Australia’s Woodside records weaker Jan-Mar LNG output

: Crude oil, Natural gas
24/04/19

Australian independent Woodside Energy's January-March output dropped against a year earlier and the previous quarter, as reliability fell at its 4.9mn t/yr Pluto LNG project offshore Western Australia.

Woodside produced 494,000 b/d of oil equivalent (boe/d) across its portfolio for January-March, 5pc below the 522,000 boe/d reported during October-December and 4pc below its 2023 full-year figure of 513,000 boe/d.

Lower production at its Bass Strait, Pyrenees and Pluto assets was partially offset by increased production at the 140,000 b/d Mad Dog phase 2 oil field in the US Gulf of Mexico, which hit peak production of 130,000 b/d during the quarter.

Reliability at Pluto was 94.6pc for the quarter because of an offshore trip and an onshore electrical fault. Woodside made a final investment decision (FID) on the Xena-3 well to support Pluto production during the quarter.

The 16.9mn t/yr North West Shelf (NWS) LNG achieved 97pc reliability for the quarter with NWS' joint-venture partners taking a FID on the Lambert West field, which will support continuing production.

Lower seasonal market demand and offshore maintenance activity saw production drop at the firm's Bass Strait fields, while production ended at the Gippsland basin joint venture's West Kingfish platform because of slowing oil output from Kingfish field.

The Pyrenees floating production storage and offloading vessel began planned maintenance in early March and will return to crude production for April-June, Woodside said. Two 550,000 bl cargoes of Pyrenees crude loaded each quarter during 2023.

Revenue dropped by 31pc to $2.97bn from $4.33bn a year earlier and 12pc from $3.36bn during October-December. Woodside's total average realised price dipped to $63/boe, 6pc down on the previous quarter's $67/boe and 26pc below the year-earlier figure of $85/boe.

Woodside's average realised price for LNG produced was $10.40/mn Btu or 10pc down on the previous quarter's $11.50/mn Btu. The firm is more heavily exposed to spot prices and gas hub pricing than fellow domestic LNG producer Australian independent Santos, with about 30pc of Woodside's equity-produced LNG sold at these spot prices.

By Tom Major

Woodside LNG production (mn boe)
	NWS	Pluto	Wheatstone*	Total

Jan-Mar '24	8.2	11.8	2.4	22.3
Oct-Dec '23	7.8	12.4	2.5	22.7
Jan-Mar '23	9.7	12.2	2.5	24.3
2023	32.8	45.6	10.2	88.6
2022	29.7	46.2	9.2	85.1
y-o-y % ±	-15	-3	-4	-8
q-o-q % ±	5	-5	-4	-2
Source: Woodside
*Woodside controls a 13pc interest in Wheatstone LNG

