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Events

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  • 3 Sep 2026Tajikistan

    Tajikistan presents draft of third-cycle climate NDC

    According to the Committee for Environmental Protection under the Government of the Republic of Tajikistan, the draft third-cycle nationally determined contribution — NDC 3.0 — was presented and discussed in Dushanbe on 31 August. Representatives of government agencies, the private sector, international organisations, youth and civil society took part in the discussion; the agenda covered climate targets, sectoral priorities and further implementation steps. The committee's own statement gives no numerical parameters. Asia-Plus named the target of the draft on 3 September, quoting the document itself: a 15% cut in greenhouse gas emissions by 2035 “compared to the base year.” The outlet does not specify which year is meant, but the year itself is not in doubt: Tajikistan's base year remains 1990, and the biennial transparency report separately calls it fixed, citing decision 4/CMA.1 on the consistent use of a once-chosen reference point. The question is not which year this is, but which 1990 figure is meant. No other publications citing the 15% figure were found in the available open sources — a report on the draft's presentation that came out a day earlier does not name any figures at all. And the base year 1990 now has two figures. The former inventory estimate is 36.9 mn tonnes of CO₂ equivalent, the recalculated figure is 24.4 mn tonnes, and both refer to the same year. If the 15% is counted from the recalculated figure, which the report declares to be the base, the 2035 ceiling is 20.7 mn tonnes — against actual emissions of 20.2 mn tonnes in 2022. If counted from the former estimate, to which the absolute figures of the current target are pegged, the ceiling rises to 31.4 mn tonnes. The gap between the two readings of the same target is more than ten million tonnes — more than half of what the country emits in a year. Nominally, the new target is lower than the current one: 15% versus the 30–40% unconditional and 40–50% conditional-on-international-support cuts that the 2021 NDC, submitted in October, counts from the 1990 level to 2030. But whether it is stricter or looser in substance depends on which 1990 figure is used: 15% off the recalculated base gives 20.7 mn tonnes, which falls inside the 2021 NDC's conditional range of 17.76–21.32 mn tonnes; 15% off the former estimate gives 31.4 mn tonnes, above either of its ranges. The 2035 horizon here is not a deadline shift but the standard framework of the third cycle; whether the draft retains a separate 2030 target is not clear from the reports. Tajikistan launched the NDC update in the summer of 2025 with a national workshop in Dushanbe — a scheduled five-year cycle, not a one-off initiative. The process is led by the Committee for Environmental Protection, with the Regional Environmental Centre for Central Asia involved through the SWITCH-Asia component. According to Asia-Plus, the committee and the Youth Ecological Centre announced the presentation of the draft, while the drafting itself is carried out with technical support from UNDP in partnership with the Agency for Hydrometeorology; a network of climate NGOs contributed proposals on inclusiveness and a just transition. The outlet writes that the document separately addresses the social side of climate policy — gender equality, protection of vulnerable groups, “green” jobs. The inventory underlying all these calculations is fixed in Tajikistan's First Biennial Transparency Report submitted to the UNFCCC. In 2022, emissions totalled 20.2 mn tonnes of CO₂ equivalent excluding land use — 17.7% below the 1990 level; including land use, 19.5 mn tonnes, or 25.8% below. The base year itself was recalculated for the report using the 2006 IPCC Guidelines and the global warming potentials from the Fifth Assessment Report: 1990 emissions excluding land use fell from the former 36.9 to 24.39 mn tonnes, with most of the revision coming from agriculture, down 7.6 mn tonnes, and energy, down 5.7 mn tonnes. The emissions structure changed no less than the totals: in 2022, energy accounted for 40.8%, agriculture 34.8%, industrial processes 13.6% and waste 10.9%, against shares of 64.0%, 19.0%, 12.3% and 4.7% in 1990. The report separately notes that the economic downturn of the 1990s cut emissions threefold, and that they have been rising again since 1999. The rebasing has a consequence the current NDC does not resolve, and a second one has now been added to it. The 2021 targets are set both in percentages and in absolute figures: 21.32–24.87 mn tonnes for the unconditional target, 17.76–21.32 for the conditional one. These absolute figures were derived as 60–70% of the 1990 base of 35.53 mn tonnes, and the NDC itself defines that base as net emissions — the list of covered sectors includes a separate line for forestry at minus 1.82 mn tonnes, meaning the base was calculated including land use. The 2024 biennial transparency report redefined the target's scope: in it, “greenhouse gas emissions” mean total emissions “excluding LULUCF,” the coverage is described the same way, and the base figure is declared as 24,386 kt excluding land use. The former absolute ceilings are repeated unchanged. Hence a discrepancy visible in simple arithmetic. From the figure the report declares as the base, the same 60–70% gives 14.6–17.1 mn tonnes, not 21.32–24.87. In other words, “minus 30% by 2030” means 25.8 mn tonnes if counted from the former 1990 estimate to which the target was pegged when the NDC was submitted, and 17.1 mn tonnes if counted from the current base. The stated “minus 15% by 2035,” counted from the current base, gives 20.7 mn tonnes. Both figures are worth holding up against the fact that in 2022 the country emitted 20.2 mn tonnes — 82.3% of the 1990 level against a 60–70% target. Reconciling the former absolute ceilings, the recalculated base and the new percentage target into one count is now a task for the third NDC. A separate line of the update concerns Article 6 of the Paris Agreement. In the biennial transparency report, Tajikistan states that it is considering participation in cooperative approaches using internationally transferred mitigation outcomes under Articles 4 and 6. For a country where hydropower plants account for 90.1% of electricity generation and the target ranges for per-capita emissions are 1.5–2.2 tonnes of CO₂ equivalent, this mechanism hinges above all on access to climate finance. The indicative submission deadline has already passed. Third-cycle NDCs with updated 2030 figures and new 2035 targets were expected from countries by early 2025; those submitted are to feed into the annual update of the UNFCCC secretariat's synthesis report ahead of COP31, to be held in Antalya from 9 to 20 November 2026.

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  • 2 Sep 2026Turkmenistan

    UN confirms first mitigated methane leaks at Turkmenistan's oil and gas fields

    Turkmenistan has started fixing super-emitter sources of methane at its oil and gas fields, and the UN Environment Programme (UNEP) has confirmed the first eight stopped leaks. The first was recorded in November 2024; in February 2026 two leaks were stopped at Dowletabat—one of the country's largest gas fields; the latest confirmed case is dated March 2026 and relates to Lebap province, one of the main gas-producing regions. The International Methane Emissions Observatory (IMEO) publishes cards for confirmed mitigation actions in a UN repository, most of them issued in April 2026; according to The Guardian, the mitigated leaks were linked to pipeline corrosion, faulty wells and failed flare units—a typical set for infrastructure, much of which was built back in the Soviet era. The MARS alert system sent Turkmenistan 192 notifications of satellite-detected methane plumes over the past year: the system captures a plume from a satellite and notifies the country and the operator, and the response after that remains voluntary. Ashgabat responded to about 20% of the notifications—with ground-based leak data and, in some cases, possible mitigation plans. For comparison: the United States received 138 alerts, responded to none of them and reported no mitigation actions; Mexico, where the world's largest leak was recorded at a rate of 37 tonnes per hour, responded to all 23 alerts, but mitigation there has not yet been completed. Megan Demeter, MARS programme manager at IMEO, called the first repairs a breakthrough in terms of documenting real mitigation measures, but noted that they have not yet become a breakthrough in the country's overall emissions volume. Other data back up that assessment: ranking all the leaks the system detected worldwide over the past six months, three of the six largest were in Turkmenistan, and nine of the fifty largest were Turkmen; the country accounts for more than a third of all MARS oil and gas observations in Eurasia. According to the International Energy Agency's (IEA) Global Methane Tracker 2026, Turkmenistan and Venezuela have the world's highest production methane intensities; in 2020–2023 emissions from super-emitter events in the country grew by more than 15% a year on average. The volume is known: according to an estimate by the analytics firm Kayrros cited by The Guardian, the two main fossil fuel production areas produced 4.4 mn tonnes of methane in 2022—2.6 mn in the west, on the Caspian coast, and 1.8 mn in the east. Converted using the twenty-year global warming potential, that is 366 mn tonnes of CO₂ equivalent (CO₂e), more than the UK's annual carbon footprint; on the standard hundred-year horizon, it is about 120 mn tonnes. Public tracking of this issue began in March 2023, when The Guardian, citing satellite data, named Turkmenistan the country with the world's largest methane leaks. On 1 Dec 2023, at COP28, Turkmenistan joined the Global Methane Pledge, which calls for cutting anthropogenic methane emissions by at least 30% by 2030 from 2020 levels. On 1 Nov 2024, the Cabinet of Ministers adopted a roadmap for 2025–2026 to strengthen international cooperation under the pledge: scientific and practical conferences and seminars with international organizations, work with foreign companies, feasibility studies for associated gas utilization projects, and participation in the MARS platform. The Ministry of Foreign Affairs's statement on the roadmap gives no quantitative emissions-reduction targets, and the text of the roadmap itself has not been published. European regulation sets the economic dimension of this issue. Most Turkmen gas goes to China; since 1 Mar 2025 small volumes have been going to Turkey under a swap scheme via Iran—a contract between Türkmengaz and BOTAŞ for about 1.3 bcm a year—while the Trans-Caspian gas pipeline remains unbuilt. The EU Methane Regulation (2024/1787) introduces requirements for fossil fuel importers in three stages. From 1 Jan 2027, an importer must prove to the competent authority of an EU member state that the producer applies emissions monitoring, reporting and verification (MRV) measures equivalent to the regulation's requirements, or reports at OGMP 2.0 level 5 with independent verification—a level no producer in the world has reached to date. From 5 Aug 2028, an importer must report production methane intensity using the European Commission's methodology. From 5 Aug 2030, that intensity must stay within a maximum value to be set by the Commission—meaning gas with a high methane footprint will not enter the EU market under new contracts. The first two stages apply to contracts signed or renewed after 4 Aug 2024; for earlier contracts, the importer must make “all reasonable efforts,” report annually on the results and explain why the contract could not be renegotiated. Requirements for operators inside the EU itself are broader and include leak detection and repair programmes and limits on venting and flaring; for imports, the first stage requires equivalence of measurement and reporting alone. The Clean Air Task Force has reported discussions with Nury Jumashov, Turkmenistan's deputy minister of environmental protection, in which methane regulation and the EU's import requirements were discussed.

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  • 31 Aug 2026Uzbekistan

    Marking 35 years of independence, Uzbekistan launches four energy facilities worth nearly $1.7 bn

