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.

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.

Appendix: Useful Links and Guidance

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

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.

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.

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.

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.

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.

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.

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.

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.

Despite the cost of renewable energy dropping significantly over the past decade, a perfect storm of events has suddenly triggered an increase in the price of cleaner fuels.

It’s an increase that could have big consequences for the development of renewable energy projects and, subsequently, businesses who are striving to go green.

Not to mention the impact it could have on the planet.

Renewable energy became cheap, fast.

The cost of renewable energy has increasingly undercut fossil fuels. This has largely been driven by new and improved technologies, competitive supply chains, reductions in capital costs and increased competition.

As the renewable energy sector matured and continued to make improvements in efficiency, scale and technology, the Levelized Cost of Energy (LCOE) for wind and solar declined significantly.

In fact, according to Lazard’s LCOE analysis – version 15.0 – in 2009 a MWh of electricity obtained from solar photovoltaic had an LCOE of $359. But by 2021, that LCOE had reduced to just $36 – significantly less than the LCOE of coal, nuclear and gas. Both on and offshore wind energy have also seen a dramatic decrease in costs since 2009.

It’s this decline in the LCOE that’s led to the rapid upscaling of renewable energy sources. And as a result, businesses have been able to secure a competitive rate for renewable energy relative to fossil fuel energy.

However, what does the future hold?

The cost of renewable energy in the UK increases

For the first time in a long time, the LCOE for renewables has increased. And not just increased slightly but it’s doubled in price in the last couple of years.

In the UK the LCOE for solar, has risen from circa £40/MWh in 2020 to over £80/MWh in 2022.

Renewable energy is not exempt from global trends that are driving costs upwards globally. Some of the increase is related to increased capital costs as interest rates rise around the world to tame inflation, other factors include global supply chain disruptions, soaring cost of materials – particularly steel – and an inflation in the cost of labour.

In fact, the cost of steel for wind turbine blades had risen by more than 50% since the start of the Covid-19 pandemic.

European PPA prices also double in 2022

As a result of these increased costs globally, 10-year PPAs for solar, onshore wind and offshore wind technology doubled in price in 2022 to an average of €107.80/MWh.

With uncertainty continuing in the energy market, inflation rising and developers still tussling with disruption to the global supply chain, there’s no telling how long the hike in the cost of PPAs will last.

The cost of renewable energy is increasing. What’s the impact?

For years, the cost of renewables has increasingly undercut fossil fuels. But what we’re witnessing now is a global reset in the cost of the resources we need the most – renewable energy.

It’s a change that could have a huge impact on the expansion of renewable energy projects, businesses and our planet.

Slower expansion of renewable energy projects

As the cost of generating power from renewable energy increases developers will be debating whether they can move ahead with building renewable energy projects at all.

As a result, investors could lose confidence and the expansion of renewable energy could stall at a time when Europe needs it the most.

Businesses could pay double the price to go green

System costs are now higher and with that, the cost of going green increases, too. For many, the journey to net zero will cost more in the future.

With rising costs, those businesses that failed to hedge wisely may now struggle to deliver on their net zero commitments, without paying significantly higher prices.

It’s no secret how damaging it can be for businesses who fall short on their environmental, social and governance (ESG) promises.

The disconnect between fossil fuel and renewable power pricing

The worrying thing is: if the price of gas decreases, that does not mean the cost of renewables will decrease with it.

There’s no doubt that renewable energy buyers will need to reset their expectations on pricing. And perhaps reset their stakeholders’ expectations on delivering on their green agenda, too. It could be sometime before the LCOEs of renewable energy start falling again.

What if renewables become more expensive than gas?

For some time, renewable power has freed economies from volatile fossil fuel prices by curbing costs and enhancing market resilience. The whole world has experienced a reduction in the LCOE of wind and solar power. A report showed that, in 2021, two-thirds of renewables were cheaper than coal.

But the important question now is – although renewables are currently cheaper than gas, how long will that remain the case?

What can businesses do to secure a cost-effective, long-term supply or renewables?

Businesses are not only desperate to protect themselves against price volatility right now, but they are also under growing pressure from investors and consumers to decarbonise and deliver on their net zero promises.

However, these net zero commitments could be under threat from the rising price of renewable energy.

The only way businesses can mitigate against the risk of these costs rising further and lock in a long-term supply of clean energy is with a CPPA.

A CPPA is a long-term contract between an energy buyer and an energy generator. The two parties agree to buy and sell an amount of energy which is, or will be, generated by a renewable asset. A CPPA is usually agreed over a period of 10-15 years, although we are starting to see shorter terms.