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24/10/16

IEA sees steeper oil demand fall in long-term outlook

London, 16 October (Argus) — Long term global oil demand is set to fall by more than previously anticipated, according to the baseline scenario in the IEA's latest World Energy Outlook (WEO). The Paris-based agency's stated policies scenario (Steps), which is based on prevailing policies worldwide, sees global oil demand — excluding biofuels — falling to 93.1mn b/d in 2050, compared with 97.4mn b/d in last year's WEO. This is mainly because of lower-than-previously expected oil use in transportation, particularly in shipping. The Steps scenario still sees global oil demand peaking before 2030 at less than 102mn b/d, after which it falls to 2023 levels of 99mn b/d by 2035. This is mostly because of a rapid uptake of electric vehicles (EVs), reducing oil demand for road transport. EVs have displaced around 1mn b/d of gasoline and diesel demand since 2015 and are set to avoid 12mn b/d of oil demand growth between 2023 and 2035 under Steps, the IEA said. The latest Steps scenario shows China's pre-eminence in global oil demand growth is fading, as the world's second largest oil consumer shifts towards electricity. Steps sees Chinese oil demand growing by just 1.2mn b/d to 17.4mn b/d by 2030, and then falling to 16.4mn b/d by 2035 and to 11.8mn b/d by 2050. India overtakes China as the world's main source of oil demand growth in Steps, adding almost 2mn b/d by 2035 and 2.4mn b/d by 2050. But its oil consumption in 2050 of 7.6mn b/d will still be lower than China's in the same year. The IEA's latest baseline oil demand scenario widens the gap with producer group Opec, which sees oil consumption continuing to rise to 2050 "with the potential for it to be higher." Opec's World Oil Outlook (WOO) — released in September — bumped up its long-term oil demand forecast to 2045 by around 3mn b/d compared with its previous release. It extended its forecast period to 2050, when it put oil demand at 120mn b/d. That equates to a 27mn b/d difference between the IEA and Opec baseline oil demand scenarios in 2050. Binding contraction The IEA said the slowdown in oil demand growth in its Steps scenario puts major resource owners, such as Opec+ countries, "in a bind" as they face a significant overhang of supply. Global spare oil production capacity of around 6mn b/d is set to rise to 8mn b/d by 2030 if announced projects go ahead, it said. The Steps scenario sees global oil production falling from 96.9mn b/d in 2023 to 90.3mn b/d in 2050, with Opec increasing its share of output from 34pc to 40pc in the period. Steps sees US oil supply growth continuing to 2030 and then contracting by around 250,000 b/d a year on average between 2030-50. Brazil, Argentina and Guyana are seen adding more than 2.5mn b/d to supply by 2035. The WEO explores two other scenarios — the announced pledges scenario (APS) assumes government targets on emissions are met in full and on time, while the net zero emissions by 2050 (NZE) scenario lays a path to limit global warming to 1.5°C. Oil demand in 2050 in APS and in NZE is lower compared with last year's WEO. In APS, oil demand falls to 92.8mn b/d by 2030, 82mn b/d in 2035 and 53.7mn b/d by 2050 — with around 135mn more EVs on the road by 2035 compared with Steps. In NZE, oil demand falls to 78.3mn b/d by 2030, 57.8mn b/d by 2035 and 23mn b/d by 2050 — with 1.14bn more EVs on the road by 2035 compared with Steps. By Aydin Calik Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

PetroChina offloads TMX crude pipeline commitment

24/10/15

PetroChina offloads TMX crude pipeline commitment

Calgary, 15 October (Argus) — PetroChina Canada is no longer a shipper on the 590,000 b/d Trans Mountain Expansion (TMX) crude pipeline, less than six months after Canada's newest pipeline went into service. The Chinese-owned refiner has parted with its commitment on the pipeline connecting Edmonton, Alberta, to Burnaby, British Columbia, according to a letter to the Canada Energy Regulator on 10 October. The project has helped Canadian crude producers reach new markets on the Pacific Rim, with China often singled out as a target. PetroChina Canada "has now assigned these agreements to another party and will not be a committed shipper going forward," the letter read, without disclosing the other company or reasoning. TMX roughly tripled the capacity of the Trans Mountain system to 890,000 b/d when it went into service on 1 May, but critics questioned how useful the expansion would be. Shippers were quick to dispel any concerns about the line's utilization by ramping up throughputs in the first few months of service. The latest official figures from Trans Mountain show 704,000 b/d was shipped in June , its first full month of operation. However, the expansion was riddled with construction delays and of concern is who will ultimately foot the bill for the C$35bn ($25bn) project's cost overruns — Trans Mountain or shippers through higher tolls. The original budget for the project was C$5.5bn when first conceived more than a decade ago with many of the shippers signing up for capacity around that time. The tolling dispute will continue into 2025 to determine what portion of the extra costs the shippers will be responsible for, with the regulator responsible for making the final decision. Interim tolls in place have the fixed costs for a heavy crude shipper with a 20-year term to move 75,000 b/d or more at about C$9.54/bl ($6.96/bl). "Shippers should not reasonably be expected to be subject to C$7.4bn (and counting) in cost growth without serious scrutiny of Trans Mountain's costs," lawyers in March this year told the CER on behalf of several shippers, including PetroChina. Trans Mountain says approximately 80pc of the TMX is backed by firm commitments with the balance saved for walk-up shippers. PetroChina Canada owns the MacKay River oil sands project in northeast Alberta which has produced about 10,000 b/d of bitumen from January to August this year, according to data from the Alberta Energy Regulator (AER). PetroChina Canada also owns the undeveloped Dover oil sands project, has a 50pc stake in the Grand Rapids oil sands pipeline, natural gas production in western Canada and a 15pc stake in the 14mn t/yr LNG Canada export facility. By Brett Holmes Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Lignite displaces gas in German power mix

