UK Government launches new taskforce to tackle greenwashing in finance sector

9 June 2021, source edie newsroom

The UK Government is set to launch a new advisory group tasked with creating a 'green taxonomy' for finance, in a bid to crack down on greenwashing in the investment space.

Pictured: Chancellor Rishi Sunak at the recent G7 Finance Ministers' Meeting. Image: HM Treasury, CC BY-NC-ND 2.0

Pictured: Chancellor Rishi Sunak at the recent G7 Finance Ministers' Meeting. Image: HM Treasury, CC BY-NC-ND 2.0

Called the Green Technical Advisory Group (GTAG), the taskforce will comprise of members from NGOs, trade bodies and academia, alongside organisations that will use the finalised taxonomy and organisations with expertise in creating such frameworks. It is set up to be independent from the Treasury and other Government departments.

Organisations represented within the GTAG's membership include the Green Finance Institute, WWF, the Institutional Investors Group on Climate Change (IIGCC), the Confederation of British Industries (CBI) and the Aldersgate Group. Under the category of taxonomy and data experts sit representatives from the likes of the UN Principles for Responsible Investment (PRI), the Climate Bonds Initiative and the Government’s own Environment Agency and Committee on Climate Change.

The Green Finance Institute’s executive director Ingrid Holmes has been appointed as chair of the GTAG. Holmes also heads up policy and advocacy at investment manager Federated Hermes International. Prior to taking up these roles, she was a director at think-tank E3G, contributing to the establishment of the now-closed UK Green Investment Bank.

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Nitrous Oxide (laughing gas) - the forgotten greenhouse gas.

Emissions of the greenhouse gas commonly known as laughing gas are soaring. Can we cut emissions from its greatest anthropogenic source?
In the world's effort to cut greenhouse gas emissions, the source of our food is coming into the spotlight. There's good reason for that: Agriculture accounts for 16 to 27% of human-caused climate-warming emissions. But much of these emissions are not from carbon dioxide, that familiar climate change villain. They're from another gas altogether: nitrous oxide (N2O).

Also known as laughing gas, N2O does not get nearly the attention it deserves, says David Kanter, a nutrient pollution researcher at New York University and vice-chair of the International Nitrogen Initiative, an organisation focused on nitrogen pollution research and policy making. "It's a forgotten greenhouse gas," he says.

Yet molecule for molecule, N2O is about 300 times as potent as carbon dioxide at heating the atmosphere. And like CO2, it is long-lived, spending an average of 114 years in the sky before disintegrating. It also depletes the ozone layer. In all, the climate impact of laughing gas is no joke. Scientists at the Intergovernmental Panel on Climate Change (IPCC) have estimated that nitrous oxide comprises roughly 6% of greenhouse gas emissions, and about three-quarters of those N2O emissions come from agriculture.

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Why are energy-from-waste schemes so troublesome?

by Roddy Wilkie at Construction Manager Magazine  14.03.2019

Development of CCS in Fortum Oslo Varme

The EU’s 27 members will need to find a way to deal with 142 million tonnes of residual waste by 2035. That’s assuming they hit their own targets under the bloc’s Circular Economy Action Plan. 

For now, the UK is still signed up to that target as part of the Brexit deal struck last December. 

At the moment, there is enough waste-to-energy capacity in the EU to deal with 100 million tonnes of residual waste, material that can’t be recycled or reused. So the EU will need to increase incineration capacity to cope with an additional 40mt by the 2035 deadline. That means EU countries will need to build more waste-to-energy plants over the next ten years. 

At the same time, the UK is aiming to reduce its carbon emissions by 68% by 2030 (the EU’s goal is a reduction of 55%) and net zero emissions by 2050. 

Fortum Oslo Varme offers a way to achieve these two ambitious goals. We are ready to fit our waste-to-energy plant on the outskirts of Oslo with technology that would capture 90% of the CO2 emissions from the plant. Once the project is running, about 400,000 tonnes of liquefied CO2 will be taken by zero emission trucks to the harbour. From there the CO2 will be taken over by the Northern Lights project and transported by ship to a terminal on the west coast of Norway. There it will be pumped into rock formations 3,000 meters below the seabed in the North Sea for safe storage.   

