Estonia’s state-owned transmission system operator Elering has presented a plan for a network of gas-fired power plants with a total capacity of up to around 900 MW. The plants are intended to strengthen Estonia’s electricity-system restart capability, replace the current island-mode support mechanism and add dispatchable capacity as ageing oil shale units are phased out.
Judging by statements in Estonia’s public media ERR, the direction of the plan is supported by ministerial-level comments and by the management of Enefit, the electricity business of state-owned Eesti Energia.
Formally, Elering’s plan is a domestic Estonian energy-security project. In practice, in an interconnected Baltic electricity and gas system, implementation of a project of this scale would affect the whole region.
The question is whether the Baltic region can treat a new near-gigawatt gas-power network as a neutral security measure after decades of dependence on Russian gas. Estonia decided in 2022 to stop importing Russian gas by the end of that year.
This could shape Estonia’s post-oil-shale energy model, LNG infrastructure, nuclear prospects, regional gas flows and Baltic energy costs for decades to come.
Data card: who is behind the gas reserve debate
Elering
Role: Estonia’s independent electricity and gas transmission system operator.
Ownership: State-owned strategic infrastructure company.
Function: Operates Estonia’s electricity and gas transmission networks; responsible for system reliability, market functioning and security of supply.
2025 operating scale
Revenue: €300.5 million
EBITDA: €80.5 million
Net profit: €21.7 million
Investments in property, plant, equipment and intangible assets: €182.5 million
Major planned investment projects: €3.419 billion, including synchronisation, EstLink 3, the fourth Estonia-Latvia interconnection, crisis-preparedness and hydrogen-related investments
Elering also reported accumulated congestion income of €539.1 million at the end of 2025, of which €278.4 million remained unallocated at the reporting date.
Eesti Energia / Enefit
Role: Estonia’s state-owned energy group.
Enefit: Market-facing electricity business / brand within Eesti Energia. From 2026, Eesti Energia’s new structure separates Enefit as the electricity business, Enefit Industry as the industrial arm, and Elektrilevi as the distribution network operator.
2025 operating scale
Sales revenue: €1.647 billion
EBITDA: €317 million
Renewable electricity generation: 2.3 TWh
Retail electricity sales: 9.4 TWh
Non-renewable electricity production: 1.4 TWh, down 18% year-on-year
Eesti Energia said fossil-based generation facilities remain critical strategic assets for flexible power generation and frequency services. It also noted that from 2026 Elering can procure reserves to ensure regional energy security, providing about €59.5 million per year in compensation for maintaining dispatchable capacity and system stability.
Data card: Elering’s proposed gas reserve plan
Project type: Distributed restart-capacity / dispatchable generation procurement
Likely technology: Gas-fired power plants
Proposed total capacity: Up to around 900 MW
Unit / connection-point size: 90-250 MW
Full output requirement: Within 15 minutes
Autonomous operation: Up to 72 hours without external power supply
Planned regions: Tartu, Virumaa, Pärnu, East Tallinn and West Tallinn areas
First units: 2031-2032
Full deployment: By 2035
Policy function: Replacement of the island-mode support mechanism and system restart capability
Market role: Units may participate in the electricity market when not needed for post-crisis restoration
Strategic question: Reserve mechanism, or a new gas-based dispatchable layer for Estonia’s post-oil-shale economy?
ERR reported these project parameters from Elering’s public explanation. The same report noted that the specific gas-reserve plan is not explicitly included in Estonia’s recently approved ENMAK 2035 energy development plan.
1. Estonia’s energy situation: why the plan matters
Estonia’s electricity system is small – annual consumption runs to single-digit terawatt-hours. Against that backdrop, up to around 900 MW of new gas-fired dispatchable capacity is very large. It is not a marginal emergency reserve.
The old oil shale units have been the historical backbone of Estonia’s controllable generation. That backbone is now ageing. Enefit CEO Juhan Aguraiuja told ERR that the role of Eesti Energia’s oil shale power plants as security-of-supply guarantors is beginning to end.
