Karoon cuts 2024 guidance on lower US output

  • : Crude oil, Natural gas
  • 24/04/19

Australia-listed oil producer Karoon Energy has cut its production guidance for 2024 to reflect lower production from its stake in the Who Dat floating production system in the US' Gulf of Mexico.

Who Dat's weaker well and facility performance has led to the lower guidance, with Karoon now expecting to produce 29,000-34,000 b/d of oil equivalent (boe/d) in 2024, down from a previous 31,000-37,000 boe/d guidance. Karoon said it and joint-venture partner LLOG Exploration will continue to prioritise higher value oil production over gas for the remainder of the year.

The firm's January-March output rose by 17pc against October-December 2023. Who Dat's production on a net revenue interest (NRI) basis was 9,000 boe/d for January-March, with Karoon downgrading its forecast NRI production from 4mn-4.5mn boe in 2024 to 3-3.5mn boe.

But output from Karoon's Bauna asset offshore Brazil was 15pc lower than the previous quarter because of continuing reliability problems with Bauna's floating production, storage and offloading (FPSO) vessel, the shut-in of the SPS-88 well for the full period and natural field decline.

Production for January-March at Bauna was 24,000 b/d, down from 28,000 b/d the previous quarter. Karoon expects to resume production from the well during July-September following an intervention, assuming no delays in regulatory approval.

Bauna's annual maintenance will take place next month with a three-week shutdown of the FPSO planned to boost reliability.

Karoon Energy results
Jan-Mar '24Oct-Dec '23Jan-Mar '23y-o-y % ±q-o-q % ±
Sales revenue ($mn)19720914437-6
Production (b/d)34,00029,00022,0005517
Sales volume (b/d)30,00028,00022,000367
Average prices ($/bl)
Bauna oil price7683734-8
Who Dat sales gas ($/mn ft³)2.952.22n/an/a33
Who Dat oil, condensate, NGLs7873n/an/a7

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24/05/27

Brent, FX drive Brazil natural gas price hike

Brent, FX drive Brazil natural gas price hike

Sao Paulo, 27 May (Argus) — Average Brazilian natural gas network prices have continued to increase this year, maintaining their differential to the North Sea Dated crude benchmark, amid higher Brent crude prices and the Brazilian real's depreciation to the US dollar. Brazilian pipeline gas prices rose by 6.7pc to $12.15/mmBtu on 24 May from $11.39/mmBtu on 2 January — while crude rose by 5.9pc, according to Argus data. That increase was more than four percentage points higher the increase in Henry Hub Day-ahead gas index price, which rose by 1.6pc. The Brazilian real depreciated by 5.3pc to R5.1508 to the US dollar on 24 May from R4.8916/$1 on 2 January. Brent prices, the real-US dollar exchange rate and the Henry Hub index are the main indexations of natural gas contracts in Brazil. North Sea Dated and Brazilian natural gas prices spiked sharply starting in early April, with crude peaking on 13 April at $93.19/bl and Brazilian gas at $13.525/mmBtu, because of dueling missile strikes between Israel and Iran . Price increases were spearheaded by Transportadora Brasileira Gasoduto Bolivia (TBG), with that pipeline system reaching $12.833/mmBtu on 24 May, up by more than 12pc from January. Brent accounts for a larger percentage of the price for contracts on that grid than any other, at 16.75pc. The terms were signed in 2022, during the early months of the Russia-Ukraine war when global gas prices were rising. State-controlled Petrobras is a supplier in most of these contracts, but Portugal's Galp also owns a few deals. Average natural gas prices in the 4,500km (2,796-mile) pipeline owned by Transportadora Associada de Gas (TAG) — which operates in the north, northeast and southeast — were at $11.607/mmBtu on 22 May, a 2.9pc rise from January. Over 40 long-term contracts are connected to the TAG pipeline, reflecting the most diverse chunk of the Brazilian market . The 2,000km Nova Transportadora do Sudeste (NTS) pipeline — which links Rio de Janeiro, Minas Gerais and Sao Paulo states with Bolivia — has eight different contracts with indexation to Brent above 12.9pc, including all of Rio de Janeiro's contracts. The most recent expanded premium to the US gas benchmark price — which stood at $2.60/mmBtu on 23 May — indicates a rise in gas demand driven by cooling across south-Atlantic US states . Extreme weather was responsible early in the year for a hit on spot and futures prices, notably on 12 January, when Henry Hub Day-ahead price posted a sharp rise above $12/mmBtu. By Betina Moura Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Q&A: Oman Shell to balance upstream with renewables


