Philippines opens transmission to private builders, but keeps the grid-control question unanswered

In September 2026, the Energy Regulatory Commission (ERC) approved a wave of point-to-point transmission projects that mark a structural shift in the Philippines' power system: private renewable developers can now finance and own their own wires to the grid, bypassing the National Grid Corp. of the Philippines (NGCP) for the first time at meaningful scale.^[1] AboitizPower's subsidiary North Luzon Green Power won approval for a 230-kV transmission line to connect a 187-megawatt-peak solar project and separate 276.954-megawatt-hour battery storage system in Ilocos, with an estimated cost of P830.3 million (about $14.8 million USD).^[1] Another AboitizPower unit, Wind Renewable Energy Corp., was cleared to build transmission for its 64-MW Presentacion 2 wind project in Camarines Sur at P173.2 million (about $3.1 million USD).^[1] Separately, San Miguel Global Power and San Ildefonso Alternative Energy also won approvals for battery and solar transmission connections.^[3] The ERC's stated intent is clear: to break the NGCP's construction bottleneck and accelerate renewable deployment by allowing developers to own their point-to-point wires.^[2] That reasoning is sound. Where the framework breaks down is on the questions that follow: who controls dispatch of power flowing through these privately owned lines; how are grid-stability costs allocated when multiple private corridors intersect the backbone network; and what happens when point-to-point projects conflict with each other or with NGCP's long-term grid plan.

The Philippines' transmission monopoly was never a technical necessity; it was a regulatory choice that priced access and delayed renewables. NGCP holds the license to develop, own, and operate all high-voltage transmission, giving it no incentive to prioritize new entrants' projects in its construction queue and every incentive to cost-plus every interconnection study. The ERC's move is a direct answer to that hold-up: allow the generator to own its own fence-post connection and skip the queue. But opening the wires layer to private construction without concurrent rules for dispatch, stability coordination, and cost-allocation writes volatility into the system. A point-to-point line is not a closed system; the power it carries flows into a grid that NGCP still operates, with voltage and frequency stability requirements that do not care who owns the copper. If three independent developers build transmission corridors that meet the backbone at the same substation, and each assumes the grid will accommodate its power flow, the operator faces unsolved dispatch coordination problems. The congestion cost, reactive-power requirements, and protection-system complexity land on the entire system but are not baked into any single project's approval.^[4]

The cost-allocation trap is the deeper issue. In the Philippines, as in the United States, 'beneficiary pays' sounds neutral until you ask who counts as a beneficiary and who performs that count. A point-to-point transmission facility clearly benefits its owner and the consuming region it serves. Does it benefit the NGCP-operated backbone, whose stability margins shrink with every new uncoordinated injection point? Does it benefit other generators whose access to the grid is now constrained by the new line's operational envelope? The ERC's approvals do not answer these questions on the record; they treat each project in isolation, as if transmission is a series of private pipes rather than a networked system. That approach works until it does not, until the second or third coordinated-operation problem forces a costly retrofit or unplanned network upgrade that no single project's calculation anticipated.

The precedent is instructive. In the United States, FERC Order 1000 (2011) opened transmission to competitive bidding but left cost allocation to regional operators, which produced decades of litigation and arbitrary decision rules. The Philippines is now entering that terrain with less institutional experience and a much simpler grid. The buildable alternative is to require, before any point-to-point approval, a short-term coordinated-operations study (funded by the applicant, performed by an independent third party, not NGCP alone) showing how the new line interacts with existing and planned transmission, what stability or congestion costs it imposes on the backbone, and how those costs are allocated or covered in the applicant's tariff.^[4] Require the developer to offer grid-stability ancillary-service contributions (reactive power, fast ramps, black-start capability) as part of its transmission tariff. And establish a standing technical committee, separate from NGCP, to coordinate dispatch and to propose shared-cost upgrades to the backbone when multiple projects push the system past a stability threshold. That committee should include the ERC, NGCP as system operator (not as incumbent competitor), the large generators and point-to-point owners, and an independent grid engineer. The cost of building these rules now, a few weeks of docket work and a modest technical panel, is trivial compared to the cost of retrofitting a fragmented transmission layer that no one predicted or planned.

The Philippines is also pursuing a larger interregional connection, the Mindoro-Panay 230-kV Interconnection Project, which, under new DOE and ERC rules, might itself be built by a non-NGCP entity.^[9] That is a genuine breakthrough for grid efficiency. But interregional and point-to-point projects exist in the same system. If the Mindoro-Panay line carries power from a cluster of Panay solar farms to Metro Manila through a point-to-point corridor already owned by another developer, dispatch control and cost allocation become a system-level question, not a merchant-transmission question. The ERC should not approve the Mindoro-Panay project, or any large interregional transmission, without first establishing the technical and financial coordination framework that point-to-point has now made urgent.