India allocates over $4bn for net zero goals in budget

: Biofuels, Emissions, Hydrogen
23/02/01

The Indian government has allocated 350bn rupees ($4.28bn) for its 2070 net zero goal in its latest budget, covering areas like hydrogen, renewables and green mobility.

The allocation for the April 2023-March 2024 fiscal year is a priority capital investment towards India's energy transition, net zero objectives and energy security needs, finance minister Nirmala Sitharaman said in parliament on 1 February.

Sitharaman reiterated the government's aim to have green hydrogen production of 5mn t/yr by 2030, at an initial outlay of Rs197bn. The government had approved a national green hydrogen mission on 4 January, aiming to reduce the country's dependence on fossil fuels and turn India into a global hydrogen hub. The government later detailed plans for incentivising domestic hydrogen production and electrolyser manufacturing in a policy document on 13 January.

In the renewable segment, the government will support the setting up of 4,000MWh of battery energy storage and will come up with a detailed framework for the development of "pumped storage" projects in the country, Sitharaman said, but did not give more details.

The federal government has also promised support of Rs83bn out of a total investment of Rs207bn for an inter-state transmission system for evacuation and grid integration of 13GW of renewable energy from Ladakh, where state-controlled power company NTPC's renewables subsidiary NTPC REL plans to set up India's first green hydrogen mobility project.

The government has increased its allocation for faster adoption and manufacturing of electric vehicles to Rs51.7bn for 2023-24, a 78pc rise from Rs28.97bn in the previous fiscal year, in a bid to boost green mobility in the country. The finance minister also announced duty exemptions on imports of capital goods and machinery required for lithium-ion cells for batteries used in electric vehicles. The move could make electric vehicles cheaper in India and in turn boost their uptake.

The government also earmarked Rs100bn towards setting up of 200 compressed biogas (CBG) plants and 300 community and cluster-based biogas plants under its Galvanising Organic Bio-Agro Resources Dhan (Gobar-Dhan) scheme.

India had previously set a target to roll out 5,000 CBG production plants to reduce its reliance on energy imports and control pollution. It currently has 31 CBG plants in operation and about 100 retail outlets selling biogas.

"In due course, a 5pc CBG mandate will be introduced for all organisations marketing natural and biogas," Sitharaman said in her budget speech.

India imports about half of its natural gas requirements and is aiming to replace some of these imports with domestic biogas.

State-controlled firms Gail, IOC, HPCL and BPCL are some of the companies with existing plans for CBG plants.

By Rituparna Ghosh

Related news posts

Argus illuminates the markets by putting a lens on the areas that matter most to you. The market news and commentary we publish reveals vital insights that enable you to make stronger, well-informed decisions. Explore a selection of news stories related to this one.

25/01/03

US 45V update opens door to more H2 from natural gas

Houston, 3 January (Argus) — The US Treasury Department's updated requirements for hydrogen production tax credits amends the way upstream emissions are calculated, potentially making it easier for natural gas producers to qualify for the lucrative subsidy. Previous guidelines used fixed assumptions about the rate of methane leaked from wells and pipelines rather than accepting data from individual projects. The industry argued that using uniform figures under the existing GREET model to calculate emissions would unfairly penalize companies that had taken steps to reduce methane leakage. In final rules released Friday , the Treasury Department creates a pathway for companies to submit project-specific emissions data, an amendment that had been advocated for by ExxonMobil and the American Petroleum Institute, among others. Without this change, some companies considering ammonia export projects along the US Gulf Coast said they would instead consider applying for 45Q tax credits for carbon sequestration, which cannot be used in conjunction with 45V. Previous guidance only provided a pathway for renewable natural gas (RNG) produced from landfills to qualify for lucrative tax credits. The new rules include wastewater treatment, animal manure and coal mine methane. By Jasmina Kelemen Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US relaxes rules for H2 production tax credits: Update

