The geographical distribution of fossil fuels unused when limiting global warming to 2 °C.

Policy makers have generally agreed that the average global temperature rise caused by greenhouse gas emissions should not exceed 2 °C above the average global temperature of pre-industrial times. It has been estimated that to have at least a 50 per cent chance of keeping warming below 2 °C throughout the twenty-first century, the cumulative carbon emissions between 2011 and 2050 need to be limited to around 1,100 gigatonnes of carbon dioxide (Gt CO2). However, the greenhouse gas emissions contained in present estimates of global fossil fuel reserves are around three times higher than this, and so the unabated use of all current fossil fuel reserves is incompatible with a warming limit of 2 °C. Here we use a single integrated assessment model that contains estimates of the quantities, locations and nature of the world's oil, gas and coal reserves and resources, and which is shown to be consistent with a wide variety of modelling approaches with different assumptions, to explore the implications of this emissions limit for fossil fuel production in different regions. Our results suggest that, globally, a third of oil reserves, half of gas reserves and over 80 per cent of current coal reserves should remain unused from 2010 to 2050 in order to meet the target of 2 °C. We show that development of resources in the Arctic and any increase in unconventional oil production are incommensurate with efforts to limit average global warming to 2 °C. Our results show that policy makers' instincts to exploit rapidly and completely their territorial fossil fuels are, in aggregate, inconsistent with their commitments to this temperature limit. Implementation of this policy commitment would also render unnecessary continued substantial expenditure on fossil fuel exploration, because any new discoveries could not lead to increased aggregate production.

The Economic Merits of Flexible Carbon Capture and Sequestration as a Compliance Strategy with the Clean Power Plan.

Carbon capture and sequestration (CCS) may be a key technology for achieving large CO2 emission reductions. Relative to "normal" CCS, "flexible" CCS retrofits include solvent storage that allows the generator to temporarily reduce the CCS parasitic load and increase the generator's net efficiency, capacity, and ramp rate. Due to this flexibility, flexible CCS generators provide system benefits that normal CCS generators do not, which could make flexible CCS an economic CO2 emission reduction strategy. Here, we estimate the system-level cost effectiveness of reducing CO2 emissions with flexible CCS compared to redispatching (i.e., substituting gas- for coal-fired electricity generation), wind, and normal CCS under the Clean Power Plan (CPP) and a hypothetical more stringent CO2 emission reduction target ("stronger CPP"). Using a unit commitment and economic dispatch model, we find flexible CCS achieves more cost-effective emission reductions than normal CCS under both reduction targets, indicating that policies that promote CCS should encourage flexible CCS. However, flexible CCS is less cost effective than wind under both reduction targets and less and more cost effective than redispatching under the CPP and stronger CPP, respectively. Thus, CCS will likely be a minor CPP compliance strategy but may play a larger role under a stronger emission reduction target.

Association Between Energy Prices and US Hospital Patient Outcomes.

OBJECTIVE: To evaluate associations between changing energy prices and US hospital patient outcomes. METHODS: Generalized estimating equations were used to analyze relationships between changes in energy prices and subsequent changes in hospital patient outcomes measures for the years 2008 through 2014. Patient outcomes measures included 30-day acute myocardial infarction, heart failure, and pneumonia mortality rates, and 30-day acute myocardial infarction, heart failure, and pneumonia readmission rates. Energy price data included state average distillate fuel, electricity and natural gas prices, and the US average coal price. All of the price data were converted to 2014 dollars using Consumer Price Index multipliers. RESULTS: There was a significant positive association between changes in coal price and both short-term (P = 0.029) and long-term (P = 0.017) changes in the 30-day heart failure mortality rate. There was a similar significant positive association between changes in coal price and both short-term (P <0.001) and long-term (P = 0.002) changes in the 30-day pneumonia mortality rate. Changes in coal prices also were positively associated with long-term changes in the 30-day myocardial infarction readmission rate (P < 0.001). Changes in coal prices (P = 0.20), natural gas prices (P = 0.040), and electricity prices (P = 0.040) were positively associated with long-term changes in the 30-day heart failure readmission rate. CONCLUSIONS: Changing energy prices are associated with subsequent changes in hospital mortality and readmission measures. In light of these data, we encourage hospital, health system, and health policy leaders to pursue patient-support initiatives, energy conservation programs, and reimbursement policy strategies aimed at mitigating those effects.

