VIETNAM’S LNG POWER: INSTITUTIONAL BOTTLENECKS AND THE PATH FORWARD

Truong Van Thien – Director, PM Solutions Vietnam

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Abstract

Vietnam targets the commissioning of 22,500 MW of imported LNG-fired power by 2030 under the revised Power Development Plan VIII. This represents a strategic transition to replace coal-fired generation, enhance system flexibility, and support renewable energy integration. Yet after years of negotiations, most private LNG power projects have still failed to reach financial close, despite electricity demand growing at 9–10% per year and dwindling room to expand conventional generation.

The bottleneck lies not in capital or technology — but in an institutional framework not yet mature enough to allocate risk correctly, leaving PPAs unable to meet the bankable standards required by international financial institutions.

This analysis identifies three core issues:

• Three parties — three substantive bottlenecks: The Government/Ministry of Industry and Trade, EVN, and investors each face distinct limitations that combine into a spiral preventing project progress.
• Risk is being allocated to the wrong parties: Multiple risk categories (dispatch, LNG spot, legal change, transmission infrastructure) are being placed in the hands of parties who cannot control them.
• A 2026–2030 roadmap for resolution: A new institutional framework built on phased contracted capacity (Qc), EAF-based capacity payments (CP), long-term LNG SPAs, CAPEX control mechanisms, and post-COD monitoring.

When risk is placed in the hands of those best equipped to manage it, 22,500 MW becomes an achievable — not impossible — target.

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I. Context: Why 22,500 MW of LNG is a Matter of Survival

Vietnam’s power system is under three simultaneous pressures:

• Electricity demand is growing at 9–10% per year, driven primarily by industry and exports.
• Coal and large hydro have reached their ceiling in terms of development potential.
• Net-Zero commitments require rapid phase-down of coal, while renewables have yet to deliver sufficient flexibility.

In this context, LNG is seen as a strategic transition fuel: cleaner than coal, more flexible than conventional baseload, and capable of supporting wind and solar integration.

Yet the gap between planning and implementation is vast: from 1,600 MW of existing LNG capacity (Nhơn Trạch 3 & 4), Vietnam must build an additional 21,000 MW in under four years — a pace unprecedented in the country’s power sector history.

The bottleneck is not in technology or capital — it lies in an institutional framework not yet robust enough for international banks to disburse funds under project finance structures.

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II. Anatomy of the Bottleneck: Three Parties, Three Unsolved Problems

2.1. The Government and Ministry of Industry and Trade: A Legal Framework Not Yet “Bankable”

Although the amended Electricity Law, Decree 56/2025, and Circular 12/2025 have laid an initial foundation, several critical components remain absent:

• No separate capacity payment (CP) mechanism distinct from energy payments. By contrast, South Korea allocates 9.5% of total electricity payments to CP — an essential system cost.
• No Deemed COD mechanism to protect investors against delays caused by transmission infrastructure gaps or administrative procedures.
• Misclassification of integrated LNG terminal costs, distorting electricity tariffs and reducing competitiveness.
• Standard PPA lacks mandatory clauses required under IFC/ADB standards: Lender Step-in Rights, Change in Law provisions, Termination Payment frameworks, and Deemed Dispatch.
• Project-by-project “special mechanism” approach increases transaction costs and prolongs negotiations.

2.2. EVN: Financial Credibility and Offtaker Capacity Under Strain

EVN faces three major pressures:

• Deteriorating financial credibility after years of losses caused by artificially suppressed retail electricity prices.
• Limited capacity to negotiate international PPAs, particularly around complex LNG-linked clauses.
• Transmission infrastructure lagging behind generation development, creating dispatch risks and stranded LNG costs.

EVN cannot absorb the full burden of LNG risk without parallel reform of retail electricity pricing.

2.3. Private Investors: Legitimate Demands and Those Needing Recalibration

Investors have many legitimate demands:

• EAF-based capacity payment (CP)
• Deemed COD
• Change in Law, Step-in Rights
• FX adjustment for USD obligations
• Termination Payment in line with international standards

But some demands require recalibration:

• Full fuel cost pass-through → creates risk of moral hazard.
• Fixed Qc for the entire project life → obstructs the development of a competitive electricity market.
• International arbitration for all disputes → ill-suited to Vietnam’s institutional context.

The key point: Without a long-term LNG SPA, any debate about Qc or pass-through is meaningless. Even JERA (handling 35 MTPA) regards dependence on spot LNG as the “worst-case scenario.”

