Written by Rowena Cristina L. Guevara. Undersecretary at the Department of Energy Philippines

From 2023 to 2025, the Philippine power system experienced a period of sustained pressure. Electricity demand continued to rise, with Luzon peak demand exceeding 14,000 MW for the first time. Yellow and Red Alerts occurred in all three grids during the dry months of each year. Rising demand and tight supply margins would be expected to drive electricity prices higher. However, wholesale electricity prices moved in the opposite direction. In Luzon, the Load-Weighted Average Price (LWAP), the wholesale rate that distribution utilities and grid-connected end users pay, dropped from roughly USD 105 per MWh in 2023 to roughly USD 65 in 2025, a 39 per cent decline. Visayas prices fell by about 31 per cent over the same period, while Mindanao saw a smaller decrease.

This article examines the drivers behind this outcome. It focuses on the role of renewable energy deployment in the Philippine power system between 2023 and 2025 and how changes in the generation mix influenced electricity prices, market dynamics, and exposure to imported fuel costs.

A consistent decline across price measures

Electricity prices fell across most parts of the Philippine power market between 2023 and 2025, even as the system faced sustained operational pressure. The decline was not confined to one segment of the market.

In the Visayas, LWAP fell from roughly USD 119 per MWh in 2023 to USD 82 in 2025. Mindanao saw a smaller change, easing from USD 81 per MWh to USD 78, reflecting a generation mix that already differs from the rest of the country.

Spot prices moved harder than the weighted average. The Independent Electricity Market Operator of the Philippines (IEMOP) recorded Wholesale Electricity Spot Market (WESM) prices averaging around USD 71 per MWh in the first half of 2025, down 26 per cent from the year before, the lowest reading since 2020. Across January to November 2025, the WESM effective price averaged about USD 75. The market operator linked the move to better supply margins, more renewable energy capacity, and improved transmission.

End consumers also saw lower prices in their electricity bills.  Utility generation charges, which combine costs from Power Supply Agreements (PSAs), Independent Power Producers (IPPs), and WESM purchases, came down repeatedly through 2025. Meralco, the country’s largest distribution utility, announced rate reductions in May, June, August, September, and December, citing different combinations of lower WESM, IPP, and PSA charges each month. Late in the year, PSAs accounted for about 73 percent of Meralco’s energy purchases, IPPs another 21 percent, and WESM only 6. The decline reached consumers mainly through the contracted supply portion of their bills, with WESM as a smaller, faster-moving piece.

Across spot, weighted-average, and end-user measures, prices moved in the same direction over the period.

What drove the price decline

Most of the price drop comes down to changes in capacity and the generation mix.

In Luzon, renewable energy capacity went from 5,457 MW in 2023 to 6,854 MW in 2025, a 25.6 per cent increase. Coal sat at 8,637 MW the whole time. Visayas added 321 MW of renewable energy; Mindanao added 68 MW. Nationally, renewables now account for roughly a quarter of gross generation capacity: hydro (11.2 per cent), geothermal (8.0 per cent) , solar (3.8 per cent), biomass and wind (1 per cent each).

Three things connect that capacity growth to lower prices.

First is the spot market. Variable RE plants, including those holding Feed-in Tariff and Green Energy Auction Program contracts, bid into WESM at zero. They clear first under the merit order. The next plant in the queue, almost always coal or gas, sets the marginal price. Add more zero-bid capacity, and that marginal price has more room to fall.

Second is contracted supply. Distribution utilities buy most of their generation through long-term Power Supply Agreements under Competitive Selection Process, rather than the spot market. RE projects awarded under the Green Energy Auction Program (GEAP) enter those portfolios at fixed prices set in competitive auctions. Once dispatched, a portion of the utility procurement cost stops moving with fuel markets entirely. The Department of Energy plans another 25 GW of GEAP capacity through 2035, and GEA-4 alone awarded 10.2 GW in November 2025.

