4 minute read time

Putting some gas in the net zero tank

To avoid the ever-growing impacts of climate change, we need to decarbonise our economies as rapidly as possible.

Shifting to zero-carbon power systems will get us a long way there, and although the technologies needed do exist, unfortunately many of them remain prohibitively costly to deploy at scale.

Overly ambitious targets and timelines risk heaping costs on consumers, triggering a political backlash that could delay the entire process.

This delicate balance between climate commitments and cost was thrown into the spotlight by the recent news that the UK government wants new gas-fired power plants to be built. It argues that these plants are vital to avoid blackouts in an electricity system dominated by intermittent renewable energy capacity.

Environmental groups instead argue that this represents the latest roll-back of climate commitments by a government running scared of right-wing climate sceptics and anti-regulation ideologues. They say that the right mix of subsidies and incentives can create a zero-carbon power system without the need for more fossil generation.

As is often the case, both sides are right – up to a point. The current prime minister is markedly less enthusiastic about the net-zero transition, slowing or abandoning a number of climate policies introduced by his predecessors. But the awkward reality is that, without incurring socially and politically untenable costs, we will need back-up fossil generation for some years to come. The challenge is to make sure that that generation has as little climate impact as possible, for as short a time as possible.

The problem

The UK has made great strides in decarbonising its power system. Last year, renewables supplied 47.1% of the UK’s power, up from just 2% in 1991 and 15% in 2013. Zero-carbon nuclear power supplied 13%. Of the remainder, natural gas supplied 31%, coal around 1%, while 7% was imported from the continent.

However, we have a long way to go to meet the government’s goal of 95% low-carbon power by 2030, and a fully decarbonised grid by 2035. The Labour Party’s timeline is even more ambitious: it wants to deliver a “zero-carbon electricity system by 2030”.

There is considerable devil in the detail of these pledges. But fundamental to both is a massive increase in wind and solar generation. The challenge here is that wind and solar are intermittent – and the nightmare for electricity system operators is what Germans call Dunkelflaute. This describes windless, overcast and cold periods when renewable energy generation plummets – and the lights risk going out.

Solutions on the horizon

There are a number of solutions to the problem. One is to increase the size of the system, to provide the capacity to transport large volumes of clean power from where the wind is blowing or the sun shining. Considerable investment in transmission capacity is underway – across Europe, 23 GW of interconnector capacity is expected to be added in coming years to the existing 93 GW.

However, this investment is trailing behind the 64 GW the grid operators’ association says is needed by 2030. And, even if transmission capacity met demand, despatching power across large distances results in losses that substantially increase the cost of that power.

The cheapest megawatt hour of power is the one that isn’t needed. Reducing peak demand for power – through better insulation, more efficient equipment, or by shifting demand from periods of high demand to periods of excess supply – can dramatically reduce overall system costs.

Here, the UK has made less progress than it should have done, with repeated failures to properly incentivise domestic insulation and half-hearted efforts to encourage demand-side management technologies and practices. In addition, overall power demand will inevitably increase as we electrify transport, heating and grow power use in the production of hydrogen and the expansion of data centres.

The ultimate goal is to match intermittent renewable energy generation with long-duration storage. However, for all the dramatic falls in the cost of short-duration battery storage, and the increase in its capacity, we have limited cost effective ability to store power for more than eight hours with lithium-ion, and the cost of doing so with this technology remains very high. There are solutions on the horizon, such as Redox flow and Metal-air batteries, which promise to allow seasonal storage of excess power, but their commercialisation is years off.

Getting from here to there – without breaking the bank

We need to build a bridge to a future when sufficient long-duration storage and system flexibility allows us to drive carbon emissions out of the power system. That will involve gas-fired generation which, over time, is fitted with carbon capture and storage (CCS) technology.

This is not a costless option. Energy research firm Aurora Energy Research calculates that 5 GW of back-up capacity will be needed, at a cost of £5 billion – putting an average of £178 on each household’s annual energy bill for a decade. This bill will increase when gas-fired generators are required to capture and store their carbon.

But pursuing a limited increase in gas-fired generation, with requirements that any such capacity is CCS-ready, is likely to offer the best balance between cost and ambition. Simultaneously, this government – and whichever party wins the next election – must much more aggressively pull all the levels at its disposal to encourage investment in transmission, demand-side management and energy storage. It should ensure that the UK’s carbon price recovers, helping to underpin the economics of CCS.

The case for urgent climate action is irrefutable. But that action can’t come at a cost or a pace that consumers and voters find unacceptable.

5 minute read time

Clean energy, all of the time? – why 24/7 carbon free energy is easier said than done

What does it mean for a company to commit to source 100% renewable electricity? How does an electricity grid get to net zero emissions? Given that wind and solar energy are intermittent, the answer to date has been something of a fudge.

Typically, the company can either buy a renewable tariff and let the supplier source green certificates – Renewable Energy Guarantees of Origin (REGOs) in the UK – to demonstrate that it has bought an equivalent volume of renewable power to meet the buyer’s consumption. Or the company can buy power and green certificates directly from a generator under a power purchase agreement (PPA).

Green certificates provide evidence that a certain volume of renewable electricity has been fed into the grid. They can be unbundled and traded separately to the underlying electrons. This allows buyers to demonstrate their ‘ownership’ of an amount of green power over an annual period, without needing to somehow track that power through the grid.

However, questions are increasingly being asked as to whether this passes muster. If a buyer is using green certificates from solar farms, how can these be applied to the power it’s consuming on a winter’s night? What about when the wind farm that is generating REGOs is becalmed?

Essentially, these buyers are still using power generated from fossil fuels, merely offsetting those emissions at some other time by buying green certificates from clean power that is being fed into the grid. Can such “100% clean powered” corporate claims stand up to scrutiny?

Companies seeking to make copper-bottomed green power commitments are therefore seeking 24/7 carbon-free energy (CFE) matching. This involves matching, on an hourly or half-hourly basis, green power as generated with the buyer’s consumption profile.

Both Microsoft and Google, for example, have committed to reach 100% 24/7 CFE by 2030. Meanwhile, Sustainable Energy for All and UN Energy have launched the 24/7 Carbon-free Energy Compact. More than 140 companies and government bodies have signed up, committing to moving, over time, towards sourcing clean energy 24/7.

However, reaching 100% CFE, 24 hours a day, seven days a week, is much harder than it sounds.

The problem with intermittent generation

According to our modelling, if a buyer with a flat baseload consumption profile enters into a PPA with various renewable energy technologies, it may only match its consumption with green power:

  • 28% of the time from a typical solar PV farm in England
  • 62% of the time from a typical onshore UK wind farm
  • 68% of the time from a best-in-class UK offshore wind farm.

The rest of the time, the buyer (via its supply arrangements) will be buying power from the grid, along with the associated emissions. Whilst Google has touted an achievement of 64% 24/7 CFE in 2022 (a target that would be quite easy to hit in the UK using offshore wind), reaching 100% CFE becomes an increasingly difficult challenge.

Although CFE matching can be slightly improved by contracting with a portfolio of different technologies, until a feasible storage solution can be found, getting to very high levels of CFE is very hard.

This is because renewable energy generation across different sites, but within the same geographic region, remains highly correlated. Solar farms along the same longitude all produce their power at the same time, with available sunlight varying dramatically from winter to summer. While wind speeds do vary, UK-wide weather systems can often becalm wind farms across the whole country.

This problem of temporal correlation can be seen in the impact of the massive build-out of wind capacity in the UK over the past six years. In January 2017, wind supplied 32.3% of UK power generation during the windiest half-hour period, contrasting to just 1.6% in the stillest half-hour, with a median contribution of 10.8%.

Five years on, in November 2022 the maximum contribution had doubled to 65.1% of UK power demand in a half-hour period, with the median tripling to 35.6%. Crucially, however, during the stillest period, the contribution of wind power was even lower than in January 2017, at just 1.4% of UK generation.

Wind share UK generation chart

Building more and more renewable energy capacity with correlated generation cannot solve the problem caused by periods of calm weather or cloudy skies. This means that the carbon emissions intensity of the UK’s overall grid is likely to stay stubbornly high – it fell rapidly from 505g CO2/kWh in 2012 to 168g CO2/kWh in 2020, but has yet to average below 150g CO2/kWh since.

This all means that companies seeking 24/7 CFE have a problem. So too do governments (or opposition parties) promising to completely decarbonise electricity supply.

How to solve 24/7 CFE

The good news is that there are a number of solutions that, technically, could solve the problem of getting to 100% CFE. The bad news is that, to date, none have been deployed anywhere near the scale required, and doing so is likely to be extremely expensive.

The solutions are:

Long-duration energy storage

Linking renewable energy to long-duration storage will enable excess renewable supply to better match demand. In practice, over the medium-term, this remains both unfeasibly expensive, and overly complex for corporates to contract. While battery technology is evolving rapidly, it is unlikely to be able to meet the needs of companies with 24/7 CFE commitments in the immediate future. Similarly, a range of long-term storage technologies are being developed – ranging from pumped hydro to compressed air storage – but few are currently viable at scale.

 

Use of hydrogen for energy generation

Some advocates of hydrogen suggest that it could be produced using excess renewable electricity, stored and then used to power gas turbines. There are several reasons why this is a bad idea, including the low round-trip efficiency of the process (at just 40%) and the greater value-add of using hydrogen to decarbonise hard-to-abate sectors such as steel, petrochemicals and heavy transport.

 

Carbon capture and storage

Most scenarios for reaching net zero anticipate the large scale deployment of carbon capture and storage (CCS) systems to tackle emissions that are otherwise impossible to avoid. But – despite being touted for decades by the fossil fuel sector as a key tool for solving climate change – barely any progress has been made deploying CCS at scale. Also, for a company claiming to source 100% renewables, relying on fossil fuel energy, even with the emissions captured, would stretch its environmental credibility.

The fact is, as companies debate whether green certificates (or REGOs) are an effective offset to their carbon emissions, reaching 24/7 CFE will mean chasing limited volumes of matching green power, until the solutions above reach scale and economic viability.

 

 

6 minute read time

Credit where it’s due: supporting the CPPA market

As we argued in our last blog, a healthy corporate power purchase agreement (CPPA) market is vital to cost-effectively decarbonise power systems. However, there are a number of barriers to creating such markets, not least of which is the credit risk developers face from long-term contracts with corporate offtakers.

The good news is that solutions exist to CPPA credit risk – whether from government guarantees or from private sector innovation. Below, we consider which might be most appropriate for the UK power market.

A credit crunch?

One of the appeals to both buyers and sellers of CPPAs is their long-term nature. A corporate buyer can lock-in its power costs for up to 10-15 years. Equally, a developer can match the tenor of its debt with a long-term revenue stream. However, both parties to the contract are at risk of the other defaulting.

For the corporate buyer, that risk tends to be minimal. If the seller stops generating power, the buyer can usually expect to replace the contract without too much difficulty, albeit with the risk that it might be forced to pay a higher price for its power, depending on where the market is at that point.

In some cases, CPPA contracts can be structured where the buyer has recourse to the project’s assets in case of default. Probably the most important factor is that the project has limited operating costs once it’s operational, so project SPVs – the buyers typical counterparty for the transaction – very rarely default on CPPAs.

The seller, however, faces greater credit risk. If the buyer defaults, the project operator also becomes exposed to wholesale power market prices, and may not earn enough to cover its debt payments. Moreover, by the time its buyer goes bankrupt, it is likely to have lost weeks or months of revenue from power supplied but not paid for.

Credit risk is not front of mind for developers in the UK market who have previously relied on government support schemes. Entering into contracts-for-difference with the government-owned Low Carbon Contracts Company exposes them to the credit of the UK Government, which – despite the best efforts of some recent prime ministers – retains an AA-rating.

