Section 1: NEA Financial Health — 6-Year Scorecard
P&L Trajectory (NPR Million)
Source: NEA Annual Report FY 2024/25 (provisional, subject to audit), Statement of Profit & Loss 10-year summary.
| Metric | FY 2019/20 | FY 2020/21 | FY 2021/22 | FY 2022/23 | FY 2023/24 | FY 2024/25* |
|---|---|---|---|---|---|---|
| Sales Revenue | 71,293 | 70,859 | 87,155 | 100,346 | 115,505 | 125,277 |
| Power Purchase — IPPs | (20,554) | (17,901) | (23,493) | (32,149) | (41,473) | (53,326) |
| Power Purchase — NEA Subsidiaries | (1,141) | (1,124) | (9,114) | (10,001) | (10,732) | (10,851) |
| Power Purchase — India | (13,425) | (21,821) | (15,438) | (19,706) | (16,802) | (12,923) |
| Other Cost of Sales | (15,012) | (15,439) | (15,574) | (18,682) | (19,771) | (20,686) |
| Profit Before Tax (PBT) | 13,366 | 6,272 | 15,058 | 12,077 | 14,465 | 9,067 |
| PBT Margin | 18.7% | 8.8% | 17.3% | 12.0% | 12.5% | 7.2% |
| Profit After Tax (PAT) — FY 2024/25 only | — | — | — | — | — | 6,446 |
| Net Profit Ratio (per NEA AR) | 16% | 9% | 15% | 9% | 9% | 5% |
FY 2024/25 marked the first year with material deferred tax expense (NPR 2,621M), bringing PBT of NPR 9,067M down to PAT of NPR 6,446M. Prior-year PBT and PAT were close because of carried-forward accumulated losses (NEA's FY 2015/16 PBT was -NPR 8,890M); those carry-forwards have now been substantially absorbed.
Balance Sheet Trajectory (NPR Million)
Source: NEA Annual Report FY 2024/25, Statement of Financial Position 10-year summary.
| Metric | FY 2015/16 | FY 2019/20 | FY 2024/25* |
|---|---|---|---|
| Property, Plant & Equipment | 88,521 | 157,384 | 242,066 |
| Capital Works in Progress | 66,684 | 114,300 | 257,312 |
| Trade & Other Receivables | 11,187 | 31,492 | 37,853 |
| Total Assets | 210,689 | 416,446 | 683,913 |
| Long-Term Borrowings | 111,304 | 163,737 | 264,673 |
| Total Equity | 26,009 | 154,139 | 263,752 |
Operating Ratios
| Metric | FY 2015/16 | FY 2019/20 | FY 2024/25* |
|---|---|---|---|
| System Loss | 25.78% | 15.27% | 12.26% |
| Avg Sales Rate (NPR/kWh) | n/a | 8.74 | 9.13 |
| Avg Power Purchase Rate (NPR/kWh) | n/a | 5.21 | 6.08 |
| Gross Spread (NPR/kWh) | n/a | 3.53 | 3.05 |
| Number of Consumers | n/a | 4.4M | 5.71M (excl. ~0.33M Community Rural) |
| National Peak Demand | n/a | 1,408 MW | 2,409 MW (recorded 10 June 2025) |
| System Peak Demand incl. Export | — | — | 2,901 MW (recorded 1 July 2025) |
Section 2: The Spread Problem
NEA buys power at a blended average of NPR 6.08/kWh (IPP + own generation + NEA subsidiaries + India) and sells at NPR 9.13/kWh. The gross spread of NPR 3.05/kWh must cover:
- Transmission & distribution losses (12.26% of energy purchased — i.e. NEA receives revenue on only ~87.7 units of every 100 it buys)
- Personnel and administrative expenses (Personnel: NPR 6,788M FY 2024/25; G&A: NPR 586M)
- Interest on long-term borrowings of NPR 264.7B (Finance cost FY 2024/25: NPR 7,173M)
- Depreciation & amortisation (NPR 9,485M FY 2024/25)
- Royalty (NPR 1,849M) and power-service export charge (NPR 1,292M)
- Income tax (FY 2024/25: NPR 2,621M deferred tax expense)
After deducting the system-loss adjustment, the effective net spread on each unit sold is roughly NPR 1.95/kWh. On 13,723 GWh of total electricity sales (internal 11,343 GWh + exports 2,380 GWh), this works to ~NPR 27B of contribution before fixed costs — which has to cover the financing, depreciation, and tax block of NPR 19B+, leaving the residual that drops to PBT.
