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The UK’s last coal-fired power plant, Ratcliffe-on-Soar in Nottinghamshire, will close this month, ending a 142-year era of burning coal to generate electricity.
The UK’s coal-power phaseout is internationally significant.
It is the first major economy – and first G7 member – to achieve this milestone. It also opened the world’s first coal-fired power station in 1882, on London’s Holborn Viaduct.
From 1882 until Ratcliffe’s closure, the UK’s coal plants will have burned through 4.6bn tonnes of coal and emitted 10.4bn tonnes of carbon dioxide (CO2) – more than most countries have ever produced from all sources, Carbon Brief analysis shows.
The UK’s coal-power phaseout will help push overall coal demand to levels not seen since the 1600s.
The phaseout was built on four key elements.
First, the availability of alternative electricity sources, sufficient to meet and exceed rising demand.
Second, bringing the construction of new coal capacity to an end.
Third, pricing externalities, such as air pollution and carbon dioxide (CO2), thus tipping the economic scales in favour of alternatives.
Fourth, the government setting a clear phaseout timeline a decade in advance, giving the power sector time to react and plan ahead.
The UK’s experience, set out and explored in depth in this article, demonstrates that rapid coal phaseouts are possible – and could be replicated internationally.
As the UK aims to fully decarbonise its power sector by 2030, it has the challenge – and opportunity – of trying to build another case study for successful climate action.
The UK’s resource endowment has long included abundant coal, which had been used in small quantities for centuries. Coal use for electricity generation only came much later.
Over the centuries, surface coal deposits had been exhausted and mining became a necessity, despite the dangers of subsurface flooding, rock collapse and noxious gases.
The earliest steam engines, in use from around 1700, burned coal to pump water out of mines, enabling deeper coal deposits to be accessed.
These steam engines were very inefficient, but improvements by inventors including James Watt and George Stevenson made the use of coal more economical – and more widespread.
(This effect, whereby greater efficiency reduced costs, which, in turn, raised demand and fueled greater use of coal, despite higher efficiency, became known as the Jevons paradox.)
As a result, UK coal use began to surge as shown in the chart below, helping to power the Industrial Revolution, the British empire – and an explosion in global carbon dioxide (CO2) emissions.
Speaking to Carbon Brief, Dr Ewan Gibbs senior lecturer in economic and social history at the University of Glasgow and author of “Coal Country: The Meaning and Memory of Deindustrialization in Postwar Scotland”, says:
“The way the UK’s Industrial Revolution unfolded, coal was absolutely pivotal to becoming the industrial economy that Britain developed in the 19th century. The steel industry was powered by coal. And over the late 18th – and certainly in the first half of the 19th century – Britain became a coal power economy. It was the world’s first coal-fired economy.”
This is before looking at the coal mining industry and its role in the British Industrial Revolution, adds Gibbs, which employed more than a million miners at its peak and shaped the industrial economy of large regions of the country.
In 1810, coal began to be used for town gas for lighting and from 1830 it was used to fuel the expansion of the railways as they snaked across Britain.
It was in 1882 that coal was first used to generate electricity for public use. In January of that year, the world’s first coal-fired power station began operating at Holborn Viaduct in London.
Built by the Edison Electric Light Station company, the “1,500-light” generator, known as Jumbo, supplied electricity for lighting to the viaduct and surrounding businesses until 1886. It was hailed by Edison himself as a success.
These new uses – supplying heat, light and locomotion, in addition to industrial energy – helped drive a steep uptick in the use of coal in the UK. Demand grew more than tenfold from 14.9m tonnes (Mt) in 1800 to 172.6Mt by 1900.
Small coal-fired power plants were being opened around the UK during this period, including the Duke Street Station in Norwich. Opened in 1893, the site provided lighting for the Colman’s mustard factory on Carrow Road and surrounding area.
Despite surging domestic demand, the UK also became the “Saudi Arabia of 1900”: coal was its largest bulk export and it was the biggest energy exporter in the world until 1939.
By 1920, the UK was generating 4 terawatt hours (TWh) of electricity from coal, meeting 97% of national demand – the bulk of which came from factories.
It was around this time that the first hydropower plants were also being built in Scotland, although most were used to directly power nearby aluminium plants. As industries such as this continued to grow in the UK, so too did the demand for electricity.
Throughout the first half of the 20th century, the use of coal continued to expand in the UK, despite notable blips driven by miners strikes in the 1920s and the Great Depression between 1929 and 1932.
By the time UK coal use had reached its peak of 221Mt in 1956, however, coal power was still only a small fraction of demand. Steelmaking, industry, town gas, domestic heat and the railways dominated, as shown in the chart below.
Over the second half of the 20th century, all of these uses – except power – declined steeply.
Reasons for the decline in UK coal use in this period include the advent of North Sea gas and the end of steam railways, as well as increasing globalisation and deindustrialisation.
The coal mining workforce dropped from more than 700,000 in the 1950s to less than 300,000 by the mid-1970s. However, these losses occurred as part of a fairly “just transition”, as mining jobs were replaced by those in manufacturing, Gibbs says.
After the mine closures that triggered the 1984 strikes, mining jobs fell again to less than 50,000 by 1990. Many former coal mining communities remain impoverished and this period has been cited as a “failed just transition” for coal workers.
Another key factor in the post-war coal decline was that, by the 1950s, the environmental impact of burning coal was becoming too obvious – and dangerous – to ignore.
As early as the 1850s, pollution from burning coal in London’s homes and factories had started causing “pea-souper” days – when a greenish fog settled over the city. In 1905, Irish doctor Harold Antoine des Voeux had coined the term “smog” while working in London.
But events came to a head in December 1952. As winter temperatures began to bite, the people of London stoked their coal fires. An anticyclone weather pattern caused cold, still conditions, trapping polluted air over the city.
Smoke from fires mingled with pollution from factories and other sources dotted across London, creating what became known as the “Great Smog”.
Lasting for four days, the fog was up to 200 metres thick, according to the Met Office. Conditions were worst in London’s East End, which was home to a large number of factories powered by coal.
During this period, around 1,000 tonnes (t) of smoke particles, 2,000t of CO2, 140t of hydrochloric acid and 14t of fluorine compounds were emitted per day in London, according to the Met Office. Additionally, “and perhaps most dangerously”, 370t of sulphur dioxide was converted into 800t of sulphuric acid, it adds.
About 4,000 people are known to have been killed by the Great Smog, although it could have been many more. Hospitalisations increased by 48%, instances of asthma grew in exposed children and the city was disrupted for days.
Three years later, parliament responded with the 1956 Clean Air Act. This outlawed “smoke nuisances” or “dark smoke” and set limits for what new furnaces could emit. Laws around emissions were further strengthened in 1968.
The decades that followed saw the use of coal for domestic heating, rail travel and industry continue to decline as cheaper and cleaner alternatives began to take over.
