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Russia: 5 energy policy briefs

The energy policies moving Russia’s power markets, one brief each: the problem, the mechanism, the market effect, who gains and who pays, where it stands on the path to binding law, and the official text.

Digital-currency mining law and the regional mining bans · legalise, register, then restrict

Russia · Federal Assembly and the Government of the Russian Federation · statute · 2024

Where it stands: Mining legalised and registered under the 2024 federal law, with regional bans and seasonal winter restrictions in force since 1 January 2025 and enforced through grid companies

Russia legalised and registered cryptocurrency mining by federal law in August 2024 and then, within months, used government resolutions to ban or seasonally restrict mining in the regions where it was causing deficits, including parts of Siberia, the North Caucasus and the Far East, making mining the first large load class in the country to be managed by explicit administrative curtailment.

The problem

Cheap hydro power in Irkutsk, Krasnoyarsk and Buryatia and subsidised residential tariffs across the North Caucasus made Russia one of the world's largest destinations for bitcoin mining. The load arrived faster than the network could absorb it and in the wrong places: it concentrated in exactly the regions where the second price zone and the Far East were already heading into deficit, much of it on residential connections priced below cost, so the cost of serving it was socialised across other consumers while the revenue accrued to the miner. Distribution networks in the North Caucasus were overloaded by unregistered installations, and in Siberia mining load coincided with the winter peak and low-water hydro years. Because mining had no legal status at all, there was no register of who was consuming what, no way to apply a distinct tariff, and no lawful way to disconnect a miner without disconnecting an ordinary consumer.

What it does

The first step was legalisation and visibility. The federal law on digital currency mining, adopted in August 2024, defines mining and mining pools, restricts the activity to registered Russian legal entities and individual entrepreneurs entered in a state register kept by the tax authority (with an exemption for individuals consuming below a threshold set by the government), requires reporting of mined currency, and prohibits the circulation of mined currency inside Russia except through an experimental legal regime. Once miners were identifiable, the second step was restriction: the government adopted resolutions prohibiting mining entirely in a list of regions and, in others, prohibiting it seasonally during the autumn-winter maximum load period, with the bans running from 1 January 2025 for a multi-year term. The listed territories cover the North Caucasus republics, the Donetsk and Luhansk regions and Zaporizhzhia and Kherson, and the seasonal restrictions cover parts of Irkutsk oblast, the Republic of Buryatia and Zabaykalsky Krai, precisely the systems in which SO UES identified deficits and for which new coal capacity was later procured. Enforcement runs through the Ministry of Energy, the government commission on electric power development, the tax register and the grid companies, which may disconnect an unregistered or non-compliant installation. In parallel the differentiated household tariff removes the underlying subsidy that made residential-connection mining profitable in the first place.

Market effect

Mining is the clearest example in any large power market of load being treated as an adjustable policy variable rather than as demand to be served. The immediate effect is regional: in the restricted Siberian and Baikal regions several hundred megawatts to low gigawatts of interruptible load leave the system during the winter maximum, which materially improves the adequacy position in exactly the territories where the 2029 capacity selection cleared at 590,713.14 roubles per MW-month and where 1,050 MW of new coal capacity was awarded in December 2025 for 2031 delivery. That relief is why the deficit response has been staged rather than emergency. The second effect is locational: legal mining is being pushed toward the first price zone and toward regions with surplus, so the pattern of new data-hall and container-mine investment now follows the ban list rather than the tariff map. The third is fiscal and structural: registration brings the load into the tax base and onto commercial tariffs, which raises revenue and ends the residential cross-subsidy that the sector was capturing. For any operator of electricity-intensive digital infrastructure in Russia, including conventional data centres, the precedent is the risk: the state has demonstrated that it will legalise a load class, register it, and then curtail it by region and by season when the system is tight.

