Octillion advances efforts to generate power from moving vehicles

UAE Barakah Nuclear Plant connects Unit 1 to the grid, supplying clean electricity, nuclear baseload power, and lower carbon emissions, with IAEA oversight, FANR regulation, and South Korea collaboration, supporting energy security and economic diversification.

Key Points

The UAE Barakah Nuclear Plant is a four-reactor project delivering clean baseload power and reducing CO2.

✅ Unit 1 online; four reactors to supply 25% of UAE electricity

✅ Cuts 21 million tons CO2 annually; clean baseload for grid

✅ FANR-licensed; IAEA and WANO oversight ensure safety

Unit 1 of the UAE’s Barakah plant — the Arab world’s first nuclear energy plant in the region — has connected to the national power grid, in a historic moment enabling it to provide cleaner electricity to millions of residents and help reduce the oil-rich country’s reliance on fossil fuels. 

“This is a major milestone, we’ve been planning for this for the last 12 years now,” Mohamed Al Hammadi, CEO of Emirates Nuclear Energy Corporation (ENEC), told CNBC’s Dan Murphy in an exclusive interview ahead of the news.

Unit 1, which has reached 100% power as it steps closer to commercial operations, is the first of what will eventually be four reactors, which when fully operational are expected to provide 25% of the UAE’s electricity and reduce its carbon emissions by 21 million tons a year, according to ENEC. That’s roughly equivalent to the carbon emissions of 3.2 million cars annually.

The Gulf country of nearly 10 million is the newest member of a group of now 31 countries running nuclear power operations. It’s also the first new country to launch a nuclear power plant in three decades, the last being China’s nuclear energy program in 1990.

“The UAE has been growing from an electricity demand standpoint,”  Al Hammadi said. “That’s why we are trying to meet the demand (and) at the same time have it with less carbon emissions.”

The UAE’s electricity mix will continue to include gas and renewable energy, with “the baseload from nuclear,” including emerging next-gen nuclear designs, the CEO added, which he described as a “safe, clean and reliable source of electricity” for the country.

The project is also providing “highly compensated jobs” for the Emiratis and will introduce new industries for the country’s economy, Al Hammadi said. The company noted that it has awarded roughly 2,000 contracts worth more than $4.8 billion for local companies.

International collaboration
The UAE’s nuclear watchdog FANR, the Federal Authority for Nuclear Regulation, granted the operating license for Unit 1 in February, after an extensive inspection process to ensure the plant’s compliance with regulatory requirements. The license is expected to last 60 years. The program also involved collaboration with external bodies including the U.N.’s International Atomic Energy Agency (IAEA) and the government of South Korea, and its pre-start-up review was completed in January by the World Association of Nuclear Operators (WANO). The WANO and the IAEA have conducted over 40 inspection and review missions at Barakah.   

But the project has its critics, particularly some experts from the independent Nuclear Consulting Group non-profit, who have expressed concern about Barakah’s safety features and potential environmental risks.  

In response, ENEC said the “adherence to the highest standards of safety, quality and security is deeply embedded within the fabric of the UAE Peaceful Nuclear Energy Program.”

“The Barakah Plant meets all national and international regulatory requirements and standards for nuclear safety,” a  company statement said. It added that the reactor design had been certified by the Korea Institute of Nuclear Safety, FANR and the US-based Nuclear Regulatory Commission, “demonstrating the robustness of this design for safety and operating reliability.”

Worries of regional proliferation 
The achievement for the UAE is particularly significant given tensions in the wider region over nuclear proliferation. 

Some observers have warned of a regional arms race, though the UAE already partakes in what nuclear energy experts call the “gold standard” of civilian nuclear partnerships: The U.S.-UAE 123 Agreement for Peaceful Civilian Nuclear Energy Cooperation. It allows the UAE to receive nuclear materials, equipment and know-how from the U.S. while precluding it from developing dual-use technology by barring uranium enrichment and fuel reprocessing, the processes required for building a bomb.

By contrast, nearby Iran has suspended its compliance to the multilateral 2015 deal that regulated its nuclear power development and many fear its approach toward bomb-making capability. Meanwhile, Saudi Arabia has voiced its desire to develop a nuclear energy program without adhering to a 123 agreement.

