Seung Wan Kim

Phasing out coal-fired generation is central to power-sector decarbonization, yet many coal-dependent systems still lack a concrete, fleet-wide schedule specifying when each unit should retire or convert. This study develops an integrated capacity expansion model that endogenously represents fuel switching and early retirement of existing coal units, including the associated decommissioning cost. Long-term capacity planning is coupled with short-term mixed-integer unit-commitment operation through an iterative planning–operation algorithm. Because the fuel-transition options are defined separately from the country-specific input data, the formulation is transferable to other coal-dependent power systems. Applied to a 12-node representation of the South Korean power system from 2025 to 2050, the model phases out coal by 2040 across all three renewable scenarios examined, and as early as 2035 under accelerated renewable expansion with revisable conversion schedules, while renewables remain the main source of emission reductions. For fuel switching, the model selects LNG conversion as the main pathway and adds no coal–ammonia co-firing beyond a small pre-scheduled conversion. A roadmap that meets the annual emission targets in long-term planning can still violate a later target once short-term operation is represented; the iterative algorithm restores compliance through operational screening.

The accelerated integration of inverter-based resources (IBRs) equipped with grid-following (GFL) technology has led to a weaker, lower-inertia system, thereby intensifying operational challenges. To address these issues, grid-forming (GFM) technology has gained increasing attention due to its ability to provide synthetic inertia, potentially replacing conventional synchronous generators. The successful adoption of emerging technologies such as GFM technology requires accompanying policy, regulatory, and financial support. In particular, to lower entry barriers and facilitate faster deployment, non-market financial support mechanisms based on the value of GFM resources are necessary; however, their value in the power system remains unquantified. To bridge this gap, this study proposes a quantitative cost-benefit analysis of GFM resources. An inertia-constrained unit commitment framework is developed to assess the operational benefits of GFM integration. The results demonstrate that GFM resources can effectively substitute the inertia-providing function of synchronous generators, achieving up to a 44% reduction in operational costs and a 58% decrease in the curtailment of renewable energy compared to an all-GFL scenario in an IBR-rich island power system. Moreover, the analysis confirms that the operational benefits of GFM resources are substantial relative to the additional costs incurred in transitioning from GFL to GFM control.

Large-scale offshore wind (OFW) integration on the Korean West Coast faces inland transmission bottlenecks and permitting risks from multiple onshore landfalls. To address these constraints, this study proposes a natural-island Energy Hub consolidating OFW connections—an intra-national configuration distinct from European hub designs for cross-border electricity trade. The proposed Hub is evaluated against a business-as-usual (BAU) radial baseline across three dimensions: structure, operation, and design. Structurally, capital expenditure (CAPEX) decomposition quantifies infrastructure cost savings from Hub adoption. Operationally, national-scale power system simulation estimates system benefits preserved under one- to three-year delays in high-voltage direct current (HVDC) transmission expansion. From a design perspective, six alternative Hub configurations combine downsized interconnection capacity with on-island battery energy storage systems (BESSs) as a non-wires alternative. Hub adoption reduces total CAPEX by 20.5%, from 10,926 to 8,683mEUR, through shorter export cables and elimination of redundant connection links. Timely Hub commissioning, enabled by reduced permitting exposure, preserves system benefits of 737-2,205mEUR across the delay range by avoiding renewable curtailment and displacing fossil generation via the HVDC corridor. Configurations pairing a 200MW BESS with downsized interconnection capacity yield positive Net Benefits across the full BESS cost range, whereas larger BESS capacities incur capital costs that may outweigh infrastructure savings and marginal operational gains. These findings provide a transferable reference for countries facing concentrated OFW development, distant demand centers, and social-acceptance constraints on onshore grid expansion.

