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.

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Table of contents

• Market Options
  • Four strategy options
  • Comparing MACSE and capacity market options
  • MACSE auctions
  • Capacity Market auctions
  • Regional considerations
• Market strategies
  • Baseline MACSE returns
  • Capacity market risks
  • Hybrid strategies and risks
  • The timing conundrum

Market Options

Italy’s ambitious drive towards renewable energy integration, targeting 50 GW solar and 28.1 GW wind capacity by 2030, has created distinct pathways for Battery Energy Storage System (BESS) investments –  the MACSE auction and Capacity Market auctions.Choosing between these mechanisms involves weighing the trade-offs between long-term stability and short-term flexibility.

The MACSE programme (Meccanismo di Approvvigionamento di Capacità di Stoccaggio Elettrico or, the Electricity Storage Capacity Procurement Mechanism), managed by grid operator Terna, offers 15-year contracted storage opportunities with high revenue certainty, particularly suited to southern Italy’s abundant renewable resources but weaker grid infrastructure. The Capacity Market, prevalent in the industrialised north, provides shorter-term opportunities aligned with the region’s robust infrastructure and higher electricity demand.

While MACSE aims to deploy 50 GWh of long-term contracted storage by 2030, focusing on renewable integration, the Capacity Market addresses immediate grid stability needs through more dynamic, market-driven approaches. This regional and mechanical divide presents investors and project developers with risk-return profiles that need careful consideration of project specifics, location advantages, and investment horizons.

The timing of these markets adds a layer of complexity: Capacity Market auctions are happening soon, before MACSE’s first auction. This means developers and investors need to decide whether to commit to the capacity market or wait for potentially better terms with MACSE.

Four strategy options

Within this landscape, according to Timera Energy, investors can pursue four distinct strategies, each with unique characteristics:

1. MACSE auction and sign 15-year contracts with high revenue certainty (IRR 5–6%), particularly suited to southern Italy
2. Capacity market which provides 15-year contracts with potential merchant revenue upside
3. A combination of stable MACSE contracts with merchant opportunities to optimise returns while maintaining security
4. Market benchmark: merchant opportunities, but high risk

Comparing MACSE and capacity market options

The MACSE and Capacity Market mechanisms represent different approaches to incentivising storage deployment in Italy, each with distinct operational structures and risk profiles. This split approach reflects Italy’s broader energy strategy: MACSE focuses on supporting renewable energy growth in the south, while the capacity market helps keep the grid stable across Italy, especially in the industry-heavy north.

MACSE auctions

MACSE operates as a ‘pay-as-bid’ auction system with zonal quotas, specifically targeting new stand-alone storage projects that haven’t begun construction. Think of it as a stable, long-term partnership: projects get high revenue certainty (over 90%) through fixed capacity payments from Terna, Italy’s trusted grid operator. The mechanism has a revenue-sharing model – projects give up all their wholesale market earnings in exchange for keeping 80% of the balancing market revenues, with safeguards in place to protect against extreme price swings.

MACSE particularly favours longer-lasting batteries – the longer your battery can provide power, the better the price you’ll get per megawatt-hour. It also rewards more efficient systems with higher premiums. However, over the medium term, there may not be enough capacity within the limits set by the Transmission System Operator (TSO) to accommodate all projects. This dynamic may push participants toward aggressive bidding strategies, although the scheme ensures that bids must reflect prices participants are willing to accept.

Capacity Market auctions

The Capacity Market (CM) uses a ‘pay-as-cleared’ system with zonal pricing, open to both existing and new power capacity projects. While it also offers 15-year contracts, it lets projects keep all their market revenues on top of capacity payments (though there are caps on total earnings). But actual payments can be lower than expected because of ‘derating’. This means the payment might be reduced if the battery can’t deliver power for as long as the market needs it.

Regional considerations

Italy’s ambitious renewable energy targets present significant challenges for system security. A substantial portion of growth is expected in southern regions and islands, areas already facing critical grid flexibility issues. To address these challenges, expanding electricity storage and transmission infrastructure is essential to support the integration of renewable energy sources.

There’s disparity between Renewable Energy Sources (RES) capacity and peak load across different zones. Northern Italy shows a relatively balanced capacity-to-load ratio, but southern regions and Sicily face potential capacity surpluses that need robust storage solutions to manage energy flows effectively.

Right now, battery storage projects aren’t making enough money without some form of government support in Italy – that’s why choosing between these market mechanisms is so crucial. The capacity market in the north is getting crowded, with existing power plants already taking most contracts at the highest allowed prices. This makes it harder for new battery projects to compete unless they can offer something special.

Location plays a big role in which strategy might work best. Southern projects can benefit from MACSE’s focus on supporting renewable energy integration, though they face challenges with grid connections. Northern projects enjoy better infrastructure and reliable industrial power demand but face tough competition from existing players.

If you can’t get into MACSE auctions because they’re oversubscribed, mixing capacity market participation with energy trading is an option, but one that needs deep market expertise.

Market strategies

Baseline MACSE returns

The MACSE scheme offers long-term contract support, effectively swapping merchant revenue volatility for a stable, predictable premium over 15 years. This makes it particularly appealing for risk-averse investors. In contrast, the capacity market involves higher exposure to merchant risk. It compensates participants for maintaining standby capacity to ensure security of supply but does not provide the same level of revenue stability as MACSE.

The expected returns (‘unlevered IRR’) range from 5–6% if you stick purely to MACSE contracts. This can rise to 7–9% if you mix these contracts with market trading activities in a hybrid approach. But fierce competition is expected in MACSE auctions, which could mean lower returns than initially hoped.

