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Although hydropower produces a relatively small portion of the electricity we use in the United States, it is a flexible and dispatchable resource that serves various critical functions for managing the electricity grid. Climate-induced changes to water availability will affect future hydropower production, and such changes could impact how the areas where the supply and demand of electricity are balanced, called balancing authority areas, are able to meet decarbonization goals. We calculate hydroclimate risk to hydropower at the balancing authority scale, which is previously underexplored in the literature and has real implications for decarbonization and resilience-building. Our results show that, by 2050, most balancing authority areas could experience significant changes in water availability in areas where they have hydropower. Balancing areas facing the greatest changes are located in diverse geographic areas, not just the Western and Northwestern United States, and vary in hydropower generation capacity. The range of projected changes experienced within each balancing area could exacerbate or offset existing hydropower generation deficits. As power producers and managers undertake increasing regional cooperation to account for introducing more variable renewable energy into the grid, analysis of risk at this regional scale will become increasingly salient.

The change in the global energy production mix towards variable renewable energy sources requires efficient utilization of regulated rivers to optimise hydropower operations meet the needs of a changing energy market. However, the flexible operation of hydropower plants causes non-natural, sub-daily fluctuating flows in the receiving water bodies, often referred to as ‘hydropeaking’. Drastic changes in sub-daily flow regimes undermine attempts to improve river system health. Environmental decision makers, including permitting authorities and river basin managers facing the intense and increasing pressure on river environments, should consider ecosystem services and biodiversity issues more thoroughly. The need for research innovations in hydropeaking operation design to fulfil both the water and energy security responsibilities of hydropower is highlighted. Our paper outlines optimized hydropeaking design as a future research direction to help researchers, managers, and decision-makers prioritize actions that could enable better integration of river science and energy system planning. The goal of this is to find a balanced hydropower operation strategy.

Integrated water-energy management is crucial for balancing socioeconomic and environmental objectives in multi-reservoir systems. Multipurpose reservoirs support clean energy production, recreation, navigation, and flood protection but also disrupt natural water flows and fish migration. As hydropower’s role evolves with grid decarbonization, managing these tradeoffs becomes increasingly complex. An integrated model combining economic and environmental factors is essential to inform how to adapt hydropower operations effectively to complement decarbonization of the electric grid. However, existing literature lacks such comprehensive models. This study introduces an integrated water-energy optimization model using the Columbia River Basin (CRB) and Mid-Columbia energy market as a case study. The model couples a simulation of operations of 47 CRB reservoirs with a unit commitment/economic dispatch model of the California and West Coast Power system. We employ Direct policy search and a multi-objective evolutionary algorithm to optimize four objectives: maximize economic benefits from energy production, minimize fossil fuel electricity generation, minimize environmental flow violations, and minimize peak flood levels. Our findings reveal that the integrated model discovers superior operational strategies compared to existing rules, with some policies outperforming current operations on all objectives simultaneously. Insights from the optimized policies include strategies for improved coordination of reservoir operations using storage and inflow data, and the strategic timing of water releases to ensure increased hydropower production leads to less fossil fuel dependence and greater revenue. These results highlight the potential of integrated models to enhance the sustainability of hydropower operations amid a transitioning energy landscape.

The Grand Ethiopian Renaissance Dam (GERD) on the Nile is expected to influence many ecosystem services, such as flood regulation, hydro-electricity production, food supply, and habitat provision, among others. Understanding these impacts (positive and negative) requires a comprehensive evaluation framework. This study develops and applies an integrated simulation framework for assessing the impacts of the GERD on Sudan, focusing on the simultaneous economywide effects of riverine flood hazards, irrigation water supply, hydropower generation, and floodplain-dependent industries, namely traditional fired clay brick production. The simulation framework incorporates three models: a river infrastructure system model, a flood model, and a Computable General Equilibrium Model. Results indicate positive impacts for hydropower generation and flood control, marginal benefits for water supply to existing irrigation, and negative consequences for brick production and the construction sector. Assuming that the GERD starts its long-term operation in 2025, we find an overall positive economic impact on Sudan’s Gross Domestic Product in 2025, with an increase of up to just over 0.1%, subject to river flow conditions. Recognizing the differences in impacts across sectors and income groups, the study emphasizes the need for interventions that ameliorate negative effects. While the study captures several impacts, other effects on the environment, recession agriculture, and soil fertility require further investigation. Still, our findings underscore the importance of adopting an integrated simulation approach to dam evaluation, acknowledging the interconnected nature of water and related sectors in national economies.

