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Wind and solar power are expected to play important roles in many countries to achieve carbon neutrality; however, their inherent instabilities pose significant threats to existing power grids. Because hydropower has been recognized as a viable compensatory resource for solar and wind energy uncertainties, many studies have sought to determine optimal scheduling strategies for hydro-PV, hydro-wind, and hydro-PV-wind systems. However, few studies have simultaneously considered the sizing and scheduling of large-scale hydro-PV-wind hybrid systems connected to long-distance transmission lines. Therefore, this paper develops a mathematical metric to measure the wind and solar output complementarity and incorporates it into a multi-objective sizing and scheduling model for a hybrid hydro-PV-wind system, in which resource complementarity, profit generation, system reliability, and power curtailment trade-offs are concurrently considered. The ɛ -constraint method is employed and decision makers' attitude parameters are introduced to transform the proposed model into its equivalent single objective form. A case study in China reveals that the maximum wind and solar power output complementarity rate can be at least 0.19 for the studied hybrid hydro-PV-wind system. The incorporation of wind enables the hybrid hydro-PV-wind system to provide 4.11% more load than a hydro-PV system. In addition, if 2% of power curtailment is permitted, 1.53% more load can be served and 14.9% higher profits can be earned. To better explore the application of hybrid systems, management recommendations are provided for system operators, the power industry, and management administrations. • Multi-objective sizing and scheduling method for the hybrid renewable system is proposed. • Mathematical metrics to measure wind and solar power complementarity is provided. • A complementarity rate of 0.19 can be reached with 100% reliable service and no curtailment. • Integrating wind power into the hydro-PV system can reliably serve 4.11% more load. • An optimal rather than minimal level of the renewable power curtailment is more efficient. [ABSTRACT FROM AUTHOR]

The intensification of global climate change has led to a widespread consensus on carbon reduction, with the power industry being the principal contributor to carbon emissions necessitating an inevitable transition of its energy structure. Concomitantly, the escalating frequency of natural disasters caused by extreme weather presents formidable challenges to both secure power supply and the low-carbon transition of the power system. To fulfill the developmental requirements of a low-carbon power system and address the carbon emission risks imposed by natural disasters, this paper proposes a bi-level model for generation expansion planning (GEP) that incorporates constraints on the carbon emission trajectory and the influence of natural disasters. The planning-level model optimizes investment costs of various generation technologies and energy storage (ES), as well as the overall operational expenses over the planning period, with an objective to minimize them. It incorporates carbon emission trajectory constraints and policy constraints, such as carbon peaking, carbon neutrality and renewable energy (RE) penetration rates, in order to optimize the planning installed capacity of power sources. The operational-level model aims to minimize typical daily operating costs while also simulating power unit outputs in routine and disaster scenarios. A case study is conducted in a disaster-prone province in southern China to analyze the power generation expansion planning and the trajectory of carbon emissions from 2020 to 2060 under different scenarios. The simulation results show that compared to thermal power, the planning scheme mainly focused on RE with ES is better suited to achieve the goal of a low-carbon transition of the power grid. Moreover, after considering natural disasters, the cost and carbon emissions of power system planning are higher, and the risk of carbon emissions increases with the severity of disasters. • A multi-time scale bi-level low-carbon GEP model is proposed. • Natural disaster scenarios and low-carbon policy constraints are considered in the GEP model. • Carbon emission trajectory of the planned power system is estimated and introduced as a constraint into the GEP model. • Evaluation indicators that comprehensively consider low-carbon performance and economic feasibility are proposed. [ABSTRACT FROM AUTHOR]

[Display omitted] • Quantitative methods for power flexibility. • Decentralized and coordinated model for sharing hydropower flexibility in interconnected power systems. • New linearization methods for complex nonlinear constraints of hydropower system and DC tie-lines. • The method and model are performed on the China Southern Power Grid. In 2020, China pledged to become carbon neutral before 2060, which implies the acceleration of China's low-carbon energy transition and development of new energy (wind and solar). As a result, the demand for flexibility in China's power system has never been so urgent. Because China has the greatest installed hydropower capacity in the world, sharing hydropower flexibility in its interconnected power systems is of great practical significance to China. This paper reports the necessity and feasibility of sharing the hydropower flexibility of Yunnan's large hydropower bases in the China Southern Power Grid (CSG) through direct-current (DC) tie-lines. In addition, an effective solution to this problem is presented. First, several quantitative methods of flexibility are proposed. Second, a decentralized and coordinated scheduling model that taps and shares the power flexibility of large hydropower bases in interconnected power systems is constructed. The model considers the complex nonlinear constraints of hydropower and DC tie-lines. Third, new linearization modeling methods are proposed to transform the model to a mixed integer linear programming (MILP) model, reducing the computational complexity. The MILP model is applied to the CSG to determine the hourly generation schedules for power plants in Yunnan's large hydropower bases and the power transmission plans for DC tie-lines. The cases studies demonstrate that the proposed model can fully tap hydropower flexibility and ensure that large hydropower bases simultaneously respond to the flexibility demands of sending-end and receiving-end power grids. The study provides a valuable technical approach for alleviating the lack of power flexibility in other countries with large hydropower bases. [ABSTRACT FROM AUTHOR]