General Overview: Ambitious Targets, Realisation to Follow

Croatia enters 2026 and looks towards 2027 with a policy framework that is broadly aligned with the EU’s decarbonisation agenda, but still needs to translate this framework into concrete project implementation in order to reach the targets set. The updated Integrated National Energy and Climate Plan (NECP), finalised in 2025, sets a binding contribution of at least 42.5% renewables in gross final energy consumption by 2030, and envisages an even higher share of renewables in electricity consumption. In parallel, Croatia has committed to deep reductions in greenhouse gas emissions in both ETS and non-ETS sectors, effectively locking in a long-term transition towards a low-carbon electricity system.

In practice, the current generation mix remains anchored in large hydropower plants, with wind and solar accounting for a growing share of annual generation, supported by gas-fired plants and cross-border exchanges that provide flexibility and security of supply. In 2024, domestic power plants supplied 73.3% of total electricity consumption, while renewable energy sources accounted for approximately 54% of consumption. Installed wind and solar capacity is now broadly comparable to hydropower capacity, at around 2.2 GW against some 2.19 GW of hydropower. Despite comparable installed capacity, hydropower still produces significantly more electricity over the year than wind and solar combined, due to higher capacity factors and favourable hydrological conditions. This combination of high renewable penetration and conventional back-up shapes the context in which new projects must be structured.

Regulatory and Market Framework

Croatia’s electricity market is fully liberalised and largely aligned with EU internal energy market rules. The core legal framework consists of the Energy Act, the Electricity Market Act and the Act on Renewable Energy Sources and High Efficiency Cogeneration (RES Act), complemented by numerous secondary acts adopted by the regulator HERA, the transmission system operator (HOPS), the distribution system operator (HEP ODS) and the market operator (HROTE). HERA issues licences, adopts tariff methodologies and approves grid and market rules, while HROTE acts as the market operator in a public-service capacity, administering the support scheme for renewables and high-efficiency cogeneration, managing Guarantees of Origin and carrying out imbalance settlement. The organised wholesale spot market (day-ahead and intraday) is operated separately by CROPEX in its capacity as Croatia’s nominated electricity market operator.

On the wholesale side, the Croatian Power Exchange (CROPEX) acts as the country’s nominated electricity market operator (NEMO), operating day-ahead and intraday markets which are fully integrated into the EU Single Day-Ahead Coupling (SDAC) and Single Intraday Coupling (SIDC) mechanisms. The exchange offers 15-minute products and continuous intraday trading, while financial derivatives listed on EEX provide hedging opportunities for Croatian price exposure. The retail market is formally open, with several dozen licensed suppliers and traders, while the HEP Group still holds a substantial share of final sales.

Support Schemes: From Feed-In Tariffs to Auctions

The Croatian support framework for renewable electricity has undergone a gradual shift from administratively set feed-in tariffs and guaranteed purchase prices towards auction-based mechanisms. The original feed-in system, in place from around 2007, was phased out and replaced by a scheme based on market premiums and guaranteed prices for smaller plants, implemented under the RES Act and related government decrees. The current regime is underpinned by the secondary acts which determine the total capacity to be supported (2.265 GW) and its allocation among different technologies.

HROTE is responsible for conducting competitive tenders for the award of market premiums and guaranteed purchase prices. These programmes are financed mostly through a combination of levies on final customers and revenues from the sale of electricity produced by supported plants. A state aid programme adopted in April 2024 provided EUR286.8 million for a total quota of 658.25 MW across three measures and focuses primarily on new wind and solar capacity. On this basis HROTE launched a public tender in April 2024 covering the two market-premium measures, for a combined 607.25 MW and EUR257.2 million. The market-premium tender resulted in 86 support agreements for approximately 404 MW (84 solar projects of around 400 MW and 2 hydro projects of around 4 MW). Market response in the first auction rounds was strong, with more than 140 project applications submitted. This was particularly evident in the segment of larger solar power plants, where the combined connection capacity of the received bids reached more than 577 MW, significantly exceeding the scheme’s quota of 350 MW.

By the end of 2024 more than 1,200 plants were registered within the support scheme, predominantly small solar PV installations, with a more limited number of wind, biomass and biogas projects. Although this portfolio confirms that the support framework is operational, the level of ambition set in the NECP means that most of the additional renewable capacity will have to be delivered by projects that are not yet operating and, in many cases, not even fully permitted.

