India has a federal structure of government, in which the power to legislate is divided between the union (central) legislature (Parliament) and the state legislatures, with subjects reserved for them under the Constitution of India. In accordance with the Constitution of India, Parliament has been entrusted with the power to legislate on matters pertaining to the regulation and development of oilfields and mineral oil resources and on petroleum and petroleum products. Additionally, ownership of minerals and other things of value within territorial waters or the continental shelf and of resources of the exclusive economic zone, is vested in the Union. The Government of India (GoI) is the sole and exclusive owner of hydrocarbons and petroleum, except when title passes to contractors under exploration and production contracts.

The Ministry of Petroleum and Natural Gas (MoPNG) is the administrative ministry of the GoI overseeing the petroleum and natural gas sector, including the administration of legislation. The Government of India (Allocation of Business) Rules 1961 entrust the transaction of hydrocarbon exploration and exploitation to the MoPNG.

The upstream sector is under the de facto regulatory control of the Directorate General of Hydrocarbons (DGH). The DGH was established by the MoPNG pursuant to a 1993 resolution to promote sound management of Indian petroleum and natural gas resources, with balanced regard for the environmental, safety, technological and economic aspects of petroleum activity. The DGH, in its advisory functions, advises the MoPNG on matters related to the upstream sector and the Indian government on the formulation of safety norms and regulations in oilfield operations.

The Petroleum and Natural Gas Regulatory Board (PNGRB) is the regulatory authority for the midstream and downstream sector. It is entrusted with regulating the refining, storage, transportation, distribution, marketing and sale of petroleum, petroleum products and natural gas. The PNGRB also exercises adjudicatory functions in the midstream and downstream sector. Other functions of the PNGRB include promoting a competitive market and addressing consumer grievances.

The following regulatory and administrative bodies have been established primarily to ensure safety in the oil and gas sector.

• The Oil Industry Safety Directorate (OISD) is a technical directorate established in 1986 under the MoPNG. By formulating and co-ordinating the implementation of a series of self-regulatory measures, the OISD serves as the safety regulator for upstream offshore blocks.
• The safety, health and welfare of mine workers is governed by the Mines Act 1952. The Directorate General of Mines Safety (DGMS) is a regulatory agency under the Ministry of Labour and Employment that aims to achieve risk- and hazard-free working conditions for persons employed in onshore blocks.

While the above regulatory and administrative agencies are established specifically to regulate the oil and gas sector, there are other government regulatory and administrative agencies pertaining to environmental and labour matters.

Companies in which the GoI has the majority shareholding include:

• Oil and Natural Gas Corporation Limited – the largest oil and gas exploration and production company. It has subsidiaries including refining companies, Hindustan Petroleum Corporation Limited and Mangalore Refinery and Petrochemicals Limited;
• Oil India Limited – the other government-owned exploration and production company;
• Indian Oil Corporation Limited – a refining and downstream company;
• Bharat Petroleum Corporation Limited – a refining and downstream company; and
• GAIL (India) Limited – a dominant player in the midstream and downstream sector, including natural gas pipelines.

The key legislation in the oil and gas sector is as follows.

• The Oilfields (Regulation and Development) Act 1948 (“Oilfields Act”), as amended by the Oilfields (Regulation and Development) Amendment Act, 2025, governs the upstream oil and gas sector. The Oilfields Act provides for the regulation of oilfields and the development of mineral oil resources and includes provisions relating to the licensing and leasing of oil and gas blocks. Pursuant to the Oilfields Act, the GoI is vested with the power to make rules with respect to petroleum leases and mineral oil development and the royalty rates to be paid by the holder of a petroleum lease.
• The Petroleum and Natural Gas Rules 1959 (“PNG Rules”) were enacted under the Oilfields Act and included detailed provisions for the granting of licences and leases for both offshore and onshore areas. A petroleum exploration licence (PEL) and petroleum mining lease (PML) were granted pursuant to the PNG Rules. In December 2025, the GoI notified the Petroleum and Natural Gas Rules 2025 (“PNG Rules 2025”), framed under the amended Oilfields Act and superseding the PNG Rules and the Petroleum Concession Rules 1949, which replace the PEL/PML framework with a single petroleum lease covering the exploration, development and production of all hydrocarbons (see 7.4 Material Changes in Law or Regulation).
• The Mines Act 1952 (“Mines Act”) and the Oil Mines Regulations 2017 contain provisions relating to the health, safety and welfare of workers in oil mines. The Mines Act also lists obligations in the form of duties for owners, agents and managers and prescribes strict penalties for contravention.
• The Petroleum Act 1934 (“Petroleum Act”) regulates matters relating to the import, transport, storage, production, refining and blending of petroleum.
• The Petroleum and Natural Gas Regulatory Board Act 2006 (“PNGRB Act”) provides for the establishment of the PNGRB, which has the authority to regulate the refining, processing, storage, transportation, distribution, marketing and sale of petroleum, petroleum products and natural gas.

In addition to the above, the government from time to time promulgates policies, standards, directives and guidelines to govern various aspects of the sector.

Prior to the liberalisation of the oil and gas sector in 1999, the Indian government and the national oil companies dominated it and the government adopted various licensing regimes to promote the upstream sector.

A block/field awarded under one licensing regime continues to be governed by such regime despite a new licensing regime coming into force. Therefore, the different blocks in India are governed by different licensing regimes, which can be broadly classified as follows.

