For years, carbon pricing was mostly discussed as a climate-policy question. But from next year, it will also increasingly be a trade question. The UK has included India’s Carbon Credit Trading Scheme (CCTS) in its list of overseas carbon-pricing systems that qualify for relief under its Carbon Border Adjustment Mechanism (CBAM). Britain’s CBAM begins on January 1, 2027, covering imports such as iron and steel, aluminium, cement, fertilisers and hydrogen.

For Indian exporters, the important part is simple: where an eligible carbon price has already been paid in India, the UK can take it into account when calculating the carbon liability at its border. The recognition is not an exemption and does not mean every Indian exporter will automatically receive relief. The actual amount depends on the carbon price paid, the emissions embedded in the goods and the evidence provided.

Almost $1 Billion in Steel and Aluminium Exports

The stakes are not trivial. India exported $13.44 billion in merchandise to the UK in 2025–26. Iron, steel and related products accounted for about $893.4 million, while aluminium exports were around $94 million. Together, those two categories were worth nearly $1 billion.

That does not mean $1 billion will be subject to CBAM. The UK mechanism applies to specified products and calculates liability according to their embedded emissions. But the numbers show the scale of industrial trade that could be affected. The issue is what happens when other markets follow the same path.

India is not Alone

The UK’s qualifying list contains 16 overseas carbon-pricing systems, including those of the EU, China, Japan, South Korea, Australia, Canada, New Zealand, Singapore and South Africa, alongside India. This is where the global picture gets interesting.

The European Union already operates the world’s best-known carbon border mechanism. China has a national emissions trading system. South Korea has had an emissions trading system since 2015. Japan introduced its national GX emissions trading system in 2026. But these systems do not all put the same price on carbon.

The World Bank’s 2026 Carbon Pricing Dashboard puts the main EU ETS price at about $70 per tonne of CO₂ equivalent. South Korea’s ETS is around $10, while Japan’s carbon tax is around $2. India’s compliance mechanism is still being developed, so the World Bank does not yet assign it a comparable compliance carbon price.

The numbers should not be read as a league table. Carbon-pricing systems cover different sectors, use different rules and offer different levels of free allocation or compensation. But they reveal something important: there is no single global carbon price. There is, however, an increasingly global expectation that carbon should have a price.

Changes the Calculation for Indian Industry

For an Indian steel or aluminium producer, emissions are no longer only an environmental metric. They can become an export cost. That creates an incentive to reduce energy use, switch to cleaner power, improve production efficiency and measure emissions more accurately. India’s CCTS is therefore becoming relevant to trade policy as much as climate policy. But there is a catch.

A carbon market only helps exporters if the system behind it can produce reliable, verifiable data. Indian engineering exporters have already warned that smaller companies could struggle with carbon certification requirements in overseas markets, particularly because verification can be expensive and technically demanding. For a large steel producer, measuring emissions may be an administrative challenge. For a small manufacturer supplying components to an exporter, it can become a cost that determines whether it can remain in the supply chain.

Who Pays — and Who Benefits?

The immediate beneficiaries of the UK’s recognition are likely to be exporters whose goods qualify for carbon-price relief. The wider benefits are less direct.

If Indian manufacturers remain competitive in overseas markets, that can support production, logistics and jobs. If carbon rules push companies to invest in cleaner technologies, new markets can emerge around emissions measurement, verification, energy efficiency and low-carbon manufacturing. But there is no basis yet to say that households will see lower electricity bills or cheaper products because of this decision. For most people, the connection is likely to be through employment and the wider economy rather than prices.

The Real Race is only Beginning

India’s recognition by the UK is useful, but it is not the finish line. The countries now competing for industrial investment and export markets are also building their own carbon-pricing systems. Some have been doing so for years; others are only beginning.

The question for India is whether its carbon market can move quickly enough from a regulatory framework to a functioning economic system — one that gives companies a reason to cut emissions while ensuring that cleaner Indian products remain competitive abroad. Because the next phase of global trade may not ask only how much a product costs. It may also ask how much carbon it costs to make it.

Six months into the Hormuz crisis, global fossil fuel importers have paid USD 330 billion above expected prices, with India’s additional bill reaching USD 22.5 billion.

