As the lizards of Transylvania roam its incomparably beautiful grasslands, they are blissfully unaware that a lot of money and human hopes rest on their thin little shoulders. They also do not know that their homes are in grave danger.

Lizards have quite the life in Târnava Mare, in the southeast corner of the region, thanks to its incredible biodiversity spread over endless vistas of meadows, gentle hills and forests.

Their grassland habitats are in danger because of changing land use, the same principal cause of global biodiversity loss. The land is very fertile, making it ideal for big agricultural companies to buy at a time when farmers in the region are aging and their incomes are in the low thousands of euros.

Târnava Mare is consequently under pressure, losing more than 5% of its grasslands to arable farming in just the last few years, says local charity Adept, with satellite images suggesting that 25% of the entirety of the nearby Hârtibaciu basin, more easily accessible by road, has already been turned over to arable farming. It all portends disaster for the area’s biodiversity.

Saving Transylvania’s Grasslands with Biodiversity Credits

Georgiana Păun, a 30-year-old Romanian herpetologist and lizard expert, demonstrated her ability to spot and record more than 60 of the creatures during an OPIS site visit last summer. “I am a lizard,” she explained. This put her at the forefront of a bold new project that aims to measure the biodiversity of the grasslands, preserve them and then create voluntary biodiversity credits. Those credits might then be sold on by an investor willing to fund the initial conservation work.

Developed by Adept and British ecological restoration company rePLANET, the Târnava Mare project is one of the first biodiversity credit projects to use an “uplift” methodology that can in theory be applied to ecosystems around the world requiring restoration or preservation.

The methodology works by cataloguing the abundance of several “indicator species groups” that reflect the wider biodiversity of an area.

In the case of nature restoration projects using the methodology, voluntary biodiversity credits are then issued once an intervention to boost nature has resulted in a measured increase in the median abundance of those indicator species groups, with measurements of uplift taking place at a maximum of five-year intervals.

One biodiversity credit represents a 1% uplift in the median abundance of the indicator species in a hectare of a project. “Additionality” is baked into credit issuance: if there is no measured uplift in median species abundance in the wake of an intervention, no credits are generated.

In the case of “avoided loss” biodiversity credit projects such as Târnava Mare, the baseline is created by measuring biodiversity in areas that have already been ploughed, with very harmful effects for the indicator species.

The difference between the biodiversity found in those baseline reference sites and the biodiversity measured every five years in the conserved grasslands then forms the basis of biodiversity credit issuance over the 40-year lifetime of the project. If biodiversity measurements take place every five years and show that the project area’s biodiversity is being conserved, credits will be issued in five-year increments.

The methodology’s proponents say that the 1% uplift per hectare methodology creates a unit of quantification that is comparable to the metric ton of carbon that is used to generate carbon credits and allowances.

From Conference Hype to Hard Yards

In the year and a half since COP15 negotiations between 190 nations brokering the Global Biodiversity Framework in Montreal, there have been dozens of typically well-attended conferences about biodiversity credits. Such summits have been more numerous than projects actually capable of generating voluntary biodiversity credits.

That is beginning to change, and the Târnava Mare scheme, the most advanced of the rePLANET-affiliated projects, has now completed its base-lining work, which has been submitted for verification to the Biodiversity Futures Initiative, a non-profit peer reviewer employing academics.

The level of effort involved in collecting that indicator species data becomes quickly apparent during the OPIS site visit to the 2,219-hectare project area in Târnava Mare, as does the gulf in biodiversity between the conserved and razed grasslands.

Several Romanian and British ecologists, in addition to a Romanian support team recruited by Adept and rePLANET, spent two months in the summer of 2023 in Angofa, a wildlife center housed in a small former 19th century village schoolhouse a few miles from the castle town of Sighișoara, a potential birthplace of Vlad the Impaler, the inspiration for Dracula.

The data collection was overseen by 34-year-old Dr. Max Bodmer, a coral reef expert and former teacher, who verified Păun’s lizard observations over several hours of trekking in the heat between different sites.

Biodiversity and Beauty in Transylvania

Târnava Mare’s ability to beguile lies in the contrasts it serves up with every bend of the road. “Welcome to hobbit land,” says Păun as the car passes soft-sloping green hills that crest into the far distance to the left, while mighty oaks, some of Europe’s oldest, loom to the right. But the car turns a corner, and the hills suddenly give way to cloud-capped mountains, which soar above one of the region’s fifteen valleys carpeted with thick forest.

The beauty and biodiversity contained in Transylvania and its threatened grasslands have attracted visitors, writers and royalty through the ages. During a late-afternoon break from lizard spotting, Bodmer’s mud-caked car is passed by King Charles III as he exits a 12th century fortified church in the village of Viscri. Britain’s Transylvania-loving king has a home in the village and has previously lauded the region’s “priceless biodiversity [and] remarkable examples of sustainable farming.”

Nat Page, a former British diplomat and the director of Adept, employed ecologists in 2009 to measure the biodiversity of the Târnava Mare grasslands, and their study showed some of the highest concentrations of plant species ever recorded, with 45 species identified in a 0.1 square meter space.

“It really is incredible when you’re walking through the grasslands in the Târnava Mare. With every step you take, you’re seeing something new,” says Bodmer, who hopes that the project can serve as a template for restoring biodiversity in his native Britain. “It really can be used as a model for what a European grassland and what a European agricultural landscape could look like if we start to manage land more effectively and with more care for biodiversity in the natural environment,” he argues.

It is a shock, then, when Păun and Bodmer finally reach one of the sites that appeared to be home to pristine grassland, only to find that it has been ploughed up in the two days between being observed via satellite images and the pair’s arrival at the site.

Gone are the all-you-can-eat grasshopper food bars, the butterflies of every hue and the hares jumping out of the grass, with the lizards hit the hardest. The data collected by Păun show that lizard sightings in the conserved grasslands are more than 20 times higher than in the ploughed areas, some of which are not being actively managed but are already in the process of being converted for arable farming.

Boosting Farmer Incomes Key to Saving Biodiversity

Preserving a large part of the grasslands in the medium-to-long-term will depend on finding cold, hard cash to combat the lure of big agrifood money and the region’s stark demographic challenges.

Large parts of Romania have all the trappings of modern European life, but high in the Transylvanian hills, a few villagers still travel by horse and cart along often decrepit roads in half-abandoned villages.

