that change is underway. A new state law requires power companies to only sell clean electricity by 2040. Electric vehicle sales are growing, and energy efficient heat pumps are starting to replace gas furnaces — even in northern Minnesota.
But one of the biggest challenges for eliminating greenhouse gas emissions in Minnesota will be finding clean energy solutions for one of the state’s biggest industries: taconite mining. The state’s Iron Range supplies three-quarters of the raw material used to make domestic steel. Getting it out of the ground requires massive, diesel-powered trucks and other heavy-duty equipment for which less-polluting options aren’t yet widely available.
The steelmaking industry is facing pressure from customers and governments to reduce its climate impact, and Minnesota mine operators Cleveland-Cliffs and U.S. Steel are both exploring new fuels and technologies to help them meet sustainability goals.
According to the companies’ public statements to shareholders, the path forward is likely to include investments in new, more efficient vehicles and equipment, along with a switch to powering them with renewable electricity, biogas, or hydrogen instead of coal or gas.
U.S. Steel announced in April 2021 a goal to achieve net-zero carbon emissions by 2050. Cleveland-Cliffs says it’s already exceeded its goal of reducing greenhouse gas emissions 25% by 2030.
The transition to clean energy could create new economic opportunities for the Iron Range, experts say, including the possibility to process iron ore on-site into a cleaner, premium product.
A recent event hosted by the city of Duluth and the National Renewable Energy Lab called industrial decarbonization the “billion-dollar question for the Northland.” Rolf Weberg, leader of the University of Minnesota-Duluth’s Natural Resources Research Institute, says industrial operations have a real interest in reducing their carbon footprints.
“When you look globally between steel and concrete, that accounts for between 16-18% of carbon dioxide emissions globally,” Weberg explained. “Countries and industries are really trying to reduce their carbon footprint because we’re not meeting carbon goals across the globe.”
Weberg said NREL is interested in Minnesota because of its resources. Hydrogen, for example, is a clean-burning fuel that can be produced with no emissions using water and renewable energy – both relatively plentiful in Minnesota.
“(This includes) infrastructure for future energy, access to water — all of the things you need to have a hydrogen-based approach to preparing green iron and steel,” he said.
Aaron Brown, a Hibbing native and columnist who has written extensively about the region’s culture and economy, says the Iron Range is in a unique position to capitalize on new technologies and production methods designed to eliminate climate emissions. For example, one strategy steelmakers are exploring involves processing higher-grade iron pellets in electric arc furnaces, which is less geographically constrained by access to coal.
“What the new technology might do is create opportunities for entrepreneurs, and existing companies like Cleveland-Cliffs or U.S. Steel, to produce (steel) in Minnesota,” Brown said in a phone interview. “Now, whether that will happen or not, of course, is subject to speculation, but it is an opportunity to open up modern industry near the mouth of iron mines. And that should be very interesting to people in northern Minnesota.”
Minnesota’s Iron Range has experienced monumental shifts since settlers found iron-rich deposits there in the late 19th century. The giants of American industry — James J. Hill, Andrew Carnegie and John D. Rockefeller — collectively created U.S. Steel, the world’s first billion-dollar company, with iron ore largely mined from the Iron Range.
Taconite is a hard, dense rock containing a mixture of silicates and magnetite. After it’s mined in vast open pits, it is crushed into a fine powder, with the magnetite extracted to eventually create marble-sized pellets that contain over 65% iron.
Mining efforts in the Mesabi Iron Range have focused on taconite ore, a lower-grade iron ore processed from vast pits, since the 1950s. Taconite mining transformed the region after underground mining depleted the high-grade hematite deposits. Forty million tons of iron ore are mined there each year.
That ore from Minnesota is shipped across the Great Lakes to plants from Chicago to Pittsburgh, where it is combined with coke, a product derived from coal that is shipped by rail from Appalachia to make steel.
But what if coal were taken out of this equation? New shifts in technology are moving toward using specially formulated iron briquettes in electric arc furnaces instead of lower-grade iron materials in coal-powered blast furnaces. And Iron Range taconite plant owners Cleveland-Cliffs and U.S. Steel are both increasing production of a new type of iron pellet that does not require coal-powered blast furnaces to process into steel. Electricity can be used instead, meaning a rail connection to coal mines may no longer be necessary for processing the raw material into steel.
These direct reduced-grade pellets are a metallic iron product instead of an iron oxide product like taconite. And they require less energy to process. The company did not respond to interview requests, but its website lists the environmental benefits of these pellets.
“If we converted United Taconite’s full standard pellet production … net greenhouse gas emissions would decrease by approximately 370,000 tons per year,” Cleveland-Cliffs states.
U.S. Steel announced in 2022 plans to break ground on a new $150 million direct reduced iron production facility near Keewatin on the Range. In November 2022, the company announced Keetac was the selected site for the expanded operation. Keetac currently employs about 400 people.
“Keetac’s high quality ore body and long mine life makes it the best choice for DR-grade pellet capabilities. We will have the ability to produce both blast furnace and DR-grade pellets at Keetac in the future. These actions will allow us to become increasingly self-sufficient to feed our mini mills segment with key metallics.”
Weberg defines “green” iron and steel as having no fossil fuels involved at any point in its production.
“Our iron industry in Minnesota has been working toward this for some time,” Weberg said. “Our colleagues at Cleveland-Cliffs and at U.S. Steel have been making significant progress with direct reduced grade pellets.”
Brown speculated about a possible future with steel created using hydrogen power and what that could mean for the Iron Range.
“What hydrogen steel might do for Minnesota is create the opportunity … for efficient and profitable steel production near where the mining occurs — an opportunity that doesn’t exist now because the cost of getting the coke and coal … to Minnesota is prohibitive,” Brown said.
As in decades before, the ebbs and flows of the global steel market will continue to impact the Iron Range. As policymakers and manufacturers look toward a sustainable future, the Iron Range may be well poised to prosper in a new, green economy built on the industrious foundation of its core: mining.
The following story is the second in a series produced in collaboration with KAXE/KBXE, an independent, nonprofit community radio station that tells the stories of northern Minnesota.
Minnesota taconite mine operator Cleveland-Cliffs is testing a new method for treating industrial wastewater in hopes of decreasing water, chemical and energy use — as well as costs.
The project is among several efforts by the company to lower its energy use as steelmakers face growing pressure from governments, investors, and customers to reduce the climate impact of their operations.
Energy efficiency is often the quickest and most cost-effective way for companies to cut their carbon footprint. When it comes to mining, the opportunity is as large as the massive trucks and other heavy-duty equipment used to haul and process taconite.
Cleveland-Cliffs was recently recognized by the U.S. Department of Energy for cutting companywide energy use by nearly one-third since 2017. The federal agency’s office of industrial efficiency and decarbonization is monitoring the water treatment project, as well.
“Bringing these emerging technologies out of the laboratory and onto the factory floor is a critical part of reaching our industrial decarbonization goals,” said Avi Schultz, director of the Industrial Efficiency and Decarbonization Office.
Decarbonization refers to the process of lowering or eliminating emissions of carbon dioxide, the heat-trapping greenhouse gas that causes climate change. The steel industry is among the three biggest sources of carbon emissions on the planet, accounting for around 8% of all global carbon emissions. Most steelmakers, including those that own and operate the Iron Range’s taconite mines, have adopted internal goals for reducing emissions.
“One of the most important issues impacting our industry, our stakeholders and our planet is climate change,” Cleveland-Cliffs told its investors this year. “We plan to achieve our GHG emissions reduction goal by focusing on actionable, commercially viable technologies and solutions while supporting research for breakthrough technologies for the primary iron and steel sector.”