Key numbers

Legalisation
Federal law on digital currency mining adopted in August 2024, creating a state register of miners and mining infrastructure operators
Restriction start
Regional bans and seasonal restrictions in force from 1 January 2025 for a multi-year term
Territories affected
Full bans in the North Caucasus republics and the annexed territories; seasonal winter restrictions in parts of Irkutsk oblast, Buryatia and Zabaykalsky Krai
System context
The same Baikal-region deficit prompted 1,050 MW of new coal capacity awarded in December 2025 for 2031 and a second-price-zone capacity price of 590,713.14 roubles per MW-month for 2029

Who gains and who pays

  • Registered mining companies (mixed): Legal status and tariff access in exchange for registration, reporting and regional curtailment.
  • Miners in banned or seasonally restricted regions (costs): Must relocate or stop during the autumn-winter maximum load period.
  • Grid companies in Siberia, the Far East and the North Caucasus (gains): Overload relief and an enforceable basis for disconnecting non-compliant installations.
  • Other consumers in the affected regions (gains): Less deficit risk and an end to subsidising mining through residential tariffs.
  • Federal Tax Service and the Ministry of Energy (obligation): Maintain the register, monitor consumption and enforce the restrictions.
  • Data-centre and digital-infrastructure investors (costs): A precedent that electricity-intensive load can be curtailed administratively by region and season.

Implementation

Implementation runs on three tracks. The tax authority maintains the register of miners and mining infrastructure operators and receives consumption and output reporting. The Ministry of Energy and the government commission on electric power development maintain the list of restricted territories and the seasonal windows, which can be extended or amended by resolution as the balance changes. Grid and supply companies enforce at the connection point, disconnecting unregistered installations and applying the seasonal restriction to registered ones. Because the restrictions are set by resolution rather than statute, the list is a live document and can change between heating seasons, which is the main operational risk for an operator. The federal law number and date, the government resolution numbers, the precise list of regions and the exact end date of the restriction period were not verifiable from this environment; SO UES material confirms the underlying regional deficits and the associated capacity procurement but not the mining instruments themselves, so the legal parameters must be checked directly before any siting or compliance decision.

Concerns

  • The restricted-region list can be changed by resolution between heating seasons
  • Enforcement against unregistered installations on residential connections remains difficult
  • Precedent for administrative curtailment of other electricity-intensive load, including data centres
  • Relocation of mining load simply moves the adequacy problem to another region
  • Interaction with differentiated household tariffs is untested at scale
  • No compensation mechanism for curtailed registered miners

Dates to watch

  • 1 October 2026: Start of the autumn-winter maximum load period in which the seasonal mining restrictions apply
  • 2027: Expected review of the restricted-territory list against the updated regional balances
  • 2031: Commissioning of the new Baikal-region capacity that the restrictions were designed to bridge to

Sources

Checked against sources on .

Price-zone expansion · the Far East joins the competitive market and the 2025 tariff and cross-subsidy decisions

Russia · Federal Assembly, Government of the Russian Federation and the Federal Antimonopoly Service · statute · 2024

Where it stands: Price-zone expansion executed: Arkhangelsk and Komi included from the 2028 selection and the Far East from the 2029 selection, with differentiated household tariffs and cross-subsidy limits applying in parallel

Russia is dismantling its non-price zones: Arkhangelsk and Komi entered the price zones in time for the 2028 capacity selection and the Far East followed for the 2029 selection held in February 2026, so regions that had been paid at tariff now clear against competitive capacity prices, while in parallel the government has pushed differentiated household tariffs and cross-subsidy limits to move cost off industrial consumers.

The problem

For two decades the Russian wholesale market had a two-tier geography. The first and second price zones, covering European Russia and the Urals and then Siberia, had competitive day-ahead, balancing and capacity markets. Everything else, the Far East, Arkhangelsk, Komi, Kaliningrad and the isolated systems, sat in non-price zones where supply was paid at regulated tariffs because the network was too weak for competition. The result was chronic underinvestment where the tariff did not cover cost, no price signal to locate load efficiently, and a Far Eastern system that was heading into deficit just as mining, port and, later, cryptocurrency-mining load arrived. At the same time the retail side carried an enormous cross-subsidy: households paid below cost and industrial consumers paid above it, which distorted competitiveness, encouraged industrial self-generation and, because household tariffs were flat, gave heavy domestic users, including illegal crypto miners operating on residential connections, an effectively subsidised input.

