What Are Participatory Climate Vulnerability Assessments, and Why Do They Matter?

Climate change is not affecting everyone equally. The communities most exposed and vulnerable to climate impacts are often the ones with the least voice in the decisions that shape their future. Closing that gap is at the heart of locally led adaptation (LLA), also referred to as community-based adaptation (CBA): an approach that places communities at the centre of climate adaptation decision making. Rather than prescribing solutions from the outside, LLA aims to strengthen communities' agency in identifying their own priorities and designing their own solutions.

A participatory climate vulnerability assessment (PCVA) is the essential first step in this process. It is a facilitated process that combines community knowledge with scientific climate data to map current and future climate risks, and to understand how those risks affect distinct gender and social groups within a community differently.

Getting this right matters. A poorly conducted PCVA (rushed, superficial, or failing to capture the diverse perspectives) leads to poorly designed adaptation plans. Resources go to the wrong priorities. Vulnerable groups are left out. Opportunities to build genuine resilience are missed.

"This project allowed the communities to have an input, instead of assuming what they want or what they are going through; the communities are speaking for themselves, instead of going with preconceived ideas of what is needed."

CBA SCALE+ project partner

Despite more than 20 years of practice, scaling LLA meaningfully remains elusive. Many assessments that call themselves participatory are still extractive in practice. The Intergovernmental Panel on Climate Change confirmed in its 2022 Sixth Assessment Report that LLA can successfully enhance adaptive capacity. Yet the persistent challenge is implementing it at a scale that meaningfully reflects the social diversity of communities and the urgency of the crisis.

A new report from the International Institute for Sustainable Development and CARE offers a field-tested account of what keeps going wrong and what practitioners can do about it. It draws on PCVAs conducted in nearly 100 communities across Mozambique, Zambia, and Zimbabwe between 2024 and 2025, as part of the CBA SCALE+ project. While many of the challenges identified have already been documented, they persist today. Here’s why.

Why Are Participatory Climate Vulnerability Assessments Harder Than They Look?

We know communities need to lead efforts to strengthen their resilience to climate change impacts. But doing this well (respectfully, rigorously, and at scale) is far harder than it looks. Three challenges in particular resonate from the CBA SCALE+ experience.

Adapting and Responding to Overlapping Crises

In early 2024, Zambia declared a state of national emergency. Zimbabwe followed weeks later. A prolonged drought driven by El Niño had been devastating harvests since mid-2023. Cereal yields in Zambia fell 43% below the 5-year average. In Zimbabwe, the figure was 50%. Communities across the project area were hungry, water-scarce, and under acute stress.

In this context, conducting a PCVA didn’t seem like a priority to the communities and local governments, who were understandably focused on food relief, not multi-decade planning. Some partner organizations, with histories of humanitarian work in the same areas, were expected to provide emergency assistance that the project was not designed to deliver. When flexible emergency funding was not available, trust began to erode. Communities that had committed to engaging with the process started to pull back.

This kind of polycrisis context, when climate, economic, and political crises overlap and reinforce each other, is increasingly the normal operating environment for climate adaptation practitioners.

This means that flexible funding mechanisms need to be built into project design from the start, not scrambled for after a crisis hits. Equally critical is honest expectation management. Communities in survival mode cannot meaningfully engage with 30-year climate projections unless their immediate reality is first acknowledged. The project teams that rebuilt trust most effectively were those that adapted their engagement (through shorter sessions, more flexibility, transparent communication about delays) while finding ways to address urgent needs alongside longer-term work.

Bridging Community Knowledge and Climate Science

Even without a drought emergency, one of the hardest tasks in any PCVA is integrating what communities know from lived experience with what climate science tells us about future risks.

Communities hold rich knowledge of their local environments, built over generations: how rainfall has shifted over decades, which crops no longer perform as they once did, and where seasonal flooding has become more frequent. While irreplaceable, this knowledge is, by definition, rooted in observed experience. Climate projections, on the other hand, describe what climate variables such as temperature and rainfall may look like in 2040 or 2060; a future no one has yet lived through.

The CBA SCALE+ team encountered four recurring barriers to bridging this gap.

• The first is framing. Framing the PCVA primarily as a participatory exercise may have unintentionally signalled that scientific climate projections were optional, rather than central to the analysis.
• The second is capacity. Translating technical climate projections into accessible, locally meaningful messages requires both scientific fluency and skilled facilitation. That combination is rare, and the report found that some project teams lacked the confidence to engage communities meaningfully with future climate data.
• The third is present bias: the human tendency to prioritize immediate concerns over long-term risks. This is particularly true for communities already under stress: Getting people to think about 2050 when 2024 is already a crisis requires deliberate, skilled facilitation.
• The fourth is trust in the messenger. In some communities, scientific information was received with skepticism, particularly when it came from the government. The credibility of the person delivering the information shaped whether communities were willing to engage with it.

What worked? A gradual, trust-based approach. Seasonal weather forecasts are shorter-term predictions that communities can connect to immediate decisions about planting and livestock. Teams that started with those forecasts found that when they proved accurate, communities became more open to longer-term projections.

"Building trust is slow. Last year, the traditional community predictions and the scientific predictions matched, so the communities were more willing to listen to the scientific knowledge."

CBA SCALE+ project partner

Building community confidence in climate science requires time, repeated interactions, trusted local messengers, and visual tools that make abstract data tangible.

Meaningfully Engaging Local Governments

For LLA actions to move from community plans into funded, implemented reality, local governments need to be genuine partners, not just formal signatories or occasional attendees.

The CBA SCALE+ experience showed that meaningfully engaging local governments is essential, but challenging. Across the three countries, teams encountered gaps in local officials' technical capacity on climate adaptation, competing pressures from drought emergencies, and in some cases, pre-existing tensions between civil society organizations and government actors that affected collaboration.

At the same time, the project's strongest outcomes came precisely where local governments were most engaged. In Mozambique, early and sustained collaboration with district-level councils meant that PCVA results fed directly into the local adaptation plans of two districts. In Zimbabwe, regular updates to government extension workers through existing communication channels helped keep the process connected to formal planning systems.

Local government involvement must begin at the outset of a PCVA, not at the validation stage. Officials brought in early become advocates for the process and champions for its results within formal systems. Those invited only at the end remain, at best, passive endorsers.

The Knowledge Is Already There: A Call to Do This Better

In Zimbabwe, project teams documented how some communities had already adapted their cropping patterns and livestock types to changing climate conditions; responses developed through observation and necessity, without external support. They identified community-led initiatives that deserved to be scaled up: drought-tolerant seed multiplication programs, locally enforced wetland protection rules, and diversified livelihood strategies built around shifting seasonal patterns.

In Zambia, the PCVA process revealed that 4 of the 12 focus communities relied primarily on legal mining rather than agriculture—a fact that fundamentally changed what climate adaptation needed to look like for those communities and that no existing secondary data had captured.

These findings were only possible because the process was genuinely participatory: communities were given space to speak for themselves, rather than having their realities assumed in advance. They also demonstrate the value of PCVAs in generating nuanced, context-specific information. Such insights are critical for identifying adaptation measures that build on existing strengths while addressing priority needs.

The challenge, then, is building the systems (the funding structures, the facilitation capacity, the inter-institutional trust, the policy frameworks) that allow existing community knowledge to surface, be taken seriously, and be acted upon.

That requires NGOs to resist the temptation to arrive with pre-packaged solutions. It requires funders to accept that genuine participation takes time and cannot be compressed into a short project cycle. It requires local governments to show up as partners in collective learning, not as authorities dispensing directives.

The lessons from this report have been documented before. The challenges persist because the structural conditions that generate them (tight timelines, inflexible funding, insufficient investment in local capacity) have not changed significantly.

Closing that gap is not just good practice. For the nearly 100 communities in Mozambique, Zambia, and Zimbabwe that took part in this process, and the many millions more living on the frontlines of climate change, it is a matter of urgency.
 

The quotes in this article come from partners who wished to stay anonymous. All photos are from Margret Ngonga, CARE Zambia.

The Community-based Adaptation: Scaling-up Community Action for Livelihoods and Ecosystems (CBA SCALE+) project is implemented by a consortium led by CARE Deutschland along with IUCN, FANRPAN, IISD and local partners, with financial support from The International Climate Initiative.

While China has concluded investment treaties and other international investment agreements with the vast majority of its Belt and Road Initiative partners, political understandings, policy guidance, and MoUs frequently continue to shape the on-the-ground legal architecture of many projects. This creates a hybrid environment where informal diplomatic mechanisms and formal legal frameworks operate in parallel and where the interactions between them can create real legal risk for host countries. To navigate it well, governments need to understand all three layers: the hard law foundation, the soft law overlay, and the distinctive role played by Chinese SOEs. 

The Hard Law Ecosystem: Treaties and contracts

Traditional international investment governance is anchored in investment treaties, domestic investment laws, and binding contracts. For host countries participating in the Belt and Road Initiative, it is important to understand these instruments before layering on the soft law features of the Initiative.

Investment treaties are binding international agreements that set out the rules governing investment flows. They typically grant investors substantive protections—such as through contentious fair and equitable treatment clauses, provisions protecting against expropriation without compensation, and national treatment, which requires host states to treat foreign investors no less favorably than their own. They also grant procedural rights to foreign investors, including the right to bring claims directly against host states through investor-state dispute settlement (ISDS) for introducing measures impacting their investment. This includes for introducing general laws or policies, such as new labor laws or environmental standards. 85 to 90% of the investment treaties currently in force are considered “old-generation” and are at urgent need for reform. Encouragingly, we see a growing number of reform initiatives across national, regional, and international levels. However, the powerful vested interests who profit from keeping the status quo, together with reform coherence challenges, remain significant obstacles to lasting, positive change. 

Many investment treaties with China were concluded in earlier waves of treaty-making—some dating to the 1980s and 1990s—when states had less awareness of how broad investor protections could constrain public interest regulation.

Governments participating in the Belt and Road Initiative would benefit from reviewing these investment treaties and, where appropriate, pursuing reform or renegotiation to bring them into line with more recent treaty practice, including clearer carve-outs to secure space for economic, social, climate, and other public interest policies. Even where domestic frameworks are strong, an outdated treaty can still expose a host state to unexpected claims after it has adopted new regulations.

Investor-state contracts are another binding “hard law” layer at the project level, where financing, construction, and operation terms are formally agreed. A construction contract for a bridge project, for instance, might specify payment milestones, construction schedules, and a dispute resolution forum—terms that are legally enforceable regardless of what any earlier MoU said. Getting these contracts right matters enormously, and governments should not wait until the contracting stage to start thinking about their terms.

