Brazil, Germany in talks for hydrogen pilot project

: Biofuels, Emissions, Hydrogen
20/10/22

Brazil is in talks with Germany for a pilot project to produce green hydrogen from its abundant renewable energy sources, but it must first overcome logistical bottlenecks, industry specialists said in a recent webinar co-hosted by the Brazilian government and Germany's Konrad Adenauer Foundation (KAS).

Brazil already has one of the world's cleanest energy mixes, with both a strong biofuels industry and a heavily renewable power generation matrix. But the country has yet to tap into its renewable energy base to produce green hydrogen.

Small steps are underway. Brazil began holding public hearings in July to define a regulatory framework for hydrogen fuel. And the government included green hydrogen in its long-term energy plan for 2050, which is expected to unlock potential financing.

"Brazil still does not have public policies for green hydrogen. Currently, this is still not a big problem," said Lavinia Hollanda, the executive director of Escopo Energia. "But in the near future, we need to develop a long-term plan so we have the infrastructure in place when it is needed."

According to estimates by the hydrogen research laboratory at the Rio de Janeiro federal university, green hydrogen has the potential to account for 8pc of Brazil's total energy consumption by 2050.

Brazil also has potential to be a green hydrogen exporter in the medium term. Details of the talks that Brazil's mines and energy ministry is holding with its German counterpart for the pilot project are still sketchy, but the objective would be to export the new fuel to Europe. The EU recently unveiled plans to build 40GW of hydrogen electrolyzing capacity by 2030, leaving the door open for Brazil to supply the trade bloc, said Giovani Machado, director of energy economics and environmental studies at the energy ministry.

Green hydrogen is produced using biomass, biofuels such as ethanol or biogas as feedstock. Domestically, hydrogen is well suited as a liquid fuel to power batteries that could be used in electric long-haul trucking and aircraft equipped for such technologies, two areas of demand that are largely limited to liquid fuels such as diesel or natural gas at present, according to Hubertus Bardt, an economist at the German Economic Institute.

"Development of the technology over the next decade could be remarkable, especially with the strong demand from heavy vehicles, such as city bus systems, which would allow a more centralized distribution infrastructure for the hydrogen fuel," thus reducing costs, according to Paulo Emilio de Miranda, the head of the hydrogen research laboratory.

"We need shipping capacity that does not exist today with new technology to store and carry hydrogen, as well as pipeline and storage facilities. It will mean big investments," Machado said, adding that there are no current technologies in place to transport and store liquid hydrogen via pipelines or shipping, which would require policies to lead major infrastructure investment.

