Nepal faces a USD 121 billion climate financing gap to meet its NDC 3.0 and National Adaptation Plan commitments, with nearly 90% dependent on conditional international support. The Voluntary Carbon Market (VCM) and Article 6 mechanisms represent critical pathways for bridging this deficit. However, studies identify a series of structural barriers – constitutional vulnerabilities in the fiscal regime, additionality erosion in mature sectors, absence of baseline technical data, and institutional capacity constraints – that must be addressed before Nepal can translate its climate assets into bankable revenue.

The recommendations below are organised across six pillars: Constitutional and Legal Reforms, Fiscal and Tax Reforms, Technical and Institutional Reforms, Strategic Market Protection, Priority Project Development, and Domestic Market and Demand Development. Together, they chart a pathway from Nepal’s current annual VCM revenue potential of USD 3.8–4.6 million toward a scalable, constitutionally sound, and internationally credible carbon market regime.

Core Message: Nepal’s policy successes – near-100% electricity access, >70% EV adoption for private vehicles – have created a “Maturity Paradox” that erodes the additionality required for carbon credits. The recommendations below are designed to navigate this paradox by pivoting toward I-RECs, aggregated public transport projects, captive industrial supply, and a constitutionally durable regulatory framework.

Pillar	Key Thrust
A. Constitutional & Legal	Statutory basis for fiscal levies; I-REC exemption; carbon rights in PPAs; Electricity Bill alignment
B. Fiscal & Tax	Early adopter fee waivers; income tax reclassification; VAT zero-rating for exports
C. Technical & Institutional	Grid Emission Factor gazette; line ministry capacity; domestic VVB development; National Registry
D. Strategic Market Protection	Overselling trap check-valve; LDC graduation pivot strategy
E. Priority Project Development	I-REC monetisation; public EV fleet pivot; captive hydro for industry; charging aggregation
F. Domestic Market & Demand	Carbon-linked banking; corporate demand activation; Article 6.2 government aggregation

Pillar A: Legal Reforms

The Carbon Trading Regulation 2025 (CTR) provides Nepal’s first unified legal umbrella for carbon market activities. However, the fiscal architecture embedded within it – the NRs. 100 per-tonne sales levy, 10% mandatory profit sharing, and 5% credit retention – raises fundamental constitutional questions and creates market distortions that must be resolved to attract investment and ensure legal durability.

Recommendation 1

Reframe Fiscal Levies as Statutory Royalties Under a Parliamentary Act

Problem: The CTR imposes compulsory fiscal obligations – the NRs. 100 per-tonne sales charge and 10% mandatory profit sharing – through delegated regulation rather than a Parliamentary Act. Applying established legal tests of voluntariness, quid pro quo, cost-basis, and general revenue purpose, these charges operate as taxes in substance, not administrative fees. This places them in direct conflict with Articles 60 and 116 of the Constitution of Nepal, which mandate that all taxes and compulsory public revenues be imposed only by law enacted by Parliament.

The 5% mandatory NDC retention constitutes a compulsory appropriation of a tradable private asset, engaging the right to property under Article 25 without explicit legislative authorisation or compensation. Judicial precedent (Raj Bahadur Shah v. Council of Ministers, Bulletin 2068 Poush; Federation of Community Forestry Users Nepal v. National Planning Commission, Decision #7184) supports the position that such levies are ultra vires.

Solution: Enact a Parliamentary Act (or amendment to the Environment Protection Act) that explicitly defines carbon credits as a sovereign resource and establishes the fiscal regime as a statutory royalty for the transfer of carbon rights, grounded in Section 28 of the EPA. This mirrors international practice:

• Indonesia: Law No. 4/2023 (P2SK) and Government Regulation 21/2022 authorise carbon economic value as state fiscal rights under sovereign oversight – enacted by Parliament, not regulation.
• Mexico: General Law on Climate Change (2012), a full statute enacted by Congress, mandates carbon market frameworks and benefit-sharing for REDD+.
• EU: Directive 2003/87/EC requires Member States to enact national laws for ETS auction revenue – Germany’s TEHG Act, UK’s Climate Change Act 2008.
• Canada: Greenhouse Gas Pollution Pricing Act (SC 2018, c. 12) is a federal statute; provincial systems similarly require legislative enactment.

