Brazil boosts foreign spending in energy transition

Market: Biofuels, Crude oil, Emissions, Natural gas, Oil products
27/02/24

Brazil's climate fund and green transition plan received multi-billion monetary commitments from multilateral agencies during the G20 meetings, as part of government efforts to boost foreign investment in decarbonization.

Brazil estimates that only 6pc of funding for its energy transition projects comes from the private sector, compared with an average of 14pc in other emerging markets and 81pc in developed countries.

The high cost of long-term currency hedge contracts has contributed to the limited participation of foreign investors in Brazil's energy transition, the president of the Inter-American Development Bank (IDB) and former president of Brazil's central bank Ilan Goldfajn said.

To ease the entry of foreign investments, the government launched the Eco Invest Brasil program, which will create currency hedge mechanisms to limit exposure to exchange-rate volatility. Brazil's finance ministry and central bank developed the program with the World Bank and IDB.

The IDB has committed a total of $5.4bn to get the Eco Invest program started, including $3.4bn for currency swaps and $2bn for lines of credit. IDB will also help Brazil prepare and structure projects to receive financing.

The plan seeks to remove obstacles for foreigners to invest in Brazil's energy transition by reducing risks related to the volatility of the Brazilian real, according to the treasury secretary Rogerio Ceron.

As part of the program, the government plans to issue a presidential decree that will create four new lines of credit within the Climate fund.

The goal of the plan is to expand Brazil's integration with the international financial system and boost foreign investment in companies and projects that decarbonize the economy.

Brazil's Bndes development bank also reached an agreement with the Glasgow Financial Alliance for Net Zero (GFANZ) to expand financing for Brazilian decarbonization projects.

IDB will also provide an additional $2bn line of credit and technical support for Brazil's Climate fund, while the World Bank is considering allocating up to $1bn to the fund.

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30/12/24

Viewpoint: Chancay port may increase Peru bunker demand

New York, 30 December (Argus) — The opening of Peru's Chancay port next year likely will boost the country's bunkering demand and drive-up competition on the Latin American Pacific coast. Able to accommodate larger ships and vessels equipped with marine exhaust scrubbers, the unveiling of the new facility — likely in the first quarter — could spur demand for very low-sulphur fuel oil (VLSFO) and high-sulphur fuel oil (HSFO). Chancay, which is owned by Chinese state-owned port operating company Cosco Shipping and Peruvian mining company Volcan, has a 17.8-meter depth, compared with a depth of 16 meters in El Callao part, which is south of Chancay near Lima, Peru. Chancay's depth allows it to receive container ships with a capacity of up to 18,000 twenty-foot equivalent units The larger vessels will likely take on around 3,000-5,000 metric tonnes of marine fuel in one port call, according to one source familiar with the Peruvian bunker market. "The port is gradually beginning to receive container vessels, RoRo, and bulk carriers," said Augusto Ganoza, who heads Chilean bunker supplier Agunsa's operations in Peru. "I anticipate an increase in bunkering demand at Chancay, particularly if vessels call at Callao first and then proceed to Chancay, which I believe will be the case for most." But bunker buying appetite in Chancay also will depend on marine fuel prices in China. El Callao VLSFO was assessed at a $85/t premium to Zhoushan, China, in November. That differential tightened from its peak earlier this year at $143/t in April. That differential could temper the expected increase in bunkering demand in Peru. Other market contacts from outside Peru said that any increase in demand stemming from Chancay's opening is unlikely to drag down activity in competing ports such as Panama, largely because of higher prices in Peru and better quality of bunker fuel available in Panama. The VLSFO November monthly average in El Callao was $656/t, which was an $89/t premium to Panama VLSFO. By Luis Gronda Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Viewpoint: US midcon E15 shift looms again

30/12/24

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30/12/24

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.

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Viewpoint: US fuel oil supply challenge to deepen

