This article addresses 9 key levers that wind farm owners should take into account when negotiating a PPA in order to optimize their project’s risk-return profile.
For many years, and across many European countries, onshore wind projects have relied on bilateral Power Purchase Agreements (PPA) to sell their energy to third-party offtakers, usually utilities or licensed energy suppliers. These PPAs can be structured in multiple ways given the bilateral nature of the transaction, but they are usually in line with the applicable remuneration scheme for renewable assets in each country. For instance, in a Contract-for-Difference (CFD) scheme, whereby the project receives a variable premium from the government on top of the reference market price, the PPA price will usually be indexed to reference price to avoid any basis risk and also to fix the total price (i.e., PPA plus the premium). In cases where renewable assets are incentivized through the issuance of Renewable Energy Certificates (REC), such as green certificates, the PPA parties have much more freedom to negotiate alternative structures, on both the power and REC offtake legs.
In the offshore wind segment, though, PPAs are now starting to get traction, either because governments started to award concessions under a CFD scheme or because some projects won auctions with a zero-subsidy bid (which in Germany and in the Netherlands means that projects will be fully exposed to market prices).
On the consumer side, many large companies and industrial clients are now choosing to source renewable energy directly from project developers, not only to negotiate a lower long-term cost for energy consumption, but also to facilitate investments in new renewable assets. Such agreements, referred to as corporate PPAs (CPPA), are being used by many developers to improve bankability for projects without a subsidy scheme and fully exposed to merchant risk. In 2019, according to WindEurope, a total of 2.5GW of renewable energy assets have been backed by CPPAs, of which approximately 1.5GW in onshore wind and 250MW in offshore wind.
Thus, a PPA is a critical project management tool not only to secure project financing but also to optimize the project’s economics during the operations phase.
What are the implications of PPA obligations across the project’s development, construction, and operations phases? And what levers can developers manage across the different commercial and technical interfaces (from service agreements to energy offtake) to maximize their project’s EBITDA?
As we will see in this two-part article, most of the implications depend on the type of energy buyer, the type of offtake agreement, the desired risk-return profile of developers and key contractual terms. These will facilitate or pose a challenge on the developer’s ability to maximize the project’s economics by aligning the O&M strategy with PPA mechanics.
When structuring and negotiating a PPA, there are several levers that developers should bear in mind, which can potentially impact the project’s ability to maximize profitability during its lifecycle. But before addressing such levers, it’s worth distinguishing three high-level PPA models that are used to implement different energy offtake strategies.
These refer to what have been the mainstream offtake strategy so far, whereby the project developer and a licensed energy supplier or trader sign a bilateral offtake agreement. The licensed supplier will represent the developer in the wholesale market. It’s typically a seller’s market where developers maximize commercial terms by launching competitive offtake tenders.
This usually consists of a three-party agreement, whereby an industrial client directly offtakes the energy produced by the project to cover its power consumption. Usually, neither the developer nor the corporate client have a license to operate in the wholesale market so the transaction is intermediated by a licensed energy supplier. The Corporate PPA is a buyer’s market where corporate clients minimize their energy costs by launching competitive energy procurement tenders.
This type of framework consists of having a market agent (a licensed energy supplier) that represents the developer in the wholesale market. The market agent sells the project’s energy and pays backs to the developer the market price minus a management fee. Given the full exposure to market prices, some developers choose to complement this agreement with a financial PPA, whereby the offtaker agrees to fix the price for all or a part of the project’s production.
The PPA negotiation levers are directly affected by the choice of energy offtake strategy described above. We will focus on nine key areas, as described in Figure 1.
Figure 1. The 9 key levers to consider when negotiating a PPA.
In projects that have won a CFD auction and have a long-term concession to operate, the term of the traditional PPA does not necessarily impact the project’s bankability (there is only a PPA replacement risk). In such cases, the PPA price will be indexed to the CFD reference price and the offtaker will charge a management fee for representing the project in the wholesale market and potentially a balancing fee to manage project imbalances. The project developer may want to keep a shorter term contract or guarantee exit options in order to potentially benefit from lower fees due to increased competitiveness on the offtakers side.
For merchant projects, the Corporate PPA plays a pivotal role to secure project financing and the term of the contract is critical to provide the lenders with sufficient cashflow visibility in the long run. Usually, the term of the PPA mimics the term of the financing agreements. To secure such a long-term commitment from the corporate client, the developer usually accepts an offtake price below market price expectations.
Overall, the developer should balance the ability to optimize the offtake terms on a regular basis (by entering into shorter term PPAs) and the benefits of securing a long-term offtake commitment, potentially at a fixed price and increased project bankability.
The PPA should reflect the desired risk-return profile that the developer wishes to assume during the operations phase. The main risk levers to consider are: price risk (i.e., price volatility), volume risk (i.e., project produces more or less than expected from long-term modelling), counterparty credit risk (i.e., default on contract payment obligations), mark-to-market (MtM) risk (i.e., locking-in commercial terms under changing market conditions) and imbalance risk (i.e., mismatch between scheduled and real production).
There are multiple ways to manage the price risk within a PPA. The developer will either opt for a fixed price to offtake all energy or a variable price referenced to a market price index. An intermediate solution is often used, whereby the parties either agree on a fixed price for a part of the energy volume, a variable pricing with a floor mechanism or a collar structure (with a floor and a cap on a variable price). While in Corporate PPAs the parties usually rely entirely on a fixed price for, at least, 75%-80% of the expected production, in traditional PPAs the pricing terms can be much more complex. A levelized price analysis should be undertaken to adequately assess all potential pricing options. In case no risk mitigation measures have been considered under the PPA, the developer can always procure price hedge tools provided by financial and trader agents to optimize the project revenue based on market price expectations.