Expected Outcome: Constitutional durability for the fiscal regime, elimination of litigation risk, and a sovereign-grade regulatory signal to international investors and development finance institutions.

Recommendation 2

Explicitly Exempt I-RECs from CTR Fiscal Provisions

Problem: I-RECs (International Renewable Energy Certificates) certify the renewable origin of electricity generation – one certificate per MWh – without quantifying emission reductions. They are fundamentally distinct from carbon credits: I-RECs are attribute certificates measured in MWh; carbon credits are emission reductions measured in tCO₂e. Applying CTR’s fiscal regime (5% retention, NRs. 100/tonne, 10% profit share) to I-RECs would constitute double-taxation of renewable energy exports and deter private investment.

Under the UNFCCC’s production-based accounting framework (IPCC Guidelines for National GHG Inventories), Nepal can legitimately sell I-RECs from its hydropower projects while simultaneously counting the associated emission reductions toward its NDC. The “two-ledger” principle separates Ledger A (physical emissions inventory, where Nepal retains its zero-carbon claim) from Ledger B (market-based consumption claims, where the I-REC buyer obtains Scope 2 reporting rights). Selling I-RECs does not trigger corresponding adjustments under Article 6 of the Paris Agreement.

Revenue at Stake: IPPAN’s MoU with ProClime targets 2,000 MW of generation for I-REC issuance. At current market rates of USD 0.50–1.00 per I-REC, this represents potential annual revenue of USD 4–8 million – value that risks being suppressed if CTR levies apply.

Solution: Issue clarifying guidance or amend CTR to state that I-RECs fall outside the scope of the regulation. If any fiscal treatment is applied, structure it as a modest benefit-sharing or CSR obligation rather than the full carbon credit levy framework.

Expected Outcome: Immediate unlocking of I-REC revenue for Nepal’s 3,600+ MW operational hydropower fleet without triggering corresponding adjustment obligations or suppressing developer returns.

Recommendation 3

Establish Carbon Rights Clarity in Power Purchase Agreements

Problem: A dispute exists between the Nepal Electricity Authority (NEA) and Independent Power Producers (IPPs) regarding ownership of carbon credits and environmental attributes. NEA argues that as the sole off-taker and exporter bearing market and dispatch risk under “Take or Pay” PPA structures, it has a legitimate claim. IPPs assert ownership as primary investors and project developers.

Under the current CTR, carbon credits generated by private projects belong to the developer. However, the prevailing “Take or Pay” PPA model guarantees revenue to IPPs by obligating NEA to pay for contracted electricity regardless of demand, thereby transferring significant operational and market risk to NEA. This shared-risk profile is not reflected in the current carbon rights framework.

Solution: Introduce a split benefit-sharing arrangement:

• “Take or Pay” PPAs: Equitable sharing (e.g., 50–50) of net revenues from carbon credits and I-RECs, reflecting NEA’s absorption of dispatch and market risk.
• “Take and Pay” PPAs: Developer retains exclusive rights to carbon credits, as they bear full market risk.

Operationalise through a dedicated “Environmental Attributes Clause” in standard PPA templates. Globally, PPAs are the primary legal instrument for defining ownership and revenue allocation of environmental attributes.

Recommendation 4

Address Electricity Bill 2080 Compounding Policy Risks

Problem: The proposed Electricity Bill 2080 introduces several structural changes that compound the existing uncertainty for carbon project bankability:

• License Duration: Reduced from up to 50 years to 25 years, shortening the revenue horizon for transmission and generation projects that underpin carbon credit generation.
• 5% Transmission Royalty: A new royalty on wheeling charges adds to the cost structure of projects that rely on grid transmission.
• Mandatory Open Access: May alter tariff structures and revenue predictability for captive hydropower projects targeting industrial consumers.
• BOOT Transfer: Mandatory free transfer of all infrastructure upon license expiry confirms a terminal-value-zero structure that complicates long-term equity investment.

Solution: Ensure that the Electricity Bill 2080’s provisions are calibrated to avoid stacking regulatory costs (transmission royalty + CTR carbon levies + income tax) beyond the threshold at which projects become unbankable. The ERC and MoFE should conduct a joint fiscal impact assessment of the cumulative burden on carbon-eligible projects before the Bill is enacted.