Phasing out coal-fired generation is central to power-sector decarbonization, yet many coal-dependent systems still lack a concrete, fleet-wide schedule specifying when each unit should retire or convert. This study develops an integrated capacity expansion model that endogenously represents fuel switching and early retirement of existing coal units, including the associated decommissioning cost. Long-term capacity planning is coupled with short-term mixed-integer unit-commitment operation through an iterative planning–operation algorithm. Because the fuel-transition options are defined separately from the country-specific input data, the formulation is transferable to other coal-dependent power systems. Applied to a 12-node representation of the South Korean power system from 2025 to 2050, the model phases out coal by 2040 across all three renewable scenarios examined, and as early as 2035 under accelerated renewable expansion with revisable conversion schedules, while renewables remain the main source of emission reductions. For fuel switching, the model selects LNG conversion as the main pathway and adds no coal–ammonia co-firing beyond a small pre-scheduled conversion. A roadmap that meets the annual emission targets in long-term planning can still violate a later target once short-term operation is represented; the iterative algorithm restores compliance through operational screening.

As power systems evolve toward AC/DC hybrid networks, electricity market prices need to reflect the distinct operational characteristics of the AC and DC subsystems, as well as their resulting impacts on system operation. However, the design of economically interpretable pricing schemes remains challenging because the operation of AC/DC hybrid grids is inherently complex and nonconvex. To address this challenge, we propose an integrated pricing mechanism for energy and reactive power in AC/DC hybrid grids based on convex relaxation. The proposed framework is built on a quadratically constrained quadratic programming (QCQP)-based optimal power flow model that captures the operational characteristics of AC/DC hybrid systems while minimizing the procurement costs of both active and reactive power. To reveal the drivers of nodal price formation, energy and reactive power prices are derived from the Karush-Kuhn-Tucker optimality conditions and decomposed into interpretable components. Case studies on AC-only and AC/DC hybrid grids demonstrate that the proposed scheme properly internalizes the system-level contributions of HVDC and the locational value of energy and reactive power, thereby providing informative price signals. The results also show that energy and reactive power prices are closely coupled and exhibit similar temporal patterns.

The accelerated integration of inverter-based resources (IBRs) equipped with grid-following (GFL) technology has led to a weaker, lower-inertia system, thereby intensifying operational challenges. To address these issues, grid-forming (GFM) technology has gained increasing attention due to its ability to provide synthetic inertia, potentially replacing conventional synchronous generators. The successful adoption of emerging technologies such as GFM technology requires accompanying policy, regulatory, and financial support. In particular, to lower entry barriers and facilitate faster deployment, non-market financial support mechanisms based on the value of GFM resources are necessary; however, their value in the power system remains unquantified. To bridge this gap, this study proposes a quantitative cost-benefit analysis of GFM resources. An inertia-constrained unit commitment framework is developed to assess the operational benefits of GFM integration. The results demonstrate that GFM resources can effectively substitute the inertia-providing function of synchronous generators, achieving up to a 44% reduction in operational costs and a 58% decrease in the curtailment of renewable energy compared to an all-GFL scenario in an IBR-rich island power system. Moreover, the analysis confirms that the operational benefits of GFM resources are substantial relative to the additional costs incurred in transitioning from GFL to GFM control.

The accelerated integration of inverter-based resources (IBRs) equipped with grid-following (GFL) technology has led to a weaker, lower-inertia system, thereby intensifying operational challenges. To address these issues, grid-forming (GFM) technology has gained increasing attention due to its ability to provide synthetic inertia, potentially replacing conventional synchronous generators. The successful adoption of emerging technologies such as GFM technology requires accompanying policy, regulatory, and financial support. In particular, to lower entry barriers and facilitate faster deployment, non-market financial support mechanisms based on the value of GFM resources are necessary; however, their value in the power system remains unquantified. To bridge this gap, this study proposes a quantitative cost-benefit analysis of GFM resources. An inertia-constrained unit commitment framework is developed to assess the operational benefits of GFM integration. The results demonstrate that GFM resources can effectively substitute the inertia-providing function of synchronous generators, achieving up to a 44% reduction in operational costs and a 58% decrease in the curtailment of renewable energy compared to an all-GFL scenario in an IBR-rich island power system. Moreover, the analysis confirms that the operational benefits of GFM resources are substantial relative to the additional costs incurred in transitioning from GFL to GFM control.