Projected Impact of Changing Conditions on the Power Sector

Transcription

1 BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector From the Staff of the Bipartisan Policy Center July 2012

2 AUTHORS Jennifer Macedonia, Senior Advisor Colleen Kelly, Policy Analyst DISCLAIMER This report was prepared by the staff of the Bipartisan Policy Center to promote a better understanding of the possible impacts of U.S. Environmental Protection Agency regulation of the electric power sector. The views expressed here do not necessarily reflect those of the Bipartisan Policy Center s Energy Project. ACKNOWLEDGEMENTS The Bipartisan Policy Center would like to express its thanks for the strong support of its funders. In addition, we would like to thank Chris MacCracken and the team at ICF International for their modeling support and guidance on this project. BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 2

3 Electric Power Sector Current Landscape The electric power sector in the United States is facing a changing market environment one that features low natural gas prices, rising coal prices, flattening electric demand, new environmental regulations, expanding renewable power, uncertainty about future carbon risk, and an aging coal fleet. This combination of factors continues to influence the relative competitive positions of all forms of electricity generation, as evidenced by recent shifts in dispatch resulting in a declining share of electricity generation from coal-fired generators, as well as infrastructure decisions including announced coal plant retirements, planned gasfired and renewable capacity additions, and proposed retrofits. To help understand the impacts of these changes, the Bipartisan Policy Center (BPC) has continued its ongoing effort begun several years ago to model and to analyze the power sector with ICF International s Integrated Planning Model (IPM). This document is a followup to the power-sector analysis presented in the June 2011 BPC staff paper, Environmental Regulation and Electric System Reliability, specifically to the modeling results presented in that report s Appendix B: BPC Modeling Using ICF s Integrated Planning Model. This paper details the assumptions including important updates on fuel price trends, electric demand projections, and final air regulations and results from BPC s recent analysis. BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 3

4 Background on IPM Modeling IPM is a multi-region model that endogenously determines capacity- and transmissionexpansion plans; unit dispatch and compliance decisions; and power, coal, and allowance price forecasts all based on power-market fundamentals. To use the model, it is necessary to make a number of assumptions concerning key market parameters, including electricity demand growth, fuel prices, cost and performance of new generating capacity, and cost and performance of pollution controls and other options for complying with environmental regulations. This document details the assumptions and regulatory compliance scenarios included in the BPC analysis. With complex and differing financial, regulatory, and local considerations influencing the investment decisions for specific generators, IPM is not intended to accurately predict each unit level decision, but rather is designed to reflect national trends and to incorporate the key drivers of investment and dispatch decisions. Assumption for Analysis BPC based many of the assumptions for this analysis on information from the Energy Information Administration s Annual Energy Outlook (EIA AEO 2012 Early Release). In some cases, BPC selected alternative assumptions to reflect recent market conditions. Assumptions for electricity demand growth, cost and performance of new capacity, and costs of regulatory compliance options were held constant across the scenarios analyzed. Natural gas and coal prices varied by scenario based on the relative fuel demand from scenario to scenario. The model is designed to include the relevant pollutant emission rates for different fuel and unit types and to choose compliance options to meet the defined emission limits assumed for each scenario based on the assumed cost and performance of available pollutant-control technology options and/or fuel switching, as appropriate. Table 1 below summarizes the sources of key assumptions in the analysis. Table 2 summarizes our detailed assumptions for select parameters. BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 4

5 Table 1: Sources of Key Input Assumptions INPUT PARAMETER Electric Demand Growth Peak Demand Growth Natural Gas Prices Coal Price & Production SOURCE OF ASSUMPTION EIA AEO 2012 Early Release (regional net energy for load) EIA AEO 2012 Early Release and the same premium in peak overload assumption that EPA makes in the December 2011 MATS analysis EIA AEO 2012 Early Release and ICF-derived curves ICF-derived coal supply curves NOTES BPC did not simulate demand response or additional electric demand sensitivities to represent further energy efficiency investment, appliance standards, etc. EPA s peak growth rates are derived from AEO s load growth and the assumed hourly load profiles in each region. BPC used ICF-derived curves, which were created from plotting gas prices and consumption points from AEO 2011 scenarios and calibrating with AEO 2012 Early Release; AEO 2011 data were used for the curve shape and slope, because AEO 2012 Early Release didn t include scenarios to represent the curve. For HCl-compliant coal in the Powder River Basin, BPC adopted EPA s coal supply curves to limit the production of these coal types as a response to policy drivers. Air Pollution Control Costs EPA (FGD, scrubber upgrades, LSD, DSI, SNCR, Fabric Filter, ACI); BPC (SCR) For those plants that burn HCl-compliant coal, the capital costs of backup DSI were imposed without the operating costs. Nuclear Power Licensing / Operation BPC Nuclear units are assumed to receive one 20-year license extension and then retire (at age 60). Production Tax Credit (PTC) Outlook BPC The full value of the PTC is assumed to retire this year, but half of the PTC value is assumed through 2015, before it completely disappears. The half value is intended to reflect some probability that the PTC will be renewed. Abbreviations used: MATS: Mercury and Air Toxics Standards HCl: Hydrogen Chloride; air pollutant FGD: Flue Gas Desulfurization; pollution control technology known as a scrubber LSD: Lime Spray Dryer; pollution control technology known as a dry scrubber DSI: Dry Sorbent Injection, pollution control technology SNCR: Selective Non-Catalytic Reduction; pollution control technology ACI: Activated Carbon Injection; pollution control technology SCR: Selective Catalytic Reduction; pollution control technology BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 5

