That was one of the core sentiments expressed by Mark Copley, CEO of the European Federation of Energy Traders (EFET), in a discussion about how Europe’s new gas price cap will impact markets.

Copley stressed that despite Europe’s well-established regulatory framework, price caps and national interventions ultimately make a regulatory framework more risky and that translates into price premiums and decreased willingness to trade and invest in Europe.

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Price caps don’t address the supply problem

Copley explains that the price cap is a newly introduced market correction mechanism that places a cap on the price at which derivative contracts can be bought.

However, according to Copley, the price cap is not a solution to the supply and demand issue which he believes to be the cause of the current energy crisis.

“We warned against the introduction of price caps…because the energy crisis we have experienced over the past year to 18 months was around not having enough gas… or power and our view is very clearly that you need to tackle that by increasing supply or reducing demand.

“If we’re talking about increasing supply in the short term at least you have to make sure that LNG cargos reach Europe.”

Not only do price caps not address the issue of supply, but it also leads to negative consequences that could make the situation worse, says Copley.

Price caps could have negative consequences

Even though it’s too early to say what changes might result in market behaviour, Copley suggests that capping derivative prices could result in the following negative effects:

• Reducing the incentive for gas to flow to Europe and largely making markets other than Europe more attractive.
• Increasing the uncertainty in Europe’s regulatory framework means people are less likely to want to deliver gas to Europe.
• It reduces incentives to reduce demand.

We would expect to see traded volumes moving away from exchanges and towards over-the-counter markets, argues Copley. “People might also start looking to trade in venues outside of Europe, such as the UK, Singapore, or US.”

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Ultimately, there is a chance of a general increase in uncertainty, leading to traders being more risk-averse and deciding to trade less. This will lead to a fall in market liquidity, increasing market volatility and risk.

How safe are the safeguards?

Although attempts have been made to ensure the price cap is only triggered in exceptional circumstances, says Copley, there are some challenges around figuring out when it will be triggered and under what circumstances.

“It’s good that safeguards have been built in, but what we need to realise is that the cap doesn’t need to be triggered to have an effect on market behaviour. What we worry about is its effects of merely existing”.

“If you’re trying to hedge gas transactions long term, you’re thinking about what to buy and how to manage the risks associated with it. If you don’t know if the policy will be triggered, how the policy will be triggered, or in some cases how it will be implemented…all of that translates into an increase in risk and a greater unwillingness to trade.”

The way forward

According to Copley, despite the search for the magic bullet, there simply isn’t one.

In a crisis of short supply, there are however ways to alleviate the problem. He suggests expanding LNG capacity, resolving bottlenecks in the grid, making as much cross-border power available as possible, working with member states on security of supply arrangements and coordinating filling tenders.

Copley suggests that taking more time on policy-making is critical now. It’s time to carefully consider how to remove these temporary interventions and if this is done in consultation with stakeholders, it would be a measure welcomed by the market and would go a long way to rebuilding lost trust.

For more insights from Mark Copley, listen to the Energy Transitions podcast episode:

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While the conference and exposition officially begin on Tuesday, February 21, enthusiastic attendees from all over the globe flew in early to take in a tour of the Orlando Utilities Commission (OUC) Gardenia Innovation and Operations Center followed by a tour of the 740MW Cane Island Power Park.

Visit POWERGEN International in Orlando, Florida, 21-23 Feb 2023

Grid-edge R&D

OUC’s facility is where the municipal utility tests pre-commercialized or newly commercialized technology and includes a floating solar array, a vehicle-to-grid bi-directional charger, a 50-kW DC fast charger (soon to be upgraded to 120 kW), several Level 2 EV chargers, a 10-kW/40-kWh vanadium redox flow battery and two underground 8-kW/32-kWh flywheels.

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“We want to make sure we understand how they work, their operational characteristics and build new business cases around them before we put them in a position where they could be affecting our customers,” explained Rubin York, one of the three OUC engineers leading the tour.

In addition, OUC is testing a site controller that can operate the system in three main modes: PV smoothing, demand mitigation, which performs autonomous peak shaving, and contingency mode, which collects the assets into a microgrid.

“That is only possible thanks to these flywheels,” said York.

They go through a grid-forming bi-directional inverter which, in contingency mode, assess the frequency and voltage of the buildings and meters and disconnects the EV chargers, the PV inverter (per the IEEE standard), and any other load until the flywheels can output a good 60 hertz, 480-volt AC signal, said York. Once the flywheel generation is firm, OUC can slowly bring the loads back up and charge the EVs.

