Markets
Italy is short of buyers, not projects
The PPA study the European Commission's Directorate-General for Energy published in May 2026 contains one figure worth pulling out. In Italy, the gap between renewable output available to contract and the demand able to absorb it widens from around 20 TWh in 2030 to around 80 TWh in 2035.
For years the binding constraint on the Italian market sat on the supply side: land, permits, grid connection queues, projects to carry through to ready to build. The study establishes that the scarcity has moved. Italy has more contractable projects than it has off-takers in a position to sign for them, and the ratio gets worse over time.
Our reading of this is operational. If demand is the bottleneck, value moves to whoever can structure it: qualifying the off-taker, allocating risk so that the contract survives a board meeting and not only a model, and recognising the cases where the right answer is not a PPA at all but self-consumption.
Potential Italian PPA supply and demand, TWh
2030
2035
| Horizon and scenario | Supply (TWh) | Demand (TWh) |
|---|---|---|
| 2030 Low | 47.56 | 25.92 |
| 2030 Average | 68.54 | 47.53 |
| 2030 High | 68.54 | 55.50 |
| 2035 Low | 103.80 | 34.00 |
| 2035 Average | 164.83 | 69.61 |
| 2035 High | 164.83 | 85.03 |
What the study is, and what it rests on
The report is titled Understanding the renewables power purchase agreements market and is the final deliverable of contract ENER/C1/2024-334, awarded by the Commission to Grant Thornton Greece and Capgemini Invent.
Its evidence base is stated: 157 responses to an EUSurvey questionnaire that closed on 11 April 2025, 22 interviews, and two DG ENER workshops with 155 and 140 participants. The supply and demand projections rest on two explicit assumptions, both worth holding in mind when reading the gap: low appetite for merchant risk among developers, and a progressive reduction in public support. If support proves more generous than expected, or if the market takes on more merchant exposure than the study assumes, the numbers move.
The European picture in three numbers
By 2030 the study puts potential greenfield PPA supply at between 350 and 500 TWh, potential demand at between 200 and 300 TWh, and the gap between them at 167 to 220 TWh. By 2035 supply almost doubles while demand grows by around 50%: the spread widens.
The market is concentrated on both sides. Mature markets accounted for over 90% of cumulative EU volume in 2024, and Spain, Sweden, Germany and the Netherlands alone make up 60% of that. On the buy side, ICT and heavy industry together covered roughly 75% of the market between 2021 and 2025, with the ICT share falling from 73% to 40% in 2024. Typical contract tenors remain 8 to 15 years.
The underlying technology has changed as well. Wind was around 80% of the market between 2000 and 2021; today solar is around 60% of volume.
Technology mix of the European PPA market
2000-2021
Today
Wind plus solar hybrids
10% of the last four years' volumes, up to 30% in Spain.
| Period | Leading technology | Stated share | Rest of the market |
|---|---|---|---|
| 2000-2021 | Wind | 80% | 20% |
| Today | Solar | 60% | 40% |
Italy is a mature market with the opposite problem
The study classifies Italy as a mature market, fourth by size in Europe, solar-dominated. In its allocation of intervention areas it places demand stimulation at the highest priority, alongside improving an already mature market, and supply stimulation at the lowest.
The projections explain why. In the Average scenario Italian supply goes from 68.54 TWh in 2030 to 164.83 TWh in 2035, while demand moves from 47.53 to 69.61 TWh: the gap widens from 21.01 to 95.22 TWh. The study summarises this as a shift from around 20 to around 80 TWh, and the 2035 figure there corresponds to the High scenario, where livelier demand of 85.03 TWh absorbs a larger share of the same supply. In the Low scenario the gap is 21.64 TWh in 2030 and 69.80 TWh in 2035. Whichever scenario is taken, the direction is the same and the order of magnitude is tens of TWh.
The Italian gap in the Average scenario, TWh
| Year | Demand (TWh) | Supply (TWh) | Gap (TWh) |
|---|---|---|---|
| 2030 | 47.53 | 68.54 | 21.01 |
| 2035 | 69.61 | 164.83 | 95.22 |
Our reading: for a market that has spent recent years debating suitable-area rules, permitting timelines and connection queues, this reverses the priorities. The permitted project stops being the scarce resource. The counterparty able to sign becomes it.
