India has a federal structure of government where power to legislate is divided between the union/central legislature (parliament) and the state legislature in terms of the subject reserved for them under the Constitution of India. In accordance with the Constitution of India, parliament has been entrusted to legislate on matters pertaining to the regulation and development of oilfields and mineral oil resources, and petroleum and petroleum products. Additionally, ownership of minerals and things of value within territorial waters or the continental shelf, and resources of the exclusive economic zone are vested with the union. The Government of India (GoI) is the sole and exclusive owner of hydrocarbons and petroleum, except when the title passes to contractors in accordance with 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 administering 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 Hydrocarbon (DGH). The DGH was set up by the MoPNG pursuant to a resolution in 1993, with the aim of promoting 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 and 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 promotion of the competitive market and addressing the grievances of consumers.
The following regulatory and administrative bodies have been established primarily to ensure safety in the oil and gas sector.
While the above regulatory and administrative agencies are primary agencies established specifically to regulate the oil and gas sector, there are other government regulatory and administrative agencies pertaining to the environment and labour matters.
Companies in which the GoI has the majority shareholding include:
The key legislation in the oil and gas sector is as follows.
Since the oil and gas sector is a highly regulated field, in addition to the above legislation, the government from time to time promulgates policies, standards, directives and guidelines for governing 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 the oil and gas sector, 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.
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. As of 1 October 2022, a total of 85 blocks had been awarded under the three rounds of DSF, out of which 55 are operational.
As per the model revenue sharing contract (RSC), the GoI is the owner of petroleum except for that part of the crude oil, condensate or gas title which passes to a contractor or any other person under the RSC. Once the block is awarded by the government to the contractor, the rights available to the contractor can be broadly classified into the following categories based on the stage of the block.
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 suo motu expression of interest (EoI).
The DGH helps investors propose their suo motu EoI, based on the data available at the National Data Repository (NDR), where sedimentary basins are placed in three categories, namely Category I, Category II and Category III. Category I sedimentary basins are those which have established production and Category II and Category III basins are those which have prospective and contingent resources. The NDR helps investors to shortlist or select a block for the submission of an EoI to the GoI. The entity proposing the EoI has to fulfil certain technical and financial criteria and also 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 the bidders to submit bids after the date of publishing of the NIO.
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 at the time of 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 DSF. Under the revenue-share model, bidders pay a share of revenue for the commencement of production, as per their quoted bid. The revenue share varies from USD50,000 to USD7 million per day.
The royalty rates are determined as per the Oilfields Act, PNG Rules 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, according to the PNG Rules, before being granted a lease, a security deposit must be paid for due observance of the terms of the lease. 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 income of the operator is taxed. The profits and gains of the entities in upstream operations are computed on the basis of the determined value and revenue realised on the sale of oil and gas as per 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 case of any infructuous or abortive exploration expenses, drilling or exploration activities, and depletion of mineral oil in the mining area.
Crude oil, high speed diesel, petrol, natural gas and aviation turbine fuel are subject to value added tax/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. However, since the turn of the century, these privileges have been curtailed and the national oil exploration and production companies have been treated as equal to private companies in so far as awarding of blocks is concerned. 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 had 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 for preference to bidders on the grounds of promotion of 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”). The PPP-MI Order is applicable on procurement of goods, services and works (including turnkey works) by a GoI ministry, department, their attached, 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 business 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.
The terms of the licence of newly awarded blocks are governed by the RSC, the key terms of which are as follows.
A contractor is granted an exploration period of six years from the date of execution of the RSC. The exploration period is divided into two phases, namely:
During the initial exploration period, the contractor must complete the work programme quoted in its bid, which will be its committed work programme for the Initial Exploration 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.
A contractor may relinquish the contract area:
On relinquishment of the contract area, the contractor must demobilise all equipment and installations from the area pursuant to the abandonment plan, and perform all site restoration activities as per 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.
The contract restricts the freedom of the contractor 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.
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.
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.
The contractor may terminate the RSC with respect to any development or contract area by giving prior written notice of 90 days (contract area) or 180 days (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.
Upon expiry or termination of the RSC or relinquishment of the contract area, the contractor is, inter alia, required to:
The PNG Rules allow transfer of the PEL or PML, subject to the prior approval of the government. Furthermore, the RSC stipulates prior written consent of the government for:
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 RSC envisages a 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 comprising the contractor, 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 where the FDPs are approved after 28 February 2019. In October 2020, MoPNG approved the “Natural Gas Marketing Reforms”, whereby marketing freedom is granted to the blocks in which production-sharing contracts provide pricing freedom.
