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Falling LCFS credit price narrows RNG prospects

  • Market: Emissions, Natural gas
  • 20/05/22

Sliding prices may narrow development of one of last year's fastest-growing sources of California Low Carbon Fuel Standard (LCFS) credits.

Interlocking incentives led by the state's transportation fuel program spurred a nationwide build-out of projects to harvest methane from dairy cattle and swineherds over the past five years to produce more renewable natural gas (RNG).

But a surge in new credits helped cut LCFS prices by nearly half since January 2021. The drop may refocus investment in the largest, cheapest projects.

"Not every dairy farm is created equal," said Tyler Henn, Clean Energy Fuels vice president of business development and renewable natural gas investment.

California's LCFS program reduces the carbon intensity of transportation fuels through steadily falling annual limits on the amount of CO2 emitted during their production and use. Higher-carbon fuels that exceed the annual maximum incur deficits that suppliers must offset with credits generated by distributing approved lower-carbon fuels.

The lower or higher a fuel's score compared with the annual limit, the more credits or deficits it will generate. Dairy methane harvested and supplied to compressed natural gas vehicles has surged, in part due to scores that can place individual projects hundreds of points below the annual limit, many times lower than the nearest low-carbon competitor.

The gap translates to outsized credit generation. RNG made using dairy and other animal methane generated 2.1mn t of LCFS credits in 2021, or about 11pc of all new credits for the year. But dairy digester or animal waste gas made up just 1.5pc of alternative fuel volume in 2021 — displacing less than 2,800 b/d of equivalent diesel. Renewable diesel, which generated three times the credits of dairy and swine RNG last year, displaced more than 20 times the volume of petroleum diesel.

Spot credits have fallen to nearly $100/metric tonne from about $200/t at the beginning of last year. Supplies of new credits from renewable fuels outpaced the demand for higher-carbon gasoline and other fuel in 2021.

Dairy deluge

Thin margins and economies of scale have helped consolidate especially western US dairies to larger herds, according to the US Department of Agriculture (USDA).

Such concentration can reduce the investments needed to capture, process and connect harvested biomethane to US natural gas pipelines. It takes thousands of cows, either at a single large dairy or clustered across several operations, to produce sufficient gas. Projects need not always build new feeder pipelines — trucks can move compressed gas from some sites for injection.

State regulators need dairies and renewable natural gas infrastructure to capture more. California hosts about 20pc of all US dairies, and the operations produce the largest share of the state's methane emissions. California was on pace to meet just half of a targeted 40pc reduction in dairy methane emissions by 2030, according to California Air Resources Board estimated last year. The agency estimated that at least 160 additional dairies would need to use methane capture and processing to meet state goals.

California utilities also face renewable natural gas requirements. Southern California Gas expects RNG including landfill methane to make up 12pc of the gas it delivers to customers in 2030. Pacific Gas & Electric, California's largest utility, plans for RNG to make up 15pc of its gas by 2030, and already serves 22 CNG stations.

Competition for large or otherwise well-suited dairies soared with the combination of mandates and incentives, said Kevin Dobson, vice president of biomass for DTE Vantage.

"We are part of a big, $10bn company, and we are competing against, literally, people that work off of their kitchen table and drive a pickup truck into the farm," Dobson said.

But some dairies may lack manure management infrastructure, may lack easy access to offtake infrastructure, or need costlier equipment to produce the gas, Henn said.

The falling price environment raises the bar on project selection without halting it, Dobson said.

"You got to sharpen the pencil, you got to be a little bit more efficient," he said.

Reined in

Regulatory action could again curb the RNG boom. California limits methane emissions from landfills via another regulation. To generate LCFS credits, landfills must go beyond the cuts the state already requires. Gas captured from landfills averaged 8,260 b/d of diesel replacement but produced just 624,630 t of credits in 2021.

Regulators could still apply credit-slashing, landfill-style methane reductions to dairies. California's SB 1383, passed in 2016, authorized the state to regulate dairy methane as early as 2024. The state would need to consider dairy prices, the potential for dairies to move to other, less rigorous states, and assure that the regulations were "cost effective."

CARB has focused on incentives in communications about meeting dairy methane goals.

Environmental justice and animal welfare groups insist the incentives perpetuate large-scale agriculture that harms cattle, concentrates odors and wreaks other environmental damage. Some truck operators also question the long-term demand for the fuel.

The industry faces state mandates to electrify its fleets, with requirements that manufacturers making rising numbers of zero-emissions medium- and heavy-duty trucks available beginning in 2024. Major fleets that would otherwise prefer compressed natural gas were wary of heavy spending on those fuel systems, Western States Trucking Association head of regulatory affairs Joe Rajkovacz said.

"Those trucks are not even part of the future of what the California Air Resources Board wants to allow," Rajkovacz said.


