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Between 2010 and 2020, residential solar installations grew at an average rate of 42% per year in the United States with subsidies and promises of rapid payback times contributing to adoption. However, the relationship between geographically localized economic drivers, adoption of residential solar energy, and the impact on carbon emissions remain poorly quantified. Here we assess the geospatial variations in economic payoff and carbon offset within the United States and propose a more efficient geographical roadmap for subsidies focus. The results show that the economic benefits of residential solar depend strongly on local electricity prices and energy mix. We find favorable economics in some regions with low solar irradiance and some sunny locations where residential solar will not be competitive relative to local electricity prices. Similarly, the reduction in the carbon footprint of electricity generation that the adoption of residential solar could provide varies strongly by location. We also identify optimal places for policy deployment and provide helpful data to allow for informed decisions by policymakers. [ABSTRACT FROM AUTHOR]

Renewable electricity generation technologies provide a more sustainable solution than the non-renewables. However, as a complete system, renewable energy generation systems have some overall environmental impacts on humankind, resources and ecosystems. This paper will address the environmental effects caused by different types of renewable plants through life-cycle assessment. A comparative study is done among solar PV, biomass, and pumped storage hydropower plants in the United States. Life-cycle impact analysis has been carried out by the Eco-indicator 99, TRACI (Tool for the Reduction and Assessment of Chemical and other Environmental Impacts), CED (Cumulative Energy Demand), Ecopoints 97, RMF (Raw Material Flows) and IPCC (Intergovernmental Panel on Climate Change) methods, using the SimaPro software. The impacts are considered in 10 mid-point impact categories and three end-point indicators. The results show that pumped storage hydropower plants have the highest impact on human health (7.74E-05/kWh) and the ecosystem (3.35E-06/kWh), whereas biomass plants have the maximum effect on resources (4.79E-07/kWh). Overall, the solar PV plants are found to be much more environment-friendly than other renewable electricity generation systems. These findings will guide investors in installing sustainable and clean power plants. • Comparative environmental impacts of solar-PV, biomass and pumped storage hydropower plants was investigated. • Impacts are assessed by a systematic LCA analysis using the ecoinvent database and SimaPro software. • Solar-PV plants are found least hazardous to environment than other renewable energy plants in the United States. • Findings will guide the investors in installing the best renewable power plant considering the environmental aspects. [ABSTRACT FROM AUTHOR]

• Modeling method to quantify technology costs required to reach specific deployment. • Nuclear levelized costs of $53–84/MWh required for incremental 1% by 2050. • Concentrating solar power costs of $65–91/MWh required for incremental 1% by 2050. • Offshore wind costs of $39–77/MWh required for incremental 1% by 2050. • More challenging cost targets found with greater penetration due to value decline. Clean energy deployment scenarios typically assume a diverse mix of low-emission generation. However, because of historically low natural gas prices and cost reductions for onshore wind and photovoltaic technologies, recent new capacity deployment, especially in the United States, has come largely from these three generation sources. Here, we quantify competitive cost targets for three less-common zero-emission generation technologies—nuclear, concentrating solar, and offshore wind—under a range of future conditions. We determine the cost targets based on the technologies' system value, such that technology value equals or exceeds its cost. Using a capacity expansion model that develops system-wide, economically optimal generation scenarios of the United States power sector, we find that nuclear, concentrating solar, and offshore wind would need to attain levelized cost ranges of $53–84/MWh, $65–91/MWh, and $39–77/MWh, respectively, to achieve 1% additional grid penetration. We refer to this metric as the "required cost," which is a technology's levelized cost of energy needed to achieve a specific penetration level. Higher penetrations lead to lower required costs as lower-cost generation is displaced. We estimate that to reach 10% penetration, the required cost for nuclear declines to $45–76/MWh. Because of resource variability and increased transmission needs for concentrating solar power and offshore wind, even lower costs are needed to reach higher penetrations: required cost ranges to achieve 10% penetration are estimated to be $30–56/MWh and $18–40/MWh for these two technologies respectively. Our analysis informs research and development priorities and the design of policies supporting clean technologies. [ABSTRACT FROM AUTHOR]

• Across NYS, a wealth of low-value land exists to support utility-scale solar PV. • Solar generation can reduce summer peak demand by up to 9.6% in certain regions in New York. • Regional ramping requirements may increase by up to 151% during sunny winter days. • PV performance during system peak should be retained in capacity valuation of solar. Rapidly growing utility-scale solar photovoltaic (PV) holds promise for addressing the energy and environmental challenges posed by high electricity demand days (HEDDs). We assessed the implications on strategic planning of future solar development in an emerging solar market, New York State (NYS) in the U.S., by synthesizing information on electrical infrastructure, tax assessment, geographical constraints and measured meteorological data. Considering three solar PV penetration scenarios (4500 MW, 6000 MW, and 9000 MW), we examined the impact of distributed utility-scale solar farms on peak demand reduction and ramping requirements during historical peak events. Our results reiterate that, across NYS, a wealth of low-value land exists to support utility-scale solar PV and that generation from these resources can reduce peak demand by up to 9.6% under the 9000 MW scenario. In addition, peak demand reduction displays locational and temporal dependency. Contingent upon local meteorology, a solar farm can reduce demand during the peak hour by anywhere between 10 and 74% of its rated capacity during summer HEDDs. However, the highest ramping requirements are more likely to occur during winter than summer. Furthermore, because developers cannot predict performance during the annual system peak, current capacity valuation methodologies for solar projects may not be adequate to promote a healthy competitive market for solar. Incorporating a broader spectrum of peak demand conditions into variable resource capacity valuation would improve strategic planning, not only in NYS, but across growing solar markets worldwide. [ABSTRACT FROM AUTHOR]

