Australian Enterprise gas drives Beach’s Apr-Jun output
Australian independent Beach Energy produced more gas and liquids during April-June than the previous quarter but ended its 2023-24 fiscal year to 30 June with output down against a year earlier.
April-June sales gas production of 20.2PJ (539mn m³) was 10pc higher than the previous quarter's 18.3PJ and up on April-June 2023's 19.6PJ as it commissioned its Enterprise field in Victoria state's Otway basin.
Beach's total 2023-24 production of 18.5mn bl of oil equivalent (boe) was 5pc down on the 19.5mn boe achieved in 2022-23, with natural field decline and rainfall resulting in Beach's oil output falling by 11pc from the previous quarter to 7,400 b/d from 8,300 b/d in January-March.
The firm shipped a second 79,000t Waitsia cargo from the Woodside-operated 16.9mn t/yr North West Shelf LNG terminal during the quarter, consisting of Xyris gas plant production and third-party surplus gas sourced through swaps.
It expects to achieve the first gas at its delayed 250 TJ/d (6.7mn m³/d) Waitsia gas plant in Western Australia's onshore Perth basin in early 2025 ahead of a 3-4 month ramp-up period.
The firm has released a wider than usual production guidance for 2024-25 of 17.5mn-21.5mn boe, to account for uncertainty on the timing of Waitsia commissioning and output growth.
Beach identified A$135mn ($90.5mn) in field operating cost savings and sustaining capital expenditure reductions as part of its strategic review findings released on 18 June.
Beach confirmed it expects to recognise an A$365mn-400mn pre-tax impairment charge in its full-year results following reassessment of its Bass basin assets in Australia and Taranaki basin project in New Zealand.
It is targeting new gas supplies of 150 TJ/d over the coming 12-18 months from the Enterprise, Thylacine West and Waitsia fields.
| Beach Energy results (mn boe) | |||||
| Apr-Jun '24 | Jan-Mar '24 | Apr-Jun '23 | 2022-23 | 2023-24 | |
| Production | 4.8 | 4.5 | 5.0 | 19.5 | 18.2 |
| Sales | 5.4 | 4.8 | 5.7 | 20.7 | 21.3 |
| Sales revenue (A$) | 433 | 392 | 450 | 1,617 | 1,766 |
| Realised gas price (A$/GJ) | 10.30 | 9.70 | 9.50 | 8.80 | 9.50 |
| Source: Beach Energy | |||||
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Greece's Desfa to front-load gas grid expansion plans
Greece's Desfa to front-load gas grid expansion plans
London, 10 September (Argus) — Greek transmission system operator Desfa plans to complete nearly all the gas projects in its updated 10-year development plan (TYDP) within the next three years. Desfa's projected spend on all projects comes to over €1.37bn, of which €1.34bn would be used within the next three years. The most important of these projects are presented below, split by category. Interconnectors Desfa expects the 1.5bn m³/yr Greece-North Macedonia interconnector to start commercial operations in January 2026, a delay of roughly a year from the timeline it gave in October 2023. The pipeline will run from Nea Messimvria — where Azeri gas enters the Greek grid — to Gevgelija and will cost around €92mn. LNG terminals The connection of the Dioriga LNG terminal will start commercial operations in December 2026, according to the latest TYDP, 1½ years later than previously envisaged. Desfa expects to reach a final investment decision (FID) on a metering and regulating station to connect the planned Dioriga LNG terminal in February 2025. Developer Motor Oil Hellas recently told Argus it plans to make FID on the project by the end of this year . The project will cost Desfa around €21mn and will be financed through connection fees. The new entry point will have a capacity of around 11.8mn m³/d, or 4.3bn m³/yr. Desfa expects a new small-scale jetty already under construction at Revithoussa to start commercial operations in December 2025. The €38mn project will enable ships with capacities of 1,000-30,000m³ of LNG to unload and reload. And Desfa has also taken FID on a compressor station for Revithoussa, which will allow for boil-off gas to be sent into the transmission system rather than flared. Commercial operations are envisioned to start in May 2025. No mention of grid connections for the Argo floating storage and regasification unit or Thessaloniki LNG projects were included in the TYDP, throwing their future into further doubt following recent delays . Power plants Desfa included multiple pipeline connections to gas-fired power plants in the TYDP. The operator expects the 877MW Thermoilektriki Komotinis plant's connection to the grid to start commercial operations in October. It will have a