Coal should be a warming concern: scientists

UK low-carbon electricity 2019 saw stalled growth as renewables rose slightly, wind expanded, nuclear output fell, coal hit record lows, and net-zero targets demand faster deployment to cut CO2 intensity below 100gCO2/kWh.

Key Points

Low-carbon sources supplied 54% of UK power in 2019, up just 1TWh; wind grew, nuclear fell, and coal dropped to 2%.

✅ Wind up 8TWh; nuclear down 9TWh amid outages

✅ Fossil fuels 43% of generation; coal at 2%

✅ Net-zero needs 15TWh per year added to 2030

The amount of electricity generated by low-carbon sources in the UK stalled in 2019, Carbon Brief analysis shows.

Low-carbon electricity output from wind, solar, nuclear, hydro and biomass rose by just 1 terawatt hour (TWh, less than 1%) in 2019. It represents the smallest annual increase in a decade, where annual growth averaged 9TWh. This growth will need to double in the 2020s to meet UK climate targets while replacing old nuclear plants as they retire.

Some 54% of UK electricity generation in 2019 came from low-carbon sources, including 37% from renewables and 20% from wind alone, underscoring wind's leading role in the power mix during key periods. A record-low 43% was from fossil fuels, with 41% from gas and just 2% from coal, also a record low. In 2010, fossil fuels generated 75% of the total.

Carbon Brief’s analysis of UK electricity generation in 2019 is based on figures from BM Reports and the Department for Business, Energy and Industrial Strategy (BEIS). See the methodology at the end for more on how the analysis was conducted.

The numbers differ from those published earlier in January by National Grid, which were for electricity supplied in Great Britain only (England, Wales and Scotland, but excluding Northern Ireland), including via imports from other countries.

Low-carbon low
In 2019, the UK became the first major economy to target net-zero greenhouse gas emissions by 2050, increasing the ambition of its legally binding Climate Change Act.

To date, the country has cut its emissions by around two-fifths since 1990, with almost all of its recent progress coming from the electricity sector.

Emissions from electricity generation have fallen rapidly in the decade since 2010 as coal power has been almost phased out and even gas output has declined. Fossil fuels have been displaced by falling demand and by renewables, such as wind, solar and biomass.

But Carbon Brief’s annual analysis of UK electricity generation shows progress stalled in 2019, with the output from low-carbon sources barely increasing compared to a year earlier.

The chart below shows low-carbon generation in each year since 2010 (grey bars) and the estimated level in 2019 (red). The pale grey bars show the estimated future output of existing low-carbon sources after old nuclear plants retire and the pale red bars show the amount of new generation needed to keep electricity sector emissions to less than 100 grammes of CO2 per kilowatt hour (gCO2/kWh), the UK’s nominal target for the sector.

 Annual electricity generation in the UK by fuel, terawatt hours, 2010-2019. Top panel: fuel by fuel. Bottom panel: cumulative total generation from all sources. Source: BEIS energy trends, BM Reports and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
As the chart shows, the UK will require significantly more low-carbon electricity over the next decade as part of meeting its legally binding climate goals.

The nominal 100gCO2/kWh target for 2030 was set in the context of the UK’s less ambitious goal of cutting emissions to 80% below 1990 levels by 2050. Now that the country is aiming to cut emissions to net-zero by 2050, that 100gCO2/kWh indicator is likely to be the bare minimum.

Even so, it would require a rapid step up in the pace of low-carbon expansion, compared to the increases seen over the past decade. On average, low-carbon generation has risen by 9TWh each year in the decade since 2010 – including a rise of just 1TWh in 2019.

Given scheduled nuclear retirements and rising demand expected by the Committee on Climate Change (CCC) – with some electrification of transport and heating – low-carbon generation would need to increase by 15TWh each year until 2030, just to meet the benchmark of 100gCO2/kWh.

For context, the 3.2 gigawatt (GW) Hinkley C new nuclear plant being built in Somerset will generate around 25TWh once completed around 2026. The world’s largest offshore windfarm, the 1.2GW Hornsea One scheme off the Yorkshire coast, will generate around 5TWh each year.

The new Conservative government is targeting 40GW of offshore wind by 2030, up from today’s figure of around 8GW. If policies are put in place to meet this goal, then it could keep power sector emissions below 100gCO2/kWh, depending on the actual performance of the windfarms built.

However, new onshore wind and solar, further new nuclear or other low-carbon generation, such as gas with carbon capture and storage (CCS), is likely to be needed if demand is higher than expected, or if the 100gCO2/kWh benchmark is too weak in the context of net-zero by 2050.

