Table of contents

• Who wants a capacity market, and why?
• But why fix a system that isn’t broken?
• The BKZ Wildcard
• Lessons from elsewhere

In a previous analysis of Germany’s renewable energy opportunities, we noted ongoing discussions around a potential capacity market mechanism by 2028. The industry debate around this is intensifying, revealing significant disagreements between stakeholders who feel that the current system works and those who fear it may not work for much longer.

On the one hand, Germany’s current energy-only market (EOM) functions effectively: generators are paid exclusively for the electricity they actually deliver, and this market-based mechanism has successfully driven massive investment in renewable energy and battery storage (BESS).

On the other hand, powerful voices, including one of the country’s Transmission System Operators (TSOs), TransnetBW, are calling for the introduction of a capacity market (CM). This proposed system would pay providers not for the power they produce, but for the mere promise of capacity – the guaranteed availability to generate electricity during future periods of high demand or system stress, such as the dark, still periods of winter. Proponents argue it is essential to ensure reliability as coal and nuclear are phased out, while opponents see it as a dangerous distortion of a thriving market that risks locking in fossil fuels and stifling innovation. This article looks at both sides of the argument, the immediate regulatory hurdle of the BKZ grid fee, and what these dynamics could mean for project financing.

Who wants a capacity market, and why?

Germany’s energy transition (Energiewende) has positioned the country as a leader in renewable energy adoption, with renewables accounting for between 50% and 67% of its electricity mix. However, this rapid expansion of variable renewable sources like solar and wind creates challenges for grid stability and reliability. Generation fluctuates based on weather conditions, leading to potential supply gaps during periods of low wind and sunlight known as Dunkelflaute (“dark doldrums”).

To address this, Germany is considering introducing a capacity market mechanism by 2028 designed to ensure reliable electricity supply. The proposal involves consultation around various options for the design of the CM and to introduce it as part of a combined (centralised and decentralised) model that incentivises flexible consumer and storage facilities alongside power plants. It’s supported by the German Federal Ministry for Economic Affairs and Climate Protection (BMWK) and involves a technology-neutral approach to guarantee system adequacy and stable investment, including renewables, storage, and flexible loads.

Another CM advantage is its ability to unlock financing for new projects. By providing a stable, long-term revenue stream for being available, capacity payments would de-risk investments, particularly for capital-intensive projects. Guaranteed income reduces reliance on volatile merchant revenues from energy trading and ancillary services, making banks more comfortable providing debt financing. Project bankability like this addresses a key concern for developers and financial institutions.

Proponents also argue that a centrally organised capacity auction would facilitate a more strategic and predictable build-out of necessary capacity, instead of piecemeal, reactive development driven by short-term market signals. Planned expansion like this ensures that the right types of resources are developed in the right locations, creating resilience and reliability. In short, those in favour of a CM think it will solve:

• Volatility of energy prices 
• Barriers to investment
• Risk of undersupply
• The need for additional measures to ensure network stability

But why fix a system that isn’t broken?

Developers who are not in favour of a CM point to the fact that the current system is working effectively, delivering substantial investment in BESS and other flexibility solutions without government intervention. Worries about a CM revolve around these concerns:

• The additional costs of securing capacities are usually passed on to electricity customers.
• CMs can create excess capacity when too many plants are built just to receive capacity payments.
• CMs can distort competition by favouring certain technologies or existing, larger players who have easier access to capital.
• CMs can support the continued operation of environmentally damaging fossil power plants or delay their closure.
• They may distort prices in the EOM and undermine investments made on the basis of the EOM.

EOM proponents hold that introducing a capacity mechanism would distort the very price signals that drive innovation and efficient operation in the existing market. Analysis shows that Germany’s current market design has successfully attracted significant investment in flexibility resources without capacity payments.

Then there is the gas plant problem, with substantial risk that a technology-neutral CM auction would primarily subsidise the construction of new gas-fired power plants, potentially locking in fossil fuel infrastructure for decades. This would directly contradict Germany’s decarbonisation goals and climate commitments. Critics point to experiences in other European markets where capacity mechanisms have disproportionately benefited fossil fuel assets.

Then there is the question of whether BESS even needs CM support. Battery storage is already proving its commercial viability in Germany’s frequency regulation and energy arbitrage markets. CM mechanisms are traditionally used to support technologies that aren’t economically viable on their own – but revenue stack analyses show that BESS projects are achieving attractive returns through existing market mechanisms. And they are being built and financed based on their ability to compete and generate revenue in Germany’s existing EOM, operating without direct taxpayer subsidies. The introduction of a capacity market would force them to compete against government-backed assets – such as already-mentioned new gas power plants – that receive guaranteed payments through the CM. This creates an uneven playing field, where the true cost of securing capacity is passed through to all electricity consumers via their bills, potentially distorting the market that BESS projects have so far thrived in without public financial support.

The BKZ Wildcard

The Baukostenzuschuss (BKZ) is a significant upfront grid connection fee charged by distribution (DSO) and TSO system operators, directly adding to a project’s capital expenditure. This creates immediate financial strain and uncertainty. A lost court battle over its legality for storage projects, coupled with cost variations between different grid operators, makes projects more expensive and financial planning and site selection more complex.

In the EOM, the high, unpredictable BKZ erodes project returns, making it harder for merchant projects to secure financing based on volatile revenue forecasts. For a future CM, these fees directly undermine the mechanism’s goal of ensuring new capacity. If the BKZ remains a barrier, it could prevent the very new, flexible assets the CM is meant to incentivise from being built, rendering the policy less effective before it even starts.

Lessons from elsewhere

The UK’s and Poland’s experience with CMs offers insight. The UK’s model demonstrates that a well-designed mechanism can integrate batteries and demand response, avoiding a pure lock-in for large gas plants. Conversely, Poland’s example serves as a cautionary tale of how these markets can inadvertently prolong the life of polluting fossil assets if climate goals are not hardwired into their design. 

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Table of contents

• The potential
• What does repowering involve?
• BESS’s contribution to repowering
• The European repowering picture
• Policy support 
  • EU policy framework
  • UK policy support
  • Overall barriers to repowering in the EU

Europe’s first generation of turbines is reaching retirement age. Some of the oldest farms, occupying Europe’s best wind sites, have already reached end-of-life and are operating less efficient turbines. According to WindEurope, about 20% of Europe’s 90,000 onshore turbines are 15 years old or older. Modernisation (rather than decommissioning or extending maintenance) is therefore essential to maximising potential. Between 2023 and 2030, 83 GW of European onshore wind power will reach 15 years of age – well past middle age for technology with a 20–25 year lifespan. WindEurope projects that of this aging capacity, only about 6.7% will be repowered.

Repowering projects are increasingly looking to combine wind generation with on-site BESS, as in the Wind Park Hartel 2 project in the Netherlands. Investors such as Triodos Energy Transition Europe Fund also recognise the important role of storage in these projects, saying: “Energy storage at the parks also plays a crucial role in coping with the peaks and troughs in electricity generation. Batteries can therefore no longer be ignored in the (re)development of wind and solar farms.” 