The renewable energy transition is leading to increased electricity trade between the United States and Canada, with Canadian hydropower providing firm lower-carbon power and buffering variability of wind and solar generation in the U.S. However, long-term power purchase agreements and transborder transmission projects are controversial, with two of four proposed transmission lines between Quebec, Canada and the northeast U.S. cancelled since 2018. Here, we argue that controversies are exacerbated by a lack of open-source data and tools to understand tradeoffs of new hydropower generation and transmission infrastructure in comparison to alternatives. This gap includes impacts that incremental transmission and generation projects have on the economics of the entire system, for example, how new transmission projects affect exports to existing markets or incentivize new generation. We identify priority areas for data synthesis and model development, such as integrating linked hydropower and hydrologic interactions in energy system models and openly releasing (by utilities) or back-calculating (by researchers) hydropower generation and operational parameters. Publicly available environmental (e.g. streamflow, precipitation) and techno-economic (e.g. costs, reservoir size,) data can be used to parameterize freely usable and extensible models. Existing models have been calibrated with operational data from Canadian utilities that are not publicly available, limiting the range of scientific and commercial questions these tools have been used to answer and the range of parties that have been involved. Studies conducted using highly resolved, national-scale public data exist in other countries, notably, the United States, and demonstrate how greater transparency and extensibility can drive industry action. Improved data availability in Canada could facilitate approaches that (1) increase participation in decarbonization planning by a broader range of actors; (2) allow independent characterizations of environmental, health, and economic outcomes of interest to the public; and (3) identify decarbonization pathways consistent with community values.

Located in Southern Europe, the Drina River Basin is shared between Bosnia and Herzegovina, Montenegro, and Serbia. The power sectors of the three countries have an exceptionally high dependence on coal for power generation. In this paper, we analyse different development pathways for achieving climate neutrality in these countries and explore the potential of variable renewable energy (VRE) and its role in power sector decarbonization. We investigate whether hydro and non-hydro renewables can enable a net-zero transition by 2050 and how VRE might affect the hydropower cascade shared by the three countries. The Open-Source Energy Modelling System (OSeMOSYS) was used to develop a model representation of the countries’ power sectors. Findings show that the renewable potential of the countries is a significant 94.4 GW. This potential is 68% higher than previous assessments have shown. Under an Emission Limit scenario assuming net zero by 2050, 17% of this VRE potential is utilized to support the decarbonization of the power sectors. Additional findings show a limited impact of VRE technologies on total power generation output from the hydropower cascade. However, increased solar deployment shifts the operation of the cascade to increased short-term balancing, moving from baseload to more responsive power generation patterns. Prolonged use of thermal power plants is observed under scenarios assuming high wholesale electricity prices, leading to increased emissions. Results from scenarios with low cost of electricity trade suggest power sector developments that lead to decreased energy security.

Reservoir-based hydropower systems represent key interactions between water and energy systems and are being transformed under policy initiatives driven by increasing water and energy demand, the desire to reduce environmental impacts, and interacting effects of climate change. Such policies are often guided by complex system models, whereby divergence in system representations can potentially translate to incompatible planning outcomes, thereby undermining any planning that may rely on them. We review different approaches and assumptions in hydropower representation in water and energy systems. While the models and issues are relevant globally, the review focuses on applications in California given its extensive development of energy and water models for policy planning, but discusses the extent to which these observations apply to other regions. Structurally, both water-driven and energy-driven management models are similar. However, in energy models, hydropower is often represented as a single-priority output. Water management models typically allocate water for competing priorities, which are generally uninformed by dynamic electricity load demand, and often result in a lower priority for hydropower. In water models, constraints are increasingly resolved for non-energy components (e.g. inflow hydrology and non-energy water demand); few analogues exist for energy models. These limitations may result in inadequate representations of each respective sector, and vastly different planning outcomes for the same facilities between the two different sectors. These divergent modeling approaches manifest themselves in California where poorly reconciled outcomes may affect decisions in hydropower licensing, electricity grid flexibility and decarbonization, and planning for environmental water. Fully integrated water-energy models are computationally intensive and specific to certain regions, but better representation of each domain in respective efforts would help reconcile divergences in planning and management efforts related to hydropower across energy and water systems.