Capacity market risks

The capacity market is well-suited to industrialised northern Italy with its developed infrastructure and higher industrial demand for power. While it offers 15-year contracts like MACSE, investors can stack their capacity payments (payments are then available when needed) on top of what they earn from selling energy in the wholesale market. This could mean higher returns, but you’re also more exposed to market swings. When energy prices go above certain levels, investors might have to pay money back, so they need to be comfortable with this uncertainty.

Hybrid strategies and risks

A hybrid MACSE strategy offers reliable baseline returns from the contracted portion while keeping the ability to earn extra through market trading: BESS operators keep 20% of earnings from grid balancing services (ancillary services) while passing the day-to-day market trading risk to Terna (Italy’s grid operator).

The timing conundrum

Capacity Market auctions are coming up first (late 2024 and early 2025), while MACSE auctions follow in the first half of 2025. This means investors face a choice: jump into the capacity market early or hold out for potentially more stable MACSE opportunities. This is tricky for projects that could work in either market.

For investors who prioritise steady, predictable returns, MACSE’s inflation-linked payments and clear protections against downside risk are attractive. Those comfortable with more market exposure might prefer the Capacity Market’s flexible structure and potential for higher returns through sophisticated trading strategies. Success in either market comes down to the specifics of your project – how long your battery can provide power (duration), how efficient it is, and where it’s located. MACSE particularly rewards batteries that can provide power for longer periods through its pricing structure, while doing well in the Capacity Market often depends on how quickly and flexibly you can respond to market needs.

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Table of contents

• How do you generate revenue with a BESS project?
  • Energy arbitrage
  • Ancillary services
  • Capacity payments
• Performance factors for arbitrage operations
  • Availability
  • Duration
  • Location
  • Timing
• Price volatility drives higher returns
  • Will arbitrage or grid services lead the way?

Battery Energy Storage Systems (BESS) provide operators with multiple avenues to generate revenue. These systems are not limited to a single function but can capitalise on various market opportunities, making them highly versatile investments. From energy arbitrage – where batteries buy electricity at low prices and sell it during peak demand – to ancillary services that stabilise the grid, and capacity payments for ensuring power availability, BESS projects offer diverse revenue streams. This kind of ‘revenue stacking’, where operators combine multiple income sources from a single asset, has become important to maximising returns on BESS investments.

As renewable energy integration increases, so do the opportunities for BESS to maximise profits through price volatility and advanced trading strategies. The ability to dynamically shift between these different revenue models – sometimes within the same day – positions BESS as a critical player in the evolving electricity markets.

How do you generate revenue with a BESS project?

Each of the three main ways that BESS generates revenue offers distinct opportunities to monetize investments.

Energy arbitrage

The primary revenue stream for BESS projects comes from price arbitrage – buying electricity when prices are low and selling it when prices are high. The strategy is straightforward: charge when prices are low and discharge when prices are high. The most profitable times to charge batteries are typically during off-peak hours (often between 2:00-5:00 AM) and discharge during peak demand periods (usually around 7:00-8:00 PM).

This allows BESS operators to capture the maximum price differential in electricity markets. The profitability of this strategy varies significantly by market. Arbitrage is particularly profitable in Germany due to high price volatility in the energy market and Germany’s supportive regulatory framework. The German Renewable Energy Sources Act encourages energy storage participation, making it easier for battery systems to capitalise on price differentials

With increasing renewable energy integration, price volatility in day-ahead markets has grown, creating more opportunities for profitable arbitrage operations. These price swings, driven by the variable nature of wind and solar generation, can create significant profit potential for well-positioned BESS projects. This effect is particularly evident in markets with high renewable penetration. For example, Denmark, Luxembourg, and Lithuania (with 52.8%, 42.4%, and 39.8% wind and solar share respectively) experience significant price variations, creating more potential arbitrage opportunities for BESS operations.

Ancillary services

Ancillary services provide another revenue stream, where BESS operators support grid stability through frequency regulation, voltage control, and spinning reserves. These services become increasingly valuable as power systems accommodate more renewable energy. In addition to contracting with grid operators for these services, balancing energy from automatic Frequency Restoration Reserves (aFRR) can also be traded across borders via platforms like PICASSO.

However, mature markets, such as France, are showing clear signs of saturation, according to the Oxford Energy Forum article Powering the Future. While once highly profitable, ancillary service revenues have fallen more sharply than expected in 2023, making it no longer viable for operators to rely solely on these markets.

Capacity payments

Capacity payments can also provide revenue in markets where operators are compensated for guaranteeing power availability during high-demand periods or grid stress. Some markets also offer government incentives or subsidies for energy storage deployment, adding another potential revenue layer.

BESS is already playing a critical role in capacity markets, with several EU member states allowing energy storage to compete alongside conventional generation sources. Countries like Italy and Poland have seen capacity markets unlock large-scale battery storage, with contracts awarded based on cost-effectiveness.

Recent capacity market auctions have shown strong momentum for battery energy storage systems (BESS) in European markets. In Belgium’s latest Capacity Remuneration Mechanism (CRM), BESS projects dominated new capacity awards, securing 350MW across 13 projects and bringing total BESS contracts to 1.1GW. Similarly, Italy’s recent capacity market results reflected this trend, with BESS projects winning over half of new contracts (89MW out of 174MW), spread across three projects with durations of 2-3 hours in different market zones.