IPP Generation Tariff Schedule (Standard NEA PPAs in Force)
Source: ERC Nepal and NEA model PPA terms (publicly available at erc.gov.np / nea.org.np). Specific tariff bands are subject to project-level negotiation and the standard tariff in force at PPA-signing date.
| PPA Type | Wet Season (NPR/kWh) | Dry Season (NPR/kWh) | Escalation |
|---|---|---|---|
| Standard RoR (≤25 MW) | ~4.80 | ~8.40 | 3% × 5 years |
| Storage / Peaking RoR | Negotiated; typically 7.10–12.40 | Negotiated; typically 7.10–12.40 | Negotiated |
| Solar (competitive bidding) | Tariff-based competitive bidding adopted; recent winning bids in the NPR 5.94–7.30 range | Same | None |
In FY 2024/25, NEA selected 63 grid-connected solar PV projects with combined capacity 960 MW via competitive bidding; PPAs were signed for 8 projects totalling 170 MW that year (NEA AR FY 2024/25).
In dry season, the standard RoR rate of ~8.40 is close to NEA's average sales rate of NPR 9.13. On incremental dry-season IPP power purchased at the standard rate, NEA's effective spread before opex is essentially zero.
Section 3: IPP Payment Obligations and Receivables
Total IPP power purchase cost grew from NPR 17.9B (FY 2020/21) to NPR 53.3B (FY 2024/25) — a 3x increase in four years (NEA AR FY 2024/25, P&L 10-year summary).
Trade and other receivables stood at NPR 37.85B at end of FY 2024/25, down from NPR 40.22B a year earlier (NEA AR FY 2024/25, SoFP 10-year summary). Within receivables, NEA recognised NPR 5,500M of impairment in FY 2024/25 — one of several material write-downs in recent years (impairment was NPR 5,162M in FY 2023/24 and NPR 632M in FY 2022/23 per the same source).
PPA Pipeline as of FY 2024/25 (NEA Annual Report, Generation Directorate):
| PPA Status | Project Type | No. of Projects | Installed Capacity (MW) |
|---|---|---|---|
| PPA Signed | RoR | 402 | 6,720 |
| PROR | 51 | 4,196 | |
| Storage | 1 | 140 | |
| Bagasse | 2 | 6 | |
| Solar | 38 | 375 | |
| Total | 494 | 11,436 | |
| PPA Processing | RoR | 152 | 3,889 |
| PROR | 40 | 6,231 | |
| Storage | 6 | 5,117 | |
| Solar | 55 | 790 | |
| Total | 253 | 16,027 |
Section 4: Generation Mix & Capacity
Energy Mix (GWh, NEA AR FY 2024/25 chart)
| Source | FY 2015/16 | FY 2024/25* | Change |
|---|---|---|---|
| NEA Own Generation | 2,133 | 2,953 | +38% |
| NEA Subsidiaries | 154 | 2,400 | 15.6× |
| Private IPPs | 1,012 | 8,606 | 8.5× |
| India Imports | 1,778 | 1,681 | -5% |
| Total Energy Available | 5,077 | 15,641 | 3.1× |
| India share of total | 35% | 11% | — |
Capacity Snapshot (FY 2024/25)
NEA's own generation directorate reports installed capacity of approximately 627 MW. NEA subsidiaries include Upper Tamakoshi (456 MW), plus Chilime, Trishuli 3A, Rasuwagadhi and others. The total installed capacity figure for the Nepali grid (NEA + subsidiaries + private IPPs) is greater than national peak demand of 2,409 MW (recorded 10 June 2025) and 2,901 MW system peak including export (recorded 1 July 2025). Detailed capacity reconciliation by entity is best taken from NEA AR Section: Power Generation Subsidiaries.