To feed the growing population, achieve the Sustainable Development Goals, and fulfil the commitments of the Paris Agreement, West African countries need to invest in agricultural development and renewable energy, among other sectors. Irrigated agriculture, feeding millions of people, and hydropower, generating clean electricity, depend on water availability and compete for the resource. In the Volta basin, the planned 105 000 ha of irrigated land in Burkina Faso and Ghana could feed hundreds of thousands of people. However, irrigation in the dry season depends on upstream dams that change the river’s flow regime from intermittent to permanent, and at the same time irrigation water is no longer available for hydropower generation. Using an integrated eco-hydrological and water management model, we investigated the water demand and supply of three planned irrigation projects and the impacts of the planned Pwalugu multi-purpose dam on the hydropower potentials and water availability in the entire Volta basin. We found that future irrigation withdrawals would reduce the hydropower potential in the Volta basin by 79 GWh a ^−1 and the operation of Pwalugu by another 86 GWh a ^−1 . Hence, Pwalugu contributes only about 101 GWh a ^−1 of its potential of 187 GWh a ^−1 . Under climate change simulations, using an ensemble of eight bias-adjusted and downscaled GCMs, irrigation demand surprisingly did not increase. The higher evaporation losses due to higher temperatures were compensated by increasing precipitation while favouring hydropower generation. However, water availability at the irrigation site in Burkina Faso is clearly at its limit, while capacity in Ghana is not yet exhausted. Due to hydro-climatic differences in the Volta basin, the cost of irrigating one hectare of land in terms of lost hydropower potential follows a north-south gradient from the hot and dry north to the humid south. Nevertheless, food production should have priority over hydropower, which can be compensated by other renewables energies.

Hydropower plays a significant role in the transition towards a low-carbon power system, being a renewable energy source that can complement solar and wind power, which are highly intermittent. However, hydropower is itself dependent on local weather conditions and climate variability. Moreover, extreme climate conditions, such as hot-dry compound events, can have a major impact on hydropower production (HP). Here, we examine the impacts of hot-dry conditions on HP under current and future climate scenarios in Switzerland, a country where hydropower provides the biggest share (60%) of the total electricity production. Overall, our results point out that the impacts of hot-dry conditions on HP are case-specific. We found that hot-dry compound conditions during the warmer months negatively impact HP in power plants with little or no water storage capacity (run-of-river schemes). On the contrary, schemes with large, seasonal accumulation lakes and significant glacier resources will continue to be able to produce high amounts of HP during hot-dry conditions in summer, which is an important result for Alpine hydropower.

Production cost models (PCMs) simulate dispatch of generators across a large power grid and are used widely by planners to study the reliability of electricity supply. As energy systems transition away from the thermoelectric technologies that have traditionally balanced electricity supply and demand, hydropower and its representation in PCMs is of increasing importance. A limitation of PCMs applied to continental power grids with diverse generation portfolios is that hydropower generation is simulated without full consideration of complex river dynamics, leading to possible misrepresentation of grid flexibility and performance. In addition, data used in PCMs may reflect outdated operating policies. In this paper we propose a hydropower generation feasibility test for PCMs. The approach uses a detailed hydropower model to determine whether the hourly hydropower schedule from a PCM with simplified monthly parameterization can be attained after accounting for realistic river dynamics and operating policies, such as spill requirements and general water movement and balance through a cascade reservoir system. We perform this hydropower generation test for the ‘Big 10’ hydropower system on the Columbia River (part of the Western Interconnect of the United States), revealing 9% overestimation of available hydropower generation in a PCM solution in an average hydrologic year. Our evaluation provides insight on the cost and opportunities for better representing hydropower in PCMs.

