Deconstructing pricing framework for energy

Nepal’s substantial increase in hydroelectricity generation capacity in recent years has been driven overwhelmingly by run-of-river (RoR) projects. The output depends on seasonal river flow and this explains the surplus supply during the wet season and deficit during the dry season. In an effort to address this vulnerability in energy supply, the Government of Nepal has prioritized storage hydropower projects in the national budget of 2025-26. This also marks a strategic shift toward energy security and grid reliability.

Alongside this policy shift, the Electricity Regulatory Commission (ERC) hired a London-based firm Economic Consulting Associates (ECA) to undertake a study on pricing. The assignment has resulted in the "Discussion Paper on Storage Hydro PPA Pricing”. The paper provides an illustrative tariff framework to guide Power Purchase Agreements (PPAs) for storage hydropower projects and is a welcome step, as it marks the first efforts towards a structured pricing regime for energy from storage projects. This analysis is based on the exploration of the key findings, sensitivities, and practical limitations of the ERC discussion paper.

Proposed tariffs

The discussion paper provides an illustrative two-part tariff structure – one based solely on energy pricing and another, which incorporates both energy and capacity components.

The paper explicitly notes that the proposed tariffs are illustrative and not benchmarks but they are already shaping discussions on PPA pricing, and hence the importance of dissecting the underlying assumptions. The tariff structure in the ERC example is based on the following key principles:

• Storage projects are primarily built by the government, not the private sector. Hence, government has to seek international financing agencies such as the International Development Association (IDA) or some other concessional loans backed by sovereign guarantee.
• Storage projects are always assumed to be of enormous sizes.

• The pricing model is based on a single hypothetical project of 650 MW, almost the capacity of the Dudhkoshi Storage Project (670 MW), which makes it more than a coincidence – perhaps!

Evaluation of assumptions and sensitivities
Even though the model for the proposed tariffs, which is based on a project about the size of the Dudhkoshi Storage Project, provides a starting point, applying a ‘one-size-fits-all’ approach to such complex infrastructure is risky. Following is a breakdown of some of the key assumptions and their mismatch with the situation on the ground:

1. Project life
While the Electricity Act permits a 50-year operation period, in practice, most Independent Power Producers (IPPs) in Nepal have received licenses for 30 years. The consultant has assumed a full 50-year operational window without conducting tariff sensitivity analysis for a shorter project lifespan. This assumption significantly lowers the levelized cost of electricity (LCOE) but lacks realistic grounding.

2. Debt-equity ratio
In Nepal, the common debt-equity structure is 70:30. According to the ECA analysis, shifting from 82:18 ratio to one in vogue (70:30) would raise the required tariff by 12.1 percent.

3. Cost of equity
Private investors in Nepal typically demand at least 17 percent internal rate of return (IRR). The paper sets the cost of equity at 13.8 percent and ECA says, this would necessitate a 12.1 percent tariff increase to meet the practical return threshold.

4. Cost of debt
The assumed cost of debt is 3.9 percent, which is based on concessional financing through IDA or sovereign loans. However, most domestic projects rely on loans with average effective rates of around 11 percent over the project lifespan. A rise from 3.9 percent to 11 percent would require an estimated 38.6 percent increase in the tariff, as the ECA suggests a 7.6 percent increase, if the interest rate rises to 5.1 percent from 3.9 percent. (Note: The 38.6% is derived using the unitary method.)

5. Debt tenor
Nepali commercial banks typically provide a maximum of 12 years for repayment post-commissioning of hydropower projects. The ECA’s model assumes 27 years, and a reduction to 12 years would necessitate an 18 percent tariff increase. ECA itself notes that an 8.4 percent increase would be required in the tariff rate, if the tenor is reduced to 20 years from 27 years. (All percentages have been derived using the unitary method)

6. O&M cost assumption
The ECA paper considers a 0.4 percent O&M cost with three percent annual escalation. This appears low, particularly given the added insurance and operation complexities of storage projects. According to the discussion paper, increasing O&M cost by 30 percent leads to only 2.3 percent increase in the tariff.

7. Other assumptions
Other assumptions - such as two percent for employee bonuses and 20 percent as the corporate tax rate - have been reflected accurately. Also assumed are a 100 percent tax holiday for the first 15 years and 50 percent reduction for the next six years. Additionally, the energy royalty is set at two percent of energy sales and capacity royalty at NPR 100 per kW per year for the first 15 years. For the remaining project period, the energy royalty increases to 10 percent of sales and capacity royalty rises to NPR 1,000 per kW per year. The consultant has provided tariff sensitivities in case the parameters change, but since they are unlikely to be revised in the foreseeable future, no tariff adjustment has been made in this area.

Recalibrating the tariffs
If we apply the real ratios that apply to IPPs in Nepal – such as 70:30 debt-equity, 17 percent return on equity, 11 percent interest rates, and 12-year debt repayment – the required tariff, based on the approach suggested by the ECA would be:

*Loan has been repaid so it is arguable.