25/01/03

US relaxes rules for H2 production tax credits: Update

Adds information on state-specific additionality rules in paragraphs 6-8. Houston, 3 January (Argus) — The US Treasury Department has issued long-awaited tweaks to 45V hydrogen production tax credit (PTC) guidelines, relaxing rules in a bid to make it easier for producers to benefit from the subsidy. The final guidance released today retains the fundamental approach from the preliminary rules set out in December for the tax credits of up to $3/kg. The "three pillars" of additionality, temporal matching and regional deliverability remain in place for electrolytic hydrogen, but the Treasury has tweaked certain aspects. The additionality rule prescribes that hydrogen production facilities can only use electricity from clean power generation capacity that predated them by 36 months or less to encourage a further build-out of such capacity. But under the final rules, hydrogen made with power from existing nuclear plants can qualify for the credits under certain circumstances. Hydrogen producers can access the credits if nuclear power companies demonstrate that adding hydrogen production to their revenue stream extends the life of reactors otherwise slated for shutdown. Companies such as utility Constellation Energy have argued that using some of their nuclear capacity for hydrogen would provide a pathway for future relicensing of their reactors , but that this would hinge on access to the tax credits. The final guidelines now also consider existing fossil fuel-based power plants where carbon capture capabilities have been retrofitted within the 36-month window prior to starting up hydrogen production as additional capacity. This makes hydrogen output using electricity from these plants eligible for the tax credits. The guidelines also introduce a rule under which hydrogen production in certain states is eligible for the tax credit even if it is based on clean power generated from existing assets that do not meet the 36-month window. "Electricity generated in states with robust greenhouse gas emissions caps paired with clean electricity standards or renewable portfolio standards" that meet specific criteria will automatically be considered as additional, the Treasury said. This is because in these states "the new electricity load" from electrolysers "is highly unlikely to cause induced grid emissions," it said, adding that rules on temporal matching and regional deliverability still apply. For now, "California and Washington are qualifying states under these final regulations," but other states could qualify in the future, according to the Treasury. Hourly matching — which prescribes that hydrogen has to be made from clean power produced within the same hour to avoid increased grid emissions — will now be required only from the start of 2030 onwards rather than from 2028. Annual matching will continue to apply until the end of 2029. The new phase-in date for hourly matching at the start of 2030 brings it in line with EU rules , although the bloc requires monthly rather than annual matching before then. US industry participants have repeatedly argued that the hourly matching rules drive up production costs and stymie the nascent industry's development, while environmentalists have warned that strict rules are necessary to curb greenhouse gas (GHG) emissions. The regional deliverability rules require electrolysers to source clean power from within their operating region — as defined by the Department of Energy — to avoid grid congestions between regions resulting in use of emissions-intensive power for hydrogen production. But the final guidelines would allow for direct "cross-region delivery" of power for hydrogen production where this "can be tracked and verified… on an hour-to-hour or more frequent basis". Under certain circumstances, US hydrogen producers could now even be eligible for the tax credits if they use electricity generated in Canada or Mexico, the Treasury said. ‘Significant improvements' A lobbying group representing the interests of hydrogen producers called the updated guidance "significant improvements" and said it would allow the industry to move forward to the next planning stage. "After years of strategic engagement and persistent advocacy, the issuance of this final rule now affords project developers the basis for evaluating opportunities to scale clean hydrogen deployments," Fuel Cell and Hydrogen Energy Association chief executive Frank Wolak said. A raft of hydrogen projects were announced in the US after President Joe Biden announced billions of dollars in funding and tax credits for hydrogen with the 2022 Inflation Reduction Act. But much of that euphoria fizzled out during the long wait for clarity on the rules and concerns that the Treasury's guidelines would be too strict to allow competitive production. Many would-be producers paused or cancelled US plans in 2024 because of widespread uncertainty over which projects would qualify for PTC, leaving companies unable to make long-term investment decisions. By Jasmina Kelemen and Stefan Krumpelmann Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US relaxes rules for H2 production tax credits