These years also saw a shift away from small coal plants in cities towards large-scale power plants in rural areas, closer to coal mines. While the UK was also pioneering nuclear power, it was not until 1957 that coal’s share of annual electricity generation fell below 90% for the first time.
Between 1960-64, the Central Electricity Generating Board (CEGB) unveiled plans for 10 coal-fired power stations using 500 megawatt (MW) “turbo-generator” units. These projects formed a wave of new coal plants that were opened between 1966 and 1972.
Construction of these projects saw coal capacity climbing to an all-time peak of 57.5GW in 1974. Coal generation peaked a few years later in 1980, at 212TWh, but by this time – with electricity demand rising rapidly – it only made up 76% of electricity supplies, as oil and nuclear power had eroded its market share.
The UK’s last new coal-fired generating capacity was at Drax, which had opened in 1975 as a 2GW plant, but was doubled to 4GW in 1986.
By 1990, despite significant growth in nuclear capacity in the previous decade, coal still made up 65% of the UK’s electricity mix.
The combination of the Clean Air Act, the switch from town gas to North Sea gas, deindustrialisation and globalisation had all helped drive down the use of coal in the second half of the 20th century.
But, as noted above, coal power continued to thrive for much of this period, as alternative sources of electricity generation failed to keep up with rising demand.
As a result, coal generation did not peak until 1980 – and remained at similar levels in 1990.
Then, after a century dominating UK electricity supplies, coal was phased out in two rapid and distinct stages, punctuated by a plateau that lasted more than a decade.
The first stage was the “dash for gas” of the 1990s.
The second stage saw the buildout of renewables, rising energy efficiency and policies to make coal plants pay for their pollution.
From the 1950s, the expansion of nuclear and oil-fired power-plants had begun to erode coal’s share of the UK electricity mix. Still, coal-fired electricity generation continued to grow throughout the 1960s and 1970s as coal-fired power stations were built up and down the country. This included Ratcliffe-on-Soar, the UK’s last operating coal-fired power plant, which was commissioned in 1968 by the CEGB.
While gas had been discovered in the North Sea in the 1960s, its large-scale use for electricity generation was ignored and restricted for many years.
With the exception of 1984 – when oil power helped keep the lights on during the miners’ strike – coal generation continued to hold steady through the 1980s.
By the end of that decade, however, coal power was about to enter its first stage of decline.
Amid rising concern about acid rain, the EU passed the 1988 Large Combustion Plant Directive (LCPD), requiring reductions in sulphur dioxide emissions. Coal plants were a major source, with abatement technology added to their running costs.
At the same time, ”combined cycle” gas turbine technologies were advancing and gas prices were falling, making gas not only cleaner, but also cheaper than coal.
The ensuing dash for gas within the newly privatised electricity sector saw coal-fired generation roughly halve in a decade. It fell from more than 200TWh and 65% of the total in 1990 to just over 100TWh and 32% in 2000 – with gas power going from near-zero to nearly 150TWh over the same period.
Following the turn of the century, the UK’s coal power entered a period of stagnation, with its output rising, then falling and rising again, in response to the ebb and flow of gas prices.
In 2000, the UK’s now-defunct Royal Commission on Environmental Pollution had published a report on energy and the “changing climate”. It called on the government to cut UK greenhouse gas emissions to 60% below 2000 levels by 2050, including via a “rapid deployment of alternative energy sources” to replace fossil fuels.
By the time of the 2003 energy white paper, the “60% by 2050” target was government policy, as was a goal for 10% of electricity to be renewable by 2010, supported by a “renewables obligation”. New nuclear was “not rule[d] out” – but it remained uncertain.
Yet the 2003 white paper also left the door open to “cleaner coal” using carbon capture and storage (CCS). And it proposed government-backed investment in new coal reserves.
It was to take another decade, including a range of new policy developments, a major protest movement and an unexpected – but highly significant – decline in electricity demand, before UK coal power would enter the second stage of its phaseout.
One such policy development was the 2005 entry into force of the EU Emissions Trading System (EUETS), the world’s first major carbon market. It was initially ineffective – carbon prices crashed, particularly in the wake of the 2008 financial crisis – but the EUETS established the principle that polluting power plants should pay for their CO2 emissions.
Another notable policy was the 2001 update to the EU’s LCPD, which set out tighter limits on air pollution from power plants and came into force in 2008.
Many of the coal-fired power plants in the UK were old by this point and opted to use a “derogation” (exemption) that allowed continued operation until 2015, without the need to invest in pollution control equipment, if they only operated for a limited number of hours.
While this sealed the fate of a raft of older plants, the prospect of new coal-fired capacity in the UK was very much still on the agenda at this point.
In late 2007, the “Kingsnorth six” scaled the chimney of an existing coal plant in Kent to protest against plans for a new station at the site. In January 2008, the local council approved the plans for what would have become the UK’s first new coal plant for 24 years.
In October 2008, the UK passed the Climate Change Act, including a legally binding target to cut greenhouse gas emissions to 60% below 1990 levels by 2050 – later strengthened to 80% and then, in 2019, to “net-zero”.
Sean Rai-Roche, policy advisor at thinktank E3G, tells Carbon Brief that the Act, as the first legally binding climate goal set by a country, was a “seminal moment” in the UK’s journey, including its coal phaseout.
By 2009, then-energy and climate secretary Ed Miliband – now secretary of state for energy security and net-zero – announced that no new coal plants would be built in the UK without CCS.
“The era of new unabated coal has come to an end,” Miliband stated at the time.
Yet the Labour government continued to back new coal with CCS, describing it as part of a “trinity” of low-carbon electricity sources along with new nuclear and renewables.
It was only towards the end of 2009, when developer E.On postponed its Kingsnorth plans, that protestors were able to claim their “biggest victory” for the UK climate movement.
The Kingsnorth plant was formally cancelled the following year and no new coal projects were ever built again in the UK, paving the way for an early phase out as old plants retired.
(In contrast, countries including the US and Germany built a wave of new coal capacity around 2010, locking themselves in to continued use of the fuel for longer periods.)
After 2010, with no new coal plants built in the UK and with many older sites set to close rather than making costly upgrades to meet tighter air pollution rules, coal power was primed for the second stage of its phase out – but not before alternative generation was available.
The 2013 Energy Act formalised the end of unabated coal power with an emissions performance standard (EPS). This set a limit of 450g of CO2 per kilowatt hour for new power plants – around half the emissions of unabated coal.
Dr Simon Cran-McGreehin, head of analysis at thinktank the Energy and Climate Intelligence Unit (ECIU), tells Carbon Brief that the combination of air-pollution rules, the cost of CCS and carbon pricing has made ongoing coal generation “uncompetitive”. He says:
“Ongoing coal power simply isn’t an option, as it would have such high costs…that it would be uncompetitive with even gas and nuclear, let alone new renewables.”
The 2013 Energy Act also revived plans for new nuclear, leading to the construction of Hinkley Point C in Somerset, and created “contracts for difference” to support the expansion of low-carbon generation.
