In terms of Article 246 of the Indian Constitution, the ownership of oil and gas falls within the ambit of the central government and, accordingly, contracts for exploration and production activities. State governments are responsible for providing approvals relating to local requirements, including the use of land, water and labour. The relevant state governments provide the licences/leases to land for undertaking exploration and production (E&P) activities for onshore blocks and the central government provides such approvals for offshore blocks.

In terms of model revenue sharing contracts (MRSCs), the central government is the sole owner of petroleum, except that part of crude oil, condensate or gas with regard to which the title has passed to a contractor or any other person in accordance with an MRSC.

Different regulatory bodies govern the upstream and downstream sector. The oil and gas sector is primarily under the administrative control of the Ministry of Petroleum and Natural Gas (MoPNG). The Directorate General of Hydrocarbons (DGH) is the primary regulatory body for the upstream sector, whereas the Petroleum and Natural Gas Regulatory Board (PNGRB) assumes relevance in terms of governance relating to the downstream sector.

• MoPNG – primarily concerned with the exploration and production of oil and natural gas, along with the refining, distribution and marketing, importation, exportation and conservation of petroleum products (http://petroleum.nic.in/).
• DGH – responsible for discharging regulatory functions relating to leasing and licensing, safety and the environment along with the development, conservation and reservoir management of hydrocarbon resources in India. The DGH also advises the MoPNG on exploration strategies and production policies (http://dghindia.gov.in/).
• PNGRB – constituted under the PNGRB Act, 2006, notified via a gazette notification dated 31 March 2006 for the purposes of protecting the interests of consumers and entities engaged in specified activities relating to petroleum, petroleum products and natural gas, and the promotion of competitive markets and other connected matters (https://www.pngrb.gov.in/).
• Oil Industry Safety Directorate (OISD) – a technical directorate under the MoPNG responsible for formulating and co-ordinating the implementation of a series of self-regulatory measures aimed at enhancing safety in the oil and gas industry. It is the designated competent authority under the Petroleum and Natural Gas (Safety in Offshore Operations) Rules, 2008 (the “Safety Rules”) (https://www.oisd.gov.in/).
• Petroleum and Explosives Safety Organisation (PESO) – administration of responsibilities delegated under the Explosives Act 1884 and the Petroleum Act 1934 related to the manufacture, importation, exportation, transportation, possession, sale and use of explosives, petroleum products and compressed gases falls within the purview of PESO (https://peso.gov.in/).
• Directorate General of Mines Safety (DGMS) – a regulatory agency under the Ministry of Labour and Employment responsible for matters pertaining to occupational safety, and the health and welfare of persons employed in mines (http://www.dgms.gov.in/).

Further, several regulatory and administrative bodies provide directions/guidelines on the environment, land, tax and labour matters. Please also refer to 1.1 System of Petroleum Ownership for the role of the state and central government.

The national oil and gas companies are as follows.

• Oil & Natural Gas Corporation Limited (ONGC) – established in 1955, as the Oil and Natural Gas Directorate under the then Ministry of Natural Resources and Scientific Research, ONGC converted into a corporation in 1994. "Maharatna" ONGC, the largest crude oil and natural gas company in India, contributes approximately 75% to domestic production. The government of India (GoI) held 60.40% of the shares in ONGC on 31 March 2020 (https://ongcindia.com/).
• ONGC Videsh Limited (OVL) – the wholly owned subsidiary and overseas arm of ONGC has the primary business of prospecting for oil and gas acreages outside India, including the exploration, development and production of oil and gas (https://www.ongcvidesh.com/).
• Indian Oil Corporation Limited (IOCL) – established on 30 June 1959, IOCL is currently engaged in activities relating to the refining, pipeline transportation and marketing, exploration and production of crude oil and gas, petrochemicals, gas marketing, alternative energy sources and the globalisation of downstream operations. The GoI held 51.50% of the shares in IOCL on 30 June 2020 (https://www.iocl.com/).
• Bharat Petroleum Corporation Limited (BPCL) – established as Bharat Refineries Limited (BRL) on 24 January 1976, BRL was later renamed as BPCL and is primarily engaged in the business of refining crude oil and the marketing of petroleum products. It serves the retail market through liquefied petroleum gas (LPG) service/distribution lines and through its own gas stations. The GoI held 52.98% of the shares in the company on 31 March 2020 (https://www.bharatpetroleum.com/index.aspx).
• Gas Authority of India Limited (GAIL) – established in August 1984 under the MoPNG for the purposes of the construction, operation and maintenance of the Hazira Vijaypur Jagdishpur pipeline project. GAIL is involved in E&P activities, the transmission and marketing of gas, petrochemicals, LPG and other liquid hydrocarbons, etc. The GoI held 51.76% of the shares in the company on 30 June 2020 (https://gailonline.com).
• Oil India Limited (OIL) – established on 18 February 1959, OIL is currently engaged in the business of exploration, development and production of crude oil and natural gas, the transportation of crude oil and the production of LPG. The GoI held 56.66% of the shares in the company on 31 March 2020 (https://www.oilindia.nic.in/).

These public sector undertakings (PSUs) are incorporated under the Indian Companies Act, 1913/1956 and do not enjoy regulatory powers. Please also refer to 2.5 National Oil or Gas Companies for further details.

The primary pieces of petroleum legislation governing the upstream, midstream and downstream sector include the following.        