Grid Connection and Network Constraints

The single most significant bottleneck for new renewable projects has been the grid connection regime. A new methodology introducing a “shallow” cost approach – under which project developers pay standardised connection charges while broader network reinforcement is socialised – was adopted in 2022. Its practical implementation has been enabled by HERA’s decision on the unit connection fee, adopted in April 2026 and effective as of 1 May 2026. HERA’s decision sets unit charges differentiated by voltage level and investors should note that the model is genuinely “shallow” only at low and medium voltage; at high and very-high voltage the charge also incorporates actual, study-based connection costs, so transmission-level projects still require a case-specific cost assessment rather than a purely standardised fee. However, even with this key parameter now in place, developers still face delays and uncertainty in obtaining binding connection cost offers and final grid connection approvals, and a substantial part of the project pipeline remains effectively stalled despite having secured quotas or other regulatory clearances.

At the same time, HOPS faces increasing challenges in integrating variable renewables into a transmission network that, in certain corridors, is approaching its technical limits. The operator has adopted new rules that allow for temporary limitations on the offtake of renewable generation in order to preserve system security, which has raised concerns among investors and lenders about long-term curtailment risk. The situation is further complicated by the fact that requests for detailed grid data for the preparation of the transmission connection study (EOTRP) are subject to HOPS grid-study procedures, which developers report can add to the timing and administrative burden of preparing a transmission connection.

Balancing, Aggregation and Storage

Croatia has aligned its balancing arrangements with EU Electricity Balancing Guideline requirements. HOPS procures balancing services in a transparent and non-discriminatory manner, including aFRR and mFRR through public tenders, and the number of balancing service providers has increased over recent years. The legal framework recognises the roles of aggregators and, at least at a conceptual level, energy storage facilities as new sources of system flexibility, although large-scale battery storage projects are still at an early stage of development.

Under the Croatian regulatory framework, connection charges are cost-reflective and, as a matter of principle, energy that is stored and consumed within a consumer’s own premises should not attract double network charges. Beyond that principle, the detailed treatment of storage is still developing: the precise connection and network-charge position of a standalone battery on the grid, and the extent to which a battery co-located within a generation plant is treated as part of that installation rather than as a separately authorised facility, are not yet exhaustively settled in published methodology and should be confirmed with the relevant operator on a project-specific basis. In practice, therefore, the sizing of import/export capacity and the choice between standalone and co-located configurations, and between transmission and distribution connections, remain critical commercial parameters for investors.

On the market side, CROPEX’s 15-minute products, intraday auctions and continuous trading provide tools for short-term portfolio optimisation and risk management. However, the effective use of these products requires sophisticated forecasting and trading capabilities, which many smaller renewable developers and investors are only now starting to build. As variable renewables expand, the ability to combine physical trading, balancing market participation and potential storage solutions will become a key differentiator among market participants.

The takeaway for investors is that in the absence of a dedicated feed-in or premium scheme for storage, the emerging business model for battery projects in Croatia is expected to rely on a combination of revenues from balancing services (such as aFRR and mFRR procured by HOPS), price arbitrage on day ahead and intraday markets, and, in some cases, contracts for grid-related services supported by EU funds. This is probably best illustrated by the first 60 MW grid-level battery project in Šibenik. In this environment, regulatory clarity on how storage is classified and how grid fees and taxes apply will be crucial in determining bankability.

NECP 2.0 and Policy Direction

The updated NECP raises Croatia’s 2030 renewable energy and energy-efficiency targets, in line with the EU’s reinforced climate ambitions and the revision of the Renewable Energy Directive (RED III). The plan foresees a steep increase in renewable shares, reductions in primary energy consumption and stronger focus on security of supply, while also emphasising energy efficiency and electrification of end uses. In the electricity sector, this translates into the expectation that a significant majority of consumption will be covered by renewable generation by 2030, backed by modernised networks and more flexible system operation.

For investors, this signals that the strategic direction is clear and unlikely to reverse: renewables remain at the centre of Croatian energy policy, and the role of fossil-fuelled generation is expected to gradually decline, even though gas will continue to provide flexibility in the medium term. The key question is whether permitting procedures, grid connection rules and network investments can be adjusted quickly enough to enable the volume of projects needed to meet NECP targets.

Project and Investor Trends

Solar PV is emerging as the leading technology in the pipeline of new capacity, particularly through medium-size and large-scale solar parks and prosumer installations, while onshore wind continues to expand, although with growing emphasis on repowering and efficiency optimisation of existing sites. Geothermal and biomass projects remain niche contributors, and there is currently no mature business case for offshore wind projects.