Renewable generation went on to double in the space of five years, from around 50TWh in 2013 to 110TWh in 2018. Renewables are on track to generate more than 150TWh in 2024.
The coalition government also introduced the “carbon price floor” in 2013, which added a top-up price to CO2 emissions from the power sector and tipped the scales in favour of gas over coal.
This additional carbon price had a “significant effect” on UK coal power, according to thinktank Ember, helping drive a sharp reduction in generation over the years that followed.
Coal dropped from nearly 40% of the UK electricity mix in 2012 to 22% in 2015.
In addition to the growth of renewables, an additional factor allowing the rapid phaseout of UK coal generation has been the fall in electricity demand since 2005.
Indeed, by 2018, demand had fallen to levels not seen since 1994, saving some 100TWh relative to previous trends – equivalent to the output of four Hinkley Point Cs.
Electricity demand has declined thanks to a combination of energy efficiency regulations, LED lighting and the offshoring of some energy-intensive industries.
The rapid pace of progress meant that, by 2015, then secretary of state for energy and climate change Amber Rudd was able to announce a target to phase out coal by 2025.
Speaking at the Institution of Civil Engineers, Rudd said:
“It cannot be satisfactory for an advanced economy like the UK to be relying on polluting, carbon-intensive 50-year-old coal-fired power stations. Let me be clear: this is not the future.”
The following year, in 2016 – after the last plant closures due to the EU’s LCPD – coal power dropped precipitously to just 9% of annual electricity generation.
That year also witnessed the first hour with no UK coal power since the Holborn Viaduct plant had opened in 1882. This was followed in 2017 by the first full day without coal power, in 2019 by the first week without the fuel and, in 2020, by the first coal-free month.
The coal phaseout target was then brought forwards in 2021 to October 2024, with just 1.8% of the electricity mix having come from coal in 2020.
Coal plants continued to shutter throughout this period, as shown in the maps below. SSE’s last coal-fired power station, Fiddler’s Ferry, and RWE’s Aberthaw B station closed in March 2020. Drax’s two remaining coal units and EDF’s West Burton A all closed in March 2023.
(Four of the six coal units at Drax have been converted to burn biomass – mostly wood pellets imported from North America – with uncertain climate impacts. It generates around 14TWh of electricity per year from these units, roughly 4% of the UK total.)
Then, in late 2023, the UK’s second-last coal-fired station – Kilroot in Northern Ireland – stopped generating electricity from coal, leaving just one plant remaining.
These closures left Ratcliffe-on-Soar as the only operating coal-fired power station in the UK in 2024, with coal having met just over 1% of demand in 2023.
On 28 June 2024, the last coal delivery to Ratcliffe took place, a “landmark moment” in the country’s coal journey. The shipment of 1,650 tonnes of coal was only enough to keep it running for a matter of hours.
At full capacity, the 2GW Ratcliffe would have needed roughly 7.5Mt of coal each year, the burning of which would have produced around 15MtCO2.
Ratcliffe’s closure by 1 October will bring to an end 142 years of coal power in the UK. And, contrary to scores of misleading headlines over the years, the lights have stayed on.
Remarkably, the UK’s coal power phaseout – as well as the closure of some of the country’s few remaining blast furnaces at Port Talbot in Wales and Scunthorpe in Lincolnshire – will help push overall coal demand in 2024 to its lowest level since the 1600s.
In total, coal-fired power stations in the UK will have burned through some 4.6bn tonnes of coal across 142 years, generating 10.4bn tonnes of CO2, Carbon Brief analysis shows.
If UK coal plants were a country, they would have the 28th-largest cumulative fossil-fuel emissions in the world. This would mean greater historical responsibility for current climate change from those coal plants than the likes of entire nations such as Argentina, Vietnam, Pakistan or Nigeria.
The UK’s electricity system today looks dramatically different to even just a few decades ago, with renewables increasingly dominating the generation mix.
In 2023, renewables set a new record by providing 44% of the country’s electricity supplies, up from 31% in 2018 and just 7% in 2010. Their output is set to increase from around 135TWh in 2023 to more than 150TWh this year, Carbon Brief analysis shows.
By comparison, fossil fuels made up just a third of supplies, with a record-low 33% of the electricity mix, of which coal was a touch over 1%.
This decrease of just under 20% brought fossil fuel supplies down to 104TWh, the lowest level since 1957, when 95% of the mix came from coal.
The changing makeup of the UK’s electricity mix over the past century is shown in the figure below. Notably, while oil, nuclear and gas have each played important roles in squeezing out coal power, it is now renewables that are doing the heavy lifting.
Indeed, all other sources of generation are now in decline: nuclear as the UK’s ageing fleet of reactors reaches the end of its life; and gas, as well as coal, as renewables expand.
In 2024, renewables have continued to take up an increasing share of the electricity mix, with Carbon Brief analysis of year-to-date figures putting them on track to make up around 50% of supplies for the first time ever.
The growth of renewable electricity in the UK’s electricity mix has been “instrumental in driving coal out”, E3G’s Rae-Roche tells Carbon Brief:
“Crucially, coal hasn’t been replaced by other fossil fuels, gas generation fell from 46% in 2010 to 32% in 2023. [Carbon Brief analysis suggests gas will fall again, to around 22% of electricity supplies in 2024.] So, on a gigawatt basis, we’ve replaced the ‘firm’ coal capacity with gas, but on a gigawatt hour basis – which is what matters to emissions – we stopped using as much [of either] coal or gas because of the renewables on the system.”
For one hour in April, for example, the share of electricity coming from coal and gas fell to a record-low 2.4%, Carbon Brief analysis revealed.
This pressages the first-ever period of “zero-carbon operation”, when the electricity system will be run without any fossil fuels – a moment that the National Energy System Operator (NESO) expects to reach during at least one half-hour period during 2025.
In 2009, the lowest half-hourly fossil-fuel share was 53%. The first half-hour period where there was less than 5% fossil fuels only happened in 2022, Carbon Brief’s analysis found.
Last year, there were 16 half-hour periods with less than 5% fossil fuels and more than 75 periods of such in the first four months of this year.
This switch has been enabled by the swift growth of renewable technologies, in particular wind, which now vies with gas month-to-month as to the biggest source of electricity in the country. In the first quarter of 2024, wind contributed more electricity than gas generation for the second quarter in a row.
After becoming the first major economy to phase out coal generation, the UK is looking to go one step further by fully decarbonising its power supplies by 2030.
Under the previous Conservative government, the UK was targeting a fully decarbonised power sector by 2035. The newly elected Labour government brought this forward to 2030.
At the same time, the power sector will need to start expanding in order to meet demand from sectors such as transport and heating, as they are increasingly electrified.
Former Climate Change Committee (CCC) chief executive and now head of “mission control” for the government’s 2030 power target Chris Stark told a central London event in mid-September that he saw the goal as “possible”, but “challenging in the extreme”.
Noting scepticism that clean power by 2030 is achievable, he said that it was nevertheless a real goal and not an aspirational “stretch target”.
