Why Hydros in Nepal should urgently start merging?

Option

What It Is

What It Solves and How

How It Could Be Implemented in Nepal

Implementation Challenges

Mandatory BOOT Countdown (Doom Clock) Disclosure & Equity Reclassification

A regulatory requirement that all listed hydropower companies prominently disclose their license expiry dates in all investor communications (annual reports, prospectuses, trading screens, promotional materials), accompanied by mandatory reclassification of such stocks as “Limited-Life Concession Equity” or “Finite-Life Infrastructure Equity” distinct from standard perpetual equities. This transforms informational disclosure into a structural market reclassification that forces rational pricing.

This solution addresses the fundamental information asymmetry and perpetual-equity illusion that has allowed hydropower stocks to trade as if they possess infinite terminal value. By mandating a “BOOT Countdown Clock” in annual reports, IPO/FPO prospectuses, and NEPSE trading interfaces, the solution forces market participants to confront the legally predetermined zero-compensation transfer obligation embedded in every project’s lifecycle. The reclassification into a separate equity category destroys the false perpetuity narrative that has enabled speculative trading at prices disconnected from underlying asset economics. The solution is particularly effective because it operates through disclosure rather than prohibition, making it politically feasible while still achieving substantial market correction. Historical precedent from China’s toll road sector demonstrates that mandatory disclosure of finite concession terms, even without structural reform, has gradually shifted investor behavior and valuation methodologies.

Implementation requires coordinated action by SEBON, NEPSE, and the Electricity Regulatory Commission. SEBON would need to issue a directive amending to include Schedule for Concession Disclosure Requirements, mandating specific disclosure formats, font sizes, and placement for license expiry information. NEPSE would need to modify its trading systems to display remaining license life as a data field alongside current price and volume, similar to how derivative contracts display expiry dates. The reclassification would require amendments to NEPSE Listing Rules to create a new sector or classification category, potentially “Limited-Life Infrastructure,” with distinct trading, margin, and investment guidelines for institutional investors. 

Implementation timeline could be rapid—90 to 120 days for regulatory amendments, with system modifications at NEPSE requiring an additional 60 to 90 days. The cost to companies is minimal (primarily disclosure formatting), making compliance burden low.

The primary challenge is regulatory capture and political economy resistance. SEBON has historically been accommodating to hydropower promoters, and the securities industry benefits from high trading volumes in hydropower stocks regardless of fundamental value. There is genuine risk that the disclosure requirements, if implemented, would be weak—permitting small-font footnote disclosures rather than prominent dashboard-style presentations that actually influence investor behavior. A second challenge involves definitional complexity: determining the “true” license expiry date when many projects have received extensions, upgrades, or amendments. The Andhi Khola case (BPCL), which received a license extension following its 2072 upgrade from 5.1 MW to 9.4 MW, demonstrates that license life can be extended through capital investment, creating uncertainty about expiry dates that sophisticated parties can exploit. Finally, disclosure alone does not solve the terminal value problem—it merely reveals it—meaning retail investors may still purchase shares at inflated prices while fully aware of the expiry risk, preferring speculation to alternative investments in a market with limited options.

Mandatory Capital Redemption Reserve / Sinking Fund

A regulatory requirement that listed BOOT SPVs retain a specified portion (typically 15% to 25%) of annual Net Distributable Cash Flow into a restricted Capital Redemption Reserve or Sinking Fund, which can only be used to repurchase or redeem public shares at par value (NPR 100) upon license expiry. This transforms perpetual equity into a de facto amortizing instrument by legally obligating companies to accumulate capital for shareholder return.

This solution directly addresses the guaranteed zero terminal value problem by creating a statutory mechanism for capital return. Under current law, shareholders face certain total loss at license expiry with no redemption pathway. The mandatory sinking fund requirement forces companies to systematically repay public capital during the operational phase, ensuring that the par value of shares is returned before the asset transfers to the state. The mechanism is economically equivalent to amortization—each year of operation sees a portion of share value “extinguished” through reserve accumulation rather than through share buybacks at market prices. The solution is particularly powerful because it targets the specific timing mismatch: retail investors provide permanent capital for finite assets, and the sinking fund corrects this by ensuring permanent capital is not required. 

International precedent from project finance structures in the UK and Australia demonstrates that mandatory reserve requirements for infrastructure with state reversion prevent the “zombie equity” scenario where shares become worthless shells after asset transfer.

Implementation requires SEBON to promulgate the Hydropower Capital Redemption Regulations establishing mandatory reserve percentages, calculation methodologies, and restricted use provisions. The regulations should specify: (a) minimum annual contribution based on calculation methodology considering the  remaining license life to ensure full accumulation by expiry; (b) prohibition on using reserve funds for inter-SPV investments, dividends, or debt substitution; (c) trustee oversight through an independent financial institution; and (d) clear waterfall for distribution at license expiry. 