What it does

Legislation and government resolutions adopted in 2024 and 2025 brought the remaining large non-price territories into the competitive market in stages. Arkhangelsk oblast and the Komi Republic were included in the price zones from the 2028 delivery year: SO UES's capacity selection for 2028, held in February 2025, was the first run over territories that had previously been non-price. The Far East followed one cycle later: the selection for the 2029 delivery year, held from 9 to 13 February 2026, was conducted across the price zones including the territory of the Far East, previously part of the non-price zone, and cleared at 590,713.14 roubles per MW-month in the second price zone against 369,390.73 in the first. Where the transition exposes a deficit the government uses targeted new-capacity procurement rather than tariffs: Government Order No. 3371-r of 20 November 2025 authorised a competitive selection of new generating facilities for the southern parts of the Buryatia and Zabaykalsky Krai power systems, under which 1,050 MW of new coal-fired capacity was awarded in December 2025 for delivery in 2031. On the retail side the government has moved to differentiated household tariffs, under which a household's rate rises once consumption passes thresholds set at regional level, and has tightened the framework within which the Federal Antimonopoly Service and regional tariff authorities set long-term tariffs and account for cross-subsidy, with the stated aim of reducing the amount shifted onto industrial and commercial consumers.

Market effect

Bringing the Far East into the price zones is the biggest geographic change to the Russian market since it was created. It replaces a tariff with a clearing price in a region where demand is growing fastest, which does three things: it gives generators there a revenue signal that can actually support investment, it exposes Far Eastern industrial consumers to a capacity price rather than a regulated rate, and it makes the deficit visible in the price instead of in load-shedding. The 60 percent premium the second price zone commands over the first in the 2029 selection is now the number that determines siting for any new electricity-intensive facility, and the gap is the reason data-centre and mining load has been pushed toward the west and the reason the government has been willing to authorise new coal build in Zabaykalsky Krai at a capped 842 million roubles per MW. Differentiated household tariffs cut the other way: they raise the marginal price faced by the largest domestic consumers, which is a direct attack on the residential-connection mining that has been distorting distribution loads in Irkutsk, Buryatia and the North Caucasus, and they slowly reduce the cross-subsidy that industrial buyers fund. For a trader or an industrial offtaker, the practical consequence is that regional price dispersion in Russia is now a market variable rather than an administrative one, and it is widening.

Key numbers

Far East joins the price zones
The KOM for the 2029 delivery year, held 9-13 February 2026, was the first run across the price zones including the Far East, previously a non-price zone
Arkhangelsk and Komi
Included in the price zones for the KOM for the 2028 delivery year, held in February 2025
Resulting price gap
590,713.14 roubles per MW-month in price zone 2 against 369,390.73 in price zone 1 for 2029
Deficit response
Government Order No. 3371-r of 20 November 2025: 1,050 MW of new coal capacity for southern Buryatia and Zabaykalsky Krai, delivery 2031

Who gains and who pays

  • Far Eastern generators (gains): Competitive capacity prices replace regulated tariffs in a tightening region.
  • Far Eastern industrial and commercial consumers (costs): Move from regulated rates to a second-price-zone capacity price that cleared 60 percent above zone 1.
  • High-consumption households (costs): Differentiated tariffs raise the rate above regional consumption thresholds.
  • Industrial consumers nationally (gains): Cross-subsidy limits are intended to shift cost away from them over time.
  • Federal Antimonopoly Service and regional tariff regulators (obligation): Must set long-term tariffs and thresholds and police the cross-subsidy ceiling.
  • New electricity-intensive investors (mixed): Clearer price signals, but a widening east-west price gap that reshapes siting.

Implementation

The transition is executed through amendments to the Wholesale Market Rules in Government Resolution No. 1172 of 27 December 2010 and through the annual capacity-selection schedule, so the observable milestone is the first selection in which a territory appears, not the date of the enabling law: February 2025 for Arkhangelsk and Komi and February 2026 for the Far East. SO UES then operates day-ahead, balancing and capacity processes over the new territory, the Trade System Administrator settles it, and transitional arrangements smooth the effect on consumers who previously paid tariffs. Household tariff differentiation is implemented by regional tariff authorities within federal parameters, so the thresholds and the resulting rates vary by region and are reset annually, normally with effect from 1 July. Cross-subsidy limits are enforced through the Federal Antimonopoly Service's tariff methodology. The federal laws and resolutions behind the price-zone change, the precise transitional mechanics for Far Eastern consumers and the 2025 household threshold parameters were not verifiable from this environment and should be confirmed before use.

