UK oil, gas 2030 emissions target 'within reach': NSTA
The UK oil and gas sector cut upstream greenhouse gas (GHG) emissions again in 2023 and its 2030 target "appears within reach", the government's North Sea Transition Authority (NSTA) said today.
But this is "just one step… and does not diminish the urgency of further abatement", the NSTA said. The UK oil and gas industry in 2021 signed the government's North Sea transition deal, which set offshore production emission reduction targets of 10pc by 2025, 25pc by 2027 and 50pc by 2030, all from a 2018 baseline.
The UK upstream oil and gas industry emitted 12.9mn t/CO2 equivalent (CO2e) in 2023, a 3.7pc drop on the year, and 29pc lower than 2018 levels, the NSTA said. Of the decrease in GHG emissions, half came from "actively producing assets" and the other half from assets that had ceased or were approaching the end of production.
Absolute emissions fell, but emissions intensity increased on the year in 2023, "as expected in a basin with declining production", the NSTA said. It projected the average emissions intensity for offshore assets at 24kg of CO2e/bl of oil equivalent (boe) in 2023 — up from 22kg of CO2e/boe in 2022.
The majority of emissions, at 79pc, were from hydrocarbon combustion for offshore power generation. Flaring and venting accounted for 17pc and 3pc of GHGs, respectively.
"Electrification or low-carbon power must play a significant role" in further reducing emissions, the NSTA said. It warned that if electrification is considered "reasonable" for existing developments but has not been implemented, "there should be no expectation that the NSTA will approve field development plans and similar decisions that give access to future hydrocarbon resources on that asset."
The organisation also promised "increased scrutiny of assets with high emissions intensity" and said it will publish later this year a list of assets that flare routinely. The amount of gas flared in 2023 was the lowest on record, at 691mn m³, although it dropped only incrementally from the previous year, the NSTA found.
The upstream industry's "total production emissions" make up just over 3pc of overall UK emissions, according to the NSTA. The North Sea industry has committed to reducing GHG emissions by 90pc by 2040, from 2018 levels, and to net zero by 2050. The UK has a legally binding goal of net zero GHG emissions by 2050.
Overall, upstream emissions make up a relatively small proportion of total GHG emissions from the fossil fuel industry. The UK government in August said it would develop new environmental guidance for oil and gas firms, in light of a recent Supreme Court decision that ruled consent for an oil development was unlawful, as the scope 3 emissions — those from burning the oil produced — were not considered.
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IEA cuts global refinery runs forecast
IEA cuts global refinery runs forecast
London, 12 September (Argus) — The IEA has trimmed its forecast for global refinery runs in 2024-25 as weakening refining margins weigh on throughput. In its latest Oil Market Report (OMR), the IEA said it expects global crude throughput at 83mn b/d this year, down from its previous projection of 83.3mn b/d. The agency puts throughput in 2025 at 83.7mn b/d, down from 83.9mn b/d previously. Economic run cuts are expected in the second half of this year as a result of a deterioration in refining margins, the IEA said. Some operators may not cut runs quickly enough in concert with other refiners to support margins, it said, although it noted that Atlantic basin refinery turnarounds this autumn should boost refined product values. The IEA forecasts that refinery runs will contract by 100,000 b/d each in OECD and non-OECD Europe this year compared with 2023, as refineries in the region temper throughput to support margins. Throughput in the former Soviet Union is projected to fall by 200,000 b/d, partly reflecting planned maintenance at Russian refineries in September and a power-related outage at Belarus' 240,000 b/d Mozyr refinery. The agency expects Chinese throughput to drop by 450,000 b/d in 2024, as lacklustre margins prompt independent refiners in Shandong to rein in activity. Chinese throughput declined by 960,000 b/d on the year in July alone, the IEA said. But an uptick in run rates may emerge ahead of the Golden Week holidays at the start of October and a seasonal peak in construction activity at the end of the third quarter, it added. Non-OECD runs are forecast to increase by 640,000 b/d this year, underpinned by new refineries in the Middle East ramping up throughput. The IEA now expects Middle East crude runs to rise by 800,000 b/d this year compared with 2023, which is 200,000 b/d more than its previous projection last month. By George Maher-Bonnett Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Francine moves inland as tropical depression
Francine moves inland as tropical depression
New York, 12 September (Argus) — Hurricane Francine weakened to a tropical depression on Thursday after slamming into southern Louisiana as a Category 2 hurricane the previous evening and spurring offshore operators to shut in around 39pc of oil output in the Gulf of Mexico. Francine was last about 30 miles south of Jackson, Mississippi, according to an 8am ET advisory from the National Hurricane Center, with maximum sustained winds of 35mph. The storm will move over central and northern portions of Mississippi through early Friday bringing heavy rains. Offshore oil and gas operators including Shell, ExxonMobil and Chevron evacuated workers and shut in production from some of their offshore operations in advance of Francine, while a number of ports, including New Orleans, Louisiana, shut down. About 674,833 b/d of offshore oil output was off line as of 12:30pm ET Wednesday, according to the Bureau of Safety and Environmental Enforcement (BSEE), while 907mn cf/d of natural gas production, or 49pc of the region's output, was also off line. Operators evacuated workers from 171 platforms. Shell said Wednesday evening that production at its Perdido, Auger, and Enchilada/Salsa facilities in the Gulf of Mexico remained shut in, but it would reassess its position as offshore conditions improve. BP said it temporarily shut down and evacuated personnel from its Castrol lubricants facility in Port Allen, Louisiana. By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Tanker freight rates expected to rise from 4Q: Appec
