PPA Pricing

Summary

Public evidence for Power Purchase Agreement pricing in Nepal comes from several sources with different authority: standard NEA tariff schedules, signed-project disclosures, issuer and ratings records, ERC discussion papers, and the 2082 reservoir directive. RoR and PRoR records commonly use energy tariffs differentiated by wet and dry season. Reservoir procurement now has a dedicated regulatory framework, but project-level implementation must be established from ERC decisions and signed agreements rather than inferred from the directive alone.

Simple Explanation

When a private company builds a hydropower plant in Nepal, its PPA states what the buyer will pay and under what delivery conditions. Many published RoR and PRoR records use a rate per kilowatt-hour, with different wet- and dry-season prices. Reservoir projects raise additional questions about fixed costs, available capacity, construction risk, financing, and long-term service; the ERC's 2025 discussion paper and 2082 directive address that distinct contract problem.

Common Misunderstandings

• "PPA rates are market prices." They are regulated, negotiated tariffs — not set by competitive auction or spot market dynamics.
• "All projects get the same rate." NEA subsidiaries (like Chilime) use different billing architectures that produce structurally higher blended rates than private IPPs.
• "Lower PPA rates are always better for consumers." Rates below cost of capital deter investment, lengthen project timelines, and can increase system risk.
• "One PPA rule explains why the fleet is RoR-heavy." Current sources do not quantify that causal claim. Contract form is one factor among capital, approvals, project scale, risk allocation, land, safeguards, transmission, and state delivery capacity.

How Power Purchase Agreement rates are set for hydropower projects in Nepal — and whether rate-setting follows an economic formula or a discretionary process. The central institutional framework is NEA Triple-Authority Conflict: the same entity that sets PPA rates (NEA as single buyer) is also the penalty enforcer and dispatcher.

Source Status

PPA Rate Comparison Table

The table below compiles project terms disclosed in primary corporate or ratings records. It is not a complete register of signed PPAs, and no row should be generalized to a technology-wide current rate without checking its contract date, escalation, season definition, delivery obligation, and current applicability.

| Upper Chameliya (Api Power) | 40.0 | 4.00–4.80 | 7.00–8.40 | — | private_IPP | ~2020 | 3% annual | CARE/ICRA Nepal rating rationales | PARTIALLY VERIFIED |

NOTE 1 — Trishuli 3A and Chameliya classification: Upper Trishuli 3A (60 MW) and Chameliya Hydropower (30 MW) are directly NEA-owned generation assets, not independent corporate entities. They use internal transfer pricing based on cost of generation rather than commercial PPAs. Trishuli 3A is frequently confused with Trishuli Jal Vidhyut Company Limited (37 MW, the 3B cascade), which IS a subsidiary entity with a standard commercial PPA at NPR 4.80/8.40. Similarly, Chameliya (NEA-owned, 30 MW, Darchula) is frequently confused with Upper Chameliya (Api Power, 40 MW, private IPP), which DOES have a commercial PPA. Prior research cycles carried an erroneous NPR 8.85/5.40 rate for Chameliya — this figure is a data hallucination derived from misattributed retail consumer tariffs in the NEA Annual Report FY2016/17. Chameliya has no commercial PPA. Source: NEA Generation Directorate Report 2080/2081 (16th Issue, 2024). See Chameliya Hydropower.

NOTE 2 — Sanima Mai promotional tariff expiry: The Mai HPP (22 MW) initially operated under a government promotional tariff of NPR 4.80 wet / 8.40 dry. This expired mid-April 2022 after 7 years from COD. The current active rate of NPR 5.08/8.89 reflects accumulated escalations post-expiry. The promotional tariff mechanism — and its expiry — is itself a structural feature of Nepal's PPA framework, not an anomaly.

NOTE 3 — Sahas Urja reframing: Sahas Urja operates on the identical base rate as Nyadi and Rasuwagadhi (NPR 4.80/8.40). Its superior financial performance (NPR 902M net profit on NPR 2.648B revenue, FY2023/24) is entirely attributable to cost efficiency (NPR 172–175M/MW build cost vs industry average NPR 200–300M/MW) and scale (86 MW generating large absolute dry-season cash flows despite a ~19% dry energy mix). Sahas Urja does not demonstrate that the standard IPP PPA rate is viable — it demonstrates that the rate is only viable at exceptional scale and cost discipline unavailable to most developers. See Sahas Urja — Solu Khola (Dudh Koshi) Hydroelectric Project.

