Australia RBA forecasts continued firm iron ore exports
Australian iron ore exports are expected to remain strong for the next 12 months because of firm demand from China and extended disruptions in Brazil, the Reserve Bank of Australia (RBA) forecast.
Extended maintenance at some LNG facilities is expected to weigh on LNG exports, while coal exports are expected to be lower because of weaker global demand for coal, Australia's central bank said in its quarterly economic statement. "By contrast, iron ore exports are expected to remain strong."
The benchmark iron ore price has remained elevated since the previous RBA statement in August, briefly reaching its highest level since 2014 in early September. The iron ore price has been supported by continued strength in Chinese steel production, underpinned by public infrastructure and real estate construction.
Port congestion in China has also supported prices, although this has eased more recently. Supplies of iron ore from Brazil have increased following various disruptions earlier in the year, which has dampened the upwards pressure on prices, the RBA said.
Australia's iron ore exports rose in September from a year earlier and were 3.9pc up for January-September.
The RBA maintained its view of firm investment in new iron ore producing capacity and associated infrastructure from its August statement. But it was not as optimistic about the outlook for thermal and coking coal because of the prospect of Chinese import restrictions on Australian coal shipments.
Coking coal prices are not far from their lows for the year. Reports that some Chinese utilities and steel mills have been instructed to stop importing Australian coal have led to increased uncertainty about the demand outlook for seaborne coal, the RBA said. But thermal coal prices have rebounded of late, underpinned by gradually rising global demand and earlier supply cutbacks from producers, it said.
Coking and thermal coal prices have also been supported by analysts' concerns that predicted increased rainfall over Australia, as a result of the La Nina weather pattern, will disrupt supplies in the coming months, the RBA said. Heavy flooding during Australia's last significant La Nina period led to a 20pc fall in Queensland's coal production in the January-March quarter of 2011.
LNG market conditions have improved from earlier in the year from the impact of the Covid-19 pandemic, the RBA said. Higher oil prices will result in an increase in the average price received by Australian LNG exporters for the October-December quarter. The majority of Australia's LNG exports are sold via long-term contracts linked to oil prices at a one to two quarter lag. The Asian LNG spot price has also recovered over the past few months because of extended maintenance at some Australian LNG projects and disruptions to US supplies, while demand has also picked up.
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Oil emissions progress slows ahead of Cop 29
Oil emissions progress slows ahead of Cop 29
London, 12 August (Argus) — After a unanimous agreement to "transition away from fossil fuels" at last year's UN Cop 28 summit in Dubai, the oil industry says it stands by its net-zero goals. But its short-to-medium term focus on increasing production appears in conflict with last year's agreement, and with the ambition required from the forthcoming round of national climate plans, expected over the next year. Large Mideast Gulf national oil companies (NOCs) have mostly stuck to their net zero milestone targets, but continue to avoid making any commitments concerning the Scope 3 emissions that come from the use of their products. These account for the overwhelming majority of oil and gas company emissions. State-controlled Saudi Aramco is keeping its ambition to reduce by 15pc the carbon intensity of its upstream production by 2035, targeting 7.7kg of CO2 equivalent per barrel of oil equivalent (CO2e/boe) against the company's 2018 baseline figure of 9.1kg CO2e/boe. It intends to achieve net zero Scope 1 and 2 emissions from its operations by 2050. But last year, Aramco's upstream carbon intensity measure increased by 3.2pc, compared with 2022, to 9.6kg CO2e/boe, in part because the company increased its gas production. Aramco says gas is more energy and carbon-intensive to