Current Financing Landscape of LNG-to-Power Projects in Vietnam

May 08, 2025

Highlights

INTRODUCTION

After much anticipation, Power Development Plan No. 8 (“PDP 8”) was issued in May 2023 (as subsequently updated in April 2025).  The plan outlines the country’s energy strategy from 2021 to 2030, with a vision extending to 2050.  In a major legislative development, the National Assembly passed the revised Electricity Law (“New Electricity Law”) in November 2024, which came into effect on February 1, 2025.  Following this, in February 2025, the Ministry of Industry and Trade (“MOIT”) issued Circular 12 (“Circular 12”), introducing a standardized model power purchase agreement (the “Model PPA”) applicable to power projects, including LNG-to-power developments.  The circular also provides detailed guidance on electricity tariff calculation methodologies.  Most recently, in March 2025, the Government issued Decree 56 to implement the New Electricity Law (“Decree 56”).  Those long-awaited legislations replace the existing laws and codify significant policy objectives to modernize and strengthen the energy sector.

The New Electricity Law aims to balance national energy security and financial sustainability, while fostering a transition to green and clean energy and a competitive energy market.  Among these objectives of the New Electricity Law, the first two—national energy security and financial sustainability—are paramount.  Achieving energy security requires ensuring a reliable and sufficient electricity supply by diversifying energy sources, reducing dependence on any single energy type, and strengthening infrastructure to support uninterrupted power delivery.  LNG plays a critical role in Vietnam’s energy mix as it serves as a bridge fuel to enhance energy security while supporting the transition from coal-fired power to renewable energy, thermal power using hydrogen or nuclear power.  Financial sustainability, on the other hand, depends on minimizing reliance on government subsidies, ensuring a balanced cost-revenue structure for both the government and private investors, and fostering a competitive wholesale electricity market where prices reflect actual costs and market dynamics.

In the context of those broad policy objectives, the Government is shifting away from both Government Guarantees and Undertakings (“GGUs”) and the Buil-Operate-Transfer (“BOT”) model for power projects, including LNG-to-power developments, and is now generally unwilling to offer such guarantees or support the BOT structure for these projects.  Historically, large-scale BOT power projects in Vietnam with the capacity of 1,200 MW or more were financed through project finance models.  These projects benefited from secure revenue streams guaranteed by the state-owned off-taker, Electricity of Vietnam (“EVN”), and the Government under GGUs.

In recent years, most projects have been developed as Independent Power Producer (or IPP) projects, reflecting a policy shift driven by several factors.  The Government believes Vietnam’s legal framework has improved significantly since earlier BOT coal-fired power projects, reducing the need for government guarantees.  Additionally, the country’s banking system has matured, enhancing greater foreign currency availability and convertibility for debt servicing.  While foreign currency reserves have recently declined from their peak of over USD 100 billion, the State Bank of Vietnam (“SBV”) asserts that such reserves are sufficient to stabilize the foreign exchange market when needed.  Notably, there is no record of the banking system failing to provide sufficient foreign currency, nor of EVN and MOIT defaulting on tariff and other payments for large-scale BOT projects backed up by GGUs.

As competition in the energy market is approaching, the Model PPA establishes a structured pricing mechanism that applies both prior to and following a project’s participation in the competitive wholesale electricity market.  Prior to a project’s participation in the competitive wholesale electricity market, electricity tariffs remain largely regulated, and PPAs follow fixed or cost-plus pricing structures, ensuring price stability.  Following a project’s participation in the competitive wholesale electricity market, the pricing model shifts to a more dynamic mechanism, allowing EVN to adapt its procurement strategies in response to market conditions.  In a competitive wholesale electricity market, electricity prices are driven by supply and demand, with generators bidding to set real-time prices rather than relying on long-term fixed agreements.  This transition enables EVN to secure electricity from the most cost-effective sources in real time.  The National Power System and Market Operator Company (“NSMO”) continues to play a key role in market operations, including electricity dispatch.

PPAs for LNG-to-power projects are expected to be based on the Model PPA, which, at present, remains relatively basic in structure.  Circular 12 provides only headings for many key provisions and leaves most substantive terms open for negotiation between the parties, aside from the pricing formula. This raises important questions regarding the willingness of EVN or its subsidiaries to accept commercially bankable terms that align with international standards, the extent of their authority to do so, and more broadly, the degree to which the Government is prepared to address bankability concerns in support of project development.

