Electricity and Biomethane

Following the market normalisation observed in 2025, 2026 will mark a significant stress test for EU power markets, particularly in Italy. Rising electricity demand – driven by continued electrification and the rapid expansion of AI-driven data centres – will increasingly strain ageing grid infrastructure, prompting accelerated investment in grid digitalisation, utility-scale storage and more flexible market designs; corporate Power Purchase Agreements (PPAs) are expected increasingly to adopt hybrid “renewables-plus-storage” structures to stabilise revenues. Grid congestion, rather than resource scarcity, is set to emerge as the primary constraint, mitigated only partially by new storage capacity and reinforced cross-border interconnections. In parallel, EU 2030 climate and energy targets, together with Italy’s National Recovery and Resilience Plan (PNRR) measures, should support the ramping-up of biomethane capacity and the development of standardised GO Energy-backed offtakes schemes; hydrogen policy is expected to shift from strategic planning to early-stage implementation. Nuclear energy is taking initial steps toward a potential re-entry as a reliable alternative power source, while oil and gas remain pivotal for security of supply and price formation, albeit under tighter regulatory scrutiny and within a gradual shift toward lower-carbon molecules and the provision of flexibility services.

Electricity market

Italian electricity demand for 2025 was reported to be approximately 354 Terawatt-Hour (TWh), a slight increase compared to 2024. This trend is likely to continue also in 2026, although being affected by weather conditions and by the cyclical nature of industrial sectors.

Wholesale prices, instead, have declined. After peaking in the early months of the year, there has been a progressive normalisation in line with the end of the heating season and the fall in gas prices. In particular, the average Italian Prezzo Unico Nazionale (PUN) Index Gestore dei Mercati Energetici (GME) stood at around EUR120.5/MWh in March 2025 (-19.9% month on month), compared with an average Title Transfer Facility (TTF) of around EUR41.6/MWh and a virtual trading point (punto di scambio virtuale, PSV) of around EUR42.8/MWh. Then, in June, the average PUN was close to EUR111.8/MWh. The correlation between electricity prices and gas benchmarks therefore remains the main short-term determinant.

At European level, April 2025 saw a significant reduction in electricity prices compared to the peaks in February, due both to the cooling of gas quotations and to the increase in renewable production, particularly photovoltaics (PVs).

The Italian generation-mix market shows that photovoltaics remains the leading renewable source by energy produced in 2025, while hydroelectric output slightly declined, being penalised by below-average water availability. In the first ten months of the year, renewable sources met approximately 42% of Italian demand, with a monthly share close to 39% in October. At the same time, in terms of installed capacity, approximately 4.8 gigawatts (GW) of new photovoltaic power was connected between January and October (-12% year on year), with a significant resumption in utility-scale plants over autumn.

The volatility of electricity prices remains high, linked directly to gas dynamics and to the intermittency of Renewable Energy Systems (RES) generation. This creates a growing need for flexibility resources. In this context, investment in the high-voltage transmission grid and in major interconnection projects – including the Tyrrhenian Link – continues to intensify, to ensure renewable integration and maintain system security.

It should also be noted that Italy awarded approximately ten Gigawatt-hours (GWh) in the first tender dedicated to electrochemical storage systems, providing for regulated revenues over a 15-year horizon and foreshadowing further procedures, including hydroelectric solutions.

In light of the foregoing, several guidelines emerge for operators in the electricity sector:

• renewed interest in long-term power purchase agreements (PPAs) and multi-year hedging strategies;
• strengthening of the bankability of both standalone and co-located Battery Energy Storage Systems (BESS) projects;
• persistence of critical issues concerning grid connection and congestion, against the backdrop of Ten-Year Network Development Plan (TYNDP) planning aimed at reducing curtailment risks; and, finally;
• expansion of demand-response programmes and indexed contracts with price-risk sharing clauses for energy-intensive industrial customers.

Biomethane market

Biomethane, subject to traceability and guarantees-of-origin schemes, is categorised among advanced fuels and plays a strategic role under the Renewable Energy Directive (RED) III Directive, particularly for transport and other high-emission-intensity sectors.

In Europe, 1,678 production plants were operational in the first quarter of 2025, consistent with the Repowering Europe (REPowerEU) target of achieving annual production of 35 billion cubic metres by 2030 and with initiatives promoted under the Biomethane Industrial Partnership.

