Citgo dismisses LPG supply plan for Venezuela

  • Market: Crude oil, LPG, Oil products
  • 13/07/21

Citgo, the US refining arm of Venezuelan state-owned PdV, told Argus it has no immediate plan to supply LPG to Venezuela under new US authorization for sale of the cooking fuel to the Opec country.

"We are aware that OFAC recently issued General License 40, authorizing certain transactions involving the exportation of LPG to Venezuela," Citgo said, referring to the US Treasury Department's Office of Foreign Assets Control (Ofac) that administers sanctions. "At this time, CITGO has no plans to engage in this activity."

Although LPG trade was never explicitly banned by the 2019 oil sanctions on Venezuela, suppliers had shied away in cautious overcompliance.

Citgo's stance is consistent with other US product traders that have said they are unlikely to resume supplying LPG to Venezuela in spite of the new clearance, reinforcing the largely symbolic nature of the US license.

Among the suppliers' concerns are PdV's credit-worthiness, market tightness and a prohibition on crude swaps that would have made LPG transactions with Caracas more commercially appealing.

But the license issued yesterday had spurred some speculation that Citgo would be an exception because it is nominally controlled by Venezuela's US-backed political opposition since 2019, when the US recognized opposition leader Juan Guaido as president of an interim government and imposed oil sanctions to force President Nicolas Maduro out of power. PdV itself remains under the control of Maduro's government in Caracas.

Allowing Venezuela to import LPG — a fuel that nearly 90pc of Venezuela's population relies on for cooking — was a humanitarian gesture, US deputy assistant secretary of state Kevin O'Reilly said today in a virtual event hosted by Washington-based think tank the Atlantic Council. "Our Treasury Department has loosened certain restrictions on cooking gas because we see that it is fundamental to the well-being of Venezuelans, their day-to-day lives, so that they can then focus on these more enduring political questions and help resolve their challenges," he said.

Faced with an acute shortage of propane canisters, many Venezuelans have been forced to use electric hot plates or firewood instead.

In 2018, the year before the US imposed the oil sanctions, Venezuela imported a monthly average of 238,000 bl (20,000t) of US propane, according to US Energy Information Administration data.

Citgo owns three refineries: the 425,000 b/d Lake Charles facility in Louisiana, the 158,000 b/d Corpus Christi, Texas, refinery and the 167,000 b/d Lemont, Illinois, refinery.

The company is a target of various lawsuits by creditors and arbitration claimants seeking to fulfill Venezuela's unpaid obligations.


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24/05/24

Dangote refinery to export 10ppm diesel in June

Dangote refinery to export 10ppm diesel in June

London, 24 May (Argus) — Nigeria's 650,000 b/d Dangote refinery will start exporting diesel conforming to European specifications along with gasoline sales in June, its vice president for oil and gas Devakumar Edwin has said. "We expect before the end of next month we'll also have gasoline in the market, and we'll also have Euro V diesel for export, that is below 10ppm", Edwin said this week at a Society of Petroleum Engineers event in Lagos. Dangote chief executive Aliko Dangote reiterated the planned June start for gasoline on 17 May. Dangote started its crude distillation unit in January, and received approval to start up a mild hydrocracker with its desulphurisation units in March. A source at Nigeria's downstream regulator NMDPRA said the refinery has now received approval to start its residual fluid catalytic cracker. Dangote started naphtha exports in March, low-sulphur straight run fuel oil (LSSR) exports in May and began selling diesel and jet fuel domestically in April. It has a waiver from NMDPRA to sell diesel with sulphur levels above 600ppm into the local market. At full capacity Dangote will be able to more than meet Nigerian domestic gasoline demand. But a trader in the region said gasoline production is unlikely to start next month, citing the amount of cargoes to be delivered to the country. Exports of naphtha, a key blending component in finished-grade gasoline, are continuing from the refinery, with 80,000t due to load on 31 May according to Kpler. And Edwin hinted at a slowing of spot sales. "We had a meeting to see, probably, how we can slow down our sales because we've already made quite a few forward bookings," he said this week. "Export, for example, aviation/jet, the last vessel went to the Caribbean islands. The next vessel, we are booking for US market." Dangote recently added TotalEnergies as a buyer in a deal that could see the French company take refined products for its African network of 4,800 retail fuel stations, including more than 540 in Nigeria. The deal could also see the oil major supply crude to the refinery. A source told Argus there is a deal for TotalEnergies to supply two crude cargoes each month, or around 2mn bl. Indications based on the refinery's slate to date and TotalEnergies' Nigerian crude equity suggest one cargo of the very light Amenam blend one of Bonny Light. By Adebiyi Olusolape and George Maher-Bonnett Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Q&A: Shell Oman to balance upstream with renewables


