Preface

1 In the 107th Congress this subcommittee has been renamed the Subcommittee on Energy Policy, Natural Resources and Regulatory Affairs.

2 Energy Information Administration, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, SR/OIAF/2005 (Washington, DC, December 2000).

Highlights

1 In the 107th Congress this Subcommittee has been renamed the Subcommittee on Energy Policy, Natural Resources and Regulatory Affairs.

2 All the results presented in this report are based on the assumption that electric power generators must meet the specified emissions caps fully, without trading with other domestic sectors or internationally and without credits for offsets, such as reductions in other greenhouse gas emissions or changes in forestry practices. Allowing trading with other sectors and offset credits could produce different results.

3 At the request of the Subcommittee, it was assumed that no new nuclear units would be constructed.

4 See J.A. Beamon, T. Leckey, and L. Martin, “Power Plant Emission Reductions Using a Generation Performance Standard,” web site www.eia.gov/oiaf/servicerpt/gps/gpsstudy.html.

Executive Summary

1 In the 107th Congress this subcommittee has been renamed the Subcommittee on Energy Policy, Natural Resources and Regulatory Affairs.

2 A renewable portfolio standard (RPS) requires that qualifying renewable facilities generate a specified share of power sold. Qualifying renewable generators are issued credits for each kilowatthour they generate, which they can keep for their own use or sell to others who need them to meet the RPS requirement.

3 Energy Information Administration, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Nitrogen Oxides, Sulfur Dioxide, and Carbon Dioxide, SR/OIAF/2000-05 (Washington, DC, December 2000).

4 The reader should be aware that numerous policy instruments—e.g., taxes, Maximum Achivable Control technology (MACT), no-cost allowance allocation with cap and trade, allowance auction with cap and trade, Generation Performance Standard (GPS) allowance allocation with cap and trade—are available. Each of the options  would have different price and cost impacts.

5 One case prepared for this analysis assumed that emissions allowances would be treated as having zero value in regions where electricity prices continue to be based on cost of service rather than competitive pricing.

6 The ACI recycling technology is meant to be representative of several Hg removal technologies that are now in various stages of development. It is impossible to predict at this time which technology might prove to be the most economical.

7 Although coal-fired plants usually do not set market clearing prices, they do set them in some regions during periods of relatively low demand.

8 In the early years of the forecast, electricity prices are projected to be higher in the case that combines an RPS with caps on NO_x, SO₂, CO₂,and Hg emissions than in the case that includes only the four emission caps.

9 Retail electricity prices are assumed to be determined competitively in regions where most of the States have passed legislation or issued regulatory orders to deregulate their electricity sectors. In other regions, retail electricity prices are assumed to continue to be based on cost of service pricing.

Introduction

1 Because power companies accumulated (banked) emissions allowances during Phase I of the program (1995 to 1999), the Phase II cap of 8.95 million tons per year will not become binding until the banked allowances have been exhausted.

2 For more information on these bills see Energy Information Administration, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, SR/OIAF/2000-05 (Washington, DC, December 2000), pp. 1 and 2 .

3President George W. Bush, National Energy Policy: Report of the National Energy Policy Development Group (Washington, DC, May 2001).

4 In the 107th Congress this subcommittee has been renamed the Subcommittee on Energy Policy, Natural Resources and Regulatory Affairs.

5 Energy Information Administration, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, SR/OIAF/2000-05 (Washington, DC, December 2000). See also J.A. Beamon, T. Leckey, and L. Martin, “Power Plant Emission Reductions Using a Generation Performance Standard,” web site www.eia.gov/oiaf/servicerpt/gps/gpsstudy.html.

6 For a discussion of one possible alternative policy instrument, see the box on “Generation Performance Standards” on page 14 of the earlier EIA report. See also J.A. Beamon, T. Leckey, and L. Martin, “Power Plant Emission Reductions Using a Generation Performance Standard,” web site www.eia.gov/oiaf/servicerpt/gps/gpsstudy.html.

7 Energy Information Administration, Analysis of the Impacts of an Early Start for Compliance with the Kyoto Protocol, SR/OIAF/99-02 (Washington, DC, July 1999).

Analysis Cases and Methodology

8 Energy Information Administration, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, SR/OIAF/2000-05 (Washington, DC, December 2000) (referred to here as “the earlier EIA report”).

