Philippine grid upgrades could cut system costs by $20bn

Part 2 of 2: Part 1 showed that expanding the grid capacity can reduce renewable curtailment, reshape dispatch, and change regional power flows. Here, we examine what those changes mean for system costs, emissions, and the longer-term investment under different system futures.

Summary

Transmission expansion helps sustain target renewable energy shares through 2050 while cutting overall system costs by $20bn, or 9%, compared with a constrained grid.

The bigger value of transmission comes from the generation it enables. Transmission-enabled scenarios unlock 55–58 GW of renewables, with 45–52 GW coming from solar. Transmission expansion alone cuts cumulative emissions by 115 Mt CO₂e (5%), while combined coal reduction and higher gas prices increase the reduction to 466 Mt CO₂e (20%).

Constrained coal and sustained higher gas prices shift the system further towards renewables. Renewable energy share peaks up to 60% and remains above 50% through 2050, while overall operating costs fall by $12bn.

Understanding current system constraints and how planned infrastructure shapes long-term investment is critical to realising its full system value. Scenario Builder can further test alternative pathways, including different transmission build-outs, demand-side response and non-fossil flexibility.

Transmission can be the backbone of the Philippine energy transition

Part 1 of this analysis showed that transmission expansion is not inherently green so the outcome depends on the capacity already available in the power system. Without enabling policies, greater transfer capacity can also increase the dispatch and trade of existing low-cost coal. The long-term view therefore examines how grid upgrades could reshape power-sector investment and underpin the Philippines’ energy transition.

The two major grid upgrades reflected in the latest Transmission Development Plan of National Grid Corporation of the Philippines (NGCP) come with significant costs. If approved by the Energy Regulatory Commission, NGCP can recover these costs through transmission charges.

But transmission represents only part of the Philippine electricity bill. Generation typically accounts for around 55–60%, compared with roughly 8–10% for transmission. The larger consumer benefit could therefore come from what stronger interconnection enables: greater access to lower-cost generation and more renewable power displacing fuel-based supply.

Over the longer term, the key question is what generation transmission expansion enables and whether it ultimately benefits the Philippine power system.

1. Will new corridors support greater renewable energy (RE) integration and lower system costs, or reinforce dependence on fossil generation? How does this change when gas prices remain higher and coal utilisation is further constrained?
2. Does a more interconnected grid deliver a net advantage once generation mix, fuel costs, and emissions are factored in?

We explore these longer-term effects using Scenario Builder.

Model and scenario set-up

Model set-up

This analysis uses the same three-node (Luzon, Visayas, Mindanao) capacity expansion (CE) set out in Part 1. It compares a base case (250 MW / 420 MW transfer limits) against a Transmission (Tx) upgrade case (880 MW and 900 MW) starting in 2035 up to 2050.

An additional exploratory scenario reduces coal annual utilisation to test how reduced coal use beyond coal moratorium affects long-term system outcomes and policy targets.

We also include a gas price sensitivity: a sustained 10% uplift from 2035 onwards. This tests how exposure to rising gas costs could shape long-term investment. This matters as the Philippines becomes more reliant on imported liquefied natural gas (LNG) while domestic gas reserves decline.

Overall, this analysis looks at four capacity expansion scenarios summarised below:

For full details on the input data, please download our documentation here.

Early boom: a constrained grid leads renewables share but collapses in the long-term

In the near to medium term, constrained transmission favours a more locally self-sufficient buildout from renewables. This results in about 57% of RE share in 2032, around 13 percentage points higher than the transmission-enabled scenarios. With less access to generation from other regions, Luzon and Mindanao add more local renewable capacity, i.e. solar and batteries.

The system generally reaches a 50% RE target by 2040 without a binding constraint, and sustains it through 2050 once transmission is expanded. Greater transfer capacity allows generation to be shared across regions and supports continued renewable growth as demand rises.

The RE share in the no-upgrade scenario eventually falls back towards its 2025 level by 2050. Without sufficient capacity to move surplus renewable power between regions, additional solar becomes harder to integrate. The constrained system then increasingly turns to fossil generation through the 2040s.

Meanwhile, capping coal utilisation does little to accelerate renewable buildout. By 2050, the mix is nearly identical to the Tx upgrade case, with lower coal use largely replaced by gas rather than renewables. A change in gas economics, however, shifts the least-cost pathway towards a cleaner generation mix. This is discussed further in the next section.

A constrained grid can boost local renewables at first, but it limits the system's ability to balance power across regions. Greater interconnection can ease these constraints, while making the reliability of key transmission backbones more important. Where alternative transfer paths are limited, outages or line trips on major corridors can restrict interregional flows and increase the risk of wider supply disruptions.

