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Oil emissions progress slows ahead of Cop 29

  • : Crude oil, Natural gas
  • 24/08/12

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.

Majors' emissions progress
Scope 1 and 2Scope 3
BP41pc reduction in emissions by 2023 from 2019 baseline13pc reduction in emissions by 2023 from 2019 baseline
Chevron5.07pc reduction in portfolio carbon intensity to 71g CO2e/MJ achieved by 2023 from 2016 baseline
ExxonMobil11.7pc reduction in GHG emission intensity over 2016-2023-
Shell31pc reduction in absolute emissions over 2016-20236.3pc reduction by 2023 in net carbon intensity against 2016 baseline
TotalEnergies24pc reduction achieved by 2023 against 2015 baseline35pc reduction in scope 3 emissions from oil output over 2016-2023
Majors' emissions goals
Scope 1 and 2Scope 3Net Zero by 2050?
BP*20pc reduction by 2025, 50pc by 203010-15pc reduction by 2025, 20-30pc by 2030Yes
Chevron**>5pc reduction in carbon intensity across Scopes 1, 2 and 3 by 2028No
ExxonMobil†20-30pc reduction in GHG intensity by 2030. Net zero by 2050-No
Shell‡50pc by 20309-13pc reduction by 2025, 15-20pc by 2030, 100pc by 2050Yes
TotalEnergies#>17pc reduction by 2025, >34pc reduction by 203040pc 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

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24/12/30

Viewpoint: Permian waiting on new gas lines

Viewpoint: Permian waiting on new gas lines

Houston, 30 December (Argus) — Natural gas prices in the Permian basin of west Texas and southeast New Mexico fell to historic lows in 2024, with increased takeaway out of the region likely not picking up before 2026. Gas in the Permian basin is fundamentally tied to crude economics, with associated gas being a byproduct of crude-directed drilling. US benchmark WTI values continued to boost crude output in 2024, with month-ahead Nymex WTI futures for delivery in 2024 averaging $76.20/bl, down from $78/bl in 2023, but still much higher than in previous years since 2014. As of the week ended 20 December, the Permian basin rig count stood at 304 rigs, down by only five rigs from the same time a year prior , according to oilfield service provider Baker Hughes. The vast majority of those rigs were crude-directed. Strong associated gas output has frequently pushed spot prices at the Waha hub in west Texas into negative territory since 2019. Waha prices held positive through 2021, helped in part by increased takeaway capacity, before turning negative in four trading sessions in 2022 and seven sessions in 2023. Negative Waha prices were a much more regular feature in 2024, with sellers needing to pay buyers to take Permian gas for about 47pc of the trading sessions throughout January-November. The Waha index fell to -$7.085/mmBtu on 29 August, a historic low. But prices averaged above $2/mmBtu from the middle of November into the first half of December , buoyed by seasonally stronger demand and the end of planned and unplanned maintenance on several Permian pipelines. Spot prices at the Waha hub returned below $1/mmBtu in the final full week of December, as unseasonably mild weather crimped demand. The January-March block for Waha was $2.235/mmBtu as of 27 December, according to Argus forward curves. Spot prices often have been negative despite growing export demand from the LNG sector and for pipeline flows to Mexico. Even excluding potential flows through the most recently commissioned 1.7 Bcf/d (17.6bn m³/yr) ADCC pipeline in south Texas, aggregate feedgas flows to US liquefaction facilities edged higher to 12.9 Bcf/d in January-November from 12.75 Bcf/d a year earlier. Pipeline exports to Mexico rose to 6.06 Bcf/d in January-September from 5.7 Bcf/d a year earlier, US Energy Information Administration (EIA) data show. Pipelines out of the Permian have typically taken little time to reach capacity, as was the case when US firm Kinder Morgan's Gulf Coast Express and Permian Highway pipelines opened in 2019 and 2020, respectively, and more recently in 2021 with the Whistler pipeline. Similarly, flows on the 2.5 Bcf/d Matterhorn Express Pipeline quickly ramped up in October after the line began taking on gas in September. Takeaway capacity out of the Permian is not planned to rise much further before 2026. Several large new pipelines remain under construction or in the planning stage, including the 2 Bcf/d Apex and 2.5 Bcf/d Blackcomb pipelines, both due to enter service in 2026. Oneok's 2.8 Bcf/d Saguaro Connector pipeline is not expected before 2027. Targa's proposed Apex Pipeline, which would link the Permian to the Port Arthur LNG project, remains under consideration. Oversupply led to output cuts in more gas-directed fields in the US in 2024, but Permian gas production has been immune to the low price environment. Low or negative prices at Waha may eventually spur output cuts in the oil-oriented Permian, but that would require WTI prices falling closer to breakeven. Permian producers need WTI to be at a minimum of $62/bl to profitably drill a new well, while the breakeven price for an existing well was $38/bl, according to an April survey by consumer data platform Statista. Producers such as Chevron do plan to curb spending in the region by as much as 10pc in 2025. Chief executive Mike Wirth noted in the company's third quarter 2024 earnings call that Permian "growth will become less the driver and free cash flow will become more of the driver". Yet Permian gas, which accounts for roughly a fifth of US output, is still set to rise to 26.1 Bcf/d in 2025 from a projected 24.8 Bcf/d in 2024, according to the US EIA's December Short-Term Energy Outlook . By David Haydon Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Trump tariffs may shift crude flows to USWC


