US backs Opec calls for more oil, gas investment

Spanish Market: Crude oil, Emissions, Natural gas
31/10/22

The US' top energy envoy Amos Hochstein today supported calls for investment in oil and gas to increase globally alongside spending on the transition to a lower-carbon energy system.

"We hope this happens around the world," Hochstein told the Adipec conference in Abu Dhabi. "Increased investment in production, investment in refining capacity and… at the same time additional investment in the [energy] transition."

After weeks of tense exchanges between the US and Opec linchpin Saudi Arabia over the wider Opec+ group's decision to lower crude output quotas, Hochstein's comments put Washington on the same page as Opec, which has long called for increased oil and gas investment. UAE energy minister Suhail al-Mazrouei told the Adipec conference today higher oil and gas spending will help the world navigate the energy transition and reduce the risk of today's supply crunch being experienced in the future.

Al-Mazrouei was at pains to stress that increased oil and gas spending is not just an issue for Opec+ producers. "We in the UAE, as well as our fellow producers in Opec+, are keen on supplying the world with the [oil] requirements it needs. But, at the same time, we are not the only producers," he said. "Others also need to do their part in investing and encouraging investments."

Opec+ — which groups Opec countries with 10 non-Opec producers led by Russia — is doing its part when it comes to investing in hydrocarbons, al-Mazrouei said. Saudi Arabia and the UAE, in particular, are pursuing aggressive upstream expansions that should deliver close to 2mn b/d of additional crude capacity before the end of the decade.

Prior to Russia's invasion of Ukraine, many governments in Europe and the US were pushing for a more urgent commitment to move away from fossil fuels. But Hochstein today insisted that energy investment is needed across the board. Spending on fossil fuels and cleaner energies is "not contradictory", he said. "They are just two different timelines," he said. "It may be that our climate goals are met by 2035 or 2050. But to get to those goals, we had to invest yesterday."

The Opec+ group's decision earlier this month to lower its collective crude output target by 2mn b/d from November was met with heavy criticism from Washington, with US president Joe Biden describing the cut as short-sighted at a time when consumers are struggling with high energy prices.

"The price of energy is a critical piece for global economic growth, because so much of what we do is dependent on that," Hochstein said today, adding that a prolonged period of higher oil prices could hamper economic growth prospects. "Energy has to be priced in a way that allows for economic growth," he said. "If not, they will accelerate the economic downturn, which ultimately is the one thing that will be terrible for energy demand itself."