6 Table 2: BPC Assumptions for the Cost and Performance of Air- Pollution Controls CAPACITY (MW) WET FGD LSD DSI SCR SNCR Capital Costs (2010$/kW) N/A Variable O&M (2010$/kW) Bit Sub. & Lig Energy Penalty % 2.10% 1.33% 0.02% 0.50% 0.05% Removal SO 2 95% SO 2 92% SO 2 70% NO X 85% NO X 30% First Year Allowed Source EPA EPA EPA BPC EPA CAPACITY (MW) FABRIC FILTER ACI FGD UPGRADE ESP UPGRADE Capital Costs (2010$/kW) Variable O&M (2010$/kW) 0.15 Bit. H 3.65; Bit. L 2.72; Lig ; Sub Bit. H 0.41; Bit. L 0.27; Lig. 0.50; Sub Energy Penalty % 0% 0% 0% 0% Removal Hg 90% Hg 90% SO 2 90% Hg 99% PM Compliance First Year Allowed Source EPA EPA EPA EPA Abbreviations used (see also: list under Table 1): MW: Megawatt kw: Kilowatt O&M: operation and maintenance Bit: bituminous coal Sub: sub-bituminous coal Lig: lignite coal SO 2 : sulfur dioxide NO X : nitrogen oxides Hg: mercury BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 6

7 Description of Scenarios For this analysis, BPC defined two scenarios a Base and a Policy to examine the impacts of the Environmental Protection Agency s (EPA) proposed regulations on the U.S. power sector. BPC had ICF analyze these cases using IPM based on the assumptions described above. The cases are described below in more detail. BPC conducted similar modeling analysis in spring 2011; two of the cases for the 2011 scenarios are also detailed briefly below as they are included for comparison in some of the results figures. Table 3: Overview of Modeling Scenarios MODELING SCENARIO Base Policy Former BAU Former Policy DESCRIPTION All existing regulations as of summer 2011 without CSAPR and MATS All existing regulations as of summer 2011 with CSAPR and MATS All existing regulations as of winter 2011 with CAIR and without MATS and CSAPR All existing regulations as of winter 2011 with proposed rules MATS, Transport Rule, cooling water intake rule, and coal ash regulation BPC BASE CASE The BPC Base represents a business-as-usual (BAU) projection in the absence of two recently finalized EPA air regulations: the Mercury and Air Toxics Standards (MATS) for power plants and the Cross-State Air Pollution Rule (CSAPR). This Base incorporates other existing finalized federal and state regulations as of summer 2011, including state mercury, SO 2, and NO X requirements, as well as state renewable portfolio standards. It assumes regional cap-and-trade programs for SO 2 and NO X in the eastern United States, as stated under Phases I and II of the Clean Air Interstate Rule (CAIR). Pollution control and retirement decisions reflected in completed New Source Review consent decrees, settlement agreements, and firm 1 public retirement announcements as of fall 2011 are also included in the BPC Base. BPC POLICY CASE This case builds on the BPC Base and adds the recently finalized EPA air rules MATS and CSAPR. This BPC Policy does not include proposed regulations for cooling water and coal ash, the proposed New Source Performance Standard for greenhouse gases, or more stringent requirements for SO 2 and NO X beyond CSAPR that might be required in the future to meet National Ambient Air Quality Standards and/or future Regional Haze BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 7