24/05/24
24/05/24

Q&A: Oman Shell to balance upstream with renewables

Dubai, 24 May (Argus) — Shell has been in Oman for decades now and had a front row seat to its energy evolution from primarily an oil producing nation to now a very gas-rich and gas-leaning hydrocarbons producer. Argus spoke to Oman Shell's country chairman Walid Hadi about the company's energy strategy in the sultanate. Edited highlights follow: How would you characterize Oman's energy sector today, and where do new energies fit into that? Oman is one of the countries where there is quite a bit of overlap between how we see the energy transition and how the country sees it. Oman is clear that hydrocarbons will continue to play a role in its energy system for a long period of time. But it is also looking to decrease the carbon intensity to the most extent which is viable. We need to work on creating new energy systems or new components of energy system like hydrogen and EV charging to facilitate that. It is what we would like to call a 'just transition' because you think about it from macroeconomic perspective of the country and its economic health. Shell is involved across the energy spectrum in Oman – from upstream gas to alternative, clean energies. What is Shell's overall strategy for the country? In Oman, our strategic foundation has three main pillars. The first is around oil and liquids and our ambition is to sustain oil and liquids production. At the same time, we aim to significantly reduce carbon intensity from the oil production coming from PDO. The second strategic pillar is gas, and our ambition here is to grow the amount of gas we are producing in Oman and also to help Oman grow its LNG export capabilities. The more committed we are in unlocking the gas reserves in the country, the more we can support Oman's growth, diversification, and the resilience of its economy through investments and LNG revenue. Gas also offers a very logical and nice link into blue and green hydrogen, whether in sequence or as a stepping stone to scale the hydrogen economy in the country. The last strategic pillar is to establish low-carbon value chains, predominantly centered around hydrogen, more likely blue hydrogen in the short term and very likely material green in the long term, which is subject to regulations and markets developing. How would you view Oman's potential to be a major exporter of green hydrogen? When examining the foundational aspects of green hydrogen manufacturing, such as the quality of solar and wind resources and their onshore complementarity, Oman emerges as a highly competitive country in terms of its capabilities. But where we are in technology and where we are in global markets and on policy frameworks — the demand centers for green hydrogen are maturing but not yet matured. I think there will be a period of discovery for green hydrogen globally, not just for Oman, in the way LNG started 20-30 years ago. When it does, Oman will be well-positioned to play global role in the global hydrogen economy. But the question is, how much time it is going to take us and what kind of multi-collaboration needs to be in place to enable that? The realisation of this potential hinges on several factors: the policies of the Omani government, its bilateral ties with Japan, Korea, and the EU, and the technological advancements within the industry. Shell has also been looking at developing CCUS opportunities in the country. How big a role can CCUS play in the region's energy transition? CCUS is going to be an important tool in decarbonising the global energy system. We have several projects globally that we are pursuing for own scope 1, scope 2 emissions reductions, as well as to enable scope 3 emissions with the customers and partners In Oman, we are pursuing a blue hydrogen project where CCUS is a clear component. This initiative serves as a demonstrative case, helping us gauge the country's potential for CCUS implementation. We are using that as a proof point to understand the potential for CCUS in the country. At this stage, it's too early to gauge the scale of CCUS adoption in Oman or our specific role within it. However, we are among the pioneers in establishing the initial proof point through our Blue Hydrogen initiative. You were able to kick off production in block 10 in just over a year after signing the agreement. How are things progressing there? We have started producing at the plateau levels that we agreed with the government, which is just above 500mn ft³/d. Block 10 gas is sold to the government, through the government-owned Integrated Gas Company (IGC), which so far has been the entity that purchases gas from various operators in Oman like us, Shell. IGC then allocates that gas on a certain policy and value criteria across different sectors. We will require new gas if we are going to expand LNG in Oman. There is active gas exploration happening there in Block 10. We know there is more potential in the block. We still don't know at what scale it can be produce gas or the reservoir's characteristics. But blocks 10 and 11 are a combination of undiscovered and discovered resources. We are aiming to significantly increase gas production through a substantial boost. However, the exact scale and timing of this expansion will only be discernible upon the conclusion of our two-year exploration campaign in the block. We expect to understand the full growth potential by around mid to late 2025. Do you have any updates on block 11? Has exploration work there begun? We did have a material gas discovery which is being appraised this year, but it is a bit too early to draw conclusions at this stage. So, after the appraisal campaign is completed, we will be able to talk more confidently about the production potential. Exploration is a very uncertain business. You must go after a lot of things and only a few will end up working. We have a very aggressive exploration campaign at the moment. We also expect by the end of 2025, we would be in a much better position to determine the next wave of growth and where it is going to come from. Shell is set to become the largest off taker from Oman LNG, how do you view the LNG markets this year and next? As a company, we are convinced, that the demand for LNG will grow and it needs to grow if the world is going to achieve the energy transition Gas must play a role, it has to play a bigger role globally over the time, mainly to replace coal in power generation and given its higher efficiency and lower carbon intensity fuel in the energy mix. While Oman may not be the largest LNG exporter globally or hold the most significant gas reserves, it is a niche player in the gas sector with a sophisticated and high-quality gas infrastructure. Oman's resource base remains robust, driving ongoing exploration and investment efforts. This growth trajectory includes catering to domestic needs and servicing industrial hubs like Duqm and Sohar, alongside allocating resources for export purpose. We have the ambition to grow gas for domestic purpose and for gas for eventual exports Have you identified any international markets to export LNG? We have been historically and predominantly focused on east and we continue to see east as core LNG market with focus on Japan, Korea, and China. Europe has also emerged on the back of the Ukraine-Russia crisis as growing demand center for LNG. Over time we might focus on different markets to a certain extent. It will be driven on maximising value for the country. By Rithika Krishna Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Opec+ to take June meetings online