The CCC says it is “likely” to “reflect the need for more rapid deployment” of low-carbon towards net-zero emissions in its advice on the sixth UK carbon budget for 2033-2037, due in September.

Trading places
Looking more closely at UK electricity generation in 2019, Carbon Brief’s analysis shows why there was so little growth for low-carbon sources compared to the previous year.

There was another increase for wind power in 2019 (up 8TWh, 14%), with record wind generation as several large new windfarms were completed including the 1.2GW Hornsea One project in October and the 0.6GW Beatrice offshore windfarm in Q2 of 2019. But this was offset by a decline for nuclear (down 9TWh, 14%), due to ongoing outages for reactors at Hunterston in Scotland and Dungeness in Kent.

(Analysis of data held by trade organisation RenewableUK suggests some 0.6GW of onshore wind capacity also started operating in 2019, including the 0.2GW Dorenell scheme in Moray, Scotland.)

As a result of these movements, the UK’s windfarms overtook nuclear for the first time ever in 2019, becoming the country’s second-largest source of electricity generation, and earlier, wind and solar together surpassed nuclear in the UK as momentum built. This is shown in the figure below, with wind (green line, top panel) trading places with nuclear (purple) and gas (dark blue) down around 25% since 2010 but remaining the single-largest source.

 Annual electricity generation in the UK by fuel, terawatt hours, 2010-2019. Top panel: fuel by fuel. Bottom panel: cumulative total generation from all sources. Source: BEIS energy trends, BM Reports and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
The UK’s currently suspended nuclear plants are due to return to service in January and March, according to operator EDF, the French state-backed utility firm. However, as noted above, most of the UK’s nuclear fleet is set to retire during the 2020s, with only Sizewell B in Suffolk due to still be operating by 2030. Hunterston is scheduled to retire by 2023 and Dungeness by 2028.

Set against these losses, the UK has a pipeline of offshore windfarms, secured via “contracts for difference” with the government, at a series of auctions. The most recent auction, in September 2019, saw prices below £40 per megawatt hour – similar to current wholesale electricity prices.

However, the capacity contracted so far is not sufficient to meet the government’s target of 40GW by 2030, meaning further auctions – or some other policy mechanism – will be required.

Coal zero
As well as the switch between wind and nuclear, 2019 also saw coal fall below solar for the first time across a full year, echoing the 2016 moment when wind outgenerated coal across the UK, after it suffered another 60% reduction in electricity output. Just six coal plants remain in the UK, with Aberthaw B in Wales and Fiddlers Ferry in Cheshire closing in March.

Coal accounted for just 2% of UK generation in 2019, a record-low coal share since centralised electricity supplies started to operate in 1882. The fuel met 40% of UK needs as recently as 2012, but has plummeted thanks to falling demand, rising renewables, cheaper gas and higher CO2 prices.

The reduction in average coal generation hides the fact that the fuel is now often not required at all to meet the UK’s electricity needs. The chart below shows the number of days each year when coal output was zero in 2019 (red line) and the two previous years (blue).

 Cumulative number of days when UK electricity generation from renewable sources has been higher than that from fossil fuels. Source: BEIS energy trends, BM Reports and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
The 83 days in 2019 with zero coal generation amount to nearly a quarter of the year and include the record-breaking 18-day stretch without the fuel.

Great Britain has been running for a record TWO WEEKS without using coal to generate electricity – the first time this has happened since 1882.

The country’s grid has been coal-free for 45% of hours in 2019 so far.https://www.carbonbrief.org/countdown-to-2025-tracking-the-uk-coal-phase-out …

Coal generation was set for significant reductions around the world in 2019 – including a 20% reduction for the EU as a whole – according to analysis published by Carbon Brief in November.

Notably, overall UK electricity generation fell by another 9TWh in 2019 (3%), bringing the total decline to 58TWh since 2010. This is equivalent to more than twice the output from the Hinkley C scheme being built in Somerset. As Carbon Brief explained last year, falling demand has had a similar impact on electricity-sector CO2 emissions as the increase in output from renewables.

This is illustrated by the fact that the 9TWh reduction in overall generation translated into a 9TWh (6%) cut in fossil-fuel generation during 2019, with coal falling by 10TWh and gas rising marginally.

Increasingly renewable
As fossil-fuel output and overall generation have declined, the UK’s renewable sources of electricity have continued to increase. Their output has risen nearly five-fold in the past decade and their share of the UK total has increased from 7% in 2010 to 37% in 2019.