The implementation should be phased: Phase 1 (immediate) requires new issuers to establish reserves from first year of commercial operation; Phase 2 (within 2 years) requires existing listed companies to begin accumulation, with catch-up provisions for late-stage projects. Nepal Rastra Bank would need to issue guidelines for trustee banks on reserve account management and reporting. 

The total cost to the sector is substantial but manageable: approximately NPR 10 to 15 billion annually across 91 listed companies, funded through modest dividend reduction rather than operational impact.

The most significant challenge involves cash flow adequacy for late-stage projects. Companies with fewer than 10 years remaining on licenses cannot accumulate sufficient reserves to return full par value even at 100% cash flow retention. For hydros nearing expiry the accumulation requirement would be a substantial portion of the paid-up capital per year, which may exceed free cash flow after debt service and royalties. 

A second challenge involves promoter resistance and political economy dynamics. Promoters currently benefit from the zero-compensation transfer—they invest construction capital, extract dividends during operation, and exit before expiry with no obligation to return public capital. The mandatory sinking fund fundamentally alters this calculus, reducing promoter net present value and likely triggering industry opposition. 

Sectoral Consolidation Through Mandatory or Incentivized Mergers

A regulatory-driven consolidation of the listed hydropower SPVs into approximately 15 to 20 portfolio companies through mandatory mergers for closely-related projects (common river basins, geographic proximity) and incentivized mergers for unrelated companies through tax benefits, expedited approvals, and simplified regulatory processes. The resulting entities would hold diversified portfolios of projects with staggered license lives, enabling portfolio NAV logic rather than single-asset terminal value collapse.

This solution addresses the structural vulnerability of single-asset SPVs by creating diversified entities where license expiry risk is spread across multiple projects with different handover dates. Under current structure, each listed company faces a binary outcome: either the license is extended (value preserved) or it expires (value destroyed). A diversified portfolio company with 10 projects, each expiring in different decades, provides continuous revenue generation as older projects transfer while newer projects remain operational. The solution transforms the market from 100+ “cliff edge” listed investments into a smaller number of “rolling horizon” infrastructure vehicles. 

International precedent from Australia’s Spark Infrastructure and even Nepal’s Chilime Holding Company model demonstrates that diversified holding structures successfully maintain listed entity viability beyond individual project lifecycles. The consolidation approach is particularly effective for Nepal because it leverages existing market structures—listed entities remain listed, regulatory relationships continue, and investor portfolios merely rebalance—while fundamentally addressing the finite asset problem through portfolio construction.

Implementation requires SEBON to promulgate the Hydropower Capital Redemption Regulations establishing mandatory reserve percentages, calculation methodologies, and restricted use provisions. The regulations should specify: (a) minimum annual contribution based on calculation methodology considering the  remaining license life to ensure full accumulation by expiry; (b) prohibition on using reserve funds for inter-SPV investments, dividends, or debt substitution; (c) trustee oversight through an independent financial institution; and (d) clear waterfall for distribution at license expiry. 

The implementation should be phased: Phase 1 (immediate) requires new issuers to establish reserves from first year of commercial operation; Phase 2 (within 2 years) requires existing listed companies to begin accumulation, with catch-up provisions for late-stage projects. Nepal Rastra Bank would need to issue guidelines for trustee banks on reserve account management and reporting. 

The total cost to the sector is substantial but manageable: approximately NPR 10 to 15 billion annually across 91 listed companies, funded through modest dividend reduction rather than operational impact.

The most significant challenge involves cash flow adequacy for late-stage projects. Companies with fewer than 10 years remaining on licenses cannot accumulate sufficient reserves to return full par value even at 100% cash flow retention. For hydros nearing expiry the accumulation requirement would be a substantial portion of the paid-up capital per year, which may exceed free cash flow after debt service and royalties. 

A second challenge involves promoter resistance and political economy dynamics. Promoters currently benefit from the zero-compensation transfer—they invest construction capital, extract dividends during operation, and exit before expiry with no obligation to return public capital. The mandatory sinking fund fundamentally alters this calculus, reducing promoter net present value and likely triggering industry opposition. 

Sectoral Consolidation Through Mandatory or Incentivized Mergers

A regulatory-driven consolidation of the listed hydropower SPVs into approximately 15 to 20 portfolio companies through mandatory mergers for closely-related projects (common river basins, geographic proximity) and incentivized mergers for unrelated companies through tax benefits, expedited approvals, and simplified regulatory processes. The resulting entities would hold diversified portfolios of projects with staggered license lives, enabling portfolio NAV logic rather than single-asset terminal value collapse.

