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Indiana ratepayers spend hundreds of millions of dollars per year for power from coal plants that are operating despite the availability of cheaper sources, including wind and solar.
The state is emblematic of a larger problem, as electricity market rules typically allow utility-owned power plants to essentially cut in line even when they are not the most economical option for customers.
A recent report commissioned by the Natural Resources Defense Council examined how this phenomenon plays out in the Midcontinent Independent System Operator (MISO) regional transmission organization specifically, building on previous research by RMI, the Union of Concerned Scientists and others — all of which show that uneconomic coal plant dispatch takes a huge toll on ratepayer wallets and public health.
The problem happens primarily with vertically integrated utilities or municipal utilities and cooperatives, which can recoup costs of fuel and operations from ratepayers even if they are operating at a loss. In most of MISO territory, energy markets have not been restructured as open markets, making such cost recapture the norm.
The NRDC study showed that Indiana ratepayers bore the second-highest burden in MISO, paying $338 million for uneconomic coal power from 2021-2023, just behind Louisiana’s $341 million. North Dakota ratepayers spent an extra $120 million, Wisconsin $69 million, and Minnesota $54 million, the study found.
Indiana’s R.M. Schahfer plant, run by utility NIPSCO, cost ratepayers more than $100 million in such uneconomical dispatch from 2021-2023, the NRDC study found.
In an ongoing rate case, Duke Energy is seeking to increase reliance on its Gibson and Cayuga plants in Indiana. These plants were responsible for $29 million and $7.6 million in uneconomic dispatch costs to consumers in 2023, according to RMI’s economic dispatch dashboard.
“This has been a problem plaguing Indiana coal plants for many years, it’s costing our consumers in Indiana millions of dollars and it’s one of the factors driving rates higher and driving clean energy off the grid,” said Ben Inskeep, program director for Citizens Action Coalition in Indiana. “It’s a tale of utilities making bad decisions as part of their profit motive and then utility regulators failing to hold them accountable as they’re supposed to. Certainly utilities should be operating their plants efficiently and economically, and when they fail to do so, they shouldn’t be getting cost recovery.”
Duke spokesperson Angeline Protogere said the study misses important context.
“There are a lot of considerations that go into plant dispatch decisions, and the priority is always reliability of service and economics,” Protogere said. “We weren’t able to replicate the NRDC data, but it appears it’s based on incomplete information. For example, there are times when MISO calls on a unit because of grid reliability needs. There’s a bigger picture that’s not reflected here.”
The NRDC study found that over three years across MISO, about 400 MW of wind power was curtailed in favor of power from coal plants generating at higher-than-market costs.
Power producers bid into regional energy reverse-auctions for real-time and next-day power, offering the price for which they can produce their electricity. Grid operators like MISO and PJM are supposed to dispatch the power starting with the most affordable option, until demand is met.
Even if vertically integrated utilities are not selling their power on the open market but rather serving their own customers, they still need to be dispatched by the grid operator to send their energy onto the grid.
But under the rules for MISO and other grid operators, coal plants can “self-commit” to run for a given time period even if they cannot produce power below the market rate. The idea is that coal plants can’t ramp up or down quickly, so they may need to keep running at a certain level to be ready to provide more power when needed.
If this relatively expensive coal power weren’t on the grid, more wind power would be purchased and demand for new renewables would likely be created.
“That increment of power would be filled through the market selecting the next highest bidder,” providing “an accurate picture of what electricity should cost that gives a signal that incentivizes newer generation,” explained James Gignac, Union of Concerned Scientists Midwest senior policy manager.
The lower the energy prices at a given time and the lower the demand, the worse the coal plant dispatch problem gets. Data from RMI and a 2020 report by the Union of Concerned Scientists shows that ratepayer losses due to uneconomic coal dispatch were lower in 2022, because Russia’s invasion of Ukraine caused natural gas prices to spike, making coal more competitive by comparison. Conversely, when energy demand plummeted in 2020 because of the pandemic, uneconomic dispatch of coal plants soared.
Since 2015, the uneconomic dispatch of coal plants has cost Indiana ratepayers $1.9 billion and ratepayers nationwide $20 billion, according to RMI’s dashboard.
The issue has real impacts on the growth of renewables, experts note. If the practice was prevented, market prices would be higher and there would be more incentive for renewable developers to build projects to sell their power on the open market. Meanwhile if vertically-integrated utilities were not allowed to recoup their costs for uneconomic dispatch, they would be motivated not to run coal plants and might decide to invest in building renewables instead, or at least buy wind power on the open market.
“I’ve talked with [wind] developers who say they look at where coal plants self-commit uneconomically, and they avoid those transmission lines because they know they will be curtailed,” said Joseph Daniel, principal in RMI’s Carbon Free Electricity team and lead author of the Union of Concerned Scientists report.
That report shows that if uneconomic coal dispatch was avoided, Indiana customers would save money — but not as much money as ratepayers in other states, because there is less wind power available around Indiana. Over time, a market unfettered by uneconomic coal plants might correct this situation.