Big tech are the big winners of renewable energy

Big tech has long been the leading buyer of CPPAs and 2021 was no different.

In 2021, tech companies were the biggest buyers of corporate renewable energy. In fact, Amazon’s total CPPA capacity made its portfolio the 12th largest globally – across all sectors – ahead of EDF.

Amazon’s decision was for good reason. CPPAs offer parties who have long term power needs the chance to secure a clean energy supply, at a fixed price.

There are few who’ve made it out as winners during the current energy crisis. But this was a smart move made by several tech giants and it certainly puts them up there.

Take action or risk the consequences

The UK’s biggest organisations are now exposed to eye-watering energy prices, as well as uncertain renewable energy costs.

Now’s the time to act and protect your business from financial and reputation risks of inaction.

Interested to hear more? Reach out to us, we’d love to help you.

The energy support package for businesses is essential. It’ll save many from collapsing this winter. However, there are risks that come with such a huge bailout.

In this blog, you’ll find out about the unintended consequences of the energy support package for businesses. Plus, we’ll discuss the long-term measures you can implement to protect your business now and in the future.

Businesses receive energy support package from the government

After calls for urgent government action on rising business energy bills, the UK government announced its support scheme for non-domestic users:

Under the Energy Bill Relief Scheme, gas and electricity costs for UK businesses, charities and public sector bodies are to be capped for six months, with discounts applied to energy usage initially between 1 October 2022 and 31 March 2023.

In its announcement, the Department for Business, Energy & Industrial Strategy (BEIS) announced wholesale prices would be fixed for all non-domestic energy customers at £211 per MWh for electricity and £75 per MWh for gas for six months, with the scheme applying to contracts signed since December 1st 2021.

However, the reality is that the discount your business receives will depend on whether you are on a fixed or a flexible contract.

So, let’s clarify where your business stands:

How will the energy support package work for fixed-price contracts?:

The December 1st cut off is for fixed price contracts only, so any fixed price contract not started before December 1st 2021, will not benefit from the scheme.

Prices are not fixed to £211 per MWh for electricity and £75 MWh for gas. Instead, for fixed price contracts, a discount is applied to businesses’ rates, which is calculated by the government based on its interpretation of the difference between wholesale costs and the ‘government supported price’.

For example, two customers with the same usage who signed contracts on the same day, but have different suppliers, will receive the same discount per/kWh, but their costs will be different overall.

In essence, no matter the discount provided by the government, the total cost to you (excluding taxes) cannot drop below £211. The discount is a floor.

How will the energy support package work for flexible contracts?:

All flexible contracts will benefit and any hedges made before December 1st will be included in the weighted average price.

The discount for flexible contracts is the difference between £211 and the weighted average price for the business, up to a maximum discount of £345/MWh. The discount is only applied to metered volumes and does not include transmission or distribution losses.

The BEIS has shared a table, which will be updated on a weekly basis, to reflect market developments.

You can find this information here.

It outlines the daily discount rates available for business and other non-domestic energy users who are on both fixed and flexible contracts with their energy supplier.

Business energy support package will cost billions

There’s no question over whether the support is needed. It helps to cushion the biggest and most volatile cost pressure facing British businesses like yours. Without it, many firms would collapse and many more jobs would be lost.

However, we can’t escape the reality that this support package is a hugely expensive intervention and will cost billions.

Although the government has not outlined an overall price tag, consultancy Cornwall Insight, estimated the six month relief alone will cost up to £25bn.

And as I write this, businesses are still in the dark as to what happens when the six-month cap runs out. Undoubtedly, many businesses will need financial support beyond this initial period.

With that in mind, it’s likely the overall bailout for the energy crisis will be the biggest financial support package seen in history. The government’s support could stretch way beyond the billions pledged for the furlough scheme.

As a result, Capital Economics has forecast the UK’s borrowing will hit £165bn, or 6.5% of GDP, in 2022-2023, rather than the £99bn the Office of Budget Responsibility (OBR) forecast.

This is a worryingly high figure when we compare this with the borrowing amongst our European counterparts.

If one thing’s for sure, the UK has an immense bailout to manage.

And unfortunately, it’s one that doesn’t come without its consequences.

The unintended consequences of the energy support package

The Energy Bill Relief Scheme will undoubtedly save British businesses.

However, there is a risk that businesses will treat the scheme as a get out of jail free card for their lack of prudence ahead of the crisis. And one that gives them a green light to return to their old, energy guzzling practices.