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III. The Qc–CP–Risk Matrix Framework: A Balanced Structure for All Three Parties

3.1. Phased Contracted Capacity (Qc)

A four-phase Qc structure is proposed:

• Phase 1 (Years 1–10): 75–80% — Ensures DSCR coverage and LNG SPA obligation fulfillment.
• Phase 2 (Years 11–15): 70–75% — Balances interests as the majority of capital has been recovered.
• Phase 3 (Years 16–20): 65% ± 5% — Increases dispatch flexibility.
• Phase 4 (Post Year 20): No fixed Qc — Full participation in the competitive electricity market.

3.2. EAF-Based Capacity Payment (CP)

CP is separated from energy payments and compensates for a plant’s readiness to generate. When a plant achieves its committed Equivalent Availability Factor (EAF) but is not dispatched, EVN pays an availability fee sufficient to cover fixed costs (FC) plus fixed O&M costs (FOMC).

3.3. Risk Allocation Matrix

The core principle: risk to the party best positioned to control it.

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IV. Vietnam’s Particular Context: When Investors Are Already “Named”

Since most LNG power projects already have designated investors, Vietnam cannot apply a Competitive Selection Process (CSP) as practised in some other countries. Instead, four layers of cost control are needed to ensure a fair balance of interests:

• Mandatory technology performance standards
• CAPEX review against international benchmarks
• LNG Procurement Audit
• Periodic monitoring and true-up

Competition must occur at the EPC contractor / CCGT technology supplier and LNG SPA levels, not at the investor level.

4.1. Layer 1 — Mandatory Technology Performance Standards

Minimum mandatory technical requirements must be established for all new LNG power plants — regardless of who the investor is. These include requirements for technology type, heat rate, availability, reliability, and emissions standards.

Enforcement mechanism: Investors must submit an independent technical report confirming that the technology meets standards and is suited to Vietnam’s operating conditions before PPA approval.

4.2. Layer 2 — CAPEX Benchmark Review

A CAPEX reference table should be established for each project component (CCGT plant, LNG terminal (FSRU/onshore), pipeline, auxiliary systems), updated annually against international construction cost indices. Reference: Gas Turbine World Magazine.

Enforcement mechanism: Investors must conduct an open international EPC tender based on evaluation criteria covering the full project lifecycle. EPC tender results must be submitted to the Ministry of Industry and Trade.

Core principle: Competition does not occur at the investor level, but MUST occur at the EPC contractor / CCGT technology supplier selection level.

4.3. Layer 3 — LNG Procurement Audit

For fuel cost pass-through to be justified and accepted by EVN, investors must demonstrate they have procured LNG through an optimized portfolio.

An internationally benchmarked optimal LNG portfolio:

• Tier 1 — Long-term SPAs (10–20 years): 60–70% of ACQ (Annual Contract Quantity). Contracts with reputable strategic partners. Pricing: a combination of oil-indexed (JCC) and hub-indexed (Henry Hub) to reduce volatility. Destination flexibility clauses allowing cargo resale on the spot market when plants are not dispatched.
• Tier 2 — Medium-term (3–5 years): 15–25% of ACQ. JKM-indexed pricing. Flexible adjustment based on A0/NLDC dispatch forecasts.
• Tier 3 — Short-term / spot: ≤15–20% of ACQ. Used solely to cover volume shortfalls — not as a primary supply source. JERA (35 MTPA) calls spot dependency the “worst-case scenario.”

Enforcement mechanism: Open international LNG SPA tendering (mandatory prior to PPA signing).

Synchronizing LNG delivery schedules with dispatch planning: A0/NLDC provides six-month dispatch forecasts to LNG investors → investors adjust delivery schedules accordingly. When actual dispatch deviates from forecast by >15% due to system factors: EVN bears cargo rescheduling fees. When deviation falls within the 15% band: investors absorb it — this is normal operational risk.

4.4. Layer 4 — Annual Performance Monitoring and True-Up

• Annually post-COD: Investors submit a technical and financial report (actual EAF, actual heat rate, actual LNG costs versus SPA). Confirmed by an independent auditor.
• True-up adjustment mechanism (drawing on India’s CERC model): If actual CAPEX at COD is lower than approved CAPEX, the FC component in the PPA is adjusted downward accordingly — protecting electricity consumers.
• LNG cost audit: Classifying the cause of excess costs (EVN non-dispatch versus investor mismanagement). Only costs attributable to EVN non-dispatch qualify for PPA reimbursement.
• Lesson from Pakistan (NEPRA): The absence of post-COD enforcement and monitoring led to inflated invoices and protracted disputes.

