The Climate Transition Crackdown: Who Gets Hurt First in 2026–2027?
Author: Justin Kew
The climate transition risk landscape in 2026–2027 is fragmenting into three distinct regulatory regimes:
The EU Carbon Border Adjustment Mechanism entered definitive regime on 1 January 2026, imposing direct carbon costs on steel, cement, aluminium, fertilisers, electricity and hydrogen imports—creating a two-tier global market in heavy industry
US federal climate policy rollbacks eliminate renewable tax credits and accelerate fossil fuel permitting, yet state-level mandates in 28 jurisdictions and hyperscaler demand for clean power purchase agreements sustain renewable deployment momentum
China's 15th Five-Year Plan, finalised March 2026, introduces explicit total emissions controls alongside intensity targets for the first time, with emissions peak potentially arriving in 2026–2027, four years ahead of pledge
This divergence matters now because capital allocation decisions made in the next eighteen months will lock in exposures to border adjustments, subsidy reversals, and emission-intensity penalties that cannot be hedged through financial instruments alone. The transition is no longer about voluntary targets; it is about who absorbs the cost of decarbonisation and which balance sheets break first.
The regulatory trilemma: pricing, permitting, fragmentation
Three forces are reshaping climate transition risk with binding effect in 2026–2027, each operating through different transmission channels but converging on the same question: which sectors can pass through carbon costs, and which must absorb them on their balance sheets.
Europe: carbon pricing goes live at the border
The EU Carbon Border Adjustment Mechanism shifted from transitional reporting to financial obligation on 1 January 2026, requiring non-EU producers to purchase CBAM certificates matching the embedded emissions in their exports. The mechanism initially covers cement, iron and steel, aluminium, fertilisers, electricity and hydrogen—precisely the sectors where carbon intensity diverges most sharply between jurisdictions and where free EU Emissions Trading System allowances are being phased out through 2034.
The mechanism creates a step-change in cost structure: steel producers in India and China face cost increases approaching 50% by 2034 relative to 2026 as CBAM fees scale up and free allowances disappear, whilst EU-based producers face a more modest 12% increase. At a EUR 70 per tonne CO₂ price, this translates to over 16% additional cost per tonne of steel imported into the EU today. The UK follows with its own CBAM from 1 January 2027, aligning implementation with the second free allocation period of the UK Emissions Trading System.
This is not a future risk; it is a present-tense balance sheet problem. Exporters to Europe must either decarbonise production, redirect high-carbon output to non-CBAM jurisdictions (creating a "two-tier market"), or accept permanent margin compression. The EU briefly considered exempting fertilisers in January 2026, paralysing trade flows, before reinstating the obligation—demonstrating the political fragility and implementation complexity that will characterise the next twelve months.
The second-order effect is more subtle: CBAM revenues are being discussed for funding clean industrial investment in least-developed countries, creating a potential mechanism for technology transfer that could accelerate global decarbonisation but also entrenches Europe's regulatory leadership.
United States: federal rollback, sub-national resilience
The Trump administration's climate policy since January 2025 has been characterised by systematic dismantling of federal frameworks: revoking renewable energy development orders, directing the Environmental Protection Agency to repeal the 2009 greenhouse gas endangerment finding (the legal basis for regulating vehicle and stationary source emissions), attacking state climate laws, terminating the American Climate Corps, and fast-tracking fossil fuel project permitting.
EPA Administrator Lee Zeldin identified 31 regulatory rollbacks in a January 2026 "hit list" spanning air quality standards, power plant pollution rules, and the endangerment finding itself. The Department of Interior revoked 3.5 million acres of federal waters previously designated for offshore wind development, effectively eliminating the federal offshore wind leasing schedule. Investment in wind and solar dropped 18% in the first half of 2025, and uncertainty slowed project pipelines.
Yet renewables accounted for 93% of US capacity additions through September 2025 at 30.2 gigawatts, predominantly solar and battery storage because economic fundamentals and sub-national policy are filling the federal vacuum. Renewable Portfolio Standards remain in force across 28 states, corporate procurement from hyperscalers seeking 24/7 clean power for data centres drives massive power purchase agreements, and falling costs make solar and wind the cheapest new power sources regardless of subsidy environment. Hydrogen projects emerged as a relative policy winner, with extended tax credit eligibility providing a pathway for industrial decarbonisation.
California is advancing its own climate disclosure rules despite the Securities and Exchange Commission's abandonment of federal requirements, signalling state-level regulatory divergence that creates compliance complexity for multi-state operators. The administration's executive order directing the Attorney General to identify and "take all appropriate action to stop the enforcement" of state climate laws faces legal challenges from the US Climate Alliance, but the litigation timeline extends well into 2027.