Technoeconomic Assessment of an Advanced Aqueous Ammonia-Based Postcombustion Capture Process Integrated with a 650-MW Coal-Fired Power Station.

Using a rigorous, rate-based model and a validated economic model, we investigated the technoeconomic performance of an aqueous NH3-based CO2 capture process integrated with a 650-MW coal-fired power station. First, the baseline NH3 process was explored with the process design of simultaneous capture of CO2 and SO2 to replace the conventional FGD unit. This reduced capital investment of the power station by US$425/kW (a 13.1% reduction). Integration of this NH3 baseline process with the power station takes the CO2-avoided cost advantage over the MEA process (US$67.3/tonne vs US$86.4/tonne). We then investigated process modifications of a two-stage absorption, rich-split configuration and interheating stripping to further advance the NH3 process. The modified process reduced energy consumption by 31.7 MW/h (20.2% reduction) and capital costs by US$55.4 million (6.7% reduction). As a result, the CO2-avoided cost fell to $53.2/tonne: a savings of $14.1 and $21.9/tonne CO2 compared with the NH3 baseline and advanced MEA process, respectively. The analysis of energy breakdown and cost distribution indicates that the technoeconomic performance of the NH3 process still has great potential to be improved.

A Techno-Economic Assessment of Hybrid Cooling Systems for Coal- and Natural-Gas-Fired Power Plants with and without Carbon Capture and Storage.

Advanced cooling systems can be deployed to enhance the resilience of thermoelectric power generation systems. This study developed and applied a new power plant modeling option for a hybrid cooling system at coal- or natural-gas-fired power plants with and without amine-based carbon capture and storage (CCS) systems. The results of the plant-level analyses show that the performance and cost of hybrid cooling systems are affected by a range of environmental, technical, and economic parameters. In general, when hot periods last the entire summer, the wet unit of a hybrid cooling system needs to share about 30% of the total plant cooling load in order to minimize the overall system cost. CCS deployment can lead to a significant increase in the water use of hybrid cooling systems, depending on the level of CO2 capture. Compared to wet cooling systems, widespread applications of hybrid cooling systems can substantially reduce water use in the electric power sector with only a moderate increase in the plant-level cost of electricity generation.

Residential Solar PV Systems in the Carolinas: Opportunities and Outcomes.

This paper presents a first-order analysis of the feasibility and technical, environmental, and economic effects of large levels of solar photovoltaic (PV) penetration within the services areas of the Duke Energy Carolinas (DEC) and Duke Energy Progress (DEP). A PV production model based on household density and a gridded hourly global horizontal irradiance data set simulates hourly PV power output from roof-top installations, while a unit commitment and real-time economic dispatch (UC-ED) model simulates hourly system operations. We find that the large generating capacity of base-load nuclear power plants (NPPs) without ramping capability in the region limits PV integration levels to 5.3% (6510 MW) of 2015 generation. Enabling ramping capability for NPPs would raise the limit of PV penetration to near 9% of electricity generated. If the planned retirement of coal-fired power plants together with new installations and upgrades of natural gas and nuclear plants materialize in 2025, and if NPPs operate flexibly, then the share of coal-fired electricity will be reduced from 37% to 22%. A 9% penetration of electricity from PV would further reduce the share of coal-fired electricity by 4-6% resulting in a system-wide CO2 emissions rate of 0.33 to 0.40 tons/MWh and associated abatement costs of 225-415 (2015$ per ton).

