The long and winding road to energy net-zero 2050



For a power plant due to be mothballed amid a long-term plan to abandon electricity generation from coal, West Burton A weathered last winter surprisingly well. And following a letter from secretary of state for business, energy and industrial strategy Kwasi Kwarteng to its owner EDF Energy telling them it would need to be on standby for a while longer, it is probably going to have another good winter.

Amid generation shortages in the winter of 2021, the electricity system operator (ESO) arm of National Grid was forced to call West Burton A back into action to the point that for a while it would match wind generation: 5.5 per cent of the nation’s electricity mix. Though it was the lack of wind that made the headlines, according to the spring 2022 Energy Trends report published by Kwarteng’s department BEIS, the revived dash for gas during late 2021 also had its roots in the problems facing the ageing nuclear fleet as well as decisions by fossil-fuel extractors themselves.

Seasonal demand was increasing just at the point when nuclear operators performed maintenance on their fleet, which cut output by almost 10 per cent to levels last seen in 1982. It was a similar story for North Sea oil and gas, who cut production by close to 20 per cent during the summer of 2021 while global gas prices also continued their climb, hitting 300p at the end of last year. Electricity prices followed almost in lockstep, pushing close to £300/MWh from a low of less than £50/MWh only the year before when, amid Covid lockdowns, gas and oil prices had slumped. Day-ahead contracts for both gas and electricity hit new highs at the start of July on the threat of strikes at Norwegian oilfield operator Equinor.

The dramatic rises seem counter-intuitive at a time when renewables deliver a substantial and increasing chunk of power and at successively lower prices. According to the BEIS Energy Trends reports, renewables’ share of electricity increased in the last quarter of 2021 to almost 43 per cent compared to 2020 and increased again to 45.5 per cent in the first quarter of this year.

The wind farm projects expected to come onstream by 2025 have agreed to deliver power at just under £40/MWh and will, if they are in the contracts-for-difference (CfD) scheme that sets a minimum price for their electricity, wind up paying back the money from higher prices to the publicly owned Low Carbon Contract Company normally used to offset payments for the following quarter. The first quarter of 2022 saw the scheme return money to electricity suppliers for the first time.

The prospect of starting off their CfD arrangement by paying out has seen a number of generators delay their use of the 15-year contracts on their latest farms in order to benefit from the full market price of energy in the short term: they can hold off potentially for as long as three years. According to management consultancy Cornwall Insight, 90 per cent of the hourly periods used to calculate electricity prices from the start of 2022 up to mid-May were above the strike price. On average the wholesale price was more than double the agreed CfD price.

Though its structure makes it vulnerable to larger swings, the UK’s market structure is not all that different from that in many other developed nations in that a ‘merit-order stack’ determines which energy source is prioritised at different network loads. Operators will naturally favour cheap supplies over more expensive options up to the point where they run out, forcing them to use the next more expensive available option until they have met their needs.

Studies such as one by Michael Grubb, professor of energy and climate at UCL, and colleague Paul Drummond published in 2018, have shown that it is a combination of this effect and the way in which prices are set nationally that means it is the marginal cost of that final, last-resort fuel that controls the price seen by consumers, not protection by a price cap.

In March, Cian McLeavey-Reville, senior director of market development at National Grid ESO, explained in a seminar organised by the company on the possible restructuring of the way electricity capacity is managed in the UK that a variety of perverse incentives and shortcomings have become embedded in today’s energy market. “We don’t believe that the current market was designed for net-zero and left unchanged will result in excessive and unnecessary costs for consumers,” he claimed.

If we discount the pricing problems faced by the consumer, the target set by Prime Minister Boris Johnson of a fully decarbonised electricity grid by 2035 – ahead of a net-zero energy sector in 2050 – is not unrealistic from the perspective of building out more low-carbon capacity. Fintan Slye, National Grid ESO executive director, had claimed a few months before the announcement of the target: “We’re confident that by 2025 we will have periods of 100 per cent zero-carbon electricity, with no fossil fuels used to generate power in Great Britain.”

One reason for this optimism is electricity’s role in the current energy mix. At the end of the last decade, gas and oil for heating and transport were responsible for more than three times as much energy as electricity, for a total of almost 1400TWh. That imbalance makes delivering a zero-carbon mix by 2050 more of a stretch compared to net-zero electricity by 2035. However, few expect to have to do it by boosting electricity generation threefold in as many decades.

Scenarios considered by National Grid ESO in a series of annual studies assume efficiency improvements will bring the total required by 2050 down significantly. In the most optimistic forecast, tagged Consumer Transformation in the 2021 edition of its Future Energy Scenarios reports, total energy delivered in 2050 would be 600TWh, almost all of it electrical: double 2020’s electricity usage. A less optimistic but net-zero System Transformation option calls for 800TWh of annual capacity, which equates to an average power delivery of around 90GW. The biggest cuts to energy use would come from substantially electrified transport with industrial and residential energy use falling by around 25 per cent.

