Nigeria's Petroleum Industry Act 2021: fiscal terms for field economics
Royalty, hydrocarbon tax, CIT, cost price ratio, production allowance and host community trust under the PIA 2021, each tied to its section.
By Converge Engineering · Technical review: Patrick Mwafor
Under the Petroleum Industry Act 2021 (PIA), a Nigerian oil field pays royalty on volume and on price, hydrocarbon tax on crude profit (onshore and shallow water only), and companies income tax. It also contributes to a host community trust. This guide gives the screening values for each term and the section or schedule of the Act it comes from. It also says which terms Converge's economics module computes.
Section references are to the gazetted Act (Act No. 6 of 2021, Official Gazette No. 142, Vol. 108, 27 August 2021), as held on FAOLEX, the UN Food and Agriculture Organization's legal database. The Nigerian Upstream Petroleum Regulatory Commission (NUPRC), set up by s.4, collects royalty and issues the regulations.
What applies where
| Term | Onshore | Shallow water (≤ 200 m) | Deep offshore (> 200 m) | Frontier |
|---|---|---|---|---|
| Royalty by production | Yes | Yes | Yes | Yes |
| Royalty by price | Yes | Yes | Yes | No (7th Sch. para 11(2)) |
| Hydrocarbon tax | Yes | Yes | No (s.260(3)) | No, until reclassified (s.260(3)) |
| Companies income tax | Yes | Yes | Yes | Yes |
| Host community trust | Yes | Yes | Yes | Yes |
Royalty by production
Royalty by production is charged on the chargeable volume of crude oil and condensate, field by field, each month (Seventh Schedule, para 10). For royalty, condensate counts as crude oil and natural gas liquids count as gas (s.260(4)).
| Terrain | Rate | Low-volume tranches |
|---|---|---|
| Onshore | 15 % | First 5,000 bopd at 5 %, next 5,000 bopd at 7.5 %, above 10,000 bopd at 15 % (para 10(4)) |
| Shallow water, up to 200 m | 12.5 % | First 5,000 bopd at 5 %, next 5,000 bopd at 7.5 %, above 10,000 bopd at 12.5 % |
| Deep offshore, over 200 m | 7.5 % | First 50,000 bopd at 5 %, the rest at 7.5 % (para 10(3)) |
| Frontier basins | 7.5 % | None |
| Natural gas and NGLs | 5 % | 2.5 % for gas produced and used in Nigeria (para 10(6)) |
The tranches are incremental, so each slice of daily production pays its own rate. Effective crude royalty rates:
| Field rate | Onshore | Shallow water | Deep offshore |
|---|---|---|---|
| 8,000 bopd | 5.94 % | 5.94 % | 5.00 % |
| 20,000 bopd | 10.63 % | 9.38 % | 5.00 % |
| 80,000 bopd | 13.91 % | 11.72 % | 5.94 % |
Royalty by price
On top of royalty by production, onshore, shallow-water and deep-offshore crude and condensate pay a royalty by price (Seventh Schedule, para 11). The rate is 0 % below US$50/bbl, 5 % at US$100/bbl and 10 % above US$150/bbl, interpolated linearly in between. The price levels were set for 2020 and rise 2 % at the start of each calendar year. The Act's own example is US$75/bbl in 2020, which gives 2.5 %. Royalty by price is credited to the Nigerian Sovereign Investment Authority (para 11(3)).
| Year | 0 % below | 5 % at | 10 % above | Rate at US$75/bbl |
|---|---|---|---|---|
| 2020 | US$50.00 | US$100.00 | US$150.00 | 2.50 % |
| 2026 | US$56.31 | US$112.62 | US$168.92 | 1.66 % |
The 2026 levels are the 2020 levels times 1.02⁶.
Hydrocarbon tax
Hydrocarbon tax (HT) is charged on profit from crude oil, field condensate and liquid NGLs from associated gas, measured upstream of the measurement point (s.260(1)(a)). It doesn't apply to gas, to deep offshore, or to frontier acreage until it is reclassified (s.260(1)(b), s.260(3)).
| Item | Screening value | Source |
|---|---|---|
| HT rate, petroleum mining lease (PML) | 30 % of crude profit | s.267(a) |
| HT rate, petroleum prospecting licence (PPL) | 15 % of crude profit | s.267(b) |
| Associated-gas costs upstream of the measurement point | Allocated to crude oil | s.260(2) |
| Deductible | Rents, royalties, opex, decommissioning-fund contributions, levies, host community trust, NDDC and similar contributions | s.263(1) |
| Not deductible | Gas-flare fees and penalties, finance costs, head-office costs, among others | s.264 |
| Losses | Carried forward | s.265 |
Production allowance
The production allowance is deducted from HT profit per barrel (Sixth Schedule, para 1).
| Lease | Allowance | Cumulative limit for the higher rate |
|---|---|---|
| New lease, onshore | Lower of US$8.00/bbl and 20 % of fiscal oil price, then the lower of US$4.00/bbl and 20 % | 50 MMbbl |
| New lease, shallow water | Same | 100 MMbbl |
| New lease, deep offshore and frontier | Same | 500 MMbbl |
| Converted oil mining lease | Lower of US$2.50/bbl and 20 % of fiscal oil price | None |
Cost price ratio
The cost price ratio (CPR) caps the HT costs you can deduct in a year at 65 % of gross revenue at the measurement point (Sixth Schedule, para 2(1)). Rents, royalties and the s.263(1)(h) contributions sit outside the cap. Costs above the cap carry forward. Any still unrelieved when crude operations end are lost (para 2(2)(c)).