Here’s the issue:

If business leaders operate under the proviso they will always be bailed out, it’s unlikely they will exercise caution on such important matters in the future.

With no incentive for businesses to manage the risk, it’s likely they will continue to use and waste huge amounts of energy. Consequentially stalling on the climate agenda and impacting the race to net zero, too.

Businesses must implement long term measures to protect themselves

Businesses that choose to treat the government’s support package as a get out of jail free card, risk leaving themselves exposed to future volatility.

Let’s be clear:

The energy crisis is entirely out of businesses’ control. But I urge corporate leaders to view this as a wake up call.

There are a number of measures businesses can implement in the long-term to reduce costs, mitigate risk and maintain their commitment to the climate.

Let’s take a look at four actions you can put in place for your business:

Reduce energy consumption

Energy crisis or no energy crisis, you should be doing what you can to reduce your use of energy.

The reality is:

You could save a considerable amount of money by looking at your current consumption practices. Although this could be said for all industries, it is perhaps most relevant in industrial and manufacturing firms where energy usage is at its highest.

New products and technologies, such as LED lighting and task lighting systems, can significantly reduce energy consumption across a workplace.

Change behaviours to waste less energy

Billions will be spent on bailing out bills. But there is much less focus on targeting the root of the problem:

Businesses waste huge amounts of energy.

Behavioural changes, such as turning lighting and electrical equipment off in unoccupied areas of the workplace and ensuring machinery is properly maintained, can make a huge difference.

Finding and eliminating energy wastage can yield dramatic results for businesses who are looking to reduce the impact on their finances and the environment.

Plan ahead and hedge wisely

Some firms have done a good job of hedging their energy. As a result, they have shielded themselves from the volatility of the energy crisis.

However, others have long chosen to bury their heads in the sand. But one mustn’t interpret that as a green light to put risk mitigation on the back burner.

Hedging is essential, even now.

Double-down on security of energy supply

Without a doubt, this is the time to double down on energy security.

One way to achieve that is with a Corporate Power Purchase Agreement (CPPA).

A CPPA is a long-term contract between an energy buyer and an energy generator.
The two parties agree to buy and sell an amount of energy which is, or will be, generated by a renewable asset.
A CPPA is usually agreed over a period of 10-15 years, although we are starting to see shorter terms.
And there are MANY benefits.
A CPPA will enable you and your company to:
One, mitigate risk by protecting against price volatility and securing price certainty.

Two, buy energy at below wholesale market prices.

Three, lock in a long term supply of clean energy.

Four, trace your energy so you know it’s 100% clean.

Five, lock up REGOs for long periods of time.

Six, reduce Scope 3 Emissions.

Seven, accelerate your journey to net zero.

And finally, prove you are a purpose-driven organisation by demonstrating your commitment to CSR.

Talk to us about risk mitigation

In this post, we have outlined the unintended risk of the energy support package for businesses. As well as the measures you can put in place to protect your firm in the long term.

Of course, if you’d like to find out more about how to mitigate risk and ensure your business is shielded from rising energy costs, reach out.

We’d love to talk with you.

Greenwashing is commonplace among UK energy suppliers. Many energy firms market their tariffs under an eco-friendly banner, but continue to supply electricity that’s generated by fossil fuels.

So how do you work out if your supplier is fuelling your business with the type of energy it says it is?

Well, it’s not easy – partly because many suppliers work hard to cover up the true source of their energy. But fear not, we’ve done the legwork for you.

Our experts analysed the actual fuel mix of the UK’s key industrial and commercial (I&C) suppliers between 2020-2021. Including: British Gas, Npower, Drax and E.ON.

Our findings suggest many business energy suppliers are misleading their customers about the type of fuel they supply.

We’ve presented our findings in this blog so you can quickly check if your supplier is being honest about its fuel mix, or not.

The Fuel Mix Disclosures of UK business energy suppliers

Each year, energy suppliers submit their annual Fuel Mix Disclosure data to Ofgem for the previous supply year (1 April- 31 March).

The FMD regulation was introduced in 2005 with the aim of helping customers (domestic and commercial) understand the makeup of the power they are buying.

In other words, it’s a way for you to check your energy supplier is supplying you with the fuel mix it says it is.

The fuel mix disclosure (FMD) breaks energy sources into five categories:

1. Coal
2. Gas
3. Nuclear
4. Renewable
5. Other

(In essence – fossil fuel, nuclear and renewable.)

Now:

You should be able to find your energy supplier’s FMD on its website. But to make things easier, we’ve compiled a table of the UK’s key I&C suppliers’ FMDs for the financial year 2020-2021.