Among these revenue streams, energy arbitrage has emerged as the most scalable opportunity for BESS operators. While ancillary services can provide steady income, these markets are often capacity-limited and showing signs of saturation. In contrast, arbitrage operates in an open market where opportunities scale with price volatility and market dynamics. This explains why arbitrage currently accounts for 60% of installed storage systems’ activity. Understanding the key performance factors that drive successful arbitrage operations therefore becomes crucial for BESS project development.

Performance factors for arbitrage operations

Availability

Availability planning becomes crucial – operators must balance maximizing arbitrage opportunities against maintaining reserve capacity for grid services and managing battery degradation over the project’s lifetime.

Duration

The duration of a BESS system – how many hours it can discharge at rated power – significantly impacts arbitrage potential. Research shows optimal returns typically require 4-6 hour systems, as these can capture the full evening price peaks while maintaining operational flexibility. Shorter duration systems miss opportunities during extended high-price periods, while systems beyond 6 hours face diminishing returns against their higher capital costs.

Location

Market location proves to be a determining success factor for arbitrage operations. The most profitable European markets consistently show two characteristics: high intraday price volatility and sufficient market liquidity to execute trades. According to a 2023 report, markets with significant renewable penetration tend to create more arbitrage opportunities – Romania, Finland, and the Baltic states achieve over 300 profitable cycles annually, while others manage fewer than 100 despite higher average prices.

Timing

While traditional arbitrage focused on overnight charging and evening discharge, markets with significant solar capacity now often present midday charging opportunities as prices drop during peak generation. Success may depend on advanced trading algorithms that can find and take advantage of the best price differences while considering energy losses during charging and discharging. But, as we discuss next, high electricity prices alone don’t guarantee better returns for BESS projects. The key driver is actually price volatility within each day.

Price volatility drives higher returns

The success of a BESS project in energy arbitrage depends more on the size of price differences during each day than on how high the average prices are. What matters is how much prices swing up and down within a single day; how many buy-low, sell-high opportunities there are.

Energy trading in day-ahead and intraday markets plays a crucial role in creating these opportunities. In the day-ahead market, participants forecast and trade electricity for the next day, locking in prices based on expected supply and demand. However, unexpected changes can occur, leading to price fluctuations. In the intradaymarket, positions can be adjusted closer to real time, responding to unforeseen changes in demand or renewable generation.

For example, Spain’s market had some of Europe’s highest average electricity prices in 2022, but supported only 58 profitable trading cycles because prices remained relatively flat throughout each day. In contrast, markets like Romania, Finland, and the Baltic states saw frequent price swings within each 24-hour period, enabling over 300 profitable cycles annually. Their success comes from combining substantial price differences between peak and off-peak hours with consistent day-to-day trading opportunities.

In short, the most successful BESS markets tend to have both high prices and significant intraday price variations.

Will arbitrage or grid services lead the way?

As we move to longer-duration storage and 100% renewable energy goals, which revenue model may become dominant? Will these systems continue to serve as primarily grid-balancing workhorses?

The traditional playbook of parking batteries in the frequency response market and watching the revenues roll in may not serve for much longer. According to a 2024 Energy Storage Report published by Energy Storage News, optimization firms are already adapting to this new reality, developing sophisticated trading strategies that can navigate multiple revenue streams simultaneously. The maths on this is fairly simple – when any single market becomes saturated, returns diminish, pushing operators to seek new opportunities.

Energy arbitrage already commands a 60% share of installed storage systems’ activity, and that number is trending upward. Yet, at the same time, we’re seeing new grid service models emerge. Germany’s “Grid Boosters” program, for example, positions batteries to mimic transmission line capacity, potentially eliminating the need for expensive backup infrastructure. This kind of dual-purpose thinking suggests that the future might not be an either/or scenario between arbitrage and grid services.

Winners in this evolving landscape will likely be those who maintain maximum flexibility. The ability to quickly shift between arbitrage opportunities and grid services – sometimes within the same day – could become the key to maximising battery storage value. Rather than betting everything on a single revenue stream, the trend points toward a more nuanced approach where batteries play multiple roles in our grid ecosystem.

The evidence suggests that European BESS projects that rely on single-revenue models are seeing diminishing returns, while those embracing operational flexibility across multiple revenue streams are pulling ahead. Versatile revenue stacking like this is becoming a requirement for success.

La entrada How to create revenue with a BESS project se publicó primero en We turn good projects into great deals - Green Dealflow.

Why develop a solar project?​​

Investing in solar energy offers numerous advantages, not only for individuals and companies but also for the environment.

From a financial perspective, solar projects can be highly profitable, and developers and asset owners can benefit from:

• Ongoing income from electricity sales
• Potential profits from selling the project
• Supportive government policies create a favorable investment climate but before getting to the point of financing your projects, it is worth the time to check out the crucial elements that should be on your solar project teaser.

Selling solar projects​

Developers can sell solar projects at various stages, from pre-development to operational. Projects closer to completion typically fetch higher prices due to reduced risk and quicker time to market. The decision on when to sell depends on the developer’s strategy and the stage of project development.

Selling the electricity ​

The primary financial benefit of solar projects is the sale of electricity. Depending on where you are in the world, a 1-megawatt solar project typically generates between $21,250- $42,500 per acre per year. and significantly more than this in some markets.

While initial land preparation costs are substantial, scaling up by adding more panels can increase electricity output without proportionally increasing costs. Bulk purchasing of solar panels can further reduce expenses.

Government incentives​

Governments across the world are keen on encouraging the development of renewable projects for several reasons, including energy security and meeting agreed-upon climate targets, such as the EU’s goal of reducing its emissions by at least 55% by 2030, compared to 1990 levels.

