India’s upstream reforms and the current OALP bid rounds: what international explorers should know

Neeraj Menon

TRILEGAL, Mumbai

neeraj.menon@trilegal.com

Why the current rounds deserve a second look

International explorers evaluating Indian acreage have had to price in fiscal uncertainty, dispute-resolution risk, regulatory enforcement and the legacy of cost recovery disputes. Recent reforms materially improve that proposition. Since early 2025, parliament has amended the statute governing oilfields: the Ministry of Petroleum and Natural Gas (MoPNG) has replaced the 1959 Rules, and revised model contracts and a consolidated royalty schedule have been issued. Cabinet has also approved a scheme to share deepwater exploration costs.

The current bidding terms for Rounds X and XI of the Open Acreage Licensing Policy (OALP) incorporate the statutory and contractual reforms. Round X, launched on 11 February 2025, offers 25 blocks across 13 basins covering approximately 182,589 sq km, including 13 deepwater or ultra-deepwater blocks. Round XI, launched on 30 March 2026, offers 21 blocks across eleven basins covering approximately 80,234 sq km, nine offshore. Onland and shallow-water bidding closed on 19 June 2026. The Directorate General of Hydrocarbons (DGH) currently advertises noon Indian Standard Time, 15 November 2026 for deepwater and ultra-deepwater bids in both rounds. Bidders should confirm the operative notice and portal timetable before submission.

From cost recovery to revenue sharing

The New Exploration Licensing Policy (NELP), formulated in 1997, produced nine rounds launched between 1999 and 2010, with the final-round contracts signed in 2012. Government-selected blocks were awarded under production sharing contracts providing for cost recovery and sharing of profit petroleum. Cost recovery required scrutiny of expenditure, and disputes over the treatment of costs became a recurring feature of NELP and earlier production sharing contracts alike.

The Hydrocarbon Exploration and Licensing Policy (HELP), introduced in 2016, adopted revenue sharing without contractual cost recovery. It enabled investor-led acreage selection through OALP, uniform licensing for conventional and unconventional hydrocarbons, and marketing and pricing freedom subject to contract and policy. Domestic sales remain required unless the government permits otherwise. HELP also reduced offshore royalty. The 2019 reforms placed greater weight on exploration commitments. Current Category I terms use a bid sliding scale between average daily contractual revenue points of US$0.05m and US$7m.[1] Category II and III sharing only applies above US$2.5bn of contractual revenue in a financial year, with progressive bands. Contractual revenue deducts royalty and specified production or sales taxes, but not input taxes or corporate income tax. These fiscal terms are distinct from profit sharing.

A firmer statutory foundation

The Oilfields (Regulation and Development) Amendment Act 2025, effective from 15 April 2025, makes four changes relevant to bidders. An integrated petroleum lease covers exploration through production. The definition of mineral oils includes shale hydrocarbons, tight oil and gas, coal bed methane and gas hydrates. Section 5(3) of the Oilfields (Regulation and Development) Act 1948 (Oilfields Act) protects lease terms against alteration to the lessee’s disadvantage; existing licences and operations retain protection under the savings provisions. Monetary penalties replace criminal punishment under this Act: INR25 lakh (approximately US$26,000) for specified contraventions, with further penalties up to INR10 lakh (approximately US$10,500) per day for continuing contraventions after the first penalty. Appeals lie to the Appellate Tribunal for Electricity. Other applicable laws remain relevant.

Statutory stability is, in our view, particularly significant for a long-term investor. It protects lease terms but without insulating the lessee from legislation of general application. The change-in-law mechanisms in the rules and contract must be considered alongside it.

The Petroleum and Natural Gas Rules 2025, notified on 9 December 2025, implement the amended statute. Initial leases run between four and 30 years, with conditional extensions linked to economic field life. Complete applications have a 180-day decision period: silence results in deemed approval for Central Government territory but deemed rejection for state territory. Onshore leases require state grant with prior Central approval, making early state engagement important. Rent increases in five-year bands; royalty is payable on production.

