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Understanding Nigeria’s Petroleum Industry Act
Monday, August 23, 2021

Over two decades in the making, the Petroleum Industry Act (PIA) has become law and establishes a new reality for Nigeria’s oil and gas industry. The scale of the changes implemented by the PIA is widespread and profound – it is a root and branch overhaul of the administrative, regulatory and fiscal regime, as well as the key petroleum institutions. As a result, the PIA is complex, detailed and not easily digestible – but this note summarises the key provisions that are relevant to upstream participants grappling with the new regime.

While the passing of the PIA delivers much needed stability for the industry in settling the applicable regulatory and fiscal terms, the upstream community will now assess whether it creates a framework that can support them in meeting the long-term challenges of declining investment and project development, withdrawing Majors, and the energy transition and its implications.

Five key upstream changes

  1. Fundamental reform of the administrative and regulatory regime and petroleum institutions. Creation of a new upstream regulator, the Commission, largely replacing DPR. The PIA reforms aim to follow international upstream norms, remove potential conflicts of interests, and introduce greater transparency and rule-based systems. It attempts to transition NNPC to be a commercial entity that is not dependent on Government support.

  2. Grandfathering of existing upstream licences until their conversion to the new PIA regime. Existing OPLs and OMLs continue on their present terms and only certain PIA terms apply to them (including requirements to establish and fund community trusts and decommissioning and abandonment escrow accounts but excluding the new fiscal terms). These licences convert to the new PIA terms either voluntarily or mandatorily on licence renewal, with changes to the existing terms only applying from conversion (along with significant relinquishment requirements, and the abandonment of related litigation proceedings on a voluntary conversion). This will be a key area of review and transitionary activity for existing upstream participants – assessing the benefits of early conversion against its implications.

  3. General reduction in the taxation and royalty-take of new / converted licences from the prior fiscal regime. The extent of the reduction varies dependent on the nature of the acreage and whether it is freshly granted or converted pre-PIA acreage (with onshore / shallow water joint venture acreage receiving the biggest net reduction). The new fiscal regime only applies to existing licences from conversion.

  4. Establishment of a new host community development trust structure. This entails payment of a 3% levy and the creation of community trusts to initiate local projects, as well as the transfer of existing community projects. Operators have 12 months to establish these trusts.

  5. Companies must segregate their upstream, midstream and downstream operations. Midstream (and any downstream) activities that were being carried out as part of upstream operations will require the grant of new a midstream / downstream licence within 18 months.

What are the PIA’s main provisions?

Regulatory reform:

  • Institutional changes:

    • A new Nigerian Upstream Regulatory Commission, who assumes most of the upstream regulatory functions of the DPR and becomes a key regulator. The Commission is involved in the grant of new licences and the approval of assignments of licence interests.

    • A new Nigerian Midstream and Downstream Petroleum Regulatory Authority is established for the midstream and downstream sectors.

    • A Revised and reduced Ministerial role. The Minister of Petroleum retains general supervision over petroleum operations but his existing powers to grant and revoke licences and to approve licence assignments require recommendations from the Commission.

    • NNPC overhaul. NNPC to be replaced by NNPC Limited (a new limited liability company) within 6 months from PIA enactment.  NNPC Limited is to operate on a commercial basis without government funding and must publish annual reports and audited accounts. Government owns all shares in NNPC Limited and controls the selection of its management team.

  • New types of licences / leases:

    • Petroleum Exploration Licences, Petroleum Prospecting Licences and Petroleum Mining Leases are the new forms, with the PIA specifying mandatory terms for these licences (but remaining largely the same as with the prior licence forms, including a 20 year term for PMLs, and allowing for production sharing contracts, or concessions that joint venture with NNPC Limited).

    • Model forms of the PEL, PPL and PML are to be developed by the Commission (but are not currently available).

    • Marginal fields to receive their own separate form of licence. This helps to close a longstanding lacuna about their legal status, and the potential consequences from a termination / expiry of their establishing OML.

  • New joint venture arrangements:

    • If a PEL, PPL and PML is granted on a “concession” basis, then NNPC Limited has the right to a carried interest participation of up to 60%. NNPC Limited must refund its share of development and production costs in cash or from future production.