Renewable energy is the key to reducing greenhouse gas emissions, and is one of the most concerning issues worldwide. China has the largest hydropower potential in the world. Yet, how China’s hydropower potential will change under 1.5 °C and 2.0 °C global warming and beyond remains unknown. Here, we find that China’s hydropower will increase greatly because of global warming. Gross hydropower potential (GHP) will increase by about one-half compared to the baseline period (1986–2015) under 1.5 °C and 2.0 °C warming, and about two-thirds under 4.5 °C warming. The spatial and temporal changes in GHP will vary largely. GHP will increase relatively more in summer than in winter, and more in Southwest China than in other regions. Compared to GHP, increases in per-capita GHP will be relatively less under 1.5 °C (5%) and 2.0 °C (7%) warming, but of a similar magnitude under 4.5 °C warming (71%). This study provides important information on China’s hydropower potential changes under global warming.

Hydroelectric power is playing a new and often expanded role in the world’s major power grids, offering low carbon generating capacity in industrializing, dam-building economies while providing reserve and flexibility to co-manage fledgling wind and solar resources in high income countries. Driven by river flows, conventional hydropower is exposed to the vagaries of weather and climate, motivating drought and climate change hydropower impact studies at large spatial scales. Here we review methods of climate-driven hydropower simulation at large spatial scales, specifically multi-basin regions to global. We identify four types of approach based on complexity of tools and richness of data applied to the problem. Since the earliest attempts to model climate-driven hydropower at continental scale almost two decades ago, the field has transitioned from one of scientific curiosity to practical application, with studies increasingly motivated by the need to inform power grid expansion planning and operation. As the hydrological and water management models used in large-scale hydropower studies become more sophisticated, new opportunities will emerge to study the impacts of changing hydropower on power system reliability and performance at large power grid scale. To grasp these opportunities, the water resources community must continue to enhance data and models for representing river flows and anthropogenic water use and management at subcontinental to global scales.

This study aims to review the existing literature on the past and future effects of climate, land use, and land cover changes on hydropower generation in West Africa (WA), based on listings in the Scopus and Google Scholar databases. This review shows that several African hydropower plants have experienced repeated power disruptions over the last three decades due to climate change and variability but it is less documented how increasing land use and land cover changes around the major dams have impacted the hydrological system and the hydropower generation. In the future, the risks of hydropower in WA may not be equally distributed within a country or region. Despite uncertainties in precipitation and on impacts on streamflow and water level in major basins, climate change is likely to reduce the available water over the range of 10%–20% (15%–40%) for the RCP4.5 (RCP8.5) scenario by 2050, which may considerably affect the water demand across all sectors, including hydropower. However, in the Kainji dam (Niger River basin), models project an increase in rainfall favorable to hydropower production for both RCP4.5 and RCP8.5. In contrast, within the Black Volta sub-basin, the intensification of land use is predicted to favor runoff and, consequently, an increase in the generation of Bui hydropower in the near future, even though models predict a rainfall decrease. This increase in land use for agriculture to feed a growing population has other adverse effects that need to be assessed, namely sedimentation and siltation, which are harmful to hydropower plants. Finally, the combined impact of climate and land use changes on the efficiency of hydroelectric infrastructure in WA is not well documented, while sustainable planning and investments in the hydropower sector require consideration of the nexus between climate, land use changes, and water.

As the largest renewable energy source, hydropower is essential to the sustainability of the global energy market. However, a considerable amount of water can be lost in the form of evaporation from the associated multipurpose reservoirs, and hence enlarge the blue water footprint (BWF) of hydropower in a warming climate. To facilitate the sustainable management of both water and energy resources under the impact of climate change in the contiguous United States (CONUS), the BWF values of 143 major multipurpose reservoirs were evaluated during the historical period (1985–2014) and two future periods (2020–2049 and 2070–2099). The historical reservoir evaporation loss was calculated using the Landsat-based reservoir surface area and a new evaporation rate algorithm that considers the heat storage effect. Future projections of runoff availability, hydropower generation, and reservoir evaporation were estimated based on the downscaled climate model ensemble from phase 5 of the Coupled Model Intercomparison Project. It was found that the BWF for the CONUS is highly spatially heterogeneous, with an average value of 26.2 m ^3 MWh ^−1 in the historical period. In the future, the BWF values are projected to increase under both Representative Concentration Pathway (RCP) 4.5 and 8.5 scenarios. This is especially noticeable under RCP 8.5, which has an average BWF value of 30.2 m ^3 MWh ^−1 for 2070–2099 (increasing by 15.3% from 26.2 m ^3 MWh ^−1 ). The uncertainty ranges increase even more, from 3.4 m ^3 MWh ^−1 during 2020–2049 to 5.7 m ^3 MWh ^−1 during 2070–2099. These findings can benefit water and energy resources management in identifying suitable environmental, economic, operational, and investment strategies for multipurpose reservoirs in a changing environment.