However, those raising debt secured against CPPAs will face careful scrutiny from their lenders. Their bankers will consider the credit risk of the CPPA counterparty when pricing their debt, and would likely refuse to lend against those struck with sub-investment grade offtakers.

Solutions are at hand

There are a variety of possible solutions at hand.

Government intervention

An obvious solution is for the government to step in, providing risk guarantees in ways that are analogous to the export credit guarantee model. Here, government agencies provide guarantees to help their exporters manage the risk of selling goods and services overseas.

Indeed, in Norway, the country’s export finance agency has been offering a product aimed at the CPPA market since 2011. Its power purchase guarantee is available to counterparties based in Norway (with no requirement to export power). The guarantee can either safeguard the power seller against default by its buyer, or the lending bank against non-repayment of any loans that the buyer has taken out to purchase power in advance.

It is a targeted programme, restricted to companies involved in wood processing, metal production and chemicals production.

The Spanish government established a similar programme in 2020, allocating €600m to provide guarantees to energy-intensive companies signing renewable energy PPAs. These are also available through Spain’s export credit agency, Cesce, and the first such guarantee was made last April, to power supplied under a 12-year PPA to steel maker Sidenor Aceros Especiales from a Sonnedix solar plant.

France followed suit with state-owned investment bank Bpifrance launching a PPA guarantee fund last year, with capacity to support up to 500MW of generation, which would double the size of France’s corporate PPA market. The first CPPA supported by the fund was struck last October, between Arkolia Energies and food company Bonduelle.

Such initiatives are likely to become more common in the EU following the agreement by the Council of Ministers in December on proposals for electricity market reforms. Among other things, the reform package will allow member states to set up guarantee schemes “at market prices, if private guarantees are not accessible”.

Development banks

As a variation on this theme, there have been calls for development finance institutions to step in with such a product. Indeed, the Spanish government has called for the European Investment Bank (EIB) to offer financial guarantees to CPPAs. Again, the development bank could provide a guarantee to the project owner or lender to make them good if the seller defaulted.

Project finance insurance

An option for project finance banks is to take out non-payment insurance to protect themselves from the failure, refusal and/or inability of their counterparties to repay debt on its scheduled due date. Whilst this is one step removed from the CPPA off-taker and is typically limited to 50% of the borrowing, such insurance provides a useful source of investment-grade, unfunded risk capacity, and protection for project finance lenders. Insurers offering non-payment insurance are typically rated A or above, providing additional security to the lenders.

Monoline insurers

Another possible way to manage the credit risk of the buyer is the provision of guarantees by monoline insurers. These are specialist insurance companies which focus on one line of business, using particular sector expertise and portfolio diversification to manage risk more efficiently – and therefore at a lower cost – than non-specialists.

Essentially, the monoline insurer is able to lend its – typically triple-A – credit rating to the cash flows from the PPA buyer, using an over-capitalised special purpose vehicle to turn them into a bankable revenue stream for the project developer.

General insurers

An alternative to a specialist monoline insurer would be a generalist credit insurer that was willing to insure the default risk of the offtaker. Like the monoline insurer, it would lend its credit rating to the cash flows from the buyer, but here there wouldn’t be a special purpose vehicle and the insurer would pay out under the policy in the event of a default of the buyer if, and only if, the seller suffers a loss.

The actual loss would have to be settled in a transparent way by establishing the replacement price of a new offtake agreement with a similar buyer credit for the remaining term of the CPPA. Because of the uncorrelated relationship between the default risk of the buyer and the power price, this insurance product is effectively a structured credit product and, as such, should cost less than a simple credit default swap.

A government-backed intermediary

A more ambitious proposal is to create an entity to manage credit and long-term price risk, or use an existing one, such as the Low Carbon Contracts Company. Such an entity would aggregate end-user demand, manage market risk on behalf of end-users, and execute large, long-term contracts with generators. This model assumes that the entity is provided with either low-cost capital from a development bank or government, or has a government guarantee.

Market solutions

Probably the most obvious market solution is the aggregation of buyers into a single CPPA. This spreads the credit risk over a number of corporate credits which reduces the impact of credit default; if there are five buyers in the CPPA with 20% of the offtake each, then a single default has less impact on the seller.

Options for the UK?

So, which might be most attractive in the UK context? The government was looking at the question of guarantees as part of its Review of Electricity Market Arrangements (REMA), which it launched in 2022. We are still waiting for visibility as to what the government is likely to propose in its response to the consultation it carried out, and it may be that the process is slowed by the election due later this year. Whatever the government decides, the CPPA market will be watching closely.

5 minute read time

UK power market reform: why we shouldn’t put all our eggs in the CFD basket

Contracts for difference (CfDs) are doing much of the heavy lifting in decarbonising the UK’s electricity system. But CfDs are not without their drawbacks. If the government doubles down on CfDs as the primary mechanism for supporting large-scale renewable generation – as indications suggest it might – it could hobble critical parts of the UK’s power market, raising risks and costs for companies and consumers.

If CfDs come to dominate how developers – particularly offshore wind – underpin the revenue of their projects this will fundamentally alter the way wholesale power is bought and sold in the UK. The forward power market – which is already very illiquid – would dry up, making it difficult and costly for companies to hedge their power costs as all the physical power from CFD projects would be sold in the spot market. It would also, as I have blogged about before, transfer large amounts of risk to consumers who are ill-equipped to manage it.

However, a simple fix – exempting companies entering into corporate power purchase agreements (CPPAs) from the CfD levy – could help alleviate some of these risks.

Consulting on decarbonisation

The UK government is currently undertaking a major consultation on the future of the national electricity system, its Review of Electricity Market Arrangements (REMA). The process is intended to identify key policy changes to enable a “decarbonised, cost effective and secure electricity system”.

In this current REMA consultation, the government seems to be moving towards increasing its reliance on CfDs. First introduced in 2014, the CfD scheme involves generators bidding for long-term contracts with a government-owned company that, essentially, ensures they receive a guaranteed price for the power they produce. Potential reforms are being focused on this area, with ever-continuing expansion of the scheme envisaged.

However, there are considerable risks with putting all the UK’s eggs in the CfD basket.

The case for caution on CfDs

CfDs have helped underpin considerable growth in the UK’s renewables capacity, particularly in offshore wind. However, a CfD-dominated electricity system has a number of drawbacks for buyers, generators and the market as a whole.

Firstly, an increasing proportion of UK electrical generation will become effectively detached from the normal market forces of supply and demand. With their revenues already guaranteed by the government, CfD projects will simply sell their power at the prevailing spot market price. This means a decreasing proportion of generators will be willing to sell their power on a forward-hedged basis. This will increase volatility in market pricing, make it difficult and expensive for companies to find counterparties with whom to hedge their power purchases, creating greater uncertainty for buyers on what price they will have to pay for power.

Secondly, the costs of supporting this CfD roll-out will be socialised across all UK electricity market participants, no matter whether they have separately sourced their electricity from other electricity sources. The cost of the CfD scheme has the potential to grow greatly as more generation is subsidised, and as power prices return to historic levels. The cost of this scheme is both unpredictable and unhedgeable for corporate buyers.

Thirdly, for developers, the fixed nature of the CfD scheme means that renewable projects that do not align with its strict auction timetables and contractual constraints will find it hard to get built if they can’t get an alternative like a CPPA. This will have the overall effect of reducing the amount of renewables generation built across the UK.

Supporting the CPPA market

Corporate PPAs offer a complementary method to promote investment in UK renewable generation. For companies, signing a PPA can demonstrate a clear commitment to renewable energy, supporting the development of a specific generation project. They also have the advantage of providing the buyer with a stable source of physical renewable power at a fixed price for a long period of time, acting as a useful hedge against future price rises and enabling the company to secure physical green electrons.

However, as wholesale power prices fall from their peaks in 2022 and 2023, many corporate buyers are proving reluctant to enter into long-term PPA contracts. Citing the high price expectations of developers – who need higher prices because of the higher levelised costs of energy they face  – as a reason for not doing deals. What the market needs is additional incentives for companies to enter into CPPAs, otherwise the government will be forced to use CfDs to hit our green energy targets, resulting in the unintended consequences outlined above.

A potential solution that would help would be to exempt corporate PPA buyers from the costs of supporting the CfD scheme. This is one of the reforms that we proposed as part of REMA process. While most of those proposals seem to have been put on hold for now, this is a key reform we believe is worth exploring further.

Exempting CPPAs from CfD costs – and fixing a market distortion

Currently, electricity suppliers are subject to the CfD Supplier Obligation Levy, which funds any payments to generators under the CfD. Electricity suppliers pass the cost of the levy on to their customers.

The current application of the CfD Levy to all volumes supplied to an end user reduces the relative attractiveness of supporting projects with corporate PPAs. For example, a company that has committed to support a renewable generation project with a PPA will pay a fixed price for the power that it buys from the project. In addition, the company must also pay the CFD Supplier Obligation Levy on that power, to subsidise renewable generation projects from which it does not draw power. With a CfD levy, that could rise to more than £10/MWh, which creates a significant distortion in the all-in cost of power for a company buying directly from a project, as they also have to pay the CfD levy on this volume of power within their supply agreement. At its extreme, if a company bought all its power via a CPPA – as a hydrogen project would need to, for example – then this company is effectively supporting projects both directly via its CPPA and indirectly via the CfD levy.

The implementation of a CfD levy exemption should be relatively straightforward and could be enacted through a variety of mechanisms. One such option could be via the creation of CfD levy exemption in the same way that many industrial and commercial consumers are exempt from some Renewables Obligation and Capacity Market payments, and will soon be exempt from some network charges under the Network Charging Compensation Scheme. The exemption could be based on the proportion of a corporation’s total supply volume contracted under a CPPA.

To focus policy reform on incentivising additional renewables capacity, this CfD levy exemption could apply only to CPPAs linked specifically to new-build generation assets. Assets that are either operational or at a late stage of development can be judged to be already economically viable and thus do not require policy support.

Conclusion

It’s clear that an electricity system dominated by CfD-supported renewables has a number of drawbacks, socialising price and capture risk, shrinking the forward power market and reducing volumes available to corporate buyers. Growing the CPPA market could help fix some of these problems. As a falling market price challenges the economics of these deals, fixing the unfair application of the CfD levy is an achievable reform that can help to improve the relative attractiveness of CPPAs, further driving the sorely-needed development of additional UK renewables capacity.

6 minute read time

All change? What REMA means for the UK’s corporate PPA market

Zero-carbon power markets work very differently to those supplied by thermal power plants. While the end-product may remain the same, the operation, regulation, and related legal and contracting arrangements of wholesale markets need to be very different to take into account intermittency and the dramatically higher number of generating assets.

In recognition of this, the UK is undertaking its Review of Electricity Market Arrangements (REMA). This review, launched in July 2022, is intended to explore, among other things, how to decouple the system from gas prices, incentivise consumers to use more of their power when clean energy supply is abundant – and less when it’s not- , and increase the participation of flexible low-carbon technologies, such as batteries.

Kwasi Kwarteng, then Business and Energy Secretary, hailed REMA as “the biggest electricity market shake up in decades”. The government launched a consultation to consider a range of options for reforms covering wholesale markets, the balancing mechanism, ancillary services provision, the Capacity Market and contracts for difference (CfDs).

In March this year, the government released a report summarising the 225 responses it received to its consultation. It plans to undertake a second consultation this year – presumably on as-yet-unannounced concrete proposals – but has not provided a timeline for reform. However, in discussions with industry, the Department for Energy Security & Net Zero has suggested a number “intervention options”.