Stark added that many people had been similarly sceptical of the UK’s ability to phase out coal power by this year – and that that scepticism “really motivates me”.
Electricity demand in the UK is expected to increase by 50% by 2035, according to the CCC.
Meeting this growth at the same time as phasing out unabated gas will require a very large increase in renewable generating capacity, as well as supporting systems to ensure the grid can run securely on predominantly variable generation from wind and solar.
At the event, Stark noted that clean power by 2030 was a “smaller target” than for 2035 because it would come before widespread electrification of heat and transport.
Even so, meeting the goal would require unabated gas power to be phased out within six years, from its current share of around 22%. This would be roughly twice as fast as the UK has phased out coal, from 39% in 2012 to zero in 2024, as the chart below shows.
In order to meet its 2030 target and wider UK climate goals, the Labour government has pledged to double onshore wind capacity, treble solar and quadruple offshore wind.
The expansion of renewables is continuing to be supported by the government’s “contracts for difference” (CfD) scheme. The latest allocation round wrapped up earlier this month and secured contracts for 131 projects, with a total capacity of 9.6GW.
While many welcomed the results as a boost to the renewable pipeline in the UK, others highlighted the need to ramp up capacity in the coming years.
Analysis by trade association Energy UK found that the next CfD auction would need to secure four times more new capacity in order for the UK to reach its targets.
The Labour government is also backing new nuclear projects, CCS and a “strategic reserve of gas power stations” to guarantee security of electricity supplies.
According to a 2023 report from the CCC on how to meet the then-2035 power-sector decarbonisation target, renewables were expected to make up around 70% of generation in 2035, with nuclear and bioenergy contributing another 20% and the final 10% coming from flexible low-carbon sources, including energy storage, CCS or hydrogen turbines.
(A September 2024 report from the International Energy Agency sets out the “proven measures” that can be taken to integrate growing shares of variable wind and solar into electricity grids, while maintaining system stability. It says: “Successful integration maximises the amount of energy that can be sourced securely and affordably, minimises costly system stability measures, and reduces dependency on fossil fuels.”)
Since taking office, the Labour government has asked the Electricity System Operator (ESO, soon to become the National Energy System Operator NESO) to provide “practical advice” on how to reach the “clean power by 2030” target.
Stark told the event that he expected this advice to show that 2030 was unachievable under the current policy and regulatory regime. He said that, by the end of the year, the government would publish a paper setting out the policies that would be needed.
After 142 years of near-continuous electricity generation from coal, the closure of Ratcliffe-on-Soar is truly the end of an era for the UK.
Moreover, there is an obvious symbolism around the UK, home to the world’s first-ever coal-fired power station in 1882, becoming the first major economy to phase out coal power.
Perhaps because of its status as the birthplace of the Industrial Revolution and as the world’s first “coal-power economy”, the UK’s coal phaseout is also viewed internationally as an “inspiring example of ambition”, says COP29 president-designate Mukhtar Babayev.
Beyond mere symbolism, the UK’s coal phaseout also matters in substantive terms, because it shows that rapid transitions away from coal power are indeed possible.
Coal’s share of UK electricity generation halved between 1990 and 2000 – and then dropped from two-fifths of supplies in 2012 to zero by the end of 2024.
This progress hints at the potential for other countries – and indeed the whole world – to replicate the UK’s success and, in so doing, making a major contribution to climate action.
Already Belgium, Sweden, Portugal and Austria have phased out coal-powered generation, and increasingly countries around the world are announcing targets to follow-suit. This includes the G7 announcing in May plans to phase out unabated coal by 2035.
The world’s roughly 9,000 coal-fired power plants account for a third of global emissions, notes IEA chief Fatih Birol. And pathways that limit global warming to 1.5C or 2C include very rapid reductions in CO2 emissions from coal overall – and coal-fired power, in particular.
Indeed, unabated coal-fired power stations have been singled out for attention by the Intergovernmental Panel on Climate Change, the IEA and the UN.
Despite this attention, some 604GW of new coal power capacity is still under development, with the vast majority located in just a handful of countries, including China and India.
In developed countries, three-quarters of coal-fired power plants are on track to retire by 2030, according to the Powering Past Coal Alliance (PPCA). But, globally, 75% of operating coal capacity still lacks a closure commitment, it says.
As other countries look to retire their coal fleets and move away from the fuel, the UK can be used as a case study of a successful phaseout.
There are four key elements that enabled the UK phaseout:
Illustrating each of these elements in turn, on the first point, alternative sources of electricity generation in the UK were initially insufficient to cut into coal power output.
Oil and nuclear from the 1950s onwards eroded coal’s share of electricity generation, but were not sufficient to meet rising demand, meaning coal output kept growing.
In contrast, gas power plants were built so rapidly in the 1990s that they exceeded demand growth and pushed coal generation into decline. Similarly, the rapid growth of renewables after 2010, combined with declining demand, was key to the UK’s coal phaseout.
On the second point, the UK did not build any new coal plants after 1986, partly as a result of protests and political action in the 2010s.
Speaking to Carbon Brief Daniel Therkelsen, campaign manager at campaign group Coal Action Network, says the end of coal-fired power was a “historic moment”, adding that it was “a huge win for the UK public…particularly [those] who spent countless hours campaigning”.
The fact that the UK did not build new coal plants meant there were no recently built assets – with associated economic interests – needing to be retired early for a phaseout.
Moreover, the UK’s existing coal-power fleet was reaching the end of its economic lifetime.
The fact that there were few UK coal mining jobs remaining after the 1980s removed another interest group, that might have stood in the way of the coal power phase out. (In contrast, “influential…coal corporations and unions” have slowed coal’s decline in Germany.)
In terms of externalities, a series of UK and EU policies and regulations covering air pollution and carbon pricing helped tip the scales against coal power.
By making coal plants pay for pollution control equipment, CCS infrastructure or CO2 emissions permits if they wanted to stay open, these policies changed the economic calculus in favour of alternative sources of electricity generation.
Finally, the UK government’s 2015 pledge to phase out unabated coal sent a clear signal to the electricity sector. It allowed decision-making to proceed in the full knowledge that coal plants would need to close, that plant operators would need to diversify their portfolios rather than investing in continued coal-plant operation, and that the sector as a whole would need to ensure alternatives were in place to maintain reliable electricity supplies.
E3G’s Rae-Roche highlights the long-term political goal of coal phaseout as the starting point for successful implementation. He explains:
“You need to set long-term goals and have policy stability about where you want to get to from there. Once you’ve got that established, you think about the legislation that’s required to incentivise clean and move away from fossils. What support needs to be delivered to the clean industry, how that support needs to be managed in terms of the power system and what the power system needs to actually deliver it.”
Similarly, Frankie Mayo, senior energy and climate analyst at Ember, tells Carbon Brief that clear political commitment and policies are key. He says:
“The biggest lesson is that, once the commitments and policies are clear, then rapid, large-scale clean power transition is possible, and it lays the groundwork for future economy-wide decarbonisation.”