Because of its heavier reliance on the use of hydrogen, National Grid’s System Transformation scenario is not far from the near-700TWh picture presented by the UK government in its 2020 Energy White Paper. In the scenarios modelled by BEIS, around 9 per cent of the energy required would continue to come from methane coupled with carbon-capture and storage, pushing green hydrogen to less than 5 per cent. Nuclear would be responsible for 17 per cent and potentially higher than 20 per cent under alternatives. The projected share for nuclear has now risen to 25 per cent of the total with a peak capacity of 24GW announced in the British Energy Security Strategy launched in April.

According to the June 2022 BEIS Energy Trends report, renewables capacity increased by 1.8GW in 2021 to surpass 25GW, with another 1.5GW added in the first quarter of this year alone. Most of the new generation came in the form of offshore wind. And the government’s focus in renewables is now very much on offshore wind, setting a target in the spring of 50GW by 2030, four times the level at the end of 2020. Onshore wind and solar do not have targets. And the former is increasingly becoming mired in planning disputes, though public opinion overall is broadly in favour of the technology and it is the cheaper option. On a cost-per-kWh basis, according to estimates from IRENA (the International Renewable Energy Agency), it can be half that of offshore turbines, which fell to around 9 US cents per kWh by 2019 based on projects around Denmark, which started building these farms in 1991.

Were wind the sole contributor to power delivery, the 2050 target would call for a nameplate power capacity of around 200GW and perhaps a little higher. This figure reflects the lower load factor that renewables have compared to nuclear or gas: a factor of their variability. That would reflect a build-out from 2030 of some 7GW per year, though that is only double the increase seen in 2018.

Trading as much as a third of that for nuclear and gas would bring the increase needed in terms of nameplate capacity down to the same pace as that envisaged for the government’s current targets. However, it is not likely to be the lowest-cost option. The strike prices for nuclear are set today at higher levels – now more than £100/MWh – than those projected for renewables. Construction costs are also likely to be high for nuclear though, once load factor is taken into account, some offshore wind works out more expensive than the £23bn currently estimated for the 3.2GW Hinkley Point C reactor. Novel floating farms such as Hywind Scotland off the coast of Peterhead came with a construction price tag that worked out at almost £9m/MW of nameplate capacity. However, it also recorded an average capacity of almost 60 per cent in 2020 compared to the mid-30s average seen for older offshore wind turbines. Many other fixed-turbine offshore projects that can stand in shallower North Sea waters have fallen to below nuclear, even taking into account the lower load factor. In the meantime, Equinor expects the Tampen floating-wind project in Norway to cut costs by 40 per cent compared to its Hywind Scotland.

The market is also increasingly in favour of borrowing cash to fund wind farms, with a large chunk now coming from pension funds, though this may change if the cost of capital increases in the wake of quantitive tightening by central banks. Though the Scottish government aimed for 11GW of offshore by 2030, up from 1GW in 2020, the ScotWind auction in January 2022 wound up with 17 fixed- and floating-turbine projects for almost 25GW across 7,000 square kilometres of sea area.

This is where the details start getting in the way. A continuing problem is moving wind-generated energy south of the border thanks to congestion on the transmission network that already affects Scotland’s onshore farms. A particular problem lies in the B6 boundary that divides the England and Scotland grid sectors. A report by Aurora Energy Research published in February pointed to National Grid’s plans to add 7GW in transmission capacity across the B6 boundary by 2035 but added “this will not keep pace with the expected build-out of Scottish wind capacity in a net-zero world”. The result is that wind farms have had to suffer additional curtailment – and be forced to dump power – even when that electricity is needed elsewhere in the country. In compiling a report for generation operator Drax, consultants Lane Clark & Peacock found 80 per cent of the energy forced to be dumped through curtailment of renewables was generated in Scotland.

At the March National Grid ESO event, McLeavey-Reville showed a graph that demonstrated how the costs caused by dealing with transmission constraints had risen eight-fold since 2010. The company’s current modelling points to those costs alone possibly hitting £2.5bn by the end of the decade. The ESO has advised Ofgem to change the way electricity is sold so that it reflects where the usage takes place to try to better control regional demand and prevent perverse incentives in the current structure that can lead to power being imported through international interconnectors even when there is cheap power available domestically. However, at the event, some such as Cathy McClay, trading and optimisation director at Sembcorp Energy UK, pointed out that the boundary problem may simply need a lot more high-voltage cables to move energy where it is wanted across Great Britain.