For the gas produced from the nomination fields of ONGC/OIL, NELP and Pre-NELP blocks, the New Domestic Gas Pricing Guidelines 2014 (Gas Pricing Guidelines) are applicable. Recently, 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 in the preceding month and the prices 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 sector is liberalised, allowing free participation for 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 sphere and the pipeline sphere are dominated by PSUs. The development of pipeline infrastructure across the country is not uniform, with states close to gas sources having a robust pipeline infrastructure, while states further from gas sources have a significantly smaller pipeline network.
As discussed in 1.3 National Companies, the PSU GAIL owns more than half of the pipeline infrastructure in India 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.
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.
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 2010 (“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: (a) on receipt of an application for the development of a pipeline; or (b) 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 for securing equitable distribution or ensuring adequate availability of natural gas throughout India. The NG Pipeline Regulations and the Petroleum Pipeline Regulations regulate the manner of submission of a bid, its 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 which an entity must fulfil in order to be awarded authorisation to develop a pipeline.
Other Licences Required for Midstream/Downstream Operations
These include the following:
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 provide a procedure for determination of the 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 to be charged for a period is calculated based on the discounted cash flow (DCF) methodology, which considers a reasonable rate of return to be 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 for the entire economic life of the project. An authorised entity is allowed to charge shippers compression charges, in addition to the transportation tariff, under the regulations framed by the PNGRB. For petroleum and petroleum products pipelines, the tariff, bench-marked against the goods tariff table of the Indian Railways, is determined in accordance with the Petroleum Pipeline Tariff Regulations.
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 of natural gas quoted in the bid and the PNGRB will monitor the actual progress in this regard on a quarterly basis. Failure to adhere to the annual target will result in encashment of the performance bond submitted to the PNGRB during the time 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 of the land for the laying of pipelines may be acquired, after which, 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 following the procedure prescribed under the Right to Fair Compensation and Transparency in Land Acquisition, Rehabilitation and Resettlement Act 2013, provided such land is acquired for 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 and Regulation, the Government of India is responsible for policy framework related to hydrocarbons of India and the union Parliament legislates on the matters related to hydrocarbons. The PNGRB established under the PNGRB Act regulates activity pertaining to 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 deal with third-party access to natural gas pipelines and other infrastructure, whereas the Petroleum Pipeline Guiding Principles and the Petroleum Pipeline Regulations deal with third-party access to petroleum and petroleum products pipelines. The NG Pipeline Regulations and the Petroleum Pipeline Regulations specify that the authorised pipeline entities are to make extra 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 an objective to serve consumer interests by promoting competition and avoiding infructuous investments, by 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, with entities laying, building, operating or expanding petroleum and petroleum product pipelines.
In the Union Budget 2021–2022, it was announced that an independent gas transport system operator will be set up for facilitation and co-ordination of booking of common carrier capacity in all-natural gas pipelines on a non-discriminatory, open-access basis, and the same is in the deliberation stage.
As discussed in 3.8 Other Key Terms: Midstream/Downstream, since the midstream/downstream sector is highly regulated, with no 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: (a) exclusivity for development of the city gas distribution (CGD) network; and (b) exemption from 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 as 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 purview of a common carrier or contract carrier is granted for a period of eight years. Furthermore, if: (a) the entity meets all works programme targets in a timely manner, an extension of two years is granted; and (b) 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
100% foreign direct investment (FDI) under the automatic route is permitted in the following:
FDI in petroleum-refining by the PSUs has been permitted to the extent of 49% under the automatic route, without any divestment or dilution of domestic equity in the 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 put LNG imports under the Open General Licensing (OGL) category and the establishment of LNG infrastructure, including LNG terminals, is also under 100% FDI (automatic route) to promote the usage and distribution of LNG. Further, in July 2021, the GoI amended the FDI policy on 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 where an in-principle approval for strategic disinvestment of a PSU has been granted by the GoI.
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
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 does not therefore have the freedom to choose the arbitration procedure and law.
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. Other than its regulatory function, the PNGRB also performs an adjudicatory function for the downstream sector and has the jurisdiction to hear and decide any dispute arising from 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 the oil and gas sector needs to be in compliance with exchange control regulations and applicable laws.