It cited its partnership with the U.S. Department of Energy to implement and test energy-saving technology as a key piece of its climate strategy.
Cleveland-Cliffs operates Hibbing Taconite, United Taconite, Northshore Mining and the Minorca Mine on Minnesota’s Iron Range. The company is working with Arizona-based Dynamic Water Technologies on two pilot projects to reduce lost water and energy waste from treating wastewater.
The technologies are first being tested in a Cleveland, Ohio, plant.
Michael Boyko is the co-founder and director of business development for Dynamic Water Technologies. He said the equipment being studied is fundamentally better at what it does.
“These technologies are justified because they do it better, faster, and more cost effectively,” Boyko said. “If they were just an environmental benefit with no water, sewer, or chemical savings, it would be a harder sell to industrial clients.”
The project is piloting two different technologies for oil and hydrocarbon removal. One is called electrocoagulation, and the other is electrochemical water treatment.
Electrocoagulation is done by applying direct-current electricity to iron plates, which creates a coagulant that bonds with contaminants in the water and makes them much larger. These enlarged particles then either float to the top or sink to the bottom, making them easier to remove.
Boyko said this process eliminates the need for several chemical processes and various agitators, mixers and pumps along the way, making it more cost-effective and faster.
“There’s definitely a lot of energy savings, because we’re doing in one process what seven different chemical water treatment systems basically were doing,” he said.
Electrochemical water treatment, meanwhile, replaces chemical treatment of processed water within cooling towers using dynamic scale reactor technology. This technology quickens the natural process of scale buildup from minerals within reactor chambers, sequestering it for later removal. The process allows the same water to cycle through the system eight or more times, instead of as few as three.
Cleveland-Cliffs did not respond to interview requests, but the company touted the technology’s environmental benefits in its most recent sustainability report.
“The alternative technology yielded significant reduction in solid waste from process water, and preliminary data shows it could also increase process water reuse,” the report said.
This technology is already in use at Los Angeles City Hall and the Juliette Gordon Low Federal Building in Savannah, Georgia, with federal government testing validating the positive effects.
Cleveland-Cliffs also participates in the Department of Energy’s Better Buildings program. The voluntary program encourages improved energy performance across industrial operations, which account for more than one-third of total U.S. end-use energy consumption.
“This is essential for the industrial sector, as inattention to greenhouse gas emissions, inefficient energy and water use, and excessive waste production can hurt domestic competitiveness in a global marketplace,” the department says.
A detailed report of the Cleveland-Cliffs project is expected to be issued by the end of the year.
The following story is the fourth in a series produced in collaboration with KAXE/KBXE, an independent, nonprofit community radio station that tells the stories of northern Minnesota.
A Hoyt Lakes native leading a regional hydrogen partnership says the emerging fuel source could someday help make Minnesota’s Iron Range a leader in the production of green steel.
“Yes, certainly it has great potential,” said Tom Erickson, president and chief operating officer of the Heartland Hydrogen Hub, one of seven regional projects recently funded by the U.S. Department of Energy to kickstart hydrogen fuel production. “The first obvious use of hydrogen within the taconite (mining) industry is just to produce electricity.”
The federal government is investing billions to develop regional hydrogen production hubs, intended to spur the infrastructure needed to increase the supply and lower the cost enough to make it commercially viable.
Hydrogen emits only water vapor and warm air when burned, but it’s typically produced from natural gas in a process that creates high greenhouse gas emissions. The Heartland Hydrogen Hub will use renewable energy and nuclear power to try to reduce the climate impact, as well as the price tag.
The initial focus will be on supplying hydrogen for ammonia fertilizer, but Erickson said the same output could also replace more carbon-intensive fuels used to heat and power taconite mining operations on the Iron Range.
“That industry uses a lot of natural gas for heat and thermal systems, for producing the pellets,” Erickson said. “You’d have to design (the systems) quite a bit differently, but you could certainly add some hydrogen power to that and decrease the emissions from that standpoint.”
The most abundant element in the universe, hydrogen has historically been difficult to harness into energy. The Hindenburg Disaster of 1937 is an infamous example that demonstrates hydrogen’s explosive qualities.
“You can’t mine it. You can’t stick a pipe in the ground, then bring hydrogen up. You have to produce it from something else. It’s the smallest molecule, the hardest one to trap,” Erickson explained. “It’s the hardest one to move around once you’ve produced it, so we have some things that we need to get over and get behind coming up with new innovative ideas to really bring the costs down.”
Most commercial hydrogen is produced today by separating the hydrogen atoms from methane under high heat and pressure, with many industrial facilities using natural gas as the methane source. This method produces hydrogen, carbon monoxide and a relatively small amount of carbon dioxide.
Electrolysis splits hydrogen from water using an electric current. This method does not create any byproducts or emissions other than oxygen and hydrogen. It is the primary focus of the Department of Energy’s investment into hydrogen energy.
The Heartland Hydrogen Hub’s projects are expected to reduce carbon emissions by roughly 1 million metric tons per year, the equivalent of 220,000 gasoline-powered cars.
Erickson — who is also the director of exploratory research at University of North Dakota — said infrastructure for hydrogen’s use on a wider scale is in the future.
“Shipping — whether it’s trains or whether it’s ships moving large quantities of oil around — they are even bigger targets,” he said. “Maybe even a little bit easier targets for application of the hydrogen fuel.”
Erickson, whose grandfather and numerous other relatives worked in the taconite mines on the Iron Range, said technology to produce higher quality taconite pellets has been studied in Keewatin, where U.S. Steel plans to invest $150 million in a new higher-grade taconite plant.
“Folks on the Range have looked at (higher grade taconite pellets) produced from natural gas, from coal derived gases and of course from hydrogen,” Erickson said.
The Heartland Hydrogen Hub is currently in the concept development phase, and Erickson said he is excited for the advancing technology in energy for the future.
“What I’m most excited about is to start to see larger scale production of hydrogen,” he said. “Once we start producing it, we can start to find other ways to utilize the things that advantages society, different ways that we can manipulate the molecule …. to provide clean, reliable and sustainable energy.”
Steel is made using a lot of heat, and coal-powered blast furnaces are still used for 57% of global steelmaking capacity. That’s a decrease from the year before, when 67% of the world’s steel capacity was made using blast furnaces — marking a shift toward electric arc furnace technology worldwide.
The Iron Range supplies three-fourths of the country’s iron ore, from which steel is made. Steelmakers such as U.S. Steel and Cleveland-Cliffs, which own the mining operations on the Iron Range, are seeing growing pressure from governments, investors, and customers to reduce their climate emissions. It’s not just the potential for future environmental regulations. More companies are willing to pay a premium for steel that comes with a smaller carbon footprint.
Cutting emissions from mining and other heavy industry is expected to be a bigger challenge than cleaning up cars or power plants. That’s because of the need to power massive furnaces and other equipment for which electric alternatives aren’t widely available.
These factors are leading many manufacturers to be interested in the potential of hydrogen fuel. Cleveland-Cliffs, which owns and operates Hibbing Taconite, has already committed to funding a hydrogen power project at its Toledo plant. Without any modification to the plant, the company says it could replace up to 30% of natural gas consumption with hydrogen. And with equipment upgrades and other investments, this number could rise to 70%, accounting for 1 million metric tons of greenhouse gases each year.
Cleveland-Cliffs is also part of a federally funded hydrogen hub based in northern Indiana. In October, the company was recognized by the U.S. Department of Energy for cutting its greenhouse gas emissions by more than one-third.
The company didn’t respond to requests for comment on what its emission-cutting efforts might mean for northern Minnesota, but researcher Rolf Weberg said the state’s mining industry is well-positioned to make use of hydrogen fuel.
