Nigeria’s 2025 Upstream Cost-Efficiency Order: Structure, Context, Implications

President Tinubu’s new Upstream Petroleum Operations Cost Efficiency Incentives Order (2025) ties tax relief to verifiable cost savings in Nigeria’s oil sector.

Under the Order, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) will set annual cost benchmarks for different terrains (onshore, shallow-water, deep offshore).

Operators that beat these benchmarks can claim tax credits equal to half of the government’s incremental revenue gains from the efficiency improvements. In practice this means companies keep 50% of any verified cost savings as a tax benefit, while the state retains the other half.

To protect fiscal revenues, however, credits are capped at 20% of each company’s annual tax liability. Detailed implementation guidelines are expected soon, and the President has charged his Energy Adviser (Olu Verheijen) with coordinating across agencies to ensure the policy delivers real savings. As Tinubu put it, the reform “signals to the world” that Nigeria’s oil sector is becoming “efficient, competitive, and works for all Nigerians”.

Performance-based tax incentives: Companies meeting or beating NUPRC’s cost-efficiency targets receive defined tax credits, effectively sharing half of the efficiency gains with government and half with the operator

Terrain-specific benchmarks: NUPRC will publish annual operating-cost targets by asset type (onshore, shallow offshore, deepwater). Only savings below these benchmarks count for the incentive.

Credit cap (20%): To balance incentives against revenue, the maximum tax credit any firm can claim is 20% of its total tax bill.

Execution and sunset: The Order runs through 2035 (extendable by the President) and relies on inter-agency alignment. NUPRC and other agencies must monitor compliance and verify reported savings to prevent gaming.

By explicitly rewarding efficiency, the reform aims to lower Nigeria’s very high upstream costs (the subject of longstanding concern) without cutting headline tax rates. In Tinubu’s view, “every barrel must count” – so oilfield operators should have a direct financial stake in trimming waste and delays.

Global Trends in Upstream Fiscal Regimes

The Nigerian move reflects a broader shift of oil producers easing fiscal terms to attract capital. Since the 2014 price crash, many countries have competed for dwindling investment by adopting more investor-friendly regimes. However, tying tax breaks specifically to cost savings is relatively novel.

Norway: A mature producer, Norway offers stability and generous investment allowances. Its system lets firms deduct most exploration and development spending (with an effective super-deduction of ~78%), but otherwise imposes a high tax rate. In practice, Norway rewards efficiency through these built-in allowances rather than performance bonuses.

Brazil: Brazil’s offshore is mainly developed under production-sharing contracts, with heavy state take (via royalties and “special participation” taxes on large fields). Recent bidding rounds have eased signature bonuses and down-payments to spur new investment, but direct efficiency rebates are not a feature.

U.S. Shale: Onshore U.S. oil and gas operates in an open-market regime with minimal sector-specific taxes. Producers rely on competitive service markets and technology for cost-cutting, rather than fiscal incentives. There is no federal royalty; state-level fees and taxes vary but no performance-linked credits exist.

Guyana: By contrast, Guyana’s oil model is famously generous to operators. Its Exxon-led Stabroek block PSC allows companies to recover up to 75% of production as “cost oil,” then splits the remainder of barrels roughly 50/50 with the government. This fast-cost-recovery, high-profit-oil share has attracted massive investment in Guyana’s low-cost offshore fields. (By comparison, Nigeria’s new order essentially splits efficiency gains 50/50, but only up to a modest tax-credit cap.)

Overall, regulators worldwide are loosening fiscal terms in various ways – trimming royalties or signature bonuses, offering accelerated deductions, or ensuring greater profit shares to investors. Nigeria’s approach is distinct in quantifying and sharing efficiency gains. It sits somewhere between laissez-faire U.S. policy and Guyana’s very generous PSC, and resembles certain oil-services incentives (like time-based drilling bonuses) used elsewhere. Its success will depend on how Nigeria’s system is calibrated and enforced.

Cost Competitiveness: Nigeria vs. Peers

Nigeria’s cost of production has long been a problem. Industry data show Nigeria’s average upstream operating cost is on the order of $25–$48 per barrel (depending on field and location). These are among the highest in the world. For context, Gulf producers like Saudi Arabia and Iraq typically produce oil for only $3–$10/bbl thanks to large onshore fields, abundant infrastructure and low security risks.

Even among other emerging producers, $25–$48 is high – most would aim for $20–30/bbl or less. Regulators themselves have sounded the alarm. A February 2025 NUPRC report noted Nigeria’s cost is “300% higher” than in Saudi fields. In practical terms, that means for every $75 of revenue, a Nigerian producer might spend over half on lifting costs – far more than peers. The consequence has been lost competitiveness. As the Vanguard energy desk observed, Nigeria’s share of sub-Saharan investment slipped from 44% in 2014 to just 30% in 2022. The NUPRC cites high costs (alongside insecurity, bureaucracy and policy uncertainty) as key reasons global investors shun Nigerian fields.