For developers, the push by governments to meet targets means that it is not only a great time to enter the renewable energy sector but also, a great time to turn large profits.

Many governments, from local to national scale, may offer rebates and other financial incentives that can help with the transition to renewable energy. To know more we suggest you look at the EU policies for funding the renewable energy sector.

Challenges in securing funding for solar projects​

Despite the environmental benefits, obtaining funding for solar projects hinges on solid economic planning. The cost of solar energy generation has significantly decreased over the past decade, primarily due to cheaper Chinese solar panels and increased manufacturing efficiencies. However, upfront costs remain a considerable barrier.

Additionally, whereas the cost of materials was previously closer to 50% of the initial solar project development costs, this is now closer to 10% for some companies. This decrease in costs can largely be attributed to increases in manufacturing efficiencies and as such, manufacturing costs. However, this upfront cost, among others, still represents a significant and often problematic investment for many businesses and organizations.

The biggest challenge in raising capital is attributed to the large levels of early-stage risk. With all costs taken into account, a 1 MW solar power plant easily sets you back between $890,000 and $1.01 million. but returns on the solar project investment are between 10-20% on average. Most solar farms pay off their system within five to ten years, and then have at least 20 years of almost “free” electricity after that.

These upfront costs include site surveys, feasibility studies, planning permission applications, power generation license applications, legal fees, site preparation fees, cost of materials, and many more. We cover this in more detail here.

Given the risks of permission applications getting rejected or developers’ teams not being able to execute for other reasons, coupled with high fees, early-stage renewable projects can be very risky for investors, which is also reflected in the price they are willing to pay.  

However, once planning permission is granted, the projects are mostly considered low risk. Solar development is a rapidly growing industry, and with careful planning, all these challenges can be overcome.

Types of Solar Project Financing ​

Self-financing​

For those with available capital, self-financing allows complete control over the energy produced. This is most common for smaller projects where the energy is primarily for personal or business use. The project owner pays for the equipment and installation costs. The greatest benefit of this option is that the individual or company then owns and has control over all the energy produced; hence it is used most frequently for small projects where most or all energy is to be consumed.

Solar leasing​

While some may have the option to absorb the entirety of the cost, this is not always possible or most efficient.

Leasing solar PV systems avoids the upfront costs of purchase and installation. This option, which involves fixed monthly payments, is prevalent in residential rooftop projects and some commercial and industrial (C&I) projects.

Funding for larger-scale projects​

Utility-scale solar projects demand significant financial investment, and developers strive to secure the least expensive capital while minimizing their risk exposure. Various financing options are available, each involving different levels of third-party involvement.

In the early stages of development, equity financing is typically the most accessible due to the inherent risks and challenges. For projects that are ready-to-build (RTB), debt financing becomes more viable and cost-effective, provided a predictable revenue stream is established.

From a profit-maximizing perspective, developers often prefer to leverage debt as extensively as possible. This strategy minimizes the need for equity investment and enables rapid access to asset bases without being constrained by their own financial limitations.

De-risking revenue: PPAs ​

Securing cash flows can be achieved through Power Purchase Agreements (PPAs). These long-term contracts (usually 10+ years) between developers and energy buyers ensure a fixed rate for the electricity generated. Buyers can range from corporations to governmental bodies, each with distinct risk profiles.

PPAs are key to most utility-scale solar projects since they represent a low-risk and predictable source of revenue, given that the buyer is chosen carefully. With a signed PPA, the guaranteed revenue typically unlocks other sources of funding.  

Construction and installation​

With permits and financing secured, the construction and installation phase of a solar project can commence.

This phase is where the physical solar panels and equipment are installed on-site and connected to the power grid. It includes several key steps that require careful planning and execution.

Bank loans/Debt financing​

Debt can finance 60-80% (sometimes more) of a project’s capital outlay. Lenders bear no upside but face full downside risk, making risk assessment crucial. Traditional debt forms, such as personal and company loans, rely on historical financial metrics like repayment history and cash flow available for debt service (CFADS).

For new developers with no cash flow history, leveraging large debt amounts can be challenging and sometimes not even a possibility.

If you’re not put off by the thought of taking on large amounts of debt to finance the construction of your first projects or to rapidly accelerate the number of projects, then let’s look at project financing.

Project financing​

Project finance is transformative for developers, enabling them to isolate risks, secure more borrowing, and accelerate development. Unlike corporate financing, project finance involves creating a Special Purpose Vehicle (SPV), where loan repayments come solely from the project’s cash flows, typically generated by selling solar energy.

This method confines revenue risks to off-taker or counterparty risks, avoiding complications from other corporate activities. It usually features a non-recourse structure, limiting collateral to SPV assets and protecting the corporate owner’s balance sheet.

Equity financing​

For capital-intensive projects, equity financing often fills the funding gap left after securing debt. Typically, if a project is 60-80% debt-financed, the remaining 20-40% is covered by equity or shareholder loans, which can be even more efficient.

This involves issuing project equity in exchange for funding. Unlike loans, equity financing doesn’t require repayment; instead, investors receive a share of the project’s profits, which allows project owners to maintain control while providing investors with potentially high returns, incentivizing them to undertake higher risks associated with early-stage renewable projects.

How to find the right investor for your solar projects​

Whether you’re a new or seasoned developer, you’ve probably already witnessed first-hand that there are many investors out there, many of whom are willing to invest in renewable energy projects.

Although finding investors for solar projects is easy, finding just the right one typically proves itself to be a whole different game, oftentimes taking multiple months, especially if you want to be sure that you also get the optimum price for you project.    

Having been in this business for nearly a decade, we know the struggle, but we also know the solution to it.