“It turns out that Minnesota is by far highly competitive for making green iron and steel, beyond other states in the country,” said Weberg, the executive director of University of Minnesota-Duluth’s Natural Resource Research Institute. “We have essentially all of the resources, including infrastructure for future energy and access to water. All the things you need to have for a hydrogen-based approach to preparing green iron and steel.”
With the future of hydrogen energy, Weberg said conversations with stakeholders are only just beginning.
“Minnesota industry has been investing to prepare for this,” Weberg said. “It’s an exciting opportunity for Minnesota to embrace, and the conversation is just started. This is an opportunity to really lead the charge in this area, and also do it in tandem with green hydrogen and green steel.”
Ohio-based Cleveland-Cliffs’ success in beating its goal to cut greenhouse gas emissions from its U.S. iron and steel operations won recognition from the Department of Energy last month.
The progress is part of a broader industry trend to cut pollution that drives human-caused climate change. Yet advocates say there’s lots of room for further cuts.
Cliffs slashed greenhouse gas emissions for almost four dozen U.S. facilities by nearly one-third from a 2017 baseline as of the end of last year. As a result, the Department of Energy named the company a 2023 Goal Achiever in the agency’s Better Climate Challenge.
The steel industry was responsible for about 7% of global carbon dioxide emissions as of 2020, the U.S. Energy Information Administration reported last year. That’s roughly one-sixth of all worldwide emissions from generating power, according to a Canary Media analysis of the International Energy Agency data. The iron and steel industry led the industrial sector, with the cement industry coming in second.
The achievement and ongoing decarbonization efforts by Cliffs and other companies stand out because the steel industry has been seen as a hard-to-decarbonize sector, due to its need for high heat and continuous operations, as well as process reactions that emit more carbon dioxide.
At the same time, the energy transition and growth of renewable energy will likely increase demand for steel, and global demand for low-carbon steel should grow as well, according to a McKinsey & Company analysis released earlier this year. Companies in the steel industry also see a need to curb emissions in order to limit the worst impacts of climate change.
“We do know that we play a role in global warming,” said Traci Forrester, executive vice president for environmental and sustainability matters at Cliffs.
Added incentives come from the prospect of possible government regulation of carbon emissions in order to address climate change, as noted in the company’s 2022 annual report to shareholders, released this past April.
Customer demands also play a role. “At U.S. Steel, it’s not just about reducing our own carbon footprint,” said Arista Joyner, who manages financial and sustainability communications for that company. “We must adapt to the changing needs of our customers and their sustainability goals too.”
The traditional method of making steel mixes iron ore in a blast furnace with a high-carbon form of coal, called coke. The carbon combines with oxygen in the ore to form carbon dioxide. The iron melts. Other leftover waste takes the form of slag.
The iron — called “pig iron” at this stage — is then sent to a second furnace that blows in oxygen to make steel from the iron and some other elements. That also releases greenhouse gas emissions.
Together, the two steps account for nearly three-fourths of the U.S. iron and steel industry’s carbon dioxide emissions, according to RMI, a nonprofit whose work focuses on decarbonization.
Much of Cliffs’ progress on emissions is thanks to the 2020 opening of its “direct reduction” plant in Toledo. The facility starts with pelletized iron ore, which comes primarily from Minnesota, where a preliminary baking process has already removed some impurities.
Direct reduction removes oxygen from the ore with reformed methane, which is basically a combination of carbon monoxide and hydrogen. Both the hydrogen atoms and the carbon monoxide molecules can combine chemically with the oxygen. So, direct reduction is a lower-carbon way to process the ore pellets. The plant’s output is hot briquetted iron.
The Toledo plant has not eliminated the company’s use of blast furnaces. But hot briquetted iron can reduce the amount of coke needed if its next stop is a blast furnace, Forrester said. Transporting the briquettes while they’re hot also cuts down on fuel needs there or for the oxygen process furnace.
Hot briquetted iron can also go into an electric arc furnace. The steel industry mainly uses those furnaces now to recycle scrap steel.
“The beauty of steel is that it’s infinitely recyclable,” said Rich Freuhauf. The senior vice president and chief strategy and sustainability officer for U.S. Steel spoke at a Reuters Industry Transition conference in September.
Recycling eliminates the need to repeat the carbon dioxide-releasing steps of refining iron ore. And, as the name implies, electric arc furnaces run on electricity. So they could use nuclear power or renewable energy with battery storage instead of fossil fuels.
But recycled steel from electric arc furnaces won’t necessarily satisfy all the forecast demands for steel. Nor does it yet meet the requirements for some higher-grade or specialty types of steel. Those include higher-strength steel and high-ductility steel, which can be formed into different shapes, such as the exposed panels on automobiles.
“That’s really our niche in servicing the automotive market, in addition to many other markets,” Forrester said. Some carbon content can also help achieve different properties in steel.
Cliffs’ emissions cuts also reflect energy efficiency improvements throughout its facilities, Forrester said. And there’s room for more emissions reductions.
Cliffs is part of the Midwest Alliance for Clean Hydrogen. Assuming acceptable agreements can be negotiated with the agency, the coalition stands to get up to $1 billion in hydrogen hub funding, the Department of Energy announced last month.
The hub could help supply Cliffs’ Indiana Harbor and Burns Harbor plants. Hydrogen would likely be blended with natural gas at first, Forrester said. Then, if all goes well, hydrogen could substitute for more or potentially all of the fossil fuel.
Cliffs also was part of the Great Lakes Clean Hydrogen Hub Coalition, which proposed making so-called “pink hydrogen” with excess electricity at the Davis-Besse nuclear plant in Ohio. Although DOE did not pick the project for a regional hydrogen hub award, the Energy Harbor plant has been working on hydrogen production for several years. Spokesperson Todd Morgano said the project “is scheduled to be operational by spring of 2024.”
The steel industry has also been buying more renewable energy. Last December, for example, Cliffs agreed to a 15-year power purchase agreement with EDP Renewables for 180 megawatts of power from a wind farm in Indiana near the Ohio border. State laws passed in 2014 and 2021 make it extremely difficult to site new commercial wind farms in Ohio.
Carbon capture utilization and storage, or CCUS, could also curb the steel industry’s emissions, although its feasibility hasn’t been proven yet.
“While carbon capture technologies exist and are widely adopted in the oil and gas realm and some other industries, carbon capture has never been done with blast furnace gas,” Forrester said. Cliffs has multiple facilities near areas with suitable geologic formations for storing the waste carbon dioxide, she noted.
Other research is exploring whether carbon might be further cut or eliminated from the ore-processing stages. In June, the Department of Energy announced nearly $32 million in funding for projects to decarbonize iron and steel.
One of the 10 projects that won funding, led by Cleveland’s Case Western Reserve University, would use an electric current with molten salt to strip oxygen from iron ore. Case Western is also among the partners for the Center for Steel Electrification by Electrosynthesis, headed by Argonne National Laboratory in Lemont, Illinois.
“From our standpoint, Cleveland-Cliffs has been a good actor to date,” said Nick Yavorsky, an RMI industry analyst who co-authored a September report on opportunities for making near-zero-emissions steel in the Great Lakes region. But, he added, “now we have to look at the big stuff.”
While hydrogen could potentially power all of a direct reduction plant, there are limits on how much could be blended with coal at a blast furnace, he said. Further big cuts would likely call for retiring coal-burning blast furnaces and replacing them with more direct reduction plants. Yavorsky said he also thinks most specialty steel products could be made in electric arc furnaces run on renewables or nuclear power with hot briquetted iron.