• Oilfields Regulation and Development Act (the “Oilfields Act”) provides for the regulation of oilfields and for the development of mineral oil resources, and covers the granting of Petroleum Exploration Licenses (PELs) and Petroleum Mining Leases (PMLs) in accordance with the provisions stipulated thereunder.
• The Petroleum and Natural Gas Rules, 1959 (the “PNG Rules”), as enacted pursuant to the Oilfields Act, regulate the grant of exploration licences and mining leases with respect to petroleum and natural gas that belongs to the GoI, and for the conservation and development thereof.
• The Territorial Waters, Continental Shelf, Exclusive Economic Zone and other Maritime Zones Act, 1976 provides that no person shall be entitled to explore and exploit resources of the continental shelf and an exclusive economic zone unless a licence has been granted by the GoI.
• The Safety Rules, as enacted pursuant to the Oilfields Act, provide for the regulation of safety in offshore exploration, exploitation, conservation and the management of petroleum and natural gas, and connected matters.
• The Petroleum Act, 1934 (the “Petroleum Act”) and the Petroleum Rules, 2002 (the “Petroleum Rules”) primarily govern the law relating to the importation, transportation, storage, production, and refining and blending of petroleum.
• The PNGRB Act, 2006 (the “PNGRB Act”) is the primary piece of legislation governing the development, operation and expansion of pipelines. It provides for the establishment of the PNGRB as the regulatory body with jurisdiction over the regulation of pipeline business. Pursuant to powers granted to the PNGRB under the PNGRB Act to frame subordinate legislation, the PNGRB has framed a number of regulations and guidelines that govern the domain of pipeline business in India, including the refining, processing, storage, transportation, distribution, marketing and sale of petroleum, petroleum products and natural gas, excluding the production of crude oil and natural gas.
• The Mines Act, 1952 and the Oil Mines Regulations, 2017 set forth the duties of owners, managers and agents in relation to oil mines; penalties; and regulate the working conditions in oil mines by providing for measures to be taken for the safety of the workers employed.

The above-mentioned list only includes the primary oil and gas legislation and does not discuss in detail the ancillary pieces of legislation (including directives, notifications, guidelines and policies), as may be promulgated by the central or the respective state governments, that may be applicable to the oil and gas sector.

Currently, investment rights are granted to private investors pursuant to a competitive bidding process under the following.

• Hydrocarbon Exploration and Licensing Policy (HELP) Regime – announced by the GoI in 2016, a revenue sharing contract (RSC) along the lines of MRSCs published by the GoI is executed between a private investor and the GoI. Pursuant to the RSC, a contractor is appointed and constituted as an exclusive entity to conduct E&P activities in the allotted contract area. The contractor is responsible for bearing complete risk in carrying out the E&P activities, and is solely responsible for the execution and management of petroleum operations.
• Discovered Small Fields Policy (DSF) – introduced to monetise marginal fields of ONGC and OIL under the Nomination Era (discussed below) that remained undeveloped for a long period, RSCs are executed pursuant to the DSF, wherein a single licence is provided to enable E&P operators to explore and extract all hydrocarbon resources covered under the Oilfields Act and PNG Rules under one PEL/PML.

Nature of Rights Provided to Private Investors under the MRSC

MRSCs can broadly be segregated into (i) an exploration phase and (ii) a development phase, which implies that the rights are provided to the contractor for the exploration of petroleum and upon the discovery and development/production of such petroleum. The terms of such rights are further governed by a PEL and PML granted to such contractor.

Historic Forms of Contract

• Nomination Era – from 1948 until 1991, when the process of deregulation was initiated for oil blocks, a state monopoly existed and the oil blocks were awarded only to national oil companies (ie, OIL and ONGC) on nomination basis.
• Pre-NELP Era – in 1991, 28 producing fields and 28 exploratory blocks were awarded to several companies that included private players.
• New Exploration Licensing Policy (NELP) Era – 1997 to 2009 witnessed further liberalisation of the E&P sector, during which nine NELP rounds and four coal bed methane (CBM) rounds were concluded. During this period, 254 exploratory and 33 CBM blocks were awarded through competitive bidding processes. The NELP Era is of significant importance and has been considered as a major milestone in the history of the oil and gas sector in India.

The contracts awarded during the Pre-NELP Era and the NELP Era were based on the model of "production sharing", wherein a percentage of profit (determined in accordance with the proposals) was to be shared with the GoI. Given that the terms of these contracts range between 20 and 30 years, some of these contracts continue to be in subsistence. The annual publication by the DGH for the year 2018-19 specifies that 88 such contracts are active from the Pre-NELP Era and the NELP Era.

The process by which a private investor obtains the contract/licence to undertake upstream activities is currently regulated under HELP and is as follows:

• Bidding – the process starts with the bidding process under the Open Acreage Licensing Policy (OALP), as applicable in the HELP regime. A bidder intending to explore hydrocarbons such as oil and gas, CBM or gas hydrate may apply to the GoI suo moto seeking exploration of any new block, without waiting for the formal bid round from the GoI (contrary to the HELP regime, under the NELP regime, exploration was confined to blocks that have been put on tender by the GoI).
• National Data Repository (NDR) – the NDR is a central repository for E&P data in India. The sedimentary basins of India have been classified into three categories – Category I, Category II and Category III – based on the availability of hydrocarbons in the basin. The DGH provides a database for the relevant blocks through the NDR, through which a bidder can select a block for its expression of interest (EOI).
• RSC – the applications for suo motu EoI can be filed for RSCs that permit exploration, development and production operations in any onland (including CBM), shallow water, deepwater and ultra deepwater block for all types of hydrocarbons.
• Carving of blocks – the GoI then carves out the blocks on the basis of the EOI received or if it deems it necessary and offers the same for bidding by issuing a "notice inviting offer" (NIO). The bids submitted by interested bidders are then examined by the GoI on the basis of the qualification and bid evaluation criteria.
• Qualification criteria – the bidder is required to meet technical and financial qualification criteria. The financial criteria involve assessment of net worth at two stages. In the first stage, an NIO specifies the minimum net worth for various kinds of blocks on offer – for instance, onland/frontier, shallow water and ultra deepwater – in proportion to their participating interest. In the second stage, net worth is reassessed and should be equal to or higher than the estimated expenditure for a committed work programme (CWP) and liquidated damages (LD) equivalent value of the CWP.

