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LONDON (ICIS)–Russia may need to increase its reliance on Kazakhstan to consolidate its position in the Chinese market and strengthen its gas price negotiation position with buyers in China, a former UK government advisor on Central Asia said. Speaking to ICIS, Angus Miller, chairman of UK-based advisory TelosNRG, said Russia and Kazakhstan may consider a combined approach to gas sales to China. Russia concluded a 38billion cubic metre/year agreement with China’s CNPC and started supplying gas from 2019 via the 3000km Power of Siberia pipeline. However, the sale price may have been $9.00/MMBTu in 2021, at a time when European hub prices soared well-above that to record levels. Meanwhile, in 2018, Kazakhstan’s KazTransGaz (KTG) signed a five-year export deal to supply 10bcm/year to China, but it represents a third of the country’s annual output and has at times stretched its ability to respond in full to China’s peak demand. Miller said China had had a real say on export prices in recent years but a joint Kazakh-Russian strategy could boost chances of negotiating more attractive contractual terms for producers. He said that in his view, the recent events in Kazakhstan were likely to usher in a comeback of Russian interests, noting that many institutions and companies, including in the energy sector, could witness a clearout of the old guard and the return of an elite closer to the Kremlin. CHANGE OF GUARD This may prompt China to seek alternative supplies from the Middle East. In fact, as events were unfolding in Kazakhstan, China met representatives of some Gulf states with a view to expedite and implement a free trade agreement that would help to negotiate attractive terms for oil and gas deals. “Central Asian countries had the opportunity and plans for reform in the 2000s but some had let these die on the vine, resulting in the kind of reaction seen recently in Kazakhstan,” said Miller. Miller said Central Asian gas producers had focused on selling volumes to China rather than European markets over the last decade because of EU policies favouring a renewable energy. This meant they had no incentives to invest in upgrading and maintaining the export infrastructure such as the Central Asia-Centre lines, which have historically connected the regional networks to the Russian transmission system. Even so, it is possible that in 2021, some Central Asian gas may have helped Russia to meet soaring demand at home, in Europe and in Turkey. GOING WEST OR EAST? According to ICIS calculations, Kazakhstan supplied 8.03bcm to Russia in the first ten months of 2021, a small decline on the 8.70bcm supplied over the same period the previous year and 1bcm/year lower than in 2019. Turkmenistan signed a five-year contract for 5.5bcm/year supplies to Russia via the Central Asia-Centre pipeline which transits Kazakhstan and merges in southern Russia with the Soyuz pipeline heading west to Ukraine. International press reports quoting the Russian ambassador to Turkmenistan suggested in December that Russia imported double the contracted volumes for the full year 2021. Speaking to ICIS, Vitaliy Yermakov from the Oxford Institute for Energy Studies, said he was sceptical about the figures. He said Russia had swap agreements in place with Central Asian countries but imports had been declining in recent years, noting that regional countries were torn between Russia and China. THE TURKISH FACTOR Nevertheless, Gazprom may have relied on Central Asian gas to meet demand, particularly in Turkey, where consumption rose 46% year on year in the first ten months of 2021, according to latest figures by the regulator EPDK. Yermakov explained that since prices plummeted in 2020, Gazprom relied on storage withdrawals rather than increase domestic output to supply the domestic and European markets. If that is the case, this means that based on the 2020 experience, Gazprom may have been preparing to rely on its 23 domestic storage facilities located mostly in the southern regions to supply not only its domestic market but also European and Turkish consumers in 2021. However, when Turkey’s gas demand soared and domestic consumption from its own clients rose 14%, Gazprom may have been scrambling to secure extra volumes, not least because surplus production at some of the legacy fields in western Siberia has been declining. The premature decline may have been caused by the introduction in 2014 of a formula-based mineral resource extraction tax (MRET). The levy, Yermakov argued in a number of earlier articles, incentivised Gazprom to ramp up production at the higher cost newer fields such as Bovanenkovo in the Yamal peninsula and hold back output at the legacy fields in the Nadym-Pur-Taz area which supply Europe via Ukraine.

