Carbon in UK Power – Part 1: Lower Costs or Least Carbon?


Carbon in UK Power – Part 1: Lower Costs or Least Carbon?

December 8, 2020

“The easy work is behind us; the hard work is yet to come”

The UK has made great strides in decarbonising its power generation with emissions at the end of 2020 forecast1 to fall 55% compared with five years ago. That’s almost four times better than the 14% reduction forecast1 in non-power8 emissions over the same period. However, the real challenge lies ahead if the country is to achieve its ambition of being net-zero by 2050. The carbon emissions from the power industry are set to decline just 7% over the next three years1.

In 2019, total UK greenhouse gas emissions were 45% per cent lower than in 1990. Achieving the newly announced target, a 68% cut by 2030, will require the UK to work 50% harder than it currently is.

The bulk of the reductions in the energy sector have come from the successful transition away from coal generation in favour of gas, thanks to a combination of the carbon price floor2 and the EU ETS3.  Simultaneously, government subsidy schemes have supported renewable generation resulting in large increases in both wind and solar capacity both in the UK and Europe.

Hartree analysis of generation by fuel type driven by the UK’s carbon policies

With coal soon to be entirely removed from the UK’s generation network, attention switches to how the remaining emissions will be removed and how a net-zero carbon energy supply system will look. The outlook is further clouded by the huge growth in electricity demand that is anticipated over the next few decades as the UK accelerates its transition to a fully electric vehicle fleet with Prime Minister Boris Johnson recently announcing the ban on new sales of petrol and diesel-powered cars from 20307.

National Grid’s Future Energy Scenarios 20204 peak demand forecast

As the National Grid recently said in its Future Energy Scenarios 20204 report: “Reaching net-zero carbon emissions by 2050 is achievable, however, it requires immediate action across all key technologies and policy areas, and full engagement across society and end consumers,” adding that significant investment will be required in low carbon generation.

Globally there needs to be swift and coordinated action too with the COP26 Energy Transition Council stating9 earlier this week that the global transition to clean electricity generation needs to at least quadruple by 2030.

Using our proprietary model at Hartree Solutions, when we look forward over the next five years the pace of emission reductions dramatically slows. This is despite our view that subsidy-free renewables will see significant growth. The easy switches have been done and any further reductions will face a headwind of sharply rising demand.

Hartree emissions forecast for the UK Power sector taking our in-house modelled dispatch profile for each power station and its applicable emissions generated hourly

At Hartree Solutions, we believe it is essential to consider the lifetime emissions of each solution. All electricity generation has some form of carbon footprint and so far, this has typically been measured by the direct emissions. It doesn’t for example factor in the huge costs, in both financial and emission terms, of decommissioning a nuclear plant.

As the industry awaits the government’s long-delayed energy white paper for further details on how the UK reaches net-zero, it’s worth noting the World Nuclear Association’s “lifetime emissions analysis”5.  Nuclear generation has a much larger upfront negative carbon impact than wind and solar due to the vast amounts of energy and materials used in its construction. Also, when the carbon intensity of decommissioning plants is taken into consideration, it shows that the lifetime emissions from stations such as Hinkley C and the proposed Sizewell C are worse than wind, as well as the cost of this nuclear generation being 2.3 times greater than its renewable alternative6.

The World Nuclear Association’s “lifetime emissions analysis”5

“Our actions today affect our carbon emissions tomorrow”

The reality of a net-zero electricity grid is still some decades away (see Market Insight) and while we must be drawing up long-term plans to meet this goal, we should not lose sight of the impact of carbon emissions in today’s power generation and the importance of our transitional steps towards this decarbonisation goal over the upcoming decades. Our actions today affect our carbon emissions tomorrow.

Currently, the UK power network is designed around cost, using the lowest marginal cost of generation, but if we want to reach net-zero, is this still the correct approach? And when should our focus shift towards solving for the lowest carbon solution?

For example, does it make sense to have regulatory policies that incentivise reduced production from UK gas generators with much lower carbon emissions and substitute that with cheaper continental lignite generation that produces nearly twice as much carbon to produce the same amount of electricity? Whilst consideration of this in the current UK regulatory system is questionable, we can take our own actions to prioritise mitigating carbon emissions above the cost of the power itself.