The answer recommended by Aurora and a growing community around renewables is to invest far more heavily in long-duration storage to be able to support many hours of delivery. Right now, according to National Grid ESO, storage accounts for just 1 per cent of the electricity delivered to users over its grid; much of it still comes from the pumped-hydro plants in Scotland and Wales originally built in the 1970s to support an earlier planned transition from fossil fuels to nuclear. The new storage capacity, which represents about a quarter of the current total, is mostly based on a growing collection of lithium-ion battery installations and used by the ESO to prevent short-term stability problems in the grid. Drax, however, wants to expand its pumped-hydro installation at Cruachan in Scotland with 600MW of storage.

According to the Lane Clark & Peacock (LCP) report, 600MW of power would cover almost half of the curtailment situations the team identified in 2020 and 2021. In principle, a greatly increased storage pool could overcome the need to use natural gas at all.

Several groups have calculated the mixture of renewables most likely to be able to support net-zero when coupled with storage. Stanford University’s 100 Per Cent project, headed by Professor Mark Jacobson, estimated in 2017 that a 60/40 split between wind and solar would likely work best. Bruno Cárdenas and colleagues at the University of Nottingham found a mix of 85 per cent wind and 15 per cent solar would deliver the lowest-cost option: it is the one that minimises the amount of storage capacity required.

However, among policymakers, large-scale storage is a relative latecomer. The 2020 Energy White Paper made almost no mention of energy storage. A year later, BEIS and National Grid ESO began to look more closely at a much expanded role for storage to deal with the shortfalls that will inevitably occur when renewables cannot meet peak demand as well as to maximise the amount of energy recovered from renewables. Following a call for evidence last autumn, BEIS expects to update its policy on long-duration later this year.

With the installation of plants like Drax’s expansion at Cruachan, wind operators would be able to send their peak power, in principle, to large pumped-hydro stations in Scotland optimised for long-duration storage. Even then, there remains the issue of later shipping that energy to England and Wales and what pricing signals would allow for it to happen at the right times in a grid that is largely built around managing very short-term storage.

If the recommendations made by National Grid ESO to move to location-based pricing go through, it is possible that this would shift the investment decisions made by both generators and major users. Industrial and data-centre users could decide to set up shop close to Scotland’s wind farms while the renewables projects themselves decide to risk greater NIMBYism in the south in order to avoid curtailment if and when they get their installations approved. Another consequence, however, might be the more widespread deployment of floating wind platforms around the coast. A 2017 UCL study found this would reduce storage levels by taking advantage of differences in wind around the island of Great Britain and potentially could lead to generation more often being close to large users.

Storage operators have a lot of choices. They can turn to pumped-hydro, compressed or liquified air as well as batteries, though lithium-ion tends to become very expensive for durations beyond four hours according to analysis performed by engineering group Jacobs. Pumped-hydro is not only the most mature storage technology, it also works out the cheapest on a per-kWh basis in most studies. The bad news is that pumped hydro has the highest capital cost. Not only that, LCP on behalf of Drax argue that pricing distortion in the current market makes these large plants even more difficult to finance because of problems such as paying twice for connections to the grid on the basis they both absorb and deliver power.

Compressed air has a far shorter track record and costs more to operate, at least at the moment, but it has the distinct advantage of being easier to site, not just the transmission grid but the distribution network. That could help ease problems with network constraints and deliver savings in terms of the grid infrastructure they need around them. Consumers’ own batteries – both fixed and sitting inside electric vehicles – would in a grid managed around storage provide a large distributed reservoir even if it only acts ‘behind the meter’ to support their own management of pricing peaks.

From pumped hydro to batteries, electrical storage has an underlying shortcoming in a renewables-heavy grid: fixed capacity. Large installations distributed around the country could possibly deliver energy on bad days for a few days, and proposals such as the experimental sand battery operating in Finland can last for weeks. But to support big inter-seasonal changes, such as those seen between 2020 and 2021, the UK system will need something else to make up the difference. This is likely to be some form of gas, which under existing government plans is a mixture of methane and hydrogen. The question is where does that gas come from? It might not need to be imported at all but it could continue to play a major role in determining how much energy costs to consumers; decisions taken in the near future may ripple out across the decades.

One answer is to convert wind and solar that cannot be used immediately or stored as potential energy into hydrogen. The round-trip efficiency of hydrogen electrolysis and burning is around 30 per cent compared to 80 per cent for pumped-hydro and as much as 90 per cent for batteries. As hydrogen will be an important feedstock for synthetic fuels and chemicals as well as a methane substitute, it may prove to be commercially viable in a renewables-dominated grid and provide a way to profit from over-generation from renewables.