Some of the headline reforms include: splitting the wholesale market in two, with separate markets for firm and variable power; pricing based on location, replacing a single national power price; and a range of reforms to the UK’s Contracts for Difference (CfD) regime, which supports low-carbon generators.

A number of respondents to the consultation noted the potential of corporate power purchase agreements (PPAs) to provide an alternative to CfDs in underpinning investment in low-cost renewable energy capacity. The government is now considering what it could do to help stimulate the PPA market.

Below, we consider how some of these options could affect the market for corporate clean energy PPAs and give our initial thoughts – always bearing in mind that, for any market reform, the devil will be in the details.

Introducing standardised PPA contracts

For consumers of power, entering into PPAs can be complex and time-consuming. Contracts are typically bespoke, incurring legal costs and taking time to negotiate. By introducing standard PPA contracts, some consultation respondents argued that the government could reduce costs, increase liquidity and encourage the growth of the PPA market.

Our view is that introducing standardised contracts would be far from straightforward without allowing for some flexibility in key commercial terms. We know, from over fifteen years of experience in negotiating CPPAs, that developers and corporates want bespoke terms to address some of the contractual and commercial risks. That said, we do think it is possible to create contractual frameworks and to have standardisation of certain legal clauses across all PPAs. It really comes down to lawyers agreeing to standardised terms but as we know that would reduce the fees they could charge.

Government to provide guidance on striking PPA deals and creating a green power pool
It is unclear what the government is considering here in terms of guidance, or how this proposal would work.

On splitting the wholesale power market to create a green power pool, respondents to the survey warned it would create significant market disruption, and could undermine market confidence. Nonetheless, 47% of respondents supported the suggestions, versus 38% against. Our view is that the market can do this without any government intervention; as we move towards 24/7 clean energy it’s likely that we will see corporates paying a premium for green electrons.

Create a voluntary central contract register

Such a register could provide a means to benchmark transaction pricing which may lower price discovery and transaction costs. However, a lot of the important commercial information in such contracts is confidential, raising questions over whether counterparties would be willing to share useful information. In addition, the unique characteristics of a project and its LCOE mean it is hard to compare project pricing without detailed project information. This proposal is therefore likely to be of limited impact.

Government to underwrite PPA contracts
A big challenge for PPA sellers is that, in long-term PPA contracts, they are exposed to the credit risk of the buyer – and, for any but the largest of corporate buyers, this risk can be considerable.

The idea here is the government provides a ‘credit wrap’, making the seller good in the event of default. Similar schemes are underway in Norway and Spain. The challenge is that it puts the government in a position where civil servants are having to make individual credit decisions on specific corporates. A better option might be to set up, or contract out to, a specialist credit insurer that operates with government support. Nonetheless, we remain concerned that, while such an approach could support the growth of the PPA market, it would socialise risk, and potentially lead to poor decision-making.

Give preference to CfD sellers with merchant PPAs

It is unclear how this proposal would work but, potentially, it could encourage PPA supply by favouring those generators seeking CfDs from the government which have already entered into PPAs for some of their output.

However, we see serious difficulties in designing this, in particular in its interactions with the existing auction process. It would risk creating preserve incentives, for example encouraging bidders to enter into PPAs to deliberately game the process.

Similarly, we are sceptical about the value of allowing private buyers to bid into the government CfD auction. It would add to the risk taken on by the government, which we don’t believe would be worth it for the limited positive impact it would have.

Allow PPA buyers to avoid CfD costs

Every electricity supplier is subject to the Supplier Obligation, a levy that funds payments to CfD generators when wholesale power prices are below CfD strike prices. This spreads the cost of the CfD (which effectively subsidises renewables) across the market in proportion to the power sold.

However, it can be argued that buyers entering into clean energy PPAs with new-to-ground generation are already directly supporting renewables, by helping to increase the volume of renewable energy capacity in the system. We believe they shouldn’t have to pay twice and, as such, Squeaky put forward a proposal that buyers who enter into corporate PPAs be exempted from some CFD costs. If, as is quite possible, this levy rises above £10/MWh, its exemption could make a material difference to the economics of PPAs.

There will be various factors that need to be carefully considered, such as how much of the Supplier Obligation they would be exempted from, how to tackle PPAs entered into with existing (non-additional) generation, etc., but there is clear merit for the government to consult on this.

Devilish details

There are other proposals for which the information provided is, at this point, insufficient to pass initial judgement on, such as proposals for reforms to the Renewable Energy Guarantee of Origin system. Equally, a suggestion that suppliers could be obliged to offer competitive sleeving arrangements, helping to bring down the cost of credit risk management, has potential, but needs more consideration – this is an issue we will return to in a future blog.

Overall, we are encouraged to see the government engaging seriously with promoting the PPA market. We believe it will need to play an important role in supporting the necessary growth of the UK’s renewables sector – the CfD alone simply cannot do all the heavy lifting needed. But any reforms will have to be carefully considered and, to the degree possible, should allow the market to operate as efficiently as possible.

5 minute read time

Accounting for Power Purchase Agreements (PPAs) – a quick guide

Power purchase agreements (PPAs) are complex products and understanding the correct accounting treatment for them can be difficult.

How PPAs are dealt with for accounting purposes can significantly impact corporate balance sheets and profit and loss (P&L), potentially introducing volatility into company earnings.

This short blog outlines some of the key approaches and tests to consider when looking at PPA accounting from the point of view of a PPA off-taker. It also includes some useful links and various guidance documents from across the industry.

It likely goes without saying, but this guidance – as detailed as some of it is – is no substitute for professional advice.

Introduction

Assuming the customer does not have control over the project supplying the power, there are essentially three ways to account for a clean energy PPA. To decide on the appropriate approach, accountants will follow a decision tree – as per the graphic below.

The first question is to ascertain if the contract can be interpreted as a lease, thus falling under leasing accounting, as set out in the IFRS 16 accounting standard.

Whether or not it contains a lease, some PPAs are considered to be financial instruments. This means that they need to be accounted for under derivative accounting (IFRS 9).

If none of these criteria are met, the PPA falls under executory contract accounting (IAS 37). This is the most straightforward and preferable accounting treatment.

Now let’s look at which accounting standard is likely to be most appropriate, and their respective pros and cons.

Lease accounting

A lease is defined by IFRS 16 as a “contract or part of a contract that conveys the right to use an asset for a period of time in exchange for consideration”.

A contract is treated as a lease if:

  1. there is a specific asset identified;
  2. the customer purchases substantially all the output of an asset;
  3. the customer has the right to direct how and for what purpose the asset is used throughout the period of use.

Determining the final criteria requires careful consideration of the contract terms, but typically for a PPA that has predetermined operation (e.g., no right for the customer to impose curtailment), the test for a right to direct use comes down to whether the customer operates the asset itself or has been involved in the asset’s design.

The implications of lease accounting treatment are that, if a PPA is accounted for as a lease, it must be recognised as a right-of-use asset and appear as a liability on the balance sheet. Such accounting can have significant impacts on the offtaker’s financial statement, EBITDA and debt-to-equity and interest cover ratios. This, in turn, can have impacts on debt covenants and management incentive schemes.

Derivative accounting

Whether the PPA implies a lease of the assets or not, the next stage is to consider whether it effectively incorporates a derivative. If it does so, accounting rules usually require these embedded derivatives to be accounted for as if they were a free-standing contract.

Determining if a host contract contains an embedded derivative can be challenging. One indicator is that its value is based on an underlying variable (e.g., electricity prices). Others include the contract requiring no (or a relatively small) initial net investment, and that it is settled at a point in the future.

If the PPA is considered a derivative, it falls under IFRS 9, and must be fairly revalued in every reporting period, with any changes to its value recorded as a profit or a loss. This can introduce volatility into the offtaker’s P&L, even though there may be no actual financial impact (because any ‘loss’ on the PPA would be balanced by an offsetting ‘profit’ in the offtaker’s actual electricity bill).

Own-use exception

However, an exception from IFRS 9 accounting may be applicable if the purpose of the PPA contract is to directly provide electricity for the customer’s use. This would allow for the PPA to be treated as a normal course executory contract (see below).

The conditions to qualify for the own-use exception are particularly strict, requiring actual physical delivery and consumption by the customer of all electricity purchased under the contract. This requirement rules out all virtual PPA structures, as well as physical PPAs where there is net settlement, or any sale of excess generation.

Very careful consideration of the requirements is necessary before applying the exception. The IFRS is currently undergoing a process to amend the standards relating to the application of the own-use exemption, having accepted in June 2023 that the current requirements do not provide an adequate basis to determine the appropriate accounting for certain PPA scenarios submitted to it.

Hedge accounting

If the PPA doesn’t qualify for an own-use exemption, there is another accounting treatment option. If certain conditions are met, a PPA can be designated to be in a cash-flow hedging relationship and can be accounted for as other comprehensive income. This results in lower volatility in P&L from the recognition of changes to the PPA’s fair value.

An important requirement for designation as a hedging instrument is for the hedged item to be highly probable in all cases, and therefore there may be some effectiveness from the hedge. Assessing the correct application of the highly probable criteria requires thorough consideration by professional advisors.

Executory contract accounting

If the PPA does not contain a lease nor a derivative, it can be accounted for as a regular supply contract, where expenses are included in the income statement based on the costs attributable to the power delivered to, and consumed by, the off-taker in its course of business.

Under this treatment, the PPA is accounted for using IAS 37. This is the most preferable treatment for corporates, as it avoids the significant balance sheet impact under lease accounting, or the increased P&L volatility under IFRS 9 accounting.

Summary

Accounting for PPAs is by no means a simple task. The links below provide more in-depth information and advice, but careful consideration by professionals is necessary to ensure the correct treatment. If you’d like further information on this pretty complex area then please do reach out to the team at Squeaky.

IFRS accounting outline for Power Purchase Agreements (WBCSD)

https://www.wbcsd.org/Programs/Climate-and-Energy/Energy/REscale/Resources/IFRS-accounting-outline-for-Power-Purchase-Agreements

Accounting for Green/Renewable Power Purchase Agreements from the Buyer’s Perspective (PwC)

https://viewpoint.pwc.com/dt/gx/en/pwc/in_depths/in_depths_INT/in_depths_INT/Accounting-for-Green-Renewable-Power.html

Energy Transition: lease considerations for Power Purchase Agreements (EY)

https://www.ey.com/en_gl/ifrs-technical-resources/energy-transition-lease-considerations-for-power-purchase-agreements

Accelerate Accounting for Power Purchase Agreements (Deloitte)

https://www2.deloitte.com/content/dam/Deloitte/de/Documents/energy-resources/Accelerate-Accounting-for-Power-Purchase-2022.pdf

Application of the “Own Use” Exemption for IFRS 9 (IFRS Amendment Process)

https://www.iasplus.com/en/meeting-notes/ifrs-ic/2023/june/ifrs-9

https://www.ifrs.org/projects/completed-projects/2023/application-own-use-exception-physical-power-purchase-agreements/#current-stage

6 minute read time

13 Power Purchase Agreement (PPA) terms explained

In common with most technical fields, the world of power purchase agreements (PPAs) is shrouded in a thick cloak of jargon. To make matters worse, the same concepts often have different terminology attached, particularly across different jurisdictions. This short guide explains some of the key PPA terms we use at Squeaky, alongside some of the other names by which they are referred to by others in the industry.

Route-to-market or market-access PPA

In a route-to-market PPA, a generator agrees to sell the output of a facility referenced to the prevailing market price (as quoted on an exchange such as N2EX or EPEX). These are also known as market-access PPAs and are predominantly offered by utilities or aggregators. They typically include a discount to the market price, in exchange for services including registration of the meter within the system (which requires a supply license), forecasting, balancing and physical trading.