This solution addresses the structural vulnerability of single-asset SPVs by creating diversified entities where license expiry risk is spread across multiple projects with different handover dates. Under current structure, each listed company faces a binary outcome: either the license is extended (value preserved) or it expires (value destroyed). A diversified portfolio company with 10 projects, each expiring in different decades, provides continuous revenue generation as older projects transfer while newer projects remain operational. The solution transforms the market from 100+ “cliff edge” listed investments into a smaller number of “rolling horizon” infrastructure vehicles. 

International precedent from Australia’s Spark Infrastructure and even Nepal’s Chilime Holding Company model demonstrates that diversified holding structures successfully maintain listed entity viability beyond individual project lifecycles. The consolidation approach is particularly effective for Nepal because it leverages existing market structures—listed entities remain listed, regulatory relationships continue, and investor portfolios merely rebalance—while fundamentally addressing the finite asset problem through portfolio construction.

Implementation requires a two-track approach: mandatory consolidation for projects with obvious synergies (same river system, shared transmission infrastructure, geographic proximity) and incentivized voluntary consolidation for unrelated projects. For mandatory consolidation, SEBON and the MoWERI, ERC should jointly issue the Hydropower Consolidation Directive, identifying clusters of projects suitable for merger based on: (a) common river basin or hydrological system; (b) shared transmission infrastructure; (c) geographic proximity enabling operational synergies; and (d) promoter commonality. The directive would establish timeline for merger completion (24 months), governance framework for merged entities, and dispute resolution mechanisms for minority shareholders. 

For incentivized consolidation, the Ministry of Finance could offer: (a) corporate tax reduction for merged entities meeting diversification thresholds; (b) expedited approval for right share issuances and inter-SPV investments; (c) exemption from recharacterization taxes such as deemed disposals under Income Tax Act, 2058 – like those offered to the BFI sector, (d) NEPSE fee waivers for merger-related transactions. 

The merger implementation should be supervised by  ERC with authority to appoint provisional management and resolve disputes. Implementation timeline is 36 to 48 months for full sector consolidation, with initial mandatory clusters completed within 24 months.

The primary challenge involves valuation disputes and minority shareholder protection. When two listed companies merge, minority shareholders of both entities must receive equivalent value, but project-level valuations for finite-license assets are inherently contentious. The party receiving lower valuation will claim expropriation, potentially triggering litigation that delays consolidation. A second challenge involves promoter incentives—many current promoters built their reputations and extracted fees through single-project structures. Consolidated entities reduce individual promoter influence and may trigger resistance from established figures in the sector. 

Third, Nepal’s legal framework for mandatory mergers is underdeveloped. Drafting enabling regulation would require time and political consensus that may be time taking. 

Fourth, scale economies from consolidation must be genuine—merged entities must achieve cost savings through shared overhead, coordinated maintenance, and optimized dispatch. If merged companies merely replicate existing structures with added management layers, consolidation creates cost rather than value. 

Finally, the concentrated ownership resulting from mergers reduces market liquidity and may create “too-big-to-fail” dynamics that increase systemic risk rather than reducing it.

Conversion into Listed Holding Company Structures

A structural transformation where existing single-asset SPVs become subsidiaries of newly-formed or existing holding companies, with public equity shifted from project-level to corporate-level trading. The listed holding company holds stakes in multiple unlisted operating subsidiaries, each with its own BOOT license, and the consolidated entity survives beyond any single project’s license expiry through dividend income from remaining subsidiaries.

This solution addresses the finite asset problem by aligning listed entity structure with the underlying asset reality. Under current structure, a listed company IS a project—license expiry equals entity death. Under the holding company model, the listed entity is a corporate shell that owns project stakes; when one project transfers, the entity continues because it owns other projects. The solution is structurally identical to sectoral consolidation but operates through market transactions (share swaps, asset sales) rather than regulatory mandates. 

The Chilime Hydropower (CHCL) model—where the 22.1 MW Chilime plant is one asset among a portfolio including Rasuwagadhi (111 MW), Sanjen (14.8 MW), and Madhya Bhotekoshi (102 MW)—provides proof of concept in Nepal’s market. Chilime’s equity value survives its own license expiry because dividends flow from subsidiary stakes. 

The holding company structure is internationally validated: Australian infrastructure trusts, European utilities, and Indian InvITs all operate on this principle. For Nepal, the solution offers the additional benefit of preserving the “perpetual entity” assumption embedded in securities law while making that assumption accurate through portfolio construction.

Implementation operates through two pathways: organic conversion and acquisition-based conversion. For organic conversion, existing listed companies with sufficient capital and project pipelines would establish wholly-owned subsidiaries for new projects, gradually shifting their asset base from single-project to multi-project. SEBON would need to amend listing rules to permit (and eventually require) holding company classification for entities meeting portfolio thresholds. For acquisition-based conversion, smaller SPVs would be acquired by larger holding companies through share-for-share exchanges, with the acquired entity becoming a subsidiary. The Securities Registration and Issuance Regulation would need amendments to create streamlined approval processes for holding company formations and acquisitions. 

