The government is all set to increase exploration activity and accelerate the development of oil and gas fields in the country through favourable policies and reforms in the exploration and production (E&P) of hydrocarbons. In a major development, the government approved the long-pending proposal to replace the 16-year-old New Exploration Licensing Policy (NELP) with the Hydrocarbon Exploration and Licensing Policy (HELP).
Under the reformed framework, key improvements have been made to address problem areas such as the production sharing regime, pricing and licensing. While these issues have been long discussed, HELP was approved only in March 2016, following proposals announced in the Union Budget 2016-17. With this move, the government expects to revive investments in the oil and gas sector so as to boost domestic output and reduce dependence on imports. The policy is also aimed at enhancing transparency and reducing administrative discretion in the sector.
Salient features of HELP
HELP is applicable to new discoveries and areas which are yet to commence production as of January 1, 2016. It would thus include fields where exploration is under way and commercial production has not yet commenced. The key features of the new policy are:
Revenue sharing regime
HELP proposes a shift from the production sharing contract to a revenue sharing regime. The new regime is a “pay-as-you-go” model where the operator will have to part with a percentage of gross revenues generated from the block. The government’s share of revenue will move in accordance with the developer’s total earnings from the block. The government will not be concerned with the cost incurred and will receive a share of the gross revenue from the sale of the output (oil, gas, etc.). This is also a step towards fulfilling the government’s agenda of the “Ease of Doing Business” initiative.
Marketing and pricing freedom
Under HELP, a company will have freedom in pricing and marketing the gas produced in the domestic market on an “arm’s length” basis. To safeguard the government’s share of revenue, the share will be calculated based on the higher of the prevailing international crude price and the actual price.
Single licence for exploring all types of hydrocarbons
HELP requires companies to get just one licence to manage all hydrocarbon reserves such as oil, gas, shale and coal bed methane. A single licence for E&P of all forms of hydrocarbons in a block would be given to the firm offering the maximum revenue to the government.
The policy has also changed the method of awarding oil and gas licences. It has proposed a shift to the Open Acreage Licensing Policy, allowing companies to choose the area for exploration rather than the government identifying blocks and offering them in different bid rounds. Now, a bidder may apply to the government seeking permission for the exploration of a new (unexplored) block. The government will then examine the expression of interest for awarding the block for further activity. If the block is found suitable, competitive bids will be invited. This will enable faster coverage of the geographical area available for exploration.
Other changes under the HELP regime call for lower royalty rates as compared to those in the NELP. A concessional royalty regime will be implemented for deepwater and ultra-deepwater areas. These areas will not have to pay any royalty for the first seven years. Thereafter, a concessional royalty of 5 per cent for deepwater areas and 2 per cent for ultra-deepwater areas will be charged. In shallow water areas, the royalty will be reduced from 10 per cent to 7.5 per cent. Royalty for onland areas has been kept intact so that revenues of state governments are not shaved off. Besides, cess and import duty exemptions have been retained from the NELP framework.
Further, under the new policy regime, the government plans to provide complete freedom in pricing and marketing of the gas produced. At present, gas prices in the country are determined by a formula based on average gas prices in gas-surplus areas. Under the new policy, producers will be allowed marketing freedom including pricing freedom for all the discoveries in deepwater/ultra-deepwater/high temperature/high pressure areas which are yet to commence commercial production as on January 1, 2016 and for all future discoveries in such areas. However, in order to protect user industries from sharp increases, this freedom will be accompanied by a price ceiling based on the opportunity cost of imported fuels.
The ceiling price will be based on the lowest of the landed price of imported fuel oil, the weighted average import landed price of substitute fuels (coal, fuel oil and naphtha) and the landed price of liquefied natural gas. These prices will be reset biannually. This price cap, at current prices of the fuels that form part of the equation, works out to $6-$7 per million British thermal units (mmBtu) of gas. This is significantly higher than $3.4 per mmBtu, which is the current price of natural gas as fixed by the government.
Expected impact of HELP
The new policy certainly comes as good news for E&P players. It is expected to address key problem areas that have thus far deterred investments by both domestic and foreign players in the sector. The shift towards a unified licence and lower royalty rates are likely to incentivise domestic production of hydrocarbons, especially from deepwater and ultra-deepwater blocks, which are currently lying untapped. Besides, it is expected to bring about greater transparency in the auctioning process. However, E&P firms are not very upbeat about the new revenue sharing model as this will increase the risk for them as the investment recovery period for producers will be prolonged.
Further, the policy will ensure transparency in awarding blocks as well as speedy implementation of projects. According to India Ratings, nearly 190 billion cubic metres or around 35 million metric standard cubic metres per day of gas reserves (15-year production profile) can benefit from the changed policy. Also, unlike in the existing contracts where 100 per cent of the gas allocation is decided by the government on the basis of the gas priority allocation policy, the new regime provides more flexibility to developers to choose end-consumers as well as the price at which the gas is sold to them.
The new pricing formula for output from difficult areas also comes as a huge relief. However, E&P players will have to revisit their costs as there are blocks that have both deepwater and shallow water discoveries. Averaging the price will be difficult if the same infrastructure is used. Over time, it would pave the way for a level playing field between domestic and imported gas and create a competitive gas market. However, prices of alternative fuels, to which India’s gas prices are indexed, should stay healthy for the derived gas prices to remain attractive and support new investments in the sector. According to industry experts, the new policy will increase investments in the difficult fields but prices of gas from normal fields will stay subdued, discouraging investments in that segment.
Meanwhile, it is pertinent to note that some of the difficult fields are greenfield projects and many discoveries will need approvals for capital outlays as well as some time to implement. Hence, it will take at least three years for these fields to start production. Still, the attractive pricing is a big positive going forward. The government estimates that the new pricing could help monetise about 38 field reserves valued at over $25 billion that are still to be put up for production. In the long run, when crude and gas prices harden, the effect of these investments will definitely be visible.
Going forward, the oil and gas sector will be significantly reshaped by these policy measures, which are likely to usher in a new era where the government will act as a facilitator rather than a sector regulator. However, there is an urgent need to address some underlying gaps and issues which may crop up in the future. These relate to environmental clearances, fiscal stability, a complex regulatory framework and a differential gas pricing mechanism.
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