EdPublica Data Desk   |   Analysis

Since the United States and Israel struck Iran on 28 February 2026 and shipping through the Strait of Hormuz collapsed, countries that import oil and gas by sea have paid more than USD 330 billion above what markets had expected to charge them, according to new research published by the Centre for Research on Energy and Clean Air (CREA). That works out to roughly USD 55 billion extra every month for half a year — the largest sustained fossil fuel price shock since the 1990 Gulf War, and one that is still running.

Hormuz crisis drives global fuel costs higher

India’s share of that bill is USD 22.5 billion, the second-highest of any country in the world, behind only China’s USD 35.5 billion and ahead of the United States, despite America being the world’s largest oil producer. That ranking is a direct consequence of how much of its energy India buys from abroad: the country imports close to 90 percent of the crude oil it uses, more than almost any other major economy, which leaves it with limited room to absorb a shock at the source.

India paid the second-highest fossil fuel import premium of any country over the six months to August 2026, behind only China.  Source: CREA analysis. Illustration: EdPublica

A shock rivalled only by the 1990 Gulf War

CREA’s estimate is built from actual, ship-tracked cargo data — sourced from Kpler — for crude oil, refined fuels and gas that moved by sea between March and August 2026, compared against the futures prices the market had already set for those same delivery months in the twelve days before the strikes. Because both sides of the comparison are settlements of the same contract, the gap is a direct, like-for-like price difference rather than a modelled estimate. The analysis covers 170 countries and deliberately excludes pipeline gas, coal, fuel oil, naphtha, freight and war-risk insurance, all of which would push the true cost higher. CREA describes its USD 330 billion figure as conservative on that basis.

Brent crude’s trajectory over the six months traced a path familiar from past oil shocks: a sharp spike in the first weeks, a partial retreat, and a second surge later on. Prices briefly touched pre-war levels in late June before climbing back above USD 100 a barrel in late July, a pattern CREA’s researchers compared directly against the 1990 Gulf War, the 2019 Abqaiq attack and the 2022 Russian invasion of Ukraine. Of those four episodes, only the Gulf War produced a larger and longer-lasting price premium than the current crisis.

Refined fuels rose faster than crude itself

Crude oil accounts for the largest single share of the extra cost, USD 164 billion, at an average premium of 35 percent over pre-war expectations. But the fuels people and businesses actually use day to day rose by a steeper proportion still. Diesel and gasoil were up 59 percent, adding USD 74 billion; gasoline rose 43 percent, adding USD 36 billion; jet fuel rose 59 percent, adding USD 20 billion; and LNG rose 60 percent in the Atlantic basin and 75 percent in the Pacific, adding USD 38 billion.

Refined fuels — diesel and gasoil in particular — rose by a steeper margin than crude oil itself.  Source: CREA analysis. Illustration: EdPublica

Diesel’s premium mattered more than any other single figure in the analysis, because of how widely it is used. Industry, freight and farming all run substantially on diesel, so its price feeds directly into the cost of nearly everything else. Of the 170 countries CREA analysed, 134 paid more for diesel than their pre-war futures had implied. The war premium for diesel stayed above 55 percent in five of the six months, dipping to 43 percent in June before climbing back to 65 percent by August. Even the United States, the world’s largest oil producer, was not insulated: the average price of a gallon of diesel rose to USD 5.57 in the week of 17 August, the highest level since 2022 and closing in on that year’s record, according to AAA.

The clean energy dividend

The research’s central finding on mitigation is that a country’s exposure to the shock has been shaped less by geography than by how much of its power already comes from clean sources. Clean power capacity added since 2020 saved importing countries an estimated USD 36 billion in avoided coal, gas and oil imports in the first five months of the crisis alone. Of that, USD 10.6 billion existed only because of the war itself: every unit of coal or gas a country did not need to buy was a unit it did not have to purchase at inflated wartime prices, on top of whatever it would ordinarily have saved.

“The energy transition is an investment,” Wickenden added, “so the best day to have started is yesterday.” Electrification is compounding the effect: the world’s electric vehicle fleet is on course to displace around five million barrels of oil a day by 2030, roughly comparable to the volume of crude Saudi Arabia currently moves through its East-West Yanbu pipeline specifically to bypass the Strait of Hormuz, according to the International Energy Agency’s Global EV Outlook.