30/12/24

News

30/12/24

Viewpoint: US fuel oil supply challenge to deepen

Houston, 30 December (Argus) — US residual fuel oil supplies are dwindling and face multiple challenges in 2025 because of reduced global inventories and a persistent backwardation in the domestic market. Total US inventories of residual fuel oil fell to a historic 42-year-low multiple times during 2024, including nine instances in the fourth quarter alone, according to Energy Information Administration (EIA) data. Supplies hit rock bottom at just under 23mn bl in the week ending 29 November, down by 12pc year-on-year. Despite the shrinking supplies, the US market has shown little reaction. Throughout 2024, ICE Brent futures — the basis for US residual fuel oil — remained in backwardation between the front and second month, averaging $0.60/bl. This is nearly double the full year 2023 backwardation average of $0.39/bl. The persistent backwardation of the fuel oil curve means inventory figures lack the drive to encourage wholesalers and retailers to make purchases in anticipation of future demand, traders said. The diminishing future value results in potential losses for traders who are considering purchasing spot barrels for storage as forward prices are lower than current spot prices. Residual fuel oil is primarily used as a maritime fuel for large ships, a fuel for backup power generation and for various industrial purposes. In the US it is often refined further into other road fuels. The production of US residual fuel oil has been steadily increasing in recent years, beginning even before implementation of the International Maritime Organization's 2020 global rule imposing a 0.5pc sulphur cap on marine fuels. However, output averages over the past four years remain well below pre-2019 levels. Since the US imposed sanctions on Russian fuel exports in February 2023, weekly residual fuel oil imports into the US have averaged just over 100,000 b/d, nearly half of the previous two-year average at 196,000 b/d. Mexico has now become the largest fuel oil exporter to the US, accounting for nearly 33pc of all US fuel oil imports over the past two years, claiming the top spot from Russia. Planned expansion of Mexico's refinery infrastructure may crimp US supplies, however. Mexican state-owned Pemex's 400,000 b/d Dos Bocas refinery — which is still in the start-up process — would take a greater share of Mexico's Maya crude. Maya crude yields a significant portion of fuel oil when refined. This would leave less Maya bound for the US, which has taken nearly 60pc of Mexico's Maya over the past three-years, according to Vortexa data. Pemex is also adding two new coker units to its Tula and Salinas Cuz refineries as part efforts to become more self-reliant and add an additional 168,000 b/d of road fuel output. Coker units process fuel oil to turn it into higher value road fuels, which would curtail flows to the US. Refinery maintenance involving a few US crude distillation units is set to begin in January, which could further limit domestic fuel oil production. The National Weather Service's winter forecast for the east coast is expected to be warmer than usual, likely leading to reduced demand for both high-sulphur fuel oil used in power generation and low-sulphur blending components. By Craig Ross Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Viewpoint: Carbon offsets face bumpy road

30/12/24

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30/12/24

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.

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Viewpoint: European diesel to stay under pressure

30/12/24

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30/12/24

Viewpoint: European diesel to stay under pressure

London, 30 December (Argus) — The European diesel market appears to be in a period of transition defined by economic headwinds, a decline in structural demand and anticipated refinery closures in the new year. These factors are exerting downward pressure on diesel refining margins, with the IEA forecasting no return to the high margin environment experienced immediately after the Covid-19 pandemic. Margins in Europe have been trending downwards in 2024 to below $17/bl, lower by a third from $28.53/bl in 2023 and less than half the heady levels of $37.27/bl in 2022. The economic rebound experienced in the immediate aftermath of the pandemic bequeathed a high inflationary environment, and this became a significant headwind in Europe going into 2024. Central banks tightened monetary policy to counteract this, dampening economic activity and as a consequence demand for diesel, the primary fuel grade powering transport fleets, construction equipment and manufacturing. European demand has been notably lacklustre. The largest economies in the region, Germany and France, saw diesel consumption decline by 4pc and 3pc respectively in 2024, according to the most recent published data. The former's loss of cheap Russian gas has undermined its economic model, which appears to have had a structural effect on national diesel demand. Any improvement in European economic fortunes in 2025 will likely provide a tailwind for outright diesel values. Driving issues Europe is also experiencing a systemic decline in diesel vehicle usage as electric and hybrid vehicles take up an ever increasing share. Newly-registered diesel passenger vehicles made up 14.9pc of the German market and 6.1pc of the UK market in November, according to SMMT and KBA data, compared with 31.6pc and 45.8pc for pure gasoline vehicles. New hybrid vehicles claimed a 38.7pc market share in Germany. Delays to outright national bans on new diesel or gasoline vehicle sales may stem the decline in popularity for diesel vehicles, but the trend is unlikely to be reversed. European refinery closures could serve to rebalance the market next year. Petroineos' 150,000 b/d Grangemouth refinery in Scotland will become an import terminal. In Germany, Shell will cease crude processing at its 147,000 b/d Wesseling refinery and BP plans to permanently shut down a crude unit and a middle distillate desulphurisation unit at its 257,000 b/d Gelsenkirchen plant. The degree to which these capacity losses are baked into market pricing is debatable, as the refiners could decide to delay closures in the event that diesel margins recover. But the limited effect of recent unscheduled refinery outages in the Mediterranean region illustrates how Europe can bear to lose two crude units, at least in the short term. In 2025, European diesel prices may again take direction from developments outside the region, particularly the profitability of key arbitrage routes from the US Gulf coast, the Mideast Gulf and India. European diesel values and margins were affected by refinery turnarounds in supplier regions in 2024. Prices may come under further pressure in 2025 from the start of 10ppm diesel production this month at Nigeria's 650,000 b/d Dangote refinery, which could completely offset the loss in European refining capacity. Any easing in Yemen-based Houthi militant aggression in the Red Sea may encourage diesel cargoes back through the Suez Canal, cutting down delivery times and weighing on supply volatility. Price-supportive developments may come from the EU tightening sanctions on Russia's 'dark fleet', which could weigh on global supply, and an upcoming US refinery maintenance season that is is touted to be disruptive. Two US refineries will close in 2025. By George Maher-Bonnett Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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