Implementation timeline is 24 to 36 months for regulatory framework development, with market-driven conversion proceeding over 5 to 10 years as companies pursue commercial advantages of holding company status.

The fundamental challenge involves the zero-sum nature of holding company creation. When Company A acquires Company B, Company B shareholders become Company A shareholders. No new value is created—only transferred. Promoters of target companies may resist acquisition if they believe their stakes are undervalued, or may demand premium prices that reduce acquisition benefits. A second challenge involves corporate governance complexities. Holding company structures create agency problems between parent management and subsidiary minority shareholders, potential for related-party transactions that disadvantage subsidiaries, and opacity in consolidated financial statements. Nepal’s track record on related-party transaction oversight is poor, and extending this to holding company structures risks amplifying existing governance failures. Third, the solution requires sophisticated financial management capabilities that many current hydropower promoters lack. Managing a portfolio of projects with different hydrological profiles, license expiries, and capital requirements demands financial expertise beyond single-project development. Fourth, the regulatory framework for listed holding companies must address consolidated leverage limits, cross-guarantee prohibitions, and inter-company financial support rules. Finally, there is timing risk: if consolidation occurs slowly and the first BOOT transfers occur before the market has diversified sufficiently, the crisis may unfold before the solution takes effect.

Post-BOOT Continuity Through Operator / Management Contracts

A regulatory framework and contractual mechanism that enables listed SPVs to transition from asset ownership to asset operation upon license expiry, continuing as listed entities through O&M contracts with the government (or its designated entity) rather than through asset ownership. The listed company becomes an O&M service provider earning management fees, preserving a revenue stream and listed status after asset transfer.

This solution addresses the terminal value problem by creating an alternative business model for post-transfer periods. Current law (Clause 6.5.1 of Hydropower Development Policy, 2001) grants the previous operator priority for continuing operations after transfer, but this provision has no regulatory framework or listed company adaptation. The operator contract solution explicitly structures this priority right into a continuing listed entity: when the asset transfers, the entity continues as an O&M contractor earning fees based on capacity, energy generation, or availability. The solution is elegant because it leverages existing legal provisions rather than requiring new legislation, transforms a forced transfer into a negotiated continuation, and preserves both investor capital and listed entity status. 

International precedent from airport and toll road concessions demonstrates that operator models successfully maintain private sector participation after public reversion. The solution is particularly appropriate for Nepal’s context because the private sector has developed operational expertise over 30+ years of BOOT projects—the same entities that built the assets are best positioned to operate them efficiently.

Implementation requires coordinated regulatory action across multiple ministries and agencies. The Ministry of Energy should issue the BOOT Transition Framework Regulations, establishing: (a) standard O&M contract terms for post-transfer operations; (b) fee calculation methodology (capacity-based, energy-based, or availability-based); (c) contract duration (typically 10 to 15 years with renewal options); (d) performance standards and penalty provisions; and (e) dispute resolution mechanisms. SEBON should issue listing rule amendments permitting listed entities to continue trading after asset transfer if O&M contracts are in place, with appropriate disclosure requirements for contract terms and fee projections. The Nepal Electricity Authority should develop standardized O&M procurement processes for transferred assets, with priority to previous operators who built operational familiarity. Implementation should begin with pilot projects: companies with licenses expiring in the next 10 to 15 years should begin government negotiations now, establishing template contracts that other projects can follow. The Hydropower Association should develop industry-standard O&M contract templates to reduce negotiation costs and establish market norms. Implementation timeline is 12 to 18 months for regulatory framework, with company-specific negotiations proceeding over the remaining license life.

The primary challenge involves government capacity and willingness to negotiate. The MoEWRI, NEA and ERC have limited experience with O&M contracting, and government bureaucracy may resist taking on procurement responsibilities that were previously unnecessary (assets transferred automatically). Political risk is significant: successive governments may refuse to honor predecessor commitments, particularly if O&M fees appear excessive in retrospect. A second challenge involves fee adequacy. O&M contracts generate substantially lower margins than asset ownership—the return on equity for a pure O&M business is typically lower than 8% compared to 15% to 20% for ownership operations (along with equity upside). This margin compression reduces shareholder returns and may not preserve par value. Third, the solution creates dependency on government procurement decisions. If the government chooses to operate transferred assets directly rather than contracting the previous operator, the continuity mechanism fails. Fourth, the priority right in Clause 6.5.1 is not exclusive—the government can choose any operator, not necessarily the previous one. Securing actual contracts requires competitive positioning and relationship management, not merely relying on legal priority. Finally, listed entity viability after transfer depends on O&M fee volume. Small projects may not generate sufficient fees to justify listed entity maintenance, leading to delisting and forced shareholder liquidation even with O&M contracts in place.