25/01/03

US relaxes rules for H2 production tax credits

Houston, 3 January (Argus) — The US Treasury Department has issued long-awaited tweaks to 45V hydrogen production tax credit (PTC) guidelines, relaxing rules in a bid to make it easier for producers to benefit from the subsidy. The final guidance released today retains the fundamental approach from the preliminary rules set out in December for the tax credits of up to $3/kg. The "three pillars" of additionality, temporal matching and regional deliverability remain in place for electrolytic hydrogen, but the Treasury has tweaked certain aspects. The additionality rule prescribes that hydrogen production facilities can only use electricity from clean power generation capacity that predated them by 36 months or less to encourage a further build-out of such capacity. But under the final rules, hydrogen made with power from existing nuclear plants can qualify for the credits under certain circumstances. Hydrogen producers can access the credits if nuclear power companies demonstrate that adding hydrogen production to their revenue stream extends the life of reactors otherwise slated for shutdown. Companies such as utility Constellation Energy have argued that using some of their nuclear capacity for hydrogen would provide a pathway for future relicensing of their reactors , but that this would hinge on access to the tax credits. The final guidelines now also consider existing fossil fuel-based power plants where carbon capture capabilities have been retrofitted within the 36-month window prior to starting up hydrogen production as additional capacity. This makes hydrogen output using electricity from these plants eligible for the tax credits. Hourly matching — which prescribes that hydrogen has to be made from clean power produced within the same hour to avoid increased grid emissions — will now be required only from the start of 2030 onwards rather than from 2028. Annual matching will continue to apply until the end of 2029. The new phase-in date for hourly matching at the start of 2030 brings it in line with EU rules , although the bloc requires monthly rather than annual matching before then. US industry participants have repeatedly argued that the hourly matching rules drive up production costs and stymie the nascent industry's development, while environmentalists have warned that strict rules are necessary to curb greenhouse gas (GHG) emissions. The regional deliverability rules require electrolysers to source clean power from within their operating region — as defined by the Department of Energy — to avoid grid congestions between regions resulting in use of emissions-intensive power for hydrogen production. But the final guidelines would allow for direct "cross-region delivery" of power for hydrogen production where this "can be tracked and verified… on an hour-to-hour or more frequent basis". Under certain circumstances, US hydrogen producers could now even be eligible for the tax credits if they use electricity generated in Canada or Mexico, the Treasury said. ‘Significant improvements' A lobbying group representing the interests of hydrogen producers called the updated guidance "significant improvements" and said it would allow the industry to move forward to the next planning stage. "After years of strategic engagement and persistent advocacy, the issuance of this final rule now affords project developers the basis for evaluating opportunities to scale clean hydrogen deployments," Fuel Cell and Hydrogen Energy Association (FCHEA) chief executive Frank Wolak said. A raft of hydrogen projects were announced in the US after President Joe Biden announced billions of dollars in funding and tax credits for hydrogen with the 2022 Inflation Reduction Act. But much of that euphoria fizzled out during the long wait for clarity on the rules and concerns that the Treasury's guidelines would be too strict to allow competitive production. Many would-be producers paused or cancelled US plans in 2024 because of widespread uncertainty over which projects would qualify for PTC, leaving companies unable to make long-term investment decisions. By Jasmina Kelemen and Stefan Krumpelmann Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Q&A: EU biomethane internal market challenged