Why demand is not taking off
The study identifies four recurring obstacles on the demand side. None of the four is solved by building more plant.
- Creditworthiness. A ten-year PPA is a balance-sheet commitment, and many industrial counterparties that would like to sign one do not carry a rating that holds over that tenor. This is why guarantee instruments are appearing: the EIB has launched a EUR 500 million pilot that counter-guarantees banks for up to 50% of the credit risk, aimed at SMEs, mid-caps and energy-intensive firms without a solid rating. National precedents have seen limited take-up: Spain's FERGEI is associated with a single documented PPA, France's GER with three uses, Norway's Eksfin with two.
- Shaping costs. Turning a generation profile into a consumption profile has a cost, and which party carries it depends on the delivery structure.
- Negative prices and curtailment. In Germany, curtailment affected 4.01% of renewable generation in 2024. In Spain 1.7 TWh were curtailed the same year, with expectations of around 5% across 2027 and 2028. For a buyer this means the contracted volume may not arrive.
- Transaction costs. Negotiating a ten-year bilateral needs legal, credit and market skills that few firms hold in house.
Above the four sits a structural fact. European electrification has been stuck at around 23% for a decade, against a target of 32 to 33% by 2030. Until electricity consumption grows, PPA demand has nowhere to come from.
Nor is it easily imported. Between 2013 and mid-2025 the study counts 66 cross-border partnerships, worth 15.6 TWh a year, at an average size of 273 GWh a year and an average tenor of 10.6 years, 85% greenfield and all of them virtual. No physical cross-border PPA is confirmed anywhere in Europe. The liquidity that would make hedging straightforward is missing too: the conventional threshold for a forward market is a churn rate at or above 10, and in Europe only Germany clears it.
The technical crux: who carries which risk
The point at which a PPA either works or does not is the delivery structure, meaning what exactly the seller commits to deliver and when. The study records that Pay-as-Produced accounts for 60% of PPAs signed: the seller delivers what the plant produces, hour by hour, and the buyer takes what arrives.
Who bears which risk, by delivery structure
| Structure | Profile risk | Volume risk | Price risk | Effect on the strike price |
|---|---|---|---|---|
| Pay-as-Produced60% of PPAs signed | Buyer | Buyer | Sharedresidual with the buyer | Benchmark, the lowest |
| Baseloadflat, constant delivery | Seller | Seller | Sharedresidual with the seller | Carries the full shaping premium |
| Pay-as-Nominateddelivery against a nominated schedule | Seller | Seller | Sharedresidual with the seller | Above Pay-as-Produced |
| Pay-as-Consumeddelivery against the offtake profile | Seller | Seller | Sharedresidual with the seller | The highest, absorbs the buyer's volume too |
The practical consequence deserves stating plainly. For a consumer with an inflexible load, a plant on fixed shifts or a continuous process, a Pay-as-Produced contract can wipe out the expected saving. Energy arrives when the plant generates, not when the factory consumes: the shortfall has to be bought on the market in the hours it costs most, and the surplus sold back in the hours it is worth least. The strike price looks attractive and total procurement cost does not fall.
Our reading: the delivery structure is chosen before the price. A Baseload contract at a higher price can cost less than a Pay-as-Produced one at a lower price, and the test is run against the consumer's actual hourly profile, not against the price per MWh. It is the same reasoning we applied to routes to market in When, not how much.
What is moving in Italy
The regulatory picture is moving on several fronts, and they do not all push the same way.
The five deadlines redrawing the market
- 2024EU Reg. 2024/1747Article 19a(5): a share of output reservable for PPAs by projects in support schemes.
- December 2025CfD guidanceCommission guidance on how public support relates to the contracted market.
- 1 January 2026IFRS 9Own use exemption holds if the firm stays a net buyer over 12 months.
- In implementationMPPAA market dedicated to PPAs: guidelines with GME, GSE as guarantor of last resort.
