Nepal Electricity Authority (NEA) — Company Analysis

Why We Analyze NEA

NEA is not in the portfolio. It cannot be. It is wholly owned by the Government of Nepal and has no listed equity. But NEA is the counterparty on every PPA that underpins every hydro IPP we own or consider owning. Understanding NEA — its financials, its management, its structural pressures, its sovereign backstop — is more important than understanding any individual IPP. A 30-year PPA with a bankrupt offtaker is worth nothing. A 30-year PPA with a structurally sound, sovereign-backstopped utility is the closest thing to a bond that Nepali equity markets offer.

This report is therefore an underwriting document. We are not asking "should we buy NEA?" We are asking: "Is NEA solvent and payment-disciplined enough to anchor a long-horizon hydro IPP portfolio?"

Executive Summary

Nepal Electricity Authority is a 100% government-owned vertically integrated utility that generates, transmits, and distributes electricity across Nepal, while also acting as the single mandatory offtaker for all private-sector Independent Power Producers (IPPs) under the 2018 Electricity Act. In FY 2024/25, NEA served 6+ million customers, purchased 8,606 GWh from private IPPs and 2,953 GWh from its own plants, transmitted 15,641 GWh total, and reported NPR 125bn in revenue against NPR 6.4bn in net profit — a 5.1% net margin, down from 18.7% in FY 2019/20. NEA went from losing NPR 8.9bn annually (FY 2015/16) to earning NPR 6.4bn, cutting system losses from 25.8% to 12.3%, eliminating load-shedding, and becoming South Asia's newest net power exporter — all in nine years. The current challenge: a 3,770 MW IPP commissioning wave arriving 2026-2029 under take-or-pay PPAs, consumer tariffs frozen since 2018, and a spread between average purchase cost (NPR 6.08/kWh) and average sale price (NPR 9.13/kWh) that is shrinking every year. The sovereign backstop is real, but so is the margin compression.

Business Quality Score: 6.5 / 10

What earns points:

• Natural monopoly — no alternative buyer for IPP power; no alternative distributor for most of Nepal
• Sovereign ownership guarantees survival (GoN cannot let the grid go dark)
• Operational transformation under Kul Man Ghising is genuine and measurable: system losses halved, load-shedding eliminated, collections modernized
• Balance sheet de-levered from D/E 4.3x (FY16) to 1.0x (FY25) — remarkable for an SOE
• Net exporter for the first time in history (FY 2023/24), widening surplus in FY 2024/25
• NPR 257bn CWIP pipeline will become earnings-generating assets within 3-5 years
• Electricity demand growing 10-12% annually — structural tailwind for volumes

What costs points:

• Margin structurally compressing as take-or-pay IPP costs scale faster than revenue
• Consumer tariffs politically frozen since 2018 — real purchasing power of revenue base declining
• NPR 5,500M receivables impairment in FY25 signals collection discipline problems (industrial consumers, dedicated feeders)
• CWIP execution risk: Tanahu (140 MW storage) significantly over budget; Budhigandaki questions remain
• Political management risk: Kul Man Ghising removed in 2020, reinstated 2023 — tenure uncertainty
• No pricing power with consumers (tariff regulator politically captured); squeeze comes only from the cost side
• Foreign currency debt (~USD/INR portions) creates forex exposure on an NPR revenue base

The Business Model in Depth

Three Roles, One Entity

NEA operates simultaneously as:

1. Generator — Owns ~620 MW of its own plants (Kulekhani I/II/III, Trishuli, Marsyangdi, Middle Marsyangdi, Kali Gandaki A). In FY25, own generation was 2,953 GWh — only 19% of total energy handled. NEA's own generation is almost entirely legacy hydro, much of it 30-50 years old. Maintenance costs are rising; upgrade capex is substantial.

2. Single Buyer / Offtaker — Under the 2018 Electricity Act, NEA is the mandatory buyer of all domestic IPP generation not directly wheeled or exported. This is the dominant role by FY25: IPP purchases (8,606 GWh) now represent 55% of all energy in the system, up from 20% in FY15/16. Every new IPP commissioned adds to NEA's fixed purchase obligations. Take-or-pay provisions post-2024 mean NEA pays even for energy it cannot sell domestically.

