Many electricity economists have long hoped that it might be possible to establish competition, not just in providing generation and load assets, but also in the provision of the transmission network itself. Attempts in the 1990s to achieve so-called merchant transmission investment using conventional Financial Transmission Rights (FTRs) proved disappointing. We develop an extension of screening-curve models to include the optimal choice of both generation and transmission. Such models, although stylised, provide valuable insight into the long-run co-optimisation of generation and transmission. We propose new regulatory and merchant transmission investment mechanisms that achieve the socially optimal investment.

Photovoltaic panels, electric vehicles, and vehicle-to-grid technologies are becoming more common and hold significant promises to improve the grid and foster the energy transition. However, significant questions remain unanswered with respect to who should invest in this equipment and what tariff should be used. This paper examines whether the distribution company or prosumer should invest in and manage Distributed Energy Resources (DER), the ideal combination of DER to utilize, and the appropriate tariff to implement. Central to this analysis is the assessment of different stakeholder objectives, particularly from the investor's perspective, where net present value is used as the primary criterion for evaluating the different investment scenarios. Additionally, the impact of these scenarios on the annual system cost is calculated. A mathematical scenario analysis model is developed to simulate the operation of DER and energy management systems. This model utilizes the Vermont electricity grid's real-world consumption, generation data, and cost structures. The results underscore the significance of incorporating vehicle-to-grid technology to enhance the profitability of DER investments. This inclusion of specific data sources and stakeholder criteria aims to provide insight into the complex dynamics of smart-home deployment.

From January 2021 to March 2022, wholesale Spanish spot electricity prices reached a record high of €700/MWh. Surprisingly, hydropower set the marginal market price for 52% of the hours in 2021 and 43% in the first quarter of 2022. Combined-cycle gas-fired units, which typically determine the marginal price, were marginal in only 16% and 21% of the hours in 2021 and 2022, respectively. Hydropower set prices between 3% and 12% higher than an estimate of their opportunity cost, and they were responsible for charging 69% of the prices above €500/MWh. The empirical evidence suggests that 2021 was an unusual year compared to 2018 and 2019 because the role played by hydropower as a marginal price setter was relatively more prominent.