Introduction: Nepal’s Growing Need for Energy Security
In recent years, Nepal has experienced a substantial increase in electricity generation capacity, mainly driven by run-of-river (RoR) hydropower projects. However, the country’s energy landscape is still heavily dependent on seasonal river flow, leading to surpluses in the wet season and deficits during the dry season. Recognizing this vulnerability, the Government of Nepal has prioritized storage hydropower projects in the national budget, marking a strategic shift toward energy security and grid reliability.
In parallel with this policy shift, the Electricity Regulatory Commission (ERC) of Nepal commissioned a study titled "Discussion Paper on Storage Hydro PPA Pricing," prepared by Economic Consulting Associates (ECA), a London-based consulting firm. This discussion paper presents an illustrative tariff framework intended to guide future Power Purchase Agreements (PPAs) for storage hydropower projects in Nepal.
The document is a welcome step toward a structured pricing regime for storage projects. This blog provides a critical yet constructive analysis of the discussion paper, exploring its key findings, sensitivities, and practical limitations.
The Proposed Tariff Structure: At a Glance
The discussion paper provides two illustrative two-part tariff structures—one based solely on energy pricing and another incorporating both energy and capacity components.
Energy Tariff Only (NPR per kWh):
Period | Wet Season | Dry Season |
Years 1–15 | NPR 5.69 | NPR 9.95 |
Years 16–50 | NPR 4.83 | NPR 8.46 |
Energy + Capacity Tariff:
Period | Wet Season | Dry Season | Capacity Tariff (NPR/kW/month) |
Years 1–15 | NPR 1.14 | NPR 1.99 | NPR 2,141 |
Years 16–50 | NPR 0.97 | NPR 1.69 | NPR 1,464 |
The paper explicitly notes that these are illustrative figures, not benchmarks. However, these rates are already shaping discussions around PPA pricing, making it crucial to dissect the assumptions underlying them. But few things are clear from the paper. The tariff structure is based on the following key principles:
a) Storage projects are primarily constructed by the government, not the private sector. Hence, government has to seek international financing agencies such as IDA or other concessional loan backed by sovereign guarantee.
b) Storage projects are always assumed to be enormous in size.
c) The model is based on a single hypothetical project. The entire analysis is carried out on a hypothetical 650 MW project-frequently referencing the Dudhkoshi Storage Project (670 MW)
Critical Evaluation of Assumptions and Sensitivities
The proposed tariffs are based on a model project similar to the Dudhkoshi Storage Project (670 MW). While this offers a starting point, applying a one-size-fits-all approach to such complex infrastructure is risky.
Here is a breakdown of some key assumptions and how they deviate from practical realities in Nepal:
1. Project Life: 50 Years
While the Electricity Act permits a 50-year operation period, in practice, most Independent Power Producers (IPPs) receive licenses for 30 years. The consultant assumes a full 50-year operational window without conducting tariff sensitivity for a shorter lifespan. This assumption significantly lowers the levelized cost of electricity (LCOE) but lacks a realistic grounding.
2. Debt-Equity Ratio: 82:18
In Nepal, the common debt-equity structure is 70:30. According to ECA, shifting from 82:18 to 70:30 would raise the required tariff by 12.1%.
3. Cost of Equity: 13.8%
Private investors in Nepal typically demand at least a 17% internal rate of return (IRR). A cost of equity set at 13.8%.ECA says it would necessitate a 12.1% tariff increase to meet practical return thresholds.
4. Cost of Debt: 3.9%
This assumes concessional financing through IDA or sovereign loans. However, most domestic projects rely on loans with average effective rates around 11% over their lifespan. A rise from 3.9% to 11% would require an estimated 38.6% increase in tariff, as ECA suggests a 7.6% increase if the interest rate rises to increase to 5.1% from 3.9%. The 38.6% figure is derived using the unitary method.
5. Debt Tenor: 27 Years
Nepali commercial banks typically provide a maximum of 12 years of repayment post-commissioning. ECA’s model assumes 27 years, and a reduction to 12 years would necessitate an 18% tariff increase as ECA notes an 8.4% increase if the tenor is reduced to 20 years from 27 years; again, the unitary method is applied.
6. O&M Cost Assumption: 0.4% of Capex
While the report considers a 0.4% O&M cost with 3% annual escalation, this appears low, particularly given the added insurance and operation complexity of storage projects. Increasing O&M by 30% leads to only a 2.3% tariff increase, per the paper.
7. Other assumptions
Other assumptions - such as a 2% for employee bonuses and as a 20% corporate tax rate-are accurately reflected. A100% tax holiday for the first 15 years and 50% reduction for the following 6 years are also assumed. Additionally, energy royalty is set at 2% of energy sales and capacity royalty at NPR 100 per kW per year for the first 15 years. For the remaining years, energy royalty increases to 10% of energy sales and capacity royalty rises to NPR 1,000 per kW per year.
The consultant has provided tariff sensitivities in case these 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 Tariff for Practical Scenarios
If we apply the realistic assumptions commonly faced by IPPs in Nepal—such as 70:30 debt-equity, 17% equity return, 11% interest rates, and 12-year debt repayment—the actual required tariff as suggested by ECA would be.
