Gas Supply Agreements for Power Projects: Clauses That Determine Whether Your Plant Runs or Sits Idle
A Practical Guide for Buyers in Nigeria’s Energy Sector
Nigeria’s gas-fired power plants, industrial facilities, and gas-dependent manufacturing operations share a common vulnerability: the Gas Supply Agreement (GSA). This single contract frequently determines whether a facility operates at capacity, runs at a loss absorbing gas it cannot use, or sits idle waiting for supply that never arrives. Across power generation, fertiliser production, industrial gas processing, and liquefied natural gas (LNG) operations, the pattern is consistent: operators who treat the GSA as a procurement formality discover its commercial weight only when something goes wrong.
A GSA is not merely a supply contract. It is the operational and financial constitution of any gas-dependent project. The clauses within it allocate risk, define obligations, and in many cases predetermine the outcome of disputes before they arise. This article examines the provisions that executives, project sponsors, and investors must understand and actively negotiate, because the consequences of these clauses are felt at the operational level long before any disagreement reaches an arbitral tribunal.
Take-or-Pay and Take-and-Pay: The Cost of Gas You Cannot Use
The distinction between take-or-pay and take-and-pay obligations is important. Under a take-or-pay arrangement, the buyer is obligated to pay for a minimum quantity of gas whether or not it is actually taken. Under a take-and-pay arrangement, payment is only triggered upon actual delivery and lifting. For gas buyers across all sectors, the commercial risk of a take-or-pay structure is the same: payment liability for gas that the buyer has no operational use for.
A power generation company (GenCo) operating under a Power Purchase Agreement with Nigerian Bulk Electricity Trading Plc (NBET) faces this when its off-taker reduces dispatch instructions, it must pay for gas it cannot convert into dispatchable electricity. An industrial facility faces it during scheduled maintenance shutdowns or production slowdowns. A fertiliser plant faces it when urea prices fall and it elects to reduce output. In each case, the take-or-pay floor continues to run. The negotiating objective is the same across sectors: link the minimum take obligation to actual operational requirements. Where that linkage is absent, the buyer is assuming stranded gas risk, a risk that is rarely priced into project models at financial close.
Daily Contract Quantity and Nomination Procedures
The Daily Contract Quantity (DCQ) defines the volume of gas the supplier is obligated to deliver each day. Nomination procedures govern how the buyer requests gas for each operating period. These provisions are technically detailed but commercially decisive, and their implications differ across project types.
A power plant that trips unexpectedly needs to reduce its gas nomination quickly. An industrial facility running a batch process may need to increase nominations on short notice. A nomination window that closes 24 hours before delivery, without a renomination right, locks the buyer into a volume commitment that no longer reflects operational reality and triggers shortfall payments. Similarly, a DCQ set at theoretical design-capacity levels, rather than actual achievable throughput, creates persistent payment exposure whenever the facility operates below nameplate. We recommend that to resolve this, executives across all gas-dependent sectors may insist on renomination windows with meaningful lead times and DCQ levels calibrated to realistic operational outputs.
Delivery Point, Pressure, and Quality Specifications
Where gas is delivered, at what pressure, and in what condition are cost allocation decisions, not merely technical ones. Under the Petroleum Industry Act 2021 (PIA), midstream gas infrastructure ownership and transportation obligations have been restructured, with the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA) now exercising oversight over gas transportation and processing operations. A GSA that places the delivery point upstream of the buyer’s facility, at pressures below the minimum inlet specification, transfers compression and transportation costs to the buyer, costs that are rarely modelled in project financial projections.
Force Majeure: The Clause That Swallows the Contract
Force majeure clauses, in some cases, carry disproportionate risk for buyers. Suppliers have historically invoked force majeure to excuse under-delivery arising from pipeline vandalism, third-party infrastructure failures, community disruptions, and regulatory interventions events that, in a more developed gas market, a supplier with a managed supply portfolio would have been expected to mitigate. For a power plant, an industrial facility, or a gas-dependent manufacturer, the consequence of a force majeure invocation is identical: no gas, no production, no revenue, but continuing fixed costs and depending on the off-take structure, potential liability to the buyer’s own off-takers.
The practical solution is to narrow the force majeure definition deliberately and include supply restoration obligations. Pipeline vandalism on a specific route should not qualify as force majeure if alternative supply routes exist or can reasonably be arranged. Regulatory delays should not excuse supply failures where the supplier bears responsibility for obtaining and maintaining the relevant approvals. We recommend a defined cure period after which a force majeure event that has not been resolved triggers the buyer’s right to source alternative gas supply and recover the cost differential from the supplier.
Liability Caps and Consequential Loss Exclusions
Almost every GSA presented to a gas buyer will contain a clause excluding the supplier’s liability for consequential or indirect losses, and capping direct liability at some multiple of the annual contract value. For gas-dependent projects across all sectors, this creates the same structural problem: the losses that flow most directly from a supply failure, lost production revenues, liquidated damages payable to off-takers, capacity charge clawbacks, demurrage costs, product spoilage are precisely the losses that consequential loss exclusions are designed to eliminate.
The stronger negotiating argument available to buyers across sectors is that production and revenue losses flowing directly and inevitably from a failure to deliver gas to a facility whose purpose is to consume that gas are direct losses, not consequential ones. At a minimum, we recommend that the liability cap is set at a commercially meaningful level relative to the losses that would actually flow from sustained under-delivery, and that the cap resets annually rather than accumulating as a ceiling across the entire contract term.
Contract Duration and Renewal: Matching Supply to Project Life
A gas-dependent project, whether a power plant, a petrochemical facility, or an industrial plant typically carries project finance debt with a tenor of 10 to 15 years. A GSA that expires after five years, or that contains rolling annual renewal options exercisable at the supplier’s discretion, creates a tenor mismatch that project finance lenders will identify as a security risk and, in most cases, will require to be resolved before financial close. Even for projects without external debt, a short-duration GSA that expires mid-project life forces the buyer into a renegotiation from a position of operational dependency, the worst possible negotiating position.
Where long-term supply commitment is unavailable, the GSA should contain a right of first refusal on renewal, a price re-opener mechanism that uses an objective benchmark, such as the gas pricing framework under the PIA and applicable NMDPRA pricing guidelines rather than leaving quantum to supplier discretion, and an obligation on both parties to negotiate renewal terms in good faith within a defined period before expiry. The consequences of failing to agree should also be specified: a deemed extension at the existing terms, or an independent determination mechanism, is preferable to a contractual vacuum in which the supplier holds all the leverage.
The Practical Takeaway
Gas Supply Agreements in Nigeria are negotiated in a market where suppliers hold structural leverage, infrastructure constraints are real and persistent. Across power generation, industrial processing, and gas-dependent manufacturing, the clauses examined in this article are not abstract legal concerns. Each one has a direct line to operational performance, revenue certainty, and the bankability of the project as a whole.
The executive who understands what a take-or-pay obligation costs during a production slowdown, what a broadly drafted force majeure clause excuses a supplier from delivering, and what a consequential loss exclusion eliminates from the buyer’s recovery, is better placed to make sound commercial decisions at the negotiating table and to recognise when the terms on offer make the project commercially unviable before the first cubic metre of gas has been consumed.
