What’s in the PPA?
Puzzles for Southeast Asian modellers and problems for policymakers
Summary
Power purchase agreements (PPAs) have been critical to funding the build out of Southeast Asian power systems over the past thirty years, but their rigid terms have limited system flexibility. In many markets, they will also shape access to funding for new renewables and storage assets. Unfortunately, the rigid terms of fossil fuel PPAs conflict with the dynamic market structures that are emerging as renewables change the way power markets dispatch and price electricity.
Policymakers in Indonesia, Vietnam, and the Philippines are now juggling complex choices for the energy transition that may be hampered by their heavy reliance on PPAs. Both Vietnam and the Philippines are negotiating terms for LNG-fired power plants that will involve long-term commitments for LNG offtake. At the same time, Indonesia is struggling to deploy cost-effective renewables that many consumers want due to legacy PPAs that have resulted in coal lock-in and over-capacity.
One of the biggest challenges for analysts and investors is coping with the information asymmetry from legacy fossil fuel assets financed by PPAs. Most system operators in Southeast Asia provide only limited information about PPA terms. A lack of transparent and granular data makes it difficult to assess whether legacy assets are cost-effective. This poses a competitive problem for renewables investors who are often expected to take more market risk.
More transparent and real-time data will help energy planners understand the cost of legacy PPAs and the potential savings from power market reforms. Energy system modellers have an important role to play in mapping the impact of energy policy. As market participants accept more risk, they will need smarter tools that make it possible to differentiate between theoretical versus actual financial and political risks.
The intricacies of power purchase agreements (PPAs) in the Southeast Asian power sector remain elusive to most, despite being fundamental to the way that many power systems are financed and run. Few understand the fine print or have tried to map how they influence the energy transition within these markets.
Policy questions about the impact of complex PPAs that grant strong legal rights to project sponsors have been hiding in plain sight over the past decade as a number of energy growth markets have begun to suffer from fossil fuel lock-in. Since the launch of the Asian Development Bank’s (ADB’s) Energy Transition Mechanism (ETM) program at the Glasgow COP in 2021 analysts have begun to assess the system cost of PPA-driven inflexibility. Many of the thermal power assets in the pilot markets—Indonesia, the Philippines, and Vietnam—that might be suitable targets for early retirement are insulated from market processes and many newer regulatory initiatives.
For over two decades, consequential public policy decisions regarding Southeast Asian power systems have been embedded in detailed PPAs between state-owned power companies, system operators and independent power project (IPP) sponsors. And yet, these billion-dollar documents are often cloaked in a veil of confidentiality. A generation of bankers, lawyers, and bureaucrats has come and gone, and drift has set in as new system challenges test the rigid mechanism created to protect returns. As a result, investors, policymakers and researchers struggle to find credible sources of information to confirm how the intricate provisions are defined in practice, enforced, or potentially changed as markets evolve.
This is not to say that nothing is known about the project finance disciplines that support Southeast Asia’s PPAs. There are reams of material from credit rating agencies and multilateral development banks about how tightly structured PPAs—and their guarantees—are fundamental to the bankability of power projects and how much-needed international funding will need to be channelled into emerging and developing markets.
More recently, the lack of bankable PPAs for renewables in Southeast Asia has been identified as a barrier to rapid scaling of solar, wind, and storage assets. Governments have responded to the push for renewable and green PPAs with incentive-based solutions that still fall short of what has been offered to fossil fuel developers in the past. This has forced renewables developers to chase smaller pools of high-cost capital that can take more offtake and pricing risks. The tragic irony is that renewables developers are effectively paying the price for PPA-driven system inflexibility due to the legacy of guaranteed offtake commitments to earlier fossil fuel projects.
This is a problem that will be hard to solve until we can accurately map the impact of decades of reliance on fixed PPAs.
The need for transparency
Despite available analysis, what remains absent is government-validated, transparent market-level information that confirms how assets covered by PPAs operate in different power systems. Top-down analysis suggests that much of Southeast Asia’s fossil fuel and large hydro power capacity is locked-in by fixed PPAs. However, market-level data often fails to verify how various PPA terms such as offtake, capacity factors, curtailment, and final tariff payments, function in practice.
As a result, energy system modellers and developers often struggle to verify how system operators prioritise dispatch of units covered by PPAs compared to state-owned or merchant generating assets. This includes new renewable assets that face elevated curtailment risk. While detailed regulations exist, market insiders frequently mention exceptions to these rules that are negotiated rather than codified.
