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Climate change mitigation requires developing zero-carbon, highly renewable energy systems, which require technologies to capture excess renewable electricity such as energy storage. Endeavoring to capture all available excess renewable electricity, however, may require large energy storage capacities and costs. This study therefore investigates how much curtailment is cost-optimal to allow in developing fully decarbonized electricity systems, using compliance with California's Senate Bill 100 goal as a representative case study. We combine electric grid dispatch modeling with an optimization approach for selecting the composition of energy storage technologies to capture excess renewable electricity to minimize overall system costs. We found that overbuilding cheap wind and solar and allowing the curtailment of excess renewable electricity equivalent to 25–43% of the total annual electric load resulted in the lowest cumulative systemwide cost for a fully decarbonized electricity system of about $1.8 trillion, spent between 2020 and 2045. Allowing no renewable curtailment results in significant battery requirements and a cumulative systemwide cost of $5.2 trillion spent between 2020 and 2045. Therefore, allowing some curtailment reduced the cost of building a fully decarbonized electricity system by a factor of 3 when the portfolio of technologies to capture and manage excess renewable electricity is carefully chosen. • Examined cost-minimal renewable curtailment levels for a zero-carbon grid. • Assessed cost-optimal technology mixes for harnessing excess renewable electricity. • Overbuilding renewable capacity is cheaper than vastly expanding energy storage. • Long duration storage is critical to minimize costs to build a zero-carbon grid. • Power-to-gas is well suited for long duration storage alongside batteries. [ABSTRACT FROM AUTHOR]

Demand for electricity is expected to increase significantly in the coming decades, one reason being the ongoing decarbonization process of the power and the transportation sectors, in an effort to reduce greenhouse gas emissions and thus alleviate climate change. Photovoltaics that harvest solar energy, coupled with energy storage systems are addressing these challenges effectively. In the current study, the simulated energy winnings from typical photovoltaic-battery (PV-BAT) configurations were economically evaluated, under equal technical and site-specific meteorological conditions. Furthermore, their capital, replacement, operation, and maintenance costs were inquired and the average unit cost of electricity per kWh was estimated based on specific energy cost estimation methods and a Monte-Carlo analysis addressing uncertain meteorological risk factors. The cost of electrical energy production in Greece was examined for six scenarios with varying battery technologies and module topologies. Calculated costs ranged from 0.17 to 0.24 €/kWh indicating a significant downward trend in the unit cost of electricity generated by PV-BAT systems. These findings indicate the need for further investigation into how the integration and utilization of such systems can be optimized. The proposed methodology is developed in line with the circular economy action plan which requires increased system efficiency, storage and renewable energy use. • Techno-economic assessment of six different PV-Battery scenarios. • A methodology was developed in line with the circular economy action plan. • Meteorological conditions used as risk factors, affecting energy generation. • Low Price-performance ratio for PV systems backed by lithium-ion batteries. • LCOE for all examined scenarios ranged from 0.17 to 0.24 €/kWh. [ABSTRACT FROM AUTHOR]

Accelerating the penetration of photovoltaics (PV) oriented renewables is a vital mainstay in climate mitigation. Along with continuous growth of PV generation in the power system, PV costs have been rapidly declining. Levelized cost of electricity (LCOE) is commonly applied to cost accounting of energy, while neglecting the specific cost compositions of PV leads to an overly optimistic scenario. By integrating grid costs and balancing costs into conventional LCOE framework, a System LCOE (S-LCOE) model was constructed to evaluate the economic feasibility of PV generation, more accurately. The results revealed that all provincial S-LCOE of China's PV is currently higher than local desulfurized coal electricity price (DCEP). Based on the comparative analysis of provincial S-LCOE and DCEP, four regions with diverse economic competitiveness were identified. PV projects in Region I and Region II are considered to be potentially competitive comparing to thermal generation, in terms of environmental benefits and S-LCOE, especially in Guangdong, Jilin, and Hainan. Furthermore, by simulating the descent trajectory of S-LCOE, we estimate that China will achieve S-LCOE equal to DCEP in Region I as early as 2023, while it will be postponed to 2042 in Region Ⅳ at the latest, depending on different S-LCOE descent rates. [Display omitted] [ABSTRACT FROM AUTHOR]

Accelerating the penetration of photovoltaics (PV) oriented renewables is a vital mainstay in climate mitigation. Along with continuous growth of PV generation in the power system, PV costs have been rapidly declining. Levelized cost of electricity (LCOE) is commonly applied to cost accounting of energy, while neglecting the specific cost compositions of PV leads to an overly optimistic scenario. By integrating grid costs and balancing costs into conventional LCOE framework, a System LCOE (S-LCOE) model was constructed to evaluate the economic feasibility of PV generation, more accurately. The results revealed that all provincial S-LCOE of China's PV is currently higher than local desulfurized coal electricity price (DCEP). Based on the comparative analysis of provincial S-LCOE and DCEP, four regions with diverse economic competitiveness were identified. PV projects in Region I and Region II are considered to be potentially competitive comparing to thermal generation, in terms of environmental benefits and S-LCOE, especially in Guangdong, Jilin, and Hainan. Furthermore, by simulating the descent trajectory of S-LCOE, we estimate that China will achieve S-LCOE equal to DCEP in Region I as early as 2023, while it will be postponed to 2042 in Region Ⅳ at the latest, depending on different S-LCOE descent rates. [Display omitted] [ABSTRACT FROM AUTHOR]