As the UK embarks on its next major challenge in the power sector – targeting clean power by 2030 – it has another opportunity to provide a successful climate case study to the world.
Data analysis by Verner Viisainen.
Graphics and design by Joe Goodman.
HYDROGEN: Uncertainty surrounding federal tax credit rules has left the clean hydrogen industry stuck in neutral, but experts say the delay is providing much-needed time to figure out the best uses for the fuel. (Canary Media)
ALSO: General Motors plans to partner with a large supplier to build a hydrogen fuel cell plant in Detroit, which could take a few years until production starts. (Crain’s Detroit, subscription)
OIL & GAS:
ELECTRIC VEHICLES:
UTILITIES: Advocates sound the alarm over a lack of policies stopping utilities from shutting off customers’ power for nonpayment during deadly heat waves. (The Guardian)
GRID:
NUCLEAR: The U.S. Energy Department greenlights California startup Oklo’s plan to begin developing an advanced nuclear reactor at the Idaho National Laboratory. (Newsweek)
POLITICS: Environmentalists push back against a bill that would weaken semiconductor industry oversight that President Biden is reportedly set to sign. (The Hill)
PIPELINES: A planned 645-mile pipeline across Texas from the Permian Basin to a Louisiana terminal creates landowner concerns about its effects on nearly 13,000 acres of land, including the possibility of eminent domain. (KOSA)
MINING: Arkansas sees a rush to mine lithium for batteries, triggering memories of unscrupulous and shady behavior during a previous oil boom and raising concerns about the ephemeral nature of extraction. (Grist)
COMMENTARY: Federal support for carbon capture and storage relies on the assumption that unproven and prohibitively expensive technologies will soon become viable, an energy analyst writes. (Utility Dive)
COURTS: An environmental group sues Vermont’s natural resources secretary over allegedly breaking a state climate solutions law by using a data model that is “technically and mathematically insufficient” to claim the state was on track to meet a 2025 emissions deadline with no further legislative action needed. (VT Digger, Seven Days)
RENEWABLE POWER: A New York energy siting office issues final permits for a 240 MW solar project in St. Lawrence County and a 147 MW onshore wind facility in Steuben County. (news release)
SOLAR:
EMISSIONS: A new report finds that industrial and transportation activities create roughly two-thirds of all the greenhouse gas emissions in Pennsylvania’s Lehigh Valley. (Morning Call)
NUCLEAR:
GRID:
WORKFORCE:
GEOTHERMAL: A geothermal company raises $40 million in a Series C round led by Google Ventures and plans to relocate from Mount Kisco, New York, to Arlington, Virginia. (DC Inno)
WORKFORCE: The governors of 22 states launch an initiative aimed at getting 1 million residents to complete climate-related apprenticeships by 2035, pledging to set up funding and partnerships to expand the clean energy workforce. (The Hill)
POLITICS:
CLEAN ENERGY: Large tech firms part of the Sustainable Steel Buyers Platform launch a competitive bidding process asking steelmakers to deliver 1 million metric tons of near-zero emissions steel a year by 2028. (Canary Media)
HYDROGEN: There’s been little progress on plans to convert a troubled West Virginia coal-fired power plant to run on hydrogen, and its new owners have operated it barely half the time since acquiring it a year ago. (West Virginia Public Broadcasting)
EMISSIONS:
NUCLEAR: The nuclear industry reckons with how to best take advantage of a sweeping pro-nuclear law passed in June and weighs future legislative goals. (Utility Dive)
GRID:
ELECTRIFICATION:
COAL: An Alaska utility scraps plans to shutter a troubled coal plant, saying it needs the facility’s generation to offset a looming natural gas shortage in the Cook Inlet. (Alaska Beacon)
SOLAR:
WIND:
CLEAN ENERGY:
HYDROPOWER: The U.S. Energy Department awards Pacific Gas & Electric $34.5 million to fund 19 hydropower projects in northern California. (Power)
GRID: California’s grid operator says new data center interconnections have led them to increase demand forecasts for the San Jose area by 60%. (RTO Insider, subscription)
MINING:
ELECTRIFICATION: Washington state’s building industry and conservative advocates push a ballot measure that would prohibit local and state governments from banning natural gas hookups. (Crosscut)
EMISSIONS: Colorado advocates say a newly launched state initiative using cutting-edge technologies to monitor landfill methane pollution could be a model for slashing emissions of the potent greenhouse gas. (Canary Media)
PUBLIC LANDS: A federal court begins hearing a Utah lawsuit seeking to revoke presidents’ authority to establish landscape-scale national monuments that block mining and oil and gas drilling on hundreds of thousands of acres of public land. (Bloomberg Law)
BIOFUELS: A company looks to produce biofuels by injecting molasses into coal seams in Wyoming, extracting the methane and leaving the carbon dioxide underground. (Buffalo Bulletin)
UTILITIES: The Tennessee Valley Authority rolls out a long-term plan that presents 30 different pathways to balance energy generation with growing power demand, including the construction of between 9 GW and 26 GW of new power by 2035. (Knoxville News Sentinel)
SOLAR:
WIND: A long-delayed plan to build a 75 MW onshore wind farm in Virginia is pushed back yet another year, with plans to begin construction next year and begin generating power by 2026. (Roanoke Times)
ELECTRIC VEHICLES: A planned Hyundai electric vehicle and battery plant in Georgia that’s being supported by local, state and federal incentives sparks protests from farmers and residents concerned that it will use roughly 4 million gallons of water per day. (E&E News)
PIPELINES: An energy analyst discusses how the 580-mile Matterhorn Express Pipeline between west Texas and Houston will relieve bottlenecks and likely spur more oil and gas production in the Permian Basin. (Texas Standard)
OIL & GAS:
NUCLEAR: U.S. Sen. Joe Manchin trumpets the federal climate package’s role in a deal to restart Three Mile Island Nuclear Generating Station in Pennsylvania. (WV News)
GRID:
POLITICS: Republican governors from Louisiana, Nebraska, South Carolina and Tennessee meet in Chattanooga, Tennessee, to discuss energy efficiency, nuclear power, ethanol and the grid’s growing demand for power. (Chattanooga Times Free Press)
COMMENTARY:
Across California, the companies that are trying to build charging stations for electric trucks are being told that it will take years — or even up to a decade — for them to get the electricity they need. That’s because utilities are failing to build out the grid fast enough to meet that demand.
This poses a major problem for a state that’s aiming to clean up its trucking industry. California has the most aggressive set of truck electrification goals in the country, and compliance deadlines are coming up fast.
State legislators did pass two laws last year — SB 410 and AB 50 — ordering regulators to find ways to speed up the process of getting utility customers the grid power they need, and last week the California Public Utilities Commission issued a decision meant to set timeframes for this work.
But charging companies, electric truck manufacturers, and environmental advocates are not happy with the result. They say the decision does next to nothing to get utilities to move faster or work harder to serve the massive charging hubs being planned across the state.