Ohio policymakers could support investments to achieve those shifts, including through existing programs for JobsOhio, said Lachlan Carey, an RMI policy analyst and economist who also worked on the September report. Supporting green steel could increase the state’s steel industry employment, while also enhancing Ohio’s ability to attract other manufacturing jobs where companies want access to clean energy, he said.
U.S. Steel has already committed to net-zero greenhouse gas emissions by 2050, Freuhauf said. Cliffs has so far shied away from that.
“We take a very practical approach to reducing greenhouse gases and the statements and promises that we make,” Forrester said, adding that while the company has aspirations, it focuses on what it knows it can achieve. “We take action on what we can today,” she said.
As an Ohio uranium enrichment plant opened this month, yet another study questioned whether nuclear power from small modular reactors can compete with other types of electricity generation.
Centrus Energy’s new plant in Piketon produces high-assay, low-enriched uranium, or HALEU. The fuel will contain between 5% and 20% fissile uranium, or U-235, which is the range needed for various types of small modular reactors, or SMRs. The current fleet of large nuclear reactors uses fuel with up to 5% U-235.
Large nuclear plants have had problems competing with other types of electricity generation in recent years. Ohio’s House Bill 6 would have mandated ratepayer spending of more than $1 billion to subsidize the 894-megawatt Davis-Besse plant and 3,758-megawatt Perry plant in Ohio, for example. Lawmakers repealed that law’s nuclear subsidies after alleged corruption came to light.
Now the question is whether small modular reactors designed to produce up to 300 MW of electricity can compete better.
Huge gigawatt-scale nuclear plants can have economies of scale because their power output grows faster than increases in capital and operating expenditures.
“However, the extensive customization of many of the currently deployed reactors undercuts much of that economy,” said William Madia, a nuclear chemist and emeritus professor at Stanford University who is now a member of Centrus’ board of directors.
The lack of a standard design also makes it harder for large reactors to get replacement parts when needed. “Things like large-scale forgings are in short supply globally,” Madia noted.
In contrast, small modular reactors can be built in indoor factories and then sent to where they’ll be used. That avoids site-by-site mobilization costs, as well as weather problems that might interrupt construction.
“But the real driver is standardized design,” Madia said. So eventually, production can take place on assembly lines. And that should produce its own economies.
All in all, “the capital cost for SMRs is much lower than GW-scale machines,” Madia said. Also, if the choice is between lower-cost modular reactors and huge ones, “many, many more utilities can afford a few billion dollars on their balance sheets. Very few can handle $10-plus billion.”
No small modular reactors are operating commercially in the United States yet.
“Right now, if you’re looking to spend money on bringing new generation online, you have tech that you know works with wind and solar and storage,” said Neil Waggoner, federal deputy director for energy campaigns at the Sierra Club.
An analysis published this month by the journal Energy estimated the levelized cost of electricity, or LCOE, for different types of small modular reactors. The LCOE basically reflects the average costs for producing a unit of power over the course of a generation source’s lifetime.
Small modular reactors “seem to be non-competitive when compared to current costs for generating electricity from renewable energy sources,” the Energy study found.
Comparing intermittent resources like wind and solar to “dispatchable resources with small land footprints is a flawed exercise,” said Diane Hughes, vice president of marketing and communications for NuScale Power. Nuclear energy from small reactors requires little new transmission infrastructure, she added. So, “the cost per plant is comprehensive in a way that one solar array or wind farm is not.”
Yet the Energy study found renewables would still be more competitive even with added system integration costs that would roughly double the levelized cost of electricity.
“These costs can stem from batteries, but there are also many other means of flexibility that can be used,” said Jens Weibezahn, one of the study’s corresponding authors and an economist at the Copenhagen Business School’s School of Energy Infrastructure.
Weibezahn’s group got similar results when they compared the projected market value for energy from small modular reactors with the weighted market value for renewable electricity at the time of generation. Costs for dealing with radioactive waste “will add a significant additional economic burden” on nuclear technologies, he added.
A March 2023 study by Colorado State University researchers suggested the economics for SMRs wouldn’t be dramatically better than those for large reactors. The researchers also found the levelized costs of electricity for different types of small modular reactors would be substantially higher than that for natural gas power plants without carbon capture.
However, “natural gas plants release tremendous amounts of greenhouse gases which engender societal and environmental costs,” said the paper in Applied Energy. Adding in carbon capture increased the estimated levelized cost of energy for the natural gas plants to the general range for the small modular reactors.
Commercial methane-fired power plants with carbon capture are not yet running at scale. The American Petroleum Association has objected to proposed rules that might effectively require such equipment.
How things will shake out in the future is unclear, said Jason Quinn, who heads the sustainability laboratory at Colorado State University and is the corresponding author for the March study. But, he added, “typically decisions are driven on economics, and current SMR estimates show them not to be a commercially viable solution as compared to other technologies.”
For now, initial production at the Centrus HALEU plant will meet a commitment to the Department of Energy. Centrus expects the plant will employ up to 500 direct employees when it moves to full-scale commercial production, said Larry Cutlip, vice president for field operations. Supporting industries will provide work for another 1,000 to 1,300 people. And all those workers could stimulate economic activity for roughly eight times as many jobs, he added.
Centrus already plans to supply HALEU fuel to TerraPower and Oklo, Inc. Each company has its own individual SMR design and is working with the Nuclear Regulatory Commission toward having the designs certified.
Oklo plans to build two sodium-cooled fast reactors in Piketon near the Centrus’s HALEU production plant. Each of the SMRs could supply up to 15 MW of electricity and more than 25 MW of clean heating, said spokesperson Bonita Chester.
Plans call for the SMRs to supply some carbon-free electricity for the Centrus facility. Other possible customers for electricity include commercial, industrial or municipal entities.
“As for the clean heating output, we envisage potential industrial partners and applications for district heating systems,” Chester said.
The ability to sell or otherwise use the heat as well as electricity could potentially lower the average costs.
“We are committed to ensuring that our electricity and heating output remain competitive with other forms of energy generation,” Chester added. “Our technology benefits from simplified design and cost-effective materials, making it an economically effective option.”
NuScale plans to deploy a dozen 77-megawatt small modular reactors in Ohio and another dozen in Pennsylvania for Standard Power data center projects by 2029. Those pressurized water reactors can use low-enriched uranium and won’t need HALEU, Hughes noted.
Deputy Secretary of Energy David Turk expects HALEU and small nuclear reactors that rely on it will be competitive.
“People appreciate the importance of baseload power, and I think that will be even more important as we further decarbonize the electricity economy,” Turk said. That will appropriately include more wind and solar energy, “but it’s good to have that baseload power to make it all work in the end.”
Electricity from SMRs will be “a real source of energy security and energy resilience,” Turk added. “You need diversification, but you need to have a variety of different inputs going into the system.”
“Nuclear certainly can provide baseload, but it does this at a cost significantly higher than an integrated renewables-based system,” Weibezahn said.
A bigger question may be whether there will be enough carbon-free electricity.
The Department of Energy estimates the United States will need to triple nuclear energy production to about 300 GW by 2050. That growth will be driven by advanced nuclear technologies, much of which will use HALEU.
“If we want to meet our climate goals and meaningfully reduce carbon emissions, we need all sources of clean energy, including wind, solar and nuclear energy,” said Jess Gehin, associate lab director for nuclear science and technology at Idaho National Laboratory. “Current projections show that we cannot meet our climate goals without nuclear energy.”
No, City Councilor Andreas Addison was never trying to ban cars in Richmond.
All along, his gambit to scrap parking space requirements for developers was about curtailing sprawl. It’s expected to curb emissions of heat-trapping gases in an evolving capital city that prizes walking, bicycling and ready access to public transit.