“The greatest immediate savings for customers from stopping uneconomic coal plant operations are in areas where there are existing low-cost resources such as wind power being curtailed by that behavior,” said Gignac. “If the replacement for the uneconomic coal generation is something like a relatively higher-cost gas plant, then the market clearing price is higher and customer savings are not as significant. However, that higher clearing price is a signal and an incentive for low-cost renewables to locate projects in that area and deliver further cost savings.
“Removing the market distortion of uneconomic coal operations helps move us toward the cleaner, lower-cost energy system we need.”
Studies show that coal plants that sell their power on the open market – known as “merchant” plants – rarely decide to operate when they are not getting market prices at least equal to their cost of operating – the way vertically-integrated or publicly-owned coal plants do when they know they can recoup their costs from ratepayers, without compensation from the market. In other words, merchant plants do not ask grid operators to be uneconomically dispatched.
These merchant plants nonetheless seem to ramp up in time to operate when their power is needed, experts note, indicating that vertically-integrated plant operators in MISO are understating their ability to ramp up and down quickly, as noted by NRDC policy analyst Dana Ammann and other experts.
“There’s so little incentive to ramp up quickly, because the market really accommodates their inflexibility,” said Ammann, lead author of the recent NRDC study. The vertically-integrated coal plants in MISO are “much less flexible than coal plants in other markets. In PJM you see coal plants turning on much more quickly, since the merchant plant operators are reliant on the price signals to turn a profit. They don’t have the guaranteed rate recovery, so they’re very responsive to price signals.”
State utility commissions can prevent regulated utilities from recouping costs when coal plants are dispatched uneconomically. Michigan regulators did exactly this last year in a rate case for Indiana Michigan (I&M) Power, preventing the utility from passing on such costs for its share of the Rockport coal plant, located in Indiana.
Daniel said Indiana regulators should likewise protect Indiana customers from paying for uneconomic power from the Rockport plant. The RMI dashboard shows that plant dispatched $142 million worth of such power last year. Meanwhile the Michigan ruling could be considered precedent for Michigan utilities like DTE and Consumers Energy in future rate cases.
Ammann noted that states can also use the Integrated Resource Plan process to curb uneconomic dispatch, as Minnesota’s utility commission did when it recently decided that Otter Tail Power’s Coyote coal plant can only recoup costs during a designated power emergency.
“It’s an interesting approach for getting ratepayers basically off the hook for coal plants that aren’t retiring, that might still be economic to run for a small number of hours,” Ammann said.
Grid operators like MISO may have the most important role to play in better managing markets, refusing to dispatch coal plants that aren’t necessary and doing deeper analysis to figure out exactly how much power is needed. Experts say multi-day markets – rather than just real-time and day-ahead ones – could better match supply with demand and avoid unnecessary coal plant dispatch.
MISO’s Independent Market Monitor has recommended such measures, including de-committing coal power producers who sold into the day-ahead market if it turns out that others – including renewables – could sell power more efficiently in the real-time market once the time comes.
“MISO works closely with our members, state regulators and our independent market monitor to ensure our markets are efficient,” said MISO spokesperson Brandon Morris. MISO’s June 2024 monthly operations report shows that in June, 18% of coal-fired power dispatched in the region was uneconomic self-committed dispatch.
Experts note that fuel delivery contracts often include a minimum purchase, so utilities committed to buying a certain amount of fuel might as well burn the fuel even if they are not making a profit on the power. This might not have been an issue in years past when coal plants operated at high capacity most of the time, but as coal plants have become increasingly uncompetitive, the NRDC study notes, they are more likely to be committed to buy fuel they actually don’t need. Fuel contracts are usually of short duration, with 88% of those reviewed by the federal Energy Information Administration expiring by 2025, meaning there is ample opportunity for fuel delivery contracts to be revised, the NRDC study said.
Such fuel contracts have meant massive stocks of unneeded coal piling up at Duke plants in Indiana, Inskeep said, forcing the company to burn it even if the power isn’t needed.
Protogere said the coal supplies are necessary, as “the goal is to ensure a reliable supply in an increasingly uncertain market. The aim is to manage volatility as well as maintain long-term supply reliability and security, so that we don’t have to resort to higher cost options in the market.”
Inskeep hopes state regulators deny requests by Duke and other utilities to increase coal-fired generation and the recouping of the costs from ratepayers.
“The bottom line with this uneconomic dispatch situation is it means utilities are keeping their old expensive coal plants open longer than they should,” Inskeep said. “Utilities should be rapidly transitioning to a renewable energy-based portfolio of resources. Instead, utilities are feeling pressure to justify a lot of the bad economic decisions they’ve made in the past, foolish decisions to invest millions or even billions of dollars to keep these plants open.”