Enefit supports the objective of Elering’s restart-capacity tender: strengthening Estonia’s electricity security of supply and improving the system’s recovery capability. But Aguraiuja also said the new gas plants would be financed at the expense of maintaining old oil shale units, meaning Eesti Energia would need to begin gradually closing older oil shale blocks from 2030.
Energy Minister Andres Sutt also framed the need to replace old oil shale capacity as expected rather than surprising. He said the 900 MW figure is currently a consultation volume, and that the final amount will be known after feedback and the tender process. At the same time, Sutt described gas-fired plants as the most likely solution and said the restart-capacity project is needed “rather quickly” because the oil shale plants are old.
So the debate is not about whether Estonia needs system reliability. It does. The real question is what kind of infrastructure and dependency will replace oil shale.
2. ENMAK and the suddenness of the concrete gas scheme
The broader need for dispatchable capacity exists in Estonia’s strategic debate. The absence of a precise 900 MW gas-plant scheme from ENMAK should not be simplified into a claim that Estonia has no strategic basis for new controllable power.
But the concrete scheme now in public debate is different from a general category in an energy plan.
A distributed network of gas-fired units with a combined capacity of up to around 900 MW, defined by connection regions, unit sizes, technical requirements, market participation and a 2031-2035 implementation horizon, is a specific infrastructure trajectory. According to ERR, the plan surprised Fermi Energia, and the report itself notes that ENMAK does not contain such a scenario. Elering’s chief executive Kalle Kilk told ERR: “Kindlasti seda ENMAK-is pole” – “It is definitely not in ENMAK.”
That is why the question is not whether Elering is acting outside all strategic logic. The question is whether the concrete implementation now being discussed – up to 900 MW of distributed gas-fired capacity – is large enough to require public strategic debate, not only a technical consultation.
ENMAK gives the strategic category. Elering’s plan gives the concrete gas trajectory. And that trajectory is specific and substantial enough to matter.
3. What the project hides: fuel, LNG and the Baltic market
The proposed plants answer one question: where Estonia can get fast dispatchable electrical capacity.
They do not fully answer another question: where the fuel comes from, under stress, in winter, at what price and through which infrastructure.
Elering is both Estonia’s electricity transmission system operator and gas transmission system operator. But Elering is not a gas buyer. If Estonia builds gas-based electricity security, the fuel side will depend on commercial suppliers, LNG terminals, storage, pipelines, cross-border routes and contracts.
This is where the project becomes regional.
Without a domestic LNG entry point, Estonia’s gas-backed electricity security depends on Inkoo, Balticconnector, Klaipėda, Inčukalns and the southern route through Lithuania and Latvia. Balticconnector is a subsea pipeline in the Gulf of Finland. The previous Balticconnector outage showed that such infrastructure can be unavailable for months, not days.
If a similar disruption happens in a cold winter, after Estonia has added major gas-fired capacity, the issue is no longer only whether the region has gas in aggregate. The issue is whether gas can be delivered to Estonia at the right time, in the right volume and under stress.
Fermi Energia CEO Kalev Kallemets raised a similar question in comments to ERR. He said the issue deserves analysis: whether gas supply from Latvia can actually ensure Estonia’s security of supply. He also pointed to the security vulnerability of reliance on one Latvian storage facility and the Karksi metering point.
This is why Paldiski returns to the discussion. Paldiski does not appear as part of Elering’s gas plan. But if the project is implemented, the Paldiski question becomes unavoidable. Not because Paldiski is formally part of the plan, but because a gas-based security-of-supply model requires a credible answer to the fuel-entry question.
The effect would not stop at Estonia’s border. In a small Baltic gas market, implementation of up to 900 MW of new gas-fired reserve capacity will change the regional gas architecture. The market is too small for such a volume not to shift flows, storage logic, LNG terminal competition and price formation.
This is the less visible infrastructure layer: a national Estonian gas-power plan can redistribute flows, costs and strategic relevance across the Baltic gas system.
