Caracas threatens to seize Chevron oil assets

Spanish Market: Crude oil, Natural gas
10/07/19

Venezuela is threatening to nationalize Chevron's oil assets if Washington declines to extend a sanctions waiver that expires on 27 July.

The waiver issued as a general license by the US Treasury Department on 28 January allowed Chevron and oil services companies Halliburton, Schlumberger, Baker Hughes and Weatherford International to continue some operations with Venezuela's state-owned oil company PdV.

If the Trump administration allows the waiver to lapse at the end of July, forcing Chevron and the oil services companies to pull out, President Nicolas Maduro is likely to seize the assets and offer Russian, Chinese and other non-US oil companies an "opportunity to acquire" them, a presidential palace official told Argus.

"Discreet discussions" have already started with Russian state-controlled Rosneft and Chinese state-owned CNPC, the palace official said.

The assertions were confirmed by a senior oil ministry official in Caracas.

Chevron is PdV's main western partner in Venezuela, which its peers ExxonMobil and ConocoPhillips abandoned when the government nationalized key Orinoco assets in 2007. Chevron, in common with European oil companies Total and Equinor, accepted the government's less favorable terms and stayed as PdV's minority partners.

The US major is a 30pc shareholder in the PetroPiar integrated Orinoco heavy crude project that PdV is currently transitioning to utilize for crude blending. Chevron also owns a 39.2pc stake in PetroBoscan, which operates the legacy Boscan heavy oil field in Zulia state, and a 25.2pc stake in PetroIndependiente, which operates the LL-652 medium oil field in Lake Maracaibo. Still in the early development stage is the 400,000 b/d Petroindependencia Orinoco extra-heavy crude production joint venture, in which Chevron holds a 34pc stake.

Chevron also has a 60pc stake in the Loran offshore gas field that holds 7.3 trillion cf of estimated reserves and forms a single cross-border field with Trinidad and Tobago's Manatee field, which holds a further 2.7 Tcf of gas.

In terms of offtake, the Venezuelan assets are a small part of Chevron's global portfolio. Chevron's combined net daily offtake in 2018 from these four joint ventures averaged 42,000 b/d of crude and 9mn cf/d of associated natural gas, according to the company. But the potential for future growth is huge, considering the Opec country's abundant reserves and nearby markets. The assets would also position Chevron to play a key role in Venezuela's future reconstruction.

Local Russian and Chinese diplomatic sources declined to comment on the potential to acquire Chevron's assets. But they reaffirmed that Rosneft and CNPC will maintain their respective long-term commitments to expanding their presence in Venezuela's oil industry regardless of escalating US pressures aimed at forcing Maduro to step down.

Chevron declined to comment. In response to queries, the company routinely responds that its Venezuelan operations comply with all laws and regulations. The oil services companies have little or no presence in Venezuela.

If the US Treasury does not extend the waiver, Maduro would issue a nationalization decree under broad executive powers he was granted in mid-2017 by the government-controlled National Constituent Assembly (ANC), a body established in 2017 to effectively bypass the opposition-controlled legislature.

Venezuela's US-backed opposition has been campaigning unsuccessfully for six months to unseat Maduro, and is currently engaged in controversial EU-backed negotiations with a government delegation in Barbados to find a way to establish a transition to free elections.