Concerns

  • Far Eastern consumers face a step change from regulated rates to a high capacity price
  • A widening gap between the two price zones distorts industrial siting
  • Transitional smoothing arrangements are opaque and time-limited
  • Regionally set household thresholds produce inconsistent outcomes across the country
  • Cross-subsidy reduction depends on political tolerance for higher household bills
  • New coal build is the chosen answer to the eastern deficit, with long-term fuel and emissions consequences

Dates to watch

  • 1 July 2027: Annual reset of regulated and differentiated household tariffs by regional authorities
  • 2029: First delivery year in which Far Eastern capacity is paid at the price-zone clearing price
  • 2031: Commissioning of the 1,050 MW of new capacity procured for the Buryatia and Zabaykalsky deficit

Sources

Checked against sources on .

Federal Law 35-FZ on the Electric Power Industry · the 2017-2025 amendment cycle and Law 516-FZ on demand response

Russia · State Duma, Federation Council and President of the Russian Federation · statute · 2023

Where it stands: 35-FZ in force as amended; the 516-FZ demand-response framework is operational with SO UES running aggregator selections in both price zones

Federal Law 35-FZ of 2003 is the parent statute of the Russian power market, and almost every market change since 2017 has arrived as an amendment to it; the most consequential recent one, Federal Law No. 516-FZ of 2 November 2023, wrote demand-side response into the wholesale market as a paid service, which the System Operator now procures from aggregators in both price zones.

The problem

Russia's wholesale market was designed in the 2000s around a simple bargain: competitive day-ahead and balancing markets for energy, a separate capacity market to pay for availability, and non-price zones where tariffs still applied because the network was too weak or too isolated for competition. That design assumed a system with surplus capacity, stable demand and no need to manage the load side. By the late 2010s none of that held. Demand was growing in the south and east, the thermal fleet was ageing past its design life, the price cap on capacity was suppressing investment signals, and the only tool for a tight hour was to start another old unit. There was no legal basis for paying a consumer to reduce load, so the cheapest available flexibility in the system simply did not exist as a market product. The statute itself had to change because 35-FZ defines exhaustively what may be traded on the wholesale market and who may be a participant.

What it does

Federal Law 35-FZ of 26 March 2003 sets the architecture: the wholesale market of electric energy and capacity, the roles of the System Operator (SO UES), the Market Council association and the Trade System Administrator, the price and non-price zones, guaranteeing suppliers in retail, non-discriminatory access to networks, and the government's power to make the operative rules by resolution. The 2017 to 2025 amendment cycle has reworked it repeatedly: to extend and restructure capacity-supply agreements, to add microgeneration and consumer self-supply, to regulate digital-currency mining as an electricity-consuming activity, to reassign functions in the Far East, and to strengthen FAS and Ministry of Energy powers over tariffs and long-term planning. The clearest market-design change is Federal Law No. 516-FZ of 2 November 2023, which amended 35-FZ to create a new wholesale product: services for managing changes in the electricity consumption regime. The law defines an aggregated demand-management object, obliges its provider to be ready to change consumption when called, and makes the service payable through the wholesale market. SO UES now runs periodic competitive selections of aggregators under this framework: in the selection held in June 2025 six wholesale market participants qualified, offering 32 aggregated objects in the first price zone and 18 in the second, and a further selection ran in March 2025.

Market effect

The statutory layer is what a foreign counterparty has to read first, because it determines what is tradable and by whom, and because it changes more often than the market architecture suggests. The demand-response amendment is small in volume but large in direction: it converts the load side from a passive price-taker into a capacity resource that can be dispatched, which puts a ceiling on the value of the most expensive peaking units and gives large industrial consumers a revenue line for flexibility they already had. Aggregators are the new intermediaries, and because selections are run separately for the first price zone (European Russia and the Urals) and the second (Siberia), the product is priced against two very different generation mixes: a thermal and nuclear system in the first zone, a hydro-dominated one in the second. The broader amendment cycle matters differently: each change to capacity-supply agreements or to zone boundaries moves billions of roubles of obligations between generators and consumers, and because the operative detail sits in government resolutions rather than the law, a participant who reads only 35-FZ will always be a step behind. For pricing, the practical rule is that 35-FZ tells you what can happen and the Wholesale Market Rules in Government Resolution 1172 of 27 December 2010 tell you what it costs.