If a corporate buyer of the project’s biodiversity and carbon credits can be attracted, a viable future in farming is still possible, say rePLANET and Adept. The all-in costs for the 40-year-long project come to $17,560,000, with the estimated biodiversity credits slightly more numerous than carbon credits (the exact prices are featured in the OPIS Biodiversity Market Report, published for the first time this month).

Around 115 small-scale farmers would receive direct payments representing 60% of the project’s funds if they pledge to maintain and boost traditional biodiversity-friendly farming practices, greatly improving their livelihoods. Under current arrangements, according to rePLANET’s calculations, a farmer owning five cows, 15 sheep, nine hectares of hay meadow and 12 hectares of pasture can expect a net annual income of €3,150 ($3,400), which includes recently reduced EU Common Agricultural Policy payments.

Funding from the credits would boost net income to €5,800. Furthermore, if the credits were resold by the project backer, 60% of any profit would go back to the project participants. The biodiversity-carbon credit project would consequently tilt the balance in favor of preserving the all-important traditional farming practices, say rePLANET and Adept.

The latter has discussed the proposal with local community mayors, but the early-stage nature of the project means that the developers do not want to get farmers’ hopes up before a backer is found.

A lot is riding on whether the project receives funding and biodiversity crediting takes off, says Adept’s Page. The former diplomat is critical of how Romanian government payments are being reduced at the same time as payment schemes’ requirements are changing.

“The ability of farmers to access payments is going to fall massively,” says Page. “In 2024, there is no longer a high nature value scheme. It is a massive threat to the area. … New conditions are being attached which would forbid farmers from receiving money unless they leave their land alone until August 1 every year.” That stipulation is at odds with traditional mowing practices, which have taken place at different times of the year, contributing to the region’s biodiversity over centuries.

“The biodiversity and carbon credit proposal is coming at a key moment,” he suggests. “If we can offer sensible, ecologically-literate payment and inspection, rather than bureaucratic Bucharest-based payment and inspection … it’s better than state payments. The power of corporate money to influence the area is even greater.”

Conclusion: Pressure Growing for Corporate Action

The natural world is melting into thin air at a greater rate than human history has ever known. Accounting firm Deloitte warned last month of “a catastrophic future if this depletion persists.” Its report focused on nature-related risks for the U.S. banking system running into the trillions of dollars, and it is indeed the global banking system that is a focus of the Taskforce on Nature-Related Financial Disclosures that was published in 2023.

The market-led, government-supported TNFD is shaping up to be a key driver of corporate action to stem biodiversity loss. A total of 320 early adopters, mainly banks and asset managers, have agreed to use the TNFD framework to assess and disclose the impact of their investments and lending on the natural world.

Such impact assessments and biodiversity footprinting must take place first before companies can undertake actions potentially enabling them to make “nature positive” claims. Voluntary biodiversity credits could offer companies a means to quantify their positive impacts on biodiversity after offsetting the direct impact of their operations on nature.

But a lot must happen to reach that point, including a broader acceptance that “pricing the priceless” and putting a value on nature restoration is necessary and achievable, even as other means to stop nature loss such as legislation and ending nature-harming subsidies are also pursued by governments.

There will also be a time lag between nature restoration project developers undertaking their interventions and actually generating the biodiversity uplift that allows credits to be issued.

It remains to be seen whether a sufficient number of big businesses can be chivvied into making “nature positive” commitments that they then buy voluntary biodiversity credits. Dorothée Herr, then a senior associate at NatureFinance, suggested last year that scaling up biodiversity markets might require “policy-induced demand.”

As the Târnava Mare grasslands project shows, threats are lapping at the edges of even the most widely recognized homes of pristine biodiversity. Credit methodologies to put a rope around them and restore nature to barren ground now exist, as do the ecologists willing to get the projects started.

Plastic. It’s ubiquitous in our lives, from food packaging to medical equipment. However, its convenience comes at an environmental cost: plastic pollution is threatening our oceans and ecosystems. This month, representatives from nearly 200 countries convene in Ottawa, Canada, for a critical moment – negotiations on a global treaty aimed at curbing plastic pollution by the end of 2024. One of the most contentious issues on the table? Plastic production cuts. Let’s explore the key points of this debate.

The Plastic Pollution Challenge

A 2022 report by the Organization for Economic Co-operation and Development (OECD) revealed a concerning trend: plastic waste volume has more than doubled since 2000, with only 9% being recycled. The situation is projected to worsen, with plastic waste expected to reach a staggering 1 billion metric tons by 2060. Our oceans are particularly impacted, accumulating millions of tons of plastic annually. Microplastics, tiny plastic fragments, have been detected everywhere from the deepest trenches to human bodies, raising concerns about potential health risks.

The Push for Production Cuts

Environmental groups and a growing number of governments advocate for significant reductions in plastic production. They argue that this is essential to stem the tide of plastic waste overflowing landfills and polluting our natural world. A recent Greenpeace survey supports this view, with 82% of respondents worldwide backing production cuts as a means to tackle plastic pollution.

Industry Concerns

The plastics industry is strongly opposed to production cuts. They argue that such measures would stifle innovation in developing new, more sustainable plastics. Additionally, they raise concerns about the potential impact on developing nations that rely heavily on plastic packaging for essential goods.

The Plastics Industry Association, a Washington-based group representing the US plastics supply chain, issued a statement advocating for a “circular economy” where even controlled plastic waste is valued for its potential uses. They believe a focus on circularity would be more successful than production limitations.

Chemical Market Analytics by OPIS echoed this sentiment, highlighting a recent letter from the American Chemistry Council to President Biden outlining the need for a successful global plastics agreement that prioritizes circularity while acknowledging the benefits of plastics in achieving a lower-carbon future.

Potential Consequences of Production Cuts

Industry representatives warn that drastic production cuts could have unintended consequences. Nick Vafiadis, vice president of global plastics, at Chemical Market Analytics, expressed concern that such cuts would disproportionately impact developing nations struggling to provide adequate quantities of safe food, water, and critical medical supplies, as plastic packaging offers a cost-effective way to reduce spoilage.

“Draconian cuts to plastic production would have significant unintended adverse consequences to people all over the world. The impact would be most harsh on developing nations struggling to provide adequate quantities of safe food, water, and critical medical supplies to their population as plastic packaging provides a low cost and highly effective method of reducing food spoilage. Those least able to afford the increased costs of essential products produced with alternative materials would suffer most.”

However, Vafiadis also acknowledged positive developments within the industry. Plastics production in Canada is being adjusted to minimize environmental impact, and Dow’s recent announcement of a net-zero carbon emission ethylene and polyethylene production facility in Canada is a promising step.