Strict Ring-Fencing of Inter-SPV Investments

A regulatory framework limiting the amount and conditions under which listed hydropower SPVs can invest retained earnings or raised capital into new subsidiary SPVs, affiliated projects, or related-party ventures. Limits would be expressed as percentages of free cash flow rather than equity, require shareholder approval for investments above thresholds, mandate separate financial reporting for invested entities, and establish clear ring-fencing to prevent cross-subsidization and risk contamination.

This solution addresses the systematic risk migration from inter-SPV capital flows that currently transforms mature, low-risk operating assets into construction-risk funding sources. Under current practice, companies like Arun Valley (AHPC), Ridi Power (RIDI), and Api Power (API) have redirected substantial capital from operational projects into new construction through rights issuances and retained earnings. This practice breaks project-level risk isolation, misleads investors who purchase shares expecting stable dividend yields, and creates opacity that prevents accurate valuation. The strict ring-fencing solution restores the intended function of SPV structures: each listed company should stand on its own project economics, with diversification achieved through holding company structures (requiring investor consent) rather than through cross-investment (which often occurs without full disclosure). 

International precedent from infrastructure finance demonstrates that strict ring-fencing is essential for project finance viability—cross-subsidization between projects violates the risk allocation principles on which lender pricing depends. The solution is particularly urgent in Nepal because inter-SPV investment has become the dominant capital strategy, with over 70% of recent rights issuances indicating “new project investment” as a primary use of funds.

Implementation requires SEBON and NRB joint action: SEBON and ERC through amendments in its regulations establishing inter-SPV investment limits, and NRB through Unified Directive amendments establishing banking limits on cross-SPV exposure. The regulatory framework could specify provisions along the line of: (a) maximum inter-SPV investment of 30% of free cash flow (not paid-up capital) per fiscal year; (b) mandatory special resolution approval for investments exceeding 10% of free cash flow; (c) requirement for independent valuation opinion for invested SPVs; (d) prohibition on guaranteeing subsidiary debt using parent assets; and (e) public disclosure of investment rationale, projected returns, and risk factors.

The most significant challenge involves definitional complexity: distinguishing “inter-SPV investment” from legitimate business development activities. Companies legitimately expand into new projects, and distinguishing growth-oriented investment from risk-diversion requires careful regulatory design. Overly restrictive rules may prevent efficient capital allocation; under-restrictive rules fail to address the core problem. 

Secondly, the solution conflicts with the holding company development pathway that many companies are pursuing. If Chilime (CHCL) is the successful model, preventing other companies from following similar paths may limit future market development. 

Thirdly, companies may structure around limits through off-balance-sheet arrangements, related-party loans that technically fall outside “investment” definitions, or corporate restructurings that create affiliated entities outside regulatory scope. 

Finally, the aggressive rights issuance pattern suggests companies face genuine capital requirements—debt repayment, working capital, construction financing—that may not be satisfiable without inter-SPV fund flows. Simply prohibiting the behavior without addressing underlying capital needs may trigger liquidity crises.

Instrument Conversion Near License Maturity

A regulatory mechanism mandating automatic conversion of public ordinary shares into redeemable preference shares or fixed-yield instruments once remaining license life falls below a specified threshold (typically 10 to 15 years). The converted instruments would carry guaranteed dividends, priority in liquidation, and defined redemption values, gradually removing equity-like risk as terminal risk increases.

This solution addresses the late-stage exposure problem by structurally transforming the investment instrument as license expiry approaches. Under current structure, retail investors hold perpetual ordinary shares regardless of remaining project life—someone purchasing shares in a project with 5 years remaining faces identical instrument risk as someone purchasing shares in a project with 25 years remaining. The equity conversion solution creates a graduated risk reduction: early-stage investors enjoy equity upside and dividend growth; late-stage investors receive preference shares with guaranteed yields and defined redemption values. The mechanism is conceptually similar to amortizing bonds, where principal is systematically returned over the instrument’s life rather than all at maturity. 

International precedent from infrastructure finance in developing markets demonstrates that maturity-contingent instrument structures successfully manage terminal risk—Mexico’s renewable energy certificates and Chile’s mining royalties both incorporate maturity-based transformations. The solution is particularly effective because it operates at the instrument level rather than requiring fundamental restructuring of project economics or corporate governance.

Implementation requires SEBON to issue the Concession Equity Conversion Regulations, establishing: (a) trigger threshold (10 years remaining license life); (b) conversion ratio (par value preservation or slight premium); (c) preference share terms (dividend rate, cumulative vs. non-cumulative, redemption schedule); (d) conversion mechanics (automatic upon regulatory certification of license status); and (e) trading restrictions post-conversion (preference shares may trade on separate market or with price bands). 