As a result, the UK’s increasingly renewable grid is seeing more minutes, hours and days during which the likes of wind, solar and biomass collectively outpace all fossil fuels put together, and on some days wind is the main source as well.

The chart below shows the number of days during each year when renewables generated more electricity than fossil fuels in 2019 (red line) and each of the previous four years (blue lines). In total, nearly two-fifths of days in 2019 crossed this threshold.

 Cumulative number of days when the UK has not generated any electricity from coal. Source: BEIS energy trends, BM Reports and Carbon Brief analysis. Chart by Carbon Brief using Highcharts.
There were also four months in 2019 when renewables generated more of the UK’s electricity than fossil fuels: March, August, September and December. The first ever such month came in September 2018 and more are certain to follow.

National Grid, which manages Great Britain’s high-voltage electricity transmission network, is aiming to be able to run the system without fossil fuels by 2025, at least for short periods. At present, it sometimes has to ask windfarm operators to switch off and gas plants to start running in order to keep the electricity grid stable.

Note that biomass accounted for 11% of UK electricity generation in 2019, nearly a third of the total from all renewables. Some two-thirds of the biomass output is from “plant biomass”, primarily wood pellets burnt at Lynemouth in Northumberland and the Drax plant in Yorkshire. The remainder was from an array of smaller sites based on landfill gas, sewage gas or anaerobic digestion.

The CCC says the UK should “move away” from large-scale biomass power plants, once existing subsidy contracts for Drax and Lynemouth expire in 2027.

Using biomass to generate electricity is not zero-carbon and in some circumstances could lead to higher emissions than from fossil fuels. Moreover, there are more valuable uses for the world’s limited supply of biomass feedstock, the CCC says, including carbon sequestration and hard-to-abate sectors with few alternatives.

Methodology
The figures in the article are from Carbon Brief analysis of data from BEIS Energy Trends chapter 5 and chapter 6, as well as from BM Reports. The figures from BM Reports are for electricity supplied to the grid in Great Britain only and are adjusted to include Northern Ireland.

In Carbon Brief’s analysis, the BM Reports numbers are also adjusted to account for electricity used by power plants on site and for generation by plants not connected to the high-voltage national grid. This includes many onshore windfarms, as well as industrial gas combined heat and power plants and those burning landfill gas, waste or sewage gas.

By design, the Carbon Brief analysis is intended to align as closely as possible to the official government figures on electricity generated in the UK, reported in BEIS Energy Trends table 5.1.

Briefly, the raw data for each fuel is in most cases adjusted with a multiplier, derived from the ratio between the reported BEIS numbers and unadjusted figures for previous quarters.

Carbon Brief’s method of analysis has been verified against published BEIS figures using “hindcasting”. This shows the estimates for total electricity generation from fossil fuels or renewables to have been within ±3% of the BEIS number in each quarter since Q4 2017. (Data before then is not sufficient to carry out the Carbon Brief analysis.)

For example, in the second quarter of 2019, a Carbon Brief hindcast estimates gas generation at 33.1TWh, whereas the published BEIS figure was 34.0TWh. Similarly, it produces an estimate of 27.4TWh for renewables, against a BEIS figure of 27.1TWh.

National Grid recently shared its own analysis for electricity in Great Britain during 2019 via its energy dashboard, which differs from Carbon Brief’s figures.

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Georgia Power June bill credit delivers PSC-approved savings, lower fuel rates, and COVID-19 relief for residential customers, driven by natural gas prices and 2018 earnings, with typical 1,000 kWh users seeing June bill reductions.

Key Points

A PSC-approved one-time credit and lower fuel rates reducing June bills for Georgia Power residential customers.

✅ $11.29 credit for 1,000 kWh usage on June bills

✅ Fuel rate cut saves $10.26 per month from June to September 2020

✅ PSC-approved $51.5M credit based on Georgia Power's 2018 results

Georgia Power announced that the typical residential customer using 1,000-kilowatt hours will receive an $11.29 credit on their June bill, reflecting a lump-sum credit model also used elsewhere.

This reflects implementation of a one-time $51.5 million credit for customers, similar to Gulf Power's bill decrease efforts, approved by the Georgia Public Service Commission, as a result of

Georgia Power's 2018 financial results.

Pairing the June credit with new, lower fuel rates recently announced, the typical residential customer would see a reduction of $21.55 in June, even as some regions face increases like Pennsylvania's winter price hikes elsewhere.

