Power-to-hydrogen systems have the potential for long-term energy storage and diversified terminal utilization, contributing to high renewable integration in power systems. To explore the potential energy arbitrage of integrated power-to-hydrogen systems (IP2HSs) across power systems and hydrogen supply chains, we propose a long-duration robust optimization (LDRO) framework for IP2HSs considering energy, ancillary services, and hydrogen markets. A unified capacity bidding model in the ancillary service market is established for fuel cells and electrolyzers of IP2HSs to simulate the bidding strategy in typical markets. The hybrid hydrogen demand model is based on the Cournot model considering the cost-competitiveness of hydrogen in different sectors. A direct solution method combining the column-and-constraint generation algorithm and strong duality theory is proposed for the LDRO framework with quadratic terms. Uncertainty sets are constructed based on day-ahead prices in typical markets. A case study investigates the feasibility of energy arbitrage and the ability of the LDRO framework to deal with long-duration price uncertainties in 15 markets. The results highlight the advantages of hybrid hydrogen demand and the sensitivity of energy arbitrage by IP2HSs to different parameters.

Due to the significantly differentiated electrolytic hydrogen capacity caused by resource characteristics such as wind, solar, hydro, and thermal power in different regions of China, region joint electrolytic hydrogen systems (RJEHS) considering multiple energy sources is proposed to improve this situation. In this framework, a regional decoupling model is established for typical cascade hydropower in Southwest China to simulate the actual operation of it. Moreover, the advantages of RJEHS compared with region separate electrolytic hydrogen systems (RSEHS) in reducing levelized cost of hydrogen (LCOH), carbon emission and the installed capacity of renewable energy power generation are also studied. In addition, differential models considering the power and ramping characteristics of three different types of electrolyzers are established. And the evolution process and development prospect of the planned configuration of the three types of electrolyzers during 2025-2050 are given. The case study verifies the rationality and effectiveness of the proposed framework.

Hydrogen production by electrolysis is considered an essential means of consuming renewable energy in the future. However, the current assessment of the potential of renewable energy electrolysis for hydrogen production is relatively simple, and the perspective is not comprehensive. Here, we established a Combined Wind and Solar Electrolytic Hydrogen system, considering the influence of regional wind-solar-load characteristics and transmission costs to evaluate the hydrogen production potential of 31 provincial-level regions in China in 2050. The results show that in 2050, the levelized cost of hydrogen (LCOH) in China’s provincial regions will still be higher than 10 ¥/kg, which is not cost-competitive compared to the current hydrogen production from fossil fuels. It is more cost-effective to deploy wind turbines than photovoltaic in areas with similar wind and solar resources or rich in wind resources. Wind-solar differences impact LCOH, equipment capacity configuration, and transmission cost composition, while load fluctuation significantly impacts LCOH and electricity storage configuration. In addition, the sensitivity analysis of 11 technical and economic parameters showed differences in the response performance of LCOH changes to different parameters, and the electrolyzer conversion efficiency had the most severe impact. The analysis of subsidy policy shows that for most regions (except Chongqing and Xizang), subsidizing the unit investment cost of wind turbines can minimize LCOH. Nevertheless, from the perspective of comprehensive subsidy effect, subsidy cost, and hydrogen energy development, it is more cost-effective to take subsidies for electrolysis equipment with the popularization of hydrogen.

The Yangtze River, as the world’s largest clean energy corridor, links key economic regions and plays a crucial role in inland waterway transportation. However, few studies have comprehensively evaluated the potential of the Yangtze River for cross-regional hydrogen transport. Here, we develop a comprehensive integrated power and hydrogen supply chain (IPHSC) optimization model to evaluate the potential of cross-regional hydrogen transport via the Yangtze River. The IPHSC optimization model covers the entire hydrogen production-storage-transportation-utilization chain through cross-sector modeling of energy, transportation, water scheduling, and environmental protection. Results show that, in the 2060 carbon neutrality scenario, the deployment of 62.2 kilotons of 574 differentiated liquid hydrogen (LH2) carrier ships could enable the transportation of 5,018 kilotons (1,512 million ton-km) of hydrogen annually, meeting nearly 20% of the total electrolytic hydrogen demand across eight riverine provinces. Unlike west-to-east electricity transmission in China, the central Yangtze River region is expected to become the main hub for hydrogen exports in the future. Compared with alternative methods such as transmission lines or pipelines, LH2 carrier ships offer the lowest energy supply costs, at 3 US cents/kWh for electricity and 5 US cents/kWh for hydrogen. Additionally, a full-parameter attribution analysis of over 40 factors is conducted to assess variations in supply costs. Our study offers a thorough evaluation of the feasibility and economic benefits of hydrogen transportation via inland waterways, providing a comprehensive, multi-sectoral coupling assessment framework for regions with well-established inland waterway networks, such as Europe and the United States.

Under the carbon neutrality target, the energy transition of power systems requires a well-designed long-term generation expansion plan to ensure safe, stable, and low-carbon operation. To address the challenge of centralized planning failing to balance generation expansion and load development effectively, a market-driven multi-stage generation expansion planning (MMGEP) model is proposed, which incorporates the supply function equilibrium model to simulate bidding behavior in the electricity market, leveraging market forces to guide generation planning and incentivize demand response. The MMGEP model is formulated as a game-theoretic optimization problem and further reformulated into a single-layer quadratic programming model to reduce the computational complexity. Moreover, the latest capacity tariff mechanism is integrated into the MMGEP model to evaluate its effectiveness in guiding planning and reducing energy supply costs. Additionally, the optimal capacity tariff pricing range for enhancing the cost competitiveness of thermal power units is identified. A case study based on the latest real-world data from Jiangsu Province in China demonstrates the advantages of the MMGEP model over the centralized planning model and emphasizes the effectiveness of introducing market mechanisms into generation expansion planning.