The Soft Law Ecosystem: MoUs, policy frameworks, and creeping obligations

What makes the framework for the Belt and Road Initiative distinctive is its combination of a hard law “overcoat” and a layered hierarchy of soft law instruments, rather than a single, unified legal code. This ecosystem typically includes two main types:

• Non-binding MoUs: Broad political commitments that signal intent but lack specific enforcement mechanisms. A “Statement of Intent” to cooperate on a bridge project may contain no price tag, feasibility requirements, or timeline—and yet it can create a political expectation that the project will proceed with Chinese partners who are already informally identified. These documents may set the stage for more binding commitments downstream.
• Guiding principles and policy frameworks: High-level Chinese policy documents—such as the 2021 Guidance on Overseas Investment, Cooperation and Green Development—set expectations for SOEs without being legally binding on host states. An SOE might, for instance, reference the Green Investment Principles when presenting an environmental management plan, even though compliance with those principles is not contractually required. The result is a kind of soft accountability that does not translate into hard legal obligations—unless the host state later acts in reliance on those commitments.

A central challenge for developing countries engaging with large-scale infrastructure projects is what has been termed “creeping obligations”—the phenomenon by which early, non-binding political commitments gradually harden into binding commercial obligations. This dynamic is not unique to any single investment partner, but it is a structural risk whenever soft law instruments such as MoUs are used as the entry point for major projects. In the context of the Belt and Road Initiative, this risk is heightened where the host state also has concluded investment treaties with China. Without strong legal oversight at the MoU stage, governments may find themselves effectively committed to specific contractors, financing terms, or project structures before they have completed feasibility studies or environmental assessments.

That said, this dynamic is not unique to the Belt and Road Initiative. It mirrors patterns seen in investment contract negotiations more broadly. Governments should therefore set up early-stage internal coordination mechanisms, such as inter-ministerial committees that bring together ministries and agencies responsible for finance, planning, sectoral regulation, and project oversight. Such committees help consolidate negotiating positions, avoid contradictory signals to investors, and ensure that technical, financial, and legal considerations are aligned from the start.

The Multifaceted Identity of Chinese SOEs

The Belt and Road Initiative also stands out for the central role of Chinese SOEs, which often operate in multiple capacities at once: commercial actors seeking profit and market share, policy instruments executing industrial and strategic objectives of the Chinese government, and diplomatic tools strengthening bilateral relationships. A Chinese state-owned port operator might function as a commercial partner today, while its strategic decisions are shaped by state-level directives to prioritize specific trade routes over local profitability.

This multifaceted identity can create asymmetries in bargaining power. When a host government negotiates with a Chinese SOE, it may be unclear whether it is engaging a commercial partner or effectively be negotiating with the Chinese state itself. An SOE negotiating a power plant contract might simultaneously reference its commercial track record and its alignment with China’s national development strategies, making it difficult for the host government to distinguish corporate from state-backed motivations
 

The Belt and Road Initiative also stands out for the central role of Chinese SOEs, which often operate in multiple capacities at once: commercial actors seeking profit and market share, policy instruments executing Beijing’s industrial and strategic objectives, and diplomatic tools strengthening bilateral relationships.

 

For instance, most of China’s centrally administered, non-financial SOEs are supervised by the State-owned Assets Supervision and Administration Commission of the State Council (SASAC). SASAC performs the state-investor function on behalf of the State Council, the Chinese government’s highest decision-making body, and is mandated to preserve and increase the value of state capital. Senior leadership appointments at central SOEs are primarily handled by the Chinese Communist Party's Central Organization Department. However, even where central SASAC supervision applies, SOEs also retain separate legal personality and are not automatically equated with the Chinese state. 

In short, these SOEs have a dual identity which poses distinct practical legal implications. Consider a hypothetical: a Chinese SOE builds a major highway in a developing country. The SOE later falls short of the environmental standards agreed in the contract. The host government seeks to enforce those standards and withhold payment. At that point, a fundamental legal question arises: is the SOE acting as a commercial entity subject to the contract terms, or does its relationship with the home state, China, alter the legal analysis?

How this question is resolved has direct consequences. If the SOE is treated as a commercial actor, the host state’s remedies are primarily contractual—suing the SOE for breach of the project agreement. But if the SOE’s conduct is attributable to the Chinese state under international law, the same facts may also trigger state responsibility under international law. Conversely, where a host state takes action against an SOE whose conduct could be attributed to China, it may itself face counterclaims under an applicable investment treaty, brought by the SOE or China directly, or more generally, face other diplomatic repercussions. 

Above all, these pathways are not mutually exclusive, and the same facts may give rise to parallel contractual and investor-state proceedings. The legal pathway available depends entirely on how the SOE’s role has been characterized in the project documents—and whether state approvals, guarantees, or directives have been recorded.

The practical upshot for host states is straightforward: project documents should clearly specify the legal role of the SOE—whether it is acting in a sovereign or commercial capacity—and any state approvals, guarantees, or directives that could create or support treaty-level attribution should be carefully documented and reviewed before signature. This is not a mere technical housekeeping; it is a fundamental element of managing legal exposure in Belt and Road Initiative projects.

The Transparency Gap

The challenge posed by the opacity of agreements between the parties is common to other forms of cross-border investment, just as it is to investments under the Belt and Road Initiative. However this challenge carries heightened governance implications here given the scale of the Belt and Road Initiative and the wide variation in host-country regulatory environments.

Many contracts under the Belt and Road Initiative contain expansive confidentiality clauses, a pattern documented in research on Chinese overseas lending. They include “silent clauses” that prohibit the host country from disclosing the existence, terms, or even the amount of the loan, and "No Paris Club" clauses that prohibits the borrowing country from including that specific debt in any Paris Club restructuring. This lack of transparency has several practical consequences:

• Erosion of oversight: Legislatures and audit institutions cannot fully assess the scale of sovereign guarantees or contingent liabilities.
• Limited participation: Civil society and local communities are side-lined from environmental and social impact processes.
• Debt governance risks: Hidden fiscal exposures can accumulate and later manifest as debt crises.

What Host Countries Can Do

The hybrid nature of the Belt and Road Initiative creates unique governance challenges that cannot be addressed through any single instrument. It is the combination of soft political commitments, opaque contracting practices, and the multifaceted role of SOEs that can leave host countries exposed. What makes the Belt and Road Initiative distinctive—and what requires a response going beyond general investment advice—is this layered interaction between instruments that were designed to be non-binding and those designed as binding legal frameworks.

Domestic law remains the most powerful safeguard. As IISD’s Rethinking Investment Treaties and Rethinking National Investment Laws reports both emphasize, strong domestic frameworks form the foundation of sustainable investment governance. The Belt and Road Initiative context only confirms this: host states cannot rely on the non-binding character of MoUs or the goodwill of SOEs to protect them from hard legal consequences.

The hybrid nature of the Belt and Road Initiative creates unique governance challenges that cannot be addressed through any single instrument.

 

General recommendations (applicable to all investment):

1. Robust pre-investment assessments: Require technical, financial, and legal assessments before MoUs are signed—not after. This matters especially in the Belt and Road Initiative context, where early political commitments can harden into binding obligations faster than governments anticipate.
2. Standardized contracting tools: Develop or adopt sector-specific model contract clauses for use across investor-state agreements. This means leveraging existing model frameworks and adapting them to the specificities of Belt and Road Initiative projects—not reinventing the wheel, but ensuring that standard protections on transparency, local content, labour rights, environmental safeguards, and dispute resolution are built in from the start.
3. Cross-sectoral alignment: Ensure that every Belt and Road Initiative project is legally tied to national development plans, environmental statutes, and fiscal frameworks. Inter-ministerial committees that coordinate early and consistently—across finance, planning, sectoral regulation, and legal affairs—are essential to avoiding the contradictory signals and overlooked linkages that can create legal exposure later.
4. Review and reform investment treaties: Outdated investment treaties with China can expose host states to investment claims even where domestic frameworks are robust—because investors can rely on treaty protections regardless of domestic law. Governments should audit their treaty portfolio, identify provisions that unduly restrict their space to regulate in the public interest, and pursue reform or renegotiation where needed. Termination should also be considered as an option where reform is not feasible.

Recommendations specific to the Belt and Road Initiative:

1. Review MoUs for potentially binding language: Governments should conduct a systematic review of existing and proposed MoUs for the Belt and Road Initiative, screening for language that creates expectations, commits to specific partners or financing arrangements, or could later be relied upon as the basis for legal claims. Where possible, MoUs should include standard clauses explicitly clarifying that they create no binding legal obligations and do not constitute consent to investor-state arbitration. Legal counsel should be involved before signature, not after.
2. Clarify SOE status in contracts: Project contracts with Chinese SOEs should include express language specifying whether the SOE is acting in a sovereign or commercial capacity, and should document any state-level approvals, guarantees, or directives that connect the SOE’s actions to the Chinese state. This record-keeping matters for managing legal exposure in both directions: it protects the host state if it needs to establish state attribution, and it manages the risk of the SOE later claiming state immunity from contractual claims.

The flexibility of the Belt and Road Initiative can be a significant asset for developing countries—but only when paired with strong domestic systems that prevent creeping obligations and ensure transparent outcomes aligned with sustainable development. By reinforcing domestic legal frameworks, institutionalizing early-stage coordination across ministries, standardizing contracting practices, and taking specific steps to manage the distinctive risks of MoUs and SOE involvement, host states can strengthen their negotiation power and ability to engage with the Belt and Road Initiative on their own terms.

Globally and across the EU, public procurement is a powerful policy lever available to governments in their transition to a low-carbon economy. It is a force capable of shaping entire markets, incentivizing green technologies, and driving down emissions in high-carbon industries. The political ambition is real: the Paris Agreement, the European Green Deal, the Clean Vehicles Directive, the Energy Performance of Buildings Directive, and many others place explicit expectations on public buyers to procure greener goods and services.

Yet, ask any government today whether its procurement is actually delivering on those ambitions—in tonnes of carbon dioxide (CO₂) avoided, not in boxes ticked—and the honest answer is: we don’t know. The data infrastructure to change that is now emerging. In September 2024, the European Commission launched the Public Procurement Data Space (PPDS), a platform that for the first time brings together procurement data from Tenders Electronic Daily (TED), the official online platform for all EU procurement notices, and national systems into a single analytical environment. With EU procurement reform now gaining momentum, the window to close the gap between green ambition and action is open. Using data already flowing through the PPDS, we tested whether that gap can be closed without creating new reporting burdens. This article explains what is already possible, where the bottlenecks are, and what the EU should do now.
 

Measuring intent, not impact

The way green public procurement (GPP) is currently monitored is telling. Most systems, including the European Commission’s PPDS, track whether a contracting authority declared an environmental objective. The “strategic procurement” dashboard reports the share of procurement procedures tagged as ‘‘reduction of environmental impacts.’’ It does not, and currently cannot, tell you whether those procedures reduced emissions or led to any other impacts.

To understand the gap, it helps to think about GPP monitoring in three layers. The first is institutionalization: whether the right policies and tools are in place, such as national action plans, criteria libraries, and training for buyers. The second is outputs, or procurement activity: how many tenders included environmental criteria, in which sectors, and at what value. Most monitoring systems, including the PPDS, operate at this level. The third layer is about actual environmental outcomes: tonnes of CO₂ avoided, water conserved, materials diverted from landfill, and energy saved. 