    • The PIA specifies some model principles for establishing incorporated joint venture companies with NNPC Limited – but this structure operates on a voluntary basis and cannot be imposed on upstream participants.

    • All contracts, licences and leases with NNPC are to be non-confidential and should be made available to the Commission (and published by the Commission on its website) within 1 year. This is stated to apply to existing contracts – but is not one of the express mandatory provisions that applies to un-converted pre-PIA OPLs / OMLs and so it is unclear if they fall within this requirement.

    • All new PPLs and PMLs must be granted through a fair, transparent, competitive bidding process.

Fiscal terms:

  • Tax:

    • The existing Petroleum Profits Tax is replaced by hydrocarbon tax, along with the application of Companies Income Tax (previously exempt).

    • Hydrocarbon tax applies to crude oil, condensates and natural gas liquids produced from associated gas. It does not apply to associated and non-associated natural gas, nor frontier acreage.

    • Hydrocarbon tax rates:

      • New acreage granted post-PIA: onshore and shallow water 15% (and for all OMLs /OPLs with PSCs converted into PPLs).

      • Converted acreage (see below): onshore and shallow water 30%.

      • No rate specified for deep offshore.

      • These rates are reduced from those contained in earlier drafts of the PIB and are lower than the prior Petroleum Profit Tax rates (even with CIT now applying).

    • The Commission will set fiscal oil prices on an “export parity” basis, which is used for taxation calculation purposes.

    • There is a cost tax deductibility threshold of 65% of gross revenue (but excess can be carried forward). Head office costs are not tax deductible.

  • Production royalty:

Crude oil / condensate produced per field per month


5,000 – 10,000 bopd: 7.5%

>10,000 bopd: 15%

Shallow water

5,000 – 10,000 bopd: 7.5%;

>10,000 bopd: 12.5%

Deep offshore

>50,000 bopd: 7.5%



Gas produced per field per month

All depths

gas utilised in-country: 2.5%

all other gas or NGLs: 5%.

These rates are lower than previous PIB drafts and are, broadly, reductions from the prior regime (though may not be the case in every scenario given water depth and a new requirement to apply weighted royalties to fields located across acreage types).

  • Price royalty:

US$ 100 per barrel: 5%

>US$ 150 per barrel: 10%

  • The rate between these markers is determined by linear interpolation (e.g. an oil price of US$ 75 per barrel would mean a royalty of 2.5%).

  • These rates apply to 2020 and are to be increased by 2% each year.

  • No price royalty is payable for frontier acreages.

New community and environmental related obligations:

  • Licence holders must set up a “host community development trust” to fund social and environmental projects in the communities in which facilities related to operations are located, with the JOA operator made responsible.

  • It appears that this applies to existing OMLs that are not converted under the PIA (though is not made expressly clear in the PIA). Operators of existing OMLs must create PIA trusts within 12 months of the PIA.

  • Each licence holder must make an annual contribution to the trust of an amount equal to 3% of its operating expenditure for the relevant operations from the previous year.  This has been one of the Act’s most controversial and contested provisions (with some earlier PIB drafts proposing a 5% levy).

  • The licence holder must appoint a board of trustees (which does not necessarily include members of the host community) and a management committee (which must include one member of the host community) for each trust.

  • Failure to comply with host community obligations under the PIA is grounds for licence revocation.

  • Trust funds are exempt from taxation and payments to the trust are deductible for hydrocarbon tax and CIT purposes.

  • Existing host community projects must be transferred to the new PIA-established trusts. PIA-host community development trust obligations appear to be additional to existing community levies (such as the Niger Delta development levy).

Transition and conversion process:

  • Except for some specific mandatory terms, much of the PIA does not apply to existing OPL / OML holders and the existing OPL and OML continue and their terms (including fiscal) are preserved until “conversion”.

  • Conversion can be voluntary or becomes mandatory on licence expiry / renewal.

    • Voluntary conversion: the licence holder must enter into a conversion contract, which will terminate all outstanding arbitration and court cases related to the relevant OPL / OML, removes any stability provisions or guarantees given by NNPC, and relinquishes no less than 60% of the acreage. Voluntary conversion appears to only be available for an 18 month period.

    • Conversion on licence expiry and renewal: the licence becomes subject to the 60% relinquishment requirement.

  • For marginal fields:

    • Producing marginal fields convert to a PML within 18 months of the PIA but retain their original royalty rates.