• We incorporate life cycle impacts to energy systems models via monetization. • The cost of leaving the Paris Agreement for the US is 1103 billion USD 2013 in 2030. • Further economic savings could be realized by minimizing life cycle impacts. • Wind onshore is critical for minimizing all environmental impacts concurrently. • The Paris Agreement could induce burden-shifting between sustainability criteria. Current energy systems models focus on cost minimization with a bound on some greenhouse gas emissions. This limited environmental scope can lead to mixes that are not consistent with our sustainable development. To circumvent this limitation, we here make use of the concept of monetization and life cycle assessment to quantify the indirect costs of electricity generation in the design of energy systems. Applying our approach to the United States, we found that the indirect costs of electricity generation could be reduced by as much as 63% by meeting the Paris Agreement. Consequently, the total opportunity cost (i.e., direct and indirect costs) of withdrawing from the Paris Agreement and continuing with the current mix would be as high as 1103 ± 206 billion USD 2013 in 2030 (i.e., 6% of the United States gross domestic product in 2017). By optimizing the direct and indirect costs of electricity generation concurrently, we found an optimal ecological solution that attains total economic savings compared to the Paris Agreement mix of as much as 373 ± 164 billion USD 2013 in 2030. Our work highlights the need to extend the environmental policies that regulate energy systems beyond the direct greenhouse emissions to consider other critical environmental criteria. [ABSTRACT FROM AUTHOR]

Abstract The economic viability of new energy technologies is held as a central tenet to their future deployment; conventional wisdom posits economically rational decision-makers will readily invest in proven low-risk and affordable technologies. But what happens when this is not true. This paper examines the non-financial barriers facing economically viable Combined Heat and Power (CHP) projects. CHP is a mature and lower carbon technology that efficiently uses waste heat from thermal electricity generation; CHP can also provide flexibility services to help integrate variable renewable resources. CHP is low risk and many industrialized countries, particularly those in colder climates in Northern Europe and Russia, generate as much as 50% of their electricity and heat needs from CHP, but United States deployment remains low and investment hurdle rates high. While lower U.S. energy costs make some projects un-economic, many economically-viable CHP projects are stalled or killed by non-financial barriers. To better understand why financially viable CHP projects are not getting built, developers, owners and operators, regulators, and other stakeholders of this technology were interviewed and three major barriers emerged a) the business model of the electrical utility b) negative subjective impressions and c) challenges in allocating the risks and benefits. [ABSTRACT FROM AUTHOR]

Highlights • Hybrid LCA used to compare global warming potential of water refill stations to bottled water. • Several water consumption scenarios examined in four locations (Israel, USA, UK, and China). • GWP of water refill stations 2-6 times less than bottled water and most strongly influenced by electricity generation mix. Abstract Growing consumption of single-use bottled water has received criticism due to potentially adverse environmental outcomes. Networks of public-sphere water delivery stations have been proposed as a sustainable alternative for water consumption on-the-go, yet the life-cycle impacts of such stations are poorly understood. Here we evaluate the potential cumulative energy demand and climate change impacts of water delivered from a filtered water refill station under various consumption scenarios and provide a comparison to published results for bottled water. Using a hybrid life-cycle analysis framework employing physical and economic data, we model the water station's performance in four locations: Tel-Aviv, Israel; Miami Beach, Florida, USA; London, UK; and Shanghai, China. We find that the climate change impact of the station is two to six times lower than those of bottled water and that use phase electricity is the most influential factor in determining the station's environmental impact. We provide additional observations related to scaling up such a system and recommendations to realize further gains in eco-efficiency. [ABSTRACT FROM AUTHOR]

Decarbonization goals in the United States electricity sector are increasing the levels of renewable energy generation in the electricity supply system, and are driving increased attention to building electrification, which will increase the magnitude and shift the timing of the electricity system peak. These changes are motivating new approaches to coordinate building electricity demand with low-carbon renewable generation, elevating the importance of demand flexibility (DF) in buildings and the need to quantify the temporal impacts of DF. In this paper, we first characterize the hourly predictive accuracy of six commonly used baseline models in an application context of quantifying building-level load shift. Our analysis revealed insights such as hours of the day (afternoons), periods of the week (weekends), and seasons (summer) that were predicted with more accuracy than other time periods. In addition, the analysis showed tendencies toward overprediction or underprediction of load. Secondly, we provide the first published investigation of baseline erosion from repeated dispatch of building load shifting. We observed that as the baseline period is pushed back further from the prediction day, the distribution of errors across baseline model predictions increases, with notable inflection points near the three-week erosion point for two of the three models. [ABSTRACT FROM AUTHOR]

Wave energy is one of the most concentrated ocean renewable energy resources. Although wave energy has been studied extensively for more than four decades, there is no large commercial installation for wave energy production or a consensus framework on how to exploit this resource. Wave energy is a complex resource that directly depends on two meteorological parameters, which produced significant fluctuations of wave energy in both temporal and spatial criteria. This paper presents a new concept called Energy Event, to analyze meteorological data generated by WaveWatch III over 36 years in the U.S. to characterize and assess wave energy behavior using the peak-over-threshold methodology. This methodology used extreme statistics, segmented the wave energy with different thresholds, and assessed wave energy production on a temporal and spatial framework. Three areas were studied in this paper, including the Gulf of Mexico, the East and West U.S. Coasts. The results indicated that wave energy behaved as a two-state energy system with each state having independent characteristics. The main difference among the three studied areas was the constant baseline of wave power density, with the West Coast having the highest constant baseline and the Gulf of Mexico having the lowest baseline. [ABSTRACT FROM AUTHOR]

We investigated the accuracy of numerical weather prediction (NWP)-based global horizontal irradiance (GHI) and clear-sky index forecasting over southern Nevada. Accurate forecasts of solar irradiance are required for electric utilities to economically integrate substantial amounts of solar power into their power generation portfolios. Solar irradiance forecasting can enhance the value of renewable energy by anticipating fluctuations in these variable resources. Summertime cloud variability depends largely on the combination of tropical and extratropical synoptic-scale forcing, most of which is observable, predictable, and highly related to the North American Monsoon moisture surge events. We used high-resolution realtime NWP output based on the weather and research forecasting (WRF) model to study the ability of the model to deliver day-ahead GHI and clear-sky index forecasts for a the National Renewable Energy Laboratory (NREL)-University of Nevada site, located in Las Vegas, Nevada. High-resolution forecast products were obtained from the Desert Research Institute (DRI) archived real-time numerical weather forecasting products. Results showed the importance of developing a site-specific seasonal and weather-dependent model output statistics (MOS) approach to improving forecast accuracy, which removes the bias and reduces the overall relative root-mean – square error (rRMSE) of GHI by as much as 6%, when compared to the uncorrected model output; improving forecast accuracy is obtained by adding information that relates regional-scale circulation patterns driving cloudiness, hence irradiance variability to the target area. We show the seasonal dependence of the NWP forecast accuracy and demonstrate that intelligent weather functions provide a pathway to improve accuracy of solar forecasts further. [ABSTRACT FROM AUTHOR]