In Italy, on 17 April 2025, Gestore dei Servizi Energetici S.p.A. (GSE) published the ranking for the fifth competitive procedure under the Ministerial Decree of 15 September 2022, admitting 298 projects – new constructions and conversions – for total capacity of approximately 122,842 standard cubic metres per hour (Smc/h) and cumulative incentivised capacity close to 240,000 Smc/h. However, coverage of the non-repayable grant and tight implementation schedule raise concerns, since the PNRR requires activities to be completed by 30 June 2026.

Considering the allocations made and project progress, the potential capacity is estimated to exceed 320,000 Smc/h, confirming the attractiveness of the asset class, also due to the incentive framework and consolidation dynamics in the secondary market. The Integrated National Energy and Climate Plan confirms the target of 5.7 billion cubic metres/year of biomethane by 2030: this requires a significant acceleration of authorisation procedures, stabilisation of support instruments capital expenditures/operating expenses (CAPEX/OPEX), definition of multi-year off-take contracts, and further development of GO markets.

This trajectory was marked by the broader gas and hydrogen package, introduced by Directive (EU) 2024/1788 and Regulation (EU) 2024/1789 (the EU Gas and Hydrogen Package), governing third-party access, ownership unbundling, integrated planning, and certification schemes for renewable and low-carbon gases, with the aim of facilitating biomethane’s integration into existing infrastructure and into future markets.

Measures to incentivise and accelerate the energy transition

European Union

At EU level, the 2024 electricity market reform strengthened long-term investment support through two-way Contracts for Difference (CfDs), capacity mechanisms, PPA promotion, and new flexibility targets. The objective is to reduce price volatility and promote revenue stability for operators.

Directive (EU) 2023/2413 (RED III) simplified and accelerated authorisations for renewable plants, introducing acceleration areas and binding maximum procedural timelines for Member States. In parallel, the European Network Action Plan (COM(2023) 757) and designation of Projects of Common Interest (PCIs) promoted expansion and digitalisation of electricity and gas infrastructure, with preferential authorisation lanes and direct financial contributions.

The REPowerEU programme and the Biomethane Industrial Partnership have also targeted 35 billion cubic metres/year of biomethane by 2030, while the Gas and Hydrogen Package aims to promote network access, unbundling, and certification for renewable gases, creating an integrated, transparent market.

On the financial side, the Clean Industrial Deal State Aid Framework (CISAF) – which replaced the Temporary Crisis and Transition Framework – has allowed Member States to grant aid for decarbonisation, storage, renewables, and biomethane projects with high aid intensities and multi-year durations, co-ordinated with the Innovation Fund, CEF Energy, and InvestEU.

Italy

At national level, simplification and regulatory certainty for renewable investments have been accelerated with the Legislative Decree 178/2025 (the Corrective Decree) amending Legislative Decree 190/2024, also known as the Consolidated Renewables Act (TUFER). In particular, the Corrective Decree has clarified some legal definitions and introduced new ones (eg, agrivoltaics and hybrid plants with storage/electrolysers), while it has streamlined authorisation procedures, especially for interventions without land consumption and with reduced environmental/landscape impact. In addition, it has enacted new provisions to strengthen alternative dispute-resolution tools in administrative matters, to simplify repowering of existing plants, to enhance a digital platform for co-ordinating procedures, and to establish a focal point for local interventions. The three-track system has also been confirmed (including free building, a simplified authorisation procedure, and a single authorisation regime), where free-building cases have been expanded (eg, replacement/reconstruction of existing PV systems without volumetric increase; certain floating installations <10 MW on artificial reservoirs of no particular value within occupancy thresholds; integration of storage systems). These changes will reduce administrative burdens and litigation risk, consistent with TUFER’s acceleration purpose.

The Suitable Areas Decree (Ministerial Decree 21 June 2024) will continue to define uniform criteria for identifying areas suitable for RES plants but is now improved, stabilising interpretation and reducing procedural timing, in co-ordination with regional planning and environmental protection instruments. In parallel, the FER2 Decree (Decree 19 June 2024) has introduced incentives for innovative or high-cost technologies (including offshore wind, solar thermal, and geothermal) through competitive auctions and administered tariffs, promoting efficient allocation of public resources and the bankability of frontier projects.

An organised PPA market is being implemented under GME management, with the GSE as guarantor of last resort, to improve bankability of long-term contracts. In addition, flexibility mechanisms include the Capacity Market and the new Storage Capacity Mechanism (MACSE), which has already allocated ten GWh of storage with regulated revenues over 15 years, enabling participation of standalone and hybrid BESS and helping manage intraday volatility.