By Nader Itayim and Bachar Halabi

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23/12/24

Viewpoint: US LPG cargo premiums poised to fall

Houston, 23 December (Argus) — The booming US LPG export market has fueled record spot fees this year for terminal operators that send those cargoes abroad, but those fees are poised to fall next year as additional export capacity comes online. US propane exports surged over the past two years, hitting an all-time high of 1.85mn b/d in the first quarter of this year, according to data from the US Energy Information Administration (EIA). Terminal fees for spot propane cargoes out of the US Gulf coast hit an all-time high of Mont Belvieu +32.5¢/USG (+$169.325/t) in mid-September. US propane production is expected to grow by another 80,000 b/d in 2025 to 2.22mn b/d while the outlook for domestic consumption is fairly steady, at 820,000 b/d next year — meaning even more propane will be pushed into the waterborne market. But that is dependent on US infrastructure keeping up with the pace of production. US export terminals in Houston, Nederland and Freeport, Texas, have run at or above capacity for the last two years given the thirst for cheaper US feedstock, largely from propane dehydrogenation (PDH) plant operators in China. This demand has created bottlenecks at US docks, and midstream operators like Enterprise, Energy Transfer, and Targa have rushed to ramp up spending on both pipelines and additional refrigeration to stay ahead of the wave of additional production. US gas output spurs LPG exports As upstream producers have ramped up natural gas production ahead of new LNG projects, most producers are counting on LPG demand from international outlets in Asia to offload the ethane and propane the US cannot consume. For the past four years, Asian buyers have been more than happy to oblige. US propane exports to China rose from zero in 2019, when China imposed tariffs on US imports, to an average of 1.36mn metric tonnes (t) per month in January-November 2024, according to data from analytics firm Kpler, making China the largest offtaker of US shipments. US exports to Japan averaged 480,000t per month throughout most of 2024, and exports to Korea averaged 460,000t per month in the first 11 months of 2024. China, Korea, and Japan received 52pc of US propane exports in 2024, up from 49pc in 2020, according to data from Vortexa. Strong demand in Asia has kept delivered prices in Japan high enough to sustain an open arbitrage between the US and the Argus Far East Index (AFEI). Forward-month in-well propane prices at Mont Belvieu, Texas, have remained well below delivered propane on the AFEI. In 2020, Mont Belvieu Enterprise (EPC) propane averaged a $143/t discount to delivered AFEI — a spread that has only widened as additional PDH units in Asia have come online. During the first 11 months of 2024, the Mont Belvieu to AFEI spread averaged a hefty $219/t, leaving plenty of room for wider netbacks in the form of higher terminal fees for US sellers, especially as a wave of new VLGCs entering the global market has left shipowners with less leverage to take advantage of the wider arbitrage. The resulting wider arbitrage to Asia has kept US export terminals running full for the last two years. So when a series of weather-related events and maintenance in May-September limited the number of spot cargoes operators could sell and delayed scheduled shipments, term buyers willing to resell any of their loadings could effectively name their price. This spurred the record-high premiums for spot propane cargoes in September. New projects may narrow premium An increase in US midstream firm investments in additional dock capacity and added refrigeration in the years ahead could narrow those terminal fees, however. Announced projects from Enterprise and Energy Transfer, in particular, will add a combined 550,000 b/d of LPG export capacity out of Houston and Nederland, Texas by the end of 2026. Enterprise's new Neches River terminal project near Beaumont, Texas, will add another 360,000 b/d of either ethane or propane export capacity in the same timeframe. These additions are poised to limit premiums for spot cargoes by the end of 2025. Already, it appears the spike in spot cargo premiums to Mont Belvieu has abated for the rest of 2024. Spot terminal fees for propane sank to Mont Belvieu +14¢/USG by the end of November. The lower premiums come not only as terminals resume a more normal loading schedule, but at the same time a surplus of tons into Asia ahead of winter heating demand has narrowed the arbitrage. The spread between in-well EPC propane at Mont Belvieu fell from $214.66/t to $194.45/t during November. A backwardated market for AFEI paper into the second quarter of 2025 means US prices are poised to fall more in order to keep the spread from narrowing further. By Amy Strahan Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Low-carbon fuel battles tumble into 2025

23/12/24

Viewpoint: Low-carbon fuel battles tumble into 2025

Houston, 23 December (Argus) — Fights over North America's largest low-carbon fuel mandates will tumble into 2025, long after a contentious year spent updating the program. California's minority Republican lawmakers have seized upon fears that new, tougher targets approved in November to the state's Low Carbon Fuel Standard (LCFS) could hike today's pump prices by 15pc. Environmental opponents have sued the California Air Resource's Board (CARB) alleging regulators ignored shortcomings to push through those amendments. And fuel suppliers, meanwhile, continue to grapple with new demands on feedstock selection, certification and other decisions that will begin to tighten by the end of this decade. LCFS programs require yearly reductions in transportation fuel carbon intensity. Higher-carbon fuels including petroleum diesel and gasoline incur deficits for exceeding annual targets. Suppliers must offset these deficits with credits generated from distributing approved, lower-carbon alternatives to the state. California operates the oldest and largest among five operating programs on the continent. The program helped drive a surge in US renewable diesel production capacity that earlier this year cut petroleum's share to less than a quarter of the liquid diesel used in the state. Credit trade representing each metric tonne (t) of carbon reduction drives the incentives for renewable diesel, captured dairy methane or electric vehicle charging capacity used in California transportation. Credits peaked at $219/t in February 2020, equivalent to roughly $267.10/t in today's dollars. But spot credits have languished below $100/t since late 2022. Prices buckled under the growing weight of more than 30mn t of extra credits available for future compliance — enough to satisfy all the deficits generated in 2023 a second time, with another 30pc leftover. CARB staff estimated that the targets board members approved in November would reduce that reserve by more than 8mn t, or less than a third. Fuel producers warned that carbon reduction could stagnate under the smothering imbalance of new credits. Staff dismissed outside estimates of 65¢/USG increases to gasoline prices attributed to the tough new program targets, but declined to offer a competing cost estimate. Spot credit prices would need to more than triple to $250/t next year to hit gasoline prices that hard at the pump, based on Argus analysis. Pump prices make good politics Governor Gavin Newsom (D) has for two years sought and received state tools to scrutinize oil company profits on California fuel sales. Now a California state senate Republican bill would repeal the new targets and other newly adopted changes intended to restore incentives under the program. A state assembly bill would require any CARB new rulemaking or standard to undergo a cost analysis by the state's Legislative Analyst Office, a nonpartisan office that performs such reviews of legislative proposals. These Republican measures face a likely impossible climb through Democratic supermajorities in both chambers. But lawmakers noted the potency of fuel price complaints. A legislative session — framed in defiance of a new federal administration hostile to their climate efforts — opened with leaders acknowledging the need to balance costs. "California has always led the way on climate change and we will continue to lead on climate," speaker Robert Rivas (D) said on 2 December. "But not on the backs of poor and working people. Not with taxes or fees for programs that don't work." Similar battles have already spilled out of the state. British Columbia voters in October narrowly denied conservatives a majority on a platform that included ending the province's aggressive LCFS. National conservatives targeted Canada's carbon taxes in a campaign against Premier Justin Trudeau's wobbling government ahead of elections next year. As regulators update programs to drive ambitious transportation changes, voters will become more aware of where the changes are heading. By Elliott Blackburn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US tax fight next year crucial for 45Z