Capital allowances
Qualifying plant, pipeline, building and drilling expenditure is written down at 20 %, 20 %, 20 %, 20 % and 19 % over five years, with 1 % kept until disposal (Fifth Schedule, para 17). The first exploration well and the first two appraisal wells in a field are deducted when incurred (s.263(1)(d)).
Companies income tax and the development levy
Upstream operations also pay companies income tax (s.260(5), s.302). HT isn't deductible for it. EY reports that under the Nigeria Tax Act 2025, effective 1 January 2026, companies other than small companies pay 30 %. The same Act brings in a single 4 % development levy on assessable profit, which replaces earmarked taxes such as the Tertiary Education Tax.
Host communities development trust
Each settlor pays 3 % of its actual operating expenditure for the preceding financial year into the host communities development trust fund (s.240(2)). The settlor is the licensee or lessee, paying through the operator where there is one. The contribution is deductible for HT (s.263(1)(h)).
Funds outside field cash flow
| Fund | What the Act says | In a field model? |
|---|---|---|
| Frontier Exploration Fund (s.9(4)–(5)) | 30 % of NNPC Limited's profit oil and profit gas under production sharing, profit sharing and risk service contracts | No: paid out of NNPC's share, not by the field |
| Midstream and Downstream Gas Infrastructure Fund (s.52(7)) | 0.5 % of the wholesale price of petroleum products and natural gas sold in Nigeria, collected from wholesale customers. Also gets grants and gas-flare penalty money | Only if you model domestic gas sales at the wholesale point |
| Environmental remediation (s.103) | Financial contribution for remediation of environmental damage | Model it if your licence sets an amount. We give no screening value |
Production sharing contracts
For new acreage, a PSC has a 70 % cost limit on total oil production (Seventh Schedule, para 14(4)). Conversion contracts have 60 % (para 14(9)). The minimum government profit oil rises with cumulative field production: 5 %, 10 %, 15 %, 25 %, 35 % and 45 %, at thresholds of 50, 100, 350, 750 and 1,500 MMbbl.
What Converge models
In Economics, choose Nigeria PIA 2021 under Fiscal regime on the Fiscal tab. Then set Terrain, Licence (PML or PPL) and Lease (granted after the Act, or converted).
| Term | Converge | Default |
|---|---|---|
| Royalty by production, with tranches | Yes, from terrain and the period-average oil rate | Statutory rates above |
| Royalty by price, with the 2 %/yr escalation | Yes; none for frontier | On |
| Gas and NGL royalty | Yes | 5 %, or 2.5 % for gas used in Nigeria |
| Hydrocarbon tax | Yes, onshore and shallow water only | 30 % PML, 15 % PPL |
| Production allowance | Yes, including the split when cumulative production crosses the threshold | New lease |
| Cost price ratio | Yes, with carry-forward and a warning for costs lost at the end | 65 % |
| Fifth Schedule capital allowances | Yes, or each capex item's own method | Fifth Schedule |
| Companies income tax | Yes | 30 % |
| Development levy | Yes, on assessable profit | 4 %; set 3 % to model the Tertiary Education Tax for years before 2026 |
| NDDC levy (NDDC Act, not the PIA) | Yes, approximated as 3 % of opex plus capex | 3 % |
| Host community trust | Yes, 3 % of the previous period's opex | 3 % |
| PSC cost limit and minimum profit-oil scale | Yes: choose the PSC regime and click Apply PIA 2021 PSC minimum terms | 70 % cost limit |
| Gas flare penalty | Yes, on the Carbon tab, not deductible | Off |
| Frontier Exploration Fund, gas infrastructure levy, remediation fund | No | – |
Converge simplifies in four ways. The first three are stated in the warnings on the results:
- Royalty tranches are monthly in the Act. Converge applies them to the period-average daily rate.
- NGLs are treated as gas for royalty and kept out of the HT base.
- HT and CIT are computed on the field alone (ring-fenced). Multi-field consolidation isn't modelled.
- The fiscal oil price is your price deck net of the differential.
The PIA is excluded from Converge's benchmarks. The royalty, tax, NPV and IRR arithmetic is checked against hand calculations there, but the fiscal template isn't. See the economics guide for the full input list.