capacity of around 3.4mn m³/d, or 1.24bn m³/yr. The project's operators expect test operations to begin this autumn . Another project will connect Elpedison's planned 826MW plant near Thessaloniki, with a capacity of around 1.14bn m³/yr. Desfa envisions commercial operations beginning in November 2025. A third project would connect to an 840MW plant at Alexandroupolis and start commercial operations in May 2027. Lastly, Desfa expects a project connecting the 873MW Larisa Thermoelectriki plant to start commercial operations in mid-2027. Pipeline capacities for these two projects were not disclosed, but would likely be similar to the first two. Compressor stations Several compressor station plans have been delayed, notably at Komotini and Ampelia. The two expansion phases at Komotini have been pushed back by six months to March and June 2025, respectively, because of delays during the permitting process. The project will increase the system's "technical adequacy", as well as its capacity, according to Desfa. And Desfa expects the compressor station at Ampelia, a crucial part of enabling higher north to south transmission, to start commercial operations only in June 2025. The nine-month delay is because of "extreme weather events" in the area in 2023. And a booster compressor for the Trans-Adriatic pipeline at Nea Messimvria — which will enable fully bidirectional flows — is scheduled to start commercial operations in December 2025. Permitting delays have pushed back the start date by more than a year. Domestic grid Several large projects are also in the works to expand the domestic grid. Desfa plans a 145km pipeline to connect the city of Patras and its industrial area to the grid, expecting FID in June 2025 and the start of commercial operations in March 2027. The pipeline will have a capacity of around 240mn m³/yr, but with the possibility to be doubled if demand is sufficient. Desfa is also planning a 157km pipeline to connect west Macedonia and a metering station at Kardia-Kozani, with a planned capacity of around 440mn m³/yr. This project will help to enable gas supply to district heating installations in the area, Desfa said. Desfa has taken FID and expects commercial operations to start in June 2025. And Desfa's most expensive plan, at €311mn, will duplicate the 215km main transmission line from Karperi to Komotini. This will increase capacity from north to south and aims to eliminate bottlenecks for the provision of firm capacity from new entry and exit points in the northern part of the system, as well as the provision of firm access to the VTP. This will increase liquidity and provide "equitable access to all northern exit points, and is a "priority project" for Desfa. FID is planned for June 2025, and commercial start-up in March 2027. A related €151mn plan will duplicate the 100km Patima-Livadeia line, which will increase pressure in the system and enable firm capacity from the Dioriga Gas terminal. FID is planned for October 2025, and commercial operations in March 2027. By Brendan A'Hearn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Opec trims oil demand growth forecasts again
Opec trims oil demand growth forecasts again
London, 10 September (Argus) — Opec has cut its global oil demand growth forecasts for 2024 and 2025 for a second month in a row, but its projection for demand remains way above other outlooks. In its latest Monthly Oil Market Report (MOMR) the producer group revised down its 2024 demand growth projection to 2.03mn b/d from 2.11mn b/d. This is mainly due to lower than previously expected oil demand growth from China and the US. It now sees China's oil demand growing by 650,000 b/d this year, compared with 700,000 b/d in the previous report. It cut US oil demand growth by 60,000 b/d to 110,000 b/d. Opec's forecast for this year remains bullish. The IEA projects oil demand will increase by 970,000 b/d this year, and the EIA sees demand rising by 1.1mn b/d. Opec noted its 2mn b/d growth forecast for this year "remains well above the historical average of 1.4mn b/d seen before the Covid-19 pandemic." Oil prices have declined sharply in early September following weaker-than-expected economic data from the US and China. And on 5 September eight members of the Opec+ alliance agreed to delay a plan to start increasing output by two months. Opec also today cut its oil demand growth forecast for next year, by 40,000 b/d to 1.74mn b/d, again mainly driven by lower consumption growth estimates this time in the Middle East. On the supply side, the group has kept its non-Opec+ liquids growth estimate for 2024 and 2025 unchanged at 1.23mn b/d and 1.10mn b/d, respectively. Opec+ crude production — including Mexico — fell by 304,000 b/d to 40.655mn b/d in July, according to an average of secondary sources that includes Argus . This is about 2.15mn b/d below Opec's projected call on Opec+ crude for this year, which stands at 42.8mn b/d. By Aydin Calik Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Asia has TMX option as heavy crudes tighten: PetroChina