York also showed off the Cloud Impact Mapping System (CIMS), an in-house developed system that was designed to predict the ramp rate of solar PV as clouds come over and depart the solar PV. Should the technology scale, it could prove to be useful to electric utilities in Florida that are relying on a large amount of solar PV generation because Florida generally experiences a large amount of clouds.

“The goal is to build an array of these all around our territory, build a central repository, and have them effectively ‘hand off’ cloud systems to one another,” said York.

The OUC Gardenia site is also host to a rooftop solar array with bifacial solar panels and a solar parking canopy, which covers the parking lots for the facility.

Exceptional availability

After a quick bus ride and lunch, attendees toured the 740-MW Cane Island Power Park, which was available more than 90% of the time in 2021 and won an award for its exceptional availability.

Unit 3 of the park ran for nine months with no trips said Ken Rutter, COO of the Florida Municipal Power Authority (FMPA), which owns the plant. He added that the unit ran through Hurricane Ian and supplied power to customers who were able to accept it.

The POWERGEN group was split into four smaller groups and taken all throughout the park, viewing each generating unit, one turbine (that was not currently operating), condensers, cooling towers, the control center, and more. Rutter encouraged attendees to ask their tour guides anything at all – and they certainly took him up on that offer.

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04h00 New York | 08h00 GMT | 09h00 London | 10h00 Amsterdam | 10h00 Johannesburg | 12h00 Dubai | 13h30 New Delhi | 16h00 Singapore

60-minute session

The energy landscape is changing rapidly with a clear focus on reduced emissions, decarbonized energy, and increased efficiency. Sustainability is an important prerequisite for remaining qualified for existing business relationships and developing new customers and markets.

To anticipate these trends, Rolls-Royce with its product brand mtu has approved most of its generator sets for use with paraffinic diesel fuels EN15940, including HVO (Hydrotreated Vegetable Oil).

To support the customer’s journey towards sustainability, Rolls-Royce established the foundation for a strategic partnership with Neste, a worldwide leading HVO upstream player.

Working with Neste, we will promote the contribution of internal combustion engine technology towards sustainability—a transition from fossil fuel to renewable fuel, thus underlining and demonstrating the openness of this technology. Our common goal is to transfer existing technology to a greener century.

Join this live webinar that aims to bring transparency to alternative fuel solutions, focusing on HVO and how its use can be applied to our mtu power generation applications.

What you will learn:

• Insights into mtu Rolls-Royce net zero roadmap focused on Power Generation
• Background on European emission legislation
• Categorize and explain the range of paraffinic fuels as alternatives to fossil fuels
• HVO as today’s available solution
• HVO testing results
• Characteristics positively impacting genset performance

Our partner Neste enriches this webinar by adding information about NESTE MY Renewable Diesel, global availability, and pricing mechanisms.

Speakers

Michael Stipa, Vice President Business Development, Strategy and Product Management Stationary | Rolls-Royce Power Systems AG

Mats Hultmann, Head of OEM Partnerships | Neste

Moderator

Pamela Largue, Senior Content Producer | Power Engineering International

The post Webcast 30 March | HVO fuel for mtu power generation appeared first on Power Engineering International.

As part of modernisation of Kazakhstan’s power infrastructure, Turkish power producer Aksa Energy will build a new 240MW combined heat and power (CHP) plant to provide flexible and sustainable heat and power for the Kyzylorda region.

The plant, expected to be commissioned in 2025, will be powered by two GE 6F.03 gas turbines, which will boost fuel efficiency and reduce carbon emissions.

Korkut Ozturkmen, Aksa Energy board member and vice chairman of the executive committee, said in a statement: “We chose GE’s technology based on the evaluation of multiple parameters such as CAPEX, OPEX, performance, delivery cycle, reliability, service as well as flexibility to meet grid operator requirements.”

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The country’s ageing power infrastructure has been operating for an average of 40 years, and it is heavily reliant on coal-fired power generation.

According to the International Energy Agency, the country produces 70% of its electricity from its abundant resources of coal but aims for other sources to supply half its power by 2050.

The country is looking to reach net-zero carbon emissions by 2060.

Brice Raisin, commercial leader, GE Gas Power in EMEA, Europe, said in a statement: “Transitioning baseload generation fuel from carbon-intensive coal to a more efficient natural gas will help ensure grid stability as well as a better future for the people in Kazakhstan.”

