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"Licenses for projects with signed Power Purchase Agreements but construction not yet started will be cancelled and replaced with new 'Take or Pay' PPAs. Immediate PPAs will be concluded for projects below 10 MW. Dry-season power purchase rates will be set in advance by agreement."
— Budget §19, FY 2083/84
The FY 2083/84 budget's PPA reform provision is being read as good news by most hydropower developers. That reading is partially correct.
"Take or Pay" — where the offtaker must pay for a committed volume of electricity regardless of whether it is actually dispatched — is more bankable than "Take and Pay," where payment tracks actual consumption. That distinction matters enormously for project finance.
But a PPA labeled "Take or Pay" and a PPA that is actually bankable under international DFI standards are not the same document. This article explains the difference — and what Nepal's new PPA regime needs to contain for developers to close financing successfully.
Why the Distinction Between "Take or Pay" and "Take and Pay"
Has Been Nepal's Defining PPA Battle
To understand why the budget's provision matters, you need the history.
Nepal's PPA regime has oscillated between the two models in ways that have directly determined the investability of the sector:
Pre-2018: Most PPAs were "Take and Pay" — NEA paid for electricity only when it needed it. Several projects became financially unviable or unbankable because lenders could not model reliable revenue streams against uncertain dispatch.
2018: Ministry of Energy directed NEA to sign "Take or Pay" PPAs for up to 1,500 MW of run-of-river projects. The sector responded positively; several projects reached financial close on the back of these agreements.
2082/83 (2025/26): The previous government reversed course, introducing "Take and Pay" PPAs for new run-of-river projects under Clause 227 of that year's budget. The Independent Power Producers Association of Nepal (IPAN) met urgently with the Energy Minister, warning that the policy could halt hydropower development and jeopardise the 28,500 MW target by 2035.
2083/84 (2026/27): The RSP government reverses again — committing to "Take or Pay" for projects that had signed PPAs but not started construction, with existing agreements cancelled and replaced.
The oscillation itself is the risk. A developer whose project financial model depends on "Take or Pay" revenue certainty — and whose lenders have priced debt against that certainty — cannot absorb a mid-development policy reversal to "Take and Pay" without triggering covenant breaches, lender acceleration rights, and in extreme cases, project abandonment.
The budget's reinstatement of "Take or Pay" is necessary. Making it durable is what the documentation needs to accomplish.
What "Bankable" Actually Requires: The DFI Lens
Project finance is a structured financing of a specific economic entity where the lender considers cash flows as the primary source of loan reimbursement and where assets of the company represent the only collateral. Siddhartha Capital In this structure, the PPA is not simply a commercial agreement — it is the primary risk-allocation instrument that makes or breaks a lender's credit decision.
For a Nepal hydropower PPA to satisfy the credit standards of ADB, IFC, DEG, FMO, or equivalent DFIs, it must address six categories of risk that Nepal's standard PPA templates have historically handled inadequately:
1. Minimum Offtake Commitment — The Quantity Floor
What it needs to say: The PPA must define a minimum contracted energy quantity (typically expressed as Plant Load Factor or percentage of installed capacity) that the offtaker is obligated to pay for regardless of dispatch. For run-of-river projects with seasonal hydrology, this is typically set at 70–80% of dependable dry-season output.
Nepal's historical gap: NEA's standard PPA templates have used broad force majeure definitions and "grid availability" carve-outs that effectively allowed NEA to avoid Take or Pay obligations during curtailment events caused by grid limitations — which in Nepal have been frequent and systemic, not exceptional.
What the new regime must fix: Force majeure definitions must exclude grid curtailment caused by NEA's own transmission constraints. If NEA cannot offtake because its grid is full, the payment obligation must remain. The risk of grid capacity must sit with the buyer, not the seller.
2. Tariff Structure and Escalation — Revenue Predictability
What it needs to say: The PPA must specify:
- Base tariff (NPR/kWh) differentiated by wet and dry season
- Annual escalation mechanism (CPI-linked, fixed percentage, or formula-based)
- Currency of payment (NPR, USD, or a blended currency basket)
- FX conversion rate mechanism for foreign-currency denominated debt service obligations
Nepal's historical gap: Nepal PPAs have been overwhelmingly NPR-denominated with no FX protection mechanism. For projects with foreign debt — ADB loans, DFI co-financing, international commercial debt — this creates a currency mismatch that lenders must provision for through higher interest rates or reduced loan amounts, both of which worsen project economics.
What the new regime must fix: The budget's commitment to advance dry-season rate setting is a positive step — it removes the uncertainty of what price a developer will receive for its most valuable production period. The implementing PPA template must lock this rate for the full PPA term, not just the current year.
3. Payment Security — Who Backstops NEA's Obligation
What it needs to say: DFIs require certainty that PPA payments will be made even if NEA (or post-unbundling, the Distribution & Trading Company) faces financial stress. This requires explicit payment security:
- Government guarantee of offtaker obligations
- Escrow arrangement for PPA payments
- Payment undertaking from Ministry of Finance
- Or a combination of the above
Nepal's historical gap: Nepal's standard PPAs rely on NEA's implicit government ownership as the effective backstop. Post-unbundling, this implicit backstop becomes structurally ambiguous — the Distribution & Trading Company may not carry an explicit government guarantee as NEA did.
