Amid heightened concern last winter about the security of the electricity supply across the island of Great Britain, National Grid Electricity System Operator (ESO) brought in a first-of-its-kind demand-management system.
The Demand Flexibility Service (DFS) relied on consumers reacting to notifications from the operator to help reduce their demand and keep the island’s grid secure during times of particular strain. (The island’s grid incorporates England, Scotland and Wales, but not Northern Ireland.)
Over the course of the winter of 2022/23, the system-level impact of DFS was significant, reducing demand by 2.92 gigawatt hours (GWh) from times of grid strain, according to a recent report from the Centre for Net Zero.
This is equivalent to the electricity needed for every person in Great Britain to make a large cup of tea, it claims.
This helped ensure, it adds, that the ”lights stayed on” and reduced the need for reliance on coal-fired power stations or exceptionally expensive alternatives. Additionally, 681 tonnes of carbon dioxide (tCO2) emissions were avoided through the use of DFS.
ESO has reintroduced the service for 2023/24, with the first session taking place on 16 November.
The Q&A below examines what the service has achieved – and whether it offers value for money.
- What is the ‘demand flexibility service’ and why was it created?
- Who took part in last year’s trial of the service and why?
- What did the demand flexibility service achieve?
- Did the demand flexibility service offer value for money?
- What will the service look like in winter 2023-24?
What is the ‘demand flexibility service’?
In 2022, ESO launched its new DFS to provide an additional mechanism to support energy security over the winter.
There was heightened concern about the potential of blackouts over the winter of 2022/23, due to the volatility in the gas market, exacerbated substantially by the Russian invasion of Ukraine earlier that year.
As such, in its Winter Outlook report, the operator added new tools in the form of securing contingency contracts with coal-fired power plants and launching DFS.
From 1 November 2022, DFS started to incentivise users to reduce consumption during key times, to reduce the overall demand across the system.
Households with a smart meter or business sites with half-hourly metering were eligible to sign up to the scheme and could sign up through either their supplier or a technology provider. In total, there were 31 providers that registered by the end of the DFS period in March 2023.
This was made up of 14 “domestic only”, 10 “non-domestic only” and seven “both domestic and non-domestic”.
DFS was designed so that the ESO could notify providers about the times when capacity on the grid was expected to be tight, allowing them to reach out to their customers who had signed up to the scheme. They could then opt-in to the DFS sessions and work to reduce their demand during the specified periods.
Over the winter of 2022/23, there were 20 test events – which were used to “onboard” providers – and two live uses of DFS, where it was used to ensure there was sufficient capacity to meet demand. These sessions had a duration of 60, 90 and 120 minutes.
Across the test events, ESO established a guaranteed “acceptance price” of £3,000 per megawatt hour (/MWh) for all bids submitted by DFS providers. This was designed to offer assurance to providers.
During the live events, DFS providers presented bids at higher prices than the guaranteed acceptance price, allowing them to incentivise participants further and, therefore, provide more substantial demand reductions during times when balancing the grid was particularly challenging.
The two live events – which took place on 23 and 24 January 2023 – saw providers submit bids within the range of £3,300/MWh and £6,500/MWh, according to data from LCP Delta.
Who took part in last year’s trial of the service?
Between November and March, 1.6m households and businesses participated in DFS, according to the ESO.
Collectively, they provided ~350MW of flexibility during events, helping to avoid blackouts during periods of particular constraint on the grid.
According to a survey conducted by the system operator, a wide range of households took part in DFS. Of those surveyed, 30% had a health condition or long-term illness, 18% were tenants and 30% lived in households with three or more people. This highlighted the low barriers to participation of DFS, according to ESO.
There were still groups that were underrepresented, including younger age groups, lower income households, renters and city residents.
According to ESO’s survey, those under the age of 45 were underrepresented in DFS participation in comparison with the British population. (Britain’s electricity system covers England, Wales and Scotland, therefore, the population of Northern Ireland was not eligible to take part in DFS.) The most pronounced underrepresentation was seen in those aged 18-19 and 20-24 years old. The most overrepresented age groups were 55-64 and 65-74.
Within the under-45 age group, women made up the majority of participants, whereas in the over-45 group men made up the majority. Overall, 54.9% of those surveyed identified as female, in comparison with 51.7% of the British population, the survey continues.
The white ethnic group was overrepresented, with 95.7% of respondents falling within the category, notes the ESO, compared to 82.7% of the British population (a 13% difference).