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27/12/24

Viewpoint: Mild weather may pressure gas prices in 2025

Houston, 27 December (Argus) — The US natural gas market has worked to lower inventories and bring prices up this year, but a warm 2024-25 winter may once again keep storage levels elevated in the new year. US natural gas inventories at the end of the 2023-24 winter season were well above average due to minimal heating demand caused by mild winter weather and robust US production. Storage levels ended the season on 29 March at 2.259 Tcf (64bn m³) — 39pc higher than the five-year average and 23pc higher than a year earlier. The higher inventories pushed down gas prices by minimizing concerns about supply shortfalls and disincentivized production this year, as large natural gas producers such as Chesapeake Energy and EQT reduced output on low prices and minimal expected demand. These interventions helped reduce the supply glut. Total US gas inventories for the week ending 1 November were 3.932 Tcf, entering the 2024-25 winter season only 6pc higher than the five-year average and 4pc higher than a year earlier. In addition, the US Energy Information Administration (EIA) predicted in its November Short Term Energy Outlook (STEO) that production in 2025 would be up 1pc from 2024 as lower inventories push up prices and once again incentivize production. EIA estimates that demand this winter will exceed last year's levels and keep inventories only just above average. According to December's STEO, inventories are expected to be 1.92 Tcf at the end of March 2025, only 2pc higher than the five-year average . However, the mild weather that has covered much of the country this November and December risks once again sharply cutting into heating demand, leaving inventories at the start of 2025's spring injection season high enough to again put downward pressure on gas prices. Heating demand in November was 12pc below the seasonal average, according to the National Weather Service (NWS). The mild weather caused prices at the Henry Hub, the US benchmark, to average roughly $2/mmBtu in November. However, EIA's December STEO predicted that prices at the Henry Hub would average just under $3/mmBtu for the rest of the winter heating season on expectations for cold weather. That cold weather has yet to fully materialize. While demand in the first week of December was 20pc higher than average on cold snap, temperatures since then have been above seasonal norms, with heating demand in the week ending 20 December landing at 22pc below average and demand in the week ending 28 December expected to be 26pc below average. If below-average demand continues into 2025, it is unlikely that inventories will drop as much as forecast. Prices this winter would be close to $3/mmBtu if withdrawals this season are close to 2.1 Tcf , East Daley Analytics senior director Jack Weixel said in September. US inventories had that level of withdrawal in winter from 2020-22. However, if temperatures this winter are once again well above average, Weixel said inventories could end the season more than 530 Bcf above average, cutting average prices to $2.50/mmBtu and undoing price from the smaller-than-average injection season. Prices may be especially pressured by rising production in the Permian basin of west Texas and southeastern New Mexico. Since most of the gas output from the Permian comes from oil wells, low gas prices may not affect production, as drilling decisions there are influenced by oil production rather than gas production. Prices may still rally this winter if temperatures dip low enough in January and February, offsetting the mild weather of November and December. In addition, the rise of LNG exports next year may boost demand and subsequently raise prices. Several LNG projects or expansions are currently underway in the US with the Golden Pass export terminal, the Plaquemines export terminal and the stage 3 expansion at Cheniere's Corpus Christi liquefaction terminal all expected to start up in 2025. By Anna Muthalaly Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US gas market poised for more volatility