At Brady Hot Springs, a geothermal field in Nevada, heated fluids have been extracted, cooled, and re-injected to produce electrical power since 1992. Analysis of daily pumping records and catalogs of microseismicity between 2010 and 2015 indicates a statistically significant correlation between days when the daily volume of production was at or above its long-term average rate and days when no seismic event was detected. Conversely, shutdowns in pumping for plant maintenance correlate with increased microseismicity. We hypothesize that the effective stress in the subsurface has adapted to the long-term normal operations (deep extraction) at the site. Under this hypothesis, extraction of fluids inhibits fault slip by increasing the effective stress on faults; in contrast, brief pumping cessations represent times when effective stress is decreased below its long-term average, increasing the likelihood of microseismicity. [ABSTRACT FROM AUTHOR]

The US power sector is in a state of transition, prompted by significant shifts in technological innovations, energy markets, regulatory structures, and social pressures. As the electricity generation fleet changes, so too does the spatial & temporal distribution of the cooling water requirements for power plants. However, to date, these impacts have yet to be quantified. This study uses power plant-specific fuel consumption, generation, and cooling water use data to assess changes in the water withdrawn and consumed by thermoelectric power plants across 8-digit Hydrologic Unit Code (HUC-8) watersheds between 2008 and 2014. During this period, a few prominent trends are noted, including transitions in generation from coal-fired steam to natural-gas combined cycle units, from once-through cooling to wet recirculating towers and dry cooling systems, and from traditional fresh and saline surface cooling water to reclaimed water and groundwater sources. Total US cooling water withdrawals and consumption volume decreased from 2008 to 2014. The average water withdrawn per unit of electrical output decreased over this time, while changes in water consumption rates stayed relatively flat. Changes in water use at the watershed scale were unevenly distributed, as some water-scarce regions experienced increases in cooling water usage for thermal power plants, while others experienced significant water reductions and environmental benefits, especially where coal-fired generation was retired or retrofitted. The results from this study underscore the importance of evaluating water withdrawals and consumption at local spatial scales, as the water extraction, water quality and environmental health consequences of power plants on downstream users are non-uniform. [ABSTRACT FROM AUTHOR]

This analysis compares the cost of various electric grid scenarios at the national level over a one-year period. Scenarios include high renewable, zero nuclear, zero carbon, and deployment of advanced nuclear. Additionally, several carbon tax scenarios are explored in the model to further assess the cost generation if the current nuclear fleet retired. The cheapest scenarios were those that involved less reliance on conventional nuclear reactors and more molten salt reactors, renewables, or natural gas. [ABSTRACT FROM AUTHOR]

Future scenarios and assessment studies used to prepare for long-term energy transitions and develop robust strategies to address climate change are highly dependent on the assessment of technology characteristics and availability. The electric power sector in the United States recently experienced a significant cost escalation: e.g., construction costs for large plants such as nuclear and coal-fired power plants doubled between 2003 and 2007. We assess the main drivers of this escalation. While many factors have affected costs, some of the most significant include cost of materials, particularly the price of metals and to a lesser extent cement, possible increases in labor quantity requirements, the aggressive worldwide competition for power plant design and construction resources, driven by high demand in Asia, market and regulatory changes, and general uncertainty about future regulations and climate policies. We recalibrate power sector technology costs in the Global Change Assessment Model (GCAM) based on an extensive literature review of recent (post-2010) studies and in the process develop a coherent and updated set of current cost and performance assumptions for all major electricity-generating technologies. While current cost and performance assumptions of electricity-generating technologies are key drivers of short-term technology deployment and technology mix in the electricity sector, medium- and long-term deployment pathways are significantly affected by assumed efficiency improvement rates and cost reductions. We develop and demonstrate a method to project efficiency and construction cost of power plants and report a sensitivity analysis to explore the importance of such assumptions in future scenarios generated by GCAM. [ABSTRACT FROM AUTHOR]

This study answers a critical question facing the energy sector in the United States: how does natural gas compare to coal as a climate change mitigation technique? Although natural gas burns cleaner than coal, methane leakage potentially undermines the climate benefits of fuel switching. This study investigates the impact of methane leakage using a novel plant-level lifecycle emissions inventory of greenhouse gas emissions associated with coal mining, transportation, and combustion at 337 existing coal power plants in the United States. Individual plant emissions rates ranged from 901 to more than 2200 kgCO2e/MWh (100-yr GWP); generation-weighted average was 1046 kgCO2e/MWh. Our study finds that the “breakeven” leakage rates for natural gas to have short and long term climate benefits over coal range from 4.4 to 20.9%, depending on the timeframe, plant efficiency, and upstream coal emissions. Emissions benefits can be maximized by replacing highest emitting coal plants with new natural gas plants. Finally, we find fugitive methane emissions can limit carbon reductions from natural gas carbon capture; above 2% leakage, methane leakage reduces CCS benefits by up to half for 20-yr GWP. [ABSTRACT FROM AUTHOR]

Technology costs, state and federal policies and incentives, and local factors such as construction costs and prevailing electricity prices interact to determine the economic favorability of a generation technology in a particular place. To disentangle these factors and better understand how federal policies can make new generation economically viable, we present an integrated multi-technology, state-level project finance model called the Project Finance Mapping Tool and apply it to a variety of policy scenarios. [ABSTRACT FROM AUTHOR]