24/05/24
News
24/05/24

Q&A: Shell Oman 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 Shell Oman'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. 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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? 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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.

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Opec+ to take June meetings online


24/05/24
News
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.

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Richmond City Council proposes Chevron refinery tax


23/05/24
News
23/05/24

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.

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US ethane supply gains seen trailing demand growth


23/05/24
News
23/05/24

US ethane supply gains seen trailing demand growth

Houston, 23 May (Argus) — Export and domestic demand growth for US ethane is expected to outpace US supply growth by as much as 72,000 b/d by 2026, according to a recent forecast from consultancy East Daley Analytics. A surplus of US ethane production, bolstered by gains in natural gas drilling and production to meet growing demand for electricity generation and LNG exports, has led to increasing investments in additional ethane export terminal capacity to provide other outlets for the petrochemical feedstock. The US Energy Information Administration (EIA) showed US ethane production from natural gas processing rose to a record 2.78mn b/d in October of 2023 and fell to 2.69mn b/d in February, the latest data the agency has available. Those volumes don't take into account ethane that is rejected into the gas stream at processing plants during periods of restrained capacity or when natural gas prices spike on weather-related outages, incentivizing lower ethane recovery. Mont Belvieu, Texas, EPC ethane's premium relative to its natural gas fuel value at Waha reached a peak of 50.31¢/USG on 6 May, a 16-month high, and has averaged 26.08¢/USG in May so far, according to Argus data. As ethane margins versus natural gas rise, ethane extraction at natural gas processing plants becomes even more profitable, pushing ethane recovery rates higher. Yet East Daley's forecasts suggest projects to absorb this additional feedstock may quickly outpace production. The consultancy projects US ethane production will rise by 283,000 b/d by 2026, driven mostly by gains in natural gas production in the Permian and Marcellus basins. Increased gas takeaway capacity from the completion of maintenance on Kinder Morgan's Permian Highway pipeline (PHP), the Gulf Coast Express (GCX) pipeline, and the Transwestern pipeline at the end of this month, will allow for higher levels of ethane rejection, according to Rob Wilson, East Daley's vice president of analytics, limiting potential gains in ethane production from the additional gas. Further gas capacity restrictions in the Permian are expected to be mitigated when the 2.5 Bcf/d Matterhorn Express pipeline — which runs from the Waha, Texas, gas hub to Katy, Texas, on the Gulf coast — comes online in the third quarter of this year. Domestic demand for ethane is projected to rise by 129,000 b/d by 2026 with the addition of Chevron Phillips Chemical's joint venture with QatarEnergy to construct a 2mn t/yr ethane cracker on the Texas Gulf coast that is scheduled to come online in 2026. That joint venture will consume 118,000 b/d of ethane when at full capacity, but will operate at 50pc of capacity when first on line in 2026, according to East Daley. Increased US ethane cracking will come on top of a 231,000 b/d increase in ethane exports by 2026, driven by demand from Chinese crackers and burgeoning demand from Indian crackers, according to the consultancy. Ethane export expansions at Energy Transfer's Marcus Hook terminal in Pennsylvania and Enterprise Products Partners' new flexible LPG and ethane terminal at Beaumont, Texas, are expected to be complete by 2025 and 2026, respectively. Combined, these projects add another 360,000 b/d of ethane demand by 2026, outstripping expected supply growth by an estimated 72,000 b/d, according to East Daley's forecast. By Abby Downing-Beaver Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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