New electricity capacity is expected to take the form primarily of solar and wind – but also gas and hydro. The government is considering constructing its first commercial nuclear power plant, building on its role as one of the world’s largest sources of uranium.

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Measures to phase out fossil gas and support the development of a EU hydrogen backbone have been approved by the EU’s Industry, Research and Energy Committee (ITRE).

The legislative proposals backed, a regulation and a directive, are aimed to facilitate the uptake of renewable and low carbon gases, including biomethane and hydrogen, into the EU gas market.

The legislation would also create a certification system for low carbon gases and ensure that consumers can switch suppliers more easily to choose these gases over fossil fuels in their contracts.

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In its amendments to the directive, the Committee found that the hydrogen corridors identified in the REPowerEU plan should be supported by adequate infrastructure and investments.

The aim is to ensure that enough cross-border capacity is available to establish an integrated European ‘hydrogen backbone’ enabling the product to move freely across borders.

Regarding the phase out of fossil gas, the Committee wants it phase out by EU countries as soon as possible, taking into account the availability of alternatives.

Member states may decide on an earlier end-date for the duration of long-term contracts for unabated gas before the end of the year 2049.

In the interim on the replacement of Russian gas supply the Committee agreed that by the end of 2030 member states should ensure collectively at least 35 billion m3 of sustainable biomethane.

This would be produced and injected into the natural gas system annually, with the aim of replacing 20% of Russian natural gas imports.

Reform to the European Network of Transmission System Operators for Gas (ENTSOG) to also cover hydrogen network operators also was proposed.

Jens Geier, rapporteur on the directive, said the vote is the next step towards a climate-neutral Europe.

“We call for gas, hydrogen and electricity infrastructure to be planned jointly to better coordinate energy systems in the future.”

Jerzy Buzek, rapporteur on the regulation, said the age of hydrogen is coming.

“To make it happen in the EU, we need a stable and well-balanced regulatory framework, financial support as well as investments in new infrastructure. With this legislation, we are preparing it.”

Hydrogen Europe has welcomed the ITRE Committee’s conclusions, saying it is a big step towards the establishment of hydrogen as a traded commodity and as a crucial energy carrier in the campaign for net zero.

“It is now up to the Council to develop its general approach in line with the ambition of MEPs and industry and to shore up all remaining issues in this important legislative package.”

Nevertheless, some outstanding issues remain, the organisation says.

Policymakers should be cautious when imposing excessive conditions on hydrogen pipelines without considering the different usages of hydrogen transported and their specificities.

Hydrogen Europe also calls on policymakers to ensure appropriate exemptions for existing hydrogen networks; ensure independence on the governance of hydrogen infrastructure planning and network codes and provide flexibility for member states in applying third party access for storage and terminals.

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EIA said that substantial US coal-fired capacity has retired over the past decade, and a record 14.9GW was retired in 2015.

Annual coal retirements averaged 11GW a year from 2015 to 2020, fell to 5.6GW in 2021, and then rose to 11.5GW in 2022.

In 2023, power plant owners and operators plan to retire 8.9GW of coal-fired capacity, around 4.5% of the total coal-fired capacity at the start of the year.

Most coal-fired power plants currently operating were built in the 1970s and 1980s. As these plants compete with a growing number of natural gas-fired plants and low-cost renewables, more coal-fired units are being retired.

EIA said the largest coal-fired power plant expected to retire this year is the 1,490MW W.H. Sammis Power Plant in Ohio. The oldest four of the plant’s seven coal-fired units were retired in 2020; the last three units are slated to shut down this year, along with the plant’s five petroleum-fired units (13MW of combined capacity).

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Pleasants Power Station (1,278MW) is the second-largest coal-fired power plant retirement expected this year. Energy Harbor, which plans to become a carbon-free electricity supplier by the end of this year, owns both W.H. Sammis and Pleasants.

In addition, some 6.2GW of natural gas-fired capacity is slated to retire, roughly 1.3% of the operating natural gas fleet as of January. Most of that retiring capacity is made up of older steam and combustion turbine units.

Three aging natural gas-fired plants in California (Alamitos, Huntington Beach, and Redondo Beach), with a combined 2.2GW of capacity, are scheduled to retire. These plants were originally slated to retire in 2020 but were granted a three-year extension to maintain grid reliability.

Petroleum-fired power plants make up a small portion of generating capacity at around 2.2%. Most of these plants are seldom run and serve as peaker plants. This year, around 0.4GW of petroleum-fired capacity is scheduled to retire.