 

Source: Erizaputri, Bechauf, and Casier, 2024

The latter is what ultimately matters for understanding real progress on procurement’s contribution to climate policy, and unfortunately, measurement at this level remains very limited today. This is not a minor technical limitation. It is a fundamental constraint on the evidence base that governments and the European Commission need to make informed decisions. Without knowing whether green public procurement is delivering real-world results, governments cannot scale what works, fix what does not, or convince suppliers to take environmental requirements seriously. 

The result is a missed opportunity of significant scale. Public procurement has the buying power to drive market transformation. But without the tools to measure its impact, it functions more as a checkbox exercise than a strategic instrument. 

The data to start fixing this already exists

The OCP and IISD recently examined this question more closely.  Our starting hypothesis was that the data needed to measure the environmental impact of public procurement is, to a large extent, already being collected; it is simply not being used for that purpose.

We examined whether the procurement data already flowing through the PPDS and TED data ecosystems could be combined with established environmental impact modelling approaches to generate meaningful estimates of carbon emissions and potential savings, crucially, without imposing new reporting burdens on contracting authorities.

We focused our pilot on two sectors that have high-volume procurement and are strategically central to Europe’s climate agenda: construction works (linked to the Energy Performance of Buildings Directive, and relevant to the Construction Products Regulation and Industrial Accelerator Act) and vehicles (linked to the Clean Vehicles Directive). We used German contract award data as our test case. For each contract, we looked at how much was spent and applied known figures for how much CO₂ that sector typically produces per euro spent. This approach—known as spend-based estimation—is not the most precise method available, but it is the only one that works with the data currently flowing through the PPDS, which lacks the detailed quantity and unit information that more accurate methods would require.

What follows is an overview of what the current PPDS gave us to work with. It reveals the current state of structured data, what is achieved today, and most importantly, the scale of the opportunity currently left untapped.

Source: Authors' compilation

We started with 2.5 million procurement rows available in the PPDS. The full PPDS dataset covers the period of July 2018 to December 2025. However, the analysis relied on data downloaded directly from TED due to missing variables in PPDS. The TED notices used for Common Procurement Vocabulary (CPV) 34 (vehicles) cover October 2023 to January 2026 and for CPV 45 (construction works) October 2023 to March 2026.

Because almost no contracts included data on quantities or units—for example, how many vehicles were bought or how many square meters were built—we could only use contract values to estimate emissions. Even for this method, missing and inconsistent sub-classification fields meant that isolating the specific contracts relevant to each sector required aggressive filtering: the usable motor vehicle sample shrank to just 125 contracts, and the construction sample to 5,623 records. This is a direct reflection of the current state of structured procurement data across the EU, and it is precisely the gap this analysis sets out to make visible. 

What the numbers tell us

In the construction works sector, public procurement already tagged with green criteria delivers an estimated saving of more than 42 million kg of CO₂e relative to a conventional construction baseline. That is a meaningful contribution, but it represents only a fraction of what is possible.

When we modelled what would happen if all procurement were tagged as green in our sample (the overwhelming majority of the spend), the estimated additional savings reached approximately 898 million kg CO₂e. That is more than 21 times the savings currently achieved by the green-tagged contracts.

The motor vehicles sector tells a similar story. Assuming that only battery electric vehicles are bought under GPP, applying green criteria to the rest of our vehicle sample would have yielded an additional saving more than five times larger than what the existing green-tagged contracts already deliver.

These figures are illustrative, not definitive. But even as order-of-magnitude estimates, they make a powerful point: the environmental potential embedded in public procurement is vastly larger than what current green procurement practices are unlocking. And we can begin to see it—and measure it—using data that governments are already collecting.

A solvable problem, not an insurmountable one

The data gaps we identified are real, but they are not insurmountable. The chain that connects data to impact is straightforward: better data creates visibility into what procurement is actually delivering; visibility enables accountability for buyers, policy-makers, and suppliers; accountability drives more ambitious and consistent application of green criteria; and more green procurement translates into real environmental impact—lower emissions, less waste, and more sustainable use of resources. Closing the data gaps is therefore not a technical nice-to-have—it is a prerequisite for public procurement to be the strategic lever everyone expects it to be. Progress toward EU-wide environmental impact tracking does not require rebuilding procurement data systems from scratch. It requires targeted, proportionate improvements to what already exists. Specifically, our analysis points to two concrete actions that could substantially improve the analytical power of the PPDS without requiring changes to the existing data collection infrastructure. 

• First, the use of environmental objective tags in eForms, particularly the “Reduction of environmental impacts” designation, should be clarified through binding guidance so that it is applied consistently across member states.
• Second, for procedures that are already flagged as environmentally strategic, item-level data should be strengthened. This means making structured reporting of quantities, units, and additional classification codes mandatory, using controlled vocabularies aligned with procurement classification codes.

The path from the current state to routine EU-wide environmental impact monitoring is incremental rather than transformational. What it requires is not new technology or new reporting systems (at least not immediately), but disciplined use of the infrastructure that European institutions and member states have already built, combined with the tools to turn that data into useful policy insight.

 

We propose a phased implementation roadmap. 

 

In the short term, impact tracking should be extended to a limited set of high-impact priority sectors beyond vehicles and construction, such as computers and energy efficiency, using methodologies that rely on already available structured data: product classification codes, contract values, and buyer country. This phase should prioritize testing and refining the methodology using existing PPDS datasets.

In the medium term, impact indicators should be introduced within the PPDS as experimental “beta” dashboards, clearly labelled as estimates and accompanied by plain explanations of how they were calculated. During this phase, member states can be encouraged rather than required to strengthen item-level data for procedures with explicit environmental objectives, including more detailed product classifications and structured reporting of quantities and units.

In the long term, once data completeness and consistency are sufficiently improved, environmental impact indicators can become core PPDS outputs, supporting routine policy monitoring, benchmarking, and evaluation of Green Public Procurement targets at both EU and national levels.

Source: Authors' compilation

An invitation to act

The procurement data infrastructure to track public spending in Europe is in place. And the methodology to measure real-world impact has been demonstrated. What is needed now is the commitment from the European Commission, the European Parliament, and EU member states to close the gap between the data being collected today and the insight it could generate by scaling these approaches across Europe, embedding impact tracking into the PPDS and national procurement ecosystems, and equipping public buyers with the tools to see and improve the environmental performance of their spending. When reforming the EU’s procurement rules, monitoring the results must not be an afterthought. Every euro of public spending has environmental consequences, whether or not they are measured. The question is whether governments choose to know those consequences and act on that knowledge.
 

The detailed technical report with the data and methodology used for this analysis is available upon request. Contact: [email protected]
 

When energy costs spike, it is households and businesses who pay the price. From homes cooking with liquefied petroleum gas (LPG) in India to drivers of mass transit jeepney vehicles in the Philippines, the human cost of energy insecurity is visible in every crisis.

And these crises are not exceptional: the world has experienced roughly one major oil price shock per decade since the 1970s. Most recently, the closure of the Strait of Hormuz has triggered what is now the largest oil supply disruption ever, pushing crude above USD 100 per barrel.

The choices governments are making today will shape their fiscal exposure and energy vulnerability for decades to come. When prices spiked in the wake of Russia's invasion of Ukraine, global public support for fossil fuels shot up by over USD 750 billion to a record USD 2 trillion. Many governments introduced measures that proved politically sticky and hard to unwind—North America's petroleum subsidies, for instance, were still running at six times their 2021 levels in 2024.

The cycle of price shock, subsidy response, and entrenched dependency can only be interrupted by actively redirecting fiscal flows toward cleaner, more resilient energy systems. In the short term, governments should prioritize targeted social protection over blanket fossil fuel subsidies. In the short and medium terms, better aligning all public finance with transition goals can structurally reduce exposure to future shocks, lower energy bills, and build more resilient systems. Together, these shifts would allow governments to shield households and businesses today while reducing the likelihood and severity of the next crisis.

To understand how public financial support for energy is currently directed, we analyzed government subsidies, state-owned enterprise capital expenditure, and international public finance across G20 economies between 2020 and 2024—mapping where the misalignment is greatest, where momentum is already building, and what it would take to shift the balance. 

Note: Fossil fuel subsidies data covers 195 economies. Data for government renewable energy support, state-owned enterprises capital expenditure, and international public finance is limited to G20 economies. For definitions and more details on the data collection for the different elements of public financial support for energy, please refer to our Public Financial Support for Energy webpage.

Fossil Fuel Subsidies: Declining but likely set to rebound

The most recent comprehensive estimate of subsidies is for 2024, when governments allocated USD 921 billion. We can anticipate, however, that the subsidy allocations in 2026 will skyrocket. Fossil fuel subsidy totals tend to track global oil prices. With crude oil prices rising above USD 100 per barrel in April, there is a strong likelihood that subsidies will rise substantially as governments implement measures to shield consumers from price shocks. In 2022, in the aftermath of Russia’s invasion of Ukraine, subsidies reached a historic peak of USD 1.7 trillion.

Consumption subsidies are usually untargeted and benefit the wealthy, who consume the most energy, more than anyone else. They are typically extremely costly, taking up resources that could have been used to address other priorities, like health, education, and infrastructure investments. And they further lock in fossil fuel consumption and production, leaving households and businesses just as vulnerable to the next price shock.

Energy consumers are the target for 90% of subsidies—approximately USD 862 billion in 2024. Subsidies for producers are estimated to have been around USD 43 billion in 2024, which is likely an underestimate due to the lack of transparent data. Though modest in scale relative to consumer subsidies, their impact is outsized: governments tend to use producer subsidies to crowd in private investment, unlocking higher production and reinforcing fossil fuel reliance.

The latest IEA data show that, as of April 7, 2026, around 43 countries have implemented support measures in response to the current energy crisis, including fuel price caps, direct subsidies, or tax cuts on petroleum products and natural gas.

The good news is there are tested alternatives that support people, not fuels. Countries have responded to previous price shocks with targeted cash transfers, cost-of-living payments, and energy assistance for lower-income households. In response to the current energy crisis, Egypt, Thailand, and South Korea—are providing targeted support measures and strengthening of social protection rather than with blanket subsidies. These types of programs protect purchasing power while encouraging energy efficiency and a shift to clean alternatives. Using fossil fuel revenues to provide such alternatives—including electric vehicles, heat pumps, household solar and batteries, induction cooking, and public transport—can help consumers decouple energy bills from volatile international markets.

Support for Renewable Energy: Still lagging behind fossil fuels

G20 governments’ financial support for renewable energy has been relatively stable between 2020 and 2024, reaching an estimated USD 169 billion.

About three-quarters of this support was technology neutral within renewable energy types in 2024, while solar and wind continued to attract the bulk of dedicated capital.

Japan and the United States were the leading contributors, with combined spending of approximately USD 81 billion. However, U.S. support may show a different picture for 2025–2026, as policy changes have tightened eligibility for tax credits, introduced budget cuts, and made incentives more conditional, contributing to a decline in solar installations in 2025.