23/12/24

Viewpoint: US tax fight next year crucial for 45Z

New York, 23 December (Argus) — A Republican-controlled Congress will decide the fate next year of a federal incentive for low-carbon fuels, setting the stage for a lobbying battle that could make or break existing investment plans. The 45Z tax credit, which offers greater subsidies to fuels that produce fewer emissions, is poised to kick off in January. Biofuel output has boomed during President Joe Biden's term, driven in large part by west coast refiners retrofitting facilities to process lower-carbon fats and oils into renewable diesel. The 45Z tax credit, created by the 2022 Inflation Reduction Act (IRA), was designed to extend that growth. But Republicans will soon control Washington. President-elect Donald Trump has dismissed the IRA as the "Green New Scam", and Republicans on Capitol Hill, who had no role in passing Biden's signature climate legislation, are keen to cut climate spending to offset the steep cost of extending tax cuts from Trump's first term. Biofuels support is a less likely target for repeal than other climate policies, energy lobbyists say. But Republicans have already requested input on 45Z, signaling openness to changes. Republicans plan to use the reconciliation process, which enables them to avoid a Democratic filibuster in the Senate, to extend tax breaks that are scheduled to expire in 2025. "I want to place our industry in a place to make sure that the biofuels tax credit is part of reconciliation," said Kailee Tkacz Buller, president of the National Oilseed Processors Association. But lawmakers "could punt the biofuels discussion if stakeholders aren't aligned." A decade ago, biofuel policy was a simple tug-of-war between the oil and agriculture industries. Now many refiners formerly critical of the Renewable Fuel Standard produce ethanol and advanced biofuels themselves. And the increasingly diverse biofuels industry could complicate efforts to present a united front to Congress. Farm groups worry about carbon intensity scoring hurting crop demand and have lobbied to curtail record-high feedstock imports, to the chagrin of some biorefineries. Those producers are no monolith either: Biodiesel plants often rely more on local vegetable oils, while ethanol producers insist on keeping incentives that do not discriminate by fuel type and some oil majors would back subsidizing fuels co-processed with petroleum. Add airlines into the picture, which want greater incentives for aviation fuels, and marketers frustrated by 45Z shifting subsidies away from blenders — and the threat of fractious negotiations next year becomes clear. There are options for potential compromise, according to an Argus analysis of comments submitted privately to Republicans in the House of Representatives, as well as interviews with energy lobbyists and tax experts. The industry, frustrated by the Biden administration's delays in clarifying 45Z's rules, might welcome legislative changes that limit regulatory discretion regardless of what agency guidance eventually says. And lobbyists have floated various ways to appease agriculture groups without kneecapping biorefineries reliant on imports, including adding domestic content bonuses, imposing stricter requirements for Chinese-origin used cooking oil, and giving preference to close trading partners. Granted, unanimity among lobbyists is hardly a priority for Republican tax-writers. Reaching any consensus in the restive caucus, with just a handful of votes to spare in the House, will be difficult enough. "These types of bills always come to down to what's the most you can do before you start losing enough votes to pass it," said Jeff Navin, cofounder of the clean energy advocacy firm Boundary Stone Partners and a former House and Senate staffer. "Because they can only lose a couple of votes, there's not much more beyond that." And the caucus's goal of cutting spending makes an industry-wide goal — extending the 45Z credit into the 2030s — even more challenging. "It is a hard sell to get the extension right away," said Paul Winters, director of public affairs at Clean Fuels Alliance America. Climate costs Cost concerns also make less likely a simple return to the long-running blenders credit, which offered $1/USG across the board to biomass-based diesel. The US Joint Committee on Taxation in 2022 scored the two-year blenders extension at $5.5bn, while pegging three years of 45Z at less than $3bn. An inconvenient reality for Republicans skeptical of climate change is that 45Z's throttling of subsidies based on carbon intensity makes it more budget-friendly. Lawmakers have other reasons to not ignore emissions. Policies elsewhere, including California's low-carbon fuel standard and Europe's alternative jet fuel mandates, increasingly prioritize sustainability. The US deviating from that focus federally could leave producers with contradictory incentives, making it harder to turn a profit. And companies that have already sunk funds into reducing emissions — such as ethanol producers with heavy investments in carbon capture — want their reward. Incentives with bipartisan buy-in are likely more durable over the long run too. Next time Democrats control Washington, liberals may be more willing to scrap a credit they see as padding the profits of agribusiness — but less so if they see it as helping the US decarbonize. By Cole Martin Tax credit changes 40A Blenders Tax Credit 45Z Producers Tax Credit $1/USG Up to $1/USG for road fuels and up to $1.75/USG for aviation fuels depending on carbon intensity For domestic fuel blenders For domestic fuel producers Imported fuel eligible Imported fuel not eligible Exclusively for biomass-based diesel Fuels that produce no more than 50kg CO2e/mmBTU are eligible Feedstock-agnostic Carbon intensity scoring incentivizes waste over crop feedstocks Co-processed fuels ineligible Co-processed fuels ineligible Administratively simple Requires federal guidance on how to calculate carbon intensities for different feedstocks and fuel pathways Expiring after 2024 Lasts from 2025 through 2027 Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Japan’s Chugoku restarts Shimane nuclear reactor early