What the new regime must fix: Any "Take or Pay" PPA issued under the new regime that names the unbundled Distribution & Trading Company as offtaker must come with explicit government payment undertaking or escrow mechanism. Without it, DFIs will treat the PPA as unguaranteed corporate exposure — and price accordingly.
4. Curtailment and Dispatch Priority — Managing the
Surplus Power Problem
Nepal currently has a surplus power problem during wet season. NEA curtails production from multiple projects simultaneously during peak monsoon months. For projects under "Take or Pay" agreements, this creates a direct tension: the agreement says NEA must pay regardless, but NEA argues curtailment is operationally necessary.
What bankable documentation requires:
- Clear curtailment waterfall — which projects get curtailed first and in what sequence
- Explicit compensation mechanism for curtailment above contractual tolerance
- Dispute resolution procedure with defined timelines (not the standard "mutual agreement" language that produces years-long standoffs)
Nepal's historical gap: Curtailment compensation has been handled through informal negotiation between NEA and developers, without contractual enforceability. For a DFI lender, "we will negotiate" is not a bankable provision.
5. Change of Law Protection
What it needs to say: The PPA must contain explicit change-of-law provisions that protect the developer's revenue model against future government decisions that alter the tariff, PPA structure, or dispatch obligations.
Why this is non-negotiable after 2082/83: The "Take and Pay" reversal in the 2082/83 budget demonstrated that Nepal's PPA policy can change materially between fiscal years. DFIs that financed projects under "Take or Pay" assumptions in 2081/82 watched their credit assumptions deteriorate without contractual recourse.
A properly drafted change-of-law provision would have required the government to compensate developers for the financial impact of the policy switch — or maintain the original PPA terms.
What the new regime must include: PPA templates must contain explicit change-of-law protection with a defined compensation mechanism. This is standard in international power project PPAs and non-negotiable for any project seeking DFI financing.
6. Term and Termination — Exit Architecture for Equity
What it needs to say:
- PPA term minimum of 25 years (matching typical project license periods) or until loan repayment plus 5 years, whichever is longer
- Termination events defined exhaustively — not open-ended
- Termination compensation formula that covers outstanding debt, equity IRR to date, and reasonable future profit
Nepal's historical gap: Termination compensation in Nepal PPAs has been loosely defined, creating uncertainty about the recoverable amount in an early termination scenario. DFIs require termination compensation that covers at minimum outstanding senior debt — and most require equity protection as well.
The Dry-Season Rate Commitment: Positive but Incomplete
The budget's commitment to set dry-season power purchase rates "in advance by agreement" (§19) addresses one of the most persistent complaints of run-of-river developers: the uncertainty of what they will receive for their most bankable production.
Dry-season production (typically Magh–Baishakh, roughly January–April) carries a premium because it fills Nepal's grid deficit period. A committed advance rate for this window provides revenue certainty that can be modelled in financial projections and presented to lenders.
The gap: "Set in advance by agreement" is not the same as "locked in the PPA for the project life." If the advance rate is set annually — subject to NEA's or the government's discretion each year — it provides operational planning certainty but not financing certainty. Lenders model the full debt service period, not just the next twelve months.
The PPA implementing this provision must lock the dry-season rate escalation formula for the full PPA term, with automatic adjustment based on an agreed index. Annual renegotiation of rates is not bankable.
What Developers Should Do Before the New PPAs Arrive
The budget has announced the new PPA regime. The implementing template — which will be drafted by the Energy Ministry and NEA — has not yet been published.
In this window, three actions are highest priority:
1. Audit your existing PPA against the six bankability categories above. If your existing agreement has gaps in force majeure definitions, curtailment compensation, change-of-law protection, or termination compensation — document them. When the new "Take or Pay" template is issued, you have a basis for negotiating specific provisions rather than accepting the template as-is.
2. Engage your DFI's technical team before the template is published. DFIs will have their own positions on what constitutes a bankable PPA under the new regime. Getting ahead of their requirements — ideally influencing the template before it is finalised — is significantly more effective than negotiating exceptions after the standard template is set.
3. Get legal opinion on PPA transition obligations. The budget cancels existing PPAs for unstarted projects and replaces them with new agreements. The transition mechanism — whether existing PPAs are novated, replaced, or simply terminated — has implications for any existing lender consent obligations, shareholder agreements, and land acquisition rights that may reference the original PPA as a foundational document.
The Candid Assessment
The return to "Take or Pay" PPAs is the right decision. The hydropower sector's investability depends on it, and the government deserves credit for reversing the 2082/83 policy that threatened to halt private sector development momentum.
But "Take or Pay" as a label and "Take or Pay" as a bankable legal instrument are different things. Nepal's PPA templates have historically fallen short on force majeure carve-outs, curtailment compensation, change-of-law protection, and termination architecture — in ways that have directly increased the cost of debt for Nepal hydropower projects or prevented financial close entirely.
The test of the new PPA regime is not the budget announcement. It is the template that the Energy Ministry publishes. That document — its force majeure definitions, its curtailment provisions, its payment security architecture — is what determines whether Nepal's hydropower sector gets the financing it needs to deliver the 5,535 MW target.
Watch for the template. Engage on it early. The details are the deal.
Silicon Himalayas provides feasibility studies, SPV structuring, and project finance advisory for energy developers in Nepal.
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This article is for informational purposes only and does not constitute legal or investment advice.