24/05/24
24/05/24

Opec+ to take June meetings online

Dubai, 24 May (Argus) — Meetings to discuss Opec+ crude output policy that had been scheduled to take place in Vienna at the start of June have been pushed back by a day and will now be held online. The meetings — one involving Opec ministers, another involving the wider Opec+ coalition and a third consisting of the group's Joint Ministerial Monitoring Committee (JMMC) — will "convene via videoconference on Sunday 2 June 2024", the Opec secretariat said on Friday. The original schedule was for Opec+ ministers to meet in person on 1 June. The announcement puts to bed more than a week of rumours and delegate chatter about whether or not the meeting would take place in person as speculation mounts around what policy decision the group would need, or be prepared, to take. Effectively, the only thing up for debate at these meetings is the fate of the 2.2mn b/d supply cut that eight member countries, led by Saudi Arabia and Russia, committed to after the Opec+ group's last meeting in late November. That cut was originally due to last for just three months, but it was later extended for another three months until the end of June. Several weeks ago, when oil prices were under sustained upward pressure in the face of tightening fundamentals and rising geopolitical tensions, expectations were high that the group would agree to begin unwinding at least part of the 2.2mn b/d from July. But a relative easing of tensions in the Middle East, coupled with signs of continued restrictive monetary policy by the US Federal Reserve and other major central banks, has since led to a softening of oil prices and with that a change in sentiment among Opec+ delegates about what the group should do next. Delegates today argue that the market is on the whole well-supplied and in no need of additional supply from the group, particularly given the uncertainty around the outlook for oil demand, highlighted by the wide range of growth projections for 2024. At one end of the spectrum, Opec sees oil demand growth of 2.25mn b/d this year. At the other end, the IEA recently revised down its 2024 growth forecast for a second consecutive month. It now stands at 1.06mn b/d. Two Opec+ delegates said earlier this week that they expect the eight countries to extend the 2.2mn b/d cut in its entirety beyond the second quarter. One said they could extend it through to the end of the year. Compensation plans A renewed emphasis by Opec+ in recent weeks on the need for those member countries producing above their targets to not only scale back but also compensate fully for their past overproduction could be interpreted as acknowledgement by the group that the market is indeed well-supplied. Iraq and Kazakhstan, the group's biggest overproducers this year, this month issued detailed programmes outlining how they plan to compensate , while Russia this week acknowledged it had exceeded its Opec+ target for April and said it would soon submit a plan to the Opec secretariat detailing how it will make up it. Although all eyes will be on the fate of the 2.2mn b/d cut at the upcoming meetings, the fact it is a voluntary pledge and one agreed by only a handful of countries means, in theory, a decision need not happen at the ministerial meeting. As the eight countries participating in that cut are all members of the JMMC, there is a good chance the decision gets announced at the committee's meeting instead. By Nader Itayim Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Richmond City Council proposes Chevron refinery tax


