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This paper presents an evaluation of the impact of extensive introduction of photovoltaic (PV) systems and stationary battery technology into the optimal power gen-eration mix in the Kanto and Kinki regions. The introduc-tion of solar PV systems is expected to be extensively deployed in the Japanese household sector and utility com-panies in order to address the concerns of energy security and climate change. Considering this expected large-scale deployment of PV systems in electric power systems, it is necessary to investigate the optimal power generation mix which is technologically capable of controlling and accom-modating the intermittent output-power fluctuations inher-ent in PV systems. Against this background, we develop both a solar photovoltaic power generation model and an optimal power generation mix model, including stationary battery technology, which can be used to explicitly analyze the impact of PV output fluctuations at a detailed time interval resolution such as 10 minutes for 365 consecutive days. Simulation results reveal that PV introduction does not necessarily increase battery technology due to the cost competitiveness of thermal power plants in the load-follow-ing requirement caused by PV systems. Additionally, on the basis of sensitivity analysis on PV system cost, dramatic cost reduction proves to be indispensable for PV to supply bulk electricity similarly to thermal and nuclear power plants. © 2012 Wiley Periodicals, Inc. Electr Eng Jpn, 182(2): 9-19, 2013; Published online in Wiley Online Library (wileyonlinelibrary.com). [ABSTRACT FROM AUTHOR]

Abstract: There is growing attention to the regulation of greenhouse gas (GHG) emissions to mitigate the global warming, and the target of 50% reduction of GHG emissions by the year 2050 has been discussed in concrete as a long-term goal. The authors have been revising the regionally disaggregated world energy model which is formulated as a large scale linear optimization model from the aspect of nuclear and photovoltaic power generation technologies and calculate the optimal energy system development path over the time horizon with the CO2 emissions constraints. The obtained results indicate that the world electricity in 2050 is to be mainly provided by natural gas-fired power plants and LWR (light-water reactors), and that in 2100 is to be done by FBR (fast breeder reactors) and IGCC with CCS. The results also indicate that the relative importance of major technologies, such as FBR and CCS, may differ significantly due to the regional availabilities of energy resources and CO2 storage capacities. [Copyright &y& Elsevier]

In this paper, a regionally disaggregated global energy model treating energy and CO2 transportation in detail is used to examine a cost-effective pattern for their interregional transportation over the 21st century under the CO2 stabilization target of 550 ppm. Also, we assess future perspectives for the hydrogen economy in such a scenario. The results show that as major petroleum and gas supplies shift to unconventional resources along the second half of this century due to resource depletion, the Middle East loses its importance as a petroleum and gas exporter and the global patterns of their transportation change significantly. We then show that while hydrogen's competitiveness decreases due to the detailed treatment of energy and CO2 transportation, biomass- derived Fischer­Tropsch (FT) fuels become attractive because their production facilitates a wide diffusion of CO2-neutral energy carriers by considerably reducing the transportation cost. FT fuels are produced in regions rich in forest resources and then transported on a large scale by tanker. By contrast, hydrogen is produced mainly at the center of its consumption regions using domestic feedstock, and its interregional delivery, which is done only by pipeline, plays a marginal role due to its high transportation cost. It is confirmed that such a hydrogen supply structure offers energy security benefits. Finally, we show that the regional distribution of CO2 storage capacity is a major determinant of the pattern of hydrogen transportation around 2100, because all the CO2 generated from hydrogen production is required to be captured for sequestration in that period and because interregional CO2 transportation is hardly chosen for economic reasons. [ABSTRACT FROM AUTHOR]