The regulations should specify transition provisions: for existing listed companies, conversion would occur on the later of regulatory effective date or the 10-year threshold date. For new listings, conversion would occur automatically at the threshold date regardless of subsequent market conditions. ERC should issue guidelines for institutional investor treatment of converted preference shares, including capital adequacy and concentration limits. 

The conversion mechanism should be tested through pilot implementation with companies having licenses expiring in 2035 to 2038.

The primary challenge involves market acceptance. Preference shares with guaranteed yields and defined redemption values are a fundamentally different investment proposition than ordinary equity. Retail investors accustomed to dividend growth and mainly capital appreciation may resist conversion, particularly if preference share pricing implies significant value reduction. A second challenge involves conversion pricing and valuation disputes. Determining fair conversion ratio requires projecting remaining cash flows, discounting at appropriate rates, and allocating value between ordinary and preference shareholders. Sophisticated parties will dispute these calculations, potentially triggering litigation that delays implementation. Third, the solution may create perverse incentives. If companies know conversion is mandatory at 10 years, they may accelerate value extraction in years 11 through 20, reducing long-term project maintenance or deferring necessary capital expenditure to maximize short-term dividends. The conversion trigger creates a “use it or lose it” dynamic that may harm long-term asset quality. Fourth, the preference share market in Nepal is underdeveloped. Creating a viable secondary market for converted instruments requires similar market makers, and sufficient trading velocity all of which are currently absent. Finally, regulatory complexity is substantial: the conversion mechanism must address multiple edge cases including license extensions, partial transfers, and corporate restructuring during the conversion window.

Replace Equity Issuance by Redeemable Preference Shares or Fixed-Yield Instruments

A structural shift from ordinary equity IPOs and rights issuances toward preference shares, participating debentures, or other fixed-yield instruments for retail investor capital raising. These instruments would carry defined maturity dates (aligned with license life), guaranteed or participating dividends, priority in liquidation, and mandatory redemption at par or premium upon license expiry. The solution transforms the fundamental instrument structure from “perpetual ownership” to “maturity-matched debt-like investment.”

This solution addresses the core instrument mismatch by replacing the inappropriate equity form with a more suitable instrument. Perpetual ordinary shares are appropriate for businesses with indefinite life; finite-concession hydropower assets require instruments with defined maturities and redemption mechanisms. Preference shares and participating debentures provide guaranteed returns, priority liquidation treatment, and maturity features that align investment economics with asset reality. The solution is conceptually simple but structurally transformative: rather than fixing the equity instrument through disclosure or conversion, it replaces equity with more appropriate instruments. International precedent from project finance globally demonstrates that debt instruments (bonds, debentures, project finance loans) are the appropriate form for finite-life infrastructure—equity is used only when residual value exists after debt repayment. 

Nepal’s Hydropower Development Policy, 2001 explicitly mentions mobilization of capital markets through “bonds as well as other financial instruments,” providing policy foundation for the solution. The UK PFI model and Luxembourg infrastructure bonds both demonstrate successful debt issuance for finite-concession assets.

Implementation requires coordinated regulatory action: SEBON must develop preference share and participating debenture frameworks for hydropower issuers; Ministry of Finance should provide tax treatment clarity and waivers (e.g. preference dividends are not tax-deductible, affecting cost of capital); and NEPSE and SEBON must strengthen market for trading fixed-yield instruments. 

The implementation pathway should be: Phase 1 (immediate): Allow preference shares as alternative to ordinary equity for new issuers, with enhanced disclosure requirements and regulatory approval. Phase 2 (within 18 months): Require preference shares for projects with less than 20 years remaining license life. Phase 3 (within 36 months): Permit ordinary equity only for holding companies meeting diversification thresholds; single-asset SPVs must use preference shares or debt instruments.

The most significant challenge involves investor expectations and market culture. Nepal’s retail investor base has been conditioned to expect ordinary equity with dividend growth potential. Preference shares with fixed yields represent a fundamentally different value proposition that may not appeal to the same investor base. If retail investors reject preference shares, companies may face capital-raising difficulties that slow hydropower development. A second challenge involves cost of capital. Preference dividends are not tax-deductible (unlike interest payments), making preference shares more expensive than debt. For projects already facing cost challenges, this increased financing cost may affect viability. Third, the solution may reduce promoter control. Preference shareholders arranged to receive governance rights including board representation and veto powers over certain transactions reduces the promoter control. Promoters accustomed to unfettered control may resist instruments that constrain their autonomy. 

Fourth, secondary market development currently designed for equity trading requires exchange modifications, market maker networks, and price discovery mechanisms. 

Fifth, the solution applies only to new issuances—existing ordinary shares remain outstanding, creating parallel markets and potential regulatory complexity.

