Bulgaria to axe Russian gas tax after Hungary ultimatum

Spanish Market: Natural gas
18/12/23

The Bulgarian parliament today approved in its first reading a bill to revoke the country's tax on Russian gas transit after Hungary threatened to veto the country's accession to the EU's Schengen area because of the levy.

The tax "should be waived" until the EU introduces explicit regulations on how to determine if gas is of Russian origin, according to the bill, which still needs to be approved in a second reading and then signed by the president to become law. Bulgaria's coalition parties agreed to suspend the levy last week, but adopting the plan in parliament became urgent after Hungary gave Sofia an ultimatum.

"We have made it clear to the Bulgarians that if the tax is maintained, we will veto their Schengen membership," Hungarian foreign minister Peter Szijjarto said on 16 December. "And since the decision on this will be made next week, they suddenly started trying hard to abolish this law." Budapest will not veto if Sofia withdraws the tax, "but first we want to see the Bulgarians actually repeal this law", Szijjarto said.

Bulgaria adopted the original law — which introduced a tax of 20 lev/MWh, or roughly €10/MWh, on the import and transit of gas originating in Russia — on 13 October. Hungary — along with Serbia and North Macedonia — repeatedly called on Sofia to abolish the levy, arguing that it endangers Russian gas supply to the region.

"The problem with Hungary will end as soon as we abolish the tax on Russian gas," Bulgarian prime minister Nikolai Denkov said on 17 December, according to state-owned news agency BTA. He said Sofia had preliminary talks with Budapest and pledged to abolish the tax on 15 December, but missed this deadline after protests by opposition parties disrupted the parliament's sessions.

Joining the Schengen free-travel zone has long been a key priority for Bulgaria, an EU member state since 2007, but its accession was so far rejected, most recently in December last year.

By Bela Fincziczki

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28/10/24

Japan’s election leaves energy policy in limbo

Tokyo, 28 October (Argus) — Japan's ruling Liberal Democratic Party (LDP) and its coalition partner Komeito were heavily defeated in the country's election on 27 October, and this is likely to leave the country's energy policy in limbo, especially for nuclear power. The LDP's first defeat in 15 years means no single party holds the majority of seats to govern parliament now. Forming a fresh alliance, if not a coalition government, would be essential for any party, but depending on who teams up with whom, the country's energy policy could deviate from its present course, especially because of the parties' different approaches to nuclear power policy. The LDP and Komeito together won 215 seats, falling short of the 233 seats needed to hold the majority and take control of parliament. The LDP is now faced with the choice of seeking other parties to join its coalition, or to remain as a minority in the government. Komeito could also face challenges in establishing a new structure, as Keiichi Ishii, the leader of the party, was defeated in the election. "We have to take the outcome seriously," said Shigeru Ishiba, the current prime minister and the LDP's governor, indicating he intends to take immediate action for political reforms. But the LDP's weakened position may make it difficult to push for its pro-nuclear energy policy to ensure the country's energy security, economic growth and decarbonisation as part of its 2050 net zero emissions goal. The second-largest opposition party with 38 seats, the Japan Innovation Party (JIP), also called Ishin, holds a similar stance on nuclear policy as the LDP. But it is unwilling to align itself with the current coalition government, because of distrust against the LDP resulting from a political fund scandal that was part of the reason for the current political turmoil within the LDP. JIP is not planning to form a coalition with any parties, said its leader Nobuyuki Baba. The Democratic Party for the People, also named Kokumin, which quadrupled its number of seats to 28, has also promoted the use of domestic nuclear and renewable power sources. Forming an alliance with Kokumin may keep the LDP's nuclear power policy in place. But Kokumin's leader Yuichiro Tamaki has also declined to form a coalition with the LDP and Komeito, although he said that co-operating on a specific agenda could be possible. The biggest opposition party, the Constitutional Democratic Party of Japan (CDPJ), which won 148 seats, will step up efforts to co-operate with other opposition parties to change the government, according to the party leader Yoshihiko Noda. Noda served as prime minister of Japan and president of the then democratic party of Japan from September 2011 to December 2012. The CDPJ pledged in its manifesto to not build a new nuclear fleet or expand capacity, while pushing for a swift phase-out of existing reactors. The party aims to cut Japan's greenhouse gas (GHG) emissions by more than 55pc by 2030 against 2013 levels, and ensure carbon neutrality by 2050, while lifting the share of renewable energy in its power mix to 50pc by 2030 and 100pc by 2050. The climate goal by the CDPJ is ambitious compared with the LDP's strategies so far. Japan's strategic energy plan, which was updated by the LDP-led government in 2021 and is now under review, targets a 46pc reduction in the country's GHG emissions by the April 2030 to March 2031 fiscal year from its 2013-14 level, in line with its goal to have net zero emissions by 2050. The 2030-31 target assumes Japan relies on thermal generation for 41pc of its electricity demand, along with a 36-38pc share for renewables, 20-22pc nuclear power and 1pc hydrogen and ammonia. A special diet session is scheduled to be held before 26 November to appoint the new prime minister. Following the LDP's defeat, it remains unclear if Ishiba, who was just sworn in on 1 October, will be re-elected despite his willingness to hold onto power. By Motoko Hasegawa and Yusuke Maekawa Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