You can use this table to:

1. Check in on what your energy supplier claims its fuel mix is
2. See how your supplier stacks up against the competition

On the surface, the FMD appears to give you all the information you need to make a good decision about the supplier you use to fuel your business.

However:

There are several limitations with the FMD which means it does not give you the full picture about the energy you’re buying.

In many cases, it misses out important information about the genuine makeup of the fuel mix. And it’s the type of information that might make you think differently about the supplier you’ve chosen for your business.

Let’s take a closer look at how limitations with the FMD can impact you.

Energy suppliers can hide their use of ‘dirty’ fuels behind an eco-friendly banner of ‘renewable’

First, the small segmentation of fuel types in the FMD (fossil fuel, nuclear and renewable) enables suppliers to hide the truth about their energy supply.

How?

Because the term ‘renewable’ in the context of the FMD does not necessarily mean non-polluting, sustainable or carbon neutral.

As well as clean sources such as wind, solar and hydro power, ‘renewable’ in the FMD constitutes energy from a range of ‘brown’ sources, too. These include biomass, landfill gas and sewage gas.

In fact, biomass creates just as much CO2 as burning coal. Plus, biomass pellets are usually shipped in from outside the UK – as far away as in North and South America.

When you consider the carbon footprint of biomass pellets, that ‘so called’ green energy starts to become an awful lot browner.

Energy suppliers can buy cheap renewable energy certificates to cover up their use of fossil fuels. But they do not need to declare this in the FMD

Second, energy suppliers can buy fossil fuel electricity from the wholesale market or generate it themselves, combine it with a renewable energy certificate – a Renewable Energy Guarantee of Origin (REGO) or an European Guarantee of Origin (GO) – and legally claim that fuel is 100% renewable.

This is called greenwashing.

How can this happen?

REGO and European GO certificates can be sold separately from the power.

In essence, a supplier could source all of its energy from fossil fuel sources, then buy the equivalent volume of REGOs and claim they only sell renewable energy.

Energy suppliers are required to declare the makeup of their energy in the FMD. But they are not required to provide detailed information about the source of their power and their use of REGOs and European GOs.

So, even if you look at the FMD of your supplier, this loophole makes it almost impossible for you to know whether the electricity you’ve chosen to power your business contains fossil fuels, or not.

Given how little clarity the FMD gives, the big questions is:

How do you work out what’s really in your supplier’s fuel mix?

Here’s where we can help…

Find out if your supplier’s renewable energy was backed with clean or non-clean REGOs (2020-2021)

REGO information is publicly available on the Ofgem website. In fact, REGOs are broken down by type of generation. This makes it easier to see what percentage of your suppliers’ REGOs are clean, and what percentage are non-clean.

For us, clean REGOs are ones that are combined with energy that has no adverse impact on the environment. This includes hydro, ocean, photovoltaic, wind and filled storage hydro.

Non-clean REGOs are everything else:

Sifting through the REGO data on the Ofgem website can be a minefield. So we’ve extracted the latest available REGO data for you.

Here’s what we found:

In this table, we’ve outlined the percentage of renewable supply that is backed by clean and non-clean REGOs for each supplier in the 2020-2021 reporting period.

Analysis of REGOs suggests greenwashing is commonplace amongst key I&C suppliers

Our deep-dive into REGOs suggests greenwashing is commonplace amongst key I&C suppliers in the UK.

Let’s look at a few examples:

According to British Gas’s FMD, 75% of the overall energy it supplied was renewable. Now, 6.6% of British Gas’s renewable energy was REGO backed. However, 39.4% of the energy backed by REGOs, was backed by non-clean REGOs.

In its FMD, Npower states 31.9% of the energy it supplied was renewable. Of that energy, 99% is REGO backed. However, 46.6% of the energy backed by REGOs, was backed by non-clean REGOs.

Engie’s FMD states 60% of the overall energy it supplied was renewable. Of that, 88% is REGO backed. However, 68% of the energy backed by REGOs, was backed by non-clean REGOs.

Want to find out if your energy supplier is masking its use of dirty fuels behind cheap European renewable energy certificates, too?

Read on.

Find out if your supplier’s renewable energy was backed with clean or non-clean European GOs (2020-2021)

In recent years there’s been a sharp rise in suppliers buying the European counterpart of UK REGOs. These are called European GOs.

In fact, energy suppliers in the UK submitted more than 64.4 TWh of European GOs, in the 2020-21 FMD period. This accounts for approximately 19.7% of overall electricity supply in that period.