9 Energy Information Administration, Annual Energy Outlook 2001, DOE/EIA-0383(2001) (Washington, DC, December 2000).

10 See chapter 5 of the earlier EIA report for discussion of New Source Review isues.

11 Federal Register, Vol, 65, No. 245 (December 20, 2000), pp. 79825-79831.

12 See page 12 of the earlier EIA report.

13 See page 14 of the earlier EIA report. See also J.A. Beamon, T. Leckey, and L. Martin, “Power Plant Emission Reductions Using a Generation Performance Standard,” web site www.eia.gov/oiaf/servicerpt/gps/pdf/gpsstudy.pdf; and D. Burtraw, K. Palmer, R. Bharvirkar, and A. Paul, The Effect of Allowance Allocation on the Cost and Efficiency of Carbon Emission Trading (Washington, DC: Resources for the Future, April 2001).

14 For more information, see web site www.eia.gov/bookshelf/docs.html, which provides documentation of the NEMS submodules.

15 See Appendix A, letter from Subcommittee staff dated August 17, 2000.

16 The EMM dispatches over 108 time periods: 6 seasons, 3 types of day, 3 time periods per day, and 2 blocks per time period.

17 The NETL model parameters were used to calculate the amount of activated carbon injection required to achieve a target Hg removal level. Those target levels for each plant configuration serve as Hg removal supply steps in the capacity planning module of the EMM. The costs for constructing and operating a carbon injection and disposal system and (when called for) a spray cooling and fabric filter system were estimated assuming a 500-megawatt plant with a heat rate of 10,000 Btu per kilowatthour using 12,000 Btu per pound coal.

18 These parameters differ by coal rank and plant configuration.

19 Dyncorp Corporation, Contract DE-AC01-95-ADF34277, deliverable DEL-99-548 (Alexandria, VA, July 1997).

Electricity Market Impacts

20 This analysis employs a no-cost cap and trade system for emissions allowances for all required emission reductions. For a discussion of the impacts of alternative policy instruments see J.A. Beamon, T. Leckey, and L. Martin, “Power Plant Emission Reductions Using a Generation Performance Standard,” web site www.eia.gov/oiaf/servicerpt/gps/pdf/gpsstudy.pdf (April 2001); and D. Burtraw, K. Palmer, R. Bharvirkar, and A. Paul, The Effect of Allowance Allocation on the Cost and Efficiency of Carbon Emission Trading (Washington, DC: Resources for the Future, April 2001).

21 Sensitivity cases with less stringent NOx and SO2 caps were prepared in the earlier EIA report. See Energy Information Administration, Analysis of Strategies for Reducing Multiple Emissions from Power plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, SR/OIAF/2000-05 (Washington, DC, December 2000).

22 For similar NOx allowance price results with an annual versus a seasonal NOx emission cap, see K. Palmer, D. Burtraw, R. Bhanvitkar, and A. Paul, “Restructuring and Cost of Reducing NOx Emissions in Electricity Generation,” Resources for the Future Discussion Paper 01-10 (Washington, DC, March 2001); and D. Burtraw, K. Palmer, R. Bharvirkar, and A. Paul, “Cost-Effective Reduction of NOx Emissions from Electricity Generation,” Resources for the Future Discussion Paper 00-55 (Washington, DC, December 2000).

23 The earlier EIA report included cases with a 2005 target date. The earlier date increases the potential for short-term reliability and pricing problems.

24 North American Electric Reliability Council, Reliability Impacts of the EPA NOx SIP Call (Washington, DC, February 2000); U.S. Environmental Protection Agency, Feasibility of Installing NOx Control Technologies by May 2003 (Washington, DC, September 1998); and Utility Air Regulatory Group, The Impact of EPA’s Regional SIP Call on Reliability of the Electric Power Supply in the Eastern United States (Washington, DC, September 1998).

25 This discussion only includes the cost of the activated carbon. Some capital investment and operations and maintenance costs will also be required but they are very small when compared with the cost of the activated carbon.

26 Throughout this report carbon dioxide (CO2) emissions are reported in terms of metric tons carbon equivalent. In other words, they are reported in carbon units, defined as the weight of the carbon content of carbon dioxide (i.e., the “C” in CO2). To convert to metric tons of carbon dioxide multiply by 44/12 or 3.6667. For more discussion of this issue, see Energy Information Administration, Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99) (Washington, DC, October 2000).

27 Resource costs include total fuel costs, operations and maintenance costs, and investment costs. They do not include allowance costs.