And most recently, in the wake of a historic deal that has seen the UAE become the first Gulf country to normalize relations with Israel, Iran responded by warning the agreement would bring a “dangerous future” for the Emirati government. 

But ENEC and UAE officials emphasize the program’s commitment to safety, transparency and international cooperation, and its necessity for meeting growing electricity demand by cleaner means. 

“The nuclear industry is growing, with milestones around the world being reached, and the UAE is no exception. We are pursuing our electricity demand to meet that in a safe, secure and stable manner, and also doing it in an environmentally friendly way,” Al Hammadi said.

“Having four reactors that will provide 25% of electricity for the nation and will avoid us emitting 21 million tons of CO2 on an annual basis, as part of a broader green industrial revolution approach, is a very serious step to take — and the UAE is not talking about it, it is doing it, and we are reaping the benefits of it as we speak right now.”

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Texas PUC Electricity Market Reforms aim to boost grid reliability, support ERCOT resilience, pay standby generators, require capacity procurement, and mitigate blackout risk, though analysts warn higher consumer bills and winter reserve margin deficits.

Key Points

PUC proposals to bolster ERCOT reliability via standby capacity, capacity procurement, and measures to reduce blackout risk.

✅ Pays generators for standby capacity during grid stress

✅ Requires capacity procurement to meet forecast demand

✅ Could raise consumer bills despite reliability gains

The Public Utility Commission of Texas is discussing major reforms to the state’s electricity market with the purpose to avoid a repeat of the power failures and blackouts during the February 2021 winter storm, which led to the death of more than 100 people and left over 11 million residents without electricity for days.

The regulator is discussing at a meeting on Thursday around a dozen proposals to make the grid more stable and reliable in case of emergencies. Proposals include paying power generators that are on standby when the grid needs backup, and requiring companies to pre-emptively buy capacity to meet future demand.

It is not clear yet how many and which of the proposals for electricity market reforms PUC will endorse today, while Texans vote on funding to modernize electricity generation later this year.

Analysts and consumer protection bodies warn that the measures will raise the energy bills for consumers, as some electricity market bailout ideas shift costs to ratepayers as well.

“Customers will be paying for more, but will they be getting more reliability?” Michael Jewell, an attorney with Jewell & Associates PLLC who represents clients at PUC proceedings, told Bloomberg.

“This is going to take us further down a path that’s going to increase cost to consumers, we better be darn sure these are the right choices,” Tim Morstad, Associate State Director, AARP Texas, told FOX 4 NEWS.

Last month, a report by the North American Electric Reliability Corp warned that the Texas power grid remained vulnerable to blackouts in case of a repeat of this year’s February Freeze.

Beyond Texas, electricity blackout risks have been identified across the U.S., underscoring the stakes for grid planning.

According to the 2021-2022 Winter Reliability Assessment report, Texas risks a 37-percent reserve margin deficit in case of a harsh winter, with ERCOT moving to procure capacity to address winter concerns, NERC said.

A reserve margin is the reserve of power generation capacity comparative to demand. The expected reserve margin for Texas for this winter, according to NERC, is 41.9 percent. Yet if another cold spell hits the state, it would affect this spare capacity, pushing the margin deeply into negative territory.

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EU Power Market Overhaul targets soaring electricity prices by decoupling gas from power, boosting renewables, refining price caps, and stabilizing grids amid inflation, supply shocks, droughts, nuclear outages, and intermittent wind and solar.

Key Points

EU plan to redesign electricity pricing, curb gas-driven costs, boost renewables, and protect consumers from volatility.

✅ Decouples power prices from marginal gas generation

✅ Caps non-gas revenues to fund consumer relief

✅ Supports grid stability with storage, demand response, LNG

While energy prices are soaring around the world, Europe is in a particularly tight spot. Its heavy dependence on Russian gas -- on top of droughts, heat waves, an unreliable fleet of French nuclear reactors and a continent-wide shift to greener but more intermittent sources like solar and wind -- has been driving electricity bills up and feeding the highest inflation in decades. As Europe stands on the brink of a recession, and with the winter heating season approaching, officials are considering a major overhaul of the region’s power market to reflect the ongoing shift from fossil fuels to renewables.