Key Environmental Laws
The key environmental laws applicable to various industries, including to 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, the state governments are empowered to declare any areas within the state 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 of the same, the MoEFCC issued a notification in 2016 dealing with environmental impact assessments (“EIA Notification”) to minimise the adverse impact of development projects on the environment. Furthermore, as per Coastal Regulation Zone Notification 2011, 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 wastes. 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.
Forest (Conservation) Act 1980 (“Forest Act”)
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 usage 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 1958
This act stipulates safeguards and civil liability in the case of oil pollution damage.
Key Environmental Regulators
These are the MoEFCC and the Central Pollution Control Board.
As per the EIA Notification, all projects in respect of 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 regulatory authority concerned either with granting prior environmental clearance on stipulated terms and conditions, or rejecting the application for prior environmental clearance, together with reasons.
Environmental Impact Assessments
An EIA involves three stages:
At the scoping stage, the EAC determines comprehensive terms of reference addressing all relevant environmental concerns for preparation of the EIA report. In February 2020, sector-specific standard terms of reference were developed in order to streamline the process of scoping and bring uniformity across the proposals. All new projects or activities are to be referred to the EAC by the regulatory authority within 30 days from the date of application, for recommending the specific terms of reference. If the regulatory authority does not refer the matter to the EAC within 30 days of the date of application, standard terms of reference will be issued by the regulatory authority on the 30th day.
This public hearing, at the site or in close proximity to it, is conducted to ascertain the concerns of the locals and obtain responses in writing from other stakeholders. After completion of the public consultation, the applicant must address material environmental concerns expressed during this process and make appropriate changes to the draft EIA and environmental management plan.
This stage covers detailed scrutiny by the EAC of the application and the final EIA report. The appraisal is done transparently and the applicant is invited to furnish 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 such, 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, on termination of the PEL or PML, the contractor has to 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:
The government has published the Site Restoration and Abandonment Guidelines for Petroleum Operations which provides detailed guidelines for decommissioning offshore and onshore production sites.
For blocks under 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 has pledged to reduce the emission intensity of its gross domestic product (GHG emissions per unit GDP) by 33–35% over 2005 levels by 2030 and to create an additional carbon sink of 2.5–3 billion tonnes of CO₂-equivalent through additional forest and tree cover. While no specific legislation has been enacted to fulfil the commitment to the Paris Agreement, the government has formulated various guidelines and policies aimed to promote renewable energy. In 2008, the government launched the National Action Plan on Climate Change, under which eight national missions on advancing India’s climate change-related objectives are provided, including missions relating to solar power, water, sustainable agriculture and energy efficiency.
See 5.1 Environmental Laws and Environmental Regulator(s) for specific legislation pertaining to the environment which is, in turn, related 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 according to the authority legislating on the subject. Furthermore, in India there is decentralisation of power to local authorities for better administration.
In 2018, the GoI issued a policy framework for the exploration and exploitation of unconventional hydrocarbons (“Policy on Unconventional Hydrocarbons”). Until the launch of the Policy on Unconventional Hydrocarbons, 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 encompassing 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.
The PNGRB Act mandates registration of any entity establishing or operating an LNG terminal. The PNGRB (Eligibility Conditions for Registration of Liquefied Natural Gas Terminal) Rules 2012 stipulate the eligibility conditions for registration of an LNG terminal and state that any entity desirous of establishing an LNG terminal and fulfilling the eligibility condition has to apply to the PNGRB. However, the PNGRB has not yet issued final regulations regarding registration of LNG terminals, only draft regulations – namely, the PNGRB (Registration for Establishing and Operating LNG Terminals) Regulations 2018, which were circulated for comment from stakeholders.
Recently, the PNGRB clarified that it does not have jurisdiction under the PNGRB Act to issue authorisation for the operation and establishment of LNG dispensing stations, and authorisation from the PNGRB is not required to dispense LNG as automotive fuel, allowing wider market participation in the LNG distribution sector. In February 2021, the MoPNG published the Draft LNG Policy for comments from stakeholders. The Draft LNG Policy focuses on the creation of LNG terminals and re-gasification facilities to address the need for LNG and to promote the use of LNG in various sectors, including transportation and the mining sector.