Opportunities for Decarbonizing Existing U.S. Coal-Fired Power Plants via CO2 Capture, Utilization and Storage.

This study employs a power plant modeling tool to explore the feasibility of reducing unit-level emission rates of CO2 by 30% by retrofitting carbon capture, utilization, and storage (CCUS) to existing U.S. coal-fired electric generating units (EGUs). Our goal is to identify feasible EGUs and their key attributes. The results indicate that for about 60 gigawatts of the existing coal-fired capacity, the implementation of partial CO2 capture appears feasible, though its cost is highly dependent on the unit characteristics and fuel prices. Auxiliary gas-fired boilers can be employed to power a carbon capture process without significant increases in the cost of electricity generation. A complementary CO2 emission trading program can provide additional economic incentives for the deployment of CCS with 90% CO2 capture. Selling and utilizing the captured CO2 product for enhanced oil recovery can further accelerate CCUS deployment and also help reinforce a CO2 emission trading market. These efforts would allow existing coal-fired EGUs to continue to provide a significant share of the U.S. electricity demand.

Environmental implications of United States coal exports: a comparative life cycle assessment of future power system scenarios.

Stricter emissions requirements on coal-fired power plants together with low natural gas prices have contributed to a recent decline in the use of coal for electricity generation in the United States. Faced with a shrinking domestic market, many coal companies are taking advantage of a growing coal export market. As a result, U.S. coal exports hit an all-time high in 2012, fueled largely by demand in Asia. This paper presents a comparative life cycle assessment of two scenarios: a baseline scenario in which coal continues to be burned domestically for power generation, and an export scenario in which coal is exported to Asia. For the coal export scenario we focus on the Morrow Pacific export project being planned in Oregon by Ambre Energy that would ship 8.8 million tons of Powder River Basin (PRB) coal annually to Asian markets via rail, river barge, and ocean vessel. Air emissions (SOx, NOx, PM10 and CO2e) results assuming that the exported coal is burned for electricity generation in South Korea are compared to those of a business as usual case in which Oregon and Washington's coal plants, Boardman and Centralia, are retrofitted to comply with EPA emissions standards and continue their coal consumption. Findings show that although the environmental impacts of shipping PRB coal to Asia are significant, the combination of superior energy efficiency among newer South Korean coal-fired power plants and lower emissions from U.S. replacement of coal with natural gas could lead to a greenhouse gas reduction of 21% in the case that imported PRB coal replaces other coal sources in this Asian country. If instead PRB coal were to replace natural gas or nuclear generation in South Korea, greenhouse gas emissions per unit of electricity generated would increase. Results are similar for other air emissions such as SOx, NOx and PM. This study provides a framework for comparing energy export scenarios and highlights the importance of complete life cycle assessment in determining net emissions effects resulting from energy export projects and related policy decisions.

Assessment of the US EPA's determination of the role for CO2 capture and storage in new fossil fuel-fired power plants.

On September 20, 2013, the US Environmental and Protection Agency (EPA) proposed a revised rule for "Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units". These performance standards set limits on the amount of carbon dioxide (CO2) that can be emitted per megawatt-hour (MWh) of electricity generation from new coal-fired and natural gas-fired power plants built in the US. These limits were based on determinations of "best system of emission reduction (BSER) adequately demonstrated". Central in this determination was evaluating whether Carbon Dioxide Capture and Storage (CCS) qualified as BSER. The proposed rule states that CCS qualifies as BSER for coal-fired generation but not for natural gas-fired generation. In this paper, we assess the EPA's analysis that resulted in this determination. We are not trying to judge what the absolute criteria are for CCS as the BSER but only the relative differences as related to coal- vs natural gas-fired technologies. We conclude that there are not enough differences between "base load" coal-fired and natural gas-fired power plants to justify the EPA's determination that CCS is the BSER for coal-fired power plants but not for natural gas-fired power plants.

Siting is a constraint to realize environmental benefits from carbon capture and storage.