8 requirements. BPC incorporated the following assumptions regarding the final air regulations: Mercury and Air Toxics Standards (MATS): IPM models emissions from various fuels and unit types and allows the model to choose the most economic compliance strategy based on the cost and performance assumptions of pollution retrofits and fuel changes available for specific unit types to comply with emission limits under the MATS rule. As mentioned above, this case primarily relies on EPA assumptions from the MATS final rulemaking for control-equipment costs and performance. For compliance timing, this Policy assumes that when chosen as a viable and economic compliance option, installations of ACI, DSI, as well as ESP upgrades will be completed by January To simulate use of the one-year MATS compliance-deadline waiver authorized by permitting authorities, BPC assumed that all wet and dry scrubber and baghouse/fabric filter installations required for compliance would be completed by January In addition, units that were economically projected to retire rather than incur compliance costs were assumed to get a one-year compliance waiver that would allow operation without MATS compliance through the end of 2015 for units that retire by January To simulate potential reliability constraints, retirements were limited to 15 gigawatts (GW) in 2014 and then determined on an economic basis thereafter. This BPC Policy assumes a limited supply of sub-bituminous coal with low chlorine content that allows compliance with the MATS HCl limit without any additional pollution controls. For units burning this HCl-compliant coal, we assigned a capital cost for the installation of backup DSI, but did not include an operating/sorbent cost for DSI. Cross-State Air Pollution Rule (CSAPR): This BPC Policy, developed without knowledge of the court s final decision, assumes that the court s stay on the regulation delays Phase I CSAPR compliance until 2013 and that Phase II and the assurance provisions begin in In this exercise, interstate trading is limited to regional markets (i.e., Group 1 vs. Group 2 SO 2 ; annual vs. ozone season NO X ). Before 2013, the Policy includes the same CAIR assumptions as the Base. BPC FORMER BAU AND POLICY CASES The BPC Former BAU was presented in the June 2011 BPC staff paper Environmental Regulation and Electric System Reliability and represents our business-as-usual (BAU) projection as of spring This case includes existing federal and state regulations as of January 2011, including state mercury, SO 2, and NO X requirements, as well as renewable portfolio standards. The case assumes regional cap-and-trade programs for SO 2 and NO X in the eastern United States, as stated under CAIR Phases I and II. The case does not include any federal mercury-reduction or carbon dioxide requirements for the power sector. The BPC Former Policy was also presented in the June 2011 staff paper and includes BPC assumptions as of spring 2011 for the requirements under EPA s then-proposed suite of new regulations, including the proposed MATS, proposed transport rule (which was BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 8

9 subsequently finalized as CSAPR), the proposed cooling water intake rule 316 (b), and an assumed non-hazardous coal ash regulation. Select Results of BPC Analysis The following charts present select results for the BPC cases described in the previous section and, in some cases, also include the 2011 BPC scenarios for comparison. Unless otherwise specified, the results are presented for the continental United States and do not include Hawaii and Alaska. Figure 1: Projected Fate of Current Fleet by Retiring coal (56 GW = 5% of total fleet) Remaining Coal Other (168 GW) Remaining Coal (264 GW) Natural Gas/Oil Retired in Base Remaining Natural Gas/Oil Nuclear (105 GW) Nuclear Remaining Natural Gas/Oil (427 GW) Other (Renewables, Hydro) Coal Retired in Base (40 GW) Coal Retired by Air Rules (16 GW) Natural Gas/Oil Retired in Base (30 GW) Figure 1 reflects the projected status of the current fleet of U.S. electric-generating units as of the year 2016 under BPC s Policy with MATS and CSAPR. (New capacity additions are not included in Figure 1.) A total of 56 GW of coal-fired generating capacity is expected to retire by 2016, with 40 GW retiring under BAU market conditions and an additional 16 GW retiring as a result of MATS and CSAPR compliance requirements. For the Base, the key drivers of coal plant retirements include flattening electric demand, low natural gas prices, and higher coal prices. These model inputs have experienced significant changes since the last round of BPC analysis in BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 9

10 $ / MMBTU Billion kwh Figure 2: Electric Demand Annual Forecasts AEO 2012 AEO 2011 AEO 2010 AEO 2009 AEO 2008 AEO 2007 A key input that has changed since BPC s 2011 analysis is the forecast for electric demand. As seen in Figure 2, electric demand projections from EIA AEO 2012 reflect a flattening of demand growth. The AEO 2012 demand forecast is lower than in recent years, which has a significant impact on power-sector projections. Even though there are some regions of the country expecting growth in electricity demand, the national trend reflects a slowing of the historical growth rate for electricity demand due to a slow economic recovery in the short term, as well as deployment of energy efficiency measures throughout the economy. The absence of growing demand for electricity, combined with the excess capacity in the existing fleet, is expected to depress the need for new generating capacity, even as significant amounts of existing generation retire. Figure 3: Projected Natural Gas Prices at Henry Hub 4, Base Policy Former BAU Former Policy BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 10