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24/12/30

Viewpoint: Bearish year ahead for NOx markets

Houston, 30 December (Argus) — The Cross-State Air Pollution Rule (CSAPR) NOx allowance markets will likely face a bearish year in 2025, as the incoming administration of president-elect Donald Trump creates uncertainty over the fate of the latest federal regulation to curb emissions. The US Supreme Court halted implementation of the US Environmental Protection Agency's (EPA) "good neighbor" plan in June with a nationwide stay. This left an already stunted regulation to cut NOx emissions, a precursor to harmful ground-level ozone, obsolete for the foreseeable future. EPA finalized a plan in March 2023 to help downwind states meet the 2015 national air quality standards by setting tighter ozone season NOx caps on power plants covered by CSPAR as well as new limits for industrial facilities in more than 20 upwind states. But by the time the justices issued the stay, the number of covered states had already shrunk by more than half because of lower-court orders pausing implementation in 12 states. Prices for seasonal NOx allowances have flatlined and the market has been illiquid over much of 2024 because of uncertainty over how numerous legal challenges against the good neighbor plan would play out. Argus has assessed Group 2 allowances at $775/short ton (st) and Group 3 allowances at a record low $1,250/st since January. This could change, albeit at a slow pace, because EPA finalized an interim rule in November to comply with the nationwide stay. Power plants that had been covered by the good neighbor plan are now under less-stringent NOx budgets tied to older air quality standards, and the 10 states that had been participating in the Group 3 market prior to the stay are now reshuffled into Group 2 and a separate 12-state "expanded" Group 2 market. All that remains is… uncertainty In the new year, the market will wait to see how the Trump administration will deal with the good neighbor plan and the associated legal challenges in the US Court of Appeals for the DC Circuit and the US Supreme Court. Because of the stay, there is no hurry for the new administration to address the legal woes, and it is unlikely the DC Circuit will soon rule on the legality of EPA's rejection of state ozone reduction plans. The Trump EPA, following precedent of prior administrations, will likely ask the court to pause litigation until it decides whether to continue defending the plan, according to Jeff Holmstead, assistant administrator at the agency under former president George W Bush. The agency will likely revoke the plan at some point and replace it with a rule that is more "modest" and would not significantly affect allowance prices, he said. The EPA under Trump could ultimately decide that upwind states do not significantly contribute to interstate pollution, reversing a determination that has underpinned the good neighbor plan. That could lead to downwind states asking the agency to address specific sources that contribute to their air quality problems, said Carrie Jenks, executive director of Harvard Law School's Environmental and Energy Law Program. The Supreme Court is also hearing a case to decide the proper court venue for Clean Air Act disputes, which involves the good neighbor plan. The Trump administration likely will agree with various states and industry groups that say EPA's rejections of individual state plans are not a "nationally applicable" action and must be litigated in the regional circuit courts, but the Supreme Court is likely to continue the venue case, Jenks said. Oral arguments will likely be held early next year. It is also unclear how Lee Zeldin, Trump's pick to lead EPA will affect the regulation. Zeldin is a moderate, given his history, and will likely "not want to impose significant new burdens on fossil fuel power plants", Holmstead said. Trump's plans to downsize the federal bureaucracy could also affect future rulemakings, according to Jenks. "Nobody really knows what's going to happen," she said. As a result, market activity is likely to remain limited in the coming months as participants await legal and regulatory clarity. In addition, markets are likely to be oversupplied now that power plants are under lighter NOx caps. Most states in the seasonal NOx markets were well below their limits for the 2024 ozone season, despite a 9.2pc increase in cumulative emissions in the expanded Group 2. EPA will also allow some power plants to convert vintage 2021-23 Group 3 allowances to Group 2 or expanded Group 2 allowances, adding to supply. With low demand and a potential oversupply, seasonal NOx allowances could see prices fall . By Ida Balakrishna Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US midcon E15 shift looms again