Originally published on power-eng.com

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The GE TM2500 aeroderivative gas turbine was shipped to Ukraine from Arizona, US, on a Ukrainian Antonov cargo plane.

The 28MW mobile power plant can provide enough power for 100,000 homes and will be used to supply hospitals, schools, and critical infrastructure providers.

The mobile nature of the power plant means it can be operated in different cities or regions depending on where the need is greatest. It can also be attached to a damaged power plant or hooked directly to the electrical grid within a few weeks.

According to GE, once in place, the plant can power up and shut down in just five minutes, providing emergency responsiveness when needed. And where fuel is limited, the TM2500 can run on natural gas or diesel, as well as sustainable aviation fuel blends.

Russia’s invasion of Ukraine has resulted in damage to critical heating, power, and gas infrastructure, with utility workers routinely risking their lives to repair the damage after air strikes.

Aman Joshi, general manager of GE’s aeroderivatives business at GE Gas Power, which is part of GE Vernova, said in a statement: “The situation is pretty severe. The Ukrainians know they need a lot of power, but it’s like a moving chessboard because every week something new is happening and something new is getting damaged.”

“It might be very difficult, because it’s a war zone,” adds Joshi, reiterating that GE will be involved and will coordinate with contractors and local crews to get the TM2500 up and running as soon as possible.

Since the start of the war, USAID has procured equipment for Ukraine from American companies and engaged the private sector in partnerships to meet Ukraine’s urgent wartime needs.

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USAID has already delivered more than 1,700 generators to 22 oblasts across Ukraine, with many more on the way. These generators ensure electricity and heating for schools, hospitals, accommodation centres for internally-displaced persons, district heating companies, and water systems if and when power is knocked out.

USAID has also invested $55 million in Ukraine’s heating infrastructure, supporting repairs and maintenance of pipes and other equipment necessary to deliver heating to homes, hospitals, schools, and businesses across Ukraine.

The post USAID delivers GE mobile gas power plant to Ukraine appeared first on Power Engineering International.

It truly is a sight to behold: an offshore wind farm with over 100 giant turbines covering an area of 300km2. With a capacity of 714MW, the East Anglia One wind farm off England’s Suffolk coasts produces enough renewable energy to power the equivalent of more than 630,000 homes.

To watch the power-generating field amidst the relentless waves of the southern North Sea is extremely impressive. Yet there’s a hidden feature that also makes the wind farm notable. On each wind turbine, the field uses the greenest insulation possible for its high-voltage switchgear: clean air instead of SF₆ (sulphur hexafluoride), which used to be the standard.

The answer is indeed blowin’ in the wind, and the times they are a-changin’.

This article is part of the ‘Future Energy Perspectives’ series, in which experts from Siemens Energy share their insights into how we can move towards a decarbonised energy system.

SF₆, a man-made and odourless gas, belongs to the family of F-gases (fluorinated gasses). As the most harmful and long-lasting greenhouse gas emitted by human activity, it’s 25,200 times more potent than CO₂ and has an atmospheric lifetime of up to 3,200 years.

According to the US Environmental Protection Agency, around 80% are used worldwide in the switchgear industry. Therefore, it’s clear that tackling this segment is paramount.That’s why East Anglia One should lead the way for effective efforts towards protecting the environment.

It doesn’t just generate renewable energy, but it also sets new standards in decarbonizing the power transmission part of the project.The wind farm has been in operation for almost three years, being one of the first using switchgear with a global warming potential (GWP) of zero.

Regulating F-gases

Today, the continued use of SF₆ and other fluorinated gases in high-voltage insulation are pressing concerns when it comes to clean power transmission, especially, as the demand for insulated switchgear has risen sharply.

This is due to decentralised renewable energy production, the global rise in electricity consumption and increased urbanisation which also increases the demand for small substations, and hence, for compact environmentally friendly switchgear.

Regulators have taken note and are increasingly pushing away from fluorinated gases. For instance, the high GWP of SF₆ led the EU to prohibit SF₆ in 2014 for most applications, except for the power sector due to a lack of alternatives at the time.

In April 2022, the European Commission proposed a revision of this key legislation calling for more restrictions on using F-gases in grid technologies.

It would reduce F-gases by 90% by 2050, and ban using F-gases in switchgear with a GWP of more than 10 by 2026 to 2031 (high-voltage), depending on the voltage of the switchgear.

