Thought Leadership

By Juan Gomez Prado, Head Consultant, Decarbonisation, KBR and Nenad Zecevic, Head of Hydrogen & Derivatives, KBR

The downstream refining and petrochemical industries are some of the most affected by the energy transition. In recent years, governments and leaders across the sector have committed to ambitious decarbonisation goals, including net zero emissions by 2050. Despite this, global demand for oil and gas products is still strong and, in some cases, growing.

Even in the most aggressive decarbonisation forecasts, hydrocarbons are still expected to play a role in the global energy system for decades to come. In fact, according to analysis by Reuters in December 2025, “World oil demand is expected to rise in 2026 by 860,000 bpd, up 90,000 bpd from last month's outlook, the IEA said. It raised its 2025 forecast by 40,000 bpd to 830,000 bpd.”  

This demand is driven, in large part, by population growth, urbanisation and the need for lightweight, durable materials. However, it creates a tension for asset owners, where facilities that were designed to be used for decades, must now navigate tightening emissions rules while still being reliable, safe and profitable.

For downstream operators, decarbonisation is not something that can come with the flick of a switch, for example by switching fuels or installing new equipment. It’s a much more complex, longer-term transformation that must take into consideration everything from asset life, capital cycles, regional policy frameworks and the maturity of the available technologies. The challenge is understanding how best to sequence this transformation for each individual application.

Why pathways matter more than targets

Although net zero targets and public commitments are a good indicator of the direction the industry is headed, they don’t actually tell operators how to get there. Refineries, crackers and related infrastructure are complex, capital-intensive systems. Many were designed decades ago and still have years of life left in them. Displacing them at scale, especially in the short term, is rarely feasible.

This is where a pathway-based approach offers a better solution. Instead of focusing on whether an asset can reach net zero, owners should consider the best ways to reduce emissions steadily over time.

Forcing assets to achieve unrealistic end-goals will at best result in delays and at worst result in stranded capital.

A global patchwork of policy

Because decarbonisation does not occur in a vacuum, investment decisions can be significantly influenced by policy and factors like carbon pricing mechanisms, not all of which have been developed at the same speed across the world.

In Europe, policymakers have introduced the EU Emissions Trading System (ETS) and the Carbon Border Adjustment Mechanism (CBAM) to force change. The ETS increases the cost of emissions for European producers and CBAM prevents “carbon leakage” by ensuring that imported carbon-intensive products come with a carbon cost.

Without this mechanism, stricter regulation would end up simply shifting production outside of Europe where regulation might be less stringent, reducing regional output and making no difference to, or even increasing global emissions. Instead, CBAM levels the playing field and encourages decarbonisation globally rather than incentivising operators to export their emissions elsewhere.

The United States does not have a direct carbon pricing mechanism like the EU ETS and the approach has been more market driven. Initiatives like the Inflation Reduction Act (IRA) include tax credits and subsidies for clean energy projects including clean hydrogen, CCUS, and electrification.

In contrast, Canada has rolled out a national carbon pricing approach focused on large emitters, using large-emitter trading systems (LETS), which encourages industrial emitters to invest in low-carbon solutions.

Africa faces a different set of challenges and opportunities. Many African nations, such as South Africa, Zimbabwe, Mozambique and Botswana, rely heavily on non-renewable sources like oil and coal. Cleaner energy alternatives are not only costly, they’re also difficult to roll out because of challenges such as poor energy-grid infrastructure and difficulties with underdeveloped legal and regulatory systems. Despite this, there is an abundance of renewable energy potential, which could support long term decarbonisation.

The Asia-Pacific (APAC) region is varied. China is the world’s largest emitter, responsible for around a third of global greenhouse gas emissions. Despite this, it has set an ambitious target for net zero by 2060 and is heavily investing in hydrogen, CCS, and industrial electrification. Meanwhile, other countries, including Japan and South Korea have high hopes for hydrogen. However, like Africa, Southeast Asian countries face the same challenge of trying to balance industrial growth with cleaner technologies.

Regardless of this patchwork of regional differences, using a pathway approach allows flexibility in responding to these variations, while still moving towards cleaner solutions long term.

A practical framework for decarbonisation

The first step to decarbonising is establishing an emissions baseline. This should take into account direct and indirect emissions from utilities, process and feedstocks. This is important because for many industrial assets, a few units often account for a disproportionate share of site emissions. By identifying these sources, operators can focus their efforts where they’ll have the greatest impact.

For downstream and petrochemical facilities, these sources often include hydrogen production units, high-temperature furnaces, steam crackers, fluid catalytic cracking units and other energy-intensive process steps. Identifying these early allows operators to focus on measures that deliver reductions rather than spreading investment thinly across lower-impact changes.

From there, potential decarbonisation options should be assessed using a structured framework. For example, marginal abatement cost (MAC) is a useful way to identify measures that deliver the greatest emissions reductions for the lowest cost. Energy efficiency improvements, heat recovery and operational optimisation frequently score well here and are often a good starting point.