Third is fuel exposure. Unlike coal and gas plants, renewables do not depend on imported fuel. That means less exposure to global fuel prices and exchange rate swings. According to Meralco, 97 to 99 per cent of its IPP costs and 48 to 57 per cent of its PSA costs are denominated in US dollars, exposed to coal prices, LNG prices, and peso depreciation. Solar, wind, hydro, geothermal: none of that. Each megawatt of renewable capacity displaces a slice of the generation cost that used to ride those volatile channels.

These mechanisms work together rather than separately. Lower spot prices reduce the volatility of the WESM-priced portion of utility supply. Auction prices set benchmarks that the next round of contracting takes seriously. A more diversified mix dilutes overall fuel cost exposure. Other things moved during the period, too. The peso strengthened against the dollar at points in 2025, and global fuel prices eased. But the variable that changed the most was the mix.

Renewable energy during stressed conditions

What renewables did under stress varied by grid and by hour. Across all grids, the key constraint is that renewable output does not align with peak stress hours.

In Luzon, geothermal stayed steady, between 472 and 521 MWh, through each of the three recorded peak events. Solar contributed 5,500 to 5,800 MWh on each peak day, all of it concentrated around midday. Hydro was the variable element year on year, ranging from below 3,000 MWh in 2024 to over 12,000 MWh in 2023. The most striking single example is 05 March 2025, when hydro alone supplied 15,756 MWh during a Yellow Alert Day. Combined with stable geothermal and a strong midday solar contribution, that mix held the alert to a single hour. On most alert days, total renewable energy supplied 1,000 to 1,100 MW during alert hours, enough to soften them but not to head off prolonged Yellow or Red Alerts on the worst evenings.

The trajectory of renewable energy share at the recorded peaks is its own observation. Even with all that capacity growth, the renewable energy share in Luzon peaks fell from 12.79 per cent in 2023 to 10.65 percent in 2025. The reason is straightforward: demand grew fastest in the evening, and the new renewable energy coming online has been mostly solar, which doesn’t dispatch in the evening. Capacity growth doesn’t translate to peak-hour relief if the new MegaWatts run at the wrong times.

The Visayas grid had the strongest relative renewable energy contribution under stress. Geothermal anchored everything, supplying between 200 and 672 MWh. Solar pushed the renewable energy share to 31 to 44 per cent of dispatched generation during midday alerts. Even after dark, when solar was gone, geothermal and occasional wind held renewable energy at 25 to 41 percent.

Mindanao runs largely on hydro. During alerts and peaks, hydro contributed between 350 and over 660 MWh, with solar adding only a small share. Renewable energy share barely moved, from 30.44 per cent to 31.08 per cent across the three peak years.

Climate variables show up in the data as a structural factor, not a one-off. In Luzon, peak demand correlates more strongly with the Heat Index than with raw temperature: 0.89 against 0.83 across the three peaks. The 14,016 MW Luzon record on 24 April 2024 came on a day with a Heat Index of 43 degrees Celsius, the highest reading in the record. Heat-driven cooling load is now a persistent input into capacity planning and demand-side management, not a feature of individual hot days.

The grid-by-grid picture lines up on one point. Alerts cluster between 1600H and 2000H, while solar peaks between 1000H and 1300H. The two windows do not overlap. Evening peaks still depend on dispatchable thermal generation, including oil-based plants, with the spot price effect that follows. Renewable energy’s contribution was thinnest at the moments of greatest stress.

The renewable energy pipeline ahead

The gap that emerges from the 2023 to 2025 record is structural, not cyclical. Variable renewable energy addresses midday demand. It does little for the evening peak window where the worst alerts hit. Closing that gap means dispatching renewable energy across more of the daily load curve.

Different renewable technologies fill that requirement differently. Solar covers midday, while wind contributes through the evening, where the resource allows. Geothermal runs through the day at firm baseload, which is what made it the most reliable renewable energy contributor during 2023 to 2025 alerts in both Luzon and the Visayas. Hydropower, conventional and pumped-storage, is dispatched when needed, and the resource can bridge the evening peak. Battery storage, charged on midday solar, releases that energy in the hours that drive both alerts and price spikes.