The technical qualification criteria include a minimum operatorship experience in oil and gas exploration/production/development of one year for each onland, shallow water, deepwater, ultra deepwater and CBM block, and positive minimum acreage holding or positive minimum average annual production for the previous ten years.

• Participation bond – along with the bids, an originator is also required to submit a participation bond of value USD150,000 per sector for all types of blocks. The bond value is subject to a cap of USD1 million for a block falling under onland, shallow water or the CBM category and USD2 million for a block falling under the deepwater or ultra deepwater category.
• Bid evaluation criteria – the bid evaluation criteria is specific to the category of sedimentary basins. For Category I basins and CBM blocks, it is based on (i) the government share of revenue offered by the bidder at the lower revenue potential (LRP) and the higher revenue potential (HRP); (ii) the CWP quoted by the bidders; and (iii) an originator's incentive, which implies that the bidder submitting an EoI first (the “Originator”) will be rewarded for the initiative taken (the “Originator's Incentive”). For Category II and III basins, it is based on the CWP and the Originator's Incentive. In the case of Category I basins and CBM blocks, more weight is given to the work programme (ie, 70% against 30% weight to revenue share) and the government share of revenue is capped at 50%. In the case of Category II and III basins, 100% weight is given to the work programme.
• Execution of an RSC – pursuant to the examination, the successful bidder gets the block and an RSC is executed between the GoI and the successful bidder. The contractor is then required to procure the PEL and PML within 30 days of the execution of the RSC. Please refer to 1.4 Principal Petroleum Law(s) and Regulations for further details regarding PMLs and PELs.

The following payments are required to be made for undertaking upstream licences.

Royalty Payments

The requirement of a royalty payment as a percentage of the value of the petroleum receivable by the contractor is prescribed in the Oilfields Act, the PNG Rules and the terms of the RSC. The applicable royalty rates as provided under the HELP regime are as follows.

Crude oil

• Onshore – 12.5%;
• shallow water – 7.5%;
• deepwater – no royalty for the first seven years, and 5% after seven years; and
• ultra deepwater – no royalty for the first seven years, and 2% after seven years.

Natural gas and CBM

• Onshore – 10%;
• shallow water – 7.5%;
• deep water – no royalty for the first seven years, and 5% after seven years; and
• ultra deepwater – no royalty for the first seven years, and 2% after seven years.

In order to expedite the production of oil and gas, the GoI has vide notification dated 11 April 2019 notified concessional royalty rates that will be applicable if production is commenced within four years for onland and shallow water blocks, and five years for deepwater and ultra deepwater blocks.

The concessional royalty rates for crude oil are as follows.

Category I basin

• Onshore – 11.25%;
• shallow water – 6.75%;
• deepwater – no royalty for the first seven years, and 4.50% after seven years; and
• ultra deepwater – no royalty for the first seven years, and 1.80% after seven years.

Category II basin

• Onshore – 10%;
• shallow water – 6%;
• deepwater – no royalty for the first seven years, and 4% after seven years; and
• ultra deepwater – no royalty for the first seven years, and 1.60% after seven years.

Category III basin

• Onshore – 8.75%;
• shallow water – 5.25%;
• deepwater – no royalty for the first seven years, and 3.50% after seven years; and
• ultra deepwater – no royalty for the first seven years, and 1.40% after seven years.

The concessional royalty rates for natural gas are as follows.

Category I basin

• Onshore – 9%;
• shallow water – 6.75%;
• deepwater – no royalty for the first seven years, and 4.50% after seven years; and
• ultra deepwater – no royalty for the first seven years, and 1.80% after seven years.

Category II basin

• Onshore – 8%;
• shallow water – 6%;
• deepwater – no royalty for the first seven years, and 4% after seven years; and
• ultra deepwater – no royalty for the first seven years, and 1.60% after seven years.

Category III basin

• Onshore – 7%;
• shallow water – 5.25%;
• deepwater – no royalty for first the first seven years, and 3.50% after seven years; and
• ultra deepwater – no royalty for the first seven years, and 1.40% after seven years.

Annual Licence Fee and Security Deposit

Prior to the grant of a licence, the licensee is required to pay INR100,000 for the grant of a licence and INR400,000 as a security deposit for the grant of a licence to the appropriate government.

Subsequent to the grant of a licence, a licensee is required to pay an annual licence fee for each square kilometre or part thereof covered under the licence at the rate of:

• INR200 for the first year of the licence;
• INR400 for the second year of the licence;
• INR2,000 for the third year of the licence;
• INR2,800 for the fourth year of the licence; and
• INR4,000 for each subsequent year of renewal.

Mining Lease Fees Rent and Security Deposit

Prior to the grant of a lease, a prospective lessee is required to deposit a sum of INR200,000 for the grant of a lease, a sum of INR800,000 as a security deposit and a sum not exceeding INR120,000 towards preliminary expenses with the appropriate government.

Revenue Share

In the case of a Category I basin, a contractor is required to provide a revenue share to the GoI based on the LRP and the HRP quoted by the bidder in the bid and as agreed in the revenue sharing contract. For Category I basins, the LRP is equal to USD50,000 of revenue per day and the HRP is equal to USD7 million of revenue per day. Further, the revenue sharing ceiling at the HRP has been set at 50%. In the case of Category II and Category III basins, no revenue or production sharing with the GoI is envisaged, except when a windfall gain accrues to the contractor; ie, when revenue net of royalty from the contract area exceeds USD2.5 billion in a financial year. Revenue sharing between the contractor and the GoI in the case of such windfall gain shall be as per the graded rates of revenue sharing as provided under the notification dated 28 February 2019 issued by the GoI.

The following pieces of legislation set forth taxes that apply to upstream operations in oil and gas.