• Nomination Regime: Under this licensing regime, exploration and production licences were awarded on a nomination basis to the two national oil exploration and production companies, OIL and ONGC, until the late 1970s. Under the Nomination regime, ONGC and OIL are operating six petroleum exploration licences and 355 petroleum mining lease blocks.
• NELP Regime: Post the nomination regime and prior to NELP, the GoI signed 56 contracts for exploration blocks and development fields. The introduction of the New Exploration Licensing Policy (NELP) in 1999 was a watershed moment in the upstream oil and gas sector. Under NELP, the GoI adopted international competitive bidding to award blocks to the private sector and foreign companies. The government awarded the blocks under the production-sharing model, wherein the contractor is required to pay a share of the profits earned to the government after deducting costs incurred. Nine bidding rounds were conducted under the NELP regime from 1999 to 2012. As of 31 March 2024, 19 petroleum exploration licences and 69 petroleum mining leases are operational under the production-sharing contract regime.
• HELP Regime: Due to certain shortcomings in the NELP regime, the GoI introduced the Hydrocarbon Exploration and Licensing Policy (HELP) in 2016 to attract greater private participation and foreign investment. Presently, oil and gas blocks are awarded under the HELP regime. Unlike its predecessor, HELP includes a revenue-sharing mechanism which allows marketing and pricing freedom for the hydrocarbons produced. Furthermore, a uniform licence is granted encompassing exploration and production of all hydrocarbons (such as oil, gas, coal-bed methane, shale gas/oil and gas hydrates). The GoI has also introduced the Open Acreage Licensing Policy (OALP) within the ambit of HELP. Unlike in NELP, where the government determined the blocks on offer for bidding, the OALP allows oil companies to choose hydrocarbon blocks from the designated area, which are then put up for bidding. The government launched OALP Bid Round X on 11 February 2025, offering 25 blocks across 13 sedimentary basins, covering an area of 1,91,986.21 square kilometres, for exploration and development through international competitive bidding. In the previously conducted OALP IX Bid Round, a total of 28 blocks were offered for bidding and were awarded to both government and private entities. As of December 2025, a total of 172 exploration blocks covering approximately 3,78,652 square kilometres had been awarded across the nine completed OALP bid rounds, with OALP Bid Round X being the largest single round by acreage offered under the HELP regime. On 30 March 2026, the GoI launched OALP Bid Round XI, offering a further 21 blocks covering approximately 80,234.49 square kilometres.
• To monetise various small and marginal hydrocarbon blocks under the national oil companies, the GoI rolled out the Discovered Small Field Policy 2015 (DSF), previously known as the “Marginal Field Policy”, to bring these fields into production. Similar to the HELP regime, a revenue-sharing mechanism and a uniform licensing policy are adopted for all hydrocarbons. The contractors must sell the crude oil exclusively in the domestic market through a transparent bidding process. In April 2025, the DGH launched the DSF Round IV, offering 55 discoveries across nine contract areas with estimated in-place reserves of around 258.59 million metric tonnes of oil equivalent. Under the previous DSF bid rounds (Rounds I to III), 85 revenue-sharing contracts (RSC) covering 175 fields have been awarded. Further, in April 2025, two contract areas were awarded under the Special DSF Round 2024.
• As per the model RSC, the GoI is the owner of petroleum, except for that part of the crude oil, condensate or gas title that passes to a contractor or any other person under the RSC. Once the government awards the block to the contractor, the contractor’s rights can be broadly classified into the following categories based on the block’s stage.
1. Exploration phase: Under the earlier PNG Rules, the contractor was required to obtain a PEL from the GoI (for offshore blocks) or the state government (for onshore blocks) under the Oilfields Act. Under the PNG Rules 2025, a single petroleum lease now covers exploration, development and production; however, for contracts entered into before the PNG Rules 2025 came into force, the PEL framework continues to apply. As per the PEL, the contractor is granted exclusive rights to drilling operations (information drilling or test drilling) and leasehold rights over any part of the licence area.
2. Development and production phase: Under the earlier PNG Rules, the contractor was required to obtain a PML for the areas covering the discoveries. The PML grants the contractor exclusive rights over the leased land to carry out mining operations for petroleum and natural gas. Under the PNG Rules 2025, the single petroleum lease encompasses the development and production phases, eliminating the need for a separate PML for new contracts.

Since the advent of NELP, the government has followed international competitive bidding procedures for awarding exploration blocks. Furthermore, since the introduction of OALP, the DGH has allowed private investors to apply directly to the GoI for any exploration in a new block, pursuant to a suo motu expression of interest (EoI).

The DGH helps investors propose their suo motu EoI based on data available in the National Data Repository (NDR), where sedimentary basins are classified into three categories:

• Category I;
• Category II; and
• Category III.

Category I sedimentary basins are those with established production and Category II and Category III basins are those with prospective and contingent resources. The NDR helps investors shortlist or select a block for submitting an EoI to the GoI. The entity proposing the EoI must fulfil certain technical and financial criteria and submit a participation bond. The technical criteria primarily consist of minimum operatorship experience, minimum acreage holding and minimum average annual production. The financial qualification criteria are primarily based on the net worth of the entity (which is based on the estimated expenditure for the committed work programme for the block concerned). Once the DGH receives an EoI, it may offer the whole block for bidding by publishing a notice inviting offers (NIO). A period of 60 days is allowed for bidders to submit bids after the NIO is published.

After receiving the bids, the DGH evaluates them based on certain parameters. The key evaluation criteria are a biddable work programme and the share of revenue offered to the GoI. The originator of an EoI is given an incentive during the bid evaluation. The bidders scoring the highest marks against the evaluation criteria are awarded the RSC.

Contractors pay royalties, profit share for blocks under the NELP regime and revenue share for blocks under HELP and the DSF. Under the revenue-share model, bidders pay a share of revenue for the commencement of production, as per their quoted bid.

The royalty rates are determined in accordance with the Oilfields Act, the PNG Rules (or the PNG Rules 2025 for new contracts) and the terms of the RSC. Under HELP, royalty rates for onshore blocks are 12.5% for oil and 10% for gas and coalbed methane. The royalty rates for hydrocarbons in shallow water, deep water and ultra-deep water blocks are 7.5%, 5% and 2.5% respectively. Furthermore, no royalty is payable for the first seven years for deep water and ultra-deep water blocks.

Pursuant to the granting of a licence, the licence holder must pay a nominal yearly fee for the licence based on each square kilometre or part thereof covered by the licence.

Furthermore, under the PNG Rules (or PNG Rules 2025 for new contracts), before a lease is granted, a security deposit must be paid to ensure observance of the lease terms. Additionally, on the granting of a lease, the lessee must pay the GoI or the state government, as the case may be, a fixed nominal yearly dead rent.

An entity engaged in upstream operations is subject to the following tax legislation.

Income Tax Act 1961 (“IT Act”)

Under the IT Act, the operator’s income is subject to tax. The profits and gains of the entities in upstream operations are computed based on the determined value and revenue realised from the sale of oil and gas under the contract, after allowing deductions. Deductions at a rate of 100% are allowed for capital and revenue expenditures incurred in respect of exploration operations and drilling operations. Companies can also claim depreciation for newly installed machinery and plants and can carry forward losses to set off against subsequent revenues. Entities in the upstream sector can also claim special allowances in the event of any infructuous or abortive exploration expenses, drilling or exploration activities or depletion of mineral oil in the mining area.

Indirect Taxes

Crude oil, high-speed diesel, petrol, natural gas and aviation turbine fuel are subject to VAT/sales tax/excise duty. The procurement side of the upstream sector is subject to the Central Goods and Services Tax Act 2017 (GST Act), a unified indirect tax levied on the supply of goods and services.

Prior to the advent of the NELP regime, the national oil exploration and production companies were nominated by the government to explore and develop oil and gas blocks. Since the early 2000s, these privileges have been reduced and national oil exploration and production companies now compete on equal terms with private companies for the awarding of blocks. Furthermore, the terms of the revenue-sharing contracts under the HELP and DSF regimes do not offer any special concessions to national oil exploration and production companies.

The GoI launched the “Make in India” initiative in 2014 to promote domestic manufacturing industries. Under the General Financial Rules 2017 (GFR), the GoI can provide for mandatory procurement of any goods or services from any category of bidders or provide preference to bidders on the grounds of promoting locally manufactured goods or locally provided services. Pursuant to the GFR, the Department for Promotion of Industry and Internal Trade, Ministry of Commerce and Industry, has issued the Public Procurement (Preference to Make in India) order 2017 (“PPP-MI Order”), as amended from time to time, most recently by DPIIT Order dated 19 July 2024. The PPP-MI Order introduced a Class-I / Class-II local supplier framework (pursuant to the 4 June 2020 amendment), with Class-I suppliers typically required to meet a minimum local content threshold of 50%. The PPP-MI Order is applicable to the procurement of goods, services and works (including turnkey works) by a GoI ministry or department, their attached or subordinate offices, autonomous bodies controlled by the GoI, GoI companies, their joint ventures and special purpose vehicles.