1. How is electricity priced? 
Unlike oil or natural gas, there’s no efficient way to save lots of electricity to use in the future, though projects to store electricity in gas pipes are emerging. Commercial use of large-scale batteries is still years away. So power prices have been set by the availability at any given moment. When it’s really windy or sunny, for example, then more is produced relatively cheaply and prices are lower. If that supply shrinks, then prices rise because more generators are brought online to help meet demand -- fueled by more expensive sources. The way the market has long worked is that it is that final technology, or type of plant, needed to meet the last unit of consumption that sets the price for everyone. In Europe this year, that has usually meant natural gas. 

2. What is the relationship between power and gas? 
Very close. Across western Europe, gas plants have been a vital part of the energy infrastructure for decades, with Irish price spikes highlighting dispatchable power risks, fed in large part by supplies piped in from Siberia. Gas-fired plants were relatively quick to build and the technology straightforward, at least compared with nuclear plants and burns cleaner than coal. About 18% of Europe’s electricity was generated at gas plants last year; in 2020 about 43% of the imported gas came from Russia. Even during the depths of the Cold War, there’d never been a serious supply problem -- until the relationship with Russia deteriorated this year after it invaded Ukraine. Diversifying away from Russia, such as by increasing imports of liquefied natural gas, requires new infrastructure that takes a lot of time and money.

3. Why does it work this way? 
In theory, the relationship isn’t different from that with coal, for example. But production hiccups and heatwave curbs on plants from nuclear in France to hydro in Spain and Norway significantly changed the generation picture this year, and power hit records as plants buckled in the heat. Since coal-fired and nuclear plants are generally running all the time anyway, gas plants were being called upon more often -- at times just to keep the lights on as summer temperatures hit records. And with the war in Ukraine resulting in record gas prices, that pushed up overall production costs. It’s that relationship that has made the surging gas price the driver for electricity prices. And since the continent is all connected, it has pushed up prices across the region. The value of the European power market jumped threefold last year, to a record 836 billion euros ($827 billion today).

4. What’s being considered? 
With large parts of European industry on its knees and households facing jumps in energy bills of several hundred percent, as record electricity prices ripple through markets, the pressure on governments and the European Union to intervene has never been higher. One major proposal is to impose a price cap on electricity from non-gas producers, with the difference between that and the market price channeled to relief for consumers. While it sounds simple, any such changes would rip up a market design that’s worked for decades and could threaten future investments because of unintended consequences.

5. How did this market evolve?
The Nordic region and the British market were front-runners in the 1990s, then Germany followed and is now the largest by far. A trader can buy and sell electricity delivered later on same day in blocks of an hour or even down to 15-minute periods, to meet sudden demand or take advantage of price differentials. The price for these contracts is decided entirely by the supply and demand, how much the wind is blowing or which coal plants are operating, for example. Demand tends to surge early in the morning and late afternoon. This system was designed when fossil fuels provided the bulk of power. Now there are more renewables, which are less predictable, with wind and solar surpassing gas in EU generation last year, and the proposed changes reflect that shift. 

6. What else have governments done?
There are also traders who focus on longer-dated contracts covering periods several years ahead, where broader factors such as expected economic output and the extent to which renewables are crowding out gas help drive prices. This year’s wild price swings have prompted countries including Germany, Sweden and Finland to earmark billions of euros in emergency liquidity loans to backstop utilities hit with sudden margin calls on their trading.

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UK Market Stability Outlook remains febrile as the Bank of England, Treasury, and OBR forecasts shape fiscal policy, interest rates, gilt yields, inflation, energy bills, and pound sterling, with Oct. 31 guidance to reassure investors.

Key Points

A view of investor confidence as BOE policy, fiscal plans, and energy aid shape inflation and interest rates.

✅ Markets await Oct. 31 fiscal statement and OBR projections

✅ Energy support design drives inflation and disposable income

✅ Pound weakness adds imported inflation; rates seen up 75 bps

Bank of England Deputy Governor Dave Ramsden said financial markets are still unsettled about the outlook for the UK and that a Treasury statement due on Oct. 31 may provide some reassurance.

Speaking to the Treasury Committee in Parliament, Ramsden said officials in government and the central bank are dealing with huge economic shocks, notably the surge in energy prices that came with Russia’s attack on Ukraine. Investors are reassessing where interest rates and the fiscal stance are headed.