Yet, progress is uneven across Europe. Germany hosts more than half of all repowered projects, while Spain – Europe’s second-largest onshore wind market – accounts for just 3%, despite massive potential. Grid connection difficulties, restrictive height regulations, and cumbersome permitting processes are slowing the uptake that could transform Europe’s renewable energy landscape.

The potential

According to consulting firm Sia, Europe must achieve 250 GW of wind power installations by 2030 to reach its targets, with repowering offering a pathway to contribute an additional 65 GW through 2030. Since the oldest wind farms are usually in the best wind sites (and have small and less efficient turbines), there’s a clear opportunity to maximise energy production from Europe’s prime wind locations through modernisation. But, of the 83 GW reaching 15+ years by 2030, WindEurope projects only 5.6 GW will be repowered, 70 GW life-extended, and 7.8 GW decommissioned.

Repowering typically triples wind farm output and quadruples output per turbine. It can also reduce the total number of turbines required by 25%. The UK, for example, has about 1.3 GW of onshore wind that will reach the end of its operating life by 2030 and approximately 2.2 GW by 2035. Another example, Spain, has an estimated potential of 15 GW in the repowering segment.

What does repowering involve?

Repowering usually means dismantling old turbines and replacing them with fewer, higher-capacity, more efficient models. This often requires repositioning turbines due to their larger size, triggering a new approval process that can be equivalent to building an entirely new wind farm. A challenge is that regulatory hurdles frequently complicate these projects: existing permits typically don’t transfer to new turbines, and some jurisdictions may even prohibit rebuilding on the same site. In many cases, authorities lack clear guidelines for repowering, leaving developers navigating uncertain regulatory territory where rules simply don’t exist yet.

The complete dismantling process removes every component from blades to foundations, with materials either recycled or disposed of properly before restoring unused land to its natural state.

Up to 85–90% of turbine materials are now recyclable, with ongoing innovation in blade recycling as part of improved recycling and circularity practices.

BESS’s contribution to repowering

As mentioned, repowered sites can produce significantly more electricity with greater peaks and variability, creating new challenges for grid integration. BESS is increasingly essential to store surplus energy, enable flexibility, and provide frequency regulation services for the grid. New repowering projects that combine wind generation with on-site BESS improve the value of the project, enabling participation in ancillary services markets and maximising grid export during peaks. This co-location trend is part of the move towards solutions that address both generation and grid stability requirements.

Battery storage systems can play several critical roles in repowered wind farms, including smoothing intermittent wind power output, providing flexibility to balance supply and demand, and enabling better use of grid connections. Additional opportunities include arbitrage between low and high electricity prices, participation in balancing markets, and congestion management to alleviate grid constraints. The FLEXITRANSTORE project in Greece, for example, integrated BESS at a wind park to provide frequency and voltage regulation and improve grid stability. In the UK and Germany, national grids and local projects are increasingly combining BESS with new and repowered wind to maximise renewable penetration and grid reliability.

The European repowering picture

The repowering of wind farms is not equally distributed between EU Member States and the UK, with significant variations in adoption and policy support across the continent.

• Germany leads with more than half of all repowered projects located here – it’s one of the biggest markets for wind energy and home to many first-generation wind farms now reaching end-of-life.
• Spain, Europe’s second-largest onshore wind energy market with much repowering potential, hosts only 3% of repowered projects. Grid connections for repowered wind farms are so difficult to get that developers prefer to simply keep the old turbines running.
• France is missing out on the advantages of repowering due to their restrictive tip height rules that don’t allow developers to build the latest and most efficient onshore wind turbines.
• The UK offers promise with policy changes allowing fully repowered onshore wind projects to participate in the Contracts for Difference (CfD) regime from mid-2025.

Despite the clear benefits of repowering, many EU Member States lack effective repowering strategies, leaving significant potential untapped across Europe.

Policy support 

EU policy framework

The European Commission has put forward key permitting and repowering provisions in the revised Renewable Energy Directive. This gives repowering projects a targeted 6-month permitting decision timeline, potentially opening up more tender and support opportunities through national plans. As part of its REPowerEU Plan and European Wind Power Action Plan, the EU has passed new legislation, including the Emergency Regulation on Renewables Permitting, which seeks to facilitate repowering renewables projects through expediting the permitting process.

UK policy support

In 2024, the UK government removed a de facto ban on onshore wind in England. From CfD Allocation Round 7, expected in mid-2025, repowering onshore wind projects that meet the required criteria will be allowed to apply for a CfD, with forward bidding permitted so projects are not required to decommission and lose their revenue stream before applying.

Overall barriers to repowering in the EU

• Permitting challenges – overly cumbersome and lengthy permitting procedures are holding back the much-needed uptake of repowering. Many Member States have yet to implement streamlined procedures despite EU policy direction.
• Grid access presents major obstacles, as securing new or upgraded grid connections can be difficult and expensive, especially in markets like Spain, where this is stunting repowering progress.
• Site restrictions that include limiting blade-tip height regulations, which prevent the use of higher-capacity next-generation turbines.
• Economic factors – some sites cannot access adequate financial incentives, and the lack of subsidies or suitable revenue stabilisation like CfDs can make repowering uneconomic compared to operating old assets.

Onshore wind repowering is poised for significant growth as market incentives and policy reforms streamline the process across Europe. For countries with limited suitable wind sites, repowering is an important solution. Higher-capacity installations on proven locations can compensate for land scarcity and accelerate progress toward energy targets. Technical feasibility, improving economics, and increasingly supportive regulatory frameworks at both national and European levels are likely to create the conditions for scaled deployment. This alignment makes repowering projects particularly attractive for BESS developers seeking established grid connections and proven wind resources.

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Table of contents

• Servizi ausiliari tramite MSD
• Arbitraggio sul mercato all’ingrosso e servizi atti a risolvere i problemi di congestione
• Mercati di capacità a breve termine e tolling agreements
• PPA privati
• La pronta crescita di ricavi indica la strada giusta

I contratti di capacità a lungo termine disciplinati dal Meccanismo per l’Acquisizione di Capacità di Stoccaggio Elettrico (MACSE), approvato con Decreto Legislativo dell’8 novembre 2021, n. 210, sono progettati per supportare fino a 50 GWh di nuova capacità di stoccaggio, principalmente al Sud e nelle isole. A breve sarà lanciata la prima asta, la quale offrirà una bancabilità su larga scala dei sistemi di accumulo     (Battery Energy Storage System, BESS). Tuttavia, recenti dati sulle prestazioni suggeriscono che si potranno ottenere valori significativi da diverse fonti di reddito alternative all’approvvigionamento di capacità. Ad esempio, gli asset standalone di 4 ore con le migliori prestazioni nel Nord Italia sono passati da margini annualizzati che faticavano a raggiungere i 100 €/kW nel 2024, a picchi settimanali che superano regolarmente i 200 €/kW nella primavera del 2025.  Con la capacità solare ed eolica dell’Italia che si prevede raddoppierà entro il 2030, e il disaccoppiamento dei prezzi zonali ormai in atto per quasi il 30% delle ore totali, esistono molteplici opportunità di introiti negli ancillary services e nell’arbitrage all’ingrosso, nonché in modelli contrattuali come i tolling agreements.