Read more about how we help developers find the right investor for utility-scale solar projects.

La entrada How To Finance Your Solar Project se publicó primero en We turn good projects into great deals - Green Dealflow.

In this article, we explore how to increase the likelihood of finding the right investor for your renewable energy project by teaming up with industry specialists.

The intricacies of finding the right investor​

Renewable energy projects, despite their environmental benefits, can be complex. They often require substantial upfront capital, expert knowledge, and long-term operational know-how. Traditionally, developers have relied on a one-size-fits-all approach, pitching their projects to a broad range of investors. This shotgun method often proves inefficient, leading to wasted time and missed opportunities. 

Matchmaking for efficiency and success ​

Effective matchmaking in the renewable energy sector involves a targeted approach. Here’s how it works: 

• Understanding Developer Needs:  A skilled matchmaker delves deep into the project specifics, including technology type, location, scale, and potential risks. They also assess the developer’s experience, track record, and financial capabilities. This comprehensive understanding allows for the creation of a detailed profile that highlights the project’s unique value proposition. 

• Identifying Ideal Investors:  Matchmakers leverage their extensive network of investors with diverse interests and risk appetites. They screen potential partners based on their investment criteria, industry expertise, and alignment with the project’s goals. This ensures a tailored approach, connecting developers with investors who understand the specific project landscape and are genuinely interested in backing the venture. 

• Facilitating Communication and Partnership:  Beyond simply introducing parties, matchmaking fosters open communication and collaboration. What developers get is that the matchmaker acts as a bridge, facilitating discussions, addressing concerns, and ensuring both sides fully understand the project’s potential and risks. This creates a foundation of trust, a crucial element for any successful long-term partnership. 

The power of the right partnership ​

While securing investments is crucial for renewable energy projects, it’s not just about knowing your numbers. Building strong relationships with investors plays a critical role in securing investments and fostering long-term project success. More and more studies support the claim that entrepreneurs with strong communication, persuasion, and relationship-building skills are more likely to attract venture capital funding, which is why developers should not downplay soft skills.  

Matchmaking is more than just intros​

Effective matchmaking goes beyond simply connecting developers with potential investors. It fosters the development of crucial soft skills by facilitating open communication and building trust between both parties. This personal connection allows for a deeper understanding of each other’s needs and goals. Developers can clearly state their project vision and potential, while investors gain confidence in the team’s capabilities and commitment. Ultimately, this strong foundation fosters a successful and collaborative partnership that benefits all parties involved. 

Avoiding mismatched partnerships: A recipe for disaster ​​

Imagine this scenario: a developer with a cutting-edge BESS project pitches their idea to an investor primarily focused on established onshore solar farms, so despite the project’s potential, a fundamental disconnect exists regarding risk tolerance and project timelines. This mismatch, if not identified early on through proper matchmaking, can lead to wasted time, frustration, and ultimately, project failure. 

Beyond capital: The value-added advantage ​

A well-matched investor brings more to the table than just capital. They can offer valuable industry expertise, strategic guidance, and access to their own networks. Having such a comprehensive support system can prove invaluable for navigating regulatory hurdles, getting permits, and can also help ensure project success throughout its lifecycle, and building strong relationships with investors can also lead to significant financial advantages. Investors who are confident in the developer’s team and vision are often more willing to offer favorable terms and higher valuations during funding rounds. 

Embrace the transaction advisor: A call to action for renewable energy developers ​

In today’s competitive landscape, renewable energy developers cannot afford to rely on a shotgun approach to securing funding. By partnering with a skilled transaction advisor, developers gain access to a targeted pool of investors, increase their chances of securing funding, and build strong, long-term partnerships that foster project success. 

By using a transaction advisor as a strategic tool, renewable energy developers can unlock the full potential of their projects, speed up the global transition to clean energy, and create a greener future for all, but promise us that once you have an investor on the hook, don’t fall into the many traps that could still sink your potential investment.

Now, if that doesn’t answer the question of why matchmaking is essential for renewable energy developers, we don’t know what else would. 

Intrigued? Learn more about how we can help you find the right investor for your projects.

La entrada How To Find The Right Investor se publicó primero en We turn good projects into great deals - Green Dealflow.

The trilemma: Decommission, extend, or repower?​

Decommissioning: A clean slate​

Decommissioning involves dismantling the site, removing turbines and infrastructure, and restoring the land to its original state. This option, while seemingly straightforward, carries significant costs and environmental considerations.

Recent forecasts from Zero Waste Scotland suggest that by 2050, decommissioning activities could generate up to 47,000 tonnes of blade material alone. This number alone underscores the importance of forward-thinking waste management strategies in the wind energy sector.

Wind farm life extension: maximizing existing assets​

Extending a wind farm’s operational life involves prolonging land rights and planning consents, often coupled with strategic upgrades to turbine components. This approach can offer a cost-effective means of maintaining energy production without the need for wholesale changes.

Repowering: Embracing technological advancements​

Repowering entails replacing existing turbines with newer, often larger, and more efficient models. This option capitalizes on technological advancements, potentially increasing energy output and overall farm efficiency. Industry organization Wind Europe has called for more repowering of wind farms, as it sees this as an opportunity yet to be fully exploited by the industry.  

Last year, and for the first time in Scotland, ScottishPower started the repowering process of the Hagshaw Hill wind farm in South Lanarkshire, which upon completion will have upgraded the 16MW wind farm to 79MW.