Addison is jubilant that the council has joined cities such as Seattle, Buffalo, Raleigh and Hartford by voting in late April to repeal decades-old zoning rules that forced new residential and commercial buildings to have a certain number of dedicated, off-street parking spots.
Instead, that number will be set by property owners and developers.
“It has been a journey,” Addison said about the conversations he initiated two years ago with anybody who would listen. “Usually the first reaction was, ‘Oh my God, you’re getting rid of parking.’”
That attitude matured as he explained his ordinance’s environmental benefits and how eradicating parking minimums could free up space for affordable and additional housing.
“I was surprised at how smooth and easy it was,” he said about the unanimous votes, first by the city Planning Commission and then by the council. “Even opponents who had spoken out against it, when they saw the writing on the wall, they said, ‘Fine.’”
Surveying the big parking picture, he envisions the new measure will “reinvent paved space” by introducing the concept of shared parking in off-street lots. Before, those spaces could only be used for the particular purpose laid out in the zoning code.
In conjunction, he is urging the city to streamline smartphone parking applications and windshield parking permits. The latter would better allow residents of popular neighborhoods to regularly access street parking near their homes.
For years, Addison, a gym owner who is an active walker, bicyclist and ride-sharer, was puzzled by the abundance of parking lots in the city empty during certain times. He realized most of them were designated for one specific use, which constrained access.
A city analysis of 50 large residential, commercial and mixed-use developments constructed over a recent five-year period confirmed his suspicions that regulations were contributing to a single-use parking glut. The study revealed that developers had built 12,600-plus spaces — more than double the 4,800 spaces required by rules.
“When that data was presented, I realized we don’t have a parking problem,” Addison said. “We have a lack-of-access-to-parking problem.”
Clean transportation specialists at the Washington, D.C.-based American Council for an Energy-Efficient Economy have kudos for Richmond and other cities thinking holistically about shrinking their carbon footprints.
“Land-use decisions are often forgotten in conversations about climate change,” said Shruti Vaidyanathan, the organization’s transportation program director. “We need to get people to think beyond electrification.
“Yes, electric vehicles will be a significant part of how we reduce emissions in the transportation sector, but we need to consider more than that.”
Auto-centric development since World War II has turned huge chunks of land into parking lots that could be dedicated instead to more compact communities where people can go car-free, she said.
“Places like Richmond are where electrification and other opportunities come together with creative people-focused transportation policy,” she said. “That’s when vehicle miles traveled, a big component of emissions, go down significantly.”
While vehicle miles traveled tapered off appreciably across the country during COVID-19, preliminary numbers indicate they are creeping back to pre-pandemic levels — which showed little sign of ebbing.
In Richmond, for instance, those annual figures stood at 1.97 billion miles in 2019, according to state Department of Transportation figures. That’s up from 1.79 billion miles in 2009.
Stewart Schwartz, president of the Richmond Partnership for Smarter Growth, said eliminating mandatory parking minimums would advance the goals of the city’s climate action plan, RVAGreen 2050.
Briefly, that plan calls for reducing greenhouse gas emissions by 45% by 2030 and achieving net-zero emissions by 2050. The baseline year is 2008.
The ordinance “is an essential tool to foster a city that is more affordable and dynamic while also minimizing car traffic, carbon emissions, and noise,” he wrote in a letter to the city Planning Commission. “At the same time, it must be combined with other initiatives.”
For instance, Schwartz urged the city to focus on safer walking conditions while also expanding public transit and adding lanes, sharing, parking and electric bikes to Richmond’s bicycling infrastructure.
The Greater Richmond Transit Company is heeding that plea. GRTC continues to offer fare-free buses, a policy instituted in March 2020 with the onset of the pandemic.
“Going fare-free has been a great tool for expanding our pool of ridership beyond our pre-pandemic numbers,” GRTC spokesperson Henry Bendon said. “Plus, we can offer more reliable and efficient bus service because customers don’t have to stop at the front of the bus to pay.”
One of the biggest boosters to ridership is the Pulse, a high-capacity, high-frequency rapid transit bus line that serves a busy 7.6-mile corridor along Broad and Main streets. It began operating five years ago as a congestion-reducing measure.
“We are in the process of expanding that type of service,” Bendon said. “You don’t sit in traffic. The reality is, people rely on this bus system. We continue to improve service and we’re really proud of that.”
Statewide, transportation of all methods accounts for the majority of greenhouse gas emissions. In 2019, the sector accounted for 52.5% of those emissions, according to calculations from the U.S. Energy Information Administration.
Much of that is because annual vehicle miles traveled in Virginia alone continue to rise — from 81 billion miles in 2009 to 85.4 billion miles in 2019 — according to the Federal Highway Administration.
City Councilor Katherine Jordan told her constituents that she supported the idea of stamping out parking minimums because cars are the No.1 source of greenhouse gas emissions in Richmond.
“Clearly, eliminating parking minimums will not ‘fix’ the climate crisis or our housing crisis, but I do believe this change will have a positive, cumulative impact on both,” she wrote in a memo.
Jordan, who served as a member of the Green City Commission before being elected, said “the walkable, historic, mixed-use and neighborhoods we love, like the Fan, Jackson Ward, and Carver could not be built today, in part because of onerous parking requirements for residential development.”
She also noted that the cost of building parking — between $10,000 to $40,000 per space — is a burden for neighborhood businesses and also saddles residents with higher rents and mortgages. That money would be better spent on filling the housing gap, she added.
Her sentiments have been echoed by city planners and others in Mayor Levar Stoney’s administration.
Collectively, they have emphasized that the ordinance eliminating parking minimums aligns with Richmond 300: A Guide for Growth, which was adopted in 2020. The master plan outlines specifics for a vision of sustainability, innovation and equity the city wants to achieve by 2037, its tricentennial year.
Both Jordan and Addison serve on the council’s Land Use, Housing and Transportation Committee.
Addison is hopeful Richmond’s decision to scale back on parking lots can be a model for other Virginia cities intent on reshaping how people move around.
That antiquated requirement meant a missed opportunity for growth, he said. “Changing it forces Richmond to be strategic about its future.”
Vermont’s only natural gas company is exploring possible sites for its first fossil-fuel-free, networked geothermal project, a heating and cooling technology that could be a natural fit for a company already skilled at designing and constructing piping systems.
“It’s a near-perfect overlay of our current business model,” said Richard Donnelly, director of energy innovation at Vermont Gas Systems, which currently serves about 55,000 customers.
Legislation pending before the House Committee on Environment and Energy could help speed such geothermal innovation. The bill, still awaiting a number, directs the state Public Utility Commission to adopt rules for permitting thermal energy networks — underground loops of liquid-filled pipes that are heated or cooled by the earth and connected to multiple buildings.
It would authorize any entity, not just existing utilities, to operate geothermal networks as regulated utilities, enabling them to recover their costs through the rates paid by customers.
“An electric cooperative, a homeowners’ association, a municipality, a large fuel dealer — they could become utilities so they could access the capital needed and recover their costs over time,” said Debbie New, a community organizer who helped draft and is promoting the legislation.
Emissions from heating and cooling buildings represent about 34% of Vermont’s carbon dioxide emissions. The state must find ways to reduce those emissions in order to meet its climate goals, and geothermal could be a key part of the solution, advocates say.
A geothermal system — or ground-source heat pump — consists of an underground piping network and a connected heat pump inside the building. Powered by electricity, the pump moves heat from the pipes to warm the building in cold weather. In hot weather, it reverses the process and draws heat from the building into the ground.
The pipes are placed at a depth where the earth’s temperature is relatively constant, around 50 degrees in Vermont.