4. A gas plant does not buy cheap electricity. It buys controllability
Gas-fired power plants can start quickly. They can support the system when wind and solar output is insufficient. They can provide restart capability and peak-load coverage.
But they should not be described as a route to cheap electricity.
Aguraiuja told ERR that gas-fired plants do not provide cheap electricity for consumers, although they can stabilise peak-hour prices and serve security-of-supply and peak-load functions. He also said that adding gas plants would increase the number of hours when Estonia’s peak electricity price depends specifically on the gas price.
That is a central point for the Baltic region.
Today, Latvian and Lithuanian gas plants often shape peak prices for Estonia, according to Aguraiuja. If Estonia adds a large gas-fired layer of its own, peak-price formation may move partly inside Estonia rather than being shaped mainly by neighbouring gas plants. Estonia may reduce reliance on imported peak electricity, but it may also internalise gas as a stronger marginal price-setter.
In practical terms, Estonia would buy controllability. The price of that controllability would be higher exposure to gas.
The cost question is not only how much the plants will cost to build. It is also who pays for availability when they are not running. In a restart-capacity or security-of-supply model, the cost of readiness is normally recovered from the system – directly or indirectly through network tariffs, security-of-supply charges, public support mechanisms or market payments.
For consumers, this distinction matters. A plant that runs rarely can still be expensive if the system pays it to remain available.
5. Decarbonisation and the EU green course
Gas is cleaner than oil shale in carbon intensity, but it is still fossil fuel.
That makes the decarbonisation question unavoidable. Replacing ageing oil shale plants with gas plants may reduce emissions compared with Estonia’s legacy generation. But building up to 900 MW of new gas-fired infrastructure with a likely lifetime of 25 years or more is not automatically a climate transition. It may become a transition tool only if use is limited, costs are transparent and a credible low-carbon fuel pathway exists.
Aguraiuja raised this point directly. He told ERR that before making such a large investment in fossil-fuel-based plants, Estonia should carefully analyse possible changes in European carbon and climate policy.
Biomethane may be relevant at the margin, but it cannot credibly be treated as the fuel base for a 900 MW reserve system without demonstrated volumes, contracts, infrastructure and cost data.
The same applies to hydrogen or other low-carbon gases. They may become part of a future fuel mix, but they do not remove the fuel-security question unless the volumes, timing and costs are visible.
Until then, a 900 MW gas-reserve system should be assessed primarily as infrastructure dependent on imported fossil gas.
If the plants run on LNG or pipeline gas during tight market periods, their operating cost will also reflect fuel prices and carbon costs. That limits their role as a price-reduction tool: they may cap extreme peaks, but not necessarily lower the average cost of electricity for consumers.
The question is therefore practical: is this a transition tool, or a new fossil-based infrastructure lock-in for a generation?
If the plants run rarely, with transparent costs and a credible low-carbon fuel path, the risk profile looks materially different. If they become a broad balancing layer for the electricity system and future industrial projects, the fossil-lock-in risk becomes larger.
6. What happens to nuclear?
The gas plan does not formally cancel Estonia’s nuclear option. But it changes the market into which any future nuclear project would enter.
Kallemets told ERR that if security of supply is largely ensured through subsidised gas-fired plants, it raises the question of whether a nuclear power plant would still fit into the market. He also said such supported gas capacity would strongly affect the common Baltic electricity market.
This is not just an industry complaint. It is a structural issue.
Gas and nuclear solve different problems. Gas provides fast start-up, flexibility and peak support. Nuclear provides stable baseload power and a different fuel-risk profile. Neither is a magic solution.
The comparison with nuclear is not ideological. Gas and nuclear are not substitutes one-to-one. But in a small power system, a supported gas-capacity mechanism of this size can change the investment case for other firm generation.
Estonia is small. Up to 900 MW of gas-fired dispatchable capacity may occupy enough of the post-oil-shale space to make the later nuclear case harder to explain, even if it remains legally possible.