LONDON (ICIS)–Acrylonitrile (ACN) markets around the world have seen spot prices soften amid improving supply, although logistics problems and rising costs remain key concerns. In this podcast, ICIS senior editors Jane Massingham (Europe), Li Li Chng (Asia) and Lucas Hall (US) discuss the latest market developments and what lies in store. Asia faces near-term supply overhang Europe closely monitoring costs US calm on easing supply, good demand Logistics and Omicron impact Podcast interview by Jane Massingham, Lucas Hall and Li Li Chng Podcast editing by Jane Massingham

SINGAPORE (ICIS)–Japan’s chemical exports rose by 15.6% year on year to yen (Y) 964bn in December, supporting the overall rise in shipments abroad, official data showed on Thursday. Exports of organic chemicals rose by 40.7% year on year to Y192bn in December, while shipments of plastic materials were up by 9.2% at Y277bn, Ministry of Finance data showed. On a volume basis, exports of plastic materials fell by 12.1% year on year to 522,916 tonnes in December. Japan’s overall exports rose by 17.5% year on year in December to Y7,881bn while imports surged by 41.1% to 8,464bn. This resulted in a trade deficit of around Y582bn, compared with a surplus of Y708bn in December 2020. Overall exports to China rose by 10.8% year on year in December while shipments to the US were up by 22.1%.

HOUSTON (ICIS)–Shifting Mexico’s power generation mix to rely more on state-owned power plants could negatively affect system reliability, increase natural gas and other fuel consumption as well as emissions, according to new analysis from the US-based National Renewable Energy Laboratory NREL, which is part of the Department of Energy. The technical impact analysis published in the first half of January 2022 concludes that prioritising state-owned power plants would increase electricity production costs by 31% to 53% depending on the scenario, amid renewables curtailment, higher production costs and decreased private generation participation. The release of the study came between the 22 December and upcoming meetings between the US energy minister Jennifer Granholm and Rocio Nahle, her Mexican counterpart. Mexican president Andres Manuel Lopez Obrador (AMLO) said on 17 January that Granholm would be in Mexico this week to talk about several issues with a number of ministers. The US Department of Energy announced on 19 January that Secretary Granholm would visit on 20 and 21 January. NATURAL GAS, FUEL CONSUMPTION Natural gas consumption would increase over the reference scenario by 6% to 29%, depending on the scenario, while the consumption of fuel oil would jump several-fold in all scenarios. Coal consumption would increase over the reference scenario by 47% to potentially more than double. The analysis modelled scenarios that simulate increased participation of state-owned power plants in Mexico’s generation mix. Each scenario represented different levels of priority of generation from state-owned power plants. The analysis compared these scenarios against a reference scenario that is supposed to represent current practices in Mexico using data for the year ending 31 August 2021. The increase in the share of annual electricity generation by publicly-owned generators increased in the scenarios from 40% to 74%, displacing private generation. SYSTEM RELIABILITY The analysis concluded a shift in the generation mix could hit grid reliability because of higher forced outage rates of older plants owned by state-run utility CFE and state producer Pemex. It used data from a 2019 Mexico government audit, indicating the average age of CFE power plants was between nearly 34 years and 42 years, while the average age of private power plants holding independent power producer (PIE) contracts with CFE is about 12 years. EMISSIONS Prioritising state-owned generation would up annual CO2 emissions by 26%, or 29.4m tonnes, in the first scenario to 65%, or 73.5m tonnes, in the third scenario while SO2 emissions would more than double or triple. The increased emissions would result from the potential increased use of fuel oil and coal generation and curtailment of wind and solar. Curtailment of these two types of generation was estimated at 0.32TWh, or 0.8% of available wind and solar under the reference scenario. The figure remains the same under NREL’s first scenario but wind and solar curtailment more than doubled in the second scenario. Nearly 91% of generation was curtailed in scenario three. NREL is a national laboratory of the US Department of Energy. The institution said its analysis report is part of the 21st Century Power Partnership program in Mexico. The program is supposed to support Mexico’s power system transformation by accelerating the transition to a “reliable, financially robust and low-carbon system.” NREL said its analysis is not a forecast of the potential effects of the administration’s energy initiative currently being debated in Mexico’s congress.