Finding Common Ground

The debate over production cuts is likely to be heated, but there’s a growing recognition of the need for collaboration. A successful global treaty will likely require a multi-pronged approach:

A Turning Point for Plastic?

The upcoming negotiations in Ottawa represent a critical juncture. The outcome will determine the future of plastics. Can the industry adapt and embrace sustainable practices? Can a global agreement be reached that protects the environment without crippling essential industries? The next few months will be telling. One thing is certain: the way we produce, use, and dispose of plastics is on the cusp of a major transformation.

Germany’s approach to achieving climate neutrality by 2045 includes various strategies to mitigate climate impact, but the country’s ambitious move towards hydrogen mobility stands out.

The recent update to Germany’s National Hydrogen Strategy (NHS) lays a framework for integrating hydrogen technology across various modes of transport, including road, air and sea. This multi-faceted approach aims to significantly reduce the transport sector’s carbon footprint, leveraging hydrogen’s potential as a clean energy carrier.

Camila Tubella, green hydrogen project developer at Pacifico Energy Partners, said at a recent webinar: “In Germany, there is a lot of readiness to use hydrogen in mobility.”

One of the central components of Germany’s hydrogen mobility strategy is the development of a nationwide hydrogen refueling infrastructure, an initiative many other European countries are wary of as hydrogen’s low volumetric energy density puts it at a disadvantage to diesel. In the UK, energy major Shell opened three hydrogen filling stations between 2017 and 2019, but by 2022 the company had taken a decision to close them all down.

This German hydrogen endeavor is supported by the long-standing National Innovation Programme for Hydrogen and Fuel Cell Technology (NIP), an early adopter of hydrogen mobility in the continent, which started off with a sizeable budget of €1.4 billion ($1.5 billion). The National Organisation for Hydrogen and Fuel Cell Technology (NOW) runs this ambitious scheme.

HySteelStore, one such project funded by the NIP, aims to solve the difficult integration of a hydrogen tank into a passenger vehicle. Heavy trucks are more suited to being fitted with a hydrogen tank.

The HySteelStore project’s modular steel tank system, designed for integration into future battery electric vehicle (BEV) platforms with underbody battery modules, aims to offer better geometric flexibility, cost-effectiveness, and sustainability compared to Carbon Fiber Reinforced Polymer (CFRP) tanks. This is an example of an innovation that could make a difference in passenger vehicle hydrogen mobility.

Moreover, Germany is making investments in the overall innovation and development of hydrogen technologies. The establishment of the German National Hydrogen Council (Nationaler Wasserstoffrat) early on is a testament to the country’s dedication to supporting research and innovation in the field, much needed in the nascent development of hydrogen fuel cells.

However, transitioning to hydrogen-powered transport is riddled with challenges, including the high initial costs of hydrogen technology and security of green hydrogen supply.

Recent difficulties also included the sacking of a key government official in February in the wake of a nepotism scandal. Consequently, the German transport ministry has put a temporary freeze on the approval of new hydrogen-related funding initiatives.

But other sources of funding for hydrogen continue. The European Commission has approved a €2.2 billion German scheme to support the electrification and decarbonization of industrial processes, including investments enabling the substitution of fossil fuels with renewable hydrogen or renewable hydrogen-derived fuels, to foster the transition to a net-zero economy. The aid will take the form of direct grants, it will not exceed €200 million per beneficiary and will be granted no later than Dec. 31, 2025.

The European Commission has also approved €350 million German state aid in April to support domestic renewable hydrogen production through the Auction-as-a-Service mechanism from the European Hydrogen Bank. The funding will come in the form of direct grants per kilogram of green hydrogen produced and will be available for up to ten years. The goal is to support the construction of up to 90 megawatts of electrolysis capacity, and to incentivize the production of up to 75,000 metric tons of renewable hydrogen in Germany.

The term ‘energy transition’ is a hot topic at global climate summits, in the news, and during policy discussions. It typically suggests a shift towards renewable energy sources like solar and wind. Yet, this definition often misses broader challenges, particularly in regions outside the developed areas of Europe and the United States, where many still rely on basic energy sources like firewood.

In developed countries, the narrative focuses on adopting clean, renewable energy technologies, with a push for global adoption. This progressive stance can overshadow the unique challenges of countries not as advanced on this path. For example, Mexico still struggles with transitioning away from harmful energy sources like coal and fuel oil. These polluting sources have significant environmental and health impacts. Notably, between 13.5 and 20 million Mexicans use firewood for cooking, making it more prevalent than natural gas. Globally, over 2 billion people use biomass for cooking—double the population of developed countries in Europe and the U.S.

This disparity in energy transition stages highlights that there is no one-size-fits-all solution. Voltaire aptly said, “Perfection is the enemy of good.” In terms of energy transition, this means that while the ultimate goal may be a complete shift to renewable sources, intermediate steps are both inevitable and necessary. Overemphasis on clean fuels alone can reduce investments in more accessible, albeit less clean, fuels. This could lead to setbacks, like an increased reliance on firewood by those unable to afford alternatives like LPG or natural gas.

Transitioning from firewood to LPG, or from coal and fuel oil to natural gas, are not perfect solutions, but they represent significant steps in reducing environmental impact and improving public health. Waiting for a 100% clean and non-hydrocarbon based energy solution shift forces millions, especially the disadvantaged, to continue enduring precarious energy sources. Furthermore, reliance on firewood disproportionately affects women, who often bear the responsibility of cooking and are exposed to harmful smoke. In some countries, collecting firewood also falls to young girls, preventing them from engaging in productive activities like attending school. This exposure can lead to respiratory diseases in vulnerable groups like older adults and children. India’s embrace of LPG has proven successful in addressing these challenges, showcasing the benefits of a flexible approach to energy transition.

The path to a sustainable energy future involves dismantling an established global system, a process that is inherently disruptive and requires both social and infrastructural changes. While renewable technologies hold promise, they still need to prove their reliability, affordability, and scalability to meet global energy demands.

It would be misleading to consider any single technology, such as hydrogen or electrification, as the ultimate solution. Each region has its unique circumstances—geographic, economic, and social—that shape its energy needs and solutions. A diversified, “buckshot” approach, tailoring a variety of technologies and strategies to specific regional needs, is crucial for advancing towards a sustainable future.