GRID: Minnesota regulators approve key permits for a utility’s $940 million plan to upgrade and boost the capacity of a 465-mile transmission line, allowing it to carry more wind energy from North Dakota and help meet clean energy targets. (Star Tribune)
ALSO:
PIPELINES: Minnesota regulators conclude that a small portion of the Summit carbon pipeline in the state’s northwestern corner would have a net benefit on greenhouse gas emissions. (North Dakota Monitor)
TRANSPORTATION: Owners of the nation’s last coal-fired steamship, which runs between Michigan and Wisconsin, examine potential carbon-free ways to power the vessel. (Bridge)
UTILITIES: Michigan’s attorney general says DTE Energy’s $456.4 million electric rate increase, which the utility says prioritizes grid infrastructure, is “excessive and unnecessary.” (Michigan Advance)
CLEAN ENERGY:
POLITICS:
EFFICIENCY: Homebuilders threaten to move their work to Kansas City’s suburbs as city officials consider stricter building codes for energy efficiency. (Kansas City Business Journal, subscription)
COMMENTARY: An Ohio building trades official says U.S. Sen. Sherrod Brown has backed key federal legislation that led to large clean energy manufacturing investments in the state. (Columbus Dispatch)
EQUITY: Low-income households are increasingly vulnerable to extreme heat, highlighting the urgency of ensuring equitable access to electricity and energy efficiency measures, advocates say. (Associated Press)
ALSO: Massachusetts awards $53 million — with plans for additional funding — to allow affordable housing operators to execute energy efficiency retrofits. (Energy News Network)
GRID:
HYDROGEN:
CLIMATE:
OIL & GAS:
ELECTRIC VEHICLES: A U.S. Senate committee this week discussed ways to help the domestic electric vehicle industry be more competitive globally. (States Newsroom)
NUCLEAR: A company developing a nuclear fusion prototype at a Tennessee nuclear plant raises capital from enthusiastic investors who see potential for an alternative to creating nuclear power from fission. (Knoxville News Sentinel)
COMMENTARY: A utility-funded California program says smart panel technology can help homeowners convert to electric appliances without expensive upgrades. (CalNEXT, sponsored)
Massachusetts has awarded $53 million — and announced plans for additional funding — to allow affordable housing operators to execute energy efficiency retrofits that are expected to reduce carbon emissions, cut energy bills, and create healthier, more comfortable homes for residents.
The state in late July announced the second round of awards in the Affordable Housing Decarbonization Grant Program, allocating $26.1 million to five organizations to improve insulation, tighten building envelopes, and switch to heat pump heating and cooling systems. These grants come seven months after an initial round of $27.4 million was awarded to seven affordable housing operators statewide.
“This has been a really critical funding stream for moving forward critical energy projects at some of our family public housing sites,” said Joel Wool, deputy administrator for sustainability and capital transformation at the Boston Housing Authority, which received grants in both rounds.
Along with the most recent round of awards, the state also announced it would invest another $40 million into the program in anticipation of giving out another set of grants in the fall.
The program was designed to address two major policy goals: decarbonization and addressing the state’s affordable housing crisis.
Massachusetts has set the ambitious goal of going carbon-neutral by 2050. Buildings — which contribute 35% of the state’s carbon emissions — are a particularly important sector to target for decarbonization. This means finding ways to retrofit the state’s existing housing stock, much of which is drafty, heated by fossil fuels, and decades — or even centuries — old.
At the same time, Massachusetts is experiencing an acute housing crisis. State officials estimate at least 200,000 new homes are needed to accommodate demand by 2030. Finding an affordable home is even more challenging for lower-income residents faced with soaring rents and home prices — and often, high energy bills.
“We have such a housing crisis in Massachusetts that we want to do anything we can to create more housing, but also to make the housing we have now a better place to live,” said state Energy Department Commissioner Elizabeth Mahony. “These are investments in our infrastructure.”
Nonprofit Worcester Common Ground received an $820,000 grant in the latest round that it will use to complete deep energy retrofits on four buildings that were last updated some 30 years ago. The money will allow the renovations to include air sealing, more energy-efficient windows, and extra insulation. The grant will also allow the buildings to go fully electric, including with air source heat pumps that will provide lower-cost, more comfortable heating and cooling.
“Even though it’s a higher upfront cost, the hope is that maybe it reduces expenses going forward,” said Timothy Gilbert, project manager for Worcester Common Ground. “It might sound a little cheesy but we really do care about the well-being of the folks who live in our houses.”
In most cases, the grant money is being combined with other funding to allow more complete — and even downright ambitious — upgrades. In Worcester, other funding sources will pay for rooftop solar panels that will make the newly energy-efficient buildings even more cost-effective and environmentally friendly. The Boston Housing Authority is using its latest $5.8 million award as part of a larger project that aims to completely decarbonize the Franklin Fields housing development in the Dorchester neighborhood by combining energy efficiency upgrades and Boston’s first networked geothermal system.
In the Boston neighborhood of Roxbury, the Madison Park Development Corporation is receiving $13.5 million from the Affordable Housing Decarbonization Grant Program to do work at its 331-unit Orchard Gardens development. But it is also seeking out other sources to meet the $20 million expected cost of the planned sustainability upgrades.
“It’s a big property and the heart of one of Boston’s oldest, most diverse, most underserved neighborhoods,” said Oren Richkin, senior project manager for the organization. “This grant money is pivotal for this project.”
Supporters of the program are expecting it to strengthen the state’s ability to respond to climate change in the future as well. Switching affordable housing units from fossil fuel heating to heat pump heating and cooling will allow residents to stay comfortable and safe in their own homes during increasingly hot summers, Wool said.