28 Under an RPS, each seller of electricity is required to hold “credits” equivalent to the required percentage of sales from renewables. The credits, each representing 1 kilowatthour of generation from renewable fuels, can be sold by renewable generators to nonrenewable generators.

29 In the early years of the forecast, electricity prices are projected to be higher in the case that combines an RPS with caps on NOx, SO2, CO2, and Hg emissions than in the case that includes only the four emission caps.

Fuel Market and Macroeconomic Impacts

30 Coal Age (October 2000).

31 Energy Information Administration, Coal Data: A Reference, DOE/EIA-0064(93) (Washington, DC, February 1995), p. 25.

32 U.S. Environmental Protection Agency, Mercury Study Report to Congress, Volume 2: An Inventory of Anthropogenic Mercury Emissions in the United States (Washington, DC, December 1997).

33 The changes in the projected rate of technological advancement made in the integrated high gas price case are the same changes that were made in the slow technology case in the AEO2001.

34 For a discussion of the challenges faced in meeting the production required in a CO₂ emission reduction case, see the earlier EIA report, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, SR/OIAF-2000-05 (Washington, DC, December 2000).

35 For discussion of the renewable energy sources included, see pages 46-48 of the earlier EIA report.

36 Small additions of new solar thermal capacity (107 megawatts) and central-station photovoltaic generating capacity (500 megawatts) are also assumed from 2000 to 2020. It is assumed that experience gained from solar and wind technology applications in foreign countries will contribute to reducing domestic capital costs through a learning effect. Based on a review of international renewable energy developments, it is assumed that 5 megawatts of photovoltaic capacity additions and 50 megawatts of wind capacity additions will contribute to the international learning effect in  each year from 2000 through 2020. Other revisions from the earlier analysis include updated historical data and updated baseline projections for other renewable energy technologies.

37 In an offline analysis using the assumptions of the RPS 20% case, EIA found that additional biomass co-firing beyond the 5-percent limit (up to 10 percent) could be economical as a fuel substitute for coal, assuming retrofit costs of $200 per kilowatt. Using the projected prices of coal, biomass, and renewable credits in 2015, approximately 100 billion kilowatthours of additional co-firing could be expected in 2015 beyond the level projected in the RPS 20% case. Because the RPS establishes a given level of renewable generation, however, the additional biomass co-firing would displace generation from other renewables rather than adding to the total.

38 Because wind units generate electricity only when winds are sufficient, expected generation from a wind unit is less than for a comparably sized unit of biomass capacity.

39 Y.H. Wan and B.K. Parsons, Factors Relevant to Utility Integration of Intermittent Renewable Technologies, NREL/TP-463-4953 (Golden, CO: National Renewable Energy Laboratory, August 1993).

40 It is assumed in this analysis that biomass could be co-fired in coal plants up to 5 percent of total capacity. Co-firing above that level would require additional expenditures, whose costs are too uncertain to model at this time.

41 For analysis of employment impacts in NO_x and SO₂ cap cases, see the results published in the earlier EIA report, pages 50-52.

42 U.S. Department of Labor, Bureau of Labor Statistics, ES-202 Program, “Covered Employment and Wages.”

43 See the earlier EIA report, pages 38 and 39, for a discussion of impacts on the rail industry.

44 For further discussion of recycling issues for an economy in transition, see Energy Information Administration, Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic Activity, SR/OIAF/98-03 (Washington, DC, October 1998), Chapter 6, “Assessment of Economic Impacts.”

45 For a discussion of the relative merits of alternative policy instruments, see R. Perman, Y. Ma, and J. McGilvray, “Pollution Control Policy,” in Natural Resource and Environmental Economics (Addison Wesley Longman, 1996).

46 L.H. Goulder, I.W.H. Parry, and D. Burtraw, “Revenue-Raising Versus Other Approaches to Environmental Protection: The Critical Significance of Pre-existing Tax Distortions,” RAND Journal of Economics, Vol. 28. No. 4 (Winter 1997), pp. 708-731.

Comparisons with Other Studies

47 Energy Information Administration, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, SR/OIAF/2000-05 (Washington, DC, December 2000), Chapter 6.

48 Alliance to Save Energy, American Council for an Energy-Efficient Economy, Natural Resources Defense Council, Tellus Institute, and Union of Concerned Scientists, Energy Innovations 1997: A Prosperous Path to a Clean Environment (Washington, DC, June 1997).