Low-carbon energy freedom for your business, with zero capital investment

Hartree’s in-house modelling allows us to predict current and future power prices with a high degree of accuracy and we can use this data to predict both the average and marginal plant’s carbon intensity of the UK power generation network today and into the future. We can extract historic carbon emissions and forecast future carbon emissions from our hourly modelling and use this to question carbon policies in this seemingly sedentary period until technology allows for the next wave of dramatic reductions. More on this in Part 2.

Hartree analysis showing the hourly emissions of carbon in the power sector both on an average basis but also a marginal basis alongside power price

Three major considerations that are often overlooked, or frankly may be just too difficult to answer when we consider our own carbon goals are:

  1. How can we measure the impact of our carbon-reducing actions?
  2. What granularity should we measure our actions and emissions in?
  3. What should we do about emissions that can’t be economically reduced at source?

Over the remainder of this series of Market Insights, we look to answer these questions.

Hartree’s market-leading in-house team of experts are here to offer transparent advice and solutions for you when planning for your business over the next decade and beyond. We offer low-carbon solutions for your business, with zero capital investment to support you in the journey to net-zero.

We are consistently hearing from businesses such as industrials, data centres and universities that consumers are no longer willing to deal with companies that are not at the forefront of ‘the road to net-zero’. Don’t let your business get left behind.

Coming up in the next article in this series, we look at what it really means to be 100% renewable and whether, as an industry, we need to be more transparent over our claims. We also analyse the correlation between power prices and the grid’s average and the marginal plant’s carbon dioxide emissions and delve further into what actions we should really be taking to reduce carbon impacts in the near term.

More Market Insights

Hartree Forecast
Carbon Price Floor
4 National Grid Future Energy Scenarios 2020
5 World Nuclear Association’s “lifetime emissions analysis”
Calculated using the Hinkley Point C CfD Strike Price of £92.50/MWh (2012 prices) and the UK’s Third Contracts for Difference (CfD) auction where wind cleared at £39.650/MWh (2012 real).
7 The Ban on new sales of petrol and diesel-powered cars from 2030
Non-power industries include cement/lime, ceramics/glass, chemicals, metals, oil/gas and pulp/paper
9 COP26 Energy Transition statement

written by
Adam Lewis

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U.K.'s Wind Record Could Have Come 14 Months Sooner

Wind generation sets a record high of just over 17.5GW, but this could have been…

  • Wind generation sets a record high of just over 17.5GW, but this could have been achieved 14 months earlier if not for network constraints

  • National Grid paid £283 million to wind farms last year to constrain supplies or 5% of the total volume generated by wind

  • These curtailments cost an extra £83 million when replacement power is considered, as well as resulting in an additional 1.25 million tons of CO2 being emitted, or 2.7% of the UK’s total emissions from power generation

  • While the recent record shows the progress the UK is making, the country still needs to quadruple offshore wind capacity by 2030 if the ambitious target is to be achieved


New Highs

The UK achieved a notable milestone over the weekend, with wind generating a record high of just over 17.5GW. Impressive as this achievement is, it highlights the considerable work ahead to achieve the UK’s ambitious goal of 40GW of offshore wind capacity by 2030, nearly fourfold current levels.

National Grid Wind Generation Data – displaying the annual maximum and minimum half-hourly values. Unconstrained wind represents wind generation without National Grid turn-offs.

The record was achieved thanks to a windy weekend with high demand. The latter is crucial because more wind power can be consumed locally to its source, thus reducing volumes necessary to be transported to higher demand areas.

At times of high winds, the National Grid frequently pays operators to curtail power as the network struggles to transport these vast wind volumes to demand areas. To reach the offshore wind target, significant investment is required in the network to ensure this new capacity can generate unconstrained.

Hartree analysis of operational wind capacity as well as publicly announced future projects as of 19.02.21

By way of a live example, just a few days ago, the 2.2GW sub-sea HVDC Western Link cable, running between Western Scotland and North Wales, went offline1. This cable outage has added to an average wind curtailment of 1.7GW over the last three days. The same cable that Ofgem recently announced was under investigation around its ‘delivery and operation’.


