Metacognitions about desire thinking predict the severity of binge eating in a sample of Italian women

In this study, our principal aim was to investigate whether metacognitions about desire thinking predict the severity of binge eating in women and, if so, whether this relationship is independent of age, self-reported body mass index (BMI), negative affect, irrational food beliefs and craving. One hundred and four women, consisting of 32 consecutive patients with binge eating disorder undergoing initial assessment for cognitive therapy for eating disorders, 39 moderate binge eaters, and 33 non-binge eaters (both from the general population), completed the following measures: Self-reported BMI, Hospital Anxiety and Depression Scale, Irrational Food Beliefs Scale, General Craving Scale, Metacognitions about Desire Thinking Questionnaire, and Binge Eating Scale. A series of Spearman's rho correlation analyses revealed that self-reported BMI, anxiety, depression, irrational food beliefs, craving, and all three factors of the metacognitions about desire thinking questionnaire were significantly associated with the severity of binge eating. A stepwise regression analysis identified self-reported BMI, craving, and negative metacognitions about desire thinking as significant predictors of the severity of binge eating. These results, taken together, highlight the possible role of metacognitions about desire thinking in predicting the severity of binge eating. The clinical implications of these findings are discussed

Toward a polycentric low-carbon transition: the roles of community-based energy initiatives in enhancing the resilience of energy systems

An understanding of the resilience of energy systems is critical in order to tackle forthcoming challenges. This chapter proposes that the polycentric governance perspective, developed by Vincent and Elinor Ostrom, may be highly relevant in formulating policies to enhance the resilience of future energy systems. Polycentric governance systems involve the coexistence of many self-organized centers of decision making at multiple levels that are formally independent of each other, but operate under an overarching set of rules. Given this polycentric approach, this chapter studies the roles of community-based energy initiatives and, in particular, of renewable energy cooperatives, in enhancing the institutional resilience of energy systems. In this perspective, the chapter identifies three major socio-institutional obstacles, which undermine this resilience capacity: the collective action problem arising from the diffusion of sustainable energy technologies and practices, the lack of public trust in established energy actors and the existence of strong vested interests in favor of the status quo. Then, it shows why the development of community-based energy initiatives and renewable energy cooperatives may offer effective responses to these obstacles, relying on many empirical illustrations. More specifically, it is argued that community-based energy initiatives present institutional features encouraging the activation of social norms and a high trust capital, therefore enabling them to offer effective solutions to avoid free riding and enhance trust in energy institutions and organizations. The creation of federated polycentric structures may also offer a partial response to the existence of vested interests in favor of the status quo. Finally, some recommendations for policymakers are derived from this analysis

2017 Wind Technologies Market Report

The U.S. Department of Energy (DOE)’s Wind Technologies Market Report provides an annual overview of trends in the U.S. wind power market. Highlights of this year’s report include: -Wind power capacity additions continued at a rapid pace in 2017: $11 billion was invested in new wind power plants in 2017. In 2017, wind energy contributed 6.3 -Bigger turbines are enhancing wind project performance: Increased blade lengths have dramatically increased wind project capacity factors, one measure of project performance, and taller towers appear to be on the horizon. The average 2017 capacity factor among projects built from 2014 through 2016 was 42 -Low wind turbine pricing continues to push down installed project costs: Wind turbine prices have fallen from their highs in 2008 to$750–$950/kW. Overall, the average installed cost of wind projects in 2017 was$1,610/kW, down $795/kW from the peak in 2009 and 2010. -Wind energy prices remain low: After topping out at 7¢/kWh for power purchase agreements (PPAs) executed in 2009, the national average price of wind PPAs has dropped to around 2¢/kWh—though this nationwide average is dominated by projects that hail from the lowest-priced Interior region of the country (such as Oklahoma, Nebraska, Kansas). These prices, which are possible in part due to federal tax support, compare favorably to the projected future fuel costs of gas-fired generation. -The domestic supply chain for wind equipment is diverse: Wind sector employment reached a new high of more than 105,000 full-time workers at the end of 2017. For wind projects recently installed in the U.S., domestically manufactured content is highest for nacelle assembly (>90%), towers (70-90%), and blades and hubs (50-70%), but is much lower (<20%) for most components internal to the turbine. -Continued strong growth in wind capacity is anticipated in the near term: With federal tax incentives still available, various forecasts for the domestic market show expected wind power capacity additions of 8,000 to 11,000 MW/year from 2018 to 2020, with market contraction anticipated beginning in 2021 as those tax incentives are phased out

Power Plant Retirements: Trends and Possible Drivers

This paper synthesizes available data on historical and planned power plant retirements. Specifically, we present data on historical generation capacity additions and retirements over time, and the types of plants recently retired and planned for retirement. We then present data on the age of plants that have recently retired or that have plans to retire. We also review the characteristics of plants that recently retired or plan to retire vs. those that continue to operate, focusing on plant size, age, heat rate, and SO2 emissions. Finally, we show the level of recent thermal plant retirements on a regional basis and correlate those data with a subset of possible factors that may be contributing to retirement decisions. This basic data synthesis cannot be used to precisely estimate the relative magnitude of retirement drivers. Nor do we explore every possible driver for retirement decisions. Moreover, future retirement decisions may be influenced by different factors than those that have affected past decisions. Nonetheless, it is clear that recently retired plants are relatively old, and that plants with stated planned retirement dates are—on average—no younger. We observe that retired plants are smaller, older, less efficient, and more polluting than operating plants. Based on simple correlation graphics, the strongest predictors of regional retirement differences appear to include SO2 emissions rates (for coal), planning reserve margins (for all thermal units), variations in load growth or contraction (for all thermal units), and the age of older thermal plans (for all thermal units). Additional apparent predictors of regional retirements include the ratio of coal to gas prices and delivered natural gas prices. Other factors appear to have played lesser roles, including the penetration variable renewable energy (VRE), recent non-VRE capacity additions, and whether the region hosts an ISO/RTO