49 S. Bernow et al., America’s Global Warming Solutions (Washington, DC: World Wildlife Fund and Energy Foundation, August 1999). This study focused on CO₂ reductions. In an offline analysis, a Systems Benefits Charge of 2 mills per kilowatthour induced a 10-percent share of generation from new renewable sources. Those generators were then modeled as planned capacity, and a 10-percent RPS was achieved.

50 Interlaboratory Working Group. 2000. Scenarios for a Clean Energy Future, ORNL/CON-476 and LBNL-44029 (Oak Ridge, TN: Oak Ridge National Laboratory, and Berkeley, CA: Lawrence Berkeley National Laboratory, November 2000). This study modeled an RPS through an extension of the 1.5 cents per kilowatthour production tax credit (PTC) for wind and dedicated biomass installed by 2004 and a 1.0 cent per kilowatthour PTC for biomass co-firing in 2000-2004. The study’s Advanced Scenario included an RPS, represented as an additional 1.5 cents per kilowatthour PTC for 2005-2008, with carbon reduction scenarios. The analysis covered all end-use sectors.

51 Energy Information Administration, Annual Energy Outlook 2000, DOE/EIA-0383(2000) (Washington, DC, December 1999), p. 18.

52 S. Clemmer, A. Nogee, and M. Brower, A Powerful Opportunity: Making Renewable Electricity the Standard (Cambridge, MA: Union of Concerned Scientists, January 1999). See also S. Clemmer, D. Donovan, and A. Nogee, Clean Energy Blueprint: A Smarter National Energy Policy for Today and the Future, Phase I (Cambridge, MA: Union of Concerned Scientists, June 2001), web site www.ucsusa.org. The Clean Energy Blueprint analysis focuses on policies designed to improve energy efficiency and to develop renewable resources, including a 20-percent RPS by 2020. Projected savings on consumers’ energy bills begin to outstrip the costs of the program in 2010, and net benefits over the period 2002-2020 total $31 billion (1999 dollars). Phase II, forthcoming in summer 2001, will address emission reduction strategies and improvements in power plant efficiency.

53 S. Bernow, W. Dougherty, and M. Duckworth, “Quantifying the Impacts of a National, Tradable Renewables Portfolio Standard,” The Electricity Journal (May 1997).

54 U.S. Environmental Protection Agency, Office of Air and Radiation, Analysis of Emissions Reductions Options for the Electric Power Industry (Washington, DC, March 1999), web site www.epa.gov/capi/multipol/mercury.htm.

55 The EPA is currently working on a comprehensive update of this modeling effort.

56 The EPA analysis did provide for slight increases in price at higher consumption levels, but the model results never reached those levels.

57 Energy Information Administration, Commercial Sector Demand Module of the National Energy Modeling System, DOE/EIA-MO66(2001) (Washington, DC, January 2001); Energy Information Administration, Residential Sector Demand Module of the National Energy Modeling System, DOE/EIA-MO67(2001) (Washington, DC, January 2001); see also E. Boedecker, J. Cymbalsky, and S. Wade, “Modeling Distributed Electricity Generation in the NEMS Buildings Models,” (Washington, DC, September 2000), http://www.eia.gov/oiaf/analysispaper/electricity_generation.html.

58 In the present EIA analysis, only one region (Rocky Mountain-AZ) is projected to reach the maximum.

59 Energy Information Administration, Annual Energy Review 2000, DOE/EIA-0384(00) (Washington, DC, July 2001), Table 6.8.

60 In the UCS analysis, the RPS was 5.5 percent, reflecting the original RPS goal of the Clinton Administration.

61 For example, in 2020 RenewMarket projects a price decline of $0.015 per million Btu for each quadrillion Btu reduction in cumulative consumption. Prior to 2005, changes in gas consumption are assumed to have no effect on price in the UCS analysis.

62 The UCS analysis used the 1998 AEO reference case, which projected a decline of 1.1 cents per kilowatthour in average U.S. electricity prices between 1998 and 2020.

63 Net cost was defined as increased expenditures on electricity minus savings from lower natural gas prices.

64 Bernow reports 48 billion kilowatthours of natural-gas-fired generation displaced and 4 billion kilowatthours of coal-fired generation displaced.

65 The UCS methodology for calculating the credit price allowed renewable generators to see higher RPS targets in the future, so that while the target is increasing (as under the Jeffords proposal), more costs could potentially be recovered in the future, which tended to reduce the credit price in the near term. As the target is approached and/or met later in the forecast, the credit price and the shadow price tend to converge.