Pillar B: Fiscal and Tax Reforms

The CTR’s fiscal regime – described as the “5%-100Rs-10%-Equity” model – imposes a structured financial burden that, when combined with international certification costs (USD 10,000–15,000 per VVB audit cycle), registry fees, and ongoing monitoring expenses, can render projects with thin operating margins unbankable. For “additional” projects – those that are financially unviable without carbon finance – these upstream deductions can depress the Internal Rate of Return below commercial thresholds. The following tax-side reforms are essential.

Recommendation 5

Codify a Transitory Tiered Fee Exemption Framework

To catalyse market liquidity, facilitate early understanding of the carbon project cycle, and remove entry barriers:

• Early Adopter Exemption: 100% waiver on registration fees (excluding the 5% NDC retention) for projects registered within the first 24 months of the CTR’s operation. This rapidly populates the National Registry and enables proponents to gain practical experience in project development and credit issuance.
• Aggregation Waiver: 50% reduction on fees for projects bundling multiple proponents above a sector-defined threshold. This encourages the Programme of Activities (PoA) structures essential for small-scale projects (micro-hydro, e-rickshaws, charging stations) where individual registration is economically unviable.
• CCUS Full Waiver: Complete fee exemption for Carbon Capture, Utilisation, and Storage projects to prioritise permanently verifiable technological sequestration and incentivise early pipeline development.

Rationale: The current registration fee structure (NRs. 25,000–100,000) is modest, but when combined with international VVB costs, the cumulative burden disproportionately impacts smaller projects. Early waivers build pipeline volume, generating demonstration effects that attract later entrants at standard rates.

Recommendation 6

Reclassify Carbon Revenue Under the Income Tax Act

Problem: Income from carbon credit sales is currently liable to be treated as standard business income under the Income Tax Act 2002 (ITA), creating a fiscal burden that reduces project viability. This is compounded by the CTR’s 10% profit-sharing obligation.

Solution: Amend the ITA to reclassify carbon revenue as “Environmental Service Compensation” or a non-market environmental subsidy. On this basis, extend tax holiday facilities similar to those available for hydroelectricity under Section 11 of the ITA. This approach aligns with the objectives of the Green Hydrogen Policy 2080, which explicitly recommends income tax holidays for clean energy industries.

Expected Outcome: A structural improvement in project IRR that enables marginal projects to cross the bankability threshold, directly supporting the additionality argument for carbon crediting.

Recommendation 7

Codify VAT Treatment of Carbon Credit Transactions

The lack of explicit VAT exemption for intangible environmental assets creates uncertainty regarding the application of VAT on carbon credit transactions under the Value Added Tax Act 1996 (VATA).

• International Trade (Zero-Rated): Define the international transfer of carbon credits (including ITMOs) as an “Export of Goods/Services.” This ensures 0% VAT, allows input tax credit recovery, and aligns with the destination principle of indirect taxation.
• Domestic Trade (Exempt): Classify domestic carbon credit sales as a VAT-exempt schedule item to encourage internal market liquidity and domestic corporate procurement.

Pillar C: Technical and Institutional Reforms

The operational effectiveness of Nepal’s carbon market depends on foundational technical infrastructure – principally, a reliable Grid Emission Factor and capable institutional gatekeepers. Without these, even well-structured projects face rejection by international auditors.

Recommendation 8

Gazette an Official National Grid Emission Factor

Problem: Nepal has no officially published Grid Emission Factor (GEF). Developers are forced to calculate project-specific GEFs or rely on conservative third-party defaults, leading to a wide discrepancy range:

Source / Method	GEF Value (tCO₂/MWh)	Implication
Asian Transport Observatory	0.025	Severely undervalues Nepali credits
Standard Combined Margin (Tool 07)	~0.08	Conservative baseline
LDC Default Simplified Baseline	~0.11	Available only until Nov 2026 graduation

This 4x variance (0.025 to 0.11) directly translates into a 4x variance in credit volumes and revenue. International auditors, including those who validated the Ridi Grouped Project, have flagged the absence of an official GEF as a material challenge, forcing resort to “Harmonized IFI Default Grid Factors” and cross-border weighted averages.