Legal considerations for wind farm life extension and repowering​

Land Rights: The foundation of extension​

Extending a wind farm’s lifespan often hinges on the provisions within the original project lease. Developers and asset owners may find themselves in one of three scenarios:

1. Exercising existing extension rights:
   Some leases contain clear provisions for extension, simplifying the process if terms are well-defined and workable.
2. Negotiating lease extensions:
   Where explicit provisions are absent, developers must enter negotiations with landowners. These discussions can be complex, reflecting the evolution of wind farm leases over the decades.
3. Crafting new agreements:
   In some cases, negotiating an entirely new lease or option agreement may be necessary, particularly when considering repowering projects that might require different terms.

Planning permissions: Navigating regulatory waters​

The path forward often depends on how the original planning permission was structured:
– If duration or turbine height restrictions are in the development description, a full planning application may be required.
– Restrictions within conditions may allow for a simpler variation process under Section 42 in Scotland or Section 73 in England and Wales.

For larger projects exceeding 50MW in Scotland, the Section 36 consent process through Scottish Ministers adds another layer of complexity.

Looking ahead, consent applications might be easier to obtain given that the current UK government is looking at reintroducing the two-tier system, removed in 2016, but with a threshold of 100MW. At present, all onshore wind projects in England are required to apply to the local authority for planning permission. If Labor successfully adopts its draft planning approach, projects above the 100MW threshold will be consented by Ministers through the NSIP regime (Nationally Significant Infrastructure Projects), whereas projects below will be handled by local authorities.

Technical and operational considerations​

Grid connections: Powering the future​

Repowering projects that increase capacity will necessitate new or upgraded grid connections. Given the current constraints on grid capacity, early engagement with network operators is crucial.

Even without capacity increases, changes to turbine equipment may require modifications to existing connection agreements.

Contract for Difference (CfD) support

Recent developments in the UK’s CfD scheme offer a glimmer of hope for repowering projects. The seventh allocation round, expected in 2025, may include eligibility for repowered onshore wind farms, subject to specific conditions such as maintaining or increasing capacity and aligning with CfD intervention principles. If this becomes the reality, repowering could get a well-deserved boost.   

Financial and market dynamics​

Power Purchase Agreements (PPAs)​

Existing PPAs may contain obligations that impact decommissioning or repowering plans. Developers must carefully review and potentially renegotiate these agreements to ensure compatibility with future project phases.

Economic viability​

The decision to extend, repower, or decommission ultimately hinges on economic factors. A 2021 analysis by Wikborg Rein highlighted that while repowering can offer significant benefits in terms of increased energy production and efficiency, it does often require a substantial capital investment. If it’s possible to do a partial repowering (not undertaking major infrastructure works) would likely offer the best return to developers. A full repowering would in many cases lower a return if infrastructural changes are required as opposed to merely replacing turbines.

Life extension, on the other hand, may provide a more cost-effective solution in the short term but could face diminishing returns as equipment ages, and

Environmental and community impact​

Whichever path developers choose, considerations extend beyond mere economics. Environmental impact assessments, community engagement, and local economic benefits all play crucial roles in shaping project outcomes.

The Wind Europe guidelines on decommissioning emphasize the importance of sustainable practices, including the recycling and repurposing of turbine components. As the industry moves forward, these considerations will likely become increasingly central to project planning and execution.

Charting the course ahead

As the UK’s wind energy sector stands at this juncture, developers face decisions that will shape the industry’s future. The choice between life extension, repowering, and decommissioning requires a nuanced understanding of legal, technical, and economic factors.

By carefully weighing these options and engaging proactively with stakeholders, developers can more easily navigate the landscape, ensuring the continued growth and sustainability of the UK’s renewable energy sector. 

La entrada Wind Farm Life Extension in the UK se publicó primero en We turn good projects into great deals - Green Dealflow.

In addition to developers actively seeking sites to deploy more PV, land owners are also proactively pushing for more deployment on their land in a move to generate supplementary incomes with lease prices for PV installations ranging between £3000-3500 Euros per hectare in Europe, which is a substantial increase compared to the average farm lease price of 357Euro per hectare. In most countries, this trend is amplified by an ever-increasing renewable energy investment market and favorable development conditions led by various government incentive plans, such as the EU Solar Strategy.

This article will cover the considerations when building a solar farm, from initial thoughts to the final financing.

What is a solar farm?​​

Photovoltaic power plants, also just commonly referred to as solar farms or solar parks, use large arrays of solar panels to capture sunlight and convert it into electricity. When people talk about solar farms, this type is usually what comes to mind.

These installations are mostly ground-mounted and located in areas with high solar radiation and can range from a few megawatts to hundreds of megawatts in capacity, even gigawatts, like the current largest solar farm in the world boasting a huge 5 GW of capacity.

Solar farms come in two different versions: utility-scale solar farms and community solar farms.
Let’s cover their differences. 

Utility-scale solar farms ​

This type of solar farm is normally a rather large farm compared to community solar farms, but there is no generic number that defines the scale of a utility-scale solar farm since the capacity of the individual farm depends upon the local market to which the solar farm will deliver its power. In some places, farms producing only 1 MW of power are counted as utility-scale, while in others, utility-scale solar farms must produce more than 25 MW.

 It is common for utility-scale solar farms to have long-term agreements in place – often 10-20 years – with an ‘off-taker’ such as a utility company, government entity, or private business to buy their energy in what is known as a Private Purchase Agreement (PPA). PPAs are contractual agreements between energy buyers and sellers. They come together and agree to buy and sell an amount of energy that is or will be generated by a renewable asset, this provides financial security for the developer while the off-taker knows how much energy to expect coming

Community-scale solar farms​

Community-scale solar farms are generally smaller and provide power used for commercial or community consumption in a local area. Often working on a subscription basis, residents or local inhabitants can subscribe to a local community solar farm, using it to typically enjoy reduced power bills as a result.