India is aggressively pursuing its commitment to the Paris Accord by reducing carbon footprints and promoting sustainable alternative clean energy. Promotion of green hydrogen as an alternative fuel for industries is one such initiative. The GoI has launched the National Green Hydrogen Mission, providing an enabling framework for the development of green hydrogen in the country. Recently, Solar Energy Corporation of India Limited (a GoI enterprise) has also issued the first tender for setting up production facilities for green hydrogen. Under the tender, successful bidders setting up green hydrogen or its derivative-based production facilities will be eligible for applying for the incentive assistance under the Strategic Interventions for Green Hydrogen Transition (SIGHT) Scheme (which is part of the National Green Hydrogen Mission). Further, the states of Andhra Pradesh and Maharashtra have come out with separate green hydrogen policies to promote green hydrogen projects in the respective states. While several incentives are given to developers of green alternative fuels, at present there are no considerations affecting the development and utilisation of oil and gas, upstream and midstream assets for energy transition consideration.
In September 2020, the PNGRB published the PNGRB (Gas Exchange) Regulations, 2020 (“Gas Exchange Regulations”). This was the first time the PNGRB had come out with comprehensive gas exchange regulations, allowing trading in gas contracts through a gas exchange and allowing buyers and sellers (including but not limited to aggregators, CGD companies, consumers and trading licensees) to transact on gas contracts. Currently, the Gas Exchange Regulations are applicable to the following contracts:
Under the Gas Exchange Regulations, a gas exchange or clearing corporation has to obtain authorisation from the PNGRB before setting up its operations, subject to fulfilling eligibility criteria set out in the Gas Exchange Regulations. Every gas exchange or clearing corporation has to maintain a net worth of INR250 million at all times, as well as shareholding patterns, as provided in the Gas Exchange Regulations. Authorisation to operate as a gas exchange is given for 25 years.
Pursuant to the Gas Exchange Regulations, India Gas Exchange Limited was granted authorisation by the PNGRB in December 2020, thereby becoming the first gas exchange in India.
The Government of India has been constantly bringing about changes to simplify procedures and to 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.
Deregulation of Sale of Domestically Produced Crude Oil
On 11 July 2022, the GoI notified the deregulation of sale of domestically produced crude oil. Pursuant to this, exploration and production (E&P) companies have been given marketing freedom to sell crude oil from their fields directly to the domestic market. Previously, all E&P companies had to sell crude oil produced from their fields to the government or its nominee or government companies. Pursuant to the notification, the condition in Production Sharing Contracts (PSCs) to sell crude oil to the GoI or its nominee or company of GoI will stand waived off.
Sale and Resale of Gas Produce from Discoveries in Deepwater, Ultra Deepwater and High Pressure High Temperature Areas with Marketing and Pricing Freedom
In January 2023, the MoPNG clarified that the bidders for gas produced from discoveries in deepwater, ultra deepwater and high pressure high temperature areas will have to specify whether they wish to purchase gas through the auction for own use as end consumers or as traders. Traders are allowed to resell the gas to another trader or end consumer subject to a trading margin specified by the government. In case the bidders are the end-consumers then any quantity of gas which remains unconsumed for any reason including in cases of unplanned plant shutdowns can be resold subject to separate conditions to be notified by MoPNG in this regard.
The Indian oil and gas sector has witnessed a steady growth over the years and, amidst the global headwinds, the sector has maintained its momentum. Through its policy reforms, the government has ensured its commitment to energy security, ease of doing business and energy transition. India is one of the largest consumers of energy in the world and the majority of the demand is met by hydrocarbons. Crude oil and natural gas requirements are primarily met by imports. The Government of India (GoI) has been pursuing policies and reforms to reduce import dependency and has promoted domestic production by actively tapping the green shoots. The GoI has been actively pursuing various reforms in the upstream, midstream and downstream sectors. Some of the key reforms are as follows:
India’s energy strategy is based on diversifying, supplies, increasing exploration and production, alternate energy sources and energy transition through a gas-based economy, hydrogen, etc. In line with its commitment to Paris commitments, the GoI has taken multiple steps to promote a gas-based economy. India has reduced its dependency on import of natural gas from 49.2% in Financial Year 2021–22 to 46.3% in Financial Year 2022–23 (April to October). The GoI has set a target to raise the share of natural gas in its energy mix to 15% in 2030 from 6.3%. Some of the significant initiatives taken by the government for providing impetus to a gas-based economy are as follows:
Over the years, the CGD industry has witnessed outstanding growth, with active private participation from domestic and foreign investors. The CGD network primarily comprises piped natural gas infrastructure and compressed natural gas stations. The Petroleum and Natural Gas Regulatory Board (PNGRB), the regulatory body entrusted with regulating the CGD sector, authorises entities to develop the CGD network in India. The PNGRB has conducted 11 rounds of bidding with the 11th round being split into two parts. After the completion of 11A CGD bidding round, 295 Geographical Areas (GAs) covering about 98% of the population and 88% of total geographical area of the country spread over around 630 districts in 28 states/UTs have been covered under the CGD network. The PNGRB is also proposing to offer eight new GAs as a part of the 12th bidding round. Significantly, the north-east states and the union territories of Jammu and Kashmir (except areas already authorised) and Ladakh, have been considered.
