Read time: ~7 min
Standfirst: Two power plants can sell into the same market under contracts that look similar on the surface, a fixed capacity, a negotiated tariff, and still carry entirely different revenue risk, depending on one clause: whether the offtaker pays for capacity made available, or only for energy actually delivered and consumed. In Nigeria’s electricity sector, this distinction has driven a decade of disputes, and a 2024 regulatory order that is actively rewriting which structure gets used going forward.
I. The two structures, defined by what triggers payment
Under any power purchase agreement, the generator undertakes to make a specified volume of power available to the purchaser. What differs is what the purchaser is obligated to pay for.
Take-or-Pay obligates the offtaker to pay for a pre-agreed quantity of capacity or energy regardless of whether it actually takes delivery. If the offtaker does not consume the contracted volume, it still pays as though it had. This shifts demand risk almost entirely onto the offtaker, and gives the generator (and its lenders) revenue certainty independent of actual grid dispatch or consumption.
Take-and-Pay, sometimes framed as availability-based when tied to plant readiness rather than volume, ties payment to actual offtake or actual availability delivered. If the plant is not dispatched, or the offtaker does not draw the contracted volume, payment is reduced or withheld accordingly. This keeps demand and dispatch risk with the generator, and by extension with its lenders, unless a separate availability mechanism compensates the generator for being ready to deliver even when not called upon.
II. Why Nigeria has run both, and why it has mattered
For most of the post-privatization era, Nigeria’s wholesale power market ran predominantly on take-and-pay arrangements between generation companies (GenCos) and the Nigerian Bulk Electricity Trading company (NBET), with most GenCos operating without full payment guarantees at all. Only a small minority of generators, 8 of 28 at one recent count, held fully effective PPAs with payment guarantees behind them. The result was chronic underpayment: generators built and fueled capacity that the system frequently failed to dispatch or pay for in full, while NBET itself lacked stable government capitalization to backstop the gap.
Azura-Edo was structured differently from the start, specifically as a take-or-pay contract, with its baseload dispatch obligation set at its lowest take-or-pay capacity. That structural difference, a binding payment obligation regardless of dispatch, is precisely what let Azura reach financial close as Nigeria’s first true project-financed IPP, when GenCos operating on take-and-pay terms without guarantees could not attract comparable financing. Lenders will not size debt against a revenue stream that depends on the offtaker’s operational choices unless something, take-or-pay, an availability payment, or a guarantee, removes that discretion from the equation.
This is not a historical footnote. Nigeria’s electricity regulator issued an order in 2024 to transition the market toward bilateral trading, and as part of that shift, moved bulk energy trading contracts from take-and-pay toward take-or-pay terms specifically to increase market certainty and discipline, while also directing generators with take-and-pay contracts to renegotiate directly with distribution companies (DisCos) within 60 days. In other words, Nigeria’s own regulator has concluded that take-and-pay, at the volumes and payment discipline the market has shown historically, is not a bankable enough structure to build the sector on, and is actively pushing the market toward the take-or-pay model Azura pioneered nearly a decade earlier.
III. Availability-based tariffs as the renewable-sector variant
Utility-scale solar PPAs in Nigeria have generally used a different variant again: feed-in tariffs paired with availability-based payment mechanics, under which payment is tied to whether the plant was available to generate, measured against a projected net energy output, rather than to a fixed take-or-pay volume. NBET’s own standard-form solar PPA includes explicit provisions for calculating “Availability Event Energy Payments,” compensating the generator when the plant was ready to perform but was not called upon or was constrained by grid or offtaker limitations, distinct from ordinary curtailment the generator itself caused.
This distinction matters for how a project’s risk should actually be read. Take-or-pay shifts volume risk to the offtaker outright. Availability-based structures instead ask a narrower question, was the asset ready, and shift only readiness risk to the generator, while still exposing the generator to genuine grid or system-level dispatch decisions outside its control, unless the availability mechanism is drafted broadly enough to cover those events too.
IV. What to check when evaluating a Nigerian power or gas tariff structure
- Is payment triggered by contracted volume, actual offtake, or measured availability? These are three different risk allocations wearing similar contractual language, and only a careful read of the tariff and payment clauses reveals which one governs.
- Does the offtaker have a track record of honoring the payment structure as written? A take-or-pay contract with an offtaker that has historically underpaid GenCos regardless of contract terms carries counterparty risk no tariff structure alone can fix.
- Is the structure aligned with where regulatory policy is heading? With NERC actively pushing the market toward take-or-pay and bilateral GenCo-DisCo contracting, a legacy take-and-pay position may face renegotiation pressure, or a forced transition, independent of anything the generator itself does.
Read this before you read this one: Sponsor Equity vs. Mezzanine Tranches: Capital Stack Design for EPC-Led Consortia