• I servizi di stabilità della rete includono mercati ausiliari come la Riserva di contenimento della frequenza (FCR), la Riserva automatica di ripristino della frequenza (aFRR) e il Mercato dei Servizi di Dispacciamento (MSD). Questi compensano gli operatori BESS e gli asset flessibili per la regolazione rapida della frequenza e il bilanciamento in tempo reale. A questi si aggiungono i servizi in caso di congestione, in cui gli operatori di rete pagano per alleviare i cd “colli di bottiglia” a livello locale, e i programmi UVAM (Unità Virtuali Abilitate Miste), che consentono agli asset aggregati su piccola scala di partecipare ai mercati della flessibilità.
• Le opportunità di trading energetico includono l’arbitraggio tra il mercato del giorno prima (Mercato del Giorno Prima, MGP) e il mercato infragiornaliero (Mercato Infragiornaliero, MI), che consentono agli asset di capitalizzare sui differenziali di prezzo.
• Gli accordi contrattuali che riducono il rischio degli investimenti includono accordi quali i tolling agreements (in cui terzi gestiscono lo stoccaggio a un costo fisso) e accordi privati per l’acquisto di energia (PPA) che abbinano le energie rinnovabili allo stoccaggio al fine di ottimizzare la fornitura. Infine, i contratti di capacità a lungo termine forniscono a loro volta energia di riserva durante i momenti di stress del sistema.

Servizi ausiliari tramite MSD

Il mercato italiano dei servizi ausiliari, ossia il Mercato dei Servizi di Dispacciamento (MSD), offre opportunità di guadagno per le batterie e gli asset aggregati. Questi asset possono partecipare a tre mercati: Fast Reserve, Frequency Containment Reserve (FCR) e Automatic Frequency Restoration Reserve (aFRR) fornendo servizi di risposta a frequenza rapida e di bilanciamento della rete. Questi servizi sono fondamentali per stabilizzare la rete italiana procedendo di pari passo allo sviluppo delle energie rinnovabili, con la transizione di FCR e aFRR a piattaforme armonizzate a livello UE (PICASSO/MARI) avvenuta quest’anno, che aprirà opportunità di scambio transfrontaliero. Tuttavia, la saturazione del MSD ha ridotto i margini, spingendo i partecipanti verso strategie ibride, che combinano i ricavi accessori con i contratti trading merchant o relativi al mercato della capacità.

La riforma TIDE ha dato vita alle Unità Virtuali Abilitate Miste (UVAM), che aggregano risorse distribuite per partecipare alle aste nei mercati ausiliari. Le UVAM, introdotte dall’operatore di trasmissione italiano Terna nel 2018, superano ora i 1.500 MW di capacità flessibile qualificata e sono fondamentali per sostituire i servizi di bilanciamento basati sui combustibili fossili. Il Sud Italia, con la sua abbondanza di energia solare e i vincoli di rete, favorisce la partecipazione delle UVAM a risposta rapida, mentre il Nord sfrutta la volatilità infragiornaliera.

Arbitraggio sul mercato all’ingrosso e servizi atti a risolvere i problemi di congestione

L’arbitraggio sul mercato all’ingrosso sfrutta le differenze di prezzo tra il mercato del giorno prima (MGP) e il mercato infragiornaliero (MI). Il Sud Italia, in particolare, presenta una significativa volatilità dei prezzi zonali a causa della saturazione solare nelle ore centrali della giornata e dei cd “colli di bottiglia” della rete di trasmissione. Ciò offre ai BESS la possibilità di caricarsi quando i prezzi sono bassi per poi scaricarsi durante le ore di punta serali.  

La riforma TIDE ha introdotto nel MI periodi di regolamento di 15 minuti (le transazioni e i prezzi vengono calcolati e regolati finanziariamente ogni 15 minuti anziché ogni ora) e impone l’applicazione di prezzi zonali anziché di un prezzo medio nazionale. Ciò aumenta notevolmente la granularità e la volatilità dei prezzi tra il Sud, ricco di energie rinnovabili, e il resto del Paese, e amplifica le opportunità di arbitraggio sul mercato all’ingrosso, dove i BESS possono trarre profitto dalla ricarica nelle ore a basso prezzo, saturate dal solare, e dallo scaricamento durante i picchi serali di alta domanda.

Una volatilità di questo tipo, con l’intensificarsi delle congestioni della rete, rafforza il business case a favore dei BESS, che possono fornire non solo arbitraggio energetico, ma anche servizi di gestione delle congestioni e flessibilità, assorbendo l’eccesso di offerta quando i prezzi diventano negativi e sostenendo l’offerta nelle ore di prezzo elevato.

Mercati di capacità a breve termine e tolling agreements

Terna organizza aste annuali sul mercato della capacità in cui i produttori di energia elettrica forniscono capacità con due anni di anticipo rispetto alla consegna. I progetti vincitori alla fine del 2024 si sono aggiudicati contratti di fornitura della durata di 15 anni con un compenso di circa 45.000-67.500 €/MW all’anno. Ciò garantisce la stabilità della rete remunerando la disponibilità di capacità al di là dei ricavi del mercato libero dell’energia. Il mercato della capacità attrae ingenti investimenti in BESS (la maggior parte della nuova capacità contrattualizzata all’inizio del 2025). Questi contratti di capacità coesistono con i ricavi di mercato, consentendo ai proprietari degli asset di partecipare ai mercati dei prezzi del giorno prima e ai mercati ausiliari, sebbene i prezzi del giorno prima siano soggetti a un tetto massimo al fine di evitare profitti eccessivi oltre ai pagamenti per la capacità.

I tolling agreements sono contratti in cui il proprietario di un asset mette a disposizione di un toller (operatore) un impianto (ad esempio una batteria), che ne controlla la gestione commerciale, compresa la commercializzazione dell’energia elettrica immagazzinata, senza esserne proprietario. Il proprietario dell’asset continua a essere responsabile della costruzione, della messa in servizio e della manutenzione e riceve un reddito fisso e stabile.

PPA privati

I contratti di acquisto di energia privata (PPA) italiani sono in aumento nel 2025. Ad esempio, METLEN ha firmato un PPA privato decennale con Iliad Italia per fornire energia solare da due parchi solari con una capacità complessiva di 15 MW, fornendo 20 GWh all’anno a Iliad. Nonostante l’interruzione causata dalla sospensione temporanea del regime di rilascio di energia in Italia da parte dell’UE, la tendenza generale mostra un aumento dell’attività dei PPA guidata dalle aziende e dai servizi pubblici, rendendo l’Italia uno dei mercati europei leader per questi accordi.

La pronta crescita di ricavi indica la strada giusta 

Le prestazioni commerciali degli asset di stoccaggio in Italia richiedono un’attenzione particolare alla struttura dei ricavi. Grazie alla bancabilità dei progetti garantita da MACSE per alcuni operatori, è possibile integrare i pagamenti di capacità con la partecipazione UVAM, il trading infragiornaliero e i PPA privati per creare flussi di reddito resilienti. Questo tipo di accumulo dei ricavi riflette la maturità di un mercato in cui la raffinatezza operativa determina quali progetti sono in grado di cogliere appieno il valore della transizione energetica italiana.

