The problem with ‘additionality’ in renewable energy

Last week I co-hosted a webinar on the state of the European PPA market, which was a sort of synthesis of the work we’ve done over the past 18 months in helping several public and private sector organisations on various aspects of commercial power purchase agreements (PPAs). These PPAs are long-term bespoke contracts for power between two parties and over the past few years we’ve helped support live PPA deals, PPA auctions, PPA policy formation, and PPA financial instrument design. As a result we like to think we’ve got a reasonably rounded view of what they mean in the context power systems. With that in mind I thought I’d try summarise my own view on an issue that comes up again and again: additionality

Let’s start with the fact that commercial PPAs have been playing a not-insignificant role in decarbonisation of power systems. We estimate they could account for 10 – 25% of contracted power in wind and solar in Europe by 2030. In doing so they aid deployment because they de-risk the revenues of new projects by replacing exposure to market power prices with a fixed price contract. This in turn lowers the borrowing costs of the project, in theory tipping it into financially viability.

From the corporate buyer’s perspective, the two biggest drivers for doing a PPA are value and additionality. Value is if the contract can beat wholesale power prices and additionality is the ability to say ‘our buying of this renewable power is critical to whether this renewable project happens’ because the PPA tipped the project into financial viability. Additionality is the reason we now have super bowl halftime commercials with Budweiser logos on wind turbines. Big brands with big value and reputation attached to those brands are leaning into additionality to demonstrate that their commitment to decarbonisation is serious*.

(*Whether speeding up utility-scale renewables deployment is the most impactful thing corporate’s should be doing to speed up decarbonisation of the systems they operate in is a whole other area I won’t attempt to cover here but worth noting some of my colleagues - Alex Weir, Martha Samano, and Mark Turner - have recently grappled with this in detail on behalf of corporates in their work. Google have also put some thought into minimising their emissions impact is on the power system on an hourly basis, with a view to being 24/7 powered by renewables by 2030)

This pursuit of additionality has been useful so far - this is because through these PPAs corporations-as-energy-users end up shouldering some of the financial risk associated with investing in decarbonising projects. The remainder is shouldered by governments, utilities, financiers and project developers themselves. Governments have typically played the role that these corporates now play, providing feed in tariffs or contracts-for-difference which perform the same task of de-risking project revenue, with any government exposure typically passed onto consumers in the form of levies. So where a commercial PPA genuinely reduces that government burden, it can reasonably claim to be additional and to be speeding up renewables deployment. Utilities, lenders, and projects themselves do also shoulder some of this revenue risk but to date this has only ben where projects look like delivering very attractive returns - for example in Spain.

So why is additionality limiting? Because it’s hard to achieve and harder to prove. Firstly, as a corporate, it requires fixing your power price for 10 – 15 years, introducing business risk if your competitors are sticking to a mix of spot prices and 2 – 3 year forward hedges for their power. If energy is a large part of your cost base (as it still is for a wide range of the economy) then that risk is significant. Secondly, you need to be a BIG corporate. Specifically, you need to be investment-grade-balance-sheet-big in order for the renewable project’s lenders to see the PPA as ‘bankable’ revenue. This isn’t an issue for Budweiser or Google but it easily stops an independently-owned aluminium smelter, or a steel producer struggling for profitability who can’t risk any change to their credit rating. On top of this, claiming something as additional is a free-for-all. There is no regulation or auditing of claims beyond that of the contracting parties themselves.

Given it’s so hard, why do corporates need additionality? What else is there? The need arises from the absence of clear and appropriate mechanisms that facilitate corporates contributing to decarbonising power. The biggest experiment in providing such a mechanism has been the European system of ‘guarantees of origin’ (GoOs). These are certificates that prove your energy came from a specific renewable source. This system works in theory for sharing revenue risk capital if there is a minimum price for GoOs that is material in the context of a renewable project’s revenues.

