All about that grid

Last week saw several reports about power — in the realms of both politics and physics — filling primetime news and dominating the front pages of broadsheets. I leave the matter of politics to those who are more adept with its dynamics.

On the electrical power system, as of this writing, we continue to monitor the issuances of red and yellow alerts over Luzon and the Visayas by the National Grid Corp. of the Philippines (NGCP) signaling sufficiency or insufficiency of supply and reserves to meet system demand. This follows the tripping of critical transmission lines in south Luzon resulting in a loss of around 2,500 megawatts (MW) of capacity which then triggered widespread power interruptions on the main island. In a statement released on May 15, the Department of Energy (DoE) said that it has mobilized the Grid Reliability Task Force to conduct a full investigation of the incident and required the NGCP to provide full disclosure of operational data, incident reports, and technical findings for a comprehensive assessment of the event.

Quite fortuitously, earlier this week, it was also reported that the Energy Regulatory Commission (ERC) partially granted a motion for reconsideration by the NGCP for an upward adjustment of the regulated entity’s revenue cap for the 5^th regulatory period covering 2023-2027. According to the Order, promulgated on May 15, the Commission modified its earlier Final Determination, dated Jan. 9, and adjusted the NGCP’s Maximum Allowable Revenue (MAR) for the said period from P374.981 billion to P378.711 billion, or an Annual Revenue Requirement (ARR) ranging from P63.659 billion for 2023 to P89.982 billion for 2027. This will later be translated to transmission rates on peso/kW or peso/kWh basis to be collected from consumers starting in the October 2026 billing.

It is against this backdrop that we discuss the highlights of the Discussion Paper prepared by Dr. Adoracion Navarro of the Philippine Institute for Development Studies (PIDS), entitled, “The Need for Power Transmission Sector Reforms in the Philippines.”

The study was part of the January 2026 publication by PIDS (the full copy is available on its website) and presented in a webinar on May 14 — yes, fortuitously scheduled as well — for which I was invited to provide some reaction and inputs. The copy of the presentation is available at https://pids.gov.ph/CDN/document/Navarro_0514.pdf.

KEY FUNDAMENTALS
We often hear the phrase “there is no transition without transmission,” and assume this to mean that the grid just needs to continue expanding to meet the requirements of the energy transition. This is why I found it refreshing that Dr. Navarro took the time to discuss the history of the Philippine power sector in her study. It frames quite astutely the fact that, to a great extent, what we still have is a grid that existed prior to the reforms introduced by the Electric Power Industry Reform Act (EPIRA) of 2001.

While it is true that there have been expansions to the network, including the most important Mindanao-Visayas Interconnection Project, the grid remains a highly centralized network designed to operate with large power generation units, including the large renewable energy (RE) plants built and operated pre-EPIRA by the National Power Corp. and its independent power producers (IPPs). The question then that must be asked and perhaps addressed in a joint technical-economic study: given the direction the DoE has taken on increasing supply from RE and indigenous resources to wean us away from dependence on imported fuels, what revisions are needed in: a.) the grid’s design to most efficiently serve variably-sized RE plants located in multiple far-flung sites, and b.) the operation of a power system with high-and-dispersed RE penetration?

Dr. Navarro’s paper is also most helpful in dedicating a chapter discussing the economic principles governing the transmission industry. Given the tendency for political discussions to veer towards forcing competition in the transmission and distribution sectors via the issuance of parallel franchises over the same area, Dr. Navarro’s study serves as a good reminder as to why the transmission of electricity is known as a natural monopoly: it is one “characterized by high fixed costs, economies of scale, and network externalities. In liberalized electricity markets, transmission plays a critical coordinating role by enabling competition in generation and supply while remaining subject to economic regulation… Transmision investments are typically large, lumpy and irreversible…”

As a natural monopoly, the success then of the transmission sector in the grand scheme of a power system rests in several factors beyond competition.

PERSISTENT ISSUES
Dr. Navarro identified seven issues that continue to beset the sector in the Philippines: project delays; regulatory concerns; right-of-way concerns; grid reliability (including reserves and ancillary services); coordination and institutional frictions; ownership and national security concerns; and transmission capacity and congestion. I agree with the assessment of these issues and would just highlight the following points on three matters:

1. On project delays and transmission congestion. Dr. Navarro noted that although the ERC had imposed penalties on NGCP for certain project delays, “critics argue that the economic costs of delayed investments — such as congestion, reliability issues, and foregone access to cheaper generation — are substantial and often underestimated.”

Indeed, penalties cannot approximate the economic costs of delays in transmission projects. In the ERC’s evaluation of the NGCP’s application for approval of transmission projects, the economic analysis actually includes an estimate of the expected amount of energy not being served (EENS) to consumers, in the absence of the project, resulting from capacity shortages or unexpected power outages for the period considered, which is usually 15 years given the planning horizon for transmission assets. For example, in the ERC’s Order approving the Balaoan-Laoag 500-kilovolt (kV) Transmission Project (ERC Case No. 2021-003RC, promulgated on Nov. 26, 2024), the Commission computed the EENS for 15 years at 13,079,227,930 kilowatt/hour (kWh). Translating this in monetary terms using P18.75/kWh as the Cost of Alternative Energy Sources (CAES) — usually benchmarked to the cost of diesel fuel in the area to be served by the project at the time of evaluation — the ERC estimated P99.813 billion to be the cost to consumers over the 15 year period resulting from the absence of this one project alone. The potential revenue loss to generators, on the other hand, was estimated at P50.320 billion for the same period. Given the magnitude of these amounts and the maximum penalty of P50 million for each violation that ERC may impose, it is reasonable to expect the penalties will always fall short of the actual cost of delay.

The impact gets more magnified when delays affect interconnector projects and or result in line congestion.