    Uzbekistan has commissioned four energy facilities worth nearly $1.7 bn at once. The largest is a 1573 MW combined-cycle gas plant in Bayaut district, Syrdarya region, built for $900 mn by a consortium of France's EDF, Qatar's Nebras Power, and Japan's Sojitz Corporation and Kyuden International. According to the Ministry of Energy of Uzbekistan, the plant's efficiency is 61.7%, its design output is 13 bn kWh a year, and it is expected to save about 1.1 bcm of gas annually; construction employed 3,000 people, and 120 will remain in operation. In Nurata district, Navoi region, China Energy Overseas Investment commissioned a 300 MW solar plant with a 150 MW storage unit for $390 mn — 657 mn kWh a year, which the ministry equates to the annual consumption of 273,000 households. In Karauzyak district, Karakalpakstan, Saudi Arabia's ACWA Power launched a 200 MW wind farm with a 100 MW storage unit and a design output of 701 mn kWh, for $263 mn. The fourth facility is a standalone 100 MW/200 MWh storage unit in Namangan region, worth $110 mn, also from China Energy. The headline figure needs a caveat. Officially, six facilities with a combined capacity of more than 2.4 GW were announced, but storage units are counted as separate facilities and are included in total capacity alongside generation. Actual generating capacity commissioned was 2073 MW, with batteries accounting for 350 MW; a battery does not produce energy, it shifts it in time. Against Uzbekistan's installed power system capacity, estimated at 25,797 MW as of early 2026, the new generation adds about 8%. The Bayaut plant's design output also sits at the very edge of what is physically possible. A 1573 MW plant running around the clock all year yields a maximum of 13.78 bn kWh, while the declared figure is 13 bn — a 94% capacity utilization rate, meaning near-continuous operation with virtually no outages for maintenance or load reduction. A baseline combined-cycle plant is typically designed for 85–90%, so 13 bn kWh is better read as the design ceiling than as expected annual output. For the renewable facilities, by contrast, the stated figures are realistic: Nurata's 657 mn kWh implies a 25% capacity utilization rate, and Karauzyak's 701 mn kWh implies 40% — normal values for a solar plant in Navoi region and a wind farm in the Aral Sea region. The Ministry of Energy does not disclose its methodology for calculating gas savings, but it can be reconstructed by working backward: 13 bn kWh at 61.7% efficiency requires about 2.1 bcm of gas, and the declared saving of 1.1 bcm follows if that same output replaces plants with roughly 40% efficiency. All of this rests on a single assumption — that the plant actually delivers 13 bn kWh. Savings are directly proportional to load: at 60–70% capacity utilization, which is closer to the current norm for Uzbekistan's thermal generation, the same arithmetic yields just 0.7–0.8 bcm. The scale of substitution is clear from a comparison with the plant's neighbor on the same site: 13 bn kWh is the annual output of the entire old Syrdarya Thermal Power Plant, Central Asia's largest, at 3215 MW — twice the capacity. Its six units were upgraded in 2018–2021, each raised to 325 MW with specific fuel consumption cut by 40 grams per kWh, yielding about 270 mcm of annual gas savings; after the upgrade, unit efficiency reached about 41% — exactly the figure that produces the new plant's declared savings. In other words, the 1.1 bcm is calculated from displacing the neighboring plant that was just upgraded for $187 mn. The public launch was timed not to an energy milestone but to the 35th anniversary of independence, which Uzbekistan marks on 1 September. According to the presidential press service, on 25 August Mirziyoyev commissioned 163 facilities worth about 50 trillion sum (UZS) at once — 72 investment projects and 91 social facilities, from schools and kindergartens to the National Library; the energy facilities were part of this package. Trend.az dates the energy portion to 28 August, while the Ministry of Energy published its facility-by-facility breakdown only on 29–30 August. Physically, the plant had been in preparation for a long time: the first gas turbine ignition at the first unit in Bayaut took place back in February 2025, and construction readiness exceeded 80% by August 2025. What matters most in this package is not the megawatts but how it links gas and renewables. The Bayaut plant saves gas through efficiency: 61.7% efficiency against outdated units yields the declared 1.1 bcm a year. The Nurata solar plant displaces gas directly — 175 mcm and about 377,000 tonnes of avoided emissions. The Karauzyak wind farm adds another 187 mcm and about 403,000 tonnes. Combined, this is up to 1.5 bcm a year at the gas plant's declared load, and about 1.1 bcm if it operates closer to the current mode for thermal generation. The new plant's place in the system is not guaranteed: the 1500 MW Sirdaryo-1 CCGT has been operating on the same site since 2023, and solar is increasingly cutting into thermal plants' daytime load — at the daily peak on 24 June, renewables supplied 45.3% of output, and thermal generation dropped by about a gigawatt at that moment. On the other hand, Bayaut has the lowest specific gas consumption among the country's thermal plants, so it should rank ahead of them in dispatch order, and it makes sense to reduce load on the old steam units instead — the country has about 10.5 GW of them. Gas savings arise precisely from this gap, and their final size is determined by dispatch, not by design specifications. For Uzbekistan this is not an environmental figure but a currency and balance-of-payments one: in January–July 2026, the country imported $1.1 bn of gas from Russia and Turkmenistan, up 8.2% year-on-year, while its own gas exports over the same period fell 36.2% to $279.7 mn amid a structural decline in production. Storage units complete the design: 350 MW of batteries absorb the daytime surplus of solar generation that prompted a revision of the daytime tariff in August, and reduce the need to keep gas units in hot reserve for the evening peak. The result is a single package built on three different bets — gas efficiency, gas displacement by solar and wind, and the flexibility that makes the first two compatible. The package's second distinguishing feature is risk distribution. The Bayaut plant went to the consortium through a government competitive tender structured by the IFC; the winner was announced on 19 November 2021: EDF and Nebras each received 33.3%, Sojitz 19%, and Kyuden 14.3%. The project company sells electricity under a 25-year contract to National Electric Grids of Uzbekistan JSC, meaning the buyer is state-owned, and the plant does not buy gas at all: state-owned Uztransgaz supplies it under a tolling scheme, and the investor is paid for converting fuel into electricity. This means neither the price of gas nor its availability falls on the investor. Financing was assembled from an IFC loan of $150 mn plus $15 mn for risk-management instruments, along with JBIC loans of about $393 mn and financing from Mizuho, SMBC, and Société Générale with insurance cover from Japan's NEXI, at a total project cost of about $950 mn. For Uzbekistan's renewable-energy auction projects, the structure is standard: a competitive tender, a dollar tariff fixed for 25 years, and a government support agreement with the Ministry of Finance. Price benchmarks are known from international bank documentation and investor releases: the Nur Navoi solar project was won at 2.679 cents per kWh, and Uzbekistan's first public wind tender, at Karatau, produced 2.5695 cents — and it is this one for which the agreement with the Ministry of Finance is documented. The contract type for China Energy's Nurata plant has not been disclosed in open sources. The storage market is structured differently again: the subject of the agreement with Uzenergosotish is a storage service rather than energy sold — this is how, for example, Masdar's 300 MW/600 MWh contract in Navoi region, due to come online in 2028, is structured. Terms for the batteries just commissioned by China Energy and ACWA Power have not been published. In the end, the investor bears no market risk in the conventional sense on the package's key facilities. Demand is guaranteed by the single buyer, the price is fixed in dollars for a quarter-century, and fuel risk at the gas plant is removed through tolling. These risks do not disappear — they remain with the state, which here is simultaneously the buyer of electricity and the supplier of fuel. This structure explains why EDF, ACWA Power, and Chinese state-owned companies are investing in Uzbekistan's energy sector; its flip side is the accumulation of long-term, currency-denominated obligations with every new gigawatt.

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  • 26 Aug 2026Uzbekistan

    Race for data centres: Uzbekistan sells green power, Kazakhstan sells cheap coal

    Power supply stability has become the main argument in Central Asia's conversation with data centre investors. On 24 August, at the Silk Road Finance & Technology Forum in Tashkent, Bobur Khodjaev, head of the financial technology department at the Administration of the President of Uzbekistan, put it directly: “Electricity stability is question number one when we talk to investors.” According to him, Karakalpakstan was chosen for data centre placement deliberately, because of its green generation resources, and several international investors are already building wind and solar plants there. The programme's first major facility is not in Karakalpakstan yet: Saudi Arabia's DataVolt is building the TAS-1 data centre at Tashkent's IT Park—12 MW of total capacity, of which 10 MW is for server equipment, with launch planned for late 2026, and the project has attracted up to $150mn in project financing from DEG, the EBRD, the OPEC Fund and Proparco. The programme overall envisages several centres totalling up to 500 MW by 2032 with investment of about $3bn, and for TAS-1 it is stated that green electricity will cover more than 95% of energy consumption. The stated share of renewable sources needs clarification on its calculation base. Khodjaev cited “more than 30% of total generation,” but for full-year 2025 the Ministry of Energy of Uzbekistan gives different figures: out of total generation of 86.7bn kWh, renewable sources together with HPPs accounted for 16.8bn, or 19.4%, while solar and wind alone accounted for 10.5bn, or 12.1%. The share closer to 30% is in installed capacity: out of 25,797 MW nationwide, solar plants provide 3,930 MW, wind plants 1,652 MW, and hydro 2,441 MW, together about 31%. The “more than 30%” figure also matches an instantaneous snapshot: on 24 June the ministry reported that the share of renewables in generation reached as high as 45.3%. The spread is explainable—capacity, instantaneous share and annual generation are calculated on different bases—but for an investor being sold round-the-clock green load, it is the annual coverage that matters. The growth, meanwhile, is real: from the start of 2026 to 24 July, solar and wind produced 7bn kWh, reaching that mark a month earlier than the year before. The stability question is not rhetorical either: since the start of summer 2026, Uzbekistan's distribution networks have recorded about 4,000 faults, with outages on some days lasting 8–10 hours. Kazakhstan is approaching the same buyer with the opposite argument—price. In June 2026 the government signed a package of agreements worth $10bn with America's Firebird and Nvidia to create a “Data Centre Valley” near Ekibastuz, with the first stage valued at $5bn and Kazakhtelecom's contribution, via its subsidiary KT-Telecom, at $1bn; Firebird is responsible for the infrastructure and for supplying up to 100,000 Nvidia GB300 and Vera Rubin GPUs. The site is tied to the coal-fired Ekibastuz GRES-1, a 215 MW substation has been bought for the project, and the electricity price for residents is stated at $0.025 per kWh—roughly a third of the average rate for Kazakhstani enterprises and only slightly above GRES-1's own marginal tariff of $0.019. Demand is already forming: a memorandum with the UAE's Aleria covers 30 MW, preliminary applications exceed 100 MW, about 80% of the 125 MW first stage. As of 13 August, Kazakhtelecom CEO Bagdat Musin reported at a meeting with Prime Minister Olzhas Bektenov that excavation for the energy centres and AI factories was 90% complete, that the main buildings are to be erected by the end of December 2026, commissioning by May 2027, and that the first 50 MW facility will launch in June 2027. The site's potential is stated at up to 1 GW, with expected export revenue at full capacity of at least $3bn a year. The cost of this gigawatt for the power system is easy to calculate. An independent order-of-magnitude estimate, based on GRES-1 and Samruk-Energo JSC reporting, puts round-the-clock operation of 1 GW at about 8.76bn kWh a year and roughly 5.5mn tonnes of coal—more than Almaty's CHP-2 and CHP-3 burn combined (3–3.5mn tonnes a year)—and, given Ekibastuz coal's 43% ash content, this adds about 2.3mn tonnes of ash and slag. The author of the estimate notes that it is a calculation based on open data, not a forecast: the government has not published official figures for the project's energy consumption. On a national scale, the comparison is nonetheless telling: Kazakhstan's generation in 2025 totalled 123.1bn kWh, of which renewable generation was 8.6bn, or 7%. In other words, a single data centre at full capacity would consume about 7% of the country's annual generation—more than all of its renewable generation produces. Uzbekistan's programme is more modest: 500 MW at an 85% utilisation rate is about 3.7bn kWh a year, roughly 4% of 2025 generation. This load is appearing in a system that is only just emerging from shortage. In 2025 Kazakhstan generated 123.1bn kWh against consumption of 124.6bn—a gap of about 1.5bn kWh, versus 2.1bn a year earlier, covered by imports, mainly from Russia. Over January–May 2026, generation already exceeded consumption by about 0.3bn kWh; for the full year the Ministry of Energy of Kazakhstan forecasts a shortage of 1–1.2bn kWh, plans to eliminate it in 2027, and expects to reach a surplus of about 1.3bn kWh by the end of 2027 on the back of 7.3 GW of new capacity coming online. Against this backdrop, the scale of the project comes into sharper focus: even the first 50 MW facility running round the clock is about 0.44bn kWh a year, roughly a third of the future surplus, while the full gigawatt exceeds it many times over. This is precisely what AlmaU associate professor Vadim Novikov was pointing to when he noted the distributive effect: capacity that Firebird secures in advance will no longer be available to another consumer. Basic reliability, meanwhile, still requires investment. At a government meeting on 25 August—the day after the Tashkent forum—officials discussed readiness for the 2026–2027 heating season: 851bn tenge (KZT) has been allocated this year for repairing and upgrading power facilities, 60% more than last year, of which almost 384bn is going through the “Tariff in Exchange for Investment” programme. Prime Minister Olzhas Bektenov said that with financing at this scale, missed deadlines and unspent funds were unacceptable, and that delays in heating network repairs had been recorded in Kokshetau, Temirtau, Zhezkazgan, Almaty region and North Kazakhstan region. In the government's July review, five CHPs were listed in the risk “red zone”—in Semey, Uralsk, Taraz, CHP-2 in Aktau, and GRES-1 in Temirtau. The competition between the two countries, then, is not for investors in general, but over whose energy profile will prove more acceptable to a specific buyer of compute. Kazakhstan is selling cheap round-the-clock baseload capacity and a cold climate, taking on the carbon footprint in return; Uzbekistan is selling a green profile, taking on questions about grid reliability and about the basis on which its stated renewables share is calculated. The arguments are addressed to buyers with different priorities, and for those among them with their own climate commitments, the two are not interchangeable.