    • OML holders of fields that are “marginal” (as assessed prior to the PIA) must, within 3 years of the PIA, present field development plans, farm out the discovery, or relinquish the field.

Separation of upstream, midstream and downstream activities:

  • Separate companies should be used for upstream, midstream and downstream operations (and no stamp duty or CGT will be charged on the segregation of current multiple-stream companies). Strategic projects that sell products domestically can be consolidated. Midstream and downstream activities require particular licences issued by the applicable Authority.

  • Transition: Current OML holders engaged in midstream / downstream activities must obtain the new necessary licence within 18 months of the PIA.

Assignment approval process:

  • Assignments of licence interests, or changes in control in a licence holder, continue to require Ministerial approval but this now requires a Commission recommendation.

  • The PIA sets a timetable for the approval process: 60 days for the Commission to review an assignment application and to not unreasonably withhold consent; 60 days from the Commission’s recommendation for the Minster to consider and not unreasonably withhold consent. This may help to address the long delays that upstream M&A has faced in obtaining Ministerial consent.

  • The PIA does not amend or revoke the DPR 2021 Guidelines and procedure for obtaining Ministerial consent, which presumably continue to apply.

Gas development:

  • Domestic supply obligations: Separate regulations will establish the extent of the domestic gas supply obligations. If the terms of the domestic gas supply contract does not establish a penalty for failure to deliver gas under a domestic supply obligation, then the PIA sets a penalty of $3.50 per mBTU for such non-delivery.

  • New regulatory framework: Expanded provisions for gas supply and transportation that build on existing regulations, including in regard to the gas transportation network operator, gas network code, gas aggregator, access to pipeline infrastructure, and gas pricing.

Decommissioning and abandonment:

  • Lease holders require prior Commission approval before they can decommission or abandon and must first provide their programme of activities and estimated costs. Field development plans must include decommissioning and abandonment plans. For existing fields in production with no abandonment plan, the lease holder must prepare and submit a plan for approval by the Commission.

  • Lease holders must establish and fund a decommissioning and abandonment fund with a financial institution by way of an escrow arrangement with the Commission. Funding obligations are to be specified in the abandonment plan (based on the reasonable estimate of the total costs (as approved by the Commission) divided by the estimated life of the relevant facilities).

  • Abandonment funding contributions are eligible for cost recovery and are tax deductible.

  • It appears that former lease holders will not be responsible for decommissioning or abandonment if the transfer to a new company involves the assumption of these obligations that is approved by the Commission.

  • The Commission can instruct lease holders to undertake decommissioning and abandonment, when required under good international industry practice.

  • These requirements apply to existing and unconverted OMLs.

What are the next steps for upstream participants?

  1. Understanding the extent of the PIA’s application. The PIA has immediate effect – but there is grandfathering and the extent of its particular application depends on the upstream interest held. For the grant of any new PPLs, PMls or renewal of existing OPLs / OMLs, then the entire PIA applies. For existing OPLs / OMLs, their terms continue unchanged and only specific parts of the PIA apply (which excludes the new fiscal terms), until such leases are converted to the PIA regime. Understanding what from the PIA is relevant now, and what will become so in the future, will be an important first step.

  2. What actions must be taken now to comply with the new PIA requirements. The PIA introduces many new actions that upstream operators must comply with (even if they hold unconverted OPLs / OMLs). Some require action now, others have a transitional period for compliance.  The two most significant requirements are the creation and funding of host community development trusts (which will entail planning and community engagement) and which must be done within 12 months; and the opening of abandonment escrow accounts and preparation of abandonment plans (but where no clear deadline is apparent).

  3. To convert or not convert? Existing OML / OPL holders should evaluate the extent of the improved PIA fiscal terms to their licence interests and whether to seek early “conversion”. This should be assessed against the consequences of conversion, including acreage relinquishment and the release of Government-related claims and proceedings. Early voluntary conversion appears to be time limited – available until 9 March 2023 (18 months from PIA effectiveness). Otherwise, conversion happens on lease renewal.

  4. Separation and segregation of activities. For upstream companies that undertake activities within the PIA’s scope of “midstream” operations, then there will need to be restructuring of assets and contracts and such midstream activities may require the grant of licences / permits from the new midstream Authority.

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