Promoter Lock-in Redesign

An extension and restructuring of the existing three-year promoter lock-in period to create graduated lock-in that increases as projects approach license expiry. Early-stage promoters (construction phase) would face shorter lock-ins to facilitate capital recycling; late-stage promoters (operational phase) would face extended lock-ins or prohibited exits to prevent strategic abandonment of aging assets. The redesign aligns promoter incentives with long-term project stewardship rather than early exit.

This solution addresses the promoter exit problem that systematically transfers terminal risk from insiders to retail investors. Under current regulations, promoters hold shares for three years from IPO, then can freely sell regardless of remaining project life. This creates perverse incentives: promoters invest construction capital, de-risk the project, extract maximum value through share sales at market peaks, and exit before the BOOT transfer date leaves retail investors holding doomed equity. The redesigned lock-in creates alignment: promoters who benefit from the project’s operational cash flows must remain invested through those flows, rather than monetizing future cash flows through secondary market sales. 

International precedent from infrastructure finance demonstrates that sponsor retention requirements—extended hold periods, clawback provisions, and minimum ownership thresholds—are essential for preventing adverse selection. The solution is particularly relevant for Nepal because the three-year lock-in has been systematically ganged: promoters time their exits precisely when construction de-risking aligns with market enthusiasm, leaving retail investors as “greater fools” who purchase at peak valuations.

Implementation requires SEBON to amend Rule 38 of the Securities Registration and Issuance Regulation, 2073 to establish graduated lock-in provisions. The framework should specify: (a) minimum promoter holding requirement; (b) prohibition on promoter share sales in final 10 years of license life; (c) graduated lock-in for new issuers based on license maturity at listing; (d) clawback provisions for promoter shares sold at prices exceeding fair value (as determined by independent valuation); and (e) exception for transfers to affiliated entities meeting the same holding thresholds. 

The dual ISN system currently being developed by SEBON would support implementation by tracking promoter share locations separately from public float even when trading under the same parameters. 

The primary challenge involves definition and enforcement of “promoter” status. Complex corporate structures with multiple layers of holding companies, investment vehicles, and individual shareholders make it difficult to identify ultimate beneficial owners and enforce holding requirements. Sophisticated promoters may structure around limits through exempt entities, related-party transactions, indirect transfers, PE/VC route (which generally have relaxed provision relating to lock-ins), or offshore holdings. 

A second challenge involves constitutional and property rights concerns. Forced retention of shares beyond contractually agreed lock-in periods may face legal challenge on takings grounds, though securities regulation typically survives such challenges under police power rationales. 

Third, extended lock-in may reduce project bankability. If promoters cannot exit, they may be unwilling to invest, particularly in long-gestation infrastructure projects. The balance between promoter retention and capital attraction must be carefully calibrated. 

Fourth, the graduated lock-in creates edge cases and transition complexity. Companies with intermediate license remaining (10 to 20 years) face unclear treatment; companies with licenses extended after initial listing face retroactive application concerns. 

Finally, the solution does not address the underlying terminal value problem—promoters remain incentivized to maximize early value extraction even if they cannot sell shares, potentially through excessive dividends, related-party transactions, or underinvestment in maintenance.

Optional Buyback / Redemption Windows Near BOOT Expiry

A regulatory requirement that listed hydropower companies establish mandatory buyback or redemption windows in the final 5 to 10 years of license life, enabling shareholders to sell shares back to the company at prices determined through independent valuation, regulatory formula, or predetermined multiples. The solution creates an organized exit mechanism for late-stage investors rather than forcing them to trade in an illiquid market as expiry approaches.

This solution addresses the terminal liquidity problem by creating structured exit opportunities before license expiry. Under current structure, shareholders have no mechanism to exit positions as license expiry approaches—market liquidity dries up as rational investors refuse to purchase shares with guaranteed zero terminal value, leaving late-stage investors unable to sell without accepting near-zero prices. The buyback window solution creates an alternative: shareholders can require the company to repurchase shares at fair value (determined through independent valuation) during defined windows. This transfers terminal risk from late-stage shareholders back to the company (and ultimately to promoters who control the company), creating incentives for earlier resolution of the expiry problem. 

International precedent from infrastructure finance demonstrates that exit mechanisms—put options, buyback provisions, and forced sale rights—are standard features of finite-life investments. The solution is particularly effective because it creates market discipline: companies anticipating buyback obligations will manage the expiry problem proactively to limit valuation exposure.

Implementation requires SEBON to issue the Hydropower Buyback Regulations, establishing: (a) mandatory buyback windows opening 10 years before license expiry and closing 2 years before expiry; (b) valuation methodology (independent valuer appointment, regulatory formula, or discounted cash flow with specified parameters); (c) funding source requirements (sinking fund, reserve account, or external financing); (d) shareholder election procedures (opt-in for individual sale, opt-out for collective continuation); and (e) company obligations and timelines for share repurchase. The regulations should permit two structural approaches: company-funded buyback (where the SPV uses accumulated reserves or external financing to repurchase shares) and trust-funded buyback (where an independent trust manages buyback using accumulated funds).