Suppliers can submit European GOs to Ofgem alongside – or instead of – REGOs for the FMD.

So, we’ve pulled the latest available European GO data for the UK’s key I&C suppliers.

And, like we did with our analysis of REGOs in the previous section of this blog, we’ve outlined the percentage of renewable supply that is backed by clean and non-clean European GOs for each supplier.

Here’s what we found:

Analysis suggests UK suppliers are bulk-buying renewable energy certificates from Europe which they are likely using to disguise fossil fuels in their FMD

Some of the biggest I&C energy suppliers in the UK are backing a significant portion of their renewable energy with non-clean European GOs.

Let’s take a closer look at a few examples:

EDFs FMD states 29% of the overall energy it supplied was renewable. Of that, 45.3% was European GO backed. However, 15% was backed by non-clean European GOs.

In its FMD, SmartestEnergy states 66.2% of the energy it supplied was renewable. Of that energy, 91.3% was backed by European GOs. However, 12.4% of the energy backed by European GOs, was backed by non-clean European GOs.

As we know, British Gas’s FMD states 75% of the overall energy it supplied was renewable. Of that, 93.4% was backed by European GOs. However, 36.5% of the energy that was backed by European GOs, was backed by non-clean European GOs.

European GOs have dirty secrets of their own

Energy suppliers can legitimately submit European GOs for the renewable part of the FMD. However, there’s a whole heap of problems with European GOs.

The main issue is that buying European GOs (instead of the UK counterpart, REGOs) enables energy suppliers to wriggle out of paying green levies which are designed to support UK clean energy projects.

In doing this, energy suppliers are undermining the UK’s support scheme for renewables.

Plus, if your business buys energy backed by European GOs, you are – whether you are aware or not – also undermining the UK’s transition towards clean energy.

British Government plans to ban energy suppliers from greenwashing their image by bulk-buying cheap certificates from Europe

On Thursday 28 July, 2022, the UK government announced a plan to ban British energy suppliers from bulk-buying cheap renewable energy certificates from foreign power stations.

Quite frankly, this new regulation couldn’t come into force soon enough.

Not only are energy suppliers manipulating their fuel mix to lure customers into buying ‘green’ tariffs. But they’re also putting their own customers at risk of greenwashing, too.

Businesses like yours – who are striving to meet sustainability targets – need clarity on the makeup of the energy they’re procuring.

Imagine claiming you procure 100% clean energy, only to find out it’s contaminated with fossil fuels.

Loose regulation has long made it difficult for customers to understand where their energy comes from. This plan, which is set to come into effect on April 1 2023, should help stamp out the deceit in the energy industry. It’s a regulation we fully supported at the consultation stage.

Key takeaway

There is only one way to ensure you are buying genuinely clean energy:

Choose a supplier who only supplies genuinely clean energy, alongside matching clean energy REGOs.

Here at Squeaky, we do exactly that. Our portfolio of generation under contract includes only 100% clean energy, backed by matching clean energy REGOs.

If you’re concerned your business is procuring dirty energy and you’d like to talk about a cleaner option, reach out.

We’d love to talk.

DOWNLOAD OUR FUEL MIX DISCLOSURE GUIDE

O.K. let’s start by getting to grips with the basics of the Fuel Mix Disclosure (FMD).

Essentially, the FMD is supposed to provide evidence of the mix of fuels used to generate electricity. It is shared with suppliers’ existing customers during a compliance period which runs for a year starting on the 1st April.

And it’s how you (as the customer) are supposed to know what the makeup of the power you are buying actually is.

In fact:

In 2005, the Electricity (Fuel Mix Disclosure) Regulations introduced a requirement on all licensed electricity suppliers to disclose the mix of fuels they use to generate the electricity supplied, annually.

Without fail, suppliers must disclose this information by 1 October, every year.

Helpfully, energy suppliers in Great Britain receive a letter from Ofgem which sets out the actions required and reminds them of the deadline for submission.

Note: The regulation was embedded into electricity suppliers’ standard license conditions (SLC) and is now known as SLC.

Why should you care about FMD?

As a responsible business that’s concerned about its environmental impact, it’s likely you’ve chosen an energy supplier based on its ‘green’ credentials.
And that’s a wise decision to make.

After all, powering your business with genuinely clean energy is one of the key tactics to meeting net zero.

So, I put this question to you:

What would you think if you found out that your chosen energy supplier – the one that claims to help reduce your impact on the planet – is actually providing you with energy from ‘dirty’, polluting sources?

Or, worse still, your supplier is masking dirty fossil fuel generated energy as clean?

