Policy Analysis pubs.acs.org/est
Implications of Near-Term Coal Power Plant Retirement for SO2 and NOX and Life Cycle GHG Emissions Aranya Venkatesh,*,† Paulina Jaramillo,‡ W. Michael Griffin,‡,§ and H. Scott Matthews†,‡ †
Civil and Environmental Engineering Department, ‡Department of Engineering and Public Policy, and §Tepper School of Business, Carnegie Mellon University, 5000 Forbes Avenue, Pittsburgh, Pennsylvania 15213-3890, United States S Supporting Information *
ABSTRACT: Regulations monitoring SO2, NOX, 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 CO2 emitters, top NOX emitters, top SO2 emitters, small and inefficient plants, and old and inefficient plants. Changes in fuel use, life cycle greenhouse gas emissions (including uncertainty), and SO2 and NOX 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 SO2, and NOX 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 SO2 and NOX 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 SO2 and NOX emissions.
■
INTRODUCTION Recent air quality regulations proposed by the U.S. Environmental Protection Agency (EPA), such as the Cross-State Air Pollution Rule (CSAPR) regulating SO2 and NOX emissions and the Mercury Air and Toxics Standards (MATS) regulating mercury, arsenic, and metals, will likely result in coal plant retrofitting or retirement. According to a recent PJM report,1 about 11−14 GW of mostly old, small, and inefficient coal-fired plants in the PJM Interconnection (including Pennsylvania, Ohio, New Jersey, and surrounding states) are likely to be retired due to these EPA regulations. Moreover, plants that have low capacity factors are good candidates for retirement due to poor retrofitting economics. In an independent report, the Brattle Group estimated that 30−60 GW of coal plants could be retired in the U.S., mostly in the PJM, Electric Reliability Council of Texas (ERCOT), and Midwest Independent Transmission System Operator (MISO) regions, by 2015.2 In 2007, PJM, MISO, and ERCOT contributed to about half of the 370 GW of coal capacity in the U.S.3 In the last two years alone, over 100 coal plant retirement announcements were made in the U.S.4 In the past few years, significant work has been done to understand the environmental benefits of displacing coal with natural gas.5−10 These studies have used life cycle methods and © 2012 American Chemical Society
assume that one kWh of natural gas-based electricity displaces one kWh of coal-based electricity. While this comparison may be relevant when the analysis is focused on choosing which technology to use when building new power plants, it is not appropriate for analyzing the impacts in existing power plant fleets. In restructured power systems, power plants are dispatched to meet load based on their short-run marginal costs, with cheaper plants being dispatched first.11−13 Since coal power plants generally have lower short-run marginal costs than natural gas plants, they are dispatched first. It is thus unlikely that power from decommissioned coal plants will be replaced entirely with natural gas-based power. For example, other coal plants with available capacity and lower short-run marginal costs than available natural gas plants could substitute electricity previously provided by the decommissioned coal plants. In this study, a simplified economic dispatch model, representing existing power plants, is developed and used along with historical load data to examine changes in power Received: Revised: Accepted: Published: 9838
June 12, 2012 August 3, 2012 August 13, 2012 August 13, 2012 dx.doi.org/10.1021/es3023539 | Environ. Sci. Technol. 2012, 46, 9838−9845
Environmental Science & Technology
Policy Analysis
plant dispatch that occur when coal power plants are decommissioned. Three separate regional systems are modeled: the Electric Reliability Council of Texas (ERCOT), the Midwest Independent System Operator (MISO), and PJM Interconnection (including Pennsylvania, Ohio, New Jersey, and surrounding states). These three systems are the largest restructured systems in the U.S.14 and contain significant coal generating capacity.3 The California Independent System Operator (CAISO) was not included in this study since the coal capacity in this system is relatively small. This analysis makes the assumption that no other changes to the existing power plant fleet other than coal plant retirement occur in the short term. Five different scenarios of coal plant retirement are considered: retiring top CO2 emitters, top NOX emitters, top SO2 emitters, small and inefficient coal plants, and old and inefficient coal plants. Resulting changes in fuel use, life cycle greenhouse gas (GHG) emissions, and emissions of sulfur and nitrogen oxides are estimated.
■
METHODS Base Case Model. Using the approach outlined in Newcomer et al.11,12 and Blumsack et al.,13 simplified economic dispatch models were developed to simulate the order in which power plants are dispatched to meet electricity load. Consistent with these studies, heat rates from eGRID3 and regionally applicable fuel prices were used to estimate short-run marginal costs, which determine the order in which power plants in a given area are dispatched to meet electricity load. The power plants with the lowest short-run marginal costs are dispatched first to meet load, with more expensive plants being dispatched as load increases. Regionally appropriate fuel costs reported by the U.S. Energy Information Administration (EIA)15 in 2011, and marginal prices of electricity production from Newcomer et al.,11 presented in Table S1 in the Supporting Information (SI), were used to estimate short-run marginal costs of the power plants in each area. Some additional considerations, over and above the methods suggested by Newcomer et al.11,12 and Blumsack et al.,13 were made. First, data for planned-committed units scheduled to come online between 2007 and 2011 were obtained from the National Electric Energy Data System16 used by the EPA and added to eGRID data, since the most recent eGRID data provide information about plants existing in 2007 only. Second, planned maintenance and forced outages were modeled by using an availability factor, presented as a percentage of nameplate capacity as reported by EPA’s Integrated Planning Model (IPM).26 For hydroelectric and wind power plants in the model, individual plant capacity factors were used instead of availability factors, since the former better identify the upper bound on electricity generation from these plants. Third, turndown constraints were modeled as a 50% minimumoperating limit for coal steam units and a 25% minimumoperating limit on oil/gas steam units. The turndown constraints ensure that these plants, usually operated to provide baseload power, are not cycled, i.e., turned on and off.26 For PJM, gas units above 800 MW were also constrained to have a 25% minimum-operating limit. Using estimated short-run marginal costs of generation and the constraints as outlined, short-run marginal cost curves (supply curves) are developed for all three regions in the base case and are presented in Figure 1. These supply curves represent the order in which plants are dispatched to meet load. For instance, when the load is 100 GW in PJM, all plants to the left of 100 GW on the supply
Figure 1. Estimated short-run marginal cost curves (supply curves) for ERCOT, MISO, and PJM.
curve are dispatched (hydro, nuclear, wind, coal, and some natural gas, in this example). The 2010 hourly load data for ERCOT, MISO, and PJM17−19 were used to represent future electricity demand in the near-term, when significant changes in demand are not expected. The specific generating units dispatched to meet hourly load were selected based on the supply curves, and electricity generated by each unit in a given year was estimated. 9839
dx.doi.org/10.1021/es3023539 | Environ. Sci. Technol. 2012, 46, 9838−9845
Environmental Science & Technology
Policy Analysis
were chosen such that less than 5% of the total capacity in each area is retired in order to maintain required reserve margins. The criteria were as follows: (1) top CO2 emitters (per MWh) were retired (>85th percentile) in PJM, MISO, and ERCOT; (2) top SO2 emitters (per MWh) were retired (>85th percentile) in PJM, MISO, and ERCOT; (3) top NOX emitters (per MWh) were retired (>85th percentile) in PJM, MISO, and ERCOT; (4) small (