This uncertainty could impose a high cost as regional policymakers weigh decisions about consequential new initiatives—all of which not only depend on the credibility of new PPA structures but also impact old ones. As Southeast Asia's power systems considers ramping down coal via flexible coal operations, introduces costly LNG power assets, and explores virtual PPAs and greater reliance on wholesale markets, there is a growing conflict with the traditional dependence on PPAs.
PPAs bring the money
Understanding the role of power purchase agreements (PPAs) in Southeast Asia requires an appreciation of their structure. PPAs are designed with layered provisions that ensure a power project owner can generate sufficient revenue to repay the project's debt and provide a reasonable return to equity investors.
The financial terms of a PPA are set by an offtake agreement, which specifies the terms for the volume of power to be purchased, the required availability of the asset, and how standard operating risks are allocated between the offtaker and the asset owner. The most advantageous PPAs guarantee offtake or payment as long as the plant meets the specified requirements thereby establishing the project’s credit profile for potential funders.
Sitting behind the offtake terms for the project is the credit quality of the offtaker. In Indonesia and Vietnam, the dominant operators are vertically integrated monopoly state-owned power companies, PLN and EVN. Their PPAs benefit from what is effectively a sovereign guarantee for any commitments made by these power companies. In the Philippines’ unbundled power market, PPAs or power supply agreements (PSAs), are typically between developers and well-established retail distribution companies or government-backed entities that supply under-served areas.
Another important attribute of PPAs is that they establish the role of other financially material suppliers and service providers. Fossil fuel PPAs often have terms that specify the performance obligations of fuel suppliers, along with payments for fuel transportation and maintenance. This is where issues such as fuel cost pass-through and fuel quality issues are specified. Some Indonesian PPAs also contain important terms regarding the provision of public land for power projects.
…And a geopolitical element to power system design
PPAs for coal- and gas-fired power units were critical to the growth of power systems across Southeast Asia from 1990 on, mobilising capital from developed markets for new power assets in key markets including Indonesia, Malaysia, the Philippines, Malaysia, Thailand, and Singapore. Project finance teams from the major global markets with power equipment to sell—the US, Japan, Germany, and France—all worked closely with Asian market regulators, regional export credit agencies, the credit rating agencies, and the largest power operators to create favourable conditions for lenders and a range of local and foreign developers.
The economic impact of international standard PPAs, typically with US dollar repayment obligations, also introduced geo-political issues. As Southeast Asian nations rapidly expanded their power systems to meet economic development goals in the 1990s, the pressure to agree to fixed–and sometimes punishing–terms was not unusual. Following the Asian financial crisis in 1997, FX-short central banks and finance ministries were often forced to prioritise payments to foreign power project sponsors over other high-priority domestic obligations. In the event of disputes over PPA terms, foreign sponsors could seek resolution in courts located in global financial centres.
As Southeast Asia’s economic fortunes have advanced, PPA terms became less favourable to foreign project sponsors. When Indonesia became an investment grade sovereign credit in 2017, the Finance Ministry adopted a more aggressive PPA negotiating stance,requiring project developers to accept more payment risk. Similarly, Vietnam has also pushed developers hard with a stance that imposes more offtake risk and insists on the use of Vietnamese courts for dispute resolution.
Another development affecting transparency over the past decade was the entry of Chinese project sponsors and partners, backed by Chinese banks. These entities have played a major role in the developing hydro and coal-fired generation assets. The willingness of Chinese banks to accept less stringent PPA terms and Chinese sponsors' readiness to offer free equity to local state-owned enterprise (SOE) partners add complexity to analysts' ability to confirm the operating terms of some key baseload assets.
Don’t forget the domestic PPAs…
One important policy strategy for increasing power sector financing in emerging markets is to reduce and manage exposure to hard currency funding terms. With the growing need for clean energy finance, multilateral development banks are supporting local institutions that can offer cost-effective products to manage foreign exchange exposure. A second challenge is to support domestic banks willing to offer loans with longer tenors—8 to 10 years instead of the usual 3 to 5 years—to match power project debt repayment terms.
