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Carbon in UK Power – Part 2: Is It Time to Prioritise Carbon Over Price?

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Carbon in UK Power – Part 2: Is It Time to Prioritise Carbon Over Price?

Date
December 22, 2020
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Up until now, the UK has prioritised keeping the lights on and consumer bills down ahead of environmental concerns. In other words, the security of supply and price are put above carbon intensity in the energy trilemma of the UK.

This priority could be set to change as Britain gets serious about its 2050 net-zero target. As we highlighted in our previous article there is still a lot of work to be done to achieve this aim or even the mid-term goal of a 68% cut in greenhouse gas emissions by 20301.

Companies are waking up to the importance of sourcing low carbon generation, yet the current design of power markets makes this both hard to achieve and difficult to quantify (something we discuss in a future thought leadership piece). For example, Volkswagen just announced2 that its top executives’ bonuses will be linked to its ESG targets and last month Sony hinted3 at leaving Japan due to limited access to clean energy with the carbon intensity of the country’s electricity network more than twice that of the UK.

In Part 2 of this series, we:

  • Highlight the challenges the UK faces to reduce carbon from power generation over the coming decade;
  • Demonstrate how our choices greatly impact the UK’s efforts to continue to reduce overall carbon emissions;
  • Introduce the concept of the marginal power unit in the UK system and its importance on carbon emission reductions;
  • Show that measuring carbon on an annual basis is nowhere near detailed enough for the UK to achieve its goal, with a much more granular, half-hourly view on carbon intensity required, just like we have on prices and,
  • Underline the importance of working with a market-leading energy partner to ensure businesses achieve maximum emission reduction.

 

The Marginal Unit

Newton’s third law states that ‘for every action, there is an equal and opposite reaction’

In the power stack, the lowest cost generation is used first while the last generating unit required to meet demand typically sets the price4. This is known as the marginal unit or price-setting unit. Our analysis in this second article highlights the key role this marginal unit will play in reducing the UK’s carbon intensity.

The relevance of Newton’s third law to electricity is that by turning on a generating asset we are displacing an alternative source of production. Yet these decisions are made based on price and not emissions. But to meet the emission goals we need to be considering the carbon impact of these actions as well as the cost of supply.

Through Hartree Solutions’ in-house modelling, we can extract a marginal balancing unit for each hour5, rather than an annual basis more typical within the industry. We can do this from both a forward-looking perspective and a retrospective view.

 

Granular Carbon Analysis

Our highly granular approach gives us a great insight into historic, real-time and forecast carbon emissions. This allows us to design long-term solutions to reduce the carbon content of a company’s electricity use and ultimately completely offset it.

Using this model, when we analyse the relationship between the grid’s average carbon intensity and the power price, we see a good correlation. As power prices increase, the average carbon intensity of the grid also increases.

Hartree Analysis of the correlation of the power price and the average carbon intensity of the network

However, when we look at the carbon intensity of the price-setting unit and the power price, this correlation breaks down. This highlights the impact of a regulatory framework that favours keeping prices down over carbon intensity and can act as a handbrake on the UK’s success in continuing to reduce power emissions.

Hartree Analysis of the correlation of the power price and the marginal carbon intensity of the network

Further, we are also able to demonstrate the poor correlation between the actual carbon impact of your actions (the marginal units carbon intensity) and the average carbon intensity. This highlights the issues in using the average carbon intensity as the driver for our decisions as it can actually lead to increased carbon emissions in the UK.

Hartree modelled correlation between the average and marginal carbon intensity

When the grid has a high percentage of low carbon generation but still needs some high carbon generation to meet demand, we could be fooled into thinking that we should look only at the low average carbon intensity and that further carbon reductions are not possible. Yet, where we can substitute this high carbon intensity grid generation with lower carbon local generation, we can further reduce the UK’s total emissions. This is why measuring specific consumers and on-site sources of generation against the marginal carbon intensity of the network is key if the UK is to continue reducing emissions at the rate required.

Hartree analysis of the carbon content showing the marginal vs average over the course of a day

 

Choosing the Right Energy Partner

If you are serious about truly reducing the carbon impact of your business it is essential to work with the right energy partner that is not only able to measure and forecast the carbon-intensity of the network but also able to optimise your energy usage in real-time to benefit you as a consumer. We believe this is a unique skillset of Hartree Solutions.