Recent line tripping incidents in 2026 highlighted the importance of adequate supply and grid resilience in managing unexpected system disruptions.

Higher gas prices shift the transmission-enabled system to more renewables

Across all scenarios, gas provides flexible generation alongside higher solar penetration. Solar remains the dominant source of new capacity, with transmission-enabled scenarios adding around 45–52 GW more than the base case. We learned in Part 1 that adding more solar does not mean all of it can be used without sufficient system flexibility and greater power-sharing capability across the grid.

However, reducing coal use largely shifts generation towards gas rather than additional renewables. When gas becomes more expensive, the least-cost pathway shifts further towards renewables, adding around 12.6 GW of new hydro capacity between 2035 and 2050.

With hydropower assumed to have an 80-year lifetime in the model, its high upfront capital cost can be offset by avoiding fuel expenditure over a much longer operating period. As gas gets pricier, the model increasingly favours upfront investment in zero-fuel-cost hydropower over continued reliance on fuel-based generation.

However, it is important to note that gas, particularly combined-cycle gas, provides baseload supply under power supply agreements (PSAs) in the Philippines. With some existing contracts locked in until 2039, consumers remain exposed to fuel-price volatility unless current PSA pricing structures include effective hedging or other fuel-cost risk mitigation mechanisms.

By contrast, the no-upgrade case relies more heavily on local balancing resources, including 14.2 GW of batteries. With less regional balancing, this scenario invests in more storage to manage higher volumes of locally produced variable generation.

For planners, this highlights the need to evaluate transmission, generation, and non-fossil flexibility options such as storage as part of the same investment strategy. For consumers, this could mean lower exposure to volatile fuel costs, depending on how these savings and reduced risks are reflected in electricity bills.

Grid expansion pays off with $20bn net savings, despite higher upfront investment

Transmission expansion reduces modelled system costs by $20bn, or 9%, relative to the no-upgrade case. Even with a coal utilisation cap and higher gas prices, the combined intervention remains $13bn, or 6%, cheaper. Lower operating expenses (OPEX) offset the higher upfront investment. Emissions also fall in every transmission-enabled scenario. Cumulative emissions fall by 5% with transmission expansion, 15% with a coal cap, and 20% when higher gas prices are also applied.

The OPEX breakdown shows that gas drives much of the change. Transmission expansion cuts gas costs by 20%, from $55bn to $43bn, while coal costs rise by around 6%. Capping coal reverses this relationship: coal costs fall 17%, but gas costs rise 23% as gas substitutes for constrained coal. When higher gas prices are introduced, gas costs fall again by 11%.

The published costs of Luzon-Visayas Bipolar Operation Project and Mindanao-Visayas Interconnection Project Stage is over $1bn, compared with $13bn in modelled system savings. This is roughly ten times the investment amount. This is indicative, not a direct payback estimate. Scenario Builder applies system-wide transmission cost assumptions rather than NGCP’s project-specific costs.

A stronger grid needs a complementary decarbonisation policy

Transmission expansion creates room for more renewable capacity, but fuel economics, resource constraints, and policy still shape what ultimately fills the system. Together, Parts 1 and 2 show that RE delivers greater system value when grid infrastructure expands alongside sufficient flexibility.

But infrastructure is only one part of the transition. Realising the value of higher renewable penetration also depends on the policy environment, existing contracting structures and how investment decisions respond to different market conditions. Long-term pathways are therefore most useful when stress-tested against what can deliver a reliable, sustainable and least-cost power system.

Without sufficient enabling policies and complementary technologies, lower coal use can simply shift dependence towards another fossil fuel like gas. Non-fossil flexibility, including storage and demand-side response, alongside more competitive renewable technologies, will therefore be important.

Offshore wind, up for green energy auction in December 2026, is one example of a future resource that could further change the generation mix and reduce reliance on fossil substitutes. Competitive pricing could strengthen its long-term system value despite higher upfront costs.

These findings can help developers and investors assess the wider system value of transmission projects under different futures. This complements the Green Grids Initiative’s work on accelerating timely and coordinated grid investment across the region.

Build your own scenario

Scenario Builder’s capacity expansion modelling lets users test how different assumptions shape the long-term generation mix, investment needs and system costs. Its updated interface and built-in AMP tool make it easier to apply sensitivities and compare alternative pathways.

Explore how changes in transmission, fuel prices and generation constraints affect long-term power system outcomes in Scenario Builder.

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