By 2020 Chile had around 3,000 MW of solar PV and 2,100 MW of wind in operation, and with what had been declared under construction it could exceed 10,000 MW of variable renewable generation by the end of 2021. That growth congests the network faster than lines can be built. This paper examines a concrete alternative: using an energy storage system (ESS) as a transmission asset, to raise the transfer capacity of an existing corridor instead of reinforcing it with new works.
The thesis has two parts. The first is methodological: the tools Chile uses to assess these projects systematically underestimate their value. The second is regulatory: even if that value were measured correctly, the current regulation prevents capturing it.
Why block-based models do not work here
Economic dispatch models that represent a month with 16 blocks —the Chilean market standard— fail to capture the dynamics that matter. In the 11:00 to 16:00 window, close to 25% of the high renewable generation data from the hourly simulation is not represented in the block model. Nor do these models represent ramps, cycling, technical minimums or spinning reserves, so they credit the coal fleet with a flexibility it does not have.
The effect propagates: block-based simulation underestimates congestion on the 500 kV Kimal–Polpaico corridor and flattens the dispersion of marginal costs across nodes. That biases PPA contract risk estimates, the assessment of network reinforcement needs, and the value of flexible assets. The authors cite that, for the SEN, the operating cost savings from integrating an ESS come out between 3 and 7 times higher when simulated with Unit Commitment models and with several services provided simultaneously.
How storage raises the corridor limit
The capacity of the Kimal–Polpaico corridor is limited by the N-1 security criterion. An ESS of Y MW connected downstream of the congestion, held charged awaiting a contingency and injecting when one occurs, allows that criterion to be relaxed and the limit to rise by Y MW. If it is also charging at Y MW during solar hours —performing arbitrage— then interrupting the charge and injecting gives a net effect of 2Y: the limit rises to twice the equipment's capacity.
Across hourly simulations for 2025-2039 with a 500 MW / 30 min ESS at Polpaico, multi-service operation produces savings between 0.5 and 25 times greater than operation dedicated solely to transmission. The gap becomes critical when the 2,000 MVA Kimal–Lo Aguirre HVDC link enters service: between 2030 and 2035 the savings of the transmission-only case fall almost to zero, while the multi-service case stays above 15 million dollars a year. An asset tied to a single service loses its value as soon as that service is no longer needed.
The regulatory knot
The Operation Coordination Regulation enables ESS to provide ancillary services and arbitrage, and provides that the resulting balances be passed through pro rata to withdrawals and considered in the single charge, analogous to the tariff revenue of a transmission line. But the Transmission Planning Regulation —filed with the Comptroller General on 16 June 2020— only allows the Coordinator to use the ESS's "compatible services" when no competitive solution exists for that need. In the authors' reading, this leaves the equipment out of the energy market in practice, and out of the ancillary services market unless reserve auctions are left undersubscribed.
The paper proposes two ways out: a mixed development logic, where only part of the cost is borne by the end customer and the rest sits at the developer's risk as a multi-service provider; or defining the transmission service as an ancillary service, with explicit hours, power, duration and activation times, and competitive schemes to provide it.