This trend is visible in the increase of domestic independent power producers (IPPs) with power purchase agreements (PPAs) involving EVN, PLN, and Philippine system operators. Although PLN and EVN do not have PPAs for assets developed on their balance sheets, they have agreements for assets owned by related entities. For instance, PLN’s subsidiaries, PT Indonesia Power and PT Pembangkitan Jawa-Bali (PJB), have assets with PPAs from their parent company. Similarly, EVN has PPAs with plants owned by three unbundled power generation companies, as well as assets from Vinacomin and PetroVietnam, two other state-owned enterprises.
As a rule, domestic IPPs hold PPAs that are less stringent than those for foreign-invested IPPs. The governing law is also local rather than international in the event of disputes. However, when leading domestic banks and development banks are involved, non-performance issues can have a different political flavour because any payment delays affect the liquidity profile of the domestic banking system, rather than bilateral trade and financial relationships.
The net effect of this funding history is a portfolio of fossil fuel power assets across Southeast Asia that relies on PPAs that shape both regulatory norms and power system operations. Often overlooked is that the systems that have grown around these privileged assets vary and reflect specific local market development challenges. In some markets the most pertinent question is how PPAs will be adapted to avoid lock-in for new LNG assets. In others, the question is how more flexible PPA structures can be used to support the development of renewables and storage.
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Indonesia’s rapid power development track record is a case study in how PPAs can facilitate but eventually constrain power system choices. The high excess capacity in PLN’s Jawa-Bali grid—estimated at 40-50%—illustrates the risks of overly-optimistic load growth forecasts coupled with project sponsors who are shielded from market risks by rigid PPA terms. The resulting coal lock-in has left PLN struggling to both finance necessary grid expansion and create targeted incentives for more flexible dispatch and variable renewables.
Policy innovation has also been stymied by difficulties in tracking reliable data in Indonesia’s complicated PPA landscape. The various PPAs, including older USD-denominated agreements, newer post-2017 USD PPAs, Chinese PPAs with free equity for PLN, and PLN's agreements with its independent power producer subsidiaries, have undisclosed terms. Analysts rely on generalised assumptions about capacity factors, reliability, and curtailment that are hard to reconcile with disclosed system operating data and new policy proposals.
Despite repeated efforts to develop bankable PPAs for renewables which offer more realistic tariffs, analysts must still rely on ad hoc efforts to account for the impact of systemic subsidies for coal that complicate efforts to create a more level playing field for renewables. Although the JETP Secretariat’s 2023 Comprehensive Investment and Policy Plan includes a detailed set of recommended policy fixes, there is no timeline for implementation of new tariff structures, system management enhancements, or incentives for ancillary services.
The most important test of how Indonesia will navigate the complexities of PPA-driven coal lock-in is playing out now as PLN establishes its stance on coal flexibility—which involves more flexible dispatch of its coal-fired fleet. The policy dimensions of coal-flex are easy to understand given the pressure on PLN to extract value from its over-sized coal fleet. What is harder to assess is how PLN will manage the cost of retrofitting units or renegotiating PPAs that were not designed to accommodate changes in fundamental operating terms. A cynic might suggest that unless PLN is prepared to adopt very public carrot-and-stick incentives, it’s hard to design a credible scenario where PPA beneficiaries willingly swap guaranteed returns for uncertain cash flows.
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Private finance bankers have long known that Vietnam’s policy stance on hard currency PPAs can be unforgiving. Complex regulations and protracted negotiations have often been the norm, even when projects have been included in PDPs. That’s why the 22GW of new LNG-fired projects included in PDP8 for delivery by 2030 are being watched with interest. How a system that has become increasingly protective of EVN’s financial health will cope with the guarantees for power offtake and LNG purchases that are common in LNG project PPAs will be a revealing test of how these new large-scale projects will be funded. So far, the Vietnamese authorities have shown little indication that they will accept inflexible offtake terms or international arbitration.
The contradiction between the traditional terms that project sponsors prefer, and the system management goals of key Vietnamese government officials is placing pressure on bankers and the various export credit agencies to take a fresh look at Vietnam’s power market dynamics. The market is already evolving rapidly with a wholesale market that is providing real-time price signals and importing low-cost power to enhance system flexibility. That makes it hard to adopt a scenario where all the planned LNG project sponsors can avoid taking some amount of market risk.
The challenge for analysts and system modellers is that it’s difficult to query local policy experts or to gain an informed view on the details that may shape future PPA terms. Most bankers have little incentive to discuss tense negotiations, especially in this promising market. Their safest option is to be relentlessly upbeat and to avoid being the first to break ranks and come to market with less favourable terms that may under-cut a future pipeline of profitable deals.