“If hydrogen starts being diverted as a fuel either for transport or heating rather than as a pure form of storage, then the demand for it will be greater and we will need a larger capacity to store the gas,” says Cárdenas. “So in a way, our numbers are conservative in the sense that what we’re saying we will need is never going to be too much.”

Competition will come from methane produced from waste using anaerobic digestion that is, under current approaches to carbon accounting, a net-zero fuel. By 2050, capacity for biogas could deliver the quantity of methane anticipated by the government for fuel. However, it may make more sense to divert it into chemical production that needs the carbon, with hydrogen taking its place in electricity generation.

What is less easy to predict is how changes in pricing structure will deal with the distortions we are experiencing today in the electricity market and what unexpected distortions the location-based pricing proposed by National Grid ESO will introduce. How that pricing policy is set may prove to be more important than the sticker price for a hundred gigawatts or so of reliable, clean generating capacity. The devil is in the detail. And if there is one thing privatised energy markets have, it’s a lot of detail.

The measure of: Padma Multipurpose Bridge, Bangladesh



Ushering in a new era for connecting the country of Bangladesh, the nation’s Prime Minister Sheikh Hasina inaugurated the Padma Multipurpose Bridge on 25 June. It is a multipurpose rail-road bridge over the Padma river, the downstream part of the Ganges after it enters Bangladesh territory.

The bridge is the longest in the country and aims to reduce the distance between the capital city of Dhaka to the Mongla seaport, which is important for regional and international trade. The Benapole land port and Payra seaport will also benefit from the construction of the bridge.

Padma Multipurpose Bridge, Bangladesh - inline

Image credit: Cover Images

They also deemed it as one of the most innovative yet most challenging developmental projects in the country’s history. “The completion of the Padma Bridge is a dream come true for the 170 million people of Bangladesh,” a spokesperson said, stressing that its government entirely funded the megaproject.

“We have eliminated the final major geographic barrier and, more crucially, the backward south-west region in Bangladesh is now linked with the rest of the country,” the government said. “In fact, it has connected 21 districts of Bangladesh’s south-west region with Dhaka and the rest of the country.”

Vital statistics: Padma Multipurpose Bridge

Main bridge length: 6.15km

Width of bridge on upper deck: 22m

Number of spans: 41

Number of pillars spanned across the bridge: 42

Distance between pillars: 150m

Depth of each pilling: 128m

Overall length of approach road: 15.1km (2.3km on Mawa side, 12.8km on Janjira side)

Number of lanes on upper deck: 4, 2 bridge decks (upper is road, lower is rail)

Load limit: 10,000 tonnes

Viaduct (road): 3.15km

Viaduct (rail): 532m

Number of lamp posts: 415

Deck height: 13.6m

Cost of construction: $3.6bn

122nd longest bridge in the world

The measure of: Padma Multipurpose Bridge, Bangladesh



Ushering in a new era for connecting the country of Bangladesh, the nation’s Prime Minister Sheikh Hasina inaugurated the Padma Multipurpose Bridge on 25 June. It is a multipurpose rail-road bridge over the Padma river, the downstream part of the Ganges after it enters Bangladesh territory.

The bridge is the longest in the country and aims to reduce the distance between the capital city of Dhaka to the Mongla seaport, which is important for regional and international trade. The Benapole land port and Payra seaport will also benefit from the construction of the bridge.

Padma Multipurpose Bridge, Bangladesh - inline

Image credit: Cover Images

They also deemed it as one of the most innovative yet most challenging developmental projects in the country’s history. “The completion of the Padma Bridge is a dream come true for the 170 million people of Bangladesh,” a spokesperson said, stressing that its government entirely funded the megaproject.

“We have eliminated the final major geographic barrier and, more crucially, the backward south-west region in Bangladesh is now linked with the rest of the country,” the government said. “In fact, it has connected 21 districts of Bangladesh’s south-west region with Dhaka and the rest of the country.”

Vital statistics: Padma Multipurpose Bridge

Main bridge length: 6.15km

Width of bridge on upper deck: 22m

Number of spans: 41

Number of pillars spanned across the bridge: 42

Distance between pillars: 150m

Depth of each pilling: 128m

Overall length of approach road: 15.1km (2.3km on Mawa side, 12.8km on Janjira side)

Number of lanes on upper deck: 4, 2 bridge decks (upper is road, lower is rail)

Load limit: 10,000 tonnes

Viaduct (road): 3.15km

Viaduct (rail): 532m

Number of lamp posts: 415

Deck height: 13.6m

Cost of construction: $3.6bn

122nd longest bridge in the world

Port of Felixstowe explores green hydrogen production



The multi-hundred-megawatt facility could deliver up to 40 tonnes of hydrogen per day, which the companies say has the potential to decarbonise industry and transport in eastern England.

