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Antero's NGL premiums to Belvieu halve in 4Q

  • Spanish Market: LPG, Natural gas, Petrochemicals
  • 11/02/26

Marcellus shale producer Antero Resources reported today that its realized natural gas liquids (NGL) price premiums to Mont Belvieu, Texas, fell in the fourth quarter by half from a year earlier.

The company's realized NGL prices fell to a $1.52/bl premium to Mont Belvieu in October-December, down from a $3.09/bl premium in the fourth quarter of 2024.

Before hedging, Antero received $35.41/bl on its propane-plus NGL production in the fourth quarter and $12.54/bl on its ethane production, which equated to a $1.38/bl premium to Mont Belvieu for the lighter feedstock.

The narrower margins on its NGL production come as propane prices at Mont Belvieu averaged 65.90¢/USG ($27.68/bl) in the fourth quarter, down from 76.26¢/USG a year earlier.

Antero expects to produce on average 213,000 b/d of NGLs in 2026, comprising 80,000 b/d of ethane and 125,000 b/d of propane and heavier liquids. Its full-year guidance is for realized propane-plus prices at $0.50/bl above or below Mont Belvieu. Antero expects to receive on average a $1-2/bl premium to Mont Belvieu for its ethane production in 2026.

Antero reported propane-plus NGL production of 116,065 b/d in the fourth quarter, up from 114,815 b/d a year earlier. Ethane production averaged 83,348 b/d, down from 92,587 b/d in the fourth quarter of 2024.

The Denver, Colorado-based company reported a profit of $193.7mn, up 29pc from $149.6mn in the fourth quarter of 2024.

By Amy Strahan

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12/02/26

US E15 group floats fewer biofuel mandate waivers

US E15 group floats fewer biofuel mandate waivers

New York, 12 February (Argus) — US lawmakers are weighing a proposal that would make it harder for oil refiners to win exemptions from annual biofuel mandates but still let regulators decide which companies deserve relief. The US House of Representatives last month punted on legislation that would allow year-round sales of 15pc ethanol gasoline (E15) and revamp the biofuel quota program, instead tasking a "rural domestic energy council" of more than 20 Republican lawmakers with hashing out reforms. One provisional plan circulated by the council this week would cap the total volume of future exemptions, according to four people familiar with the proposal and a draft framework shared with Argus . The US Environmental Protection Agency (EPA) requires oil companies to annually blend biofuels or buy Renewable Identification Number (RIN) credits from those that do, while letting small refineries bid for hardship exemptions that can save them tens of millions of dollars. Exemption decisions have varied wildly over time, from mass denials under former-president Joe Biden to generous exemptions under President Donald Trump that has frustrated farmers. 450mn RIN cap The House task force's proposal would make the program somewhat more predictable. EPA would initially have to exempt 450mn RINs from annual biofuel obligations but no more, prioritizing companies that prove the most hardship. That would be a substantial drop from the nearly 1bn RINs the Trump administration has already exempted from 2024 quotas, initially set at 21.5bn credits. If mandates rise over time, EPA must proportionally raise that 450mn RIN cap. One gallon of corn ethanol generates 1 RIN, while more energy-dense fuels like renewable diesel earn more. Unexpected exemptions can hurt RIN prices, cutting into biorefinery margins and curtail demand for crops like corn and soybeans. Other changes would limit — but not entirely eliminate — EPA's discretion. Regulators would have to largely stick to their current system for measuring hardship, which factors in criteria like a refinery's access to capital. EPA would also have to consider "additional materials" determined by the council to limit "abuse", though the framework does not elaborate on what this would entail. An earlier proposal backed by the American Petroleum Institute and ethanol groups would have restricted exemptions to companies with limited collective refining capacity, angering some larger companies that would have lost the ability to win exemptions for smaller units they own. The latest proposal would leave it to EPA to decide which facilities deserve relief, letting small companies, mid-sized refiners like Delek and even oil majors like Chevron still compete for a smaller pool of exemptions. EPA could not force larger oil companies to blend more biofuels to offset exemptions for their smaller rivals and would have to automatically extend exemptions if it takes more than six months to weigh a company's new request. The framework would also keep the program focused around fuels that retailers can easily blend, blocking EPA from ever reviving a Biden plan to credit biogas that powers electric vehicles. The proposal shared with Argus makes no explicit mention of removing summertime limits of E15, though that is the top priority for farm-state lawmakers on the council keen to help corn farmers. Trump has made clear too he wants to expand E15 access . The framework would require EPA to finalize E15 labeling and storage standards. The proposal includes no details on timing. Some biofuel advocates have pushed delaying any changes to 2028, worried that near-term shifts could delay the Trump administration's goal of finalizing new biofuel quotas before April. Not final, still an uphill battle The framework is just one idea the council is weighing and could change. A legislative source familiar with the debate told Argus that "nothing definitive has been decided". The council has a goal of aligning around fuel market reforms by 15 February. Afterwards, any plan would likely need to be added to larger legislation to have a chance of passing, such as a farmer aid package. Advocates of the plan face an uphill battle. Some Republicans, including in the US Senate, have long pushed for more substantial reforms to the biofuel mandates than what the task force has contemplated. The framework only alludes to these concerns, requiring a government watchdog agency to regularly study how the program impacts fuel prices and US refining capacity. Democrats, already frustrated they were left off the council, could also resist permanently excluding electricity. By Cole Martin Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Australia’s Origin increases gas storage investment