The investor implication is not that US decarbonisation has stopped, but that the federal policy backstop has disappeared, transferring risk from developers to corporate off-takers and making project-level due diligence on permitting, interconnection, and state regulatory stability mission-critical.
China: from intensity to absolute emissions control
China's 15th Five-Year Plan, formalised in March 2026, represents the world's largest emitter shifting from carbon intensity targets (emissions per unit of GDP) to explicit total emissions controls. This matters because China accounts for approximately 30% of global emissions, and early policy signals suggest the plan will introduce binding absolute caps alongside the traditional intensity framework.
President Xi Jinping pledged in 2021 that China would reduce carbon intensity to 65% below 2005 levels by 2030, formalised in the nationally determined contribution under the Paris Agreement. Achieving that target now requires reducing CO₂ emissions by 2–6% in absolute terms from 2025, assuming GDP growth of 4.2–5.0% , a growth rate Xi considers essential to doubling GDP per capita from 2020 to 2035, his vision of "socialist modernisation".
Multiple expert assessments suggest China's emissions could peak in 2026, potentially four years ahead of the 2030 pledge, driven by explosive renewable capacity additions (China accounts for 60–70% of global new solar and wind installations) and structural shifts in electricity generation. The State Council's 2024 plan for controlling carbon emissions confirmed that carbon intensity will remain a "binding indicator" through 2030, but the addition of absolute caps represents a fundamental shift in policy architecture.
The transition from emissions growth to stabilisation and early decline will be the key determinant of global commodity demand trajectories, particularly for thermal coal, steel, and cement. For investors, this creates a two-stage risk profile: near-term upside from China's continued renewables buildout benefiting global supply chains, followed by medium-term demand destruction in heavy industry as absolute emissions caps bind.
China's 1+N plan (2021–2029) emphasises substituting coal and fossil fuel power for renewables and nuclear, with provisions to promote low-carbon industrial production to achieve carbon neutrality by 2060. The binding constraint is whether the plan can reconcile more than 4.2% of annual GDP growth with absolute emissions reductions, a question that will be answered by late 2026 as first-year implementation data becomes available.
Countries driving vs diluting transition momentum
The regulatory geography of climate transition risk in 2026–2027 splits into accelerators, resisters, and swing states, with implications for both portfolio construction and supply chain strategy.
Accelerators: EU, UK, China
The European Union and United Kingdom are driving the most aggressive carbon-pricing architecture in any major economy, with CBAM creating direct financial incentives for global industrial decarbonisation. The UK's introduction of mandatory climate transition planning regulation in 2026, following consultation in 2025, extends disclosure obligations beyond what the International Sustainability Standards Board requires, creating a de facto global standard for UK-listed and UK-regulated financial institutions.
China's policy trajectory is more complex: whilst the 15th Five-Year Plan introduces absolute emissions controls, the government simultaneously exempted tier-1 coal miners from mandatory 2026 production cuts, signalling continued prioritisation of energy security and state revenue. The tell is in the capital allocation: China's renewables investment dwarfs all other jurisdictions combined, but coal capacity retirements remain contingent on grid stability and economic growth.
The UK's Prudential Regulation Authority issued supervisory statement SS4/25 in December 2025, requiring banks, building societies, investment firms and insurers to conduct full internal reviews of climate risk management by 3 June 2026, with board accountability, data reliability and scenario analysis expectations all materially strengthened. This elevates climate risk to the same supervisory intensity as credit, liquidity and operational risk, forcing financial institutions to embed climate resilience into strategy and capital allocation.
Resisters: United States, Indonesia
The United States under the Trump administration represents the clearest case of policy reversal, with systematic rollback of climate regulation, renewable energy support, and environmental review requirements. The administration's "drill, baby, drill" agenda prioritises fossil fuel production, expedited permitting for oil and gas projects, and efforts to prop up coal plants scheduled for closure.
Indonesia exempted tier-1 coal miners from 2026 production cuts despite an energy ministry proposal to scale back national output by nearly 24%to 600 million tonnes, aimed at stabilising prices and rebalancing domestic and export supply. The government's shift from multi-year to annual production approvals gives policymakers flexibility to adjust quotas in response to market conditions, but the exemption for large producers reveals the political economy constraint: state revenue and energy security trump emissions reduction when trade-offs become binding.
Market participants noted that import-dependent countries such as the Philippines, Malaysia, Thailand and Vietnam remain exposed to Indonesian coal supply decisions, whilst China and India can absorb some impact by raising domestic production. This creates a regional fragmentation dynamic where Southeast Asian economies' decarbonisation timelines depend on Indonesian policy choices.