Adjusted Tariff (1–15 Years):
Season | Base (NPR) | 70:30 DE | 11% Debt | 17% ROE | 12-Yr Debt | Adjusted Tariff |
Wet | 5.69 | +0.69 | +2.20 | +0.69 | +1.02 | 10.29 |
Dry | 9.95 | +1.20 | +3.84 | +1.20 | +1.79 | 17.99 |
Adjusted Tariff (16–50 Years):
Season | Base (NPR) | 70:30 DE | 11% Debt | 17% ROE | 12-Yr Debt | Adjusted Tariff |
Wet | 4.83 | +0.58 | +1.87* | +0.58 | +0.87* | 8.73 |
Dry | 8.46 | +1.02 | +3.27* | +1.02 | +1.52* | 15.30 |
*loan is repaid so it is arguable.
These revised tariffs are not in line with the rates currently offered for RoR projects. For instance, if the cost and electricity generation of storage-type projects are to be compared and brought to parity with run-of-river hydropower, then the Power Purchase Agreement (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, 1,200 MW Budhi Gandaki Storage Project would require NPR 12.64 and NPR 22.12 per kWh for wet and dry season respectively. Both projects should also be provided with an annual escalation of 3% for up to eight times, similar to other hydropower projects.
Structural and Conceptual Oversights
1. Storage Potential Is Not Uniform
Not all storage projects operate the same way. For example, Budhigandaki (1,200 MW) produces 3,383 GWh annually, while Dudhkoshi (670 MW) produces 3,442 GWh. Despite lower energy output, Budhigandaki can supply 1200 MW (or near to it) peak power during the dry season—a crucial grid-balancing function that is undervalued in the current model, whereas Dudhkoshi can only supply 670 MW at maximum.
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 6 months are penalized, receiving only 6 months of capacity payments instead of being rewarded for their grid value.
ECA assumes that storage projects are meant to generate both dry and wet energy, which is also not practical. As per the design guidelines approved by the DoED, the minimum criteria for a storage project should include a reservoir capacity to hold a minimum of 15 days of design discharge, and the minimum dry energy should be 35% of total energy. There is no limit for the maximum. However, the consultant is silent about projects that can store water for 6 months and produce dry energy with maximum peak power when it is needed the most.
In fact, the proposed tariff model penalizes such superior projects under the energy and capacity model. Since the capacity tariff is expressed per kW per month, projects operating for only 6 months can only claim 6 months of capacity tariff, not 12. Rather than incentivizing storage excellence, the tariff structure could end up discouraging it.
3. One-Project Approach
The model is based on a single, hypothetical 650 MW project. This fails to capture the diversity of Nepal’s storage portfolio. Applying this narrow analysis to all future projects may lead to inappropriate tariff benchmarks and project failures similar to what is already anticipated in the Tanahun hydropower project.
The Role of the Private Sector
One of the most significant omissions in the discussion paper is the absence of private sector input. The private sector brings ground-level understanding of cost dynamics, financing risks, and implementation hurdles. A tariff model that excludes their voices risks irrelevance or, worse, policy failure. ECA prepared the paper in consultation with the USAID Urja Nepal Program and ADB. However, the private sector -who have hand-on experience in hydropower constructions and can analyze any financial models from a real business perspective-were ignored completely. Perhaps this is because they assumed the private sector cannot construct storage projects on their own.
Conclusion: Moving Toward a Holistic Storage Tariff Model
The discussion paper by ECA is a commendable step in formalizing a tariff framework for storage hydropower. However, its current assumptions and modeling choices render it insufficient for setting real-practical PPAs. As Nepal transitions from RoR to more complex storage infrastructure, pricing must reflect not only the economic cost but also the strategic value of firm, dispatchable power.
The proposed figures of NPR 5.69 and NPR 9.95 per kWh should not be viewed as benchmarks but as outcomes tied to a very specific and often impractical set of assumptions. A more nuanced and adaptive approach—one that includes a variety of project types, financial realities, and stakeholder input—is essential for building a resilient energy future for Nepal. Policymakers should not be misled by the proposed NPR 5.69 and NPR 9.95 per kWh rates, In fact, ECA has proposed 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.
P.S. I ran the parameters suggested by the consultant on Dudhkoshi Storage project, but the project still proved unviable in these rates (rates without adjustment) . Forget about achieving acceptable IRR and EIRR, the project struggled to generate enough cash flow to meet its debt obligation from 8th year of operation.
This issue primarily stems from the 3.2% per annum USD:NPR appreciation rate suggested by the ECA, which significantly distorts the financial over time. Under this assumption, the exchange rate of NPR 133.5 per USD escalates to approximately NPR 470 per USD over the debt repayment period.
For example, what initially appears to be a soft loan with a low interest rate ends up costing far more. The total repayment (principal + interest) for USD-denominated loan of NPR 241 billion reaches NPR 755.90 billion. In contrast, if the same NPR 241 billion were borrowed domestically—with 12-year repayment period post COD at 11% interest rate per annum—the total repayment would be approximately NPR 437 billion, and the capital would remain within the domestic country.
So, while concessional foreign loans may look attractive at first glance, they can ultimately cost more due to currency depreciation impacts.
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