The economic viability of many U.S. nuclear plants has been deteriorating rapidly since 2010. To save in-state, zero-emission baseload generation, several states have passed zero-emission credits to subsidize their economically challenged plants. Our power market dispatch modeling, however, suggests that keeping nuclear plants online does not necessarily mean a reduction in carbon emissions within the region or state, as the amount of regional emissions also depends on grid characteristics and the evolution of the generation fuel mix. [ABSTRACT FROM AUTHOR]

U.S. renewable electricity resource subsidization program design relies on production-based payments that lower electric energy market prices, often below zero, contrary to the objective of increasing market prices when correcting for an environmental externality. An alternative pricing approach, capacity-based subsidy payments, would substantially reduce the likelihood of negative electric market prices. A more thoughtful examination of the impact of subsidization program design on wholesale power markets is long overdue. [ABSTRACT FROM AUTHOR]

The authors investigate uncertainties that could affect the usage of natural gas for electricity generation in the United States, including the pace of installing renewable generation resources, natural gas prices, and retirement of nuclear plants. The long-term modeling suggests natural gas usage for power generation in year 2030 could range from 8.7 to 15.1 trillion cubic feet, with the price of natural gas appearing to be the most important factor. [ABSTRACT FROM AUTHOR]

This study explores suitability of battery electric vehicles in the United States by considering their potential market share and operations costs as well as the state-specific variations in electricity generation profiles, given current government policies and the social acceptability of the technology. A performance assessment is developed to compare each state and identify major policy efforts that are needed to increase the environmental and economic competitiveness of electric vehicles. A novel multi-criteria decision-support framework, integrating Life Cycle Assessment, Data Envelopment Analysis, and Agent Based Modeling, is developed. To this end, the environmental and economic impacts of battery electric vehicles are calculated based on three scenarios: an average electricity generation mix, a marginal electricity generation mix, and a solely renewable energy mix with 100% solar. The states are classified, each requiring different policy strategies, in accordance with their performance scores. The results provide important insights for advancing transportation policies and a novel framework for multi-criteria decision-making in the future analyses. [ABSTRACT FROM AUTHOR]

For more than 20 years, the large-scale application of flue gas desulfurization technology has been a dominant cause of SO 2 emission reductions. From 1994–2004, electricity generation from coal increased, but the shift to low-sulfur coal eclipsed this. From 2004–2014, electricity generation from coal decreased, but a shift to higher-sulfur subbituminous and lignite coal overshadowed this. The shift in coal quality has also created a CO 2 emissions penalty, representing 2% of the sector’s total emissions in 2014. [ABSTRACT FROM AUTHOR]

• Fossil fuel-fired power plants' water use may be significantly curtailed by 2035. • Most rivers will see a net increase in streamflow after power plant retirement. • Plant retirement can noticeably increase streamflow over 500 km downstream. • Power plant retirements could make 2.6 km3 of water available for other uses. Nearly two-thirds of fossil fuel-fired electricity generation capacity in the United States is expected to reach its typical end of life by 2035. While the closure of fossil fuel-fired power plants will help advance decarbonization goals, the cessation of water use for fossil fuel-fired power plant cooling - the largest water user in the US - will also impact the nation's water resources. We assess when, where, and how much water will be made available upon the expected retirement of the nation's nearly one thousand fossil fuel-fired power plants by combining a lifespan-based model of fossil fuel-fired generator retirements for the US fossil fuel-fired electricity generation fleet with a national-scale hydrologic model. We show that annual water withdrawals and consumption of fossil fuel-fired power generators will be significantly curtailed (85 % and 68 % reduction, respectively) by 2035 if these generators follow their typical retirement timeline. Most rivers with fossil fuel-fired power plants diverting and/or discharging water will have a net increase in annual streamflow after plant retirement (maximum decrease of 2 %, maximum increase of 57 % by 2050), with the most pronounced increases occurring in the summer months. The retirement of fossil fuel-fired power plants will lead to a large relative change (>5%) in streamflow at least one month per year by 2050 in 31 subbasins. The retirement of power generators was shown to produce noticeable streamflow impacts up to hundreds of kilometers downstream. By the retirement of the last US fossil fuel-fired power generator, 2.6 billion m3 of water that was once consumed by these power plants could be made available for other uses. In addition to the global benefits of reduced greenhouse gas emissions, the notable increases in streamflow and water availability in many US rivers due to the retirement of fossil fuel-fired power plants could benefit local water users and ecosystems. [ABSTRACT FROM AUTHOR]

• Value and cost must be considered for all technologies in evaluating competition. • We quantify technology value at market shares above 50%. • We quantify wind and solar value at combined market shares above 90%. • We explore how technology interactions affect technology value. • We propose methods of parameterizing value in large-scale models. Evaluating competition between electricity technologies is challenging because it depends on both their costs and their values. While technology costs can typically be estimated from projections of the cost components—capital, fuel, and O&M—estimating a technology's value is more complex due to its dependence on its contributions to multiple different grid services, each with prices that can vary substantially over space and time. In this work, using an electricity model of the contiguous United States, we develop relationships between relative value and share of total generation for major electricity generation technologies which, when paired with projections of technology costs, can be used to estimate technology competitiveness. We identify significant differences in the relationship between relative value and generation share for variable renewable energy (VRE) and non-VRE sources, but we demonstrate that all technologies require consideration of their dynamic values (in addition to cost) when evaluating competitiveness. In addition, we demonstrate that relative value of a technology is substantially impacted by not only its own generation share but also other aspects of the system state, in particular the mix of other technologies present in the system. Finally, we use the developed relative value relationships in combination with projections of future technology costs in a coarse resolution model that competes technologies based on a comprehensive competitiveness metric: profitability-adjusted LCOE (PLCOE). We show that this simple representation of technology competition approximately recovers the generation mix from a detailed model, which is not possible using LCOE alone. Such an approach can be used to improve the representation of technology competition in coarse-resolution models such as integrated assessment models, for which simplified metrics are often needed. [ABSTRACT FROM AUTHOR]