3. Transmission & Distribution Monopolist — NEA owns and operates the national transmission grid and distribution network. This is the most defensible part of the business: no private entity can bypass the wire. Even in a scenario where IPPs get direct export rights, they still pay NEA wheeling charges. Capex here (CWIP: NPR 257bn) is the future earnings engine.

Revenue Composition (FY 2024/25 estimate)

The export line is the newest and fastest-growing. From zero meaningful exports in FY21/22 to NPR 17.5bn in FY24/25 — a structural shift in the revenue mix that diversifies away from politically-capped domestic tariffs.

Financial Performance: 6-Year Deep Dive

P&L Trend (NPR Million)

The compression narrative in one line: Revenue grew 75% from FY19/20 to FY24/25. IPP purchase cost grew 159%. PAT fell 52%.

Why FY20/21 was the anomaly: COVID suppressed industrial demand; NEA imported heavily from India (NPR 21.8bn — highest in the 6-year period) as domestic IPP supply was less available. Revenue was flat while import costs spiked. One-time noise.

Why FY21/22 was the best year: Post-COVID recovery drove 23% revenue growth. India import mix fell back (15.4bn). IPP costs had not yet scaled into take-or-pay territory. This was the peak of the "turnaround" moment.

Why FY24/25 is the inflection point: IPP costs are now compounding at ~28% annually while revenue grows at ~8-15%. The gap cannot persist without either tariff reform or a dramatically larger export market. FY25 net margin of 5.1% is the lowest in the profitable era.

Balance Sheet Trajectory (NPR Million)

The CWIP risk: NPR 257bn of CWIP includes:

• Budhigandaki Hydropower Project (1,200 MW, estimated NPR 280-350bn total cost — the single largest infrastructure project in Nepali history). This is NEA-GoN, not the SAHAS-linked Times Energy project.
• Naumure Multipurpose Project (60 MW + irrigation)
• National transmission grid expansion (400kV backbone, cross-border interconnects with India)
• Distribution automation and smart metering

If Budhigandaki alone overruns significantly, CWIP impairment could wipe years of retained earnings. This is the tail risk to watch.

Cash Flow & Liquidity

NEA does not publish a Western-style cash flow statement in the format most useful for analysis. Inferences from balance sheet movements:

The key question NEA doesn't answer publicly: How long does it take to pay IPPs after energy delivery? Industry reports suggest 30-90 days in normal years but 90-150 days in tight quarters. No disclosure on payables aging. This is the #1 data gap for +16 Capital as an IPP equity holder.

The Spread Problem — A Detailed Analysis

This is the most critical section for anyone owning hydro IPP equity.

How the Unit Economics Work

For every 100 units of electricity NEA "buys" (from own gen + IPPs + India imports):

• 12.26 units disappear as system losses (technical + commercial)
• 87.74 units are sold to customers

NEA pays NPR 6.08/kWh blended purchase cost on 100 units. NEA earns NPR 9.13/kWh average on 87.74 units sold.

Effective unit economics:

• Revenue per 100 units purchased: 87.74 × 9.13 = NPR 801 per 100 kWh
• Cost per 100 units purchased: 100 × 6.08 = NPR 608 per 100 kWh
• Net contribution: NPR 193 per 100 kWh (19.3% contribution margin)

From this NPR 193 contribution, NEA must fund:

• Employee costs (~NPR 12-15bn annually)
• Repair & maintenance (~NPR 8-10bn)
• Depreciation (~NPR 15-18bn on PPE base)
• Interest expense (~NPR 18-22bn on NPR 264bn debt at ~7-8%)
• Taxes (currently modest given capital allowances)

The math is tight. At FY25 revenue of NPR 125bn and contribution of ~NPR 193 per 100 kWh, NEA has approximately NPR 24-26bn of contribution before opex/depreciation/interest. Against those charges of ~NPR 50-55bn, the model requires scale and efficiency to stay in the black.

The Tariff-PPA Scissors (The Critical Risk)

The scissors are closing. If consumer tariffs don't rise by FY26/27 when the next major wave of IPP commissioning hits, NEA's nominal spread could fall below NPR 2.50/kWh — mathematically insufficient to cover opex + interest after system losses.