Dr. Navarro correctly points out that “[w]hen transmission capacity is not available on time, lower-cost or cleaner generation gets curtailed, forcing the system to rely on more expensive alternatives. Congestion is especially acute in fast-growing load centers (such as cities in the Visayas), where demand growth has outpaced transmission upgrades. These constraints not only increase system costs but also undermine broader policy objectives related to system security and decarbonization.”

One can simply monitor the average prices at the wholesale electricity spot market (WESM) daily to verify the disparity in prices in Luzon, Visayas, and Mindanao that can largely be attributed to congestion: to illustrate, for May 19, the Load Weighted Average Price (LWAP) for the system was P7.32/kWh. For Luzon, however, the LWAP was P3.90/kWh, while it stood at P20.21/kWh for the Visayas and P11.05/kWh for Mindanao.

2. On regulatory concerns. Dr. Navarro also explains the rationale behind the shift from the return-on-rate-base (RORB) methodology to the performance-based review (PBR) regime that currently governs the transmission and distribution sectors pursuant to EPIRA. The economic theory behind the adoption of PBR is to link the revenues of the regulated entity to outcomes to reduce the need for heavy-handed regulation. However, she observes, “…for reasons still insufficiently addressed in public discourse, the ERC was unable to conduct on time the regulatory reset for 2016 to 2020 (the Fourth Regulatory Period or 4th RP). This delay is inappropriate because PBR is designed to be forward-looking, relying on forecasts to establish rates before the start of each regulatory period. As a result, transmission rates for the 4^th RP were not determined as scheduled and the NGCP was allowed to operate using the wheeling charges set during the 3^rd RP…”

While the laudable intention behind the shift from RORB methodology to PBR cannot be disputed, we must also confront our scorecard for success, so to speak, in implementing a regulatory regime observed in many developed countries with stronger governance and enforcement institutions. Our experience with PBR or incentives-based methodology in the power sector, for instance, has been ad hoc and improvisational, at best.

I find merit in Dr. Navarro’s proposal to adopt what she calls a “hybrid approach” that offers a more balanced policy option. This, to my mind, allows us to still benefit from the decades of experience and jurisprudence on the RORB methodology while also developing the discipline needed among regulators and stakeholders alike for an effective incentives-based regime. For this hybrid approach, particularly for capital expenditures, Dr. Navarro suggests one “where capital expenditures are provisionally included to support financing but only fully recognized for depreciation and return upon commissioning… International experience in liberalized markets suggests that such hybrid designs can better align investment incentives with consumer protection (e.g., ‘split CAPEX’ method in the UK)…” This, of course, does not do away with ensuring that the Commission is well-capacitated to perform its job not only to make timely approvals but, perhaps more importantly, in following through on monitoring and regular validation of project completion and rate adjustments, particularly in case of unjustified project delays.

3. On coordination among institutions and grid reliability. The DoE’s push for large capacity-RE projects through the Green Energy Auction Program (GEAP) and its recent policy on energy storage solutions make coordination and alignment among the ERC, the DoE and the NGCP more crucial than ever. As clearly articulated in Dr. Navarro’s study:

“In theory, flexibility options such as energy storage, demand response, and increased interconnection can interact with transmission investment decisions. These options may reduce the need for certain transmission projects, but they also alter the risk-return profile of network investments. Well-designed market and regulatory institutions therefore are essential to ensure that transmission expansion keeps pace with system needs without imposing excessive costs on consumers.

“In the Philippine context, these theoretical concerns are evident. Transmission expansion is planned through long-term Transmission Development Plans [TDP]. But implementation faces uncertainty arising from fluctuating demand projections, delays in generation projects, rights-of-way issues, and evolving energy policies. These risks shape the incentives of the NGCP…and influence the timing and scale of investments.”

Alignment of generation and transmission projects was the focus of the modeling done for the study initiated in 2018 by the DoE, with the support of the US National Renewable Energy Laboratories (NREL), and completed in 2020 identifying what are now known as the Competitive RE Zones (CREZ) all over the country. The CREZ report already highlighted what it called the “timescale misalignment”: while it takes around two to three years only to construct a wind or solar project, it would typically take around 10-20 years to build a transmission project if factors such as ROW acquisition and regulatory delays are not addressed.

We also have today what we can call “project siting misalignment”: while the NGCP reports that there is currently 10 gigawatts of capacity available in the grid for generator connections, the location of these connection points may not be in the areas where RE projects awarded under the GEAP would connect, unless the TDP is aligned with the CREZ report, and the CREZ report is aligned with the GEAP design.

When project siting misalignment persists and close coordination is lacking in long-term planning between transmission and generation, we cannot have a grid that is optimally designed for cost-effective service delivery and reliability.

INCREASED COMPLEXITY
The recent grid incident in Luzon and the series of red and yellow alerts are just the latest of what we may consider as distress signals from the system itself to adopt certain reforms. As the generation profile is reconfigured with significant RE capacity, we must ensure that this actually results in improved energy security by reducing dependence on imported fuel and increasing system reliability. This means the transmission infrastructure and system operation will need to be adjusted accordingly.

This will not be easy, nor will it come without deliberate design. “The evolution of ancillary services procurement and reserve markets highlights the importance of institutional adaptability, but it also underscores the need to carefully manage cost pass-through to consumers,” Dr. Navarro observes. “As grid complexity increases, regulatory frameworks must ensure reliability while maintaining transparency and accountability in cost recovery.”

Monalisa C. Dimalanta is a senior partner at Puyat Jacinto & Santos Law (PJS Law). She was the chairperson and CEO of the Energy Regulatory Commission from 2022 to 2025, and chairperson of the National Renewable Energy Board from 2019 to 2021.