Many US states have targets for vastly expanding electricity generation from renewable resources. As installed wind capacity increases, several factors can lead to the curtailment of potential wind-generated electricity. Reliably estimating wind power outputs remains a challenge given the dearth of available hub height-altitude wind speed data and measured outputs from newer turbines. A methodology to make such estimates with large increases in wind capacity is described. A regional wind power model, including subroutines for evaluating Statewide grid constraints, and a linear program to solve the model were developed to assess capacity factors and curtailments with deep penetration of wind power into an existing grid under several constrained scenarios implied by demand, baseload generation and transmission. Actual zonal demand and interzonal transmission limits were used for the New York State electricity grid, which has significant potential for wind power mostly distant from the concentrated electricity demand in and around New York City. The analysis indicates that current wind power outputs in the State underperform when compared to what the potential output should be at the same locations and could be if better wind regime sites were selected. Even with improved selection of sites and turbines, no constraints considered caused curtailment until systemwide capacity exceeds 6 GW; beyond this capacity, curtailment occurs only due to the presence of inflexible baseload generators until systemwide capacity exceeds 15 GW. At deeper penetrations of wind, mismatches in potential wind power supply and electricity demand coupled with continuously operating baseload generators have the most significant impact on the curtailment of wind-generated electricity, with much of the curtailment occurring during October-March. Interzonal transmission constraints further increase wind curtailment and would require very large transmission capacity increases to capture fully; however, more modest increases in transmission capacity can significantly reduce curtailment. [ABSTRACT FROM AUTHOR]

Climate change will have potentially significant effects on hydropower generation due to changes in the magnitude and seasonality of river runoff and increases in reservoir evaporation. These physical impacts will in turn have economic consequences through both producer revenues and consumer expenditures. We analyze the physical and economic effects of changes in hydropower generation for the contiguous U.S. in futures with and without global-scale greenhouse gas (GHG) mitigation, and across patterns from 18 General Circulation Models. Using a monthly water resources systems model of 2119 river basins that routes simulated river runoff through reservoirs, and allocates water to potentially conflicting and climate dependent demands, we provide a first-order estimate of the impacts of various projected emissions outcomes on hydropower generation, and monetize these impacts using outputs from an electric sector planning model for over 500 of the largest U.S. hydropower facilities. We find that, due to generally increasing river runoff under higher emissions scenarios in the Pacific Northwest, climate change tends to increase overall hydropower generation in the contiguous U.S. During low flow months, generation tends to fall with increasing emissions, potentially threatening the estimated low flow, firm energy from hydropower. Although global GHG mitigation slows the growth in hydropower generation, the higher value placed on carbon-free hydropower leads to annual economic benefits ranging from $1.8 billion to $4.3 billion. The present value of these benefits to the U.S. from global greenhouse gas mitigation, discounted at 3%, is $34 to $45 billion over the 2015–2050 period. [ABSTRACT FROM AUTHOR]

The United States has and will likely continue to obtain an increasing share of its electricity from solar photovoltaics (PV) and wind power, especially under the Clean Power Plan (CPP). The need for additional solar PV modules and wind turbines will, among other things, result in greater demand for a number of minor metals that are produced mainly or only as byproducts. In this analysis, the quantities of 11 byproduct metals (Ag, Cd, Te, In, Ga, Se, Ge, Nd, Pr, Dy, and Tb) required for wind turbines with rare-earth permanent magnets and four solar PV technologies are assessed through the year 2040. Three key uncertainties (electricity generation capacities, technology market shares, and material intensities) are varied to develop 42 scenarios for each byproduct metal. The results indicate that byproduct metal requirements vary significantly across technologies, scenarios, and over time. In certain scenarios, the requirements are projected to become a significant portion of current primary production. This is especially the case for Te, Ge, Dy, In, and Tb under the more aggressive scenarios of increasing market share and conservative material intensities. Te and Dy are, perhaps, of most concern given their substitution limitations. In certain years, the differences in byproduct metal requirements between the technology market share and material intensity scenarios are greater than those between the various CPP and No CPP scenarios. Cumulatively across years 2016–2040, the various CPP scenarios are estimated to require 15–43% more byproduct metals than the No CPP scenario depending on the specific byproduct metal and scenario. Increasing primary production via enhanced recovery rates of the byproduct metals during the beneficiation and enrichment operations, improving end-of-life recycling rates, and developing substitutes are important strategies that may help meet the increased demand for these byproduct metals. [ABSTRACT FROM AUTHOR]

Thermoelectric power plants contribute 90% of the electricity generated in the United States. Steam condensation in the power generation cycle creates a need for cooling, often accomplished using large amounts of water. These large water requirements can lead to negative consequences of power plants dialing down or shutting down during times of low water availability. Consequently, water constraints can translate into energy constraints. Projected future population growth and changing climate conditions might also increase the competition for water in many areas, motivating a resource accounting analysis to both establish a baseline of current water requirements and simulate possible impacts from future water and energy management decisions. Our analysis of the current water demands for power generation, focused on the state of Illinois, combined existing digital spatial datasets with engineering basic principles to synthesize a geographic information systems (GIS) model of current and projected water demand for thermoelectric power plants. We evaluated two potential future cases based on water use implications: (1) a shift in fuel from coal to natural gas, and (2) a shift in cooling technology from open-loop to closed-loop cooling. Our results show that a shift from coal-generated to natural gas-generated electricity could decrease statewide water consumption by 0.10 billion m 3 /yr (32% decrease) and withdrawal by 7.9 billion m 3 /yr (37% decrease), on average. A shift from open-loop to closed-loop cooling technologies could decrease withdrawals by an average of 21 billion m 3 /yr (96% decrease), with the tradeoff of increasing statewide water consumption for power generation by 0.18 billion m 3 /yr (58% increase). Furthermore, we performed an economic analysis of retrofitting open-loop cooling systems to closed-loop cooling, revealing an annual cost between $0.58 and $1.3 billion to retrofit the 22 open-loop cooling plants considered, translating to an effective water price between $0.03 and $0.06/m 3 . The synergies and tradeoffs between water resources and power generation yield interesting implications for integrated decision making and policy in Illinois and elsewhere. [ABSTRACT FROM AUTHOR]