Many efforts towards a settlement of the CO2 problem have already been made through internationally organized meetings. It is not unlikely that some targets will be set for the reduction of CO2 emissions. If a stringent reduction target should be imposed on CO2 emitted from a national energy system, this cw possibly have as severe an impact upon electric power sectors as the oil price crises experienced in the seventies. It is, however, quite uncertain whether or not political muscles will be used specifically for tackling the CO2 problem in the near future. In such a context, this paper presents a new method for optimal power system planning under uncertain CO2 emissions control policies. The derived optimal expansion plan gives us the minimum expected value of the sum of the total system cost and the total amount of carbon taxes levied on net CO2 emissions from fossil fuel-fired power plants. The stochastic dynamic optimization problem discussed here is formulated as a linear programming problem decomposable into several small subproblems. The proposed method can take into account a specific future scenario of the magnitude of control policy uncertainties, which can be presumably resolved in the first half of the next century due to the increase in scientific wisdom. Ln order to evaluate the usefulness of the method proposed here, the authors also present a simple cue study with the Japanese national power system up to the year 2050. [ABSTRACT FROM AUTHOR]

SUMMARY This paper investigates the impact of an extensive introduction of electric vehicles ( EV) and plug-in hybrid vehicles ( PHEV) into the global energy system by 2050. The significant growth of automobile ownership in emerging countries is likely to increase world oil demand and the associated carbon dioxide emissions. In order to address these energy, security, and environmental concerns, the deployment of clean energy vehicles, such as EV and PHEV, is expected to play a crucial role due to their high fuel efficiency. Consequently, we develop both a global energy system model and a world vehicle penetration model, which can explicitly analyze the impact of EV introduction into the seasonal daily electric load curve, with consideration of the specific electricity charging profile through 2050. The simulation results confirm that EV deployment contributes to energy conservation, because oil demand reduction outstrips the growth in electricity demand and the associated fuel input into the power generation mix. Concerning carbon dioxide abatement, the magnitude of the impact relies on the carbon intensity of the power generation mix. If the intensity is low enough to guarantee a carbon mitigation effect due to EV fuel saving, emissions reduction is well assured. It should be noted, however, that in regions with high carbon intensity in the power generation mix, carbon emissions per mileage of EVs is almost equivalent to that of efficient gasoline vehicles such as hybrid vehicles, and the figure for PHEV is slightly higher than for hybrid vehicles. © 2013 Wiley Periodicals, Inc. Electr Eng Jpn, 186(4): 20-36, 2014; Published online in Wiley Online Library (wileyonlinelibrary.com). DOI 10.1002/eej.22373 [ABSTRACT FROM AUTHOR]

In germinal centers (GCs), B cells are selected through interaction with follicular dendritic cells bearing immune complexes and follicular helper T (Tfh) cells secreting Tfh cytokines, including IL-21. To analyze these cellular interactions, we have explored culture conditions that can simulate GC B cell selection in vitro using a mouse follicular dendritic cell line, FL-YB. FL-YB cells efficiently enhanced viability of cocultured mouse B cells in a BAFF-dependent fashion. Interestingly, we found that addition of IL-21, a major Tfh cytokine, readily induced death of B cells that were cocultured with FL-YB cells, whereas IL-21 alone sustained viability of B cells in the absence of FL-YB cells. The IL-21-induced death was dependent on a low m.w. soluble factor that was released from FL-YB cells, which was finally identified as PGE2. Treatment of B cells with IL-21 plus PGE2, but not either alone, resulted in enhanced expression of a proapoptotic protein Bim and the upstream transcription factor Foxo1. A PGE2 receptor isoform, EP4, was responsible for IL-21/PGE2-induced B cell death. Thus, PGE2 is an endogenous chemical mediator that can switch pleiotropic actions of IL-21 on B cells. IL-21/PGE2-induced B cell death was rescued if B cells were costimulated via CD40. In immunized mice, deficiency of IL-21R in B cells led to a significant decrease in the frequency of activated caspase-3-positive GC B cells concomitant with impaired affinity maturation of Abs. Taken together, results implicate a physiological role of IL-21/PGE2-induced B cell death in GC B cell selection. [ABSTRACT FROM AUTHOR]