HP-HT (high pressure – high temperature) operations in upstream oil and gas businesses are specifically exempted by MoPNG from the applicability of the PPP-MI Order.

Under the RSC, the contractor must take the following steps to proceed towards development and production, once a commercial discovery is made.

• Notification to the Management Committee (MC): The contractor must notify the MC of the commercial discovery. The MC comprises two representatives from the GoI, one member from the DGH and two representatives of the contractor.
• Good International Petroleum Industry Practices (GIPIP) Tests: After notifying the MC, the contractor must run tests under GIPIP in respect of such discovery, to determine whether the discovery is of potential commercial interest and merits appraisal and the contractor must submit the information in relation to the particulars of such discovery to the MC.
• Appraisal Programme: If the contractor subsequently feels that the discovery merits appraisal, it should submit the appraisal programme to the MC.
• Field Development Plan: 24 months (for onshore blocks) and 36 months (for offshore blocks) from the submission of the appraisal programme, the contractor must notify the MC of its intention to submit a field development plan (FDP) for the discoveries. The FDP comprises three parts:
1. a detailed technical assessment report for the commercial development of the field;
2. a detailed work plan for commercial development of the field, with timelines; and
3. estimated costs and budgets for the commercial production from the field, to demonstrate the economic viability of the project.
• Development Phase: This begins after approval of the technical assessment report and continues until commencement of commercial production.

The terms of the licence of newly awarded blocks are governed by the RSC, the key terms of which are as follows.

Exploration Period

A contractor is granted a six-year exploration period from the date of execution of the RSC. The exploration period is divided into two phases, namely:

• an initial exploration phase consisting of three contract years with an extension of one year where the contract areas fall onland and in shallow water areas or with a provision for up to two extensions of one year each where the contract areas fall in deep water, ultra-deep water and a specified basin; and
• a subsequent exploration phase consisting of three contract years with a similar extension policy, where the committed work programme is linked to the exploration period.

Work Programme

During the initial exploration period, the contractor must complete the work programme quoted in its bid, which will serve as its committed work programme for that phase. The subsequent work programme is submitted by the contractor prior to the commencement of the subsequent exploration phase. In the event that the contractor fails to fulfil the committed work programme during the initial exploration phase or the subsequent work programme during the subsequent exploration phase, as the case may be, then liquidated damages can be levied on the contractor.

Relinquishment

A contractor may relinquish the contract area:

• on completion of the committed work programme for the Initial Exploration Phase;
• on completion of the subsequent work programme for the Subsequent Exploration Phase; or
• on failure to submit the FDP in relation to the discovery of petroleum within the stipulated time, as provided in the RSC.

Upon relinquishment of the contract area, the contractor must demobilise all equipment and installations in accordance with the abandonment plan and perform all site restoration activities in accordance with the applicable guidelines and rules.

Period of Lease

The lease granted to the contractor under the RSC is valid for an initial period of 20 years from the date of the grant.

Domestic Supply

The contract restricts the contractor’s freedom to sell hydrocarbons. The RSC specifies that until India becomes self-sufficient and able to meet its total national demand, the contractor is obliged to sell oil and gas produced in India to the Indian market.

Extension

The term of any exploration phase of the exploration period, appraisal period, development phase or the RSC may be extended, on account of a force majeure event, as provided for in the RSC. The DGH, on the recommendation of the MC, can also extend the above-mentioned term.

Liability

The liability of the members comprising the contractor is joint and several under the previous contracts. Some of the recent model contracts provide for liability of the members comprising the contractor to the extent of their individual participating interest.

Termination

The contractor may terminate the RSC with respect to any development or contract area by giving 90 days’ prior written notice (contract area) or 180 days’ prior written notice (development area). The GoI may terminate the RSC by providing 90 days’ prior written notice in the event that the contractor has submitted a false statement or has engaged in unauthorised extraction of hydrocarbon without the permission of the government or is adjudged bankrupt or has assigned any interest in the RSC without the prior consent of the government.

Abandonment

Upon expiry or termination of the RSC or relinquishment of the contract area, the contractor is, inter alia, required to:

• remove all equipment and installations from the contract area, pursuant to an abandonment plan; and
• perform site restoration in accordance with GIPIP (the abandonment plan has to be prepared as per the Site Restoration Fund Scheme 1999).

The PNG Rules (and the PNG Rules 2025 for new contracts) allow the transfer of the petroleum lease (or PEL/PML for legacy contracts), subject to prior government approval. Furthermore, the RSC stipulates prior written consent of the government for:

• assignment of a participating interest;
• a change in control of the member or its parent company; or
• a change in the relationship of the contractor with the companies providing the guarantee (typically the parent company).

However, a member of the contractor cannot assign or transfer its right under the RSC, in the event its participating interest is to be retained by the proposed assignor or the percentage interest of the assignee is less than 10% of the total participating interest of all the constituents of the contractor, except in special circumstances where the government, on the recommendation of the MC, may permit otherwise.

The assignee/transferee to whom the participating interest is assigned/transferred has to satisfy the following requirements to obtain the consent of the government:

• the capacity and ability to meet the obligations stipulated in the RSC and willingness to provide an unconditional undertaking to the government to assume its participating interest share of obligations and to provide guarantees as provided in the contract;
• the assignee/transferee should not be a company incorporated in a country with which India has restricted trade or business;
• willingness to comply with any reasonable conditions of the government as may be necessary in the circumstances, with a view to ensuring performance under the contract;
• the assignee/transferee must provide an irrevocable, unconditional bank guarantee from a scheduled commercial bank in India, acceptable to the government, in favour of the government (where the transferee/assignee is an affiliate of the transfer); and
• the assignee/transferee must provide a financial and performance guarantee from its parent entity.

The RSC envisages deemed approval in the event the government does not accord its consent or does not respond to a request for assignment or transfer by a member of the contractor within 120 days after such request and receipt of all information.

The contractor is granted marketing and pricing freedom under the HELP regime and is permitted to sell petroleum and natural gas exclusively to the domestic market from the contract area on an arm’s length basis.

The government has also permitted marketing and pricing freedom for new discoveries under existing contracts, provided the FDPs are approved after 28 February 2019. In October 2020, MoPNG approved the “Natural Gas Marketing Reforms”, whereby marketing freedom is granted to blocks for which production sharing contracts provide pricing freedom.

For gas produced from ONGC/OIL nomination fields, NELP and Pre-NELP blocks, the New Domestic Gas Pricing Guidelines 2014 (Gas Pricing Guidelines) apply. In April 2023, the Gas Pricing Guidelines were revised to ensure a stable pricing regime for domestic gas consumers. The price of domestic natural gas (APM Price) will be 10% of the average price of the Indian crude basket for the preceding month and the price shall be subject to monthly revision. Gas produced from ONGC and OIL’s nomination fields will have a floor price of USD4/mBtu and a ceiling of USD6.5/mBtu. With respect to NELP and Pre-NELP blocks, the APM price so declared would be applicable, subject to the provisions of the PSC.