12/02/26
12/02/26

Australia’s Origin increases gas storage investment

Sydney, 12 February (Argus) — Australian utility and part-owner of the 9mn t/yr Australia Pacific LNG (APLNG) Origin Energy will spend another A$25mn ($18mn) for a planned gas storage facility in Victoria state's offshore Gippsland basin. The 19PJ (507mn m³) capacity Golden Beach, to be operated by privately owned GB Energy, will enhance its east coast gas portfolio, Origin said in its half-year results to 31 December 2025 on 12 February. The company had already agreed to spend A$65mn on the project, which was also loaned A$32mn by the previous federal Coalition government in 2022. The nearshore Golden Beach field will produce gas for the domestic market in 2028 and transition to storage use the following year, GB has said, with a withdrawal capacity of 375 TJ/d. Southeastern Australia is presently grappling with projected structural gas shortfalls expected from 2028 unless new gas comes on line locally, LNG imports begin or storage is obtained. A combination of at least two of these is required, most experts said. The 26PJ Iona underground gas storage facility is the region's largest and assists with supply to Victorian capital Melbourne on peak demand days in winter, providing 100-400 TJ/d or up to 30pc of the state's gas demand. Profit dips Origin's underlying profit fell to A$593mn in July-December 2025, down from A$924mn a year earlier due to reduced earnings in the integrated gas division. Underlying earnings before interest, taxes, depreciation, and amortisation for integrated gas were A$860mn, down by 31pc from A$1.25bn in July-December 2024, due to lower realised APLNG prices and volumes and lower trading gains. Argus ' Gladstone fob price, an LNG netback indicator calculated by subtracting freight and costs associated with production from the delivered price of LNG to Asia-Pacific, averaged $10.74/mn Btu for the second half of the year, down from $12.70/mn Btu a year earlier. Guidance for gross APLNG gas production in 2025-26 remains at 645-680PJ, as reported last month . By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

US House votes to lift Trump's Canada tariffs

11/02/26
11/02/26

US House votes to lift Trump's Canada tariffs

Washington, 11 February (Argus) — The US House of Representatives on Wednesday took the symbolic step of voting to overturn President Donald Trump's tariffs on imports from Canada. The House voted 219-211 in favor of a resolution terminating the national emergency Trump proclaimed in February 2025 to justify his tariff actions against Canada. The Senate last year passed two separate resolutions voting to overturn Trump's tariffs on imports from Canada and from Brazil. Trump has vowed to veto the House resolution and the vote margin on Wednesday is not sufficient to overturn his veto. Wednesday's vote tally included six Republicans, who defied Trump's threats to run primary candidates against them if they voted to challenge his tariff authority. "Any Republican, in the House or the Senate, that votes against TARIFFS will seriously suffer the consequences come Election time, and that includes Primaries!", Trump posted shortly before the House vote. Trump cited a law called the International Emergency Economic Powers Act (IEEPA) to justify his tariff actions last year. The Supreme Court is expected to rule soon on whether Trump's use of IEEPA is legal. The administration's lawyers told the Supreme Court last year that Congress could have voted, but did not, to terminate the economic emergencies declared by Trump to justify his tariffs. By Haik Gugarats Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