Swing states: India, ASEAN, Middle East
India faces the sharpest near-term cost shock from EU CBAM, with steel producers confronting 50% cost increases by 2034 if emissions intensity remains unchanged. The country's response—whether to invest in green steel capacity, redirect exports to non-CBAM markets, or lobby for exemptions—will determine whether CBAM accelerates or fragments global industrial decarbonisation.
Indonesia's Regulation 10/2025, issued April 2025, established a roadmap for energy transition in the electricity sector aimed at net-zero emissions by 2060, including early retirement of the 660-megawatt Cirebon-1 coal plant with Asian Development Bank support. However, the simultaneous exemption of large coal miners from production cuts illustrates the policy incoherence that characterises swing-state transitions: aspirational long-term targets coexist with short-term decisions that lock in fossil fuel dependence.
Sector positioning: three themes winning, three themes losing
The fragmentation of climate policy across jurisdictions creates distinct sector-level winners and losers based on three variables: ability to pass through carbon costs, exposure to cross-border regulatory arbitrage, and alignment with structural demand drivers (electrification, data centres, industrial decarbonisation). The relevant question for investors is not which sectors are "green," but which can navigate regulatory fragmentation without balance sheet impairment.
Three themes best positioned
Theme 1: Electrification infrastructure and grid-scale storage
Renewable energy developers, particularly solar-plus-storage configurations, are benefiting from converging demand drivers that transcend federal policy in the United States and accelerate across all major economies. Global renewables are projected to become the top electricity source by 2026 (36% share versus coal's 32 %) , with capacity doubling by 2030 and solar approaching 1 terawatt of annual additions.
The critical shift is demand-side: hyperscalers' artificial intelligence data centres are driving 20–40% US electricity demand growth, with technology giants signing massive clean power purchase agreements for 24/7 supply. This corporate procurement creates a direct revenue channel independent of federal subsidies, and corporate buyers are absorbing price increases for solar-plus-storage to secure supply. Over half of utility-scale solar projects by 2026 are paired with battery storage, enabling firm power that can compete with baseload fossil generation.
Specific beneficiaries include diversified renewable producers with pipeline visibility (NextEra Energy plans massive solar and storage additions), domestic thin-film manufacturers benefiting from US reshoring pressure (First Solar), and storage technology providers (Enphase Energy in microinverters and residential/commercial storage). Grid interconnection remains a binding constraint, but state-level mandates in 28 US jurisdictions, China's 60–70% share of global solar and wind installations, and Europe's continued renewables deployment create a multi-regional growth runway.
The second-order opportunity is in utilities and grid operators with capital allocation flexibility to exploit the mismatch between surging electricity demand and constrained fossil fuel expansion: firms that can finance, permit and interconnect renewable capacity at scale capture quasi-monopoly rents in power-constrained markets.
Theme 2: Low-carbon industrial inputs and green hydrogen value chain
Sectors producing low-carbon industrial inputs, particularly green steel, low-carbon cement, and green hydrogen, are positioned to benefit from CBAM-induced demand for emission-intensity differentiation. EU and UK border adjustments create a bifurcated market where producers with verified low emissions intensity gain pricing power, whilst high-carbon incumbents face permanent margin compression or capital expenditure to decarbonise.
Green steel manufacturing investment is accelerating both inside the EU (as free ETS allowances phase out) and outside it (as CBAM fees enter force), driven by the cost differential between traditional and low-carbon production. Lowest-cost producers of legacy steel may retain temporary advantage even with CBAM markup, but as green steel demand builds and costs decrease with deployment at scale, that advantage erodes.
Hydrogen emerged as a relative policy winner in the United States despite federal climate rollbacks, with extended tax credit eligibility supporting industrial decarbonisation pathways. The EU included hydrogen in initial CBAM scope, creating cross-border demand for certified low-carbon hydrogen and downstream ammonia for fertiliser production. Producers with access to low-cost renewable electricity and established electrolyser capacity can arbitrage the emission-intensity premium before global supply scales.
The material risk is technology and cost uncertainty: green hydrogen production costs remain above grey hydrogen (fossil fuel-derived) in most markets, and the buildout timeline for distribution infrastructure and end-use applications introduces execution risk. Projects with contracted off-take, regulatory support (EU or US state-level incentives), and integration into existing industrial clusters (refineries, ammonia production, steel) have the clearest path to commercialisation.