Just like the upstream sector, the midstream and downstream sectors are liberalised, allowing free participation by private investors, subject to obtaining the requisite approvals and licences from the government. Foreign investors are permitted to invest in the midstream and downstream sector subject to restrictions under the foreign direct investment conditions (see 4.1 Foreign Investment Rules Applicable to Domestic Investments in Hydrocarbons).

The retail and pipeline spheres are dominated by PSUs. The development of pipeline infrastructure across the country is uneven: states close to gas sources have robust networks, while those farther from gas sources have significantly smaller ones.

As discussed in 1.3 National Companies, the PSU GAIL owns more than half of India’s pipeline infrastructure and is a dominant player in the sector.

Right of Access

Third-party access to the natural gas pipeline is governed by the Petroleum and Natural Gas Regulatory Board (Guiding Principles for Declaring or Authorising Natural Gas Pipeline as Common Carrier or Contract Carrier) Regulations 2009 (“NG Pipeline Guiding Regulations”), while the Petroleum and Natural Gas Regulatory Board (Guiding Principles for Declaring or Authorising Petroleum and Petroleum Products Pipeline as Common Carrier or Contract Carrier) Regulations 2012 (“Petroleum Pipeline Guiding Principles”) deal with third-party access to petroleum and petroleum products pipelines and other infrastructure. See 3.11 Third-Party Access to Infrastructure for further discussion on third-party access.

Transportation

A customer or shipper enters into a contract with an authorised entity under the Petroleum and Natural Gas Regulatory Board (Authorising Entities to Lay, Build, Operate or Expand Natural Gas Pipelines) Regulations 2008 (“NG Pipeline Regulations”) for natural gas transportation or the PNGRB (Authorising Entities to Lay, Build, Operate or Expand Petroleum and Petroleum Products Pipelines) Regulations 2010 (“Petroleum Pipeline Regulations”) for petroleum or petroleum product transportation.

Tariffs

The tariff for pipelines authorised under the NG Pipeline Regulations or the Petroleum Pipeline Regulations is fixed by the PNGRB based on the tariff zone and based on the bid submitted by the entity. For natural gas pipelines laid down before or authorised before the NG Pipeline Regulations, the tariff is determined by the PNGRB as per the Petroleum and Natural Gas Regulatory Board (Determination of Natural Gas Pipeline Tariff) Regulations 2008 (“NG Tariff Regulations”) and for petroleum and petroleum products pipeline entities authorised or laid down before the Petroleum Pipeline Regulations the tariff is determined by the PNGRB under the Petroleum and Natural Gas Regulatory Board (Determination of Petroleum and Petroleum Products Pipeline Transportation Tariff) Regulations 2024 (“Petroleum Pipeline Tariff Regulations”).

Authorisation from the PNGRB

Pursuant to Section 16 of the PNGRB Act, an entity is not permitted to develop pipelines or a natural gas distribution network without authorisation from the PNGRB. Such authorisation may be granted by the PNGRB either:

• on receipt of an application for the development of a pipeline; or
• if the PNGRB is of the opinion that it is necessary or expedient to develop a pipeline in a specified geographical area.

In each case, the PNGRB must invite applications from interested parties to develop such a pipeline. The PNGRB is required to adopt an objective and transparent manner in selecting an entity as specified by the NG Pipeline Regulations or Petroleum Pipeline Regulations, guided by principles including the objective of promoting competition, avoiding infructuous investment, maintaining or increasing supplies or securing equitable distribution or ensuring adequate availability of natural gas throughout India.

The NG Pipeline Regulations and the Petroleum Pipeline Regulations govern the submission of bids, their evaluation, the awarding of authorisations and the development of pipeline infrastructure. An entity is authorised to develop a pipeline after a competitive bidding process, following evaluation of its technical and financial bid. The NG Pipeline Regulations and the Petroleum Pipeline Regulations specify exhaustive technical and financial criteria that an entity must fulfil to be awarded authorisation to develop a pipeline.

Other Licences Required for Midstream/Downstream Operations

These include the following:

• a licence under the Petroleum Act 1934 read with the Petroleum Rules 2002 (“Petroleum Rules”) is required from the government authority for storage of petroleum, based on the quantity and class of petroleum (similarly, a licence under the Gas Cylinder Rules framed under the Explosives Act 1884 is required for filling, possession, transport and the importation of petroleum);
• a licence under the Manufacture, Storage and Import of Hazardous Chemical Rules 1989; and
• a licence under Static and Mobile Pressure Vessels (Unfired) Rules 2016 framed under the Explosives Act 1884 for manufacturing, filling, delivery and repair of pressure vessels and transportation of compressed gas.

In addition to the above, construction of pipelines also requires environmental clearance from the Ministry of Environment, Forest and Climate Change (MoEFCC), authorisations from the relevant state pollution control boards under the provisions of the Air (Prevention and Control of Pollution) Act 1981 and the Water (Prevention and Control of Pollution) Act 1974 and other approvals prescribed under applicable local laws.

The prices of petrol and diesel are market-determined in line with changes in the international market prices and other market conditions.

The NG Tariff Regulations and the Petroleum Pipeline Tariff Regulations set out procedures for determining natural gas and petroleum pipeline tariffs, respectively. As per the NG Tariff Regulations, the entity to which the regulations apply must submit all technical, operating, financial and cost data of the natural gas pipeline project to the PNGRB for determination of the natural gas pipeline tariff. The tariff is determined based on a reasonable rate of return on the normative level of capital employed, plus the normative level of operating expenses in the natural gas pipeline. The unit rate of the natural gas pipeline tariff for a period is calculated using the discounted cash flow (DCF) methodology, which assumes a reasonable rate of return equal to the project’s internal rate of return. The rate of return on capital employed will be the rate of return on capital employed equal to 12% post-tax. The rate of return on capital employed, once applied to a natural gas pipeline project, remains fixed throughout the project’s economic life.

An authorised entity may charge shippers’ compression charges in addition to the transportation tariff under regulations framed by the PNGRB. For petroleum and petroleum products pipelines, the tariff is determined in accordance with the Petroleum Pipeline Tariff Regulations. Depending on when the pipeline was authorised/commissioned, the tariff is either benchmarked against the goods tariff table of the Indian Railways or calculated using the DCF methodology, as applicable.

The IT Act and the GST Act are applicable to midstream and downstream operations (see 2.4 Income or Profits Tax Regime: Upstream).

No special rights are given to national oil or gas companies in connection with downstream licences and PSUs and private entities are treated equally.

See 2.6 Local Content Requirements: Upstream for further details.

Unlike in the upstream sector, no standard contract is entered into by the midstream/downstream licence holder, so the terms of the licence and the principal legislation under which such licence is awarded gain importance. The licensee must abide by the terms of such licence and the legislation under which such licence is granted.