Decarbonization of the energy system is a key goal of the Paris Agreements, in order to limit temperature rises to under 2° Celsius. Hydrogen has the potential to play a key role through its versatile production methods, end uses and as a storage medium for renewable energy, engendering the future low-carbon energy system. This research uses a global model cognizant of energy policy, technology learning curves and international carbon reduction targets to optimize the future energy system in terms of cost and carbon emissions to the year 2050. Exploring combinations of four exploratory scenarios incorporating hydrogen city gas blend levels, nuclear restrictions, regional emission reduction obligations and carbon capture and storage deployment timelines, it was identified that hydrogen has the potential to supply approximately two percent of global energy needs by 2050. Irrespective of the quantity of hydrogen produced, the transport sector and passenger fuel cell vehicles are consistently a preferential end use for future hydrogen across regions and modeled scenarios. In addition to the potential contribution of hydrogen, a shift toward renewable energy and a significant role for carbon capture and storage is identified to underpin carbon target achievement by 2050. • Global linear optimization model of hydrogens role in the future energy system. • Cognizant of policy, technology learning curves and carbon targets. • Hydrogen is estimated to account for approximately 2% of energy needs by 2050. • Hydrogen to play a prominent role in the transportation sector. • Perverse incentives of different carbon reduction goals investigated. [ABSTRACT FROM AUTHOR]

Abstract Japan is the sixth largest greenhouse gas emitter in 2016 and plays an important role to attain the long-term climate goals of the Paris Agreement. One of the key policy issues in Japan's energy and environmental policy arena is the energy system transition to achieve 80% emissions reduction in 2050, a current policy goal set in 2016. To contribute to the ongoing policy debate, this paper focuses on energy-related CO 2 emissions and analyzes such decarbonization scenarios that are consistent with the government goals. We employ six energy-economic and integrated assessment models to reveal decarbonization challenges in the energy system. The modeling results show that Japan's mitigation scenarios are characterized by high marginal costs of abatement. They also suggest that the industrial sector is likely to have a large final energy share and significant residual emissions under the 80% reduction scenario, though it is generally thought that the transport sector would have large decarbonization challenges. The present findings imply that not only energy policy but also industrial policy may be relevant to the long-term environmental target. Given the high marginal costs exceeding those of negative emissions technologies that could place a cost ceiling, further model development would be crucial. Highlights • We analyze the energy system scenarios to achieve 80% reduction in carbon dioxide emissions by 2050. • We employ six integrated assessment models to reveal decarbonization challenges in the energy system. • The model results show that the industrial sector has a large final energy share and significant residual carbon dioxide emissions under the 80% reduction scenario. • We also show that Japan's mitigation scenarios are accompanied with high marginal costs of abatement. [ABSTRACT FROM AUTHOR]

Abstract In this study, the authors developed an Optimal Power Generation Mix model, which takes into account the supply chain of imported and domestically produced hydrogen, also modeling the intermittency of renewable energy at a 10-min resolution, and applied it to the case of Japan, to investigate quantitatively the possibility of achieving zero emission in 2050. Even if the costs of wind and solar PV decline drastically towards 2050 and the huge potentials that have been assumed in the literature are realized, the total system costs escalate significantly with very high shares of intermittent renewables. Since the use of hydrogen produced by excess electricity from renewable power generation sources can only make a slight contribution to reducing this escalation, it would be invaluable to introduce at least a significant amount of electricity generated by "zero-emission thermal power" technologies, including CO 2 -free imported hydrogen or conventional thermal power generation with carbon capture and sequestration (CCS). Nuclear power is also estimated as being effective in reducing the cost hike associated with achieving zero emissions. The results of this study could contribute to giving insights regarding global deployment of hydrogen-related technologies, as well as to presenting a frame of reference for Japan's future energy policies. Highlights • Variable renewables can contribute greatly to zero emission power in 2050 in Japan. • A very high share of them, however, could escalate the total cost to 20–30 JPY/kWh. • "Zero emission thermal" power generation is a necessity to meet the 2050 target. • Use of imported hydrogen is one possibility for zero emission thermal power. • Use of nuclear power is also an effective way to reduce the cost escalation. [ABSTRACT FROM AUTHOR]