The journey towards energy transition is as varied as the landscapes and challenges of the world itself. While the goal of a sustainable and cleaner energy future is universal, the pathways to achieve it are as diverse as the regions they traverse, highlighting the importance of adaptable strategies. For millions around the globe, a transition without LPG is unimaginable.

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Expect to see plenty of news stories this spring that warn of US gasoline prices about to move above $4/gallon. Prices might creep or race higher in the rest of April but there is reason to believe that the American gasoline price landscape will resemble a Bactrian camel. We’re almost certainly in the latter stages of the first “hump,” which may crest in the $3.75/gal neighborhood before retreating. Most critically, however, a second midsummer peak looks to be equally predictable.

The latest rally in pump prices, representing the first hump of the Bactrian camel, is not tied to Middle East violence and the threat of a broadening war. Instead, the advances come thanks to the transition seen every spring when the EPA begins to enforce summer gasoline standards. Motor fuel is a mix of 7 or 8 hydrocarbons plus ethanol. Some of those hydrocarbons—like butane—are very cheap but much too volatile to bake into spring and summer gasoline recipes.

All the Northeast is transitioning to this more expensive recipe in April 2024. Wholesale prices have already increased by 30-32cts/gal and gasoline retailers will play catch-up to those moves so as to achieve reasonable margins. The good news is that much of the rest of the country has already transitioned to the less volatile but more expensive summer gas. Be prepared to witness some states retreating even as northern states move to higher pump prices.

Once the US national average approaches $3.75/gal, we’ll undoubtedly see many stories trumpeting a certain move to $4/gal or even $5/gal or more. California is already flirting with a statewide average over $5.50/gal, and regionally high numbers are observed in Arizona ($4.13/gal), Nevada ($4.65/gal) as well as Oregon ($4.44/gal) and Washington ($4.67/gal).

OPIS does not believe that average US street prices will hit $4/gal in the first half of 2024.

Local gas prices can be as variable as real estate costs. One can easily find gasoline in Denver for just over $3/gal but most other states in the Rocky Mountain and Pacific Time Zones are $1.00-$2.50/gal higher.

History Always Repeats Itself in the Gasoline Futures’ Markets

Why is there so much confidence in the limited ascent of the first hump?

Intelligence plays a key role in gasoline futures’ speculation and investing to be sure, but it takes a back seat to herd behavior. One of the strongest seasonal tendencies among all commodities is the template for an early winter RBOB low, rising to an early second quarter peak.

On April 12, 2024, CME RBOB traded at a high-water mark of $2.8516/gal, reflecting a gain of 88.43cts/gal from the low recorded on December 13, 2023.

If these dates seem familiar, they should be. The 2022-2023 cycle also brought a low on December 13, 2022, and the first half 2023 peak was achieved on April 12, 2023, at $2.8943/gal.

It’s not too early to estimate whether the April 12, 2024, futures’ rally could represent the top of 2024’s RBOB price appreciation. Number crunching through the years yields some interesting parallels. A canvas of the last 20 years of futures’ performance confirms that 50% of spring tops occurred in March or April. The average peaking date? April 13.

As the days get longer, the odds of panic liquidation for speculative buyers in gasoline increase substantially. Being long RBOB futures in March and early April is like riding Secretariat 50 years ago. By Kentucky Derby weekend, betting on higher futures’ prices has a Mr. Ed quality.

All the US bulk markets for wholesale gasoline trade based on a relationship to RBOB futures. One might say that RBOB futures act like the Fed Funds’ rate, and every region’s bulk prices trade like an adjustable mortgage that adjusts every day. There is great variability in the regional numbers—Mid-April gasoline sells for 24.5-35cts/gal under RBOB futures quotes in the Midwest and Gulf Coast and fetches a modest premium of 1.5cts/gal in New York Harbor. Western markets are notably more expensive, commanding 30-40cts/gal over RBOB contracts.

If 2023 indeed proves to be an appropriate analogue, RBOB traders and every member of the refinery-to-retail distribution sector need to take notice. After peaking at $2.8943/gal last April 12 2023, RBOB futures had a rough three weeks. On May 4 2023 front month futures slipped to just $2.25/gal, reflecting a decline of over 64cts/gal. Retail prices peaked at $3.6855/gal on April 20 but spent most of May, June and the first part of July at about $3.55/gal.

The Second Hump Beckons in the Third Quarter

A second retail gasoline peak in late summer has been common in the 21st century. This year looks especially prone to a return to more expensive gasoline, not just in the US but in most of the world.

OPEC+ may begin to increase crude production in the second half of 2024, but it might not have an impact until the last 100 days of the year. There is a strong historical tradition of crude oil and RBOB declines from early autumn into winter, but prices tend to remain high into September. When summer arrives in Saudi Arabia, the Kingdom has less crude oil for export since it relies on more than 500,000 b/d to process through utilities that generate the electricity needed for ambitious air conditioning.

August is also the highest global demand month on the calendar. There isn’t an entity that measures global demand with precision but most assessments suggest that demand outpaced supply last August by 1.5-million b/d or more, even without any real consumption growth from China.

However, the true wild card for gasoline this August is the hurricane season. Hurricanes wiped out substantial U.S. refining capability in 2005, 2017, and 2021. Water temperatures in the Gulf of Mexico and Atlantic Ocean are currently several degrees above what would be normal for April. Meteorologists also expect that the El Nino climate cycle will give way to an onset of La Nina by August, incubating perfect conditions for a very active hurricane season.

If you believe the US is better prepared to handle hurricane impacts on refineries, you may want to reconsider that view.

Back in 2005 when Katrina came onshore near New Orleans, the four states of Alabama, Louisiana, Mississippi and Texas accounted for 8.1 million b/d of US refining capacity. This year, those four states have nearly 10 million b/d, much of which is at risk.

In 2023, there were no hurricanes that threatened the real estate that houses refining complexes. But we still saw a substantial gasoline price rally last August and September.

Substantial fuel for the rally came from “storm chasers”—traders and marketers who saw fit to purchase RBOB futures or options as insurance against a hurricane impact. That action may simply be a preview of a late summer buying spree that is likely to be reproduced in 2024.

If we’re lucky and the coastal geography escapes the wrath of tropical weather, there’s a final act that is almost certain. Wholesale and retail gasoline prices are inclined to move sharply lower during the last 100 days of 2024. Additional non-OPEC crude production might hasten this denouement after the twin climaxes of April and August.

The benchmark European Union carbon emissions allowance has traded at a premium to its British counterpart for over a year, and upcoming trade policies like the EU’s carbon border adjustment mechanism (CBAM) could impact British industry.