25/01/02

Q&A: EU biomethane internal market challenged

London, 2 January (Argus) — The European Commission needs to provide clearer guidance on implementing existing rules for the cross-border trade of biomethane to foster a cohesive internal market as some EU member states are diverging from these standards, Vitol's Davide Rubini and Arthur Romano told Argus. Edited excerpts follow. What are the big changes happening in the regulation space of the European biomethane market that people need to watch out for? While no major new EU legislation is anticipated, the focus remains on the consistent implementation of existing rules, as some countries diverge from these standards. Key challenges include ensuring mass-balanced transport of biomethane within the grid, accurately accounting for cross-border emissions and integrating subsidised biomethane into compliance markets. The European Commission is urged to provide clearer guidance on these issues to foster a cohesive internal market, which is essential for advancing the EU's energy transition and sustainability objectives. Biomethane is a fairly mature energy carrier, yet it faces significant hurdles when it comes to cross-border trade within the EU. Currently, only a small fraction — 2-5pc — of biomethane is consumed outside of its country of production, highlighting the need for better regulatory alignment across member states. Would you be interested in seeing a longer-term target from the EU? The longer the visibility on targets and ambitions, the better it is for planning and investment. As the EU legislative cycle restarts with the new commission, the initial focus might be on the climate law and setting a new target for 2040. However, a review of the Renewable Energy Directive (RED) is unlikely for the next 3-4 years. With current targets set for 2030, just five years away, there's insufficient support for long-term investments. The EU's legislative cycle is fixed, so expectations for changes are low. Therefore, it's crucial that member states take initiative and extend their targets beyond 2030, potentially up to 2035, even if not mandated by the EU. Some member states might do so, recognising the need for longer-term targets to encourage the necessary capital expenditure for the energy transition. Do you see different interpretations in mass balancing, GHG accounting and subsidies? Interpretations of the rules around ‘mass-balancing', greenhouse gas (GHG) emissions accounting and the usability of subsidised biomethane [for different fuel blending mandates] vary across EU member states, leading to challenges in creating a cohesive internal market. When it comes to mass-balancing, the challenges arise in trying to apply mass balance rules for liquids, which often have a physically traceable flow, to gas molecules in the interconnected European grid. Once biomethane is injected, physical verification becomes impossible, necessitating different rules than those for liquids moving around in segregated batches. The EU mandates that sustainability verification of biomethane occurs at the production point and requires mechanisms to prevent double counting and verification of biomethane transactions. However, some member states resist adapting these rules for gases, insisting on physical traceability similar to that of liquids. This resistance may stem from protectionist motives or political agendas, but ultimately it results in non-adherence to EU rules and breaches of European legislation. The issue with GHG accounting often stems from member states' differing interpretations of the IPCC Guidelines for National Greenhouse Gas Inventories. Some states, like the Netherlands, argue that mass balance is an administrative method, which the guidelines supposedly exclude. Mass balancing involves rigorous verification by auditors and certifying bodies, ensuring a robust accounting system that is distinct from book and claim methods. This distinction is crucial because mass balance is based on verifying that traded molecules of biomethane are always accompanied by proofs of sustainability that are not a separately tradeable object. In fact, mass balancing provides a verifiable and accountable method that is perfectly aligned with UN guidelines and ensuring accurate GHG accounting. The issue related to the use of subsidised volumes of biomethane is highly political. Member states often argue that if they provide financial support — directly through subsidies or indirectly through suppliers' quotas — they should remain in control of the entire value chain. For example, if a member state gives feed-in tariffs to biomethane production, it may want to block exports of these volumes. Conversely, if a member state imposes a quota to gas suppliers, it may require this to be fulfilled with domestic biomethane production. No other commodity — not even football players — is subject to similar restrictions to export and/or imports only because subsidies are involved. This protectionist approach creates barriers to internal trade within the EU, hindering the development of a unified biomethane market and limiting the potential for growth and decarbonisation across the region. The Netherlands next year will implement two significant pieces of legislation — a green supply obligation for gas suppliers and a RED III transposition. The Dutch approach combines GHG accounting arguments with a rejection of EU mass-balance rules, essentially prohibiting biomethane imports unless physically segregated as bio-LNG or bio-CNG. This requirement contradicts EU law, as highlighted by the EU Commission's recent detailed opinion to the Netherlands . France's upcoming blending and green gas obligation, effective in 2026, mandates satisfaction through French production only. Similarly, the Czech Republic recently enacted a law prohibiting the export of some subsidised biomethane . Italy's transport system, while effective nationally, disregards EU mass balance rules. These cases indicate a deeper political disconnect and highlight the need for better alignment and communication within the EU. We know you've been getting a lot of questions around whether subsidised bio-LNG is eligible under FuelEU. What have your findings been? The eligibility of subsidised bio-LNG under FuelEU has been a topic of considerable enquiry. We've sought clarity from the European Commission, as this issue intersects multiple regulatory and legal frameworks. Initially, we interpreted EU law principles, which discourage double support, to mean that FuelEU, being a quota system, would qualify as a support scheme under Article 2's definition, equating quota systems with subsidies. However, a commission representative has publicly stated that FuelEU does not constitute a support scheme and thus is not subject to this interpretation. On this basis, FuelEU would not differentiate between subsidised and unsubsidised bio-LNG. A similar rationale applies to the Emissions Trading System, which, while not a quota obligation, has been deemed to not be a support scheme. Despite these clarifications, the use of subsidised biomethane across Europe remains an area requiring further elucidation from European institutions. It is not without risks, and stakeholders require more definitive guidance to navigate the regulatory landscape effectively. By Emma Tribe and Madeleine Jenkins Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Trump, macro issues ahead for US renewables