• The Income-tax Act, 1961 (the “IT Act”) – the provisions of the IT Act are applicable to the holders of an oil and gas interest in India. Deductions at the rate of 100% are allowed for capital and revenue expenditures incurred in respect of exploration operations and drilling operations. Companies can claim depreciation for newly installed machinery or plants and carry forward losses to set off against future revenues.
• The Central Goods and Services Tax, 2017 (the “GST Act”) – in 2017, the GoI introduced the Goods and Services Tax (GST), with the aim of further rationalising taxation and reducing overlapping taxes between state and central governments. Not all energy sectors are covered and not at the same rate. Petroleum products (crude oil, aviation turbine fuel, diesel and kerosene), natural gas and electricity do not fall under the GST as they incur central excise duty, state value-added tax (VAT) or electricity duty, as applicable. Other fuels – such as coal, naphtha, furnace oil and liquefied petroleum gas (LPG) – have been brought under the GST.

As highlighted in 1 General Structure of Petroleum Ownership, while the national oil and gas companies enjoyed special privileges in relation to the allocation of oil and gas blocks during the Nomination Era, such companies do not enjoy any special rights under the HELP Era. Allocation of blocks is based on an open, competitive bidding process. MRSCs, as provided by the MoPNG, are applicable to all companies, including PSUs.

The local content requirements for private investors as provided in an MRSC set forth that preference is given by the contractor to the purchase and use of goods manufactured, produced or supplied in India subject to delivery timing, quality, price and other terms; the employment of Indian subcontractors with the required skills or expertise to the maximum extent possible subject to comparable standards of services and competitive terms; and the incorporation of such provisions in the contract between the operator and its subcontractor.

In addition, the Policy to provide Purchase Preference (linked with local content) (PPLC) intends to support and boost the domestic manufacturing sector and provides for a target (ranging from 10% to 80% depending upon the activity) for local content in several oil and gas business activities (upstream, midstream and downstream). The local content requirements, applicable to PSUs and wholly owned subsidiaries and joint ventures of PSUs with 51% or more equity held by PSUs, are provided in the PPLC implemented by the MoPNG. The PPLC provides, inter alia, for purchase preference to be given to manufacturers or service providers who meet the local targets in oil and gas upstream business activities, local content of goods and service, etc.

A licence-holder needs to satisfy the following requirements to proceed to development and production once it has a commercial discovery.

• Notification of discovery (NOD) – the contractor is required to notify the GoI within seven days of a discovery of a block. The contractor is required to run tests as per the Good International Petroleum Industry Practices (GIPIP) to determine potential commercial interest (PCI) and then submit the information in relation to such discovery in a prescribed format within the timelines prescribed in the MRSC (the “PCI Notice”).
• Appraisal programme – the contractor may submit an appraisal programme if it thinks the discovery merits appraisal to establish the commerciality of a discovery within the specific timelines prescribed for onland, shallow water blocks and deepwater/ultra deepwater blocks.
• Field Development Programme (FDP) – the contractor, after completion of the appraisal programme, can submit the FDP demarcating the development area for a PML by the GoI. Once the approval of the development area is received from the GoI, the contractor can apply to the relevant authority for the grant of a PML. The FDP shall contain a detailed technical assessment report, a development plan for commercial development of the field, and the estimated investment for commercial production. The contractor is allowed to revise the FDP within the prescribed timelines for the commencement of production.
• Development phase – the development phase begins with the FDP submission and ends with the commencement of commercial production.

The key terms of an upstream licence, as per the MRSC, include the following.

• Exploration period – the MRSC stipulates an exploration period of three years (extendable by nine months on the payment of USD25,000 per month or part thereof) for onland/CBM/shallow water blocks and four years (extendable by 18 months on the payment of USD50,000 per month or part thereof) for a deepwater/ultra deepwater block. These extensions are automatic and can be sought only for a CWP (ie, the minimum work programme specified by the contractor in the bid). An additional work programme can also be performed during the extended period.
• Lease period – the lease is granted for an initial period of 20 years from the date of grant. The lease period can be extended by mutual agreement between the parties.
• Minimum work programme – a minimum work programme is submitted by the prospective bidder at the bidding stage and is subsequently incorporated under the RSC (at the time of execution). The contractor can formulate an additional work programme during the exploration phase. If the contractor fails to complete a CWP, each member constituting the contractor is required to pay to the GoI its participating interest share for an amount that shall be equivalent to liquidated damages as provided in the RSC.
• Relinquishment requirements – upon relinquishment, the company is required to undertake (i) site restoration activities, (ii) the removal of all equipment from such relinquished area in accordance with the abandonment plan, and (iii) all other actions necessary to prevent hazards to human life, the property of others, or the environment.
• Extensions – if the performance of obligations is affected due to any force majeure event, the exploration period, appraisal period and development phase as provided in the RSC are extended to the extent of the force majeure period or by such period as may be approved by the GoI.
• Domestic supply requirements – the company is required to sell in the domestic market in India all of its entitlement to crude oil and condensate and/or natural gas from the contract area until India attains self-sufficiency. In the event that India attains self-sufficiency during any year, the GoI will advise the company accordingly.
• Liability – the liability of each of the members of the contractor is joint and several to the extent of their individual participating interest.
• Termination – the RSC may be terminated by the contractor or the GoI by providing prior notice to the other party. The RSC provides grounds for termination by the GoI that include submission of any false statement to the GoI that was a material consideration for execution of the RSC, adjudication of the contractor as bankrupt, and failure to comply with the terms of the RSC.
• Abandonment – the contractor is required to deliver the contract area back in good order and condition pursuant to an abandonment plan as agreed with the GoI, upon expiry or termination of the contract or relinquishment of part of the contract area or decommissioning of petroleum operations. The contractor is further required to undertake site restoration activities in accordance with the Site Restoration and Abandonment Guidelines for Petroleum Operations, 2018 (the “Site Restoration Guidelines”).