11 $ / MMBTU Another key assumption that was updated since the 2011 analysis is the reference case of natural gas prices, which we based on recently derived gas supply curves that were calibrated with natural gas price projections in AEO 2012 Early Release. Figure 3 shows projected natural gas prices at Henry Hub used for the current analysis compared with results from the previous 2011 BPC analysis. In the current BPC Base, the natural gas price is assumed to be near $4/mmBtu in 2013 and to climb over time to around $6.25/mmBtu in As a result of the model simulating the impacts of increased demand for natural gas under the BPC Policy, natural gas prices rise above the Base prices from 2013 and beyond, but nonetheless remain below the Former BAU case natural gas price. In 2030, the Policy natural gas price is projected to be around $6.25/mmBtu, compared with around $8.00/mmBtu projected in the 2011 BPC analysis. Figure 4: National Minemouth Coal Prices Base Policy Former BAU Former Policy While natural gas price projections have decreased recently, the coal price projections have increased over the last few years. This BPC analysis incorporates updated coal price projections (blue line in Figure 4). Figure 4 compares current coal price projections with the assumptions from last year s BPC analysis (in dashed lines). Throughout the entire period, the BPC Base and Policy coal prices were higher than the former BPC BAU and Policy s. The spike in the 2016 national average coal price in the BPC Policy is due to the projected premium for low-chlorine-content sub-bituminous western coal (HCl-compliant coal); this premium is projected based on the assumption, consistent with EPA s analysis supporting the MATS Final Rule, that such HCl-compliant coal allows compliance with the MATS HCl limit without additional pollution controls. BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 11

12 Gigawatts Gigawatts Figure 5: Cumulative Coal Retirements Current projection: 16 GW retires due to air rules Last year's BPC projection: policy retires GW 0.00 Base Policy Former BAU Former Policy In comparison with the 2011 BPC modeling scenarios, the Base coal retirements have more than doubled (from 14 GW in the previous analysis to 40 GW today), while the incremental retirements from the EPA rules is roughly the same (15 18 GW in the previous case and 16 GW today). (See Figure 5.) Figure 6: Cumulative Projected Capacity Additions Base Policy Base Policy Base Policy Base Policy Other NG/Oil Nuclear Biomass Figure 6 shows cumulative U.S. capacity additions by type in both the BPC Base and Policy s. In both cases, the build mix is dominated by renewable capacity (i.e., wind, biomass, and other renewables) in the short term, as states work to meet Renewable Portfolio Standards. Natural gas fired plants are not built in substantial numbers until 2025, largely BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 12

13 Thousand GWh Thousand GWh because of the surplus of gas-fired capacity that was built out in the 1990s. Visibly absent is new coal capacity; through 2030, no new coal generation is projected to be built in either case except for the units that began construction prior to this analysis, which are not included in this chart. Although the Policy does not include the EPA s proposed New Source Performance Standard for greenhouse gases which would essentially require any new coal capacity to include carbon capture and sequestration these results would not be impacted by such a requirement, because of the lack of new coal builds. Figure 7: Generation Mix for Base and Policy s Base 6000 Policy Coal Natural Gas/Oil Nuclear Hydro Renewables Other Coal generation has seen a decline in recent years that is expected to continue. However, even with the movement toward natural gas and renewables and a projected retirement of 56 GW of coal capacity in the coming years, coal is projected to remain the largest generation source in both the Base and Policy through 2035 (as shown in Figure 7). In fact, the differences in generation fuel mix between the two cases are somewhat modest. Generation from coal in the Policy is 3 percent lower in 2020 and 6 percent lower in 2030 relative to the Base, as compliance costs further impact the competitive position of coal generators. Increased gas-fired generation makes up for the majority of that decline. In the BPC Policy, generation from gas is 5 percent higher in 2020 and 9 percent higher in 2030, compared with the BPC Base. Potential future environmental requirements that are not included in this Policy, such as stricter NO X and/or particulate limits, GHG limits for existing sources, coal ash handling, and cooling water requirements have the potential to further influence the future generation mix. BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 13