EU Member States are progressively decarbonizing their electricity systems by replacing fossil fuels with renewable sources to achieve rapid greenhouse gases emissions reductions. While the planned decarbonized system will be more resilient to hydroclimatic change than existing water-dependent portfolios, water availability and temperature are still influential factors during this transition to a carbon neutral electricity system, with potential negative impacts on the economy and the environment. Here, we conduct a model-based analysis to assess the impacts of hydroclimatic change on EU decarbonization strategies in two regions, the Iberian Peninsula (IP) and the Danube river basin, characterized by a high share of water-dependent energy sources and expected to be highly affected by climate change. We find that, under the reference electricity system scenario for 2040 aligned with the EU climate and energy strategies, generation from fossil fuels increases, in particular from combined cycle gas turbine plants, to balance the reduction of hydro generation consistently observed in the hydroclimatic scenarios examined. This reduction, in conjunction with increased thermal plants shutdown events due to high water temperature especially in the IP, produces load cuts undermining the reliability of the electricity system. Moreover, increased fossil fuel use results in higher generation costs and carbon intensity, jeopardizing emissions reduction targets and ultimately slowing down the decarbonization process.

Reducing global carbon emissions will require large-scale transitions from fossil fuels to renewable energy resources. Hydropower will likely play a role in those transitions as it provides reliable energy storage while counter-balancing intermittent renewables. However, the construction of new dams comes at significant environmental costs to river ecosystems. An optimal future considers how to maximize the benefits of hydropower while minimizing environmental impact through revitalizing existing infrastructures. Herein, we quantify this potential using a spatially comprehensive global inventory of geolocated dams used for purposes other than hydropower, and augment these results with modelled estimates of small, unmapped dams. Furthermore, we examine increases in hydropower potential from efficiency upgrades at existing hydro-plants. These opportunities afford non-invasive increases in hydropower in populated areas neighbouring biodiversity hot spots. Overall, we estimate that these contributions could potentially provide up to a 9% increase to current global hydropower, potentially reducing the costs of construction and transmission, all while offsetting impacts to biodiversity and river ecosystems incurred by planned new hydropower construction.

Dams have fragmented rivers and threatened aquatic biodiversity globally. However, the findings regarding dam impacts on riverine macroinvertebrates vary across regions and taxa. We conducted a global meta-analysis to quantify the effects of dams on macroinvertebrate assemblages (i.e. species richness and abundance) based on 3849 data points extracted from 54 publications. Responses of macroinvertebrates to dams varied among climatic zones, dam altitudes, dam sizes (i.e. height), downstream distances from the dams, and taxonomic groups. The overall effect size of dams on macroinvertebrate richness was negative, while that of dams on abundance was positive but varied among different dam types. Richness reductions were most pronounced in cold regions and high-altitude regions and were least pronounced in tropical regions and low-altitude regions, while abundance increases were more obvious in tropical regions and low-altitude regions. Macroinvertebrate richness reduction and abundance increase were coupled (i.e. when the richness slightly decreased, the increase in abundance was more significant, and vice versa) under the influence of dams across different climatic zones, altitudes, dam heights, and downstream distances from the dams. Furthermore, different taxonomic groups responded variably to dams, with stoneflies (Plecoptera), caddisflies (Trichoptera) and true bugs (Hemiptera) being the most sensitive groups (i.e. significant reduction in richness) among the taxa examined. Macroinvertebrate richness reductions were primarily attributed to changes in downstream substrate composition (i.e. from coarse to fine substrates), while abundance increases were potentially caused by replacements among taxa at downstream sites. Collectively, our results contribute to improving the prediction of the effects of dams on riverine macroinvertebrate assemblages and are valuable for guiding assessment and monitoring of river ecosystems, as well as sustainable dam development, planning and restoration.