“Markets remain quite febrile,” Ramsden told members of Parliament in London on Monday. “Things have not settled down yet.”

He described the events following Prime Minister Liz Truss’s ill-fated fiscal statement on Sept. 23, which set out a series of tax cuts funded by borrowing that spooked investors and triggered a rout in UK assets. Ramsden said those events damaged the UK’s credibility among investors, but reversing that program and Truss’s decision to step aside have helped the nation regain confidence.

“Credibility is hard won and easily lost,” Ramsden said. “That credibility is being recovered. That has to be followed through. A return to the kind of stability around policy making and around the framing of fiscal events will be really important.”

He said the issue with the Sept. 23 statement was that “it had one side of the fiscal arithmetic in it” and that the decision to include forecasts from the Office for Budget Responsibility will help underpin the confidence investors have in assessing the UK budget due out next week, including potential moves to end the link between gas and electricity prices for consumers.

“What we are going to get on Oct. 31 will be very important,” Ramsden said, “as it will address measures such as the price cap on household energy bills and other fiscal choices.”

“My sense is that will take account of all the statements on both the revenue and on the spending side.”

The central bank already was getting some information from Chancellor of the Exchequer Jeremy Hunt’s team about the fiscal statement due. Hunt said last week he’d curtail government plans to subsidize household fuel bills in April, when a 16% decrease in energy bills is anticipated, instead of letting it run as long as planned and replace it with a more targeted program. 

“To the extent possible, we will obviously have a little bit of time to take account of that before we make our decisions later next week,” Ramsden said.

With Truss stepping down in the next day and handing power to Rishi Sunak, it isn’t certain the Oct. 31 statement will go ahead as planned. Ramsden’s remarks confirm reports that Hunt is preparing to make the statement, amid a free electricity debate in the industry, even before Sunak names his team.

Any hint about what sort of package Hunt will offer on energy is crucial to the BOE’s forecasts. Without aid for energy, consumers will be exposed to high winter heating and electricity costs and to the full force of whatever happens in natural gas and electricity markets, and that will have a big impact on how much disposable income is available to households.

The energy plan, alongside the energy security bill, “will be a key element, as obviously it will have a bearing on the path for inflation, which is critical, but also how much additional support relative to what we were assuming at the time of the September MPC there will be for households at different points in the income distribution,” Ramsden added.

Investors currently expect the BOE to hike rates by 75 basis points next week.

Ramsden also said the BOE is watching the pound’s decline to assess how that changes the outlook for inflation.

“We have to take account of it,” Ramsden said. “When sterling deprreciaties that feeds through to imported inflation. It’s fallen quite significantly. The overall trend is down.”

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Natrium small modular reactor pairs a sodium-cooled fast reactor with molten salt storage to deliver load-following, dispatchable nuclear power, enhancing grid flexibility and peaking capacity as TerraPower and GE Hitachi pursue factory-built, affordable deployment.

Key Points

A TerraPower-GE Hitachi SMR joining a sodium-cooled reactor with molten salt storage for flexible, dispatchable power.

✅ 345 MW base; 500 MW for 5.5 hours via thermal storage

✅ Sodium-cooled coolant and molten salt storage enable load-following

✅ Backed by major utilities; factory-built modules aim lower costs

Nuclear power is the Immovable Object of generation sources. It can take days just to bring a nuclear plant completely online, rendering it useless as a tool to manage the fluctuations in the supply and demand on a modern energy grid.  

Now a firm launched by Bill Gates in 2006, TerraPower, in partnership with GE Hitachi Nuclear Energy, believes it has found a way to make the infamously unwieldy energy source a great deal nimbler, drawing on next-gen nuclear ideas — and for an affordable price. 

The new design, announced by TerraPower on August 27th, is a combination of a "sodium-cooled fast reactor" — a type of small reactor in which liquid sodium is used as a coolant — and an energy storage system. While the reactor could pump out 345 megawatts of electrical power indefinitely, the attached storage system would retain heat in the form of molten salt and could discharge the heat when needed, increasing the plant’s overall power output to 500 megawatts for more than 5.5 hours. 