Pay-as-produced or as-generated PPA

In a pay-as-produced (PaP) PPA, the offtaker buys all power produced by the facility, by each half hour in the UK, typically for a fixed price. These are also called as-generated PPAs.

Baseload PPA

In a baseload PPA, the offtaker buys a constant volume of power for a specified period (annual, seasonal or monthly) over the term of the agreement, typically for a fixed price. These are also known as firm PPAs, although firm PPAs can be firmed to peakload or other shapes, to match the demand profile of the buyer.

Shape or profile risk

This risk, which is sometimes referred to as profile risk, is where the profile of a facility’s power production does not align with the demand profile of the end user. This might be due to the nature of the technology (solar generators produce most power in the middle of the day) or due to the inherent variability of renewable energy generation. While it’s possible to predict the overall output of intermittent technologies over a longer timeframe, short-term generation can significantly fluctuate due to weather conditions.

Volume risk

Sometimes conflated with shape risk, which is an inter-temporal mismatch of generation and demand, volume risk relates to greater or lesser generation than expected over a period of time (typically annually). In a pay-as-produced PPA, generation greater than expected can result in an excess quantity of power for the offtaker, whilst lower-than-expected generation would result in the offtaker receiving less power than anticipated.

Capture risk

This risk, which is driven by shape and volume risk, pertains to the variability and unpredictability of generation by intermittent energy facilities and the price that is ‘captured’ by the facility compared with the average firm market price over the same period. Capture risk is a key consideration that affects both generators and pay-as-produced PPA offtakers. For generators, capture risk influences the revenues they earn. Offtakers, meanwhile, may end up paying for power at a predetermined fixed rate which is delivered at times in which the market price is lower.

Capture rate

Dividing the capture price for a facility by the firm (baseload) market price gives the capture rate. This is also sometimes known as an asset’s quality factor. The capture rate for a particular renewable generation facility will vary over time and depends on the measurement period. It is primarily driven by the type of renewable technology. Influencing factors include:

  • Daily variation in generation. Solar facilities only operate during the day, when prices are typically higher than at night, increasing the capture rate of a solar facility.
  • Inter-seasonal variation in generation. Roughly 75% of annual generation of a UK solar facility occurs during the summer, when power prices are generally lower than the winter, therefore reducing solar facilities’ capture rate over a year. By contrast, wind generation is typically winter-weighted.
  • Cannibalisation risk (see below).

Cannibalisation risk

An increasing proportion of wind and solar generation on the grid will reduce the capture prices for those technologies. Within any grid that covers a limited geographical area, such as the UK, generation of one wind facility is likely to be correlated with other wind facilities. Similarly, solar facilities all generate power in the same pattern when the sun is shining. Therefore, during periods of high generation for one facility, the grid will tend to have an excess of supply, driving down prices. By contrast, market prices would likely be higher at times the facility, and facilities using the same technology, are not generating. As a growing volume of similar renewable energy technologies are added to a grid, the net impact of these effects can be to significantly reduce the value they can capture from the power they sell – hence the term cannibalisation.

Balancing risk

Balancing risk represents the risk that a facility’s actual output will be different to its next-day forecast generation. This can lead to the system operator charging its operator penalty fees. For a wind or solar generator, managing the balancing risk can either be done by setting up trading arrangements to manage it in house or, more typically, is outsourced to an intermediary via a route-to-market PPA, in exchange for a balancing discount from the contract reference price. Route-to-market PPAs contracts typically deliver around 95% of the reference price, while a system price contract that does not include any balancing discount would typically deliver 98-99% of the reference price.

Basis risk

This term is often used to describe mismatches in energy supply and demand. However, within the PPA market, it describes the mismatch between the reference price within a PPA and the actual prices to which contract participants are exposed. Mismatches could, for example, be found in a power market with zonal pricing, such as the US, where a virtual PPA is struck against an index (like Ercot) but the consumer buys physical power priced against a different index. In the UK, a contract for difference (CfD), which is settled against the Intermittent Market Reference Price (calculated using day-ahead data from EPEX Spot and NordPool), combined with a route-to-market PPA settled against N2EX, is exposed to basis risk.

Firming, shaping or shaping and balancing

Firming, often referred to as shaping, or shaping and balancing, is the conversion of as-produced power generation (as per a PaP PPA) into firm power (typically baseload), thereby eliminating shape, volume, capture, and balancing risks for the offtaker.

Availability

Availability is a key metric measuring a facility’s operational performance . It is typically calculated as a percentage, representing the total volume of electricity a facility is able to produce at a point in time, divided by its contracted capacity. This is a mechanical availability and doesn’t take into account weather conditions or other factors such as grid constraints, etc. It is usually covered by a manufacturer’s warranty and is also impacted by regular maintenance of the facility. Mechanical availability typically falls over time, due to the degradation of physical assets.

Contracts for difference

A CfD is a financial mechanism to stabilise the revenues a facility generates. In the UK, generators are invited to bid a strike price which they are prepared to receive to sell power. If the market price for that power is below that strike, they receive payments from the Low Carbon Contracts Company (LCCC), a government-owned entity. If it is above the strike, they agree to pay the difference to the LCCC. This is referred to as a two-way CFD, as opposed to the one-way CFDs common in Germany, where a generator is guaranteed a minimum level of revenue, but retains additional revenue if wholesale market prices exceed the CFD strike price. CfDs are settled against a market index (in the UK a combination of indices) meaning a generator either needs a route-to-market PPA, or needs to manage forecasting, balancing and trading the power themselves.

Squeaky scores another UK first with innovative solar power agreement for Britvic and Atrato

Squeaky Clean Energy, the UKs leading PPA marketplace, has secured another first by closing an innovative PPA for Britvic, the FTSE 250 global soft drinks business, and Atrato Onsite Energy (Atrato), a leading solar energy provider.

The innovative 10-year Power Purchase Agreement (PPA), developed by Squeaky whose founders were early pioneers of corporate PPAs in the UK in 2008, enables Atrato to supply Britvic with solar electricity that is commercialised on a pay-as-you-generate basis but is delivered as a baseload contract that matches the consumption needs of the company and can be sleeved into Britvic’s existing supply arrangements.

Atrato’s new solar installation in Northamptonshire will generate energy exclusively for Britvic. It will have a total capacity of 28MW and will be capable of generating 33.3 GWh pa of clean energy, the equivalent of powering 11,500 homes or planting 260,000 trees. The electricity generated will be enough to power 75% of Britvic’s current operations in Great Britain, including its Beckton and Leeds factories, which can produce 2,000 recyclable bottles per minute.

The contractual framework provides the investment security needed by Atrato to build the new solar farm in an old quarry in Northamptonshire. This will see new additional renewable energy capacity developed supporting Squeaky’s mission to accelerate the world’s transition to clean energy. Atrato has fully financed the solar installation, which is expected to be commissioned in early 2024. In only 19 months since IPO, Atrato has built a portfolio of 40 solar sites across the UK.

Britvic has committed to achieving net zero carbon emissions by 2050 and has led the industry as the first UK soft drinks company to have a 1.5°C target verified by the Science Based Targets initiative. Britvic has demonstrated its commitment to this goal, having reduced its direct carbon emissions by 34% since 2017 and generated 57% of its energy needs from renewable sources in 2022, up from 28% in 2018 .

Chris Bowden, Managing Director of Squeaky Clean Energy said:
“Having pioneered the use of corporate PPAs in the UK it has become abundantly clear that new and innovative contracting structures are needed to accelerate the transition to clean energy. We are incredibly proud to have scored another first with a unique PPA arrangement that enables Atrato to de-risk the financing of its project and Britvic to deliver on its Healthier People, Healthier Planet sustainability mission.”

Matt Swindall, Chief Procurement Officer at Britvic says:
“This deal represents a significant milestone for Britvic as we continue to partner with home-grown renewable energy projects to power our business. The 10 year deal also establishes stability, enabling us to plan more efficiently over the coming years. In short, it’s great for our Healthier Planet sustainability ambitions, and great for the business.”

Matthew Philips, Britvic’s Senior Category Manager for utilities, led the project. He said:
“This is a ground-breaking achievement for Britvic, and I am extremely proud of everyone involved. Our Healthier People, Healthier Planet sustainability strategy is a critical commercial driver for us, and nothing demonstrates this more than our factories and warehouses being powered by clean, green, domestic renewable electricity to produce the iconic quality brands that consumers love.”

Gurpreet Gujral, Managing Director and Head of Renewable Energy at Atrato said:
“We are thrilled to enter into this new corporate PPA with Britvic. This highly innovative PPA structure provides Britvic with a consistent source of renewable energy that matches their electricity needs. This project exemplifies our commitment to providing long term and attractively priced clean energy to our clients. Following an award-winning IPO, Atrato has become the ‘go to’ corporate clean energy provider.”

Ross Fairley Head of Renewable Energy at Burges Salmon said:
“We are really pleased to have been asked by Atrato to advise on this corporate PPA. We have been involved in developing the different corporate PPA models from the early days and this is a further innovation which will help renewable generators and those corporates working towards Net Zero.”

ENDS

7 minute read time

The unintended consequences of negative power prices in the UK

Large volumes of renewable power capacity with rock-bottom marginal costs can push modern power grids into negative pricing. On windy days, the design of the UK’s CfD system could send prices spiralling deep into negative territory.

I noted in our recent blog on Contracts for Difference (CfDs) that generators in the UK are not paid a top-up to their strike price in a negative price period (NPP). This is defined as six consecutive hours in the day-ahead auctions for contracts from Round AR1 to AR3 when the auction clears below £0/MWh, or just one negative hourly price for AR4 contracts.

So far this hasn’t materialised as a major issue. But, unless the overall provisions of the CfD are amended in future rounds, dysfunctional behaviour and outcomes seem inevitable as new CfD generation comes online, and if legacy wind and solar is transferred to CfDs with the same provision.

Why is this? In practice, the marginal cost of production of wind and solar photovoltaic generators is slightly below zero, because there is some cost, effort and risk in shutting down; generators would rather pay a small amount for their power to be disposed of than to shut down. If Renewable Energy Guarantees of Origin (REGOs) are taken into account, any disposal costs for surplus power can be netted against the revenue from sold REGOs. So, in theory, CfD generators should be prepared to offer volume into the day auction at slightly below £0/MWh.

However, they’re very unlikely to actually offer below this level, as there is a risk of creating an NPP for their own CfD. This would mean they would receive no payment under the CfD. They will therefore offer at exactly £0/MWh out of commercial self-interest, and a recognition that their offers may contribute towards the auction clearing price. If they offer at £0/MWh or above, they know they can’t be responsible for creating a negative price; by definition, all the bids in the auction would have to be matched by offers below their price, at negative prices. Conversely, if they do offer below £0/MWh, they may well influence the auction to clear at a negative price – either at their own offer price, or just above. This means that we can expect CfD generators to offer into the auction at precisely £0/MWh, regardless of conditions.

Incentives to go to zero

The likely consequence of this is that there will be a strong gravitation of auction clearing prices to exactly £0/MWh.

When the market clears at a particular price – £0/MWh in this case – the auction operator will scale back either bids or offers, depending on whether there is more bid or offer volume submitted at that price or better.

As an example, suppose in an auction there are 2,000MW of bids and 4,000MW of offers placed at exactly £0/MWh for hour 1, as well as 25,000MW of bids above £0/MWh, and 24,000MW of offers below £0/MWh. Then all bids priced at £0/MWh or above will be satisfied in full, and all offers below will be satisfied in full too. But any offers at exactly £0/MWh will have to be scaled back to make the total volume of accepted bids and offers equal. The auction clearing volume will be 27,000MW, and all bids at £0/MWh or above will be satisfied at £0/MWh. All offers below £0/MWh will also be satisfied at £0/MWh; but only 3,000MW of the zero-priced offers can be matched with bids – therefore all offers at £0/MWh will be scaled back to 75% of the volume offered.