Carbon capture and storage (CCS) for coal power plants reduces onsite carbon dioxide emissions, but affects other air emissions on and offsite. This research assesses the net societal benefits and costs of Monoethanolamine (MEA) CCS, valuing changes in emissions of CO2, SO2, NOX, NH3 and particulate matter (PM), including those in the supply chain. Geographical variability and stochastic uncertainty for 407 coal power plant locations in the U.S. are analyzed. The results show that the net environmental benefits and costs of MEA CCS depend critically on location. For a few favorable sites of both power plant and upstream processes, CCS realizes a net benefit (benefit-cost ratio >1) if the social cost of carbon exceeds $51/ton. For much of the U.S. however, the social cost of carbon must be much higher to realize net benefits from CCS, up to a maximum of $910/ton. While the social costs of carbon are uncertain, typical estimates are in the range of $32-220 per ton, much lower than the breakeven value for many potential CCS locations. Increased impacts upstream from the power plant can dramatically change the social acceptability of CCS and needs further consideration and analysis.

Global health costs of ambient PM2·5 from combustion sources: a modelling study supporting air pollution control strategies.

BACKGROUND: Climate actions targeting combustion sources can generate large ancillary health benefits via associated air-quality improvements. Therefore, understanding the health costs associated with ambient fine particulate matter (PM2·5) from combustion sources can guide policy design for both air pollution and climate mitigation efforts. METHODS: In this modelling study, we estimated the health costs attributable to ambient PM2·5 from six major combustion sources across 204 countries using updated concentration-response models and an age-adjusted valuation method. We defined major combustion sources as the sum of total coal, liquid fuel and natural gas, solid biofuel, agricultural waste burning, other fires, and 50% of the anthropogenic fugitive, combustion, and industrial dust source. FINDINGS: Global long-term exposure to ambient PM2·5 from combustion sources imposed US$1·1 (95% uncertainty interval 0·8-1·5) trillion in health costs in 2019, accounting for 56% of the total health costs from all PM2·5 sources. Comparing source contributions to PM2·5 concentrations and health costs, we observed a higher share of health costs from combustion sources compared to their contribution to population-weighted PM2·5 concentration across 134 countries, accounting for more than 87% of the global population. This disparity was primarily attributed to the non-linear relationship between PM2·5 concentration and its associated health costs. Globally, phasing out fossil fuels can generate 23% higher relative health benefits compared to their share of PM2·5 reductions. Specifically, the share of health costs for total coal was 36% higher than the source's contributions to corresponding PM2·5 concentrations and the share of health costs for liquid fuel and natural gas was 12% higher. Other than fossil fuels, South Asia was expected to show 16% greater relative health benefits than the percentage reduction in PM2·5 from the abatement of solid biofuel emissions. INTERPRETATION: In most countries, targeting combustion sources might offer greater health benefits than non-combustion sources. This finding provides additional rationale for climate actions aimed at phasing out combustion sources, especially those related to fossil fuels and solid biofuel. Mitigation efforts designed according to source-specific health costs can more effectively avoid health costs than strategies that depend solely on the source contributions to overall PM2·5 concentration. FUNDING: The Health Effects Institute, the National Natural Science Foundation of China, and NASA.

Techno-economic assessment of polymer membrane systems for postcombustion carbon capture at coal-fired power plants.

This study investigates the feasibility of polymer membrane systems for postcombustion carbon dioxide (CO(2)) capture at coal-fired power plants. Using newly developed performance and cost models, our analysis shows that membrane systems configured with multiple stages or steps are capable of meeting capture targets of 90% CO(2) removal efficiency and 95+% product purity. A combined driving force design using both compressors and vacuum pumps is most effective for reducing the cost of CO(2) avoided. Further reductions in the overall system energy penalty and cost can be obtained by recycling a portion of CO(2) via a two-stage, two-step membrane configuration with air sweep to increase the CO(2) partial pressure of feed flue gas. For a typical plant with carbon capture and storage, this yielded a 15% lower cost per metric ton of CO(2) avoided compared to a plant using a current amine-based capture system. A series of parametric analyses also is undertaken to identify paths for enhancing the viability of membrane-based capture technology.