The funding could also help nudge the ideas of deep energy retrofits and electrification more into the mainstream, Mahony said.
“We are essentially socializing these programs — the more we do it, the more people will get used to the ideas,” she said.
As the recipients of the first round of grants begin their projects, the state is starting to learn how to operate the program more effectively. The state has already, for example, started providing some technical assistance to organizations interested in applying for future rounds of funding. Continued conversations with building owners and nonprofits will be essential to creating an even stronger program moving forward, Mahony said.
“We’re setting ourselves up for success in the future,” she said.
COAL ASH: Georgia Power faces big questions about its plan to clean up coal ash at power plants across the state — including whether the U.S. EPA will go along after it nixed a similar scheme in Alabama. (Grist/WABE)
ALSO: North Carolina residents ask the U.S. EPA to investigate the extent of coal ash contamination in a town after extracting samples with “elevated radioactivity.” (WCNC)
TRANSITION: West Virginia regulators consider renewing an air permit for a coal-fired power plant slated for conversion to a hydrogen-powered graphite production facility after its co-owner is sued for making false statements to receive funding. (Charleston Gazette-Mail)
UTILITIES:
STORAGE: Chattanooga, Tennessee’s electric utility plans to add 36 MW of battery storage at two decommissioned substations as part of a plan to save money and add a total 150 MW of capacity to boost grid reliability. (Chattanooga Times Free Press)
WIND: A company’s unsolicited request for an offshore wind lease in the Gulf of Mexico is reviving hope around the sector after federal officials previously canceled a lease auction later this year for “lack of competitive interest.” (Utility Dive)
GRID:
OIL & GAS:
CLIMATE:
HYDROGEN: The U.S. Energy Department issues $30 million toward the development of a hydrogen hub in West Virginia, Ohio and Pennsylvania. (WV News)
SOLAR: A Korean energy company sells a 260 MW solar project in Texas to another Korean company. (Renewables Now)
POLITICS: West Virginia U.S. Sen. Joe Manchin’s support of a sweeping climate law has benefited the state with new manufacturing and energy projects, but is still unpopular with voters and may have hastened the end of his time in Congress. (E&E News)
COMMENTARY: A company’s proposal to mine mineral sands near the Okefenokee Swamp could disrupt the swamp’s status as a carbon sink, writes a conservationist. (Atlanta Journal-Constitution)
Ohio clean energy projects under an Inflation Reduction Act grant announced last month show how solar sited on closed landfills can reduce greenhouse gases, improve resilience and provide funding for other environmental goals.
Part of the $129.4 million grant from the U.S. Environmental Protection Agency will add 28 megawatts of solar generation to a county central services facility and four former landfill sites in Cleveland and Cuyahoga County. A bigger chunk of the funding will bring 35 MW of solar and 10 MW of battery storage to a brownfield site in Painesville in Lake County, which will let the city close a coal-fired peaker plant that dates back to 1908.
Representatives of the Cleveland, Painesville and Cuyahoga County governments, along with the EPA and others, met July 26 at Cuyahoga County’s 4 MW solar array in Brooklyn, Ohio, to discuss the grant and the work. Funding from the EPA grant will more than double the generation capacity of that landfill solar site, which has been in operation since 2018.
“In Northeast Ohio we’re going to see warmer, wetter, wilder weather in this region. And we have to do our part to address climate change,” said Mike Foley, director of sustainability for Cuyahoga County.
Funded projects under the grant are expected to eliminate the equivalent of 1 million metric tons of carbon dioxide over a 25-year period, with the largest cuts coming from deploying the solar projects in Cuyahoga County, Cleveland and Painesville, according to Valerie Katz, deputy director of sustainability for Cuyahoga County.
The biggest chunk of grant money will go to Painesville, which is in Lake County east of Cleveland. But the 28 MW of solar generation to be built in Cuyahoga County will have a big impact.
“This will triple our solar capacity in Cuyahoga County in the next five years,” Katz said.
The landfill and brownfield projects funded by the grant will do more than produce electricity. By avoiding pollution from fossil fuels, they’ll provide health and environmental benefits. They’ll also produce revenue.
Some of the revenue from the brownfield solar site in Painesville will fund natural habitat for pollinators, birds and other wildlife elsewhere on that site. The city plans to work with the West Creek Conservancy for that and other projects, including building public trails and creating access for fishing.
Cuyahoga County also plans to use revenue from its sites to deploy more solar, Katz said. The added solar, in turn, can help develop microgrids to boost resiliency.
While closed landfills provide plenty of open space, they also are often capped by membranes made from clay or other materials that cannot be damaged without risking environmental harm.
Solar arrays at these sites are feasible thanks to ballast systems, which have been fairly common for such uses for more than a decade. Huge concrete blocks anchor the solar array’s racks and panels. The blocks, or ballasts, support the array and protect it from wind.
“They’re not going through the cap, which works out great for us,” said Jarnal Singh, an environmental supervisor with Ohio EPA’s Twinsburg office in its division of materials and waste management.
