Typical PPA terms and risk allocation

Usually the PPA will set out the maximum annual quantity mechanism, with payment based on an output basis.

Corporates don't always take all the capacity from a renewable facility, and often prefer not to due to the risk of asset transfer pursuant to lease accounting, therefore sharing of off-take is likely to become more common.

Today the force majeure in PPAs is limited, especially in those PPAs subscribed between generators and the distribution companies. In such case, the generator must acquire energy from the spot market to comply with the agreed supply.

Also, in the last couple years, generators are facing financial risks due to decoupling of energy prices between injection and withdrawal points.

Some of the causes are transmission congestion, increase in the costs of providing ancillary services, mismatches between the injection and withdrawal time physical profiles, increase in costs per operation to the technical minimum.

Within the short-term solutions, there is the modification to the Regulation of power transfers between generating companies, to allow the progress of storage.

Given the private nature of contracts, it is difficult to generalise on commonly used pricing arrangements across CZ market.

The price of electricity is often adjusted in different ways in the contract; often the price of electricity consists of a fixed component, which covers the investment made by the producer, and a variable component, which relates to the quantity of electricity supplied. The same electricity price may be guaranteed for the entire duration of the contractual relationship or for individual sub-periods, with the possibility of further adjustments according to pre-agreed conditions.

The PPA agrees on the minimum and maximum amount of supply per year that the generator is obliged to provide to the customer. It is then common for the price arrangements to include an obligation for the customer to pay the fixed component of the electricity price even if it does not take the agreed minimum amount of energy per year; this ensures that the generator recovers its investment.

A range of pricing mechanisms could be employed in a cPPA. The following are the commonly used mechanisms in Egypt:

• A fee corresponding to the difference between the government tariff and the target rate set by the contract. This pricing mechanism is more commonly used in most of the cPPAs in Egypt.
• Fixed price (with no inflation) for the duration of the cPPA. However, this is rarely used given that usually this price will be higher than the government price.

One of the typical cPPA risks is the lack of free market structure so the buyer is generally the sole buyer of the electricity. If there is a dispute between the generator and the buyer, the generator won’t be able to sell the energy generated to any other entity.

Change in law is a common risk. Any legislative change or binding court judgment which changes the legal nature poses a risk of changing the commercial benefit of the transaction for the parties.

Not applicable

According to the recent corporate PPA that have been executed during the past 2 years, the term is typically around 21 or 25 years.

However, depending on the maturity of the installation concerned, the corporate PPA can have a term from 5 years (brownfield projects) to 25 years (greenfield projects).

To date there have been very few corporate PPAs deployed in Germany and there is a lack of publicly available information on the specifics of relevant transactions.

In many cases, corporate PPAs have only been used for marketing the production and sale of renewable energy from existing installations that – after 20 years following their commissioning – fall outside the support scheme. Therefore, at this stage, it is difficult to comment on general trends.

From an overview of the few disclosed deals in the Greek market, the price agreed in the context of a PPA usually ranges from EUR32/ΜWh to EUR45/MWh.

The allocation of project risks determines the fair value of each PPA closed. So when the agreement deviates from the industry’s standard terms (eg having a variable rather than a fixed volume) it is expected for the final agreed price to widely differ from the market average.

• Credit worthiness of purchaser.

• Unexpected/ unforeseeable events (force majeure).

• Risks related to the development, performance and volume production of the renewable power plant.

• Adverse movements in the market price of electricity.

• Legislative or regulatory changes.

Short-term corporate PPAs (for a term of less than 1 year) usually have fixed prices.

Long-term corporate PPAs tend to have floating prices and are based on the market average price for electricity minus a fixed amount.

Other typical risks are:

• financial risk linked to the economic and financial standing of the purchaser;
• construction delay and capacity shortfall; and
• force majeure.

Corporate PPAs: while there are currently limited examples, for direct wire PPAs, prices tend to be fixed and subject to escalation. 

PPAs with KPLC: the tariff applicable per kW/h is fixed, and KPLC is obliged to accept up to a certain capacity for the term of the PPA (take or pay basis).

Corporate PPAs: unknown but likely negotiated on a commercial basis.

