Power Purchase Agreement (PPA)
Renewables power purchase agreement is defined in Article 2(17) of Directive (EU) 2018/2001 of the European Parliament and of the Council of 11 December 2018 on the promotion of the use of energy from renewable sources (recast).
According to this provision it means “a contract under which a natural or legal person agrees to purchase renewable electricity directly from an electricity producer”.
More descriptive delineations see power purchase agreement (PPA) as an agreement between an offtaker and a renewable energy developer that allow the offtaker to purchase power directly or indirectly from the developer on a longer term basis for a price level agreed by the parties, where the main participants typically are:
- renewable energy developers,
- corporate offtakers,
- utility companies (responsible for the power distribution), and
The duration of the contract ranges between 1 and 15 years although in the Nordics some of the longer deals include Norsk Hydro’s 29-year PPA from Övertungen in Sweden and Alcoa’s 40-year PPA with Landsvirkjun in Iceland (see "Changed trading behaviour in long-term power trading, An analysis of the recent development in power purchase agreements in Norway", the Norwegian Energy Regulatory Authority (NVE-RME), 6 January 2020).
The same source also mentions that in the Nordics "the power associated with a PPA is transferred through the power grid as any other power. The power traded through the PPA is registered as a trade on the market exchange to allow for the market clearing and balancing. Depending on the structure of the PPA, the one responsible for ensuring sufficient power delivered will buy additional power on the exchange and vice versa for the consumed power".
Financial market innovation useful especially for parties located in different grid networks (or with multiple delivery points) are virtual PPAs (VPPAs).
The idea consists in applying purely financial contracts like contract for difference (CfD) or a long-term commodity swap transaction (including put/call options providing a price collar) - usually 2002 ISDA Master Agreement - in place of a contract for the sale electricity (i.e. physical electrons).
In this model physical flows of electricity are entirely segregated from the financial flows resulting from the VPPA.
In consequence the renewable generator sells the electricity into the wholesale market of its location (at the available wholesale price), the off-taker’s contracts for electricity delivery also remain unaffected - both are not addressed in the VPPA (therefore there is no need to manage in VPPAs risks involved with physical delivery, like balancing, etc.).
The element that matters most in the VPPA is the “strike price” - i.e. guaranteed, fixed price for the agreed volume of power output generated by producer and delivered to an agreed delivery point.
The key equation is as follows: if the price achieved by the generator is greater than the strike price, the generator pays the positive difference to the buyer, in the opposite case the difference up to the strike price goes to the generator.
Using VPPAs model does not conflict with demonstrating that the sustainability objectives of the off-taker have been met since under VPPAs the guarantees of origin (GOs) are also usually transferred to the buyer.
Using VPPAs - financial instruments - is involved with the proper application of financial market regulations, in particular MiFID (see Virtual PPA contracts - qualification under MiFID and its consequences, Tadeusz Zieliński).
Such contracts must be reported in accordance with the EMIR (Reporting Virtual PPA contracts under EMIR, Tadeusz Zieliński).
VPPAs might also be subject to derivative accounting rules (IFRS accounting outline for Power Purchase Agreements, WBCSD, January 2018,
Profile of volume
The aforementioned document of the Norwegian Energy Regulatory Authority (NVE-RME) of 6 January 2020 gives also some background information as regards the volume’s structures applied in the PPA Nordic market.
It observes, in principle the power delivered in a PPA is typically either delivered “as produced” or as baseload.
For either option, someone needs to match generation with consumption either through the market or by controlling production or consumption - this responsibility can be given to the producer, consumer or a contracted third party (“as produced” is common for wind and solar farms and is most attractive to developers of these type of projects since it removes some of their risk.
If this power is to be purchased by the consumer, it needs a third party with sufficient flexible generation sources, such as hydropower, which can be used to match the demand.
The market for utility PPAs is largely driven by the need of the developer to remove some of their production risk.
This risk is then acquired by utilities with larger portfolios who can shape the power into baseload. Some larger energy producers or consumers take on the balancing and shaping responsibility themselves.
Typically, they will have a department working full-time with balancing or hold the necessary assets to ensure the preferred shaping.
For smaller producers or consumers, it is more often preferred to designate a third party that provides shaping services for a fee as part of their business.
In practice, shaping is often done by the shaping party by optimising the production and consumption side separately and trading residual production and consumption with the market exchange.
As regards balancing on the Nordic market balancing responsibility towards the TSO can appear on both the producer and consumer side of the grid connection.
The balancing responsibility often lies with the consumer who is responsible for balancing their consumption in relation to the baseload purchase.
In practice, this is often done by a third party for a fee.
The balancing responsibility becomes even more important in cross price zone PPAs. In these cases, producers or third parties with a large production portfolio in both price zones are useful.
The producer or third party will turn up production in one price zone and down in another to ensure balancing.
This will make it more cost-effective to be the balancing responsible.