As per the NG Pipeline Regulations, an authorised pipeline entity must meet its annual target of transporting natural gas equal to the volume quoted in the bid and the PNGRB will monitor actual progress in this regard on a quarterly basis. Failure to meet the annual target will result in encashment of the performance bond submitted to the PNGRB during the time of authorisation, in proportion to the penalty specified under the NG Pipeline Regulations. An authorised entity operating pipeline facilities must enforce safety, technical and services standards including the affiliated code of conduct.

The Petroleum and Minerals Pipelines (Acquisition of Right of User in Land) Act 1962 (“PMPA Act”) provides the framework governing the acquisition of right of user in land for laying pipelines for the transportation of natural gas and matters connected therewith. The PMPA Act provides the procedure for acquisition, restrictions on the use of land and the compensation payable to the persons interested in the land. Pursuant to the PMPA Act, the GoI, for the purpose of acquisition of land for the laying of pipelines in the public interest, declares its intention by way of notification. Any person interested in the land after the declaration made by the GoI may object within 21 days of such notification. After the resolution of the objection (if any), the GoI may declare that the right to use the land for the laying of pipelines may be acquired, after which the right over the land vests in the GoI and these rights can be passed on to the state government or any other corporation or entity.

The PMPA Act envisages that fair compensation should be paid to any person who was interested in land acquired under the PMPA Act. Additionally, for the purpose of establishing refineries and terminals, the government may acquire land from the public in accordance with the procedure prescribed under the Right to Fair Compensation and Transparency in Land Acquisition, Rehabilitation and Resettlement Act 2013, provided that such land is acquired for a public purpose.

Notwithstanding the above, land may be procured by way of sale or lease entered into directly with the owners of the land.

As discussed in 1.1 System of Hydrocarbon Ownership, the GoI is responsible for the policy framework for hydrocarbons in India and the Union Parliament legislates on matters related to hydrocarbons. The PNGRB, established under the PNGRB Act, regulates activities related to the transportation of hydrocarbons in India.

Please refer to 3.2 Downstream Operations Run by a National Monopoly: Rights and Terms of Access and 3.4 Fiscal Terms and Commercial Arrangements: Midstream/Downstream for further discussion on rules affecting access and transportation costs.

The NG Pipeline Regulations and the NG Pipeline Guiding Principles address third-party access to natural gas pipelines and related infrastructure, whereas the Petroleum Pipeline Guiding Principles and the Petroleum Pipeline Regulations address third-party access to petroleum and petroleum product pipelines. The NG Pipeline Regulations and the Petroleum Pipeline Regulations require authorised pipeline entities to make additional capacity available for use on a common carrier basis. The entities must also actively promote the capacity available in the pipelines to encourage maximum utilisation.

The NG Pipeline Guiding Principles and the Petroleum Pipeline Guiding Principles have been framed with the objective of serving consumer interests by promoting competition and avoiding infructuous investments through the optimum utilisation of the natural gas and petroleum pipeline infrastructure. Both the NG Pipeline Guiding Principles and the Petroleum Pipeline Guiding Principles classify pipelines into two categories, namely, a contract carrier (pipelines for transportation of natural gas/petroleum or petroleum products by more than one entity, over and above the entity’s own requirement, pursuant to firm contracts for at least one year) and a common carrier (pipelines for transportation of natural gas/petroleum or petroleum products by more than one entity as the PNGRB may declare or authorise from time to time). The company laying, building, operating or expanding a common carrier or contract carrier pipeline has the right of first use of the capacity for its own and its associates’ requirements. Common carrier capacity is allocated on a non-discriminatory, first-come, first-served basis.

The NG Pipeline Regulations and the Petroleum Pipeline Regulations recognise the concept of allowing capacity in pipelines to be used by any entity on a non-discriminatory basis, through contract carriers or common carrier arrangements, by entities that lay, build, operate or expand petroleum and petroleum product pipelines.

As discussed in 3.8 Other Key Terms: Midstream/Downstream, because the midstream/downstream sector is highly regulated and operates without contracts, the terms of the licences and the legislation under which such licences are granted are important in determining the various rights of the entities.

With respect to transportation and marketing of natural gas, an authorisation from the PNGRB under the Petroleum and Natural Gas Regulatory Board (Authorising Entities to Lay, Build, Operate or Expand City or Local Natural Gas Distribution Networks) Regulations 2008 (“CGD Regulations”) is granted. An entity given authorisation under the CGD Regulations is granted two forms of exclusivity:

• exclusivity for development of the city gas distribution (CGD) network; and
• exemption from the purview of a common carrier or contract carrier.

Exclusivity for Development of a CGD Network

The PNGRB (Exclusivity for City or Local Natural Gas Distribution Network) Regulations, 2008 (“CGD Exclusivity Regulations”) specify that the PNGRB may grant an authorised entity exclusivity in developing the CGD network for the economic life of the project, which, pursuant to the CGD Regulations, is prescribed in the authorisation granted to the successful bidding entity. The period of exclusivity for development of a CGD network granted to an authorised CGD entity is 25 years.

Exemption From Purview of a Common Carrier or Contract Carrier

Pursuant to Section 20 of the PNGRB Act, the PNGRB has the right to declare a particular pipeline a common carrier or a contract carrier, in which case, other entities may be permitted by the PNGRB to use such pipeline. Pursuant to CGD Regulations, an exemption from the purview of a common carrier or contract carrier is granted for a period of eight years.

Furthermore, if (i) the entity meets all works programme targets in a timely manner, an extension of two years is granted and (ii) if the entity does not meet all works programme targets in a timely manner but completes the cumulative works programme at the end of the eighth year, an extension of one year is granted, for exemption from purview of a common carrier or contract carrier.

While India does not export crude oil or LNG, petroleum products may be exported, subject to obtaining a no-objection certificate from the MoPNG.

Any transfer of licences granted under the Petroleum Rules is subject to prior approval by the issuing authority.

The authorisation granted by the PNGRB for laying, developing and operating a petroleum or natural gas pipeline (or a CGD network) is subject to lock-in periods and any transfer of such authorisation is subject to the approval of the PNGRB. Typically, the PNGRB allows the transfer of authorisation on the same terms and conditions applicable to the transferor.

Foreign Investment in Petrol and Gas

Automatic route

100% foreign direct investment (FDI) under the automatic route is permitted in the following: 

• exploration activities of oil and natural gas fields;
• infrastructure related to the marketing of petroleum products and natural gas;
• marketing of natural gas and petroleum products, petroleum product pipelines and natural gas pipelines; and
• LNG re-gasification infrastructure, market study, formulation and petroleum refining in the private sector.

FDI in petroleum refining by PSUs has been permitted up to 49% under the automatic route, without any divestment or dilution of domestic equity in existing PSUs. In July 2021, the FDI policy was further liberalised, allowing FDI up to 100% under the automatic route for petroleum-refining PSUs, subject to in-principle approval for strategic disinvestment of such PSU by the GoI.

In March 2021, the government placed LNG imports under the Open General Licensing (OGL) category and the establishment of LNG infrastructure, including LNG terminals, is also permitted under 100% FDI (automatic route) to promote the use and distribution of LNG. Further, in July 2021, the GoI amended the FDI policy for the petroleum and natural gas sector, pursuant to which foreign investment of up to 100% under the automatic route has been allowed in petroleum-refining PSUs for which the GoI has granted in-principle approval for strategic disinvestment.

