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Energy market insights and news
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
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’.
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.
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 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.
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
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.
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.
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 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.
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.
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.
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 7th January at 46.3GW and with wind averaging just 3.5GW, left limited unscheduled generation to meet the peak evening demand.
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