Read more: CBAM 101: The EU’s Carbon Border Adjustment Mechanism Explained

That’s unless the United Kingdom’s emissions trading system (UK ETS) and the EU emissions trading system (EU ETS) are linked to create a single carbon price for both entities, say some analysts who think that it could gain more traction if the Labour Party forms the next British government.

Brexit led to the departure of the UK from the EU’s carbon market and the creation of the UK ETS in 2021. The two carbon schemes cover heavy industry, but the EU market is substantially larger and more liquid than the UK ETS, covering over 10,000 installations, while the UK ETS covers several hundred.

Navigating the UK-EU Relationship

Linkage between the two carbon schemes is a real possibility according to Mark Lewis, one of Europe’s best known carbon analysts and the head of climate research at commodities hedge fund Andurand Capital Management. Lewis thinks that in the case of a Labour victory in the upcoming general election, Sir Keir Starmer, leader of the opposition party, will navigate a more subtle, less confrontational relationship with the EU.

While Starmer is unlikely to pursue an agreement to re-enter a single market with the EU, Lewis suggested to OPIS in an interview last month that merging the two carbon markets would be a way to show goodwill towards the EU and, perhaps more importantly, level the playing field between British and European industries.

“I think it makes political sense, and…it makes economic sense…It’s too early for the market to really start pricing [linking] in, but as we get closer to the UK election, I think what you will see is the carbon markets [in both the U.K. and the EU] think harder about how this might work,” Lewis said. “This will be an interesting narrative in the second half of the year.”

Linkage between the two carbon markets would be straightforward, Lewis said, especially as the British government has laid down a carbon reduction policy that is more ambitious than the EU’s. The EU has legislated for a 55% reduction in greenhouse gas emissions over 1990-2030 and has proposed a 90% fall by 2040 based on 1990 levels, while the British government has written a 68% reduction into law by the same year and then a 78% cut by 2035.

Linking would also provide British industry with access to a larger pool of carbon allowances, easing concerns about higher prices in the UK ETS in the coming years, Lewis noted.

The gap between the December benchmark contracts of the EU carbon allowances (EUAs) and UK allowances (UKAs) peaked in the fall of 2023 with a spread of over €40 ($43.33). That difference has narrowed to around €18 as EUAs traded on Tuesday at €58.72/mt and UKAs at £34.93/mt ($43.90).

The British government is also considering ways to provide more market certainty with respect to the UK ETS, which has seen prices dip from all-time highs around £97.75/mt on August 19, 2022 to an all-time closing low of £31.48/mt on January 29 this year. The government announced in December that it was working on the development of a supply adjustment mechanism akin to the Market Stability Reserve (MSR), which has been active in the EU ETS since 2018. The MSR mechanism aims to maintain competitive prices by either hoovering up allowances from the market or releasing them into the supply pool.

“The real point here is much more that the prices [between the EU and UK carbon schemes] are out of sync because the U.K. like the EU is frontloading allowances, but [the U.K.] doesn’t have an MSR,” Lewis said. “It’s raining hard outside with U.K. allowances, but at some point the drought in the U.K. is going to be more severe than in the EU because of the more ambitious [U.K. carbon emissions reduction] target.”

Riham Wahba, a senior market analyst with Vertis Environmental Finance, told OPIS that unless the U.K. introduces a supply adjustment mechanism into its carbon scheme, the government’s ambitions, like zero emissions in the power sector by 2050, could “break” the UK ETS as it calls for the faster decarbonization of British utilities, lower hedges and a ballooning total number of carbon allowances in circulation. Based on the government’s projections, power sector emissions would need to drop by 75% by 2030, 83% by 2035 and 98% by 2050 based on 2021 levels.

An EU official told OPIS that linking different carbon schemes is beneficial for climate action as it would allow for more cost-effective emissions reductions. The same official said that any decision to proceed with linkage with the UK ETS “remains to be explored” and that this would be assessed in light of potential changes to the EU ETS.

The EU Commission would need to get a negotiation mandate from the EU Council and the EU Parliament would also need to be involved in the ratification process, the official explained.

“Should the parties decide to link their emissions trading systems, in practice they would negotiate an international agreement. This was done recently with Switzerland, for example,” the EU official said.

On the British side, the Department of Energy Security and Net Zero (DESNZ) maintains an open position to linking with the EU ETS under the terms of the post-Brexit Trade and Cooperation Agreement, a DESNZ spokesperson told OPIS.

“We are open to the possibility of linking the UK ETS internationally and will continue to work collaboratively with other jurisdictions to tackle shared challenges and learn from the experience of others as we develop the scheme,” the DESNZ representative said.

Ben Lee, an analyst with Energy Aspects, told OPIS that while linkage between the two carbon schemes would face better chances under a Labour government, it would still be far from certain due to political, legal and administrative barriers.

Lower Exposure to EU CBAM through Linked Schemes

Wahba said that linking the two markets would help consumers avoid the price differential between the two carbon schemes and any resulting cost being passed through to consumers in the U.K. The CBAM, according to the EU Commission, was implemented to prevent ‘carbon leakage’, or domestic industry decamping to countries without carbon pricing or taxes. The EU Commission believes that the CBAM will encourage other countries to decarbonize their domestic industries

The mismatch between UK ETS and EU ETS carbon prices would mean that British industry is exposed to higher European carbon prices, potentially affecting the flow of trade from the U.K. to continental Europe. The British government announced in December that it would consider implementing its own CBAM but that this would only go live in 2027, a year after the EU’s carbon tax has gone into effect, with potentially harmful effects for British industry, according to accounting firm KPMG.

The EU CBAM will initially cover imports of cement, iron, steel, aluminum, fertilizers, electricity and hydrogen. The U.K. carbon border adjustment mechanism will include the same sectors with the exception of electricity and will also cover imports of ceramics and glass products.

Certain sectors of British industry have called for linkage with the EU ETS. UK Steel, a trade association, called for linkage in December to keep British exports to the EU afloat as 75% of the country’s steel industry’s exports — around 2.5 metric tons — are delivered to EU ETS-covered markets.

US Midwest spot refined product market participants entered 2024 with major questions over how EPA will handle a 2022 request from a group of eight Midwest governors to allow year-round sales of E15 in their states.

The governors in 2023 asked the agency to issue regulations that would allow equal treatment of E10 and E15 during the summer of 2023 by capping the RVP for both fuels at 9 psi during the high-demand driving season.