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Argentina’s YPF sees jump in shale oil output

Montevideo, 8 November (Argus) — Argentina's state-owned YPF saw output of unconventional crude surge by 36pc to 126,000 b/d in the third quarter of the year compared to a year earlier. YPF's third quarter statement put total production at 559,000 b/d of oil equivalent (boe/d) with crude at 256,000 b/d, up by 8pc, and natural gas at 40.3mn m³/d, or 253,000 boe/d, an increase of 7pc, and 49,000 boe/d of natural gas liquids, up by 4pc. Unconventional crude accounted for 49pc of overall output. It was 39pc of total production a year earlier. YPF is the major player in Vaca Muerta, Argentina's unconventional formation that holds an estimated 16bn bl of crude and 308 trillion cf of gas, according to the US Energy Information Administration. The formation is at the heart of YPF's plans for Argentina to produce 1mn bl of crude and export up to 30mn metric tonnes/yr of LNG by the end of the decade. YPF is now Argentina's largest crude exporter, dispatching an average of 40,000 b/d in the third quarter, nearly all of this going by pipeline to neighboring Chile, according to Federico Barroetavena, chief financial officer. He said the company invested $1.35bn in the third quarter, with more than 70pc on upstream. It drilled 50 wells in the third quarter. YPF is moving ahead with its southern Vaca Muerta oil pipeline as it looks for partners for the full project. It has completed 50pc of the first 130km (81.4mi) segment. The second 440km, as well as storage tanks and a monobuoy platform, will require $2.5bn. The company anticipates construction to start in the first quarter of 2025. The initial capacity will be 180,000 b/d in 2026, increasing to 500,000 b/d in 2027 and, eventually, to 700,000 b/d. YPF is also the largest shareholder, with 37pc, in the Oldelval pipeline from Vaca Muerta to the coast. It is undergoing an expansion to 530,000 b/d in 2025. The state-owned energy company, Enarsa, completed in October the reversal of the country's northern gas pipeline to move Vaca Muerta gas to the north of the country. It will move more than 15mn m³/d of gas to northern Argentina. It previously moved gas from northern gas fields, now depleted, and Bolivia, to the capital, Buenos Aires. By Lucien Chauvin Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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California LCFS set for key decision Friday


08/11/24
News
08/11/24

California LCFS set for key decision Friday

Houston, 8 November (Argus) — Today California regulators will consider toughening carbon-slashing targets and raising hurdles for crop-based fuels to participate in North America's largest Low Carbon Fuel Standard (LCFS). California's Air Resources Board will weigh rulemaking underway for nearly a year — and on the verge of running out of time — to restore shrinking incentives in the state's program to decarbonize road fuels. The decision comes amid growing outcry over the cost of diversifying the state's fuel portfolio passed on to drivers. Choices made on incentives in the largest US renewable fuels and electric vehicle charging markets may offer some clarity to markets now roiled by uncertainty over the approach an incoming second Donald Trump administration will take. LCFS programs require yearly reductions to transportation fuel carbon intensity. Higher-carbon fuels that exceed the annual limit incur deficits that suppliers must offset with approved, lower-carbon alternatives. California's program has helped spur a rush of new renewable diesel production that quickly overwhelmed the deficits generated from petroleum gasoline and diesel use in the state. LCFS credits do not expire, and leftover credits available for future compliance grew to 29.1mn metric tonnes by July. The program generated 22.4mn deficits in all of 2023. Tougher targets on tap Board approval of amendments considered today would immediately toughen program targets for 2025 by 9pc. The one-year drop would nearly double reductions first proposed last year, and require cuts six times deeper than the typical year-to-year change in targets. Regulatory staff published models in April suggesting such a target could thin a smothering inventory of excess credits available for future compliance by 8.2mn — roughly a third of the available excess credits. Other proposals would take longer to begin. California would require new attestations about land use for crop-based feedstocks by 2026, shifting toward tougher verification requirements for such feedstocks by 2031. Regulators would limit credit generation for existing suppliers of biodiesel and renewable diesel made from soybean oil or canola oil credits to only 20pc of such fuels they supply to California by 2028. And CARB would begin phasing out outsized credit generation from renewable natural gas used in transportation in 2040, after locking-in incentives for current projects regardless of any regulations that would mandate methane reductions. The program has faced a late push of opposition from fuel suppliers and environmental critics highlighting costs to previously unaware drivers. The campaign inspired an unusual volume of public comment filings in October from residents focused on gasoline costs. But CARB faces a 5 January deadline to approve the proposals. Missing it would restart the regulatory process, which staff has said could take another two years to complete. Credits available for future compliance nearly tripled over the past two years. Renewable natural gas, electric vehicle and even biofuels groups wary of elements of the proposal have issued statements of support this week. Chairwoman Liane Randolph has repeatedly defended the program in public appearances as the temperature on fuel costs concerns rose. Targets must get tougher, she said earlier this year . She reiterated the need for the standard in response to media questions about the lack of information about potential cost increases. CARB's choices will ripple across fuel supply strategies around the world. California used two thirds of the renewable diesel consumed in the US during the second quarter, and access to the market can determine feedstock margins. With immediate federal choices on biofuel tax incentives or possible feedstock sanctions uncertain, clarity on California's may offer suppliers one of the fuel planning footholds this year. 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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Zambia UN carbon market focus on VCM transition