China has sharply reduced its renewable financial support from its 2022 peak of about USD 66 billion to around USD 15 billion in 2023. That peak, however, was an anomaly driven by a one-off effort to clear accumulated payment arrears under their feed-in-tariff system. The reduction also reflects a broader, ongoing shift toward more market-oriented support mechanisms.

State-Owned Enterprises: Increased renewable investment amid fossil dominance

Globally, energy state-owned enterprises (SOEs) are responsible for over 50% of oil and gas production and 60% of coal production and coal power generation. Investment decisions by SOEs not only shape energy production, but also national energy security, government revenues, employment, and, in many cases, vital community services.

For these firms, a continued focus on fossil fuels creates financial, security, and environmental risks that are borne by the public, neglecting opportunities to meet their public service obligations through a diverse energy supply. The current fossil price spikes are likely to accelerate the clean energy transition, and SOEs that invest in fossil fuel infrastructure will be increasingly exposed to stranded asset risks.

Governments should direct energy SOEs to invest in solutions that improve national energy independence and SOEs’ financial health. These include renewable energy installations, grids, battery and storage systems, as well as electrification.

Energy SOEs in G20 countries are mostly struggling to realign their capital expenditures (CapEx) with energy transition priorities. In 2024, they spent over USD 360 billion on energy CapEx—covering the acquisition, construction, and upgrading of physical assets across fossil fuels, renewable energy, and electricity transmission and distribution (T&D) networks. Around 81% of this investment (amounting to over USD 290 billion) funded fossil fuel infrastructure, and only the remaining 19% went to renewable power, T&D, and storage technologies.

The contrast with broader global energy investment trends (both public and private) is striking: in 2024, renewables, T&D, and storage received over USD 1.2 trillion in investments, as opposed to over USD 1.1 trillion going to fossil fuels. This suggests that many SOEs are transitioning away from fossil fuels at a slower pace than other global actors, often due to a lack of clear transition mandates from their governments.

Yet different types of SOEs face different transition challenges. Renewable energy CapEx has grown gradually, from USD 22 billion in 2020 to approximately 39 billion in 2024. The shift is most pronounced among state power and coal companies, whose renewable CapEx grew by 68% between 2020 and 2024, as opposed to a 49% growth in their fossil CapEx. A few countries have been leaders in this transition, primarily China (73% of the total increase), and to a lesser extent India (14%) and France (10%).  

National oil companies (NOCs) continue to face significant transition challenges and account for the majority of SOEs’ fossil fuel CapEx between 2020 and 2024. NOCs often serve as the primary source of fiscal revenues for national governments and provide social services and employment in areas of operation. This makes NOCs’ transition pathways inseparable from strategies for national economic diversification and transitioning away from fossil fuels.

Disaggregating renewable energy financing by technology type remains difficult due to inconsistent reporting, but available data point to some clear trends. Solar photovoltaic has seen consistent growth, with average annual increases of 50% between 2020 and 2024. Wind investments, meanwhile, declined between 2020 and 2022 before recovering slightly in 2024—mirroring global trends and reflecting challenges faced by wind developers as inflation and borrowing costs rose sharply in 2022–2023.

The installation of more renewable energy capacity is being accompanied by a notable uptick in spending on T&D infrastructure. This is crucial to integrate variable renewable sources, as well as to accommodate increasing electricity demand from electrification. Among tracked SOEs, T&D spending almost doubled from around USD 16 billion in 2020 to over USD 30 billion in 2024. Most of the increase was driven by Saudi Electricity Company’s USD 13 billion investment in grids, reflecting the country’s ambition to source 50% of its electricity from renewables by 2030 followed by clean investments by South Korea’s KEPCO, Indonesia’s PLN and France’s EDF, among others.

International Public Finance: Right direction, but still missing speed

Over the past decade, G20 governments and major multilateral development banks have provided an average of over USD 100 billion each year in international finance for energy projects. Since 2016, fossil fuel financing has been trending down (reaching USD 37 billion in 2024), while clean energy financing has seen a steady increase (rounding at USD 47 billion in 2024), partly due to the successful implementation of the Clean Energy Transition Partnership commitment by 40 governments to end international public finance for fossil fuels and redirect it toward clean energy.

While the trend has been generally positive, international public finance can and should do more. This is especially true in light of the key role it can play in catalyzing investments in clean energy for improved energy security, reducing vulnerability to volatile fossil fuel markets.

Redirecting Finance in a Volatile World

Public financial flows remain fundamentally misaligned with climate and energy security goals—and the social costs of staying on the current path are mounting. 

Energy crises do not affect everyone equally: they hit low- and middle-income households hardest, erode purchasing power, and force trade-offs between essential needs like food, transport, and heating.

 

Past crises have shown a consistent pattern: governments respond to price spikes with expanded fossil fuel support, particularly subsidies, to shield consumers. Yet these measures are often inefficient and regressive—disproportionately benefiting higher-income groups while locking in fiscal burdens that ultimately fall back on taxpayers. Over time, they entrench fossil fuel dependence and leave households exposed to the next shock.

Breaking this cycle requires a deliberate shift in how public finance is deployed. Governments should:

1. In the short term, prioritize targeted social protection over blanket fossil fuel subsidies—especially during the ongoing crisis. Measures like cash transfers, cost-of-living support, and energy assistance for low-income households can protect purchasing power quickly and fairly, without locking in costly and regressive subsidy schemes.
2. In the medium term, use public finance to structurally reduce exposure to future shocks. Scaling up investment in clean energy and electrification—while aligning subsidies, state-owned enterprise investments, and international public finance with transition goals—can lower energy bills, reduce volatility, and build more resilient systems over the long term.

Without this shift, governments risk reinforcing a cycle in which each crisis deepens inequality and fiscal pressure. With it, they can shield households and businesses and reduce the likelihood and impact of future crises—building energy systems that are not only cleaner, but fairer and more secure.

Despite continued global investment in fossil fuel expansion, many governments are adopting policies that restrict, pause, or prohibit new fossil fuel production. These measures, ranging from moratoria on oil and gas licensing to bans on coal mining or fracking, reveal a growing willingness to engage with the supply side of the fossil fuel transition.

At the same time, short-term cycles of high oil and gas prices can create strong incentives to delay, weaken, or reverse such measures to expand production. Yet such reversals will not solve the problem of high oil and gas prices. In the United Kingdom, for example, data from Rystad Energy’s UCube shows that British projects licensed in the last 20 years have taken on average 9 years to start producing. More exploration will not relieve energy pressures now. In addition, the continued growth in production restrictions over the past decade, despite the 2022–2023 energy crisis, suggests that an increasing number of governments are beginning to look beyond these short-term signals. Instead, they are designing policies with long-term demand trends in mind, including the prospect of declining fossil fuel use and the risks of stranded assets.

Drawing on a new global database of fossil fuel production restrictions, this insight explores what these policies look like in practice, where they are emerging, and what their strengths and limitations tell us about the politics of managing decline.

Rather than reflecting a single coordinated shift, the evidence points to a fragmented but expanding policy landscape.

Headline Findings

50 Places Saying No to Expansion

The database shows a steady rise in fossil fuel production restrictions since the 1970s and a sharp rise since the 2010s. The last 2 years show a temporary dip, largely reflecting a wave of rollbacks linked to the repeal campaign launched by the Trump administration during his second term.

The database identifies dozens of active restrictions (58 in total) on fossil fuel production across 25 countries and 27 subnational jurisdictions across four continents. These include bans on new coal mining, moratoria on oil and gas licensing, and prohibitions on specific extraction techniques, such as fracking or specific areas (e.g., offshore exploration). While the scope of these measures varies widely, their existence signals that supply-side interventions are becoming a normalized, even if contested, policy option.

While climate mitigation is increasingly cited, many measures are grounded in broader environmental protection, water safety, land-use planning, or social issues.  

In several cases, economic considerations also reinforce the case for restrictions. Many of the jurisdictions where restrictions have been introduced (e.g., frontier offshore areas, seismically active zones, or environmentally sensitive ecosystems) are also among the highest-cost locations for fossil fuel extraction. This means the expected economic returns are often uncertain or dependent on sustained high commodity prices. Also, in many of these areas, fossil fuel extraction could undermine other commercially viable activities (e.g., fishing in the Lofoten islands). As a result, cost–benefit assessments favour those precautionary restrictions.

By locating the regulation in a wider series of environmental, economic, and social issues, these considerations have sometimes enabled governments to act where explicit climate-based restrictions might have faced stronger opposition. For instance, many restrictions in the database refer only to specific extraction methods that are considered risky (e.g., fracking) but de facto mean an entire stop to exploration and new fossil fuel projects in regions where the costs of extracting the resources without those methods are too high.  

Increasing Numbers of Restrictions

National-level restrictions remain relatively limited in number but are increasingly visible globally. These measures typically take the form of bans or moratoria on new exploration and licensing (e.g., Belize, France, or Costa Rica), restrictions on specific extraction methods like fracking (e.g., Bulgaria, United Kingdom, or Uruguay), or prohibitions in designated areas (e.g., the Arctic in Canada, or the Great Lakes in the United States).  

Interestingly, the number of restrictions follows an exponentially growing trend over the past decade despite high oil and gas price cycles observed in this period (e.g., the price spikes observed following Russia’s invasion of Ukraine), which can reinforce pressures to expand production or roll back existing restriction policies. This suggests that an increasing number of governments are beginning to look beyond misleading short-term market signals and enact policies with long-term demand trends in mind, including the prospect of declining fossil fuel use and the risks of stranded assets, the increasing importance of protecting ecologically sensitive regions, and the need to accelerate climate action both on the demand and supply side.

Importantly, many of the countries adopting such measures are early movers in international supply-side climate initiatives, including members of the Beyond Oil and Gas Alliance. These governments have combined domestic production limits with international advocacy for a managed phase-out of fossil fuels. While their share of global fossil fuel production is small, their policies play an important role in establishing norms and policy precedents on supply-side action.

Subnational Governments Are Central Actors

A significant share of active measures originates from 27 states, provinces, or regions of nine countries. Subnational authorities have often moved first, faster, or further than national governments, particularly where political or legal constraints limit action at the centre or in countries where administrative and legal autonomy on natural resources management is ample for subnational governments. For instance, some Canadian provinces have restricted oil and gas exploration in their jurisdiction or in specific areas of high natural or cultural significance despite a traditional support to the oil and gas sector at the national level.  

In some cases, regional bans or restrictions have preceded or catalyzed national debates on fossil fuel phase-out. For instance, in the United Kingdom, Scotland (2015) and Wales (2018) enacted bans on fracking, which opened the way for a national ban in 2019, and started a conversation on fossil fuels, which culminated in much more ambitious regulation in 2025 aimed at stopping new licensing for oil and gas altogether.