Operational Scorecard

System Performance

The Kul Man Ghising scorecard: Every important operational metric improved under his watch. System losses cut by more than half. Load shedding eliminated. Customer base doubled. Net exporter status achieved. This is one of the most successful SOE turnarounds in South Asia in the past decade.

Energy Balance Detail (FY 2024/25 estimate, GWh)

Cross-Border Trade: The Strategic Relief Valve

Trade History

The Bangladesh Milestone

The 40 MW Bangladesh export commenced in FY 2024/25 — the first time Nepal exported power to a country other than India. This matters disproportionately to the volume:

• India is both buyer and gatekeeper. Every Nepal-Bangladesh electron transits the Indian transmission grid. India earns wheeling charges. India controls the interconnection capacity. Geopolitically, Nepal's ability to diversify its export customer base is constrained by India's cooperation.
• Bangladesh has 170 million people, gas-dependent power, and chronic shortages. Long-run, Bangladesh needs exactly what Nepal has: cheap wet-season hydro. A Nepal-Bangladesh corridor at scale would transform Nepal's export economics.
• The constraint is Indian transmission capacity + bilateral political agreements. Progress has been made (tripartite MoU; 400 kV interconnections being built). But the timeline to 500+ MW Bangladesh exports is 5-8 years away, not 1-2 years.

Long-Term Export Agreements (as of April 2026)

• 200 MW to Uttar Pradesh/Haryana — 25-year term, bilateral
• 200 MW to Bihar — Long-term bilateral
• 40 MW to Bangladesh — New, via Indian grid
• ~250 MW additional Bangladesh under negotiation
• India Energy Exchange (IEX) spot sales — opportunistic, wet-season surplus

The 2026-2028 glut management problem: Nepal's grid-connected capacity will grow from ~3,500 MW (FY25) to potentially ~6,000-7,000 MW (FY28) as the 3,770 MW under construction commissions. Domestic peak demand is ~2,300 MW. Even accounting for 10-12% demand growth:

• FY26 demand: ~2,580 MW
• FY27 demand: ~2,890 MW
• FY28 demand: ~3,240 MW

Against 6,000-7,000 MW of installed capacity, Nepal will have 2,760-3,760 MW of surplus capacity by FY28 — more than the entire current domestic grid. Every surplus megawatt that cannot be exported is either curtailed (NEA pays under take-or-pay) or stored (Nepal has very limited storage). This is the structural problem that the Bangladesh and expanded India export corridors must solve.

Management Assessment

Kul Man Ghising — The Turnaround CEO

No analysis of NEA is complete without understanding the human being who drove its transformation. Kul Man Ghising, an electrical engineer who joined NEA in 1984, served as Managing Director from 2016 to 2020 and was reinstated in 2023 after a political interregnum.

The FY16-FY20 first term scorecard:

• System losses: 25.8% → 13.6% (cut nearly in half)
• Load shedding: 12-16 hrs/day → 0 (eliminated by November 2018)
• Customer additions: +600,000+ new connections
• Financial turnaround: NPR 8.9bn loss → NPR 13.4bn profit
• Operational discipline: prepaid meters, automated billing, revenue recovery from theft

How he did it: The load-shedding elimination was not primarily a generation story — generation capacity grew modestly in his first term. It was a demand management and loss-reduction story. He reclassified illegal connections, prosecuted meter-bypassing, automated billing in Kathmandu Valley, and used 11 kV feeder separation (LTL – Low Tension Line separation) to isolate loss-generating distribution segments. The loss reduction freed up effectively 2-3 GWh of generation capacity that had previously been stolen.

The 2020 removal: Ghising was removed in May 2020 by the then-government — widely attributed to political pressure from factions opposed to his anti-corruption enforcement. Under his interim successors (2020-2023), load shedding threatened to return (0.5-1 hr/day in some periods) and operational momentum softened.

The 2023 reinstatement: The current Prachanda-led government brought Ghising back in 2023. He has continued the trajectory: export market development, Bangladesh deal, IPP commissioning wave management.