This means that, if it is windy, CfD generators will offer their forecast volume at £0/MWh in the auction, and will often succeed in selling some, whilst keeping the clearing price at £0/MWh, and preserving their CfD payment.

But they will now have some unsold potential generation output, which they will be keen to produce and sell (because it will be eligible for a CfD payment). Once the auction is over, the generator’s indifference price suddenly switches from just below £0/MWh to just below minus their CfD strike price.

Why is this? If, for example, their CfD strike price is £75/MWh and the auction clears at £0/Mwh, they will be eligible for a £75/MWh CfD payment on all output. They’ll also still get a REGO and face unwanted cost and risks if they do shut down. So, if they have to, they should be prepared to sell all remaining unsold output at just below -£75/MWh, knowing that the CfD payment and REGO will offset the cost of disposal.

The emergence of the Minus Strike?

What will that mean?

In these circumstances, the post-auction price will tend to crash after the auction towards exactly negative one times the most active CfD strike prices – let’s call this the ‘The Minus Strike’ level.

Speculators will be tempted also to offer volume into the auction at £0/MWh, hoping to sell some successfully (scaled back) and carry a short position into the day. They may even be tempted to offer into the auction a little at below £0/MWh, to avoid scaling back – although not too much, or too negative, as they won’t want to accidentally create a negative clearing price and make wind farms willingly turn off. Any volume they successfully sell at £0/MWh they will then look to buy back just above the Minus Strike level.

The more volume that gets offered at £0/MWh by wind generators in windy conditions, the greater the scaling back. Generators will observe the effect and deliberately offer more volume than they can generate. Speculators will offer more and more, knowing scaling back will be severe. There is no clear way to stop this upward spiral and, where there is a regular outcome, tens of gigawatts could be offered at £0/MWh in the auction, with more and more severe scaling back. Perversely, less and less volume may actually clear in the auction, as buyers may prefer to wait to buy below £0/MWh within the day.

Generators may be tempted to sell volume bilaterally in advance of the auction, but they will be wary that the buyers of that volume don’t offer the power back into the auction at negative prices. It’s therefore most likely that generators with CfDs will hold back until the auction, and offer at exactly £0/MWh.

It shouldn’t happen all the time. There are situations where a £0/MWh clearing price won’t occur. For example, there has to be a clear overhang of CfD generation compared to demand for it to materialise – but with plans to install over 100GW of CfD generation in the coming years, that will inevitably occur more and more frequently.

A nuance of the auction mechanism is that someone has to bid £0/MWh for at least one megawatt of capacity, or the auction will probably not clear at exactly that level. (If no one bids to buy at exactly £0/MWh, the most likely result is that the auction actually clears above £0/MWh, with offers at £0/MWh partly “paradoxically rejected” and scaled back just as they would have been at a clearing price of £0/MWh). The full range of auction tools, such as linked bids and offers, may also occasionally cause different results.

Prices can and probably will occasionally fix below zero which means the headline rate of the CFD will actually be lower; there are some forecasters that believe this could be as much as 5%, so a headline CfD rate of £80/MWh would actually deliver at £76/MWh.

Things may improve eventually when large-scale energy storage arrives in the form of hydrogen electrolysis, rebalancing supply and demand somewhat. But even an economically optimised grid is likely to have policy planned curtailment levels of 15% or more to ensure sufficient capacity is available, so times of surplus wind power will still occur.

Heading off dysfunction

Overall, it seems very likely that a dysfunctional pattern will occur during windy weather where prompt over-the-counter power prices are slightly negative, the auction clears at exactly £0/MWh, and post-auction spot prices trade at deeply negative numbers. This will lead to increased balancing costs for generators further reducing their net revenues and undermining the energy transition.

What’s the solution? It must lie in a change to the terms set out in forthcoming rounds of CfDs. If there is too much concentration of wind farms doing the same thing in response to the same incentives, there will be no moderating influence.

So, in response, the government could amend the terms of future auction rounds to change the definition of NPPs so that, below a low number above £0/MWh, no top-up payment is received. Or, that at exactly £0/MWh, only a scaled back proportion of output will receive a top-up payment, in line with auction oversubscription. That said any changes to the rules may create uncertainties over the revenues of projects that get a CfD.

There are many other alternatives, but policy makers need to start working on a remedy before NPP gaming materialises as a problem. They can’t be caught napping with a sub-optimal support instrument, as they have been with biomass CfDs.

7 minute read time

Understanding the evolution of the PPA market

Power purchase agreements (PPAs) are a fundamental building block for most renewable energy projects. Understanding how they’ve evolved can help buyers and sellers navigate their idiosyncrasies and challenges.

PPAs have been in existence almost as long as commercial power generation: contracts by which a generator sold power to a utility or an industrial user date back to the early 20th century. Since the power markets liberalised in the 1990s independent generators that weren’t signed up the BSC would enter in a route-to-market PPA to be able to sell their power to a third party.

First, why use a PPA?

In my previous blog, we discussed contracts for difference (CfDs), which have emerged as the favoured government-backed support mechanism for renewables in a growing number of countries. However, CfDs don’t work in isolation. A generator must enter into a route-to-market PPA to ‘enable’ a CfD.

In the UK, only registered entities can connect generation to the grid. Most generators will therefore need to enter into a route-to-market PPA with a utility such as EDF or Engie, or aggregators like Statkraft or Axpo.

Under the old Renewables Obligation Certificate (ROC) regime, route to market PPAs were used to monetise the value of ROCs – the PPA providers would offer to pay a percentage (typically in the high 90s) of the ROC value. The discount on ROCs is driven mainly by the cost of money as the PPA provider would pay for ROCs monthly but sell them annually. As the price of ROCs was fixed each year and then inflated annually in line with the Retail Price Index (now the Consumer Prices Index) these ROC revenues typically underpinned most of the investment in a new project.

The power was also sold, typically under the same arrangement, at a similar percentage of the market index (e.g. N2EX or ICIS hourly day ahead prices). The discount on the power price is driven mainly by the balancing risk between the system price and the chosen market index. Sometimes, these route-to-market PPAs have floors which provide further downside protection for a project’s cash flows, or they have fixing provisions that allow generators to fix power prices several months or seasons ahead.

The inherent risks of these route to market PPAs are the exposure to wholesale power prices, exposure to the capture risk, and a contract pricing risk when fixing – meaning that when the developer comes to fix its power with the PPA provider it has no option but to sell the power at the price offered by the utility, which can often be at a significant discount to the forward market. In addition, these route to market PPAs quite often have limits to how far out a generator can fix the power (typically four or six seasons ahead).
In response many generators sought alternative options for selling their power which drove the development of the corporate PPA.

A brief history of Corporate PPAs

The first CPPA in Europe was arranged by Utilyx in 2008 for the supermarket Sainsbury’s. Under the terms of the transaction Sainsbury’s agreed to purchase all of the electricity generated by a 6MW wind farm in Scotland for a period of 10 years. The wind farm was built by A7 Energy, and Sainsbury’s purchase of the electricity helped to make the project financially viable. Since then, a growing number of companies have followed Sainsbury’s lead and signed CPPAs with renewable energy generators.

The initial uptake of CPPAs was slow, as many companies were hesitant to sign long-term contracts for electricity. However, as the cost of renewable energy has fallen in recent years, more and more companies have seen the benefits of CPPAs. By 2016, the number of CPPAs signed by corporations had reached 100, and the total capacity of the renewable energy projects covered by the agreements had exceeded 10 GW.

By 2020, over 300 corporations had signed CPPAs, covering over 28 GW of renewable energy capacity. The largest CPPA signed to date was by Amazon, which agreed to purchase 1.5 GW of wind and solar power from several different projects. The deal was part of Amazon’s commitment to reach 100% renewable energy by 2025.

CPPAs offer a number of benefits to both corporations and the environment.

For corporations, signing a CPPA can provide a stable source of renewable energy at a fixed price for a long period of time. This can help to reduce the corporation’s exposure to volatile energy markets and provide a hedge against future price increases. In addition, CPPAs can help corporations to meet their sustainability goals and reduce their carbon footprint, which can be an important factor for customers and investors.

For the environment, CPPAs can help to drive the development of renewable energy projects by providing a stable source of revenue for generators. This can help to increase the amount of renewable energy on the grid and reduce the amount of electricity generated by fossil fuels. In addition, CPPAs can help to reduce greenhouse gas emissions, which can have a positive impact on the environment and public health.

There are broadly two types of CPPA

Sleeved/physical PPAs

Although corporate PPAs nominally involve selling power to a corporate or utilities, other power traders are still involved as only market participants can register meters and transfer power through the system. Furthermore, because wind and solar projects generate power intermittently, this creates ‘shape risk’, whereby the power generated does not match the buyer’s demand profile. In a sleeved PPA, the generator supplies the physical power as generated to a utility that, for a fee, supplies the corporate buyer with power at its site(s) in line with its demand.

Sleeved PPAs typically involve the utility providing a number of services in addition to managing issues around intermittency, such as managing the generator’s balancing costs and transferring the REGOs. The contractual framework also maintains the relationship between the corporate and its utility provider. Conversely, it can make it more difficult for the corporate buyer to change supplier over the lifetime of the PPA if the supplier is locked into the arrangement, or it can cause problems if the supplier decides they do not want to provide the sleeving services or will only provide them at a very high cost to the corporate.

Virtual PPAs

An alternative approach is known as the ‘virtual’ PPA. These purely financial contracts are essentially CfDs, by which the generator and the buyer exchange cash flows based on a strike price referenced to a particular power market index. The generator will sell power under a route to market PPA at a discount to its chosen index and the buyer will enter into a VPPA based on this index at an agreed strike price.

If the price is higher than the strike, then the generator will pay the buyer. But if it’s lower, the generator is paid by the corporate buyer. This provides both buyer and seller with a level of price certainty.

The key advantage of a VPPA is that the generator and corporate buyer do not need to be in the same power market. The structure was developed in the United States, which has a number of regional power markets with limited transmission of power between them. They have been used in the UK by companies with US parents, often simply because they are the structure with which they are most familiar. However, they are also used in Europe, allowing PPAs to be struck by counterparties in different power markets. VPPAs are particularly attractive to buyers with electricity loads distributed over numerous sites.

VPPAs can, however, introduce their counterparties to several risks. If the VPPA isn’t indexed to the same price as the generator’s route to market PPA, then there’s a ‘basis risk’, which results from differences in power prices across different markets. If prices are lower in the generator’s wholesale market than in the reference market, it may not be fully compensated for the payment it makes to the buyer. Conversely, a buyer may find that it is paying a greater spread above the VPPA strike price for its physical power than it is receiving from its VPPA counterparty.

The other risk for the generator is the balancing risk which also needs to be factored into the overall revenue stack. If the VPPA strike is £70/MWh plus CPI over 10 years this has to be adjusted down for the index discount for the next 10 years on the route to market PPA. If this isn’t fixed, which can be very expensive, then the project has a residual risk to floating power prices.

On the buyer side they are exposed to the capture risk; the VPPA payment is typically settled against the weighted value of the power generated under the generator’s route to market PPA. The buyer however is typically exposed under their supply contract to baseload power prices so there is a mismatch “capture price basis risk” between the buyer’s cost of power and the value of the VPPA.

Because VPPAs are financially settled contracts this risk can be very hard to manage, particularly in markets which are largely physical like the UK. They can also be considered derivatives for accounting purposes, requiring that they are regularly marked-to-market.