23/12/24

Japan’s Chugoku restarts Shimane nuclear reactor early

Osaka, 23 December (Argus) — Japanese utility Chugoku Electric Power restarted the 820MW Shimane No.2 nuclear reactor for test operations on 23 December, two days earlier than originally planned. The No.2 reactor at Shimane in west Japan's Shimane prefecture was reconnected to the country's power grids for the first time in nearly 13 years, after the reactor shut down in January 2012 for stricter safety inspections following the 2011 Fukushima nuclear meltdown disaster. Chugoku reactivated the Shimane No.2 reactor on 7 December, aiming to resume power generation on 25 December. But the target date for commercial operations remained unchanged on 10 January, despite the earlier than expected restart. The Shimane No.2 reactor will be a vital power source as the sole nuclear fleet in the Chugoku area, to help enhance the resilience of the power supply structure, stabilise retail electricity prices and reduce CO2 emissions, said Japan Atomic Industrial Forum's president Hideki Masui on 23 December. The Shimane No.2 reactor is the second boiling water reactor (BWR) to be restarted after the Fukushima disaster, following the 825MW Onagawa No.2 BWR unit that resumed test generation on 15 November, with normal operations scheduled to restart on 26 December. The BWR is the same type as that involved in the meltdown at the Fukushima Daiichi plant. The restart of the two BWRs would pave the way for Japan's nuclear restoration, as 15 BWRs — including advanced BWRs — are still closed in the wake of the Fukushima disaster. Japan has restored 14 reactors as of 23 December, including the Shimane and Onagaw reactors, of which 12 are installed with a pressurised water reactor (PWR) design. Nuclear power's share The Japanese government last week set a target of 20pc for nuclear power's share in the country's draft power mix for the April 2040-March 2041 fiscal year, under the triennial review for the country's Strategic Energy Plan (SEP). Tokyo is seeking to restart all existing reactors to achieve the 20pc goal, adding that replacement reactors would also be possible. The draft SEP allows nuclear power operators that had decommissioned reactors to build next-generation reactors at their nuclear sites, not limited to the same site. The previous SEP did not mention building new reactors or replacements. Japan's Federation of Electric Power Companies (FEPC) has applauded this progress, but FEPC chairman Kingo Hayashi noted that it was disappointing the SEP did not mention a nuclear capacity target which the FEPC had requested. It also did not include building new reactors or the expansion of existing nuclear plants, Hayashi added. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Europe’s refiners eye support from closures