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Table of contents

• Ancillary services
• Wholesale market arbitrage and congestion services
• Short-term capacity markets and tolling agreements
• Private PPAs
• Agile revenue stacking points the way

Italy’s long-term capacity contracts under the Electricity Storage Capacity Procurement Mechanism (Meccanismo per l’Acquisizione di Capacità di Stoccaggio Elettrico – MACSE) are designed to support up to 50 GWh of new storage capacity, primarily in the south and the islands. The first auction launches shortly and will offer crucial bankability for large-scale BESS deployment. But recent performance data suggests significant value is being captured from diverse revenue streams beyond capacity payments. The best-performing 4-hour standalone assets in northern Italy, for example, have surged from struggling to reach €100/kW annualised margins in 2024 to regularly exceeding €200/kW in weekly performance peaks during spring 2025. With Italy’s renewable capacity set to double by 2030 and zonal price decoupling now occurring for almost 30% of total hours, multiple revenue opportunities exist in ancillary services, wholesale arbitrage, congestion management, and contracting models like tolling agreements.

• Grid stability services include ancillary markets like Frequency Containment Reserve (FCR), automatic Frequency Restoration Reserve (aFRR), and the Mercato dei Servizi di Dispacciamento (MSD). These compensate BESS operators and flexible assets for rapid frequency regulation and real-time balancing. These are complemented by congestion services, where grid operators pay to relieve local bottlenecks, and UVAM (Unità Virtuali Abilitate Miste) programmes, which allow aggregated small-scale assets to participate in flexibility markets.
• Energy trading opportunities include arbitrage between the day-ahead (Mercato del Giorno Prima, MGP) and intraday (Mercato Infragiornaliero, MI) markets allow assets to capitalise on price spreads.
• Contractual arrangements that de-risk investments include tolling agreements (where third parties operate storage for a fixed fee) and private Power Purchase Agreements (PPAs) that pair renewables with storage for optimised delivery. Short-term capacity contracts also provide backup power during system stress.

Ancillary services

Italy’s ancillary services market, Mercato dei Servizi di Dispacciamento (MSD), presents revenue opportunities for battery and aggregated assets. These assets can participate in three markets: Fast Reserve, Frequency Containment Reserve (FCR), and automatic Frequency Restoration Reserve (aFRR) by providing rapid frequency response and grid balancing services. These services are critical for stabilising Italy’s grid as renewables grow, with FCR and aFRR transitioning to EU-harmonised platforms (PICASSO/MARI) this year, unlocking cross-border trading opportunities. However, saturation in the MSD has squeezed margins, pushing participants toward hybrid strategies – stacking ancillary revenues with merchant trading or capacity market contracts.

TIDE reform has given rise to Unità Virtuali Abilitate Miste (UVAMs), which aggregate distributed resources to bid into ancillary markets. UVAMs, pioneered by Italian transmission operator Terna since 2018, now exceed 1,500 MW of qualified flexible capacity and are central to replacing fossil-fueled balancing services. Southern Italy, with solar abundance and grid constraints, favours fast-response UVAM participation, while the north capitalises on intraday volatility.

Wholesale market arbitrage and congestion services

Wholesale market arbitrage exploits price differences between the Day-Ahead Market (MGP) and the Intraday Market (MI). Southern Italy, especially, has significant zonal price volatility due to solar saturation during midday hours and transmission-grid bottlenecks. This creates opportunities for BESS to charge when prices are low and discharge during evening peak hours.  

The TIDE reform introduced 15-minute settlement periods (transactions and prices are calculated and financially settled every 15 minutes instead of hourly) in the MI and mandates the application of zonal pricing instead of a national average price. This sharply increases price granularity and volatility between the renewable-rich south and the rest of the country, and it amplifies opportunities for wholesale market arbitrage where BESS can profit from charging in low-price, solar-saturated hours and discharging during high-demand evening peaks.

Volatility like this, with intensified grid bottlenecks, strengthens the business case for BESS to provide not only energy arbitrage but also congestion management and flexibility services by absorbing excess supply when prices turn negative and supporting supply during high-price hours.

Short-term capacity markets and tolling agreements

Terna organises annual capacity market auctions where power producers provide capacity two years ahead of delivery. Winning projects in late 2024 secured 15-year fixed contracts paying around €45,000 to €67,500/MW per year. This ensures grid stability by remunerating capacity availability beyond merchant energy market revenues. The capacity market attracts significant BESS investments (the majority of new contracted capacity in early 2025). These short-term (yearly) capacity contracts coexist with market-based revenues, allowing asset owners to participate in day-ahead and ancillary markets, although day-ahead prices are capped to prevent excessive profits on top of capacity payments.

Tolling agreements are contracts where the asset owner makes the facility (like a battery) available to a toller (operator), who controls the commercial operation, including market trading of stored electricity, without owning the asset. The asset owner remains responsible for construction, commissioning, and maintenance and receives fixed, stable revenue.

Private PPAs

Italian Private Power Purchase Agreements (PPAs) are on the increase in 2025. For example, METLEN signed a 10-year private PPA with Iliad Italia to supply solar energy from two solar farms with a combined capacity of 15 MW, delivering 20 GWh annually to Iliad. Despite interruption by the temporary suspension of Italy’s Energy Release scheme by the EU, the overall trend shows rising PPA activity driven by corporates and utilities, making Italy one of the leading European markets for these agreements.

Agile revenue stacking points the way

The business performance of storage assets in Italy needs close attention to revenue architecture. With MACSE providing essential project bankability for some, operators can also layer capacity payments with UVAM participation, intraday trading, and private PPAs to create resilient income streams. Revenue stacking like this reflects a maturing market where operational sophistication determines which projects capture the full value of Italy’s energy transition.

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Table of contents

• Why overbuild?
  • Degradation buffer
  • Multiple revenue streams
  • Cost certainty
• What about augmentation?
  • But augmentation isn’t operationally simple
• Decision factors – overbuilding or augmentation?

As renewable energy projects face tighter performance guarantees and volatile markets, BESS developers are considering installing extra capacity upfront, rather than augmenting capacity later. ‘Overbuilding’ like this typically adds 10-20% beyond immediate needs, thus combatting battery degradation, ensuring consistent revenue from stacked use cases, and avoiding costly mid-life expansions. But with battery prices fluctuating and revenue models evolving, the calculus isn’t universal. When does overbuilding pay off, and when does it strand capital best spent on later augmentation? We need to consider three main factors: degradation curves, contract structures, and the hidden costs of playing catch-up later.

Why overbuild?

Battery energy storage systems need to deliver precision performance sometimes decades into their operational life, which makes system sizing a significant decision. Rather than installing just enough capacity to meet initial needs, many are overbuilding systems that pay dividends throughout the project lifecycle. The practice attends to three operational/market realities:

Degradation buffer

Batteries, depending on their type,  lose 1–3% capacity annually. Proper state-of-charge calibration and cell balancing can slow degradation, but even well-maintained systems lose capacity. Overbuilding ensures performance headroom regardless of calibration accuracy, maintaining performance as cells age. In many capacity markets, longer output guarantees, up to 25 years, are becoming standard, and so this approach prevents contract breaches when systems inevitably lose capacity.