25/01/02

Viewpoint: Trump, macro issues ahead for US renewables

Houston, 2 January (Argus) — A combination of substantial policy shifts under president-elect Donald Trump and macroeconomic issues puts the US renewable power sector on uncertain footing to begin 2025. Analysts expect the federal tax credits that have bolstered new renewable generation during its substantial growth over the past decade will survive in some fashion, although Trump campaigned on repealing the Inflation Reduction Act (IRA). He also has promised 60pc tariffs on goods imported from China, a major player in the solar and battery storage supply chains. The ultimate effects may vary by project type and what the new administration is able to accomplish. Chinese solar products already face 50pc tariffs , which could temper any effects on the industry from Trump's protectionist trade policies, said Tom Harper, a partner at consultant Baringa specializing in power and renewables. But the new administration could make it more difficult to claim IRA incentives and could roll back federal power plant emissions rules , creating an environment that could slow the adoption of renewables. Utilities may become more cautious in using renewables because of higher costs, while others, such as companies with sustainability goals, might be able to weather the change, according to Harper. "There might be some very price insensitive corporate [power purchase agreement] buyers out there who are looking at a $45/MWh solar [contract] and now it's going to be $50/MWh after the tariff, and they'll be fine," he said. In addition, the US renewables industry is still weathering headwinds from supply chain constraints, increased borrowing rates and inflation, which have hampered new projects. For example, the PJM Interconnection — which spans 13 mostly Mid-Atlantic states and the District of Columbia — had approved more than 37,000MW of generation at the end of third quarter 2024, with only 2,400MW of that partially in service. Developers have blamed the delays on financing challenges, long lead times for obtaining equipment and local opposition to projects. Global problems, local solutions Changes to state procurement strategies could help. Maryland state delegate Lorig Charkoudian (D) next year will propose new state-run solar, wind and hydropower solicitations that would first target projects that have already cleared PJM's reviews. Her approach would echo programs in New Jersey and Illinois, and ultimately reduce utilities' reliance on renewable energy certificates (REC) procured elsewhere. "The idea is to give a path for these projects, so presumably they can be built within a few years," Charkoudian said. Utilities would use the new procurements for the bulk of their RECs, covering remaining demand by buying legacy Maryland solar credits and other PJM RECs on the secondary market. But a quick fix for Maryland's broader renewable energy objectives is unlikely after utilities used the alternative compliance payment (ACP) for two-thirds of their 2023 REC requirements. The fee for each megawatt-hour by which utilities miss their compliance targets serves as a de facto ceiling on REC prices. Maryland's ACP is low compared to neighboring states, where the qualifying REC pool overlaps, meaning that credits eligible in the state can fetch a higher price elsewhere. While lawmakers could raise the ACP to mitigate those issues, those costs would ultimately fall on utility customers. "As best as I can tell, the options are raise the ACP or adjust how we do it," Charkoudian said. "We're really concerned about ratepayer impacts, and so I don't think there's a real appetite to raise the ACP." In other states, the policy landscape is less certain. Pennsylvania governor Josh Shapiro (D) has no clear path for his proposed hike to the state's alternative energy mandate, should he choose to revisit it, after Republicans retained their state Senate majority in November. New Jersey state senator Bob Smith (D) has been working for two years to enshrine in law governor Phil Murphy's (D) goal of 100pc clean electricity, but the proposal failed to escape committee in 2024 after dying in 2023 over opposition to its support for offshore wind . Is the answer blowing in the wind? Offshore wind is a slightly different matter. Trump has been critical of the industry and federal regulators control much of the project permitting in the US. Moreover, as a burgeoning sector with higher costs, it could be more sensitive to the loss of the investment tax credit (ITC). Based on current expenses, Baringa's analysis suggests that losing the ITC could increase project costs by "at least" $30/MWh and push offshore wind REC prices in some cases near $150/MWh. That would be a "difficult cost for states to swallow", according to Harper. "We've seen a few offshore wind developers already say, 'Hey, we're not going to spend a dime more until we know what's going on,'" Harper said. Despite the challenging landscape, Charkoudian expects Maryland will move forward in areas it can control, such as expanding the onshore transmission, that will make offshore wind viable, whether it's now or "eight years from now". By Patrick Zemanek Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Business intelligence reports

Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.

Learn more