The amount each customer receives will vary based on their 2018 usage. Georgia Power will apply the credit to June bills for customers who had active accounts as of Dec. 31, 2018, and are still active or receiving a final bill as of June 2020, and the company has issued pandemic scam warnings to help customers stay informed.

Fuel rate lowered 17.2 percent

In addition to the approved one-time credit in June, the Georgia PSC recently approved Georgia Power’s plan to reduce its fuel rates by 17.2 percent and total billings by approximately $740 million over a two-year period. The implementation of a special interim reduction will provide customers additional relief during the COVID-19 pandemic through even lower fuel rates over the upcoming 2020 summer months. The lower fuel rate and special interim reduction will lower the total bill of a typical residential customer using an average of 1,000-kilowatt hours by a total of $10.26 per month from June through September 2020.

The reduction in the company’s fuel rate is driven primarily by lower natural gas prices, even as FPL proposed multiyear rate hikes in Florida, as a result of increased natural gas supplies, which the company is able to take advantage of to benefit customers due to its diverse generation sources.

February bill credit due to tax law savings

Georgia Power completed earlier this year the third and final bill credit associated with the Tax Cuts and Jobs Act of 2017, resulting in credits totaling $106 million. The typical residential customer using an average of 1,000 kilowatt-hours per month received a credit of approximately $22 on their February Georgia Power bill, a helpful offset as U.S. electric bills rose 5% in 2022 according to national data.

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Geothermal Emergency Permitting accelerates BLM approvals on public lands via categorical exclusions for exploratory drilling and geophysical surveys, boosting domestic energy security, cutting timelines by up to a year, and streamlining low-impact reviews.

Key Points

A policy fast-tracking geothermal exploration on public lands, using BLM categorical exclusions to cut review delays.

✅ Categorical exclusions speed exploratory drilling approvals

✅ Cuts permitting timelines by up to one year

✅ Focused on public lands to enhance energy security

In a significant policy shift, the U.S. Department of the Interior has introduced emergency permitting procedures aimed at expediting the development of geothermal energy projects. This initiative, announced on May 30, 2025, is part of a broader strategy to enhance domestic energy production, seen in proposals to replace Obama's power plant overhaul and reduce reliance on foreign energy sources.

Background and Rationale

The decision to fast-track geothermal energy projects comes in the wake of President Donald Trump's declaration of a national energy emergency, which faces a legal challenge from Washington's attorney general, on January 20, 2025. This declaration cited high energy costs and an unreliable energy grid as threats to national security and economic prosperity. While the emergency order includes traditional energy resources such as oil, gas, coal, and uranium and nuclear energy resources, it notably excludes renewable sources like solar, wind, and hydrogen from its scope.

Geothermal energy, which harnesses heat from beneath the Earth's surface to generate electricity, is considered a reliable and low-emission energy source. However, its development has been hindered by lengthy permitting processes and environmental reviews, with recent NEPA rule changes influencing timelines. The new emergency permitting procedures aim to address these challenges by streamlining the approval process for geothermal projects.

Key Features of the Emergency Permitting Procedures

Under the new guidelines, the Bureau of Land Management (BLM) has adopted categorical exclusions to expedite the review and approval of geothermal energy exploration on public lands. These exclusions allow for faster permitting of low-impact activities, such as drilling exploratory wells and conducting geophysical surveys, without the need for extensive environmental assessments.

Additionally, the BLM has proposed a new categorical exclusion that would apply to operations related to the search for indirect evidence of geothermal resources. This proposal is currently open for public comment and, if finalized, would further accelerate the discovery of new geothermal resources on public lands.

Expected Impact on Geothermal Energy Development

The implementation of these emergency permitting procedures is expected to significantly reduce the time and cost associated with developing geothermal energy projects. According to the Department of the Interior, the new measures could cut permitting timelines by up to a year for certain types of geothermal exploration activities.

This acceleration in project development is particularly important given the untapped geothermal potential in regions like Nevada, which is home to some of the largest undeveloped geothermal resources in the country.

Industry and Environmental Reactions

The geothermal industry has largely welcomed the new permitting procedures, viewing them as a necessary step to unlock the full potential of geothermal energy. Industry advocates argue that reducing permitting delays will facilitate the deployment of geothermal projects, contributing to a more reliable and sustainable energy grid amid debates over electricity pricing changes that affect market signals.

However, the exclusion of solar and wind energy projects from the emergency permitting procedures has drawn criticism from some environmental groups. Critics argue that a comprehensive approach to energy development should include all renewable sources, not just geothermal, to effectively address climate change, as reflected in new EPA pollution limits for coal and gas power plants, and promote energy sustainability.