The hydrogen – produced from water using electricity from renewable sources – would be used for onshore purposes, such as road, rail, and industrial use, with the potential to create liquid forms, such as green ammonia or e-methanol. This could, in turn, provide clean fuels for shipping and aviation, and create opportunities for cost-effective export to international markets.

The project aims to continue engineering and site development works to align with customer demand from 2025 onwards.

ScottishPower says ‘homemade’ green hydrogen has clear benefits for the security of UK energy supply and is a safe, long-term energy solution that could be vital for those who cannot decarbonise their operations through renewable electricity alone.

As well as accelerating the potential for cleaner industrial processes at the port, green hydrogen is seen as a solution for the heavy transport sector, which is a significant emitter of the UK’s current carbon emissions.

Barry Carruthers, hydrogen director at ScottishPower, said: “This strategically important project could potentially create a clean fuels hub that could unlock nationally significant decarbonisation for the region, as well as playing a role in international markets.

“It’s perfectly located not far from our existing and future offshore wind farms in the East Anglia region, and demonstrates how renewable electricity and green hydrogen can now start to help to decarbonise road, rail, shipping and industry.”

ScottishPower already has two green hydrogen projects in Scotland, in the Cromarty Firth and at Whitelee in Glasgow.

Last year, to coincide with COP26, the Port of Felixstowe announced plans to order 48 electric tractors and 17 zero-emission remote controlled electric rubber-tyred gantry cranes (ReARTGs) as the first batch of new equipment in a move to phase out diesel-powered yard cranes.

The port handles more than 4 million TEUs (twenty-foot equivalent units) and is used by around 2,000 ships each year, including the largest container vessels. Approximately 6,000 heavy goods vehicles pass through the port and surrounding areas every day, creating a substantial opportunity to help decarbonise goods transport in the UK.

View from Brussels: Germany’s good intentions turn sour



The German industrial powerhouse’s unhealthy dependence on Russian fossil fuel imports is by this point extremely well documented. Berlin has lobbied against plans to curb gas shipments and helped write big loopholes into an oil embargo.

Russia’s Nord Stream 2 gas pipeline under the Baltic Sea is now permanently mothballed and its predecessor – Nord Stream 1 – is only operating at a fraction of its capacity due to what Moscow insists are maintenance issues.

Efforts to refill gas storage facilities before the winter heating season arrives are ongoing and may yet pay off, while Chancellor Olaf Scholz is doing his utmost to provide Russia with the spare parts it needs to repair the pipeline.

Nevertheless, the situation is tense and Germany is ultimately fully exposed to the whims of the Kremlin. As this war has proved so far, predictions are difficult to make and the impossible can become possible overnight.

That is why Berlin has launched a series of measures to try and curb energy demand, cut waste and frugally get through this crunch period. But the main problem is that none of them are as-yet binding.

Whereas countries like Spain have issued decrees ordering businesses to turn down their air conditioning, switch off lights at night and even telling employees to stop wearing ties so they are naturally cooler, Germany is as usual dragging its feet.

Renewable energy build-up admittedly continues: in the first half of the year nearly half of power demand was met by clean energy – a record – and the government has supercharged its existing targets.

But a big energy vacuum remains and is forcing Berlin to backtrack on two of its big power tenets: the phaseout of nuclear and coal power.

Olaf Scholz has recently suggested that extending the operating lifetimes of Germany’s existing nuclear reactors could now be the best option, while shuttered coal units are coming back online in place of prohibitively expensive gas plants.

What impact this will have on Germany’s climate policies and emission targets is difficult to fathom at this stage and will all depend on how long the coal plants will have to stay hooked up to the grid.

In any case, it is increasing the Bundesrepublik’s green workload in the second half of the decade quite drastically. Cuts not made now will have to be made at a later date.

Another particularly radical – by German standards – policy has turned sour in recent weeks,  despite its mega-popularity. A €9 passenger ticket, valid across the country for local and regional transport might be discontinued.

Intended to cut car journeys and save oil, as well as bring down carbon emissions, the €9 ticket is likely to be a victim of its own success, as frugal members of the German government are lobbying to scrap it when it comes up for renewal.

Packed station platforms and standing-room-only trains have paradoxically been cited as reasons not to make the ticket a permanent fixture of Germany’s transport offer by some politicians, who wince at the costs attached to the policy.

Finance Minister Christian Lindner is not a fan of the €9 ticket and insists that “it is not fair” because it gets subsidies and not everyone can or will use the transport voucher. That debate will likely last for a while longer.