14 2012 Generation (GWh) Coal Capacity (GW) % Difference (Base Year = 2012) Figure 8: Coal Capacity and Percent Difference in Coal Generation % % 10% 5% 0% -5% 0-10% Coal Capacity Coal Generation % Diff Figure 9: 2012 Generation from Retiring and Non-Retiring Coalfired Units 2,000,000 1,500,000 1,000, ,000 - Base Policy Operate Post-2016 Retire by 2016 Figure 8 highlights the changes in coal-fired generating capacity (i.e., nameplate capacity of all remaining coal-fired electric generating units), as well as the amount of electricity projected to be generated from coal-fired facilities. As coal-fired generators retire, coalgenerating capacity falls through 2016 and then remains constant. In response to the competitive advantage of gas-fired generation in the short term, the percent change in coal generation follows a similar downward trajectory through However, by 2020, the amount of electricity generated from coal-fired facilities is projected to increase above current levels and continue to grow well beyond today s historically low level to reach levels around BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 14

15 Million Tons Million Tons Million Metric Tons Tons Figure 9 offers an explanation for these trends, which on the surface may seem to be contradictory. The coal plants that are retiring contribute only a small percentage (see the red portion in Figure 9) to the total amount of electricity produced from coal-fired generators in As shown in Figure 10, the units projected to retire tend to be older, smaller, and less efficient on average than the rest of the fleet and tend to operate much less frequently than baseload coal capacity: 74 percent of the projected retiring coal is at least 40 years old, 50 percent are 200-megawatt capacity or less, and 55 percent have heat rates of at least 11,000 mmbtu. (Higher heat rates indicate lower efficiency.) More details about the age, size, and heat rate of units in the fleet can be found in the appendix. Figure 10: Demographics of Coal Units Projected to Retire by % 34% 5% Size of Retiring Coal % % % Less than 50 Heat Rate of Retiring Coal 3% 5% 14, % 13,000-14,000 11% 12,000-13,000 11,000-12,000 32% 36% 10,000-11,000 Less than 10,000 Age of Retiring Coal 10% 8% 16% 26% 40% Less than 30 Retiring plants tend to be older, smaller, and less efficient: 74% are at least 40 years old 50% are 200 MW capacity or less 55% are at least 11,000 mmbtu heat rate Figure 11: Nationwide Emissions of Various Pollutants in Sulfur Dioxide 2.0 Nitrogen Oxides 2500 Carbon Dioxide 30 Mercury Base Policy 0.0 Base Policy 0 Base Policy 0 Base Policy BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 15

16 Table 4: 1995 vs Emissions by Pollutant 8,9 POLLUTANT UNITS 1995 LEVELS 2016 BASE CASE LEVELS 2016 POLICY CASE LEVELS SO 2 Million Tons NO x Million Tons CO 2 Million Metric Tons Mercury Tons In addition to impacting the generation fuel mix, the impact of the Policy is seen in the estimates of nationwide emission levels in Figure 11. The largest differences from CSAPR and MATS are seen in the levels of SO 2 and mercury; the Base levels are more than two times the Policy levels for SO 2 in 2016 and more than four times for mercury. Looking at Table 4, substantial progress has also been made in reducing NO X from earlier levels. Moving forward, there is potential for further reductions both within and outside the power sector. Figure 12: Compliance with SO 2 and HCl Requirements (CSAPR and MATS) 11 for Non-Retiring Units Add DSI Add dry scrubber Add wet scrubber Compliant coal Existing Scrubbers Of the pollution controls expected for compliance with the various limits in CSAPR and MATS, a wet scrubber (flue gas desulfurization) is the most expensive technology. Contrary to the final EPA regulations and available control-technology options, some previous analyses have assumed that all plants will require wet scrubbers to comply with these regulations, which has inflated the projected costs and resulting coal plant retirements in their assessments. 12 Instead, BPC analysis allows the model to choose the most economic compliance strategy from the cost and performance data specified in the final rulemakings, which include additional lower-cost technologies and fuel-switching options. BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 16