Vietnam’s energy sector is at a pivotal moment, marked by the financial closing of the Nhon Trach 3–4 LNG-to-power Project.  As Vietnam’s first LNG-to-power project, its financing structure provides valuable insights.  A combination of tied and untied export credit agency (“ECA”) lenders and a local lender has provided long-term commercial loans to PV Power, a subsidiary of PetroVietnam.  This milestone presents an opportunity to evaluate financing issues for large-scale LNG-to-power projects, particularly in light of the transition from coal-fired power to LNG and other renewable energy and the challenges of securing financing without GGUs.  Additionally, LNG-to-power projects must compete in the competitive wholesale electricity market, where electricity prices are not fixed, posing a challenge to ensuring stable cash flow.  The financing model for the first LNG-to-power project can be described as ‘hybrid corporate finance’, as it shares similarities with traditional corporate finance while incorporating certain lender requirements akin to project finance.  It offers key lessons on the challenges of project financing in this evolving landscape, particularly in navigating market risks and lender expectations.

BANKABILITY ISSUES

To attract capital for power projects, meet energy demand, and achieve sustainable economic growth, it is essential that Vietnam addresses bankability issues in a way that balances the interests of the Government, EVN, project sponsors, and lenders.  The bankability concerns raised by private investors and international lenders remain largely unresolved.  Several significant challenges affecting project bankability are highlighted below.

No GGUs

Historically, the early BOT coal-fired power projects in Vietnam included GGUs that provide guarantees for 100% payment obligations of Vietnamese counterparties and foreign currency convertibility.  In subsequent BOT coal-fired power projects, the GGUs reduced guarantees for payment obligations and foreign currency convertibility to 30% of project revenues, after deducting local expenses, all calculated in VND.

The Government currently disavows GGUs for power projects, which international lenders accepted for the first LNG-to-power project.  Future LNG-to-power projects may need to proceed on the same basis.  As a result, investors will be compelled to find alternatives that are acceptable to international lenders in the absence of GGUs.  For example, international lenders may seek coverage from a third-party insurer for guarantee of payment obligations and foreign currency convertibility and require a sponsor guarantee of payment obligations.  Sponsor guarantees have recently been utilized in corporate finance transactions for smaller scale solar and wind power projects.  However, sponsors (particularly large State-owned groups like EVN or PetroVietnam) may be reluctant to provide guarantees in large scale power projects.

Contractual Quantity and Minimum Dispatch

Unlike PPAs in BOT coal-fired power projects, current laws do not provide for take or pay undertakings.  Therefore, it is imperative to secure a long-term contractual quantity (“Qc”) to ensure stable revenues.  The Qc mechanism applies only to projects that participate in the competitive wholesale electricity market.  Using a predefined formula, Qc represents an agreed-upon energy output of electricity that the buyer (typically EVN or its subsidiaries) commits to purchase from the power producer and net of the energy output that can be dispatched through the market.  This arrangement offers revenue certainty by guaranteeing payment for a specific capacity, even if the actual dispatch of electricity is lower than the agreed Qc.  Absent take or pay undertakings, international lenders would likely view a long-term Qc that could cover at least the loan tenor favorably.

For LNG-to-power projects, Decree 56 currently fixes a minimum Qc at 65% of the project’s average capacity allocated for a year. This minimum contracted output applies during the loan tenor but is capped at 10 years from the project’s commercial operation date (“COD”).  Additionally, this Qc mechanism is only available to projects that achieve COD before January 1, 2031.  While parties can agree to a higher Qc, EVN and its subsidiaries are unlikely to accept a Qc above 65%.  Both the 10-year period and the January 1, 2031 COD deadline are fixed and not subject to exception.  This regulatory constraint presents several challenges for LNG-to-power projects, potentially necessitating escalation to the Government for resolution.