“It’s shocking how little the commission did here. They basically adopted status quo timelines across the board,” said Sky Stanfield, an attorney working with the Interstate Renewable Energy Council, a nonprofit clean energy advocacy group.
California’s struggle to deal with this issue is raising doubts about not only whether the state can meet its own climate goals but also whether truck electrification targets are achievable at all. States in the U.S. Northeast and Pacific Northwest with transportation-electrification targets will also need to build megawatt-scale charging along highways. Those projects will likewise require grid capacity upgrades that take a much longer time to plan and build than charging sites for passenger vehicles.
Stanfield and IREC believe that the CPUC’s decision both is inadequate and runs counter to clear instruction from California law. SB 410 orders the CPUC to craft regulations that “improve the speed at which energization and service upgrades are performed” and push the state’s big utilities to upgrade their grids “in time to achieve the state’s decarbonization goals.”
But the state’s electric truck targets simply won’t be met if charging stations aren’t built more rapidly, Stanfield said. “No one’s going to buy a fancy EV truck that costs well over $100,000 if they can’t charge it.”
IREC isn’t alone in this perspective. Powering America’s Commercial Transportation, a consortium of major EV charging and manufacturing companies, wrote in its comments to the CPUC that the decision “does not comply with either the requirements or legislative intent” of the law.
PACT asked the CPUC to set a two-year maximum timeline for utilities to build new substations and complete the more complex grid upgrades required by large EV charging depots.
But instead, the CPUC simply had Pacific Gas and Electric, Southern California Edison , and San Diego Gas & Electric report how long these major “upstream capacity” grid projects are taking today and then used the lower average of that historical data to set maximum timelines that utilities should meet in the future.
Those timelines are much, much too long, electric truck manufacturers, charging-project developers, and clean transportation advocates say. They stretch from nearly two years for upgrading distribution circuits and nearly three years for upgrading substations to nearly nine years for building the new substations that utilities say they’ll need to power truck-charging depots currently being built.
“We’ve put in millions of dollars in the facilities we’ve already upgraded, and more that are in motion,” said Paul Rosa, a PACT board member.
As senior vice president of procurement and fleet planning at truck leasing company Penske, he is responsible for the company’s transport projects, including truck-charging projects in Southern and Central California.
But those projects represent just a fraction of the 114,500 chargers required to support the 157,000 medium- and heavy-duty vehicles that the California Energy Commission forecasts the state will need by 2030.
“If we can’t get the power, this all comes to a screeching halt,” Rosa said.
The slow and burdensome process of getting new customers connected to the grid — “energization” in CPUC parlance — isn’t a problem for just EV trucks.
PG&E has been under fire for years for failing to deliver timely grid hookups to everyday commercial and residential projects — a result, critics say, of poor planning and resource management.
The CPUC’s new decision does set a 125-business-day maximum timeline for these less complicated energizations. If those targets are met by utilities, “maximum timelines for grid connections could be reduced up to 49 percent compared to current operations,” the CPUC noted in a fact sheet accompanying the decision.
“I think the commission got it right” on these less complicated energization targets, said Tom Ashley, vice president of government and utility relations at Voltera, a company building EV charging projects across the state.
But how the commission handled the larger-scale grid upgrades — the kind needed to get EV truck-charging stations up and running — is a different story, he said. “That is where the industry is really frustrated that we didn’t get the help, and the utilities didn’t get the direction.”
The state’s Advanced Clean Trucks rule requires truck manufacturers to hit minimum targets for zero-emissions trucks as a percentage of total sales over the coming years, ratcheting from 30% of all medium- and heavy-duty vehicles by 2028 to 50% by 2030.
And California’s Advanced Clean Fleets rule requires the state’s biggest trucking and freight companies to convert hundreds of thousands of diesel trucks to zero-emissions models over the next 12 years, with earlier targets for certain classes of vehicles, including the heavy trucks carrying cargo containers from California’s busy and polluted ports.
Right now, many of the plans to build charging hubs for those trucks are stuck in grid-upgrade limbo — and the CPUC decision offers little indication it will get them unstuck.
“We’ve submitted for well over 50 projects in the past two years, looking for the right property to acquire,” said Jason Berry, director of energy and utilities at Terawatt Infrastructure. The startup has more than $1 billion in equity and project finance lined up to build large-scale charging hubs, including a network that will stretch from California to Texas along the I-10 highway, a major trucking corridor.
But of the sites Terawatt has scouted in California, “about 95% of those do not have the power we’re trying to request,” Berry said. To serve proposed charging hubs in California’s Inland Empire, utility SCE has said that it will need to expand existing substations, which takes four to five years, or build a new substation, which takes at least eight years, Terawatt said in May comments to the CPUC.
Terawatt is far from the only company facing delays. In testimony to the CPUC, Berry pointed out that Tesla has told the agency that 12 Supercharger sites with 522 charging stalls are facing delays because of capacity issues in SCE territory. A state-funded electric truck-charging project in the Inland Empire is also held up due to similar constraints.
The main problem is that large-scale charging sites can be built much faster than utilities are used to moving, Berry said. “We’re building projects, maybe ideally starting at 10 megawatts and then going to 20 megawatts,” Berry said. That’s about the same load on the grid as would be caused by an entirely new residential neighborhood or big commercial or industrial site.
But while those sites typically take years to plan and build, a new truck-charging site can go from planning to completion in less than a year.
“They have to have a mechanism to start on those things, or every single project is going to be four to five years out — which is what we’re being told on so many of these today,” he said.
The same point was made by Diego Quevedo, utilities lead and senior charging-infrastructure engineer at Daimler Truck North America, which joined fellow electric truck manufacturers Volvo Group North America and Navistar to weigh in on the CPUC proceeding.
“Trucks can be manufactured by OEMs and delivered approximately six months after receiving an order,” Quevedo said in testimony before the CPUC. But fleets won’t order trucks if they lack the confidence the utility grid infrastructure will be built and energized when the trucks are delivered.”
Utilities’ grid-capacity additions are taking from seven to 10 years to “plan, design, budget, construct, and energize,” he said. Unless those capacity expansions can be sped up significantly, “electric trucks become expensive stranded assets that are unable to charge,” he said.
California’s major utilities have a different perspective. They’ve argued in comments to the CPUC that it may be difficult or impossible to move more quickly on such complicated work.
First, as utilities have pointed out, many of the things that can slow down major grid projects are beyond their control. In a filing with the CPUC, PG&E noted that “one capacity upgrade project may face an extended timeline due to lengthy environmental assessments and permitting processes, and another may encounter challenges in acquiring materials in a timely manner due to manufacturer issues.”
IREC’s Stanfield conceded that equipment backlogs and environmental and permitting reviews are barriers to moving more quickly. “But we have to make it go faster if we want to hit our climate goals, if we want manufacturers to build clean trucks.”