23/12/24

Viewpoint: Europe’s refiners eye support from closures

London, 23 December (Argus) — Another tranche of European refining capacity will close for good next year, but the reprieve for margins in the region may only be temporary. Nearly 400,000 b/d of capacity, around 3pc of Europe's total, is scheduled for permanent closure in 2025, comprising Petroineos' 150,000 b/d Grangemouth refinery in Scotland, Shell's 147,000 b/d Wesseling refinery in Germany and a third of the capacity at BP's nearby 257,000 b/d Gelsenkirchen refinery . Around 30 refineries have closed in Europe since 2000. Among the most recent was Italian firm Eni's 84,000 b/d Livorno refinery in northern Italy earlier this year. And only this month, trading firm Gunvor announced it is mothballing its small upgrading refinery in Rotterdam . The Rotterdam facility had already stopped processing crude in 2020, leaving it peculiarly exposed to the margins between intermediate feedstocks and finished fuels. The refinery has been hit by a 25pc increase in operating costs in the last four years and a squeeze on margins, the latter the result of competition from new refineries outside the region, Gunvor said. Outside Europe, the world has added more than 2.5mn b/d of crude distillation capacity in the last three years. Three brand new refineries have come on stream in the Middle East in that time — Saudi Arabia's 400,000 b/d Jizan, Kuwait's 615,000 b/d Al-Zour with Oman's 230,000 b/d Duqm refineries. More recently, Nigeria's 650,000 b/d Dangote refinery, Mexico's 340,000 b/d Olmeca refinery and Yulong Petrochemical's 400,000 b/d refinery in China's Shandong province started up, all of which are likely to ramp up throughput in 2025. Refinery closures tend to support margins for those that remain. But European refiners' costs continue to rise while demand for their products falls, which means next year's closures are unlikely to be the last. Simpler and smaller refineries are prime candidates for closure as they usually achieve weaker margins. Europe also has plenty of refineries built before 1950 that are still running. These older plants can be more at risk of accidents and breakdowns. And repairs can sometimes cost so much that they tip a refinery into the red. An ongoing concern for European refiners is the trend towards lighter and sweeter crude slates , driven by supply-side dynamics, which is resulting in higher naphtha yields at a time when demand for naphtha from Europe's petrochemical sector is under pressure from a contraction in cracking capacity. But many in the market expect the greatest pressure in 2025 will fall on those coastal refineries in Europe that were built to maximise gasoline output. If, as expected, Dangote continues to shrink Nigeria's demand for gasoline imports , these refineries will be hit hardest. Any refinery that cannot desulphurise all of its gasoline output to the 10ppm required for UK or EU usage will be under intense pressure, as west Africa is presently among the only outlets for European high-sulphur gasoline. Strike support One of the strongest supports for European refining margins in 2025 could come in the form of industrial action if new capacity cuts or closures were to be announced. Refinery workers in the region have shown willing and able in the past to organise large-scale strikes, most emphatically in France. The highest diesel refining margins Argus has ever recorded came in October 2022, when the entire French refining system was shut down by strikes. Another trend to watch out for next year is the continuing shift in the ownership structure of Europe's refining sector. The large integrated oil companies that have dominated the industry for so long have been steadily selling European refining assets to independents and trading firms. The latter are nimbler and able to cut costs more ruthlessly. And with many of them not publicly listed, they are less susceptible to pressure regarding their environmental footprints. There could be more instalments in this story in 2025. Sweden's Preem started accepting bids for its Swedish refining assets in the summer of 2024 and Russia's Lukoil is considering bids for its Burgas refinery in Bulgaria. By Benedict George Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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