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  • 25 Aug 2026Tajikistan

    Tajikistan launches second stage of electric transport development program

    The government of Tajikistan has approved the parameters of the second stage of its electric transport development program: in 2026–2028 the country plans to open 1,100 new electricity points of sale for electric transport. The distribution skews toward the capital — 555 points in Dushanbe, 200 each in Sughd and Khatlon regions, 110 in districts of republican subordination and 35 in GBAO. Charging infrastructure is allocated about 167 mn somoni (roughly $18 mn) out of the 888 mn somoni valuation of the entire second stage — about $96 mn at the official rate of the National Bank of Tajikistan (9.25 somoni per dollar as of 3 August 2026); the largest line item — more than 714 mn somoni, about $77 mn — is for the purchase of 210 electric buses, 70 vehicles a year. The electric transport development program itself was adopted for 2023–2028, and the action plan for the second stage was signed on 28 April 2026. The scale becomes clear against the size of the fleet. According to the Ministry of Transport, Tajikistan had 34,400 units of electric transport as of 1 June 2025; by the end of the year estimates had risen to about 40,000. The growth is driven by tax policy: electric vehicle imports have been exempt from customs duties and taxes for ten years, and in 2024 alone the country imported 17,700 vehicles. There is no comprehensive statistics on operating charging points in the republic. If the plan for 1,100 points is fulfilled in full, coverage will amount to roughly one point per 36 vehicles in the current fleet, while in the capital — 555 points — that is about one per 27 of Dushanbe's 15,000 electric taxis; the fleet keeps growing, however, so the actual ratio by 2028 will be worse. The ratio of fleet to infrastructure differs among neighbors. In Uzbekistan, 109,200 electric vehicles were registered as of 1 April 2026 — up 68% year on year, with 79,900 of them, or 73% of the fleet, in Tashkent. Uzbekistan does not publish official statistics on the number of charging stations: according to an estimate by the analytical agency Avtostat, there were 1,675 commercial and public stations as of 1 June — one per 65 electric vehicles. The Ministry of Energy of Uzbekistan has put forward a draft that would bring the network to 4,000 stations as early as 2026 (which would give one per 27 vehicles in the current fleet) and require stations every 20 km on interregional highways. Kazakhstan has markedly fewer electric vehicles — 32,479 as of 1 June 2026, or 0.5% of the country's entire vehicle fleet, with 17,500 in Almaty and 3,200 in Astana. Charging stations, according to the Ministry of Transport as of May, numbered 665 — about one per 49 vehicles, the best ratio in the region. But the geography is skewed: the south and center are saturated, the east and west are nearly empty, and only a handful of stations line highways of republican significance — estimates diverge, with the Ministry of Transport's May data giving 49 such stations, while the prime minister in July cited about 70, announcing another 250 roadside stations by 2030 under an investment agreement. In Kyrgyzstan, the electric vehicle fleet stood at 15,278 vehicles as of 1 January 2026, or 0.8% of all vehicles — up almost fivefold in two years (in 2022 there were 1,113 vehicles). Charging stations, according to the Ministry of Natural Resources, number “more than 100” in Bishkek, meaning at best about one per 150 vehicles; there is no comprehensive nationwide count. The national electric grid company is building infrastructure separately: by 11 June it had installed 30 stations with a capacity of 120 kW in Chuy, Naryn, Issyk-Kul and Talas regions and plans to bring their number to 100 by year-end using its own funds. The density comparison here is ordinal, and the data are of varying quality: Tajikistan's “electricity point of sale” is an accounting unit of the Ministry of Transport and is not necessarily equivalent to a public station in Kazakhstan's or Uzbekistan's statistics, where a single station can have several ports and different capacities. Only Kazakhstan keeps a comprehensive count of stations; the Uzbek figure is an estimate by industry analysts, the Kyrgyz figure covers only Bishkek, and for Tajikistan there is no count of operating points at all, so its ratio is a projection based on the plan. Turkmenistan is absent from the comparison: no public data could be found on either its electric vehicle fleet or its charging network. A separate question is how such networks are connected to the power system. Globally, pairing a charging hub with a storage system is a fast-growing practice: according to BloombergNEF's Energy Storage Outlook for H1 2026, the combined capacity of storage systems installed at charging stations in China, France, the US and the UK reached about 1 GWh, with China alone reporting future projects worth roughly another 10 GWh (the report's authors themselves note the data are incomplete). The logic of the scheme is that a battery takes peak load off the connection point: a site with a relatively weak grid connection can still deliver high power to a vehicle from the storage system, while the storage system itself charges during low-demand hours, can draw on its own solar output and can time purchases to price. In Central Asia, storage systems are so far arriving at the power-system level rather than at charging hubs: in Kazakhstan, the Ministry of Energy of Kazakhstan has announced storage systems totaling 1.6 GW, built alongside wind farms and intended to cover the morning and evening peaks. No “charging plus storage” projects have been reported yet in the region's public domain, even though this format would resolve exactly the conflict between charging and the evening peak load. This conflict has already surfaced administratively in Tajikistan. An order from the head of OJSC Shabakahoi Taqsimoti Barq dated 27 November 2025 instructed branches to cut power to all electric vehicle charging stations during the evening peak, from 18:00 to 22:00, and to limit electric vehicle charging to four hours a day. The basis was the winter power limit: hydropower plants, which account for almost all of the country's generation, run at reduced capacity in winter. The scale of the load, in calculations cited by Asia-Plus, is as follows: about 15,000 Dushanbe electric taxis consume roughly 900,000 kWh a day — more than 2% of the country's average daily generation (about 44 mn kWh), and one electric taxi at 60 kWh a day is equivalent to four households; the entire electric transport fleet is estimated at 1.6 mn kWh a day, or 3.6% of generation — about 67 MW of average load, while in the evening hours charging's contribution runs noticeably above average, at roughly 60–100 MW depending on the hour. The restrictions were seasonal: the power limit was lifted in cities and district centers on 17 January and across the whole republic on 27 February 2026, and the industry expects the “power-limit era” to end in the coming years. But the 1,100 new points will be built into a system where, last winter, their operation had to be restricted by the hour, and whether such measures will return for the 2026/27 season remains unclear.

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  • 21 Aug 2026Uzbekistan

    Samarkand electricity networks handed to Turkey's Aksa

    Uzbekistan has for the first time handed the distribution networks of an entire region to private foreign operator management. The electricity networks of Samarkand region — home to about 4.3 mn people and around 5.5 bn kWh of annual consumption — will be run by Turkey's Aksa Elektrik, the retail and distribution arm of the Kazancı holding. Ownership of the assets remains with the state company Regional Electric Networks (“Hududiy Elektr Tarmoqlari”); operation, modernization and investment obligations pass to the operator. Details of the deal were disclosed on 20 August, following a presidential decree. Management is transferred for up to 30 years, with the investment obligation fixed for the first 12 years: $357 mn, plus at least $27 mn for the two-year transition period. The company's own stated plan for the full term is about $1 bn, but that is a target, not a binding commitment. The tariff for consumers does not change: the state guarantees the operator payment for every kilowatt-hour that passes through the network. Loss-reduction obligations are set conditionally, depending on the starting level: at losses of 20–25%, the network must lose 1.4 percentage points less per year; at 15–20%, 0.6 points less. The actual loss level specifically for Samarkand region is not named in the documents, so the real trajectory toward the target cannot yet be reconstructed in figures. The state's motive is clear from the condition of the network. The distribution infrastructure is worn out: more than half of it has been in operation for over 30 years, and its modernization through 2030 is estimated to require about $3 bn. Authorities intend to cut technical losses from a nationwide average of about 14% (an estimate as of early 2025) to 8–9% by 2030. Reliability remains a painful issue — in June–July 2026 alone, the networks saw about 4,000 outages, and in late April the Ministry of Energy of Uzbekistan dismissed 44 executives over high losses. The sector has been under reform since 2019, when the former Uzbekenergo was split into generation, transmission networks and distribution. Under the development strategy through 2035, distribution is being shifted to private operators and RAB tariffs (the methodology has already begun to be applied to tariffs since August 2026), and authorities plan to hand the networks of the country's other regions to operators by mid-2027. The Samarkand deal is the first such precedent. In the deal itself, it is important not to confuse two companies from the same group. The networks will be run by Aksa Elektrik, the private retail and distribution arm of Kazancı Holding, which operates in nine provinces of Turkey and serves about 4 mn people through the distributors Aksa Çoruh and Aksa Fırat. This is not the exchange-listed Aksa Enerji, which is engaged in generation; Uzbek and Turkish media regularly conflate the two entities — the gazeta.uz headline about the deal also named the operator as “Aksa Enerji”. The choice of a Turkish operator fits Uzbekistan's broader pivot toward Turkey: trade turnover reached about $3 bn in 2025, the two sides have elevated relations to a comprehensive strategic partnership and cooperate closely within the Organization of Turkic States. The Kazancı group already has a notable footprint in the country, but in generation — since 2022 Aksa Enerji has launched gas-fired plants in Tashkent and Bukhara and, together with Talimarjan, brought capacity to about 1.2 GW, operating under long-term contracts with a guaranteed tariff. The group earned its recognition as an electricity producer, while the distribution networks went to a different, distribution-focused subsidiary. The contract went to Aksa not by direct award but through an open international tender run by the Energy Market Development and Regulation Agency. Besides Aksa, nine other companies expressed interest in the project, including China's State Grid and China Southern, India's TATA Power and CESC, and a consortium of France's EDF with Japan's Kansai. Three finalists remained — Aksa, Cengiz Enerji and EDF with Kansai — and Aksa won. The question of experience remains open. Aksa Elektrik's distribution network management so far is domestic to Turkey only — two service zones in the east of the country. The company has no publicly confirmed distribution operations outside Turkey: Samarkand is presented as the Turkish distributor's first project in Central Asia, even though the losing bidders included operators with international network experience. The group's African presence relates to Aksa Enerji's generation business, not networks. How well the experience of operating a network in eastern Turkey transfers to an Uzbek region with a different state of infrastructure and level of losses will be shown by the first years of operation.

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  • 20 Aug 2026Uzbekistan

    Uzbekistan accelerates new generation as gas balance reverses

    In a single week of August, Uzbekistan took two steps at once to expand non-gas generation — and received fresh statistics showing the context behind these decisions. Small and micro HPPs. At a presentation to President Shavkat Mirziyoyev on 19 August, a package of measures for small-scale hydropower was approved: it proposes introducing minimum purchase tariffs for electricity — so that winners of auctions with a “zero” price, who have not yet started construction, get a guarantee of payback. Design procedures for plants up to 100 kW are being simplified, for facilities up to 50 kW architectural review and supervision are scrapped, and construction at water utilities for own needs will be allowed without auctions. The goal is to bring small HPP capacity to 204.8 MW and generation to 620 mn kWh by the end of 2030; the country currently has 64 such plants with a combined 41.6 MW. Second NPP. On 17 August, Mirziyoyev said that “extensive preparation is also underway for the second plant.” The parameters of the second NPP — capacity, site, timeline — have not been officially disclosed. The first NPP is being built in Jizzakh region: 2,110 MW (a combination of VVER-1000 and small RITM-200N reactors), with Rosatom as partner, at an estimated cost of up to $9.5 bn. Technical start-up of the first small RITM-200N reactor is scheduled for October–November 2029, the first large unit is expected to come online in 2033, with full completion by 2034–2035. Gas balance. At the same time, Uzbekistan's State Statistics Committee recorded a reversal in foreign gas trade: in January–June 2026, imports of natural and manufactured gas rose 41.4% to $971.7 mn, while exports fell 34.4% — from about $355 mn to $232.9 mn. Gas, for decades the backbone of Uzbekistan's energy sector and an export line item, is becoming an increasingly costly import for the country. The three developments are not officially linked in a single document, but they form a common pattern: the build-out of hydro and nuclear generation coincides in time with a reversal in the gas trade balance. How quickly small HPPs and future NPPs can offset increasingly expensive gas imports is a question of timing: small HPPs will add around 160 MW by 2030, the first large nuclear unit not until 2033, while the gas reversal is already underway.