UK ramps up climate action under new leadership

28/10/24

UK ramps up climate action under new leadership

London, 28 October (Argus) — The UK's Labour government, elected in July, has taken the country's climate policy in a new direction, restoring pledges the previous administration scrapped and seeking to funnel investment to renewables. The UN Cop 29 climate summit presents an opportunity for it to follow this up on an international stage. Hosting Cop 26 in 2021 allowed the UK to burnish its climate leadership credentials, but subsequent changes in the Conservative government saw policy reversals. Labour sought to differentiate its position on climate during the election campaign — possibly noting an increase in support for the UK's Green and Liberal Democrat parties, both of which hold firm pro-environment stances. Labour promised to issue no new oil, gas or coal licences — although it said it would not revoke existing permits — and is aiming for zero-emissions power by 2030. Energy minister Ed Miliband in his first week in office lifted the de facto ban on onshore wind, and set up a taskforce to speed the country's path to a decarbonised power grid. The UK has in recent weeks pulled in around £24bn ($31bn) of investment for renewables, including from utilities Orsted and Iberdrola, and announced "up to" £21.7bn in funding over 25 years for carbon capture, use and storage (CCUS) — although it is unclear how the money will be deployed. The government moved swiftly to raise the windfall tax on oil and gas profits, lifting it to an effective rate of 78pc and scrapping one of the investment allowances — although the decarbonisation investment allowance remains in place. And, spurred by a landmark ruling made by the UK's Supreme Court in June, the government pledged new environmental guidance for oil and gas fields by spring 2025. The judgment ruled that consent for an oil development was unlawful, as the Scope 3 emissions — those from burning the oil produced — were not considered. The government has in the meantime halted assessment of any environmental statements for oil and gas extraction, including those already being processed, until the new guidance is in place. The Labour government has declined to defend in court decisions taken by various iterations of the Conservative administration, including the permission granted for a proposed coal mine in northwest England. The High Court quashed that planning permission in September. International stage Miliband has sought guidance from independent advisory the Climate Change Committee (CCC) on the country's new climate plan, known as a nationally determined contribution (NDC). The CCC assessed the previous government as off track to hit legally binding emissions-reduction targets. The UK has cut emissions by half since 1990 and is in line with all carbon budgets to date. But much of this progress was made from a baseline of a high rate of coal-fired power generation, all of which is now shut down. The next stage of the country's decarbonisation will be more fragmented and is likely to pose more of a challenge. The UK has bucked the trend set by some European neighbours by shifting further left with Labour, although the new government has promoted fiscal caution. Climate finance will dominate the talks in Azerbaijan, and the UK has been clear it will continue to contribute. Labour pledged in its manifesto to "return to the forefront of climate action", noting that the previous administration had "squandered [the UK's] climate leadership". Foreign minister David Lammy has embedded climate and nature issues into his foreign policy brief and the government has appointed special representatives for climate and nature. But Cop 29 will prove the first real test of the pledges made, with a global audience watching. UK greenhouse gas emissions Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Pennsylvania drilling drops to 17-year low