Where we go from here

Hundreds of corporate PPAs have been struck around the world in the last two decades. Despite this, they remain bespoke contracts, which are often expensive and time-consuming to negotiate. Within them, buyers and sellers alike face numerous, often complex risks, which are not always understood nor easily managed by the counterparties involved.

In our next blog, we will consider some of these risks, how (and by whom) they are best managed, and how the PPA can be reimagined and improved.

11 minute read time

The pros and cons of contracts for difference

CfDs have proved effective in incentivising renewables investment and providing price certainty during the energy crisis. But how they move risk and cost around the system could hinder the net-zero transition.

Contracts for difference (CfDs) have become the policy tool of choice for incentivising the deployment of renewables in Europe. They offer generators a guaranteed level of revenue, reducing their risk. In exchange, they involve payments from generators to government if power prices rise above that strike price, reducing their cost. And they tend to be offered through competitive auctions, helping to drive down the price at which they are struck.

In the UK, CfDs already auctioned by the government will, by 2030, cover some 30GW of renewable energy generating capacity in the UK, mostly offshore wind. The government plans to conduct auctions on a twice-yearly basis to contract additional capacity as part of its goal to reach 80% wind and solar energy by 2035.

The exact contribution that the CfD mechanism will make to these targets is currently unclear: it will depend on the degree to which capacity can be built without recourse to government support. However, as we have seen, it appears likely that considerably more CfDs will need to be struck for the UK to meet its climate goals – implying a significant transfer of risk in ways that could undermine the efficiency of the system.

How CfDs work

CfD contracts do not involve the actual sale of physical electrical output, which the generators themselves still need to arrange. They are purely financial instruments which provide cashflows between the government-owned Low Carbon Contracts Company (LCCC) and the generator aimed at providing predictable revenue per unit of power generated.

To date, CfDs have been offered to generators based on the results of four competitive auction rounds (AR1 to AR4). These involve generators competing for the strike price they are prepared to accept. The Initial Strike Price in the auctions is quoted in ‘2012 money’, but the contract is then indexed in line with the Producer Price Index (PPI) to take inflation into account, to form the Adjusted Strike Price for each contract year.

Once in operation, a cashflow takes place each month between the generator and the LCCC equal to the output generated times the difference between the Adjusted Strike Price and the Reference Price – which tracks wholesale power prices – for each hour during the month. (CfD Payment = (ASP – RP) x Output).

There are two types of CfD contacts, Baseload and Intermittent. These are offered respectively to ‘reliable’ generators (such as those using biomass, geothermal or nuclear technology) and ‘intermittent’ generators (using solar PV, wind or tidal assets).

The main difference between the two types of contract is the calculation of the Reference Price.

For Baseload CfDs, the Reference Price is set six-monthly: it is the market price for the forward six-monthly season baseload contract, as quoted during the sixth month prior to delivery. For example, the Reference price for all delivery periods from 1st April to 30th September 2023 inclusive is the forward market price for Summer 23 baseload, averaged over all working days between 1st October 2022 and 31st March 2022.

For Intermittent CfDs, the Reference Price is set hourly: it is the weighted average of the settlement prices for the two day-ahead auctions, run by the N2EX and EPEX power exchanges, for the relevant hour.

A growing risk

The number and size of active CfDs is increasing, and the proportion of national energy demand covered by CfD-supported production is set to grow – particularly when the Hinkley C nuclear power plant comes online, which is currently expected in 2027. At present, around 10% of national demand is covered by CfD-supported generation. This figure is likely to grow steadily to 50% or more, dependent on government choices for a net-zero grid.

One additional feature of the CfD regime is that generators have some optionality on when to activate or ‘trigger’ their CfD; and a low penalty if they decide never to do so. Moray East and Triton Knoll are examples of wind farms that are active and could trigger their CfD but have elected not so far. Eventually they will reach a ‘long stop date’ at which point they must either trigger or lose the CfD contract.

Generator CfD hedging

CfDs are designed to allow generators to recover net revenue equal to the Adjusted Strike Price for all their output. They do this by selling their actual output in a way which mimics the calculation of the Reference Price as closely as possible.

Intermittent generators forecast their output for each hour at the day-ahead stage and aim to sell that amount of energy into the day ahead auctions. As long as they have forecasted output correctly (and sold in each of the two auctions – N2EX and EPEX auctions are at different times – in the correct proportion) they will collect from the sale of their power an average price equal to the Reference Price for that hour: Physical sale revenue = RF x Output.

Adding the CfD payment/receipt makes the overall net revenue equal to the generator’s output times the Adjusted Strike Price: (RF x Output) + (ASP – RP) x Output = ASP x Output.

In this situation, the generator will be left with a very predictable de-risked revenue stream, which is affected primarily by the inflationary indexation of the strike price, and by volume risk related to the variability of weather.

In entering into CfDs, consumers – via the LCCC – have absorbed the two main market risks faced by generators, namely wholesale price risk and capture risk. Capture risk is particularly acute for renewable energy generators, which are exposed to structurally lower prices if large volumes of new, low-cost wind or solar generator comes on stream. The LCCC, meanwhile, hedges this risk via the CfD levy – a premium charged by suppliers on all consumer bills, including those of industrial and corporate buyers – effectively ‘socialising’ this cost.

The other markets risks that remain with the generator are the balancing risk and the regime around “Negative Price Periods” (NPPs). During NPPs, no payment is due from the LCCC to generators. For CfDs struck in the first three auction rounds, NPPs are deemed only to occur when the Reference Price is negative for six consecutive hours. From AR4, the definition reduces to any single hour with a negative Reference Price.

(In this blog we don’t consider hedging by generators for baseload CfDs. For biomass CfDs specifically, the instrument has proved ineffective and caused unintended consequences in extreme circumstances. As an example, Drax Unit 1 was barely operational during the winter of 2022/23 despite the highest wholesale power prices of any winter to date.)

Supplier CfD Levy Hedging

Although the LCCC doesn’t purchase physical energy itself, the net financial effect of the CfD regime is very much the same as if the LCCC has made long-term purchases of energy at fixed prices, indexed to inflation, on behalf of consumers and their suppliers. Effectively, it uses the ‘balance sheets’ of all UK householders and businesses to hedge its risk.

The suppliers, meanwhile, are left with weather risk exposures – that wind speeds will be below their historic lows – and that increasing amounts of renewables will cannibalise themselves – capture risk. This is the risk that, as a growing proportion of renewables enters the system, the percentage of the average wholesale price intermittent generators are able to capture over time falls. This is because high wind (or solar) availability pushes down prices, while low wind (or solar) availability pushes prices up exactly when wind (or solar) generators are unable to benefit.

As the CfD effectively passes on these risks to consumers via their suppliers and because the suppliers are not easily able to hedge these risks, and often lack the balance sheets to absorb them, they will want, over time, a higher risk premium on their tariffs. It is worth exploring how suppliers pass on that levy to consumers, and what this will mean ultimately for the overall cost to the system.

Calculating the CfD levy

The CfD Levy paid by a supplier depends on its share of eligible demand, and the payments (or receipts) to CfD generators, on that day. This, in turn, depends on the volumes generated and the difference between the Strike Prices and the Reference Prices for that day.

Suppose for example on a particular day that:

  • Eligible demand is 1,000GWh
  • CfD intermittent generation is 100GWh
  • The weighted average Strike Price is £175/MWh
  • The weighted average Reference Price is £125/MWh
  • Supplier X has eligible demand of 50GWh

Then for that day Supplier X must pay into the CfD levy an amount equal to:
50GWh/1000GWh x (£175/MWh-£125MWh) x 100GWh = £250,000 (or £5/MWh of demand).

In the example above, however, if prices had increased so that the weighted average Reference Price was £175/MWh, then no CfD payment would have been made to generators, and no levy would have been due from the Supplier.

Conversely, if prices had fallen so that the weighted average Reference Price was only £100/MWh, the Supplier’s CfD levy payment would have increased to £375,500 (or £7.50/MWh of demand).

Alternatively, if prices and demands were as set out above, but it was a less windy day and CfD Intermittent Generation was only 50GWh, then the Levy payment due from the supplier would only have been £125,000 (or £2.50/MWh of demand).

In general, only very sophisticated customers have a “pass through” of CfD Levy in their supply contracts. So, for the most part, once a Supplier has agreed a fixed price to supply a customer, the CfD levy risk passes to the Supplier.

Suppliers (and sophisticated customers with pass-through contracts) are then left in the position where – in effect, financially – a part of their demand is hedged by something akin to an intermittent power purchase agreement (PPA) at an inflation-linked price.

Suppliers deal with this risk in different ways; but most allow for some risk when pricing customers tariffs and mitigate this risk by retaining a short position until the day-ahead auction to offset the likely impact of a movement in wholesale prices on CfD Levy rates.

In the example above, if the generation and demand levels were typical of what was expected at the time of year, the Supplier might conclude that it should leave 10% of its expected demand – or 5GWh – unhedged until the day-ahead auction, because 10% of national eligible demand is expected to be covered by intermittent CfD generation (100GWh vs. 1,000GWh).

As long as the volume of generation is as expected, then if prices rise the additional cost of purchasing the remaining energy requirement will be matched by a reduction in the CfD levy cost. Conversely, if prices fall, the saving made on purchasing energy in the day-ahead auction will be offset by a reduction in the CfD levy.

So, in the example above, suppose wholesale prices at the time of customer quotation averaged £150/MWh, but the day ahead Reference Price was only £100/MWh.

  • In customer quotations, the Supplier would have allowed £150/MWh wholesale costs, plus a levy payment allowance – which could have been equal to 10% x (£175-£150) = £2.50/MWh plus a risk premium, perhaps £3/MWh in total – giving a total energy plus CfD levy revenue price of £153/MWh.
  • The Supplier might hedge 90% of its demand at £150/MWh, and then purchase the remaining 10% at approximately £100/MWh in the day ahead auction, giving a weighted average energy cost of £145/MWh.
  • Assuming generation levels as expected, the CfD Levy would be 10% x (£175 – £100) = £7.50/MWh.
  • Therefore, total wholesale energy plus CfD costs to supply would be £152.50/MWh – very close to what was anticipated.

The risk retained

This example shows the high-level principle of how the Supplier might mitigate risks.

However, exactly as if they had bought a fixed price PPA, the Supplier is left holding a large amount of complex ‘basis’ risk related to intermittency.

If the average strike price is above typical market prices on windy days, then the Supplier will benefit if it is not windy. Conversely if the strike price is below the typical market price on windy days, the supplier will benefit if is windy. This dynamic is made more complex because there is a growing relationship between wind levels and day-ahead pricing, as more wind farms are installed.

This complex interaction between price and weather (and hence volume) is called ‘quanto risk’, and it is essentially unhedgeable. It means that even if the Supplier retains a short position to the day-ahead stage, as illustrated above, the risk related to CfD levy is reduced but not eliminated.

Other risks carried by suppliers related to intermittent CfDs include the uncertainty on when and if wind farm CfDs are triggered. At present several AR2 CfDs have not been triggered by the generators even though they are complete and operational, as they receive better revenue in the open market; they may not trigger them even at the long stop date, as the non-delivery penalties are low. This contractual “flaw” in the CfD allows generators to game the mechanism and means suppliers have another unknown variable to factor into their risk calculations. The government is currently consulting on whether to change the trigger arrangements in AR5 to increase the likelihood of contracts being triggered at an early stage.

(In this blog we don’t consider Supplier hedging for baseload CfDs. As we noted above, the instrument has proved ineffective for biomass and caused unintended consequences in extreme circumstances; Drax Unit 1 has barely run during the winter of 2022/23 despite the highest wholesale out-turn prices of any winter so far. The baseload CfD for Hinkley C is likely to prove more amenable once triggered, but suppliers and consumer are carrying uncertainty on the timing of project delivery, which will make initial hedging difficult.)