Key numbers

Parent statute
Federal Law 35-FZ of 26 March 2003 on the Electric Power Industry
Demand-response amendment
Federal Law No. 516-FZ of 2 November 2023, creating paid services for managing changes in consumption
June 2025 aggregator selection
Six wholesale market participants qualified with 32 aggregated objects in price zone 1 and 18 in price zone 2
Operative rules
Wholesale Market Rules approved by Government Resolution No. 1172 of 27 December 2010

Who gains and who pays

  • Large industrial consumers (gains): Can now be paid for reducing load through a qualified aggregator.
  • Demand-response aggregators (gains): A licensed intermediary role created by 516-FZ with periodic SO UES selections.
  • Peaking and old thermal generators (costs): Paid flexibility on the load side competes directly with expensive peaking capacity.
  • System Operator (SO UES) (obligation): Runs the selections, sets technical requirements and dispatches the aggregated objects.
  • Market Council and the Trade System Administrator (obligation): Must reflect each amendment in the accession agreement regulations and settlement systems.
  • Guaranteeing suppliers and retail consumers (mixed): New products and obligations flow into the retail price through wholesale settlement.

Implementation

Nothing in 35-FZ is self-executing. An amendment is signed by the President and published on the official legal portal, then the Government amends the Wholesale Market Rules (Resolution 1172) or the Retail Market Rules (Resolution 442) by resolution, then the Market Council Supervisory Board changes the regulations attached to the wholesale market accession agreement, and only then do SO UES and the Trade System Administrator change their systems. For demand response the chain has completed: the technical requirements, the aggregated-object definition and the selection procedure are all live, and SO UES has been running selections since the target model took effect, most recently in March and June 2025. For a participant the practical monitoring points are the Ministry of Energy drafts posted for public discussion, the Government resolutions published on the official legal portal, and the Market Council Supervisory Board agenda, in that order. Because the official legal portal and the Market Council site were not reachable from this environment, the amendment numbers and dates cited here should be confirmed against publication.pravo.gov.ru before use in a legal opinion.

Concerns

  • The operative rules sit in government resolutions that change faster than the statute
  • Frequent amendment makes long-dated contract drafting difficult
  • Demand-response volumes remain small relative to the capacity market
  • Aggregator qualification and metering requirements limit participation to large consumers
  • Price-zone and non-price-zone boundaries can be redrawn by legislation with short notice
  • Official texts are Russian-only, raising diligence cost for foreign counterparties

Dates to watch

  • 2027: Expected further amendments as the General Scheme to 2042 is implemented
  • 2026: Next competitive selections of demand-management aggregators by SO UES

Sources

Checked against sources on .

DPM VIE 2.0 · renewables capacity-supply agreements for 2021-2035 with localisation and export obligations

Russia · Government of the Russian Federation, Ministry of Energy and the Market Council · regulation · 2021

Where it stands: Programme resolutions in force; selections continuing with reprofiled volumes and deadlines while awarded projects build out toward 2035 commissioning dates

Russia supports renewables not through a feed-in tariff but through capacity-supply agreements awarded in competitive selections and paid for by wholesale consumers; the second programme, running from 2021 to 2035, cut the budget sharply against the first, switched the award criterion to the levelised cost of energy, and tightened localisation by adding an export obligation, which has left Russian renewables a small, industrially driven niche rather than a mainstream generation source.

The problem

The first renewables support programme, launched in 2013, delivered roughly 5 GW of wind, solar and small hydro by guaranteeing a return on capacity through capacity-supply agreements paid by wholesale buyers. It worked as industrial policy (it built domestic blade, tower, module and inverter plants) but it was expensive per megawatt-hour, and industrial consumers who fund it objected loudly to paying a premium for a resource that Russia, with abundant cheap gas and large hydro and nuclear fleets, does not need for adequacy. The government therefore faced a genuine trilemma when designing the successor: keep enough volume to sustain the factories built under the first programme, cut the cost to consumers, and make the industry export-capable so that it would not collapse when domestic support ended. The 2022 sanctions then removed the foreign technology partners (Vestas, Siemens Gamesa, Fortum and Enel among them) on which much of the localised supply chain depended, forcing a second redesign in the middle of the programme.