Despite efforts to understand the hydrologic impact of hydropower dams, their influence on downstream river temperatures has gone unnoticed in data limited regions. Using 30 years of Landsat thermal infrared observations (1988–2018), we identified a relationship between dry season water temperature cooling trends and dam development in the 3S Basin, a major tributary of the Mekong River. Within a year of the beginning of operations of major dams in the 3S River Basin, rapid decreases in annual average dry season river temperature were observed ranging between 0.7 ° C and 2 ° C. Furthermore, in situ water temperature observations confirmed decreasing river temperature for two major dam development events. Evidence was found that the 3S outflow has been cooling the Mekong River downstream of the confluence, by as much as 0.8 ° C in recent years. Our findings are critically important for understanding how fish and aquatic ecosystems will behave in the future as more hydropower dams are built in the Mekong River Basin.

The Mekong River Basin in Southeast Asia is undergoing extensive hydropower development, but the magnitudes of related greenhouse gas emissions (GHG) are not well known. We provide the first screening of GHG emissions of 141 existing and planned reservoirs in the basin, with a focus on atmospheric gross emissions through the reservoir water surface. The emissions were estimated using statistical models that are based on global emission measurements. The hydropower reservoirs (119) were found to have an emission range of 0.2–1994 kg CO _2 e MWh ^−1 over a 100 year lifetime with a median of 26 kg CO _2 e MWh ^−1 . Hydropower reservoirs facilitating irrigation (22) had generally higher emissions reaching over 22 000 kg CO _2 e MWh ^−1 . The emission fluxes for all reservoirs (141) had a range of 26–1813 000 t CO _2 e yr ^−1 over a 100 year lifetime with a median of 28 000 t CO _2 e yr ^−1 . Altogether, 82% of hydropower reservoirs (119) and 45% of reservoirs also facilitating irrigation (22) have emissions comparable to other renewable energy sources (380 kg CO _2 e MWh ^−1 ). These results are tentative and they suggest that hydropower in the Mekong Region cannot be considered categorically as low-emission energy. Instead, the GHG emissions of hydropower should be carefully considered case-by-case together with the other impacts on the natural and social environment.

The electricity sector is currently considered mainly on the emission side of the climate change equation. In order to limit climate warming to below 2 °C, or even 1.5 °C, it must undergo a rapid transition towards carbon neutral production by the mid-century. Simultaneously, electricity generating technologies will be vulnerable to climate change. Here, we assess the impacts of climate change on wind, solar photovoltaic, hydro and thermoelectric power generation in Europe using a consistent modelling approach across the different technologies. We compare the impacts for different global warming scenarios: +1.5 °C, +2 °C and +3 °C. Results show that climate change has negative impacts on electricity production in most countries and for most technologies. Such impacts remain limited for a 1.5 °C warming, and roughly double for a 3 °C warming. Impacts are relatively limited for solar photovoltaic and wind power potential which may reduce up to 10%, while hydropower and thermoelectric generation may decrease by up to 20%. Generally, impacts are more severe in southern Europe than in northern Europe, inducing inequity between EU countries. We show that a higher share of renewables could reduce the vulnerability of power generation to climate change, although the variability of wind and solar PV production remains a significant challenge.

In the western United States, 27% of electricity demand is met by hydropower, so power system planners have a key interest in predicting hydropower availability under changing climate conditions. Large-scale projections of hydropower generation are often simplified based on regression relationships with runoff and they are not always ready to inform power system models due to the coarse time scale (annual) or limited number of represented power plants. We developed an enhanced process-based hydropower model to predict future hydropower generation by addressing the commonly under-represented constraints, including (1) the ecological spills, (2) penstock constraints to provide flexibility in electricity operations, and (3) biases in hydro-meteorological simulations. We evaluated the model over the western United States under two emission scenarios (RCP4.5 and RCP8.5) and ten downscaled global circulation models. At the annual time scale, potential hydropower generation is not projected to change substantially, except in California. At the seasonal time scale, systematic shifting of the generation patterns can be observed in snowmelt-dominated regions. These projected annual and regional trends are comparable to other regression-based relationships. However, the representation of more complex operations and constraints tend to reduce the uncertainties inherent to climate projections at seasonal scale. In the Pacific Northwest region where hydropower is the dominant electricity source, our predicted future change of hydropower generation is about 10% less than the regression-based projections in spring and summer. The model can also capture the seasonal non-stationary in hydrologic changes. The spatio and temporal scales of the model, increased accuracy and quantification of uncertainty allow one to use the products to inform power system models toward supporting energy sector planning activities and water-energy trade-offs.