Each technology behaves differently in the spot market. Variable renewable energy bids zero during its generating hours, while firm renewable energy runs through. Storage charges off midday clearing prices and sells into the evening peak, displacing thermal generation in the hours that historically set the day’s highest spot prices. Together, they cover the daily curve more evenly than any single technology can.

Several recent developments point to where this is heading. Meralco Terra Solar (MTerra Solar), spanning Nueva Ecija and Bulacan, synchronised its first phase to the grid in February 2026 and energised its first 250 MW of solar by March, with up to 450 MWh of stored solar energy delivered into the evening hours. At full build, MTerra Solar is planned at 3,500 MWp of solar paired with 4,500 MWh of storage. Beyond that one project, GEAP rounds have already awarded substantial capacity across multiple technologies. Round three targeted 6,350 MW of pumped-storage hydropower for delivery between 2028 and 2035. Round four, awarded in November 2025, secured commitments for 10.2 GW: 4.1 GW of ground-mounted solar, 2.3 GW of floating solar, and 2.2 GW of onshore wind, with the remainder in integrated renewable energy plus storage. Later rounds will cover offshore wind, floating wind, rooftop solar combined with solar-plus-storage, and a broader mix that includes biomass, geothermal, and hydropower. The cumulative GEAP target through 2035 sits at a minimum of 25 GW.

Costs back the deployment case. Bloomberg New Energy Finance puts solar’s levelised cost in the Philippines at USD 35 to USD 72 per MWh, the cheapest source in the country. Solar-plus-storage is closing in on cost parity with new thermal capacity. Independent Electricity Market Operator of the Philippines (IEMOP) simulations of continued GEAP rounds put average Luzon WESM prices at roughly USD 58 per MWh by 2029, against a current baseline projection nearer USD 85.

The wider question is how all of this changes the grid’s structural exposure: less imported coal and LNG, a supply mix more diverse across technologies and across times of day, and infrastructure that absorbs the new generation profiles rather than struggling against them. These are the places where clean transition, energy security, and affordability stop being separate goals.

Implications for policy dialogue

Across 2023 to 2025, growing renewable capacity contributed in measurable ways to a cushioning of Philippine electricity prices through a period of rising demand and recurring system stress. 

The decline showed up in spot prices, in wholesale weighted averages, and in end-consumer generation charges. It came through three reinforcing channels: spot market dispatch, contracted supply pricing, and structural insulation from imported fuel costs. Variable renewable energy alone, however, did not address the evening peak.

None of this is automatic or permanent. The mix that pulled Luzon’s wholesale prices down 39 per cent in three years is the same mix that thinned, hour by hour, as evening demand rose. Whether the price effect holds or whether it stretches into the evening peak, where it has always been weakest, depends on choices that sit with policymakers, regulators, grid operators, and investors over the next several years.

From the data, three of those choices stand out.

The first is storage at scale, on a timeline that matches the GEAP delivery schedule, with transmission planning that makes the new dispatch profiles useful rather than orphaned. The evidence puts a number on the evening peak gap. Closing it now falls to capacity build-out, procurement timing, and grid integration decisions.

The second is firm renewable capacity, geothermal in particular. The 2023 to 2025 record shows it carried more weight than its public profile suggested. The case for continuing to invest in firm renewables, alongside the more visible solar build-out, sits in the alert-hour data.

The third is the regional read. The combinations that drove the Philippine outcome describe most Southeast Asian grids: heat-driven demand growth, imported fuel exposure, and underused renewable resource potential. Whether the same effect generalises, and on what conditions, is an analytical question for continued comparative work across the region.

The 2023 to 2025 record is now closed. The next chapter of evidence is being written in dispatch decisions, auction rounds, and transmission projects already underway. The questions raised here remain open, but the data to answer them is already accumulating.