PHMSA orders tests after Delfin LNG pipeline blast

11/02/26
11/02/26

PHMSA orders tests after Delfin LNG pipeline blast

Houston, 11 February (Argus) — A US regulator has ordered LNG developer Delfin Midstream to test and devise a restart plan for a Louisiana pipeline that ties into a proposed offshore export terminal following an explosion, according to a 10 February filing. The Pipeline and Hazardous Materials Safety Administration (PHMSA) listed a series of correctives measures for Delfin, including an order to hire a third party that will test and analyze what caused the explosion on 3 February near Johnson Bayou, Louisiana, about 60 miles southwest of Lake Charles. The roughly 30-mile pipeline previously moved gas from offshore Louisiana into an interstate network. Delfin bought the line in 2014 to repurpose it for a 4.4mn metric tonne (t)/yr floating LNG unit, which the company previously said it could greenlight this month . PHMSA wrote that the pipeline has been out of service since 2012. The regulator determined in its preliminary filings that the explosion occurred during maintenance operations as Delfin worked to restart the line. The blast injured one worker, who accused Delfin of gross negligence in a civil lawsuit on 10 February and is seeking more than $1mn in damages. By Tray Swanson Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

US LNG becomes domestic swing supply during storm

11/02/26
11/02/26

US LNG becomes domestic swing supply during storm

Feedgas supplies to LNG terminals dropped significantly, but overall exports fell only marginally, writes Tray Swanson London, 11 February (Argus) — Freezing weather across the US last month resulted in firms tapping feedgas flows to liquefaction facilities and existing LNG stocks intended for exports in order to meet gas demand from domestic users — a dynamic exacerbated by a decade-long mismatch between rapidly rising LNG production and a comparative lack of growth in underground gas storage. An arctic blast hit much of the US over 23-27 January, boosting heating demand while also causing freeze-offs at some gas production facilities. Gas suppliers drew on stocks to meet demand, marking the largest weekly storage withdrawal on record. But even this was not sufficient to rebalance the domestic market, and domestic spot prices soared to all-time highs. This led the US market to tap into its supply of last resort — gas intended for export. Gas producers and LNG exporters with the flexibility to do so were able to cede gas molecules back into the domestic market at attractive premiums. Freezing temperatures caused operational problems and production losses at upstream and midstream infrastructure, with lost output amounting to an estimated 93.2bn ft³ (2.6bn m³) over 25-31 January. Alongside this, gas demand for heating soared, leading to a record-high stockdraw of 360bn ft³ in the week ending 30 January, Energy Information Administration (EIA) data show. The stockdraw was highest in south-central US, where six operating LNG export terminals are spread across Louisiana and Texas. Withdrawals in the region reached a record-high 159bn ft³ in the week to 30 January. Even so, Henry Hub day-ahead prices still rose to a record high above $28/mn Btu over 23-26 January, more than double the value of spot LNG delivered to northwest Europe. Prices were even higher at nearby trading hubs, giving liquefaction capacity holders a strong incentive to sell their gas domestically. Aggregate feedgas flows to the US' eight liquefaction facilities fell by at least 7bn ft³/d, or 39pc, at the peak of the cold snap, compared with a 30-day average of 17.9bn ft³/d before temperatures plummeted. The aggregate reduction in gas available for export amounted to about 26bn ft³ in the week ending 30 January, equivalent to eight LNG cargoes. Among Gulf coast LNG facilities, the slowdown in feedgas nominations was most pronounced at the 33mn t/yr Sabine Pass and 15mn t/yr Cameron terminals in Louisiana, and the 28.9mn t/yr Corpus Christi and 17.3mn t/yr Freeport facilities in Texas. Cheniere procures and holds title to the gas at Sabine Pass and Corpus Christi until it is loaded as LNG onto a ship, whereas Cameron and Freeport are tolling-based terminals. For whom the bell tolls Yet aggregate US loadings fell by only 107,000t in January compared with the previous month, and exports from Sabine Pass, Cameron and the 27.2mn t/yr Plaquemines terminal even increased on the month. Cheniere has the advantage of significant LNG storage, with tanks capable of holding eight LNG cargoes across its two terminals. This likely allowed Cheniere to meet its contractual obligations with offtakers while