Without holes in the cap, the solar array doesn’t provide a pathway for methane or other gases to escape from the landfill. Leaving the cap intact also avoids creating a pathway for water to get in and percolate through the waste. That liquid, called leachate, could pollute groundwater if it’s not collected and treated properly.
Ohio has 141 landfill sites that have been subject to the state’s post-closure care requirements, according to Anthony Chenault, the Ohio EPA’s media coordinator for its Central, Northeast and Southeast districts. The agency has approved four landfills for solar development so far and has had informal discussions about several more sites.
But other practical considerations and site-specific features control whether any particular landfill is suitable for solar development.
“Some factors that could determine viability of a solar installation include proximity to existing power lines, size of the landfill, condition of the landfill cover, ownership (public vs private), and accessibility for equipment and maintenance,” Chenault said via email.
A few years should have passed since a landfill was closed and capped, so some settlement and off-gassing has already taken place, said Scott Ameduri, president of Enerlogics Networks, which was the primary developer for the Cuyahoga County solar site. There also must be a financially sound owner willing to accept responsibility for the waste at the site, he said.
Just as importantly, the electricity will need somewhere to go and a way to get there.
“In Brooklyn, for example, we were fortunate that Cleveland Public Power is a municipal utility,” Ameduri said. Municipal utilities are generally more flexible about making arrangements to take and distribute power than investor-owned utilities, he noted. Community solar legislation, such as House Bill 197, could help change things on that front, he added.
Another option is to have a large off-taker for the electricity adjacent to or near the landfill. The 7 MW of new grant-funded solar power to be built on a landfill south of the IX Center in Cuyahoga County can go to the expo center or the nearby Cleveland Hopkins International Airport, Ameduri said. The general area is also under consideration for one of the Cuyahoga County utility’s microgrids.
Otherwise, a landfill solar project putting electricity onto the grid may require a go-ahead from the regional grid operator, which is PJM for Ohio. The process takes roughly three to five years and adds extra costs. “I’d rather spread that over a 100-MW project than I would for a smaller brownfield site,” Ameduri said.
For now, Cleveland, Painesville and Cuyahoga County are celebrating the EPA grant award.
“This investment will allow us right here in Cleveland to turn brownfields into bright fields,” said Mayor Justin Bibb.
Every increment of global warming above 1.5C increases the risk of crossing key tipping points in the Earth system – even if the overshoot is only temporary, says new research.
It is well established that if global temperatures exceed 1.5C above pre-industrial levels, there is a higher risk that tipping points will be crossed.
The new study, published in Nature Communications, investigates the risk of crossing four interconnected tipping points under different “policy-relevant” future emissions scenarios.
The authors investigate the risk of tipping where warming temporarily overshoots 1.5C, but global temperatures are then brought back down using negative emissions technologies. They find that the longer the 1.5C threshold is breached, and the higher the peak temperature, the greater the risk of crossing tipping points.
The most pessimistic scenario in the study sees global warming hit 3.3C by the end of the century – in line with the climate policies of 2020 – before dropping back below 1.5C over 2100-2300. Under this pathway, there is a 45% chance of crossing tipping points by 2300, the authors say.
The authors also warn that if global temperatures rise above 2C, the additional risk of tipping for every extra increment of warming “strongly accelerates”.
For temperatures between 1.5C and 2C, the risk increases by 1-1.5% for every 0.1C increase in overshoot temperature. However, for temperatures above 2.5C, tipping risk increases to 3% per 0.1C of overshoot.
The research “underlines the need for urgent emission cuts now that do not assume substantial carbon dioxide removal later”, a scientist not involved in the study tells Carbon Brief.
Scientists have warned for decades that as the planet warms, there is an increasing risk that Earth systems will cross “tipping points” – critical thresholds that, if exceeded, could push a system into an entirely new state.
For example, if climate change and human-driven deforestation push the Amazon rainforest past a critical threshold, large parts of the forest could experience “dieback”. This would cause entire sections of lush rainforest to eventually shift to dry savannah.
(See Carbon Brief’s explainer on the nine tipping points that could be crossed as a result of climate change.)
The planet has already warmed by 1.3C above pre-industrial levels, and a recent study warned that five tipping elements – including the collapse of the west Antarctic ice sheet – are already within reach.
That study emphasised the importance of limiting global temperature rise to 1.5C above pre-industrial levels – in line with the 2015 Paris Agreement. It finds that warming of 1.5C would render four climate tipping elements “likely” and a further six “possible”. Meanwhile, 13 tipping elements will be either “likely” or “possible” if the planet warms by 2.6C, as expected under current climate policies.
Many of the potential pathways to limiting global temperature rise to 1.5C by 2100 see the planet initially “overshoot” the threshold before negative emissions methods are used to bring temperatures back down.
The new paper investigates 10 future warming scenarios which run to the year 2300. The authors use the PROVIDE v1.2 emission pathways, which they describe as “an extended version of the illustrative pathways identified” used in the recent sixth assessment of the Intergovernmental Panel on Climate Change (IPCC).