Depending on the type of PPA, the volume risk can be managed either by the developer or the offtaker. While in a traditional PPA the developer is usually able to transfer all volumetric risk to the offtaker (which on its side can easily balance any project’s under or over production within its diversified asset portfolio), in a Corporate PPA the party assuming the volume risk depends on the scope of the agreement. In case a specific production profile offtake is agreed (on an hourly or monthly basis), the producer will bear all volume risk and will have to settle any short or long positions with separate contracts (usually with the licensed energy supplier serving as an intermediate to the transaction). In a pay-as-produced scope, the volume risk is shared by both parties: the corporate client is obliged to pay for any volume produced but the producer is liable in case of under- or over-performance outside certain thresholds.
While in a route-to-market there is no considerable counterparty credit risk (only the replacement cost of signing a new market agency contract), in traditional and corporate PPAs the credit worthiness of the offtaker plays a key role in the transaction and needs to be adequately assessed. Special attention is given to a corporate client’s ability to keep their payment obligations throughout the long term duration of the offtake agreement. The developer has to assess credit security requirements based on the client’s probability of default and expected default. Credit securities usually take the form of bank guarantees or parent company guarantees (PCG) and should provide enough security for project lenders. In traditional PPAs, some offtakers usually price the credit security into the PPA fees, therefore, the developer should always ask for a breakdown of all pricing components.
Whenever the parties to a PPA lock-in commercial terms in a long-term agreement, both parties open an underlying mark-to-market risk, which increases with the term of the contract due to the higher uncertainty associated with what will be fair market conditions in the long term. The parties should adequately assess what are the market fundamentals in the long run and what impacts should these have on market prices. On the contract side, the PPA parties can mitigate this risk by securing exit options throughout the lifetime of the contract.
As a project developer, you should also decide whether to manage imbalance risk or outsource it to the offtaker or market agent. Is your core business the development of competitive projects or do you also want to operate on intra-day power markets? Do you have a large asset portfolio that allows you to benefit from an imbalance diversification effect? What is the expected yearly imbalance cost? These are some of the questions that you need to answer as a project developer before agreeing to a specific solution under the PPA or market agent agreement.
Non-performance can be related to not delivering minimum energy volumes, defaulting on payments, failing to achieve a long-stop date for project COD or not delivering minimum installed capacity obligations under the PPA. The nature and relevance of non-performance will depend on the type of energy offtake agreement, the term of the contract and the risk assessment that both parties assign to the transaction. Both parties usually provide a PPA financial security in the form of bank guarantees or PCG, depending on the risk assessment, to cover any shortfall of production, project delays or payment default. As a project owner you should be prudent and have clear visibility on the installed capacity and energy delivery commitments you take under the PPA to avoid falling below agreed minimum thresholds and triggering penalty clauses.
In a route-to-market agreement or in a PPA fully indexed to market prices, termination does not pose a considerable risk to the developer as there is only a replacement cost of finding a new counterparty. On PPAs with long term durations and fixed pricing arrangements, special care must be given to the termination clause given that it defines under what circumstances one of the parties is entitled to terminate the agreement and what are the corresponding consequences. Namely, the developer should guarantee that a fair method is used to calculate the net present market value of the PPA which will be a relevant component in determining the termination amount (which is usually capped).
For long term PPAs that represent strategic portfolio positions on both parties, the project’s development timeline is critical for the offtaker and there are usually long stop dates for the commercial operation date (COD) of the project. As a project owner, you should thoroughly assess the implications under the PPA in case there are delays in the construction phase given that it might entitle the offtaker to re-open the commercial terms (and in case both parties fail to reach a new agreement, the project owner might be liable to pay a termination amount to the offtaker). Are you aligning these PPA implications with your EPC agreements?
The offtaker usually requires specific commitments from the project owner during operations phase to ensure that the project performs according to good industry practices and that no operational risks pose any material hazard to the offtaker’s business. The main implications are twofold. Firstly, the project owner needs to guarantee that certain project management competences and procedures are in place to fulfil such commitments (communications procedures, operational and financing reporting, metering requirements, availability of forecasted outages, etc). Secondly, the project owner must guarantee flexibility under the PPA in order to optimize O&M activities and maximize the project’s EBITDA.
In a long term agreement such as a PPA, in a heavily regulated sector such as the energy sector, the parties usually rely on a change in law clause to have the ability to keep the contract’s economics balanced in case of major regulatory changes. In case of a change in law, the parties must preserve the relative benefits, liabilities, risks and rewards under the PPA but neither party is obliged to accept any proposed amendments. An ex-ante agreement on specific changes to the contract in case any regulatory scenario materializes is a prudent practice and the parties should also agree on events that shall not trigger the change in law clause. As a project owner, are you thoroughly assessing your exposure to regulatory risks?
The PPA parties shall also regulate what are the procedures in case any event occurs that materially impairs the ability of the parties to balance their rights, benefits, liabilities, risks or rewards under the agreement. Such events could be due to the disappearance of a market index without being replaced by an alternative price reference or to any material changes imposed by the market operator or the transmission system operator. The parties will usually agree on a fallback procedure to determine in good faith an alternative solution that closely represents the economics under the PPA.
The PPA is a critical document for project lenders and equity investors, which rely on its ability to provide long term visibility on revenue cashflows. They wish to be involved with a creditworthy project and in many occasions impose restrictions on the PPA parties’ ability to assign or transfer the PPA. Having predictable cashflows with a low risk profile is key to secure a bankable project with competitive financing terms. To mitigate their risk exposure, lenders may require step-in rights into the project which are set forth in a separate direct agreement between the lenders and the offtaker. As a project developer, are you taking the necessary measures to negotiate a financeable PPA?
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