And there’s an even bigger challenge to making major changes to the grid in anticipation of booming demand from EV charging: the cost involved.
“Lack of funding is the big block to meet the anticipated load growth,” Terawatt’s Berry said.
California’s utilities are already spending more than they ever have on their power grids, for myriad reasons. They are passing the costs of grid-hardening investments and integrating new clean energy into the power system on to customers in the form of electricity rates that are now the highest in the continental U.S.
Electricity rate increases are an economic and political crisis in California. Keeping them from rising any further has become the chief focus of lawmakers and regulators in the past several years. Any proposals that could raise customer bills even more face a tough battle — including plans to build grid infrastructure for electric truck-charging hubs.
SB 410 does give the CPUC permission to allow utilities to increase their spending in order to meet tighter EV-charger energization timelines. But the bill also calls on regulators to subject these requests to“extremely strict accounting.”
PG&E was the first utility to submit a ratemaking mechanism under SB 410 earlier this year. The Utility Reform Network, a ratepayer advocacy group, quickly filed comments protesting the utility’s plan to create a “balancing account” that would enable it to recover as much as $4 billion in additional energization-related spending from customers — a structure that falls outside the standard three-year “rate case” process for California utilities.
“PG&E’s electric rates and bills are now so high that they threaten both access to the essential energy services that PG&E provides and the achievement of the state’s decarbonization goals, which rely in part on customers choosing to electrify buildings and vehicles,” TURN wrote in its comments.
TURN wants the CPUC to limit the scope of SB 410’s extra cost-recovery provisions to “specific work needed to complete an individual customer connection request,” rather than the kind of proactive upstream grid investments that truck-charging advocates are calling for. TURN would prefer that those projects remain part of general rate cases, the sprawling proceedings that determine how much utilities spend on their grids.
But those general rate cases can take up to five years to move from identifying the broader, systemwide analyses of how much electricity demand is set to rise to winning regulatory approval in order to build the expensive grid infrastructure needed to actually meet those growing needs. That’s too long to wait to fix the problem, charging advocates say.
At the same time, ratepayer advocates are challenging utility efforts to expand the scope of their larger-scale plans to meet looming EV charging needs. In SCE’s current general rate case, TURN and the CPUC’s Public Advocates Office, which is tasked with protecting consumers, are protesting that the utility is overestimating how much money it needs to spend to prepare its grid from growing EV-charging needs.
Terawatt and other charging developers and electric truck manufacturers argue just the opposite — that the utility isn’t planning to spend enough over the next three years. In his testimony in the rate case, Terawatt’s Berry complained that TURN and PAO are challenging utility and state forecasts of future charging needs based on outdated data, and that failing to approve the utility’s funding request will “ensure that California fails to achieve its zero-emission vehicle goals.”
Charging advocates have also asked the CPUC to create a separate regulatory process to consider the grid buildout needs spurred by large-scale charging projects. But the CPUC rejected that concept in its decision last week, stating that “preferential treatment based on project type is prohibited by California law.”
All these conflicting imperatives leave the CPUC with tough choices to resolve the gap between charging needs and grid buildout plans, said Cole Jermyn, an attorney at the Environmental Defense Fund.
The CPUC “can and should do more here. I don’t think the timelines they set here are as strong as they could have been,” Jermyn said.
At the same time, “the commission had an incredibly difficult job here. The targets are not easy to set, and they had a very short timeline to do it.”
That’s why multiple groups have asked the CPUC to focus its next phase of work on implementing SB 410 and AB 50 on a key issue: aligning grid planning and EV charging needs.
“Part of the work here is figuring out what that proactive planning looks like,” Jermyn said. “The utility cannot wait around for customers to come to them and say, ‘We need 5 megawatts of capacity.’ They need to be looking out into the future to start proactively preparing their distribution grids for all this electrification.”
At the same time, “how do you balance that need for proactive planning and investment with ratepayer investments along the way to make sure this isn’t building assets that won’t be used and end up on someone’s bills?” Jermyn asked. That will be complicated, but, he added, “I think it’s doable — especially for a state that has such clear goals.”
SB 410 also specifically called on the CPUC to take California’s decarbonization goals into account in tackling energization delays — but last week’s decision “was relatively silent on that issue,” Jermyn said.
“This is something we think is incredibly important to be in the next phase of this proceeding, because it wasn’t in this one,” he said. “We don’t know if the timelines they set are meeting that goal or not. We should figure out if they are.”
EDF has advocated for years for utilities and regulators to approve grid spending in advance of EV charging needs, noting that such spending will end up reducing costs for utility customers in the long run.
That’s because California’s utilities don’t earn profits directly through electricity sales. Instead, their rates are structured to repay their costs of doing business. More customers buying more electricity can spread out the costs of collecting the money that utilities need to operate and invest in infrastructure, which can reduce the rates per kilowatt-hour that utilities must collect in future years.
This isn’t just a California issue. Nearly a dozen states — including Massachusetts, New Jersey, New York, Oregon, Vermont, and Washington — have adopted advanced clean truck rules. They’re not as aggressive as California’s rules, but meeting them will still require grappling with the same challenges around proactive grid planning.
Voltera’s Ashley worried that the CPUC’s decision may set a bad precedent for other state regulators on this front. “The commission has a really hard job. They’re tasked with a lot of complicated policy and execution,” he said. “And at the end of the day, they have some overarching mandates, including affordability for ratepayers,” that complicate the task.
But California also has “the most aggressive targets, goals, and statutory requirements around not just electrification of transportation but electrification of other segments” of the economy, he said. “If California doesn’t get this right, who will?”
CLEAN ENERGY: The Inflation Reduction Act has spurred more than $115 billion in clean energy manufacturing investment in its first two years, with a sodium battery plant and a solar panel factory among the latest project announcements. (Canary Media)
ALSO:
OIL & GAS:
BUILDINGS:
WIND: Opposition to offshore wind projects along the East Coast can be traced back to Robert F. Kennedy Jr.’s fight against wind turbines in the Nantucket Sound near his family’s Cape Cod estate. (Inside Climate News)
UTILITIES: Orlando, Florida’s municipal utility moves to build two new solar facilities, add battery storage and jettison 90% of its fossil fuel plants, but customers push back against plans to charge more for power during peak times and decrease solar net metering payments. (Orlando Sentinel)
ELECTRIC VEHICLES:
BATTERIES: The U.S. Energy Department awards a Colorado electric vehicle battery manufacturer $50 million as part of an effort to beef up the nation’s battery supply chain. (CPR)
ALSO: The U.S. Energy Department awards a manganese and zinc mine under development in southern Arizona $166 million to spur production of the battery metals. (Arizona Daily Star)
CLIMATE: A California report finds greenhouse gas emissions have dropped across all sectors in the state except residential and commercial, with transportation seeing the largest year-to-year decline as electric vehicle sales climb. (KTLA, news release)
ELECTRIC VEHICLES:
SOLAR:
GRID: The Western power grid reached a record-breaking peak load on July 10 even though demand was relatively moderate on California’s system. (RTO Insider, subscription)
WIND: A Hawaii wind facility’s operator says a new system designed to deter bats and prevent collisions with turbines has been successful so far. (Hawaii Public Radio)
OIL & GAS:
URANIUM: The Navajo Nation and a mining company continue working to negotiate a deal that would allow uranium ore shipments across tribal land. (AZ Mirror)
Ensuring that traditionally disinvested Black and Brown communities are not left behind is essential for a just transition away from carbon-based energy sources.