Three further features matter. Rule 15 provides economic-equilibrium relief for specified adverse changes in law, including provisional deductions if no solution is agreed within a year, subject to procedural requirements and government dispute rights. Rules 44–46 facilitate access to excess infrastructure capacity, with government determination of capacity and reasonable tariff where agreement fails. Rule 38 requires emissions monitoring and reduction plans and limits monthly gas flaring to 0.5 per cent of field production. Exceeding 0.5 per cent of daily production triggers notification within 24 hours and remedial action. Geological sequestration requires staged authorisation; a pilot injection permit confers no long-term storage rights.

Rule 51 also permits a neutral arbitral seat where any contractor member is a qualifying foreign company, or an Indian subsidiary whose foreign holding company owns more than 51 per cent. Otherwise, New Delhi is mandatory. The model’s seat wording should expressly reflect the subsidiary exception; the rules prevail over inconsistent contractual wording. Specified disputes, including penalties under these Rules and third-party rights, are excluded from arbitration. Entity structure and the chosen seat should be settled before bidding and recorded specifically in the contract.

What the revised contract offers

The Round X model revenue sharing contract is dated December 2025 and the Round XI model March 2026. Compared with the January 2020 Round V model, the principal improvements are as follows.

Fiscal stability

Article 11 seeks to restore a member’s economic position following specified adverse fiscal changes, and specified labour, environmental, safety or decommissioning changes where annual loss exceeds US$5m. The 2020 model lacked an equivalent stabilisation mechanism. Notice is due within 90 days; after a year without agreement, provisional deductions may be made through the prescribed mechanism, subject to government challenge. The contractual trigger is the commencement date, defined by issue or effectiveness of the first lease, rather than the bid date. Rule 15 uses the petroleum lease date. Judicial reinterpretations must be final, conclusive and binding.

A longer concessional period

For Category I blocks, the lower bid revenue-share percentage applies for five years onland and in shallow water, and seven years in deepwater and ultra-deepwater, from first qualifying Early Monetisation. This requires production at least one year before the prescribed commercial-production deadline, inclusive of extensions up to submission of the field development plan. The period does not restart for subsequent discoveries. The 2020 model provided two, three and five years respectively from first commercial production. The longer concession therefore has a different eligibility trigger.

Greater work programme flexibility

Commitments remain due within three years onland and in shallow water, and four years in deepwater and ultra-deepwater. Up to two additional years are available at US$25,000 per quarter with prompt payment. A further extension up to 180 days for drilling or testing is conditional on the specified circumstances and prior extension; the overall exploration period is unchanged. Survey substitution is permitted, but committed exploratory drilling cannot be replaced by another activity. Article 30.6 provides conditional relief for diligently pursued clearances, including capped additional time and exit without liquidated damages after qualifying delay or refusal. Article 26.8 permits exit after force majeure persists beyond two years. These are not general releases from statutory or environmental liabilities.

Expropriation and interim relief

Article 27 provides fair-market-value compensation for qualifying nationalisation or taking, including interests in undeveloped reserves, but only where a discovery has already been notified. Eligibility and valuation remain subject to the contractual process and dispute resolution. Article 28 preserves specified Indian court assistance, including interim measures under section 9 of the Arbitration and Conciliation Act 1996, notwithstanding a foreign seat.

Where the contractor still carries the risk

Four provisions require close attention. Article 24.11 permits invocation of guarantees or insurance surety bonds for contractual breach. Article 2.3(c) imposes joint and several liability, regardless of fault, for pollution and environmental damage; ordinary contractual liabilities are otherwise linked to participating interest. Article 19.2 contains a broad indemnity to the central and state governments without a specific monetary cap. Article 8.4 reserves emergency pre-emption at fair market price, payable within 30 days of delivery, with the government the sole judge of the emergency. These provisions require careful allocation of consortium risk and scrutiny of available insurance.

Royalty, cess and tax

The royalty Schedule was re-notified on 8 May 2026 and amended on 4 June, effective from 11 May, addressing legacy crude and condensate rates and the computation basis. Standard HELP rates are 12.5 per cent for onland crude and condensate, ten per cent for onland gas, and 7.5 per cent in shallow water. Deepwater and ultra-deepwater attract no royalty for seven years from commercial production, then five and two per cent respectively. Basin-specific concessions apply if commercial production begins within four years onland or in shallow water, and five years in deepwater or ultra-deepwater, from contractual commencement. HELP valuation allows a fixed 15 per cent post-wellhead deduction from sale price and uses an ex-royalty calculation.