Solution: NEA, ERC, and MoFE must coordinate to publish official seasonal GEF values using UNFCCC Tool 07, incorporating:

• Dry-season import factor: During winter months, Nepal imports coal-heavy electricity from India (~0.727 tCO₂/MWh from India’s CEA data), raising the effective grid factor.
• Marginal vs. average distinction: Clearly specify Operating Margin and Build Margin components.
• Annual update cadence: Dynamic recalculation as the generation mix evolves.

Expected Outcome: A single, high-impact intervention that unlocks methodology applications for EVs and waste-to-energy, maximises credit volumes from exports, and reduces project development cost by eliminating the need for project-specific GEF calculations.

Recommendation 9

Build Institutional Capacity Across Line Ministries

Problem: The CTR’s approval process requires project developers to first secure a recommendation from their relevant sectoral line ministry before approaching MoFE. These ministries often possess limited technical knowledge of carbon market mechanics. The challenge is severely compounded by frequent staff transfers, which erode institutional memory and cause recurring time lags as new officials are re-educated.

Solution: Two immediate interventions:

• Rolling Capacity-Building: Institutionalise regular training programs for line ministry officials on carbon project evaluation, additionality concepts, and CTR procedures – designed to survive staff rotation cycles.
• CTMC Expert Roster: Establish a standing panel of subject-matter experts who can pre-screen applications and advise proponents, improving submission quality and enabling the CTMC/CCMD to process projects within statutory deadlines (67 cumulative days for government processing).

Recommendation 10

Develop Domestic Validation and Verification Capacity

No accredited Validation and Verification Bodies (VVBs) are currently headquartered in Nepal. Projects typically engage international auditors – primarily from India – at costs of USD 10,000–15,000 per cycle. For smaller projects, verification costs can exceed carbon credit revenue, rendering individual registration unviable.

A “chicken-and-egg” constraint exists: local auditors require a critical mass of projects to justify accreditation costs, but projects cannot afford verification without local auditors.

Solution: Prioritise strengthening the DNA’s internal MRV capacity by engaging international experts with deep project-cycle knowledge. In parallel, aggregate projects to the scale that attracts competitive international VVB pricing. In the long term, support the establishment of domestic VVBs listed in the National Registry.

Pillar D: Strategic Market Protection

Nepal faces two existential strategic risks to its carbon market participation: the overselling trap and LDC graduation. Both require proactive, data-driven policy responses.

Recommendation 12

Establish a National “Check-Valve” Against Overselling

Problem: When Nepal sells 100 tCO₂e of carbon credits internationally, a Corresponding Adjustment transfers 95 tCO₂e of reduction claims to the buyer (after 5% NDC retention). If Nepal simultaneously fails to secure the conditional international finance (~90% of its USD 73.74 billion mitigation requirement), the combined effect is catastrophic: unmitigated emissions plus sold mitigation credits mathematically revert Nepal’s reported emissions to Business As Usual levels.

Scenario analysis taking base from LTS document demonstrates this with precision:

Year	WAM Target (MtCO₂e)	BAU (MtCO₂e)	50% Grant Failure	Overselling Trap	Net Zero Status
2030	-5.8	3.9	-0.95	3.9	Missed
2035	2.1	14.6	8.35	14.6	Missed
2040	1.6	18.8	10.2	18.8	Missed
2045	-0.4	24.0	11.8	24.0	FAILED
2050	-5.7	29.5	11.9	29.5	Collapsed

In 2045 – Nepal’s Net Zero target year – the overselling scenario shows reported emissions of 24.0 MtCO₂e, against a target of -0.4 MtCO₂e. This is not a speculative risk; it is the arithmetic consequence of selling mitigation outcomes while failing to secure conditional finance.

Solution: Establish a formal “check-valve” mechanism:

• Periodic Assessment: MoFE conducts biennial national emissions balance reviews, comparing authorised ITMO exports against actual domestic mitigation progress.
• Dynamic Quotas: Set annual ceilings on authorised exports, adjusted based on conditional finance delivery and domestic mitigation achievement.
• I-REC Priority: Encourage I-REC and voluntary credit sales (which do not trigger corresponding adjustments) over Article 6.2 ITMO exports wherever possible.