Estonia’s nuclear track is not purely theoretical. The government approved the draft Nuclear Energy and Safety Act and sent it to the Riigikogu in March 2026; the Climate Ministry described the draft as the first comprehensive legal framework for the use of nuclear energy and related activities in Estonia.
In a separate interview already published by nra.lv, Fermi Energia described Estonia’s SMR project as moving beyond a purely conceptual debate, while stressing that final site selection, licensing, financing and the final investment decision remain ahead.
That makes the timing important. If Estonia first builds a large gas-reserve system, nuclear may remain a future option, but the question becomes: future option for what market?
The risk is that a fast gas solution adopted for security reasons may occupy the investment and policy space that a slower nuclear option would otherwise need.
7. What is happening around the region
The regional context matters, but it should not be overstated.
The Finnish data-centre debate is useful mainly as a signal. The Baltic-Nordic area is entering a period in which credible, scalable and low-carbon power will matter for future industrial demand. Data centres, hydrogen, ammonia, research facilities and advanced manufacturing will require reliable electricity before they invest.
But gas-fired reserve plants are not a direct answer to data-centre baseload needs. They are a flexibility and security tool.
That distinction matters for Estonia. Energy policy typically addresses today’s immediate gaps first: ageing capacity, winter peaks, reserve needs and grid resilience. Future industries, however, do not invest on promises of emergency reserve. They invest where power is visible, scalable, predictable and competitively priced.
Central Europe adds another contrast. Czech power utility ČEZ and Rolls-Royce SMR signed an early works contract for the first Czech small modular reactor at Temelín, while Poland is expanding LNG imports through Świnoujście and continues to develop several energy-security tracks at once.
For larger systems such as Poland or Czechia, gas and nuclear can coexist inside broader industrial and power portfolios. For Estonia, the scale is different. What is a portfolio choice elsewhere becomes much closer to a strategic fork.
8. Observer hypothesis: Paldiski as the hidden infrastructure question
Baltic Focus is not claiming that Paldiski is part of Elering’s plan. The point is different. This is a hypothesis about infrastructure incentives, not a claim about coordination.
Elering’s plan may do more than replace ageing oil shale backup capacity. If implemented, it could strengthen the strategic case for Paldiski as a wider energy-infrastructure node, because a large gas-fired reserve layer requires a credible fuel-entry answer.
Without large gas-fired demand or strategic reserve logic, Paldiski remains a difficult infrastructure case. With a 900 MW gas-reserve layer, it becomes easier to present as part of Estonia’s security-of-supply architecture.
The logic is not that LNG is a chemical prerequisite for green ammonia production – it is not the feedstock. The point is narrower: hydrogen, ammonia and synthetic-fuel projects need credible power-system reliability. In that context, gas-fired reserve capacity and LNG access could strengthen the wider infrastructure case for Paldiski, even if these projects depend on different technologies and time horizons.
This creates a possible convergence of interests: Elering needs dispatchable restart capacity; gas suppliers and LNG infrastructure owners gain a stronger role in security-of-supply architecture; Paldiski gains renewed relevance as a potential LNG entry point; and green-fuels projects gain a more credible industrial power backbone.
The convergence of interests is strong enough to make transparency central. A large gas-reserve tender would not formally decide the future of Paldiski, but it could materially improve the economic and strategic case for a northern LNG entry point.
Private interests around LNG, gas supply, Paldiski, hydrogen, ammonia and synthetic fuels are not a problem in themselves. Entrepreneurs are identifying infrastructure signals and positioning themselves accordingly.
The issue is whether Estonian society and business can clearly see what kind of choice is being made.
9. A northern shift in the Baltic gas system
If Estonia implements the gas-reserve trajectory, the regional effect will not be optional. The Baltic gas market is too small for up to 900 MW of new gas-fired reserve capacity to remain a purely national matter.
The key shift would be geographical.
