How is the Coronavirus pandemic affecting the clean energy sector?
Updated 10:30, 24th June 2020
This page summarises a number of the challenges and opportunities that the Coronavirus pandemic is presenting to the clean energy market. We will be updating it regularly as the sector continues to respond to the crisis. Please contact our specialist Energy team with any comments or queries.
1. Falling demand, increasing renewables, increasing balancing costs
During lockdown, with the majority of the UK workforce at home and many large energy consumers (both industrial and commercial) closed for business, there was a dramatic fall in national electricity demand as well as a shift in the demand profile. On Easter Sunday demand hit a record low – 20% below Easter last year – and this trend continued through April and May, with weekday demand down 13-17%. On 5th April, two weeks into lockdown, electricity prices dropped well below negative (to -£66/MWh) as strong wind and solar output hit the grid. In fact solar broke its peak generation record in April – meeting about 30% of demand – and the UK’s power output went coal-free for over two months (between 9th April and 16th June), the longest period by far since the Industrial Revolution. This has had a positive effect on carbon emissions, but it also presents a challenge to the grid – managing the intermittency of renewable generation and falling system inertia. Good news for flexible assets such as batteries.
National Grid is having to take more action to balance supply and demand and to regulate system frequency, which means flexible assets are being called upon to provide balancing services more often and for longer periods. For batteries the key decision is when and how much to charge or discharge to take best advantage of price fluctuations whilst leaving sufficient capacity in the battery to respond to the next system event. Aggregators and optimisers will play a key role here.
National Grid has implemented a new service – Optional Downward Flexibility Management (ODFM) – to help it manage the electricity system during periods of very low demand. ODFM pays providers to increase demand or reduce generation so National Grid can maintain frequency and voltage control.
National Grid also sought a Grid Code modification (GC0143) to allow it to instruct distribution network operators (DNOs) to disconnect embedded generators – including solar and onshore wind farms – as a last resort if there is oversupply of electricity on the system. The instruction could be in respect of a generator’s total capacity or a percentage of capacity and would be actioned only once other balancing options had been exhausted. No compensation would be payable to the generator. Ofgem approved this modification on 7th May and it will continue in effect until 25th October.
Over the early May bank holiday, when demand was very low, National Grid confirmed that it did not need to use the Grid Code modification to disconnect embedded generators but had reduced generation through its voluntary ODFM service.
To further address the issue of low demand, National Grid has signed a one-off contract with EDF Energy to reduce the output from Sizewell B nuclear power station until at least 10th August. This is to avoid having to make daily curtailment payments which would be more expensive over the duration of the contract.
Due to intensified balancing activity and rising system management costs, a significant increase in Balancing Services Use of System (BSUoS) charges – which are levied on demand customers and generators – is expected over the summer. A CUSC modification (CMP345) was sought to defer the additional BSUoS costs, but ultimately Ofgem decided to implement an alternative proposal to cap BSUoS charges. With effect from 25th June, a cap of £15/MWh will apply to the BSUoS price in each settlement period until 31st August. If costs should go above this cap, any additional charges will be deferred and recovered through BSUoS charges equally across all settlement periods in 2021/22. The decision means that renewable embedded generation will still be able to access cash from higher BSUoS charges this summer, while giving flexibility to suppliers.
Since lockdown was eased on 15th June, system data shows that electricity demand is starting to return to normal, which should have a knock-on effect on power prices and the cost of balancing the system, provided of course that we don’t see a resurgence that forces the country back into strict lockdown.
2. Disruption to construction?
The consensus seems to be that, although COVID-driven protocols have had to be implemented, the disruption to energy projects under construction has been relatively limited – thanks in large part to the fact that the projects are outside and that much of the construction work can be performed at a distance from others. For example, Fluence told Current News in early May that it had been able to continue work on “all but two or three” of its 70+ large-scale battery projects.
Equally, we’ve received only a few reports of disruption to the equipment supply chain, including international orders for generation and storage assets, where delays have apparently been in the order of days or weeks rather than months.
