The duality of the grid: Luzon saves, VisMin pays

By Francis Allan L. Angelo

The Philippine energy landscape saw a stark regional divide during the December 2025 billing period, with Luzon consumers benefiting from lower market rates while the Visayas and Mindanao regions faced significant price surges.

According to the latest data from the Independent Electricity Market Operator of the Philippines (IEMOP), the national electricity market experienced a curious contradiction of improved overall supply and localized price volatility.

IEMOP, the non-stock, non-profit corporation responsible for operating the Wholesale Electricity Spot Market (WESM), reported that the system-wide average supply increased to 20,233 MW in December 2025.

This figure represents a 1.2% rise in available power compared to the November 2025 billing period, signaling a generally healthy capacity for the national grid.

Simultaneously, the country saw a slight cooling in energy consumption as electricity demand decreased to 13,440 MW, which is 0.5% lower than the previous month.

These combined factors successfully widened the overall system supply margin to 4,798 MW, a notable improvement from the 4,572 MW margin recorded in November.

REGIONAL DIVERGENCE, PRICE IMPACT

However, the “Independent Electricity Market Operator of the Philippines (IEMOP) said” that despite this improved national supply-demand balance, operating conditions varied drastically across different island grids.

While the national outlook appeared stable on paper, the supply margins in the Visayas and Mindanao regions declined by 136 MW and 245 MW, respectively.

IEMOP attributed these tighter regional conditions primarily to a combination of planned and forced outages of several major generating plants.

Transmission constraints further complicated the situation, as they limited the ability of the southern grids to access lower-cost generation surplus available in Luzon.

This lack of fluidity in the market contributed to an increase in the system-wide average energy price, which rose to PHP 4.38/kWh from the PHP 3.98/kWh seen in the previous billing month.

REPRIEVE FOR LUZON; CHALLENGES FOR VIS-MIN

Luzon emerged as the primary beneficiary of the month’s market dynamics, maintaining a trend of increasing supply and declining demand similar to its performance in November 2025.

These favorable conditions led to a significant reduction in the Luzon average market price, which settled at PHP 2.98/kWh compared to PHP 3.52/kWh the month prior.

Luzon’s ability to maintain a surplus allowed it to act as a potential “energy bank” for the rest of the country, though infrastructure limits prevented this from fully stabilizing other regions.

In sharp contrast to the north, the Visayas and Mindanao grids experienced much tighter operating conditions that pressured local market prices upward.

In the Visayas, available supply did manage to increase by 106 MW compared to the previous month, but this gain was eclipsed by a sharper demand increase of 181 MW.

The result for the Visayas was a net reduction in its regional supply margin, making the grid more vulnerable to price fluctuations and localized shortages.

Mindanao faced a dual challenge as its regional supply declined by 245 MW while local demand simultaneously increased by 25 MW.

Under normal operating conditions, the Visayas grid is designed to be supported by power imports from Luzon through the Leyte–Luzon high-voltage direct current (HVDC) interconnection.

This subsea cable system is a critical piece of national infrastructure that allows for the sharing of energy resources across the archipelago, balancing the surplus of one region with the deficit of another.

However, during the December billing period, the HVDC link was either operating at its maximum Luzon-to-Visayas transfer limit of 250 MW or was offline entirely for maintenance.

IEMOP data shows that this critical link was constrained or offline for 69% of the billing period, a significant jump from the 34% constraint duration recorded in November 2025.

These prolonged limitations restricted the transfer of lower-cost Luzon generation to the Visayas, which effectively caused a “price separation” between the northern and southern grids.

OUTAGES AND SCARCITY

The situation was further exacerbated by simultaneous outages of several generating units in the Visayas and Mindanao during the first half of the billing month.

In the Visayas, planned coal plant outages accounted for 238 MW of lost capacity, while forced outages across various technologies reached 110 MW.

Mindanao saw even more dramatic losses, with coal and hydro units accounting for as much as 699 MW of unavailable capacity at peak periods.

Mindanao also dealt with an additional 257 MW of forced outages from other generating technologies, significantly reducing the region’s available baseload power.

Because of these tighter supply conditions, the market was forced to dispatch higher-marginal-cost generation sources to meet peak demand in the southern regions.

Battery Energy Storage Systems (BESS) and other expensive peaking plants were dispatched more frequently during these constrained periods to prevent regional blackouts.

As a result, regional market prices in the Visayas and Mindanao reached levels between PHP 7.86/kWh and PHP 8.53/kWh during the most strained intervals.

LOCALIZED CONGESTION

Within the Visayas grid specifically, congestion along the 230 kV Leyte–Cebu transmission corridor created further internal bottlenecks.

This congestion limited power transfers within the region and specifically affected market trading nodes in Leyte, preventing local generation from reaching Cebu.

The result was localized price separation, where nodal prices in certain areas of the Visayas spiked significantly higher than the regional average due to these technical hurdles.

Beyond energy supply, both the Visayas and Mindanao also struggled with reserve deficiencies during the month of December.

The Visayas recorded shortages in dispatchable reserves, while Mindanao experienced deficits in both regulating and dispatchable reserves.

These conditions led to higher reserve market clearing prices, contributing to the overall financial pressure on the electricity market in the affected southern regions.

NORMALIZATION IN LATE DECEMBER

Relief finally arrived toward the last week of the December 2025 billing period as generation availability in the Visayas and Mindanao began to improve.

As key transmission constraints eased and operating conditions normalized, market prices in these regions finally began to decline.

During this final week, prices in the southern grids settled into a more manageable range between PHP 3.08/kWh to PHP 3.21/kWh.

However, the sustained high prices earlier in the month were severe enough to trigger the Secondary Price Cap (SPC) mechanism.

The SPC was triggered for 213 intervals in the Visayas and 216 intervals in Mindanao to protect consumers from extreme price volatility.

Despite the cap, the monthly average prices for December 2025 settled at PHP 7.22/kWh in the Visayas and PHP 7.82/kWh in Mindanao.

SPOT MARKET ACTIVITY, TRADING VALUE

Regarding market activity, IEMOP noted that spot market volume rose during the month, accounting for 13.2% of the total traded quantity.

This was an increase from the 12.3% spot market share recorded in November 2025, suggesting more reliance on the spot market for procurement.

The total amount of money traded in the spot market rose accordingly, climbing from PHP 13.13 billion to PHP 14.19 billion.

In the reserve market, zonal prices decreased across most regions, offering some general relief to the overall system costs.

Exceptions included Regulation Up in Luzon, Contingency and Dispatchable Reserves in the Visayas, and Dispatchable Reserves in Mindanao.

Overall, system-wide reserve market transactions decreased from PHP 4.10 billion in November 2025 to PHP 3.92 billion for December 2025.

The performance of the market in December highlights the ongoing importance of the Leyte–Luzon HVDC interconnection and the need for reliable baseload generation.

As the country continues to integrate more renewable energy and battery storage, the management of these transmission constraints remains a top priority for grid stability.