25/10/24

Pennsylvania drilling drops to 17-year low

New York, 25 October (Argus) — Pennsylvania oil and natural gas drilling this week fell to the lowest in 17 years, signaling dimming producer sentiment in the second-largest US gas producing state. The number of rigs drilling for oil and gas in Pennsylvania this week fell to 12, the lowest since July 2007, as the state's rig count lost one from a week earlier and fell by 10 from a year earlier, according to oil field services company Baker Hughes. There were 101 gas-directed rigs in the US this week, down by 16 from a year earlier, implying that the majority of the gas-rig decline was due to the drop in Pennsylvania, where wells produce plentiful dry gas but little crude and natural gas liquids (NGLs). The 17-year-low rig count in the regional gas-producing powerhouse, home to the prolific Marcellus shale, is due to three factors: expectations of lower US gas prices after the 2024-25 winter heating season, a lower share of currently more profitable crude and NGLs in Pennsylvania's output compared to nearby West Virginia and Ohio, and the June start-up of a new gas pipeline in West Virginia , where some Pennsylvania production may have shifted. Rig counts reflect expected prices roughly six months in the future, accounting for the lag between when the drilling of a well begins and when its production is sold. The April 2025-March 2026 strip price at the Leidy Line trading hub, a bellwether for Marcellus shale output in northeast Pennsylvania, was $2.63/mmBtu, according to Argus forward curves. Prices for crude and NGLs in 2024 have been more resilient than US gas prices, which have languished after a warmer-than-normal 2023-24 winter left the US gas market oversupplied. This price dynamic may be why the other two main Appalachian gas producing states have not mirrored Pennsylvania's drilling slowdown. The Ohio rig count rose by one this week to 10, the same number as a year earlier, while the West Virginia rig count was unchanged at 10, up by three from a year earlier. Drilling productivity has also improved dramatically in the past 17 years, surging to 21 Bcf/d (595mn m³/d) in July from 471mn cf/d in July 2007, according to the US Energy Information Administration. Above-average temperatures were expected to blanket the US from November to January, according to the National Weather Service, portending another winter with lower gas demand. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Africa pushes domestic gas role in transition