“This allows for a nuclear design that follows daily electric load changes and helps customers capitalize on peaking opportunities driven by renewable energy fluctuations,” TerraPower said. 

Dubbed Natrium after the Latin name for sodium ('natrium'), the new design will be available in the late 2020s, said Chris Levesque, TerraPower's president and CEO.

TerraPower said it has the support of a handful of top U.S. utilities, including Berkshire Hathaway Energy subsidiary Pacificorp, Energy Northwest, and Duke Energy. 

The reactor's molten salt storage add-on would essentially reprise the role currently played by coal- or gas-fired power stations or grid-scale batteries: each is a dispatchable form of power generation that can quickly ratchet up or down in response to changes in grid demand or supply. As the power demands of modern grids become ever more variable with additions of wind and solar power — which only provide energy when the wind is blowing or the sun shining — low-carbon sources of dispatchable power are needed more and more, and Europe is losing nuclear power at a difficult moment for energy security. California’s rolling blackouts are one example of what can happen when not enough power is available to be dispatched to meet peak demand. 

The use of molten salt, which retains heat at extremely high temperatures, as a storage technology is not new. Concentrated solar power plants also collect energy in the form of molten salt, although such plants have largely been abandoned in the U.S. The technology could enjoy new life alongside nuclear plants: TerraPower and GE Hitachi Nuclear are only two of several private firms working to develop reactor designs that incorporate molten salt storage units, including U.K.- and Canada-based developer Moltex Energy.

The Gates-backed venture and its partner touted the "significant cost savings" that would be achieved by building major portions of their Natrium plants through not a custom but an industrial process — a defining feature of the newest generation of advanced reactors is that their parts can be made in factories and assembled on-site — although more details on cost weren't available. Reuters reported earlier that each plant would cost around $1 billion.

NuScale Power

A day after TerraPower and GE Hitachi's unveiled their new design, another nuclear firm — Portland, Oregon-based NuScale Power — announced that the U.S. Nuclear Regulatory Commission (NRC) had completed its final safety evaluation of NuScale’s new small modular reactor design.

It was the first small modular reactor design ever to receive design approval from the NRC, NuScale said. 

The approval means customers can now pursue plans to develop its reactor design confident that the NRC has signed off on its safety aspects. NuScale said it has signed agreements with interested parties in the U.S., Canada, Romania, the Czech Republic, and Jordan, and is in the process of negotiating more. 

NuScale previously said that construction on one of its plants could begin in Utah in 2023, with the aim of completing the first Power Module in 2026 and the remaining 11 modules in 2027.

NuScale
An artist’s rendering of NuScale Power’s small modular nuclear reactor plant. NUSCALE POWER
NuScale’s reactor is smaller than TerraPower’s. Entirely factory-built, each of its Power Modules would generate 60 megawatts of power. The design, typical of advanced reactors, uses pressurized water reactor technology, with one power plant able to house up to 12 individual Power Modules. 

In a sign of the huge amounts of time and resources it takes to get new nuclear technology to the market’s doorstep, NuScale said it first completed its Design Certification Application in December 2016. NRC officials then spent as many as 115,000 hours reviewing it, NuScale said, in what was only the first of several phases in the review process. 

In January 2019, President Donald Trump signed into law the Nuclear Energy Innovation and Modernization Act (NEIMA), designed to speed the licensing process for advanced nuclear reactors, and the DOE under Secretary Rick Perry moved to advance nuclear development through parallel initiatives. The law had widespread bipartisan support, underscoring Democrats' recent tentative embrace of nuclear power.

An industry eager to turn the page

After a boom in the construction of massive nuclear power plants in the 1960s and 70s, the world's aging fleet of nuclear plants suffers from rising costs and flagging public support. Nuclear advocates have for years heralded so-called small modular reactors or SMRs as the cheaper and more agile successors to the first generation of plants, and policy moves such as the UK's green industrial revolution lay out pathways for successive waves of reactors. But so far a breakthrough on cost has proved elusive, and delays in development timelines have been abundant. 

Edwin Lyman, the director of nuclear power safety at the Union of Concerned Scientists, suggested on Twitter that the nuclear designs used by TerraPower and GE Hitachi had fallen short of a major innovation. “Oh brother. The last thing the world needs is a fleet of sodium-cooled fast reactors,” he wrote.  