Climate change significantly impacts hydrological systems resulting in hydropower generation uncertainties. In this study, a high-resolution glacio-hydrological model is coupled with an hourly-resolution power grid model to evaluate the climate change influences on hydropower generation across Nepal. Four climate future scenarios namely Cold-Dry, Warm-Dry, Cold-Wet, and Warm-Wet are developed to compare the changes in water availability and optimal power system with historical climate. The total flow increases for the wet scenarios (+11.4% under Cold-Wet for the Koshi basin), compared to the dry scenarios (−24.6% under Warm-Dry for the Karnali basin) for all the major river basins in Nepal. The results illustrate the distribution and magnitude of changes in total water availability and power generation are not proportional for dry and wet scenarios as a ∼20% reduction of water availability in the dry scenarios only results in a ∼2–3% decrease in electricity generation. The capacity requirements of hydro storage decrease by 7.2 GW for Cold-Wet and 6.8 GW for Warm-Wet scenarios compared to historical climate indicating higher capacity requirements in dry scenarios. Larger impacts observed at higher altitudes suggest more attentive adaptation strategies in developing climate-resilient hydropower systems. Results suggest that Nepal should not be entirely focused on exploiting its hydropower potential but rather diversifying the generation mix including solar PV and hydrogen technology. For the least-cost power system expansion, the Warm-Wet climate appears to be the most desirable and a cost savings of about 3.76 billion USD in hydropower development can be realized if better adaptation strategies are employed. [Display omitted] • Climate change impacts on hydro-dominated power systems in a high-mountain country. • Coupling of glacio-hydrological model and a high spatial-temporal power grid model. • Adaptation strategies for surplus electricity management are more critical in wet scenarios. • Storage hydro capacity needs drop by 7.2 in Cold-Wet & 6.8 GW in Warm-Wet scenarios. • Employing adaptation strategies results in cost savings of about 3.76 billion USD. [ABSTRACT FROM AUTHOR]

• Estimated the cost of a zero emission power sector with 28-yearly data. • Power storage requirement is decided by the duration of "windless & sunless" periods. • A "cumulative residual load" approach can correctly estimate the storage requirement. • Use of "power to gas" technologies can reduce the total system cost significantly. • Firm capacities are required even in a case with very high renewable penetrations. In recent years, several studies have been published focusing on the economics of the power sector under the high penetration of variable renewable energy (VRE) following the rapid expansion of VRE capacities worldwide. However, detailed analyses of the fluctuations in meteorological conditions have hitherto been scarce, despite the expectation that VRE output will be significantly affected by them. To fill this gap, we investigated the economic likelihood of achieving a zero-emission power system in Japan by 2050, using multi-annual meteorological data from 1990 to 2017. We used a detailed linear programming optimization model, as well as a method that uses cumulative residual loads (CRL), which proved to be useful for estimating required energy storage capacities and for understanding the complex substitution of power generation and storage technologies. The estimated unit cost for a 100% renewable electricity system depends heavily on meteorological conditions, standing at 20.9 JPY/kWh with a standard deviation of 1.2 JPY/kWh, which declines to 18.3 JPY/kWh with a standard deviation of 0.6 JPY/kWh for a system with hydrogen storage. The calculations indicate that the required storage capacity is determined mainly by the duration of "windless and sunless" periods, or "dark doldrums", and the greatest risk under high VRE penetrations is the possibility of supply disruption during such periods. The results also highlight the considerable value of "firm capacities", such as thermal and nuclear power generation, under a high share of VRE, although it should be noted that the profitability of these capacities may differ significantly from current situations, with large VRE outputs with negligible marginal costs. [ABSTRACT FROM AUTHOR]