24/10/15

Lignite displaces gas in German power mix

London, 15 October (Argus) — Rallying German gas prices have pushed a significant amount of gas-fired generation out of the country's power mix this month, opening space for lignite. Average daily gas-fired generation in Germany has slipped to 3.8GW so far this month from 4.2GW in September and August and 4.1GW in July. During that time, lignite-fired generation climbed to 9GW from 7.2GW in September and August and 7.4GW in July. Coal-fired generation has also edged down to 2.9GW so far this month from just over 3GW in September, but higher than the averages of 2.3GW in August and 1.4GW in July. Meanwhile, supporting demand for thermal-fired generation, German renewables output has fallen to 30.3GW so far in October from just under 32GW in September when wind generation stepped up, but slightly above the 29.5GW in August when wind output was lower. Remaining German power demand in recent weeks has been covered by imports, which have risen to a net 3.8GW so far this month from 3.4GW in September, but remained well below the 6.2GW in August. Electricity imports from neighbouring countries such as France are occasionally cheaper than domestic generation and can help fill in gaps between German power demand and supply. A combination of changing renewable output, higher gas prices, stable lignite prices and lower emissions prices have spurred changes in the German power mix. The German THE day-ahead has risen strongly since late July and prices have rallied in recent weeks against a backdrop of rising geopolitical tensions in the Middle East. Meanwhile, German lignite-fired plants typically source fuel from nearby mines, substantially insulating domestic lignite prices from external market forces. German regulator Bnetza assumed earlier this year that domestic lignite would cost about €3/MWh in 2024-25. At the same time, near-term prices in the EU emissions trading system (ETS) — a key driver of competitiveness for German lignite-fired generation — have fallen. Prompt ETS allowances closed at €65.36/t of CO2 equivalent (CO2e) on Monday, down from €72.14/t CO2e on 19 August, boosting the profitability of lignite-fired plants, which are the more CO2 intensive than coal and gas. Those recent price shifts have made output from lignite-fired plants with a typical efficiency of 36pc more profitable than normal 55pc-efficient gas-fired plants as well as coal-fired stations operating at 40pc efficiency, which have also become more profitable . By contrast, in the first eight months of this year, 36pc-efficient lignite-fired plants had competed tightly with 55pc-efficient gas-fired plants even as gas prices fell to the bottom of the coal-to-gas fuel-switching range ( see fuel-switching graph ). Buffer zone More competitive lignite-fired generation has also started acting as the domestic buffer to cover gaps between supply and demand left by renewable generation ( see power generation graph ). After Germany renewable generation dropped to 26.8GW on 2-9 October from a strong 45.5GW on 26-28 September, lignite-fired generation jumped to 10.1GW from 6.4GW — a 57pc gain — while gas-fired output only rose to 3.5GW from roughly 3GW and coal-fired generation increased to 2.9GW from 2.3GW. In December-July, when the gas and lignite fuel-switching range was tight, generation from both fuels reacted similarly to fluctuations in renewable output and both plant types buffered their generation based on demand ( see power generation graph ). And forward prices assessed by Argus suggest that lignite-fired generation could remain competitive against gas and coal-fired output in the German power mix next month. As of market close on Monday, November-dated fuel and emissions prices would place the operating costs of a 36pc-efficient lignite-fired plant during that time below those of a 55pc-efficient gas-fired plant and a 40pc-efficient coal-fired plant. That said, Germany's decreasing lignite and coal-fired generation capacity limits how much of the national power mix those plant types can provide. As of April, Germany had 82.4GW of gas-fired capacity, but just 15.1GW of lignite-fired capacity and 11.5GW of coal-fired plants, according to Bnetza. By Lucas Waelbroeck Boix Fuel switching range €/MWh Power generation by fuel, 7 day average GW Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