PPAs with KPLC: 20 – 25 years.

Corporate PPAs: unknown but likely negotiated on a commercial basis.

PPAs with KPLC: previously always take or pay (but see above re: movement towards take and pay).

Corporate PPAs: unknown but likely negotiated on a commercial basis.

PPAs with KPLC: political risks are typically accepted by the offtaker and backstopped by the Government (but see our note above re: this changing landscape).

Renewable technologies which may not be dispatched by the off-taker, particularly large dams, wind and solar, only follow the take or pay method for the deemed Capacity Payment (CP) method ("limited volume").

The take or pay method is generally used in the long term gas supply agreements. PPAs, particularly thermal generation facilities, such as gas turbines, engines fuelled by diesel or heavy fuel oil and coal-fired generation facilities, briefly reference this method, however only for redirecting payment to the gas supply agreement.

There are other typical risks, which include:

• force majeure events;
• political and legislative risks; and
• change in control.

Most of the PPAs in Norway have, until recent years, been based on "fixed price" for an agreed time period to ensure certainty for future energy prices and stabile revenue. Such PPAs are have relatively straightforward clauses, defining the agreed fixed time period of delivery, fixed volume/quantity, point and price model. Both seller and buyer/offtaker have an obligation to sell and deliver, buy and accept the agreed quantity regardless of actual production / consumption of power. Since the Norwegian energy market is quite predictable and stable compared to other European countries, it will usually be possible for a seller to deliver power at an agreed delivery point. The seller will be responsible for delivering the agreed fixed volume under the PPA from the market if the seller's own energy production cannot cover the agreed delivery obligation. Under fixed price PPAs the seller has high/full risk related to delivery obligations of the volume. Sellers with large portfolios normally handle this risk very well, but this must be considered from case to case. In the past few years there has been a trend to include "facility force majeure" clauses handling variable production capacity (eg in wind power projects), where the number of turbines and wind from nature will decide the total wind production capacity per year.

In the past five years a new trend of using "pay as produced" PPAs has emerged. A seller's delivery obligation will then relate to either the entire or a fixed part of the actual production from specific energy facilities. Some more tailoring of this type of PPA is needed compared to the fixed price PPA, and buyers with steady offtake of power (to sourcing or hedging purposes) may find this type of PPA less suitable. It all depends on the seller’s and buyer’s positions and market conditions.

PPAs to supply regulated customers are subject to prices set by OSINERGMIN.

For free customers it will depend on the nature of the free customer though usually fixed price subject to revisions to reflect changes in key costs.

For PPAs which supply regulated customers the term will typically be 10 to 20 years as there is a regulatory limitation to the volume of energy that can be purchased through short-term agreements (i.e. 5 years or less).

Theoretically, free customers should seek long-term agreements as the usual tendency is for prices to increase. However, customers may decide to agree otherwise based on their market knowledge and predictions. 

The duration of the cPPAs is usually linked to the lifecycle of the project and financing requirements. These are usually long-term commitments (10-15 years).

Each PPA has its own specificity and the price structure is differently negotiated. But as a general rule, Senelec agrees with the independent producer on an initial price when the agreement is signed and then they set out in the PPA mechanisms for calculating the price for each year until the end of the contract.

In some PPAs, Senelec and the independent producer have made provisions for the annual revision of the electricity purchase price with an adjustment rate agreed in advance.

The major risks that may affect the independent producer are, on the one hand, a risk of a change in law or taxation that could negatively affect the provisions of the contract or the benefits of the independent producers or, on the other hand, a political risk with a change of political regime that could terminate all the existing agreements.

Unfortunately, the PPAs we reviewed do not include stabilization clauses that could anticipate these risks in advance and address them before they arise.

Foreign denominated input costs as many components of the facility are still imported.

Recently, pandemic related risks have been prevalent (particularly whether the impacts of the pandemic constitute force majeure events etc).

Wheeled CPPAs may offer no guarantee of system availability due to the fact that, in certain circumstances, electricity is wheeled through the national grid.

Changes in law, particularly regarding recently promulgated pandemic related legislation (disaster management regulations etc).