It also allows for flexibility in niche situations where F-gas-free alternatives might not be available.

In California, regulation is already in place to remove F-gases from gas-insulated switchgear. And unsurprisingly, at the recent COP27 in Egypt, F-gases were central topics of panel discussions aimed at exploring F-gas-free alternatives globally.

In the 1960s, SF₆ replaced oil in switchgear

What made SF₆ such a popular gas for switchgear in the first place?

For obvious reasons, it’s a highly effective arc-quenching and insulating medium with long-term stability, and with precautions, relatively safe to handle. Until the 1960s, oil was used as an arc-quenching media for high-voltage circuit breakers in substations around the world.

However, it had a variety of disadvantages, such as fire risk and maintenance intensity. When SF₆ was first implemented, it was seen as an excellent alternative for improving the performance and safety of high-voltage applications.

Currently, SF₆ is still the standard gas used in switchgear worldwide today. Thousands of tons of SF₆ are installed in switchgear globally every year, with an expected lifespan of 40-60 years.

For sure, manufacturers aren’t taking risks posed by SF₆ lightly. Current state-of-the-art technology allows for keeping the leakage rate of SF₆ below 0.1% per year.

At the same time, system engineers are all sensitized to and trained in the careful handling of switchgear components containing SF₆.

Natural-origin or fluorinated gases?

Yet, given the net-zero target that’s been embraced worldwide to minimize climate change, SF₆ will need to be completely phased out for switchgear equipment.

The main contenders for replacing SF₆ are based on gases of natural origin, such as CO₂, O₂, and N₂, and gas mixtures, including other man-made fluorinated gases having a fraction of the climate impact of SF₆.

Though fluorinated gas mixtures have less global warming potential than SF₆, the GWP is still some hundreds above 1. In addition, these gas mixtures lose their effectiveness at very low temperatures.

There is also a risk that switchgear components wear out more quickly, which in turn, reduces switching performance and results in higher maintenance costs.

In addition, gas handling is much more complex than with natural-origin gases, and service and storage requirements are correspondingly higher. In this case, the tightness of the switchgear is above SF₆ and results in higher maintenance costs. As these F-gases belong to the ‘forever chemical’ PFAS (per- and polyfluoro-alkyl) group, they can involve further risks.

As PFAS chemicals are connected to environmental pollution and health risks, there’s a global trend towards PFAS phase-out and regulatory restrictions for these substances, where alternative solutions are available.

To actively ensure sustainability, one of the biggest market players, 3M, announced at the end of 2022, that it would exit (PFAS) manufacturing and work towards discontinuing its use of PFAS across its product portfolio by the end of 2025.

Shifting from SF₆ in switchgear to natural-origin gases

The other alternative to SF₆ are F-gas-free products that use natural-origin gases as an insulation medium. This gas technology poses zero harm to the environment, climate and human health. But how realistic is it to move away from SF₆ -insulated switchgear to natural-origin gases as insulation?

Today, more and more switchgear manufacturers, transmission and distribution operators as well as regulators favour F-gas-free-options with GWP of zero, or < 1, with no contamination risk of the atmosphere, water, or soil.

That also means there’s no need for careful handling, recycling, and reporting as required by law when using SF₆ and other F-gases in some parts of the world.

Finally, looking at the proposed different transition timelines for phasing out SF₆, it’s clear that today’s F-gas-free technology can meet that challenge.

Download your copy of ‘Replacing F-gases in switchgear: a revolution in the making’

Switching gears for net zero

It’s already happening: and not just offshore. In 2018, Siemens Energy supplied a substation of Norwegian network operator BKK Nett in Bergen with a clean air switchgear from its ‘Blue Portfolio’.

Clean air consists of purely 80% nitrogen and 20% oxygen and has a GWP of zero. Worldwide, the company currently has more than 1,000 switchgear units with clean air in operation.

From 2030 onwards, Siemens Energy aims to sell only F-gas-free products globally. Also, other manufacturers are very active: companies from Europe, Japan, South Korea and China are able to offer natural-origin gases-based switchgears, e.g. offering also circuit breakers based on CO₂/O₂ gas mixture with a GWP < 1.

And some of these companies have formed an alliance called “Switching gears for net zero” calling for zero F-gases in switchgear.

Natural origin gases with GWP < 1 means no new emissions, easy and safe handling, no health risks to workers or environmental harm. The CO₂ footprint of natural origin gas equipment is significantly lower than that of SF₆ and offers the only solution to have zero direct emissions and is able to achieve zero carbon footprint when coupled with a fully decarbonized supply chain.