The Ministerial Decree of 15 September 2022 (PNRR – M2C2, Investment 1.4) remains crucial for biomethane production development, by combining capital grants and incentive tariffs on energy injected into the grid via competitive procedures managed by the GSE. This framework has enabled a national project pipeline which is still at an advanced development stage. In this context, Article 5-bis of Decree Law 64/2024, converted into Law 101/2024, and the GSE Application Rules of 16 May 2025 now regulate Biomethane Purchase Agreements (BPAs), under which the concept of biomethane self-consumption is no longer restricted to production sites, but also granted to “hard-to-abate” end customers entering into a BPA with an off-site biomethane producer. This regime completes the regulatory mosaic and standardises the contractual instrument, increasingly relevant for decarbonisation of Emissions Trading System (ETS) sectors and compliance.

Activities to transpose and apply the EU Gas and Hydrogen Package are underway and partly advanced; these will provide greater certainty on network access, unbundling, integrated planning, and certification for renewable and low-carbon gases, promoting biomethane’s integration into existing gas infrastructure and full traceability through harmonised guarantees of origin. At the same time, the agrisolar and agrivoltaic tenders continue to combine CAPEX grants and premium tariffs, supporting both the energy and agricultural transitions.

As a result, the Italian system rests on a mixed model of direct incentives (CAPEX) and remuneration of produced energy (OPEX), in line with European recommendations and the Integrated National Plan for Energy and Climate (PNIEC) 2030 objectives. The electricity market thus trends towards a new scenario, where gas remains the benchmark price-setter, but greater RES penetration, regulated storage, and procedural simplification reduce volatility. In addition, the combination of incentive schemes, BPAs and TUFER simplifications will support the industrial scale-up of biomethane projects, providing financial aid, regulatory certainty and administrative tools in support of the supply chain.

Outlook for 2026

Barring exogenous geopolitical events, market normalisation should continue through 2026. In electricity, increased renewable capacity should reduce network stress and intraday volatility. Demand, driven by electrification of end consumption, is expected to grow moderately, supporting additional stable PPAs and demand-response schemes.

The biomethane market in 2026 will be marked by the entry into operation of the PNRR pipeline and by the first long-term contracts based on guarantees of origin, with growing involvement of utilities and large consumers. However, critical issues related to feedstock supply and authorisation timelines should persist, making it essential to define a post-2026 framework that is more stable and consistent with the integration objectives between biomethane and hydrogen, as outlined by the RED III targets.

Oil and Gas

According to recent studies, more than 80% of global energy demand is still met by fossil fuels, much as it was 25 years ago. In a recent monthly report, the International Energy Agency confirmed a demand increase of 740,000 barrels per day (b/d), for a total exceeding 100 million b/d.

The same Agency, traditionally cautious about stressing the need for new fossil fuel investment, estimates oil demand in 2050 at over four billion tons of oil equivalent (toe), ie, comparable to the demand levels in 2004. Similarly, by that date, gas and oil would represent around 45% of global energy demand, with coal still at approximately 12% and renewables around 38%.

In Italy, despite the continued strength of legitimate “green” ambitions, the last two years saw renewed interest in traditional fuels.

This has reinforced calls to reform the fuel distribution sector, characterised by excessive fragmentation of supply (twice as many petrol stations as the European average). After a sudden acceleration in summer/autumn 2024, the issue receded during 2025 on the government’s priority agenda.

This occurred even though sector operators broadly acknowledge the need to modernise a system constrained by rigidities introduced by regulations now more than 20 years old – obsolete and out of step with current dynamics. Views diverge on corrective measures, in the usual debate between protecting purported vulnerable categories and allowing greater contractual freedom without peremptory, mandatory schemes.

In addition, 2026 will likely bring to the surface issues that can no longer be postponed, notably, identifying solutions and economic support to enable conversion of refineries – wholly or partly – into biorefineries, given the growing role of biofuels in meeting decarbonisation targets.

Biofuels

The global role of biofuels appears to be expanding, increasing by about 3% per year and now exceeding 170 million toes of production. Europe, however, is ceding leadership to other countries, such as the United States, which currently produces around 40% of global biofuels.

Despite a general European slowdown, Italy remains among the leading producers, with an estimated contribution of roughly 47% of biofuels in Europe.

This position reflects a consistent regulatory and strategic commitment; Italy maintains tax incentives for advanced biofuels (derived from waste, agricultural residues, algae), is strengthening associated infrastructure, and as previously noted, has long studied options to convert refineries into biorefineries.