Theme 3: Climate risk analytics, verification and compliance infrastructure
Financial institutions, heavy industrial producers, and exporters to Europe all face binding regulatory requirements to measure, disclose and manage climate risk by mid-2026, creating structural demand for data, analytics and verification services. The UK Prudential Regulation Authority's SS4/25 requires banks, insurers and investment firms to demonstrate board-level understanding of climate exposures, robust scenario analysis, and auditable evidence for every climate-related decision by 3 June 2026.
EU Corporate Sustainability Due Diligence Directive (CSDDD) obligations, though the mandatory climate transition plan duty was deleted in the sustainability Omnibus package, still require detailed disclosure of plans and targets under regimes based on International Sustainability Standards Board standards. The UK government is introducing formal climate transition planning regulation in 2026 for corporates and regulated financial institutions, extending beyond ISSB baseline requirements.
CBAM implementation requires exporters to calculate and verify embedded emissions across complex supply chains, purchase certificates, and maintain audit trails, creating demand for emissions accounting platforms, third-party verification, and carbon registry infrastructure. The EU's early 2026 fertiliser exemption paralysis and subsequent reversal demonstrates implementation complexity that will sustain professional services and technology demand throughout 2026–2027.
Providers of climate risk scenario analysis tools, portfolio-level transition risk quantification, physical risk modelling (flooding, heat stress, supply chain disruption), and regulatory compliance workflow platforms are positioned to capture revenue as disclosure and risk management requirements scale from voluntary to mandatory across major jurisdictions. The shift from voluntary ESG frameworks to binding prudential regulation fundamentally changes the buyer (from sustainability officers to risk and compliance functions with budget authority) and purchasing urgency (regulatory deadlines create non-discretionary demand).
Three themes least well positioned
Theme 1: Carbon-intensive heavy industry without pricing power
Steel, cement, and aluminium producers in jurisdictions outside EU/UK carbon pricing regimes face the sharpest near-term margin compression from CBAM, with limited ability to pass through costs if they serve price-sensitive markets. Indian and Chinese steel exporters to Europe confront 50% cost increases by 2034 relative to 2026 if emissions intensity remains unchanged, whilst competing with EU-based producers facing only 12% increases.
The key variable is pricing power: producers serving differentiated markets (specialty alloys, construction-grade steel with technical specifications) can pass through some CBAM costs, whilst commodity-grade producers in globally traded markets must absorb the differential or lose volume. The result is a two-tier market where low-carbon products flow to Europe and high-carbon products redirect to non-CBAM jurisdictions, fragmenting global trade and creating stranded capacity risk in high-emissions facilities.
Cement and aluminium face similar dynamics, but with sector-specific complications: cement's high weight-to-value ratio limits long-distance trade (reducing CBAM impact on non-European producers but increasing cost for European importers reliant on regional supply), whilst aluminium's electricity-intensive production makes decarbonisation contingent on grid carbon intensity and power purchase agreement availability.
Fertiliser producers secured a brief exemption from CBAM in January 2026 before reinstatement, illustrating political vulnerability of sectors with agricultural and food security implications. The policy instability compounds balance sheet risk: firms that delay decarbonisation investment betting on exemptions face sudden capital expenditure requirements if policy reverses, whilst early movers risk stranded assets if exemptions persist.
The sector lacks a clear decarbonisation pathway at scale: hydrogen-based direct reduced iron for steel, carbon capture for cement, and renewable-powered aluminium smelting all require capital expenditure measured in tens of billions and policy certainty over 15–20 year payback periods. Firms in jurisdictions with explicit carbon pricing (EU, UK, potentially China post-2026) can model returns; firms elsewhere face unhedgeable policy risk.
Theme 2: Fossil fuel extraction and long-cycle upstream projects
Upstream oil and gas projects with long lead times and high capital intensity face acute policy risk in 2026–2027, as regulatory divergence between the United States (pro-fossil fuel) and Europe/China (tightening emissions constraints) creates return uncertainty that cannot be resolved through traditional political risk insurance.
The Trump administration's fast-tracking of fossil fuel permitting, reopening of Alaskan refuge for development, and Energy Emergency Declaration authorising circumvention of Clean Water Act and Endangered Species Act requirements provide near-term tailwinds for US-domiciled upstream projects. However, the same projects face structural headwinds from collapsing renewable costs, corporate procurement shifting to clean power purchase agreements, and state-level emissions regulations that survive despite federal rollback attempts.
China's emissions peak potentially arriving in 2026–2027 implies peak fossil fuel demand in the world's largest energy consumer within eighteen months, creating a demand cliff for thermal coal and potentially constraining long-term oil demand growth. Indonesia's exemption of tier-1 coal miners from 2026 production cuts provides short-term supply stability but locks in overcapacity if Chinese and Indian demand weakens faster than forecast.