• First, international lenders may view the 65% Qc level as insufficient and will typically require a higher figure. This is largely due to LNG-to-power projects being less cost-competitive compared to coal or hydropower plants.  As a result, their likelihood of being dispatched in a competitive wholesale electricity market is relatively low, making a higher Qc essential to secure stable revenue, particularly for debt service.
• Second, ECAs can support financing for non-nuclear power with tenors of up to 12 years, which is also a common financing term for large-scale power projects.  Given this long tenor, a Qc guarantee limited to 10 years is unlikely to satisfy lender requirements.  Most lenders would require a repayment buffer and provisions for potential slippage, making it improbable that a full 12-year loan tenor can be supported under the current constraints.
• Third, to qualify for the 65% Qc over a 10-year period, a project must achieve COD before January 1, 2031. In practice, this requires financial close and commencement of construction no later than 2026.  Given the complex and capital-intensive nature of LNG-to-power projects, this timeline poses significant challenges for projects currently in the pipeline.
• Finally, international lenders may also demand a minimum dispatch agreement with the NSMO, particularly where Qc is de facto fixed at 65%. The current legal framework offers no basis for EVN or its subsidiaries to agree to such terms with the NSMO. Without a statutory mandate, neither EVN nor the NSMO is incentivized to enter into these agreements, and resolution would require protracted negotiations.

Pass-through

As a general comment, the absence of a long-term Qc (sufficiently long to cover a reasonable loan tenor) also complicates negotiation of fuel supply agreements.  Without a guarantee to purchase an agreed-upon capacity under the PPA for a long term, borrowers cannot commit to take-or-pay liability under long-term fuel supply agreements.  An LNG-to-power plant cannot rely solely on spot fuel supply agreements because of possible higher costs, and price and supply volatility associated with spot transactions.  Only with a long-term Qc can a corresponding long-term fuel supply agreement be negotiated to ensure project viability.

International lenders will likely require full pass-through of all fuel input costs, including fuel procurement, transportation, storage, regasification, distribution, tolling, and break or cancellation fees specified in fuel-related contracts.  The fuel variable cost provisions in the price formula in Circular 12 do not fully cover these costs.  Specifically, Circular 12 omits references to tolling, break fees, and cancellation fees.  Furthermore, it caps operations and maintenance cost escalation in the tariff at 2.5% annually, rather than aligning with the actual inflation rate.  It is worth noting that Circular 12 does not specifically permit reference to the U.S. Consumer Price Index.

Under the current legal framework, the pass-through of fuel costs is not automatic and requires approval from the Prime Minister.  Both international lenders and project sponsors are expected to demand a full pass-through of fuel input costs.  In practice, the Government may resist full pass-through, particularly for cost components not explicitly addressed in Circular 12.  This issue is further complicated by the prospect of future tariff negotiations between Vietnam and the United States, which could introduce additional, unforeseen cost elements and regulatory uncertainty.

Other Critical Bankability Issues

Circular 12 does not fully resolve bankability challenges related to project finance.  Similarly, the first LNG-to-power project did not address all such concerns.  As a result, international lenders and project sponsors will need to continue working with the Government to establish a more suitable framework for future LNG-to-power projects.

The foreign currency convertibility remains an issue that needs further clarification.  However, this appeared to be a lesser concern for international lenders in the first LNG-to-power project, likely due to improvements in foreign currency availability and convertibility in Vietnam in recent years.  If any government guarantee on convertibility is to be granted, the Public-Private Partnership framework could serve as a reference—where such guarantees are typically limited to 30% of project revenues after deducting local expenses.  In practice, working closely with the converting bank may now hold greater importance in the absence of a GGU for convertibility.

The Model PPA does not address several critical issues, including:

• Force majeure provisions;
• Early termination payments;
• Change in law protections; and
• Governing law and dispute resolution mechanisms.

It is worth noting, however, that the Model PPA has been improved to include lender step-in rights, which is a welcome development.  It now permits the assignment of some or all of the seller’s rights and obligations under the PPA in connection with project financing, without requiring the buyer’s consent.

International lenders will likely require the above listed issues to be resolved before committing to future LNG-to-power projects. How the Government plans to address these concerns in a way that balances the interests of all stakeholders remains to be seen.

LOCAL FINANCING AND INTERCREDITOR ISSUES

An important consideration is whether local loans will play a significant role in financing LNG-to-power projects.  In earlier BOT projects, local banks were considered unable to support large-scale initiatives and, as a result, did not provide financing.  However, the capacity of local banks has steadily improved, culminating in their notable role in Vietnam’s first LNG-to-power project. Today, local banks are not only acting as agents for foreign banks or as converting banks but have also emerged as significant lenders to large-scale projects.