The PNG Rules provide that private investors cannot assign interest in upstream licences without the consent of the relevant government. The MRSC elaborates the procedure of transfer of upstream interests. If the contractor is a consortium of several members, one of the members is appointed as the operator in accordance with the MRSC and the joint operating agreement (to be executed between consortium members).

• Government approval – the MRSC provides that assignment of participating interests requires prior consent of the GoI and such consent cannot be unreasonably withheld if the GoI is satisfied that the prospective transferee meets such parameters as envisaged under the MRSC.
• Obligations of the assignee – if such consent is given by the GoI, the prospective assignee is required to provide, inter alia, an irrevocable, unconditional bank guarantee in favour of the GoI, a parent financial and performance guarantee issued by a guarantor in favour of the GoI, etc.
• Deemed approval – if the GoI does not respond to the request for such approval within 120 days of such request, it is deemed that such approval is granted.
• Unpermitted transfer – assignment or transfer is not permitted where the participating interest 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. However, the GoI may permit such transfer on recommendation of the management committee constituted pursuant to the MRSC.
• Encumbrance – subject to satisfaction of certain conditions, the transfer restrictions are not applicable to a mortgage, pledge, charge or other encumbrance created by a contractor or member of a contractor, at its own risk and cost, on its participating interest for the purposes of security relating to finance required for performing its obligation under the contract.
• Requirements for transfer of operatorship – change in operatorship can be effected while ensuring that the new operator meets the criteria as qualified by the existing operator with prior written consent of the GoI.

The HELP regime has permitted marketing and pricing freedom for the sale of crude oil and natural gas in the domestic market, provided such prices are determined on an arm’s-length basis.

Investment by foreign investors is subject to certain investment caps, which are further enumerated in 4 Foreign Investment.

With the opening of the oil and gas sector in India for private players, there are currently no monopolies per se in the oil and gas sector; the retail sector is primarily dominated by state-owned companies, including IOCL and BPCL, and the pipeline sector is primarily dominated by GAIL as the largest natural gas pipeline is operated by GAIL (please refer to 1 General Structure of Petroleum Ownership and Regulation for further details on GAIL).

Further, prior to undertaking any activity pertaining to the refining, processing, storage, transportation, distribution, marketing and sale of petroleum, petroleum products and natural gas excluding the production of crude oil and natural gas, entities are required to obtain licences and authorisations under the relevant legislation, including the Petroleum Act, the PNGRB Act and the rules and regulations made thereunder.

As highlighted in 3.1 Forms of Allowed Private Investment in Midstream/Downstream Operations, while no monopolies exist in the downstream sector, access, methodologies for tariffs, etc are governed by various regulations issued by the PNGRB.

Under relevant regulations, the overall capacity of a pipeline from time to time (determined as per the prescribed procedure, parameters and frequency) is subject to declaration/apportionment by the PNGRB as “contract carrier” or “common carrier” (refer to 3.10 Rules for Third-Party Access to Infrastructure for further details). The regulations provide a fairly detailed distinction, and guiding principles for such declaration. The MoPNG also launched an online portal in August 2018 for the booking of transmission services under GAIL’s pipelines for third parties to apply for capacity booking for excess (available) capacity for the transportation of natural gas through common carrier or contract carrier pipelines.

As a general principle, tariff determination under the tariff regulations is based on cost recovery (but subject to a normative level of allowable capital costs and operating expenses) using a discounted cash flow method (DCF) considering a "reasonable and justifiable" rate of return.

Some of the key licensing requirements for certain downstream activities are set out below.

• Importation and storage of petroleum – the storage of petroleum is not permitted without a licence. The storage of certain classes of petroleum (categorised on the basis of flash points) does not require a licence. Similarly, the importation of petroleum is not permitted without a licence. Permission from the Commissioner of Customs is required to unload imported petroleum in India.

• Laying down of pipelines – entities wishing to lay or build a new pipeline, or expand an existing pipeline, after 1 October 2007 are subject to a bidding process and authorisation by the PNGRB (provided (i) eligibility criteria is met and (ii) the PNGRB does not decide that natural gas for the proposed development or expansion is not available and/or (in the case of a new proposed pipeline) that the potential demand could be met more cost effectively by expansion of an existing pipeline). Detailed procedural formalities and eligibility criteria in this regard have been set out in relevant regulations and guidelines issued by the PNGRB. The eligibility criteria include design capacity, financial and technical criteria in relation to construction, as well as operation and maintenance of pipelines. A similar mechanism has also been provided for laying down of City Gas Distribution (CGD) networks in accordance with regulations issued by the PNGRB.
• Setting up a refinery – a person intending to engage in refining, cracking, reforming or blending petroleum is required to obtain consent from the Chief Controller of Explosives at PESO.

The prices of petroleum and petroleum products are determined on a daily basis, and are directly dependent on the price of petroleum and petroleum products in the international market.

In addition, tariffs for pipelines for CGD, natural gas and petroleum, and petroleum products are determined by the PNGRB in accordance with certain principles, including the following.

General Principle

As a general principle, tariff determination under the tariff regulations is based on cost recovery (but subject to a normative level of allowable capital costs and operating expenses) using a DCF method considering a "reasonable and justifiable" rate of return. The tariff regulations elaborate on how this general principle is to be applied, as noted below.

Levelisation

The tariff is to be determined and applied on a levelised basis during each tariff period.

Regulated Rate of Return

For the purposes of tariff determination, the rate of return on capital invested is fixed (for the duration of the economic life of the asset) at 12% post-tax.

Allowable Adjustments to DCF Calculation

Prospective adjustments are allowed to be made to the DCF calculations underlying the tariff determination on account of (i) any variations in respect of actual capital costs and/or actual operating costs (as against the normative assessment) and/or (ii) any variation in actual volumes transported on common carrier basis in any year (as against that for the year immediately preceding the tariff review date).

Unlike the upstream sector, wherein a model contract is executed, there is no standard form of contract for various activities under the downstream sector. However, the PNGRB Act requires pipeline owners to register their pipeline use agreements, which are also known as gas transportation agreements, with the PNGRB.