The United States Energy Information Administration releases an AEO (Annual Energy Outlook) projecting future supply, demand, and resources for energy and electricity in the U.S. It is widely relied upon for policymaking. This study assesses twelve years of these projections of generation and capacity for six classes of renewable technologies. It finds consistent under projections for most renewable energy types in the mid- and long-term, due to inaccuracies, limitations, and inconsistencies in the underlying model. It identifies and evaluates five hypotheses that may explain such inaccuracy: inaccurate modelling of state renewable energy mandates, expiration of renewable tax credits, flaws in modelling structure, a biomass co-firing assumption, and capital cost projections. Unless AEO's projections of renewable energy are greatly improved, the reliability of its sector-wide electricity projections is inherently low. Key modifications suggested by this study include: fully valuing financial and non-financial benefits of renewables, improving cost innovation expectations for renewable energy, and, perhaps most importantly, properly modelling state renewable energy mandates. [ABSTRACT FROM AUTHOR]

Wind-generated electricity is a growing renewable energy resource. Because wind results from the uneven heating (and resulting pressure gradients) of the Earth, future wind resources may be affected by anticipated climate change. Many studies have used global and regional climate models to predict trends in the future wind resource over the continental United States. While some of these studies identified regions that are expected to gain wind energy, their results often come with a high degree of uncertainty, and lack of agreement across different climate models. In this paper we focus on wind energy density as a measure of the available wind resource over the continental United States. We estimate the change in wind energy density from the period 1968–2000 to the period 2038–2070 by using output from four regional climate models from the North American Regional Climate Change Assessment Program (NARCCAP). We find strong agreement across all 4 models that the wind energy resource is expected to increase in parts of Kansas, Oklahoma, and northern Texas – a region already in possession of both large scale generating capacity and political support for wind energy. [ABSTRACT FROM AUTHOR]

The revolution of hydraulic fracturing has dramatically increased the supply and lowered the cost of natural gas in the United States driving an expansion of natural gas-fired generation capacity in many electrical grids. Unrelated to the natural gas expansion, lower capital costs and renewable portfolio standards are driving an expansion of intermittent renewable generation capacity such as wind and photovoltaic generation. These two changes may potentially combine to create new threats to the reliability of these interdependent energy infrastructures. Natural gas-fired generators are often used to balance the fluctuating output of wind generation. However, the time-varying output of these generators results in time-varying natural gas burn rates that impact the pressure in interstate transmission pipelines. Fluctuating pressure impacts the reliability of natural gas deliveries to those same generators and the safety of pipeline operations. We adopt a partial differential equation model of natural gas pipelines and use this model to explore the effect of intermittent wind generation on the fluctuations of pressure in natural gas pipelines. The mean square pressure fluctuations are found to grow linearly in time with points of maximum deviation occurring at the locations of flow reversals. [ABSTRACT FROM AUTHOR]

Despite near- to medium-term cost barriers, a future U.S. electricity system in which wind plays a major role is technically feasible; could result in enduring benefits globally, nationally, and locally; and could result in consumer and system cost savings in the long term. [ABSTRACT FROM AUTHOR]

The economics in the U.S. of solar photovoltaic (PV) systems is changing rapidly as the cost per unit power of PV modules has dropped quickly. These costs reductions have two important results: marked decrease in levelized cost of electricity (LCOE) into ranges competitive or better than traditional electricity-generation technologies and the economic role of racking has been gaining prominence relative to that of modules. As the relative importance of costs of PV racking has been marginal historically, there has been relatively little progress on reducing the materials and costs associated with it, which has caused racking to contribute to a significant portion of costs of entire PV systems. In order to overcome this challenge this study investigates a novel low-weight PV racking system for commercial rooftops based on crossed cables (X-wires) and compares it to racking systems already available on the market on capital costs, labor costs for installation, and technical specifications such as adaptability and power packing factor. The results of over 80% cost reduction and 33% increase in power density are presented and conclusions are drawn about the potential for tension-based racking systems to further reduce total PV systems costs on commercial flat roof tops resulting in LCOE savings of $0.01–$0.02/kW h. [ABSTRACT FROM AUTHOR]

The Tomato industry in the United States generates ∼40 million metric tons of pomace waste on an annual basis. Here, we demonstrate the use of pomace as the feedstock for electricity production in a microbial fuel cell (MFC). The putative redox-active compounds and the particulate characteristic of the pomace influenced the temporal dynamics of polarization, impedance, and voltammetry response of pomace-MFCs (pMFC). While the open-circuit potential of pMFC was similar to its glucose-control, the polarization response of pMFC (125 W m −2 and 500 mA m −2 ) was inferior to its glucose-control (290 W m 2 and 1300 mA m −2 ), and this difference increased with increasing scales of current density and time. The pomace oxidation was associated with a redox-active mediator that undergoes a quasi-reversible reaction at higher potential (E p = 0 V vs Ag/Agcl); its charge transfer impedance appeared as a distinct time constant in the mid-frequency region during AC electrical impedance spectroscopy analysis. [ABSTRACT FROM AUTHOR]

With the development of demand response (DR) technologies and increasing electricity demand, dynamic pricing has been a popular topic in many countries. This paper evaluates various dynamic pricing programs in the U.S. and Europe, and provides insights into various aspects including risks and rewards, enabling technologies, lower-income groups and customer types surrounding programs such as Time-of-Use (TOU), Critical Peak Pricing (CPP), Peak Time Rebates (PTR) and Real Time Pricing (RTP). We conclude this paper with three main findings: (1) policy coordination in promoting dynamic pricing programs between federal and state regulatory agencies is very critical; (2) customer engagement is very important and can be enhanced via more accessible educational programs and policy adjustments; and (3) more investment in related R&D is required to construct a commonly accepted methodology for measuring the effectiveness of dynamic pricing programs. [ABSTRACT FROM AUTHOR]