You’ll pardon me for putting words in your mouth, but I’d expect that you’d feel pretty cheated, disappointed and confused?

Well, I hate to be the bearer of bad news, but I’m here to tell you that it’s happening.

And unfortunately, it appears to be happening industry wide.

A scheme that was intended to provide transparency.

I think it would be helpful to start with some context around renewable energy certification.

For every unit of renewable electricity generated, Ofgem issues a Renewable Energy Guarantee of Origin (REGO).

In short, a REGO is a certificate of proof issued to the organisation that generates the renewable energy – like a wind farm or solar park – to show that the energy produced is, indeed, renewable.

Ultimately, the REGO scheme was put into place to provide transparency to consumers and businesses about the proportion of electricity that suppliers source from renewable generation.

However:

There is a loophole in the system that lends itself to malpractice.

Buying REGOs can mask fossil fuel energy as green.

Generators have the option to unbundle the energy produced from the REGO.
And is entirely permitted to sell each one separately.

Essentially, this means that an energy supplier can buy a REGO without needing to buy the renewable energy itself.

For example: a supplier can purchase fossil-fuel generated power, like coal or gas, combine it with a REGO, and claim that it is renewable.

And what this ultimately means is that an energy supplier can ‘act’ like it is supplying clean energy, when in fact, it is simply buying the right to say it is.

Now, I wish I could tell you that this has all been a terrible mix up.
But sadly, it is all true.

And what’s perhaps most concerning is that this has become the norm amongst many of the UK’s leading energy suppliers.

In fact, Cornwall Insight’s ‘Green certificate survey’ found the demand from big corporate power buyers pushed the prices of REGO certificates up significantly toward the end of 2021.

It found average reported prices of £1.35/REGO for Fuel Mix FMD 2021-22 and £1.41/REGO for FMD 2022-23. This is 228% and 214% higher, respectively than reported prices in the April 2021 survey.

Whether these are assigned to electricity generated from 100% clean generation or not, is very much open to debate.

And there is more worrying news still…

Sharp increase in UK suppliers buying European renewable energy certificates.

In recent years, we have also seen a sharp rise in suppliers buying European Guarantees of Origin.

These are otherwise known as European GOs, or, GoOs.

Essentially, a GO is the European counterpart of the UK’s REGO scheme.

It is worth noting that in 2019, the number of European GOs in the UK market reached 57.9 million – an increase of 41% when compared with the previous year.

In fact, our own analysis of European GOs submitted for the FMD period, 01 April 2020 – 31 March 2021, found British Gas Trading Limited (the UK’s largest energy company) is the largest user of GOs. It purchased almost 21 million certificates – twice as many as anyone else in the market.

In total, energy suppliers in the UK redeemed more than 64 million European GOs in the 2020-2021 compliance period. This accounts for approximately 19.7% of overall UK electricity supply in that period.

Lack of transparency amongst energy suppliers can cause you a tonne of issues

Arguably, the biggest issue here is transparency.

Or in this case, the lack thereof.

And it’s an issue that throws out a multitude of problems for both you as a responsible business, and for our planet.
Let’s look at the main ones, in turn.

If you do not know the FMD of your supplier, you will never truly know your own climate impact.

Firstly, you should know exactly what you are buying into when you choose an energy tariff.

Because the fact is:

If you do not know the mix of fuels that make up your power, you will never truly understand the impact of your business on the planet.
Which brings me onto my next point…

By not understanding the true source of your power, you could be falling foul of greenwashing.

As a business with a conscience and environmental goals of its own, it’s likely you’ve chosen to power you company with renewable energy.

And as many other businesses like yours have, it may be that you’ve laid claim to this on your website, or in the media.

And why not? Making this type of information public knowledge is a great way to increase loyalty amongst both your environmentally conscious customers and employees.

However:

Given our understanding of the scale at which energy suppliers are taking advantage of the trading loopholes in REGO and GO schemes, there’s a very real chance you could be unintentionally greenwashing.

Essentially, your renewable energy claim could well be undermined by your supplier masking their fossil fuel power behind REGOs or GOs.

And here’s the thing:

Greenwashing – whether knowingly or not – will likely put your company’s reputation at risk.

Ultimately it is not enough to take your energy supplier at their word on this, you will need to delve into your FMD yourself too. More on this shortly.

(Note: Greenwashing is a topic we unpacked in a previous blog post, and you can find out more on that here.)

But that’s not all…

The UK’s transition to renewable energy is hindered.