What it does

The second-stage renewables programme, commonly called DPM VIE 2.0, was established by government resolution and runs selections for wind, solar and small hydro projects with commissioning dates spread from the early 2020s to 2035. Three design changes distinguish it from the first programme. First, the award criterion moved from capital cost per kilowatt to the levelised cost of energy per megawatt-hour, with a declining cap by technology and year, which forces bidders to compete on output rather than on spend. Second, localisation is scored on a points basis covering the main components (for wind, the blades, nacelle, tower and generator; for solar, the ingots, wafers, cells and modules), with a minimum threshold that must be met for the project to be eligible and a penalty on capacity payments if it is missed. Third, the programme added an export requirement: a share of the equipment produced under the localised supply chain must be exported, which is intended to make the factories viable after the support ends. Successful projects sign a capacity-supply agreement giving a guaranteed capacity payment over a long term, funded through the wholesale capacity charge in the same way as KOM and KOMMod obligations. After 2022 the programme was reprofiled: commissioning deadlines were extended, penalties for delay were relaxed for projects hit by supplier withdrawal, and volumes and the timetable were revised as domestic manufacturers took over the technology.

Market effect

The economics are the reverse of most markets: in Russia the renewable plant earns most of its money from the capacity payment, not from the energy price, so the day-ahead price it receives is close to irrelevant to its return, and the cost lands on industrial wholesale buyers through the capacity charge. That is why the programme's size is a political number rather than a market one, and why industrial consumers lobby hard against every extension. For the system, the volumes are too small to change the merit order nationally, but they are locally significant in the south (Rostov, Stavropol, Astrakhan and Kalmykia for wind) and in the sunny parts of the south and Siberia, where they displace gas and coal at the margin and, in Buryatia and Zabaykalsky Krai, sit alongside the deficit-driven new thermal build. For equipment makers, the localisation and export rules are the whole point: the programme is essentially an industrial subsidy paid through the power bill, and the departure of Western partners in 2022 turned it into a forced technology-transfer exercise for domestic manufacturers. For investors, the key risks are a further cut to the programme's volume, revision of the localisation points table, and the enforceability of the export obligation in a sanctioned trade environment.

Key numbers

Programme window
Second-stage renewables capacity-supply agreements covering commissioning through 2035
Award criterion
Lowest levelised cost of energy per MWh under a declining cap, replacing capital cost per kW
Eligibility conditions
A minimum localisation score by component plus an export obligation on the localised supply chain
Revenue structure
Guaranteed capacity payment recovered from wholesale buyers through the capacity charge, not from the energy price

Who gains and who pays

  • Russian renewable developers and their industrial partners (gains): Guaranteed long-term capacity payments and a protected domestic equipment market.
  • Industrial wholesale consumers (costs): Fund the capacity-supply agreements through the wholesale capacity charge.
  • Domestic turbine, blade and module manufacturers (gains): Localisation points and the export obligation are designed to keep their order books full.
  • Departed foreign technology partners and their former joint ventures (costs): Sanctions and exits forced project reprofiling and technology substitution.
  • Gas and coal generators in the south and Siberia (costs): Marginal displacement in the regions where the projects are concentrated.
  • Market Council and the Trade System Administrator (obligation): Administer the selections, the localisation scoring and the payment obligations.

Implementation

Selections are run by the Trade System Administrator on a schedule fixed by government resolution, with results ratified through the Market Council. A winning project signs a capacity-supply agreement with a fixed commissioning date; missing it triggers a reduction in the capacity payment that escalates with delay, and failing the localisation threshold at commissioning triggers a separate penalty. After the 2022 supplier exits the government extended commissioning deadlines and softened penalties for affected projects and reprofiled the remaining volume, and further reprofiling has followed as domestic manufacturers have taken over turbine and module supply. The practical monitoring points are the Ministry of Energy drafts posted for public discussion, the government resolutions published on the official legal portal, and the selection results published by the Trade System Administrator and the Market Council. None of those sites resolved from this environment, so every figure in this brief that would drive a model, in particular the programme budget, the annual and cumulative megawatt volumes and the current localisation thresholds, must be taken from the official sources rather than from this summary.