Section 5: Cross-Border Trade
Source: NEA AR FY 2024/25, Import & Export charts (volume in million units; revenue/cost in Rs. million).
| FY | Imports (GWh) | Exports (GWh) | Net (GWh) | Imports Cost (NPR M) | Exports Revenue (NPR M) |
|---|---|---|---|---|---|
| 2019/20 | 1,729 | 107 | -1,622 | 13,425 | 983 |
| 2020/21 | 2,806 | 38 | -2,768 | 21,821 | 316 |
| 2021/22 | 1,543 | 494 | -1,049 | 15,438 | 3,942 |
| 2022/23 | 1,833 | 1,346 | -487 | 19,706 | 10,455 |
| 2023/24 | 1,895 | 1,946 | +51 (first net-export year) | 16,802 | 17,040 |
| 2024/25* | 1,681 | 2,380 | +699 | 12,923 | 17,471 |
FY 2024/25 net cross-border contribution: revenue NPR 17,471M − cost NPR 12,923M = NPR 4,548M of margin before transmission/wheeling charges (no domestic system loss applies to export sales).
Long-Term Cross-Border Agreements (NEA AR FY 2024/25)
Source: NEA AR FY 2024/25, Power Trade Department disclosure; aggregate approved export quantum 936.72 MW.
| Channel | Capacity | Term | Notes |
|---|---|---|---|
| Indian Power Exchange — DAM/RTM (Dhalkebar–Muzaffarpur 400 kV) | 451.62 MW | Day-ahead/real-time | 9 separate approvals |
| Indian Power Exchange — DAM/RTM (Tanakpur–Mahendranagar 132 kV) | 70.00 MW | Day-ahead/real-time | 2 approvals |
| Medium-term bilateral with India (Haryana Discoms via NVVN) | 200 MW under each of two agreements | 5 years each | Signed during NEA AR FY 2024/25 reporting period |
| Medium-term bilateral with India (Bihar State Power Holding Co. via NVVN) | up to 200 MW | 3 years (extendable up to 5) | Via Nepal–Bihar 132 kV transmission |
| Medium-term bilateral — Nepal/India/Bangladesh tripartite (NEA + NVVN + BPDB) | 40 MW | Multi-year | First export to Bangladesh; flow via Dhalkebar–Mujaffarpur–Baharampur–Bheramara network |
Total approved export quantum: 936.72 MW across 28 approvals.
Section 6: Consumer Tariff Schedule (Reference)
The current NEA tariff schedule is published on nea.org.np and on the Electricity Regulatory Commission's website (erc.gov.np). Specific slabs and rates change with each Tariff Review. The summary below is a reference of the broad customer classes.
| Customer Class | Slab |
|---|---|
| Domestic 0–20 units | First slab — lowest rate |
| Domestic 21–50 units | Second slab |
| Domestic 250+ units | Top slab — highest domestic rate |
| Industrial (peak) | Time-of-day differentiated |
| Industrial (off-peak) | Time-of-day differentiated |
| Bulk Supply | Time-of-day differentiated |
| Community Rural Electrification | Concessional |
Average sales rate across all customer classes was NPR 9.13/kWh in FY 2024/25 (NEA AR FY 2024/25, Operational Highlights).
Section 7: Structural Risks
-
The IPP commissioning wave. PPA-signed projects total 494 / 11,436 MW (NEA AR FY 2024/25). As more of this pipeline reaches commissioning, NEA's wet-season generation will exceed domestic demand by a widening margin. Take-or-pay PPA terms mean NEA pays for energy even if curtailed in the wet season; during the wet season, India's hydro is also long, so prices on the IEX often compress.
-
Forex mismatch. NEA's revenues are NPR-denominated. Long-term borrowings include USD- and INR-linked tranches (ADB, World Bank, Indian EXIM). FY 2024/25 forex loss in the P&L was NPR 2,252M (NEA AR FY 2024/25 — Statement of P&L, "Other gains/(losses)/Forex"). The NPR–INR peg insulates against INR-denominated debt; USD exposure remains.
-
Receivables impairment. NEA recognised NPR 5,500M impairment on receivables in FY 2024/25 and NPR 5,162M in FY 2023/24 (P&L 10-year summary, "Impairment (Charge)/Reversal"). The receivables base has come down — Rs. 40.22B (FY 2023/24) → Rs. 37.85B (FY 2024/25) — but the impairment line is now a recurring item.