However, as network operators are understandably focussing on critical infrastructure so some connections and non-critical reinforcement work is being delayed, although at least a few G99 connection tests have apparently been carried out remotely. Following consultation with energy networks, electricity generators, gas shippers and suppliers, Ofgem has issued guidance setting out which activities should be prioritised during the current pandemic. For energy networks, the works to be prioritised include emergency response and critical repairs, the operation of network control rooms and call centre functions, essential connections work and planned work that is necessary for the short- to medium-term security of supply and network resilience. Additionally, safety critical work that impacts the integrity of the network, the general public’s safety or work that presents a significant environmental risk if not prioritised should also continue. Among the works to be deprioritised are routine repair and maintenance, non-safety related survey, condition assessment and inspections, and meter work.
If your construction project is suffering from disruption as a result of Coronavirus, consult our Construction team’s guidance here – Coronavirus: Disruption in international construction and engineering projects.
If you are looking to enter into project development contracts in the current climate, consult our guide on Future Proofing Your Contracts.
3. Falling power prices
Impact on generators
For energy projects whose returns depend party or wholly on merchant revenue, falling power prices could have a significant impact on profitability and potentially delay new projects coming through fundraising. Even subsidised projects could be affected.
Certain energy assets will no longer be able to operate profitably – particularly where there is a cost attached to their fuel – and may therefore be sitting idle. However, generators with long-term, stable, contracted cash flows may be more resilient.
Developers, generators and investors should be checking the terms of their project contracts – whether it be equipment supply, construction or power offtake agreements – to see how the risks are allocated. For example, some (but not all) PPAs allow for periods of zero output without penalty. Sponsors and developers should seek to identify and resolve potential issues between themselves at the earliest opportunity, and those with loan obligations should also be engaging with their lenders, particularly if project cash flows are being impacted.
Refer to our Coronavirus: Commercial Contracts & Supply Chain FAQs and Coronavirus: Disruption in international construction and engineering projects guides for further information.
Developers who have secured funding should check their finance agreements for material adverse change (MAC) clauses and refer to our guidance here – Coronavirus: the effect of Material Adverse Change clauses. Those seeking funding will be reassured to hear that the project finance lending market has not stalled and deals are continuing to progress. However, lenders are understandably reviewing key areas and scrutinising risk allocations between borrowers and key counterparties.
Impact on suppliers
Electricity suppliers will be looking at their hedged positions and considering whether to unwind some if not all of them. Those with a large commercial and industrial customer base will probably be most affected and will need to look closely at managing customer default risk. Those with a large residential customer base may need to bolster their forward positions as domestic electricity demand rises thanks to home-working. Mark-to-market trading costs could significantly increase over the coming months. Plus there is anecdotal evidence of customers – from large businesses to households – seeking payment holidays or simply failing to pay their energy bills. If this results in supplier failures and Ofgem’s Supplier of Last Resort mechanism is engaged then credit default costs will simply be redistributed to remaining suppliers, putting them under further pressure.
Having consulted with energy network companies, Ofgem has taken steps to protect suppliers with the introduction of a new £350 million mechanism whereby energy suppliers will be able to defer certain network payments – electricity distribution network charges for electricity suppliers and gas distribution transportation capacity charges and gas transmission transportation charges for gas shippers. However, payments cannot be deferred to such an extent that a network’s ability to fulfil its financial covenants and credit metrics is threatened. If a network company breaches such covenants at any point, the deferral scheme may be withdrawn. Additionally, the scheme cannot be used by suppliers and shippers who have an investment grade credit rating and “can therefore be reasonably expected to be able to access alternative sources of liquidity outside these schemes”. Deferred payments would accrue interest at the default rates set out in the relevant industry codes (currently ~8%) to incentivise suppliers and shippers to only defer as much as is necessary and return to normal payment terms as quickly as possible.
Suppliers can also check to see whether they qualify for one of the Government’s support schemes – the COVID Corporate Finance Facility or the Coronavirus Business Interruption Loan Scheme. See our guidance here.
4. Relaxation of Capacity Market rules
Holders of Capacity Market (CM) contracts should note that the scheme agreement does not contain provisions for force majeure relief. The CM Rules provide that “the obligations set out in the Rules and Regulations and forming the Capacity Agreement are not excused by events out of the Control of the Capacity Provider (a project company) and apply regardless of any assertion of force majeure, frustration or equivalent legal doctrine” (Rule 6.9.1).