The tariffs (Table 2a and 2b) are not in line with rates currently offered to RoR projects. For instance, if the cost and electricity generation from storage-type projects are to be compared and brought to parity with RoR projects, then the PPA rate for the 670 MW Dudhkoshi Storage Project should be NPR 10.67 per unit during the wet season and NPR 18.67 per unit during the dry season, Similarly, the PPA for the 1,200 MW Budhi Gandaki Storage Project would have to be NPR 12.64 and NPR 22.12 per kWh for wet and dry seasons, respectively. Both projects should also be provided with the annual escalation of three percent for up to eight years as is the case for other hydropower projects.

Structural and conceptual oversights

1. Storage potential is not uniform
Not all storage projects operate in the same way. For example, Budhi Gandaki (1,200 MW) will produce 3,383 GWh energy annually, while Dudhkoshi (670 MW) can produce 3,442 GWh. Despite lower energy output, Budhi Gandaki can supply 1,200 MW peak power during the dry season – a crucial grid-balancing function that is undervalued in the current model. In the case of Dudhkoshi, the supply will be only 670 MW.

2. Misaligned capacity tariff structure
The proposed monthly capacity charge discriminates against projects that operate primarily in the dry season. Projects capable of peak saving and daily energy storage for six months are penalized, as they will receive only six months of capacity payments instead of being rewarded for their grid value.

The ECA assumes that storage projects are meant to generate both dry and wet energy, which is not practical. As per the design guidelines approved by the Department of Electricity Development (DoED), the minimum criteria for a storage project includes a reservoir capacity to hold a minimum 15 days of design discharge, and 35 percent of total energy as minimum dry energy. There is no maximum limit. However, the consultant is silent about projects that can store water for six months and produce dry energy with maximum peak power when the demand is highest. In fact, the proposed tariff model penalizes superior projects under the energy and capacity model. Since the capacity tariff is expressed in per kW per month, projects operating for only six months can only claim six months of capacity tariff, not for all 12 months. The tariff structure, therefore, could discourage instead of incentivizing storage excellence.

3. One-project approach
The proposed model is based on a single, hypothetical, 650 MW project. It fails to capture the diversity of storage projects. Therefore, applying this narrow analysis to all future projects may lead to inappropriate tariff benchmarks and project failures, similar to what is anticipated in the Tanahun hydropower project.

Role of the private sector
Private sector input is among the most significant omissions in the discussion paper. Nepal’s private sector can bring to the table ground-level understanding of cost dynamics, financing risks, and implementation hurdles. Therefore, a tariff model that excludes private sector voice risks its relevance or, worse, makes a failed policy.

The ECA prepared the paper in consultation with the USAID-supported Urja Nepal Program and the Asian Development Bank (ADB). But it completely ignored the private sector that has hands-on experience in building hydropower projects and the capacity to analyze financial models from a business perspective. This sidelining of the private sector is indicative of another misplaced assumption that the private sector is not yet ready to build storage projects, which needs a re-examination.

Conclusion
The discussion paper prepared by the ECA is a commendable step towards formalizing a tariff framework for storage hydropower projects. However, the assumptions and modeling choices adopted render it insufficient for setting practical PPAs. In order to prepare for Nepal’s transition from RoR to more complex storage infrastructure, the pricing must reflect not only the economic cost but also the strategic value of firm, dispatchable power.

Therefore, the figures proposed by the ECA of NPR 5.69 and NPR 9.95 per kWh should not be viewed as benchmarks but as outcomes tied to very specific and often impractical assumptions. A more nuanced and adaptive approach – one that includes a variety of project types, financial realities, and stakeholder inputs – is essential for building a resilient energy future for Nepal. To ensure this, policymakers should guard against being misled by the proposed rates, because the ECA proposals would actually translate into NPR 10.29 and NPR 17.99 per kWh for wet and dry seasons, respectively, when financing structures, common in Nepal, are taken into account.

At these rates, forget about achieving acceptable Internal Rate of Return (IRR) and the economic IRR, the projects will struggle to even generate enough cash flow to meet debt obligations from the eighth year of operation. This will result from the 3.2 percent per annum USD:NPR appreciation rate suggested by the ECA, which can significantly distort the financials over time. Under this assumption, the exchange rate of NPR 133.5 per USD will escalate to approximately NPR 470 per USD over the debt repayment period. When this happens, what initially appears to be a soft loan with a low interest rate can end up costing much more. The total repayment (principal + interest) for USD-denominated loan of NPR 241 billion will reach NPR 755.90 billion. In contrast, if the same NPR 241 billion were borrowed domestically – with a 12-year repayment period after the commercial operation at 11% interest rate per annum – the total repayment would be about NPR 437 billion, and the capital would remain within the country. This also suggests need for caution when considering concessional foreign loans as they may initially look attractive but can ultimately cost more due to currency depreciation.

(Mr. Thapa is the CEO of Aadhyanta Fund Management Limited. He has over 15 years of experience in the power sector.)