25/10/24

Africa pushes domestic gas role in transition

Gas could complement renewable power build-out, but guaranteeing supply will require risky investment in infrastructure, writes Elaine Mills Cape Town, 25 October (Argus) — Natural gas has the potential to play a pivotal role in Africa's energy transition, enabling greater energy security for the continent as well as decarbonising its economy — but ensuring domestic demand prospects can compete with regional LNG export opportunities still presents a major challenge. The African Union and African governments have stressed the importance of gas as a bridging fuel for Africa on its journey to achieving equal energy access and net zero emissions. Africa accounts for 40pc of new gas discoveries made globally in the past decade, mainly in Mozambique, Senegal, Mauritania, Tanzania and more recently Namibia. "Its significant natural gas reserves could turn Africa into a key player in the global gas market, while improving energy access for its rapidly growing population," the IEA says. "Africa has a very timely and good opportunity right now," agrees Norwegian state-controlled Equinor's senior vice-president, Nina Koch. "Gas is becoming increasingly important, not only as a transition fuel but as a long-term solution for the energy security challenges that we are facing." Leading African producers Algeria, Egypt, Nigeria and Libya together accounted for over 80pc of Africa's total production of 265bn m³ in 2023. Of this volume, about 115bn m³ was exported, 60pc of it in the form of LNG, according to the IEA. However, governments in sub-Saharan Africa want increasingly to support gas infrastructure investments for domestic consumption to meet their own rapidly rising electricity demand and support industrialisation objectives. According to the IEA, between 2020 and 2023 natural gas consumption in Africa almost tripled to 172bn m³, but still represented only 4pc of global demand. Until now, the role of natural gas in sub-Saharan Africa has been limited, with an estimated share of only 15pc in the energy mix. Nigeria is the largest natural gas market in the region, with an estimated 21bn m³ consumed in 2022, of which 40pc was used for power generation. But Africa's gas demand is projected to increase rapidly, especially in sub-Saharan Africa, where the IEA estimates that it will grow at 3pc/yr and could reach 187bn-246bn m³ by 2030 and up to 437bn m³ by 2050. Complement not compete "Gas as a bridging fuel is particularly important in the sub-Saharan Africa region, where energy demand is growing quickly and renewables cannot yet meet all the needs," Italian firm Eni's regional head, Mario Bello, says. As a lower-carbon base-load power generation fuel than coal or oil, proponents argue that gas can complement the growth of interruptible renewables rather than compete with it. Domestic pricing presents an immediate challenge — widespread subsidised gas retail prices currently mean that 58pc of Africa's natural gas consumed is priced below the cost of supply, according to the International Gas Union. And the rapid rise in sub-Saharan Africa's gas consumption could result in domestic demand outstripping supply in the next 10-15 years, leaving a gap that smaller gas projects could fill, with the growing help of African lenders. The African Export-Import Bank (Afreximbank) has provided financing to support Nigeria's first indigenous FLNG project, with capacity of 1.2mn t/yr to supply the local market. Policy makers in several African gas-producing countries will increasingly support these domestic-oriented schemes in the coming years. In Nigeria, Angola and Senegal, governments are already demanding that gas is used to support electrification and industry rather than for export. New natural gas markets are emerging in Ghana and South Africa, supported by the development of domestic production as well as new import infrastructure, to meet growing electricity generation needs and replace coal and oil use in the power sector. The case of South Africa, the continent's largest economy, shows the kind of challenges that will face Africa's ambitions to develop its gas sector. Gas accounts for less than 3pc of the country's energy mix, but this is growing and the Industrial Gas Users Association (IGUA) of South Africa estimates that gas demand in 2033 could more than quadruple to as high as 800 PJ/yr. South Africa's only primary supplier of gas, Sasol, supplies 185 PJ/yr, of which 160 PJ/yr is imported from Mozambique through the Rompco pipeline. But Sasol's Pande and Temane fields in Mozambique are fast depleting, and the firm has warned that by mid-2028 at the latest it may no longer be able to supply gas to South African industry. Sasol's "unilateral decision" to cut off gas supply "poses an existential risk to large industrial gas users and is likely to lead to the deindustrialisation of the South African economy", IGUA warns. Given long lead times for alternative gas supply solutions, "the governments of South Africa and Mozambique have six months to come up with a new plan and start executing it", energy advisory SLR Consulting's Steve Husbands says. Currently, Mozambique has the most advanced LNG import terminal being developed at Matola, and over the short term, South Africa will be reliant on this facility to meet its gas demand needs, according to IGUA. In the medium term, LNG import terminals are planned at Richards Bay, Coega, and Saldanha Bay. Longer term, upstream gas exploration opportunities exist offshore South Africa and especially on its side of the Orange basin. But the country's domestic ambitions suffered a major setback recently when TotalEnergies decided to quit block 11B/12B, which contains the Brulpadda and Luiperd discoveries that hold a combined estimated 3.4 trillion ft³ (96.3bn m³) of natural gas. Meanwhile, Namibia is due to become a global oil and gas supply hub over the next 10 to 15 years. "South Africa needs to understand that the bargaining position of Namibia and Mozambique is different and it's strong," Husbands says. These countries will be guided by self-interest and they will price according to alternatives, such as exporting LNG. Credit risk IGUA has also focused on facilitating gas energy demand aggregation, whereby industries collaborate to secure cost-efficient gas supply through volume aggregation, the enablement of infrastructure and the dilution of commercial risks. South Africa's industrial development depends on gas, state-owned Central Energy Fund (CEF) chief operating officer Tshepo Mokoka says. To enable this, gas-to-power projects are needed to anchor the development of a large-scale, capital-intensive gas industry, he says. The CEF is working to locate gas-to-power plants of at least 1,000MW at the ports of Richards Bay, Coega and Saldanha Bay. Gas-to-power projects need three to five years of government support to get off the ground, he says. "Without it, the critical LNG infrastructure that is required at the different ports will be sterilised," Mokoka says. For Africa more broadly, a lack of creditworthy utilities as gas offtakers, combined with small-scale and fragmented markets, makes it more difficult to aggregate demand for large developments. These challenges have led to underinvestment in gas processing facilities and transportation infrastructure, which makes developing gas reserves for domestic use a tough sell for investors across the continent. "You need feedstock as well as guaranteed offtake to ensure the economic viability of gas projects," Lekoil chief technical officer Sam Olutu says. "It is important to secure midstream offtake even before an upstream project is commissioned, as it gives you more control over pricing, so that you are not forced to flare the gas." Some governments are increasingly keen on developing industrial capacity in areas that require intensive energy use such as fertilisers or cement manufacturing that will provide enough reliable gas demand to make a project economic. Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