Lindner’s liberal party is the same one that has resisted all attempts by its green coalition partners to impose a speed limit on Germany’s autobahns, despite the energy and emissions savings such a policy would bring.

Other costs

Faced with increasingly painful energy bills and logistic problems thanks to the drying waterways of Europe amid ongoing droughts and heatwaves, Germany’s industry also has to think about geopolitics.

China’s ongoing tensions with Taiwan threaten to upset the Deutsche applecart further, if Europe is dragged more into the United States’ stand-off with Beijing. Trade disputes could make life even more difficult for Germany’s manufacturers.

According to a new report by the ifo institute for economic research, a trade war would cost Germany tens of billions of euros. Ifo calculates that the price tag would be six times what Brexit has cost the German economy.

Car manufacturers, vehicle parts and machinery would be the big losers if industry is forced to onshore supply chains. Ifo suggests that industries should be looking for a diversified list of suppliers to cut dependencies, advice that was not heeded in energy policy in the past.

The report calculates that a long-wished-for EU-US trade deal could cushion some of the negative aspects of a China-Europe decoupling but not all of them. Attempts to broker a commerce pact have failed before and are unlikely in the short-term.

Germany looks to be damned if it does, damned if it doesn’t these days, thanks largely to suspect policy decisions made over the last decade or so. Policies are slowly changing, for the better, but have little chance of easing the short-term pain being felt.

View from India: India to develop domestic carbon market to fight climate change



The Bill, recently cleared by the Union Cabinet, is expected to facilitate the state electricity regulatory commissions to go ahead with tariff revisions on a timely basis. By way of explanation, amendments to the Energy Conservation Act, 2001 have been tabled at the Lok Sabha recently. Lok Sabha, constitutionally the House of the People, is the lower house of India's bicameral Parliament; with the upper house being the Rajya Sabha, constitutionally the Council of States.

The Energy Conservation Act, 2001 was enacted for efficient use of energy and its conservation and for matters connected therewith or incidental thereto. The Act has enabled the establishment and incorporation of the Bureau of Energy Efficiency (BEE) and has conferred certain powers upon the Central Government, the State Government and BEE to enforce measures for efficient use of energy and its conservation. BEE sets consumption targets for energy-intensive industries.

As the energy market grew, the Act was amended in 2010 for effective energy use, but now renewable energy and the National Green Hydrogen Mission are driving a need for further amendments. Also, Prime Minister Narendra Modi pledged at COP26 to achieve net zero carbon emission by 2070. So, capping emissions is understandable. It’s also intended to develop a domestic carbon market to fight climate change.

As per the amendment, carbon certificates will be introduced for trading. Green fuels across industries are to be mandated and there will be penalty provisions. This will extend to include the automotive sector as well.

Non-fossil sources including green hydrogen, green ammonia, biomass and ethanol for energy and feedstock are being promoted. This is to ensure faster decarbonisation of the Indian economy, and help achieve sustainable development goals in line with the Paris Agreement.

Every sector requires energy. In practical terms, the process of energy transmission and distribution may involve energy wastage. In that sense, there could be ample scope for chalking out conservation and energy efficiency solutions.

The fact that the country aims to transit to a low-carbon economy is an opportunity that could be capitalised. The Governing Council of BEE will increase its members to enable the roll-out of low-carbon initiatives. Carbon markets, effective drivers of reducing emissions, will be established and large residential buildings will be brought within the fold of an Energy Conservation Regime. Increasing energy-efficient buildings and avoiding deforestation could help make the country’s low-carbon journey a reality.  

Let’s try to figure out what that means. It could be that all companies need to be compliant with the carbon legislation. Carbon credits could be seen as a market-based mechanism. Carbon credits by their very nature, may lead to a demand for lowering greenhouse emissions. This could happen by attaching monetary value to the cost of polluting the air. That means to say businesses may treat carbon like a raw material. Industries could also purchase low-carbon solutions. Given its intrinsic value, it would be nice if these solutions are protected through intellectual property (IP) rights. Climate-related issues, which extend to carbon footprint, generally affect agriculture. So then we may need some tech solutions to lower carbon emissions. Energy consumption targets may be set for energy-intensive industries. Maybe deployment of clean technologies could be incentivised. Perhaps we could have carbon funds for small-scale industries.

Globally as per the Kyoto Protocol and the Paris Agreement, nations have chalked out measures to reduce greenhouse gas emissions. India is also part of these global missions. The increasing heatwaves, rising sea levels, droughts and floods, and habitat loss are among India’s concerns.  Let us hope India goes along the low-carbon trail and develops carbon markets. Private equity and investors could provide the necessary encouragement. Procedures could be simplified for getting credits and incentives.