PPAs face special accounting treatment and may fall into leasing (IFRS 16), embedded derivatives (IFRS 9) or non-derivative (IAS 37) categories. Tax incentives/subsidies may also have accounting impacts. The correct accounting treatment can ensure that the PPA procurement will not impact the profit and loss statement (PnL) - see the Decision Tree for PPA Accounting Treatment at “PPA – a vehicle for utilities to become platform provider of renewable energy?”, PwC.
Given that renewable energy generators are intermittent and, on the other side, the corporate off-taker usually requires a baseload shape of the delivery profile (due, for example, to the production demands), classic (bilateral) PPAs suffer from some inconveniences for both sides.
These shortcomings can be overcome with the help of additional intermediary (so-called “sleeve”), which - for a premium - “sleeves” the power through the grid and sells power to the corporate at its site.
Among the sleeve's usual offers are the balancing of the electricity profile of the off-taker as well as the topping up the profile with extra electricity, if needed.
The specialised services in the sleeve’s portfolio cover also feed-in forecasts, marketing green certificates or guarantees of origin or de-risking original parties from some inherent dangers like default/insolvency risks of a contractual partner.
The sleeve is able to manage these risks being a licensed electricity supplier (often a utility) aggregating various generators to a portfolio, creating balancing group, etc.
In addition, the transfer of guarantees of origin (GoOs) usually takes place.
Practically, in a sleeved PPA after both parties (the developer and the off-taker) enter into contract the off-taker appoints a utility to act as its agent and sleeve the power (through a back-to-back supply arrangement between the off-taker and the utility) in exchange the off-taker pays the sleeving fee.
In the main part of the deal the developer delivers power physically according to contract and the off-taker pays for power at the agreed price.
The intermittent electricity output of the renewable generator is typically credited against its electricity obligation, but specific conditions thereof are the subject of the agreement between the off-taker and the utility.
Excess power is sold to the grid.
It needs to be reserved that the model at issue requires all parties to be on the same grid network (unless the generating plant is directly connected to the off-taker's installation, through a direct line) - hence, the it can be questioned from the perspective of corporate buyers with multiple delivery points. In this case the VPPAs may be the better option.
European energy market regulators (Regulatory Aspects of Self-Consumption and Energy Communities, CEER Report, Customers and Retail Markets and Distribution Systems Working Groups, 25 June 2019, Ref: C18-CRM9_DS7-05-0, p. 17) observe that in this instance the role of a licensed supplier is to emulate a peer-to-peer trade sharing arrangement by taking the electricity in question into its balancing perimeter and delivering it to the final customer. In this respect, the involved supplier manages the imbalance risk of the exchange.
Hence, a sleeved PPAs can be considered a specific variant of a standard PPA (involving netting) with the basic roles of the utility categorised into three main groups:
- the topping-up of the renewable electricity with extra output when intermittent renewable generation does not satisfy the off-taker’s needs, and
- balancing (for example, to achieve a baseload shape of the supply contract);
- additional services: aggregation various generators to a portfolio, balancing group management, forecasting, risk management, etc.
The final structure and extent of these services will influence the sleeving costs.
Qualification under REMIT
Some PPA contracts are reportable under REMIT regulations, in such a case qualifying businesses (contract for the delivery of more than 10MW of electricity, 600GWh per year) must register as market participants and report their electricity transactions to ACER every month.
According to the ACER, in case of PPAs with defined pricing, delivery point, billing and payments conditions, which are not traded at an organised market place. the contract will be reported under Table 2 and, following the billing, the executions specifying an outright volume and price will be reported no later than 30 days after the invoicing date, using Table 1 of the Annex to Commission Implementing Regulation (EU) No 1348/2014 (ACER's Frequently Asked Questions (FAQs) on REMIT transaction reporting, Question 3.1.43).
Nevertheless, it needs to be noted that according to Article 3(1)(a)(vii) of Commission Implementing Regulation (EU) 1348/2014, contracts for the supply of electricity or natural gas to a single consumption unit with a technical capability to consume 600 GWh/year or more are reportable to the Agency.
Consequently, if the technical capability of the consumer to consume is less than 600 GWh/year, which means that the contracts are not reportable under REMIT - if the consumer uses the purchased energy solely for own consumption and not for resale.
The said circumstances may have a meaning when assessing the PPA’s status under REMIT reporting rules see ACER's clearance of 30 April 2021 (Question 3.1.53, FAQs on transaction reporting).
ACER's Frequently Asked Questions (FAQs) on REMIT transaction reporting
Question 3.1.53 (published on 30 April 2021)
We are enabling a corporate PPA between a consumer and a generator. The consumer does not have an individual consumption unit >600GWh but the applicable generators capacity does exceed 10MW.
We are not contracting direct with the generator but are registering the export meters to our supply.
We will be the registered supplier of the consumer. In terms of cashflow we will be paying the consumer who will in turn pay the generator for the generation.
What, in your opinion, would be the best way to report this?
We think it could be either of the following:
1. We report transaction(s) with the consumer with the generator as beneficiary
2. Consumer reports transaction with Generator only If option 1 is applicable, and we report both sides of the transaction(s) through our designated RRM, would this mean that all 3 entities have met their reporting requirements or would the generator and consumer still need to submit their own reports?