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  • 18 Aug 2026Uzbekistan

    Khorezm launches Uzbekistan's first waste-to-energy plant, amid a wave of such projects across Central Asia and the CIS

    **What's happening.** On 17 August, during a presidential visit to the Khorezm region, 12 projects worth $176 mn were commissioned and construction began on another 15 facilities worth $7.42 bn. On the energy side is Uzbekistan's first waste-to-"green"-power complex built on a closed-loop principle: declared capacity of 71 MW, investment of about $100 mn, with Korean investors. Separately, cogeneration with a Saudi investor is starting in Urgench, which will supply heat and electricity to 183 apartment buildings and 37 social facilities. According to the official description, the waste-processing complex is moving into the construction phase rather than being commissioned; no commissioning date has been given. **Not the first in the region.** "First in Uzbekistan" is an accurate description, but not "first in Central Asia." An operating waste-to-energy plant already runs in Bishkek (up to 30 MW, about $95 mn, roughly 1,000 tonnes per day at startup, Chinese investors) — sources directly call it the first in the region, and a Tajik delegation travelled in June 2026 to study its experience. Kazakhstan has the most advanced programme: three waste incineration plants in Almaty, Astana and Shymkent worth a combined 293 bn tenge (KZT), all with Chinese investors (Junxin in Almaty), with the flagship Almaty plant due to be commissioned by the end of 2028. In Uzbekistan itself, a parallel programme of six plants worth almost $933 mn is under way (Andijan, Namangan, Fergana, Samarkand, Kashkadarya, Tashkent; once all are running — 3.6 mn tonnes of waste per year and about 1.6 bn kWh) — Khorezm is not part of it, this is a separate project; in addition, South Korea's Sejin G&E is building 16 MW of landfill-gas capture at landfills in the Tashkent region. In the CIS, the largest reference is Russia's RT-Invest "Energy from Waste" programme: five plants totalling 355 MW, with the first turbine near Voskresensk launched in late 2024. A plant in Balakhany near Baku has also long been in operation (since 2012, about 200 mn kWh per year). **Why this power is expensive.** WtE economics work the same way everywhere: waste disposal comes first, and electricity is a byproduct. Capital costs run around $3,000–5,000 per kW of installed capacity (about $4,700/kW in Almaty, $3,200/kW in Bishkek), whereas according to IRENA, the 2024 average specific cost was $691/kW for solar plants and $1,041/kW for onshore wind. Such generation only pays back through an elevated tariff. In Kazakhstan, plants go through auctions held by the Ministry of Energy of Kazakhstan on the KOREM platform with a cap price of 130 tenge/kWh; direct negotiations halved it to 54–55 tenge/kWh, still several times above the country's solar auction prices (about 16 tenge at the 2024 auction). In Russia, the mechanism is capacity supply agreements with a guaranteed 12% return over 15 years; according to the Community of Energy Consumers, the capacity price of such plants is roughly 25 times higher than for gas plants, and according to the Market Council's calculations, consumers will pay about 300 bn roubles for these plants' capacity through 2035 (about 19 bn roubles a year for the first price zone). The second revenue stream is a waste acceptance fee (gate fee), which internationally runs $40–120 per tonne; in Central Asia and the CIS there is almost no payable tariff for waste collection, so the burden shifts onto the power tariff. Against this backdrop, the Khorezm figures should be read with caution: $100 mn for 71 MW works out to about $1,400 per kW, two to three times below comparable projects in the region. Either this is an incomplete project cost, or 71 MW is an upper-bound design estimate of capacity. **Effects and criticism.** WtE has an obvious upside: it sharply cuts the volume sent to landfill and removes landfill methane. But there is also a persistent line of criticism. First, the environment: dioxin emissions when incineration temperature control is inadequate, and a toxic ash fraction. Second, competition with recycling: a plant "locks in" a city's waste stream for 20–25 years and can slow separate collection and recycling. Tellingly, the European Union is cooling toward incineration instead: since 2024, emissions from EU waste incineration plants have already been subject to mandatory monitoring under the EU ETS, and their full inclusion in emissions trading from 2028 is under review by the European Commission as part of the ETS reform. **Barriers across Central Asia and the CIS.** These are common to the region. Low electricity tariffs — without a special tariff or a capacity agreement, a project does not pay back. No separate collection — the input is mixed, wet waste with a high organic share, meaning low calorific value and a risk of falling short of declared capacity. Weak waste-management regulation and uncollectable waste-removal fees — a key revenue stream falls away and the burden lands on the power tariff. Finally, dependence on foreign capital and equipment: across the whole Central Asian sample, investors and technology are external — Chinese, Korean, Turkish, Saudi. For Uzbekistan, the Khorezm project is less about new energy capacity than about whether the country can handle its landfill problem without overpaying for it through the tariff.

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  • 17 Aug 2026Kazakhstan

    A weak ring: what the 14 August blackout teaches

    On 14 August, a cascading failure hit the Integrated Power System (IPS) of Central Asia: within minutes, the outage affected southern Kazakhstan, Uzbekistan, Kyrgyzstan and Tajikistan — partial in each case, but simultaneous across four countries. Power started coming back the same day: Kyrgyzstan was fully restored by evening, and Uzbekistan restored supply to all regions except part of Surkhandarya region. But public explanations of the incident diverged, and that divergence is itself telling. Three versions of the cause. The most specific account comes from Kazakhstan's grid operator, KEGOC: according to the company's managing director, at 14:37 (Kazakhstan time) two units (about 600 MW combined) tripped at the Toktogul HPP in Kyrgyzstan; according to the operator, this overloaded the North–East–South transit corridor of the Kazakh power system, emergency automatics activated, and three 500 kV lines tripped (“Agadyr–Ulken” and “Aktogai–Taldykorgan”), after which the southern zone of Kazakhstan separated from the unified grid. Kazakhstan's Ministry of Energy was vaguer, citing a “power surge caused by a sharp change in the electricity flow from the Central Asian power system” — framing the same episode as an external factor. The Kyrgyz side (NESK) described the incident differently: at 15:34 (Bishkek time, an hour ahead of Kazakhstan), the Kyrgyz power system switched to isolated mode “following an external outage on the high-voltage line connecting the northern and southern parts of the Kazakh power system” — pointing to a line within the Kazakh grid rather than to its own generation. Why 600 MW brought down four countries. In absolute terms the loss was small — roughly one large generating unit. But it took down neighbours not through its size but through the grid's design. The IPS of Central Asia is a loosely connected ring inherited from the Soviet unified system, and today it does not operate at full strength: the synchronous core is southern Kazakhstan, Kyrgyzstan and Uzbekistan; Tajikistan was cut off after Uzbekistan left the ring in 2009 and is only now reconnecting (the fact that the 14 August incident reached it too shows it is already connected), while Turkmenistan operates separately. But even in this reduced form, the ring retains a narrow, chronically overloaded North–East–South transit corridor through Kazakhstan and a thin emergency reserve. In this configuration, a local imbalance is not absorbed on the spot but reaches every participant within minutes; protective automatics, in saving equipment, “cut” the system into isolated islands — which is what happened on 14 August. This has happened before: on 25 January 2022, the same kind of cascade along the overloaded transit corridor cut power to southern Kazakhstan, almost all of Kyrgyzstan and a significant part of Uzbekistan — and at the time Kazakhstan and Uzbekistan also publicly blamed each other. The ring is genuinely being reinforced. Reconstruction of the unified system has been underway since 2019, and some projects target the ring specifically: the Asian Development Bank (ADB) is financing a 22 km, 500 kV line from the Sughd substation in northern Tajikistan to the New Syrdarya substation in Uzbekistan ($15mn grant, October 2024) — so that Tajikistan connects to the system year-round rather than seasonally. But most of the money and attention goes into generation (the Rogun HPP in Tajikistan, the trilateral Kambarata-1 in Kyrgyzstan) and into export corridors leading out of the region — the CASA-1000 Datka–Sughd 500 kV line has been energized since March 2025, but it is an export corridor to Afghanistan and Pakistan, whose Afghan section is still under construction (expected by 2027), and there are no commercial deliveries yet. New links and plants are being added faster than emergency reserves, frequency regulation and coordinated cross-border automatics — and it is precisely the shortage of these that turns a local fault into a cascade. “Strengthening the grid” and “strengthening grid resilience” are not the same thing, and the difference here is fundamental. New lines and plants connect countries more tightly, but a more tightly connected ring with weak reserves and mismatched automatics is a system where a fault spreads faster rather than being contained more reliably. 14 August showed exactly that: a single disturbance of about 600 MW reached four countries within minutes. As long as the money goes into generation and outward export rather than into resilience infrastructure — shared emergency reserves, modern adaptive grid protection and coordinated emergency automatics, a unified dispatch loop — cascades like this will recur. And it is telling that the operators' first statements were not an analysis of the shared vulnerability but a staking-out of their own boundary of responsibility: whose generation and whose line was at fault.

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  • 14 Aug 2026Tajikistan

    Tajikistan gives the green light to rooftop solar

    The state news agency Khovar reports that solar panels are being installed on a mass scale in Khatlon region — on residential buildings, industrial enterprises and other facilities. The report gives no specific figures, but the story reflects a shift in national policy toward residential and commercial solar generation. The regulatory framework was set by Government of Tajikistan Decree No. 449 of 1 Jul 2026 (announced by the Ministry of Energy and Water Resources). It introduced the category of "active consumer": a panel owner can sell surplus output to the single buyer or to a power supply company, with monthly settlement. For installations up to 15 kW, applications are reviewed within 10 working days, and connection is free where technical capacity allows. Tax breaks support the economics: imports and supply of panels, inverters and storage systems are exempt from VAT until 2031, and facilities with panels from 0.1 MW are exempt from property tax for five years. Khatlon is not a standalone pilot in this story. It is the country's largest region (about a third of the population) and its energy heartland: the Vakhsh HPP cascade supplies roughly three-quarters of the republic's generation. But the rooftop simplification is a nationwide measure, and the region is merely an illustration here. The scale of the plan is large: the 2026–2030 power sector development programme envisions about 1.5 GW of solar — roughly a quarter of the power system's current installed capacity (estimated at ~6.5 GW) — while a separate Roof Top project targets up to 2 GW, nearly a third of the system. So far, however, actual solar capacity is being built not on rooftops but as large plants — 250 MW each in Jayhun (Khatlon) and Asht (Sughd). How much a solar kilowatt-hour costs. Under koregen's transparent model estimate (capex of about $600 per kW turnkey, output of ~1,400 kWh per kW per year, a 25-year service life), a rooftop panel delivers a kilowatt-hour for about 2.2 cents — half the new retail tariff for households of 4.5 cents (41.37 diram), in effect since 1 Feb 2026. By comparison, the Dushanbe-2 coal-fired CHP plant costs 4.0–4.5 cents per kilowatt-hour on a full-cost basis, with coal alone accounting for about 2–3 cents. Rooftop solar lands in the same range as utility-scale plants, whose regional contracts are signed at 1.7–3.4 cents. Exempting equipment from VAT (14%) cuts only about 8% off capex: the break helps, but the economics are driven by kit price and output, not the tax. This is a model built on public assumptions, not an offer. Authorities are presenting solar plants as a response to the winter shortage. The problem is real: by a structural estimate, the republic falls short by roughly 2.2–2.5 bn kWh in winter, and from autumn 2025 to February 2026 supply limits were in effect in most regions. But rooftops do not close the winter gap directly — in December–January a panel produces half of what it does in summer; they help mainly indirectly, through the storage potential of HPP reservoirs: summer sun relieves the plants, and the water saved is released in winter. The Nurek reservoir's capacity for this is limited (a usable ~4.5 km³, a fifth of the Vakhsh's annual flow); it will be supplemented by the Rogun HPP upstream, with more than twice the usable volume (~10.3 km³) and deeper seasonal regulation — the plant is due to be completed by 2033 under the World Bank's plan, with the reservoir's full filling scheduled for 2039. The Green Economy Strategy targets 10% of the energy balance from non-hydro renewables by 2030.