08/11/24
News
08/11/24

Zambia UN carbon market focus on VCM transition

Berlin, 8 November (Argus) — Zambia is expecting to generate at least 10 projects under the UN's new carbon market mechanism, mostly by transferring projects from the voluntary carbon market (VCM). At least five Zambia-based VCM projects could be transitioned to the new mechanism under Article 6.4 of the Paris climate agreement next year, head of the environment ministry's green economy and climate change department, Ephraim Mwepya Shitima, told Argus in a recent interview. By contrast, Zambia expects to transition only one or two projects from its limited portfolio under UN predecessor the clean development mechanism (CDM), although others might decide to follow suit if they see that "it works", Shitima said. Zambia also expects two projects generated under the new Paris Agreement Crediting Mechanism (PACM) proper to be validated next year, thanks to the Supporting Preparedness for Article 6 initiative that provides support to Zambia, Colombia, Pakistan and Thailand. The PACM, a centralised mechanism for trading carbon credits, is expected to launch next year following agreement on outstanding details at the UN Cop 29 climate summit starting in Baku, Azerbaijan, next week. The more advanced and less regulated bilateral carbon market mechanism under Article 6.2, which has already seen some activity, also depends on agreement at Cop 29 to provide clarity on registries, and the scope and timing of project authorisations. There is an overall expectation that agreement will be reached at this Cop, following years of slow progress and failed deals, not least because the Cop presidency has named Article 6 a priority . The lack of progress on Article 6.4 so far has not stopped project developers in Zambia, Shitima stressed, which have received support from the Zambian government. The government is also working on setting up a registry, although if it does not succeed in time, Zambia will use the international registry earmarked for countries unable to set up their own. And despite the credibility crisis the VCM has suffered since early last year, the standard of Zambia's VCM projects — mostly registered under Verra and Gold Standard — is sufficiently high to allow them to transition to the PACM, Shitima said. It is not yet clear whether the PACM will allow all forestry activities, which constitute most of Zambia's VCM projects. Afforestation and reforestation will be included, but the trickier "avoided deforestation" category is still being negotiated. For forestry projects, carbon storage permanence is an important issue, and the Article 6.4 supervisory body recently proposed relatively strict conditions in the shape of a buffer pool for unavoidable reversals and insurance for avoidable ones. These rules have been criticised as possibly too strict and costly for host countries. But Zambia welcomes these "stringent" rules, Shitima said. The country's green economy and climate change law, expected to come into force by the end of the year, will provide the legal basis for charging proceeds from project developers. These will go into a climate change fund, some of which will cover costs for dealing with reversals or guaranteeing the permanence of removals. Zambia is also in talks with buyer countries under Article 6.2 and expects to sign bilateral agreements with Sweden — with which it already signed an initial agreement — and Norway in Baku. By Chloe Jardine Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Hungary’s Mol cuts forecast for 2024 refinery runs


08/11/24
News
08/11/24

Hungary’s Mol cuts forecast for 2024 refinery runs

Budapest, 8 November (Argus) — Hungarian integrated oil firm Mol has revised down its 2024 forecast for crude runs at its two landlocked refineries after a "turnaround-heavy" third quarter, it said today. The company expects to refine around 11.5mn t of crude combined at the 161,000 b/d Szazhalombatta plant in Hungary and the 115,000 b/d Bratislava complex in Slovakia this year, down from its previous guidance of about 12mn t. The two refineries processed 8.25mn t of crude in January-September, down from 9.09mn t a year earlier. Their combined crude throughput was down by 11pc on the year at 2.81mn t in the third quarter. Mol carried out scheduled maintenance at Szazhalombatta between 26 July and 19 September and expects to complete maintenance work on petrochemical units at Bratislava in the first half of November. Crude intake at Mol's third refinery, the 90,000 b/d Rijeka plant on Croatia's Adriatic coast, rose by 2.6pc on the year to 802,000t in the third quarter and was largely unchanged year-on-year at 1.26mn t in January-September. The company's crude throughput forecast only includes the Hungarian and Slovakian refineries. Mol cut the share of imported crude in its overall slate to 3.35mn t, or 93pc, in the third quarter from 3.8mn t, or 97pc, a year earlier, while it almost doubled intake from its own crude production to 255,000t in July-September from 129,000t in the same period last year. Szazhalombatta and Bratislava mostly process Russian crude received through the Druzhba pipeline system under an EU oil ban waiver, while Rijeka mainly takes non-Russian seaborne crude. The profitability of Mol's refining business was hit by a 71pc year-on-year fall in its refinery margin indicator — calculated based on the Dated Brent crude benchmark — to just $3.70/bl in July-September. Its oil product sales fell by 4.2pc from a year earlier to 4.88mn t in the third quarter. This included 1.52mn t of products Mol had to buy from third parties to complement its own output and satisfy demand, a significant rise from 1.25mn t of third-party oil products it sold a year earlier. The firm's upstream oil and gas production rose by 11pc on the year to 96,100 b/d of oil equivalent (boe/d) in the July-September quarter. It has raised its full-year forecast to about 92,000-94,000 boe/d from previous guidance of around 90,000 boe/d. Mol's profit fell to 111.5bn forint ($295mn) in the third quarter from Ft175.8bn a year earlier. By Béla Fincziczki Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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German energy-intensive industry reduces output