The systems have no visual impact because they are underground. The pumps are significantly more efficient than other forms of heating and cooling, “and if the electricity being used is renewable, you can envision a really, truly decarbonized future,” said Jake Marin, senior emerging technology and services manager at Efficiency Vermont.
The downside, however, is cost.
“Without question, geothermal is one of the most, if not the most, expensive options out there,” Marin said. “The big question mark is, can we do this at scale? The networked geothermal is an interesting take on this. If that cost can be sucked up into a utility model and amortized over time with the end users paying an access fee to spread that out, the speculation is that that may be a good answer for helping to scale geothermal.”
Donnelly said Vermont Gas has been trying to develop a business model around geothermal for the past two years, “primarily because it’s a unique way for the company to use its core functions and decarbonize.”
The company is currently considering the feasibility of installing its first networked system at a multifamily housing construction project that includes some affordable units. They are largely focused on new construction projects as possible testing grounds because it is easier to put in a system where the ground hasn’t been developed yet, Donnelly said.
Vermont Gas previously submitted a proposal to develop a geothermal project at one of the buildings at Rutland Regional Medical Center, a hospital in central Vermont. But that idea was rejected by regulators last year, largely because Rutland is out of the utility’s service territory.
That rejection “is one example of a need for clear statutory guidance to direct development of these types of decarbonized projects in the future,” said Dylan Giambatista, director of public affairs for Vermont Gas.
Another bill identified by legislative leaders as a major priority this session would also help advance geothermal. Senate Bill 5, the Affordable Heat Act, would require importers of fossil heating fuels to compensate for that pollution by delivering or paying for cleaner heating options. It designates geothermal as one of the technologies that would generate the necessary clean heat credits.
Utilities in New York and Massachusetts are also exploring geothermal technology. Legislation adopted last year in New York directs the state’s seven largest gas and electric utilities to develop at least one and as many as five pilot thermal energy network projects.
And in Massachusetts, Eversource has broken ground on a networked geothermal system in a neighborhood in Framingham. The system will serve around 40 homes, as well as part of a school, a firehouse, and a few businesses, said Audrey Schulman, co-founder and co-executive director of the Home Energy Efficiency Team, known as HEET, a Cambridge-based nonprofit that has been promoting the networked concept.
The Framingham installation should be active by this fall. A research team assembled by HEET is studying every aspect of the system along the way, and will make the data available in a public data bank, Schulman said.
The organization’s outreach efforts with gas utilities around the country have so far yielded a coalition of about a dozen of them, including Vermont Gas, that are actively discussing or installing networked geothermal, she said.
“We believe the fastest way forward for building electrification is for us to work with gas utilities,” she said. “They will otherwise have no business plan going forward.”
The future business plan for Vermont Gas does not envision a complete transition to geothermal, however. The company’s long-term decarbonization objectives also call for renewable natural gas, green hydrogen, and carbon capture technology for industrial users.
The networked geothermal bill previously included a provision calling for a prohibition on the extension of natural gas transmission lines into new service territories. But Vermont Gas did not support that provision — “as we seek to decarbonize, flexibility is going to be very important,” Giambatista said.
So sponsors made the geothermal provision a standalone bill, uniting the gas utility and climate advocates behind it.
Virginia’s participation in an East Coast greenhouse gas emissions pact is pivotal to curbing the climate impact of its thriving data center industry.
Globally, northern Virginia has become one of the largest data center hubs over the last decade-plus. Offering generous tax incentives has attracted tech giants eager to construct massive server farms with proximity to crucial digital infrastructure. An estimated 70% of the world’s internet traffic moves through the suburbs of Washington, D.C., daily.
That burgeoning has propelled a surge in electricity use. In 2020, the sector consumed close to 12,000 gigawatt-hours in Dominion Energy’s territory — roughly one-sixth of the investor-owned utility’s total retail sales that same year.
And yet, the state’s carbon emissions from power plants have fallen 12% annually during the last two years.
William Shobe, an environmental policy professor at the University of Virginia, is among those crediting the 11-state Regional Greenhouse Gas Initiative. Known as RGGI, the initiative is a voluntary carbon cap-and-invest venture designed to tamp down heat-trapping gases emitted by the utility sector. Virginia’s downward emissions trend will halt without that cap in place, Shobe said.
Even as electricity-hungry data centers multiply across the state, RGGI’s binding carbon cap keeps emissions in check. Basically, the amount of fossil fuels a utility is allowed to burn shrinks each year as the cap is lowered.
It’s a crucial dynamic to understand, Shobe said, as Republican Gov. Glenn Youngkin has vowed to extract Virginia from the market-based climate initiative.
“As a planetary citizen, I’m happy with that [cap],” said Shobe, who directs the Energy Transition Initiative at the University of Virginia’s Weldon Cooper Center for Public Service. “If the state relaxes RGGI, then data centers have climate consequences that we need to worry about.”
He’s hopeful that legislators won’t follow Youngkin’s lead on RGGI during the session that opened last Wednesday. Republicans control the House of Delegates while Democrats have a majority in the Senate.
Shobe also argues that continuing to build data centers in Virginia can be a net positive for climate change — assuming data centers will be built somewhere and the state stays committed to the regional greenhouse gas program. That construction trend shows no signs of abating in Virginia for at least the next 10 years.
“As long as we are a member of RGGI, then we should encourage data centers here rather than Ohio, Indiana or someplace else without a cap on carbon dioxide emissions,” Shobe said.
Shobe played a significant role in designing the mechanisms behind RGGI, which debuted in 2009. In a nutshell, each member state limits emissions from fossil fuel power plants, issues carbon dioxide allowances and sets up participation in auctions for those allowances.
In 2020, Virginia became the first Southern state to join RGGI, after ample back-and-forth bickering. Advocates have hailed the program for its climate benefits and the upward of $450 million the allowance auction has so far yielded for statewide flood resiliency projects, energy efficiency upgrades, and home repairs for low-income residents statewide.
Youngkin has been itching to extract Virginia from RGGI since he took office a year ago. In early December, the state’s Air Pollution Control Board voted 4-1 to accelerate that exit.
Attorneys with environmental organizations maintain that the Youngkin administration lacks the authority to leave the compact. That decision, RGGI proponents say, is in the hands of the General Assembly. A legislative effort to derail RGGI failed last year.
The air board’s initial vote to leave RGGI will trigger a 60-day comment period this winter. Shobe and his colleagues are prepared to weigh in with insights that the board will review before voting again on the proposal.
Shobe published an electricity use forecast in April 2021 predicting that data centers will be the driving force behind a 38% increase in electricity sales between 2020 and 2035. That equals an average increase in electricity use of around 44,000 gigawatt-hours per year.
“Whether we think this is a good thing or not, data centers are growing very fast,” Shobe said. “Unfortunately, they use a lot of energy. How we provide that energy is what will make a difference.”
Shobe noted that residential electricity sales are close to flatlining due to slower population growth and improved energy efficiency. Likewise, commercial and industrial demand have fallen for several years.
For the most part, large technology companies have pledged to power their facilities with renewable energy. However, it’s unclear whether or how they are following through on those commitments.
Thus far, Virginia’s solar expansion is on pace with a legislative mandate to decarbonize the grid by 2050, Shobe said. But the state can’t afford a solar stumble if it’s going to feed the needs of voracious data centers.
Some in the environmental community doubt that server farms will be able to live up to their vows to harness 100% of their energy from clean sources. Rooftop solar can’t cover those needs because the average solar array on a data center would only offset about 2.2% of its annual electricity consumption, according to calculations by solar developers.