The U.S. government's move to implement emergency permitting procedures for geothermal energy development marks a significant step toward enhancing domestic energy production and reducing reliance on foreign energy sources. By streamlining the approval process for geothermal projects, the administration aims to accelerate the deployment of this reliable and low-emission energy source. While the exclusion of other renewable energy sources from the emergency procedures has sparked debate, especially after states like California halted an energy rebate program during a federal freeze, the focus on geothermal energy underscores its potential role in the nation's energy future.

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Manitoba Hydro unpaid leave plan offers unpaid days off to curb workforce costs amid COVID-19, avoiding temporary layoffs and pay cuts, targeting $5.7M savings through executive, manager, and engineer participation, with union options under discussion.

Key Points

A cost-saving measure offering unpaid days off to avert layoffs and pay cuts, targeting $5.7M savings amid COVID-19.

✅ 3 unpaid days for executives, managers, engineers

✅ Targets $5.7M total; $1.4M from non-union staff

✅ Avoids about 240 layoffs over a four-month period

The Manitoba government's Crown energy utility is offering workers unpaid days off as an alternative to temporary layoffs or pay cuts, even as residential electricity use rises due to more working from home.

In an email to employees, Manitoba Hydro president Jay Grewal says executives, managers, and engineers will take three unpaid days off before the fiscal year ends next March.

She says similar options are being discussed with other employee groups, which are represented by unions, as the Saskatchewan COVID-19 crisis reshaped workforces across the Prairies.

The provincial government ordered Manitoba Hydro to reduce workforce costs during the COVID-19 pandemic, as some power operators considered on-site staffing plans, and at one point the utility said it was looking at 600 to 700 temporary layoffs.

The organization said it’s looking for targeted savings of $5.7 million, down from $11 million previously estimated, while peers like BC Hydro’s Site C began reporting COVID-19 updates.

A spokesperson for Manitoba Hydro said non-unionized staff taking three days of unpaid leave will save $1.4 million of the $5.7 million savings.

“Three days of unpaid leave for every employee would eliminate layoffs entirely,” the spokesperson said in an email. “For comparison, approximately 240 layoffs would have to occur over a four-month period, while measures like Alberta's worker transition fund aim to support displaced workers, to achieve savings of $4.3 million.”

Grewal says the unpaid days off were a preferred option among the executives, managers, and engineers in an industry that recently saw a Hydro One worker injury case.

She says unions representing the other workers have been asked to respond by next Wednesday.

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Kenya Power token glitches, inflated bills disrupt prepaid meters via M-Pesa paybill 888880 and third-party vendors like Vendit and Dynamo, causing delays, fast-depleting tokens, and billing estimates; customers report weekend outages and business losses.

Key Points

Service failures delaying token generation and disputed charges from estimated meter readings and slow processing.

✅ Impacts M-Pesa paybill 888880 and authorized third-party vendors

✅ Causes delays, fast-depleting tokens, weekend business closures

✅ Linked to system downtime, billing estimates, meter reading gaps

Kenya Power is again on the spotlight following claims of inflated power bills and a glitch in its electronic payment system that made it impossible to top up tokens on prepaid meters.

Thousands of customers started experiencing the hitch in tokens generation on Friday evening, with the problem extending through the weekend.

Small businesses such as barber shops that top up multiple times a week were hardest hit.

“My business usually thrives during weekends but I was forced to close early in the evening due to lack of power although I had paid for the tokens that were never generated,” said Mr John Kamau, a fast food restaurant owner in Nairobi.

Kenya Power processes up to 200,000 electronic transactions per day for power users, with 85 per cent done through its Safaricom M-Pesa paybill number 888880.

The remaining share is handled by its authorised third party vendors such as Vendit (paybill number 501200) and Dynamo (800904), which charge a premium for the transaction.

The sole electricity distributor admitted its system encountered challenges that crippled token generation across all vendors, advising customers on prepaid meters to buy the units from Kenya Power banking halls across the country until normalcy returned.

STATEMENT

“The IT team is trying to figure out where the problem was before we issue a comprehensive statement on the issue,” the firm responded to Nation queries, adding that the issue had been resolved by yesterday afternoon.

Customers who use Vendit confirmed to Nation they had successfully bought tokens yesterday afternoon.

However, there have been complaints that third party vendors process tokens almost in real time, unlike Kenya Power which, despite indicating a 30 minute delay in its service promise, sometimes takes up to six hours.  