Implications of the recent reductions in natural gas prices for emissions of CO2 from the US power sector.

CO(2) emissions from the US power sector decreased by 8.76% in 2009 relative to 2008 contributing to a decrease over this period of 6.59% in overall US emissions of greenhouse gases. An econometric model, tuned to data reported for regional generation of US electricity, is used to diagnose factors responsible for the 2009 decrease. More than half of the reduction is attributed to a shift from generation of power using coal to gas driven by a recent decrease in gas prices in response to the increase in production from shale. An important result of the model is that, when the cost differential for generation using gas rather than coal falls below 2-3 cents/kWh, less efficient coal fired plants are displaced by more efficient natural gas combined cycle (NGCC) generation alternatives. Costs for generation using NGCC decreased by close to 4 cents/kWh in 2009 relative to 2008 ensuring that generation of electricity using gas was competitive with coal in 2009 in contrast to the situation in 2008 when gas prices were much higher. A modest price on carbon could contribute to additional switching from coal to gas with further savings in CO(2) emissions.

Implications of near-term coal power plant retirement for SO2 and NOX and life cycle GHG emissions.

Regulations monitoring SO(2), NO(X), mercury, and other metal emissions in the U.S. will likely result in coal plant retirement in the near-term. Life cycle assessment studies have previously estimated the environmental benefits of displacing coal with natural gas for electricity generation, by comparing systems that consist of individual natural gas and coal power plants. However, such system comparisons may not be appropriate to analyze impacts of coal plant retirement in existing power fleets. To meet this limitation, simplified economic dispatch models for PJM, MISO, and ERCOT regions are developed in this study to examine changes in regional power plant dispatch that occur when coal power plants are retired. These models estimate the order in which existing power plants are dispatched to meet electricity demand based on short-run marginal costs, with cheaper plants being dispatched first. Five scenarios of coal plant retirement are considered: retiring top CO(2) emitters, top NO(X) emitters, top SO(2) emitters, small and inefficient plants, and old and inefficient plants. Changes in fuel use, life cycle greenhouse gas emissions (including uncertainty), and SO(2) and NO(X) emissions are estimated. Life cycle GHG emissions were found to decrease by less than 4% in almost all scenarios modeled. In addition, changes in marginal damage costs due to SO(2), and NO(X) emissions are estimated using the county level marginal damage costs reported in the Air Pollution Emissions Experiments and Policy (APEEP) model, which are a proxy for measuring regional impacts of SO(2) and NO(X) emissions. Results suggest that location specific parameters should be considered within environmental policy frameworks targeting coal plant retirement, to account for regional variability in the benefits of reducing the impact of SO(2) and NO(X) emissions.

Accelerated reduction in SO2 emissions from the U.S. power sector triggered by changing prices of natural gas.

Emissions of sulfur dioxide (SO(2)) from the U.S. power sector decreased by 24% in 2009 relative to 2008. The Logarithmic Mean Divisia Index (LMDI) approach was applied to isolate the factors responsible for this decrease. It is concluded that 15% of the decrease can be attributed to the drop in demand for electricity triggered by the economic recession, and 28% can be attributed to switching of fuel from coal to gas responding to the decrease in prices for the latter. The largest factor in the decrease, close to 57%, resulted from an overall decline in emissions per unit of power generated from coal. This is attributed in part to selective idling of older, less efficient coal plants that generally do not incorporate technology for sulfur removal, and in part to continued investments by the power sector in removal equipment in response to the requirements limiting emissions imposed by the U.S. Environmental Protection Agency (U.S. EPA). The paper argues further that imposition of a modest tax on emissions of carbon would have ancillary benefits in terms of emissions of SO(2).