The changing carbon content of coal consumed in China between 2002 and 2012 is quantified using information from the power sector. The carbon content decreased by 7.7% over this interval, the decrease particularly pronounced between 2007 and 2009. Inferences with respect to the changing carbon content of coal and the oxidation rate for its consumption, combined with the recent information on coal use in China, are employed to evaluate the trend in emissions of CO2. Emissions are estimated to have increased by 158% between 2002 and 2012, from 3.9 Gt y-1 to 9.2 Gt y-1. Our estimated emissions for 2005 are notably consistent with data reported by China in its “Second National Communication” to the UN (NDRC, 2012) and significantly higher than the estimation published recently in Nature. The difference is attributed, among other factors, to the assumption of a constant carbon content of coal in the latter study. The results indicate that CO2 emissions of China in 2005 reported by Second National Communication are more reliable to serve as the baseline for China's future carbon commitments (e.g. those in Paris Agreement of the UNFCCC). Discrepancies between national and provincial statistics on coal production and consumption are investigated and attributed primarily to anomalous reporting on interprovincial trade in four heavily industrialized provinces.
Current Chinese policy promotes the development of both electricity-propelled vehicles and carbon-free sources of power. Concern has been expressed that electric vehicles on average may emit more CO2 and conventional pollutants in China. Here, we explore the environmental implications of investments in different types of electric vehicle (public buses, taxis and private light-duty vehicles) and different modes (fast or slow) for charging under a range of different wind penetration levels. To do this, we take Beijing in 2020 as a case study and employ hourly simulation of vehicle charging behaviour and power system operation. Assuming the slow-charging option, we find that investments in electric private light-duty vehicles can result in an effective reduction in the emission of CO2 at several levels of wind penetration. The fast-charging option, however, is counter-productive. Electrifying buses and taxis offers the most effective option to reduce emissions of NOx, a major precursor for air pollution.
The paper considers opportunities to reduce emissions of CO2 through increases in commitments to wind in a representative US power market. A model is applied to simulate market operations for different wind levels focusing on implications of the reduction in clearing prices arising due to increasing inputs of zero marginal cost power from wind, a dilemma referred to as the missing money problem. The resulting decrease in income poses problems for existing thermal and nuclear generating systems, at the same time making investments in wind uneconomic in the absence offsetting policy interventions. Two options are considered to subsidize cost: an investment credit (IC) or a subsidy on production (PC). The dilemma could be addressed also with a carbon tax targeted to increase income. It is assumed that the cost associated with the IC and PC options should be borne by the consumer, offsetting benefits from lower wholesale prices. It is assumed further that income from the carbon tax should be rebated to the consumer offsetting related increases in clearing prices. IC and PC options offer opportunities to reduce emissions at low or even negative net costs to the consumer. Higher costs are associated with the option of a carbon tax.
Deploying high penetration of variable renewables represents a critical pathway for deep decarbonizing the power sector. The conflict between their temporal variability and limited system flexibility has been largely ignored currently at planning stage. Here we present a novel capacity expansion model optimizing investment decisions and full-year, hourly power balances simultaneously, with considerations of storage technologies and policy constraints, such as carbon tax and renewable portfolio standards (RPS). Based on a computational efficient modeling formulation, all flexibility constrains (ramping, reserve, minimum output, minimal online/offline time) for the 8760-hour duration are incorporated. The proposed model is applied to the northwestern grid of China to examine the optimal composition and distribution of power investments with a wide range of renewable targets. Results indicate that the cost can increase moderately towards 45% of RPS, when properly designing the generation portfolio: prioritizing wind investments, distributing renewable investments more evenly and deploying more flexible mid-size coal and gas units. Reaching higher penetrations of renewables is expensive and the reductions of storage costs are critically important for an affordable low-carbon future. RPS or carbon taxes to reach a same target of emission reduction in China will result in similar overall costs but different generation mixes.
Investment for renewables has been growing rapidly since the beginning of the new century, and the momentum is expected to sustain in order to mitigate the impact of anthropogenic climate change. Transition towards higher renewable penetration in the power industry will not only confront technical challenges, but also face socio-economic obstacles. The connected between environment and energy systems are also tightened under elevated penetration of renewables. This paper will provide an overview of some important challenges related to technical, environmental and socio-economic aspects at elevated renewable penetration. An integrated analytical framework for interlinked technical, environmental and socio-economic systems will be presented at the end.
With the largest installed capacity in the world, wind power in China is experiencing a ∼20% curtailment. The inflexible combined heat and power (CHP) has been recognized as the major barrier for integrating the wind source. The approach to reconcile the conflict between inflexible CHP units and variable wind power in Chinese energy system is yet un-clear. This paper explores the technical and economic feasibility of deploying the heat storage tanks and electric boilers under typical power grids and practical operational regulations. A mixed integer linear optimization model is proposed to simulate an integrated power and heating energy systems, including a CHP model capable of accounting for the commitment decisions and non-convex energy generation constraints. The model is applied to simulate a regional energy system (Jing-Jin-Tang) covering 100-million population, with hourly resolution over a year, incorporating actual data and operational regulations. The results project an accelerating increase in wind curtailment rate at elevated wind penetration. Investment for wind breaks-even at 14% wind penetration. At such penetration, the electric boiler (with heat storage) is effective in reducing wind curtailment. The investment in electric boilers is justified on a social economic basis, but the revenues for different stakeholders are not distributed evenly.