NOTE 4 — Upper Chameliya seasonal modality: Unlike the standard 8-month wet / 4-month dry split, Api Power's Upper Chameliya PPA uses a 6-month wet / 6-month dry modality, with the dry-season rate mathematically double the wet-season rate. This significantly bolsters the blended tariff average and enhances cash flow for commercial debt service. Source: CARE Ratings Nepal. [PARTIALLY VERIFIED: exact base rate is a range rather than single confirmed figure — CARE/ICRA rationales give wet ~NPR 4.00–4.80, dry ~NPR 7.00–8.40.]

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NEA Internal Generation Cost vs Commercial PPA Rates

Directly NEA-owned generation assets do not operate under commercial PPAs. They use internal transfer pricing based on operational cost, royalty, and allocated depreciation — accounting figures that bear no relation to the full capital cost of the asset. These internal generation costs are structurally incomparable to commercial PPA rates and should not appear in rate comparison tables alongside IPP or subsidiary PPAs.

The table below shows FY2080/81 internal generation costs for five major NEA-owned assets:

Source: NEA Generation Directorate Report 2080/2081 (16th Issue, 2024).

Why these figures cannot be compared to commercial PPA rates: NEA internal generation costs reflect post-subsidy accounting where sovereign capital failures are absorbed off-balance sheet. The state utility tolerates catastrophic inefficiency in its own construction — Chameliya cost $7.5M/MW vs the global benchmark of $1.5–2.5M/MW — without letting those financial failures reflect in the energy pricing metric. Simultaneously, the NEA enforces rigid PPA caps on private developers who must fully amortize commercial debt at double-digit interest rates. A private IPP that suffered Chameliya's $226M cost overrun on a 30 MW asset would be insolvent at any standard PPA rate. The NEA's own asset registers that same energy at NPR 3.04/kWh. This asymmetry is the quantitative core of the NEA Triple-Authority Conflict governance problem. See Chameliya Hydropower.

The tariff regime's evolution is best understood through two bookend cases. Khimti-I (60 MW, 1996 PPA) — Nepal's first large private IPP — negotiated a USD-denominated tariff (US$0.052–0.059/kWh) with US CPI escalation and no seasonal split, before the NPR 4.80/8.40 standard existed. It generated 103% of contracted energy over 25 years. Upper Tamakoshi (456 MW, ~2012 PPA) — Nepal's largest plant — was built at NPR 87–89.4 billion with an effective 88:12 debt-to-equity ratio at commissioning (capitalized interest from an 11-year construction period). At NPR 3.63/6.96/kWh, even 90% of contracted generation cannot cover interest expense. Khimti's PPA was arguably too generous; Upper Tamakoshi's is demonstrably unserviceable. The gap between them is the arc of Nepal's PPA evolution: from attracting first-mover capital at premium terms to imposing rates that cannot sustain the projects they license.

Rate-Setting Mechanism and Regulatory History

The 2025 ERC/ECA discussion paper records NEA's April 2017 standard tariffs for RoR, PRoR, and reservoir projects in NPR per kilowatt-hour. It says ERC understood the reservoir schedule to have been intended for Kulekhani I and subsequently withdrawn. The paper then examines a reservoir-specific approach that could distinguish fixed or available-capacity recovery from generated-energy recovery while addressing construction, financing, foreign-exchange, and volume risks.

The Reservoir-Based Generating Station Electricity Purchase and Sale Directive 2082 is the current official framework. The original Nepali text was approved by ERC's 299th meeting on 2082/10/20 BS and published on ERC's site. For this page, issuance establishes regulatory status only. The earlier claims that it imposed a simple size split and two universal tariff caps are removed pending a project-level legal and implementation review of the official text.

The directive's practical effect remains a record-by-record question. ERC applications, tariff decisions, signed PPAs, financing close, construction milestones, and operating obligations are needed before the framework can be described as having delivered reservoir capacity or dependable service.