The governance risk: Ghising is not a technocrat insulated from politics — he is a technocrat enabled by political cover. When that cover shifts, the institution's quality shifts with it. This is an SOE reality, not a personal failing.

Succession planning: Zero. There is no publicly identified successor who could replicate Ghising's combination of technical credibility, anti-corruption willingness, and political savvy. This is the management risk that most analysts discount but that +16 Capital should weight heavily.

Board Composition

NEA's Board is government-appointed and changes with political administrations. The current board includes:

• Secretary, Ministry of Energy, Water Resources and Irrigation (ex-officio Chairman)
• Secretary, Ministry of Finance (ex-officio)
• Professional directors (typically 3-4) appointed by government
• No independent directors in any Western governance sense

The IPP Ecosystem: NEA as Contractor

Understanding NEA's relationships with the ~200 operational IPPs is critical for evaluating any specific IPP investment.

PPA Contract Structure (Standard RoR)

The Take-or-Pay Amendment — The Most Underappreciated Risk Transfer

Before 2024, NEA could curtail IPP generation during wet-season surplus without payment obligation. This was an enormous hidden subsidy to NEA's balance sheet: during the wettest months, NEA could simply switch off expensive IPP units and rely on cheaper Indian imports or its own cheap legacy hydro.

The 2024 amendment changed this. Now NEA must pay for contracted energy even if curtailed. This:

1. Eliminates IPP's curtailment risk (bullish for IPP equity)
2. Transfers curtailment cost to NEA (NEA's wet-season cost base rises)
3. Makes wet-season surplus a direct NEA cash drain rather than an operational decision

For +16 Capital: The take-or-pay amendment is net positive for our IPP holdings. But it is net negative for NEA's medium-term margins. Both things are true simultaneously.

Payment Cycle Intelligence

From SHPC annual reports and industry sources:

• SHPC reported NEA receivables of NPR 422.9M in FY81/82 (~37 days of annual revenue)
• SAHAS reported NEA receivables of NPR 412M in FY81/82 (growing 27% vs. 8% revenue growth — a flag)
• Industry reports suggest NEA pays 30-90 days in normal conditions, 90-150 days in tight quarters (wet season when NEA is accumulating take-or-pay obligations but hasn't yet collected export revenue)

Regulatory & Policy Environment

The Electricity Regulatory Commission (ERC)

The ERC, established under the Electricity Regulatory Commission Act 2074 BS (2017), is nominally the independent regulator for:

• Consumer tariff setting
• IPP PPA approval
• Grid code enforcement
• Dispute resolution between NEA and IPPs

In practice: The ERC has approved modest tariff adjustments but has not mandated the step-change in consumer tariffs that NEA's economics require. The ERC commissioners are government-appointed and serve at political pleasure — structural independence is limited.

The tariff petition: NEA has filed for a tariff increase to reflect rising power purchase costs. The ERC's track record is increases of 5-15% every 2-3 years — meaningful but inadequate to restore the pre-FY18 spread. Expect the next increase to be ~10-15% on the domestic residential side, phased over 2-3 years.

The 2018 Electricity Act

Key provisions relevant to IPP investors:

• NEA as single mandatory buyer (until IPP direct-wheeling/export rules are operationalized)
• 30-year license for hydro projects; 25-year for solar and wind
• Project assets revert to GoN at license expiry
• DoED (Department of Electricity Development) retains licensing authority for projects > 1 MW
• Cross-border power trade requires MoU between Nepal and buyer country + Energy Exchange or bilateral agreement

India Export Framework

India has progressively opened its transmission access for Nepal:

• Cross Border Electricity Trade Guidelines (India, 2016, amended 2021 and 2023): Allows Nepal IPPs to sell directly to Indian entities if licensed by Indian CERC — currently only NEA does this; individual IPP direct sales are in regulatory limbo
• Indian Energy Exchange (IEX): Nepal can sell into the Day-Ahead Market (DAM) — spot prices. NEA uses this for marginal wet-season surplus
• Bilateral long-term PPAs: 200 MW to Haryana, 200 MW to Bihar — these are NEA-to-SEIL/state utility contracts, not IPP-direct

The direction of travel is toward allowing IPP-direct exports, but this will take 3-5 years of regulatory groundwork in both countries.