- In implementationFER-XA CfD at a guaranteed price: it competes with the PPA for the same project.
| Step | When | What changes |
|---|---|---|
| EU Reg. 2024/1747 | 2024 | Article 19a(5): a share of output reservable for PPAs by projects in support schemes. |
| CfD guidance | December 2025 | Commission guidance on how public support relates to the contracted market. |
| IFRS 9 | 1 January 2026 | Own use exemption holds if the firm stays a net buyer over 12 months. |
| MPPA | In implementation | A market dedicated to PPAs: guidelines with GME, GSE as guarantor of last resort. |
| FER-X | In implementation | A CfD at a guaranteed price: it competes with the PPA for the same project. |
The MPPA, a planned Italian marketplace dedicated to PPA trading, is the most direct intervention on the demand problem. A decree from MASE, the environment and energy security ministry, issued jointly with the finance ministry MEF, tasks the power exchange operator GME with writing the guidelines and puts the state energy agency GSE in the role of guarantor of last resort should a counterparty default. Contracts are standardised, 5 to 10 years long, with a 1 MW minimum size and all renewable technologies admitted. The study flags two limits: standardisation that adapts poorly to specific requirements, and a guarantee available only to those trading on the platform. Our reading is that the second limit weighs more than the first, because it leaves uncovered exactly the tailored bilateral deals where creditworthiness is the real obstacle.
On curtailment, the energy regulator ARERA extended compensation to all renewable technologies from March 2025, solar included; it previously covered wind only. That is one risk item fewer to negotiate. The IFRS 9 amendments the IASB approved in December 2024, effective from 1 January 2026, remove an accounting obstacle that has stalled more than one negotiation: the own use exemption holds even where occasional resales occur, provided the firm remains a net buyer over a horizon of no more than twelve months. How that applies to a specific set of accounts is a question for the company's own accounting advisers, not one to settle at market level.
FER-X, Italy's forthcoming renewables support scheme, runs the other way: the study flags it as a possible factor compressing the Italian PPA market, because it offers the same project a contract for difference at a guaranteed price. In the background, EU Regulation 2024/1747 at Article 19a(5) obliges member states to let projects taking part in support schemes reserve a share of their output for PPAs. Belgium's PEZ-1 case shows how that can be calibrated: up to 75% of volume contractable through PPAs, of which 50% open to any counterparty and 25% reserved for SMEs, citizens and local authorities.
Flexibility is moving as well, and flexibility is what makes shaping cheaper: the MACSE auction of September 2025, run under Italy's storage capacity mechanism, covered around 10 GWh of battery projects to be commissioned by 2027.
PPAs and self-consumption are a ladder, not a fork
The question almost always arrives framed as a choice: a PPA or self-consumption. Our reading is different. They are rungs on the same ladder, ordered by how much consumption can be brought under a single profile.
On-site self-consumption captures full value because it removes the profile problem at source: the energy is needed where and when it is produced, and there is no delivery structure to negotiate. Remote self-consumption extends the same principle across several offtake points, which is the ground we covered writing about Italy's iperammortamento 2026. A PPA comes in when demand exceeds what a self-consumption configuration can cover, and at that point the delivery structure decides whether the contract creates or destroys value.
If demand is what constrains the market, the skill that counts is not finding another project. It is being able to say, against a real consumption profile and a real balance sheet, which rung is needed and which contract will hold. That is the part of the work we set out under capabilities, with the typical counterparties listed on the sectors page.
If you have a consumption profile on the table and are weighing whether a PPA is the right instrument, write to us.
Sources
All figures cited come from European Commission, DG ENER, Understanding the renewables power purchase agreements market, Final Report, May 2026, prepared by Grant Thornton Greece and Capgemini Invent under contract ENER/C1/2024-334. ISBN 978-92-68-41506-1, doi:10.2833/8245351, MJ-01-26-068-EN-N. © European Union 2026. Reuse authorised under the Creative Commons Attribution 4.0 International licence (CC BY 4.0).
The figures shown in the charts are taken from the study unmodified. The risk allocation by delivery structure, and the passages introduced by «our reading», are Altheon analysis and form no part of the original publication. This article is not legal, accounting or tax advice.