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V. International Lessons: What Vietnam Can — and Cannot — Learn

5.1. Thailand — Hin Kong 1,400 MW CCGT: A Viable Private IPP Model

The Hin Kong project (RATCH Group 51%, Gulf Energy 49%) signed a 25-year PPA with EGAT on 12 July 2019 and achieved financial close with a structure of: AIIB A-loan USD 100 million + commercial B-loan USD 289 million. This was the first CCGT in Thailand to be financed through international project finance with gas supply outside PTT — a breakthrough in gas market liberalization. The PPA used Thai law with EGAT as offtaker; O&M was contracted back to EGAT to leverage operational experience.

Lesson: Thai law jurisdiction did not prevent AIIB financing.

5.2. Philippines — Ilijan/MGen/SMGP: A Dual Lesson on Fuel Cost Pass-Through

Failure (2021–2023): San Miguel signed a Power Supply Agreement (PSA) at a fixed price of PHP 4.15/kWh with no fuel pass-through. When LNG prices surged in 2022, San Miguel incurred losses of PHP 15 billion and cancelled the contract.

Success (2024–2025): A 15-year PSA with full fuel cost pass-through through competitive selection (CSP), a vertically integrated model (LNG terminal + power plant). Long-term LNG contract signed with Vitol (0.8 MTPA × 10 years) in March 2025.

Lesson: Fuel cost pass-through only works when backed by a long-term LNG SPA.

5.3. Pakistan (NEPRA) — A Cost Determination Model for Pre-Designated IPPs

Pakistan is a representative case of cost control mechanisms for pre-designated IPPs. NEPRA issues technology-specific upfront tariffs (CCGT, OCGT, etc.) with standard parameters for CAPEX, OPEX, heat rate, and a reasonable rate of return. IPPs may accept the upfront tariff and receive immediate licensing — saving time — or submit a cost-plus petition with actual cost documentation for NEPRA’s project-by-project review.

The Pakistan experience is also a cautionary tale: the absence of post-COD enforcement and monitoring led to inflated invoices, prolonged disputes, and systemic loss of trust. Pakistan’s 2020 Inquiry Report found that most problems stemmed from inaccurate IPP billing and misinterpretation of PPA terms.

Lesson: A technology-based reference tariff (upfront tariff) framework is necessary, but without independent post-COD monitoring it leads to disputes.

5.4. JERA (Japan) — Optimal LNG Procurement Strategy and Lessons for Vietnamese Investors

JERA manages 35 MTPA of LNG with a portfolio of: 25–26 MTPA under long-term contracts + approximately 5 MTPA spot (~16%). JERA’s CEO describes spot LNG dependence as the “worst-case scenario” and is in the process of signing an additional 5.5 MTPA in long-term contracts from the US in preparation for the post-2030 period. FOB base contracts enable logistics control; destination flexibility in the majority of new contracts allows cargo resale on the spot market when plants are not in operation.

Lesson: An optimized LNG portfolio is a prerequisite.

5.5. South Korea — CP Going in the Right Direction, But Requiring Synchronized Retail Price Reform

South Korea’s Cost-Based Pool (CBP) electricity market with a clear CP structure is directionally correct: in 2023, CP accounted for 9.5% of total electricity payments, with 43% of CP allocated to gas-fired generation. However, when LNG prices surged in 2022, KEPCO suffered heavy losses because it was purchasing electricity at high prices while selling at low retail prices — the Government had not adjusted retail tariffs for political reasons. KEPCO accumulated massive debt — not because of CP, but because of the absence of a parallel retail price adjustment mechanism.

Warning for Vietnam: CP is the right mechanism, but it must be accompanied by retail electricity price reform.

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VI. The 2026–2030 Resolution Roadmap

A four-phase roadmap:

• Phase 1 (2026) — Legal completion: Amendment and supplementation of relevant decrees and circulars.
• Phase 2 (2026–2027) — Project preparation: Independent review of EPC/CCGT technology supplier tendering results for each LNG project, confirming CAPEX appropriateness; LNG SPA due diligence, confirming competitive LNG pricing.
• Phase 3 (2027–2028): Mass financial close
• Phase 4 (2028–2030): Operations — monitoring — optimization

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VII. Conditions for Consensus: Getting All Three Parties Aligned

The 22,500 MW challenge cannot be solved if each party views it solely through the lens of its own interests.