Most companies and businesses similarly look at their annual carbon intensity rather than a more granular measure. Usually, this is for ease and a lack of data available. It leads to public announcements which boast of ‘purchasing 100% renewable generation’. We believe these can be misleading as it is unclear how their electricity is generated when the wind doesn’t blow or the sun doesn’t shine.

We only need to look back at 26th Nov ’20 where renewable generating made up only 7% of total generation over the day. On days like these, claims of a grid-connected user’s electricity being 100% renewable are questionable.

Generation by fuel type from National Grid data

 

The Challenges that Lie Ahead

The reality is that the UK network is some years away from being able to provide economic solutions for 24/7 low carbon generation. And this is a reality that we as an industry need to better understand and be more open and transparent about.

Delving deeper still, we have charted the UK power generation units that most frequently set the marginal price and then animated them to be sorted by carbon intensity to further highlight the breakdown in correlation between those aspects.

Hartree Analysis highlighting the breakdown in the correlation between price and the marginal setting unit

Any action we take, say via on-site generation, which displaces a marginal unit and reduces emissions from the grid should be the measure against which we consider the impact of that action.

There is also a wide variation in the volume of carbon emissions that are offset depending on the exact timing of the action. All hours are not equal. This becomes clear when we look at a specific day using our in-house modelling between the impact of our action on carbon emitted into the UK atmosphere on an hourly basis.

Much like the total emissions chart in Part 1, we can see the average tCO2/MWhe has significantly and consistently decreased over time as has the marginal equivalent.

 

Hartree analysis of the UK’s annual carbon intensities – average vs marginal

Additionally, displayed over a 24-hour day we can see the importance of analysing any effort to reduce carbon emissions on an hourly basis both on an average and marginal basis. Again, we see a large drop from 2015 as gas has largely replaced coal as the marginal unit. The impact of Covid-19 has led to a big fall from 2019 to 2020 but our analysis indicates that declining trend is set to halt by 2023.

Hartree analysis showing the hourly profile of the average carbon intensity

 

Hartree analysis showing the hourly profile of the marginal carbon intensity

As mentioned in the first article in this series, the easy switches have been exhausted and the real challenges lie ahead. Further evidence of this since we released Part 1 is the prequalification result for the upcoming Capacity Market auction for the delivery year 2024/25. Even four years from now the makeup of reliable generation to insure against blackouts is little changed in its carbon makeup with gas generation continuing to be both relied upon and constructed in the medium term.

The 2024/25 Capacity Auction continues to attract the same fuel type of mix as per the current system

Material carbon reductions from a change of fuel type or technology are not on the immediate horizon in the same way we have experienced over the last five years. We must therefore work harder to reduce our impact on emissions. However, the granular approach adopted by Hartree Solutions can make this achievable, certainly from an individual company’s perspective. We measure the carbon savings from your actions utilising new or existing generation assets. These assets can be optimised to reduce costs, carbon emissions or a combination of both. In the latter, of course, there is a trade-off between reducing costs and reducing emissions and how we balance those two desires. This is where we believe our partners should not only have open transparent data to make this decision but also set these goals themselves.

Ultimately, not all emissions can currently be reduced to zero at source in an economical manner. Therefore, we offer a best-in-class set of carbon offset solutions so each customer can strike their own balance.

No two customers will have the same basket of offsetting products. It is an open and bespoke solution to meet your needs, but Hartree Solutions can offer you a complete solution via directly connected additional renewable generation, optimization of flexible assets to further reduce emissions and completed by offsetting your entire business operation.

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Footnotes  
68% reduction in greenhouse gas emissions
Volkswagen announcement
3 Sony hints at move away from Japan
4 The unit setting the imbalance price is derived via a complicated calculation as seen in this document by Elexon
5 The marginal price setting unit extracted from our model is our in-house estimate
6 The Christmas Day Carbon challenge is limited to one entry per person. Entries must be received before 00:01 on Christmas Day. Hartree’s modelling will be used to determine the maximum marginal carbon intensity for any hour on Christmas day. The winning entry is the one closest to the maximum value. Where there is a tie the first entry received will be the winning entry. No Hartree or Hartree affiliate employees will be eligible to win. For each unique entry received we will donate £10 to the winners verified charity of choice up to a cap of £5,000.

 

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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.

 

Footnotes
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.

 

Footnotes
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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