Multiple revenue streams

Extra MW capacity supports stacked revenue streams. A 100 MWh system with 15% overbuild can simultaneously provide frequency regulation (fast-discharging 30 MW) and energy arbitrage (slow-discharging 70 MW) without performance trade-offs. This is valuable in markets where ancillary services and energy trading require distinct power-to-energy ratios. Excess capacity allows operators to pivot between use cases as market conditions shift, such as transitioning from peak shaving to black-start services during grid emergencies.

Cost certainty

Overbuilding avoids hidden costs of augmentation, like permitting, labour, and downtime. Projects with long-term contracts routinely overbuild 15–30%, locking in today’s pricing while hedging against future disruptions.

The calculus varies by project, but where certainty brings a premium value, overbuilding is a good option.

What about augmentation?

Augmentation is an alternative to overbuilding in scenarios where flexibility outweighs the benefits of upfront capacity, for example, merchant projects operating in volatile energy markets, where revenues fluctuate dramatically based on real-time pricing. Starting with a leaner system can test market conditions before committing to expansion, and capacity can be added later when revenue streams prove sustainable. The economics of augmentation also improve when battery prices are in steady decline. Sites designed with expansion space could potentially acquire more advanced technology later at lower prices. This approach could work well for projects anticipating new grid service opportunities that may emerge years after initial commissioning, and it allows projects to address capacity fade.

But augmentation isn’t operationally simple

The approach faces technology compatibility issues, and operational downtime during installation and permitting delays. The technical implementation alone requires careful planning. Augmentation can be done through DC blocks (adding battery enclosures to existing inverters) or AC blocks (requiring new inverters and switchgear). Each method carries different cost implications and technical considerations. Systems originally designed without augmentation in mind may face compatibility issues, particularly when mixing older and newer battery technologies.

Developers must consider updated permitting processes, potential shutdowns of operating systems during installation, and the complex integration of new components with existing energy management systems. Poor documentation of the original installation can complicate things further. Financially, augmentation makes the most sense for projects where revenue depends critically on maintaining discharge capacity – particularly those participating in capacity markets with strict performance requirements. But systems focused on frequency regulation or short-duration applications may find the costs outweigh the benefits, as these use cases are less sensitive to gradual capacity loss.

Successful augmentation is about foresight – preserving adequate space, electrical capacity, and maintaining thorough system documentation from day one.

Decision factors – overbuilding or augmentation?

Overbuilding makes sense when prices and costs are stable, revenue streams are predictable, and you want to avoid future hassles. Augmentation can work if you think future tech costs will reduce, or you need your upfront costs to stay low. Here are many of the factors to consider:

A middle-ground approach might default to modest overbuilding for a degradation buffer and operational simplicity, stay augmentation-ready for when future flexibility has measurable value, and remain scenario-aware for adjustments based on price forecasts and regulation changes.

La entrada When does it make sense to overbuild your BESS? se publicó primero en We turn good projects into great deals - Green Dealflow.

Table of contents

• European solar commitments
• Charter commitments
• How China dominates clean energy
  • Solar panels
  • The Global Energy Interconnection initiative
  • Dominance in BESS
• What can we learn from China?

Europe’s renewable energy transition is uncomfortably dependent on one of its biggest geopolitical rivals. Whilst the European Union races to install panels and storage, it has also become heavily reliant on Chinese manufacturing for the technologies that underpin its goals.

Almost all solar panels installed in the EU are imported from China, as are many of the batteries. China’s dominance isn’t accidental. The country’s coordinated industrial strategy is outlined in its policies, including the 14th Five-Year Plan for Energy Storage, which targets 100 GW of battery storage capacity by 2030 alongside 30% cost reductions. Beijing has backed this with billions invested in solar manufacturing alone, integrated supply chains, and provincial mandates requiring renewable projects to include storage systems. Now, China can produce panels at between half and two-thirds the cost of European alternatives.

The situation has reached what the European Solar Charter describes as “unsustainable,” with European manufacturers closing operations or turning to protected US markets. As panel prices drop and the EU targets 780 GWh of battery storage capacity by 2030, the question is whether Europe can mount an effective industrial response to China’s state-directed dominance.

European solar commitments

Solar energy is currently the fastest-growing renewable energy source in the EU, according to the Commission.  

• Last year, 56 GW of solar PV were installed in the EU (two-thirds on rooftops).
• Installations in 2022 and 2023 saved the equivalent of 15 billion cubic metres of Russian gas imports.
• The sector provides around 650,000 jobs, 90% on the deployment side, projected to increase to around 1 million by 2030.

Growth stems partly from the absence of tariffs or duties on Chinese solar module imports, but these same open trade conditions have exposed domestic producers to continuous price declines. Panel prices fell from about €0.20/W to less than €0.12/W in 2023, creating what the European Solar Charter describes as an “unsustainable situation”. Some European manufacturers are closing or reducing operations, or prioritising production for the US market, where tariffs and other trade policies make Chinese imports more expensive. A number of initiatives aim to address the problem.

The European Commission has not announced tariffs on imported solar panels, instead focusing on supportive policies:

• The EU’s Net-Zero Industry Act, agreed in early 2024, sets a binding target for European net-zero technologies manufacturing capacity to “approach or reach at least 40%” of annual deployment needs by 2030.
• The EU Clean Industrial Deal mobilises over €100 billion for clean-tech manufacturing, including solar. 
• For solar specifically, the European Solar PV Industry Alliance, launched in late 2022, targets 30 GW of annual production capacity by 2025, with more than 20 projects in its pipeline.
• Following on the heels of these policies, the European Solar Charter, also signed last year, aims to address plummeting prices and import dependency on China. But the proposed actions in support of EU photovoltaic manufacturing are voluntary.

Charter commitments

With no timelines or mandated targets in the Charter, will cooperation and goodwill be enough to secure the sector’s competitiveness? Critics are not so sure. Nevertheless, the charter commits member states to rapidly implement non-price criteria in renewable energy auctions and public procurement. These include resilience, sustainability, cybersecurity, and “ability to deliver” standards. Countries pledge to create favourable conditions for manufacturing facilities and remove regulatory barriers for innovative solar deployment like agri-PV, floating solar, and building-integrated systems.

Financial support includes using EU funding opportunities and flexibilities under the State Aid Temporary Crisis and Transition Framework. The Commission intends to work with the European Investment Bank to reinforce support through InvestEU and explore an Important Project of Common European Interest (IPCEI) for solar manufacturing innovations.

Europe’s struggles become clearer when viewed against China’s systematic approach to energy dominance.

How China dominates clean energy

Solar panels

China dominates the global solar panel supply chain, controlling over 80% of manufacturing capacity across all stages with 90% of panels including Chinese components such as polysilicon, wafers, cells, and modules. This has driven down costs by more than 80% over the last decade. Since 2011, China has invested more than €44.3 billion in solar PV manufacturing. This dominance is driven by large-scale government investment, cost efficiencies, and a well-integrated supply chain, which has enabled China to produce solar panels at two-thirds the cost of European-made panels.