That means operators resort to power purchase agreements, which allow them to go solar even if the utility-scale arrays they invest in are located miles away or in other states and might not be generating when data centers are consuming power.
Some are leery of those pacts. But Shobe defends the agreements as “perfectly fine ways” to contain greenhouse gases.
“If a data center has a solar farm built somewhere else to cover emissions, why wouldn’t you want to credit them for that?” he said, adding that his university does just that with two off-campus arrays. “From the point of view of resolving global warming, it doesn’t matter where it is built.
“As long as it’s on the same planet, it has the same effect on emissions.”
Shobe suggested that in the big picture, a third-party monitoring organization — along the lines of a Good Housekeeping seal of approval — should be tasked with holding data centers accountable for clean energy pledges.
“Enforcement is a tricky problem,” he said. “What it boils down to is, are people holding true to their promises?”
Boosting in-state solar capacity is far preferable to importing electricity because that might be sourced from states without a carbon emissions cap, Shobe said.
“The question is how fast we can add renewable energy,” especially over the next five or six years, he said. “We are going to have to be more aggressive and do it faster if we are going to be a center for data center construction.”
In the meantime, the air board’s vote and the start of Virginia’s new, two-month legislative session has ushered in fresh fears that the state’s progress could be stymied. Shobe said he and other RGGI champions will meet with lawmakers to tout the climate value of sticking with the cap-and-invest program.
Withdrawing from RGGI would halt the flow of auction allowances. Instead, in mid-December, Youngkin proposed replacing that with $200 million in taxpayer dollars dedicated to a Resilient Virginia Revolving Fund.
That shift away from the RGGI model signals a lack of commitment to tackling climate change, Shobe said, because it removes not only environmental certainty but also the incentive for utilities to pivot from high- to low-emitting generation.
In Virginia, he emphasized, the original reason for joining RGGI was about having a cost-effective tool for reducing emissions. Producing revenue was an afterthought.
“If what the governor is hoping is that we will give up on achieving carbon dioxide reductions, that’s another matter,” Shobe said. “If we’re serious about reducing carbon emissions, we need to be thinking ahead and asking ourselves what our energy portfolio is going to look like.”
This article originally appeared in Canary Media.
Local Law 97, New York City’s groundbreaking, multistage effort to rein in carbon emissions from its big buildings, is facing its first major test — and it’s just a preview of the much steeper challenges to come.
Last week, New York City Mayor Eric Adams released proposed guidelines for how owners of the worst-performing buildings can comply with the law’s mandate to curb emissions by 2024. Next year, the city will begin imposing fines on buildings that haven’t reduced their emissions below certain thresholds, with even steeper cuts and rising fines to come in 2030 and 2040.
The response to the new compliance guidelines was swift. Real estate owners opposed to the law reiterated long-standing complaints that the mandates will force them to choose between paying steep fines or making efficiency investments that don’t make economic sense today.
Environmental activists countered with evidence that near-term compliance is not nearly as costly as opponents say it will be. They also worry that two parts of the proposed regulations, which would allow laggard buildings to postpone compliance for two years and use clean-energy purchases to offset continued building emissions after that date, amount to a surrender by the Adams administration to real estate interests at the expense of fighting climate change.
“Mayor Adams is proposing a gigantic giveaway to his real estate buddies that’s going to increase pollution and crush jobs,” said Pete Sikora, climate and inequality campaigns director of New York Communities for Change and a former member of the Local Law 97 advisory board.
That’s why Sikora’s group and a host of environmental and community activists are protesting what they describe as loopholes in the new proposed guidance. The conflict over these proposals underscores a key tension around the broad goal of decarbonizing buildings: how to balance the carrots with the sticks. If the cost of meeting the law’s emissions-reduction mandates is too high, building owners may simply choose to pay the fines instead, an outcome that does little to help the climate.
But building-efficiency experts agree that meeting the law’s 2024 targets should be relatively simple for the vast majority of commercial and multifamily residential buildings in New York City. As evidence, they point to the fact that 89 percent of buildings covered by the law are already in compliance with its requirements, including many older buildings that are harder to retrofit to become more energy-efficient. They also note that alternative compliance options have been established for more challenging buildings such as low-income housing.
“I do not believe there is a serious building professional in this city who would say that a building making a good-faith effort, absent very unusual circumstances, would not be able to get under the 2024 limit,” said Sikora. “In some buildings, they could do it almost immediately if they wanted by making some very basic changes — putting in LEDs [and] aerated shower heads, insulating exposed heating pipes, tuning the boiler correctly” and other such remedial actions.
What will be harder, he said, is meeting Local Law 97’s longer-term goals. Roughly 70 percent of the city’s buildings do not yet comply with the law’s tougher targets of cutting carbon emissions by 40 percent from 2019 levels by 2030.
Hitting that end-of-decade figure in particular will require far more extensive efforts to switch from the oil- and fossil-gas-fueled systems that heat the majority of buildings today to electric heat-pump systems or low-emissions steam heat systems. It will also require deeper building-efficiency retrofits to ease stress on the power grid.
Difficult as it may be to pull off, it’s crucial to meet these targets. Buildings contribute 70 percent of the carbon emissions in New York City, which means “we will not achieve our climate goals without addressing buildings,” said John Mandyck, CEO of the nonprofit Urban Green Council, which has played a key role in creating the law and monitoring its implementation. While building owners have been waiting for key guidelines on how the law will be enforced, with last week’s proposed guidance, “the compliance pathway is now evidently clear,” he said.
But the ongoing political fight over the law’s short-term targets could derail these longer-term efforts, Sikora said. New York City officials estimate the costs of hitting the law’s 2030 targets to range from $12 billion to $15 billion. If building owners don’t start making investments now, they run the risk of missing the law’s targets, which are designed to reduce the city’s carbon emissions in line with the Paris Agreement, he said.
“The law’s limits are achievable and affordable,” he added — a view backed by the Urban Green Council and other groups. The 2024 targets were meant to “get the most polluting buildings here to cut their pollution as a warmup to the 2030 requirements, which are quite a bit tougher.”
Environmental groups have two key complaints about the regulation proposed by the Adams administration last week.
The first is the proposal to allow the roughly 11 percent of buildings not yet hitting their targets to escape fines through 2026 if they make a “good-faith effort” to get on track. Some environmental groups argue that building owners have already had four years to prepare for 2024 targets and shouldn’t be rewarded for inaction.
“Responsible landlords are already doing that, not just to cut pollution but to save money on bills, too, and raise the property value,” Sikora said. “The mere fact that some landlords are incompetent doesn’t mean they should be let off the hook.”
But in Mandyck’s view, the good-faith exemption is a reasonable approach to forcing buildings that are behind schedule to meet the law’s mandates. Since Local Law 97 was passed in 2019, “we had Covid; we had supply-chain delays,” he noted. “It took the appropriate amount of time for regulations to unfold. And we’re now months away from compliance. So we have two options: We fine all those buildings and forfeit the carbon savings, or we find a pathway for compliance.”
The law’s fines — $268 per metric ton of carbon dioxide emissions that exceed an individual building’s cap — equate to “the highest price of carbon in the world,” he noted. “Do we tie up the administrative courts and start issuing fines? Then people are paying fines and not doing investments in the buildings. We need carbon savings — we don’t need fine revenue.”
Tristan Schwartzman, energy services director and principal at New York City–based building engineering consultancy firm Goldman Copeland Associates, agreed that a two-year extension could help a number of his clients that “do have a path that’s going to be arduous but feasible” to meet their compliance deadlines.
To qualify for the good-faith exemption, “you have to have a plan in place; you have to show that you’ve done something that’s been impactful,” he said. “There are a lot of hurdles you’re supposed to jump — but those are hurdles you’re supposed to be jumping anyway.”