But other users complained of inflated power bills after being slapped with abnormally high charges.

TOKENS

The holder of account number 30624694, for instance, received a post-paid bill of Sh16,765 last month, up from Sh894 the previous month.

She indulged the company and ended up paying just over Sh1,000.

There have also been complaints of tokens getting depleted too fast. For instance, one customer who normally uses Sh4,000 per month complained of her credit running out in a week.

Kenya Power maintains it cannot read all post-paid meters across the country, compelling it to make estimates for a number of customers.

The company argues it is not cost-effective to have meter readers go to all homes. The firm recently indicated plans to put all domestic consumers on prepaid meters to reduce non-payment of electricity bills and cut operation costs on meter reading and postage.

POWER CONSUMPTION

The Nairobi Securities Exchange-listed firm has also adopted a new integrated customer management system to enable consumers to self-check their power consumption and understand their electricity bill and payment obligations through a phone app.

In the past, concerns have been rife that customers often encounter delays when buying tokens through paybill number 888880, unlike through other vendors.

This has raised questions on the ownership of the vendors and the cash commissions they are entitled to, with holiday scam warnings circulating in some markets as well.

FOUL PLAY

Kenya Power has, however, denied any foul play, saying the authorisation of other vendors was to ease pressure on its payment channel, which handles 85 per cent of the nearly 200,000 transactions per day.

“In fact we have 11 vendors, including Equitel, it’s just that people are only aware of Vendit and Dynamo because they have been aggressive in their marketing,” the company said.

Kenya Power has been battling court cases over inflated power bills after it emerged that the utility firm was backdating bills worth Sh10.1 billion from last November.

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Vogtle Unit 3 Initial Criticality marks the startup of a new U.S. nuclear reactor, initiating fission to produce heat, steam, and electricity, supporting clean energy goals, grid reliability, and carbon-free baseload power.

Key Points

Vogtle Unit 3 Initial Criticality is the first fission startup, launching power generation at a new U.S. reactor.

✅ First new U.S. reactor to reach criticality since 2016

✅ Generates carbon-free baseload power for the grid

✅ Faced cost overruns and delays during construction

For the first time in almost seven years, a new nuclear reactor has started up in the United States.

On Monday, Georgia Power announced that the Vogtle nuclear reactor Unit 3 has started a nuclear reaction inside the reactor as part of the first new reactors in decades now taking shape at the plant.

Technically, this is called “initial criticality.” It’s when the nuclear fission process starts splitting atoms and generating heat, Georgia Power said in a written announcement.

The heat generated in the nuclear reactor causes water to boil. The resulting steam spins a turbine that’s connected to a generator that creates electricity.

Vogtle’s Unit 3 reactor will be fully in service in May or June, Georgia Power said.

The last time a nuclear reactor reached the same milestone was almost seven years ago in May 2016 when the Tennessee Valley Authority started splitting atoms at the Watts Bar Unit 2 reactor in Tennessee, Scott Burnell, a spokesperson for the Nuclear Regulatory Commission, told CNBC.

“This is a truly exciting time as we prepare to bring online a new nuclear unit that will serve our state with clean and emission-free energy for the next 60 to 80 years,” Chris Womack, CEO of Georgia Power, said in a written statement. 

Including the newly turned-on Vogtle Unit 3 reactor, there are currently 93 nuclear reactors operating in the United States and, collectively, they generate 20% of the electricity in the country, although a South Carolina plant leak recently showed how outages can sideline a unit for weeks.

Nuclear reactors, which help combat global warming and support net-zero emissions goals, generate about half of the clean, carbon-free electricity generated in the U.S.

Most of the nuclear power reactors in the United States were constructed between 1970 and 1990, but construction slowed significantly after the accident at Three Mile Island near Middletown, Pennsylvania, on March 28, 1979, even as interest in next-gen nuclear power has grown in recent years. From 1979 through 1988, 67 nuclear reactor construction projects were canceled, according to the U.S. Energy Information Administration.

However, because nuclear energy is generated without releasing carbon dioxide emissions, which cause global warming, the increased sense of urgency in responding to climate change has given nuclear energy a chance at a renaissance as atomic energy heats up again globally.

The cost associated with building nuclear reactors is a major barrier to a potential resurgence in nuclear energy, however, even as nuclear generation costs have fallen to a ten-year low. And the new builds at Vogtle have become an epitome of that charge: The construction of the two Vogtle reactors has been plagued by cost overruns and delays.
 

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