Government route

Under the extant Indian foreign exchange laws, an entity of a country which shares its land border with India or the beneficial owner of an investment into India who is situated in or is a citizen of, any country which shares a land border with India, can only invest in an Indian entity with the approval of the GoI, irrespective of the sector involved. This approval is applicable whether the beneficial ownership is held directly or indirectly.

Dispute Resolution in Relation to Foreign Investors

As of now, the RSC does not provide for international arbitration and arbitration under the RSC is pursuant to the (Indian) Arbitration and Conciliation Act 1996, with the venue of the arbitration being New Delhi. A contractor, therefore, does not have the freedom to choose the arbitration procedure or law. However, the Oilfields (Regulation and Development) Amendment Act, 2025, enables the GoI to make rules allowing the resolution of disputes relating to petroleum leases through alternative dispute resolution methods in a place within or outside India.

For the downstream sector, in the absence of any contract governing the rights of private entities vis-à-vis the government, the legislation under which the licence or authorisation is granted determines the dispute resolution process. In addition to its regulatory function, the PNGRB also performs an adjudicatory function for the downstream sector and has jurisdiction to hear and decide any dispute arising under the PNGRB Act and its regulations.

In India, there are currently no specific sanctions with respect to investing in the oil and gas sector. However, any investment in that sector must comply with exchange control regulations and applicable laws.

Key Environmental Laws

The key environmental laws applicable to various industries, including entities in the oil and gas sector, are listed below.

Water (Prevention and Control of Pollution) Act 1974 (“Water Act”)

The Water Act was enacted to govern the prevention and control of water pollution and the maintenance/restoration of the wholesomeness of India’s water. Pursuant to Section 25 of the Water Act, prior consent of the relevant State Pollution Control Board (SPCB) is required to establish any industry which is likely to discharge sewage or trade effluent into any land or water source.

Air (Prevention and Control of Pollution) Act 1981 (“Air Act”)

The Air Act was enacted to provide for the prevention, control and abatement of air pollution. Under Section 19 of the Air Act, state governments are empowered to declare any areas within their states as air pollution control areas. Section 21 of the Air Act prohibits the undertaking of industrial activities in the air pollution control area without the previous consent of the SPCB.

Environment Protection Act 1986 (“EP Act”)

This was enacted to govern the protection and improvement of the environment and, in furtherance thereof, the MoEFCC issued a notification in 2016 on environmental impact assessments (“EIA Notification”) to minimise the adverse impact of development projects on the environment. Furthermore, as per the Coastal Regulation Zone Notification 2019, the exploration and extraction of oil and natural gas in the coastal zone requires permission from the MoEFCC.

Hazardous Wastes (Management, Handling and Trans-boundary Movement) Rules 2016 (“HWM Rules”)

The HWM Rules were framed under the EP Act to provide for the management and transportation of hazardous waste. Under Rule 6 of the HWM Rules, the occupier of a facility that generates hazardous waste is required to obtain authorisation under the HWM Rules from the relevant SPCB.

Van (Sanrakshan Evam Samvardhan) Adhiniyam, 1980 (formerly Forest (Conservation) Act 1980) (“Forest Act”), as amended by the Forest (Conservation) Amendment Act, 2023

Pursuant to Section 2 of the Forest Act, prior permission is required from the forest department of the relevant state, along with subsequent approval from the MoEFCC, for use of forest land for a non-forest purpose.

Wildlife (Protection) Act 1972

This also applies to gas/oil exploration.

Oil Mines Regulations 2017

This includes detailed provisions relating to the health, safety and welfare of workers in oil mines.

The Merchants Shipping Act 2025

This Act establishes safeguards and civil liability for oil pollution damage.

Key Environmental Regulators

These are the MoEFCC and the Central Pollution Control Board.

As per the EIA Notification, all projects for offshore and onshore oil and gas development and production, except exploration, require prior environmental clearance. Seismic surveys, which are part of exploration surveys, are exempted, provided the concession areas have previous clearance for physical surveys.

The assessment is carried out by the Expert Appraisal Committee (EAC) set up under the aegis of the MoEFCC. After the assessment is completed, the EAC makes recommendations to the concerned regulatory authority either to grant prior environmental clearance on stipulated terms and conditions or to reject the application for prior environmental clearance, together with reasons.

Environmental Impact Assessments

An EIA involves three stages, which are outlined below.

Scoping

At the scoping stage, the EAC determines comprehensive terms of reference that address all relevant environmental concerns for the preparation of the EIA report. In February 2020, sector-specific standard terms of reference were developed to streamline the process of scoping and ensure uniformity across the proposals. All new projects or activities are to be referred to the EAC by the regulatory authority within 30 days of the application date to recommend the specific terms of reference. If the regulatory authority does not refer the matter to the EAC within 30 days of the application date, it will issue standard terms of reference on the 30th day.

Public consultation

This public hearing, at the site or in close proximity to it, is conducted to ascertain local concerns and obtain written responses from other stakeholders. Upon completion of the public consultation, the applicant must address material environmental concerns raised during the process and make appropriate changes to the draft EIA and environmental management plan.

Appraisal

This stage covers detailed scrutiny by the EAC of the application and the final EIA report. The appraisal is conducted transparently and the applicant is invited to provide any necessary clarifications. On conclusion of this proceeding, the EAC makes recommendations either to grant environmental clearance on stipulated terms and conditions or to reject the application for environmental clearance, together with reasons.

The MoEFCC, pursuant to a notification in January 2020, changed onshore and offshore oil and gas exploration activities from Category A to Category B2. As a result, oil and gas exploration activities will now require environmental clearance only from the states and will not require preparation of an EIA report or public hearing. Development or production activities, both on offshore or onshore fields as hydrocarbons blocks, continue to fall under Category A, requiring an EIA report and public hearing.

In addition to the general environmental, health and safety regulations, entities involved in offshore development must adhere to the Petroleum and Natural Gas (Safety in Offshore Operations) Rules 2008 (“PNG Offshore Rules”). These rules have been framed under the Oilfields Act and prescribe safety standards and measures to be taken for the safety of offshore oil and gas operations. The PNG Offshore Rules stipulate various consent requirements and prescribe penalties for contravention of these rules.

Under the PNG Rules (or PNG Rules 2025 for new contracts), upon termination of the petroleum lease (or PEL/PML for legacy contracts), the contractor must deliver the leased area and any wells contained therein in good condition. The licensee/lessee is given six months to remove or dispose of any petroleum recovered during the period of such licence or lease, as well as stores, equipment, tools and machinery and other improvements on the land covered by the licence or lease. Failure to remove or dispose of the materials from the land within the aforementioned timeline entitles the government to auction the material lying on the land.

Under the RSC regime, upon expiry or termination of the RSC or relinquishment of the contract area, the contractors are, among other things, required to:

• remove all equipment and installations from the contract area pursuant to an abandonment plan; and
• perform site restoration in accordance with any specific guidelines, rules or regulations formulated by the government in relation to site restoration and, in the absence of any specific guidelines, rules or regulations by GIPIP, take all other actions necessary to prevent hazards to human life, to the property of others and to the environment.