produce, despite being a lower-emitting fuel when it is used. Riyadh recently put the brakes on Aramco's plan to lift crude production capacity to 13mn b/d from 12mn b/d by 2027 as it ushers in an ambitious gas expansion programme, which fits the view within the industry that gas is a "transition fuel". Aramco plans to increase its gas production by more than 60pc by 2030, compared with its 2021 production. Meanwhile, lower overall hydrocarbon production helped decrease Aramco's Scope 1 emissions by 2.4pc between 2022 and 2023. Its Scope 2 emissions jumped by 26.3pc, although this was mainly because of the inclusion in Aramco's greenhouse gas (GHG) emissions inventory of the new Jazan refinery, which became fully operational in early 2023. Slower burn Riyadh is also turning to renewables, with the aim of delivering significant growth in lower-emission power to the national grid and providing an opportunity for Aramco to lower its Scope 2 GHG emissions. Domestic renewable power will free up more crude production for exports and reduce crude burn. Riyadh plans to increase the share of renewables in its oil-and-gas-heavy energy mix to 40pc by 2030. How Saudi Arabia could change its climate plans by early next year remains to be seen. All Cop parties have to reflect the outcome of Dubai, including transitioning away from fossil fuels, in their new nationally determined contributions (NDCs) — climate plans — due by February 2025. Saudi energy minister Prince Abdulaziz bin Salman said in January that the Cop 28 text was something his country "was willing to agree on because this is something we are doing". Oil and gas producers the UAE, Azerbaijan and Brazil — the so-called Cop presidencies Troika — last month encouraged parties to "step up the work" on NDCs and keep the Paris Agreement's 1.5°C target in reach. The three countries called on "early movers", including themselves, to signal their commitment as early as September, but always within "national capacities". "The ambition of keeping 1.5°C within reach in a nationally determined manner and building global resilience will be determined by our resolve to act at this critical moment," the three presidencies said. In Abu Dhabi, state-owned Adnoc is moving forward with plans to raise its crude production capacity to 5mn b/d by 2027, after bringing this to 4.85mn b/d earlier this year. It is also heavily investing in expanding its LNG business. But it has brought forward its ambition to achieve net zero across its operations by five years to 2045. By 2030, it aims to reduce its upstream GHG intensity by 25pc compared with its 2019 level. This metric stayed flat at 7.2kg CO2e/boe in 2023, although Adnoc notes its performance is in the industry's top tier. Adnoc's key advantage is that since 2022, all its onshore activities have received "clean electricity" through the grid from nuclear and solar facilities. The western majors are sticking to milestone targets that were already in place last year. Shell made a slight adjustment to its 2030 reductions goal for Scope 3 emissions coming from the use of its oil products by introducing a target range of 15-20pc, against a 20pc target previously. BP is sticking to its interim targets for 2025 and 2030, which it revised at the start of 2023, as is TotalEnergies. In the US, Chevron has kept to its target for a portfolio carbon intensity of 71g CO2e across Scopes 1, 2 and 3 by 2028 — representing a 5.2pc decrease against the company's 2016 baseline. ExxonMobil's emission-reduction plans remain the same, aiming to achieve "a 20-30pc reduction in company-wide GHG intensity" by 2030. Despite the majors making plenty of progress in nearing these 2025-30 emissions-reduction milestones in 2022 and 2023, the latest data reveal this progress began to slow last year. Shell's Scope 1 and 2 emissions fell by just one percentage point in 2023 to 31pc below their 2016 baseline, after having fallen by 12 percentage points the year before. BP's Scope 1 and 2 emissions cuts, compared with its 2019 baseline, remained steady at 41pc between 2022 and 2023. TotalEnergies was one major that improved its progress on Scope 1 and 2 last year, reducing these emissions by 24pc against its 2015 baseline. Although the progress at BP and TotalEnergies means those companies have already dipped below their