Our Oslo waste-to-energy plant has been operating for over thirty years and annually deals with 400,000 tonnes of residual waste from Oslo, the surrounding area and the UK. The energy generated by the plant is used to produce electricity and district heating for around 200,000 people in the city. 

Equipping the plant with CCS capacity will cut Oslo’s CO2 emissions by 14% by itself. The project is essential for the city’s plans to cut emissions by 95% by 2030.  

The Norwegian state has already pledged funding for the transport and storage of the carbon and has agreed to pay around half of the project’s start-up and running costs for 10 years. Fortum Oslo Varme has applied to the EU’s Innovation Fund for energy and decarbonisation solutions for the remaining funding. 

At Fortum Oslo Varme, we believe that this project is essential if the EU and its partners are going to achieve net zero emissions by 2050. The CCS technology can be rolled out to around 500 similar waste-to-energy plants across the EU that will also need to cut their emissions over the next ten years. It can also be used for the extra 100 plants of the size of Fortum Oslo Varme that the EU will need to deal with the 40 million tonnes of residual waste it faces as more and more landfill sites are closed. 

It is important to be aware that incineration does not compete with reuse and recycling. Even if Norway and the EU achieve the ambitious targets for reuse and recycling there will still be waste that we cannot dispose of any other way. Much of this is from biological sources so if we use CCS technology we are actually removing CO2 from the atmosphere. 

We have to deal with the climate challenges with the tools we have at hand today –  and that includes incineration of residual waste and CCS. We can’t wait for miracle solutions that may never be invented or considered good enough. 

At Fortum Oslo Varme we strongly believe this project could be a blueprint for cities on how to best deal with non-recyclable waste, while producing heat and electricity for city inhabitants and meeting ambitious greenhouse-gas emission reduction targets in the coming decades. 

Fortum Oslo Varme (FOV) AS is owned 50/50 by the City of Oslo and Fortum Participation Ltd. Oslo and the surrounding region, one of the most prosperous regions in Europe, have a population of more than 1.2 million.

Oslo is aiming to be a fossil-fuel-free city by 2050.

Launching the carbon capture and storage project at the waste-to-energy plant is an important steppingstone towards meeting this goal.

Fortum, founded in 1998, is the world's fourth largest heat supplier and has a number of combined heat and power (CHP) plants as well as biomass plants for energy recovery and district heating.

Circular use of resources, recycling, district heating and overall sustainable waste management are key features of Fortum's business.

With the vision “for a cleaner world” Fortum aims to be at the forefront of developing both the industry, technology and new green jobs.

With approximately 19,000 professionals and a combined balance sheet of approximately €69 billion, we have the scale, competence and resources to grow and to drive the energy transition forward. Fortum's share is listed on Nasdaq Helsinki.

By Jannicke Gerner Bjerkås, Director Carbon Capture and Storage, Fortum Oslo Varme AS

McKinsey: Power consumption to double by 2050 as COVID-19 helps pull back fossil fuel peak

Image: Getty.

Image: Getty.

Power consumption is set to more than double by 2050 as electrification increases, according to new research from McKinsey.

The consultancy found that the share of electricity in energy consumption will grow to 30% by 2050, up from 19% today. Renewables will be dominating this from 2030, with cost reductions over the next decade resulting in the technology becoming cheaper than existing fossil fuel plants.

This is to trigger a sharp uptake in the installed capacity of solar and onshore and offshore wind, with 5TW of new solar and wind capacity installed by 2035 and over 50% of global power power generation coming from renewables the same year.

The consultancy is also predicting that the aggregate fossil fuel demand peak will be brought forward to 2027 partially as a result of COVID-19’s impact on energy demand.

It found that while global coal demand has already peaked, oil and gas are now not far behind, falling in 2029 and 2037 respectively.

In McKinsey's report The Global Energy Perspective 2021, it discusses how the pandemic has resulted in a significant reduction in energy demand, which it will likely take between one and four years to recover from. Additionally, the company expects that electricity and gas demand will bounce back quicker than demand for oil, and that demand for fossil fuels overall will never return to its pre-pandemic growth curve.

However, McKinsey did state that over the long-term, the impacts of behavioural shifts due to COVID-19 are minor compared to more known long-term shifts such as decreasing car ownership, growing fuel efficiencies and a trend towards electric vehicles, whose impact is estimated to be three-to-nine times higher than the pandemic’s by 2050.