The original scenarios run over 2015-2300, but the authors carried them forward for another 50,000 years by following the temperature trajectory set over 2290-2300. All scenarios stabilise at 1.5C, 1C or pre-industrial temperatures. However, many include overshoots, with peak temperatures ranging from 1.57C to 3.30C.
These scenarios show a range of options for how global temperatures change under these 10 scenarios in the “medium term” – until the year 2300 – as well as in the “long term”, which runs 50,000 years into the future to see how the planet eventually stabilises.
Scenarios that reach net-zero or negative emissions by 2100 and maintain them thereafter are classified as “NZGHG emission scenarios”. The table below gives more detail on each scenario.
There is quite a range between the 10 pathways.
At the high end, the “CurPol-OS-1.5C” scenario sees a continuation of the global climate policies implemented in 2020 until the year 2100, with warming peaking at 3.3C. It then sees a decline in global temperature until reaching a stabilisation of 1.5C by the year 2300.
At the low end, “Neg-OS-0C” scenario initially overshoots 1.5C to 1.67C, but then returns warming to 1.5C by 2100 using “heavy carbon dioxide removal deployment”. It also then sees average global temperatures drop to pre-industrial levels by the year 2300.
In the middle, the Ref-1p5 scenario is the only one that does not include an overshoot, instead stabilising quickly at 1.5C.
The chart below shows greenhouse gas emissions (top) and corresponding global temperature changes (bottom) associated with each scenario, identified by the different-coloured lines. The bottom chart illustrates the range in how quickly the pathways return to 1.5C or below.
Dr David McKay is a research impact fellow at the University of Exeter’s Global Systems Institute, who has published extensively on climate tipping points, but was not involved in this study.
He also notes that some of the scenarios shown in this study “may not be possible”, because there is debate about whether or not “the substantial carbon dioxide removal needed for large overshoots is feasible”.
Many Earth systems are interlinked, so crossing one tipping point can increase the likelihood of crossing others. This is often described as a “domino effect” or “tipping cascade”.
The study focuses on four interconnected tipping points – collapse of the Greenland ice sheet and west Antarctic ice sheet, shutdown of the Atlantic Meridional Overturning Circulation and dieback of the Amazon rainforest.
Annika Högner is a researcher at the Potsdam Institute for Climate Impact Research (PIK) and co-lead author on the study. She tells Carbon Brief these four tipping points were chosen because they “play a significant role in the functioning of the Earth system” and “their tipping would have severe global impacts”.
The graphic below shows how the tipping points interact with each other. A “+” symbol indicates that crossing one tipping point can destabilise another. For example, a collapse of the Greenland ice sheet makes the AMOC more likely to shut down, as a result of the sudden influx of freshwater into the north Atlantic Ocean. A “±” symbol indicates that the relationship between two tipping points is uncertain.
A “-” symbol indicates that crossing one tipping point stabilises another. Högner tells Carbon Brief that the interaction between the Greenland ice sheet and AMOC is the only stabilising interaction in this study. She explains that if the AMOC were to cross a tipping point, “we [would] expect to see strong cooling in the northern hemisphere”, which will contribute to stabilising the Greenland ice sheet.
Earth system models “often don’t resolve tipping processes very well”, making them less suited to modelling full tipping cascades, Högner tells Carbon Brief.
Instead, she explains that the authors developed a “conceptual model”. This model does not attempt to simulate the entire Earth system, but instead just models the likelihood of tipping at different temperatures, based on existing knowledge about tipping elements from other studies.
The model takes temperature trajectories as an input and gives the state of the tipping elements after a specified time – that is, whether or not the element has tipped – as an output.
Importantly, these models include “hysteresis” – a feature of tipping systems, in which a system that has moved to a different state does not easily move back to the original state even if temperatures are reduced again.
The authors use their conceptual model to calculate “tipping risk” under the 10 future warming scenarios. Högner tells Carbon Brief that tipping risk “refers to the model of all four interacting tipping elements analysed in the study”. For example, a 50% tipping risk means there is a 50% chance that at least one of the four climate elements will tip.
The top row of the graphic below shows the risk of tipping in the year 2300 (left) and in 50,000 years from now (right). Bars placed higher up indicate a greater likelihood of tipping. The dot shows the average value for each data point, while the bars show the 10-90% range.
The text on the right hand side gives likelihood levels in the calibrated language used by the IPCC: very likely means a likelihood of 90-100%, likely is 66-100%, about as likely as not is 33-66%; unlikely is 0-33%; and very unlikely is 0-10%.
The middle row shows the peak temperature under each scenario (left) and stabilisation temperature (right). The bottom row shows how long temperatures overshoot before stabilising in each scenario.
The longer the 1.5C threshold is breached for, and the higher the peak temperature is, the greater the risk of crossing tipping points by the year 2300, the study shows.
The authors find the greatest risk of crossing tipping points in the CurPol-OS-1.5C scenario (red), which follows the climate policies of 2020 until the year 2100 and then reaches 1.5C by 2300, as this scenario has the greatest overshoot temperature and duration.
Under this scenario, there is a 45% tipping risk by 2300 and a 76% chance in 50,000 years, according to the paper.
The five pathways that do not return warming to 1.5C by the year 2100 have the greatest medium-term risks, and those with less than 0.1C overshoot have the lowest medium-term risks.