National Green Hydrogen Mission
After the announcement of the National Green Hydrogen Mission in 2021 (Hydrogen Mission), on 17 February 2022, the GoI issued the Green Hydrogen Policy. The policy, though named the Green Hydrogen Policy, also provided a framework for the development of green ammonia. Under the Green Hydrogen Policy, the GoI defined green hydrogen and green ammonia as hydrogen or ammonia produced by way of electrolysis of water using renewable energy, including renewable energy which has been banked or produced from biomass.
While the Hydrogen Mission was launched in 2021, the mission document setting out the finer details was published in January 2023. Under the Hydrogen Mission, the GoI has committed nearly INR197 billion to make India a global hub for production, utilisation and export of green hydrogen and its derivatives. The Ministry of New and Renewable Energy (MNRE) has been assigned the responsibility for overall co-ordination and implementation of the Hydrogen Mission. The Hydrogen Mission provides a blueprint by providing a robust framework for the creation of a green hydrogen ecosystem. The GoI aims to achieve the following through the Hydrogen Mission:
Under the Hydrogen Mission, the GoI has proposed a suite of incentives to the investors in the form of providing low-cost funds for setting up projects, identifying land and providing existing schemes available to solar parks, manufacturing zones and special economic zones. The Hydrogen Mission envisages competitive bidding for procurement of green hydrogen and its derivatives. Awarding of long-term contracts for procurement of green hydrogen, post competitive bidding will incentivise lenders to finance hydrogen projects.
Aware of the nascency of the green hydrogen sector, the government, pursuant to the Hydrogen Mission, has identified various components which it will address for the creation of a strong foundation for promoting India as a global hub for green hydrogen and piquing investor interest. The major areas under the Hydrogen Mission are demand creation, supply-side incentives and enabling an ecosystem for scaling and development, and understanding the importance of demand and supply for the development of nascent technology. To create bulk demand and scale up production of green hydrogen, the Hydrogen Mission provides for specifying a minimum share of consumption of green hydrogen or its derivative products (green ammonia, green methanol, etc) as energy or feedstock for different consumers. Under the Hydrogen Mission, the GoI would lay down an annual trajectory for such minimum share of consumption. This would be similar to a renewable purchase obligation in the renewable energy industry. The Hydrogen Mission advocates for regulatory requirements to ensure enforceability of consumption targets for the industry to use green hydrogen and its derivatives through the Energy Conservation Act, 2001.
Since water is key for the production of green hydrogen, the Hydrogen Mission provides for better utilisation of industrial or municipal waste water, wherever feasible. The Hydrogen Mission provides for creation and promotion of hydrogen hubs in regions capable of creation of cluster-based production and utilisation models to enhance the viability of green hydrogen projects. Under the Hydrogen Mission, the GoI plans to set up two such hubs in the initial phase.
The GoI intends to implement the Hydrogen Mission in a two-phased manner, with the first phase being from 2022/23 to 2025/26, with focus on creation of demand and bringing down the cost of production to ensure wide coverage. In this phase, the government intends to promote use of green hydrogen in the refineries, fertilizers and CGD sectors. The second phase will be from 2026/27 to 2029/30, in which the GoI intends to achieve accelerated growth in production of green hydrogen and scale up the projects. In the second phase, the government also plans to deploy green hydrogen usage in steel, mobility and shipping industries based on the evolution of cost and demand in the first phase.
Recently, the states of Andhra Pradesh and Maharashtra came out with separate green hydrogen policies to promote green hydrogen projects in the respective states.