Over 95% of solar panels installed in the EU are imported from China. While this reduces costs and accelerates deployment in Europe, it has made European solar panel manufacturing unviable.

The Global Energy Interconnection initiative

China’s deployment of ultra-high-voltage (UHV) grid infrastructure under its “Global Energy Interconnection” (GEI) initiative solves two challenges: domestic renewable integration and global technology standardisation. Domestically, UHV lines enable China to transmit vast amounts of wind and solar power from resource-rich western regions to industrial eastern hubs, slashing energy losses even over distances exceeding 3,000 km. It means China has cheap energy for it’s manufacturing sector. 

Through projects like hydropower links in Brazil and cross-border grids in Africa and Southeast Asia, China bundles UHV infrastructure with its renewable tech, locking nations into Chinese equipment, protocols, and financing. The State Grid Corporation (SGCC), which controls 80% of global UHV patents and 70% of equipment production, drives this expansion. It’s establishing Chinese standards (like voltage control algorithms), as global norms, sidelining EU competitors.

For the EU, China’s UHV lead erodes Europe’s green industrial competitiveness by enabling cheaper Chinese exports. Geopolitically, it extends Beijing’s influence via energy dependencies. While the EU struggles with fragmented national grids and slow permitting, China’s state-backed model rapidly deploys integrated infrastructure, turning renewable hardware dominance into control over future energy networks.

Dominance in BESS

A 2024 International Energy Agency report describes Europe’s near-total reliance on Chinese battery storage systems (BESS), where China controls “almost 85% of battery cell manufacturing capacity” and “90% of cathode and 98% of anode active material global manufacturing capacity.” Europe holds about 7% of battery cell manufacturing capacity and is deeply reliant on Chinese supply chains to manage grid stability, as batteries are key to stabilising the grid. For European policymakers looking for energy independence through renewables technology, concentration like this is vulnerable to supply chain disruptions or geopolitical tensions with China.

China’s battery manufacturing has been supported by decades of direct incentives and financial concessions for local firms, with the cost advantage accelerated by state planning, including a 30% cost-reduction target for energy storage by 2025 under China’s 14th Five-Year Plan. Worldwide, over 75% of BESS deployments are reliant on cells from China. While the EU targets 780 GWh of storage capacity by 2030, China’s innovation speed could cement European dependency on Chinese technology and supply chains.

What can we learn from China?

China’s dominance is the result of deliberate government policy: huge state investment, subsidies, and a focus on building a complete supply chain from raw materials to finished panels and batteries. The ability to rapidly innovate, scale up production, and cut costs has made solar affordable worldwide, but has also concentrated supply risk and left other regions scrambling to respond. Meanwhile, Europe continued to rely on cheap fossil fuels and did not implement a clear industrial strategy. Fragmented policies did not help.

The EU’s challenge is whether it can replicate any of these strategies in a political and economic environment that is less centralised and less willing to deploy large subsidies and tariffs. Both may be necessary to move away from the status quo.

La entrada Can Europe Compete with China’s Renewable Energy Strategy? se publicó primero en We turn good projects into great deals - Green Dealflow.

Table of contents

• Poland’s ambitious energy storage push
• Growth in renewable capacity drives storage demand
• Funding and eligibility
• Application basics
• Market potential and investment opportunities

Poland has just rolled out one of Europe’s most ambitious energy storage programmes – a €980 million initiative that’s set to transform the country’s grid infrastructure. The Polish Ministry of Climate and Environment has finalised this landmark subsidy scheme, targeting over 5 GWh of new storage capacity by 2028. The National Fund for Environmental Protection and Water Management (NFOŚiGW) will administer the programme. With applications now open through May 2025, the initiative represents a major step forward in Poland’s renewable energy transition, helping the grid adapt and thrive as the country rapidly scales up solar and wind power.

Poland’s ambitious energy storage push

The programme aims to improve the stability of Poland’s National Energy Network (KSE) and bolster the country’s energy security by supporting the construction of medium to large-scale electricity storage facilities. Eligible projects must have a capacity of at least 2 MW/4 MWh, connected to the distribution and transmission network at all voltage levels.

The scheme has been brewing since 2024, with the final regulation published in the Journal of Laws of the Republic of Poland in March this year. It received European Commission approval, which authorised state aid of €1.2 billion in state aid to support at least 5.4 GWh of new electricity storage facilities. The Supervisory Board of the National Fund for Environmental Protection and Water Management signed off on the final criteria, including one that rewards applicants who commit to not selling the supported project for at least five years after completion.

Growth in renewable capacity drives storage demand

Poland’s shift toward renewable energy has accelerated significantly in recent years, creating an urgent need for energy storage solutions. According to the Energy Market Agency, Poland’s installed solar capacity reached approximately 20.7 GW by the end of November 2024 – a 28% year-on-year increase. 

Projections from the Polish transmission system operator PSE’s grid development plan for 2025-2034 are that up to 45 GW of photovoltaics and about 18 GW of offshore wind power could be operating within the next decade, plus additional gigawatts of offshore wind and nuclear capacity. But this dramatic increase in intermittent renewable generation has, of course, heightened the risk of grid imbalances.

As we know, the changing structure of electricity generation creates more chances of oversupply or shortages in the electricity system. Battery energy storage systems (BESS) will soak up surplus electricity during high production periods and release it when generation dips, providing essential grid stabilisation services as Poland moves away from conventional power sources.

Funding and eligibility

The budget is divided between non-returnable grants (€865 million/PLN 3.735 billion) and repayable loans (€96 million/PLN 415 million). The percentage of total investment costs covered by government funding support varies by company size:

• Large enterprises, up to 45%
• Medium-sized enterprises, up to 55%
• Micro and small enterprises: up to 65%

Eligible beneficiaries include businesses registered in Poland, excluding financial sector entities, and eligible investments include:

• Construction of electricity storage facilities (mandatory)
• Connection to the network and associated infrastructure (optional)
• Storage configuration and adaptation (optional)

Application basics

Applicants must demonstrate that without public aid, they would not undertake the investment or would implement it in a significantly limited way. They also need to contribute at least 15% of the costs from their own funds in the form of share capital covered by a cash contribution. Cost-effectiveness is the key evaluation metric, with points awarded as follows:

• 3 points for projects requesting less than €185,000/MWh (PLN 0.8 million/MWh)
• 2 points for projects with costs between €185,000-€347,000/MWh (PLN 0.8-1.5 million/MWh)
• 1 point for projects exceeding €347,000/MWh (PLN 1.5 million/MWh)

Market potential and investment opportunities

The energy storage sector in Poland showed significant momentum even before the launch of this new subsidy programme. Through power market auctions for 2021-2028 and supplementary auctions for 2021-2025, contracts for energy storage with a total capacity of 9.5 GW were already wrapped up. The Polish Economic Institute noted that in December 2024’s power market auction alone, approximately 2.5 GW of storage capacity was contracted – a 44% jump over the 1.7 GW contracted in 2023. This growth trajectory looks set to continue as renewable penetration ramps up and grid stabilisation becomes more critical.