Aside from the obvious problem that European GOs enable suppliers to mask fossil fuel sourced energy as ‘green’, there’s another major issue with the REGO’s European counterpart…

In the UK, all suppliers are required to pay into government schemes to support the development of renewable energy in the UK.

But buying a European GO enables suppliers to dodge these costs. Electricity suppliers can seek exemption from certain industry costs in respect of renewable electricity generated in an EU member state and supplied to customers in Great Britain (GB). Eligible imported electricity is not included in a supplier’s market share of supply for the purpose of calculating their obligations to pay CfD and FIT scheme costs. This means that suppliers supplying electricity in GB which has been generated via renewable sources in an EU member state can reduce their liability to pay towards the costs of these support schemes.

In 2019 alone, this practice enabled suppliers to collectively avoid paying £126 million into government mandated renewable energy schemes, like new wind or solar farms. In fact, a Sunday Times investigation found this same practice helped British Gas to avoid £49 million in green levies, 2019-2020.

These are schemes that will ultimately help accelerate the UK on its net zero mission.

Essentially, if you procure energy from a supplier that buys European GOs, you are, unfortunately and probably unintentionally, undermining the UK’s transition to net zero.

View and download our detailed explanation of the FMD and find out how clean your energy supplier’s fuel mix really is.

It’s time to scrutinise your energy supply chain.

The reality is:

This is not a time to be paying lip service to environmental concerns.

We recently questioned 250 sustainability and energy managers who work at FTSE250 and equivalent size companies…

And one of the questions we asked them was: “What do you rely on to ensure your supplier is providing you with the energy they say they are?”

40% said they merely rely on their supplier to tell them, whilst 14% said they rely on the FMD of their supplier.

What’s more, only 15% of sustainability and energy managers at some of the UK’s biggest companies look up how many REGOS their supplier has redeemed – information which can be found on the Ofgem website.

The sad fact is:

It is not enough to put trust in your supplier’s word – the evidence is there to prove it.

As a leader or sustainability professional reporting back to your C-suite, it is time to get up, close and personal with your energy supply chain.

Now is not the time to have any skeletons in your energy closet.

At Squeaky, our energy mix is 100% clean. We only provide electricity that has been generated by the force of the wind, the power of water and the rays of the sun. Take a look at our Fuel Mix Disclosure for yourself.

MORE BLOGS SQUEAKY FUEL MIX DISCLOSURE

Claims against companies who greenwash by misleading or lying to customers about their environmental credentials are on the rise.

In fact, a collective of environmentalist groups recently filed the first lawsuit against the airline industry for greenwashing. And in June, a report exposed “a litany of misleading claims” by household names, including Coca-Cola and Unilever.

These are just two of hundreds of examples.

So far, voluntary action seems to have led only to a corporate world littered with false claims. The pressure is now on regulators to impart heavy sanctions on those who fall foul of greenwashing.

Now’s the time for you to get ahead and mitigate the risks you could face from tighter regulations on corporate greenwashing.

Big targets on paper do not equate to impact delivered in reality

Reaching net zero by 2050 is essential if we are to limit global warming to 1.5C and ward off climate breakdown. To get there, we need to see an unprecedented commitment of net zero targets from the world’s largest companies.

The good news here is that big targets have been set. In fact, net zero targets now cover 91% of global GDP and 65% of greenhouse gas emissions. All-in-all, this equates to around six times more than two to three years ago.

This is progress indeed.

However, major global analysis of more than 4,000 pledges by countries and companies around the world has recently uncovered something of significant concern:

Corporate climate targets which – compared to country-level targets – lack robustness, fail to meet minimum standards and, for two-thirds of corporations globally, are “alarmingly weak”.

This adds to the growing evidence which suggests corporations around the world are concealing their lack of action with grand net zero targets.

Sanctions for greenwashing are incoming

It wasn’t long ago corporations could make vague promises and baseless claims on their climate commitments without facing scrutiny.

However, the table stakes around sustainability have significantly changed.

Although greenwashing is nothing new, the consequences of corporate greenwashing have become significantly more grim. For those at the helm, covering up an environmental scandal could soon spell more disaster than the scandal itself.

What we are witnessing now is a long-overdue push by regulators across industries to tame the wild west of greenwashing:

In June 2022, the EU set out its plan to hold firms accountable for environmental violations:

The European Parliament and the Governments of EU member states have struck a provisional agreement on new reporting requirements. These have been designed due to increasing concern from regulators that greenwashing has become commonplace.

Businesses will be required to disclose the impact of their activities and supply chains on the environment and on people each year. Standardised reporting will be introduced so stakeholders can compare the performance of different companies.