All other groups were underrepresented, with Asian or Aisan British the most severely so, with only 2.4% of respondents compared to 8.7% of the British population (6.3% difference).
The majority of participants took part for the financial benefits, be they savings or rewards. Of those surveyed by ESO, 76% selected this as their main motivation.
Beyond this, 41% of households were motivated by the challenge of responding and 37% by balancing the grid.
The actions taken by participants to reduce demand varied, with the majority (three-in-four) shifting demand, according to the Centre for Net Zero’s research. For example, shifting the times they used high-load appliances, such as heating or ovens, by an hour, to avoid the DFS session.
Around one-in-two participants reported “demand destruction” in at least one event, according to the research. This is where the demand is completely removed – for example, households who chose to go for a walk instead of putting on the television and did not subsequently watch an extra hour of television later to make up for it.
The Centre for Net Zero’s research found that 17% of participants manually switched off appliances, while the rest scheduled them to either come on before or after the event.
What did the demand flexibility service achieve?
Overall, DFS was considered a success, delivering a total of 3,300MWh of electricity reduction across the 22 events, according to ESO. This is nearly enough to power 10m homes for an hour during peak times across the island of Great Britain.
Through demand reduction, DFS is considered to have avoided a total of 681tCO2.
Great Britain was spared blackouts over the winter of 2023/24 – while services such as DFS played a role in helping to keep the grid balanced and secure during this time. Favourably warm weather, among other factors, also played a role.
Additionally, DFS provided financial benefits to participants. For example, CUB, a family-run commercial energy and utilities consultants business, introduced the CUB Reduction Reward Scheme, allowing its customers to participate in DFS.
In a case study released by ESO, it highlighted that throughout six events, there was an average of 86 businesses taking part in each through the CUB Reduction Reward Scheme. Participants ranged from using 14,000 kilowatt hours (kwh) to 14,000,000kwh per annum.
As of 30 January, participants had earned £34,025, with one business earning £1,726 in one event. Over these events, CUB delivered 12MWh of energy reduction, and avoided 945kg of carbon emissions.
With regard to the domestic market, 13 sessions were offered to 1.4m Octopus Energy customers over the course of last winter, via financial incentives. Overall, the company’s “Saving Sessions” resulted in a reduction in energy demand of 12-25%.
The trial also managed to answer several questions around the potential of demand schemes and the challenges they may face.
For example, the impact of cold weather on the willingness of participants to reduce their demand was an area in need of data, with heating being one of the easier and more common energy uses to turn down during DFS sessions.
Those who opted into Octopus’s Saving Sessions on cold winter days provided a “mean average turndown” of 0.2kW, a similar level to mild or warm days. If this was scaled to the UK’s 30m households at the same rate of participation (one-in-three), the company estimates that would equate to around 2GW of consumer flexibility on cold winter days.
This is roughly equivalent to the entire capacity of Britain’s contingency coal power plants.
Did the demand flexibility service offer value for money?
Overall, ESO paid households and businesses nearly £11m to reduce their power use during the DFS period of 2022/23.
As such, the average cost per megawatt hour of reduced electricity was around £3,330/MWh across the 22 sessions. While this is relatively high, it is also reflective of the scarcity of the use of the service. This is not a cost paid out consistently, but only in the tightest of periods where the alternative options were expensive fossil-fuel generators.
During the same winter, some gas-fired power plants cost up to £6,000/MWh, for example.
Across the two live events, ESO paid more than £3m to suppliers, split between around £850,000 during the shorter event on Monday 23 January and £2.1m for the longer session on Tuesday 24 January.
These arguably provide a clearer picture of what this service could cost in the future, given they allow suppliers to bid what they are happy to pay as opposed to the guaranteed price offered during the test sessions.
For example, during the first live session on Monday 23 January, 400,000 customers participated and were given £3.37/kWh of electricity demand they reduced. Customers were offered £4/kWh on Tuesday 24 January, as ESO accepted a higher bid.
By contrast, ESO’s other additional measure for the winter of 2022/23 was to contract five coal units to stay online under contingency contracts. This was estimated to cost between £340m and £395m, subject to the procurement and use of the coal.
While the coal units were “warmed” six times, according to the Centre for Net Zero’s research, they were not ultimately used. ESO paid approximately £6,000/h to the plants that were warmed, in order to synchronise them with the grid frequency.
ESO has not contracted them for the coming winter.
DFS cost approximately £10.5m in total meaning 2.7% of the capacity payments were spent on the contingency coal contracts.