This scheme opens up a real opportunity for developers and investors in Poland’s energy storage market. The generous subsidy rates, particularly for small and medium-sized enterprises, help lower capital barriers and take some risk out of investments. Clear eligibility criteria, significant grant funding, and Poland’s pro-EU policy approach create a welcoming environment for both domestic and international players.

As the country continues its transition away from fossil fuels, investors can expect strong demand for storage technologies and long-term growth prospects in this emerging sector.

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Table of contents

• BESS economics: The numbers now add up
• Repowering could triple output from Europe’s prime wind sites
• The case for modernisation
• Ambitious auction pipeline to secure Europe’s wind future
• The Copenhagen call to action on regulations

Green Dealflow joined over 15,000 renewable energy professionals in April at WindEurope 2025 in Copenhagen, rallying around the theme ‘Scale Up, Electrify and Deliver’. Here, we’re focusing on four aspects of interest to project developers and investors: the increasing viability of battery storage systems, the opportunities in repowering ageing turbines, the regulatory landscape, and the pipeline for upcoming wind auctions.

BESS economics: The numbers now add up

Battery storage emerged as a central focus at WindEurope 2025, with industry leaders highlighting the critical role of storage systems in balancing supply and demand. “Storage systems play a crucial role in enhancing grid flexibility by balancing supply and demand, accommodating the intermittent nature of renewable sources, and ensuring a stable and reliable energy supply,” noted Aurélien Ballagny, Head of Policy at the Energy Storage Coalition.

Rystad Energy’s “Renewables and Power Outlook 2025” underscores the increasing viability of BESS projects and investment. Their research confirms that, globally, 2024 saw nearly 200GWh of new BESS capacity — an 80% year-on-year increase. Cost reductions have been dramatic, with average capital expenditure falling below £300 per kilowatt-hour alongside improved cycle life guarantees exceeding 10,000 cycles. California exemplifies the trend, with batteries now supplying about 11% of power demand during discharge periods — up from less than 1% four years ago.

In Europe, the report shows, growing price volatility is creating attractive arbitrage opportunities, with profits exceeding €77 per discharged megawatt-hour in many Western European markets. This is particularly significant given that European BESS implementation costs remain substantially higher than those in China, where vertically integrated supply chains and strong policy support have driven battery block prices down to around €65 per kWh – with Chinese manufacturers still maintaining substantial 45% profit margins. Despite European projects often facing costs exceeding €300 per kWh due to labour, energy, and manufacturing limitations, the widening arbitrage potential is increasingly offsetting these higher capital costs, making the business case for storage deployment stronger even in high-cost regions.

Repowering could triple output from Europe’s prime wind sites

As Europe’s wind fleet ages, the question of what to do with thousands of first-generation turbines has become a pressing issue for the industry. There is significant potential in replacing older, less efficient turbines with modern models.

The case for modernisation

The oldest wind farms in Europe occupy the continent’s best wind locations, but many run on outdated technology that delivers far less electricity than today’s turbines can achieve. According to WindEurope, repowering can more than triple the output of a wind farm and reduce the number of turbines by 25%. This translates to more power and a smaller visual footprint – a compelling proposition for communities and developers. Despite these benefits, the session titled Repowering: why ain’t it happening? revealed significant barriers to progress:

• Many European countries lack clear national strategies for repowering
• Cumbersome permitting procedures are the main obstacle
• Updated grid connections are needed to accommodate repowered turbines The EU has taken steps to address these issues with new permitting rules that mandate six-month decisions for repowering projects.

The scale of opportunity is substantial, with permitting rates for new and repowered wind farms rising sharply across the EU in 2024. Germany has led the way, with approvals reaching 12 GW – up 60% from the previous year and exceeding the rest of the EU combined.

Ambitious auction pipeline to secure Europe’s wind future

WindEurope has proposed a New Offshore Wind Deal for Europe, calling for governments to auction at least 100 GW of offshore wind capacity between 2031 and 2040. This proposal, if adopted, would create a predictable schedule of approximately 10 GW annually, providing the steady flow of projects needed for factories and developers to scale operations efficiently. Unlike the current approach with its changing targets and compressed timeframes, WindEurope’s method would give investors and supply chain companies greater certainty for long-term planning.

Meanwhile, actual projections show Europe is on track to install 187 GW of new wind power capacity from 2025 to 2030, with the 27 EU member states accounting for 140 GW of this total. This represents an average annual addition of 23 GW across both onshore and offshore projects. While financing is materialising, with €33 billion secured in 2024 alone for nearly 20 GW of upcoming projects, the industry requires more consistent auction schedules to sustainably scale manufacturing capacity and development resources.

Currently, Germany, the UK, and France are leading the way in auction implementation and capacity installations. Other markets, including Poland, Ireland, Portugal, and Spain, have confirmed they are preparing concrete tender announcements for 2025. Speakers advocated for two-sided Contracts for Difference (CfDs) as the preferred auction mechanism, citing their effectiveness in reducing risk and improving project bankability. (CfDs guarantee a fixed price for electricity, with the developer receiving top-up payments when market prices fall below this level but returning money when prices exceed it).

The Copenhagen call to action on regulations

At the opening session, the wind industry launched the Copenhagen Call to Action, urging European governments to:

• Apply new EU permitting rules to speed up project approvals and filter out stalled (“zombie”) projects from grid queues.
• Remove barriers to electrification – including reforming taxes and enabling state aid for renewable power purchase agreements (PPAs).
• De-risk wind investments by ensuring a stable pipeline of CfD auctions, which provide cost visibility and investment certainty.

The message from Copenhagen is clear: Europe’s wind industry is at a moment where technological innovation, strategic investment, and regulatory courage must converge to transform the clean energy vision into reality.

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Table of contents

• Ready-to-build pipeline
• National picture
• Regional hotspots
• Infrastructure and regulatory considerations
• Track progress

Italy’s solar photovoltaic (PV) sector has a significant pipeline of ready-to-build projects poised to accelerate the country’s renewable energy transition. Recent data from Italy’s grid operator Terna shows strong momentum in the solar market, particularly in southern regions. The large number of fully authorised projects indicates that installation rates could accelerate significantly once construction begins on these sites.

Ready-to-build pipeline

As of early 2025, Italy has 137 fully authorised ready-to-build solar PV projects with a combined capacity of 6.14 GW, up from 5.84 GW in January. These projects are concentrated primarily in Sicily (49 projects, 2.96 GW), Lazio (33 projects, 1.52 GW), and Sardinia (9 projects, 0.30 GW). All the necessary permitting is complete, and construction is next – a major advancement in Italy’s renewable infrastructure.

National picture

These figures show significant momentum in Italy’s commitment to expanding renewable energy capacity as part of its 2030 decarbonisation targets.

• 3,857 connection requests for solar PV plants as of March 31, 2025
• Total requested solar capacity of 153.54 GW
• Solar represents more than half of all renewable energy applications
• 804 projects have obtained environmental authorisation, totalling 33.77 GW

Regional hotspots

For investors and developers, the concentration of approved projects in specific regions suggests where infrastructure development and grid connection opportunities may be most immediately available, while also highlighting areas where additional policy support could help convert the substantial pipeline of requested capacity into shovel-ready projects.