24/12/30

Viewpoint: US midcon E15 shift looms again

Houston, 30 December (Argus) — A potential reformulation of gasoline in eight midcontinent states to accommodate year-round 15pc ethanol gasoline (E15) could lead to shortages in midcontinent fuel supply and an increase in retail prices in 2025. Approaching the 2025 summer driving season, Illinois, Iowa, Minnesota, Nebraska, Ohio, South Dakota, Wisconsin and, now, Missouri once again await the US Environmental Protection Agency's (EPA) enforcement of compliance on their exclusion from the 1-psi rule. The one-pound waiver in the Clean Air Act allows for a 1 psi higher Reid Vapor Pressure (RVP), a more expensive specification for 9-10pc ethanol blend that allows gasoline during the summer to be 9 RVP. Opting out would lead to the production of two separate grades of gasoline, the standard summer 9 RVP CBOB and a new, non-waiver 7.80 RVP CBOB that could be blended into E15. Many of the refiners and pipelines in the region would serve states that have opted out of the waiver, and states that will remain within the waiver and the lack of uniformity in specifications across the midcontinent would likely cause difficulty in logistics for refiners and pipeline operators. This new 7.80 RVP gasoline formulation would be a boutique grade CBOB that would only be found in the midcontinent during the summer, adding to the difficulty of producing the grade. The differences between the waiver and the non-waiver grades of gasoline would be mostly contained to the summer driving season, according to participants in the US midcontinent gasoline market. American Fuel and Petrochemical Manufacturers (AFPM), a trade association for fuel makers, again petitioned the EPA to delay the midcontinent governors' request until 2026. AFPM cited a new study by US consultancy Baker and O'Brien that forecast a 131,000 b/d decrease in CBOB production if the midcontinent states were to opt out of the waiver. This would be the equivalent of a sustained refinery outage in the region and could lead to supply-cost increases of 9-12¢/USG, up from an estimated 8-12¢/USG a year earlier. Baker and O'Brien's study also indicated that supply costs could be between $700mn and $1.2bn, with the lower end using the 185 days of the summer driving season with no disruptions and the upper end of the range assuming at least a two-week regional supply shortage. The study also said that a delay until 2026 would allow for more time to implement the capital investments needed to fully accommodate the change to non-waiver gasoline in some of the states but noted that many of the improvements needed would take two years to complete. Many refiners and pipeline operators are hesitant to invest when a legislative solution could make the changes unnecessary. US Gulf coast supply lines The US midcontinent relies on the US Gulf coast to provide resupply in the event of a refinery outage in the region or to accommodate increasing demand. The Explorer Pipeline which connects from the US Gulf coast to the US midcontinent is one of the major pipelines to deliver product into the region. Transit time on the pipeline for delivery to the Chicago area is roughly two weeks. The US midcontinent in 2021-2024 averaged receipts of 1.16mn bl/month of finished gasoline during the May-September summer driving season, according to US Energy Information Administration data. The arbitrage for shipping CBOB into the US midcontinent from the US Gulf coast is already on average open across the summer. A change in formulations would likely increase the need for product. Southern US midcontinent CBOB averaged an 8.33¢/USG premium to US Gulf coast product during the summer, over the Explorer's 7.14¢/USG tariff for shipping product from Pasadena, Texas, to Tulsa, Oklahoma. Chicago's Buckeye Complex CBOB averaged a 10.10¢/USG premium to its Gulf coast counterpart, also over the 8.40¢/USG tariff for shipping. History of delays The governors of Iowa, Nebraska, Illinois, Minnesota, Wisconsin, Illinois, Kansas, South Dakota and North Dakota in 2022 requested an exclusion from the 1-pound waiver in the Clean Air Act by claiming the waiver was contributing to air pollution in those states, a request that would require blendstocks for E10 and E15 sold in those states to be reformulated. The EPA granted their request in February 2024, but delayed lifting the waiver for summer 2024, following a slew of petitions from trade associations, refiners and pipeline companies asking for delays. The measure is still pending. President Joe Biden's administration avoided a potential disruption to seasonal E15 sales by tapping emergency powers in April 2022 to allow for the sale of E15 during the approaching summer, citing supply disruptions in the wake of Russia's invasion of Ukraine. EPA issued similar emergency waivers ahead of summer in 2023 and 2024 to facilitate the sale of E15, using the waiver 9 RVP gasoline. The US Congress is considering legislation options to avoid requirements to reformulate gasoline. A stopgap government funding bill that would fund the government through March included language to extend the one-pound waiver to E15 year-round and make the shift by the eight midcontinent states and the attached reformulation unnecessary. But the E15 provision was pulled from the stopgap funding bill following criticisms from President-elect Donald Trump and Telsa chief executive Elon Musk . By Zach Appel Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Carbon offsets face bumpy road