also selling feedgas into the domestic market. Cheniere's feedgas supply fell by 9.8bn ft³ over 24-28 January, pipeline data show. This volume is equivalent to three LNG cargoes and could easily be offset by supplies from Cheniere's sizable storage capacity. And customers with LNG tolling arrangements have considerable flexibility because they control their gas supply and are not obligated to liquefy it. In fact, tolling LNG terminals on the Atlantic coast not only cut their feedgas flows during the late-January freeze but they also imported cargoes. Firms in the east coast region withdrew 74bn ft³ of gas from storage in the week ending 30 January, just 2bn ft³ shy of the record set in January 2018, EIA data show. This propelled day-ahead prices to a record high of $133.85/mn Btu on 26 January at Transco zone 5, a bellwether market for demand between the Georgia-South Carolina and Virginia-Maryland borders. Trading firms imported LNG to Georgia's 4mn t/yr Elba Island and Maryland's 5.75mn t/yr Cove Point terminals for the first time in more than five years, with BP shipping two cargoes to Cove Point and Shell sending one to Elba Island, data from trade analytics firm Kpler show. Last month's events may have exposed the limits of a market that has seen its flexibility eroded over the past decade, as the US' rapid rise to the rank of top global LNG exporter has not been matched by comparable investment in storage. Underground storage capacity has remained flat over the past decade, during which time the US has transformed from a net gas importer into the world's largest LNG producer. That process has left the US with little slack in its gas system, particularly on the Gulf coast during periods of weather-related supply disruptions. Aggregate US storage capacity stood at 4.67 trillion ft³ in November, the most recent data made available by the EIA show. This compares with 4.66 trillion ft³ a decade earlier, when the country was on the cusp of shipping its first domestically produced LNG cargo from the lower 48 states. Storage capacity available at present likely equates to approximately 14pc of the overall size of the US market, compared with 17pc a decade earlier. The imbalance is even more striking in the key exporting states of Texas and Louisiana, where total designed storage capacity has remained flat at 988bn ft³ over the past 10 years, while feedgas to Gulf coast LNG facilities has risen to 16.5bn ft³/d at the end of 2025 from virtually zero a decade earlier, before the Sabine Pass facility had been commissioned. Up to speed Differences across storage withdrawal ratescan also add to price volatility. The south-central region has the highest technical withdrawal capacity of about 51.8bn ft³/d, in part because almost a third of its storage sites consist of salt caverns, according to the EIA. Salt caverns can send out gas much faster than storage at depleted reservoirs and aquifers, which make up the majority of capacity in other regions and have withdrawal speedsof around 4.3bn-28.2bn ft³/d. Narrow seasonal spreads in US gas prices have caused investments in storage capacity to dry up since the beginning of the last decade. Nymex futures contracts for delivery at the Henry Hub this summer currently hold a 86¢/mn Btudiscount to corresponding contracts for delivery in winter months, having slightly expanded from last year's average of 55¢/mn Btu. Tighter spreads reduce the intrinsic value of storage capacity — or the ability for capacity holders to lock in margins months or years in advance because of the seasonal spread in gas prices. But the volatility caused by growing LNG production is increasing the extrinsic value of storage — the ability to benefit from short-term price volatilitybecause of the additional optionality gas stocks provide — resulting in renewed interest in investing in such capacity. Extreme weather will continue to threaten price volatility until more underground gas storage is built. Projects comprising 262bn ft³ of capacity have been proposed in the US in recent years. If all are built, the country's capacity would increase by nearly 6pc, after holding flat at around 4.7 trillion ft³ since 2015. Even so, liquefaction capacity is expected to grow at an even faster pace, following a banner year for investments in US LNG in 2025. US liquefaction capacity is predicted to increase by 80pc over 2026-30, reaching nearly 225mn t/yr, or 28bn ft³/d, by the end of the decade. Feedgas flows to LNG plants trillion Btu Henry Hub implied seasonal spreads $/mn Btu LNG vs key TX/LA day-ahead prices $/mn Btu Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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