EPA, in March 2023, proposed a rule that would allow the summertime sale of E15 in the petitioning states, but not until the spring of 2024.

Refiners, however, have argued that EPA’s decision would require them to provide a lower 7.8 lb RVP CBOB that would allow both E10 and E15 to meet the 9 psi specification.

Fuel producers, however, are concerned that because not all Midwest states signed onto the petition to EPA, the waiver could create logistical issues for the Midwest market, especially for pipelines, which could be forced to move two different CBOB RVP specifications during the summer. Some Midwest sources, however, told OPIS that if EPA grants the waiver in the spring of 2024, those states in the region that were not part of the request would likely move to the lower 7.8-lb RVP CBOB.

While the petitioning states and the ethanol industry criticized the agency for failing to approve the regulatory change in time for the 2023 driving season, the Biden administration, for a second straight summer in 2023, issued a series of waivers lifting restrictions on the sale of E15. Those did not, however, require refiners to provide lower RVP blendstock.

See also: US Ethanol Industry Explores Avenues for Expanding its Markets, Jan. 26, 2024

Midwest market participants said they would enter 2024 somewhat in the dark over what the summer RVP requirements will look like, cautioning that unrestricted sales of E15 could have big impacts on the fuel supply chain and prices.

Patrick Searles, downstream fuels policy director with the American Petroleum Institute, told the EPA at a March 2023 public hearing on the proposed rule that even with the decision to delay the move to April 2024, “there still is likely to be insufficient time to engineer projects, identify capital, obtain the permits, and contract and deploy the skilled trades to construct the systems needed.”

In September 2023, Paul Machiele, director of the EPA’s Fuel Programs Center, acknowledged that the rule could “require significant changes in the distribution systems.” And he added that EPA has the right to delay implementation if concerns over the supply persist.

And if EPA does approve the change in the spring of 2024, then many are wondering just how the decision would affect the spot gasoline market. “You instantly increase the gasoline pool by 5% with the stroke of a pen,” one source said. “What does that do to the basis?”

Spot gasoline prices trade at differentials to NYMEX futures and the question being asked by many in the market is whether more E15 will lead to lower spot RBOB prices and just how the lower 7.8 lb CBOB will be priced in relation to more typical 9 psi blendstock.

The Midwest gasoline and distillate spot market also experienced strong price volatility in 2023 and a question on the minds of many is whether this is likely to continue into the new year.

One market player, citing the unusually long period of volatility this year, said he believes more of the same is likely on tap for the Chicago market in 2024.

According to OPIS data, Chicago CBOB spot prices fell to a 2023 of just under $1.70/gal on Dec. 7, 2023. The last time the price fell below that mark was mid-February 2021.

And the 2023 low came just four months after prices hit a 2023 high above $2.80/gal.

Group 3 sub-octane gasoline also saw hefty price spikes in 2023, rising to a $3.57/gal high for the year on Sept. 7, 2023, the highest mark since late June 2022.

Similarly Group 3 ULSD hit a 2023 high price of $4.20/gal on Oct. 20, 2023, the highest recorded price in about a year.

While this type of volatility remains difficult to plan for, and market participants have grown used to price swings due to extreme weather and refinery disruptions, and one source said 2023 may be viewed by some as a reference market, given that the Midwest harvest season – a period of high distillate demand – was “ideal.”

2023 was also notable for a lack of major refinery upsets, particularly in the fourth quarter. If this trend continues into 2024, participants may have a clearer picture of what they can expect.

The Energy Information Association put Midwest refinery utilization at above 100% for two weeks starting in late August, allowing the region’s refiners to easily meet increased demand as the harvest season ramped up.

That baseline of what supply and pricing looks like when running at full capacity may provide market participants with a clearer picture for 2024 – if they can count on that continuing.

See also: Changing Regulations Could Spur Pricier Midwest Gasoline This Summer, Feb. 3, 2023

The prices of the solar supply chain continued to hit new lows in 2023 due to overcapacity in China. The relentless capacity buildup, which the International Energy Agency (IEA) says accounts for 75-95% of the global solar production capacity, is expected to exacerbate the supply glut and drag prices across the solar supply chain down as more capacities are added in 2024.

In 2023, China produced more than 1.43 million metric tons (mt) of polysilicon, an increase of 66.9% from 2022, data from China’s Ministry of Industry and Information Technology showed. Meanwhile, wafer production exceeded 622GW, a year-on-year increase of 67.5%, with wafer exports totaling 70.3GW, an increase of 93.6% from 2022.

Cell production exceeded 545GW in 2023, an increase of 64.9% from the previous year, while exports totaled 39.3GW, a year-on-year increase of 65.5%. Module production exceeded 499GW, up 69.3% from 2022, with exports in 2023 totaling 211.7GW, an increase of 37.8% year-on-year.

The Global Polysilicon Marker, the OPIS assessment for polysilicon produced outside of China, fell 32.9% over the year to end 2023 at $26.12/kg, the lowest since October 2021. But even this sharp reversal pales in comparison to the 56.07% fall in the China Mono Grade polysilicon price, which ended 2023 at 61.50 yuan per kilogram (kg) ($8.62/kg), the lowest since July 2020.

Prices of Chinese Mono PERC M10 wafers and cells likewise fell by a massive 60.27% to $0.265 per piece (pc) and 57.54% to $0.0484 per Watt peak (wp) respectively in 2023, while the Chinese Module Marker (CMM), the OPIS assessment for Chinese Mono PERC modules, fell by 47.83% to $0.120/wp, all of which were record lows since OPIS began assessments of these products.

Daqo Energy’s Baotou Phase II 100,000-ton polysilicon plant is expected to start up in the second quarter of 2024, while Hoshine’s Xinjiang 200,000-ton polysilicon plant and Tongwei’s Yunnan Phase II 200,000-ton polysilicon plant are both expected to start up by the end of March.

Around 170,000 mt of polysilicon, or about 70GW of downstream products, were manufactured in China each month in January and February 2024, according to the Silicon Industry of China Nonferrous Metals Industry Association. The amount of polysilicon produced in China might reach 230,000 mt per month by the end of 2024, equivalent to about 95GW of downstream products. A large build-up of polysilicon inventories is anticipated for this year, and that demand pickup will have minimal effect on pricing when there are excessive inventories, states a China-based source.

Furthermore, according to the China Photovoltaic Industry Association, China is expected to add 190-220 GW of solar installations in 2024, indicating a negligible increase compared to the installed capacity of 217GW in 2023.The difficulties associated with power consumption and grid connectivity could lead to a less notable increase in solar installations.