17 Figure 12 shows that almost 70 percent of the coal capacity projected to remain in operation through 2016 already has scrubbers in place, although some require upgrades. To comply with the SO 2 requirements of CSAPR and the HCl limit in MATS, 13 percent of the coal capacity forecasted to remain in operation is projected to add control technology (6 percent to add DSI, 4 percent to add a dry scrubber, and 3 percent to add a wet scrubber). In addition, almost 20 percent (49 GW) of the remaining coal-fired fleet is projected to comply by burning compliant coal 13 (primarily Powder River Basin/western sub-bituminous coal with low enough chlorine and sulfur contents to meet the HCl and SO 2 emission requirements without add-on controls). The units projected to burn such compliant coal are units that have previously burned sub-bituminous coal, either in total or as part of a blend (see Figure 18 in the Appendix). Because these units are not projected to install a scrubber or operate DSI, their compliance costs are substantially less than most analyses assume and many are projected to avoid retirement and remain competitive. Figure 13: Regional Pollution Control Status by 2016 Figure 13 shows the projected status and pollution control complement of the remaining coal fleet in 2016, broken out by areas of the country. The local conditions, environmental requirements, and extent of pollution controls vary by state and region. Most of the units in the West and Northwest are well controlled for SO 2 /acid gases with a scrubber or DSI but lack post-combustion NO X controls. The amount of post-combustion NO X control (i.e., SCR and SNCR) increases as you move east across the country, reflecting the fact that many of these eastern areas have a regional ozone problem that has led to control requirements. The central region has the largest percentage of capacity without advanced post-combustion controls and is where much of the lower-emitting (for SO 2 and HCl) compliant western coal is burned. BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 17

18 Heat Rate (Btu/KWh) Size (MW) Appendix: Additional Figures Figure 14: Coal Retirements by Age and Size 1,400 1,200 1,000 Coal Retirements by Age and Size Operates Post-2016 Retires in Policy Retires in Reference Age in 2016 (Years) Figure 15: Coal Retirements by Age and Heat Rate Coal Retirements by Age and Heat Rate 16,000 15,000 14,000 13,000 12,000 11,000 10,000 9,000 8,000 7,000 6,000 Operates Post-2016 Retires in Policy Retires in Reference Age in 2016 (Years) BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 18

19 Figure 16: Status of SO 2 and NO X Pollution Controls after Implementation of CSAPR and MATS 14 SO2 Controls in 2012 SO 2 Controls by 2016: Policy Wet Scrubbers 20% Wet Scrubbers Dry Scrubbers 44% 0% 56% Dry Scrubbers 6% No add-on SO2 4% Controls 70% DSI No add-on SO2 Controls NOx Controls in 2012 SCR NO x Controls by 2016: Policy SCR 17% 4% SNCR 19% 4% SNCR 78% No postcombustion NOx Controls 77% No postcombustion NOx Controls Figure 17: Regional Breakout of Projected Coal Plant Retirements (GW) BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 19

20 Gigawatts Figure 18: Impact of Policy on Coal Switching: Coal Consumption by GW Lignite Blended HCl Compliant Sub-Bit Sub-Bit Bituminous BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 20

21 Endnotes 1 For this analysis, firm planned retirements are defined as units that were (1) subject to agreement with EPA, (2) tied to construction of new capacity that is underway, and (3) already in the process of closing as of fall Firm coal retirements using that criterion totaled roughly 14 GW over the period 2011 to The firm units did not include more recent announcements made specifically in response to MATS, low natural gas prices, and electric demand which may coincide with IPM projected economic retirements. 2 New capacity additions not included. 3 Energy Information Administration. Annual Energy Outlook. Available at: 4 The 2011 BAU and Policy s are in 2006 dollars, while the 2012 BAU and Policy s are in 2010 dollars. 5 IPM does not model every year that is illustrated in the figures; the model includes , 2020, 2025, 2030, and Data for the other years in the charts throughout the paper was extrapolated. 6 This chart does not include firm builds. Firm builds are units that are currently under construction or units that are sufficiently far along in the permitting and financing processes. 7 The percentages are computed as percent of megawatts. 8 Energy Information Administration. U.S. Carbon Dioxide Emissions from Electric Power Sector Energy Consumption, Environmental Protection Agency. National Emissions Inventory Air Pollutant Emissions Trends Data levels listed in lieu of 1995 figure. Environmental Protection Agency. Mercury and Air Toxics Standards (MATS): Cleaner Power Plants. Available at: 11 Analysis based on BPC Spring 2012 Policy ; Particulate control upgrades/retrofits may also be required. 12 For example, in their May 2012 analyses, the Electric Power Research Institute assumed scrubber installations in its Reference (Environmental Controls) Scenario, and North American Electric Reliability Corporation assumed wet scrubbers for all units in its analyses. 13 This is projected to result in a premium for such compliant coal, which is reflected as a spike in the national mine-mouth coal price in Figure SO2 controls charts include just coal plants; NO x controls charts include both coal and natural gas plants. The percentages are computed as percent of megawatts. BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector 21