Since the end of Russian pipeline dependence, the region’s gas-security logic has relied on Klaipėda LNG, Inčukalns storage, Inkoo LNG through Balticconnector, GIPL and cross-border routes. A working Paldiski LNG entry, combined with large Estonian gas-fired capacity, would move part of the energy-security anchor northwards.
This would not make Klaipėda or Inčukalns irrelevant. But it would change their role. Klaipėda would face stronger competition for northern Baltic flows. Inčukalns would remain a storage asset, but the system would move further away from a single dominant storage-and-southern-route model toward a more distributed gas-security architecture.
For Latvia and Lithuania, that is why the Estonian decision matters. The choice is national. The consequences are regional.
If implemented, the project will not only replace old oil shale reserve capacity. It will shift part of the Baltic gas-power architecture northwards.
10. Why Latvia and Lithuania should care
Estonia will make this decision nationally, but the Baltic gas market is too small for a project of this scale to remain purely domestic.
Klaipėda LNG is currently one of the region’s main gas entry points. In 2025, the terminal received 34 LNG cargoes, regasified 30.5 TWh of LNG and reached average utilisation of 68%. In 2024, total LNG handling, including regasification and reloading operations, amounted to 27.7 TWh. The 2024 figure included both regasification and reloading operations, so it is not directly identical to a pure domestic-consumption measure.
A working Paldiski LNG entry would not remove Klaipėda from the system, but it would create a northern gas-entry option with direct relevance for regional flow patterns.
The technical scale is material. Elering’s Pakrineeme calculations put the preliminary technical capacity of a Paldiski FSRU at 113 GWh/day, with the flow toward Estonia-Latvia limited by the metering line to about 86 GWh/day. Actual capacity would depend on the specific FSRU and system conditions. These are preliminary technical calculations, not an approved terminal project. But the scale is not symbolic; if activated, such an entry point could affect how gas moves between Estonia, Latvia, Finland and Lithuania.
Inčukalns would remain important as seasonal storage, and Klaipėda would continue to serve Lithuanian and wider regional demand. But if Estonia combines large gas-fired reserve capacity with a working northern LNG entry, the Baltic gas architecture would move toward a more nationally anchored security-of-supply model.
That does not mean the regional market disappears. It means that nationally planned resilience measures would have regional effects on flows, infrastructure utilisation, cost allocation and consumer bills in Latvia and Lithuania.
11. Conclusion: Estonia at a fork
Estonia’s gas plan should not be read as a simple choice between “good” and “bad” technologies. Gas may be the fastest practical way to replace ageing oil shale units, provide restart capability and support the system when wind and solar output is low.
But the strategic issue is not gas alone. It is sequencing.
If Estonia first builds a large gas-reserve layer, that choice may shape the conditions under which later decisions on nuclear energy, LNG infrastructure, industrial demand and regional gas flows are made. A technical tender may therefore become the first step in defining the post-oil-shale system.
Estonia will make the decision nationally. But in a small and interconnected Baltic energy market, nationally anchored security-of-supply choices do not remain purely national. They influence infrastructure use, investment signals, cost allocation and consumer bills across the region.
Data basis / method note
Data basis: ERR reports on Elering’s gas reserve plan and statements by Elering, Enefit, Fermi Energia and Estonian ministers; Elering 2025 reporting; Eesti Energia / Enefit 2025 financial materials; Elering information on Russian gas import restrictions; nra.lv interview material with Fermi Energia; ERR reporting on Finland’s data-centre electricity-demand debate; public information on Klaipėda LNG and Pakrineeme / Paldiski technical capacity.
Comparison method: Qualitative infrastructure and market-risk assessment. Estonia’s proposed gas capacity is compared with national electricity-system scale, regional LNG routes, storage infrastructure, post-oil-shale options and the emerging Baltic-Nordic demand question.
Interpretation: This article does not claim that Estonia has made a final gas-over-nuclear decision. It identifies a strategic fork and the regional questions raised by a possible gas-reserve trajectory.
Reply / correction note
Baltic Focus will publish substantive corrections, clarifications or replies from the companies and institutions mentioned in this article.