Recommendation 13

Execute a Proactive LDC Graduation Pivot Strategy

Problem: Nepal ceases to be an LDC on November 24, 2026. This removes the “LDC Shield” of automatic additionality that currently simplifies carbon credit eligibility. The consequences are sector-specific:

• Grid Hydropower: Run-of-river projects face “Common Practice” disqualification – hundreds of MW are commissioned annually by private developers without carbon support, and India export revenues push IRR above hurdle rates.
• Private EVs: 73% market share for new imports constitutes the most extreme “Success Penalty” in the global VCM – these projects cannot credibly claim additionality.
• Micro-Hydro: CDM Methodological Tool 32 restricts automatic eligibility for rural electrification to LDCs and SIDS – Nepal loses this after graduation unless “Special Underdeveloped Zones” are designated.
• Financing Terms: LDC-rate concessional loans (near-zero interest, long grace periods) give way to blended or market-rate financing, raising the WACC for hydropower projects.

Solution: A three-track pivot:

Sector	Current Status	Post-Graduation Path	Instrument
Grid Hydro (RoR)	Eligible (Positive List)	Ineligible (Likely)	I-RECs, Cross-border trade
Grid Hydro (Storage)	Eligible	Eligible (Conditional)	Article 6.2 ITMOs, Green Bonds
Micro-Hydro	Automatic	Conditional	Gold Standard, CSR funds
Private EVs	Eligible	Ineligible	Policy incentives only
Public Transport	Eligible	Eligible (Strong case)	Verra VMR0014, Article 6.2
Clean Cooking	Eligible	Eligible	Gold Standard (SDG premiums)

Strategic Imperative: Projects in sectors losing eligibility (grid hydro, private EVs) should be registered before November 2026 to lock in current additionality treatment during the crediting period.

Pillar E: Priority Project Development

Realizing Nepal’s VCM revenue potential requires targeting specific project types where additionality is defensible, data infrastructure is adequate, and scale is achievable.

Recommendation 14

Prioritise I-REC Monetisation for Operational Hydropower

Nepal’s 3,600+ MW installed hydropower capacity represents a massive environmental attribute base. At least 10 projects totalling 134 MW are already registered in the Evident I-REC registry, with 4 projects having issued over 106,000 I-RECs (including Taksar Hydro at 43,758 MWh and Iwa Khola at 38,807 MWh).

Revenue Potential: At USD 0.70 per I-REC, directing just 25% of Nepal’s 15.6 TWh annual generation toward I-RECs yields approximately USD 2.74 million annually – without triggering corresponding adjustments or requiring additionality demonstrations.

Action: IPPAN should accelerate registration of remaining eligible capacity. The IPPAN–ProClime MoU targeting 2,000 MW provides the institutional framework. NEA should clarify that I-REC issuance from IPP projects does not conflict with PPA obligations.

Recommendation 15

Pivot Carbon Credit Strategy Toward Public and Commercial EV Fleets

Problem: Private passenger EVs (73% of new imports, ~35,378 vehicles on road) are “Common Practice” and fail additionality tests. However, significant financial barriers persist in public transport:

• Capital Costs: Electric buses require substantially higher upfront investment than diesel equivalents.
• Lending Terms: Commercial operators face stricter LTV ratios and shorter loan tenors.
• Infrastructure Gaps: Route-specific charging infrastructure requires coordinated investment.

Critical: Resolve the double-counting conflict between fleet operators and charging networks before registration. Only one entity can claim credit for the same displaced emission. Carbon Rights Transfer Agreements and RFID-based vehicle tagging at chargers are the practical solutions.

Recommendation 16

Develop Captive Hydropower for Industrial Decarbonisation

Nepal’s Open Access Directive 2026 unlocks a high-value carbon pathway: wheeling clean hydropower directly to energy-intensive industries that currently rely on diesel captive generation (~NPR 28/kWh).

Methodology: AM0123 (Renewable energy generation for captive use). International clarifications AM_CLA_0310 and AM_REV_0267 confirm that separate ownership between the IPP and industrial consumer is permitted, provided a PPA with an explicit carbon rights clause exists.