Power Plant Retirements: Trends and Possible Drivers

This paper synthesizes available data on historical and planned power plant retirements. Specifically, we present data on historical generation capacity additions and retirements over time, and the types of plants recently retired and planned for retirement. We then present data on the age of plants that have recently retired or that have plans to retire. We also review the characteristics of plants that recently retired or plan to retire vs. those that continue to operate, focusing on plant size, age, heat rate, and SO2 emissions. Finally, we show the level of recent thermal plant retirements on a regional basis and correlate those data with a subset of possible factors that may be contributing to retirement decisions. This basic data synthesis cannot be used to precisely estimate the relative magnitude of retirement drivers. Nor do we explore every possible driver for retirement decisions. Moreover, future retirement decisions may be influenced by different factors than those that have affected past decisions. Nonetheless, it is clear that recently retired plants are relatively old, and that plants with stated planned retirement dates are—on average—no younger. We observe that retired plants are smaller, older, less efficient, and more polluting than operating plants. Based on simple correlation graphics, the strongest predictors of regional retirement differences appear to include SO2 emissions rates (for coal), planning reserve margins (for all thermal units), variations in load growth or contraction (for all thermal units), and the age of older thermal plans (for all thermal units). Additional apparent predictors of regional retirements include the ratio of coal to gas prices and delivered natural gas prices. Other factors appear to have played lesser roles, including the penetration variable renewable energy (VRE), recent non-VRE capacity additions, and whether the region hosts an ISO/RTO

Customer economics of residential photovoltaic systems: Sensitivities to changes in wholesale market design and rate structures

The customer economics of U.S. residential photovoltaics (PV) often depend on retail electricity rates, because most utilities compensate customer-sited PV generation via net metering. The future bill savings from net metering are uncertain and dependent on retail rate structures, wholesale market design, and renewable penetration levels, among other factors. We explore the impact of the following assumptions on the bill savings from residential PV: a wholesale electricity market design with a price cap (as opposed to an energy-only market); a retail rate with a fixed customer charge (as opposed to a fully volumetric rate); and increasing-block pricing (as opposed to a non-varying flat rate). A wholesale price cap can dampen the expected bill-savings erosion due to moving from a low to a high renewables scenario for customers with time-varying rates and net metering. Moving from a fully volumetric rate to a two-part tariff rate with a fixed customer charge could severely Erode the bill savings under net metering, because PV generation could only displace the (reduced) volumetric portion of the rate. Finally, increasing-block pricing might have an even greater impact on the bill savings from behind-the-meter PV than the other uncertainties explored in this paper

Income Trends of Residential PV Adopters: An analysis of household-level income estimates

The residential photovoltaic (PV) market has expanded rapidly over the past decade, but questions exist about how equitably that growth has occurred across income groups. Prior studies have investigated this question but are often limited by narrow geographic study regions, now-dated analysis timeframes, or coarse estimates of PV-adopter incomes. At the same time, a spate of new programs and initiatives, as well as innovations in business models and product design, have emerged in recent years with the aim of making solar more accessible and affordable to broader segments of the population. Yet, many of those efforts are proceeding without robust underlying information about the income characteristics of recent residential PV adopters. This work aims to establish basic factual information about income trends among U.S. residential solar adopters, with some emphasis on low- and moderate-income (LMI) households. The analysis is unique in its relatively extensive coverage of the U.S. solar market, relying on Berkeley Lab’s Tracking the Sun dataset, which contains project-level data for the vast majority of all residential PV systems in the country (a subset of which are ultimately included in the analysis sample). This analysis is also unique in its use of household-level income estimates that provide a more-precise characterization of PV-adopter incomes than in most prior studies

Long-term implications of sustained wind power growth in the United States: Direct electric system impacts and costs

This paper evaluates potential changes in the power system associated with sustained growth in wind generation in the United States to 35% of end-use demand by 2050; Wiser et al. (2016) evaluate societal benefits and other impacts for this same scenario. Under reference or central conditions, the analysis finds cumulative wind capacity of 404 gigawatts (GW) would be required to reach this level and drive 2050 incremental electricity rate and cumulative electric sector savings of 2% and 3% respectively, relative to a scenario with no new wind capacity additions. Greater savings are estimated under higher fossil fuel costs or with greater advancements in wind technologies. Conversely, incremental costs are found when fossil fuel costs are lower than central assumptions or wind technology improvements are more-limited. Through 2030, the primary generation sources displaced by new wind capacity include natural gas and coal-fired generation. By 2050, wind could displace other renewables. Incremental new transmission infrastructure totaling 29 million megawatt-miles is estimated to be needed by 2050. In conjunction with related societal benefits, this work demonstrates that 35% wind energy by 2050 is plausible, could support enduring benefits, and could result in long-term consumer savings, if nearer-term (pre-2030) cost barriers are overcome; at the same time, these opportunities are not anticipated to be realized in their full form under “business-as-usual” conditions