Solar project economics in three countries

Solar case study: Pricing structure affect returns, but batteries can enhance performance

We analyse the economics of 10 MW solar projects in selected locations in three countries. Project returns are highly sensitive to pricing, but integrating batteries can boost returns by up to nine percentage points, highlighting their growing value for profitability and system reliability. However, PPA design and capital costs remain critical, as a ten percentage point change in either can shift returns by up to 45 percentage points.

Clean energy investment in ASEAN has averaged $72 billion between 2022–2024 which delivers renewable energy capacity additions. However, this should be almost double to $130 billion to keep the global climate goal within reach. Getting on track for these targets would require reducing the cost of capital for renewable projects, while maintaining flows of investment. 

To better understand the dynamics of these markets, we analyse economic viability of solar PV projects across Viet Nam, the Philippines and Indonesia to identify factors that influence project performance, comparing the technical parameters across sites with similar solar potentials (16%–17% capacity factors), capital and operating expenditures, PPA structures and financial assumptions. The result shows PPA price and capital expenditure are dominant factors shaping project profitability.

Differences in PPA pricing resulted in a wide range of Internal Rate of Returns (IRR) values, despite variations in the capital costs of 10 MW solar projects. Our study selected Indonesia’s Sumatra, North Viet Nam, and the Philippines’ Mindanao as representative locations with similar solar capacity factors.

The PPA ceiling prices for solar projects in these locations range from $0.09/kWh in Sumatra – with a reduced rate of $0.049/kWh applied during the 11th–20th contract years – to $0.076/kWh across the Philippines and $0.053/kWh in North Viet Nam.

In comparison, the PPA prices for solar plus battery projects are up to $0.145/kWh in Sumatra – with a reduced rate of $0.079/kWh applied during the 11th–20th contract years – to $0.092/kWh across the Philippines and $0.06/kWh in North Viet Nam.

Capital costs for 10 MW solar projects range from $4.3–$6.4 million, based on IRENA’s study, EREA & DEA report, and Bloomberg assumptions. Integrating batteries will typically add to the capital cost around $0.7 million to over $2 million. 

Among the three countries, the IRR for solar projects under maximum PPA varies. Indonesia records 14%, the Philippines records a range between 11%–16% and Viet Nam 6.1%. Integrating batteries will raise the IRR significantly for Indonesia, to up to 23% and Viet Nam’s IRR to up to 7.3%. Meanwhile, the Philippines’ project returns remain the same. 

PPA design, pricing and capital costs determine whether energy projects can hit a 10% IRR – and which models make the cut. The model shows project returns in the three countries are mostly influenced by PPA terms and capital cost. For example, a ten percentage point change in the new PPA prices can change the IRR to up to 33–45 percentage points; a ten percentage point difference in capital costs can incur a change of 18%–41 percentage points change in IRR.

Indonesia offers the strongest price signal for storage. Its PPA ceiling price for solar plus battery is about two-thirds higher than that of solar, indicating the government’s prioritisation of increasing its storage capacity. In practice, utilities and developers will negotiate the actual PPA price that might be lower than the ceiling price. 

The Philippines takes a different approach. It applies a uniform ceiling price through the Green Energy Auction Reserve (GEAR) prices, which is 21% higher than the ground-mounted system. But while the Philippines shows a comparatively lower ceiling price for solar plus battery systems relative to Viet Nam and Indonesia, this should be interpreted with caution. The Philippines has an incentive structure including import duty and tax exemptions, and a clear framework supporting its operations, which are designed to reduce project-level cost. 

Capital costs also shape project viability. For Viet Nam, the capital cost of 10 MW solar projects would need to fall by about 20 percentage points  to reach a 10 % IRR dropping from $6.1 million to $5.1 million for solar plus battery projects, and $5.5 million to $4.4 million for solar projects. In contrast, the current capital cost for Indonesia and the Philippines has already corresponded to a minimum of 10% IRR.

Viet Nam has a modest PPA pricing compared to the other markets. In recent years, the country has experienced a solar boom, driven by attractive Feed-in-Tariff (FiT). The rapid expansion of solar and transmission bottlenecks resulted in curtailment of solar generations. At the same time, FiT has been revised several times in a downward trend, making solar projects with battery integration the most economically attractive. Currently, the Vietnamese government is incentivising the development of rooftop solar, and focusing on onshore and offshore wind.

Clear and consistent policies are essential to derisk clean-energy investment across the three economies. The demand for clean energy warrants a clear business case for solar buildout in the three economies. They can rely on a fast deployment of solar projects to meet electricity demand from hyperscalers, like data centres.