Another framework is technology readiness level (TRL), which is particularly useful for hard-to-abate processes. Although solutions, such as large-scale hydrogen integration, electrification of high-temperature processes or full carbon capture systems are technically feasible, they are not yet widely deployed across downstream applications. So, before committing capital, operators should understand their maturity and reliability, as well as the challenges with integration.

The next step is to gauge how feasible it is to implement these approaches. Space constraints, utilities availability, downtime requirements, safety considerations and workforce capability can all limit what is achievable on an existing site. This is where scenario-based planning tools and multi-criteria decision analysis (MCDA) can help asset managers sequence actions carefully.

The takeaway here is that decarbonisation is not a one-and-done project. It requires continuous improvement and adjustment, combined with strong governance, monitoring, reporting and verification. Above all, clear accountability with a well engaged workforce will ensure long term success.

Implications for refineries and petrochemical complexes

For refineries and petrochemical sites, decarbonisation will take place in stages, starting with quick wins that cause the least disruption, before moving to larger structural changes.  

Hydrogen production units are often among the largest single sources of emissions on site, making them prime candidates for early intervention. Retrofitting existing steam methane or autothermal reformers with carbon capture can significantly reduce direct emissions, while longer-term replacement with low-carbon hydrogen production further deepens reductions.  

Alongside this, carbon capture is expected to be integrated into other high-emitting units such as fluid catalytic crackers and hydrogen plants, particularly where shared transport and storage infrastructure is available.

Beyond process emissions, the product mix is also evolving. In many regions, demand for gasoline and diesel is expected to plateau or decline by the early 2030s, thanks to the rise of EVs and policies such as the planned phase-out of new internal combustion engine vehicle sales in the EU and UK.  

This is driving a trend to adapt existing refinery and petrochemical solutions to produce the likes of chemical feedstocks, sustainable aviation fuels (SAF) and other circular products. This includes the processing of bio-based and waste-derived feedstocks such as biomass, hydrotreated vegetable oil (HVO), biogenic waste streams and recycled plastics. Over the longer term, some refineries are likely to be repurposed into low-carbon hubs producing hydrogen, bio-naphtha and SAF alongside conventional petrochemical intermediates.

Hydrogen, ammonia and fertiliser pathways

Hydrogen is already a key part of many downstream operations, used extensively for hydrotreating and hydrocracking, making it ideal for decarbonisation.

In the short term, blue hydrogen produced from natural gas with carbon capture will be important, particularly where access to storage infrastructure and policy support exists. Over time, as electrolyser costs fall and renewable electricity becomes more prevalent, green hydrogen is expected to expand, further reducing emissions.

With ammonia, global fertiliser production currently exceeds 190 million tonnes per year and makes up a significant share of global food production. At the same time, ammonia production alone is responsible for 450 Mt of direct CO2 emissions annually and another 170 Mt of indirect CO2 emissions, according to the IEA. Therefore, transitioning from conventional steam methane reforming to blue and green ammonia pathways will have a significant impact on emissions reduction globally.  

For refineries and petrochemical operators, low-carbon ammonia also offers an opportunity to develop new export markets, being used as an energy carrier and making use of existing hydrogen and syngas infrastructure.

What success looks like by 2035-2050

By the middle of the century, the downstream and petrochemical sectors are likely to look very different from today, but the transition will need to be steady rather than abrupt. Successful operators should not rely on a single technology or strategy. Instead, they should deploy solutions tailored to their assets, that take into consideration wider regional policy and market demand.

Decarbonising downstream and petrochemical operations is one of the most complex challenges facing heavy industry. It cannot be achieved through targets alone or by copying solutions from other sectors. It requires balanced, pragmatic pathways.

Rather than some blanket concept of decarbonisation, in practice this journey will be made up of a portfolio of changes, including energy efficiency improvements, a move to low-carbon hydrogen, electrification, as well as hub-based carbon capture and storage.  

These approaches will be supported by increased circularity and a changing product mix. Crucially, the most successful asset owners and operators will be those that take more deliberate, phased decisions rather than responding last-minute to external pressure.

About the authors:  

Juan Gomez Prado is a chartered chemical engineer with a strong technical background in process design, evaluation, optimisation and development of decarbonisation projects, with over 40 margin improvement programmes and projects for facilities worldwide. He has a track record developing techno-economic evaluation and design for green hydrogen projects globally at capacities going from MW to GW scale. These projects not only covered production facilities (gaseous hydrogen, liquid hydrogen and ammonia) but utilisation. He is part of KBR’s Energy Transition team, actively developing projects and business opportunities that this sector is creating.  

Nenad Zecevic has 25 years of experience in operations and maintenance activities of ammonia and syngas production and finished fertilizer products e.g. UREA, CAN, NPK’s, and AS/ASN. He holds Ph.D. in Chemical Engineering and Technology, University of Zagreb, Republic of Croatia. Areas of expertise include Production & Maintenance, CAPEX & OPEX Management, Environmental Regulations, Chemical Engineering, Strategic Development, Techno-Economic Feasibility Studies, Automation and Modelling of Chemical Processes.