24/12/30

Viewpoint: Carbon offsets face bumpy road

Houston, 30 December (Argus) — Carbon offset credits from California's cap-and-trade program will meet reduced compliance demand next year, while program updates promise to upend market dynamics. Each carbon offset under the joint California-Quebec carbon market, known as the Western Climate Initiative (WCI) equals 1 metric tonne of greenhouse gas (GHG) emissions from sources not covered by either cap-and-trade program. California and Quebec allow covered entities to use offsets from either program to meet their annual GHG emissions obligations. But market regulators are eyeing changes for carbon offsets in Quebec that may have wider impacts. Quebec is considering phasing out carbon offsets by 2030 as part of an ongoing rulemaking for a more-stringent program. While the province has not shared its final approach, regulators have floated in workshops either limiting offset use to 4pc of overall obligations for 2027-29 or putting offsets under the program's emissions cap. Quebec's Environment Ministry allows for covered entities to utilize carbon offsets for up to 8pc of outstanding emissions, including from California. Meanwhile, the California Air Resources Board (CARB) allows for covered entities to use CCOs for 4pc of obligations through 2025 and for 6pc starting in 2026, though at least half must come from projects that provide direct environmental benefits to the state (DEBs). After 2031, Quebec is mulling transitioning to a government carbon offset purchase-and-retire system, but it remains unclear how that might function — and what it means for the longevity of carbon offset projects in Quebec, said Joey Hoekstra, a policy associate with International Emissions Trading Association (IETA). "That mechanism and how that is going to look like and what that will be, there has not been a lot of details," he said. Quebec plans to finalize its program changes early in 2025 , with implementation in the spring. The move away from carbon offsets has implications for California's program, ClimeCo chief operating officer Derek Six said. "Quebec is an outlet for the non-DEBs credits in California," Six said. The province issues very few carbon offsets under its own protocols, just under 1.8mn since 2014, according to provincial data published in November. California, which allows for projects to generate credits in and outside the state, issued nearly 13.8mn CCOs in 2023 alone, with just under 9.6mn from non-DEBs projects. The CCOs without DEBs are an oversupplied market, said Six, compared with the limited number of projects that generate the more expensive DEBs credits in California. Argus last assessed California Carbon Offsets (CCOs) seller-guaranteed offsets at $14.60/t, CCOs with a three-year invalidation at $14/t and CCOs with an eight-year invalidation at $13.90/t on 20 December. CCOs with direct environmental benefits to the state (DEBS) currently trade at an $15.50/t premium to non-DEBs CCOs. In issuances over the past five years, non-DEBs have formed the bulk of credits distributed by CARB, with DEBS-eligible credits only going as high as 42.3pc of total issuances this year. Covered emitters in Quebec used 13.2mn non-DEBs CCOs to meet their 2021-2023 compliance obligations, along with roughly 75,000 CCOs with DEBS. Provincial entities used just under 366,400 carbon offsets generated in Quebec for compliance. California emitters utilized 13.2mn non-DEBs CCOs and nearly 13mn DEBs CCOs for their 2021-2023 compliance. Washington, which hopes to link its cap-and-trade program with the WCI as early as 2026, is unlikely to stopgap the shortfall in demand for non-DEBs credits once it allows outside credits, instead feeding further demand for DEBS CCOs. The state allows participants to use carbon offsets for 5pc of its emissions and a further 3pc from projects on federally recognized tribal lands over 2024-2026, reduced to 4pc and 2pc, respectively, for 2027-2049. The state's ongoing linkage rulemaking would allow the participants to use offsets from within a linked jurisdiction, which will include CCOs with DEBs and Quebec offsets. Washington's cap-and-invest, which started in 2023, has generated few offsets of its own so far — just over 310,000t, all from ODS projects. But that may change in the short term, Six said. Project developers have likely been holding off over this year until voters rejected an effort to repeal the state's program in November. "I would not be surprised if you all of a sudden see a bit of a flood of project listings from people who had Washington ODS material," he said. Washington is also conducting a rulemaking to increase the variety of projects resulting in carbon offsets credits. Ecology plans to implement these changes in summer 2025. But carbon offsets remain unlikely to be much of a cost-saving measure for compliance in Washington, Six said. Washington, unlike California or Quebec, puts them under its annual emissions cap and removes allowances in line with offset use. By Denise Cathey Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Consolidation looms in US methanol