Using natural origin gas solutions reduces life cycle costs of the equipment significantly. The equipment can be used at very low temperatures of up to -50°C without any countermeasures.

More Future Energy Perspectives
How disruptive service solutions will re-energize power plants
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Benign non-toxic gases for higher high voltage ranges

Though the path ahead may seem clear, during this transitional phase switchgear manufacturers, as well as transmission operators, still have their work cut out for them.

That’s particularly the case with wind farms. While there are first projects equipped with F-gas-free switchgear in wind turbines, the switchgear combining the power infeed with voltages above 145 kV still uses SF₆-insulated switchgear (albeit only kilograms, not tonnes as in many substations).

Why? Alternative products with clean air or other harmless gas mixtures are not available yet for this kV-range.

But it’s no secret that they’re in the works. At Siemens Energy, for instance, validations for switchgear with 400kV are in progress, while switchgear with no circuit breaker function like instrument transformers and gas-insulated busducts are already available for up to 420kV.

Other manufacturers are also pushing forward. So, F-gas-free alternatives should also be available for these higher voltage-ranges soon.

ABOUT THE AUTHOR

Dr Mark Kuschel is Head of International Standardization at Siemens Energy, steering standardization and regulation topics for the company’s Grid Technologies business. For more than 20 years he has held various positions in the Transmission and Distribution business, where he was also one of the initiators of sustainable, F-gas-free products.

The post Replacing F-gases in switchgear: a revolution in the making appeared first on Power Engineering International.

Funding of £6 million ($7.3m) has been awarded to 20 research projects to accelerate the decarbonisation of industry in the UK.

The 20 projects are spread across 14 UK research institutions and are all intended to support the UK’s green growth and net zero ambitions by 2050.

The money has come from the Industrial Decarbonisation Research and Innovation Centre (IDRIC), which is part of the UKRI Industrial Decarbonisation Challenge.

IDRIC launched a call for industrial decarbonisation research projects, offering stakeholders the opportunity to respond to emerging innovation and research needs and complementing its existing programme of projects.

Read now: Decarbonising industries with renewable power and thermal storage

The 20 projects cover technologies including carbon capture and hydrogen, plus issues such as skills development and equality, diversity and inclusion.

The successful bids demonstrated how they would employ active dialogue and collaboration with key industrial stakeholders to ensure that outcomes and impact remain closely tied to industry needs. A full list of successful bids is listed below.

Listen now: Podcast – Lessons from a Danish hydrogen pilot project

Bryony Livesey, director of the Industrial Decarbonisation Challenge at UKRI, said the projects “will build evidence on a range of areas from economics and emissions to skilled jobs and wider net zero policy, supporting UK’s green growth and net zero ambitions”. 

IDRIC director Professor Mercedes Maroto-Valer said: “We were delighted by the quality and volume of applications received. IDRIC’s programme has demonstrated that we have the tools to transform industry and make it an engine of green growth.”

To 20 successful bids are listed here.

Video: Tangible opportunities to decarbonize industry. Watch here.

The post <strong>UK projects get £6m to decarbonise industry</strong> appeared first on Power Engineering International.

The energy company has acquired the four-acre former Knapton Generating Station from Third Energy and plans to develop a 28MW battery on the site.

In addition, Centrica is exploring how Knapton could be used for off-grid hydrogen production, as well as the possibility for solar energy in the surrounding area.

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The first project at the site near Malton will be a 56MWh battery which will utilise some of the 41.5MW export capability of the existing grid connection. It’s anticipated the battery would be able to power around 14,000 homes for two hours.

The multi-million pound deal is part of Centrica Business Solutions’ strategic plan to create a 900MW portfolio of solar and battery assets by 2026. 

“Taking an old fossil fuel asset and revitalising it to help advance the decarbonisation of the grid not only feels the right thing to do from a sustainability point of view, but aligns with our strategy,” said Greg McKenna, managing director of Centrica Business Solutions. “We’re quickly acquiring a portfolio of assets that can play an important role in facilitating a net zero future for the UK.”

Gas production ended at the Knapton site in 2019 and the gas turbine and all gas processing equipment have been cleared, together with its housing shed and associated equipment being dismantled and removed.

Third Energy will retain the ownership of the 12 well-sites and associated gas pipeline network.

The post Former gas power plant gets new life as green energy hub appeared first on Power Engineering International.