Yet multiple bottlenecks still slow investment. For example, Viet Nam experienced solar curtailment of up to 40% in 2022, resulting in revenue reductions of up to 40% for affected developers. In the Philippines, several commissioned renewable energy plants remain unable to dispatch due to delayed transmission studies, approvals and interconnection projects. 

Permitting challenges add further delays. In Indonesia and the Philippines, overlapping land rights and multi-layered local approvals can extend timelines by more than a year, reducing the project IRR by 0.6% , and this loss compounds with every subsequent month of postponement.

Currency and equipment price fluctuations also undermine returns. If the local currency weakens against the US dollar, everything bought in dollars, such as solar panels or foreign loans, costs more in local currency, which shrinks the project’s profit margin. 

Policy continuity is equally critical. Viet Nam’s suspension of its Feed-in Tariff scheme left 173 projects, representing approximately $13 billion in investment, awaiting tariff confirmation, effectively immobilising cash flows. Financial policies like credit guarantees could mitigate risks posed by inflation and volatile wholesale rates. 

Streamlined permitting could be the next major tailwind for the three countries. The Philippines has the Energy Virtual One-Stop Shop (EVOSS) is an online platform established under Republic Act No. 11234 (the EVOSS Act of 2019) to streamline and digitalise the permitting process for energy projects in the Philippines.

It allows developers to apply, track, and secure all necessary permits and clearances from multiple government agencies through a single digital portal, instead of filing separate applications to each agency. Strengthening the EVOSS system to integrate the land-related permitting process could shorten project development timelines.

In parallel, the Philippines has also introduced Green Lane Certification, stipulated under Executive Order No. 18, which expedites the approval process for various energy projects and bypasses bureaucratic delays through streamlined inter-agency coordination and local government endorsements.  The certification programme results in 176 projects with green lane access as of December 2024, of which 141 projects are solar, hydropower, wind, geothermal and biomass worth over $70 billion.

Recently, the Philippines has taken important steps of indexation of Green Energy Tariff for GEA projects. Further refinements, such as a fully transparent indexation formula, structured foreign exchange-hedging support, and clearer provisions for foreign-funded projects, would help solidify these reforms and enhance long-term investment certainty. 

Indonesia has taken parallel steps to improve PPA terms. Presidential Regulation No. 112/2022 established ceiling prices for energy projects, depending on the technology and geographic location to control procurement costs and enable faster project contracting through direct selection or appointment by PLN. Complementing this, MEMR Regulation No. 5/2025 provides long-term (up to 30-year) PPA clarity and codifies key provisions such as deemed dispatch and change-in-law clauses. The regulation also stipulates risk allocations between PLN and IPPs, including load risk, transmission risk, currency exchange rate volatility, commissioning delay and permits, effectively reducing uncertainty.

Together, these measures mark a positive step toward improving transparency and contractual stability in Indonesia’s renewable energy sector. 

Further refinements are still possible. Updating the ceiling price methodology to allow limited upward adjustments tied to verifiable cost fluctuations or indexation triggers, ensuring projects remain both competitive and financially sustainable.

Viet Nam is also taking major steps to improve its market’s competitiveness. The Viet Nam’s Electricity Law in February 2025 was the next step to boost the electricity market’s competitiveness. The law stipulates the procedures for the bidding process for power projects within the scope of PDP 8, excluding those developed by state-owned enterprises. These projects include energy sources such as solar, wind, and biomass, as well as electricity generated from green hydrogen and green ammonia. Offshore wind projects for both domestic consumption and electricity export are also being prioritised, allowing foreign investor participation. 

Decree No. 58/2025/ND-CP also incentives for rooftop solar development, storage and research and development in clean energy technologies. This represents the initial stage of resource assessment, forming the foundation for competitive auctions and the selection of winning bidders.

Blended-finance initiatives are already helping to expand access to local-currency financing and improve project bankability. Viet Nam’s ceiling prices also include an escalation rate, partially protecting developers from rising input costs over time. To further strengthen investor confidence, Viet Nam could consider explicit foreign exchange protection mechanisms for long-term PPAs or government-backed hedging and guarantee instruments, alongside clearer rules on payment currency for DPPAs.

The Ministry of Industry and Trade (MOIT) has also introduced location-based tariffs and storage incentives, signalling a shift toward market segmentation and flexibility.

Tariff stability and predictable regulation will be crucial.  Avoiding retroactive tariff adjustments and defining transparent criteria for tariff reviews would preserve the bankability of existing contracts. Moreover, since current PPA practices place curtailment risk largely on producers, with compensation often handled on a case-by-case basis, Viet Nam could enhance investor assurance by introducing standardised deemed dispatch and curtailment compensation provisions, supported by EVN liquidity backing or a central compensation mechanism.