El Niño Southern Oscillation (ENSO) strongly influences the global climate system, affecting hydrology in many of the world’s river basins. This raises the prospect of ENSO-driven variability in global and regional hydroelectric power generation. Here we study these effects by generating time series of power production for 1593 hydropower dams, which collectively represent more than half of the world’s existing installed hydropower capacity. The time series are generated by forcing a detailed dam model with monthly-resolution, 20th century inflows—the model includes plant specifications, storage dynamics and realistic operating schemes, and runs irrespectively of the dam construction year. More than one third of simulated dams exhibit statistically significant annual energy production anomalies in at least one of the two ENSO phases of El Niño and La Niña. For most dams, the variability of relative anomalies in power production tends to be less than that of the forcing inflows—a consequence of dam design specifications, namely maximum turbine release rate and reservoir storage, which allows inflows to accumulate for power generation in subsequent dry years. Production is affected most prominently in Northwest United States, South America, Central America, the Iberian Peninsula, Southeast Asia and Southeast Australia. When aggregated globally, positive and negative energy production anomalies effectively cancel each other out, resulting in a weak and statistically insignificant net global anomaly for both ENSO phases.

Numerous reservoirs around the world provide multiple flow regulation functions; key among these are hydroelectricity production and water releases for irrigation. These functions contribute to energy and food security at national, regional and global levels. While reservoir operations for hydroelectricity production might support irrigation, there are also well-known cases where hydroelectricity production reduces water availability for irrigated food production. This study assesses these relationships at the global level using machine-learning techniques and multi-source datasets. We find that 54% of global installed hydropower capacity (around 507 thousand Megawatt) competes with irrigation. Regions where such competition exists include the Central United States, northern Europe, India, Central Asia and Oceania. On the other hand, 8% of global installed hydropower capacity (around 79 thousand Megawatt) complements irrigation, particularly in the Yellow and Yangtze River Basins of China, the East and West Coasts of the United States and most river basins of Southeast Asia, Canada and Russia. No significant relationship is found for the rest of the world. We further analyze the impact of climate variables on the relationships between hydropower and irrigation. Reservoir flood control functions that operate under increased precipitation levels appear to constrain hydroelectricity production in various river basins of the United States, South China and most basins in Europe and Oceania. On the other hand, increased reservoir evaporative losses and higher irrigation requirements due to higher potential evaporation levels may lead to increased tradeoffs between irrigation and hydropower due to reduced water availability in regions with warmer climates, such as India, South China, and the Southern United States. With most reservoirs today being built for multiple purposes, it is important for policymakers to understand and plan for growing tradeoffs between key functions. This will be particularly important as climate mitigation calls for an increase in renewable energy while agro-hydrological impacts of climate change, population and economic growth and associated dietary change increase the need for irrigated food production in many regions round the world.

In their article ‘An index-based framework for assessing patterns and trends in river fragmentation and flow regulation by global dams at multiple scales’ (2015 Environ. Res. Lett. https://doi.org/10.1088/1748-9326/10/1/015001 10 https://doi.org/10.1088/1748-9326/10/1/015001 ), Grill et al utilized a graph-based river routing model to simultaneously assess flow regulation and fragmentation by dams at multiple scales. Using global dam data they developed the river fragmentation index and the river regulation index, both based on river volume. Their results indicate that, on a global basis, 48% of river volume is moderately to severely impacted by either flow regulation, fragmentation, or both. Assuming completion of all dams planned and under construction in their future scenario, Grill et al find this number would rise to 93%, an effect they attribute largely to dam construction in the Amazon Basin. They also provide evidence for the importance of considering small- to medium-sized dams. We find this approach interesting and the analysis straightforward, but in this response note some limitations to the Asia-specific data on which the analysis is based. China and India are not only the two most populous countries, but are home to the vast majority of the world’s largest dams and reservoirs, numbers which will rapidly increase in the future. Grill et al however, limit their modeling and subsequent basin assessment (flow regulation and river fragmentation) to less than ten percent of existing and forthcoming dams in those two countries. While we suspect this is due to data limitations, it results in what we feel are significant misinterpretations of the future of dams and rivers across much of Asia.