At the political level, Italian institutional stakeholders frequently urge the European Commission to recognise the role of biofuels in road transport. This argument has gained traction following a recent Council of Environment Ministers’ resolution identifying biofuels generated from renewable sources, and defined as “zero and low carbon,” as vectors capable of making a tangible contribution to decarbonising road transport.

A timely opportunity may arise with the revision of Regulations EU/2023/851 and EU/2024/1610 on CO₂ emission targets for private cars and light commercial vehicles, brought forward from their initial timetable. The desired outcome is to align legislation with the accounting logic used in major European instruments, such as the RED III Directive, the environmental, social and governance (ESG) Package, and the Emissions Trading System (ETS2) Regulation. These frameworks assess emissions using metrics more relevant to decarbonisation goals, such as Well-to-Wheel and Life-Cycle-Assessment, which consider the generation mix behind energy carriers, instead of the Tank-to-Wheel method used by current rules.

Carbon Capture Utilisation and Storage (CCUS)

CO₂ capture utilisation and storage – both in energy and industrial sectors – have been recognised in Italy since 2019 as means to achieve complete decarbonisation by 2050 and fall within the scope of the Integrated National Energy and Climate Plan (PNIEC), adopted under EU Regulation No 2018/1999.

This lever was confirmed by the National Long-Term Strategy, which identifies pathways toward climate neutrality by 2050, with CCUS among four key levers. The PNIEC 2024 further confirms and implements CCUS to deliver decarbonisation targets, already by 2030.

Against this backdrop, the technical ground required to develop a regulatory framework enabling CCUS deployment in Italy in upcoming years is still being defined. To date, the legal framework has focused mainly on geological CO₂ storage, while capture, transport, and potential utilisation remain insufficiently regulated.

An enabling law is therefore expected to identify outstanding issues and provide guidance principles for governance, unbundling and third-party access, tariffs and remuneration models, and financing resources. Meanwhile, legislation on geological storage must be completed, since measures adopted in 2023 created transitional regimes pending definitive provisions.

Hydrogen

In the context of the European Green Deal and the “Fit for 55” package, hydrogen has been positioned as a key strategic enabler of decarbonisation and security of supply. The Commission’s Hydrogen Strategy highlights hydrogen’s role in long-duration storage, seasonal balancing, and sector coupling, while offering a route to abate emissions in hard-to-decarbonise industries and in specific transport segments.

EU

At EU level, the Renewable Energy Directive as amended in 2023 (RED III) strengthens the role of Renewable Fuels of Non-Biological Origin (RFNBOs), with binding economy-wide and sectoral targets that create demand for renewable hydrogen. Delegated acts define criteria for additionality, temporal and geographic correlation, and the methodology for calculating greenhouse-gas savings, thereby underpinning certification and guarantees of origin.

The EU Gas and Hydrogen Package established the legal architecture for hydrogen networks, including:

• regulated or negotiated third-party access to pipelines, storage, and terminals;
• unbundling requirements for network operators; and
• integrated network planning through the European Network of Network Operators for Hydrogen (ENNOH), tasked with preparing a non-binding Hydrogen TYNDP.

The framework introduces Union-wide traceability and certification for low-carbon hydrogen and allows limited blending in gas grids, while preserving Member State discretion over implementation modalities.

Strategic direction is complemented by REPowerEU, which raises production and import ambitions for renewable hydrogen, and by State-aid instruments (transitioning from the Temporary Crisis and Transition Framework (TCTF) to the CISAF) to enable CAPEX and, where justified, OPEX support, in parallel with Important Project of Common European Interest (IPCEI) waves, the Innovation Fund, CEF Energy, and InvestEU.

Italy

Italy treats hydrogen as a priority tool within its decarbonisation policy mix. The national Hydrogen Strategy (2020; updated in 2024) and the revised PNIEC and National Energy and Climate Plans (NECP) (2024) outline both demand-creation and supply-side measures, including an indicative electrolyser-capacity target for 2030, support for RFNBO uptake in industry and transport, and the promotion of Hydrogen Valleys. The PNRR/NRRP earmarks roughly EUR3 billion for pilot ecosystems, industrial uses, mobility, and research and development (R&D). In the longer term, policy documents envisage Italy leveraging its location and existing gas backbone – subject to partial repurposing – to act as an import hub (eg, the SoutH2 Corridor) connecting with North Africa.

