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After the transition period last year, the UK lost access to the EU’s Emissions Trading Scheme (ETS), and in its place, the UK created its own, almost identical ETS.

Next week, on 19th May 2021, the first UK ETS auction will establish a price for this new carbon contract.

As part of this series of articles, we’ll look at the impact two different schemes on the same continent has and why the longer the two ETS schemes are left separate, the greater the risk of irredeemable divergence becomes.

• There is a significant risk that UKAs are mispriced in next weeks’ auction

• Yesterday, the UK published the final free industry allocations for 2021-25, representing an 9 Mt annual decrease

• Continued uncertainty remains over a linkage to the EU ETS scheme and is unlikely to be resolved this year

• Decarbonising the industrial sector does not begin to occur until the UK ETS price reaches £50-60 ton

 

Where are we now?

After having considered a Carbon Emissions Tax and remaining a part of the EU’s ETS, the UK decided to launch the UK ETS, which came into effect at the start of this year. The scheme operates under the same principle as the EU’s version and covers the same sectors (electricity and heat generation, heavy industry and aviation).

The UK ETS was initially planned to start with a cap of 155.7 Mt for 2021, falling to 117.6 Mt by 2030, figures which are 5% lower than the UK’s notional share of the overall EU ETS cap, which was based on a 40% emissions reduction from 1990 levels by 2030. However, the UK’s cap will have to be amended to keep it in line with the government’s newly announced target of cutting emissions by 78% by 2035, compared with 1990 levels.

In its Sixth Carbon Budget report published in December 2020, the Climate Change Committee suggested that the UK reduce the ETS cap starting 2023. While the exact trajectory is still to be defined, the UK government stated the CCCs report would play a key role in determining the trajectory of this new net-zero aligned cap.

The Free Allocation process is identical to the EU ETS, at least in the first two years, as is the auction process except for the addition of an Auction Reserve Price, or price floor, of £22.  The UK’s Cost Containment Mechanism is almost the same as its European counterpart but acts over a shorter timeframe in the first two years to protect against excessive price volatility.

On 10 May, the UK published the final free industry allocations for the 2021-25 period using the same benchmarks used by the EU ETS. The allocations amount to a yearly average of 39.1 Mt over the five years. These represent an 9 Mt annual decrease from 2020 allocations to UK installations under the EU ETS (48.1 Mt).

Yet while the two schemes are currently similar, last months’ announcement by the UK of “the world’s most ambitious climate change target” points to the direction the country is seeking to go. Therefore, the UK is likely to favour more stringent measures for its own ETS and expand the comparatively narrow range of industries covered by it.

That said, any changes are unlikely to be implemented any time soon. This year and next are likely to see “business as usual” to allow the new scheme to bed in and minimise disruption and uncertainty for participants.

 

What’s next?

After this initial settling period is over, the most likely options are either the EU and UK ETS combine once again, or that the UK takes advantage of its independence and carves out its own mark with its recent record on climate pointing to a tighter system. If the two schemes were to combine, then the UK version would likely be consumed by the EU one, and there would be price parity. In contrast, a standalone climate-ambitious UK scheme could see a noticeable gap open up, with the UK ETS trading at a premium to the EU ETS.

 

Linkage- the attractions and the hurdles

The possibility of linking the two schemes has been on the table ever since the EU-UK Trade and Co-operation Agreement (the TCA) committed both parties to co-operate on carbon pricing. But while the TCA document states that linkage will be “given serious consideration”, the UK government was more hesitant in its White Paper. Instead, saying that while it was “open to linking the UK ETS internationally in principle”, it had made “no decision on our preferred linking partners”.

Given the similarities between the two schemes currently, it makes sense for any linkage to occur sooner rather than later while they bear such close similarity. However, the UK’s new 78% target shows how quickly differences can occur. Meanwhile, across the Channel, European Commission President Ursula von der Leyen announced that the EU’s ETS is expanded to include building and transport industries. While there are clear advantages to having a unified, jointly ambitious emissions trading scheme, progress on linking them has been slow so far, with many issues still needing to be ironed out.