Measures Evolve in Two Directions

Policies restricting fossil fuel production tend to evolve along two distinct trajectories. In some jurisdictions, initial measures have been maintained over decades or even progressively strengthened by embedding them in stronger legal instruments. One example is the protection of the Lofoten Islands in Norway, which has been maintained since 2001 by successive governments. Progression in stringency can be seen in examples like the offshore Arctic oil and gas licensing ban in Canada, which started as a joint leaders' statement in 2016 and was elevated to an executive order in 2019.  

In other cases, however, restrictions have been weakened, allowed to expire, or fully repealed. We found that 15 policies that had been enacted to restrict fossil fuel production have been rolled back or repealed (sometimes in several repeal/reenactment cycles). Repeal processes often follow changes in government, energy security concerns, or legal challenges, underscoring the political fragility of production limits.

Current high oil and gas prices could create incentives to delay, weaken, or reverse measures in the name of energy security or fiscal gain, which highlights the importance of actively defending existing policies against short-term political pressures and misleading narratives. Rather than being taken for granted, these measures require continued political support, clear communication of their long-term benefits, and integration into broader transition strategies to ensure they are not easily undone.

These divergent trajectories highlight both the growing experimentation with supply-side climate policies and their political fragility. Whether restrictions endure or are rolled back frequently depends on the ability of countries to sustain political momentum and societal support around the transition away from fossil fuels, legal design, and institutional embedding.

The Legal Battleground

Our database shows that several of the repeals are currently being challenged legally.  This shows that if governments want to leave open the door to policy continuity beyond their term, they should aim at enacting stronger policy instruments (e.g., executive decrees, agreements, or regulations) instead of simple policy statements. Those stronger instruments can open the door for other civil society actors to take legal action against rollbacks and repeals. For instance, in the United States, several federal fossil fuel production restrictions from the Obama and Biden administrations have been rolled back by the Trump administration but are currently subject to litigation, stopping (or at least delaying) new investments in fossil fuel exploration and infrastructure.

Another factor that can shape the durability of fossil fuel production restrictions is the risk of claims under investor–state dispute settlement mechanisms embedded in many international investment agreements. Companies holding exploration licences, production permits, or related investments may argue that new bans or moratoria violate treaty protections such as fair and equitable treatment or protection against indirect expropriation. Even where governments ultimately prevail, the prospect of costly arbitration can create a “regulatory chill,” discouraging policy-makers from adopting or strengthening production limits. Previous research by the International Institute for Sustainable Development highlights several ways governments can reduce this risk while preserving policy space for climate action, ensuring a legally sound oil and gas phase-out.

Why This Matters Now

These findings are particularly salient in the context of growing international attention to fossil fuel supply, including upcoming discussions at the First International Conference on Transitioning Away from Fossil Fuels in Colombia, and broader efforts to operationalize a TAFF at the 31st United Nations Climate Change Conference and beyond.

Transitioning away from fossil fuels requires both demand- and supply-side action. Yet international frameworks have struggled to meaningfully address production, leaving domestic governments to navigate this terrain largely on their own (with a few exceptions such as Just Energy Transition Partnerships, Beyond Oil and Gas Alliance, and the Organisation for Economic Co-operation and Development’s EFFECT framework). The examples in the database demonstrate that such action is politically possible.

At the same time, they also highlight how fragile and contested these measures remain, particularly in periods of high energy prices and geopolitical uncertainty like the ones we are living in now. The prevalence of repeals offers a cautionary lesson. Without stronger coordination and sustained political commitment, there is a real risk that short-term pressures could lead to the rollback of existing policies, slowing progress and undermining efforts to align fossil fuel production with long-term climate goals. A way to prevent such repeals and entrench the restrictions would be via agreements between different jurisdictions. There are important precedents for this approach. The Antarctic Treaty System demonstrates how countries can collectively designate areas of exceptional ecological value as being off-limits to mineral resource development. Building on similar principles, initiatives such as the Fossil Fuel Non-Proliferation Treaty Initiative are advocating for international cooperation to halt the expansion of fossil fuel production and support a managed phase-down.

Governments can pursue bilateral agreements to lock in the measures, especially if they share borders of the no-go zones for fossil fuel exploration and production, e.g., in the Arctic or the Amazon. When neighbouring countries or regions commit jointly to protect certain areas from fossil fuel exploration and production, the political and economic incentives to roll back restrictions can be significantly reduced. Moreover, shared commitments to prohibit exploration in sensitive regions could help ensure that protections are applied consistently across jurisdictions, preventing a “race to the bottom” in which production shifts to the least regulated territory.

There is an urgent need to advance an international agenda focused on coordinated protection of key ecological areas, the closing of the fossil fuel production expansion frontier, and the development of mechanisms for a gradual, managed, and equitable decline in global fossil fuel output. As attention grows around how to operationalize such a TAFF, understanding how production limits work in practice has become increasingly important. The database compiled for this analysis provides a first systematic overview of existing, expired, and repealed restrictions on fossil fuel production worldwide, offering policy-makers and researchers a concrete evidence base to draw from. 

Introduction 

Multilateral trade cooperation is under strain, and the World Trade Organization (WTO) Fourteenth Ministerial Conference (MC14) will show whether it can adapt. As ministers gather in Yaoundé for MC14, they face a trading system pulled in many directions at once: climate imperatives, digital transformation, renewed industrial policy, food security concerns, and mounting geopolitical fragmentation. Expectations for sweeping new deals are modest. The real test is whether governments can steady the system, advance unfinished work, and agree on a clear and credible agenda for reform in a rapidly changing global economy. 

In this issue of the Trade and Sustainability Review, members of IISD’s trade team examine the pressure points shaping MC14, and what is at stake if cooperation falters. Alice Tipping opens with the reform debate itself, asking how decision making, fairness, and special and differential treatment must evolve if the organization is to remain relevant. Satish Triplicane and Ieva Baršauskaitė explore the resurgence of industrial policy, where subsidies, local content requirements, and export restrictions are stretching rules designed for a different era. Rashid S. Kaukab turns to electronic commerce, unpacking divisions over the moratorium on customs duties on electronic transmissions, the Work Programme on Electronic Commerce, and the future of the Joint Statement Initiative, the plurilateral agreement on electronic commerce. 

Other contributions also focus on negotiations that remain unfinished but consequential. Rashmi Jose analyzes the proposed incorporation of the Investment Facilitation for Development Agreement and debates over its legal status and development promise. Florencia Sarmiento assesses progress—and gaps—on negotiations towards additional disciplines for harmful fisheries subsidies that would build on the landmark 2022 Agreement on Fisheries Subsidies inked at MC12. Facundo Calvo reviews the WTO's agriculture talks, highlighting pathways that matter the most for least developed countries. Moving outside the negotiations space, Ieva Baršauskaitė and Antoine Bonnet trace the growing intersection of trade and climate, from border carbon adjustments to transparency discussions at the WTO and climate forums. 

Taken together, these articles reveal a common thread: trade rules are being tested by new economic realities, rising geopolitical tensions, and shifting development priorities. MC14 may not deliver major breakthroughs, but it can help clarify priorities and reinforce the WTO’s role as a forum for evidence-based dialogue and inclusive rulemaking. 

Happy reading, 

Maria Barral

Articles 

“World Trade Organization Reform” is the headline issue at the 14th Ministerial Conference, but what does it mean, and what are we likely to see? 

Alice Tipping explores WTO reform at MC14, focusing on decision making, rules for fair competition, and support for developing countries, highlighting how ministers can lay the groundwork for future reforms. 

Read article here. 

Old Rules, New Realities: How industrial policy is shaking up global trade

Modern industrial policies are rubbing up against WTO rules. Satish Triplicane and Ieva Baršauskaitė examine the issues at play in discussions of the balance between trade rules, development and climate objectives. 

Read article here. 

Electronic Commerce at the World Trade Organization: Can members find common ground at the 14th Ministerial Conference? 

E-commerce is central to global trade, but WTO members remain divided on digital trade rules. Rashid S. Kaukab explores debates over the moratorium on customs duties, the WPEC, and the potential incorporation of the JSI Agreement at MC14, with implications for developing countries. 

Read article here. 

The World Trade Organization Investment Facilitation Agreement in the Run-Up to the 14th Ministerial Conference 

The potential incorporation of the Investment Facilitation for Development Agreement into the WTO framework is a key issue at MC14. Rashmi Jose explores its investment facilitation commitments, capacity-building provisions for developing countries, and the debates over its legal and plurilateral status. 

Read article here. 

Fisheries Subsidies at a Crossroads: Why MC14 could determine the future of ocean sustainability 

Ahead of MC14, WTO members must decide whether to advance additional disciplines on overfishing and overcapacity, building on the 2022 Fisheries Subsidies Agreement. Florencia Sarmiento highlights the implications for ocean sustainability and the communities that depend on fisheries. 

Read article here. 

World Trade Organization Agriculture Negotiations at the 14th Ministerial Conference: Where do things stand, and where is progress for least developed countries possible? 

Facundo Calvo reviews key WTO agriculture negotiations ahead of MC14 and identifies the areas where progress is possible for LDCs, while highlighting informal dialogues on sustainable agriculture. 

Read article here. 

International Conversations on Trade and Climate: From the World Trade Organization to the United Nations Framework Convention on Climate Change

Ieva Baršauskaitė and Antoine Bonnet examine recent WTO and COP 30 discussions, including work in the Committee on Trade and Environment and the Trade and Environmental Sustainability Structured Discussions, showing how MC14 can consolidate these debates and guide the next steps for multilateral cooperation. 

Read article here.

Affordable, reliable energy matters because it affects whether households can pay their bills and businesses can prosper—but too often governments respond to energy shocks by managing the symptoms of insecurity while reinforcing dependence on volatile fossil fuel markets. Almost USD 5 trillion in public money has been poured into fossil fuels since 2020, which only perpetuates the problem. 

The long-term solution to energy security is just the opposite—reforming fossil fuel subsidies in ways that improve all “4 As” of the energy security: availability, accessibility, affordability, and acceptability. It needs to be done carefully, but it is achievable and can deliver rapid benefits for consumers, government budgets, and reduced pollution. 

Affordability: Canning gasoline and diesel consumption subsidies

Most fossil fuel subsidies arise from governments capping prices on gasoline, diesel, and liquefied petroleum gas. It may seem impossible that removing these price controls could improve affordability, but hear me out. 

The answer requires looking at the big picture of opportunity costs and long-term trends. 

Phasing out consumer subsidies would save over USD 800 billion globally (based on 2024 data). The revenue could be used to support vulnerable consumers, help businesses cope with higher energy prices, and create an incentive for consumers to improve energy efficiency and switch to cleaner alternatives. The money could also be used to fund alternatives like public transport, cycling, and pedestrian infrastructure, as well as electric vehicle (EV) affordability. 

If the future is anything like the past or present, we can expect persistent volatility and uncertainty in fossil fuel markets, driven by geopolitical tensions and trade disputes, not to mention added premiums from carbon and pollution taxes in many countries.