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  • 12 Aug 2026Uzbekistan

    Uzbekistan explores tariff revision to shift demand to daytime—solar already crowds out gas

    The Ministry of Energy of Uzbekistan is exploring the possibility of revising electricity tariffs for large consumers, the ministry's press service said on 11 August. The ministry openly acknowledges that the current structure of differentiated (time-of-use) tariffs encourages some enterprises to shift production processes to nighttime, whereas the goal is the opposite — to encourage daytime consumption. To that end, it is considering changing the ratio of surcharge and discount coefficients to the base tariff depending on time of day. Specific parameters have not yet been determined and, as the ministry notes, may change following discussion; preparation of a draft government decree has not yet been reported. The ministry states the cause directly—rapid growth in solar generation. The classic nighttime electricity discount made sense as long as the system was underloaded at night and the peak occurred during the day; now more and more cheap solar power is flowing into the grid during the day, and it has become more advantageous to shift demand toward daylight hours rather than away from them. This is a reversal of the usual logic: the price of electricity falls during the day, and the tariff should follow. Solar power already displacing gas-fired generation is not a hypothesis but operational practice. According to reports, gas-fired power plants increasingly run at half capacity during the day, as the dispatch center cuts their output because of the sharply increased solar generation. Against the same backdrop, Deputy Prime Minister Jamshid Khodjaev said at an open dialogue between the government commission and entrepreneurs of Khorezm region on 5 August that, in the energy minister's place, he “would cut the use of gas and focus on solar energy.” The tariff signal, however, still works in the opposite direction—in favor of nighttime load. The scale of solar growth explains the urgency. By the end of July, Uzbekistan had commissioned about 5.6 GW of renewable capacity across 21 facilities, according to the Ministry of Energy, of which nearly 4 GW is solar (15 sites) and 1.67 GW is wind. The largest solar plants are Karaulbazar and Nishan at 500 MW each (China's Energy China / Gezhouba), Sherabad at 457 MW and Nur-Bukhara at 250 MW (the UAE's Masdar); overall, the country's solar-and-wind buildout is being driven mainly by three groups of investors—the UAE's Masdar, Saudi Arabia's ACWA Power, and Chinese power companies. Renewable generation output since the start of the year has exceeded 7 bn kWh—a milestone reached a month earlier than last year, up 23% year-on-year. One reading from the system operator shows how much this is already changing the daytime balance. At the daytime peak on 24 June 2026, at 3 p.m., renewable generation supplied 5,310 MW out of 11,728 MW of total output—45.3%; against power-system daytime consumption of 11,365 MW, that is nearly half of it. At the equivalent moment a year earlier, the share of renewables was 33.6%. At the same time, thermal plant output fell by about a gigawatt, and gas consumption dropped by hundreds of thousands of cubic meters over the interval. A caveat on composition: the 5,310 MW figure covers all renewable sources; the operator did not disclose a breakdown, and based on installed capacity this figure likely includes hydro generation as well (June is a high-water month). But it is solar that defines the daytime profile—the country has installed nearly 4 GW of it against 1.67 GW of wind, and it is growing fastest. Pressure will only build from here: by 2030 Uzbekistan aims to bring the share of renewables in generation to more than half (the stated target is 54%), with thousands of megawatts of new solar in the pipeline, including ACWA Power's 1,000 MW plant near Samarkand. How much the tariff alone can solve the problem is a question global experience answers cautiously. A review of about 80 pilots and hundreds of tariff experiments across four continents (the Arcturus database, Brattle Group) shows that a simple time-of-use tariff with a moderate price gap shifts roughly 5–10% of load, while mass “default” enrollment of consumers shifts only 3–4%; responses in the tens of percent are typically achieved only with a large price gap and automated load control. Elasticity among households is low — a 1% increase in the price gap shifts consumption by about 0.2%. In industry, flexibility is concentrated in a narrow segment: by one estimate, about 5% of enterprises account for almost all of the response—interruptible processes such as pumps and irrigation shift easily, while continuous production, from cement to full-cycle metallurgy, cannot move its load. The closest analogue to Uzbekistan's plan is the “solar sponge” in South Australia, where daytime hours have been priced at a quarter of the normal grid tariff since 2020; and from July 2026, authorities required retailers in several states to offer a plan with three free daytime hours. The lesson from practice: a tariff is a necessary price signal, but without interval metering, automated response, and storage, it moves single-digit percentages of load rather than shifting demand into the solar hours. The first response to the daytime surplus is storage. Near Tashkent, ACWA Power has been operating a 334 MW / 500 MWh storage system since February, and Masdar and ACWA both have battery plants of thousands of megawatt-hours in the pipeline. A tariff that pulls demand toward solar hours and batteries that shift the solar power itself into the evening are two sides of the same task: finding a use for daytime energy that has become too abundant for the old consumption profile. Time-of-use tariffs alone are unlikely to be enough to seriously address the problem. Global practice suggests that no more than 2–5% of ordinary demand turns out to be price-elastic. A broader range of measures will be needed — tariffs, demand response, automated control — and, of course, storage.

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  • 11 Aug 2026Kazakhstan

    Kazakhstan builds out the framework for Article 6 of the Paris Agreement—and bets on forestry removals projects

    Kazakhstan continues to build out the regulatory base for the carbon market and Article 6 of the Paris Agreement—and it is doing so not with a single document, but in layers. The trigger was an order of the Minister of Ecology and Natural Resources dated 27 Jul 2026, which took effect on 10 Aug: it amends the Rules on state regulation of greenhouse gas emissions and removals (the base order No. 91 of 2022)—it introduces a state registry of carbon units, sets out new definitions—from project validation and verification to authorization and the state registry of carbon units—and expert-review deadlines under Article 6. According to zakon.kz, this order is the first to insert a separate chapter on Article 6 market mechanisms into the rules; the consolidated text in state databases had yet to catch up at publication time, so the chapter's details are given per the secondary source. The order is only the top, operational layer. Beneath it lies framework law No. 340 of 8 Jul 2026, “On Amendments and Additions to Certain Legislative Acts on Environmental Issues,” which for the first time introduced “Article 6 of the Paris Agreement market mechanisms” directly into legislation. Tellingly, the law anchored this not in the Ecological Code but in the Forest Code: its Article 9-1 now provides that part of the greenhouse gas removal from projects on state forest fund land, implemented through the Paris Agreement market mechanism, counts toward fulfillment of the country's nationally determined contribution (NDC). The Ecological Code itself operates with more general concepts: Article 299 defines a carbon unit as a commodity (1 tonne of CO₂ equivalent), describes the carbon market and exchange trading, and reduces international circulation to “international treaties.” Neither the code nor the law contains the term “international transfer of mitigation outcomes” (ITMO) or “corresponding adjustments”—the law delegated Article 6 mechanics to implementing regulations. Kazakhstan currently has no active bilateral carbon unit transfer deals: the country is at the stage of preparing its own Article 6.2 framework (national consultations were held in Astana in October 2023 with UNDP support). Taken together, this forms a three-tier structure: the Ecological Code sets the framework (carbon budget, quotas, registry), law No. 340 adds the Article 6 anchor and the rule for crediting removals toward the NDC, and the July order operationalizes the registry and verification. For the sector this is part of a broader system: the carbon quota threshold is 20,000 tonnes of CO₂ per year, covering electricity generation, oil and gas, mining and metallurgy, chemicals, and building materials production; the national carbon budget for 2026–2030 sets a declining trajectory from 373.9 mn tonnes in 2026 to 327.6 mn tonnes of CO₂ by 2030. All of this serves Kazakhstan's climate target: under the contribution updated at the end of 2025 (NDC 3.0), it is stated as a 17% unconditional emissions cut and up to 25% with external support by 2035 versus the 1990 level (the previous target, through 2030, was minus 15% and up to 25%). One thing in this structure deserves particular attention: where the focus has shifted—toward removals projects, chiefly forestry ones. In global practice, forestry projects remain the class of carbon units facing the most integrity questions. A study led by Y. Tang (Tang et al.), published in the journal Science in October 2025, compared 52 tropical forest protection (REDD+) projects in 12 countries against similar territories without such projects and found that only about a fifth of them met their stated emissions-reduction targets, while only around 13% of credits actually issued were backed by real reductions in deforestation—the rest reflected over-crediting. A May 2025 sector review by the Clean Air Task Force assessed two dozen forestry protocols and concluded that most are still too weak to guarantee credit quality, even though forestry projects account for about 40% of the global voluntary market. The best-known precedent is the 2023 investigation by the Guardian, Die Zeit and SourceMaterial, which found that more than 90% of the tropical forest offsets from Verra, the largest certifier, were effectively worthless (that investigation concerned primarily deforestation-avoidance projects). The key technical vulnerability of forest removals is reversibility: fire, a pest outbreak or logging returns carbon to the atmosphere, zeroing out the previously credited effect. The market addresses this with buffer accounts: a share of issued credits is not sold but placed into a shared insurance pool, and if removals are lost, an equivalent number of credits from the pool is cancelled without touching units already sold (this is how the buffer reserves of Verra, ART/TREES and Gold Standard work). The same principle is built into the methodology for Article 6.4 of the Paris Agreement: its standard for carbon removal projects requires minimizing reversal risk and fully “remediating” any loss, creates a separate buffer account in the mechanism's registry against reversal risk, and requires stress-testing its resilience at least once every three years. An open question is whether this buffer is sufficient: given the systematic over-crediting documented by the 2025 studies and increasingly frequent forest fires, the insurance pool may turn out to be undersized; this is a matter for fine-tuning the rules, not the absence of a mechanism as such. For Kazakhstan, reversal risk is not theoretical. The survival rate of young plantings under the reforestation campaign holds at around 50%, against a norm above 60%—roughly every other tree fails to take root. And in 2023 a major fire burned through the Semey Ormany reserve in the Abai region—a state forest reserve protecting the pine forests of the Irtysh basin: the burned area exceeded 60,000 ha. Carbon that the forest absorbed and that was credited toward the national target is returned to the atmosphere by fire or logging.

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  • 11 Aug 2026Uzbekistanevent: 10 Aug 2026

    Uzbekistan discloses wholesale generation and network tariffs for the first time — a step toward RAB

    The Interagency Tariff Commission under the Cabinet of Ministers of Uzbekistan has approved regulated electricity tariffs separately for each link in the chain — generation, transmission, distribution and supply. The decision was formalised in Protocol No. 37 dated 15 Jul 2026 (signed by Deputy Prime Minister and Minister of Economy and Finance Jamshid Kuchkarov) and takes effect from 1 August. Previously, the rates for individual links were not published as a single document — now they have been disclosed together for the first time, including transmission and regional networks. An important caveat: the changes concern only wholesale settlements between regulated enterprises — retail prices for households are not being revised. The disclosed structure shows how widely the cost of electricity varies by source. The spread across generation is more than twofold: electricity from Uzbekgidroenergo's HPPs is the cheapest, while old thermal power plants (the gas-fired Tashkent and Takhiatash plants, and the coal-fired Angren plant) are the most expensive. These are individual tariffs by plant, not a single rate. Separately disclosed are the transmission fee across the national grid, the distribution fee by region, and the prices charged by the single buyer that sells electricity to Energosavdo. Transmission itself costs about 0.8 ¢/kWh — comparable to Kazakhstan's KEGOC (~0.7 ¢ after VAT) and Russia's FSK, and several times cheaper than in mature European grids (Britain's TNUoS is around 2.4 ¢/kWh). The reason is not efficiency but a weak currency and regulated, underinvested transmission networks, which account for only a small share of the final price. The disclosure itself fits into a broader reform that the authorities announced back in May — the shift to tariff-setting under the RAB (regulatory asset base) methodology. There is no direct link between the July protocol and RAB: the protocol merely approves rates following the rise in fuel prices and does not mention the RAB methodology — that is a separate, previously announced course. But it is within that logic that separate tariffs make sense. Under RAB, the tariff is calculated not from actual costs incurred but from the value of a company's assets — networks, substations, plants — multiplied by an allowed return on capital, plus depreciation and operating expenses. The idea is to guarantee investors a return on infrastructure investment, make projects bankable, and lock in the tariff for several years ahead. Under the parameters announced in May, the rate of return is set at a post-tax WACC of 14–16% (nominal, in sum), with full RAB implementation planned for 2027–2028. We see the tariff disclosure and the shift to RAB as a good step for attracting investment: a transparent price by link and a clear return on capital are what any private investor in generation and networks needs. But the RAB methodology is not an autopilot. For it to truly take hold, three things are needed: regulatory consistency, regulator independence, and long-term tariffs. The regulator — the Energy Market Development and Regulation Agency (EMDRA) — was only created in 2023 and does not yet have a track record of honouring its own commitments, and the first regulatory period is set at just one year (with a plan to extend it to five years in the future). Global experience on this point is unambiguous: RAB works reliably where the regulator is trusted and tariffs are held for the full period (Britain, Italy), and stalls where the asset base and return are revised retroactively under political pressure (a telling example is Spain: after retroactively revising renewables support, it lost a series of international arbitrations to investors). One separate nuance is the return itself: 14–16% looks generous, and it is a nominal rate in sum, but with inflation of around 6–7% (6.4% in June 2026), the real return works out to about 7–9%. For network regulation that is generous — in Britain and Italy the allowed real return is about half that. Such a rate will feed into the tariff, and holding it year after year against political pressure will not be easy. So the tariff disclosure is the right signal to the market, but the real test of the new system will begin not now, but when the tariff has to be held against unfavourable conditions.