The coronavirus pandemic has pushed all other concerns down the “priority” list on both sides of the channel. And amidst all the niggles that need resolving, as the UK and the EU adjust to a post-Brexit environment, the ETS is unlikely to be a top priority.

In addition, the UK’s scheme was hit by delays as market participants waited for government announcements on when the first auction would be held and the volume of carbon credits that would be available for free. Such was the lack of clarity that SSE, one of the UK’s biggest power producers, temporarily suspended its forward hedging and instead chose to commit generation much nearer to delivery.

The slow start means that any linkage agreement, which is most people’s favoured option, is unlikely to happen this year, despite the obvious attraction of making such an announcement at this autumn’s COP26, which the UK is hosting in Glasgow.

 

What does this mean for the market?

The uncertainty over the long-term future of the independent UK ETS has left participants facing a dilemma ahead of the government’s first auction of carbon allowances next week. With the scheme starting from scratch, there are no previous trades on UK Allowances (UKA), and so the EU ETS is likely to form the basis of the initial price discovery.

As a result, participating companies will have to form a fundamental view on the UK ETS, using the EU scheme as a benchmark and price their hedging requirements accordingly.

That said, we believe there remains a significant risk of UKAs being mispriced, with utilities and their hedging obligations potentially caught off guard and forced to convert their hedges at prices that diverge from that of the EU ETS. It also complicates the path towards decarbonisation (both from an industrial and utility point of view), as the key for cap-and-trade systems is price signalling. A lack of a clear price signal will likely delay investment decisions from big industrial users – the key target for the next step in the UK’s decarbonisation efforts.

While the UK has made great strides in decarbonising its power system, heavy industry still lags. The relatively easy switches achieved by the power sector prove harder to replicate elsewhere.

 

Pricing UK Emissions

A critical factor in power emissions more than halving over the last decade has been the introduction of the Carbon Price Support, a domestic top-up tax levied in addition to the EU’s carbon price.  This experience demonstrates that putting a cost on carbon is successful in reducing emissions. Therefore, the success of the UK ETS is a critical component if the country is to achieve its increasingly ambitious targets.

Hartree Solutions’ analysis shows that decarbonising the industrial sector does not begin to occur until the UK ETS price reaches £50-60 ton, with many industries requiring much higher levels than this.

 

How can Hartree Solutions help?

First of all, any company wanting to participate in the upcoming auctions will need to ensure that it is fully compliant with the UK ETS Order. An entity that is or becomes subject to UK ETS Order should speak to its Legal or Compliance Departments to ensure compliance with its provisions.

Once an ‘Operator Holding Account’ (OHA) or an ‘Aircraft Operator Holding Account’ (AOHA) at the UK ETS registry has been set up (a process that can take up to two months), Hartree’s team of experts can help manage the risks mentioned above. We can help companies navigate the uncertainty that is likely to be a feature of the UK ETS.

Emissions trading will be a vital tool for companies seeking to achieve zero-emission goals. The sooner they familiarise themselves and find the right partners to work with them, the greater the long-term gains. For more information on Hartree Solutions and see if they are the right partner for your business, go to https://www.hartreesolutions.com/.

 

Coming up…

In Part 4 of this in-depth look at Carbon in UK Power, we’ll delve deeper into the UK ETS and present Hartree Solutions’ fundamental outlook. Among the key variables determining our view is the overall breakdown of the cap, the free industry allocations and utilities’ hedging programs.

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• 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.

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.

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.

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 CO₂ emitting 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.

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.

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 26^th 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.

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

 

• 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.

 

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.

 

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.

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.

On 6^th 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.

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.

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.

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.

 

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.

 

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.

 

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 7^th 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

 

 

London, 01/02/2021