Despite the earlier peak of hydrocarbon demand resulting in a substantial reduction in forecast carbon emissions, the report continues to state that the world remains significantly off of the 1.5ºC pathway.

This is detailed in particular in the Reference Case scenario, one of four modelled by McKinsey, which saw more than half of all global energy demand continuing to be met by fossil fuels by 2050. This scenario is McKinsey’s outlook on the continuation of existing trends, examining its expectations of how current technologies can evolve, and is compared against a 1.5 ºC pathway, a delayed transition where the societal focus is on economic recovery post-COVID-19 and an accelerated transition.

Christer Tryggestad, senior partner at McKinsey, said that there is still “a long way to go” to avert substantial global climate change, with annual emissions needing to be around 50% lower in 2030 and 85% lower by 2050 than current trends predict.

Tryggestad added that many governments need to translate "ambitious targets into specific actions", with the focus of stimulus packages for COVID-19 to "play a key role in shaping energy systems in the decades to com

Has Brexit created higher electricity prices? A look at the impact of decoupling from EUphemia

National Grid ESO has issued two Electricity Margin Notices (EMN) – one for Wednesday evening and one for Friday evening – as the cold weather and lower generation cut into its safety buffer, putting the security of supply at risk.

The tight margins led to dramatic peaks in intraday trading and Balancing Mechanism (BM) prices. Power prices in the N2EX auction hit £1,000.04/MWh for the period 17:00 to 18:00 on Wednesday 6 January, the highest hourly price seen on the auction. During the same period EDF’s CCGT plant West Burton B was called on at £3,000/MWh in the Balancing Mechanism.

Following on from the EMN issued for Friday, West Burton B2 and B3 had offers accepted at £4,000/MWh in the BM, while Uniper’s Connahs Quay 3 CCGT plant was accepted at £2,750/MWh.

An additional factor that drove up the N2EX auction price was the decoupling of the markets as Alastair Martin, founder and chief strategy officer at Flexitricity, explained: “The two main day-ahead auctions (operated by Nordpool and EPEX-Spot) are no longer linked, which means they can clear at different prices. Most of the time, they come out very close to one another, but yesterday the divergence was large. This is probably a market inefficiency, and it remains to be seen how it will be resolved.”

Decoupling and confusion: Leaving EUphemia

While much of the price volatility seen this week was driven by the changing nature of the nation’s electricity, with more intermittent renewables taking over from baseload coal stretching periods of high demand, there is now also the additional impact of Brexit and this decoupling of Great Britain’s auctions from EUphemia (EU + Pan-European Hybrid Electricity Market Integration Algorithm).

“All of the EU’s electricity markets are linked at the day ahead in a big algorithm called Euphemia,” explained EnAppSys’s director Phil Hewitt, describing it as "one of the crown jewels of the internal electricity market".

“At noon Central European Time – so that’s 11am GB, Irish and Portuguese time, and 1pm over in eastern Europe – what happens is that all of the auctions in each country are linked to their neighbours. This results in the automatic flow of power from less expensive regions to more expensive regions. So if, for example, it was tight in GB, then the power would flow across from France, Belgium and the Netherlands automatically. So, now, because we've left the European Union and the transition period has ended, we're no longer in that market arrangement; we have decoupled. Not only that but the two auctions in GB have decoupled from each other, causing more price confusion.”


Now GB has decoupled, it is running two auctions- Nord Pool and EPEX, as well as participating in the European auction. This creates more liquidity, and with it the potential for higher and lower prices.

Whilst leaving EUphemia doesn’t in itself increase energy prices, it does complicate trading which is likely to lead to higher prices for the GB market.

“Before you had a single auction, so if you were an interconnector capacity holder there was little risk to scheduling those flows,” expanded Adam Lewis, partner at market insight company Hartree Solutions. “There was a low risk methodology of optimising those flows to ensure that they flowed in the best way. Whereas now because of Brexit, we've decoupled and the UK has now decided to go on to have two auctions in the morning, which creates more confusion, volatility, uncertainty and risk. We believe the market would benefit from a single coupled UK auction.”

Does Brexit mean we’ll see more price volatility?