24/05/23
24/05/23

Richmond City Council proposes Chevron refinery tax

Houston, 23 May (Argus) — The Richmond City Council in California's Bay Area has paved the way for a tax on Chevron's 245,000 b/d refinery, voting unanimously at a 21 May meeting for the city's attorney to prepare a ballot initiative. The newly proposed excise tax would be based on the Richmond refinery's feedstock throughputs, according to a presentation given by Communities for a Better Environment (CBE) at the meeting. It is a "…legally defensible strategy to generate new revenue for the city," CBE attorney Kerry Guerin said. The city has previously looked to tax the refinery, with voters passing ‘Measure T' in 2008 before it was struck down in court in 2009. This led to a 15-year settlement agreement freezing any new taxes on Chevron's refinery, but the agreement expires on 30 June 2025. The city is projecting a $34mn budget shortfall for the 2024 to 2025 fiscal year and is seeking to shore up its finances with additional revenue. Ballot initiatives allow Californian citizens to bring laws to a vote without the support of the state's governor or legislature, and the tax proposal could go to voters as early as November this year, according to CBE's Guerin. "Richmond has been the refinery town for more than 100 years, but it won't be 100 years from now," Richmond Mayor Eduardo Martinez said during the meeting. Chevron reiterates risk to renewables A tax on the refinery is the "wrong approach to encourage investment in our facility and in the city that could lead to new energy solutions and reductions in emissions from the refinery," Chevron senior public affairs representative Brian Hubinger said during the meeting's public comments. Hubinger's comment echoes prior warnings from Chevron that a potential cap on California refining profit in the process of being implemented by the California Energy Commission (CEC) would make the company less willing to investment in renewable energy . "An additional punitive tax burden reduces our ability to make investments in our facility to provide the affordable, reliable and ever-cleaner energy our community depends on every day, along with the job opportunities and emission reductions that go with these investments," Chevron said in an emailed statement. The Richmond refinery tax is a "hasty proposal, brought forward by activist interests," the company said. The company last year finished converting a hydrotreating unit at its 269,000 b/d El Segundo, California, refinery to process both renewable and crude feedstocks. The facility was processing 2,000 b/d of bio feedstock to produce renewable diesel (RD) and sustainable aviation fuel (SAF) and said it expected to up production to 10,000 b/d last year. But Chevron has so far lagged its California refining peers in terms of RD volumes with Marathon's Martinez plant running at about 24,000 b/d in the first quarter — half of its nameplate capacity — and Phillips 66's Rodeo refinery producing 30,000 b/d with plans to up runs to over 50,000 b/d by the end of the second quarter . Chevron did not immediately respond to a request for current RD volumes at its California refineries. By Nathan Risser Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

India’s AMNS signs 10-year LNG supply deal with Shell


24/05/23
24/05/23

India’s AMNS signs 10-year LNG supply deal with Shell

Mumbai, 23 May (Argus) — Indian steel manufacturer ArcelorMittal Nippon Steel (AMNS) has signed a 10-year deal to buy LNG from Shell, with deliveries to start from 2027, people with direct knowledge of the matter have said. Under the terms of the deal, the steelmaker's direct reduced iron (DRI) plant in the western Gujarat state of Hazira will receive 500,000 t/yr of LNG, Argus understands. The Hazira plant has crude steel production capacity of 8.8mn t/yr, according to ArcelorMittal's 2023 annual report. As much as 65pc of the capacity is based on DRI. AMNS also has a deal with TotalEnergies for 500,000 t/yr that is scheduled to expire in 2026 . This deal comes at a time when AMNS plans to expand its steel capacity to 20mn t/yr in the long run . This supply pact also underscores a trend in the global steel industry to use cleaner energy sources to produce the so-called 'green steel'. The firm imports up to 75pc of its 1.72mn t in natural gas requirements on an annualised basis, a source said. The deal was signed at a 11.5pc percentage of Brent crude prices, trading firms said, adding that this is so far the lowest-heard slope for an Indian term LNG supply contract. AMNS sought LNG supply for a period of 5-10 years starting in 2027 under a tender that closed in mid-March. The firm last sought long-term LNG in 2022 through a tender for 400,000 t/yr of LNG to be delivered across 2025-30. Indian importers will continue to seek term supply despite softening spot prices, mostly to hedge their risks in a market that can still be volatile, trading companies said. The Argus front-month price for LNG deliveries to India was assessed at $11.50/mn Btu today, up from $10.16/mn Btu a week earlier. The price reached as high as $48.30/mn Btu in August 2022. The firm has lowered its carbon emissions by 32pc in calendar year 2022 from 2015 levels, it said. By Rituparna Ghosh Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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