Coal is the bulwark of US energy production making up about a third of all energy produced and about half of its electricity generation capacity, over the last decade. Current energy policy in the Unites States assumes that there is at least a century of coal remaining within the nation that can be produced at the current rate of consumption. This assumption is based on the large reported coal reserves and resources. We show that, in coal-producing regions and nations, historically reported reserves are generally overestimated by a substantial magnitude. We demonstrate that a similar situation currently exists with US reserves. We forecast future US coal production, in both raw tonnage and energy, using a multi-cyclic logistic model fit to historical production data. Robustness of the model is validated using production data from regions within the US, as well as outside, that have completed a full production cycle. Results from the model indicate maximum raw tonnage coal production will occur in a time window between the years 2009 and 2023, with 2010 being the most likely year of such a maximum. Similarly, energy production from coal will reach a maximum in the years between 2003 and 2018, with 2006 being the most likely year of maximum occurrence. The estimated energy ultimate recoverable reserves (URR) from the logistic model is 2750 quadrillion BTU (2900 EJ) with 1070 quadrillion BTU (1130 EJ) yet to be mined, while the estimated raw tonnage URR is 124 billion short tons (112 Gt) with 52 billion short tons yet (47 Gt) to be mined. This latter value is merely a fifth of the long held estimate of 259 billion short tons (235 Gt). [ABSTRACT FROM AUTHOR]

Thermoelectric power production comprised 41% of total freshwater withdrawals in the U.S., surpassing even agriculture. This review highlights scenarios of the electric sector's future demands for water, including scenarios that limit both CO 2 and water availability. A number of studies show withdrawals decreasing with retirement of existing electricity generating units. Consumption, the evaporative losses, also decreases in many scenarios. However, climate mitigation scenarios relying heavily on nuclear and carbon capture technologies may induce increases in water consumption. These increases in consumption represent a potential tradeoff between climate mitigation and adaptation of the electric sector to climate-related changes in water resources. It also points to the need for both analyses and technological solutions from the chemical engineering community. [ABSTRACT FROM AUTHOR]

Highlights: [•] Renewable electricity generation could supply 80% of U.S. generation in 2050. [•] GHGs are reduced proportionally and water use is reduced by 50%. [•] Gross land-use impacts total less than 3% of land area of the contiguous U.S. [•] Some clean energy technologies rely on materials that face short-term risks. [•] No insurmountable long-term constraints to materials supply were identified. [ABSTRACT FROM AUTHOR]

The Columbia River Treaty requires coordinated water flows between Canada and the U.S. to improve power generation and provide flood control. In September 2014 either country can announce their desire to terminate participation in the Treaty. Already there appears to be a significant chasm between the entities with respect to how they will allocate the costs and benefits associated with future coordinated operations. [Copyright &y& Elsevier]

This article reviews the challenges to U.S. offshore wind development and models used to procure offshore wind projects, specifically the utility model, state model, and the natural evolution of a regional model. While not new, the regional model does offer a viable means to support very large offshore wind projects while mitigating the costs to ratepayers. [Copyright &y& Elsevier]

Abstract: In the United States, electricity consumers are told that they can “buy” electricity from renewable energy projects, versus fossil fuel-fired facilities, through participation in voluntary green power markets. The marketing messages communicate to consumers that they are causing additional renewable energy generation and reducing emissions through their participation and premium payments for a green label. Using a spatial financial model and a database of registered Green-e wind power facilities, the analysis in this paper shows that the voluntary Renewable Energy Certificate (REC) market has a negligible influence on the economic feasibility of these facilities. Nevertheless, voluntary green power marketers at least implicitly claim that buying their products creates additional renewable energy. This study indicates the contrary. Participants in U.S. voluntary green power markets associated with wind power, therefore, appear to be receiving misleading marketing messages regarding the effect of their participation. In the process of completing this analysis, a potentially relevant factor in explaining investor behavior was identified: the potential for the overlap of voluntary REC markets with compliance REC markets that supply utilities need to meet their obligations of Renewable Energy Portfolio Standard (RPS). The majority of state RPS rules allow for regional or even national sourcing of RECs, meaning that projects are generally eligible to provide compliance RECs to utilities not only in their home states, but in several other states. [Copyright &y& Elsevier]

Abstract: Renewable energy resources have historically played a small role for electricity generation in the US. However, concerns such as security of energy supply, limitations and price fluctuations of fossil fuels, and threats of climate changes have encouraged US policy makers to think and debate about diversification strategy in the energy supply and promotion of renewables. The current paper discusses the role of renewable portfolio in the US energy action plan during 2010–2030. A system dynamics model is constructed to evaluate different costs of renewable energy utilization by 2030. Results show that while renewables will create a market with near 10 billion $ worth (in the costs level) in 2030, the total value of renewable energy promotion and utilization in the US will be more than 170 billion $(in the costs level) during 2010–2030. [Copyright &y& Elsevier]

Abstract: This paper presents high renewable electricity penetration scenarios in the United States using detailed capacity expansion modeling that is designed to properly account for the variability and uncertainty of wind and solar resources. The scenarios focus solely on the electricity system, an important sector within the larger energy sector, and demonstrate long-term visions of a U.S. power system where renewable technologies, including biomass, geothermal, hydropower, solar, and wind, contribute 80% of 2050 annual electricity, including 49–55% from wind and solar photovoltaic generation. We present the integration challenges of achieving this high penetration and characterize the options to increase grid flexibility to manage variability. Four high renewable pathways are modeled and demonstrate the robustness and diversity of renewable options. We estimate 69–82% annual greenhouse gas emission reductions and 3%–30% incremental electricity price increases associated with reaching 80%-by-2050 renewable electricity relative to reference scenarios. This paper affirms and strengthens similar analysis from the Renewable Electricity Futures study by using an improved model and updated data to better reflect investment and dispatch decisions under current outlooks for the U.S. electricity sector. [Copyright &y& Elsevier]

Residential solar's diffusion across the U.S. power grid is inspiring concern in the utility industry. Of particular debate have been net energy metering policies (NEM), which engender revenue losses and lead to cross-subsidization of solar customers by non-solar customers. An emerging alternative to NEM is the value of solar tariff (VOST), which is designed to pay residential solar generation based on a more nuanced benefit-cost analysis to determine the actual value of residential solar to utility operations. [ABSTRACT FROM AUTHOR]