At the same time, many of these communities have vast stretches of vacant or underutilized properties, which could present opportunities for clean energy development.
For instance, in Detroit, city officials are working with DTE Energy to build 33 MW of solar arrays on vacant property around the city. Detroit’s mayor has touted the project as a way to deal with blight while producing clean energy, but neighbors are divided.
Meanwhile, in the West Woodlawn neighborhood on Chicago’s South Side, a community-based geothermal project is intentionally bypassing vacant lots, focusing instead on placing the necessary loop fields in alleyways.
“Not every block in the neighborhood even has a vacant lot that could be leveraged,” said Andrew Barbeau, president of The Accelerate Group in Chicago, which is providing technical assistance for the geothermal pilot, in an email. “Further, communities often have other ambitions for that land, whether it is new housing development, parks, greenways, or other beneficial uses.”
For Blacks in Green, the Chicago-based organization leading the geothermal project, recognition of the role of the project within a broader scope is central to an overall goal of generating economic development and a healthy environment within the community, said Nuri Madina, Sustainable Square Mile director, who serves as point person for the pilot.
“We know that the communities have been underserved. And underserved by definition means that we have not gotten our fair share of taxpayer investment in the communities. We know what our streets look like. And one of the major assets in the community, which is not really viewed as an asset, is our vacant lots,” Madina said.
Conventional geothermal systems require substantial plots of land to lay the subterranean loop fields that circulate both hot and cold water — land that is often scarce in densely populated urban areas.
But while West Woodlawn has a number of vacant lots, they are not being utilized for the project. Instead, alleys provide a potential solution for constructing geothermal loop fields, along with allowing for connection points for houses and multifamily buildings within the pilot footprint, Barbeau said.
“The good news is that based on the system design, we have more than enough capacity in the alleys to serve the load of the blocks we have modeled. The modeling also so far is showing us that the shared network model would require 20-30% less wells than if each home built their own system,” Barbeau said in an email.
Locating the bulk of the geothermal infrastructure in alleyways also sidesteps the underground congestion of existing gas, electric and water infrastructure on city streets, said Mark Nussbaum, owner and principal of Architectural Consulting Engineers in Oak Park, Illinois.
“There’s a lot of stuff happening out near the street. It doesn’t mean it’s not possible to coordinate it, but it’s just what’s nice about the alley concept is, it’s kind of unused for utilities typically,” Nussbaum said.
“White flight” and housing segregation have left many U.S. cities with sections of vacant or underinvested property, typically in communities populated by Black and Brown people.
With roughly 60% of the land area of Chicago, Detroit nonetheless has a much larger proportion of vacant land — approximately 19 square miles. In some neighborhoods, multiple blocks may only have a single structure remaining, if any at all.
DTE Energy’s plan to build large-scale solar arrays on some of that land is supported by some residents and municipal officials as a means to reduce illegal dumping and other nuisance crimes while working toward meeting city climate goals — and reducing utility bills for residents.
But there has also been pushback, largely focused on potential detrimental impact on property values in adjacent properties and limitations on future use of the sites themselves.
“Solar panels will disrupt and destroy entire neighborhoods. There will be no future affordable housing being built anywhere around a solar farm,” councilmember Angela Whitfield-Calloway said during a city council meeting in July, as reported by Planet Detroit.
Whitfield-Calloway also questions why municipal buildings or sites outside the city limits had not been considered for the solar arrays.
In Chicago, a battery storage facility constructed as part of the Bronzeville Microgrid project administered by electric utility ComEd generated similar debate during an extended period of community input. ComEd officials said the location of the battery facility, in the middle of a stretch of vacant plots near the South Side Community Art Center, was strategic to the overall microgrid project.
A 40-yard-long mural designed and created by local artists and mounted on the exposed long side of the battery storage facility not only serves to obscure the structure, but also to highlight prominent figures in Black history and culture. While reactions to the mural have been overwhelmingly positive, reception of the battery storage facility itself has been mixed.
“There were thorough talks with the community and the art community in Bronzeville about what they wanted, what [ComEd] planned to do [with] that battery station, because they did not want it to be an eyesore … they did not want it to just be, you know, brick walls around infrastructure,” Jeremi Bryant, a resident of Bronzeville, told the Energy News Network in February 2021.
For Bruce Montgomery, founder of Bronzeville-based Entrepreneur Success Program and a member of the advisory council for the Community of the Future, the location of the battery storage facility precluded potentially more beneficial future development for the site.
“That lot in most communities probably would have ended up being invested in as more quality residential,” Montgomery told the Energy News Network in February 2021. “But now you’ve taken it up with this box car. … You’ve got big things sitting out in the middle of a vacant lot a couple of doors down from one of the most historic locations in Bronzeville.”
For Blacks in Green, what might appear to the casual observer as a vacant lot overtaken by weeds belies its ultimate potential — as an affordable, energy-efficient residential complex, small business owned by a community resident, a much needed basic amenity like a grocery stocking fresh produce — or a native plant garden to attract pollinators.
On June 17, 2023, Blacks in Green collaborated with the Delta Institute to hold a combined Juneteenth celebration and BioBlitz to identify potential sites for green infrastructure. Experts and community residents worked side-by-side to map and measure plant life, insect populations, drainage and other elements during a walking inventory of vacant lots in the area.
In the case of West Woodlawn, installation of geothermal loop fields in its alleys — versus locating them in vacant plots — presents an opportunity to promote climate resiliency through mitigation of persistent urban flooding, by utilizing permeable pavers to replace existing concrete or asphalt, said Madina.
“All of our programs are designed to create multiple benefits,” Madina said.
Projects like the West Woodlawn community geothermal project represent a drive to revive and reinvent Chicago’s Black Wall Street within what once constituted the redline-confined boundaries of the Black population drawn to the city during the Great Migration of the 20th Century.
“In most communities, the vacant lots are really indicative of a declining community. But what we have tried to do is take that negative and turn it into something positive. So if we can take those vacant lots with weeds and debris and turn them into beautiful gardens, that is a very significant improvement in the community,” Madina said.
“So [we] could improve the quality of life, improve the spirit of the people in the community… that vacant lot can provide more than just beauty. It can provide more than just comfort for the residents. It can also provide biodiversity, it can provide pollination, it can provide food for the residents.”
Correction: A 40-yard-long mural was mounted on the side of a ComEd battery storage facility to obscure the structure and highlight prominent figures in Black history and culture. An earlier version of this story misstated its size.
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