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  • 5 Aug 2026Uzbekistan

    Uzbekistan allows private business to supply LPG to households

    The Ministry of Energy of Uzbekistan has formed an interagency expert working group to reform the system of household liquefied gas (LPG) supply and phase in market mechanisms in this area. The move follows directly from instructions given by the head of state at a meeting chaired by President Shavkat Mirziyoyev on 27 July. The group is working on three tracks at once: the LPG supply reform itself, improving the mechanisms for benefits and discounts in electricity tariffs, and simplifying mandatory advance payment for natural gas for entrepreneurs. It has been tasked with preparing proposals and draft regulations. How the system works now. About 3.7mn households use bottled LPG (the standard format is a 20-kilogram cylinder); the state sector handles supply. Despite digitalization of the supply system, delivery disruptions persist: in the pilot Andijan region, 41,000 tonnes were delivered in H1 2026 versus a planned 48,000, and demand remained only partially covered in 318 mahallas (communities). What is changing. Entrepreneurs will be allowed to supply households and businesses with gas they have imported themselves or purchased on exchange trading. The model will be piloted first in Andijan region. The private sector has already imported 157,000 tonnes of LPG into the country since the start of the year. Within a month, the authorities promise to revise the system of gas transportation, storage and distribution in line with international standards and to work out cylinder formats other than the standard 20-kilogram one. State subsidies for gas purchases will be retained for low-income families in the social registry. Why. The reform is unfolding against a backdrop of a physical gas shortage: domestic production is falling (−16% over the half-year, to 18.3 bcm), pipeline gas is retreating from small settlements, and imports are rising — in June, gas purchases reached $247mn, the highest since the start of the year. Separately, over three months the authorities will calculate the necessary electricity network infrastructure and additional electricity volume, as well as a financing program, to switch 1,916 mahallas where pipeline gas supply is difficult to electric heating — which will add load to the electricity network. LPG production, meanwhile, is planned to be increased to 606,000 tonnes by year-end, up from the previous plan of 520,000. What stands out to us is that it is precisely a physical shortage — of both natural gas and the LPG made from it — that is pushing the authorities toward market mechanisms. When domestic production stops being enough and pipeline gas retreats from small towns, holding on to the old distribution logic for bottled gas becomes both costlier and harder. That is why this looks less like a one-off measure than a pivot: opening the door to private imports, an exchange, targeted subsidies instead of universal ones. Our reading is simple: shortage is acting here as a reformer — it is forcing the state into active steps, market ones included, that in flusher years it would have approached far more cautiously.

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  • 3 Aug 2026Uzbekistanevent: 1 Aug 2026

    Uzbekistan's gas production in structural decline: the country has become a net gas importer — fueling the power crisis

    Natural gas production in Uzbekistan has long been below its former peaks, and the decline accelerated in 2026. According to the National Statistics Committee, annual output fell from about 60 bcm at its 2018 peak to 41–42 bcm in 2024–2025 — a drop of nearly a third. The statistics have also been recently revised: in January 2026 the National Statistics Committee cut its estimate of 2024 production from 44.6 to 41.3 bcm, and put 2025 output at 42.3 bcm — meaning year-on-year production barely changed. The decline accelerated in 2026: the first quarter was down 15% year-on-year, March was down 30.8%, and April was down 18.8%; for January–April, production fell by about 16%. Daily production, according to the energy minister, fell from 125.8 to 87.1 mcm year-on-year in March. Authorities have named the cause directly. Minister of Energy Jurabek Mirzamakhmudov said back in May that the decline was linked to the natural depletion of old fields — Shurtan and fields in the Bukhara-Khiva and Kashkadarya regions, which he estimated to be 85–90% depleted. In other words, this is not an accident or a one-off repair, but a long-term geological trend. Uzbekistan generates about 65–70% of its electricity by burning gas, so the decline in domestic production is hitting generation costs and reliability over the medium term. However, gas is not cited as the direct cause of this summer's widespread outages. Since early summer 2026, thousands of faults have been recorded in distribution networks, and outages on some days lasted 8–10 hours, but authorities attribute them to network wear, abnormal heat, and the fact that consumption has grown faster than generation over the past decade (5.0% versus 4.4% per year). President Mirziyoyev stated directly that the problem is not money — $23bn has been invested in the sector — but the quality of system management. The gas decline and the grid crisis are two related but distinct problems within one overloaded system. In terms of foreign trade, Uzbekistan has long become a net gas importer. In H1 2026, natural gas imports rose 41% to about $1bn, while exports contracted more than 1.5-fold, to $233mn. The shortfall is being covered mainly by supplies from Russia: the physical volume of Russian pipeline gas came to about 6.5 bcm in 2025, and in 2026 it could exceed 10 bcm, according to estimates. The government's response is focused on production. Uzbekneftegaz has established a national drilling company, UNG Burg'ilash, with 21 drilling rigs capable of reaching depths of up to 9,000 metres; deliveries are to begin in October 2026, with work concentrated primarily on the Ustyurt plateau. British BP has also moved into the area, taking a 40% stake in six blocks of the Ustyurt project, with the first exploration well planned for 2027. The bet is that new Ustyurt fields will partially offset the declining output of the older ones. Against this backdrop, tariffs are also being revised: electricity has become almost 10% more expensive since June, and an analytical institute under the Ministry of Economy and Finance has proposed raising the tariff for above-norm heating several-fold (this is a proposal, not an adopted decision). The gas decline has turned from a line in industry statistics into a node that ties the power crisis, rising imports, and tariff policy into a single story.

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  • 31 Jul 2026Uzbekistanevent: 30 Jul 2026

    Uzbekistan has proposed a carbon tax from 2028—aimed less at climate than at CBAM and the budget

    On 30 Jul 2026, an analytical body under the Ministry of Economy and Finance of Uzbekistan presented a proposal to introduce a carbon tax in the country for the first time, targeting large industrial enterprises. To be clear from the outset: this is a concept still under discussion, not an adopted decision—there is no draft law or amendment to the Tax Code yet. In substance, only the timeline has been disclosed: 2027 is the preparatory year (an emissions inventory, defining the tax base and rates), 2028 sees the tax introduced, and 2029–2030 brings a phased increase in rates. The rate itself has not been named; the tax base under consideration is either the volume of CO2 emissions or the volume of hydrocarbon fuel consumption; coverage is large industrial enterprises, but without specific thresholds. Expected revenue and the effect on prices have not been publicly estimated. The initiative comes from a specialized institute under the Ministry of Economy and Finance (its full name includes both “fiscal analysis” and “improving tax administration”—hence the different abbreviations used in publications). For Uzbekistan, this is a qualitatively new step. Until now, the country has approached carbon through the logic of exporting climate achievements: the World Bank's iCRAFT project (payments for emission reductions from fuel subsidy reform—the first tranche of $7.5 mn for 0.5 mn tonnes in 2024, with the whole program designed for roughly 60 mn tonnes through 2027), the trade in carbon units under Article 6 of the Paris Agreement legalized by a presidential decree in July 2025 (up to 80% of units may be sold abroad), and agreements with Japan and Korea. A carbon tax would be the first domestic price on emissions for the country's own industry—that is, a fiscal instrument, not a way to sell reductions abroad. Among the stated goals is reducing the risk of paying carbon charges abroad, which primarily means the EU's CBAM. The EU carbon border adjustment mechanism (CBAM) took effect on 1 Jan 2026 and covers imports of cement, ferrous metals, aluminum, fertilizers, electricity and hydrogen. The payment is calculated on embedded emissions net of the carbon price already paid in the country of origin. The logic follows directly: if Uzbekistan taxes carbon domestically, that money stays in its own budget rather than flowing into the EU budget as a CBAM charge. At the same time, Uzbekistan's actual exposure to CBAM remains narrow. Cement is shipped mainly to Afghanistan and neighboring Central Asian countries rather than the EU; electricity and hydrogen are not exported to Europe; the country has essentially no primary aluminum production of its own. The one genuinely vulnerable sector is nitrogen fertilizers: their exports totaled around $240 mn in 2023 (mostly urea and ammonium nitrate), and according to trade statistics, roughly 9–19% of that volume ends up in the EU one way or another—in Romania and Bulgaria, as well as via Baltic ports, where part of it may be transit rather than final consumption. The largest producers are the state-owned Navoiazot and Maxam-Chirchiq, controlled by the Spanish group MAXAM. But nitrogen fertilizers also account for only about 1% of Uzbekistan's total exports, so at the level of the economy as a whole, the World Bank does not classify the country as heavily exposed to CBAM. For comparison, neighboring Kazakhstan introduced an emissions trading system back in 2013, one of the first in Asia, but the carbon price there remains nominal, at around $1 per tonne against nearly $90 in the EU system. Uzbekistan is entering regulation later and through a simpler instrument—a tax rather than a quota market—but so far without a rate.

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  • 29 Jul 2026Tajikistanevent: 28 Jul 2026

    Tajikistan builds up solar: 4–5 GW of proposed projects, cheap power and a boost for HPPs — but it all comes down to one barrier, financial

    Almost all of Tajikistan's generation — about 98% — comes from HPPs. Over the past three years, the country has assembled a pipeline of proposed solar projects with a combined capacity of roughly 4–5 GW. Solar power benefits it in two ways at once — as cheap energy and as a means of conserving water in HPP reservoirs. But it all comes down to one barrier, and it is financial. The latest occasion: on 28 Jul 2026 the Ministry of Energy and Water Resources discussed the construction of another 200 MW plant with China's China Energy; the parties confirmed their readiness to continue cooperation. This is talks, not the start of construction — and there have been many such statements over the past year and a half, with little actually built. Solar is entering the market via two routes. The first is a competitive tender run with IFC (World Bank Group) as transaction adviser — so far one, for 200 MW in Sughd region: a public procedure, with a named buyer — the state operator Barqi Tojik — under a power purchase agreement, and competition among bidders pushes the price down; the January 2025 shortlist included Saudi Arabia's ACWA Power, France's EDF and a Chinese-Tajik joint venture. The second is direct agreements, including through free economic zones with Chinese companies (Pingmei Shenma at 1,000 MW, Eging PV at 200 MW with expansion to 2,000 MW), plus the national distributed Ruftob programme (up to 2,000 MW by 2030): without a tender and with an undisclosed buyer. The whole difference comes down to the buyer. Barqi Tojik has no credit rating of its own, and its ceiling is Tajikistan's sovereign rating: speculative-grade (B from S&P; Moody's upgraded it to B2 in March 2026, for the first time), still five notches below investment grade. The company's accumulated losses exceed 31 bn somoni (TJS) (per audited 2023 financial statements published by the World Bank), its overdue debt is estimated by the IMF at about 8.2% of the country's GDP and could fall on the budget, the tariff covers less than half of cost, and the largest consumer — aluminium producer TALCO — buys power at a preferential rate. For a twenty-year power purchase agreement with such a buyer, lenders demand sovereign guarantees, payment mechanisms and currency-convertibility guarantees — and assembling that package drags on for years. The company itself said in the summer of 2026 that its debts were gradually declining, but under the World Bank programme it is not expected to break even until 2027. That is exactly why the transparent tender matters. Announced in October 2024, it reached the shortlist stage by January 2025 — and has been stuck there ever since: no winner has been named in a year and a half. No reason has been given publicly, but it can be read from the buyer's finances — as long as Barqi Tojik is not creditworthy, a bankable contract cannot be put together. The projects that are actually being built simply sidestep this problem. Two Ayon Energy plants totaling 500 MW (250 MW each, in Asht district and in Jayhun, commissioning by the end of 2026) are proceeding not through a tender but under a direct investment agreement following presidential directives; no power purchase agreement with Barqi Tojik is mentioned in reports at all, nor are the financing scheme or the investor's own beneficiaries disclosed. The Chinese projects in the zones and the distributed Ruftob programme are designed primarily for self-consumption: the solar power feeds the zone's own industry or enterprises' rooftops rather than flowing under a long-term contract to the state operator — and the payment risk of a weak Barqi Tojik drops out of the equation. The state supports them not with money or guarantees but with tax holidays: Ruftob gets five years without profit tax, zero VAT and customs duties. In other words, these projects do not solve the buyer's weakness — they bypass it. At the national scale, this pipeline is not trivial: at the roughly 20% solar capacity factor typical of southern Tajikistan, 4–5 GW would generate about 7–9 bn kWh a year — around a third of the country's current output of roughly 22 bn kWh (koregen estimate). The physics deserves separate discussion — how solar coexists with the hydro system, since it is the HPPs that must balance it. Here Tajikistan has a rare advantage: reservoir hydropower is an almost ideal intraday partner for solar. Nurek HPP, with its seasonal reservoir, can hold back water and unload turbines during the day while the sun is shining, then release the stored water in the evening; shifting water from midday to evening does not disrupt irrigation releases, because irrigation is accounted for in daily-to-weekly volumes rather than at a specific release hour. But the manoeuvre has a physical floor: the minimum summer flow for irrigation holds around a gigawatt of an “irreducible” minimum, and the cascade's lower run-of-river plants (Baipaza, Sangtuda) cannot manoeuvre at all. According to koregen's estimate, without storage the system can absorb about 3 GW of solar — which, incidentally, roughly matches the national target for renewables commissioning (about 3,000 MW of solar and wind by 2030). Above that level, summer daytime output would significantly exceed the country's own load and would be lost — at least until major export corridors such as CASA-1000 appear.