Poorer countries are absorbing a bigger hit

The burden of the crisis has fallen unevenly by income, not just by geography. Low- and lower-middle-income countries paid an additional 1.0 percent of their 2024 GDP in higher fossil fuel costs, more than twice the 0.45 percent burden faced by high-income countries.

India’s particular exposure

India’s position in the top three is not simply a function of the size of its economy. The country entered 2026 already navigating a difficult trade-off on energy: after Washington imposed additional tariffs on Indian exports over New Delhi’s imports of discounted Russian crude, India had been cutting back on Russian oil and increasing purchases from the Middle East in pursuit of a US trade deal. The Hormuz crisis disrupted that shift almost immediately, cutting off much of the Middle Eastern supply India had been leaning on and pushing it back toward Russian crude even as prices climbed and a separate US sanctions waiver on Russian oil purchases lapsed in April.

By June, India’s total crude imports had hit a monthly record of roughly five million barrels a day, with Russian supplies alone reaching an unprecedented 2.6 million barrels a day — 54 percent of the country’s total crude imports, and more than double the volume seen in February. That pivot briefly inverted the usual arithmetic: discounted Urals crude, which had traded well below Brent since 2022, began trading at a premium to it in March, as Indian and Chinese refiners competed for the limited Russian cargoes still reaching them outside the Gulf. By July, as Gulf supply chains began to normalise, Urals discounts had reopened to more than USD 10 a barrel below Brent.

Russian crude functioned, in effect, as India’s insurance policy against a disruption its strategic reserves were not large enough to absorb on their own — but insurance still has a premium, and India’s USD 22.5 billion bill is a measure of how much of that premium it ultimately paid, on top of what it saved through the Russian discount.

India is preparing to open its civilian nuclear power sector to wider private participation as it attempts to increase nuclear capacity more than elevenfold by 2047. The country currently has 8.78 GW of installed nuclear capacity across 24 reactors, contributing about 3.1% of electricity generation. The government wants to raise this to 100 GW by 2047.

That means adding more than 91 GW in two decades.

The scale of the ambition explains the policy shift. The government expects nuclear capacity to reach around 22 GW by 2031–32. Beyond that, NPCIL is expected to account for about 54 GW by 2047, while the remaining 46 GW is expected to come from other public-sector enterprises, state governments, private companies and joint ventures. The 46-GW figure is crucial. Private participation is not simply an experiment in changing ownership. It has become part of the government’s arithmetic for reaching 100 GW.

But opening the sector does not guarantee that the reactors will be built. The harder questions concern finance, construction, technology, safety, liability and who ultimately bears the risks of nuclear power.

Why Nuclear Power When Renewables are Expanding?

India’s nuclear power expansion is taking place alongside a much larger renewable-energy programme. By June 2026, renewable-energy capacity had reached 288.58 GW, including 162.15 GW of solar, 57.44 GW of wind and 57.24 GW of hydropower. So why invest heavily in nuclear?

The government’s argument is that the two technologies perform different functions. Solar and wind generation varies with weather and time of day, while nuclear reactors are designed to provide continuous generation.

Nuclear power is therefore being positioned as a source of firm, low-carbon electricity alongside renewables, rather than as a replacement for them. That distinction matters as electricity demand rises. Government projections put India’s peak demand at around 446 GW in 2034–35, with electricity requirements of about 3,215 billion units.

The projected power mix for that year includes 22 GW of nuclear, 679 GW of renewable and 327 GW of thermal capacity. The question, then, is not whether India needs electricity. It clearly does. The question is how much nuclear capacity makes economic sense within an electricity system increasingly dominated by renewables and supported by storage and other technologies.

What Actually Changes Under the New Framework?

The SHANTI Act, 2025 provides the legal framework for wider participation in specified civilian nuclear activities. This is not unrestricted privatisation. Private entities remain subject to government licensing and nuclear-safety requirements.

The significance is that the pool of potential participants can now extend beyond the traditional state-controlled nuclear establishment. The government expects this to create opportunities for private investment, manufacturing, technology development and new project structures. But permission to participate is not the same as willingness to invest.

Nuclear power projects are expensive, technically complex and slow to build. Investors have to commit large amounts of capital long before a plant begins generating revenue. That is why the success of the reform will depend less on how many companies enter the sector and more on whether they are willing to put substantial capital behind actual projects.

Can Private Capital Solve the Financing Problem?