The United States has committed to reduce its greenhouse gas emissions by 26%–28% by 2025 and by 83% by 2050 relative to 2005. Meeting these objectives will require major investments in renewable energy options, particularly wind and solar. These investments are promoted at the federal level by a variety of tax credits, and at the state level by requirements for utilities to include specific fractions of renewable energy in their portfolios (Renewable Portfolio Standards) and by opportunities for rooftop PV systems to transfer excess power to utilities through net metering, allowing meters to operate in reverse. The paper discusses the current status of these incentives.
China hosts the world’s largest market for wind-generated electricity. The financial return and carbon reduction benefits from wind power are sensitive to changing wind resources. Wind data derived from an assimilated meteorological database are used here to estimate what the wind generated electricity in China would have been on an hourly basis over the period 1979 to 2015 at a geographical resolution of approximately 50 km × 50 km. The analysis indicates a secular decrease in generating potential over this interval, with the largest declines observed for western Inner Mongolia (15 ± 7%) and the northern part of Gansu (17 ± 8%), two leading wind investment areas. The decrease is associated with long-term warming in the vicinity of the Siberian High (SH), correlated also with the observed secular increase in global average surface temperatures. The long-term trend is modulated by variability relating to the Pacific Decadal Oscillation (PDO) and the Arctic Oscillation (AO). A linear regression model incorporating indices for the PDO and AO, as well as the declining trend, can account for the interannual variability of wind power, suggesting that advances in long-term forecasting could be exploited to markedly improve management of future energy systems.
Accommodating variable wind power poses a critical challenge for electric power systems that are heavily dependent on combined heat and power (CHP) plants, as is the case for north China. An improved unit-commitment model is applied to evaluate potential benefits from pumped hydro storage (PHS) and electric boilers (EBs) in West Inner Mongolia (WIM), where CHP capacity is projected to increase to 33.8 GW by 2020. A business-as-usual (BAU) reference case assumes deployment of 20 GW of wind capacity. Compared to BAU, expanding wind capacity to 40 GW would allow for a reduction in CO2 emissions of 33.9 million tons, but at a relatively high cost of US$25.3/ton, reflecting primarily high associated curtailment of wind electricity (20.4%). A number of scenarios adding PHS and/or EBs combined with higher levels of wind capacity are evaluated. The best case indicates that a combination of PHS (3.6 GW) and EBs (6.2 GW) together with 40 GW of wind capacity would reduce CO2 emissions by 43.5 million tons compared to BAU, and at a lower cost of US$16.0/ton. Achieving this outcome will require a price-incentive policy designed to ensure the profitability of both PHS and EB facilities.
Although capacity credits for wind power have been embodied in power systems in the U.S. and Europe, the current planning framework for electricity in China continues to treat wind power as a non-dispatchable source with zero contribution to firm capacity. This study adopts a rigorous reliability model for the electric power system evaluating capacity credits that should be recognized for offshore wind resources supplying power demands for Jiangsu, China. Jiangsu is an economic hub located in the Yangtze River delta accounting for 10% of the total electricity consumed in China. Demand for electricity in Jiangsu is projected to increase from 331 TWh in 2009 to 800 TWh by 2030. Given a wind penetration level of 60% for the future additional Jiangsu power supply, wind resources distributed along the offshore region of five coastal provinces in China (Shandong, Jiangsu, Shanghai, Zhejiang and Fujian) should merit a capacity credit of 12.9%, the fraction of installed wind capacity that should be recognized to displace coal-fired systems without violating the reliability standard. In the high-coal-price scenario, with 60% wind penetration, reductions in CO2 emissions relative to a business as usual reference could be as large as 200.2 million tons of CO2 or 51.8% of the potential addition, with a cost for emissions avoided of $29.0 per ton.
Demands for electricity and energy to supply heat are expected to expand by 71% and 47%, respectively, for Beijing in 2020 relative to 2009. If the additional electricity and heat are supplied solely by coal as is the current situation, annual emissions of CO2 may be expected to increase by 59.6% or 99 million tons over this interval. Assessed against this business as usual (BAU) background, the present study indicates that significant reductions in emissions could be realized using wind-generated electricity to provide a source of heat, employed either with heat pumps or with electric thermal storage (ETS) devices. Relative to BAU, reductions in CO2 with heat pumps assuming 20% wind penetration could be as large as 48.5% and could be obtained at a cost for abatement of as little as $15.6 per ton of avoided CO2. Even greater reductions, 64.5%, could be realized at a wind penetration level of 40% but at a higher cost, $29.4 per ton. Costs for reduction of CO2 using ETS systems are significantly higher, reflecting the relatively low efficiency for conversion of coal to power to heat.
Demand for electricity in China is concentrated to a significant extent in its coastal provinces. Opportunities for production of electricity by on-shore wind facilities are greatest, however, in the north and west of the country. Using high resolution wind data derived from the GEOS-5 assimilation, this study shows that investments in off-shore wind facilities in these spatially separated regions (Bohai-Bay or BHB, Yangtze-River Delta or YRD, Pearl-River Delta or PRD) could make an important contribution to overall regional demand for electricity in coastal China. An optimization analysis indicates that hour-to-hour variability of outputs from a combined system can be minimized by investing 24% of the power capacity in BHB, 30% in YRD and 47% in PRD. The analysis suggests that about 28% of the overall off-shore wind potential could be deployed as base load power replacing coal-fired system with benefits not only in terms of reductions in CO2 emissions but also in terms of improvements in regional air quality. The interconnection of off-shore wind resources contemplated here could be facilitated by China's 12th-five-year plan to strengthen inter-connections between regional electric-power grids.
The Harvard-China Project adopted an Open Access policy in September 2017. Most journal articles published henceforth are available in the Harvard University open-access repository, DASH.