UK summer LNG imports at long-term low

25/10/24

UK summer LNG imports at long-term low

London, 25 October (Argus) — The UK received the fewest number of LNG cargoes in April-September since 2008, when it had just one commissioned LNG import terminal. The UK's three LNG terminals — 5.6mn t/yr Dragon, 15.6mn t/yr South Hook and 14.8mn t/yr Isle of Grain — together received 24 cargoes in April-September, down from 41 over the same period in 2023 and 104 in 2022. The UK's summer LNG imports were previously below 30 only twice since all three facilities have been on line — in 2018 and 2019 when 26 and 28 LNG deliveries were completed, respectively. The origin of the UK's LNG was also the least diverse since 2017, coming from just five countries. Dragon received exclusively US cargoes, while South Hook took cargoes from the US and Qatar. Isle of Grain received LNG from the US, Algeria, Norway and Peru. The UK received LNG from six countries in 2023, 2021 and 2020, and from nine countries in 2018 and 2019. Its most diverse summer of supply was in 2022, when the country received LNG from 10 countries. South Hook — owned by a joint venture between Qatargas, ExxonMobil and Total — was the only terminal to receive Qatari LNG this summer, while in previous years all three UK terminals had taken Qatari cargoes. And South Hook received just five Qatari cargoes in April-September, the lowest since the commissioning of all three terminals. This was down from 12 in summer 2023 and 39 in 2022. Qatar had constituted more than half of the UK LNG mix in 2019-20 and was the dominant supply source in 2010-17. Part of the reason for slower Qatari deliveries to South Hook may have been the effective closure of the Suez Canal route. All five Qatari vessels that delivered to the UK went the longer way around the Cape of Good Hope. The need for a change in route — triggered by Yemen's Houthi militants' attacks on ships — almost doubled the journey time. And no firms hold long-term Qatari contracts that specify UK ports as the exclusive destination point. Europe's demand for LNG was consistently weak over the summer because of low injection demand and strong Norwegian pipeline supply. Asian demand, in contrast, was strong enough to keep the arbitrage between the Atlantic and Pacific basins mostly open. And the NBP front-month market held below the TTF on all but one day over the summer, which priced out UK terminals relative to those in continental Europe. The additional buildout of LNG import capacity in northwest Europe since 2022 has significantly reduced the UK's role as an LNG transit country. In the 2022 and 2023 summers, when more LNG arrived in the UK, exports to continental Europe through the Interconnector and BBL pipelines were much higher. Interconnector flows to Belgium fell to 21.2mn m³/d in April-September, from 29.2mn m³/d in 2023 and 54.6mn m³/d in 2022. BBL deliveries to the Netherlands were roughly unchanged from a year earlier but fell by around 5mn m³/d from 2022. The Argus NBP everyday price held below the TTF throughout the past summer, apart from five days in late April and one day in early May. In addition, British consumption continues to decline. UK demand — excluding storage injections — fell to 98.1mn m³/d in April-September, from 109.5mn m³/d over the same period in 2023, 130.6mn m³/d in 2022 and 142.8mn m³/d in 2021. The continuing decline in domestic production was mostly offset by higher Norwegian pipeline deliveries. Norwegian flows to the UK through Gassco infrastructure averaged 64.6mn m³/d in April-September, up from 38.8mn m³/d in summer 2023 and 63mn m³/d in 2022. By Alexandra Vladimirova Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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