The Centre for Net Zero’s research, completed a welfare analysis to explore what the marginal social benefits of the policy were with regards to the net cost to the government.
In doing so, it found Octopus’ Saving Sessions demonstrated a marginal value of public funds (MVPF) – which is calculated by dividing the beneficiaries’ willingness to pay by the net costs of the policy – of between 1.05 and 2.6.
This metric shows that the welfare impacts of DFS are sensitive to the extent to which demand response reduces the likelihood of “lost load”, namely, the security of the electricity supply. If it is considered to have reduced the likelihood of a blackout, the MVPF is high, with 2.6 larger than many other popular policy programs, such as housing vouchers, job training, cash transfers, and adult-health subsidies, according to the Centre for Net Zero.
The report notes that during DFS events – when the grid was particularly strained – a marginal unit of electricity would have been sourced from a carbon-intensive gas or coal-fired power plant. These would incur a “marginal private cost” of £835/MWh on average for the ESO, with a maximum of £5,500/MWh, plus the social cost of continued fossil fuel reliance.
It is a difficult balance for the operator to ensure the service offers value for money, while paying consumers enough to make participation attractive.
Lucy Yu, the Centre for Net Zero’s CEO, tells Carbon Brief:
“The DFS is one of the biggest innovations the grid has seen in years. Our analysis shows consumers can offer gigawatt-scale flexibility, at good value for public money. This value exceeds policy spending in areas such as adult education, healthcare and housing.”
According to figures from Octopus in January, the average saving for a household was 23p for each test event. Some participants saved up to £4.35 for each session.
During the first live test, the largest savings seen by domestic users were about £8.75 for the hour.
The supplier estimates that a customer that reduced its demand by 1kWh during 25 events at an average of £4/kWh – as seen in the second live event – could save £100 over a winter.
What will the service look like in winter 2023-24?
DFS has been reintroduced for winter 2023/24. It began on 1 November, with the first test event taking place on 16 November. The first live event has now been announced for 29 November.
As with last year, ESO will run 12 incentivised test events that consumers and businesses can participate in. A guaranteed acceptance price of £3/kWh will be on offer to suppliers, aggregators and businesses for at least six of the test events.
According to the surveys conducted by the Centre for Net Zero, 92% of customers were “very interested” in continuing to participate in future sessions year-round.
DFS remains in a trial stage, with lessons yet to be learnt before it could be truly integrated into the ESO’s system stability services. As such, there are a number of changes made to this year’s service, including the lead time given by the ESO, changes to metering requirements and the ability for providers to make the service “opt-out” rather than “opt-in”.
While the DFS is currently only used to reduce demand, there is also the potential that such a system could be used in the future to manage periods of high generation on the system.
For example, during a period of low demand, such as in the middle of the night, when there is high wind generation. Currently, wind generation has to be “curtailed” to protect the system if there is more generation than demand. DFS could be used to increase demand to take advantage of such periods.
Of those surveyed by the Centre for Net Zero, 81% said they were interested in using more energy to avoid curtailment.
Yu tells Carbon Brief:
“As the energy system evolves to optimise demand closer to real-time, it is important to understand the role schemes such as the DFS might play – including as an important contingency resource targeted at times and locations where it is needed most.
“In the near term, it is a critical tool that allows us to raise consumer awareness of demand response, scale flexibility behaviours and deliver meaningful value to both the grid and households, transforming the relationship between the two.”
The post Q&A: How Great Britain’s ‘demand flexibility service’ is cutting costs and CO2 emissions appeared first on Carbon Brief.
Q&A: How Great Britain’s ‘demand flexibility service’ is cutting costs and CO2 emissions
Claver Gatete is Executive Secretary of the UN Economic Commission for Africa. Jason Veysey is Energy Modeling Program Director and Senior Scientist at the Stockholm Environment Institute. Lisa Sachs is Director of the Columbia Center on Sustainable Investment at Columbia University.
The case for global energy transition has rarely been clearer. The closure of the Strait of Hormuz earlier this year exposed the cost of unplanned, fossil-dependent systems, while the falling cost of renewables, the rising penetration of electric vehicles, and the growing value of demand flexibility have made the direction of travel obvious. The benefits of a clean, secure, integrated system are no longer in dispute. What remains unclear is how to build it.
Countries around the world have called for faster renewable energy deployment and alternative energy arrangements. A secure, affordable, resilient, decarbonised system requires specific investments in specific places in a specific sequence, optimised across sectors and borders. But very few governments have the analytical foundation to translate those imperatives into investment.