The primary challenge involves funding adequacy. Many projects will lack sufficient accumulated reserves to buy back all shares at fair value. If buyback obligations exceed available funds, companies may face liquidity crises or be forced into fire sales of assets at suboptimal prices. A second challenge involves valuation disputes. Determining “fair value” for shares in a company whose asset will transfer for zero compensation is inherently contentious. Shareholders will argue for valuations based on historical prices, dividend yields, or replacement cost; the company will argue for valuations based on remaining cash flows, adjusted for terminal transfer. Independent valuation provides legitimacy but does not eliminate dispute risk. Third, the solution may trigger anticipatory behavior: knowing buyback windows are mandatory, rational investors may refuse to purchase shares except at deep discounts, knowing they can exit at fair value later. This would reduce market liquidity and pricing far in advance of actual buyback windows. Fourth, promoter incentives are misaligned. Promoters who control companies will resist buyback obligations that return capital to shareholders rather than accumulating for their benefit. Enforcement requires regulatory capacity to compel compliance against well-resisted opposition. Fifth, the solution creates potential for selective buyback—companies may repurchase shares from friendly parties at favorable prices while treating hostile shareholders poorly. Anti-avoidance provisions are essential but difficult to draft comprehensively.

Project Bond Market Development

The development of a domestic project bond market where hydropower companies issue debt instruments with maturity dates aligned to license terms, replacing or supplementing equity financing. Bonds would be issued at the project level (single-asset financing) or corporate level (portfolio financing), with statutory protection for bondholders including security interests, covenants, and trustee oversight. The solution aligns capital structure with asset life—debt is repaid from project cash flows before transfer, eliminating equity terminal value risk.

This solution addresses the fundamental asset-liability mismatch by replacing inappropriate perpetual equity with maturity-matched debt. The core problem is financing 30 to 35 year assets with infinite-life equity; the solution is financing finite assets with finite-maturity debt. Project bonds provide known repayment schedules, fixed or floating interest obligations, and secured claims on project cash flows. When the license expires, bondholders have been fully repaid and bear no residual loss. 

The solution is internationally validated: UK PFI projects, Luxembourg infrastructure bonds, and emerging market project finance all demonstrate successful debt issuance for finite-concession assets. The Hydropower Development Policy, 2001 already mentions mobilization of capital through “bonds as well as other financial instruments,” providing policy foundation. For Nepal, the solution offers additional benefits: domestic bond development deepens capital markets, provides institutional investors with appropriate-duration assets, and reduces dependence on bank financing that crowds out other borrowers.

Implementation requires coordinated action across multiple regulatory domains. The MoF and SEBON should issue the Infrastructure Bond Guidelines, establishing: (a) eligibility criteria for hydropower project bonds; (b) approval process and regulatory oversight; (c) disclosure requirements for bond prospectuses; (d) trustee appointment and responsibilities; and (e) default and enforcement mechanisms. NRB should issue guidelines for bank investment in hydropower bonds, including capital adequacy treatment, concentration limits, and valuation methodologies. SEBON should clarify the boundary between securities regulation (for bonds offered to public) and debt financing (for privately placed instruments). 

The initial issuers should be larger, more established projects to establish market credibility. Tax incentives—exemption from capital gains tax for bondholders, deductibility of interest and issuance cost for —would accelerate market development.

The most significant challenge involves market infrastructure. Nepal’s bond market is underdeveloped, with limited trading liquidity, few market makers, and no established yield curves for infrastructure credit. Investors accustomed to equity returns may find bond yields unattractive; issuers accustomed to equity dilution may find covenant requirements burdensome. Building market infrastructure requires coordinated effort over multiple years. A second challenge involves credit quality. Most hydropower projects carry BB-range credit ratings (CARE-NP / ICRA NP), indicating moderate default risk. Investors may demand yields that make bond financing more expensive than equity, reducing project viability. Third, the solution addresses only new financing—existing equity remains outstanding and unaddressed. Fourth, bond covenants may be incompatible with BOOT structures. If bonds require security interests in project assets, but those assets must transfer to the state at license expiry, the security value is inherently limited. Fifth, currency and interest rate risks create additional complexity. Nepal’s bond market operates in NPR with limited hedging instruments; projects with foreign currency debt (from development finance institutions) face additional complexity. Finally, the solution requires sophisticated investor education. Bond investing is fundamentally different from equity investing—investors must understand yield, duration, credit risk, and covenant protection rather than dividend growth and capital appreciation. Building investor sophistication requires time and sustained educational effort.