Concerns

  • Cost falls entirely on industrial wholesale consumers, who lobby for cuts at every review
  • Programme volumes and deadlines have been reprofiled repeatedly since 2022
  • Localisation and export obligations are hard to satisfy under sanctions
  • Loss of Western technology partners left gaps in the wind supply chain
  • Renewables are marginal to adequacy, so political support is thin
  • Returns depend on administered capacity payments rather than on market prices

Dates to watch

  • 2027: Commissioning deadlines for reprofiled projects awarded in the early rounds
  • 2035: End of the second-stage programme window

Sources

Checked against sources on .

Capacity market and the thermal modernisation programme · KOM 2029 cleared at 369,391 and 590,713 roubles per MW-month

Russia · Government of the Russian Federation and the System Operator (SO UES) · regulation · 2019

Where it stands: Capacity selections running on schedule: KOM 2029 cleared in February 2026, KOMMod 2029 and the gas-turbine tranche for 2029-2031 in selection, KOM NGO awarded for the Buryatia and Zabaykalsky deficit

Russia pays for availability through a competitive capacity selection held four years ahead, and since 2019 it has bolted on KOMMod, a government programme that awards guaranteed capacity payments to modernisation projects on ageing thermal plant; the 2029 selection held in February 2026 cleared 164,914 MW in the first price zone at 369,390.73 roubles per MW-month and 52,380 MW in the second at 590,713.14 roubles.

The problem

Two thirds of Russia's thermal fleet was commissioned in the Soviet period and much of it is past its design life. The capacity market as originally designed paid for availability at a price set by a competitive selection with a cap, which is enough to keep a depreciated plant running but nowhere near enough to fund a new turbine, boiler or generator. Meanwhile the first wave of capacity-supply agreements, which had financed roughly 30 GW of new build in the 2010s, was running off, taking with it the guaranteed payment stream. The choice was to let old units retire and risk deficits in the south, Siberia and the Far East, or to create a second, administered payment channel for refurbishment. Sanctions after 2022 made the question sharper: Western gas turbines, spare parts and long-term service agreements became unavailable, so any modernisation programme also had to work as an industrial policy that pulled demand toward domestically produced turbines.

What it does

The competitive capacity selection (KOM) is run by SO UES under the Wholesale Market Rules approved by Government Resolution No. 1172 of 27 December 2010, separately for each price zone, four years ahead of the delivery year. Generators submit price bids for each generating capacity unit; SO UES stacks them against a demand curve and publishes the selected volumes and the clearing price used to calculate every buyer's capacity obligation. For the 2029 selection, bids were taken from 9 to 13 February 2026 covering 640 power plants and 1,808 generating capacity units offering 217,509 MW; preliminary results published on 14 February 2026 showed 164,913.932 MW selected in the first price zone at 369,390.73 roubles per MW-month and 52,379.581 MW in the second at 590,713.14 roubles per MW-month, 217,293.513 MW in total, with final results confirmed on 18 February 2026. Layered on top is the modernisation programme introduced by government resolution in 2019, which runs annual KOMMod selections awarding long-term guaranteed payments to refurbishment projects, plus a separate additional selection for projects installing gas turbines (KOMMod PGU): for the 2029 delivery year, technical parameters were taken from 15 to 17 October 2025 and cost parameters from 30 to 31 October 2025, with the preliminary project list published on 10 November 2025 covering both the 2029 modernisation selection and the gas-turbine selection for 2029 to 2031. A third channel, KOM NGO, procures entirely new plant where the system operator identifies a deficit: on 30 December 2025 SO UES published the register for the southern parts of the Buryatia and Zabaykalsky Krai power systems, held under paragraph 112(1) of the Wholesale Market Rules and Government Order No. 3371-r of 20 November 2025, in which En+ Generation was the only qualified bidder and won with three 350 MW coal-fired units at the Zabaikalskaya thermal power station, 1,050 MW in total, at the maximum permitted capital cost of 842 million roubles per MW, with delivery starting on 1 July, 1 October and 1 December 2031.