Tanker freight rates expected to rise from 4Q: Appec
Singapore, 12 September (Argus) — Tanker freight rates are expected to pick up in October-December and into next year's first quarter on recovering demand for dirty tankers, delegates said at the S&P Global Commodity Insights Appec conference in Singapore. Clean tanker freight rates for Long Range (LR) 2 and LR1 vessels fell in the third quarter because of competition from dirty tankers, Rohit Radhakrishnan, general manager, tanker and gas, Pacific Carriers, said at the conference on 11 September. Rates were dampened on higher competition from increased vessel supply, largely because several dirty tankers such as very large crude carriers (VLCCs) switched to ship clean products. A fully laden VLCC equates to slightly more than three LR2 cargoes, which are the vessels normally used to ship diesel and gasoil from the Middle East to Europe. This was in line with a trend since July when several dirty tankers such as VLCCs were booked to carry clean petroleum products from the Mideast Gulf and Asia to Europe, given weak seasonal demand for VLCCs in the northern hemisphere and higher time-charter equivalent (TCE) rates for clean LR vessels. But the dirty tanker freight market has risen since late last week. With the recent increase in demand for dirty tankers, its $/t discount with clean tankers has decreased, said Peter Kolding, vice president of commercial and pool management at Hafnia, a tanker company. As the winter season is also coming up, demand should increase, lending a general recovery in the fourth-quarter rates, Kolding added. VLCC freight rates have steadily moved higher from about 11 months-low because of active chartering activity late last week, with several freight participants also noting that they have already touched a bottom and should continue rebounding. The Argus -assessed rate for a VLCC carrying a dirty cargo from the Mideast Gulf to southeast Asia rose to $7.52/t on 11 September, from the 11 months-low of $6.49/t on 4 September. Tanker freight rates in 2025 will still be strong compared with past years, Radhakrishnan said, but might be slightly weaker than in 2024. With freight rates in the first quarter being seasonally strong, the market should be off to a good start, Kolding added, but noted that "we still got to keep an eye on geopolitical effects." The Red Sea conflict has played a huge part in freight rates this year because of increased tonne-mile demand and costs as vessels reroute through the Cape of Good Hope, said Kolding, adding that it would take a while for the conflict to be resolved. Rates could also find further support if crude prices continue to fall, attracting charterers to book tankers such as VLCCs as offshore storage for oil, the conference moderator said. By Sean Zhuang Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Australia’s Victoria seeks further gas storage capacity
Australia’s Victoria seeks further gas storage capacity
Singapore, 12 September (Argus) — The state Labor government of Victoria will introduce laws to allow offshore gas storage projects in its waters as it grapples with a predicted supply deficit because of declining Bass strait production. Victoria, which is Australia's largest user of household and commercial gas, will allow gas to be stored in empty gas reservoirs offshore in a bid to boost supply security, Victorian energy minister Lily D'Ambrosio said on 11 September. But the state's waters extend three nautical miles offshore, meaning the laws will not cover most of the state's depleted fields in the Otway and Gippsland basins which lie in federally administered zones. Victoria's largest storage is the 26PJ (694.3mn m³) onshore Iona facility in the state's west, owned by domestic gas storage firm Lochard Energy which plans to expand its capacity by 3PJ . But further capacity is needed to help bridge seasonal gaps, with the new laws possibly advancing privately-owned GB Energy's Golden Beach gas project, which could add 12.5PJ of storage to the grid. The Gippsland basin joint venture (GBJV) and Kipper Unit JV which feed the three Longford gas plants in the state's east have historically supplied about 60pc of southern states' gas, but operator Exxon plans to close one of the plants in July-October , cutting the 1.15 PJ/d facility's capacity to 700 TJ/d and further to 420 TJ/d later this decade. GBJV operated just 50 producing wells and six gas platforms in the 2024 southern hemisphere winter, with Exxon expecting a 70pc reduction in the number of wells from 2010 levels by next winter. The Australian Energy Market Operator's (Aemo) 2024 Victorian Gas Planning Report (VGPR) update confirmed the need for greater supply in Victoria, as declining demand would not offset the loss of supply from the GBJV. Peak southern state winter demand exceeds 2 PJ/d, but at full capacity, pipelines linking Queensland state's coal-bed methane fields to the southern states can meet only 20pc of such demand. Coal and gas-dependent Victoria this year approved its first nearshore gas project in a decade as the government softens its anti-gas stance. LNG import plans The possibility of LNG imports is firming in Victoria, with Australian refiner Viva Energy announcing public consultation has begun on its supplementary environmental effects statement (EES) for a planned floating storage and regasification unit, adjacent to its 120,000 b/d Geelong refinery. The Geelong LNG terminal would have the capacity to supply more than half of Victoria's current gas demand, Viva said on 12 September. The terminal's surplus gas could also flow into the connected southern states of South Australia, New South Wales and Tasmania. A public hearing into the proposal, which could see the import of 45 cargoes/yr, is expected to be held in December before an independent committee reports to the state's planning minister next year. Subject to a final investment decision, works could commence in 2026 to deliver first gas for winter 2028, Viva said, aligning with Aemo's expected shortfall of 50PJ in that year. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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