It seems likely that there will be more power price volatility going forward, especially if the UK sees continued cold weather as well as low wind generation. This is more a mark of the changing makeup of the nation’s energy mix than the impact of Brexit however, with that more a secondary aspect.

“The current system was designed to create peaky prices, reflective of the stress on the system at the time,” pointed out Martin. “The idea was that electricity suppliers and wind farm operators would put more effort into forecasting, and thermal generators would put more effort into reliability if the consequences of getting it wrong at the wrong moment were more unpleasant.

“Since then, renewable generation has continued to grow, and the electricity system looks quite different. So, we may see a revision to the pricing mechanism at the extremes. Whether that calms down prices, or re-directs the peakiness to different types of event remains to be seen.”

Additionally, it is worth noting that price spikes are not entirely negative as they can help keep power stations that might ordinarily struggle to compete in auctions running and encourage increased expansion.

“The high prices encourage people to enter the market, so they're not necessarily a bad thing,” argued Hewitt. “A power station that’s marginal is going to make reasonable money in periods of high prices, which might mean it will decide to stick around for another year or maybe somebody who’s developing battery projects or developing gas peakers or maybe even CCGTs is going to look at these high prices and say, ‘well, there we go, I can make money in this market'. So they're going to be more encouraged to build."

Balancing Mechanism price jumps to highest level since 2001, hitting £4,000/MWh

Image: Getty.

Image: Getty.

The imbalance price reached a high of £4,000/MWh on Friday evening, capping off a dramatic week in the energy market.

For the price periods 39-40 – between 19:30 and 20:30 on 8 January – the imbalance price soared to a high equivalent to 400p a unit, the like of which hasn’t been seen since 2001.

It followed a dramatic jump during price period 35 as well on Friday, hitting £2,750/MWh. At the time, this was the highest seen for nearly two decades but this was beaten just two and a half hours later.

The first week of 2021 was particularly volatile for the energy markets, as tight margins and low temperatures pushed National Grid ESO, leading it to issue two Electricity Margin Notices (EMN). Both were followed by periods of high prices in the Balancing Mechanism, with prices jumping to £3,000MWh on Wednesday 6 January as EDF’s West Burton B was called on, allowing NGESO to cancel the first EMN.

The second ENM was issued for Friday evening, and although it was subsequently cancelled, it led to EDF’s West Burton B2 and B3 successfully having their bids accepted at £4,000/MWh on Friday.

For the previous high period on Friday, Uniper’s Connahs Quay 3 CCGT plant was accepted at £2,750/MWh.

The last time prices were as high as they have been in Great Britain’s Balancing Mechanism was in 2001, when the New Electricity Trading Arrangements (NETA) were first introduced. The NETA Go-Live on 27 March that year created a new wholesale market, with a number of minor problems with the simplicity of the algorithm used for the Balancing Mechanism leading to two records being set that year that have yet to be broken.

On 5 May 2001, during period 32 the price soared to £4,993.88/MWh, before this record was broken on 19 June 2001 during period 32 with a price of £5,003.33/MWh, according to EnAppSys.

These high prices can be seen as a positive according to Phil Hewitt, director of EnAppSys, as “they encourage the building of new assets and the development of innovations such as demand response that allow the electricity system to decarbonise".

“In the future prices will become more extreme at certain points – either super-high prices like this week or super-low prices when renewables are running at maximum output and this will encourage solutions via the market to smooth generation and demand.”

Price volatility is likely to become increasingly common, as Great Britain relies increasingly on intermittent generation such as offshore wind. Additional factors that have driven high prices so far in 2021 also include the BritNed interconnector with the Netherlands remaining down, as well as the decoupling of the UK’s electricity markets with EUphemia – a consequence of Brexit that has added a level of complexity to energy trading.

As well as driving up prices in the Balancing Mechanism these also led to record N2EX auctions prices last Wednesday, when it hit £1,000.04/MWh for the period 17:00 to 18:00 on 6 January, the highest hourly price seen on the auction.

“Looking at the demand/supply stack for UK power moving forward, we see limited baseload generation coming online so this tightness is likely to be more acute in future years,” expanded VEST Energy’s Aaron Lally.