Future demand for solar​

In the EU, the total solar power capacity reached 259,99 GW, up from 204,09 GW the year before. The EU predicts that it can manage to reach a total solar capacity of 320 GW by 2025 and almost 600 GW by 2030, leaving plenty of space for more growth.

The really encouraging aspect of solar farm development is how accessible it is to private individuals when compared to fossil fuel energy production. Granted, establishing a solar farm is a cost-intensive investment, however, routes to third-party investment are becoming more accessible as we’ll explore later on in this article. Further to this, the cost of generating solar energy becomes cheaper with every passing year due to advances in technology and the widespread production of solar generation components. 

How do you make money from a solar farm?​

Traditionally, there are two main ways to make money from solar farms. These include leasing land to a renewable developer or, developing the land and operating the solar farm yourself.

Farmers across the EU are increasingly aware of the supplementary income that’s possible to generate from leasing their land to developers, with prices in some countries ranging between €3000-3500 per hectare. This annual rate is for most crops more profitable than what’s possible to generate from crops. However, this trend has caused some politicians to put the brakes on solar farm development on what’s being classified as prime agricultural land over fears that it might compromise local food supplies in the long run.

But given that it’s a possibility to lease and get approval to build a solar farm, the main benefit to leasing your land is that you just need to provide the land, and the project developer will do the rest.

On the other hand, if landowners have access to renewable energy project investment to develop the solar farm themselves, they stand to make money off the electricity that they generate and earn an average ROI of 10%-20% per annum. These numbers vary, in the US for instance, it’s possible to make $21,250- $42,500 per acre per year.

It’s important to consider where your solar farm will be as this will determine how much solar energy it will be able to generate.

Whichever model you choose, income will trickle down into your pockets by selling energy to off-takers that include utilities, government entities, or private businesses via a Private Purchase Agreement (PPA).

Solar farm development considerations​

If you choose to act as the project developer and build the solar farm, there are several common mistakes and considerations that you need to be aware of before committing. Below, we’ve compiled a list of these considerations.

Also read: Our grand guide to PV project development

Environmental permits​

The location of a proposed solar project will determine how difficult it will be to attain a valid environmental permit with different countries having different regulations in place.

It’s important for developers to determine – as early as possible – whether they will be required to obtain such permits. This information should be available on local authority websites.

Figuring out whether you’ll require a permit means conducting an environmental impact assessment (EIA) which will evaluate the effects of the project on the surrounding wildlife and habitats – in some cases, a wildlife and habitat protection plan may need to be developed.

Site selection​

Location can make a big difference, not just in terms of solar irradiance but also, in whether your solar project can go ahead. 

The first consideration is the amount of sunlight/direct light the area gets as this will massively impact the output of the panels. The land should be flat, and ideally south-facing. It should get at least 4 hours of peak sun per day.

You will need to check the local zoning laws and land-use regulations since these vary across the EU.

Grid access is an important factor, if not the most important factor. You’ll need to make sure that your land will have access to the grid and how long it will take for your project to get a grid connection, and lastly, make sure that the site isn’t located in an area that’s prone to flooding.

Financial planning​

Starting a solar farm requires capital. A lot. The starting phase of the project is always the most capital-intensive when the infrastructure is being built. The good news is that roughly 1/3 of the costs associated with a solar farm are directly related to the solar panels, and these are currently at an all-time low, falling 40% in the last twelve months alone.

The cost of a 1 MW solar power plant varies depending on a number of factors, including:

• The type of solar panels you choose
• The efficiency of the solar panels
• The cost of labor and materials in your area
• The amount of land you need
• The permitting process

In general, you can expect to pay between $0.89 and $1.01 per watt for a 1 MW solar power plant. This means that a 1 MW solar power plant could cost between $890,000 and $1.01 million.

Don’t have the money on hand? Few do. There are many funding options out there to assist, including financing part of the capital expenditure through raising debt and typically bringing on board investors to cover much of the remainder or the whole lot.

You may give equity in exchange for the money, or agree on repayment options with a financial institution and retain full ownership of the solar farm.

You can learn more about funding and how to source capital for a solar farm in our article on how to finance your solar project.

Government incentives​

Depending on where you are in the world, various governments have different incentives to promote the development of solar energy infrastructure. What you can access will depend on where you are and the current schemes, but common financial incentives include tax incentives, capital subsidies, subsidized loans, and generation-based incentives.

How much financing you need and what financing options are right for you will depend heavily on how big your solar farm will be, where it’s going to be built, who it will serve, and more. Think about whether you are creating a utility-scale farm, a solar farm for a specific nearby commercial off-taker, or a farm just to power nearby residential consumption. The size and type of off-taker will determine the revenue risk and hence the kind of financing options available.

If you are seriously considering starting a utility-scale solar farm and are looking for financing options or investors, then read more on how we can help you find the right investor.

Equipment and technology​

Understanding the equipment that you are purchasing and the pros and cons that come with each part is important. Additional research and speaking to an advisor before going ahead with anything is recommended, but here are a few basics that you may find useful. 

Permitting and compliance​

Although governments in the EU are currently adjusting local legislation to align with the European Solar Strategy, it is still necessary to research the regulations in your local area since regulations still vary country by country.