The government has published the Site Restoration and Abandonment Guidelines for Petroleum Operations, which provide detailed guidelines for decommissioning offshore and onshore production sites.

For blocks under the Discovered Small Field Policy 2015, it is also envisaged that a site restoration fund should be maintained by the contractor, as per the Site Restoration Fund Scheme 1999.

Under the Paris Agreement, India submitted an updated Nationally Determined Contribution (NDC) in August 2022, enhancing its climate commitments. India pledged to:

• reduce the emission intensity of its GDP by 45% over 2005 levels by 2030 (up from 33–35% in the original 2015 NDC);
• achieve 50% cumulative installed electric power capacity from non-fossil energy sources by 2030 (targeting 500 GW of non-fossil fuel-based capacity); and
• create an additional carbon sink of 2.5–3 billion tonnes of CO₂-equivalent through additional forest and tree cover.

At COP26 (Glasgow, November 2021), India announced its “Panchamrit” climate commitments, including a long-term target to achieve net-zero emissions by 2070. India has already achieved several targets ahead of schedule: in July 2025, India achieved the milestone of 50% non-fossil power generation capacity and by February 2026, non-fossil capacity reached approximately 52.57%.

In March 2026, the Union Cabinet approved India’s new NDC for the period 2031–2035, further enhancing the country’s climate ambition. The 2035 targets include:

• reducing the emission intensity of GDP by 47% from 2005 levels;
• achieving 60% cumulative installed electric power capacity from non-fossil fuel-based energy sources; and
• creating a carbon sink of 3.5–4 billion tonnes of CO₂-equivalent through forest and tree cover.

These enhanced commitments align with India’s vision of “Viksit Bharat” (Developed India) by 2047 and its net-zero target of 2070.

While no specific legislation has been enacted to fulfil its commitment to the Paris Agreement, the government has formulated various guidelines and policies to promote renewable energy. In 2008, the government launched the National Action Plan on Climate Change, under which eight national missions to advance India’s climate change-related objectives were established, including missions related to solar power, water, sustainable agriculture and energy efficiency.

See 5.1 Environmental Laws and Environmental Regulator(s) for specific environmental legislation that, in turn, relates to climate change.

As discussed in 1.1 System of Hydrocarbon Ownership, under the constitutional scheme of India, power to legislate is divided between the centre and the states. As a result, the government authorities from which licences are obtained will vary depending on the authority that legislates on the subject. Furthermore, in India, power is decentralised to local authorities for better administration.

The energy transition plays an important role in GoI policies, with a focus on clean energy. India set a net-zero emissions target for 2070 at COP26 and has been actively promoting renewable energy and the government has been encouraging the clean energy transition by providing financial incentives and support to stakeholders in the clean energy ecosystem.

Some of the major government programmes focused on energy transition are as follows.

National Green Hydrogen Mission

The GoI has launched the National Green Hydrogen Mission, providing an enabling framework for the development of green hydrogen in the country. The mission provides a roadmap for 2030 to make India a global hub for the production, use and export of green hydrogen and a framework for the creation of a comprehensive green hydrogen ecosystem. The GoI aims to achieve 5 MMT of green hydrogen production capacity per annum and reduce dependence on fossil fuel imports. The GoI has proposed a phased approach to creating a hydrogen ecosystem, with the first phase focusing on building demand for green hydrogen and reducing its cost to enable greater deployment. The key sectors for demand creation would be refineries, fertilisers and the CGD sector. The second phase would focus on broader adoption of green hydrogen across other sectors to achieve net-zero emissions. Under the mission, the GoI provides for, inter alia, the Strategic Interventions for Green Hydrogen Transition Programme, which would focus on developing domestic manufacturing units for electrolysers and other technology along with producing green hydrogen and setting up pilot projects in the sectors with potential to adopt and transition to green hydrogen, such as steel, heavy-duty mobility and shipping, etc.

National Policy on Biofuels 2018 (“Biofuel Policy”)

The policy published by MoPNG seeks to increase the use of biofuel in India’s energy and transportation sector. The Biofuel Policy categorises biofuels as “Basic Biofuels”, namely First Generation (1G) bioethanol and biodiesel and “Advanced Biofuels”, namely Second Generation (2G) ethanol, Municipal Solid Waste (MSW) to drop-in fuels, Third Generation (3G) biofuels, bio-CNG, etc, to enable the extension of appropriate financial and fiscal incentives under each category. The Biofuel Policy sets an indicative target of 20% ethanol blending in petrol and 5% biodiesel blending. The National Policy on Biofuels was amended in June 2022 for advancing the ethanol blending target of 20% blending of ethanol in petrol to 2025-26 from 2030.

Sustainable Aviation Fuel (SAF)/ BioAviation Turbine fuel (Bio-ATF)

The GoI has set targets of 1%, 2% and 5% blending of SAF in aviation turbine fuel initially for international flights with effect from 2027, 2028 and 2030, respectively.

Green Credit Programme under the Environment (Protection) Act

The GoI published the Green Credit Rules, 2023, under the Environment (Protection) Act, 1986, on 12 October 2023. Pursuant to this, the “Green Credit Programme” is proposed to be launched at the national level to leverage a competitive, market-based approach to green credits, incentivising voluntary environmental actions by various stakeholders. The Green Credit Programme is envisaged to encourage private sector industries and companies to meet their existing obligations under other legal frameworks by undertaking activities that generate green credits. Green credits will arise from a range of sectors such as tree plantation, sustainable agriculture, waste management and air pollution reduction. Green credits will be made available for trading on a domestic market platform.

Credit Trading Scheme Carbon, 2023

On 28 June 2023, the GoI notified the Carbon Credit Trading Scheme, 2023 under the Energy Conservation Act, 2001. The primary objective of the Carbon Credit Trading Scheme is to establish a robust platform for the trading of carbon credits. Such credits may be traded among the country’s industries and entities to control greenhouse gas emissions. The scheme intends to encourage obligated entities to minimise their carbon footprint by reducing emissions.

Sustainable Alternative Towards Affordable Transportation (SATAT) Initiative to Promote Bio-CNG

The SATAT Scheme was launched by the MoPNG to promote the use of CBG (bio-CNG) in the CNG (transport) and PNG (domestic) sectors of City Gas Distribution (CGD) supplies of natural gas. The proposed PNGRB (Blending of Biogas/CBG with Natural Gas) Regulations, once notified, will impose statutory blending obligations on CGD entities – requiring legal alignment with volumetric targets, grid injection standards and interconnection protocols. The Oilfields (Regulation and Development) Amendment Act, 2025, introduced several progressive legal and policy reforms, including enabling provisions for hydrogen production and carbon capture, utilisation and storage (CCUS) activities within licensed areas.

Several state-owned oil and gas majors such as ONGC, IOCL, HPCL and BPCL and GAIL have prepared roadmaps for net zero emissions and are earmarking significant amounts towards investment in energy transition projects.