LONDON (ICIS)–The Romanian and Ukrainian gas transmission system operators will be holding a consultation for incremental capacity at the critical Tekovo-Mediesu Aurit border point. According to the draft project published this week, an estimated 7mcm/day of technical firm export capacity could be made available at the border point from Romania to Ukraine from the third quarter of 2026 through 2041. The total annual import capacity into Ukraine would be 2.5bcm. The Romanian grid operator Transgaz said it would have to invest €300m to build new infrastructure, including a compressor station of 15MW. The upgrades would enable the reversal of gas flows, allowing exports between northern Romania and southern Ukraine and eventually make flows bi-directional. The Ukrainian counterpart GTSOU will invest €35m to build a compressor station of 10MW. The consultation period started on 18 January and will conclude on 17 March. Companies can express an interest in writing to the two transmission system operators. The results will be sent to the Romanian regulator ANRE in October 2022 and subsequently be assessed by both Romanian and Ukrainian authorities in 2023. Yearly capacity auctions will be held in July 2023. The border point had been historically used for imports from Ukraine into Romania particularly during peak winter demand. However, the point has not been used since January 2020 when Ukraine signed a new transit agreement for Russian gas until 2024. Bi-directional flows would be needed on both sides of the border, helping to boost regional integration and allowing Ukrainian traders to access volumes in southeast Europe and Romanian traders to tap gas on central European hubs imported via Ukraine.

LONDON (ICIS)–The announcement of 336MW in solar power purchase agreements (PPA) in Poland this week indicates investment interest in a market with untapped potential. On 19 January Swiss energy firm Axpo via its subsidiary Axpo Polska, signed one of the largest solar PPAs ever concluded in the Polish energy market with local developer R Power for 300MW solar projects, set to come online in the middle of 2023. Axpo will buy the full output generated by the solar plants between 2022 and 2026 and will act as the balancing agent for the project portfolio, said the firm in a statement. Separately, the Norwegian state-owned company Statkraft signed a 10-year PPA for 36MW solar park in Poland with Danish producer Better Energy, said an official statement on 18 January. The new solar park will bring subsidy-free solar power to Poland from 2023, added Statkraft. PPAs are an alternative to tenders and subsidy schemes for funding the construction of new renewable capacity. In Poland, this type of agreement has mainly seen corporate involvement, reflecting a market largely driven by foreign investment. The size of the two recent deals means that future installed capacity covered by Polish PPAs in January 2022 has already exceeded the 2021 total. According to data on publicly announced deals collected by ICIS, during 2021 Polish PPAs were signed on a total of 223MW generation capacity. RENEWABLE TARGETS The Polish government’s energy policy until 2040 sets a renewable energy goal for 2030 of “not less than 32% in electricity consumption.” The government strategy points to increasing installed offshore wind capacity to 5.9GW and reaching between 5GW and 7GW of solar generation capacity by 2030. ICIS figures are less conservative with regards to both. Solar generation capacity would reach nearly 15GW in 2030, while offshore wind would reach 6.4GW, according to the Power Horizon 2030 model. This would lift the share of renewable generation within total electricity consumption to over 35%. Polish electricity generation is currently dominated by fossil fuels with more than 70% of electricity being generated from coal. Additional reporting by David Battista