Asia has TMX option as heavy crudes tighten: PetroChina
Singapore, 10 September (Argus) — The recently expanded 590,000 b/d Trans Mountain Expansion (TMX) pipeline's start-up has improved Asian refiners' access to heavy Canadian crude at a time when supplies of such grades have tightened, PetroChina International's chief economist Wu Qiunan said. The TMX pipeline has cut the shipping time to export crude from Canada's west coast to Asia-Pacific to "only 19 days compared with the US Gulf [coast] which is basically 45 days," Wu said at the S&P Global Commodity Insights Appec conference in Singapore on 9 September. This "opens a very good option for Asia to receive more from Canada". Wu pointed out that the Middle East is seen as the "natural supply" source of crude for Asian refiners, but the freight distance to ship crude from the region is now similar to shipping crude from Canada's west coast. Canadian crude exported from the TMX pipeline is also heavy, while supplies of similar-quality crude from the Mideast have become tighter because of Opec+ production cuts. This meant that Asian refiners will "find value" for such heavy grades. Canadian crude is also not cheap and in fact has found "a fair price", Wu said. Asian demand will continue to grow in importance against the prospect of increasing production from the Americas, including from Guyana and Brazil. Asian demand has been key in soaking up the growth of US production and exports, Norway's state-controlled Equinor's senior vice-president for crude products and liquids Alex Grant said, with Asian oil demand and US supply growth sharing a "symbiotic" relationship. But the potential production increase from the Americas brings uncertainty to the outlook for US shale growth, especially with the current negative sentiment over oil demand growth. "We know there's going to be a lot of sources of [supply] growth coming in the next year or two, no matter what the price," Grant said. "So, the big question is what happens to US shale growth?" By Fabian Ng Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
US Gulf producers curb operations before storm: Update
US Gulf producers curb operations before storm: Update
Adds latest NOAA forecast data, BP update. New York, 9 September (Argus) — Oil companies started to evacuate workers and halt some operations in the US Gulf of Mexico ahead of an expected hurricane later this week. Tropical storm Francine, which is forecast to strengthen to hurricane status as it moves north toward the Texas and Louisiana coasts by mid-week, threatens an offshore region that accounts for about 15pc of US crude output and 5pc of US natural gas production. Shell said it paused some drilling operations at the Perdido and Whale platforms, located about 190 miles south of Houston, and is withdrawing non-essential workers from its Enchilada/Salsa and Auger facilities. ExxonMobil said all staff had been transported off the Hoover platform, located about 200 miles south of Houston, and operations shut-in. And Chevron said it is evacuating non-essential workers from its Anchor, Big Foot, Jack/St. Malo and Tahiti facilities, though production from company-operated assets remains at normal levels. Those facilities are located about 280 miles south of New Orleans. "We continue to supply our customers at our onshore facilities, where we are following our storm preparedness procedures and paying close attention to the forecast and track of the storm," Chevron said. So far no major problems are reported for BP's offshore facilities in the region. Francine is forecast to approach the Louisiana and upper Texas coast on Wednesday, according to the National Hurricane Center. In a 2pm ET NHC advisory, the storm was about 450 miles south-southwest of Cameron, Louisiana, with maximum sustained winds of 60 mph. Strengthening is expected over the next day and Francine is forecast to be a Category 1 hurricane, with winds of 85mph, on Wednesday evening, when it is expected to make landfall along the Louisiana coast. By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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