CfDs and the 2022 energy crisis

In 2022, gas and electricity prices spiked to unprecedented levels and experienced huge volatility in response to the Russian invasion of Ukraine, and the loss to Europe (and the world) of c. 350 million m3/day of Russian gas exports.

Across Europe, national governments felt obliged to protect domestic and business users from the high prices; and also place windfall taxes on domestic producers of primary energy to pay for it.

In this environment, it has been seen as desirable that the government should act to create price stability for consumers, and limit excess profit for primary energy producers. The renewable CfD is an instrument that does both, in addition to its original purpose of supporting new generation and supply chains.

The UK government and the EU considered widening the scope and purpose of CfD instruments to achieve the new aims – for example in the UK by switching RO support on existing schemes to a CfD; and offering “follow on” CfDs to “post-support period” assets.

On the one hand, this does create some price stability for consumers, and limit the potential for excess profits. On the other hand, it is a government intervention in what has previously been a free market and imposes long-term hedges on consumers that they may not want.

What this all means

CfDs have proved extremely effective in incentivising new renewables and, more recently, in helping to manage the impacts of the energy risk. However, the way they are structured in the UK leaves suppliers – and large consumers with pass through contracts – with considerable amounts of weather and quanto risk that is extremely difficult to quantify and hedge. The suppliers only response must be to increase the prices they charge their customers, making the system and the net-zero transition more expensive than it otherwise could be. Generators on the other hand face both balancing and NPP risks that are also very complex and difficult to manage.

As the volume of generation under CfDs increases these quanto risks will only get larger as we will discuss in a future blog.

5 minute read time

From NFFO to CfDs: three decades of renewables support in the UK

The UK’s current renewable energy support landscape is the result of more than 30 years of policy innovation and reform.

National governments around the world have brought forward many different mechanisms to support renewable energy generation, to develop technology and to pump-prime supply chains. Many of these schemes can be traced back to the Kyoto Protocol, adopted in 1997, which gave developed nations obligations to reduce their carbon emissions and to sponsor reductions in developing countries. Since then, as the climate crisis has become more pressing, emissions targets have become more ambitious, renewable energy capacity has proliferated and production costs have plummeted.

In the UK, renewable energy support pre-dated Kyoto. The Non-Fossil Fuel Obligation (NFFO) was introduced in 1990, under which the Non-Fossil Purchasing Agency (NFPA) purchased long-term contract supplies from low-carbon generators (which initially included nuclear) on behalf of suppliers and, indirectly, their customers. The last purchase was made in 1998. Under the electricity pool, suppliers were simply credited with their overall share of the energy they sold and billed accordingly by the NFPA. When market arrangements were changed in 2001 to the New Electricity Trading Arrangements, the NFPA instead auctioned output on the basis of six-month power purchase agreements (PPA). As the prices paid for long-term energy by the NFPA were lower than the auction prices, the NFPA built up a £500m surplus.

The Renewables Obligation

In the Utilities Act 2000, the government created powers for the Secretary of State to require energy suppliers to purchase a proportion of their energy from renewable sources, and the Renewables Obligation (RO) was born. From 2002 onwards, new or refurbished qualifying renewable generation received one Renewable Obligation Certificate (ROC) for each MWh of output, for a period of 20 years from accreditation. Suppliers were required to purchase and surrender ROCs to meet their annual obligation, calculated as a gradually rising percentage of their overall supply, or alternatively ‘buy out’ their obligation with cash. The sale of ROCs thus created an additional revenue stream for renewable energy generators, making them competitive with then-cheaper fossil generation.

The obligation as a percentage of demand and the buy-out price are set annually. The cash received in the buy-out fund is recycled back to those who surrendered ROCs. This means that, if there is a shortfall in overall compliance against the obligation, ROCs become worth more than the face value of the buy-out price. The greater the shortfall, the greater the subsidy, and the greater the incentive to bring forward renewable generation. An important feature of the RO is that it is a pure subsidy. The value of the electricity generated is determined by the power market, and usually reflects the market price of fuel for marginal dispatchable power stations.

Reforms to the RO

The Renewable Obligation ultimately was judged to be too blunt an instrument to effectively support both mature and emergent technologies, and from 2006 the RO was reformed, including with the introduction of banding. This rewarded different types of generation with differing amounts of ROCs per MWh produced. The RO support scheme was phased out between 2014 and 2017, replaced with the Feed-in-Tariff (FiT) for small-scale generation, and the Contracts for Difference (CfD) mechanism as the government’s main support scheme for large renewable generation (see below). Unless otherwise disbanded, the RO scheme will continue to run until 2037 when the last RO-accredited facilities stop receiving certificates.

In the Finance Act of 2000, the government also created the Climate Change Levy (CCL), a tax on business users related to their energy consumption, collected on behalf of the government by energy suppliers. One feature of the CCL regime was that most renewable generators could qualify to claim Levy Exemption Certificates (LECs). Suppliers could purchase LECs from generators on behalf of customers; the customer would then pay the supplier for the LECs rather than the CCL itself. In this way, LECs became a further subsidy support for renewable generators. The government closed the exemption regime – and hence ended the subsidy – in 2015.

In 2009, the EU Renewable Energy Directive introduced a new certification process for renewable electricity supplies – Guarantees of Origin (GOOs, also called REGOs in the UK). The aim was to support the directive’s broader aims, supporting and monitoring the progress of member countries towards their renewable energy targets. One side effect, however, was that ownership of GOOs could be used to evidence renewable energy supplied by individual suppliers. That allowed UK electricity suppliers to buy REGOs from generators and use them to back ‘green tariffs’ and their annual ‘fuel mix disclosures’.

FiTs and CfDs

The following year, the government introduced the Feed In Tariff support scheme for renewable generation assets under 5MW, which was seen as more practical alternative to the RO for small generators. As used widely in continental Europe, the FiT required electricity suppliers to buy power from licensed generators at set prices, with support lasting between 10 and 25 years. The costs of the scheme are spread across all suppliers through a levelisation process run by the regulator, Ofgem. The FiT scheme was closed to new participants in 2019.

Contracts for Difference were introduced in 2014 as part of the wider Electricity Market Reform package of measures. It is now the only central support mechanism available to new renewable generation. Under the CFD regime, the Low Carbon Contracts Company – a private company, owned by the UK government – contracts privately with generators of low-carbon power.

The scheme works through a series of auctions. Generators are invited to bid in a strike price which they are prepared to receive to sell power. If the market price of that power is below that strike, they receive payments from the LCCC. If it is above the strike, they agree to pay the difference to the LCCC. This provides the generator with revenue certainty, and transfers this market exposure to the LCCC which in turn is passed on to consumers.

Since its introduction, four auction rounds have taken place. As of the end of 2022, just under 6GW of capacity was operating under CFD contracts, with offshore wind accounting for 4.2GW, biomass for 1GW, and onshore wind for 650MW. By 2030, almost 30GW of renewables are projected to be operating with CfD contracts agreed through these four auctions.

The CfD has been enormously successful in reducing the market risk faced by generators, and in helping to reduce cost and scale capacity – particularly in offshore wind. But, as we will discuss in the next article, that risk does not disappear, but is transferred – and could yet threaten the future role of the CfD in decarbonising the UK’s power grid.

6 minute read time

Understanding power markets: Merit order and marginal pricing

Today’s electricity markets no longer reflect the real costs of building and operating today’s mix of generating capacity. What’s worse is that they have the potential to frustrate the net-zero transition.

In the UK, in common with many power markets in the industrial world, electricity prices follow the price of natural gas. As we are seeing in the current energy crisis, this is saddling consumers with sky-high bills. It is also generating windfall profits for existing renewable energy operators and nuclear plants.

This is leading many – including policymakers and regulators – to question the structure of wholesale energy markets, and to call for their reform. Power markets in the UK and other countries need to be overhauled if we are to successfully decarbonise our electricity supply. First, however, it is important to understand how they currently work.

Pricing at the margin

Electricity is hard to store; supply and demand need to be physically balanced at all times. This can be done (well) by a centralised administrative system but, in common with many other markets around the world, power price formation in the UK market is based on marginal pricing. Each generator is required to bid in the price it will accept to generate power for each 30-minute interval (in some other markets, this time band is different) throughout the day.

These bids are based on the operating costs that each generator faces, taking into account the costs of starting up or shutting down generation. Wind and solar plants tend to have the lowest operating costs, followed by nuclear power plants, while natural gas-fired plants typically have the highest operating costs – and certainly do so given current gas prices.

The prices bid in by the various generators form what is known as the merit order. This is a theoretical stack of generating capacity, from cheapest to most expensive, that is available to supply power during each 30-minute increment.

In the UK, National Grid, the electricity system operator, will then contract with enough generators to ensure that there is sufficient supply to balance expected demand.

The price bid by the marginal generator – the most expensive plant needed to supply power to balance the market – becomes the clearing price, which all generators are paid.

Most generators, then, will earn more than their operating costs. The difference between their costs and the clearing price is what will enable them to recover their capital expenditure and earn a profit. This will, over time, encourage additional investment in generating capacity.

Because very little demand is responsive to prices in the short-term, the market is typically balanced on the supply side. However, there are peaks in demand throughout the day, and seasonal fluctuations. This means that the marginal supply needed to meet these peaks in demand is only used a few times a year, and thus needs to be very expensive to capture enough revenue to be profitable.

A fossilised system

This system, or a variant of it, has operated in the UK since electricity markets were liberalised in the early 1990s. Then, the generating fleet comprised a relatively small number of large thermal power plants, mostly burning coal or powered by nuclear reactors.

Then, the low operating costs of nuclear plants put them at the top of the merit order, followed by coal and then natural gas. At periods of high demand, the most expensive capacity – gas-fired ‘peaking’ plants – could be quickly ramped up to balance the market, setting the marginal price.

Since the turn of the century, large numbers of relatively small renewable energy plants have been added to the UK’s generating mix. They are mostly wind or solar plants. Given they do not need to pay for their fuel, their operating costs are very low – perhaps 10-20% of their overall costs, compared with 30% for coal and more than 50% for baseload natural gas plants.

Competitive green power

For wind and solar plants, most of their costs are incurred upfront, in raising the capital to buy and install the generating equipment. Because renewables are so capital intensive, the returns are driven primarily by wholesale prices, unlike fossil fuel generation where returns are driven by the spread between fuel costs and power prices. Until recently, power prices have been below levels sufficient to cover the capex and opex of renewables and, as a result they have needed subsidies to get built; for example, the UK government has run several auctions for contracts-for-difference for offshore wind and solar plants, which guarantee a minimum price for the power generated.

Now, however, renewable energy is becoming increasingly competitive, and growing volumes are being built without subsidy. Some are entering into long-term power purchase agreements with utilities or corporate buyers, or are operating on a ‘merchant’ basis, selling directly into the wholesale market, earning whatever the power price is at that particular time.

However, while wind and solar power costs have fallen relative to fossil fuel generation, the power they generate remains intermittent. Solar is only available during daylight hours, and periods of low wind can leave windfarms becalmed.

Unintended consequences

As the volumes of renewable energy within the merit order rise, the functioning of a wholesale power market based on marginal pricing begins to break down.

The first problem stems from the intermittency of renewables caused by weather patterns. On average, systems with lots of renewables will push the merit order curve either to the left or to the right, potentially leading to very low or very high clearing prices. The sudden temporary disappearance of large volumes of renewables capacity from the merit order – during a period of low wind, for example – would force the marginal price to rise very high to meet demand.