The two instruments that are supposed to determine investment priorities for decarbonisation – Nationally Determined Contributions (NDCs) and country platforms – cannot answer the most basic question facing any country undertaking an energy transition: what should the energy system look like?
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To close this gap, every country needs a bankable, economy-wide optimisation model for its energy system. A model is not a plan, but it can help answer the critical question of what the future energy system should look like. It shows how optimal scenarios vary as assumptions and policies are adjusted, calculates investment requirements and sequencing, and quantifies how system costs are affected by assumptions, policies, and exogenous variables like trade policy and financing terms.
Tool for efficient investment
Optimisation is a simplified way of simulating an energy system, but it can be an extremely powerful tool for moving energy planning from reactive (how do we manage the disparate actions in the energy system?) to intentional (what energy system underpins our national objectives?). A model can show how optimal scenarios vary as assumptions and policies are adjusted, and how investment requirements are quantified and sequenced.
Optimisation models can treat the energy system and the sectors it serves as an integrated whole, optimising across sectors and projects in ways that can be mutually reinforcing. If considered independently, growth in industrial demand, transport electrification, and digital infrastructure can add stress to the energy system. But an optimised plan can arrange these and other changes in an efficient, synergistic way.
Two to tango: How governments can unlock private investment for national climate goals
New load can be added where low-cost power is available; industrial customers can ensure the viability of investments in energy supply; electric vehicle charging policy can smooth load curves and reduce costs for all consumers.
Additionally, optimisation modeling can also change the financeability of investments. Taken alone, each project faces uncertainty about the rest of the system, which raises the cost of capital and causes projects to stall or unwind after contracts are signed. A coherent, optimised plan makes visible the coordination that private capital would otherwise have to bet on: identified offtake, sequenced and committed transmission, contracted power supply, and so on.
What COP31 and COP32 should do
The upcoming COPs in Turkey and Ethiopia can shift the center of gravity of international climate cooperation from fragmented commitments to planning. Three moves are urgently needed.
First, optimised, economy-wide, long-term energy system planning must be the foundation on which any meaningful NDC, country platform, or finance commitment rests. NDCs are typically drafted by environment or single-line ministries, with limited cross-sectoral input from ministries of energy, finance, and planning. They contain targets, derived from sectoral strategies or national commitments, not from an analytically grounded picture of what the energy system should look like and what investments would make it work. Country platforms are generally a portfolio of investments assembled from existing project pipelines, rather than derived from a system-level analysis of what an optimised, decarbonised energy system would require.
Second, recognise regions as a key planning unit. Modern integrated energy systems are inherently regional. Renewable endowments are unevenly distributed; balancing variable supply across borders lowers aggregate cost, reduces redundant backup capacity, and unlocks economies of scale no individual nation can achieve. Many energy investments in Southeast Asia, East Africa, Southern Africa and Central Asia may only be financeable in a regional context. Assessing domestic infrastructure without regional optimisation perpetuates the perception that decarbonisation is more expensive than it is.
COP31 leaders unveil global targets, with spotlight on electrification
Third, finance the planning capacity. A coordinated commitment by multilateral development banks, bilateral donors, and philanthropic partners to help every region and its constituent countries develop and maintain their own modelling capability, with open-source tools and regional analytical hubs, would close the most consequential gap in the current architecture. The cost is small relative to current spending on country platforms, failed project preparation, and misallocated infrastructure investment.
This includes supporting regional institutions such as the ASEAN Centre for Energy, the African Energy Commission, regional power pools, and the Latin American and Caribbean Energy Organization to determine what optimised regional systems require. Country-by-country pledging, repeated at every COP, will not deliver what meaningfully integrated systems can.
The 2026 energy crisis made the cost of unplanned, fossil-dependent systems newly visible. That window of clarity will close. The international community should seize the moment to build the planning foundation that has been missing for thirty years, rather than commissioning another round of NDCs or pledges, striving for outcomes neither was designed to deliver.
The post Every country needs a model to help optimise its energy transition appeared first on Climate Home News.
Every country needs a model to help optimise its energy transition
The world is currently experiencing what is expected to become the strongest El Niño on record – dubbed a “super El Niño” by many.
El Niño is the warm phase of a recurring climate pattern in the tropical Pacific that releases heat from the ocean into the atmosphere.
This temporarily raises global temperatures and reshapes rainfall and extreme weather around the world – impacting the lives of billions of people.