In the long-term – looking to the next 50,000 years – the authors find that stabilisation temperature is “one of the decisive variables for tipping risks”. They find that even in the Ref1p5 scenario – which sees global temperatures stabilise at 1.5C without any overshoot – there is a 50% risk of the system tipping over the next 50,000 years.
The results “illustrate that a global mean temperature increase of 1.5C is not ‘safe’ in terms of planetary stability, but must be seen as an upper limit”, the study warns.
Högner tells Carbon Brief that the paper “underlines the importance of adhering to the Paris Agreement temperature goal”.
Tessa Möller – a researcher at the International Institute for Applied Systems Analysis (IIASA) and co-lead author on the paper – tells Carbon Brief that “we have a wide portfolio of technologies available” to limit warming to 1.5C, and just need to “implement” them.
However, she also highlights the “large credibility gap” between pledges from individual countries and the policies they have actually implemented. She tells Carbon Brief that not only do we need “stronger pledges”, but it is also essential that countries follow through on them.
The authors also explore the risk of each individual tipping point being crossed in different scenarios.
The plot below shows the tipping risk by 2300 under different scenarios, at different temperatures, on the left. Each colour represents one scenario. Dots positioned further to the right indicate a greater peak temperature and dots positioned higher up indicate a greater tipping risk.
The plot on the right shows the percentage change in tipping risk for every additional 0.1C of overshoot, for different peak global temperatures, for the Amazon (cross), AMOC (plus), West Antarctic ice sheet (black dot) Greenland Ice sheet (square) and overall (yellow dot).
The authors find that AMOC collapse and Amazon dieback would likely be the first components to tip. This could be in the next 15-300 years and 50-200 years, respectively, depending on the scenario, they find.
Meanwhile, the Greenland and west Antarctic ice sheets have tipping timescales of 1,000-15,000 years and 500-13,000 years, respectively.
However, they note that as temperatures increase, the relative risk of each element tipping changes. The graph shows that while AMOC is the main driver of tipping risk at lower temperatures, the Amazon becomes the main driver once global temperatures exceed 2C.
Finally, they find that as global temperatures rise, the risk of tipping accelerates. Overall, tipping risk increases by 1-1.5% per 0.1C increase in overshoot temperature, for temperatures below 2C, according to the study. However, above 2.5C, tipping risk increases to 3% per 0.1C increase overshoot.
McKay notes that there are some limitations in the study. For example, he notes that the paper “has to rely on tipping threshold and timescale estimates with often wide ranges and sometimes low confidence, while tipping interaction estimates are based on dated expert judgement”.
However, he adds:
“This work makes it clear that every fraction of warming increases the chance of tipping points, even if global temperature subsequently falls, and underlines the need for urgent emission cuts now that do not assume substantial carbon dioxide removal later.”
OIL & GAS: Residents say their longtime advocacy work is paying off as five of seven fracking waste injection wells in southeastern Ohio have now been suspended after state officials said they pose a threat to the public and environment. (Ohio Capital Journal)
ALSO: A North Dakota commission will take another week to 10 days to pick the state’s next top oil and gas regulator to replace a former longtime department head. (North Dakota Monitor)
SOLAR:
CLIMATE:
GRID: North Dakota regulators will hold a conference this week on the potential power grid implications of the anticipated spike in data centers. (North Dakota Monitor)
NUCLEAR: South Dakota regulators push back on Xcel Energy’s request for South Dakota ratepayers to contribute to annual payments to a tribe located near a Minnesota power plant. (SDPB)
BIOFUELS: An Iowa ethanol company with hundreds of member producers across the country sues its marketing partner for $7 million, alleging errors in attempting to sell fuel-grade ethanol. (Iowa Capital Dispatch)
ELECTRIC VEHICLES: The police department in Green Bay, Wisconsin, launches an electric vehicle pilot program that has deployed two EVs to ticket speeding vehicles and enforce parking violations. (Press-Gazette)
COAL: A federal judge grants Ameren Missouri’s request for a private mediator to potentially resolve the utility’s 13-year legal dispute with the U.S. government over Clean Air Act violations involving a coal plant near St. Louis. (Bloomberg Law, subscription)
COMMENTARY: Federal clean energy policies are helping Ohio become a leading manufacturing hub for solar and storage, the head of a national solar advocacy group writes. (Cleveland.com)
URANIUM: The Navajo Nation plans to block trucks carrying uranium ore from a Grand Canyon-area mine across tribal land to a Utah processing center, saying the shipments expose people to a substance “that has devastated our community.” (Associated Press, news release)
SOLAR:
CLIMATE: Oregon regulators seek public input on proposed climate regulations aimed at slashing greenhouse gas emissions that were overhauled after being derailed by a fossil fuel industry lawsuit. (Oregon Capital Chronicle)
POLITICS: Left-leaning climate advocacy groups endorse Kamala Harris for president based on her record as a U.S. senator from California. (Heated)
OIL & GAS:
TRANSMISSION:
GRID: California’s grid operator finds its Western Energy Imbalance Market yielded participants $365 million in benefits from April to June this year. (RTO Insider, subscription)
WIND: A Wyoming startup looks to raise nearly $13 million to develop and market its horizontal low-to-the-ground wind energy loops, saying they are cheaper and more environmentally friendly than conventional turbines. (Cowboy State Daily)
UTILITIES: Idaho regulators seek public input on Rocky Mountain Power’s proposed wildfire hazard mitigation plan. (Idaho Capital Sun)
Oregon’s plan to regulate fossil fuel companies and reduce greenhouse gases is ready for public comment after being derailed seven months ago by a lawsuit brought by natural gas companies.