Still, climate scientists view nuclear energy as a crucial source of zero-carbon energy, with analyses arguing that net-zero emissions may be impossible without nuclear in many scenarios, if the world stands a chance at limiting global temperature increases to well below 2 degrees Celsius above pre-industrial levels. Nearly all mainstream projections of the world’s path to keeping the temperature increase below those levels feature nuclear energy in a prominent role, including those by the United Nations and the International Energy Agency (IEA). 

According to the IEA: “Achieving the clean energy transition with less nuclear power is possible but would require an extraordinary effort.”

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UK Coal-Free Electricity Record highlights rapid growth in renewables as National Grid phases out coal; wind, solar, and offshore projects surge, green tariffs expand, and energy comparison helps consumers switch to cheaper, cleaner deals.

Key Points

Britain's longest coal-free run, enabled by renewables, lower demand, and grid shifts for cheaper, greener tariffs.

✅ Record set after two months without coal-fired generation

✅ Renewables outpace fossil fuels; wind and solar dominate

✅ Green tariffs expand; prices at three-year lows

On Wednesday 10 June, Britain hit a significant landmark: the UK went for two full months without burning coal to generate power – that's the longest period since the 1880s, following earlier milestones such as a full week without coal power in the recent past.

According to the National Grid, Britain has now run its electricity network without burning coal since midnight on the 9 April. This coal-free period has beaten the country’s previous record of 18 days, six hours and 10 minutes, which was set in June 2019, even though low-carbon generation stalled in 2019 according to analyses.

With such a shift in Britain’s drive for renewables and lower electricity demand following the coronavirus lockdown, as Britain recorded its cleanest electricity during lockdown to date, now may be the perfect time to do an online energy comparison and switch to a cheaper, greener deal.

Only a decade ago, around 40 per cent of Britain’s electricity came from coal generation, but since then the country has gradually shifted towards renewable energy, with the coal share at record lows in the system today. When Britain was forced into lockdown in response to the coronavirus pandemic, electricity demand dropped sharply, and the National Grid took the four remaining coal-fired plants off the network.

Over the past 10 years, Britain has invested heavily in renewable energy. Back in 2010, only 3 per cent of the country's electricity came from wind and solar, and many people remained sceptical. However, now, the UK has the biggest offshore wind industry in the world. Plus, last year, construction of the world’s single largest wind farm was completed off the coast of Yorkshire.

At the same time, Drax – Britain’s biggest power plant – has started to switch from burning coal to burning compressed wooden pellets instead, reflecting the UK's progress as it keeps breaking its coal-free energy record again across the grid. By this time next year, the plant hopes to have phased out coal entirely.

So far this year, renewables have generated more power than all fossil fuels put together, the BBC reports, and the energy dashboard shows the current mix in real time. Renewables have been responsible for 37 per cent of electricity supplied to the network, with wind and solar surpassing nuclear for the first time, while fossil fuels have accounted for 35 per cent. During the same period, nuclear accounted for 18 per cent and imports made up the remaining 10 per cent.

What does this mean for consumers?

As the country’s electricity supply moves more towards renewables, customers have more choice than ever before. Most of the ‘Big Six’ energy companies now have tariffs that offer 100 per cent green electricity. On top of this, specialist green energy suppliers such as Bulb, Octopus and Green Energy UK make it easier than ever to find a green energy tariff.

The good news is that our energy comparison research suggests that green energy doesn’t have to cost you more than a traditional fixed-price energy contract would. In fact, some of the cheapest energy suppliers are actually green companies.

At present, energy bills are at three-year lows, which means that now is the perfect time to switch supplier. As prices remain low and renewables begin to dominate the marketplace, more switchers will be drawn to green energy deals than ever before.

However, if you’re interested in choosing a green energy supplier, make sure that you look at the company's fuel mix. This way, you’ll be able to see whether they are guaranteeing the usage of green energy, or whether they’re just offsetting your usage. All suppliers must report how their energy is generated to Ofgem, so you’ll easily be able to compare providers.

You may find that you pay more for a supplier that generates its own energy from renewables, or pay less if the supplier simply matches your usage by buying green energy. You can decide which option is right for you after comparing the prices.

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