The wafer segment is likewise seeing similar capacity expansion. Hongxin New Energy’s 20GW ingots and 14GW wafering project in Yunnan and Gaoce’s 25GW wafer plant in Yibin both kicked off production in January 2024.

According to the Silicon Industry of China Nonferrous Metals Industry Association, China produced 63.97 Gigawatts (GW) of wafers in February 2024, which is China’s highest-ever monthly production output of solar wafers. This has led to decreases in the price of N-type wafers due to the necessity of wafer companies to clear the stockpile of N-type wafers that resulted from high production. As of the week of March 5, 2024, N-type wafer prices have been lower than P-type wafer prices, which used to be 10% higher than P-type wafer pricing in 2023. This suggests that N-type wafer market has engaged in a pricing war.

Furthermore, there are continuous expansions in the production of cell and module segment as well:

The headlong rush to build new solar facilities took hold during the market’s two-year bull run in 2020-2022, but the industry is now struggling to stay afloat in the supply deluge. Operating rate cuts and bouts of sell-offs were already common across the solar supply chain during the fourth quarter of 2023, with prices in all segments falling to a hair’s breadth above or even below cash costs.

Market players expect this to continue in 2024. A further decline in polysilicon prices to 50 yuan/kg is possible given the fall in production costs of the raw material. This is especially as older polysilicon factories with higher manufacturing costs are being decommissioned, which would lower polysilicon’s average production cost to below 60 yuan/kg.

If the Chinese solar supply chain continues to operate at razor-thin or negligible margins in this scenario, wafer costs could fall further to 1.862 yuan/pc, cells to 0.386 yuan/wp, and modules to 0.836 yuan/wp. On paper, from a production cost standpoint, module prices could fall no further below this.

But this is only in theory. According to company sources, module makers that are not established tier-1 solar majors are already selling below costs, several of whom had joined the 2020-2022 solar gold rush from unrelated industries. Market consolidation is a likely consequence, which sees unprofitable companies exiting the industry in a “survival of the fittest” scenario.

The next phase in the solar industry, which is currently running at a loss overall, is to remove obsolete production capacity. This could take a very long time since occasional demand spikes would push prices higher, allowing ailing companies more room to turn a profit and survive longer. However, any price hike before the industry consolidation might only be temporary, according to a source.

It’s critical for solar manufacturers to lower production costs and boost product efficiency in the race to survive. It’s important to set up research & development departments to work toward minimizing consumables. Moreover, solar producers may find it helpful to increase the capacity for producing auxiliary materials, said a source.

Buyers and sellers of voluntary carbon credits have, in recent months, begun to value offsets issued from the same projects at wildly different prices.

Vintage 2021 credits from an Asia-based REDD+ project traded in February 2024 at $16/metric ton. In January, a seller offered V18 credits from the project at $1.25/mt. V21 credits from a Latin American REDD+ project traded in February at $10.10/mt and $6.50/mt. Since October 2023, credits of various vintages from an Africa-based REDD+ project have cleared between $1.70/mt and $5/mt.

REDD+ stands for reducing emissions from deforestation and forest degradation.Voluntary carbon markets are notoriously opaque. Credits can transact on electronic exchanges either through direct trades or in standardized contracts. Many deals, however, occur on a bilateral basis. Buyers may also sign forward offtake agreements with developers for future issuances.

In that milieu, buyers and sellers can arrive at varying conclusions regarding the quality of a carbon offset project and the value of its credits.

In Search of Quality

REDD+ projects have received harsh criticism over the past two years. John Oliver detailed a range of low-quality initiatives in an August 2022 segment on the HBO show “Last Week Tonight.” In a January 2023 article, The Guardian alleged that “more than 90% of rainforest carbon offsets … are worthless.”

In the months since, further criticism of voluntary carbon markets has proliferated. In response, the market has flocked to quality.

Many buyers have reported seeking out high-quality credits. The Integrity Council for Voluntary Carbon Markets is working to signal quality by assessing methodologies under its Core Carbon Principles framework, which it published in March 2023. The Voluntary Carbon Markets Initiative has begun to approve corporate offsetting statements with its Claims Code of Practice, which it published in June 2023.

General agreement exists among market stakeholders as to what constitutes a quality REDD+ project. Among other measures, projects should be additional, meaning they would not have occurred without the intervention of the developer. Offsets should be permanent, meaning developers should reasonably expect to sequester carbon on an ongoing basis and put measures in place to address the risk of reversal. Credits should be counted just once and then retired. Projects should not simply displace carbon emitting activity somewhere else, known as leakage.

And, per the ICVCM’s principles, projects should ensure “robust quantification of emission reductions and removals.” In other words, if a project issues a credit representing a metric ton of carbon dioxide equivalent, or CO2e, it should be confident that a metric ton of CO2e has been removed, reduced or avoided.

Finally, credits can also earn co-benefit designations for advancing sustainable development goals or other benefits that do not directly relate to carbon offsetting. Many buyers pay a premium for strong co-benefit designations.

Yet, as evidenced by the disparity in prices reported to OPIS for credits from the same project, buyers and sellers can disagree over how quality translates to price.

Carbon credit ratings agencies, such as BeZero Carbon, Sylvera and Renoster, have brought greater clarity to the market, but the availability of ratings doesn’t necessarily lead to price consistency.

For example, V20 credits from an Asia-based REDD+ with a co-benefit designation traded in September for $13.50/mt. V20 credits from the same project were offered at $5.75/mt in January.

OPIS assessed the REDD+ V20 Tier 3 range at $6.75/mt to $14.75/mt on the day of the trade in September. The range was assessed at $5.10/mt to $16/mt at the end of January and was assessed at $5.50/mt to $14/mt on March 5.

Renoster rates projects based on its confidence that one credit represents one metric ton of offset emissions. An ideal score is 1. Anything above that level indicates the project has understated its impacts, and anything below indicates it has overstated them.

Renoster gave the Asia-based REDD+ project a score below 0.80. While it was judged to be additional and to have set a conservative baseline, leakage involving deforestation in nearby areas brought its score down. Significant permanence risks were also detected.

Widening Spreads Between High- and Low-Quality Credits

As carbon offset buyers began to conduct greater due diligence regarding project quality over the past 18 months, prices reflected that shift. Buyers began to pay a premium for credits they deemed to be high-quality, while sellers of credits perceived to be low-quality grew willing to trade them for less and less.