The strongest case for private participation is that it could broaden the pool of capital available for nuclear construction. The government’s own roadmap makes clear that NPCIL is not expected to deliver the entire 100-GW target. About 46 GW must come from other public-sector entities, states, private companies and joint ventures.

But private participation should not automatically be equated with lower costs. Globally, nuclear projects have faced problems with construction delays, cost overruns and high financing requirements. The International Energy Agency has identified these as major challenges for nuclear investment.

For India, the critical questions will therefore be whether private investors can secure affordable financing, whether projects can be completed on schedule and whether the electricity generated can remain competitive with other sources. The reform changes who can invest. It does not remove the underlying economics of nuclear construction.

The SMR Bet

India is also placing considerable emphasis on small modular reactors. The government has allocated INR 20,000 crore to research, development and deployment of indigenous SMRs and aims to have at least five operational by 2033. BARC is developing the 220-MWe BSMR-200 and 55-MWe SMR-55, among other designs. The government sees potential applications in captive industrial power, replacing retiring fossil-fuel capacity and locations where conventional large reactors may be less suitable.

But India’s indigenous SMR designs are still under development. Their eventual contribution to the 100-GW target will depend on whether they can move from demonstration to commercially viable deployment. For now, SMRs are an important part of India’s nuclear power strategy, not a guaranteed solution to its capacity challenge.

The Liability Question

The most consequential issue for private investors may be nuclear liability. The SHANTI framework retains no-fault liability for nuclear operators while establishing graded limits depending on the category and size of a nuclear installation. The draft rules propose operator liability ranging from INR 100 crore to INR 3,000 crore.

The government argues that a clearer liability structure will make investment and insurance more predictable. But there is another side to the question: is the statutory compensation framework sufficient if an accident causes losses far beyond the operator’s liability?

That issue is now before the Supreme Court. On 17 August 2026, the court sought clarification from the Union government on whether constitutional courts would remain able to determine fair and just compensation following a nuclear power accident under the new framework. The court has not struck down the liability provisions. But the proceedings highlight an important tension in the reform: making risk predictable for investors while ensuring that victims are adequately protected.

Nuclear Power: Who Bears the Long-term Risks?

Nuclear power also raises questions that cannot be reduced to the cost of electricity. A major accident could affect workers, nearby communities, livelihoods and ecosystems far beyond the balance sheet of the company operating the facility.

Radioactive waste presents a different challenge. Electricity generated today can create waste that requires management over much longer periods. The government retains responsibility for certain aspects of spent-fuel management, while licensed entities are responsible for managing radioactive waste generated through their activities.

This raises an intergenerational question: How should today’s electricity consumers ensure that future generations are not left with the financial and environmental burden of today’s nuclear expansion?

There is also a question of distribution. Nuclear power facilities require land, water and supporting infrastructure. Communities near proposed projects can therefore bear costs that are spread much more widely across the country than the benefits and electricity generated by the plant.

A larger nuclear power programme will need credible mechanisms for land acquisition, rehabilitation, emergency preparedness, compensation and public participation. Safety cannot become secondary to speed The government maintains that expanding private participation will not mean lowering safety standards.

Does the regulatory system has enough independence, technical capacity and enforcement power to oversee a larger and more commercially diverse nuclear power industry? That becomes particularly important when project developers have strong financial incentives to control costs and meet construction schedules.

A successful private nuclear power model therefore requires more than investment rules. It requires strong regulation that can remain independent of both political and commercial pressure.

The Real Test is Beyond the 100-GW Target

India’s nuclear power ambition is clear: 8.78 GW today, 22 GW by 2031–32, 100 GW by 2047. The government expects NPCIL to deliver roughly 54 GW of that eventual capacity and other public and private entities to account for the remaining 46 GW.

The SHANTI Act makes that wider participation possible. But it does not guarantee that private companies will invest, that projects will be financed cheaply, that reactors will be built on time or that nuclear power will remain economically attractive as renewables and storage expand.

Nor does it settle the ethical questions around liability, waste, community impacts and long-term risk. That is why the success of the reform should not be measured simply by the number of companies that enter the nuclear sector. The real test will be whether India can build enough nuclear capacity at a reasonable cost while maintaining strong safety oversight and ensuring that the risks are not disproportionately transferred to communities, taxpayers or future generations.