With regards to pricing agreements, there are several possible options: fixed prices, step prices adjusted over the term, and price indexation (sometimes with caps, floors and collar arrangements).

Hybrid forms of these variants are possible. Given the private nature of contracts, it is difficult to generalize on commonly used pricing arrangements across the Spanish market. Corporates have however been prepared to offer higher fixed prices, which can be attractive to generators. Due to the rise in energy prices, use of market indexed prices has increased. A widely used formula is a discount on the market price.

There are different kind of products. For instance, in the physical-offsite PPAs, we find:

• PPA "as generated", in which the offtaker consumes all generation produced by the plant (it is the most competitive product in terms of price, but the most risky);
• PPA "baseload", in which the renewable developer is in charge of converting the plant’s gross generation into a base load (it keeps a good balance between price and risk);
• PA "as consumed", in which the renewable developer is responsible for converting the gross generation into a curve that closely follows the customer consumption (only available to companies with a large generation portfolio).

PPAs relating to the sale to STEG of the surplus of electrical energy produced from renewable energies for self-consumption are concluded for a duration of 20 years. It will be renewed by tacit agreement, for a period of one year, unless terminated by either party by registered letter with acknowledgement of receipt at least one month before the end of the current year.

(Article 21 of the Minister of Energy's model contract of February 9, 2017).

PPAs concerning the sale of electrical energy from renewable energies in order to sell it, in full and exclusively to STEG, are concluded for the duration corresponding to the duration of the authorization. It could be extended in case of extension of the duration of the Authorization in accordance with the decision of the Minister in charge of energy on the advice of the Technical Commission and will be the subject of an amendment to the Contract.

(Article 4 of the contract -type provided for by the Order of the Minister of Energy of August 30, 2018).

PPAs relating to the sale to STEG of electricity from gas derived from hydrocarbon exploitation concessions, are concluded for a period determined by the conceding authority.

PPAs are volume-limited. Each contract determines the volume of electricity to be produced, as well as the volume of surplus energy to be sold to STEG.

For example, in the context of the sale to STEG of electricity produced from gas from hydrocarbon concessions, the volume of electricity sold for each concession is 40 MW.

(aforementioned Decree n°2002-1318 of June 3, 2002).

This is also the case for the production of electricity from renewable energies to meet the needs of local consumption subject to authorization, where the volume of energy is previously fixed by the minister of energy. (Article 14 of the aforementioned Decree No. 2016-1123 of 24 August 2016).

Under the PPA relating to the sale to STEG of electricity generated from renewable energy subject to authorization, and in case of recourse of the parties to arbitration to settle disputes, the arbitral sentence rendered will be final, will bind the parties, and will not be subject to appeal. In addition, the provisions relating to emergency arbitration will not apply.

(Article 23 of the Order of February 9, 2017, as amended by the Order of August 30, 2018, mentioned above).

Under the net metering models across the region, plants have tended to be sized to prevent substantial over-generation. The reason being that under the net metering schemes, credits against future purchases of power from the national utility tend to be time-limited, making a consistently positive position vis-à-vis the national utility uneconomical. 

However, with the roll-out of battery technology, we expect the scale of rooftop solar to be revisited and the percentage of power taken from the grid by companies with rooftop solar to reduce.

There is a lingering regulatory risk in relation to solar leasing and hire-purchase models in the region’s net metering models.  Such models are designed for self-generation as opposed to third party generation. 

This risk allocation has been addressed through a compulsory purchase of the plant.

Businesses that trade internationally or have operations overseas are likely to be exposed to foreign exchange risk arising from volatility in the currency markets. One of the typical cPPA risks is, therefore, currency exposure, with EU cPPAs being commonly priced in Euros. Concerns about currency fluctuations between sterling and the Euro as a result of Brexit are, therefore, key considerations for parties to UK-EU27 cPPAs. 

Change in law is a common risk, resulting from the legal nature of GoOs. Any legislative change, binding court judgment or changes to network codes which changes either the legal nature of the GoO or more broadly changes cost sources, including changes to the balancing regime or transmission and distribution costs, pose a risk of changing the commercial benefit of the transaction for the parties. The implications of Brexit will need to be carefully considered for change in law provisions.