Constraint Costs

Analysis by Hartree Solutions shows that the National Grid paid £283 million to wind farms last year to constrain their supplies, with the bulk of these extra costs being borne in the winter months when the wind is highest.

National Grid Balancing Mechanism data. Visible wind farm constraints plus Hartree analysis of these volumes’ replacement costs.

In addition, when these megawatts are constrained, they need to be replaced. This is often via thermal generation, resulting in the production of carbon dioxide (CO2) emissions at the expense of renewable generation. Our analysis shows that the additional cost of these replacement volumes was £83 million throughout 2020, resulting in a combined £366 million spend linked to wind constraints.

Just this week, National Grid stated:

“The cost of these constraint payments is continually weighed up against the cost of building new infrastructure, to ensure we keep the costs of running the system as low as possible. To date, these constraint payments have been the most cost-effective option to operate the electricity system securely.”

Whilst much of the £283 million paid to wind farms will be offset by reduced subsidy payments, this falls outside of National Grids considerations when investing in the network. If we take the National Grid’s statement at face value, combined with our analysis, we can conclude the cost of alleviating these constraints is more than the £366 million spent last year.


Higher Carbon

Further, through our marginal carbon analysis, we have calculated the effect these curtailments have on the UK’s emissions from power generation. Last year, the UK saw a 70% increase in CO2 emitted from these constraints. Further, we find the added emissions from curtailing wind and substituting the power, often with COemitting sources, resulted in an additional 1.25 million tonnes (Mt) of CO2 produced, or 2.7% of the UK’s total emissions from generation in 2020.  To put this into context, this equates to 211,000 homes’ electricity use for a year or, if we value these extra CO2 emissions at today’s EUA price1, just over £40 million. Valuing the emissions using this approach leads to a cost of £406 million associated with wind constraints.

Hartree’s analysis of the carbon emissions added in the UK from generation volumes replacing constrained wind volumes.

We have previously highlighted the importance of analysing the carbon intensity of the marginal price-setting unit in the UK to achieve our net-zero goals and have called for carbon to be included, alongside price, when deciding which electricity sources are utilised.


14 Months Late

Without these constraints, the 17.5 GW milestone would have been achieved some 14 months earlier, on 8th December 2019. Had National Grid not constrained 4.1GW of wind generation, the UK would have produced 17.69GW of electricity from wind. Similarly, on boxing day last year, the UK would have set a record just short of 19GW without 2GW of constraints.

Monthly maximum wind generation volumes displayed without the constrained volumes

Whilst lower demand from Covid-19 drove an increase in constraints, there has been a steady increase in these annual volumes, which have almost doubled in the last year. In fact, throughout 2020, 5% of all wind generation volumes were curtailed due to network constraints.

A look Ahead

The wind is already proving to be a crucial part of the UK’s power networks, covering as much as 74% of total demand, a record set in the early hours on 26th August 2020. According to UK government data, wind accounted for just 2.7% of generation as recently as 2010. But with the wind making up 21% in 2020, the industry’s growth has been impressive.

The annual sum of wind generation data from National Grid

While the Crown Estate’s recent auction was heavily oversubscribed, it highlights the continued investor appetite, with BP paying more than £900 million for the rights to build offshore wind farms in the Irish Sea.

All this investment should ensure that the UK can meet its 2030 capacity target from a development perspective. However, the more significant challenge is how to optimise this vast increase in wind generation and make the necessary investments in the network to avoid mounting constraints on its production.

This weekend was a hugely positive step forward in renewable generation for the UK, but it now needs to ensure there are no curtailments to continued progress.