24/12/30
24/12/30

Viewpoint: Trump tariffs may shift crude flows to USWC

Houston, 30 December (Argus) — President-elect Donald Trump's proposed 25pc tariff on Canadian and Mexican imports could redirect key imported oil grades from the US west coast, opening avenues for displaced Latin American crudes to reappear. The tariffs, which Trump announced on 25 November, could displace about 9pc of the crude US west coast refiners import. Canadian crude flows from the newly expanded 890,000 b/d Trans Mountain pipeline system, which recently have drawn purchases in the US west coast, would force barrels to Asia-Pacific . Mexican crude sellers would divert crude to other outlets as well, like Europe or Asia-Pacific. Refiners on the US west coast increased purchases of Canadian grades after the May startup of the Trans Mountain Expansion (TMX). Cheaper prices and closer proximity to Vancouver, British Columbia, where TMX crude loads, allowed the heavy sour crudes to find favor along the US west coast. But the proposed tariffs could raise landed TMX prices, no longer making it the cheapest heavy sour option. US west coast buyers would pay a 25pc import tariff to US Customs and Border Protection on TMX crude once it has entered port. US west coast refiners received around 169,000 b/d of crude from the Vancouver area since the pipeline came on line in May, up from less than 40,000 b/d a year earlier, data analytics firm Vortexa shows. Around 60pc of Mexico's crude exports in 2024 went to the US, mostly to the US Gulf coast, according to Vortexa data. Tariffs could lead to a drop in prices to adjust to a tariffed American market or for Mexican crude going more often to other destinations such as Europe or Asia-Pacific. Spain, South Korea and India, were the second, third and fourth most common destinations for Mexican crude exports in 2024, respectively. Mexico's crude production and export infrastructure is concentrated on the country's east coast, making exports to Asia-Pacific difficult. Mexico would need to invest in building exporting infrastructure from the west coast to improve trade routes to Asia, market participants say. But Mexico's state-owned oil company Pemex plans to continue cost-cutting measures, led by recently elected President Claudia Sheinbaum, so infrastructure expansion is unlikely. Other Latin crudes could also experience a rise after being displaced by the commencement of TMX in May. Since then, heavier crudes from countries such as Colombia, Ecuador and Argentina have found more frequent routes to the US Gulf coast and Asia-Pacific. Market participants believe lighter Brazilian grades could find routes to the US west coast as TMX supply increases in China. China imported 683,000 b/d of Brazilian crudes in 2024, c ompared with 180,000 b/d of imports to the US west coast from Brazil, according to Vortexa. Sources say the tariffs are a bargaining chip by the incoming administration, and participants are skeptical they will be implemented by the Trump administration. Instead, the tariffs could exclude crude and other commodities. More than $3.3bn of goods and services cross the US-Canada border each day, according to Canada's Fall Economic Statement (FES), which notes Canada is the largest market for 36 US states. Market participants are vocally against the proposed tariffs. Tariffs on crude and refined products "will not help our industry compete, nor will they support US energy dominance and affordability for consumers," the American Fuel and Petrochemical Manufactures said on 27 November . Cenovus is also trying to explain to policy makers in the incoming Trump administration how tariffs on Canada could impact the energy system in North America. But the incoming administration shows no sign of backing off the tariffs for 2025. By Rachel McGuire and João Scheller Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Mild weather may pressure gas prices in 2025


24/12/27
24/12/27

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


24/12/26
24/12/26

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


24/12/26
24/12/26

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.

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