Tropical dams are often falsely portrayed as ‘clean’ emissions-free energy sources. The letter by de Faria et al (2015 Environ. Res. Lett. http://dx.doi.org/10.1088/1748-9326/10/12/124019 10 http://dx.doi.org/10.1088/1748-9326/10/12/124019 ) adds to evidence questioning this myth. Calculations are made for 18 dams that are planned or under construction in Brazilian Amazonia and show that emissions from storage hydroelectric dams would exceed those from electricity generation based on fossil fuels. Fossil fuels need not be the alternative, because Brazil has vast potential for wind and solar power as well as opportunities for energy conservation. Because dam-building is rapidly shifting to humid tropical areas, where emissions are higher than in other climatic zones, the impact of these emissions needs to be given proper weight in energy-policy decisions.

Recent droughts and heatwaves showed the vulnerability of the electricity sector to surface water constraints with reduced potentials for thermoelectric power and hydropower generation in different regions. Here we use a global hydrological-electricity modelling framework to quantify the impacts of recent drought and warm years on hydropower and thermoelectric power usable capacity worldwide. Our coupled modelling framework consists of a hydrological model, stream temperature model, hydropower and thermoelectric power models, and was applied with data of a large selection of hydropower and thermoelectric power plants worldwide. Our results show that hydropower utilisation rates were on average reduced by 5.2% and thermoelectric power by 3.8% during the drought years compared to the long-term average for 1981–2010. Statistically significant ( p

Himalayan water resources attract a rapidly growing number of hydroelectric power projects (HPP) to satisfy Asia’s soaring energy demands. Yet HPP operating or planned in steep, glacier-fed mountain rivers face hazards of glacial lake outburst floods (GLOFs) that can damage hydropower infrastructure, alter water and sediment yields, and compromise livelihoods downstream. Detailed appraisals of such GLOF hazards are limited to case studies, however, and a more comprehensive, systematic analysis remains elusive. To this end we estimate the regional exposure of 257 Himalayan HPP to GLOFs, using a flood-wave propagation model fed by Monte Carlo-derived outburst volumes of >2300 glacial lakes. We interpret the spread of thus modeled peak discharges as a predictive uncertainty that arises mainly from outburst volumes and dam-breach rates that are difficult to assess before dams fail. With 66% of sampled HPP are on potential GLOF tracks, up to one third of these HPP could experience GLOF discharges well above local design floods, as hydropower development continues to seek higher sites closer to glacial lakes. We compute that this systematic push of HPP into headwaters effectively doubles the uncertainty about GLOF peak discharge in these locations. Peak discharges farther downstream, in contrast, are easier to predict because GLOF waves attenuate rapidly. Considering this systematic pattern of regional GLOF exposure might aid the site selection of future Himalayan HPP. Our method can augment, and help to regularly update, current hazard assessments, given that global warming is likely changing the number and size of Himalayan meltwater lakes.

Hydropower reservoirs are artificial water systems and comprise a small proportion of the Earth’s continental territory. However, they play an important role in the aquatic biogeochemistry and may affect the environment negatively. Since the 90s, as a result of research on organic matter decay in manmade flooded areas, some reports have associated greenhouse gas emissions with dam construction. Pioneering work carried out in the early period challenged the view that hydroelectric plants generate completely clean energy. Those estimates suggested that GHG emissions into the atmosphere from some hydroelectric dams may be significant when measured per unit of energy generated and should be compared to GHG emissions from fossil fuels used for power generation. The contribution to global warming of greenhouse gases emitted by hydropower reservoirs is currently the subject of various international discussions and debates. One of the most controversial issues is the extrapolation of data from different sites. In this study, the extrapolation from a site sample where measurements were made to the complete set of 251 reservoirs in Brazil, comprising a total flooded area of 32 485 square kilometers, was derived from the theory of self-organized criticality. We employed a power law for its statistical representation. The present article reviews the data generated at that time in order to demonstrate how, with the help of mathematical tools, we can extrapolate values from one reservoir to another without compromising the reliability of the results.