Royalty and Taxation Schedule

Royalties: Electricity Act, 2049 (1992), Section 11 — NPR 100/kW capacity royalty + 2% of average tariff as energy royalty for first 15 years; NPR 1,000/kW capacity royalty + 10% of tariff from year 16 onward. Corporate income tax: 20% rate with 100% rebate for first 10 years of operation and 50% rebate in years 11–15 (Income Tax Act provisions). Free-power provisions (typically 10–22% of generation to the government) are negotiated project-by-project in concession PPAs rather than codified in statute. At end of license (30–35 years), the plant transfers to the state.

NEA Subsidiary vs Private IPP Differential Analysis

The PPA rate comparison table reveals a structural divergence in how NEA treats its own subsidiaries versus private IPPs. This differential is not executed through a published discriminatory rate card — the Electricity Act theoretically mandates uniform treatment — but through bespoke contract structuring that allows subsidiaries to bypass seasonal pricing constraints.

The mathematical proof

Take the two clearest comparable cases:

NEA subsidiary — Chilime Hydropower (22.1 MW): Chilime's 1997 PPA discards the wet/dry seasonal constraint entirely. Instead, it uses a "Regular" and "Excess" quota system. In FY2078/79, Chilime generated 156.06 GWh — and 85.4% of it (133.24 GWh) was billed at the premium NPR 8.17/kWh Regular rate year-round, regardless of season. Only 22.82 GWh was classified as Excess at NPR 4.08/kWh. Total revenue: NPR 1.18 billion. Blended rate: NPR 7.57/kWh.

Private IPP baseline (Nyadi/Sahas Urja model): A standard private RoR IPP is locked into NPR 4.80/kWh (wet) and NPR 8.40/kWh (dry). Assuming an optimized 20% dry energy yield — generous for most Nepalese rivers — the blended rate is: (0.20 × 8.40) + (0.80 × 4.80) = NPR 5.52/kWh.

The differential: NPR 2.05/kWh = 37.1% revenue advantage per unit for the NEA subsidiary.

For a 50 MW comparable private IPP generating 200 GWh/year, this represents approximately NPR 410 million in foregone annual revenue relative to an identically-sized project that received the Chilime billing architecture.

The billing architecture is the mechanism, not the rate

Chilime's per-unit rates (8.17/4.08) are not dramatically higher than the private IPP cap (8.40/4.80). The advantage comes from classification escape: Chilime's PPA categorizes output by "Regular" vs "Excess" rather than by season, allowing the vast majority of its generation to bill at the premium rate continuously. A private IPP cannot reclassify its monsoon output this way — the season determines the rate.

Independent academic verification

The Fenner School of Environment and Society (Australian National University), Nepal State of Knowledge Report — Renewables and PSH, independently documents this dynamic:

"The major complaint of the rising IPPs is that the playing field is not level, that NEA as generator, transmitter and distributor gives preferential terms to its own projects compared to IPPs; and indeed, this is seen in the case of the Chilime hydropower company that is owned by the NEA and its staff."

Citation: Fenner School of Environment and Society, ANU, Nepal State of Knowledge Report — Renewables and PSH, p. 20. URL: https://fennerschool.anu.edu.au/files/Nepal%20State%20of%20Knowledge%20Report%20-%20Renewables%20%26%20PSH.pdf.

Legacy contract grandfathering

Chilime's 1997 PPA remains fully active and has not been downgraded to match contemporary IPP standards. The ERC now vests with rate-setting authority and the 2026 Directive on reservoir-based PPAs transitions large projects to cost-plus determination, but legacy contracts like Chilime's are grandfathered — perpetually skewing the market's competitive balance. See Chilime for the full PPA billing architecture and NEA Triple-Authority Conflict for the institutional framework.

Analytical links

• NEA Triple-Authority Conflict — the institutional conflict that pervades PPA rate-setting, dispatch, and enforcement
• Chilime — the primary documented case of subsidiary PPA rate advantage
• Sahas Urja — Solu Khola (Dudh Koshi) Hydroelectric Project — why the standard IPP rate only works at exceptional scale
• Q-Design Discharge — how design discharge determines contracted energy (the denominator of all PPA economics)
• Availability-Declaration Penalties — the penalty mechanism that compounds the PPA rate disadvantage