This paper presents a framework for pricing the climate resilience of an energy infrastructure project through assessing the value of its required debt and equity investments. Integrating climate scenarios into an asset valuation model provides useful and specific insights for risk management, but there is a lack of academic and market tools that effectively address this need. The critical barrier is that climate-related risks (physical and transition) are typically indirect variables in the cash flow calculation, and they should be computed based on the direct variables such as revenue, capital expenditures, operating expenses, and financing costs. The implementation of this framework shows how to delineate climate-related risks that are asset-specific and transforms them into financial risks. Using cash flow simulation and scenario analysis, it estimates an energy infrastructure asset's probability of default due to climate-related risks and the size and timing of the losses for any given default. To demonstrate the framework's application, we simulate the price climate-related risks of a utility-scale electricity generation facility powered by natural gas. • The analysis focuses on climate-related financial risk assessment of infrastructure assets. • An asset-level and forward-looking climate risk assessment framework is developed. • It tests single or combined climate risk scenarios on conventional financial metrics. • A case study on a natural gas power plant in the United States is demonstrated. [ABSTRACT FROM AUTHOR]

Abstract: In order to secure the energy future and protect the environment, the U.S. is looking for renewable resources to meet the increasing energy demands for its electricity sector (which accounts for ≈ 40% of total U.S. energy consumption in 2011). The overall aim of this article is to summarize the possible approaches that can be used to improve and optimize the utilization of renewables for electricity generation in the United States. First, an overview is presented about the resource potential, current usage, and technical status of electricity generation from renewables (in the United States). Second, a number of economic, operational, regulatory, sustainability, and technical challenges that are likely to be encountered are identified. Third, strategies are outlined that can be used to minimize costs, deal with the spatial nature of renewables, smooth temporal variations associated with intermittency, and achieve successful integration of electricity generated from renewable resources into the U.S. power grid. Fourth, a sustainability assessment framework for renewable resource deployment (for electricity generation in the U.S.) is discussed. The framework considers multiple criteria (including cost, environmental and social impacts), thus giving a comprehensive assessment of each renewable energy resource (for electricity generation in the United States). Fifth, the current U.S. renewable energy policy is analyzed, and rigorous recommendations are made for optimizing future U.S. renewable energy policy that can permanently induce a long-term sustainable shift towards electricity generation from renewables. Finally, directions for future research are highlighted. [Copyright &y& Elsevier]

Abstract: A substantial number of wind energy projects have been stalled or abandoned in the United States of America (US) due to concerns over the effects of wind turbines on radar installations. Between 2008 and 2010, military, airspace, or meteorological radar concerns in the US contributed to the delay or abandonment of an estimated 20,000 MW of wind energy capacity. These delays are a likely major factor influencing the current US Administration''s failure to double non-hydro renewable generation from 2008 to 2011; a target stated by the US President in a joint session address to Congress in February 2009. The delays are also a threat to the US Department of Energy''s target to produce 20% of electricity from wind energy by 2030 – unless radar-related barriers are mitigated. This work includes interviews with two senior representatives, from the US Department of Defence (DOD) and the American Wind Energy Association (AWEA), discussing the nature of concerns pertaining to the effects of wind turbines on radar and military/aviation in the US alongside approaches that have been trialled that aim to resolve such concerns. This research finds that the Energy Siting Clearing House, established within the DOD to review delayed wind farm projects, has brought much needed coordination to the approval process. A key challenge for any review body, however, will be to deliver an objective outcome that is not overturned by alternative political agendas. Integral to the success of any approach will be a sufficient capacity and mandate to facilitate the technical and non-technical cross-disciplinary and interagency research generating a balance between military, airspace, meteorological, and wind energy industry/political objectives. [Copyright &y& Elsevier]

Abstract: Wind energy development is booming worldwide with Germany and the United States being forerunners in installed capacity. Based on a review of relevant laws and regulations, policy, siting, and permitting documents, academic literature, and expert interviews, the paper compares the permit and environmental impact assessment (IA) policies and regulations pertaining to wind energy projects in both countries. The focus is on the potential of IAs in supporting an environmentally conscious development of wind power generation. This includes the analysis of IA regulations on the project level, strategic level impact assessment and planning processes, opportunities for public involvement and transparency of processes, and the clarity and predictability of the IA provisions. The findings suggest certain variations between both countries'' permit and IA processes for wind energy projects and further research needs, inter alia on the actual effects of strategic assessment of wind development on subsequent permitting. [Copyright &y& Elsevier]

Abstract: This paper considers some of the impacts of adopting hydrogen fuel cell powered electric automobiles in the US. The change will need significant adjustments to the electrical generation industry including additional capital and hydrocarbon fuel consumption as well as impacting anthropogenic greenhouse emissions. Examining the use of three fuels to generate hydrogen fuels, using three production methods, distributed in three geographic scenarios, we determine that while the change reduces anthropogenic greenhouse emissions with minimal additional electrical generation capital expenditures, it accelerates the use of natural gas. Electrolysis provides a sustainable, longer-term solution, but requires more capital investment in electrical generation and yields an increase in anthropogenic greenhouse emissions. [Copyright &y& Elsevier]

Abstract: Battery electric vehicles (BEVs) are often portrayed as “green,” implying negligible greenhouse gas (GHG) emissions. While BEVs are zero emission vehicles, the electrical power generators used to recharge vehicle batteries do emit copious GHGs. Some analysts have estimated the power plant GHG emissions due to charging EV batteries using the average electrical generator grid mix for a given region. However, the GHG protocol specifies that analysts should use the marginal grid mixes to accurately calculate GHG emissions from adding EVs to the vehicle fleet. This paper utilizes the marginal grid mixes for each electrical power region in the US, and calculates the vehicle-weighted average GHG emissions for the entire country. These calculations demonstrate that, on the average, each BEV that displaces a gasoline hybrid electric vehicle (HEV) will increase GHGs by more than 7% and each PHEV put in service will increase GHGs by an average of 10% compared to a gasoline HEV. [Copyright &y& Elsevier]