26/12/24

Viewpoint: US gas market poised for more volatility

New York, 26 December (Argus) — US natural gas markets may be subjected to more dramatic price swings in 2025 as growing LNG exports and increasingly price-sensitive producers place greater pressure on the US' stagnant gas storage capacity. Those price swings could pose challenges for consumers without ample access to gas supplies, as well as producers interested in keeping some output unhedged to capture potentially higher prices without taking on excessive financial risk. But volatility may also present opportunities for traders looking to exploit unstable price spreads, and for producers that can adapt their operations to fit a more unpredictable pricing environment. Calm before the storm High storage levels and low spot prices this year — averaging $2.11/mmBtu through November this year at the US benchmark Henry Hub — triggered by an unusually warm 2023-24 winter, may have obscured some of the structural factors pushing the US gas market into a more volatile future. But those structural factors remain and loom increasingly large for prices. The US has moved from a roughly 60 Bcf/d (1.7bn m³/d) market eight years ago to a more than 100 Bcf/d market today, "and we haven't grown our storage capacity at all", Rich Brockmeyer, head of North American gas and power at commodity trading house Gunvor, said earlier this year. As supply and demand for US gas grow, the country's roughly 4.7-Tcf storage capacity becomes ever less effective in stemming demand shocks, such as extreme winter weather events, which can more rapidly draw down inventories than in years past. Additionally, a growing share of US gas is being consumed by LNG export terminals being built and expanded on the US Gulf coast. When those facilities encounter unexpected problems and cease operations — as has happened numerous times at the 2 Bcf/d Freeport LNG terminal in Texas in recent years — volumes that were previously being liquefied and sent overseas were instead backed up into the domestic market, crushing prices. More LNG exports may mean more opportunities for such supply shocks. US LNG exports are expected to increase by 15pc to almost 14 Bcf/d in 2025 as operations begin at Venture Global's planned 27.2mn t/yr Plaquemines facility in Louisiana and Cheniere's 11.5mn t/yr Corpus Christi, Texas, stage 3 expansion, US Energy Information Administration data show. Spot price volatility will be most acutely felt in regions like New England that lack underground gas storage. "In areas like the Gulf coast, where you have a lot of storage, it won't be a problem," Alan Armstrong, chief executive of Williams, the largest US gas pipeline company, told Argus in an interview. Producers' trade-off Volatile gas markets are a mixed bag for producers, many of whom profit from volatility while also struggling to plan and budget based on uncertain revenues for unhedged volumes. Though insufficient gas storage deprives the market of stability, "from the standpoint of a marketing and trading guy that's trying to manage my gas supply to customers and my trading book, I love volatility",said Dennis Price, vice president of marketing and trading at Expand Energy, the largest US gas producer by volume. BP chief financial officer Sinead Gorman in November 2023 specifically named Freeport LNG's eight-month-long shutdown in 2022-23 from a fire as a driver of volatility in the global gas market. The supermajor was able to exploit the "incredibly fragile" gas market, she said, which was a key factor driving the success of its integrated gas business. "Those opportunities are what we typically seek and enjoy," Gorman said. Increasingly, producers have also been adapting to a more volatile market by switching production on and off in response to prices, but often without revealing the price at which a supply response will occur. Expand Energy, for instance, told investors in October that it was amassing drilled but uncompleted wells and wells that had yet to be brought on line, which it could activate relatively quickly when prices rise. It declined to name the price at which that would occur. Market participants, attempting to price in this phenomenon by anticipating producers' next moves may respond more dramatically to supply signals than in the past, when production was steadier. Producers' increased responsiveness to prices could help to balance the market somewhat, though more aggressive intervention into operations could take a toll on well performance and pipelines, FactSet senior energy analyst Connor McLean said. Producers are "treating the reservoir itself like a storage facility", Price said. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: MEH-Midland spread to remain wider in 2025

26/12/24

Viewpoint: MEH-Midland spread to remain wider in 2025

Houston, 26 December (Argus) — WTI Houston's premium to WTI in Midland, Texas, is set to hold at 50¢/bl or wider in 2025, boosted by swelling volumes headed toward the Gulf coast as Houston grows in importance as a center for price discovery. The locational spread between WTI Houston and Midland rose steadily throughout 2024, averaging 49¢/bl year-to-date and widening as high as $1.41/bl during the June trade month as the 1.5mn b/d Wink-to-Webster pipeline was taken offline for repairs. In 2023, the spread averaged 21¢/bl. Trading activity for WTI at Oneok's Magellan East Houston (MEH) terminal — both in the physical and financial markets — climbed to all-time highs in 2024. Reported trade month volumes for WTI Houston swelled to 1.26mn b/d during the December trade cycle, a high for the year, and just 0.8pc below its previous record. On 16 December, WTI Houston trade closed the day at 153,000 b/d for the January trade cycle, the highest single-day trade volume in the history of Argus assessments of the grade. In financial markets, WTI Houston trade activity broke records in 2024, with open interest on CME's WTI Houston futures contract climbing to an all-time high of 412,519 lots — each 1,000 bl — on 21 November. MEH demand up despite export slowdown Trading activity broke records even as US crude exports slowed in the latter half of 2024 on Chinese economic woes that dampened Asian demand. New Chinese stimulus initiatives, namely relaxed fiscal and monetary policy , are meant to reverse that trend, but it remains to be seen if the efforts will work. Further challenges weighing on the US export market are a strengthening dollar combined with a high degree of uncertainty surrounding president-elect Donald Trump's proposed tariff plans, which feature ratcheting-up trade tensions with China even more. Multiple projects to add Permian takeaway capacity at the Texas Gulf coast are in various stages of planning, which could eventually open the window for ever-larger WTI export volumes, and further support WTI Houston against Midland. But industry participants have grown skeptical of the need for new export terminals or other projects. Midstream companies showed little enthusiasm for pitching new coast-bound pipelines from the Permian basin in their end-of-year investor reports . Key firms previously sought more takeaway capacity before the Covid-19 pandemic, when WTI Houston premiums to WTI in Midland consistently topped $1/bl, which would help recoup pipeline construction costs. As it stands, the roughly 3mn b/d total available pipeline capacity from the Permian basin to the Houston area is likely to remain static in coming years. This status quo for onshore infrastructure will help prop open the Houston-Midland WTI premium for the coming year, even if export demand fails to picks up in 2025. By Gordon Pollock WTI Houston-WTI Midland spread Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US tariffs may push more Canadian crude east