If it turns out option 2 is the recommended approach, is it possible for us, as a 3rd party, to submit reports on behalf of both the generator and the consumer?
Based on your description we understand that there are two contracts concluded in your example:
1. a power purchase agreement concluded between the Consumer and MP A to purchase renewable energy from the generator
2. a supply contract concluded between the Consumer and the Generator MP A and the generator have no contractual relationship.
According to Article 3(1)(a)(vii) of Commission Implementing Regulation (EU) 1348/2014, contracts for the supply of electricity or natural gas to a single consumption unit with a technical capability to consume 600 GWh/year or more are reportable to the Agency.
Based on your description we understand the technical capability of the Consumer to consume (being involved in the above-mentioned two contracts) is less than 600 GWh/year, which means that the contracts are not reportable under REMIT.
Please be aware that this conclusion applies only if the Consumer uses the purchased energy solely for own consumption and not for resale.
For further information related to the application of Article 3(1)(a)(vii), please refer to Questions III.3.18, III.3.20, III.3.22, III.3.33, III.3.42, and II.4.44 in the Q&A document available on the REMIT Portal.
PPAs vs. financial future market
Economic interests satisfied by the PPAs can, theoretically, to some extent, be realised also on the financial futures market.
However, using PPAs, instead of futures, to source the hedging needs have several advantages.
As observed in the said document of the Norwegian Energy Regulatory Authority (NVE-RME) of 6 January 2020, the cost of putting in large bids in the future market is quite high and attempting to purchase or sell a PPA of e.g. 100 MW over 10 years would be quite expensive.
Market participants that seek to hedge 50+ MW might circumvent the financial hedging market also to avoid moving the market price - in principle, individual trades in the financial market should not have an observable effect on the price, however, putting in a bid which is much larger than the market depth available might be very expensive since they can significantly affect the market price of the futures. This risk is avoided by using PPAs instead.
Given the above circumstances, financial future market is primarily used for shorter term hedges up to five years, whereas the PPA market is used for longer term hedges.
Regulatory barriers to PPAs
Further spreading of PPAs may be hampered by some regulatory barriers still present across the EU member states.
According to the NVE-RME they can be grouped as follows:
- curtailment of renewable energy can be necessary in many countries due to grid capacity limits; however, in some member states it is not clear whether there will be given compensation for reducing the production of a power producer, this is a challenge for, e.g., wind and solar producers looking to sign a deal for delivery of electricity;
- the risk of losing compensation from increased indirect carbon cost when entering into a renewable energy PPA - the EU member states can grant compensation for the increased power price due to a higher ETS price, however, in some member states electricity through a renewable energy PPA is thought to be unaffected by the ETS price, signing such a PPA is therefore at the risk of losing compensation.
At the level of individual EU member states different tax regimes and legal systems can be an issue when engaging in a PPA.
Other obstacles are related to the number of buyers per installation and the number of suppliers per metering point, which makes PPA syndicates more complex.
Besides that, there are also limitations in the current GOs-systems.
Article 15(8) of the RED II mandates the EU Member States to:
- assess the regulatory and administrative barriers to long-term renewables power purchase agreements,
- remove such unjustified barriers, and
- facilitate the uptake of such agreements.
Member States are, moreover, required to ensure that those agreements “are not subject to disproportionate or discriminatory procedures or charges”.
Member States must also describe policies and measures facilitating the uptake of renewables power purchase agreements in their integrated national energy and climate plans and progress reports pursuant to Regulation (EU) 2018/1999.
Fit for 55 - impact on PPAs
Recital 9 of the RED II draft amendment acknowledges PPAs as a complementary route to the market of renewable power generation (in addition to support schemes by Member States or to selling directly on the wholesale electricity market).
In Article 3 paragraph 4a is, moreover, inserted imposing on EU Member States a requirement to establish a framework "which may include support schemes and facilitating the uptake of renewable power purchase agreements".
RED II draft amendment further strengthens the existing measures in Article 15 to encourage the uptake of renewable power purchase agreements, by exploring the use of credit guarantees to reduce these agreements’ financial risks, taking into account that these guarantees, where public, should not crowd out private financing.
The requirement is also introduced to provide in National Energy and Climate Plans an indication of the volume of renewable power generation supported by renewables power purchase agreements.
It is useful to note, the creditworthiness is a known problem to the PPAs markets - in Europe to be limited to 60 GW of equivalent offshore wind capacity due to a lack of investment-grade companies willing to sign long-term supply deals.
It is estimated that only 14% of industry demand is bankable and can absorb long-term power risk (Corporate Power Purchase Agreements, The Preferred Route for Corporates to Secure Renewable Energy Supplies in a Decarbonized World, Rob Broom, Peter Wright, Henry Davey, Igor Hanas, Paul O’Hop, Manuel Mingot, Squire, Patton, Boggs, 6 February 2020).
On the opposite side, developers are also typically required to to post a letter of credit or a credit-worthy parent company guarantee to cover the risk that the project fails to generate after the PPA is entered into.
Hence, it seems that RED II draft amendments on credit guarantees are precisely directed to target the main shortcomings of the current PPAs’ market.