-
Storage project execution. The Tanahu Hydropower Project (140 MW storage; NEA subsidiary, formerly Upper Seti, in Tanahu District) has experienced extended timelines. Future storage projects in the pipeline include Dudh Koshi (Dudh Koshi Jalvidyut Company Limited is a listed NEA subsidiary; capacity per project disclosure) and others mentioned in Government of Nepal hydro masterplan documents.
-
Climate and hydrology. Monsoon variability, Glacial Lake Outburst Floods (GLOFs), and natural-disaster damage are tail risks. The FY 2024/25 NEA AR explicitly notes that the Bhotekoshi River flood damaged Trishuli 3A, Rasuwagadhi headworks, and Trishuli 3B Hub substation during the reporting period.
-
MD transition. Mr. Hitendra Dev Shakya assumed the Managing Director role on 2081.12.12 (~25 March 2025), succeeding Mr. Kulman Ghising (NEA AR FY 2024/25, NEA Board Matters section). The MD transition occurred mid-FY 2024/25; operational continuity and the trajectory of payment discipline under the new MD are best assessed from quarterly disclosures and IPP-level reporting going forward.
Section 8: Implications for Hydro IPP Equity Holders
Counterparty risk. NEA had a PBT of NPR 9,067M in FY 2024/25 (down from NPR 14,465M in FY 2023/24), total equity of NPR 263.75B, and total assets of NPR 683.91B. The balance sheet is solvent and government-backed. Working-capital tightness in dry seasons can extend payment cycles for IPPs.
PPA vintage matters. Standard RoR PPAs signed in earlier vintages at lower wet/dry rates with 3% × 5-year escalation are NEA's cheaper marginal supply. Newer PPAs at higher rates are NEA's most expensive purchase, and so the first marginal supply curtailed in a wet-season glut.
Storage vs RoR vs Solar. Storage and Peaking RoR earn premium tariffs and contribute to dry-season demand. Pure RoR (a large share of currently operational IPPs) gets standard tariffs. Solar is now procured via competitive bidding, with FY 2024/25 awarded tariffs reflecting market clearing rather than fixed schedules.
Export-linked premium accrues to NEA, not the IPP. Cross-border export contracts are signed by NEA. IPPs sell to NEA at PPA rates; NEA captures the export spread. Direct IPP-to-foreign-buyer contracting is not yet in commercial operation in Nepal.
Late-cycle commissioning. Projects commissioning in the FY 2026–2028 wave will face the most pressure on offtake during wet-season gluts. Pre-2025 commissioned projects with secured PPAs are inside the relatively safer offtake zone.
Final Read on NEA as a Counterparty
| Dimension | Assessment |
|---|---|
| Operational performance | System loss down to 12.26% from 25.78% (FY 2015/16); peak demand growing |
| Profitability | PBT margin compressed from 18.7% (FY 2019/20) to 7.2% (FY 2024/25); PAT now subject to deferred tax |
| Balance sheet | Solvent; total equity NPR 263.75B; long-term debt NPR 264.67B; D/E approximately 1.0× |
| Cash conversion | Adequate; impairment on receivables is now a recurring P&L item |
| Sovereign linkage | Government-backed; ex-officio board representation from Energy and Finance ministries |
| Forward 5-year risks | IPP commissioning wave; tariff politics; MD transition; receivables impairment trend |
| Forward 10-year drivers | Cross-border export market; tariff-review outcomes; storage commissioning |
References
- NEA Annual Report FY 2081/82 (FY 2024/25) — primary financial statements, capacity, generation mix, cross-border trade, PPA pipeline
- NEA Annual Reports FY 2076/77–FY 2080/81 — historical comparatives in 10-year summary tables
- Electricity Regulatory Commission Nepal — PPA tariff schedules and regulatory framework
- NEPSE — listed hydro IPP share prices
Research date: May 10, 2026. Primary source for all NEA financial figures: NEA Annual Report FY 2024/25 (provisional, subject to audit), as published on nea.org.np.