The current El Niño event began in June and is expected to last into 2027.
El Niño is part of a wider climate pattern called the El Niño-Southern Oscillation (ENSO) cycle.
The ENSO cycle also has a cool phase, known as La Niña, as well as a “neutral” phase. El Niño and La Niña events typically last between nine and 12 months, but can go on longer.
Below, Carbon Brief explains how the ENSO cycle works, its impacts on extreme weather and global temperatures and why this El Niño event is projected to be the most intense since records began.
The post Explainer: How the ‘super El Niño’ will reshape the world’s weather appeared first on Carbon Brief.
https://interactive.carbonbrief.org/el-nino-explainer/index.html
The second-largest reservoir in the US reached a record-low water height on Saturday – just days after the country’s largest reservoir broke its own record.
Both Lake Mead and Lake Powell are located on the Colorado River.
They provide water for populations across seven US states in the south-western US, with around 40 million people getting some or all of their municipal water from the Colorado River.
The river also provides water for around 5.5m acres (22,258 square kilometres) of farmland across Colorado, Arizona, California and the other states in the river basin.
Experts tell Carbon Brief that climate change, population growth and over-consumption are all contributing to the current record-low levels of the reservoirs.
Record lows
At full capacity, Lakes Mead and Powell can hold a combined 68 cubic kilometres of water – enough to supply all household consumption in the contiguous US for nearly 1.5 years. However, the water level in both reservoirs has been declining for decades.
The chart below shows the water level of Lake Mead, in metres above mean sea level. The reservoir, which began to fill in 1935 following the construction of the Hoover Dam, has a “full pool” maximum capacity of 347.60 metres. The water level in Lake Mead reached a record low of 317.11 metres on 7 August.
The following chart shows the water level of Lake Powell, in metres above mean sea level. Lake Powell’s full-pool level is 1,127.76 metres.
While the reservoir reached its maximum capacity several times in the 1980s, it has not done so since. On 15 August, the water level in Lake Powell was recorded at a new record-low of 1,072.87 metres.
Both reservoirs have continued to decline in the days since breaking their respective records. The downward trend will largely continue in both lakes until next spring, when the snowpack in the mountains of the Upper Colorado River Basin begins to melt, says Dr Jack Schmidt, a senior research scientist at Utah State University’s Center for Colorado River Studies. He tells Carbon Brief:
“The big dilemma of the moment is that we’re only in the middle of August, and we have no assurance of what the coming winter will be. The only thing we can be sure of is that we will be depleting overall total basin reservoir storage from now until, roughly, early April.”
Compounding factors
The record lows across the two reservoirs are the result of several compounding factors, experts tell Carbon Brief.
Since the turn of the 20th century, the amount of water flowing along the Upper Colorado River has declined by about 20%. Research suggests that half of this decline can be attributed to human-induced climate change.
Most of the river’s streamflow comes from the snowpack of the Upper Colorado River Basin, which stretches across five western US states but is primarily located in Colorado and Utah.
This region has been gripped by a historic “megadrought” for more than a quarter of a century. Nearly half of the megadrought’s intensity over 2000-18 is attributable to climate change, according to a 2020 study.
At the same time, the increasing population in the US south-west has put added pressure on the Colorado River’s water supply. The number of people obtaining some or all of their water from the Colorado system has grown by 15 million (around 60%) since 1992.
Schmidt tells Carbon Brief:
“There’s an ultimate cause of the present water crisis, and there’s a proximate cause. The ultimate cause is a warming climate, a warming planet and a pretty clear correlation between warming conditions and decreased runoff in the Colorado River Basin.
“The proximate cause is that in this messy democratic republic of ours, big policy decisions that match the variability of the climate occur painfully slowly – with intense political negotiations – and only incrementally.”
On 31 July, the US Bureau of Reclamation, which manages water resources in the western US, released an environmental impact statement on its proposed post-2026 strategy for managing Lakes Powell and Mead. The strategy itself has not been released yet.
Schmidt notes that the statement does appear to give the Bureau flexibility to “respond to crisis” by reducing the delivery of water to several states. However, he adds:
“They acknowledge it won’t work if we just stay critically dry, and of course every climate model for the 21st century, especially with a continually warming planet, says that that’s exactly what’s going to happen.”
The post Analysis: The two largest reservoirs in the US have hit record-low levels appeared first on Carbon Brief.
Analysis: The two largest reservoirs in the US have hit record-low levels
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