OPIS accounts for project type, vintage and volume, as part of its voluntary carbon market assessment range. Over the past year, the spread between the high and low end of OPIS assessments has widened.

On Jan. 18, 2023, the day The Guardian published its article, OPIS assessed the REDD+ Tier 3 V21 range at $10.44/mt to $14.50/mt. On Tuesday, the REDD+ V21 Tier 3 range was assessed at $6.25/mt to $15.07/mt. In the interval between, the low end was assessed as low as $5/mt on Feb. 7, 2024, while the high end was assessed as high as $18.50/mt on March 30, 2023.

In other words, the market has weakened overall, but some projects perceived to be high-quality have been able to fetch stronger prices than they could 12 to 18 months ago.

BeZero Carbon Co-Founder and Chief Innovation Officer Sebastien Cross has also noticed this phenomenon.

“We’ve begun to see big spreads in the market, particularly after last year, when you saw some of the pricing crash off of some of the stories and headlines,” Cross said. “But, if you look at the underlying transactions going through, some projects have still been appreciating.”

Some disparity in prices can be explained by the volume of credits delivered in a trade. Sellers typically ask more for credits in smaller-volume transactions.

OPIS divides its assessments by tiers to account for these volume discounts and premiums. Tier 3 involves trades between 2,000 and 49,000 credits, Tier 2 reflects volumes of 50,000 to 349,000 credits, and Tier 3 is 350,000 credits and above.

Credit vintage can also influence pricing. Newer vintages tend to trade at a premium to older vintages, which represents a contango market structure.

But disparity can be found in credit prices from the same project even accounting for vintage and volume. Since December 2023, Tier 3 volumes of V19 credits from a Latin American REDD+ project have traded between $8/mt and $13.45/mt. Less than a year ago, Tier 3 trades for V19 credits from the project cleared as high as $17.50/mt.

What’s more, the project has a rating from Renoster well above 1, indicating very high confidence in its emissions reductions and project quality.

While the previous example of the Asia-based REDD+ project indicated that some buyers were overpaying for middling quality credits, Renoster’s rating of the Latin American REDD+ project indicated that some buyers have been able to pay less for high-quality offsets.

According to Saif Bhatti, CEO and Co-Founder of Renoster, this disconnect indicated how immature the voluntary carbon market remains.

“This is a very nascent market,” said Bhatti said. “There’s just not a high level of liquidity or information transfer from different market participants. If you compare it to the stock market, the price of the same share on one exchange is likely to be the same as the price on another. That’s obviously not the case here. It’s just such a different ballgame.”

Both Bhatti and Cross, however, believe buyers are getting smarter and savvier when it comes to judging quality.

Cross pointed out that The Guardian article based its broad conclusions on a sample of the REDD+ market. When it was published, it had a strong impact on REDD+ prices.

“The market has progressed a lot,” Cross said. “The marginal impact of these headlines [criticizing carbon projects] has been less and less. People have realized that taking a sub-sample of a sector and saying, ‘These projects are crap, therefore the whole sector is crap and therefore the whole market is crap.’ That is not actually an indication of reality. You have to be a bit more specific.”

See also: REDD+ Project Hedges Against Drought and Weakening Carbon Markets, June 1, 2023

US polyethylene (PE) spot prices finished 2023 flat to 3cts/lb lower than a year earlier as producers increased exports to offset sluggish domestic demand. The market dynamics for 2024 are looking like more of the same.

High-density polyethylene (HDPE) blow molding grade was trading at 34cts/lb railcar FOB Houston on Dec. 28, flat to where it was assessed a year earlier, according to PetroChem Wire by OPIS, a Dow Jones company.

HDPE blow mold spot export prices moved in a relatively narrow range of 33-44cts/lb railcar FOB Houston in 2023.

Some domestic market players have a cautious demand outlook for 2024, with high interest rates and slowing global GDP growth weighing on expectations.

“People are beginning to realize that demand next year is going to be weaker, so they are working hard to lock up business,” one distributor said in late 2023.

The heavy competition for 2024 contract volume commitments was also fueled by the continued ramp-up of new North American capacity.

Although it has had its share of growing pains, Shell’s 1.5 million metric ton/year Monaca, Pa. plant is expected to return to full operation in early 2024 after the company replaced a compressor for one of the three PE units.

Customers have expressed doubts over whether they will see meaningful first-quarter volumes from the restarted PE line, which will produce high-density polyethylene grades using slurry process technology. The full effects may not be seen until later in the year.

Nova Chemicals’ new 450,000 mt/year unit at the Rokeby site near Sarnia, Ont. and Bayport Polymer’s new 625,000 mt/year unit in Pasadena, Texas, will continue to increase output as well.

PE producers were able to charge out of the gate in early 2023, raising spot prices in the Houston railcar market by 8cts/lb or more from the beginning of the year through mid-March.

They have repeated that strong start in 2024 with another assist from Mother Nature. A hard freeze event in mid-January, coupled with strong export sales, helped move the Houston railcar market up by 3-5cts/lb in January.

US and Canadian PE operations have been healthy in recent months, averaging more than 5 billion lbs/month from July 2023 through January 2024. To balance those high operating rates, producers have been selling an average of 47 to 48% of their output abroad.

Some producers have said they intend to run full out as long as their facilities in the U.S Gulf maintain a substantial cost advantage compared with their counterparts overseas.

Customer pre-buying in late 2023 could be another headwind in early 2024. With prices in decline since October, some traders and processors acquired extra volumes in November and December, betting that producers will raise prices in Q1 as they have in every year since 2020.

But the PE market usually gets a boost from seasonal demand patterns in the first quarter. By the second quarter, processors exposed to industrial and construction end markets are predicting an influx of government spending from the Biden administration’s infrastructure program.

In international markets, concerns about weakness in the Chinese economy could evaporate if that market emerges strongly from the Lunar New Year holidays in February. Crude oil prices are viewed as having limited downside potential, and any rebound will put upward cost pressure on petrochemical producers, particularly those using naphtha as a feedstock.

See: Asia Remains Key to US Polyethylene Industry’s Export Strategy

PE producers believe that the downstream plastics supply chain has low inventories after a year or more of destocking.

“That could springload demand if the economy picks up,” a PE producer said. “But we don’t know when that will happen.”

If distributors’ and processors’ forecasts are accurate, any significant recovery in PE demand likely won’t be seen until the second half of 2024, if then. But crude oil prices typically rally early in the year, and that could provide some upward price pressure for North American producers looking to rebuild margins after a bruising contract negotiation season for 2024.