Bull Case

1. The Bangladesh Corridor Scales. Bangladesh's power sector is in structural deficit; its gas reserves are declining; its government has committed to buying 9,000 MW from India by 2040. If even 1,500-2,000 MW of this comes from Nepal (routed via India), NEA's export revenue triples and the wet-season glut problem disappears. The infrastructure (400kV Muzaffarpur-Dhalkebar interconnect and extensions) is being built. This is a 5-8 year timeline but a high-conviction directional bet.

2. Tariff Reset in 2026-2027. Political calculus may shift: a government facing power costs from take-or-pay obligations that threaten NEA's solvency is more likely to pass through a tariff increase than one managing a comfortable surplus. The ERC's pending petition — if approved at 15-20% across industrial and high-consumption segments — restores ~NPR 8-12bn of annual margin. Not transformative, but stabilizing.

3. CWIP Capitalization Creates Future Earnings. NPR 257bn of CWIP will progressively capitalize over FY25-FY30. When Budhigandaki (1,200 MW) and the national transmission backbone capitalize, depreciation rises but so does the earning asset base — and NEA's generation cost from its own plants is much cheaper than IPP purchased power. Every 1,000 MW of own generation at NPR 2-3/kWh replaces ~NPR 5-8/kWh of IPP purchase cost.

4. System Loss Reaches 10% (The Last Mile). Each 1% reduction in system loss at current revenue is worth ~NPR 1.2-1.5bn of additional effective revenue. Moving from 12.26% to 10% adds ~NPR 3-3.5bn. Achievable through smart metering rollout (in progress) and distribution automation.

5. NRB Interest Rate Cuts Reduce NEA's Debt Service. Nepal Rastra Bank has been in an easing cycle in 2025-2026. NEA's NPR-denominated loans at domestic banks (roughly half the debt book) will see reduced interest costs on renewal. Each 100 bps reduction across NPR 100bn of local currency debt = NPR 1bn of interest savings.

6. IPP Wave Completes Without NEA Solvency Crisis. In the best case, the 2026-2029 commissioning wave commissions, India absorbs 4,000+ GWh of annual surplus, Bangladesh begins absorbing 500+ GWh, and domestic demand grows 12-15% annually. NEA manages through on a tight margin without needing a bailout — and by FY2030, the tariff is reset and the economics normalize. IPP holders get paid on time throughout.

Bear Case

Bear 1: The Scissors Close and GoN Recapitalization Is Messy

If consumer tariffs remain frozen AND the 3,770 MW commissions on schedule AND exports don't scale above 3,000 GWh, NEA's IPP purchase costs could exceed NPR 90-100bn by FY27/28 while revenues grow to ~NPR 145bn. Net margin could approach zero or turn negative.

In this scenario, GoN recapitalization is inevitable — but Nepali government recapitalization is slow, politically contested, and typically comes with conditions (tariff reform, management changes, PPA renegotiation pressure). The 12-24 months of "negotiation" before the bailout arrives are the dangerous period for IPP equity holders: NEA may slow-pay IPPs, building receivables, effectively using IPPs' balance sheets as a working capital buffer.

The signal: Watch NEA's trade payables in annual reports. If IPP receivables (from IPP annual reports) start growing faster than 15% above revenue growth, the slow-pay period has begun.

Bear 2: Political Management Risk Materializes

A new government removes Ghising (again) and installs a MD focused on procurement and patronage rather than operational efficiency. System losses creep from 12% back toward 15-16%. Collections deteriorate. The operational gains of 2016-2025 partially reverse.

This is not hypothetical — it happened in 2020-2023. The difference: in 2020, NEA had slack (tariffs were adequate, IPP wave hadn't hit). In 2027-2028, NEA operates with zero margin for operational degradation.

The signal: System loss numbers in NEA's annual report. Any increase above 13% is a warning. Above 15% is a crisis.