Long-cycle projects, deepwater oil, Arctic gas, complex shale plays with multi-year development timelines, face the highest risk because committed capital expenditure today faces commodity price exposure in 2028–2030 when policy trajectories diverge most sharply. Projects dependent on export markets (US LNG to Europe, Indonesian coal to Southeast Asia) add trade policy risk and carbon border adjustment exposure as jurisdictions beyond the EU consider their own mechanisms.
The sector's challenge is that political tailwinds in the United States are offset by economic and policy headwinds everywhere else: even if US federal policy supports fossil fuel expansion, return on capital depends on global demand growth that is structurally decelerating. Refiners with downstream integration and petrochemical exposure have better demand visibility than pure-play upstream, but both face the same transition risk: policy support can delay decline, but cannot reverse structural demand erosion.
Theme 3: Unhedged financial institutions with concentrated transition-exposed lending
Banks, insurers and asset managers with concentrated exposure to transition-vulnerable sectors, particularly carbon-intensive heavy industry, fossil fuel extraction, and commercial real estate dependent on internal combustion engine traffic patterns, face escalating regulatory scrutiny and potential capital requirement increases if they cannot demonstrate credible climate risk management by mid-2026 deadlines.
The UK Prudential Regulation Authority's SS4/25 elevates climate risk to the same supervisory intensity as credit, liquidity and operational risk, requiring board accountability, forward-looking scenario analysis, and auditable evidence for climate-related decisions. Financial institutions must complete internal reviews by 3 June 2026 demonstrating how climate factors affect business strategy, where portfolio exposures are located, and how climate metrics and triggers are monitored.
The binding constraint is data and methodology: many institutions lack granular borrower-level emissions data, supply chain visibility, or robust models linking physical and transition risks to credit losses and asset valuations. Institutions that miss the June 2026 deadline face regulatory censure, potential capital add-ons, and reputational damage with institutional clients conducting manager due diligence.
Sector concentration amplifies risk where lenders with significant exposure to steel, cement or aluminium producers facing CBAM cost shocks, upstream oil and gas facing demand uncertainty, or commercial real estate in jurisdictions with aggressive internal combustion engine phase-outs all face correlated credit deterioration if transition accelerates. The correlation is the risk: climate stress scenarios are not idiosyncratic borrower events, but systematic sector-wide repricing that traditional credit portfolio diversification does not hedge.
European financial institutions face additional complexity from the deletion of mandatory climate transition plan duty in the Corporate Sustainability Due Diligence Directive, which removes a harmonised framework for assessing borrower transition readiness whilst leaving disclosure obligations intact under International Sustainability Standards Board-aligned regimes. UK institutions must navigate both ISSB baseline requirements and forthcoming UK-specific transition planning regulation exceeding international standards.
The second-order risk is liability, as physical climate impacts and transition policy shocks crystallise, shareholders and stakeholders may pursue legal action against financial institutions for inadequate climate risk disclosure or governance failures. The June 2026 regulatory deadline creates a clear evidentiary standard for what constitutes adequate climate risk management, increasing litigation exposure for institutions that fall short.
Conclusion
The variant view is that climate transition risk in 2026–2027 is not primarily about physical climate impacts or long-term temperature scenarios, but about near-term cash flow volatility and balance sheet stress from regulatory fragmentation across the three largest economic blocs. The EU's CBAM, US federal policy reversal with sub-national resilience, and China's shift to absolute emissions caps create different cost-of-capital and competitive dynamics within the same globally traded sectors, fragmenting markets and stranding capital in the wrong jurisdictions.
This is a structural rather than cyclical risk: firms cannot hedge regulatory divergence through commodity derivatives or political risk insurance, and the timeline for policy convergence extends beyond the investment horizon for most industrial capital expenditure decisions. The sectors best positioned are those with demand drivers orthogonal to policy (electrification infrastructure serving AI data centres), with business models that monetise regulatory complexity (climate risk analytics and verification), or with low-carbon differentiation that commands pricing power in bifurcated markets (green hydrogen, green steel). The sectors least positioned are those with high emissions intensity, low pricing power, and capital locked in jurisdictions where policy trajectory remains uncertain (carbon-intensive heavy industry, long-cycle fossil fuel projects, unhedged financial institutions with concentrated transition exposures).
The read-across for portfolio construction is clear: climate transition risk in 2026–2027 is a factor exposure that correlates with regulatory jurisdiction, emissions intensity, and pricing power, not with traditional sector classifications or ESG scores. Investors must underwrite regulatory fragmentation as a permanent feature of the transition, not a temporary dislocation that policy coordination will resolve.
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This article is for information and discussion only and does not constitute investment advice or a recommendation.