The net effect of this policy stalemate is that power sector investors in Vietnam may need to stress test models that assume all of Vietnam’s capacity needs will be delivered on-time. It will also be important to track EVN and MOIT’s evolving posture on how demand and curtailment risk will be priced and allocated. Whether it’s ring-fencing of renewables offtake risk or showing new resistance to accepting demand risk, EVN is rapidly developing practical experience with market-based tools that will lead to a new generation of PPAs that leave more risk in the hands of project sponsors and investors.
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Over the past six months, the Philippines has been the most dynamic power market in Southeast Asia, benefitting from a strong domestic banking sector and a rapidly evolving menu of new policy initiatives with the expansion of the wholesale market and the Green Energy Auction Program (GEAP).
One catalyst for the high level of policy activity is the decline of the country’s only domestic gas field in Malampaya, which has resulted in outsized plans for LNG build out in the coming decade. Government plans for investment include up to 8 GW of new gas-fired power capacity, alongside a build up of the supporting LNG infrastructure. Project sponsors have pushed hard for favourable legislation to lock-in a protected position for their proposed capacity, including moves from a trio of some of the country’s largest conglomerates to fund a large LNG terminal. The challenge for policymakers is that this high-cost power must be integrated into an increasingly market-oriented system that is moving toward shorter contracts and fewer guarantees for legacy assets and new entrants. Reliance on LNG imports exposes the Philippines to global gas prices and increases fossil fuel dependency at the risk of long-term lock-in. This could place cost pressure on the system despite the fact that LNG is intended to be a transitional solution.
The rapid pace of new policy moves has changed the arc of recent Philippine power market development and the way power is contracted. Greater reliance on the wholesale market will increase transparency and highlight the impact of fuel cost pass-through on consumer prices. While this is good for project sponsors when supply is tight, it’s less good in a market that is likely to have a growing share of cost-competitive renewables.
One byproduct of this round of policy innovation is that energy system modellers and analysts will have new feedback loops to consider. For example, if the move toward shorter PSAs is accompanied by more grid investment and constructive pricing for storage investments, lower cost renewables could begin to play an influential role in the wholesale pricing. The question is the pace at which this could play out—and how legacy market participants will respond. Some market leaders already have expertise in renewables technology and have stated their interest in storage investments. How quickly this interest could translate into a willingness to finance merchant assets will be an important variable for analysts to evaluate.
In the meantime, it will be important to monitor pending decisions from the Department of Energy (DOE) on the next round of GEAP, reforms from the Energy Regulatory for the improvement of the Competitive Selection Process, NGCP’s pending Transmission Development Plan , and the Natural Gas Bill and Energy Transition Bills pending in the legislature. Across the landscape, significant policy changes are underway that will shape the future of PPAs in the Philippines.
Transition time for PPAs—market participants need more disclosure
Over the next year, billions of dollars in funding are expected to be committed to Southeast Asian power markets based on a new generation of power purchase agreements (PPAs). These PPAs will support both LNG-fired power assets, which are sensitive to price changes, and renewable energy projects, including storage and potentially hydrogen and hybrid technologies. Concurrently, system operators will strive to incorporate more market-based pricing through wholesale markets and competitive tender processes.
Understanding the impact of these new assets requires an analysis of how legacy assets perform and how new ones will operate in dynamic market conditions. Therefore, it's crucial to discuss the costs associated with poor disclosure. Historically, limited transparency and a high reliance on PPAs served capital providers when funding was channelled through sovereign-linked SOEs or international developers. Disputes were often resolved privately, benefiting insiders. However, as the need for diverse capital sources and innovative funding structures grows, enhanced disclosure and transparency will be essential.
In Southeast Asia, developers taking on PPAs with greater price and curtailment risks will face more variable revenue streams, influenced by grid expansion and management. While forward markets and hedging tools can provide some support, reliable markets in the region are still developing. In the meantime, market analysts who can accurately model realistic development scenarios play a crucial role in navigating these challenges.
This blog is part 3 in a series on Southeast Asia’s ETM deals. Part 1 focuses on the evolution of ETM deals, using the ACEN Coal Retirement deal as a case study. Part 2 covers the three things to watch as Asia’s energy transition evolves in 2024.
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