Local banks often demonstrate a more flexible approach to risks and can negotiate and disburse funds more quickly than foreign banks. This flexibility is particularly advantageous in corporate finance models, where local banks can fund initial stages while foreign lenders finalize loan terms.  However, in project finance models involving both local and foreign lenders, the situation may differ as all lender groups typically agree on terms before disbursement. This ensures coordination and at the same time can also delay project implementation.

Balancing the interests of diverse lender groups significantly complicates project financing. While local and international loans may be negotiated independently, all lenders must ultimately agree on the distribution of project assets used as collateral.  Early lenders typically require borrowers to commit to ‘parity,’ ‘pari passu’, and ‘most favored nation’ (MFN) terms, ensuring no other lenders receive more favorable conditions.  However, differing interpretations of these principles often spark disputes, particularly when various lender groups hold different types of security, resulting in a lack of true parity.  Additionally, the choice of governing law is often contentious; foreign lenders generally prefer international legal frameworks, whereas Vietnamese lenders frequently insist on applying Vietnamese law.

Security Structures

Two security structures may be considered for financing large-scale energy projects: the differentiated security structure and the shared pari passu structure.  In both cases, a key challenge arises from legal restrictions that impact foreign lenders.  Specifically, while Vietnamese lenders are permitted to take mortgages over land use rights and assets attached to land, foreign lenders are legally restricted from holding security interests in such assets.

Under a differentiated security structure, different groups of lenders are assigned specific categories of security assets.  For example, foreign lenders may seek exclusive rights over contractual rights, permits, accounts, and receivables, whereas Vietnamese lenders may prioritize land use rights and assets attached to land.  Certain other assets could be shared as common security between both groups.  A key difficulty arises with assets that are not clearly classified as either immovable or movable.  For instance, machinery and equipment are often treated as movable assets, though they could arguably be classified as immovable.  Additionally, integrated insurance policies that cover both immovable and movable assets present further complications, as they make it difficult to allocate security interests for each asset type among different lender groups.

The shared pari passu structure typically includes a mortgage over surplus enforcement proceeds.  In this setup, Vietnamese lenders take security over land use rights and attached assets, while foreign lenders secure an interest in the surplus proceeds resulting from the enforcement of those assets (i.e., after Vietnamese lenders have been paid).  Foreign lenders may also take security over other assets that they are legally permitted to secure.  Upon enforcement, both foreign and Vietnamese lenders share the proceeds from all project assets on a pro rata basis, regardless of the specific security interests held by each group.  In other words, although different lender groups hold security over different types of assets, the proceeds from enforcement are distributed proportionally among them.  While this structure has been adopted in the market, it has not yet been tested in Vietnamese courts, leaving its enforceability in practice uncertain.

Impact of the New Land Law

As a general rule, land use rights may only be mortgaged to Vietnamese banks if land rent has been paid in a lump sum for the entire lease term. Where land rent is paid annually or through other non-lump sum arrangements, only assets attached to the land (not the land use rights themselves) may be mortgaged to Vietnamese banks.

The new Land Law, which came into effect on August 1, 2024, introduces additional restrictions on the one-time payment of land rent for the entire project term.  Such lump-sum payments are now permitted only under a narrowly defined set of circumstances.  Notably, energy projects are excluded from these exceptions—except when located within industrial zones where the zone developer has already paid land rent to the State in full for the entire lease term.  As a consequence, in most cases, land use rights can no longer be mortgaged, even to Vietnamese banks.  Only assets attached to the land may now be mortgaged to Vietnamese banks, thereby introducing further complexities in securing project financing.

Voting Procedures and Enforcement

Voting procedures among lenders during enforcement represent another critical issue that demands careful consideration.

Under a differentiated security structure (where different lender groups hold security over distinct categories of assets), enforcement may either be pursued independently by each group or through a coordinated, unified process among all lender groups.  In either case, the internal voting mechanisms within each group must be clearly defined and mutually agreed upon to ensure effective coordination and avoid delays.

Conversely, in a shared pari passu structure (where all lender groups share security interests over all project assets) voting procedures must involve all lenders collectively.  This necessitates the establishment of a unified voting framework that governs joint decision-making during enforcement.