On the other hand, a future with cheap EVs powered by low-cost renewables is already within sight. Prices for solar modules and lithium-ion batteries have fallen by more than 90% since 2010, while wind turbine prices have fallen by 49%–78% over the same period. On a total cost of ownership basis—including purchase price, fuel, maintenance, etc.—many EVs are already competitive or cheaper than conventional vehicles, especially 2- and 3-wheelers and high mileage cars. In China, two thirds of EVs sold in 2024 were priced lower than their conventional counterparts, even without purchase incentives. 

Other segments are catching up fast, including long-haul heavy trucks and low-mileage private cars, with most credible analyses expecting parity this decade, driven by declining battery costs, higher fuel prices, and tightening emissions rules. Obviously, local costs, subsidies, and vehicle types play a big part in cost competitiveness. 

EV sales overtook internal combustion engine vehicles in the European Union for the first time in 2025. In China, EVs are approaching 50% of new car sales. Surprisingly, in December 2025, battery-electric heavy-duty trucks accounted for over half of new sales in China, a segment previously considered unlikely to transition due to challenges related to weight and range.

Fortescue, one of Australia’s largest iron ore producers, has set a target to eliminate emissions from its Australian land-based iron ore operations by 2030, including by switching to 100% EV trucks and renewables. More companies would follow their lead if the government removed the generous fuel tax rebate that is maintaining the status quo, despite changing economics and company values.

There is already evidence that the subsidy shift can work. India phased out petrol and diesel subsidies starting in 2010 and ramped up support for EVs. The result was a dramatic uptake of 2- and 3-wheeler EVs and a growing appetite for EV cars. Sales of electric cars in India increased by 45%, from 2024 to 2025.

EV uptake can also reduce dependence on imported fossil fuels. Replacing all imported oil for road transport globally with EVs would cut dependency on imported energy by a third.

Availability: Subsidizing fossil fuel production is like trying to dig yourself out of a hole 

Many countries face recurrent rounds of disruptions in fossil fuel supply chains. Conflicts, sanctions, and trade wars are constantly ambushing global markets, driving unpredictable spikes in prices, and making long-term fossil fuel infrastructure investments increasingly risky. 

Pouring money into shoring up fossil fuel supplies has been standard practice. In 2024, at least USD 43 billion was spent on subsidies to fossil fuel production, plus around USD 300 billion in investments by state-owned energy enterprises and another USD 37 billion in international public finance. How can removing these supply-side subsidies help energy security? 

Instead, governments' state-owned enterprises and finance institutions need to invest in renewable energy and storage to diversify the domestic power supply. They need a technology-neutral approach to energy security. 

Once installed, renewables and batteries provide price-stable domestic power for more than 20 years. Adding solar, wind, and storage diversifies the energy mix, improving resilience. The number one golden rule of energy security is diversification, according to Fatih Birol, head of the International Energy Agency, the world’s leader on energy security.

Unlike fossil fuels, renewable power is usually produced domestically and therefore directly benefits national energy supplies. 

 

Even for producer states, fossil fuels—particularly oil and gas—are frequently sold on international markets at international prices and sometimes provide little or no benefit for domestic energy independence or affordability. For example, Nigeria is a major producer of crude oil, of which 97% is exported; meanwhile, 100% of petroleum products are imported, creating a major energy security vulnerability. 

Many forms of clean energy, including storage, are already cheaper on a levelized cost basis than fossil equivalents. However, integration costs and long-term storage often require government support. It is to these areas that governments can redirect fossil fuel support to lay the foundations for a modern, clean, reliable energy system. Governments do not need to foot the whole bill—they can crowd in private investment with incentives, public finance, loan guarantees, and public–private partnerships, and by creating a stable policy environment for investors. But first, they need to phase out fossil fuel subsidies to encourage the shift. 

Accessibility: The distributed energy revolution

Over 700 million people currently lack access to electricity, mostly in sub-Saharan Africa and in rural areas. Connecting remote locations to the grid is expensive and slow, particularly for low-income nations. Long-range transmission lines are also vulnerable to damage, leaving rural communities at high risk of blackouts.

Fossil fuel subsidies for coal and gas power are therefore not the most efficient way to deliver electricity to these households. According to the International Energy Agency, solar-powered mini-grids and standalone systems are the best options for most communities that currently lack access to electricity. Shifting support from fossil fuels to distributed renewable energy can therefore help reduce rural energy poverty. 

In India, supplying power to agricultural consumers and low-income households has resulted in huge subsidies for grid electricity, mostly from coal, which undermines the financial viability of the grid. Solar irrigation pumps and rooftop installations have become a key strategy for reducing these subsidies and providing a reliable power supply. Solar irrigation pumps can also deliver broader community benefits by powering “secondary uses” like grain mills and electric cookers.

Acceptability: Shifting support from pollution to solutions

Energy security is more than the availability of energy at reasonable prices; it also requires that the energy sources and use must come with acceptable impacts and risks. Subsidizing fossil fuels exacerbates greenhouse gas emissions, air pollution, natural resource exploitation, and associated social impacts on affected communities. 

Clean energy also has negative environmental and social impacts, which need to be carefully managed. Renewable energy uses more land than fossil fuels, raising concerns about impacts on land quality and competition with other needs. Extracting and processing critical minerals, then disposing of technologies at the end of their life, further adds to their footprint.

However, unconditional subsidies for fossil fuels do nothing to bring about a more environmentally and socially responsible energy system. Whereas support for renewables—done right—can transition the world to a more sustainable system through incentives and regulations to improve component recycling, land-siting practices, and responsible mining. 

Conclusion

Every energy crisis has seen governments pour more money into the fossil fuel system, seeking to shore up supplies and affordability. Following the 1970s oil crisis, some governments also invested in the cure: energy efficiency and renewables to break dependence on the volatile and geopolitically risky fossil fuel market. This investment is paying off.

Solar, wind, and battery storage are now highly affordable and offer a way out of fossil fuel dependency.

 

Fossil fuel subsidy reform can help this transition in two ways. First, simply by increasing prices, consumers and investors are encouraged to use less fuel and switch to alternatives. Second, the money liberated can be used to accelerate the transition to clean energy, which is getting cheaper and offers a future of price-stable, domestically produced, and clean energy, including for those in remote areas that currently lack electricity and clean cooking. 

Need to know:

• Building a new oil pipeline would be a costly mistake for both Alberta and Canada. World oil demand is likely to peak in the next few years, and existing pipelines have the potential to provide adequate capacity at lower cost and risk.
• As the Trans Mountain Pipeline (TMX) shows, building new pipelines is risky because of cost overruns. The TMX was originally forecast to cost CAD 5.4 billion and ended up costing CAD 34.2 billion.
• The TMX pipeline is not recouping its costs. Because the tolls charged to the oil industry do not cover the full project costs, Canadian taxpayers could end up subsidizing oil shipments by between CAD 8.7 billion and CAD 18.8 billion, or up to CAD 1,255 per household, over the life of the project.  
• A new pipeline would have to charge significantly higher tolls than existing pipelines to cover the high construction costs. Higher tolls on a new pipeline would result in lower returns to the oil industry and lower royalty payments to government relative to using lower cost expansion options on existing pipelines.
• A new pipeline to British Columbia’s North Coast would require lifting the current oil tanker moratorium, posing a significant risk of a devastating oil tanker spill.
• All major project proposals should be subject to a cost-benefit study and should not proceed if they do not create a net benefit to Canada. A new oil pipeline is unlikely to meet this standard and is inconsistent with Canada’s emission obligations.
• Pipelines and fossil fuel projects should not receive public subsidies. The subsidies currently being provided to oil companies using the TMX should be removed by applying a cost-recovery levy on oil shipments to cover the full construction costs.

Investing in large-scale nation-building projects has become the priority of the Carney government as it seeks to grow Canada’s economy and diversify exports away from the United States.

While this strategy to stimulate investment has merit in the current economic environment, there is a significant risk of building uneconomic projects that could leave Canadians worse off, especially if the projects are subsidized by taxpayers and expedited by bypassing normal regulatory reviews through the new One Canadian Economy Act.

One project that exemplifies these risks is Alberta’s proposal for a new oil pipeline, which was recently agreed to in a Memorandum of Understanding (MOU) signed between Ottawa and Alberta.

The MOU contains a number of provisions, including commitments not to implement an emissions cap on the oil and gas sector, to suspend the clean electricity regulations, to maintain an industrial carbon pricing system, to implement a carbon capture project, and to streamline the approval process. The effect of these measures requires further details that the parties are still working out.

But the most controversial initiative contained in the MOU is support for a new oil pipeline to the BC Coast. Alberta supports the pipeline as a means of growing the energy sector and accessing Asian markets. BC and Coastal First Nations oppose it on the grounds that it entails significant environmental risks associated with oil tanker spills, it will increase emissions contributing to climate change, and that there are lower-cost, lower-risk options for shipping oil to markets via existing pipelines.

To better understand these risks of the proposed pipeline, it is helpful to examine the most recent experience building an oil pipeline in Canada: the construction of the Trans Mountain Expansion Project (TMX).

 

Trans Mountain Pipeline Expansion

TMX was proposed by the American owner Kinder Morgan (KM) in its application to the National Energy Board (NEB) in 2013. The project tripled shipping capacity on its existing pipeline that brings oil from Alberta to British Columbia and Washington State.  

After receiving regulatory approval in 2016 to build TMX, KM announced in 2018 that it was suspending construction due to increasing concerns about the project’s economic viability. The Government of Canada commenced discussions with KM about the future of TMX and, in May 2018, announced it would purchase the pipeline.  

Following the government purchase, the approval of TMX was subject to an additional NEB review to address omissions in the first review and was reapproved in 2019. Construction resumed with completion in May 2024 at a cost of CAD 34.2 billion, more than six times he original estimate.  

The Trans Mountain Corporation (TMC) reports that the expanded pipeline is making money for the government, with a net income before tax of CAD 409 million in the first half of 2025. TMC’s income statement is misleading, however, because it does not include the full interest costs to the government on its investment in TMX. TMC’s 2025 financial statements show that only CAD 12 billion of the CAD 35 billion current value of the government’s investment in the pipeline is recorded as debt incurring interest charges on TMC’s books. The remaining CAD 23 billion was converted to equity to remove the interest charges from TMC’s expenses and transfer the debt to a separate entity, TMP Finance, that pays interest to the Export Development Canada. Interest is being paid on the loan but because it is not being paid by TMC it is not shown as an expense on TMC’s financial statements, making TMC appear profitable. If the interest charges on this CAD 23 billion debt are included (assuming a conservative 5% interest rate) the government incurred an estimated before-tax loss from TMC of CAD 166 million for the first 6 months of 2025, not a profit.  

The result is that only CAD 15.4 billion of the CAD 34.2 billion cost of the pipeline is covered by tolls. If toll rates are not increased, Canadian taxpayers could lose between CAD 8.7 and CAD 18.8 billion or CAD 581 to CAD 1,255 per household subsidizing the transportation costs of the oil industry.  