MADRID (ICIS)–The crude oil market could post a surplus in Q2 as producers increase output to take advantage of prices at multi-year highs, the International Energy Agency (IEA) said on Wednesday. Although global coronavirus cases are at record highs, the impact on healthcare services due to the Omicron variant has not been as severe as in previous waves. Measures by governments to contain the pandemic are not as strict as before, helping economic activity. “This time around, the surge [in cases] is having a more muted impact on oil use. Indeed, mobility indicators remain robust and oil demand has been stronger than expected in recent months,” said the IEA. Crude oil prices hit a seven-year high in afternoon trading in Europe on Wednesday after crude producing cartel OPEC said earlier in the week that the impact of Omicron is proving less severe than expected. POTENTIAL SURPLUS BY Q2Low-cost producers within OPEC+, led by Saudi Arabia and Russia, have been capping their output for years to rebalance the global crude market, agreements which were renewed at the beginning of the pandemic after demand collapsed in Q2 2020. However, producers outside that group who respond to normal market dynamics of supply and demand have been absent because their higher cost output was not profitable in the depressed market. That may not be the case any longer. In 2022, US output is expected to hit a record high of more than 17m bbl, the IEA said, as producers put more rigs to work. “World oil supply is forecast to grow sharply this year, with the US, Canada, and Brazil set to pump at their highest ever annual levels… Additionally, Ecuador, Libya, and Nigeria are already ramping back up,” said the Paris-based agency. “Finally, Saudi Arabia and Russia could set records if remaining OPEC+ [output] cuts are fully unwound. In this case, global supply would soar by 6.2m bbl/day on average in 2022, compared with a 1.5m bbl/day rise in 2021.” Although the market could reach a surplus by Q2, the IEA also noted that global stocks are well below pre-pandemic levels and pointed to “a growing discrepancy between observed and calculated stock changes” which suggests that demand could be higher or supply lower than reported or assumed. “Moreover, higher output would also result in lower OPEC+ spare capacity. By the second half of the year, effective spare capacity (excluding Iranian crude shut in by sanctions) could shrink from around 5m bbl/day currently to below 3m bbl/day – most of it held by Saudi Arabia and the UAE,” it said. “If demand continues to grow strongly or supply disappoints, the low level of stocks and shrinking spare capacity mean that oil markets could be in for another volatile year in 2022.” As for demand (see bottom table), the IEA said current data suggests it will exceed pre-pandemic levels in 2022. PETROCHEMICALS: NAPHTHA VERSUS LPGHealthy industrial activity around the world is keeping petrochemical demand for crude oil high. In Europe, for the majority of 2021, olefin production – a key building block for petrochemicals – took advantage of “very competitive naphtha costs” and used it as a main feedstock instead of liquefied petroleum gas (LPG). This situation could change in 2022, said the agency. “Many European steam cracker operators have flexibility to replace some of their naphtha intake with LPG. Recent tightness lifted prices, making global LPG less attractive and boosting naphtha consumption,” said the IEA. “However, with prices rebalancing, this margin advantage began to fade late in the year, suggesting that naphtha demand will begin to soften in 2022.” – Front page picture: Oil rig in the US, where output is expected to reach a record high in 2022 Source: Tony Gutierrez/AP/Shutterstock