The approval procedure can be quite rigorous; planners prefer to grant permission on unused land that is poorly suited for farming. If the land is agricultural, permission is more likely to be granted if the land can be dually used (e.g. grazing, wildflower meadows, etc.). Planners will look at socio-economic and ecological factors and the environmental impact of decommissioning the farm. This makes leasing more attractive to some individuals because it requires less work for the landowner.

Operations and maintenance​

There are operational and maintenance costs to a solar farm, although these tend to be low because there are few moving parts unless you choose trackers for your panels.

Estimates vary, but the annual maintenance may cost around 2% of the system’s startup cost per annum for a small farm, and 1% for a large farm.

Panels need cleaning and damage inspection at least twice per year. You should establish a schedule for panel maintenance. Your installer should visit twice each year to check everything is working correctly.

Read about the most common problems with solar panels.

You will also need to develop systems for monitoring the production of energy and how it is being used. This will help you to ensure that everything is running as it should be.

You should put a contingency plan in place to help you deal with any equipment failures. 

Although solar technology is good, no technology is infallible, so issues will eventually come. Having a plan allows you to respond promptly, minimizing the farm’s downtime. 

Remember that PV panels have a life expectancy of around 25 years, while monocrystalline panels should last upwards of 30 years. In the long term, you will need to think about panel replacement costs.

Community engagement and outreach​

Solar farms aren’t always the most popular addition to an area; although many people recognize the need for more solar power, nobody wants these farms in their backyards!
That means it’s important to spend time engaging with the local community, building relationships with the local authorities and organizations, and encouraging the public to get on board with your plans.

You should also work to listen to and address any concerns that local people have and do what you can to minimize the damage and disruption done to the surrounding countryside.

If you need a bit of inspiration, then take a look at our case study on how the Danish developer Andel managed to overcome NIMBY and gain plenty of public and local support for its onshore renewable energy projects.

La entrada Considerations When Building A Solar Farm se publicó primero en We turn good projects into great deals - Green Dealflow.

Inadequate Preliminary Assessments: A Costly Oversight​

One of the top mistakes PV developers make is failing to conduct a thorough preliminary project assessment, which covers both site assessment and feasibility studies. This critical step ensures that the chosen location is suitable for Solar PV installations and can significantly impact project timelines and costs. 

• Tip: Perform a comprehensive site evaluation and feasibility study, considering factors like soil quality, shading, and proximity to transmission lines. We cover these things in a more in-depth way in our guide on solar project development. 

Poor Financial Planning: The Road to Delays and Overruns​

Underestimating the financial needs of a Solar PV project is a common yet critical mistake. This can result in delays or, worse, project failure. Maybe not surprisingly, this step ties into the preliminary assessment, which includes evaluating the costs and benefits of the project to determine if the project will be financially viable in the end.  

• Tip: Develop a robust financial plan that includes all potential costs, including contingencies for unexpected expenses. 

Inadequate Permitting: The Silent Saboteur​

Permitting is a critical and often overlooked challenge in Solar PV development, and is another typical PV mistake developers make. Failing to secure the necessary permits can lead to costly delays and jeopardize your project’s success. The permitting process isn’t just about meeting basic requirements—it can involve stringent and expensive demands. Environmental permits, for example, may require mitigation measures like reforestation or stormwater management, while some projects might face additional costs for infrastructure upgrades, such as widening roads or installing stoplights.

The specific permits required depend on factors like location, size, and the nature of the project. Ground-mounted installations often attract extra scrutiny, especially when involving sensitive environmental areas or historical sites. 

• Tip: To navigate this complex process, integrate permitting considerations into your overall project management plan. This should include clear timelines, resource allocation, and regular progress reviews to ensure that all permitting requirements are met without derailing your project.

Neglecting The Local Community: Communication and Community is Key​

Failing to engage stakeholders early in the project is another common mistake that can lead to delays and budget overruns. Sometimes even complete discarding of the project. 

We have previously written an extensive piece on how a Danish developer and IPP overcame NIMBY, but since not all developers have the budget to launch nationwide campaigns to generate positive connotations to solar farms and get people to adjust their attitude, there are other ways of making sure NIMBY will not become a problem to limit the risk of local opposition, as is the case in Japan where roughly 80% of all large-scale projects are hit by some form of opposition from local residents. 

For utility-scale projects, but also even smaller ones, ensuring that communities are informed in advance through public consultations is oftentimes the key to getting any potential issues addressed before moving on. An example from the offshore industry, which isn’t that common, is RWE hosting local town halls ahead of its Thor project, resulting in minimal opposition. 

• Tip: Establish clear communication channels and identity and engage all stakeholders from the beginning of the project to limit the risk of anyone objecting against your project and putting a spanner in the works.

Lack of a Decommissioning Plan: The Long-Term Oversight​

One of the top mistakes PV developers make is overlooking the importance of a decommissioning plan. While the focus is often on the construction and operation phases, planning for the end of a Solar PV project’s life cycle is equally critical. Failing to develop a clear decommissioning strategy can lead to unexpected costs, legal complications, and environmental impacts when the time comes to retire the facility.

A well-crafted decommissioning plan outlines how the site will be restored to its original condition—or an agreed-upon state—once the solar panels are no longer in use. This includes the safe disposal or recycling of solar panels, the removal of electrical components, and the restoration of the land. Without such a plan, developers risk facing significant financial liabilities and regulatory challenges.

Moreover, decommissioning isn’t just about compliance; it’s also about sustainability. Ensuring that your solar farm can be dismantled responsibly aligns with broader environmental goals and can even improve community relations.

Tip: Begin developing your decommissioning plan during the initial project planning phase. This proactive approach can help you avoid future complications and ensure a smooth transition at the end of the project’s life.

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