This means the system needs increasing amounts of flexible generation as we shift to more renewables on standby to meet this demand. This risk could be even greater if market participants bid their capacity at prices higher than the marginal cost, knowing those bids needed to be accepted to cover the supply shortfall.

The second problem is known as cannibalisation. As the base of the merit order fills up with low-cost renewables with the same generation profile, they face growing ‘capture’ risk. Put simply, because all wind farms generate power when the wind blows, this forces prices down. Conversely, when there is no wind, power prices rise, but wind farms are unable to benefit. This means they capture a declining proportion of average power prices over a given period, making it harder for renewable plants to recoup their capital expenditure. The more renewables that come on to the system, the worse this problem becomes – hence the term cannibalisation. As a stark example of this, during December of last year the monthly capture factor (capture factor = capture price/baseload price) for UK wind under the CFD collapsed to 81.4%; the capture price was £221.09 versus the baseload price of £259.26.

The third problem is the perception that, during the period of high prices that we are currently in, these low-cost generators are seen by the public and policymakers to be earning excess profits. Because the clearing price is set by gas-fired generators, and because gas is currently so expensive, this has led to calls for renewable energy operators to face a cap on revenues or windfall taxes on these profits.

New approaches to electricity markets

Despite these drawbacks, marginal pricing currently sets the wholesale power price, and this price (averaged over months and years) has tended to drive the prices at which aggregators, electricity suppliers and corporates are willing to buy power in the market. But, as we shall see in the next article, there are alternative ways of pricing power from new-to-earth renewable generators which, we argue, could make more sense for sellers and buyers alike.

5 minute read time

Understanding power markets: The levelised cost of energy

The levelised cost of energy provides a very useful way of valuing new renewable energy assets and determining the energy price a project needs to be viable.

What does it cost to generate a megawatt/hour of electricity? This simple question throws up a lot of complicated answers. For a solar farm, powered by sunlight, the answer could – arguably – be close to ‘zero’.

A natural gas plant, conversely, would have to factor in the price of the fuel, the cost of carbon emissions permits and its other operating costs. On top of this, the cost of the capital needed to build the plant needs to be taken into account. That cost might be zero for a 25-year-old asset, which has had its original capex amortised down to zero. Or it could represent the lion’s share of a new wind farm’s cost.

As we have seen, the price of electricity in most wholesale markets is based solely on the operating costs of the various generators that bid to supply power. This is expressed as the marginal price – the price required to incentivise sufficient capacity to meet demand at a given point.

However, because these operating costs do not include the costs of repaying debt and generating a return for equity investors, they only tell part of the story. To compare the costs of different types of generating capacity, analysts use the levelised cost of energy (LCOE).

The cost of energy on the level

Put simply, a power plant’s LCOE is a measure of its lifetime costs divided by the volume of energy it produces over that lifetime.

The calculation incorporates the costs of building, financing and operating the plant (including fuel costs, staffing, maintenance and emissions allowances, if applicable). It also includes a discount rate to depreciate the cash flows to account for the returns expected by the investor, and to factor in risks, etc.

It should be noted that there is no universally agreed methodology to calculate an LCOE, and different analysts could generate different LCOEs for the same asset, depending on the assumptions they make and the granularity of the data used. However, the US National Renewable Energy Laboratory provides a useful calculator.

Once derived, the LCOE can be compared with the expected revenues a project can earn from selling electricity (and, in some markets, from selling other attributes, such as frequency control, reactive power and avoided emissions). If the expected revenues are greater than the LCOE, then the project should be profitable and, all things being equal, a developer will develop the project. Conversely, where the LCOE is higher than expected revenues, the project won’t be developed. This disconnect from the wholesale market means that it is the LOCE, not the wholesale power price, that is the driver of the price of power from new-to-earth generation.

The LCOE is not without its drawbacks. It can oversimplify the complexities around project risks and the cost of capital. But it is a useful tool for comparing different technologies and project types. It’s also very useful in establishing the price at which a project needs to sell its output under a long-term contract, and was used by the UK’s Department of Business, Energy and Industrial Strategy in developing pricing for its Contracts for Difference.

Plummeting green energy LCOEs

Over the last decade or so, the LCOE of renewable energy has fallen spectacularly. Bloomberg New Energy Finance (BNEF) produces benchmarks that track the global LCOE of various power generating technologies. Between 2009 and mid-2022, the average LCOE for a fixed-axis solar photovoltaic plants fell from $304/MWh to $45/MWh. Onshore wind fell from $93/MWh to $46/MWh, while offshore wind has fallen from a peak of around $220/MWh in 2012 to $81/MWh.

Meanwhile, the LCOE of coal-fired power has ranged between $60 and $85/MWh and that of gas plants from $45 to $81/MWh. These changes have, to a very large extent, been driven by changes in fuel costs.

The main drivers pushing down clean energy LCOEs have been technological innovation and economies of scale. More efficient solar cells and wind turbines produce more power for each unit of cost. Mass production has helped components and manufacturing become cheaper.

As the chart shows, onshore wind and solar electricity are now cheaper, on a lifetime basis, than fossil fuel-fired plants.

The LCOE of wind and solar technologies are particularly sensitive to costs of capital. According to financial advisory firm Lazard, which publishes closely-watched LCOE analysis, capital costs accounted for $26 of the $30/MWh LCOE of utility-scale crystalline solar PV plants. For wind, the figure is $20 of the $26/MWh LCOE. Since the financial crisis in 2008, central banks have pursued ultra-loose monetary policy; the resulting ‘cheap money’ has helped keep clean energy costs down.

However, the various cost curves do not all bend in the same direction. In June, BNEF reported cost rises pushing up prices of wind energy by 7% year on year, and solar by 14%. It pegged those rises to increases in the cost of materials, freight, fuel and labour.

Despite this inflation, the current energy crisis that has driven up gas prices has made renewables more attractive from an LCOE perspective. While higher fuel costs have increased the LCOE of gas plants, the LCOE of renewable energy has been largely unaffected. This has led to higher profits for renewable generators while many fossil fuel generators have struggled as they have had to cover higher fuel costs.

This gap between the two types of generation, fossil fuel generation (low capital need, expensive to run) and renewables (high capital need, cheap to run), is driving many market observers to consider how the market could be split.

Looking beyond LCOE – value-adjusted LCOE or VALCOE

There is a further dimension to valuing electricity generating assets. As is noted above, every electricity generating asset has other attributes, not all of which are financially remunerated. The ability of an asset to provide capacity on demand, or its flexibility to provide system services such as helping to stabilise the frequency of the grid, may not generate revenue, but they have value to the system operator. Equally, assets lacking those capabilities can impose costs on a system.

To capture the value or costs of these attributes, a value-adjusted LCOE can be calculated. This adjusts the LCOE by comparing an asset’s performance on three metrics – energy, capacity and flexibility – against the grid average. Energy is its ability to capture wholesale power prices, capacity its contribution to system adequacy, and flexibility is its ability to provide system services such as frequency regulation or reserve power.

So, a peaking natural gas plant might have a high LCOE, but its dispatchability would increase its VALCOE. Conversely, a solar plant without energy storage attached would mean its VALCOE would be lower to the grid operator than its LCOE.

As long as these values are not compensated for, VALCOE as a measure is of most interest to policymakers and market operators. But, as renewables penetration increases, it is likely that more of these costs and benefits will factor into market payments and the investment case for new assets.

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How to engineer a net-zero power system

Decarbonising our power system will require a careful mix of policies, regulations and incentives. Our current approach is piling on unnecessary costs, misallocating risk and causing unintended consequences.

Electricity systems around the world are in the vanguard of the net-zero transition. We are fast decarbonising our electricity grids, primarily in response to the climate crisis, and now with a tailwind from the energy crisis caused by Russia’s war on Ukraine.

This is an urgent priority. To address climate change, we will need to electrify large parts of the economy – transport, heating, industrial processes – that currently rely on fossil fuels. We will need massive investment in clean power generation, energy storage and power transmission and distribution.

Over the medium term, power systems dominated by wind, solar and nuclear generation will provide cheaper electricity than those based on fossil fuels. Eliminating our dependence on volatile, often expensive fossil energy, much of which is supplied by autocratic and unfriendly states, will have numerous economic, geopolitical and social benefits in addition to their environmental ones.

In the short term, however, the transition will be costly and disruptive. It is vital that we deploy the best policy, regulatory and market tools at our disposal to make accelerating the penetration of clean energy as cheap and painless as possible.

We have produced a short series of blog posts to explain the underlying issues we face and propose some solutions.

A new type of electricity system

The new power grids that are emerging have different characteristics than those which went before. Whereas grids used to be supplied by a relatively small number of large thermal power plants, generating predictable volumes of power as required, new grids are characterised by many thousands of generators, many of which are small solar or wind farms. Their supply is intermittent, meaning that the power market is exposed to novel risks.

‘Traditional’ approaches to remunerating operators and their investors are beginning to show themselves not fit for purpose as power systems change. Marginal pricing based on the merit order of available power plants is ill-suited to support capital investment in large volumes of intermittent capacity that has running costs that are close to zero.

To enable investment in new clean energy capacity, there has been enormous innovation in policy, regulation and market over the last three decades. The UK has been a leader in many regards, and some of its approaches have been copied elsewhere. These mechanisms have evolved to meet changing conditions, particularly in response to falling clean energy costs.

Accelerating evolution

In a number of countries, including the UK, this evolution has been enormously successful. Supported by its Contracts for Difference (CfD) regime, the UK has become a world leader in offshore wind, second only to China in terms of installed capacity. From October to December 2022, renewables produced more power in the UK than gas.

But the proliferation of intermittent clean power, mostly with operating costs close to zero, has had a major impact on electricity pricing, threatening to discourage new investment through a process known as cannibalisation.

Clearly, the tools we need to deploy to meet our goal of a net-zero grid need to evolve further.

Incentivising the transition

To get clean energy projects built, there are broadly four options for developers. They can either be supported through subsidies like the Renewable Obligation scheme or with pricing support via CfDs. They can enter into long-term power purchase agreements (PPAs), either with power traders or suppliers (utilities) or directly with corporate or public sector consumers. Or they can trade as ‘merchant’ generators: selling power into the wholesale market on a short- to medium-term basis.

Each of these options have their pros and cons, their benefits and their risks. Some suit some actors better than others. Some are not delivering against their potential. None are perfect, and all give rise to unintended consequences – especially as the generation mix changes on the way to net zero.

For example, corporate PPAs should be a key tool to get new renewables built and help companies meet their net-zero commitments. But the current ad hoc approach to structuring corporate PPAs makes them expensive and time consuming to execute. And there is a mismatch between buyers and sellers. Because companies typically benchmark PPA pricing against the wholesale market, they are most attractive when wholesale prices are high – precisely when developers would rather sell into the wholesale market. Conversely, when wholesale prices are low, companies are reluctant to commit to PPAs.

The relative lack of corporate PPAs means that government-supported CfDs have been necessary to do more of the heavy lifting to reach net zero. But the complexity of managing the risk in these apparently straightforward contracts means most of the associated price risks end up being socialised across domestic and corporate consumers reducing the efficiency of the instrument, increasing overall costs and risking a backlash from some market participants.

Finessing complexity

Electricity systems are inherently complex. The net-zero transition adds to their complexity, requiring them to address climate impacts and dramatically increase in scale, while continuing to deliver reliable power at an affordable price.

This complexity means that there are no quick fixes to make the system work better while reducing unnecessary costs. Instead, what is needed are numerous improvements and refinements, alongside new products and market solutions, to enable the decarbonisation of our power supply as quickly, efficiently and cost-effectively as possible. In this series of blogs, I am applying more than 30 years of trading power, building and leading power market businesses, and advising on regulatory reform to set out the existing problems as I see them and suggest some solutions.