LONDON (ICIS)–The Moldovan government is expecting to introduce a state of emergency from Thursday after Gazprom notified the incumbent Moldovagaz it would cut supplies from 20 January because of an unpaid bill. Prime Minister Natalia Gavrilita said in a press briefing on Wednesday there would be a government meeting later in the afternoon followed by a session in parliament on Thursday when members would be asked to introduce the state of emergency. A commission for emergency situations would then decide on measures to guarantee backup supplies. Vadim Ceban, president of the board of directors at Moldovagaz confirmed to ICIS Gazprom had notified the company of the supply cuts and said the government was working to find solutions. Moldovagaz is expected to pay its bill for current supplies by 20 January. However, a record spike in prices in December meant that its import price, which is 70% linked to the Dutch TTF front month and 30% to oil, had risen to an estimated $647.00/1000m3 (€54.29/MWh). To compare, the December import price stood at $450.00/1000m3. Speaking to ICIS, Sergiu Tofilat, a Moldova-based gas expert said the government would find the cash to pay the January bill but said February would be more difficult to cover. He said Moldovagaz was expected to make an advance payment that would cover 50% of the total sum for January. This means Moldovagaz would have to pay around $64million (€56m) by 20 January. The state company already has $38m but it still needs $25m to pay the bill by the due date. The remaining 50% of the January bill is due to be paid next month together with 50% of the February bill. Tofilat said Gazprom had always had a requirement for advance payment in its export contract with Moldovagaz, which it partly owns. However, he said, it never asked for advance payment until November 2021, insisting they were now pushing Moldova’s pro-EU government to pay before the end of the month. A possible solution may be for the government to reschedule Moldovagaz’ payment of value added tax so that they would be allowed to pay it by the end of the month. Tofilat said the February bill may amount to $547.00/1000m3. Other options the government may be looking into would be to ask the Cuciurgani thermal power plant in Transnistria to switch to fuel oil, which would lead to a 30% drop in gas demand. He said it was also necessary for the government to hike end consumer tariffs, which are now significantly lower than the gas import bill. The tariff is now around $430.00/1000m but, he said, there was a need to raise both gas and electricity tariffs. He said the gas-fired generation was taking up 30% of gas demand during winter and added there was a need for electricity tariffs to increase by approximately 20% on current levels. Moldova signed a five-year import contract with Gazprom at the end of October 2021 to import 3bcm/year of gas. About 1.2bcm/year is for Moldovan consumption, while the remaining 1.8bcm/year is for Transnistria, an unrecognised breakaway republic, with close economic and political links to Russia.

LONDON (ICIS)–Nitrogen fertilizer major Fertiglobe on Wednesday signed a collaboration agreement with Masdar and ENGIE to co-develop green hydrogen for ammonia production at Al Ruwais in the United Arab Emirates. The trio will study the development of a “globally cost-competitive green hydrogen facility targeted to be operational by 2025 with capacity of up to 200MW to supply Fertiglobe’s ammonia production plants”. The project aims to accelerate the decarbonisation roadmap of the world’s largest seaborne exporter of ammonia and urea, and boost the company’s position as a global front-runner in green ammonia production. Fertiglobe – a strategic partnership between Dutch group OCI and the UAE’s ADNOC – will work with Masdar, a renewable energy firm, and ENGIE, a low-carbon energy and services provider, on the project. Ahmed El-Hoshy, CEO of Fertiglobe said: “Abu Dhabi is an ideal location to produce green hydrogen given the country’s commitment to a low carbon future, its unique renewables profile and its strategic geographic location. “The project marks another milestone for Fertiglobe’s green ammonia portfolio and follows the announcement last month of our new 100MW electrolyser in Egypt. “Ammonia is the dominant energy carrier for hydrogen. With green hydrogen seen as essential to support decarbonisation of industry, food, transport and energy, there is a huge opportunity for green ammonia to deliver green hydrogen all over the world to fuel the clean economy and meet growing demand for renewable sources of clean energy.” The three companies will study the development, design, financing, procurement, construction, operation, and maintenance of an industrial-scale green hydrogen facility, with Fertiglobe the sole long term off-taker. Fertiglobe boasts a combined production capacity of 6.7m tonnes/year of urea and merchant ammonia and will use the green hydrogen to produce green ammonia. Green ammonia is made from renewable energies like solar and wind power instead of natural gas, with the versatile product a cost-effective carrier of hydrogen.

SINGAPORE (ICIS)–PETRONAS Chemicals Group (PCG) is building a new 60,000 tonne/year melamine plant in Gurun, Kedah, the Malaysian producer said on Wednesday. The new plant is expected to come on stream in 2024 and will make PCG the sole melamine producer in southeast Asia, the company said in a statement. PCG, through its wholly owned subsidiary, PETRONAS Chemicals Fertiliser Kedah (PCFK), will be using the urea produced from PCFK as the feedstock to produce melamine. “By housing the plant within the vicinity of PCFK, we will be able to maximise the overall value through the integration of feedstock and utilities with the existing PCFK facility,” said Mohd Yusri Mohamed Yusof, managing director/CEO of PCG. Financial details of the project were not disclosed.