But as Sikora and other environmental groups point out, it’s virtually impossible to discern whether owners of noncompliant buildings are indeed acting in good faith. These critics fear that the exemption will instead offer a two-year reprieve from fines for a subset of property owners who have been working to undermine the law.
Those efforts include a lawsuit filed last year by groups representing residential cooperative buildings in the borough of Queens demanding that the law be overturned. They also include millions of dollars of advertising and lobbying by the Real Estate Board of New York, a politically powerful group led by Douglas Durst, the owner of high-profile properties including some that are out of compliance with the law, such as the Bank of America Tower at 1 Bryant Park in Manhattan.
The group issued an analysis in January claiming that the fines from Local Law 97 could add up to $213 million for 3,780 buildings in 2024 and $902 million for 13,544 buildings in 2030, citing these findings as proof of “significant economic disruption that will occur if property owners are not provided adequate tools to reduce emissions.”
But Sikora noted that these figures misrepresent the financial impact on individual buildings and their tenants.
He cited the example of Bob Friedrich, the board president of Glen Oaks Village, a 2,900-unit co-op in Queens, who has been an outspoken opponent of Local Law 97 and a plaintiff in the lawsuit seeking to overturn the law. Friedrich has claimed that Glen Oaks would have to invest about $24.5 million to upgrade its gas and oil boilers to seek to comply with the law, and may still face an estimated $400,000 per year in fines from 2024 to 2030.
But divided among 2,900 units, that fine adds up to about $130 per unit per year through 2030, or “the equivalent of a parking ticket,” Sikora said. Similar economics apply to many other properties, making the law’s fines far from the death blow that many property owners have claimed they will be, he said.
Offering noncompliant buildings a route to avoid penalties for failing to achieve the relatively lax 2024 standards also risks setting a bad precedent for the much tougher 2030 targets, he added. That makes the good-faith exception a potential “signal to landlords and others that, well, maybe they’ll be delayed too.”
It’s certainly true that the carbon-intensity of New York City’s electricity supply will influence the emissions impact of building electrification, Sikora said. But that doesn’t mean building owners should be able to use clean-energy accounting to avoid investing in fundamental efficiency improvements.
And that brings us to the second key criticism environmental groups have made against the Adams administration’s proposed regulations. This critique centers around the role of renewable energy credits (RECs) — contracts between building owners and clean-energy producers — in the Local Law 97 scoring regime.
Today, building owners can use RECs to procure clean electricity that can be delivered to the larger New York City grid to offset their building’s emissions from electricity usage. But environmental groups have been demanding that the Adams administration set a more stringent standard, one proposed by the Local Law 97 advisory board and supported by energy experts, to limit the use of RECs to offset no more than 30 percent of a building’s total emissions.
The problem with RECs, Sikora said, is that Local Law 97 doesn’t require that they be “additional,” or tied to paying for a renewable energy project that wouldn’t have been built without the money from their purchase. Instead, building owners can purchase RECs from already existing clean-energy projects and use them to comply with the law.
That’s a problem, because in New York state, as with many other parts of the country, these RECs are becoming so plentiful that they offer building owners a much cheaper path to compliance than investing in energy-efficiency upgrades to their properties.
Today, New York City gets most of its electricity from fossil-fueled power plants. But with new transmission lines capable of carrying massive amounts of zero-carbon energy into New York City now being built and expected to be complete by 2026, building owners will soon have access to plenty of RECs from clean-energy projects that have already been built.
The Real Estate Board of New York has pushed for expanding the opportunities to use RECs to offset not just building emissions associated with electricity consumption but all building emissions. The new proposed compliance guidelines did not take up that proposal — but it also declined to institute the 30 percent cap that environmental advocates are pushing for.
It’s important to note that buildings that take the good-faith alternative pathway will be barred from using RECs to meet their requirements. But Sikora said the real danger of the current REC policy is that it could be extended to 2030 and later, threatening the law’s more ambitious longer-term goals. The Urban Green Council has estimated that 40 percent of multifamily properties and 80 percent of office buildings could offset their emissions over their 2030 limits through the use of RECs alone.
That’s a problem because “in reality, it’s not possible for the city and the state to reduce pollution unless they reduce pollution at the source — at the buildings,” Sikora said. “And that means they have to get a lot more energy-efficient.”
Green groups including Sikora’s are calling for the Adams administration to put a REC cap into place and reconsider the good-faith exemption over the coming month of public comments and hearings on the proposed rules.
Sikora didn’t downplay the challenge of paying for the deep efficiency and electrification efforts that New York City buildings will need to undertake to meet Local Law 97’s longer-term mandates. But he sees a much larger role for public funding to close that gap — and while city and state agencies are providing money through a variety of programs, it isn’t yet enough, he said.
“We think the city and state should apply billions of dollars per year to decarbonize the building stock,” he said. That big one-time transition away from gas or oil to heat pumps is a big cost.” On the other hand, “we do not think the city needs to subsidize affluent [building] owners.”
That work must start with increased funding for the variety of affordable-housing units that are currently allowed to comply with the law via so-called “prescriptive pathways,” he said. The Urban Green Council estimates that rent-controlled apartments, public housing and other affordable-housing units make up one-third of all buildings covered by Local Law 97.
Mandyck noted that the new proposed guidance provides more clarity on how those buildings can comply via “commonsense” measures, such as insulation on water heaters and steam pipes and thermostats or temperature controls on radiators.
But Schwartzmann contended that many of these buildings “are really poorly maintained because they don’t have money to maintain them properly,” due to the challenging economics of financing improvements in rent-controlled buildings or tight budgets for public housing. “The city should be throwing money at that problem, not pushing it downstream.”
Last week’s proposed regulations also included a booster for buildings exploring the switch from fossil-fueled to electric heating, primarily via heat pumps — a new credit that increases the value of electrifying at least part of their heating demands.
The new credit system “not only gives you a zero-emissions equivalent for the electricity it uses, it gives you a negative” carbon score, said Jared Rodriguez, a principal with Emergent Urban Concepts and adviser to the New York State Energy Research and Development Authority. “It’s a very clear signal that they want you doing at least partial load electrification — and that you’ll get some credit for it.”
That’s an important boost for a technology that still costs more than fossil-fueled boilers and furnaces, both in terms of upfront equipment and installation costs and in ongoing utility costs, Schwartzman said. “There was a real hesitancy to move toward these electrified options because they’re not going to save you money at this point, because electricity costs more than gas,” he said.
Last year’s Inflation Reduction Act will help make efficiency and electrification more affordable via tax credits and incentives for equipment, installation and workforce training, Mandyck noted. City officials have said they will pursue funding from a variety of federal sources, such as “green bank” loans, to ease the cost burden.
The New York state government is also funding efforts to bring down the cost of novel decarbonization technologies, he added. Some examples include a $70 million initiative to develop window-mounted heat pumps that both cool and heat apartments and the $50 million Empire Building Challenge that’s targeting high-rise commercial and residential buildings for complex efficiency and electrification retrofits.
“Because of the scale of New York City and the state…we’re going to spur innovation that’s going to help the whole market,” he said. Local Law 97 is just the most ambitious of a number of similar mandatory building-performance standards already in place in cities including Boston, Denver and Washington, D.C. and in states including Colorado, Maryland and Washington, he noted.
Finally, it’s important to remember that the climate emergency requires building owners to think differently about the costs and benefits of efficiency and electrification, Mandyck said. “We need to think about payback differently. Climate is a life-safety issue now. Nobody asks what the payback is to put a sprinkler safety system in your building. There’s no payback there — if there isn’t a fire.”
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