Thus the cost-efficiency order is meant to blunt this disadvantage. By lowering net unit cost, Nigeria hopes to narrow the gap with lower-cost rivals. (However, even with the incentives, Nigeria will still face inherent challenges – many costs are structural, not easily eliminated.)

Impact on Project Economics and Returns

The new incentive effectively lets operators share half of any efficiency gain, improving project returns. In simple terms: if a field operator cuts costs so the government would have gotten an extra $10/bbl in taxes, the company instead pockets $5/bbl (subject to the 20% credit cap). This can meaningfully boost the internal rate of return (IRR) on a project, shorten payback and improve net present value. Marginal projects that were uneconomic under old fiscal terms might become feasible if they can achieve industry-standard efficiencies. Companies therefore have a clear financial motive to innovate, negotiate better service contracts or apply technology to reduce operating expenses.

However, the benefit is capped. Under Nigeria’s typical tax regime, 20% of tax liability might correspond to a relatively small revenue amount, so very large savings beyond that deliver no additional break. Put differently, the government still keeps most of the pie. The incentive is a partial reimbursement, not a wholesale subsidy. A legal analysis of the Order points out that operators will only take action “where the net benefit (tax credit plus any operational efficiency gains) exceeds both the cost of achieving those savings and the economic benefit of maintaining the existing cost structure”.

In practice this means firms must compare the extra tax break against the investment (or inconvenience) needed to cut costs. If, for example, an operator would have recovered the same costs anyway under PIA rules, it may do little. On the other hand, fields with very high unit costs (like deepwater or remote onshore) stand to gain most.

For a large offshore development, even a modest cut in diesel use or drilling time can yield millions of extra profit. The 50% split ensures the company receives a direct share of that upside. Thus for companies planning final investment decisions on existing discoveries (such as Exxon’s Usan field, NNPC/Total’s Ubeta, etc.), this order could slightly raise expected returns. It may also influence operators considering marginal tiebacks or brownfield developments.

In sum, analysts estimate the order could improve upstream project economics materially, but not dramatically. It is a targeted efficiency bonus rather than a wholesale tax cut. The cap and profit split mean Nigeria retains the lion’s share of any gains, but even a few dollars per barrel of extra netback could make a difference, especially if oil prices soften. The ultimate impact will hinge on how ruthlessly companies can squeeze costs and how generously the benchmarks are set.

Expert Commentary and Implementation Challenges

Policy and industry experts view the cost-efficiency order as an important signal but note that its impact will depend on execution. A Thomson Reuters report quotes Clementine Wallop of consulting firm Horizon Engage: aligning government agencies behind the initiative is critical. “Succeed there and this could be highly significant towards improving Nigeria’s investment appeal,” she said. In other words, unless fiscal, petroleum and tax authorities share data and streamline approvals, the incentive could be moot.

Mrs. Verheijen, the President’s Energy Adviser, emphasizes that the reform is “not about reducing costs for its own sake” but about rewarding efficiency and competitiveness. In press statements she reiterates that the Order builds on earlier 2024 reforms (better fiscal terms, faster approvals, modernized local content rules) and positions Nigeria as a “globally competitive” market. The inter-agency structure is meant to ensure oil and tax regulators publish transparent unit-cost benchmarks each year, so companies clearly know the targets.

Nonetheless, observers warn of risks. One legal commentary notes that fundamental cost drivers in Nigeria are deep and systemic – old infrastructure, dilapidated pipelines, fuel shortages, and pervasive oil theft, none of which yield easily to cutbacks. Local-content requirements and multi-layer approval processes also inflate costs. If the main inefficiencies lie outside operators’ control, then fiscal carrots may only go so far. There is also room for disputes: firms and regulators might clash over what counts as a legitimate “industry-standard” benchmark or “verifiable” saving. The NUPRC’s role in monitoring the National Production Monitoring System (NPMS) and other data tools will be crucial.

In sum, analysts see the Executive Order as a step in the right direction – one that aligns with global trends of enhancing fiscal flexibility– but caution that real results will only come if the hard work of bureaucratic coordination and on-the-ground efficiency gains occurs. If implemented faithfully, it could modestly improve the economics of Nigerian oil projects and make the country slightly more competitive. If not, it risks joining earlier well-intentioned policies (like gas utilization allowances or bidding incentives) that were never fully realized. As one expert put it, the incentive “makes every barrel count” only if the mechanics behind the scenes actually work. These include official statements on the 2025 Order, NUPRC data on production costs, and expert commentaries on implementation challenges.

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