While the financial cost to taxpayers of TMX is high, the total net costs to Canada are even higher when considering environmental costs such as GHG emissions and potential pipeline and oil tanker spill damages as well as other economic costs such as the impact on other pipeline companies. An independent, comprehensive cost-benefit analysis estimates that the net cost of TMX to Canada, when all costs are included, ranges between CAD 11.3 billion and CAD 30.1 billion — even when the potential impact of TMX increasing the price of Canadian oil exports is included.  

Lessons From the TMX for Building Canada Smarter

The lessons from the TMX experience are clear. First, governments should not build or financially support fossil fuel projects such as pipelines that the private sector considers too risky. If projects are viable, they can be built by the private sector without government subsidies. Providing subsidies will simply increase the probability of building uneconomic projects that weaken the economy and damage the environment.

In cases such as the TMX, where the government provided financial support, the terms of the assistance should ensure that the government’s contribution is fully repaid. For the TMX, this could be done either by increasing toll rates or by applying a special levy on transportation costs to fully recover the government’s investment so that taxpayers do not incur a loss.

Second, proposals should be evaluated by the government based on a comprehensive, public cost-benefit assessment of the project to determine whether it is in the public interest.

In the case of the TMX, the NEB review  did not include a comprehensive cost-benefit analysis. Instead, the review  relied on a simplified qualitative (as opposed to quantitative) assessment of the costs and benefits. The NEB review also focused only on the TMX pipeline proposal without assessing the merits of the TMX relative to alternative pipeline options or considering whether oil production would be sufficient to justify building the TMX.

A comprehensive cost-benefit evaluation would have taken all the relevant factors into account to determine whether the TMX was in the public interest. It would have assessed the significant environmental risks from increased emissions and potential pipeline and oil tanker spills. It would also have fully assessed the economic risks by conducting a supply-and-demand analysis of pipeline capacity and examining the shipping contracts to ensure that tolls would be high enough to cover construction costs. Finally, it would have evaluated alternative, lower-cost options for existing pipelines and alternative configurations for the TMX, such as expanding pipeline capacity to Washington State refineries, which would have reduced environmental risks by avoiding marine oil tanker traffic and increased returns for oil companies by reducing the shipping distance to markets.

By conducting this type of cost-benefit assessment, the government would have been able to more fully identify the economic and environmental risks of the TMX and could have better assessed the options for either addressing them or shelving the project.

A third lesson from the TMX is that major projects consistently experience significant cost overruns. The TMX was originally forecast to cost CAD 5.4 billion and ended up costing just over CAD 34.2 billion. Unfortunately, cost overruns are the norm in major projects. A multi-jurisdictional review of 633 energy projects, for example, found that three quarters of the projects took longer to complete and exceeded their cost estimates by an average of 79%.

The cause of cost overruns is an “optimism bias” that leads project proponents to consistently underestimate costs and overestimate benefits. To address optimism bias, project proponents should use a tool called “reference class forecasting,” which consists of reviewing the costs and benefits of completed projects and adjusting the budget forecasts accordingly for the project under review. In the case of the TMX, the construction cost forecast would have been increased by the average cost overrun experienced in similar projects.

While the overruns for the TMX exceeded the reference class overrun averages and would still have resulted in an underestimate of project costs, the analysis would have provided a more accurate estimate than those the government relied on.

Finally, all project reviews should include extensive engagement with the public and with Indigenous Peoples consistent with the principles of Free, Prior, and Informed Consent.
 

Why Canada Does Not Need a New Pipeline

While a comprehensive cost-benefit assessment of Alberta’s proposed pipeline cannot be completed without more details on the proposed project, current data suggests that it will impose a significant net cost on Alberta and Canada. Forecast growth in oil demand is insufficient to justify a major new pipeline, and upgrades to existing pipelines can meet Alberta’s needs at a much lower cost than building a new one.

Currently, the oil market is experiencing a large surplus, with supply forecast to exceed demand by 4 million bpd in 2026. Forecast production for 2025 of 106 mb/d exceeds the International Energy Agency’s most optimistic demand forecast to 2035 of 105 mb/d, indicating very limited potential for increasing production beyond current levels over the next decade.

Longer-term forecasts point to slower growth or a decline in oil demand, depending on future climate policies. Even in the unlikely scenario where there are no additional climate policy initiatives and the adoption of renewables and electric vehicles slows from their current trajectory, the International Energy Agency shows  that oil demand will continue to grow to 2050, but at a much slower rate than in previous decades. With continued implementation of stated policies, effectively continuing the current trajectory, the world oil demand is expected to peak by 2030 and then decline by 3% to 2050. If global climate change is limited to 1.5°C, demand is expected to decline by about three quarters by 2050.

Private oil companies such as BP forecast a decline in oil demand of between 11% and 68% by 2050, while Chinese demand, which is the target market for a new pipeline, is forecast to peak in about 2030 and then decline due to the rapid electrification of its transportation sector.

With world oil demand growth slowing down and then potentially declining, the rationale for building a new pipeline is weak. The Canada Energy Regulator’s most recent forecast, for example, concludes that no new pipelines are required to accommodate forecast growth in Western Canadian oil production.

But even if oil production grows faster than the Canada Energy Regulator forecasts and more pipeline capacity is required, an additional 1.1 million barrels of capacity can be provided by upgrading existing pipelines at much lower cost and lower risk than a new greenfield project.

Building a new oil pipeline to BC’s North Coast would also pose a significant environmental risk by requiring the removal of the current oil tanker moratorium, which was put in place to protect the marine environment from oil tanker spills. Research on the previous Enbridge Northern Gateway Pipeline proposed for Northern BC showed that there would be a 64% chance of a major oil tanker spill of 10,000 barrels or more, even with improved safety standards, over the first 30 years of operation. The impacts of a tanker spill would be devastating to the region’s environment and economy. Other research has documented that the new pipeline would increase greenhouse gas emissions, even if the proposed project is accompanied by carbon capture.

Given these market fundamentals, there is no rationale for building a new oil pipeline and, if one were built, the tolls required to pay for it would be significantly higher than those of existing pipelines, reducing returns to the oil industry and the Alberta government while putting the environment at risk. This is why no private pipeline company has come forward with a proposed new project and is unlikely to do so without government subsidies.

While some may have a more optimistic view of future oil demand and the viability of new energy projects in Canada, the TMX experience provides valuable lessons for building economic and environmentally responsible projects.

First, governments should not build or subsidize fossil fuel projects that the private sector considers too risky. Rapid deployment and cost reductions in electric vehicles, renewables, and battery technologies mean that the economic risks of oil and gas projects will only increase with time.

Second, proposed projects should be subject to a comprehensive public cost-benefit analysis to determine whether they are in the national interest. An economic assessment should include reference class forecasting to counter the optimism bias that leads to unrealistic cost and timeline estimates.

Finally, all project reviews should include extensive public engagement and consultation with Indigenous Peoples consistent with the principles of Free, Prior, and Informed Consent. These tools will help ensure that the projects built will strengthen the economy and not waste resources on poor investments that would make us all worse off. 
 

Introduction 

Industrial policy is back—again—but this time it looks nothing like the playbooks of the past. Around the world, governments are trying to steer economies through a turbulent mix of digital disruption, green transitions, shifting labour markets, and new geopolitical pressures. But while industrial policy has returned to the centre of debate, much of the conversation still focuses on the policies of manufacturing powerhouses and high-tech giants. In this issue of the Trade and Sustainability Review, we step outside that frame. We explore what industrial policy looks like in sectors beyond manufacturing; in economies where services dominate, where digitalization is advancing faster than regulation, where agriculture remains the backbone of livelihoods, and where least developed countries are navigating global competition and limits all at once. 

The five contributions in this edition unpack the “how” of industrial policy as much as the “what.” Pierre Sauvé opens by challenging the manufacturing-first mindset, showing why services—now the bloodstream of the global economy—need a different approach to industrial policy thinking. Kitrhona Cerri and Maria Mexi take us into Kenya’s booming digital economy, asking whether digitalization will generate real domestic value or entrench new forms of dependency without stronger governance and worker protections. David Laborde draws lessons from agriculture’s long history of intervention, offering timely insights into how emerging green industrial strategies will reshape food systems and rural development. From Nepal, Paras Kharel, Kshitiz Dahal, and Dikshya Singh examine the future of its textiles and garments sector as the country prepares to graduate from least developed country status, identifying the importance of government policy if industries are to stay competitive in a tougher global market. Finally, David Luke and Hana AlWakeel turn the spotlight on process; looking at how industrial policy is designed, who shapes it, and why the politics of policy-making can be as decisive as the policies themselves. 

Together, these articles offer a different, nuanced, and timely look at industrial policy at a moment when the world is considering rewriting its economic rules. They invite readers to look beyond headline-grabbing subsidies and megaprojects and instead examine the systems, sectors, and politics that will determine whether industrial policy delivers inclusive and sustainable development. 

Happy reading, 

Maria Barral

Articles

Rethinking Industrial Policy for the Services Economy 

Pierre Sauvé explores what industrial policy looks like in a services-driven economy, highlighting the need for policies that create the conditions for services to flourish and drive growth across the entire economy. 

Read article here. 

Digital Dividends or Dependency? Industrial policy in the age of digital economies 

Drawing on Kenya’s digital economy, Kitrhona Cerri and Maria Mexi argue that without stronger data governance, labour protections, and mechanisms for domestic value capture, digitalization could lead to dependency rather than supporting inclusive industrial development. 

Read article here. 

Agriculture and the Green Transition: Impacts of new industrial policies 

David Laborde examines how industrial policy can draw on agriculture’s long history of state intervention and how emerging green industrial strategies are poised to reshape agriculture in return. 

Read article here. 

Nepal’s Textiles and Clothing Exports: Trials, triumphs, and the road ahead 

As Nepal approaches graduation from least-developed country status, Paras Kharel, Kshitiz Dahal, and Dikshya Singh explore the challenges facing the country’s textiles and clothing sector and outline the policy shifts needed to preserve its competitiveness. 

Read article here. 

Why Industrial Policy-making Is the Key to Unlocking Gains from Industrial Policy 

Prof. David Luke and Hana AlWakeel argue that unlocking the gains of industrial policy depends on strengthening policy-making capacity, making it more adaptive, consultative, and transboundary—specifically in Africa. 

Read article here.

Summary

• LNG is a fossil fuel; producing it will increase Canada’s domestic emissions.  
• Canadian LNG exports are likely to increase global emissions by adding to fossil fuel consumption and slowing the transition toward renewable energy.
• New Canadian LNG is incompatible with climate targets and diverts resources away from real climate solutions such as renewable power generation and a clean transportation system.

The leading cause of climate change is burning fossil fuels—and this is causing more frequent and intense wildfires, storms, droughts, and floods. With Canada’s first large-scale LNG terminal beginning operations in June 2025, and several others proposed or under construction, it is crucial to understand the impact that this fossil fuel could have on people and the planet. That means answering questions such as:

• Will new LNG production increase Canada’s emissions?

• How would Canadian LNG exports affect global emissions?