In order to manage it, more flexible assets such as battery storage will need to be integrated into the mainstream power system, he continued. “The highest prices we have seen in the BM for decades on Friday could have been avoided if GWs of flexible assets were confident that making themselves available in the Balancing Mechanism would have led them being dispatched by the TSO.

“This is really a competition issue; large plants exercising market power because the current market framework does not allow smaller (more dynamic) assets to participate. This needs to change.”

The heat pump rollout could fail due to high electricity costs warns EAC

Daikin's Altherma heat pump. Image: Dailkin.

Daikin's Altherma heat pump. Image: Dailkin.

The cost of electricity could cause the rollout of heat pumps to fail, as the technology must be made affordable for consumers.

With the cost of electricity roughly four times more expensive than gas, due to the government placing the costs of its low carbon policy with customers, adoption of the green heating alternative may struggle, according to a letter to energy minister Kwasi Kwarteng.

Written by the Chairman of the Environmental Audit Committee (EAC), Rt Hon Philip Dunne MP, the letter reflects on the evidence heard by the Committee during its short inquiry on Technological Innovations and Climate Change: Heat pumps.

The Committee was advised that reviewing the policy costs for gas and electricity could significantly improve the customer case for heat pumps, helping to make them cheaper than conventional gas boilers in a domestic setting.

Beyond cost concerns, the Committee heard through written evidence and a one-off evidence session that the supply chain is not currently equipped to installed the numbers of heat pumps required. To make sure the rollout happens, sufficient production and high-quality installations will be key.

While the initial growth of heat pump installers are expected to come from reskilling existing gas and electrical engineers, a concerted attempt to bring new, skilled entrants into the market over time. The government should fund a dedicated training programme, supporting education and training as part of a long-term strategy, suggested the EAC.

The uptake of heat pumps will be supported by the Green Homes Grant initially, but further confidence will need to be provided to industry to allow it to invest in skills and resources given the short window of time the scheme is expected to run for. The government should extend the grant beyond March 2022, making it a multi-year scheme.

Dunne said: “We are in an exciting and innovative time with new technologies coming to market that can make our net zero ambition a reality. But the scale of the challenge is huge, and requires government to set clear direction to instill industry confidence.

“Heat pumps could be transformative in decarbonising heating in our homes, and with homes emitting 20% of the UK’s greenhouse gases, it is a problem we need to meet head-on. Only when the supply chain is equipped to deliver the roll-out of 600,000 heat pumps a year, and costs are brought down for consumers, will we see heat pumps being a staple for many UK homes.”

The letter follows the government’s target of 600,000 heat pump installations a year by 2028, announced as part of the Ten Point Plan in October. The target was particularly welcomed following analysis from the UK Energy Research Centre that suggested it would take the UK 700 years to transition to low-carbon heating.

Charles Wood, Energy UK’s head of new energy services and heat, agreed that the EAC was right to highlight the significant barriers for the nascent heat pump sector, adding that “the low carbon heat market is most in need of clear signals from government in order to justify investment, and the 600,000 installation target is a positive move in that direction".

“Government now needs to follow this broad vision with a strategy for delivery in the 2020s. Bringing down the associated costs for low carbon heat technologies while delivering local growth, for example through developing local supply chains and increasing the number of skilled installers, is critical to giving customers the ability to choose how and when to decarbonise.

"This has to be joined with regulation, taxation and incentives in order to deliver rapid market growth towards net zero."

SSEN calls on customers to ‘signpost’ interest in flexibility services

Image: SSEN.

Image: SSEN.

Scottish and Southern Electricity Networks (SSEN) has called on generators to “signpost” their interest in providing 250MWs of flexibility to the energy system.

This will prequalify customers to participate in alleviating network constraints through formal tenders in the future, with the DNO looking to secure its flexibility options over the next eight years.

Owners of low-carbon technologies, generators and solutions that are capable of absorbing demand are being called on to announce their availability, with SSEN set to take a technology agnostic approach when the procurement process begins next year. Those who win tenders going forwards will be able to earn money, support network security and the transition to net zero.

Stewart Reid, head of future networks, said SSEN was taking a "flexibility first" approach to network infrastructure investment, assessing smart flexibility service markets when new electricity infrastructure is needed.