DGH describes HELP blocks as carrying no oil cess. The separate special additional excise duty on domestic crude, commonly called the windfall tax, was withdrawn on 2 December 2024. Specified petroleum-operation imports attract no basic customs duty and 18 per cent import IGST under Notification 45/2025-Customs, subject to goods-list, importer and certification conditions. Notification 02/2026-Customs extended the relevant sunset to 31 March 2028. Specified domestic procurement also attracts 18 per cent GST; this is not a universal input or service rate. With crude and natural gas outside the operative GST levy, attributable input tax can become a substantial cost. Royalty-GST exposure requires taxpayer-specific assessment of applicable law, limitation and court orders; a dispute does not itself suspend payment. Exploration and drilling deductions depend on section 54 of the Income-tax Act 2025, effective from 1 April 2026, and the contract.

State support for deepwater drilling

The Cabinet approved Samudra Manthan, the National Offshore Exploration Scheme, on 31 July 2026, with a Phase I outlay of INR 84,084 crore (approximately US$8.9bn) until the financial year 2030-31. The announced package includes INR 28,534 crore (approximately US$3bn) for offshore data and INR 43,200 crore (approximately US$4.5bn) for 60 deepwater exploration wells, with support up to 50 per cent of eligible drilling cost or INR 675 crore (approximately US$71m) per well, whichever is lower. Cabinet approval does not itself establish a bidder’s entitlement. Project eligibility, allocation and disbursement conditions must be confirmed; economics should be modelled with and without support.

Points to settle before bidding

Three issues deserve particular attention: the timing and enforceability of fiscal relief, consortium liability, and the tax and support assumptions underlying the investment case. The following refinements would, in our view, improve the terms further. They are reform proposals, not existing entitlements, and standard-form terms should not be assumed negotiable.

1. Change-in-law protection should run from the bid due date. Provisional relief for an adverse judicial interpretation pending final appeal would also address the delay inherent in the present trigger.
2. Government challenge to a provisional deduction can create cash-flow uncertainty; any stay requires an appropriate order. Agreed escrow or expedited determination of quantum could make the remedy more predictable.
3. Revenue points and windfall thresholds are fixed dollar amounts without specific indexation. Indexation would reduce the risk that nominal revenue growth increases government sharing without a corresponding improvement in real returns.
4. The broad indemnity and joint environmental liability warrant clearer limits and allocation between consortium members, subject to mandatory law. Insurance limits, exclusions and uninsured exposures must be assessed; cover cannot be assumed to absorb every liability.
5. Security enforcement should be proportionate to a material breach and allow an appropriate cure period.
6. Clearer royalty-GST treatment and relief for unrecoverable input tax would improve fiscal predictability. While the 2018 exemption concerned the central government’s share of profit petroleum and does not specifically cover HELP revenue sharing and royalty, it is still arguable that the exemption extends to the entire government share as the 2018 exemption notification does not specify which scheme is being referred to; a clarification from the government would settle the issue.
7. Operative Samudra Manthan conditions should be available before deepwater bids close. Any subsequent opportunity to revise bids would require specific government provision.

Conclusion

The reforms materially improve India’s upstream offer. Statutory stability and clearer fiscal and dispute-resolution remedies strengthen the proposition alongside existing frontier-water royalty concessions and announced drilling support. Their practical value depends on implementation and the executed terms. Approvals, infrastructure, taxation and risk allocation remain substantive investment considerations. For international explorers with frontier capability, the present rounds merit serious evaluation, with the decision grounded in the geology and economics of each block.

Sources

Oilfields Amendment Act 2025; PNG Rules 2025, G.S.R. 888(E), particularly Rules 5, 15, 38, 44-46 and 51; DGH model contracts for OALP X (December 2025), XI (March 2026) and V (January 2020); royalty notifications S.O. 2376(E), 8 May 2026, and S.O. 2860(E), 4 June 2026; PIB releases, 31 July and 1 August 2026; DGH bid pages; Notifications 45/2025-Customs, 02/2026-Customs, 11/2025-CT(R), 5/2018-CT(R) and 29/2024-CE; CGST Act, sections 9(2) and 17; Income-tax Act 2025, section 54. DGH's current pages advertise 15 November; the linked June extension notices reviewed state 17 September.