Energy price cap to be updated quarterly to tackle market volatility



The regulator said the change would provide more stability in the energy markets and reduce the risk of further large-scale supplier failures, the likes of which cost energy customers roughly £164 each last year.

Although Britain only imports a small amount of Russian gas, Russia’s actions have created extreme volatility in the global energy market leading to unprecedented highs in the cost of oil and gas and therefore electricity.

The price cap, as set out in law in 2018, reflects what it costs to supply energy to our homes by setting a maximum suppliers can charge per unit of energy, and caps the level of profits an energy supplier can make to 1.9 per cent. As a result of the market conditions, the price cap will have to increase to reflect increased costs, Ofgem said ahead of plans to publish the next price cap level at the end of August.  

It added that a quarterly price cap will help consumers to enjoy the benefits of falls in the wholesale price sooner but that the market remains volatile and the price cap methodology will be kept under review.

Jonathan Brearley, CEO of Ofgem, said: “I know this situation is deeply worrying for many people. As a result of Russia’s actions, the volatility in the energy markets we experienced last winter has lasted much longer, with much higher prices than ever before. And that means the cost of supplying electricity and gas to homes has increased considerably. 

“The trade-offs we need to make on behalf of consumers are extremely difficult and there are simply no easy answers right now. Today’s changes ensure the price cap does its job, making sure customers are only paying the real cost of their energy, but also, that it can adapt to the current volatile market. 

“We will keep working closely with the government, consumer groups and with energy companies on what further support can be provided to help with these higher prices.” 

Ofgem plans to also shorten the notice period between the announcement and implementation of a new cap so that prices reflect gas and electricity costs more quickly and accurately.

Brearley had previously predicted that the price cap would rise in October to “in the region of £2,800”.

Speaking to BBC Radio 4’s 'Today' programme he said: “I would say that it’s very clear that we expect significant increases again in prices, even over and above the estimate that we made in May. And that just shows you how dramatically the market is changing.”

Energy price cap to be updated quarterly to tackle market volatility



The regulator said the change would provide more stability in the energy markets and reduce the risk of further large-scale supplier failures, the likes of which cost energy customers roughly £164 each last year.

Although Britain only imports a small amount of Russian gas, Russia’s actions have created extreme volatility in the global energy market leading to unprecedented highs in the cost of oil and gas and therefore electricity.

The price cap, as set out in law in 2018, reflects what it costs to supply energy to our homes by setting a maximum suppliers can charge per unit of energy, and caps the level of profits an energy supplier can make to 1.9 per cent. As a result of the market conditions, the price cap will have to increase to reflect increased costs, Ofgem said ahead of plans to publish the next price cap level at the end of August.  

It added that a quarterly price cap will help consumers to enjoy the benefits of falls in the wholesale price sooner but that the market remains volatile and the price cap methodology will be kept under review.

Jonathan Brearley, CEO of Ofgem, said: “I know this situation is deeply worrying for many people. As a result of Russia’s actions, the volatility in the energy markets we experienced last winter has lasted much longer, with much higher prices than ever before. And that means the cost of supplying electricity and gas to homes has increased considerably. 

“The trade-offs we need to make on behalf of consumers are extremely difficult and there are simply no easy answers right now. Today’s changes ensure the price cap does its job, making sure customers are only paying the real cost of their energy, but also, that it can adapt to the current volatile market. 

“We will keep working closely with the government, consumer groups and with energy companies on what further support can be provided to help with these higher prices.” 

Ofgem plans to also shorten the notice period between the announcement and implementation of a new cap so that prices reflect gas and electricity costs more quickly and accurately.

Brearley had previously predicted that the price cap would rise in October to “in the region of £2,800”.

Speaking to BBC Radio 4’s 'Today' programme he said: “I would say that it’s very clear that we expect significant increases again in prices, even over and above the estimate that we made in May. And that just shows you how dramatically the market is changing.”

Public sector buildings to access £635m green energy fund



From September, hundreds of public buildings across England will be able to join the £635m Public Sector Decarbonisation Scheme recently presented by the government. 

The funds will be used to install low-carbon heating such as heat pumps and energy efficiency measures including double glazing and loft insulation, which will aim to decrease soaring energy bills and improve the buildings' climate resilience amid more and more frequent extreme weather events, such as the heatwave that hit the UK earlier this summer. 

The energy efficiency upgrades are expected to help public organisations and taxpayers save an average £650m a year on energy bills over the next 15 years, according to the Business Department (BEIS). 

It is the second part of more than £1.4bn due to be allocated through the public sector decarbonisation scheme between 2022 and 2025.  

“By helping even more public sector bodies ditch costly fossil fuels, we are taking an important step towards a more sustainable future while driving economic growth across the country and continuing to support tens of thousands of jobs," said Lord Callanan, business and energy minister. 