1 As shown on National Grids Daily Balancing Reports
2 Dec ’21 EUA price as of 19.02.21

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EDF Leads Generators in Winter Windfall

  EDF was paid more in 3 days than in all of Q3 by National…


  • EDF was paid more in 3 days than in all of Q3 by National Grid to balance the system

  • National Grid forced to buy power at £4,000/MWh, some 70 times greater than the average price paid over 2020

  • EPH achieved the highest average sales price for any day in the Balancing Mechanism of over £3,600/MWh


A Perfect Storm for Generators

A perfect storm of peak winter demand, low wind generation and delays to supplies from the continent saw record prices for UK power last month. Generators were quick to cash in on this tightness with National Grid forced to pay EDF nine times more than the previous year for their flexibility in January, averaging sales1 of £473/MWh compared to £53/MWh. Meanwhile, EPH and Drax settled for £387/MWh and £303/MWh.

Hartree Analysis – sales price1 to National Grid in the BM by operator4. Jan ’20 vs Jan ’21


Record Sales Prices

When the margins were especially low on January 8th, generators were able to drive a hard bargain for their much-needed megawatts. EDF was paid more in three days in the balancing market2 than in the three months through September as National Grid was required to procure their power at £4,000/MWh, some 70 times greater than the average price1 paid over 2020.

Hartree Analysis – sales price1 to National Grid in the BM against maximum sales price4.


First Mover Advantage

It was EPH on 13th January that achieved the highest average sales price1 for any day in the Balancing Mechanism2 (BM) of over £3,600/MWh during the second week of tightness. However, we can observe that EDF was quickest to react to the supply scarcity, achieving the highest average sales prices1 in the BM for the three initial tight days. On the last of these, the EDF owned West Burton B recorded the highest ever price paid in the BM contributed to an average sales price1 of over £3,200 /MWh that day.

Hartree Analysis – sales price1 to National Grid in the BM by operator4.

The weekend allowed for a brief interlude to high prices as demand edged lower. But just three days later, as demand rose again, both EPH and Uniper responded to the market dynamics adopting a similar strategy in the BM and surpassed EDF’s average sales prices1 for the remainder of the week.


Withholding Power

With high prices available in the markets, most generators sold their power in advance, locking in huge profits well before the power itself had to be delivered. As a result, the amount of unscheduled generation available was minimal, leaving National Grid with few options to balance the system.

Hartree Analysis – the volume of balancing actions by National Grid as a percentage of total generation against the EPEX3 baseload day-ahead auction price4.

On 6th January, the first day of tight margins, National Grid’s actions made up just 3.6% of total volumes compared to 19% for January 2020.

Hartree Analysis – the volume of balancing actions by National Grid as a percentage of total generation4.

As power prices hit £1,500 in the day-ahead auction, all generation sources will have been well in the money a day before delivery. Unsold volumes will either have been a prudent decision against plant failure or a commercial decision in the hope of achieving far greater profits. In the case of West Burton B, EDF offered these withheld volumes to balance the system at a huge £4,000/MWh.


Stations Profiting from Low Margins

There were just a handful of generating stations that exploited these low margins including the SSE owned Keadby, the EPH owned Langage, the EDF owned West Burton units, the Uniper owned Connahs Quay units, and the Drax owned Rye House and Draxx-5 coal unit.

Hartree Analysis – highest sales price to National Grid in the BM. Showing the top 10 generation units4.

It was the EDF owned West Burton B that achieved the highest daily and monthly revenues from BM sales across January, receiving over £7.5m in a single day.

Hartree Analysis – plant revenue from sales to National Grid in the BM. Showing the top 6 plant revenues for January

Throughout January the cost of these purchases, despite the low volumes, was over £100m with West Burton B making up over £20m or 21% of that total spend. Costs that are ultimately borne by consumers and generators alike.

Hartree Analysis – the sum of costs of National Grid’s buys in the BM against the volumes of these buys5


Estimated Generator Revenues

Whilst there is no information available to show how much volume each generator had presold coming into January, those who presold the lowest volumes will have fared much better. Suppose we estimate scheduled generation revenues using the Day-Ahead auction as an income metric. This case shows that operators such as RWE and Uniper could have seen their revenues from gas, coal, and biomass plants triple compared to the same time last year. Similarly, estimated revenues of Drax, SSE and EDF’s units nearly doubled year-on-year.