The current direct (Income Tax-act, 1961) and indirect tax regime (GST and VAT) are applicable to downstream operations. Please refer to 2.4 Income or Profits Tax Regime Applicable to Upstream Operations for further details on the applicability of direct and indirect taxes.

A national oil or gas company does not enjoy any special rights in the downstream sector. The PNGRB ensures fair trade and competition amongst the market players in the downstream sector.

Please refer to 2.6 Local Content Requirements Applicable to Upstream Operations for further details.

An entity having a licence/consents/authorisations granted under the PNRGB Act, the Petroleum Act and the corresponding rules and regulations framed thereunder is required to comply with the conditions and obligations under such pieces of legislation, which include technical standards, safety standards and code of conduct. The licences, authorisations and approvals are granted subject to the terms and conditions as provided under the respective licences, authorisations and approvals.

The eminent domain right rests solely with the state and the central government. It is governed by the Right to Fair Compensation and Transparency in Land Acquisition, Rehabilitation and Resettlement Act, 2013, which provides the procedure for land acquisition and compensation payable for the condemned land. The GoI can acquire land only for a public purpose. The GoI may acquire land for PPP projects, where the ownership of land continues to vest with the GoI and for private companies for a public purpose. Further, land can also be acquired through bilateral negotiations.

Besides the PNGRB Act, another piece of legislation that is relevant to natural gas pipeline development is the Petroleum and Minerals Pipelines (Acquisition of Right of User in Land) Act, 1962, which provides a framework governing the acquisition of right of user (RoU) of a land for laying pipelines for transportation. This piece of legislation is limited to acquisition procedure, restrictions on the use of land, and compensation payable to persons interested in land.

The PNGRB generally classifies pipelines as "common carrier" or "contract carrier". A contract carrier pipeline is one where pipeline capacity, over and above the transporter’s own requirement, is available to any other (midstream or downstream) entity who has entered into a contract for specified volumes for a minimum period of one year. A common carrier pipeline is one where the pipeline capacity, over and above the transporter’s own requirement and the capacity allocated under the contract carrier system, is available for booking by a third party for a period that is less than one year.

The contract carrier or common carrier capacity in respect of a pipeline is to be approved by the PNGRB, and may be subject to change by the PNGRB at any time on its own or on application by the entity if it considers that it is necessary or expedient to do so.

Available common carrier capacity is to be allocated on a non-discriminatory "first come, first served" basis. The customer seeking access to pipelines is required to enter into access-sharing agreements with the authorised entities. In the context of CGD networks, the PNGRB may grant exclusivity to an entity proposing to lay, build, operate or expand a CGD network from the purview of common carrier or contract carrier for a period of eight years from the date of grant of authorisation.

The authorised entity is permitted to declare additional entry and exit points within the pipeline system. It is also required to declare on a monthly basis (by notification to the PNGRB and on its website) the available capacity in the pipeline and between entry and exit points. The authorised entity is required to prepare standardised calorific value bands for the pipeline, which are to be applied on a non-discriminatory basis to all users.

In order to sell petroleum products in the local market, an authorisation is required under the PNGRB Act to build and operate pipelines or a local natural gas distribution network. The PNGRB (Authorizing Entities to Lay, Build, Operate or Expand Natural Gas Pipelines) Regulations, 2008 require an authorised entity to have an agreement for the transportation of natural gas with any entity equal to at least 50% of the natural gas pipeline volume.

The PNGRB (Authorizing Entities to Lay, Build, Operate or Expand City or Local Natural Gas Distribution Networks) Regulations, 2008 provide that an entity authorised for laying, building, operating or expanding a CGD network is required to meet certain service obligations, which include an interest-free refundable security deposit from a domestic customer.

Exports in India are governed by the foreign trade policy under the Foreign Trade (Development and Regulation) Act, 1992. India does not export crude oil and natural gas (see 2.8 Other Key Terms of Each Type of Upstream Licence) till it achieves self-sufficiency. Crude oil is reserved for export by state trading enterprises (STEs), which are governmental and non-governmental enterprises, including marketing boards, that deal with goods for export and/or import and can be exported under Advance Authorisation/Duty Free Import Authorisation only after obtaining a No Objection Certificate from the relevant STE.

Exportation of petroleum products is freely allowed subject to obtaining an NOC from the Ministry of Petroleum and Natural Gas. To export such products, an Importer Exporter Code needs to be obtained from the regional authority of the Director General of Foreign Trade.

As per the Petroleum Rules, 2002, a person can transfer a licence for the storage of petroleum after the approval of such transfer by the licensing authority. The transferee then enjoys the same privileges as the original licensee.

However, the PNGRB (Authorizing Entities to Lay, Build, Operate or Expand Petroleum and Petroleum Products Pipelines) Regulations, 2010, the PNGRB (Authorizing Entities to Lay, Build, Operate or Expand Natural Gas Pipelines) Regulations, 2008, and the PNGRB (Authorizing Entities to Lay, Build, Operate or Expand City or Local Natural Gas Distribution Networks) Regulations, 2008 permit a transfer of the authorisation to any person only after a specified time period and subject to the fulfilment of certain parameters.

The Consolidated FDI Policy (effective from 28 August 2017) issued by the Department of Industrial Policy and Promotion at the Ministry of Commerce and Industry stipulates that investments can be made under the automatic route (ie, no prior government approval is required for foreign investments) subject to the following sectoral caps:

• up to 100% automatic route for exploration activities of oil and natural gas fields, infrastructure related to the marketing of petroleum products and natural gas, the marketing of natural gas and petroleum products, petroleum product pipelines, natural gas/pipelines, LNG regasification infrastructure, market study and formulation, and petroleum refining in the private sector, subject to the existing sectoral policy and regulatory framework in the oil marketing sector and the policy of the GoI on private participation in the exploration of oil and the discovered fields of national oil companies; and
• up to 49% automatic route for petroleum refining by PSUs, without any disinvestment or dilution of domestic equity in the existing PSUs.