The PNGRB is considering using the natural gas pipeline and the CGD networks developed as the first choice for transportation of green hydrogen. The vast pipeline networks will facilitate the transport of green hydrogen from one part of the country to another by blending it with natural gas. This would aid the government’s Hydrogen Mission and will promote the use of green hydrogen in the country.

With its net-zero commitment, the government has been promoting clean energy investments to reduce fossil fuel dependence and foster a more sustainable energy landscape. India’s energy transition is based on a holistic approach and, given its historical dependence on conventional fuels, the government’s transition plans also focus on the oil and gas industry. Natural gas is a strategic fuel and, given its versatility and low carbon content, the government is actively promoting it. While the government has adopted a multi-pronged strategy for promoting energy efficiency, efforts have been made to increase the net geographical area under exploration. From time to time, the DGH has invited bids for new blocks under HELP and the DSF and has promoted exploration activities.

In 2018, the GoI issued a policy framework for the exploration and exploitation of unconventional hydrocarbons (“Policy on Unconventional Hydrocarbons”). Until the policy’s launch, contractors were not permitted to exploit unconventional hydrocarbons under licence or in leased areas. In furtherance of the Policy on Unconventional Hydrocarbons, the HELP and DSF regime focuses on a uniform licensing policy under which a single licence is granted that encompasses exploration and production of all hydrocarbons, including unconventional hydrocarbons such as shale gas or oil.

In line with the Policy on Unconventional Hydrocarbons, the definition of petroleum under the PNG Rules was also amended to include unconventional hydrocarbons. This expanded definition is carried forward in the PNG Rules 2025.

The PNGRB Act mandates the registration of any entity that establishes or operates an LNG terminal. On 8 June 2025, the PNGRB notified the PNGRB (Registration for Establishing and Operating Liquefied Natural Gas (LNG) Terminals) Regulations 2025 (“LNG Regulations”). The LNG Regulations provide for the procedure for obtaining registration for entities looking to establish and operate LNG terminals.

India’s upstream sector has seen a significant evolution in recent years, marked by the emergence of a hybrid concession-cum-contractual model under the OALP. One of the standout features of the OALP is the complete freedom in marketing and pricing granted to contractors. Companies are no longer bound by government-administered pricing or allocation requirements. Instead, they are free to negotiate and sell their crude oil and natural gas on commercial terms – whether to domestic buyers or international offtakers. This shift enhances commercial viability and gives investors greater control over revenue realisation. Further, in contrast to the traditional cost-recovery model – where profits are shared only after costs are recovered – the OALP adopts a revenue-sharing model. Contractors share a pre-agreed percentage of gross revenue with the government. This model simplifies contract administration, reduces auditing friction and provides clarity and predictability to both the government and private operators.

The PNGRB issued the Gas Exchange Regulations, 2020, establishing a legal framework for trading natural gas and LNG on authorised gas exchanges. These regulations permit trading in delivery-based contracts (day-ahead, intra-day and term-ahead), pipeline capacity contracts and other indexed gas contracts, subject to PNGRB approval. Exchanges and clearing corporations must meet eligibility conditions, including a minimum net worth of INR250 million and specified shareholding norms, with authorisation valid for 25 years. The India Gas Exchange Limited (IGX), which became the first authorised exchange in December 2020, has seen substantial growth: in FY26, IGX recorded its highest-ever annual trading volume of 76.8 million MMBtu (approximately 1.9 BCM), representing a 28% year-on-year increase, with over 1,924 trades executed. IGX operates six regional gas hubs with multiple delivery points and offers contracts ranging from intra-day to six-month tenors. The exchange has over 360 registered participants (including more than 35 sellers and over 190 buyers) and aims to account for approximately 7% of India’s total natural gas consumption by 2030.

The GoI has been continually implementing changes to simplify procedures and promote ease of doing business in the sector. The following are the recent material changes in the past year in the oil and gas laws and regulations.

Oilfields (Regulation and Development) Amendment Act, 2025

In April 2025, the Oilfields (Regulation and Development) Amendment Act, 2025 came into force. A key transformation is the introduction of the “petroleum lease” regime, replacing “mining leases”. This shift streamlines licensing under a single permit for exploration, production, processing and energy transition activities, such as hydrogen and CCUS. It expands the definition of “mineral oils” to cover unconventional hydrocarbons such as shale oil/gas, CBM, tight gas and gas hydrates, while excluding coal, lignite and helium.

Further, the amendment enhances investor protection by introducing a statutory stability clause that safeguards lease terms against unilateral amendments detrimental to lessees. It also enables the government to make rules allowing for dispute resolution outside India.

In a departure from criminal sanctions, the amendment establishes a civil penalty-based enforcement regime. Authorities may impose fines up to INR2.5 million per violation, with daily fines up to INR 1 million for ongoing breaches.

Petroleum and Natural Gas Rules, 2025

In December 2025, the MoPNG notified the Petroleum and Natural Gas Rules, 2025, framed under the amended Oilfields Act and superseding the Petroleum Concession Rules, 1949 and the Petroleum and Natural Gas Rules, 1959. The Rules operationalise the petroleum lease regime introduced by the Oilfields (Regulation and Development) Amendment Act, 2025, replacing the earlier system of separate petroleum exploration licences and petroleum mining leases with a single petroleum lease that covers exploration, development and production of all hydrocarbons.

A lease may be granted for an initial term of up to 30 years, extendable up to the economic life of the field and lessees are permitted to undertake decarbonisation and comprehensive energy projects (such as renewable energy, hydrogen and CCUS) within the lease area. Applications for a petroleum lease must be decided within 180 days of submission of complete information, with deemed approval in areas under central jurisdiction if no decision is communicated within that period.

The Rules also provide for the stability of lease terms, the sharing of pipelines, processing units and other infrastructure among lessees, annual capacity declarations and time-bound zero-flaring and emission-reduction plans. Criminal sanctions have been replaced with a financial penalty regime of up to INR 2.5 million, with an additional penalty of up to INR1 million per day for continuing default. Consistent with the amended Oilfields Act, arbitration of lease and contractual disputes will be seated in New Delhi where all lessees or contractors are Indian companies, while a neutral seat may be chosen where any party is a foreign company.

PNGRB (Registration for Establishing and Operating Liquefied Natural Gas (LNG) Terminals) Regulations, 2025

Pursuant to the PNGRB (Registration for Establishing and Operating Liquefied Natural Gas Terminals) Regulations, 2025, notified in May 2025, the PNGRB has introduced a mandatory framework requiring all entities seeking to set up or expand LNG terminals in India to register with the regulator before taking their final investment decision.

Any entity intending to establish or expand an LNG terminal must now submit a comprehensive project and evacuation plan and furnish a performance bank guarantee equal to 1% of the project cost or INR250 million, whichever is lower. The PNGRB will assess whether the project contributes to infrastructure efficiency, avoids unnecessary duplication and serves consumer interest. If approved, a certificate of registration valid for 30 years is granted.

The regulations also introduce new compliance obligations such as periodic reporting, notification of control changes and mandatory timelines for commencement of operations. The PNGRB is empowered to suspend or revoke registration in case of persistent non-compliance.