The energy sector has a vital role in climate change mitigation. In Brazil, the electricity generation sector is strongly dependent on hydropower generation, but thermoelectricity contribution has increased leading to a more carbon-intensive electricity mix. This trend will be aggravated with the expected significant increase in the electricity demand until 2050 and with the potential limitation of hydropower generation expansion due to environmental constraints. The extent of the role of solar power to overcome these challenges in the future has been hidden by energy modelling assumptions. A review on how solar energy has been considered in different models, was performed. The research further assessed the relevance of assumptions by developing an optimization model to explore the cost-effectiveness of solar electricity large-scale deployment up to 2050. The work found that most published solar energy assessments based on long-term energy modelling for Brazil currently are not updated regarding several assumptions, leading to models results where solar appears with a marginal role. The energy modeling exercise shows solar PV is cost-effective for Brazil, providing more than 36% of total electricity in 2050. This is a different conclusion from the energy and power modeling exercises conducted until now, where solar deployment has been underestimated. • The work assesses how energy model inputs have affected solar cost-effectiveness for Brazil. • Assumptions on hydropower expansion and technology costs critically affect solar cost-effectiveness. • Energy model exercises have underestimated the potential of solar energy in Brazil. • Solar energy may have an important role in the future Brazilian power sector. [ABSTRACT FROM AUTHOR]

Decarbonizing electricity generation through deployment of renewable technologies such as wind and solar is a key component of many climate change mitigation efforts. With increasing penetrations, the need to manage variability in renewable generation becomes critical. However, renewable variability is often poorly represented in energy planning studies which focus on energy and capacity adequacy. In this study, we used a hybrid capacity expansion and dispatch model with explicit inclusion of ramping and regulation services to examine balancing requirements in a decarbonizing electricity system. We find that ramping and regulation services needed for management of variable renewables alter the optimal mix of generation and transmission capacity relative to simpler planning models. In particular, we find enhanced value in expanding transmission capacity to access flexibility. • Representing short-term constraints in long-term energy models changes the outcome. • Flexibility is a key constraint in systems with high penetrations of renewables. • Interregional transmission can help provide system flexibility. [ABSTRACT FROM AUTHOR]

Whether an enormous untapped hydropower resource should be utilized domestically by heavily electrifying energy end-uses or should be exported to neighboring countries is often debated in Nepal. This study attempts to bring both policy options together and justifies with evidence the need to integrate end-use electrification and cross-border electricity trade policies in the energy transformation of Nepal. We found out that Nepal will continue to import electricity till 2027 to meet its electricity demand throughout the year though it has already started exporting its surplus electricity during the wet season because of the full availability of run-of-river type hydropower. The run-of-river will continue to dominate Nepal's least-cost generation mix with a two-thirds share resulting in considerable surplus electricity during the high-flow season. Such surplus will exceed one-third of its total energy generation capacity in long-run in all end-use electrification scenarios (low to high). Nepal can use its existing cross-border electricity trade mechanism to sell its surplus electricity and can generate revenue of 67 billion USD in the high electrification scenario, which, combined with savings from fossil fuel import savings, can provide 85 % of total electricity generation investment needs. [ABSTRACT FROM AUTHOR]

Abstract: The intensity of market penetration and hence the relevance of clean energy technologies in mitigating climate change will greatly depend on their cost-effectiveness. This paper discusses the economic and policy aspects of speeding up the market of these technologies to reach cost parity. A combination of historical energy market dynamics, technology diffusion and endogenous learning models were employed in the analyses. Starting from giving a preferential position to emerging renewable energy technologies in the energy and climate policy, which also means securing adequate financial resources for their deployment, could lead in the base scenario to a full-cost breakthrough of wind power around 2027 and of photovoltaics in 2032. The combined global market share of renewable electricity in 2050 could reach 62% of all electricity (now 19%) of which wind and solar power alone could account for almost two-thirds corresponding to a carbon saving in the range of 8–16 GtCO2. However, if the new technologies were downgraded in the energy and climate policy context, the combined impact of solar and wind could remain at no less than 11% which would marginalize these technologies in the fight against climate change. The estimates for financial support to achieve cost parity were very sensitive to the assumptions of the input parameters: in the base case the extra costs or learning investments for solar power were €1432 billion and for wind power €327 billion, but with more conservative input data these values could grow manifold. On the other hand, considering the potentially cheaper electricity from new technologies above the cost parity point and putting a price on carbon could result in a positive yield from public support instead of it being regarded merely as unnecessary spending. The findings stress the necessity of long-term policies and strong commercialization strategies to bring the new energy technologies to breakeven point, but also highlight the complexity of assessing the true costs of making new energy technologies fully competitive. [Copyright &y& Elsevier]