The hydrocarbon sector is vital in keeping India’s economic growth engine running. Domestic crude oil consumption has increased from 174.5 million tonnes (mt) in FY 2013 to 247.8 mt in FY 2023, growing at a compound annual growth rate (CAGR) of 3.6 per cent, while domestic production has declined from 37.9 mt to 29.2 mt during the same period. Currently, only 12 per cent of the country’s crude oil needs are being met domestically, while 88 per cent are being met through imports, entailing a huge import bill. The demand for crude is expected to increase by 4-5 per cent in FY 2024 and will continue to increase over the next several years. However, the growth in domestic production is expected to be limited, due to which the dependence on crude oil imports is likely to remain high.
Domestic gas consumption too has grown over the past decade, increasing from 147.7 million metric standard cubic metres per day (mmscmd) in FY 2013 to 159.3 mmscmd in FY 2023. Domestic production, meanwhile, has declined from 111.4 mmscmd to 94.4 mmscmd over the same period. Although domestic gas production is expected to increase to 106 mmscmd in FY 2024 and to 113 mmscmd in FY 2028, the dependence on liquefied natural gas (LNG) imports is expected to remain high.
Policy initiatives
To reduce the dependence on imports and increase domestic oil and gas production, the government has been taking several policy initiatives. In March 2016, the New Exploration Licensing Policy (NELP) was replaced with the Hydrocarbon Exploration Licensing Policy (HELP). Under the NELP, the government’s profit share was finalised following the recovery of other operating costs by the operator and the capex. This, in turn, required a scrutiny of costs and often led to disputes over the capex amount to which the government’s share of profit was linked. Under the HELP, the government is not involved in monitoring the costs incurred and directly gets its share from the revenues. Additionally, from July 1, 2017, bidding for oil and gas acreage through an open acreage licensing policy (OALP) was started, which allows companies to carve out their areas of exploration. Under the OALP, blocks are awarded after obtaining the necessary environmental and other clearances, which speeds up the exploration process. In February 2019, the government announced that in basins with no commercial production (Category II and III basins), exploration blocks would be bid out exclusively on the basis of exploration work without any revenue or production share to the government.
To incentivise higher production of domestic gas, the government provided marketing and pricing freedom to coal bed methane producers. It also provided marketing and pricing freedom (subject to a price ceiling) to players operating in deepwater, ultra-deepwater and high-pressure, high-temperature areas that were yet to commence commercial production as on January 1, 2016.
As per the schedule stipulated in the HELP/OALP, eight bidding rounds have so far been finalised. OALP Bid Round IX, offering eight blocks along with 18 areas for suo motu expression of interest, covering an area of approximately 0.22 million sq. km, was launched on April 1, 2023.
Gas pricing scenario
Historically, the government has controlled the prices of domestically produced natural gas. In October 2014, it approved a formula whereby gas prices were determined based on the volume-weighted prices prevailing in North America (the US, Mexico and Canada), the European Union, the former Soviet Union countries (excluding Russia), and Russia. In April 2023, the government revised the pricing formula for administered pricing mechanism (APM) gas, which is now determined on a monthly basis at an approximately 10 per cent slope to the monthly average price of the Indian crude oil basket. For gas production from the APM nomination fields of the Oil and Natural Gas Corporation and Oil India Limited, a floor price of $4 per metric million British thermal units (mmBtu) and a ceiling price of $6.5 per mmBtu has been prescribed, with an annual increase of $0.25 per mmBtu in the ceiling price from FY 2026 onwards.
Oil refining and imports
The crude oil refining and marketing sector was decontrolled in stages from 1998 to 2003, which authorised refining players to charge refinery transfer pricing. This was based on international prices of products based on import parity, which was modified in 2006 to a trade parity basis for a few products. However, as global crude oil prices showed a sharp increase, the government restrained oil marketing companies (OMCs) from increasing the prices of sensitive products (motor spirit [MS], high speed diesel [HSR], liquefied petroleum gas [LPG] for domestic use and superior kerosene oil [SKO] for the public distribution system) in line with international prices. Consequently, the gross under-recovery (GUR), which is the difference between the required selling price and the actual selling price, increased for OMCs. The burden of the GUR was mostly shared by the upstream public sector undertakings (in the form of a discount on crude oil/LPG/SKO) and the Government of India. However, since FY 2016, the under-recovery burden has been borne by the government. The government deregulated the retail prices of petrol in 2010 and diesel in 2014, which led to a decrease in the regulatory risk for OMCs. On July 1, 2022, the government levied a cess/windfall tax on the production of crude oil by upstream oil and gas producers and on exports of automatic transmission fluids, HSD and MS, which was revised many times subsequently.
India’s dependence on oil imports has been growing for many years now. The domestic refining capacity is expected to increase from 258 mt as on March 31, 2023 to 306 mt over the next three years. The Hindustan Petroleum Corporation, in a 74:26 joint venture with the Rajasthan government, is setting up a 9 million tonne per annum (mtpa) greenfield refinery-cum-petrochemical complex at Barmer, Rajasthan. It is expected to be commissioned in 2024. The Chennai Petroleum Corporation and Indian Oil Corporation have formed a joint venture for setting up a 9 mtpa greenfield refinery at Nagapattinam in Tamil Nadu, and operations are likely to commence in 2026. Besides increasing the refining capacity, the downstream industry is also setting up petrochemical projects to diversify their revenues and de-risk from lower fuel sales over the long term.
Gas sector update
The government has pushed for the setting up of trunk pipelines connecting the eastern and north-eastern parts of the country through budgetary support in the form of viability gap funding for the Urja Ganga and Indradhanush pipelines. Apart from this, the Petroleum and Natural Gas Regulatory Board has conducted bidding rounds 9 to 11 and 11A, wherein city gas distribution licences have enabled an increase in coverage, from 20 per cent of the population till round 8 to about 98 per cent till the latest round.
Several LNG terminals are being set up, at Jaigarh, Charra, etc., which, along with the recently commissioned
terminals at Dhamra and Mundra, will increase competition in the market and provide greater choice to consumers. The LNG terminal capacity will increase from 47.5 mtpa at present to 66.5 mtpa in the next three to four years.
Pain points
To attract capital investments in oil exploration and production, 100 per cent foreign direct investment (FDI) has been allowed under the automatic route. However, given the high risks, very few big global oil companies are likely to participate since India has poor data on geological prospects as compared to some countries. The other key issues hindering the development of the upstream sector include the high cess of 20 per cent advalorem, the slow pace of approvals, stalled progress in several blocks owing to the absence of approvals from various ministries, delays in decision-making by the Directorate General of Hydrocarbons, and increasing arbitration cases involving the administration of production sharing contracts.
In the gas sector, some of the key impediments are the lack of pipeline connectivity across the country, especially in the eastern and southern parts, regulated realisations/product prices of natural gas-consuming industries, the absence of uniform taxation with different states having different value added tax (VAT) rates, separation of pipeline ownership and marketing, slow pace of approvals, etc. In addition, competition from electric vehicles, especially in the state transport bus segment, and hydrogen will also increase going forward.
Sector outlook
Natural gas, crude oil and other petroleum products are currently outside the purview of the goods and services tax (GST). These products are subject to excise duty levied by the central government and VAT levied by the state governments. There has been a long-standing demand from the industry to include these products in the GST regime in order to enable the free flow of input tax credits and avoid stranded taxes.
Global efforts to transition to low-carbon energy will gradually lower the demand for petroleum products in the coming decades. The carbon transition risk for the domestic oil and gas industry will accordingly play out over the distant future.