However, having run a consultation in April, the Department for Business, Energy and Industrial Strategy (BEIS) has announced the introduction of temporary rules to modify the application of the CM Rules and Regulations during the Coronavirus pandemic. The measures do not introduce a force majeure clause but rather remove or relax certain deadlines and obligations, reduce administrative and operational burdens and minimise the likelihood of terminations arising from the pandemic. The specific measures include an extension of the long-stop date for New Build Capacity Market Units and creation of a new ground of termination of a CM contact, to apply where non-compliance by a capacity provider arises from the effects of COVID-19 (in which circumstances it is proposed that the termination fee mechanism would not apply).
According to BEIS, the measures will “only remain in place as long as necessary”.
5. Impact on Contracts for Difference (CfD)
The CfD scheme incentivises renewable and low carbon generators by subsidising the difference between the wholesale electricity price and an agreed strike price, determined through auction for each generation technology.
There are currently no plans to delay the CfD auction scheduled for 2021, which will include solar PV and onshore wind for the first time since 2015.
However, with wholesale electricity prices hitting record lows, the Low Carbon Contracts Company (LCCC) – as CfD counterparty – is being called upon to make higher top-up payments to CfD generators. Such payments are funded through a charge on consumers’ electricity bills.
BEIS has agreed to extend to LCCC a one-off interest-free loan to help cover CfD payments to generators through the next quarter, ensuring that LCCC is able to continue supporting generators without increasing the charge on consumers. However, LCCC will likely have the ability to recover the amount of the loan from suppliers (via consumer bills) in Q1 of 2021.
Generators who hold a CfD should note the force majeure clause in their contract and refer to our Commercial Contracts & Supply Chain FAQs on whether it is likely to operate in the context of Coronavirus.
As a result of the crisis, the deadline for responses to the consultation on proposed amendments to CfD Allocation Round 4 was extended from 22nd May to 29th May. BEIS is now considering the responses.
6. Impact on the Non-Domestic Renewable Heat Incentive (NDRHI)
On 11th March the Chancellor announced the introduction of a third flexible allocation of NDRHI Tariff Guarantees (TGs) to help ensure that eligible projects having difficulty meeting TG deadlines for COVID-related reasons can still access the NDRHI. Applicants will be required to submit ‘Stage 2’ information prior to the NDRHI closure date (31st March 2021) but will be able to defer submission of ‘Stage 3’ commissioning evidence up to 31st March 2022. Successful projects would be entitled to NDRHI payments from the point of commissioning until the 20th anniversary of the submission of their ‘Stage 2’ information. Additionally, BEIS intends to bring forward legislation to extend the commissioning deadlines for projects already holding TGs, to grant them additional time to fully commission in light COVID-19. The legislation would push commissioning deadlines back to at least mid-March 2021, giving TG projects at least six or seven additional weeks to reach commissioning.
7. Industry developments delayed
- A proposed modification (P379) to the Balancing and Settlement Code (BSC) which would allow multiple suppliers to compete for the supply or export of electricity through a single meter without needing to establish an agreement between themselves has been delayed by at least three months.
- National Grid has delayed its implementation of Dynamic Containment – a new fast-acting frequency response service – and the planned procurement will no longer take place in June 2020. The decision was made so National Grid “can focus on our more immediate transmission system needs and address the impacts we are experiencing from the COVID-19 pandemic”.
- For the same reason, Project TERRE – the Trans-European Replacement Reserves Exchange (a platform for gathering all the offers for replacement reserves and optimising their allocation across the different European transmission systems involved) – will not go live in June 2020 as planned. Currently the earliest expected go-live date is the end of October 2020.
Our expert Energy team can assist with queries relating to any of the above.
If you would like to talk through the consequences for your business, please email us and one of our team will get in touch.
The content of this page is a summary of the law in force at the date of publication and is not exhaustive, nor does it contain definitive advice. Specialist legal advice should be sought in relation to any queries that may arise.
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