Contractually, the market shows a rising interest in power purchase agreements (PPAs), especially corporate PPAs for industrial and commercial consumers seeking long-term price certainty and decarbonisation credentials, as illustrated by recent ten-year agreements such as Axpo’s cPPA with HVAC manufacturer Klimaoprema and Hrvatski Telekom’s virtual wind PPA with Liburana, as well as INA’s combined supply-and-buyback arrangement, marketed as a PPA, with E.ON. Nevertheless, public support schemes and CROPEX markets still play a central role in monetising renewable generation, so most projects rely on a combination of auction-based premiums, merchant exposure and, in some cases, PPAs to build a bankable revenue stack.

Lenders and investors are increasingly focused on four categories of risk:

• connection and curtailment risk linked to grid constraints and regulatory discretion;
• permitting and timing risk across energy, environmental and construction procedures;
• price risk in increasingly volatile wholesale markets; and
• regulatory risk related to future changes in tariffs and support instruments.

As a result, transaction documentation increasingly features detailed curtailment protection provisions, robust revenue scenarios and enhanced contingency buffers, raising the threshold for project bankability.

Outlook and Regulatory Fine Tuning

Croatia’s renewables regime is best read as a framework in active transition rather than a settled body of law. Over the past eighteen months the authorities have closed several long-standing gaps, most notably on connection costs: HERA’s Decision on the unit connection charge, in force since 1 May 2026, replaced the two-decade-old 2006 tariff with transparent per-kilowatt charges differentiated by voltage level. Investors should nonetheless keep in view that the charge is genuinely “shallow” only at low and medium voltage, while high and very-high-voltage connections combine actual study-based costs with a per-kilowatt component, and grid capacity, curtailment and permitting timelines remain the practical constraints on delivery.

Two significant legislative packages are expected to be adopted in the fourth quarter of 2026, and neither is yet in force. The first is a set of amendments to the Electricity Market Act (Zakon o tržištu električne energije), which passed public consultation in mid-2026 but has not been enacted. As drafted, the bill would introduce flexible connection contracts, with criteria for transition to a firm connection and the possibility of flexible connection as a permanent solution where network reinforcement is not the most efficient option. It also proposes, among other things, a 30-day deadline for system operators to provide the grid data needed to prepare a transmission connection study (EOTRP), greater transparency of hosting capacity and of the status of connection requests, a framework for energy sharing and an “organiser” role for energy sharing with a 6 MW ceiling (subject to additional local limits for large undertakings), provisions on aggregation, and transitional relief for projects that were blocked while no connection-charge decision existed. These remain proposals, not existing rights, until the final text is adopted.

The second package is a parallel amendment to the Act on Renewable Energy Sources and High-Efficiency Cogeneration (ZOIEVUK), planned for the fourth quarter of 2026. Its adoption and general direction are confirmed by the government’s legislative programme, but the detailed content is not yet publicly settled; it is expected to develop the rules on self-consumption, self-supply and energy sharing and to advance alignment with the EU electricity-market-design package. Complementing the primary legislation, HERA has moved from consultation to adoption of its incentive framework for the self-consumption of renewable energy, which it formally established by decision on 16 July 2026 following a public consultation held in April 2026. The framework is an enabling and policy instrument rather than a standalone binding subsidy scheme: among the elements most relevant to this article, it points towards a strategic roadmap and a one-stop “citizen-energy office”, greater transparency of grid hosting capacity, dedicated financing, support for battery storage and building/home energy-management systems, energy sharing and energy communities, smart and dedicated metering, and the avoidance of double network charges, among other issues. These are, for the most part, recommendations and policy direction rather than immediately enforceable rights.

For investors, the practical takeaway is twofold. The direction of travel is clearly towards greater legal certainty, EU convergence and a broader set of routes to market: merchant sales through a fully coupled CROPEX, financial hedging via EEX-PXE Croatian power futures, contracted revenue through an emerging corporate PPA market, and support through the state aid programme. At the same time, several instruments remain in draft or have only recently entered into force, and important operational details, including grid-capacity data procedures, the connection treatment of standalone and co-located storage, and the final text of the Q4 2026 amendments, will continue to evolve. Transaction structuring and due diligence should therefore track the consolidated versions of the relevant laws as published in Narodne novine (Official Gazette), together with HERA’s decisions and methodologies, rather than relying on any single point-in-time description of the regime.

For legal practitioners, this landscape means that renewable energy mandates in Croatia increasingly combine traditional regulatory and contractual issues (auctions, concessions, grid connection agreements) with complex risk allocation questions related to network constraints, balancing responsibilities and long-term offtake arrangements. The success of Croatia’s energy transition will depend not only on formal alignment with EU law, but on how effectively these practical bottlenecks are addressed.