For the Government / Ministry of Industry and Trade:

• The current legal framework is not yet fit for purpose — substantive reform is needed, not cosmetic adjustment. In particular, Technology Performance Standards, Capacity Payment (CP), and Deemed COD must be codified uniformly in law.
• CP is an unavoidable system cost that must be reflected in retail electricity pricing through a transparent roadmap. Without synchronized retail price reform = a Vietnamese version of the KEPCO debt trap.
• Vietnam’s particular context — pre-designated investors — requires post-designation cost control mechanisms (CAPEX due diligence, EPC/CCGT technology supplier tendering, LNG SPA auditing) rather than a Competitive Selection Process (CSP).

For EVN:

• EVN’s financial credibility is a critical bottleneck — and that credibility depends on a retail electricity pricing roadmap.
• A bankable PPA requires EVN to accept EAF-based CP, deemed dispatch, and conditional fuel pass-through — these are system obligations, not concessions to investors.
• Transmission infrastructure is EVN’s responsibility — firm schedule commitments and clear compensation mechanisms for delays must be established.

For Private Investors:

• International EPC/CCGT technology supplier tendering is a condition for CAPEX to be recognized in the PPA — not an intrusion into investor decision-making, but a mechanism to introduce competition in lieu of CSP.
• Negotiating long-term LNG SPAs with reputable international partners is a condition for accepting fuel cost pass-through — demonstrating that LNG prices paid are competitive market prices, not opaque negotiated rates.
• A phased Qc structure (75–80% in the first 10 years, declining thereafter) provides more durable investor protection than a rigid Qc fixed for 25 years — because a phased Qc can be codified and replicated, while a rigid Qc is project-specific and vulnerable to challenge as the electricity market evolves.

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VIII. Conclusion

LNG power is not a technical or financial challenge — it is a risk allocation challenge. When risk is placed in the hands of those best positioned to manage it, Vietnam is fully capable of delivering 22,500 MW of LNG power in the 2026–2030 period.

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References and Key Sources

The analyses in this article are based on the following publicly available sources:

Vietnamese Legal Documents:

• Amended Electricity Law No. 58/2024/QH15; Decree 56/2025/ND-CP; Decree 100/2025/ND-CP; Circular 12/2025/TT-BCT
• Revised Power Development Plan VIII (Decision No. 500/QD-TTg dated 15 May 2023 and April 2025 updates)

International Reports and Research:

• IEEFA (2024): South Korea’s Power Trilemma; LNG is not displacing coal in China’s power mix; Contracting debacles underscore long-term LNG risks in the Philippines
• S&P Global Commodity Insights (2025–2026): Vietnam’s new law evokes cautious optimism for gas-to-power; JERA sees vacuum purchasing of spot LNG as worst-case scenario; KOGAS 10-year US LNG deals
• Project Finance International / Linklaters (2022): Hin Kong IPP — Liberalising Thai gas; AIIB Project Disclosure: Hin Kong 1,400 MW CCGT, Thailand
• World Bank Executive Summary Report: LNG Demand Projection, Procurement Strategy and Risk Management for Vietnam
• NEPRA (Pakistan): Tariff Standards and Procedures Rules; Power Policy Guidelines for IPP Tariff Determination
• CERC (India): Terms and Conditions of Tariff Regulations 2024–2029 — CAPEX review and true-up mechanism model
• JERA Press Releases (2022, 2025): LNG Portfolio Strategy; US LNG Agreements with Cheniere, NextDecade, Sempra
• Aboitiz Power / MGen / SMGP Joint Statement (March 2024); Philippines LNG Terminal / Vitol SPA (March 2025)
• YKVN Law (May 2025): Current Financing Landscape of LNG-to-Power Projects in Vietnam
• Columbia University SIPA / CGEP (2025): Asia’s Fragmented Future on LNG Pricing
• IEA: Projected Costs of Generating Electricity 2020; Gas-Fired Power Technology Brief

Specialist Media Sources:

• Vietnam Energy Magazine (April 2026): Legal mechanisms for gas-fired power — An investor’s perspective on the Hải Lăng LNG Power Plant project (T&T Energy)
• The Investor Vietnam (April 2026): Vietnam moves to cement LNG supply chain as power demand surges (PV Gas 25-year LNG contract)
• Freshfields Infrastructure Spotlight Vietnam (September 2025, April 2026)