However, in light of Press Note 3 of 2020, an entity of a country that shares a land border with India or where the beneficial owner of an investment into India is situated in or is a citizen of any such country can invest only under the governmental route. Further, a citizen of Pakistan or an entity incorporated in Pakistan can invest, only under the governmental route, in sectors/activities other than defence, space, atomic energy and sectors/activities prohibited for foreign investment. Accordingly, the aforesaid automatic routes would not be applicable for investment by entities of a country sharing a land border with India.

As far as the availability of international arbitration is concerned, it may be noted that:

• for the upstream sector, an MRSC provides an arbitration mechanism governed by the Indian Arbitration and Conciliation Act, 1996, with the venue of the arbitration being New Delhi. Given that an MRSC is not negotiated prior to execution, international arbitration is not available for the upstream sector; and
• while there is no standardised contract for the downstream sector, the parties to the relevant contract are open to agree on a mutually agreed arbitration mechanism.

The key environmental regulators include:

• the Ministry of Environment, Forest and Climate Change (MoEF) (http://moef.gov.in/);
• the DGH (http://dghindia.gov.in/);
• the Central Pollution Control Board (https://www.india.gov.in/official-website-central-pollution-control-board); and
• the Ministry of Defence (https://mod.gov.in/).

Given that there are no specific pieces of environmental legislation, governmental policies or incentives that address the environmental issues surrounding upstream and downstream operations, the following generic environmental laws assume relevance in this regard.

• The Water (Prevention and Control of Pollution) Act, 1974 and Air (Prevention and Control of Pollution) Act, 1981 were enacted to preserve the water and air quality, and further provide for the prevention, control and abatement of water and air pollution. Companies are also required to obtain "consent to establish" and "consent to operate" from the central pollution control board or state pollution control boards (SPCBs), as may be applicable.
• The Environment Protection Act, 1986 (EPA), read along with the Environment Protection Rules, 1986, is one of the most inclusive pieces of legislation and sets forth the provisions addressing the protection and improvement of the environment. The EPA further prescribes certain limitations in relation to standards of emission and discharge of pollutants in the environment.
• The Hazardous Wastes (Management, Handling and Trans-boundary Movement) Rules, 2016 set forth that approval from the relevant SPCB is required in relation to generating, processing, treating, storing, packaging, etc of the hazardous waste that may have been generated during the E&P operations.
• The Oil Mines Regulations, 2017 provide for the safety management system for identifying, assessing or controlling a hazard or recovery therefrom.
• The National Oil Spill Disaster Contingency Plan, as issued by Ministry of Defence, provides for the national plan to respond to incidents regarding an oil spill and hazardous and noxious substances.
• The Guidelines for Environmental Management during Shale Gas/Oil Exploration and Production provide for the operating guidelines to be followed by companies during the E&P of shale gas/oil.
• The Merchants Shipping Act, 1958 further stipulates the provisions pertaining to civil liability in the case of oil pollution damage that are applicable to (i) every Indian ship (wherever it is), and (ii) every foreign ship while it is at a port or place in India or within the territorial waters of India or any marine areas adjacent thereto over which India has, or may hereafter have, exclusive jurisdiction with regard to control of marine pollution under the Territorial Waters, Continental Shelf, Exclusive Economic Zone and other Maritime Zones Act, 1976, or any other law for the time being in force.

The environmental clearance process for oil and gas projects and activities in the upstream sector comprises of the following.

• Stage 1: scoping for deciding the terms of reference (ToR) for the preparation of an environmental impact assessment (EIA) report – at this stage, the ToR addresses all relevant environmental concerns in respect of the project.
• Stage 2: public consultation – at this stage, the concerns of local affected persons and others who have a plausible stake in the environmental impacts of the project are considered and changes are made to the EIA report as appropriate. The EIA report or the draft of the EIA and EMP addressing all the concerns are submitted to the concerned regulatory authority for appraisal.
• Stage 3: appraisal by the Expert Appraisal Committee (EAC) of the MoEF for environmental clearance – at this stage, a detailed scrutiny of the documents submitted at Stage 2 is undertaken by the EAC in a proceeding to which the applicant is also invited. Based on recommendations of the EAC, the regulatory authority concerned grants or rejects the prior environmental clearance.

Exploration activities in the hydrocarbon sector require environmental clearance only and are exempt from undertaking processes under Stage 1 and Stage 2, whereas all three of the aforementioned stages are required to be followed for the production/development of offshore/onshore fields.

The EHS requirement for offshore blocks is governed as per the Petroleum and Natural Gas (Safety in Offshore Operations) Rules, 2008 (the “Offshore Operations Rules”), which require the operator (the person carrying out offshore activities) to prepare information and records as may be considered necessary for petroleum activities, and any other information to ensure that the petroleum activities are planned and carried out in a safe manner and are well documented.

Liability Exposure and Limitations

The Oilfield Act stipulates that contravention of any rules made pursuant to the said Act may lead to imprisonment or imposition of a fine, or both. The Offshore Operations Rules are formed pursuant to the Oilfield Act and therefore the applicability of the penalties would extend to the same.

In addition, the companies are also required to undertake E&P works in accordance with the standards stipulated under the RSC. Given the same, the companies may be held responsible for breach of the RSC and appropriate actions may be undertaken by the GoI.

The PNG Rules require the delivery of land and wells in good order and condition after the expiry or termination of a PEL and/or a PML. Such delivery of land and wells is required to be made to the respective government within six months from the expiry or termination of a PEL and/or a PML.

In addition, please refer to 2.8 Other Key Terms of Each Type of Upstream Licence for information relating to site restoration obligations of the entity.