26/12/24

Viewpoint: US tariffs may push more Canadian crude east

Singapore, 26 December (Argus) — Canada may divert crude supplies from the US to Asia-Pacific via the Trans Mountain Expansion (TMX) pipeline in 2025, should president-elect Donald Trump impose tariffs on Canadian imports. Trump has declared that he will implement a 25pc tax on all imports originating from Canada after he is sworn into office on 20 January. This will effectively add around $16/bl to the cost of sending Canadian crude to the US, based on current prices, and impel US refiners to cut their purchases. The US imported 4.57mn b/d of Canadian crude in September, according to data from the EIA. Canadian crude producers are expected to turn to Asian refiners in their search for new export outlets. This is especially after Asian refiners gained easier access to such cargoes following the start-up of the 590,000 b/d TMX pipeline in May. The new route significantly shortens the journey to ship crude from Canada to Asia. It takes about 17 days for a voyage from Vancouver to China, compared with 54 days from the US Gulf coast to the same destination. China has become the main outlet for Asia-bound shipments from Vancouver, accounting for about 87pc of the 200,000 b/d exported over June-November, according to data from oil analytics firms Vortexa and Kpler (see chart). But even if the full capacity of the TMX pipeline is utilised to export crude to Asia from Vancouver, it will still only represent a fraction of current Canadian crude exports to the US. Vancouver sent just 154,000 b/d via the TMX pipeline to US west coast refiners over June-November, Vortexa and Kpler data show. Meanwhile, latest EIA figures show more than 2.63mn b/d of Canadian crude was piped into the US midcontinent in September, while US Gulf coast refiners imported 469,000 b/d. This means Canadian crude prices will likely come under downward pressure from higher costs for its key US market, should Trump's proposed tariffs come to pass. This will further incentivise additional buying from Chinese customers, as well as other refiners based elsewhere in Asia-Pacific. India, South Korea, Japan, and Brunei have already imported small volumes of Canadian TMX crude in 2024. A question of acidity But other Asian refiners have so far been reluctant to step up their heavy sour TMX crude imports because of concerns over the high acidity content. China has been mainly taking Access Western Blend (AWB), which has a total acid number (TAN) as high as 1.6mg KOH/g. Acid from high-TAN crude collects in the residue at the bottom of refinery distillation columns where it can corrode units, which deters many refineries from processing such grades. But Chinese refiners have been able to dilute the acidity level by blending their AWB cargoes with light sweet Russian ESPO Blend, allowing them to save costs compared to buying medium sour crude from the Mideast Gulf. Cold Lake, the other grade coming out of the TMX pipeline, has a lower TAN and is currently popular with refiners on the US west coast. But higher costs from potential tariffs could prompt Cold Lake exports to be redirected from the US to buyers in South Korea, Japan, and Brunei — which had all bought the grade previously. Canadian crude appears to have so far displaced medium sour grades in Asia-Pacific, and this trend is expected to continue should TMX crude flows to the region climb higher in 2025. More Canadian crude heading to Asia may displace and free up more Mideast Gulf medium sour supplies to buyers in other regions, including US refiners looking for replacements to their Canadian crude imports. This will also limit the flows of other arbitrage grades like US medium sour Mars crude to Asia-Pacific, which has already seen exports to Asia dwindle in 2024. Opec+ is also due to begin unwinding voluntary production cuts in April 2025, which means Canadian producers will likely have to lower prices sufficiently to attract buyers from further afield. By Fabian Ng TMX exports from Vancouver (b/d) Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: California dairy fight spills into 2025