On the administrative front, TUFER – as streamlined by a subsequent Corrective Decree – has rationalised hydrogen-related procedures in line with EU fast-track principles. The regime is articulated along three tracks:

• a no-permit/free-authorisation regime for certain minor-scale interventions (including electrolysers up to 10 MW and limited modifications of existing units), subject to technical and siting conditions;
• a simplified authorisation procedure (PAS) for interventions listed in Annex B (eg, electrolysers >10 MW), with compressed statutory deadlines; and
• a Single Authorisation for complex projects (eg, standalone electrolysers coupled to generation plants under Autorizzazione Unica (AU)), with expedited processing and co-ordinated environmental assessments. These measures dovetail with national simplifications on repowering, storage integration, and spatial planning (areas suitable for renewables), reducing procedural risk and facilitating bankability.

Assuming timely secondary legislation and sustained funding, 2026 could mark a transition from pilots to early scale-up: initial Hydrogen Valleys entering operation; first network-planning outputs under ENNOH informing domestic investment; greater legal certainty on certification and market access under the EU Package; and incremental alignment of support schemes, combining CAPEX grants with targeted OPEX instruments for priority uses in hard-to-abate industry and heavy transport. Key constraints are expected to remain, including the relative cost of renewable hydrogen compared with fossil, infrastructure readiness, and demand aggregation.

Nuclear

European Union

As part of EU climate policy, Regulation (EU) 2020/852 (the EU Taxonomy Regulation) established criteria to determine whether an economic activity is environmentally sustainable, delegating to the Commission the adoption of delegated acts specifying detailed technical screening criteria. Delegated Regulation 2022/1214 subsequently included certain nuclear energy activities in the EU green taxonomy, classifying them as taxonomy-aligned environmentally sustainable under specific conditions.

Nuclear energy – considered by the EU as a low-carbon source capable of reducing CO₂ emissions – can therefore contribute to the environmental sustainability objectives incorporated into the Italian Constitution after the 2022 constitutional reform. The EU’s green taxonomy has provided an additional policy and regulatory impetus to reconsider Italy’s stance following the 2011 referendum that halted domestic nuclear development.

Italy

A law is currently under consideration before Parliament delegating to the Government the authority for the adoption, within twelve months, one or more legislative decrees concerning:

• the production of energy from nuclear sources;
• the decommissioning and dismantling of existing plants;
• the management of radioactive waste and spent fuel;
• the research, development, and use of fusion energy; and
• the reorganisation of competencies and functions in the field, including the reordering and amending of existing legislation.

Conclusions

The current policy-making approach places the transition at the core of Italian government action, with a focus on strengthening infrastructure for domestically sourced clean energy. The ongoing policy decisions highlight priority for the development of wind and photovoltaic plants, acceleration in authorisation and market design (organised PPAs, capacity, and storage), while market flexibility is being consolidated through mechanisms dedicated to electrochemical storage. At the same time, the regulatory and financial framework supporting renewable fuels has been reinforced, with a specific focus on biomethane across the entire supply chain (feedstock–plant–off-take), including standardised Comprehensive Biofuel Policy Analysis (CBPA) schemes and traceable Guarantees of Origin.

National government has also reopened the nuclear policy debate (with a delegated law in progress) and increased attention to establishing CCUS hubs supporting hard-to-abate industrial decarbonisation, in line with national and EU climate planning. Completion of the EU Gas and Hydrogen Package’s implementation should provide legal certainty on network access, unbundling, integrated planning, and certification, and support the launch of an initial hydrogen network and development of the Hydrogen Valleys.

Conversely, the oil and gas framework remains uncertain, marked by distribution-sector reform needs, licensing updates, and greater social and regulatory scrutiny. The 2026–2030 trajectory will require: stability and predictability of CAPEX/OPEX incentives; further procedural simplification with full operation of suitable areas and a single point of contact; strengthening of the grid and interconnections, including selective investments in resilience and digitalisation; expansion of forward markets and hedging tools to improve bankability; and rapid implementation of the PNRR pipeline on biomethane, storage, and hydrogen.

If these conditions are met with consistent implementation and regulatory continuity, the goal of a national power system with high RES penetration and flexibility could yield measurable medium-term results, while the renewable-gas ecosystem (mainly biomethane and renewable hydrogen) could scale up industrially to contribute credibly to 2030 targets and the climate-neutrality action plan. In short, there is much to monitor: the interplay of market regulatory reforms, authorisation speedways, investment instruments, and new technological value chains will determine the feasibility of a safer infrastructural environment and a more competitive national energy market.