The mandate will be brought in in phases and will apply to some large businesses from early 2024, and expand to listed SMEs from 2026.
In the same month, the UK’s Financial Conduct Authority (FCA) said it is ready to regulate ESG ratings firms to stop greenwashing.

Unrealistic expectations is putting corporate reputations at risk

It’s clear there has been a shift in urgency on matters of greenwashing. And it’s a shift that’s pressuring companies to face up to their sustainability journey in new and more serious ways.

However, many businesses feel unprepared to meet changing ESG reporting mandates. Especially those that are the most challenging to report against, such as Scope 3 emissions.

And there are other concerns to grapple with, too:

Our own comprehensive survey revealed sustainability and energy managers at FTSE 250 companies, believe their C-Suite has set unrealistic expectations regarding sustainability targets.

And 73% of those people admitted they are concerned about the reputational risk for the business of failing to meet these targets

Five ways to prepare your company for tighter regulations on greenwashing

We’ve listed out five actions you can take to ensure you can keep your climate promises and avoid being accused of greenwashing.

And the great thing is – you can put all of these in motion, today.

1. Ensure your communications team is the gatekeeper of your sustainability message

Companies are being criticised more than ever on how they market their sustainability impact. Those who claim to be, but are not genuinely on the sustainability journey, will come unstuck.

And this is where PR and marketing teams play a critical role. They have the skills and ability to articulate what ESG matters really mean in light of a given company’s overall environmental impact.

Give PR and marketing the autonomy to lead on your company’s communications around the environment , backed by the wisdom and knowledge of your sustainability experts. These professions will help leaders to resist stretching the truth about green-achievements the company is making.

2. Check your energy supplier is not falling foul of greenwashing themselves

74% of the UK’s top companies say they are now committed to powering their business with clean energy. It’s a smart move and an essential part of a businesses’ net zero journey.

However, there is growing concern that energy suppliers are, themselves, falling foul of greenwashing. We have uncovered plenty of examples of suppliers who promote their renewable tariffs under eco-friendly banners when in reality, they are sourcing their fuel from ‘dirty’ sources.

And the risk to your company could be huge. You may have publicly claimed that you only pump clean or green energy into your business. When in reality, it is energy from polluting fossil fuel sources.

Make it a priority to investigate the true makeup on your fuel mix. You can start by looking at your supplier’s fuel mix disclosure (FMD), which will give you a breakdown of the supplier’s energy sources.

But the FMD may only tell you half the story. A loophole in the system means energy supplier’s can mislead you about the makeup of their energy, even in the FMD. So you’ll need to dig deeper and look at how many renewable energy certificates your supplier has redeemed.

3. Be transparent and report externally on ESG initiatives

Long gone are the days when ESG was just a branding exercise. It is now the core requirement of any business strategy and it’s essential you prove that you are doing what you say you are.

Be proactive and take-charge by reporting externally on ESG initiatives. And not just reporting on what you are doing, but reporting the impact you are having. This will demonstrate to key stakeholders – shareholders, consumers, employees – that ESG is genuinely a strategic priority for you.

4. Prioritise Scope 3 emissions and plan ahead to avoid pitfalls

Arguably, Scope 3 emissions – emissions produced in the supply chain – are the most important emissions to address. That’s because they account for a whopping 80 to 90 per cent of the emissions connected with a great deal of end products.

However, Scope 3 emissions are notoriously complex to tackle. As a result, many companies sweep them under the carpet and opt to focus on the ‘easier’ tasks at hand.

It’s a risky move. Not least because the fragility of global supply networks has created a volatile environment to navigate.

Here’s an example:
Low emission materials, like green steel, are now in short supply, which means that the cost for these materials has skyrocketed.

Companies that planned ahead and locked in their supply of greener materials will be safe in the knowledge they can meet the emissions targets they set out.

On the other hand, companies that have not secured their supply will be forced to either pay a steep premium for low emissions materials so they can meet their targets. Or, break the climate promises they’ve made to stakeholders and source cheaper, polluting materials.

5. Investigate your own company, now.

The truth is: regulatory and legal action is on the way. The quicker you accept this as truth, the better.

Engage with compliance executives now, and it could help you prevent potentially catastrophic blows in the years to come.

Plus, it’s proof to the board that you’re taking your company’s environmental responsibility seriously.

Do not delay taking action

The reality is:

Companies that fail to get their stall-in-order on climate matters will be held accountable.

Act now, or risk facing potentially catastrophic penalties.

I know which path I’d take.

READ MORE BLOGS & INSIGHTS