“By registering their interest generators and owners of low-carbon technologies and solutions will help provide sight of where flexibility exists and support informed decision making that supports a cost-effective transition to a smarter electricity system. This is an exciting opportunity for owners of generation assets to play a proactive role in that journey.”

SSEN pointed to the Climate Change Committee’s recent forecast that electricity demand will potentially treble as the UK transitions to net zero, and the following requirement for a significant increase in electricity infrastructure and investment in the UK’s networks. Using flexibility and smart management can delay or sometimes avoid network reinforcement, easing the process and limiting the cost.

DNOs have repeated broke flexibility tender records throughout 2020, with Electricity North West announcing its largest flexibility tender ever in November, seeking up to 122MW, while Western Power Distribution awarded 222MW of flexibility in its sixth round of procurement in October.

SSEN has taken a number of steps to increase flexibility on its network, including launching its Constraint Management Zone flexibility scheme, which welcomed its first wind generator contract in October. The following month, it awarded Opus One Solutions a contract to develop and deploy solutions to test different flexibility market models.

Customers have until 31 January 2021 to signpost their interest in providing flexibility services to SSEN, and can register here.

Saying goodbye to 2020

from  Veronica Truman Head of Content & Communications at Cornwall Insight

While lockdown may have been the most used word overall in 2020, in the energy sector net zero would certainly give it a run for its money. The raft of policy announcements, particularly in the last few weeks, will lead to a dramatic change in sector especially with moves to decarbonise heat and transport. This has been set amid a backdown of further consolidation in the supply market and escalation of ambition to achieve net zero.

Our popular weekly articles are an opportunity for our experts to discuss topical industry news. Based on the number of downloads, these are the top five most popular 'Chart of the weeks' from 2020.

Five: E.ON UK and npower: When 2 become 1

Recent acquisitions were changing the face of the non-domestic supply market according to our Business Market Share Survey for Q220 (with a reporting date of 30 April 2020). In this 'Chart of the week' we looked at what the market will be like once the E.ON UK and npower merger was complete.

Under the proposals announced in May 2020, E.ON Group would merge npower’s I&C arm, npower Business Solutions, with E.ON UK’s I&C unit. Under the proposal the two portfolios would be integrated by the end of 2021 with the merger leading to significant changes in the rankings for the larger suppliers, most notably in the electricity market.



Four: The pipeline for CfD AR4: Who, where, when?

With the potential reinstatement of ‘Pot 1’ technologies in the next Contracts for Difference (CfD) Allocation Round 4 (AR4) in 2021, this ‘Chart of the week’ took a look at the pipeline of renewables projects most likely to enter the auction.

Drawing upon research in our new service ‘The Renewables Pipeline Tracker’, we showed a heat map of site locations by capacity for potential AR4 bidders.


Three: Energy demand falls amid coronavirus outbreak

In this ‘Chart of the week’, we looked at the timeline of the COVID-19 outbreak and the impact of milestone events on the daily gas and power consumption in the UK.

When the government imposed restrictions on movement in the UK on 24 March, demand for power fell around 11% from March 2019 levels. Comparatively, demand for gas was less affected due to the dominance of the domestic heating market on gas demand.


Two: Cha-Cha Slide: COVID-19 & falling levels of inertia

The level of inertia on the system is a key contributor to electricity system stability. In this ‘Chart of the week’, we took a look at how changes in demand brought about by COVID-19 were impacting this.

Inertia is an attribute of the system related to the energy stored in the rotating motors of synchronous generators (e.g. coal, gas, nuclear). It prevents system frequency from falling too quickly after a frequency disturbance (e.g. a generator trip) as inertia stored in these rotating motors provides resistance to system changes. It is effectively free frequency response the ESO can count on in the case of a sudden fall in frequency and is measured in Gigavolt Ampere Seconds (GVA.s). Typically, levels of inertia on the system will fall as the levels of synchronous generation on the system decline and asynchronous generation (wind, solar and interconnectors) increases.


One: What’s in it for me? Household grid balancing

This ‘Chart of the week’ looked at the potential benefits and flexibility models available to customers. The dearth in energy demand and high renewable generation brought the need for flexible consumption sharply into focus. On the weekend of 22 May, Octopus Energy paid thousands of smart meter customers to use energy. Industry then seriously looked at how households would be supported in their participation in demand side services, traditionally the domain of large commercial customers.