The Solar Energy Corporation of India Limited (a GoI enterprise) has also issued the first tender for setting up production facilities for green hydrogen. Under the tender, successful bidders setting up green hydrogen or its derivative-based production facilities will be eligible to apply for the incentive assistance under the Strategic Interventions for Green Hydrogen Transition (SIGHT) Scheme (which is part of the Hydrogen Mission).
One Nation One Gas Grid
One nation one gas grid is one of the ambitious projects of the GoI, for the development of a national gas grid which integrates various regional grids. The deployment of the one nation one gas grid project aims to increase gas demand in the country. PNGRB is the body entrusted to authorise the development of pipelines. The PNGRB has authorised 33,350 kms of gas pipeline networks in the country, out of which 21,715 km natural gas pipelines are operation and a total of 13,605 km length of pipelines are under various stages of construction. In a significant move, the PNGRB recently approved a levelised unified tariff for a natural gas pipeline, thereby paving the way for one nation one grid and one tariff.
A suo-moto proposal for development of natural gas pipeline infrastructure in the union and territory of Jammu and Kashmir from Jammu to Srinagar, is also being mooted by PNGRB.
India’s upstream sector has seen a paradigm shift in policies aimed at attracting more investors to the exploration and production (E&P) sector. Before 1999, the GoI and national oil companies had a monopoly over the oil and gas sector. In 1999, the GoI adopted NELP, under which acreages for the exploration of hydrocarbons were awarded through international competitive bidding, with domestic and foreign companies being given equal opportunity. Furthermore, there has been a significant change to government policies since 2016, with the shift to the Hydrocarbon Exploration and Licensing Policy (HELP). Under HELP, a revenue-sharing mechanism has been adopted, and marketing and pricing freedom are provided for any hydrocarbons produced. HELP follows a uniform licensing policy under which one licence covers exploration and production of hydrocarbons, such as oil, gas, coal-bed methane, shale gas/oil and gas hydrates. The OALP, one of the main facets of HELP, aims to fast-track upstream activities and create a continuous window of exploration opportunities in which exploration and production companies have the flexibility to choose the hydrocarbon blocks to carry out relevant activities. After the shift to HELP in 2016, eight rounds of OALP have been concluded for 134 E&P blocks.
The GoI also launched the DSF Policy, to monetise small and marginal hydrocarbon blocks under national oil companies. Contracts for 53 blocks were awarded under the first two DSF bidding rounds corresponding to a committed investment of USD1.63 billion. As of 1 October 2022, a total of 85 blocks had been awarded under the three rounds of DSF, out of which 55 are operational.
India has a long gas pipeline network and in recent years, the GoI has envisaged establishing a National Gas Grid to overcome imbalances and to provide more penetration of gas to various consumers. About 14,700 km of additional gas pipeline has already been recently approved by the GoI and is in various stages of development. The Urja Ganga Pipeline project, which is a 3,384 km pipeline with a capacity of 16 million MMSCMD connecting the four eastern states to the national gas grid, is one of the significant pipeline projects.
In 2021, the Indian government announced a four-year National Monetisation Pipeline (NMP) worth approximately INR6 trillion to unlock value in brownfield projects. The core brownfield infrastructure assets identified for monetisation under the NMP include energy pipelines. The natural gas pipelines are typically owned and operated by public sector entities. Similarly, petroleum, petroleum product pipelines and other assets are also considered for monetisation under the sector.
To attract more investment to the downstream retail sphere, which is mainly dominated by the national oil marketing companies, the GoI had, to some extent, relaxed the terms of eligibility criteria for authorisation of bulk and retail marketing of Motor Spirit (Petrol) and High-Speed Diesel. Until 2019, only an entity which had invested INR20 billion in either hydrocarbon E&P, or refining, pipelines or liquefied natural gas (LNG) terminals, could obtain a fuel retailing licence in India. However, the rule has since been relaxed and an entity with a minimum net worth of INR2.5 billion or INR5 billion (in the case of authorisation for both retail and bulk) can seek authorisation. Post the revision of eligibility criteria to market transportation fuels, the GoI has granted marketing authorisation to several entities, with the majority being private players.
The PNGRB has also clarified that any entity can dispense LNG to the transport sector in any geographical area or anywhere else, even if the entity is not authorised by the PNGRB.
The GoI has also published a Draft LNG Policy, which aims to promote the use of LNG in transport and other sectors where, at present, LNG has not been explored as a medium of alternative fuel.