66 EPA’s Clean Air Power Initiative (CAPI), which began in 1995, was intended to improve air pollution control efforts by involving the power generating industry in the development and analysis of alternative approaches to reducing three major emissions: SO₂, NO_x, and, potentially, Hg. The analysis used the Integrated Planning Model (IPM), a detailed model of the electric power industry in which plant operators react to alternative levels of pollution targets. CAPI proposed a “cap and trade” approach for the emissions and modeled the proposed reductions on a national scale. Initial NO_x caps were set for both summer and winter beginning in 2000, and the initial rate-based caps were then reduced to a fairly stringent absolute cap of 0.15 pounds per million Btu in 2005. At the same time, SO₂ was reduced in 2010 by lowering the Clean Air Act Amendments of 1990 Title IV SO₂ allowance cap by 50 percent, to about 4.5 million tons per year. A cap on Hg emissions was set in 2000 to the amount expected in 2000, then lowered in 2005 by 50 percent, and again in 2010 by another 50 percent (total 75-percent reduction). The results of the initial analysis were published in 1996.

67 U.S. Environmental Protection Agency, EPA’s Clean Air Power Initiative (Washington, DC, 1996).

68 EPA based the mercury concentrations on U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units—Final Report to Congress, Volumes I and II, EPA-453/R-98-004A and B (Washington, DC, February 1998).

69 U.S. Environmental Protection Agency, Emission Standards Division, Information Collection Request for Electric Utility Steam Generating Unit, Mercury Emissions Information Collection Effort (Research Triangle Park, NC, 1999).

70 In 1999, EPA also estimated total Hg emissions at around 50 tons. Both EIA and EPA now estimate these emissions at around 43 tons.

71 T. D. Brown, D. N. Smith, R. A. Hargis, Jr., and W. J. O’Dowd, “Mercury Measurement and Its Control: What We Know, Have Learned, and Need To Further Investigate,” Journal of the Air & Waste Management Association (June 1999).

72 There is much uncertainty about Hg reductions from coal preparation. A recent estimate has put the Hg reduction at nearly 60 percent. Rae-Hoan Yoon, “Developing Advanced Separation Technologies for Producing Clean Coal,” testimony before the Subcommittee on Energy and Air Quality, U.S. House of Representatives (March 14, 2001).

73 EMF rates refer to the amount of Hg remaining in the effluent gas.

74 While recognizing that coal cleaning procedures could have some promise for lowering Hg emissions, neither EPA nor EIA modeled this alternative, due to a lack of information on the incremental costs of preparation to remove Hg.

75 Both EIA and EPA estimated that about two-thirds of coal-fired capacity would add cold side electrostatic precipitators.

76 U.S. Environmental Protection Agency, Office of Air and Radiation, Analysis of Emissions Reduction Options for the Electric Power Industry (Washington, DC, March 1999), Appendix C.

77 The EPA and EIA studies assume the same cost for activated carbon, $1.00 per kilogram (1997 dollars).

78 Therefore, EPA did not model a “hard cap” in either scenario. Reductions are compared with projected baseline emissions absent any policy change.

79 Costs are annual incremental costs directly attributable to Hg control through retrofits and, to a lesser extent, altered fuel consumption.

80 EIA’s integrated case includes a 75-percent NO_x reduction below 1997 levels, whereas EPA assumes NO_x reductions only to levels stipulated by the NO_x SIP call. EIA’s SO₂ target is 75 percent below 1997 levels, whereas EPA’s target is 50 percent reduction, to 4.8 million tons. EIA’s CO₂ target is 7 percent below 1990 levels (about 440 million metric tons carbon equivalent), whereas EPA’s CO₂ target is 515 million metric tons carbon equivalent. EIA’s caps are based on assumptions provided by the House Government Reform Committee, Subcommittee on National Economic Growth, Natural Resources and Regulatory Affairs in its request for this study. See Appendix for full text of letter.

81 Demand was assumed to be reduced by 1.5 percent annually, reaching a total reduction of 15 percent in 2010.

82 “Any regulatory scheme for mercury that incorporates trading or other approaches that involve economic incentives must be constructed in a way that assures that communities near the sources of emissions are adequately protected.” U.S. Environmental Protection Agency, Federal Register, Vol. 65, No. 245 (December 20, 2000).