The government has already awarded 34 grants to public sector organisations across England through earlier rounds of the scheme. 

Some of the projects that have already been approved as part of the scheme include heating upgrades, draught-proofing and double glazing for Nottingham University Hospitals NHS Trust, as well as the decarbonisation of the Nash Conservatory and Jodrell Laboratory in the Royal Botanic Gardens, in Kew. 

The funding is part of the £6.6bn the government has pledged to cut fossil fuel use and emissions from buildings.

Buildings are currently responsible for 40 per cent of the planet's total greenhouse gas emissions, with 30 per cent of building power usage going to waste, according to Schneider Electric. 

“Decarbonising buildings is a crucial step to tackle climate change," said Kas Mohammed, VP of digital energy at Schneider Electric UKI. "There is a clear desire for this overhaul to happen, and investments like the one announced today can result in considerable savings of both money and carbon."

Mohammed celebrated the emphasis on energy efficiency, stressing that "for too long the focus has been on the switch to renewables", without accounting for the continuous waste of energy caused by current infrastructure. 

“Tracking and measuring our energy consumption with smart technology is an open goal for creating efficient public buildings," he added. "Smart buildings, bristling with IoT sensors, can offer real-time data analytics and insights, allowing public sector facilities decision-makers to spend more wisely, whilst improving occupant experience."

Environmental campaigners have welcomed the government's push towards insulating buildings and installing green energy tech solutions, but some have criticised the failure to provide extra funding for upgrades for millions of households who face poverty this winter.

“As energy prices continue to spiral, it’s great that more public buildings will be insulated and kitted out with heat pumps," said Greenpeace UK’s policy director, Doug Parr. “It’s just a shame that the Government hasn’t had the foresight to offer the same green upgrades to the homes of the millions of people that will be forced into poverty this winter, when they can no longer afford to pay their bills."

Energy consultant Cornwall Insight said a typical annual gas and electricity bill in England, Wales and Scotland could reach £3,615 in the new year, which is hundreds of pounds more than previous predictions and could leave many British households facing the "most expensive winter in history". 

Although customers are expected to see £66 taken off their energy bills in October and November and £67 each month from December to March, as part of a government support scheme, Derek Lickorish, chairman of energy company Utilita, said that households could burn through that money in just a few days, stressing that "the worst is yet to come". 

Nuclear fusion instabilities detected with simulation code



The simulation code is able to calculate and predict changes in TAE instability to increase fast ion confinement and ensure the success of fusion reactions. 

The TAE instability occurs in the course of interactions between fast ions and the perturbed magnetic fields surrounding them. As a result, fast ions disengage from the plasma core, hindering ion trapping. 

In plasma particles, fast ions are much higher in kinetic energy than general ions and increase the temperature and performance of plasma necessary for nuclear fusion. Therefore, stable fast ion trapping is essential in maintaining a nuclear fusion reaction.

The team at the Korea Institute of Fusion Energy (KFE) was able to develop the code by using and improving upon the Gyro Kinetic Plasma Simulation Program (gKPSP) nuclear fusion simulation code, which was previously used for plasma transport analysis. The team added a feature to the code that allowed it to enable electromagnetic analysis, making the code capable of analysing TAE instabilities. 

“The newly developed code will be utilised in analysing the trapping of fast ions generated as a result of nuclear fusion reactions and heating of various types,” the institute explained, adding, “Plasma performance improvement is anticipated through optimal fast ion trapping."

The new code will be used for analysing the confinement performance of fast ions generated by different methods, including various heating devices and fusion reactions. 

Nuclear fusion joins together two atomic nuclei to create a single larger nucleus with slightly less overall mass, releasing extra energy. This is the reaction that keeps the sun and stars shining, controlled by gravity. However, while nuclear fission is easy to start and hard to stop, fusion has been, to date, impossible to sustain on Earth. This is due to multiple challenges, one of which is TAE instabilities. 

In 2020, the government declared its ambition for the UK to be the first country to commercialise fusion technology, with plans for a new prototype fusion energy plant – STEP (Spherical Tokamak for Energy Production) – to contribute to the grid by 2040. To support this goal, the UK government proposed to rule this type of energy through an “innovation-friendly” approach, different from that used for mature civil nuclear technology. 

China is also reportedly hoping to get an experimental nuclear fusion reactor running by 2040.

Currently, KFE is operating KSTAR (Korea Superconducting Tokamak Advanced Research), known as the "Korean artificial sun", which set the record in 2021 for the world’s longest plasma operation at ion temperatures of over one hundred million degrees for thirty seconds.

The KFE team's findings were published in the Physics of Plasmas