• Is Canadian LNG a climate solution?

Recently, senior government officials have suggested that expanding Canadian LNG production would be good for the climate. For example, some have argued Canadian LNG has the “lowest carbon footprint of any produced in the world” and that LNG Canada Phase 1 is “60 per cent lower carbon than the average LNG plant in the world.” The federal government has suggested LNG exports “could help reduce greenhouse gas emissions by reducing coal combustion,” and a minister for the Government of British Columbia (B.C.) has added, “It's not just a question of displacing coal or other dirtier fuels … it's displacing other LNG, which has dramatically higher emissions.”

Statistics and arguments like these, however, don’t tell the full story.

Here’s why.

Q: Will new LNG production increase Canada’s emissions?

A: Yes, LNG is a fossil fuel; producing it will increase Canada’s domestic emissions.

How much carbon is expected to be emitted from Canada’s current LNG facility?

Producing LNG requires a lot of energy as it involves cooling standard piped natural gas to -162°C. LNG Canada Phase 1—Canada’s only active LNG export terminal—uses natural gas turbines to do this. That means Canada’s current LNG production relies on burning fossil fuels, with LNG Canada Phase 1 expected to emit 2.1 megatonnes of CO2e annually. This is roughly equivalent to the annual emissions of around 450,000 passenger vehicles and would make LNG Canada Phase 1 one of the most climate-polluting projects in all of B.C. These emissions could double if LNG Canada Phase 2 goes ahead as initially planned with partial electrification.

What about Canada’s proposed net-zero LNG facilities?

Most other proposed LNG projects in Canada—such as Woodfibre LNG, Cedar LNG, and Ksi Lisims—intend to be powered by hydroelectricity rather than natural gas. This could reduce their overall carbon footprint, with a goal to achieving net-zero operational emissions; however, electrifying B.C’s oil and gas industry—including all proposed LNG projects—in line with provincial climate targets would require over 40,000 GWh per year of electricity by 2030. This huge surge in demand would require the equivalent of eight Site C hydroelectric dams, just for the oil and gas sector. Electrification would also be very expensive, with a significant share of the cost expected to fall to the public—either in the form of direct government financing, government-funded infrastructure support, and/or subsidized electricity rates. Finally, due to a recent policy change from the Government of B.C., new LNG plants are no longer required to be net-zero by 2030. Instead, they only need to be “net-zero ready,” placing the burden on the province to ensure clean electricity supplies are available. In the meantime, most LNG facilities would operate by burning natural gas, increasing emissions.

Would net-zero LNG facilities produce net-zero LNG?

LNG facilities account for less than 10% of LNG’s average life-cycle emissions (figure below)—that is, the total emissions generated by a product’s life cycle from start to finish.  Far more emissions—twice as many, on average—come from upstream gas extraction, transportation, and shipping (figure below). If all proposed B.C. LNG projects go ahead, the increase in upstream emissions from natural gas extraction, processing, and transportation could be 10 Mt per year. Implementing the federal government’s proposed regulations to limit methane emissions from the oil and gas sector could help reduce this figure, but only partially. Electrifying LNG facilities themselves, moreover, does nothing to reduce these upstream emissions. In other words, a net-zero LNG facility does not produce net-zero LNG. This means that new LNG production will increase Canada’s emissions—even if the facilities’ own net-zero goals are met.

Illustrative Life-Cycle Emissions of LNG

Source: Haig et al., 2024, based on data from Nie et al., 2020. A similar emissions distribution was also found in a recent global study of average LNG life-cycle emissions: International Energy Agency (IEA), 2025.

Q: How would Canadian LNG exports affect global emissions?

A: Canadian LNG exports are likely to increase global emissions by adding to fossil fuel consumption and slowing the transition toward renewable energy.

Will Canadian LNG reduce global emissions by replacing coal use abroad?

There is little evidence to suggest that Canadian LNG will significantly displace coal use abroad. For example, in China, it is renewable energy, not imported LNG, that is reducing the market share of coal in the power sector. The cost of new utility-scale solar photovoltaic power and storage is also falling rapidly in other countries such as India, meaning this trend of shifting from coal to renewables is expected to be replicated in other Asian markets, too. LNG, meanwhile, is typically twice as expensive to produce than it needs to be to compete with coal and renewables in China, India, and many other emerging economies.

Moreover, life-cycle emissions from LNG are typically underestimated—often by a large margin. This is mostly because a significant portion of LNG-related emissions comes from methane leaks throughout the supply chain. These leaks are systematically underreported and thus underestimated in life-cycle emissions comparisons. While most studies do conclude that life-cycle emissions from LNG are still lower than those of coal (e.g., 25% lower on average, as estimated by the IEA), the emissions benefits of switching are often less dramatic than assumed and vary widely depending on the emissions intensity of the LNG in question.

Is the LNG Canada project “60%” cleaner than the global average LNG production?

The commonly cited claim that LNG Canada is “60%” cleaner than average is based on the environmental assessment report from the LNG Canada project. That report estimated the emissions intensity of both LNG Canada Phase 1 and 2, operating together at full capacity, would be 0.15 tonnes of CO2 equivalent per tonne of LNG produced (t CO2e/t LNG). This was then compared to the average of several international LNG facilities, calculated as 0.35 t CO2e/t LNG. The comparison assumes partial electrification of the total facility (Phase 1 and Phase 2). As noted above, there may be insufficient hydroelectric power available to achieve this, in which case the emissions intensity of LNG Canada could be higher than expected. Other relevant factors include policy settings, such as the stringency of industrial carbon pricing. As such, the emissions intensity of LNG Canada—and all proposed LNG projects in Canada—is uncertain, given that these figures are based on projections rather than observed emissions from operating facilities.

Even if LNG Canada was 60% less carbon intensive than international competitors, this offers an incomplete view of the relative climate impact of LNG produced in different countries. This is because the liquefaction process only refers to a small part (less than 10%, on average) of LNG’s total life-cycle emissions (figure above), as highlighted above. Assuming other emissions from upstream processing and transportation are kept constant for the purpose of illustration, 60% cleaner liquefaction processes would result in LNG that is only 5% cleaner overall (figure below). When comparing the climate impacts of LNG, what matters most is total life-cycle emissions, not the emissions intensity of the liquefaction facilities alone. 

Is Canadian LNG (in general) cleaner than the global average, and if so, could this help reduce global emissions?

Estimates regarding the total life-cycle emissions of LNG vary widely due to differing methodologies and assumptions. Emissions estimates for Canada’s LNG facilities, moreover, are based on projections that have not been confirmed with observed data.  In this context, one meta-analysis of emissions studies for Canadian LNG found the average estimate for total production, transportation, liquefaction, and shipping emissions (“well-to-tank emissions”) to be 23.35 gCO2e/MJ. The average well-to-tank emissions for LNG delivered to Europe were estimated to be 21.31 gCO2e/MJ using the same methodology.

The IEA has estimated that Canadian gas production is generally less emissions intensive on average than that of some LNG producers, such as Malaysia and Indonesia, but significantly more polluting than Qatar, which is the world’s cheapest LNG exporter. Indeed, Canadian gas is typically extracted by fracking, a highly polluting process. Relative to these estimates from the IEA, expanding LNG production in Canada would increase the emissions intensity of Canadian gas production overall (due to the increased energy requirements of LNG production and transportation), while reducing methane leakage, venting, and flaring would lower the emissions intensity.  The carbon footprint of Canada’s LNG facilities themselves may also be higher than expected if electrification is not possible in the short-to-medium term (as is likely) and facilities are powered by natural gas instead of hydroelectricity. The bottom line is that the potential emissions advantage of Canadian LNG over international competitors is currently unclear.

Even if Canadian LNG were cleaner than international competitors, we cannot assume that it will replace LNG produced elsewhere. Rather, new LNG projects will generally add to the total global production and consumption of LNG (while reducing profits for producers). In other words, addition is more likely than substitution, and thus emissions are expected to rise. Because of this, it is best practice to consider the emissions impact of new fossil fuel projects in absolute terms—that is, relative to no expansion—rather than in relation to other projects elsewhere.

Would LNG help or hinder the global transition to renewable energy?

Instead of displacing coal use abroad, or even other LNG products, flooding the market with more LNG could disincentivize investments in electrification and new renewable power generation. This is because an oversupply of LNG would deflate gas prices (at the cost of exporters, like Canada), making it more likely for governments and/or companies to lock in long-term fossil fuel infrastructure. This effect may be amplified by market distortions, such as fossil fuel subsidies and geopolitical pressure to expand LNG trade, even as market dynamics increasingly favour renewables over imported LNG. Considering factors such as these, detailed modelling from the U.S. Department of Energy in 2024 found that new LNG exports from the United States are expected to displace more renewables than coal abroad, all while increasing total fossil fuel consumption. The study concluded that “in every scenario, increases in [U.S.] LNG exports would lead to increases in global net emissions.”

Q: Is Canadian LNG a climate solution?

A: No. New Canadian LNG is incompatible with climate targets and diverts resources away from real climate solutions, such as renewable power generation and a clean transportation system.

Is more Canadian LNG compatible with a safe and stable climate?

Regardless of LNG’s emissions relative to other sources of fuel, new LNG production will make it more difficult to stabilize the climate. To maintain the science-aligned 1.5°C limit on global temperature rise, no new long-lead time upstream oil and gas projects are needed—as confirmed by the IEA and others. This includes new LNG facilities that would enable increased upstream gas extraction in Canada’s Montney Basin—one of the world’s largest sources of unburned carbon emissions. In fact, projected fossil fuel production in 2030 is more than double what would be consistent with the 1.5°C limit. Even many existing fossil fuel projects would need to shut down early—including some in Canada—if demand declines in line with this target.

Alternatively, if new projects are developed and fossil fuels continue to be consumed at a level needed to support them, the climate will be destabilized further. Every tenth of a degree of warming matters, with climate impacts on people and the planet expected to increase dramatically as temperatures increase. That means more wildfires, tropical storms, food insecurity, flooding, droughts, human displacement, and wildlife extinctions. The science is clear: a safe and stable climate requires transitioning away from fossil fuels and scaling up clean energy as quickly as possible. For governments that are serious about meeting globally agreed climate goals and protecting their citizens from the worst impacts of climate change, LNG expansion is simply not an option.

Do LNG projects come with opportunity costs?

The governments of Canada and B.C. have allocated at least CAD 3.93 billion in financial support for new LNG projects by the end of 2030. This creates an opportunity cost as public money is used to enable fossil fuel development at the expense of other projects that could create jobs, reduce household costs, and facilitate the transition toward a cleaner economy. For example, a clean transportation system could employ over 1.6 million people by 2050. A net-zero electricity grid could save Canadian households CAD 15 billion annually by 2050. Meanwhile, a wave of clean energy retrofits for Canadian homes could save households CAD 10.8 billion annually by 2050 while creating over 100,000 jobs. The more public money is used to expand fossil fuel infrastructure, the less is available to support real climate solutions.