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
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.
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.