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  • 28 Jul 2026Uzbekistanevent: 27 Jul 2026

    Uzbekistan: shake-up in the energy sector — minister and head of the distribution grid operator dismissed, stress audit announced; CCGT site error in Surkhandarya region to cost another ~$300mn

    On 27 Jul 2026, Uzbekistan's President Shavkat Mirziyoyev held a meeting on the fuel and energy sector that turned into a wave of dismissals and a decision to conduct a comprehensive audit of the industry. The minister of energy, Jurabek Mirzamakhmudov, who had headed the ministry since September 2022, and the head of the state-owned Regional Electric Networks (REN) JSC — the distribution company responsible for delivering electricity to end users — were dismissed. Sherzod Khodjaev was appointed the new minister of energy; he had previously headed the Energy Market Development and Regulation Agency, meaning he came from the sector's tariff regulator, and before that served as deputy minister of energy (2019–2023) and headed the ministry's renewable energy project office. The new minister's appointment was approved by the lower house of parliament. Sardor Isakulov was appointed the new head of REN, and Akhadkhon Isokjonov was appointed head of the energy inspectorate. The heads of four more entities — National Electric Networks, Thermal Power Plants JSC, Uztransgaz and Hududgaztaminot — were given a probationary period until the end of the year. According to Uzbek media accounts of the meeting, the president listed grievances over the state of the grid: about 4,000 outages nationwide in Jun–Jul (some local breakdowns, for instance for Yangiyul district, show lower figures for a different period), power cuts of up to 8–10 hours, an overall loss rate of 17.2% — about 4.8 bn kWh in H1 — and more than 25% in some districts. Around 300,000 gas meters and 234,000 electricity meters are not transmitting data, which directly hurts bill collection. A separate point concerned an error in siting generation capacity. A 1,560 MW CCGT power plant in Angor district, Surkhandarya region — a private project worth about $1.2bn involving Qatar's Nebras Power, Siemens Energy, the Netherlands' Stone City Energy and France's EDF, with financing from the Asian Infrastructure Investment Bank — was built without access to gas infrastructure. To supply the plant with fuel, a separate gas pipeline has to be laid to it, which, according to media accounts, requires an additional $300mn or so. The plant has not yet been launched: the groundbreaking took place in March 2022, and commissioning is expected in 2027. There is no public record of an open tender for the project or the site — the plant came through an investment agreement (2021), i.e. under a negotiated rather than an auction model; the meeting noted that the terms of the plant's contract had not been carefully studied. The response included not only the dismissals but also a decision to conduct a comprehensive audit: the Ministry of Energy plans to set up a Center for Digitalization of the Fuel and Energy Sector and AI Implementation, which will review the entire chain — production, transmission, distribution and delivery of fuel and electricity to consumers — and prepare several scenarios for the sector's development based on the findings. The experience of Yangiyul district, used as a pilot, is to be rolled out nationwide; a separate program is to be developed to cut electricity and gas losses by half, and the pilot's measures are to be completed by 1 Oct. The framing the president gave the problem is telling. According to him, the sector has attracted $23bn in foreign investment over the years and 9.5 GW of capacity has been commissioned, with 30tn sum (UZS) allocated to grid modernization — yet the system keeps failing. The conclusion he drew: the problem in the energy sector is not financing but the management system.

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  • 27 Jul 2026Uzbekistanevent: 26 Jul 2026

    Uzbekistan switches the Jizzakh NPP to dry cooling: the site was picked in 2019 for its lake water, but the lake couldn't deliver

    Uzbekistan's nuclear project in Jizzakh region is switching to a cooling system that does not consume water — a reversal from how the site was originally selected. On 22–23 July 2026, a delegation from the Uzatom agency held talks in Moscow. With Rosatom (including Dmitry Volkov, director for capital construction), the parties agreed to set up a joint working group to coordinate the review of the plant's design documentation. On a separate track with the Hungarian company MVM EGI Zrt, they “identified further steps for building dry cooling towers” — an air-cooling system that does not draw water from an external source. The site was selected in May 2019 (announced on 31 May): a government working commission, together with Uzatom's scientific and technical council, named the site near Lake Tuzkan in the Aydar-Arnasay lake system as the priority location. The project at the time called for two Generation III+ units with VVER-1200 reactors, with cooling water to be drawn from the lake. The logic was straightforward: site the plant next to water. Water at the chosen site did not work out. Lake Tuzkan is endorheic, saline and prone to drying up; in March 2025, Uzatom head Azim Akhmedkhadjaev stated directly that Tuzkan would not be used to cool the plant. Adding to the picture, the Aydar-Arnasay system is classified as a wetland of international importance under the Ramsar Convention, and the site itself lies about 40 km from the border with Kazakhstan, which at the time prompted questions from the Kazakh side about cross-border impact. The idea of dry cooling towers instead of water cooling was first raised publicly in late 2023 and is now being formalized through MVM EGI. MVM EGI is a Hungarian engineering company (founded in 1948, part of the state-owned MVM holding group) that specializes in dry — air-based — cooling systems for power plants. It is not the reactor vendor or the plant's general contractor: its role is to supply dry cooling towers with mechanical draft. A memorandum was signed in May 2025, and a protocol followed on 15 July 2025 (signed by Uzatom, Hungary's Ministry of Foreign Affairs and Ministry of Foreign Trade, and MVM EGI itself); the parties also stated plans to set up a joint venture in Uzbekistan for large-unit assembly of such cooling towers. The company links its dry-cooling approach to projects in water-scarce areas. Since 2018, the project's configuration has changed more than once: an intergovernmental agreement on two VVER-1200 units (about 2.4 GW) has effectively stalled; in May 2024, a contract was signed for a small-capacity plant using RITM-200N reactors; by autumn 2025, the project had been reconfigured into a hybrid of large VVER-1000 units and small RITM-200N units — roughly 2.1 GW in total, at an estimated cost of about $9.5 bn. The customer is Uzatom, and the general contractor is Rosatom (through its engineering division, Atomstroyexport). A license to build the first unit (with a RITM-200N reactor) was issued in June 2026. Formally, the plant is under construction: in 2026, “first concrete” ceremonies were held twice, in March and June. At the same time, the 22–23 July talks show the parties are only now setting up the review of design documentation. The first small RITM-200N unit is provisionally expected to be commissioned by 2029, and the full complex by the mid-2030s.

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  • 23 Jul 2026Kazakhstanevent: 22 Jul 2026

    Kazakhstan: 300 MW from Ekibastuz GRES-1 allocated to strategic digital mining programme for ten years — the price is 10% of output to the national crypto reserve

    The government of Kazakhstan has approved the Rules for Strategic Digital Mining under Decree No. 638 of 18 Jul 2026, signed by Prime Minister Olzhas Bektenov. The document takes effect on 1 Aug 2026. Behind the neutral title lies not a technical industry regulation but a deal between the state and large miners, with electricity as its subject. **Mechanism.** A quota of 300 MW has been allocated for the programme. Participants gain the right to sign direct power purchase agreements for ten years at a price not exceeding the cap tariff of the power-generating company: for Ekibastuz GRES-1 it stands at 9.50 tenge (KZT) per kWh — about two cents. On the energy side, one company takes part at the launch of the programme — Ekibastuz GRES-1 LLP, a wholly owned subsidiary of Samruk-Energo JSC. For comparison, the cap tariff of the neighbouring Ekibastuz GRES-2 is 15.67 tenge (KZT) per kWh. The counter-obligation is not a tariff but a share of output. No later than the 25th day of the month following the reporting month, the miner transfers 10% of the digital assets remaining after deducting the cost of electricity and the expenses of its supply, to the wallets of the Astana Hub autonomous cluster fund. From there the assets go into trust management by the National Investment Corporation, a subsidiary of the National Bank of Kazakhstan, and replenish the National Strategic Crypto Reserve. The National Bank reported work on such a reserve in September 2025; $350 mn from gold and foreign exchange assets was allocated for its launch. **Who can take part.** The requirements rule out everyone except large operators: a data centre with a capacity of at least 150 MW held in ownership, technical specifications for connection to grids of 35 kV and above, computing equipment rated at 150 TH/s or more per unit, two contracts with telecom operators, a service centre on the data centre premises with qualified personnel, no tax arrears and no encumbrances on property. The 150 TH/s threshold per unit of equipment is a characteristic of specialised ASIC devices built for the SHA-256 algorithm — that is, for bitcoin mining; general-purpose computing hardware cannot reach such figures per unit. Combined with the requirement for a dedicated 150 MW data centre, this means the rules are written not for the industry in general but for large-scale industrial bitcoin mining. An annual independent audit is required, with a report due no later than 1 Apr; if a shortfall is found, the miner is given 30 calendar days to transfer the balance, and if material contract terms are not met, the commission may decide to terminate participation early. **Status of the document.** The decree has been published in the Paragraf information system and takes effect on 1 Aug 2026. The Rules refer back to the underlying Decree No. 439 “On Certain Issues of the Digital Assets Industry” of 28 May 2026, which is marked “for official use only”; the specific parameters of the programme — the size of the quota, the tariff terms, the share of contributions — are not disclosed in the open part of the text and are known from media analyses of the document. At the time this article was prepared, the text was not available in the Adilet legal information system or in the list of decrees on the government's website. **Scale.** The installed capacity of Ekibastuz GRES-1 is 4,000 MW. A 300 MW quota, given the round-the-clock load typical of mining, corresponds to roughly 2% of Kazakhstan's annual electricity consumption, which stood at 124.6 bn kWh in 2025 (koregen estimate). For comparison, the Ministry of Energy of Kazakhstan forecasts a 1.4 bn kWh shortfall for 2026, with a 1.3 bn kWh surplus expected from 2027. **Background.** In 2021, at the peak of the miner influx, their consumption reached 693 MW through the legal channel, with a further 250–450 MW estimated to fall in the grey zone; the sharp rise in load coincided with rolling outages. According to the Cambridge Centre for Alternative Finance, in August 2021 Kazakhstan ranked second in the world by share of bitcoin hashrate, at 18.1%. After licensing and restrictions were introduced, the share fell to roughly 4% by 2026; according to media reports, 84 licensed mining farms operate in the country. The digital mining fee is set under Article 606-3 of the Tax Code and is tied to the price of electricity — from 1 to 25 tenge (KZT) per kWh, higher the cheaper the kilowatt-hour. Kazakhstan operates a single buyer model for electricity. The Wholesale Market Rules, as amended by the ministry's order of 23 Feb 2026, restrict the sale of electricity to digital miners to cases expressly stipulated by law; at the same time, the general procedure for daily prepayment no later than 08:00 Astana time does not apply to entities engaged in digital mining.