Hartree Analysis – scheduled generation revenues use the EPEX Day-Ahead auction3 as their assumed income plus the operators realised income from the BM4. No generation or fuel costs accounted for. Jan ’20 vs Jan ’21


Scarcity Pricing

Ofgem has already announced6 they will examine these high prices to fully understand the scarcity behind them, adding “Given our findings and penalties in the past year regarding manipulation in the balancing mechanism, the market knows that Ofgem takes any manipulation very seriously and that we monitor the market closely.”

However, it’s worth noting that scarcity pricing is a part of the market design. In periods of low margin, scarcity pricing acts to ensure that the cost to the country of a blackout is correctly priced into imbalance prices. For example, on 13th January the National Grid calculated de-rated margin7 was just 836MW representing the unused margin on the system8 available before a power outage. This value is then fed into a probability calculation representing the likelihood of a blackout. In this case, it generated a 14% probability. Finally, the cost of a blackout is estimated at an equivalent of £6,000/MWh, so bringing generation on at prices lower than this to avoid a blackout is the better financial option for the country. Applying the probability against the £6,000 cost generated an £835/MWh reserve scarcity price that forms a component of the imbalance price calculation for such hours.

Further consideration should also be given to thermal generators reduced run hours due to the renewable build-out. Generator’s fixed costs make up a large portion of their total annual costs alongside their variable marginal cost of generation. They are increasingly required to be recovered over fewer hours, requiring higher prices to do so or risk closure as per the recent Severn Power that in August 2020 went into administration9.

Network Constraints

Gas generators provided the bulk of this flexibility to National Grid to ensure supply met demand. However, notably in second place was wind, but for very different reasons. These volumes represent the UK’s inability to handle periods of high winds with National Grid forced to constrain the generation. Consequently, these volumes are replaced with higher carbon sources of power, typically gas that add to the UK’s emissions resulting from the network constraints.

Hartree Analysis – balancing volumes by National Grid in the BM by generation fuel type5.


What is the Balancing Mechanism?

Whilst generators sell much of their power in advance, they can also offer any unscheduled generation via the Balancing Mechanism (BM). This is National Grid’s tool to ensure supply meets demand in real-time because unlike gas, power has almost no flexibility innately in the transportation and distribution network.

By restraining from selling their power into the market ahead of delivery, operators can instead sell that power to National Grid in the BM. If the system is short of power, this strategy typically achieves a much higher price for that power. But it is a calculated gamble because if the system has excess power or there are lower-priced supply options, the operators miss out on any revenue.


The Fundamental Conditions

Temperatures 4°C below normal coupled with metered wind generation averaging just 3.5GW contributed to this power price surge. Demand surpassed last winter’s high by nearly 1GW peaking on 7th January at 46.3GW and with wind averaging just 3.5GW, left limited unscheduled generation to meet the peak evening demand.

See our latest Market Insight, where we discuss the new records in more detail.

High demand and low winds, together with delays to the start-up of the IFA2 interconnector, an undersea electricity connection between England and France, and an outage of the BritNed Interconnector between England and the Netherlands presented a unique opportunity for power plants to exploit.


More Challenges Ahead?

As the buildout of renewable generation continues, the UK power market is increasingly exposed to extreme pricing with no low-carbon alternative to coal and gas units’ flexibility to turn to at times of low wind and solar generation. January painted a stark picture of the UK’s challenges as it seeks to decarbonise its electricity. With weather forecasts pointing to further cold weather across Europe for February, the potential for extreme pricing is not yet over this winter.

These events highlight the rewards of having fully optimised assets to capitalise on these conditions. By partnering with Hartree Solutions, businesses can benefit from the team’s wealth of real-time trading and analytical experience and enjoy on-site, low-carbon generation that turns the potential liability into a performing asset.


1 Volume Weighted Average
2 National Grid Balancing Mechanism
3 EPEX Day Ahead Auction
4 Data filtered to gas, coal and biomass (flexible thermal) plants and operators with generation volumes greater than 10 million MWh’s in 2020
5 Data filtered to gas, coal, biomass, wind and hydro
6 As reported by Bloomberg on 15th January
7 De-rated margin and LoLP calculation
8 Reserve Scarcity Pricing
9 Severn Power Administration
Cover image – Drax Power Station



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