Bear 3: India's Own Hydro Surplus Undermines Nepal's Export Price

India's own hydropower capacity is growing rapidly (Himachal Pradesh, Uttarakhand, J&K — all adding run-of-river capacity that peaks in the same June-September window as Nepal's surplus). By FY28-FY30, the Indian Energy Exchange's wet-season spot price could fall to INR 2.50-3.00/kWh (vs. current INR 4-6), dramatically reducing the margin NEA earns on surplus exports.

If export revenue stays flat in NPR terms while IPP costs grow 25-30% annually, NEA's export-as-relief-valve theory fails.

The signal: IEX wet-season Day-Ahead Market prices in June-September. Any sustained fall below INR 3.50/kWh is a warning.

Moat Assessment: The NEA Paradox

Verdict: WIDE moat, but it's the government's moat — not shareholders' moat (because there are no shareholders)

NEA's economic moat is genuine and wide:

• Regulatory monopoly: No entity can legally generate and sell to domestic consumers without going through NEA. No entity can build transmission without NEA permission. This is statutory, not competitive.
• Physical monopoly: The transmission and distribution wires are a natural monopoly — replication is economically irrational.
• Counterparty lock-in: 455 signed PPAs, 200 operational IPPs. NEA cannot exit these relationships; IPPs cannot exit. The mutual dependency is real and 25-30 years long.
• Sovereign backstop: GoN cannot allow NEA to fail. Power is a national security matter. The implicit government guarantee is the widest moat of all.

The paradox: These moats protect NEA from competition but do NOT protect NEA from internal margin compression, political mismanagement, or tariff regulation. NEA's moat is a monopoly on distribution; its risk is a monopsony on generation (it must buy from all IPPs) combined with a price ceiling on sales (political tariff freeze). The moat protects the volume; the scissors threaten the margin.

For +16 Capital: We benefit from NEA's moat as IPP equity holders. NEA cannot default on PPAs without triggering a sovereign crisis. That's our protection.

Valuation Framework (Hypothetical)

NEA is not publicly traded. But: if it were listed — think Adani Green, NTPC, or China Yangtze Power — what would it be worth?

Comparable Approach

Implied NEA valuation:

• PAT FY24/25: NPR 6,446M
• Normalized PAT (ex-receivables impairment): ~NPR 9-10bn
• At 15x P/E (NTPC-like, appropriate for government monopoly in developing market): NPR 135-150bn
• At 18x P/E (NHPC-like, reflecting hydro asset quality): NPR 162-180bn
• Equity book value: NPR 263.75bn → at 1.5x P/B: NPR 396bn → this feels rich given margin compression

Plausible market cap if listed: NPR 160-250bn (USD 1.2-1.9bn)

For context: Nepal's entire listed market capitalization is ~NPR 2,000-2,500bn. NEA listed would be the largest or second-largest company on NEPSE.

Why this matters even though NEA isn't listed: Understanding what NEA is worth anchors our understanding of the sector. The ~200 listed IPPs collectively have a market cap of ~NPR 500-700bn — roughly 2-4x what NEA itself might fetch. That valuation premium reflects growth (new projects) and scarcity (limited investment alternatives in Nepal), but it also reflects how deeply investors have priced in NEA's ability to pay. If NEA's credit quality deteriorates, the entire ~NPR 500-700bn IPP market cap is at risk.

Final NEA Health Dashboard

For +16 Capital: NEA is an acceptable long-term counterparty for vintage, conservatively leveraged hydro IPP positions. The 2026-2028 period requires active monitoring of the three key signals: (1) IPP receivables growing >15% above revenue growth in our held IPPs; (2) NEA system loss rising above 13%; (3) Indian wet-season spot prices falling below INR 3.50/kWh on IEX. Any two of three flashing red simultaneously would trigger a review of our hydro exposure weighting.

Sources: NEA Annual Reports FY 2019/20–2024/25 (annual_7677.pdf through annual_8182.pdf); Industry cross-references from SHPC and SAHAS annual reports; NEA website https://nea.org.np/en

References

• NEA Annual Reports FY 2077/78–2081/82 — All financial statements and operational data
• Electricity Regulatory Commission Nepal — Tariff orders and regulatory filings
• Ministry of Energy, Water Resources and Irrigation — Policy documents
• Nepal Rastra Bank — Macroeconomic context