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  • 22 Jul 2026Uzbekistanevent: 16 Jul 2026

    Uzbekistan: Fitch affirms rating of state distribution company Regional Electric Networks (REN) at sovereign level ‘BB’—but scores standalone credit profile at ‘ccc’. President demands cuts to power losses

    Following the 2019 reform that split up Uzbekenergo, electricity distribution and sales to end users have been handled by state-owned JSC Regional Electric Networks (REN). On 16 July Fitch affirmed REN's long-term rating at BB with a positive outlook—in line with Uzbekistan's sovereign rating, as over 90% of the company's debt is backed by state guarantees. Fitch assesses REN's own credit profile at just ‘ccc’: tariffs do not cover costs, regulation lacks transparency, and liquidity is weak (about $50 mn in cash against $190 mn in short-term debt). Equity turned negative in 2025 after the free-of-charge transfer of high-voltage assets to the transmission network operator—National Electric Networks (NEN). REN draws on funding from international development banks: a $200 mn loan from the Asian Development Bank (ADB) (2023) for digitalizing distribution networks, and a $100 mn concessional loan from the World Bank (2025) for renewables integration and supply reliability. Credit rating is a material factor for access to such financing and its cost, and REN's rating rests on state support: Fitch warns the rating would fall two notches below sovereign if the share of state-guaranteed debt drops below 75%. Fitch names the following conditions for improvement: a shift to cost-reflective tariffs, lower losses and stronger governance. In June 2026 household tariffs were already raised by 8–13%—above annual inflation (6.4% in June against the central bank's 6.5% forecast); Fitch expects tariffs to grow in line with inflation in 2027–2028. On 21 July, a meeting chaired by President Shavkat Mirziyoyev cited loss figures and criticized insufficient progress in cutting them. Losses in H1 2026 stood at 17.2% of electricity (about 4.8 bn kWh). REN is among the strategic state companies the government is preparing to bring to the stock market for investment: the privatization program envisages IPOs and SPOs for major enterprises, and the company's own credit rating is just as key an element of access to capital as it is via development banks.

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  • 21 Jul 2026Turkmenistanevent: 19 Jul 2026

    Turkmenistan: interagency commission on climate and Ashgabat Climate Dialogue platform approved

    At a Cabinet of Ministers meeting on 18 July, Deputy Prime Minister and Foreign Minister Rashid Meredov presented proposals on the climate agenda; President Serdar Berdimuhamedov approved them and ordered their implementation. An interagency commission is being set up to negotiate with foreign countries, international organizations and financial institutions and to coordinate the creation of regional centers. Expanded cooperation with UN agencies, the Green Climate Fund (GCF), the Global Environment Facility (GEF), the Adaptation Fund, the World Bank and the Asian Development Bank (ADB) was announced. The initiatives include a permanent platform, the Ashgabat Climate Dialogue, a Regional Center for Climate Technologies in Central Asia, and a Regional Center for Combating Desertification. The timeline for setting up the commission, its budget and the regulation establishing it were not disclosed; the announcement contains no commitments on funding volumes.

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  • 21 Jul 2026Kazakhstanevent: 20 Jul 2026

    Kazakhstan: the Ministry of Energy and the EBRD discuss institutionalizing JETP — platform mechanisms proposed for enshrinement in regulations

    On 20 July, Deputy Minister of Energy Bakytzhan Ilyas met with an EBRD delegation: Director of the Climate Strategy and Delivery Department Felicity Spors, EBRD Deputy Head for Kazakhstan Yerlan Ramazanov, and Deputy Director of the department Cristian Carraretto. Discussions covered the formation of the Just Energy Transition Partnership (JETP) project portfolio, mechanisms for engagement with international partners, and the institutional strengthening of the initiative. The Ministry of Energy of Kazakhstan considers it necessary to enshrine the platform's operating mechanisms in regulations and to establish transparent rules for participant engagement; the EBRD expressed readiness to provide expert support in their development. JETP for Kazakhstan was announced by President Tokayev at the UN General Assembly; the ministry, the Ministry of Ecology and the EBRD had earlier signed a memorandum on establishing the QaJET country investment platform for the energy transition. The composition of the project portfolio, funding volumes, and the timeline for enshrining the mechanisms in regulations have not been disclosed.

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  • 20 Jul 2026Kazakhstanevent: 17 Jul 2026

    Kazakhstan: producers of socially significant goods offered up to 20% electricity discount in exchange for price restraint

    The Ministry of National Economy has included a preferential tariff mechanism in the draft pricing rules for socially significant markets: producers of goods on the list of socially significant food products will be able to receive a discount of up to 20% on electricity. The condition is signing a memorandum on price stabilisation with government bodies. The discount applies only to electricity used directly in the production of goods on the list. The list itself was approved by Order No. 362-nq of the Minister of Trade and Integration dated 23 Dec 2025 and expanded from 19 to 31 items as of 4 Jan 2026: tomatoes, cucumbers, apples, beef, minced meat, mutton, horse meat, fish, whole chicken, sour cream and cheese were added to the base list of flour, bread, groats, potatoes, vegetables, sugar, sunflower oil, milk, kefir, cottage cheese, butter, eggs, salt and tea. The retail markup on these goods is capped at 15%. Some Kazakhstani experts point out that expanding tariff benefits increases cross-subsidisation in the energy sector, and cite targeted support for low-income households as an alternative.

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  • 20 Jul 2026Uzbekistanevent: 19 Jul 2026

    Uzbekistan: fifth consecutive electricity consumption record — 293.4 mn kWh; president orders power supply problems resolved before heating season

    On 17 Jul, daily electricity consumption in Uzbekistan reached 293.4 mn kWh — the fifth consecutive record since 13 Jul, with a five-day increase of 14.8 mn kWh. That is 20.8 mn kWh, or 7.6%, above last year's summer peak (272.6 mn kWh, 18 Jul 2025). Output from the Unified Power System that same day was 296.1 mn kWh, or about 305 mn kWh including solar plants. The Ministry of Energy of Uzbekistan had forecast peak load on the power system on hot days at 13–13.3 GW. Amid 40–45°C heat, localized outages have been recorded: on 17 Jul, more than 8,200 consumers in nine districts of Tashkent and two districts of Tashkent region were temporarily left without power. The ministry attributes the outages to preventing large-scale accidents and equipment overheating. Following 39,200 citizen appeals to the fuel and energy sector in the first half of the year (50% on gas supply, 38.3% on electricity supply), the president ordered power networks and transformer substations in problem mahallas to be repaired and the readiness of emergency crews improved before the start of the autumn-winter season.

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  • 20 Jul 2026event: 17 Jul 2026

    European Commission submits EU ETS revision: phase 5 through 2040, free allowances for CBAM sectors extended to 2038, Article 6 credits admitted into the system

    On 17 July the European Commission put forward a proposal to revise the EU ETS emissions trading system, setting the legal framework for phase 5 (2031–2040) under the EU's target of a net 90% reduction in greenhouse gas emissions by 2040 relative to 1990 levels. For sectors covered by the EU carbon border adjustment mechanism (CBAM), the proposal would reinstate 15% of already phased-out free allowances from 2028 and stretch their full phase-out to 2038 — the Commission's stated motive is managing residual carbon leakage risk. International credits under Article 6 of the Paris Agreement are operationalised for the first time: 260 mn allowances are reserved for their purchase in 2036–2040, about 2% of the 1990 baseline emissions level, against a statutory ceiling of 5%. Both developments matter for Central Asian exporters: the slower CBAM rollout eases near-term pressure, while the admission of Article 6 credits opens a channel for projects in third countries. According to an estimate by ITC and QazTrade (the report was presented on 9 June 2026 with support from the EU Delegation to Kazakhstan), if default emissions values are used, the annual CBAM costs for Kazakh exporters could exceed €100 mn, with 90% of the effect falling on steel bars and rods.

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  • 17 Jul 2026Kazakhstanevent: 16 Jul 2026

    Kazakhstan: Samruk-Energy and SANY sign shareholders agreement on 1 GW wind farm in Zhetysu

    At a meeting between Samruk-Kazyna fund head Nurlan Zhakupov and SANY Renewable Energy board chairman Li Qiang, Samruk-Energy and SANY signed a shareholders agreement to build a 1 GW wind farm in Zhetysu region. The parties also noted the completion of a SANY wind component plant in Zhambyl region with capacity of 2 GW per year. The statement did not disclose the investment amount, commissioning timeline, or the power off-taker.

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  • 16 Jul 2026Tajikistanevent: 15 Jul 2026

    Tajikistan and Kyrgyzstan discuss CASA-1000 progress amid possible winter restrictions in Tajikistan

    On 15 July, Tajikistan's Minister of Energy Daler Juma and Kyrgyzstan's Minister of Energy Altynbek Rysbekov held an online meeting on the CASA-1000 project, discussing implementation progress and bilateral cooperation. The official statement contains no specific figures or decisions — it was a framework-setting meeting. Around the same time, the head of Barqi Tojik, Muhammadumar Asozoda, did not rule out power supply restrictions this coming winter. According to him, the Nurek reservoir will be full by winter, but the seasonal imbalance between generation and demand persists. Both stories stem from the same hydro model: Tajikistan faces a shortage in winter and a surplus in summer, which it exports at minimum prices (supplies to Kyrgyzstan at 0.98 ¢/kWh). CASA-1000 (1,300 MW, about 5 bn kWh a year) is designed to monetise this summer surplus in Afghanistan and Pakistan. The key risk is the Afghan section: readiness estimates diverge (DABS puts it at about 80%, the World Bank at about 23%), and a realistic commercial launch is expected sometime between summer and the end of 2027. CASA-1000 should be seen as more than just a “pipe to the south”. It is about 1.3 GW of new transmission capacity in a region where Central Asia is currently linked to Afghanistan by a single 220 kV line rated at 0.3 GW (already running at capacity in summer), and to Pakistan by nothing at all. But the corridor is valuable the other way round too: as a balancing cross-border flow, it is no less useful to the north. Southern Kazakhstan itself faces a shortage in summer and draws on expensive Russian imports (about 8.5 ¢/kWh), while nearby, cheap hydropower from its neighbours at 1–2 ¢ sits idle. The more tightly the region is interconnected, the easier it becomes to move these surpluses to where they are needed — and the easier it becomes to integrate future solar and wind capacity. And there will be plenty of it: the announced plans of the five Central Asian states point to roughly 20–35 GW of solar and wind generation by 2030, several times the capacity of a single corridor. To evacuate and balance volumes like that, the region needs both internal transmission sections and parallel routes — CASA should not remain alone.

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  • 14 Jul 2026Kazakhstanevent: 13 Jul 2026

    Kazakhstan introduces external filter over electricity cap tariffs

    Order No. 242-н/қ of the Ministry of Energy of Kazakhstan dated 25 Jun 2026 adds a new step to the Rules for Approving the Electricity Cap Tariff: before a seven-year tariff is approved or adjusted, calculations must now go to the State Commission on Economic Modernization — an advisory body under the President chaired by the Prime Minister. The rule has been in force since 13 July. It does not raise or lower prices — it changes the approval procedure. External oversight of tariffs by a body above the ministry matters, but it covers a base frozen for seven years — the tariff revenue of existing plants (about $3.5bn a year). It is even more important to start overseeing large-scale investment decisions on the sector's development: the ≥26 GW programme through 2035 amounts to about $24bn for already signed projects alone. Consumers pay for them through the capacity market and the renewables surcharge, and this will soon exceed the tariff revenue of existing plants.

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  • 14 Jul 2026Kyrgyzstanevent: 10 Jul 2026

    Kyrgyzstan first in Central Asia to adopt law on climate action

    President Sadyr Japarov has signed the law on climate action, the region's first framework climate law. The document creates a legal basis for the circulation of carbon units (a state registry, a quota trading framework), mandatory emissions accounting by major emitters (MRV), and climate finance; it was developed with technical support from the UNDP. It enters into force on 1 January 2027, with the mechanics to be set out in secondary legislation from the Cabinet of Ministers. The quota market stands out in this law, but more important is the infrastructure it builds for access to international climate finance. For Kyrgyzstan, with its water-energy vulnerability (HPPs account for over 90% of generation, Toktogul lost about 20% of its volume over the past year, and a winter shortage of roughly 4 bn kWh is covered by imports), a carbon registry, MRV, and climate budgeting are exactly the preconditions the GCF and Article 6 of the Paris Agreement require of a host country. The pipeline being built on this is state-driven: the World Bank's $50 mn iFIRST (the first carbon finance operation for the Kyrgyz Republic), the $4.2 bn Kambar-Ata-1 with a donor committee of WB/ADB/EBRD/AIIB, and the rehabilitation of Toktogul (ADB + EFSD) — against the country's stated need of $12–15 bn through 2035. The money was flowing even before the law; its point is to turn one-off donor deals into a repeatable framework.

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