• Sicily remains the powerhouse, with 814 total connection requests for 40.69 GW and the highest concentration of approved projects ready for development.
• Puglia shows strong development activity with 916 connection requests totalling 38.72 GW and leads in environmentally authorised projects, though it has a limited number of fully ready-to-build projects despite high interest.
• The Viterbo province stands out as a significant development hub within Lazio, with 27 projects totalling 1.28 GW now fully authorised and ready for construction. These represent just over 20% of the 120 total applications in the area, which collectively amount to 4.76 GW of potential capacity. A recent legal victory for developers has removed a key obstacle, as the courts struck down a previous moratorium that had blocked new solar installations in the region, potentially accelerating the timeline for breaking ground on these projects.

The regional approach to renewable energy approvals has proven effective in expediting projects in these areas. While the 6.14 GW of ready-to-build capacity represents just a fraction of the total 153.54 GW in requested solar connections, it signals a maturing market where projects are successfully completing the permitting process.

Infrastructure and regulatory considerations

The expansion of Italy’s solar capacity depends on several key developments. Grid infrastructure will need significant enhancement to accommodate the surge in renewable connections, particularly in regions with the highest concentration of projects. Meanwhile, regional regulatory frameworks continue to evolve at different paces, affecting project timelines across the country, although the recent court decision in Viterbo shows that legal developments can quickly change the outlook for specific areas. Industry stakeholders are working toward greater cohesion between Italy’s renewable energy targets and the practical implementation pathways needed to achieve them.

Track progress

You can use Terna’s Econnextion platform to monitor Italy’s energy transition. This interactive digital dashboard shows all renewable energy connection requests with geolocated data across different renewable sources and status tracking from initial application to full authorisation. 

La entrada Italy Market Update: Over 130 Projects Ready for Construction se publicó primero en We turn good projects into great deals - Green Dealflow.

Table of contents

• Market leadership by the numbers
• REER auctions: Investment stability through competitive bidding
• Just Transition tenders: Linking renewables to regional development
• Coming soon: Capacity markets
• Battery storage is key to Spain’s ambitions

Spain’s solar market is experiencing significant growth, creating a wave of project and investment opportunities worth watching. With a combination of natural resources, policy stability, and innovative market mechanisms, Spain’s tilt toward the sun appears to be a winning strategy.

The Spanish government recently greenlit nearly 300 renewable energy projects representing a €17 billion investment and 28 gigawatts of new capacity. The pipeline looks equally promising, with upcoming tenders expected to allocate 10 GW of solar photovoltaic capacity by the end of this year and projected growth to approximately 43,8 GW by 2028.

The country’s National Energy and Climate Plan, with its ambitious target of 76 GW of solar capacity by 2030, creates a foundation for long-term market visibility and is supported by concrete policy improvements. These include the elimination of previous barriers like the controversial ‘sun tax’ (taxing self-generated solar power even if not grid fed), and the implementation of the REER auction scheme, which provides revenue stability through long-term contracts. Innovative mechanisms like Just Transition Institute tenders that link grid access for renewables to socioeconomic development in regions affected by coal plant closures, further suggest Spain is serious about solar power leadership well into the future.

Market leadership by the numbers

Spain’s natural advantage is enviable – the country receives about 50% more sunlight than Germany, for example, but the momentum goes beyond geography:

• In January 2025, Spain’s solar PV capacity reached 32,043 MW, surpassing wind power (32,007 MW) to become the technology with the highest installed capacity in the country.
• Photovoltaic capacity is expanding nearly twice as fast as the European average, with solar now accounting for 21% of Spain’s electricity generation – nearly double the EU average of 11%.
• Since 2001, Spain’s solar capacity has seen a remarkable year-on-year increase of 27.9%.
• The PNIEC (National Integrated Energy and Climate Plan, or Plan Nacional Integrado de Energía y Clima) aims to increase renewables to 48% of final energy consumption and 81% of electricity generation by 2030.
• Specific PNIEC targets include installing 76 GW of solar PV, 62 GW of wind power, and 22.5 GW of storage capacity.

REER auctions: Investment stability through competitive bidding

Overseen by the Ministry for the Ecological Transition and the Demographic Challenge (MITECO), Spain’s renewable energy auctions operate under the ‘Régimen Económico de Energías Renovables’ (REER) framework. Auctions are held annually to allocate renewable energy capacity across various technologies, with solar and wind being prioritised. REER offers project developers a stable investment environment through a pay-as-bid system and includes sliding feed-in premiums (Contracts for Difference or CfD). These adjust payments based on market prices to incentivise participation in the wholesale electricity market. Notably, these auctions permit hybridisation between technologies and compatibility with energy storage solutions.

MITECO published an indicative auction schedule for 2020-2025 where solar PV had a quota of approximately 1.8 GW per year and wind energy around 1.5 GW annually through 2025. The auction process is straightforward: developers submit sealed bids, winners receive their offered prices, and projects proceed with regulatory certainty. Participation requires economic guarantees of 60 €/kW for intended capacity, with auctions following pre-qualification, qualification, and bidding stages. None are confirmed yet for 2026, but with PNIEC targeting 81% renewable electricity by 2030, potential extensions are suggested.

Just Transition tenders: Linking renewables to regional development

Spain’s Just Transition Institute (ITJ) created a tender system that addresses coal plant closures while expanding renewable energy. They offer grid access to projects that commit to local job creation and community investment in affected regions, with 55% of evaluation criteria focused on development plans. Endesa’s subsidiary won the first tender in November 2022, committing €1.5 billion for renewables in Andorra, Aragón, plus €60 million for social initiatives, creating 380 direct and 6,000 indirect jobs. ITJ is now preparing four new tenders, including one allocating 409 MW of grid access capacity, with dates not yet announced.

Coming soon: Capacity markets

Spain plans its first capacity market auctions by September 2025, with the system expected to be operational in 2026. These auctions, managed by grid operator Red Eléctrica de España, will contract firm power capacity through three types of auctions.

• The main auction will focus on existing facilities and new projects starting service within five years of award (service duration of one to 15 years, depending on technology).
• The annual adjustment auction targets operational facilities with 12-month service periods to address temporary system needs.
• The transitional auction will ensure system firmness until main auction services become operational, with an annual duration.

Following a pay-as-bid model, the market is technologically neutral, allowing generation, storage systems and demand-side resources to compete equally.

Battery storage is key to Spain’s ambitions

Spain’s renewable growth story is becoming a storage story too. The National Energy and Climate Plan sets a target of 22.5 GW of storage capacity by 2030, with approximately 10 GW expected to come from standalone battery projects. For developers and investors, battery economics are improving rapidly. Declining costs coincide with expanding revenue opportunities through ancillary services and market trading. Large-scale projects exceeding 300 MW are gaining momentum due to economies of scale and increasing demand for grid stability solutions.

The upcoming capacity market auctions in 2025 will provide additional revenue streams for battery storage developers by compensating for firm power availability. It will reduce investment risks while complementing income from wholesale electricity markets, making battery storage projects increasingly attractive as Spain pushes forward with its renewable energy transformation.

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