24/12/27

Viewpoint: Consolidation looms in US methanol

Houston, 27 December (Argus) — The sale of Netherlands-based OCI's methanol production assets to rival producer Methanex is set to shift the market, with US methanol production most affected by the move. Methanex in the third quarter of 2024 announced the $2bn acquisition, which is expected to close in the first half of 2025. The boards of directors of both companies and OCI's shareholders approved the transaction, but it is subject to regulatory approvals. OCI operates the 1mn t/yr OCI Beaumont plant and is a 50:50 partner in Natgasoline, a 1.7mn t/yr joint-venture plant between OCI and Proman. Methanex operates three plants in the US, all in Geismar, Louisiana. These plants carry a collective 4mn t/yr capacity and represent one-third of total US methanol capacity. At front and center of the acquisition is the Natgasoline plant in Beaumont. Natgasoline, when operational, represents 14pc of domestic production. The plant opened in 2018, and throughout those six years, the plant has seen its share of operational issues. The most recent was a fire at the reformer unit in early October, resulting in a complete shutdown lasting nearly three months. When the deal was announced, Methanex made it clear that the transaction was subject to approvals by OCI shareholders, as well as a pending legal decision between OCI and Proman. "If it is not settled within a certain period, Methanex has the option to carve out the purchase of the Natgasoline joint venture and close only on the remainder of the transaction," the company said in September. Methanex and OCI declined to give further details, as the deal is still pending. Proman did not respond to a request for comment. If it goes through, the acquisition would result in the exodus of OCI from the US methanol market. But the issue of liquidity in the US spot barge market is also looming. Market participants said OCI is a frequent buyer when the Natgasoline plant goes down. In October, when Natgasoline was completely shut down, 340,000 bl of methanol moved for delivery at ITC, the terminal on the Houston Ship Channel where methanol is exchanged, according to Argus data. Market participants expect liquidity to be about the same until some time after the deal closes. When a plant goes down, a producer will emerge in the spot market for purchases. In the longer term, there are some questions around international distribution and where US methanol exports find a home. Methanex is a major exporter to Asia, whereas OCI sells into the European market. The low-carbon methanol sector will also experience some shakeup. OCI is a major participant in the bio-methanol space, selling volume into Europe. Methanex produces carbon-captured methanol, also known as blue methanol, which has not penetrated the EU market. By Steven McGinn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: California-Quebec carbon faces murky 2025

24/12/27

Viewpoint: California-Quebec carbon faces murky 2025

Houston, 27 December (Argus) — The joint California-Quebec climate market, known as the Western Climate Initiative (WCI), is on tenterhooks going into 2025, stymied by rulemaking delays but on the cusp of a more mature phase. Both California and Quebec are eyeing more-stringent future programs and have floated a series of changes over the past year and a half designed to achieve those goals. The California Air Resources Board (CARB) is considering moving its program's mandate from the present 2030 target of a 40pc reduction in greenhouse gas (GHG) emissions, compared with 1990 levels, to a 48pc reduction to keep the state on target to meet its 2045 goal of net-zero emissions. In line with this increased ambition, CARB will need to remove at least 180mn metric tonnes (t) of allowances from the 2026-2030 auction and allocation annual budgets to start with, and up to 265mn t in total from the program budgets from 2026-2045. CARB has floated other changes , including toughening corporate relationship disclosure requirements, increasing the program's cost-containment allowance price tiers and updating a portion of the program's carbon offset protocols. Quebec has considered removing 17.5mn t of allowances, which correspond to carbon offset uses for compliance in the province over 2013-2020. The Quebec Environmental Ministry proposed to address this by removing these allowances from the province's 2025-2030 auction budgets in a November 2023 workshop. Quebec is also mulling changing the current three-year compliance period to align with statutory 2030 and 2050 GHG targets. But this a move that California, which had discussed similar compliance period changes in April , has not revisited since. Quebec is considering tapering the limit for carbon offset use for compliance in the province by 2030 and transitioning over to a provincial reduction purchase mechanism in 2031, although regulators have not gone in-depth on how a replacement system would function. The WCI rulemakings have been marked by a series of delays over this year, pushing past projections from the end of last year that it would finalize program changes by the second half of 2024. Quebec, which was set to deliver a draft of program amendments in September, rescheduled to early 2025, with implementation expected in spring 2025. While the regulation was nearly complete in late September, the Quebec Environmental Ministry chose to postpone, since it cannot publish before California, said Jean-Yves Benoit, the agency's director general of carbon regulation and emissions data. CARB has signaled it intends to publish its package of rulemaking amendments in early 2025. The agency on 19 December confirmed it expects to "complete and release the regulatory package for a 45-day public comment period" in early 2025 but did not explain the delay. The agency may be waiting for a formal extension of the cap-and-trade program when the legislature resumes on 6 January. California lawmakers have given CARB explicit authority to utilize a cap-and-trade system to reduce GHG emissions out to 2030. CARB maintains it has authority to operate a cap-and-trade program past 2030, but program participants have stressed the need for formal certainty around the program to aid future planning. CARB will begin invoking the post-2030 budgets starting in 2028 for the program's advance auctions. The various delays have compressed the timelines California and Quebec must achieve their statutory target ambitions, making 2025 a potentially pivotal year. By Denise Cathey Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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