The capacity of local banks has advanced considerably, allowing them to provide significant financing for large-scale projects.  No longer confined to the roles of agents for foreign lenders or converting banks, Vietnamese banks are now asserting a more prominent position.  This shift has introduced greater complexity to voting rights and security-sharing arrangements, as local banks increasingly seek a more influential role in decision-making and enforcement processes.

ACCOUNT STRUCTURING CONSIDERATIONS

The DSRA and other project accounts may be denominated in USD, VND, or both, depending on the preferences of different lender groups, and may be located domestically or offshore.  The final structure for any offshore accounts is subject to approval by the SBV.

Role and Funding of the DSRA

A DSRA is typically required to provide an added layer of credit protection, ensuring that borrowers have sufficient funds available to meet upcoming debt service obligations.  The method of funding the DSRA carries significant implications for both borrowers and lenders.  International lenders commonly expect borrowers to fund the DSRA from project revenues, which, in the case of Vietnamese borrowers, are generally denominated in VND.  However, these lenders often prefer the DSRA to be maintained in USD.

Vietnam’s foreign exchange control regulations pose challenges in this regard, as VND-denominated revenues cannot be freely converted into or held in USD for extended periods.  This makes it difficult for borrowers to fund a USD-denominated DSRA from VND-based project revenues.  As a more viable alternative, Vietnamese borrowers may fund the DSRA using proceeds from foreign loan disbursements.  This typically occurs during the initial USD loan drawdowns.  While this method also requires specific approval from the SBV, past experience suggests that obtaining such approval is feasible.

Lenders may require the DSRA to be replenished if its balance falls below a specified threshold.  If they do not permit additional loan disbursements for this purpose, borrowers may be compelled to maintain the DSRA in VND.  Replenishing a USD-denominated DSRA using VND can present complications due to foreign exchange restrictions.  In such cases, a VND-denominated DSRA would primarily serve as additional collateral to support debt service obligations.

Other Project Accounts

In addition to the DSRA, lenders typically require the establishment of several other accounts as part of the financing structure.  These may include:

• Loan Accounts – for receiving and disbursing loan proceeds;
• Collection Accounts – for receiving and managing project revenues;
• Insurance Proceeds Accounts – for handling proceeds from insurance claims; and
• Compensation Accounts – for managing proceeds from nationalization, expropriation, compulsory acquisition, or liquidated damages under project agreements.

As to the DSRA, the establishment of any offshore accounts for these purposes is subject to SBV approval, which is not easily obtainable in reality.  Notably, various lender groups may require the borrower to open different accounts of the same type so that each lender group may hold benefits on each group of accounts, resulting in further complication of the negotiation of the account structure for project financing.

CONCLUSION

Vietnam’s LNG-to-power projects face significant financing challenges as they navigate an evolving policy landscape.  The shift away from the BOT mechanism, the withdrawal of government guarantees available under GGUs, and the changing role of local banks have created a complex financing environment.  Additionally, unresolved issues in the Model PPA, fuel supply agreements, and security structures further complicate negotiations with international lenders.

As LNG-to-power projects progress, stronger support from the Government is essential.  Clear policies on a long-term Qc for a sufficient term satisfactory to lenders, fuel cost pass-through, and mechanisms to address exchange rate risks and foreign currency convertibility are crucial for attracting investment and ensuring the timely implementation of these projects.  Without such clarity, delays are likely, as evidenced by the recent setbacks in project developments under PDP8.

Vietnam’s first LNG-to-power project, which successfully adopted a hybrid corporate finance model, demonstrated a potential path forward.  However, this financing structure may not be replicable for other projects that rely on limited or non-recourse project finance.  These projects will require more bankable frameworks to achieve financial close.

Realizing Vietnam’s LNG-to-power potential hinges on the Government’s ability to decisively address legal uncertainties and bankability challenges to unlock both international and domestic financing.  The recent changes introduced under Decree 56 and Circular 12 are likely insufficient on their own.  Additional implementing regulations under the new Electricity Law will be necessary to comprehensively resolve these bankability issues.  If left unaddressed, such gaps could significantly delay the development and financial close of upcoming LNG-to-power projects.

 

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