Hydrogen Deployment in Vietnam under Decision 263/QĐ-TTg:

Quantitative Assessment of Carbon Quota Allocation and Cost-Effective Industrial Decarbonisation Pathways (2025–2026 Pilot Phase)

 

February 10, 2026 by VAHC's R&D Hub

 

Abstract

Decision 263/QĐ-TTg approving the total pilot greenhouse gas (GHG) emission quotas for 2025–2026 marks the operationalization of Vietnam’s domestic carbon market. A total of 110 facilities across three energy-intensive sectors—thermal power (34 plants), iron and steel (25 facilities), and cement (51 facilities)—have been allocated 243.08 million tCO₂e for 2025 and 268.39 million tCO₂e for 2026.

This paper provides a quantitative sectoral assessment of quota exposure and evaluates the economic feasibility of hydrogen-based decarbonisation pathways under assumed carbon price ranges of 5–15 USD/tCO₂e. It demonstrates that hydrogen can become cost-neutral—or even cost-reducing—if deployed through co-firing, industrial gas recovery, and carbon-sharing contractual structures.

 

1. Introduction: From Policy Framework to Compliance Obligation

Vietnam’s carbon market has transitioned from regulatory preparation to quota-based compliance. The allocation of 243.08 million tCO₂e (2025) and 268.39 million tCO₂e (2026) establishes a quantifiable emissions ceiling for large emitters.

The pilot phase does not yet impose full auctioning. However, the establishment of facility-level caps introduces:

• A measurable compliance obligation

• A future exposure to carbon pricing

• A new financial risk variable in industrial cost structures

Under conservative modeling assumptions, even a modest domestic carbon price materially affects high-emission facilities.

 

2. Sectoral Emissions Structure and Exposure Analysis

2.1 Thermal Power (34 Plants)

Thermal power constitutes the largest share of allocated quotas. Several plants exceed 10 million tCO₂e annually.

Assuming:

• Coal-fired emission factor: 0.90–1.05 tCO₂/MWh

• Average plant capacity: 1,200–2,400 MW

• Load factor: 65–75%

Estimated annual emissions per large plant:
8–15 million tCO₂e.

Carbon Cost Exposure

For a plant emitting 12 million tCO₂e:

Even if only 10% exceeds quota, exposure ranges between 6–18 million USD annually.

 

2.2 Iron and Steel (25 Facilities)

Large integrated steel complexes (e.g., Formosa Ha Tinh, Hoa Phat Dung Quat) emit:

11–15 million tCO₂e annually.

Blast furnace–basic oxygen furnace (BF-BOF) route:

• 1.8–2.2 tCO₂ per ton of crude steel.

For a 6 million ton/year facility:

Emissions ≈ 10.8–13.2 million tCO₂e.

Carbon Cost Exposure

At 10 USD/tCO₂e:

≈ 110–130 million USD per year.

Steel exporters to the EU also face CBAM liabilities.
EU ETS price (2025 reference): ~70–90 EUR/tCO₂e.

Even partial hydrogen substitution can materially reduce CBAM-adjusted costs.

 

2.3 Cement (51 Facilities)

Cement emissions consist of:

• 60–65% process emissions (calcination)

• 35–40% fuel combustion

Average emission intensity:

0.75–0.85 tCO₂ per ton cement.

For a 5 million ton/year plant:

≈ 3.75–4.25 million tCO₂e annually.

At 10 USD/tCO₂e:

≈ 37–42 million USD exposure.

 

3. Hydrogen Decarbonisation Pathways: Quantitative Impact

3.1 Hydrogen Co-Firing in Gas Turbines

Hydrogen blending ratio: 5–20%.

Emission reduction potential:

• 5% blend → ~4–5% emission reduction

• 20% blend → ~15–18% emission reduction

For a 12 million tCO₂ plant:

Carbon savings at 10 USD/tCO₂e:

6–20 million USD annually.

If hydrogen LCOH = 3.5–5 USD/kg
and substitution avoids equivalent natural gas at 8–10 USD/MMBtu,
carbon savings can partially offset fuel premium.

 

3.2 Hydrogen in Direct Reduced Iron (DRI)

Hydrogen-based DRI reduces emissions by:

80–95% compared to coal-based reduction.

Per ton of steel:

Emission reduction ≈ 1.5–1.7 tCO₂.

For 1 million ton green steel:

1.5–1.7 million tCO₂ avoided.

At 10 USD/tCO₂e:

15–17 million USD domestic carbon benefit.

Under CBAM (70 EUR/tCO₂e equivalent):

Potential avoidance ≈ 105–120 million EUR.

This significantly alters export competitiveness.

 

3.3 Industrial Gas Recovery (Blast Furnace Gas)

Typical BFG composition:

• 18–22% CO

• 3–5% H₂

• 20–25% CO₂

PSA hydrogen recovery can produce:

5,000–15,000 Nm³/h hydrogen per large complex.

Production cost significantly lower than green hydrogen (often <2 USD/kg).

This pathway yields immediate carbon intensity reduction at lower cost.

 

4. Financial Structuring to Avoid Net Cost Increase

4.1 Carbon-Sharing Model

Assume:

Plant reduces 1 million tCO₂ annually.
Carbon price = 10 USD/tCO₂e.

Gross carbon benefit = 10 million USD.

Hydrogen provider share = 40%.

Plant retains 6 million USD benefit.

If hydrogen cost premium ≤ 6 million USD:

Net production cost does not increase.

 

4.2 ESCO Model

Hydrogen provider finances:

• Electrolyser

• Storage

• Integration systems

Repayment derived from:

• Fuel savings

• Carbon savings

• International carbon credit revenue

CAPEX burden for industrial host = near zero.

 

4.3 International Credit Integration

Article 6 or JCM credits:

Possible valuation range: 20–40 USD/tCO₂.

If 500,000 tCO₂ certified internationally:

Revenue = 10–20 million USD.

This can materially improve IRR from <8% to >15% in pilot projects.

 

5. Comparative Cost Threshold Analysis

Hydrogen becomes economically rational if:

Hydrogen Cost per tCO₂ Avoided
≤ Carbon Cost + CBAM Exposure + Green Premium.

Example (steel export case):

• Carbon price (domestic): 10 USD

• CBAM implicit cost: 70 USD

• Green premium: 20 USD

Total economic leverage: ≈100 USD/tCO₂.

If hydrogen reduces 1.5 tCO₂ per ton steel:

Economic room ≈150 USD/ton steel.

This creates feasible margin space for hydrogen substitution.

 

6. Strategic Implications for the 2025–2026 Pilot Phase

1. Immediate full hydrogen replacement is economically unrealistic.

2. Incremental blending (5–20%) is cost-defensible.

3. Steel sector offers highest marginal benefit.

4. Industrial gas recovery provides lowest-cost entry point.

5. Financial engineering is as important as technological deployment.

 

7. Conclusion

Decision 263/QĐ-TTg operationalizes Vietnam’s carbon market and transforms carbon from an environmental externality into a financial liability.

With total quotas of:

• 243.08 million tCO₂e (2025)

• 268.39 million tCO₂e (2026)

Vietnam has entered a compliance-driven decarbonisation phase.

Hydrogen deployment during this pilot period is economically viable only if:

• It targets high-emission clusters,

• It integrates carbon pricing into project economics,

• It leverages blended finance and international credits,

• It adopts cost-sharing contractual structures.

 

Hydrogen in Vietnam is therefore not a purely technological transition.
It is a financial optimization strategy under carbon constraint.