Draft regulations for the state’s redo of the 2021 Climate Protection Program were published Tuesday by the Oregon Department of Environmental Quality. The agency gave the public until Friday, Aug. 30 to comment on them. The state’s Environmental Quality Commission, which oversees rulemaking for DEQ, is expected to vote on final rules by the end of the year, once again putting the state’s landmark climate change laws into action.
Little has changed from the original program standards, which were passed three years ago by the commission. The targets for reducing greenhouse gas pollution would remain the same. Under the proposed rules, Oregon would attempt to reach a 50% reduction in greenhouse gas pollution by 2035 and a 90% reduction by 2050 to confront the growing threat of climate change.
Fossil fuel companies would have to gradually decarbonize their energy supply, largely by shifting away from petroleum and natural gas and instead incorporating renewable energy sources such as wind, solar and so-called biofuels – made from captured gas and decomposing matter – into their energy offerings.
Natural gas is almost entirely methane gas, among the most potent climate-warming greenhouse gases that trap heat in the atmosphere. One-third of global warming is due to human-caused emissions of methane, according to the U.S. Environmental Protection Agency.
Under the newly proposed rules, some heavy energy users in the state would need to meet emissions reduction targets and companies would need to show compliance with the program every two years, as opposed to every three years in the original plan.
“We did build off of the work that we already did in the prior Climate Protection Program,” Nicole Singh, senior climate change policy advisor for DEQ, told the Capital Chronicle on Tuesday. “We didn’t throw that out the window. We’re using that information to help inform this.”
To give companies a little flexibility, they would be able meet some pollution reduction targets by purchasing credits sold by the state. Money from those credits are invested in projects that reduce greenhouse gas emissions.
Besides the three-year compliance schedule, the largest change to the newly proposed rules is who has to follow them.
The state, for the first time, would regulate the emissions of companies that are heavy natural gas users, not just the suppliers of their gas. These include some cement, fertilizer and gypsum producers. Gypsum is in plaster, drywall and some cement. Companies operating in Oregon, including cement maker Ash Grove and Georgia Pacific, which works with gypsum, would need to meet new emissions standards, Singh said.
The agency included other changes in the investment portion of the Climate Protection Program. This section covers what is ostensibly Oregon’s carbon crediting market, where polluters can offset some of their greenhouse gas emissions by investing in projects that reduce overall emissions. One credit would be equal to one metric ton of carbon dioxide released into the atmosphere, and companies could buy them for $129 per credit. This market, which would have begun operating this year, was previously projected to bring in $150 million a year for community decarbonization and renewable energy projects, according to the Portland-based nonprofit Seeding Justice, which had previously been tasked with overseeing the investments.
Credit recipients, largely nonprofits working on community-based projects, could use the grants to help people and businesses buy and install solar panels and heat pumps, purchase electric vehicles and chargers and help weatherize homes and buildings.
Under the proposed rules, Oregon’s nine federally recognized tribes would play a bigger role in determining grants and would receive more funding, according to Singh. It’s unclear yet what role Seeding Justice could play in distributing grants in the future, she said, because such details would follow final rulemaking.
The state would also take a fraction of the funding – about 4.5% – to pay for its oversight of the grants and to undertake internal and external auditing to ensure money is being spent appropriately and that projects are, in fact, reducing the amount of greenhouse gas emissions required.
Under the new rules, companies could offset 15% of their emissions through the purchase of these credits during the first two years of the Climate Protection Program and 20% during each two-year compliance period thereafter. Previously, companies could only offset 10% of their emissions through the credits in the first two years.
DEQ also proposes to work more closely with the Oregon Public Utilities Commission to understand how the Climate Protection Program will affect natural gas rates for Oregonians and to ensure companies aren’t passing all the costs of decarbonization on to their customers.
The Climate Protection Program was approved in 2021 by the Environmental Quality Commission after more than a year of meetings, presentations from the environmental quality department and public comment.
But in December, Oregon Court of Appeals judges agreed with lawyers representing NW Natural, Avista Corporation and Cascade Natural Gas Corporation, who argued that in the process of imposing state regulations to cap and reduce emissions, the commission failed to submit required disclosures to the companies and to other entities that hold federal industrial air pollution permits. The department was required to issue a written statement about why the state was adopting emission limits that exceeded federal rules, disclose a list of alternatives that were considered and explain why they were not adopted.
The judges ruled the program invalid on those technicalities.
Rather than appealing the decision to the Oregon Supreme Court, which would likely not hear the case until mid-2025, state environmental regulators announced in January that they would start over.
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