Scope 1 and 2 emissions targets for 2025, the UK major noted that its "operational emissions are expected to fluctuate" as new oil and gas projects come on stream. This is an important point, especially as a key factor in the majors' impressive emissions-reduction performance from 2022 has a simple explanation — Russia. As they wrote off billions of dollars of Russian assets, production and any associated emissions took a huge hit. Collectively, the majors' production from 2021 to 2023 fell by 3.7pc to 14.44mn b/d of oil equivalent (boe/d), with Shell and TotalEnergies' output declining by 11.2pc and 11.9pc, respectively. Production speed-up Now their production is growing again, with a vengeance. Year to date, they have increased their output by 5.9pc to a combined 15.29mn boe/d. BP, which in 2020 planned to slash its production to 1.5mn boe/d by 2030, now recognises this is likely to remain above its revised target of 2mn boe/d. TotalEnergies wants to grow its energy production, including electricity generation, by 4pc/yr to 2030, but this includes room for 2-3pc/yr growth in oil and gas production too. Shell sees plenty of room to grow its gas production, if not its oil output. Chevron and ExxonMobil, which were never signed up to net zero, continue to raise oil and gas output. Last year's Cop 28 summit drew intense scrutiny from campaigners, particularly as its president, the UAE's special envoy for climate change Sultan al-Jaber, was steadfast in bringing oil and gas companies to the table. This year's summit host, Azerbaijan, is drawing similar attention. Cop 29 president-designate Mukhtar Babayev, the country's ecology minister, has responded by calling on oil producing countries and companies to contribute to a climate fund. The fund will target $1bn, a tiny drop in the climate finance ocean. The move should revitalise the conversation about polluters paying to tackle climate change, but the oil industry has remained silent so far. By Bachar Halabi, Jon Mainwaring and Caroline Varin Majors' emissions progress Scope 1 and 2 Scope 3 BP 41pc reduction in emissions by 2023 from 2019 baseline 13pc reduction in emissions by 2023 from 2019 baseline Chevron 5.07pc reduction in portfolio carbon intensity to 71g CO2e/MJ achieved by 2023 from 2016 baseline ExxonMobil 11.7pc reduction in GHG emission intensity over 2016-2023 - Shell 31pc reduction in absolute emissions over 2016-2023 6.3pc reduction by 2023 in net carbon intensity against 2016 baseline TotalEnergies 24pc reduction achieved by 2023 against 2015 baseline 35pc reduction in scope 3 emissions from oil output over 2016-2023 Majors' emissions goals Scope 1 and 2 Scope 3 Net Zero by 2050? BP* 20pc reduction by 2025, 50pc by 2030 10-15pc reduction by 2025, 20-30pc by 2030 Yes Chevron** >5pc reduction in carbon intensity across Scopes 1, 2 and 3 by 2028 No ExxonMobil† 20-30pc reduction in GHG intensity by 2030. Net zero by 2050 - No Shell‡ 50pc by 2030 9-13pc reduction by 2025, 15-20pc by 2030, 100pc by 2050 Yes TotalEnergies# >17pc reduction by 2025, >34pc reduction by 2030 40pc by 2030 (oil production only) Yes *2019 baseline. Scope 3 targets lowered in early 2023 from 20pc by 2025 and 35-40pc by 2030. **Chevron uses a portfolio carbon intensity target: 71g CO2e/MJ by 2028, from 74.9g CO2e/MJ in 2016. †2016 baseline. ‡2016 baseline. Scope 3 targets refer to net carbon intensity, rather than absolute emissions. #2015 baseline. TotalEnergies has no Scope 3 targets for gas production Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Aurizon misses 2023-24 Australian coal haulage target
Aurizon misses 2023-24 Australian coal haulage target
Sydney, 12 August (Argus) — Australian rail firm Aurizon expects to increase its coal haulage volumes in the 2024-25 fiscal year ending 30 June after it missed its 2023-24 target. The firm hauled 189mn t of coal in 2023-24, up from 185mn t in a weather-affected 2022-23 but below the 194mn t hauled in 2021-22. The firm revised its guidance to 5pc year-on-year growth when it announced its half-year results on 12 February, down from 10pc indicated in August 2023 but only achieved a 2pc growth. Aurizon expects further growth in 2024-25, with its coal haulage contracted volumes rising to 235mn t from 228mn t in 2023-24. Aurizon's coal throughput was lower on the Central