07/11/24
News
07/11/24

German energy-intensive industry reduces output

London, 7 November (Argus) — Production from Germany's energy-intensive industrial sectors was lower in September than a year earlier for the first time in seven months, driven by lower generation from the chemicals sector. Energy-intensive industrial production fell by about 3.3pc in September from August, according to data from German statistical office Destatis ( see data and download ). This was driven largely by a 4.3pc fall in output from the chemicals industry. And overall industrial output was about 1.8pc lower than in September 2023, falling year on year for the first time since February this year. The chemicals industry has warned of lower business confidence in the sector since the summer . Energy-intensive industrial branches previously showed signs of a slow recovery, but general manufacturing output across Germany has been on a consistent downward trajectory in recent months ( see manufacturing index graph ). Manufacturing output across all industrial sectors fell on the month by about 2.5pc, having risen on the month by 2.6pc in August. Third-quarter output as a whole was about 2pc lower than in the second quarter. Industrial economic activity has remained "very weak" recently, German economy and climate ministry BMWK said. But it expects a bottom to form in about the new year. BMWK has predicted that Germany will be in a technical recession in 2024 , before a return to 1.1pc GDP growth in 2025. The German economy started on a downward trajectory in 2022 , triggered by higher energy prices on the back of a halt to Russian gas deliveries to the country. And it has since been hampered by other structural factors such as labour shortages and a high bureaucratic burden. Higher gas prices could drive output lower A steady rise in gas prices in recent months could lead industrial firms to curtail domestic industrial production or use LPG instead of gas for some industrial processes. Argus assessed the German THE everyday price at an average of €40.68/MWh in October, about 56pc higher than the €25.98/MWh in February, the index's lowest point this year. Much higher gas prices since 2022 have driven a drop in Germany's industrial gas demand. Gas use in German industry of 256.5TWh in 2023 was about 22pc lower than the pre-crisis 2018-21 average of 327.6TWh, according to Destatis data released earlier this week ( see sector demand graph ). Firms either curtailed production in reaction to higher prices or switched to LPG in some processes in which gas is used as an energy carrier. But some processes, such as the production of ammonia through the Haber-Bosch-synthesis, use methane as a feedstock, which means they cannot shift to LPG as easily. Gas used as a feedstock reacted more strongly to the energy crisis than the gas used for energy. Gas use as a feedstock in the chemicals industry fell by 36pc in 2023 from 2021, while gas use for energy fell by only a quarter. Many fertiliser producers curtailed capacity in 2023, and Europe's largest fertiliser producer, Yara, expects its European gas costs to rise on the year this winter . The producer has already indicated it will shift its focus towards cheaper ammonia production in the US and away from Europe. Industrial gas use on track to rise in 2024 German industrial gas demand is on course to be higher this year than in 2023, based on daily data ending at the end of October. Industrial gas use for production processes other than space heating was 746 GWh/d in January-October, about 8pc higher than a year earlier, according to Argus estimates. But if September's industrial output drops extend to a multi-month trend, this would pull down the average for this year as a whole. Industrial demand typically falls in December when the holiday period limits economic activity, which could push down the average further. And the collapsed German governing coalition is unlikely to send strong recovery signals to the German economy. German market area manager THE publishes a combined dataset for gas demand by industry and the power sector. Argus splits out power-sector gas demand data by assuming operational efficiencies of 39-42pc, in line with fuel use data from Destatis, and factors out seasonal demand swings linked to space heating by looking at analogue trends in the residential and commercial sector ( see demand split graph ). Argus' estimates diverge from Destatis' annual demand data by only about 1-3pc, except for a 6pc gap in 2021 ( see Destatis vs Argus estimates graph ). By Till Stehr German manufacturing index index, 2021=100 German industrial gas demand by sector TWh German industry and power demand split GWh/d Destatis data vs Argus estimates GWh/d Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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