24/12/24

Viewpoint: California dairy fight spills into 2025

Houston, 24 December (Argus) — California must begin crafting dairy methane limits next year as pressure grows for regulators to change course. The California Air Resources Board (CARB) has committed to begin crafting regulations that could mandate the reduction of dairy methane as it locked in incentives for harvesting gas to fuel vehicles in the state. The combination has frustrated environmental groups and other opponents of a methane capture strategy they accuse of collateral damage. Now, tough new targets pitched to help balance the program's incentives could become the fall-out in a new lawsuit. State regulators have repeatedly said that the Low Carbon Fuel Standard (LCFS) is ill-suited to consider mostly off-road emissions from a sector that could pack up and move to another state to escape regulation. California's LCFS requires yearly reductions of transportation fuel carbon intensity. Higher-carbon fuels that exceed the annual limits incur deficits that suppliers must offset with credits generated from the distribution to the state of approved, lower-carbon alternatives. Regulators extended participation in the program to dairy methane in 2017. Dairies may register to use manure digesters to capture methane that suppliers may process into pipeline-quality natural gas. This gas may then be attributed to compressed natural gas vehicles in California, so long as participants can show a path for approved supplies between the dairy and the customer. California only issues credits for methane cuts beyond other existing requirements. Regulators began mandating methane reductions from landfills more than a decade ago and in 2016 set similar requirements for wastewater treatment plants. But while lawmakers set a goal for in-state dairies to reduce methane emissions by 40pc from 2030 levels, regulators could not even consider rulemakings mandating such reductions until 2024. CARB made no move to directly regulate those emissions at their first opportunity, as staff grappled with amendments to the agency's LCFS and cap-and-trade programs. That has meant that dairies continue to receive credit for all of the methane they capture, generating deep, carbon-reducing scores under the LCFS and outsized credit production relative to the fuel they replace. Dairy methane harvesting generated 16pc of all new credits generated in 2023, compared with biodiesel's 6pc. Dairy methane replaced just 38pc of the diesel equivalent gallons that biodiesel did over the same period. The incentive has exasperated environmental and community groups, who see LCFS credits as encouraging larger operations with more consequences for local air and water quality. Dairies warn that costly methane capture systems could not be affordable otherwise. Adding to the expense of operating in California would cause more operations to leave the state. California dairies make up about two thirds of suppliers registered under the program. Dairy supporters successfully delayed proposed legislative requirements in 2023. CARB staff in May 2024 declined a petition seeking a faster approach to dairy regulation . Staff committed to take up a rulemaking considering the best way to address dairy methane reduction in 2025. Before that, final revisions to the LCFS approved in November included guarantees for dairy methane crediting. Projects that break ground by the end of this decade would remain eligible for up to 30 years of LCFS credit generation, compared with just 10 years for projects after 2029. Limits on the scope of book-and-claim participation for out-of-state projects would wait until well into the next decade. Staff said it was necessary to ensure continued investment in methane reduction. The inclusion immediately frustrated critics of the renewable natural gas policy, including board member Diane Tarkvarian, who sought to have the changes struck and was one of two votes ultimately against the LCFS revisions. Environmental groups have now sued , invoking violations that effectively froze the LCFS for years of court review. Regulators and lawmakers working to transition the state to cleaner air and lower-emissions vehicles will have to tread carefully in 2025. By Elliott Blackburn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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