Queensland Coal Network (CQCN), particularly the Goonyella and Newlands mine that connect into the ports of Hay Point, Dalrymple Bay and Abbot Point. Mining firms, including Coronado , have noted that maintenance on the Blackwater line, which connects into Gladstone, affected deliveries into that port during July-August. Gladstone coal shipments dropped by 14pc to 5mn t in July compared with both year-earlier and month-earlier comparisons. The fall in CQCN throughput was offset by a 10pc increase in throughput in New South Wales (NSW) and South East Queensland (SEQ). Planned and unplanned maintenance across the supply chain, including at the mine, port and rail affected throughput in CQCN, according to Aurizon chief executive Andrew Harding. Aurizon's coal division made earnings before interest, tax, amortisation and depreciation (ebitda) of A$528mn ($348mn) in 2023-24, up by 16pc on a year earlier, with higher revenue yield offsetting rising costs. The firm expects similar editda in 2024-25, with higher volumes offsetting higher costs. Aurizon is operated at around 83pc utilisation rates in 2023-24, up from 78pc during the Covid-19 pandemic and is aiming to return to 90pc. But it is facing competition from BMA Rail in Queensland and Magnetic Rail in NSW, as well as Pacific National in both states. By Jo Clarke Aurizon coal haulage (mn t) Jan-Jun '24 Jul-Dec '23 Jan-Jul '23 Jul-Dec '22 Jan-Jun '22 Jul-Dec '21 CQCN Newlands 6.5 6.7 8.1 8.0 8.5 9.3 Goonyella 30.2 28.0 30.4 29.7 32.1 29.4 Blackwater 22.8 24.0 21.9 22.5 24.7 24.8 Moura 6.6 7.7 6.3 6.7 5.5 6.8 Total 66.2 66.3 66.7 66.9 70.8 70.3 NSW, SEQ West Moreton 1.8 1.7 1.1 1.0 1.0 1.7 Hunter Valley, Illawarra 27.0 26.0 26.7 22.6 23.5 26.7 Total 28.8 27.7 27.8 23.6 24.5 28.4 Combined total 95.0 94.0 94.5 90.5 95.3 98.7 Source: Aurizon Totals may not add up because of rounding errors Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Australia’s Beach Energy cuts gas reserves estimate
Australia’s Beach Energy cuts gas reserves estimate
Sydney, 12 August (Argus) — Australian independent Beach Energy has slashed its total proven and probable (2P) gas reserves following revisions of some assets under a strategic review concluded in June. The firm revised its estimated oil and gas reserves downwards by 31.5mn bl of oil equivalent (boe) in 2023-24, of which 11.5mn boe was attributed to re-evaluation at Enterprise reservoir. This, combined with a 7pc on-year drop in output to 18.2mn boe in 2023-24, brought the firm's 2P oil and gas reserves to 205mn boe as of 30 June, down by 20pc from 255mn boe at the same date last year . Beach maintained its production guidance for 2024-25 of 17.5mn-21.5mn boe, which it said is wider than typical to account for uncertainty on the timing of Waitsia's production ramp-up. Pressures are declining faster than anticipated at Beach's Enterprise and Thylacine North fields in Victoria state's Otway basin, Beach said on 12 August when announcing the company's full-year results to 30 June. Reprocessed seismic testing at the Beharra Springs Deep field and results at the Beharra Springs Deep 2 well in Western Australia's Perth basin also led to a downgrade in estimates. "Following the Enterprise field coming on line on 12 June, which has flowed at peak rates of up to 68 TJ/d (1.8mn m³/d), early pressure data indicates a smaller resource pool than originally estimated," Beach said. Beach disclosed in June that drilling results at the Kupe South 9 well in New Zealand's Taranaki basin had shown low gas flow rates , contributing to cumulative impairments in 2023-24 of A$1.1bn ($720mn). A lack of political support for the gas sector and the designation of Kupe as a non-core asset has led the firm to canvass offers for selling the asset, Beach's chief executive officer Brett Woods said on 12 August, but no offers have yet been fielded. The significantly delayed 250 TJ/d Waitsia stage 2 project, co-owned with Japanese trading firm Mitsui, will deliver first gas in early 2025, Woods said, reiterating the most recent schedule announced in April for the A$1.2bn-A$1.3bn project. The Waitsia partners have an agreement with the North West Shelf (NWS) joint venture for processing of 7.5mn t of LNG, originally scheduled to occur between the second half of 2023 and the end of 2028, but the tone from NWS operator Woodside Energy was "supportive" for extending that timeline, Woods said. First gas from the Thylacine West 1 and 2 wells will flow to the Otway gas plant in July-December, Beach said, following the arrival of pipeline equipment in Australia. The Adelaide-based firm posted a A$475mn net loss for the 2023-24 fiscal year, down from 2022-23's net profit of A$401mn. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Finnish, Baltic gas demand up by 13pc on year in July