Target Sectors: Cement industry (Hongshi, Arghakhanchi) and steel mills in the Bara-Parsa industrial corridor, where diesel displacement generates indisputable additionality at emission factors far exceeding the national grid average.

Constraint: Projects must size generation to closely match industrial load, ensuring net grid exports remain below 10% to maintain methodology eligibility.

Expected Outcome: Premium carbon credits from a previously inaccessible asset class, combined with competitive energy off-take for Nepal’s industrial sector.

Recommendation 17

Aggregate EV Charging Infrastructure Under VM0038

Nepal’s charging network has expanded to approximately 1,050 DC fast-charging stations (NEA: 373, CG Motors: 290, MAW: 96, Sipradi: 50+, BYD: 50, others: ~200). Individual stations face thin margins under NEA’s regulated tariff cap of 20% profit, making standalone viability challenging.

Carbon Opportunity: Verra’s VM0038 methodology tracks kWh dispensed from OCPP-compliant smart chargers – centralised, tamper-resistant data that auditors can easily verify.

Action: Support charging station operators in establishing Carbon Rights clauses in user Terms of Service, and structure PoA umbrellas that allow new stations to be added without full re-auditing. Mandate OCPP compliance for all publicly funded charging infrastructure.

Pillar F: Domestic Market and Demand Development

While international buyers have historically dominated Nepal’s carbon credit market – Yeti Airlines achieved carbon neutrality in 2019 by purchasing 19,665 CERs from an Indian hydropower project – developing domestic demand is essential for market resilience and value retention.

Recommendation 18

Develop Carbon-Linked Banking Products

Several major Nepali banks – including Nabil Bank, Global IME Bank, and NMB Bank – have adopted the Partnership for Carbon Accounting Financials (PCAF) framework and begun disclosing financed emissions. This creates the institutional foundation for carbon-linked financial products.

Solution: NRB should encourage (and progressively mandate) carbon-linked lending products where borrowers receive preferential interest rates for verified low-carbon or carbon-neutral projects. Banks purchasing domestic carbon credits to offset their financed emissions would create a structured offtake market aligned with the Nepal Green Finance Taxonomy rollout.

Recommendation 19

Activate Domestic Corporate Demand Through Regulatory Incentives

Multinational subsidiaries operating in Nepal face global decarbonisation mandates that can be leveraged:

• Unilever Nepal: Net-zero across value chain by 2039; 99% reduction in CO₂ per tonne of production vs. 2008, but Scope 3 logistics emissions remain challenging.
• Bottlers Nepal (Coca-Cola): Net Zero by 2050; installed high-speed PET line at Balaju improving energy efficiency.
• Soaltee Hotel: 506 kWp solar array displacing 196 kiloliters of diesel annually (995 tCO₂e over 15 years).

Solution: Two regulatory interventions:

• CSR Credit: Amend the Industrial Enterprise Act to allow corporate spending on domestically verified carbon credits to count toward mandatory Corporate Social Responsibility obligations.
• Reporting Mandate: Introduce statutory requirements for large enterprises to report Scope 1, 2, and 3 emissions under NDC monitoring frameworks, compelling businesses to either reduce emissions or purchase offsets.

Recommendation 20

Enable Government Aggregation for Article 6.2 Sales

Article 6.2 Internationally Transferred Mitigation Outcomes (ITMOs) typically trade at USD 15–30 per tonne – significantly higher than voluntary credits at USD 3–5 – because they can be used for national compliance by the purchasing country.

Problem: Thousands of small distributed projects (e.g., Terai e-rickshaws, community micro-hydro) generate individually insignificant credit volumes that private aggregators have no commercial incentive to engage.

Solution: MoFE should act as sovereign aggregator, bundling small-project credits for block sales to buyer nations (e.g., South Korea, Switzerland – the latter already has cooperation frameworks with developing countries like Ghana and Vanuatu). This captures the ITMO premium while ensuring small projects access carbon markets that would otherwise be financially inaccessible.

Precedent: Switzerland’s bilateral cooperation with Ghana and Vanuatu under Article 6.2 demonstrates the operational viability of sovereign-to-sovereign ITMO transactions. Nepal’s CTR framework and DNA structure are already designed to facilitate this pathway.