Market effect

The two price-zone clearing prices are the single most quoted numbers in the Russian power market, and the 2029 result shows the structural split clearly: Siberia's second price zone cleared at 590,713.14 roubles per MW-month against 369,390.73 in European Russia and the Urals, a 60 percent premium that reflects a tighter balance and the inclusion of the Far East, which participated in the price zones for the first time in this selection having previously sat in the non-price zone. Capacity revenue on that scale is what keeps a depreciated unit in the market, so the KOM price effectively sets the retirement decision for every old plant. KOMMod changes who invests: because the payment is guaranteed for a long term and awarded administratively on cost parameters, a generator with a plant on the approved list has a bankable refurbishment case that no market price would support, which is why the visible output of the programme is a steady stream of commissionings (Smolensk CHP-2, a 130 MW turbine in April 2025 and a second turbine in May 2026; Krasnoyarsk CHP-1's new unit in May and June 2026; a new turbine at Novosibirsk CHP-3 in July 2026). The gas-turbine sub-selection is the import-substitution instrument: by ring-fencing a quota for projects that install gas turbines, the programme creates guaranteed domestic demand for Russian-built machines at a moment when Western units and service are unavailable. KOM NGO is the deficit tool, and the Zabaikalskaya award shows its economics: a single bidder, a capital-cost cap set by government order, coal as the fuel, and a 2031 delivery date, which is how Russia is now closing the Far Eastern and Baikal-region deficit.

Key numbers

KOM 2029 clearing prices
369,390.73 roubles per MW-month in price zone 1; 590,713.14 roubles per MW-month in price zone 2
KOM 2029 volumes
164,913.932 MW selected in zone 1 and 52,379.581 MW in zone 2, 217,293.513 MW in total
KOM 2029 participation
640 power plants and 1,808 generating capacity units offering 217,509 MW; bids taken 9-13 February 2026, results 18 February 2026
KOM NGO Zabaikalskaya
Three 350 MW coal units, 1,050 MW total, at the capped 842 million roubles per MW, delivery from 1 July, 1 October and 1 December 2031
Legal basis
Wholesale Market Rules, Government Resolution No. 1172 of 27 December 2010; KOM NGO under paragraph 112(1) and Government Order No. 3371-r of 20 November 2025

Who gains and who pays

  • Owners of ageing thermal plant (gains): KOM revenue keeps depreciated units alive; KOMMod funds refurbishment at administered returns.
  • Wholesale electricity buyers and industry (costs): Pay the capacity charge, which now carries KOM, KOMMod and KOM NGO obligations.
  • Russian turbine and equipment manufacturers (gains): The gas-turbine sub-selection creates guaranteed domestic demand under sanctions.
  • En+ Generation (gains): Sole qualified bidder for 1,050 MW of new coal capacity in Zabaykalsky Krai at the capped 842 million roubles per MW.
  • System Operator (SO UES) (obligation): Runs every selection, publishes results and enforces the technical parameters.
  • New entrants and merchant developers (costs): Administered selections crowd out unsubsidised entry.

Implementation

Each selection runs to a schedule fixed by government resolution, so a late resolution moves an auction by a year and with it the investment decisions behind it. SO UES publishes the input information, takes technical and then cost parameters, runs the selection and publishes preliminary and then final results on its dedicated capacity-selection site. For KOMMod the sequence for the 2029 delivery year was technical parameters on 15 to 17 October 2025, cost parameters on 30 to 31 October 2025 and a preliminary project list on 10 November 2025, with the final list and the gas-turbine tranche for 2029 to 2031 following. Payment obligations flow through the Trade System Administrator's settlement, and the Market Council reflects each change in the accession agreement regulations. Delivery risk sits with the generator: a project that misses its commissioning date faces penalties against its guaranteed payment. The modernisation resolution of 2019 is commonly cited as Government Resolution No. 43 of 2019; that number was not verified here and should be checked before it is quoted.

Concerns

  • Administered modernisation payments displace market-based investment signals
  • A 60 percent price gap between the two zones distorts siting and industrial location decisions
  • Sanctions constrain turbine supply, so gas-turbine projects carry delivery risk
  • Single-bidder selections such as Zabaikalskaya deliver no competitive tension on price
  • New coal capacity to 2031 locks in emissions and fuel logistics risk
  • Capacity charges are a rising and inescapable cost for industrial consumers

Dates to watch

  • 2027: KOM selection for the 2030 delivery year and the next KOMMod round
  • 2029: Delivery year for the capacity cleared in February 2026, the first including the Far East in the price zones
  • 2031: Commissioning of the 1,050 MW Zabaikalskaya units awarded under KOM NGO

Sources

Checked against sources on .