Finnish, Baltic gas demand up by 13pc on year in July
London, 9 August (Argus) — Combined Finnish and Baltic gas consumption increased on the year in July, but remained firmly below pre-2022 levels. Combined demand in Finland, Estonia, Latvia and Lithuania last month rose to 2.37TWh from 2.1TWh in July 2023, although it was still well below the 2018-21 average of roughly 3.7TWh ( see graph, data and download ). This was a second consecutive month-on-month increase following demand at a near two-year low in May. Demand increasing between May and July is an unusual pattern, as pre-2022 consumption in the region tended to decline over the course of the summer before reaching a nadir in July or August. The power sector was probably the main contributing factor to higher overall gas demand, as year-on-year increases in Latvian and Lithuanian gas-fired output more than offset lower Finnish generation ( see table ). In Latvia in particular, gas-fired generation jumped more than seven times compared with a year earlier, despite power demand remaining stable and hydropower output nearly doubling. Instead, Latvian gas-fired production displaced some net imports, which fell to 258GWh from 372GWh in July last year. Latvian gas demand peaked over the month at 27 GWh/d on 22-26 July, drastically above the average for other days of just 8 GWh/d. These were the same days that Latvia produced the majority of July's gas-fired power. Prices on the regional GET Baltic exchange averaged €37.84/MWh in July, down by 5pc on the month but up by 3pc on the year. July broke the three-month trend of consecutive month-on-month increases, with prices having fallen in all four markets. Firms traded 500GWh on the exchange, up from 358GWh in July last year. Lithuania accounted for 40pc of trades, followed by the joint Latvian-Estonian market at 35pc and Finland with the remaining quarter. Maintenance to change flows Maintenance at the pivotal Kiemenai interconnection point on the Latvia-Lithuania border for most of August will change regional flow dynamics. No capacity will be available in either direction at Kiemenai on the 3-25 August gas days, making it impossible to send regasified LNG from Lithuania's Klaipeda LNG terminal northward to Latvia for storage at the Incukalns facility. Klaipeda sendout consequently has dropped since 3 August, averaging 29 GWh/d on 3-8 August, compared with 101 GWh/d in July. Despite the maintenance and demand remaining stable, an additional LNG delivery for 10 August was added to Klaipeda's schedule . This half-cargo may be mostly destined for reloads, as four small-scale reloads are planned at Klaipeda after the 10 August delivery. Some of these reloads could potentially go to Finland's off-grid terminals at Tornio and Pori, which are no longer supplied with Russian LNG after Gasum halted its purchases in late July because of sanctions . But while maintenance at Kiemenai has started, restrictions further north on the Balticconnector have ended, enabling sendout from the Inkoo terminal to step up significantly to 85 GWh/d on 1-8 August from a much lower 32 GWh/d in July. Planned maintenance reduced capacity from Finland to Estonia on the Balticconnector to just 5 GWh/d for all of July, limiting sendout from Inkoo only to what could be absorbed by the domestic market and the small amount that could be sent southward. Maintenance also will reduce Finnish exit capacity to Estonia to zero on 14-27 October and 4-17 November. By Brendan A'Hearn Finnish + Baltic July gas-fired power generation GWh Jul-24 Jul-23 Jun-24 ± Jul 23 ± Jun 24 Estonia 2 2 2 0 0 Latvia 79 11 3 68 76 Lithuania 74 31 53 43 21 Finland 28 117 40 -89 -12 Total 183 161 98 22 85 — Fraunhofer ISE July consumption by country GWh Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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