IEA points to oil stocks in case of supply disruption

24/10/15

IEA points to oil stocks in case of supply disruption

London, 15 October (Argus) — The world can draw on global oil stocks and rely on Opec+ spare production capacity in case of a supply disruption erupting from the conflict between Iran and Israel, the IEA said today. In its latest Oil Market Report , the Paris-based watchdog said it was "ready to act if necessary." It said IEA public stocks alone stood at over 1.2bn bl in addition to 500mn bl held under industry obligations. The IEA also said non-member China held 1.1bn bl of crude stocks, enough to meet 75 days of domestic refinery runs. The IEA co-ordinated two emergency stock releases in 2022 after Russia invaded Ukraine. The world's reliance on stocks would become more pronounced if any supply disruption extended beyond Iran's oil industry to include flows through the Strait of Hormuz. This would threaten most Opec+ spare production capacity of more than 5mn b/d as members such as Saudi Arabia, Iraq, Kuwait and the UAE are highly reliant on the waterway to export their oil. But as long as supply keeps flowing, the IEA said that the market faces a "sizeable surplus" next year. The agency's latest balances show a supply surplus of 1.11mn b/d in 2025, up by 50,000 b/d compared with its estimates last month. For this year, the agency now sees a slight surplus of 90,000 b/d, compared with a slight deficit last month. In the final quarter of this year, the IEA sees a surplus of around 200,000 b/d. Concerns over the strength of oil demand have been rising in recent months, with the IEA once again trimming its oil consumption forecast for this year. The IEA cut its 2024 global oil demand growth forecast by another 40,000 b/d this month to 860,000 b/d, with China once again the main driver. A slowdown in China's economy remains the key drag on oil consumption growth. The IEA sees China's oil demand this year increasing by 150,000 b/d compared with 180,000 b/d in its report last month. At the start of the year the agency was guiding for growth of 710,000 b/d from China. The IEA also downgraded its estimated growth from China for next year to 220,000 b/d from 260,000 b/d last month, despite the country's recently announced stimulus packages. For next year, the agency sees oil demand growth slightly higher at 1mn b/d, up by 40,000 b/d from last month's report. But growth for both 2024 and 2025 is set to remain well below 2023's post-pandemic surge in growth of just under 2mn b/d. On global supply, the IEA kept its growth estimate broadly unchanged at 660,000 b/d. But it expects global growth to be just above 2mn b/d next year even if all Opec+ cuts are maintained. Some members of Opec+ are due to start unwinding 2.2mn b/d of voluntary cuts starting in December — although this is dependent on market conditions. The IEA said that the 500,000 b/d fall in Opec+ crude production in September — led by Libya — could make it easier for the alliance to implement its plan to raise output, although healthy non-Opec+ supply growth next year will remain a concern. The agency said global observed oil stocks declined by 22.3mn bl in August, led by a 16.5mn bl draw on crude. It also said preliminary data showed stocks fell further in September. By Aydin Calik Global oil supply/demand balance mn b/d Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Guyana crudes pressured by end of Libya blockade, TMX

24/10/14

Guyana crudes pressured by end of Libya blockade, TMX

Houston, 14 October (Argus) — The restoration of Libyan crude production and an influx of heavy-sour Canadian grades to the US west coast has pressured light sweet Guyana crudes to their widest differential against Argus North Sea Dated since the assessments launched in February. Values for Guyana crudes Liza, Unity Gold and Payara Gold fell by 20-80¢/bl last week as offer levels fell swiftly. Liza reached a $1.20/bl discount against North Sea Dated, Unity Gold fell to a 35¢/bl discount and Payara Gold a 33¢/bl discount. Liza and Unity Gold fell to their lowest value since Argus began to assess the grades, while Payara Gold fell to its lowest level since mid-March. European refiners had turned toward Guyana after the 26 August start of the Libyan oil blockade , with imports rising by around 200,000 b/d to almost 456,000 b/d in September, according to data analytics firm Vortexa, reflecting the highest flows on that route since March. Libya has since recovered to more than 1mn b/d of production after the country's oil blockade ended on 3 October, according to data from state-owned oil company NOC published last week. Output in September was less than half of pre-blockade levels, with Libya's crude exports down to 460,000 b/d in that month compared with 1.02mn b/d in August, according to Kpler data. Projected October Guyana exports to Europe are 205,000 b/d lower than September at only 193,000 b/d, Vortexa data shows. TMX takeover Guyana prices also could be under pressure from added competition on the Americas Pacific coast from crude exported via the 590,000 b/d Trans Mountain Expansion (TMX) pipeline. In May, before the startup of TMX, Guyanese exports to the US totaled 68,000 b/d, data from Vortexa shows. Refiners did not purchase any Guyanese grades in June and August, and imports in July and September were more than halved from May levels at 32,000 b/d and 29,000 b/d, respectively. Vortexa estimates October deliveries will only amount to less than 29,000 b/d, a 57pc decrease since the start of TMX. TMX has quickly become a valuable crude source to US west coast refiners, displacing many Latin American grades in the process. Ecuadorean crude imports have trended lower since May, and were down by 30pc from June-September compared to a year earlier. Crude volumes arriving at Panama's PTP pipeline from Colombia — a common way US west coast refiners receive Colombian crude — have also trended lower since July. September crude receipts of Colombian grades into Panama have fallen from 173,000 b/d in July to 50,000 b/d in September. By Rachel McGuire and Joao Scheller Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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