India is a strong advocate at international fora in the fight against climate change. Pursuant to the 21st Conference of Parties (“COP 21”) of the UN Framework Convention on Climate Change, held in 2015 in Paris, the member countries (including India) agreed to reduce and monitor the Intended Nationally Determined Contribution (INDC) to reduce the quantum of emissions of its economy and hike the proportion of non-fossil fuel-based mechanisms for the purposes of power generation whilst creating an additional carbon sink by increasing forest and tree cover. India has, post COP 21, issued and formulated various guidelines and policies aimed at shifting towards a renewable and green approach. The initiatives include Green India MissionXXX, FAME-India (Faster Adoption and Manufacturing of (Hybrid &) Electric Vehicles in India) and the National Action Plan on Climate Change.

In addition, please refer to 5.1 Principal Environmental Laws and Environmental Regulator(s) for specific pieces of legislation pertaining to the environment that are, in turn, related to climate change.

As highlighted in 1.1 System of Petroleum Ownership, petroleum and petroleum products falls within the Union List under the Constitution of India; ie, it is a subject matter over which the central government has legislative competence. In view of the foregoing, the local government restrictions are applicable to the extent of obtaining local permits from the relevant authorities, in connection with the operations, land use, etc.

In light of rapidly increasing domestic demand for energy, India has sought to supplement conventional energy with unconventional energy. Under the current HELP regime, benefits made available to conventional hydrocarbons – such as marketing and pricing freedom, and graded royalty rates – are extended to unconventional hydrocarbons.

The definition of "petroleum" under the PNG Rules, 1959 was also amended in 2018 to include unconventional hydrocarbons and thus the regime for obtaining licences with respect to unconventional hydrocarbons has also been brought on a par with that of conventional hydrocarbons. Further, the Environment Impact Notification, 2006 (the “EIA Notification”) as well as site restoration and abandonment guidelines for petroleum operations issued by the DGH also provide a uniform regulatory framework to address the environmental risks pertaining to both conventional and unconventional hydrocarbons.

However, given the specific environmental hazards that the exploration of shale gas poses, the DGH has issued guidelines for environmental management during the exploration of shale gas. Further, the compendium of Good International Petroleum Industry Practices prepared by the DGH also lists certain practices to be adhered to by E&P operators in respect of the exploration and production of unconventional hydrocarbons.

While the HELP regime is applicable prospectively to blocks allocated under HELP, prior to HELP, separate policies governed the exploration of unconventional hydrocarbons. The exploration and exploitation of CBM was permitted under the CBM Policy, 1997 where CBM was considered as natural gas. The exploration and exploitation of shale oil and gas resources in nomination areas was governed by the Shale Gas and Oil Exploration Policy, 2013. Pursuant to the Policy Framework for Exploration and Exploitation of Unconventional Hydrocarbons under Existing PSCs, CBM and Nomination Fields dated 20 August 2018 (the “Policy Framework”), the exploration and exploitation of unconventional hydrocarbons has now been permitted in all blocks under pre-NELP and NELP, including nomination blocks given to OIL and ONGC subject to terms and conditions stipulated in the Policy Framework.

LNG projects are governed by the PNGRB Act. An authorisation from the PNGRB is required to establish and operate LNG terminals. An entity is required to meet eligibility conditions as prescribed in the PNGRB (Eligibility Conditions for Registration of Liquefied Natural Gas Terminal) Rules, 2012 before making an application for registration, which consists of (i) offering as common carrier capacity the higher of 20% of its uncommitted regasification capacity or 0.5 million metric tonnes per annum (MMTPA); (ii) complying with the technical standards and specifications as provided by the PNGRB in relation to petroleum, petroleum products and natural gas, including regulations laid down by the Oil Industry Safety Directorate; and (iii) furnishing a bank guarantee of an amount that is the lesser of INR250 million or 1% of the estimated project cost. However, there are currently no special schemes relating to LNG projects.

India is the fourth-largest importer of LNG and does not export LNG to other countries.

The Indian Gas Exchange (IGX) has recently been launched by the Indian Energy Exchange as India’s first nationwide online delivery-based gas trading platform, which seeks to provide a neutral and transparent marketplace to multiple buyers and sellers to trade in spot and forward contracts at three physical hubs, Dahej and Hazira in Gujarat and Kakinada in Andhra Pradesh.

With India making a policy move towards a gas-based economy, the IGX is a step in the right direction, as currently buyers do not have direct access to the gas market and have to enter into protracted negotiations with sellers, which significantly enhances the seller's bargaining position, leading to an overall increase in the cost of gas. With buyers having multiple options as well as various products to choose from on the platform, the IGX will strengthen the position of buyers. Most importantly, market-determined pricing of gas on the IGX is likely to lead to Indian gas pricing becoming more transparent, efficient and competitive.

While there has been no material change in the oil and gas laws per se over the past year, a policy move that could have significant impact on the oil and gas sector is the recent recategorisation with respect to environmental clearance. The MoEF has, vide notification dated 16 January 2020, categorised onshore and offshore oil and gas exploration activities as Category B2 for seeking environment clearance. Prior to the issuance of said notification, “offshore and onshore oil and gas exploration, development and production” had been characterised as a Category A project under the EIA Notification.

Under the EIA Notification, projects characterised as Category A are likely to have a material impact on the surrounding environment and are thus subject to detailed scrutiny in the form of preparation of an EIA plan by the project proponent, scrutiny of the project by a centrally constituted expert committee, a public hearing of the proposal involving the locals of the proposed project site, and clearance from the central government. Category B projects require environmental clearance from the state government, with Category B2 projects being exempt from an EIA and a public hearing.

As exploration activities in the hydrocarbon sector have been moved from Category A to Category B2, they will now require environmental clearance only from the states concerned and will be exempt from an EIA and a public hearing. However, the production/development of offshore/onshore fields as hydrocarbon blocks will continue to be characterised as Category A projects and thus will require prior environmental clearance from the central government.