But GoOs don’t help get projects built. The price of GoOs floats according to supply and demand and supply has largely outstripped demand so far, making them cheap and consequently meaning they provide almost no contribution to speeding up decarbonisation of the power system. European GoOs are currently trading at 20 – 40p / MWh, which is about 1% of the price of the actual power it’s attached to. Sadly, GoO prices are especially prone to stay depressed where GoOs can be purchased from subsidised projects (e.g., UK). When this happens, their only contribution to the market is to allow utilities to market 100% green tariffs by purchasing GoOs i.e. without having to really pay for it. A classic example is the utility Bulb, Europe’s fastest growing startup, who make a point to market the quantity of CO2 emissions their tariffs abate, but who also claim to buy from subsidised assets such as the Beatrice Offshore Wind project. These projects only exist because government (and by extension consumers) shoulders the revenue risk. In short, those emissions would have been abated without the green tariff.

Yet just like the aluminium smelter or the embattled steel producer, Bulb doesn’t (presumably yet) have the balance sheet to achieve additionality. Even with the best of intentions it can’t do much other than greenwash with GoOs. And this is where the current system of GoO + PPAs failing - to contribute something material to renewables deployment i.e. to broaden the scope for helpful contributions by corporates, the buyer doesn’t need to provide additionality, it just needs to share some of the risk capital, taking on more risk or paying a premium vs what it could have done through normal retail/wholesale power products. That means committing to a combination of price and contract length that is beyond what is available in liquid power markets. For most liberalised power markets that means going beyond 2 – 3 years. A fixed-price PPA for 5 - 7 years will almost never provide additionality but it will materially de-risk someone’s portfolio of generator revenues, and that someone can allocate that risk capital back into other projects. While such products may not be enough for big brands who want the additionality story, they can bring much more corporates and generators to the table because:

a)      Credit risk is lower: at 5 – 7 years than at 15 years – the aluminium smelter that isn’t seen as bankable over 15 years often is over 5 years. 5 – 7 years is also much closer to the business planning and investment cycle.

b)     Business risk is lower - a corporate can be comfortable pivoting away from a location without having to unwind a 15-year contract.

c)      More projects are in play: a generator can find a market for de-risking assets that are already operational, e.g. those ‘merchant’ projects where the generator took the risk capital or older assets rolling off government subsidies. Win-win.

Utilities with very strong balance sheets also have an opportunity here. If they are willing to shoulder some or all of the risk required to bring the project to financial close, they can cut that exposure up and divvy it out to corporate customers in smaller chunks e.g., taking on the 10 -15 year PPA and then apportioning some of that risk out in the form of 5 – 7 year PPAs to its corporate customers, often solving for some of the complexity associated with deal execution in situ. Some are trying to do this, others are convinced that their customers will not be willing to embrace that risk sharing. If the latter are proved right it only enhances the case for the regulator stepping in.

But markets need to design-in risk-sharing as a feature. Otherwise the validity of claiming risk-transfer is as shaky as the claim to additionality, plus there is also the risk that government auction schemes are designed to do too much of the heavy lifting, leading to a lack of competitive projects offered by from generators. Regulators can act to legitimise risk-transfer in a few ways, each carrying their own risks. One easy-win is narrowing the scope of GoOs to projects without any government support. Another more ambitious option is to redesign them fundamentally to link more clearly to risk sharing. Alongside this, government auctions need to clearly make space for the PPA market or design it in. e.g., by allowing government support schemes to offer only partial risk sharing. No existing scheme to my knowledge mandates this although the most recent Polish auction schemes allow for it. Each of these mechanisms carries the risk of disrupting the flow of new projects at a time when targets are becoming more and more ambitious. But if done right they have the potential to unlock a vast swathe of mid-market corporate buyers with their own steadily increasing green ambitions.

If you’ve got your own views on this or if it’s something your organisation is grappling with, I am keen to hear from you. As full disclosure the above views are my own and not Baringa’s but have in no small part been influenced by some great discussions with my colleagues Ed Crosthwaite-Eyre, Alex Weir, and also with Dominik Ruderer of the European Investment Bank