S. 3135 The Clean Air Planning Act of 2002 Presentation for Jeff Holmstead November 2002

1. S. 3135 The Clean Air Planning Act of 2002 Presentation for Jeff Holmstead November 2002

2. Overview of Presentation • Introduction • Provisions of S.3135 • Analytical Methods • Results of Analysis • Notes on Cost Considerations • Notes on Implementation and Administration of S.3135

3. Introduction • On October 17, 2002, Senator Carper (D-DE) introduced multi-pollutant control legislation for the U.S. power sector. The legislation was co-sponsored by Senators Baucus, Breaux, and Chafee. • The proposal, which includes caps for sulfur dioxide (SO2),nitrogen oxides (NOx), mercury (Hg), and carbon dioxide (CO2), joins previously introduced legislation such as the Administration’s Clear Skies Act and Senator Jeffords’ Clean Power Act.

4. Comparison of Caps and Timing: S.3135, Clear Skies, and S.556

5. Other Provisions of S.3135 • Applies to large fossil fuel-fired electricity generating units (greater than 25 MW) that generate electricity for sale. • For CO2, the bill also covers nuclear and renewable units. • For mercury, the bill is limited to coal-fired units. • For SO2, the bill covers only units affected by the Acid Rain Program (i.e., does not include non-utility generators). • NOx, CO2, and Hg allowances allocated using updating, output-based system with set-aside for new units. SO2 allowances allocated using an adjusted Acid Rain Program distribution with set-aside for new units. • Domestic and international greenhouse gas (GHG) offsets are permitted for compliance with the CO2 cap. Offsets may come from non-capped sources, and either sequestration or non-sequestration projects. • Early reduction credits from project-based reductions made between 1990-2007 can be used in 2008 or thereafter. However these early reductions are limited to no more than 10% of the 2008 cap level (~256 million short tons CO2). • Caps reviewed 15 years after enactment of legislation and sunset at 20 years. • Provides regulatory relief from NSR by changing the definition of “modification” in attainment areas, capping LAER at twice BACT cost and adding cost considerations, and eliminating offsets for new units in non-attainment areas. • Also exempts affected units from mercury MACT and BART (for 20 years).

6. Analytical Methodology • The Integrated Planning Model (IPM) was used to model the impacts of S.3135 on both costs and emissions. This model is used by the electric generating industry for strategic planning purposes, and has been used to support numerous EPA rulemakings for control of emissions from the power sector. • The provisions in the bill were modeled as closely as possible with some important aspects of S.3135 simplified to accommodate time constraints. • Annual, nationwide caps on emissions of NOx, SO2 and Hg, with unrestricted trading. • The Hg cap in 2012 was modeled as 10 tons to approximate the S.3135 range of 5 to 16 tons. The 50 and 70 percent plant-specific reduction of mercury from coal content were modeled in 2008 and 2012, respectively, as specified in the bill. • A CO2 cap was not modeled in IPM because the broad availability of inexpensive GHG offsets suggests that sources would purchase offsets rather than invest in emission controls. Offset costs were modeled offline using preliminary estimates of transaction costs. • The sources covered by S.3135 were modeled with several simplifying assumptions: • SO2 was modeled for units greater than 25 MW, rather than the Acid Rain Program (ARP) units specified by S.3135; and, • CO2 modeling included all units (including nuclear and renewable units) that sell to the grid, including units smaller than 25 MW not covered by S.3135 • EPA did not model the 271,000 ton WRAP cap in S.3135. • The potential impacts of the allocation methodology were not included in the cost estimates. • Only existing CAA programs were included in the modeling.

7. Projected Emissions under S.3135

8. Projected Annual Costs of S.3135 Projected Annual Program Costs (1999$) • Offline analysis showed that the costs of compliance for the CO2 constraint would be low due to the wide availability of inexpensive GHG offsets. The net cost of the CO2 cap is negligible. • The net present value (NPV) of the difference in costs between S.3135 and the EPA Base Case is $89.9 billion ($1999) for the period between 2005 and 2030. (Clear Skies is $65.37 billion ($1999) for the same period.) Note: Cost projections are based on modeling using IPM. These projections show the costs to power generators over and above the costs they will incur to meet statutory and regulatory requirements that are already in effect. The projections do not take into account future regulatory actions to address fine particulates, ozone, or mercury, nor do they include costs associated with the allocation methodology.

9. Projected Allowance Prices for S.3135 • Under S.3135, the projected marginal costs of SO2 and NOx reductions are well below $2,000/ton. The projected marginal cost of Hg reductions range between $1,909/lb and $3212/lb, or $119/oz to $201/oz. • Modeled projections of the marginal cost of Hg reductions are significantly lower than would be expected because IPM attributes much of the cost of installing mercury control to compliance with the facility-specific constraint and not the trading program (i.e., the allowance price). Note: The dollar value is the projected allowance price, representing the marginal cost (i.e., the cost of reducing the last ton) of emissions reductions. Marginal costs are based on modeling using IPM.

10. Projected Coal Capacity with Emissions Controls • Graphics show cumulative capacity with existing controls, in addition to controls projected to be retrofitted under the NOx SIP call and Title IV, as well as controls projected to be retrofitted under S. 3135. • Due to plant-specific mercury requirement, a substantial amount of ACI -- approximately 34 GW -- is projected to be retrofitted under S.3135. Without the plant specific constraint, some sources would likely comply with the 2012 Hg cap (5 -16 tons) by purchasing Hg allowances from large plants that have achieved larger than required Hg reductions as co-benefits of their NOx and SO2 controls.

11. National Coal Production in 1990, 2000 and Projected Production under S.3135 in 2020 Note: 1990 data: Coal Industry Annual 1994, Table 4 (DOE/EIA-0584 (2000)). 2000 data: Coal Industry Annual 2000, Table 4 and Table 63 (DOE/EIA-0584 (2000)), January, 2002. 2020 production for the power generation sector: Derived from the Integrated Planning Model. 2020 production for other sectors: Derived from the National Energy Modeling System. In 1990, EIA did not report the coal produced for power generators. From 1998-2000, 85% of coal produced was for the power generation sector. For an estimate of coal produced for the power generation sector in 1990, EPA assumed the same percentage (85%).

12. Impacts on Fuel Prices • Under S.3135, natural gas prices are projected to increase by approximately 1.3% in 2020, compared to the Base Case. • Under S.3135, coal prices would decrease by approximately 5.6% in 2020 compared to the Base Case. Note: The coal price represents an average minemouth price across all twelve grades of coal in the model. The natural gas price is the Henry Hub price. Average national fuel prices are EPA’s estimates.

13. Projected Generation Mix in 2020 for S.3135 • New electricity generation is projected to come primarily from gas-fired turbines. • No retirement of existing coal-fired capacity is projected. Approximately 1 GW of coal capacity is projected to repower to combined cycle. • Nuclear generation is projected to increase by approximately 1% over the Base Case and renewable generation is projected to remain the same. 2020 generation mix: Projections are from EPA’s modeling using IPM, The “Other” category includes generation from nuclear, hydro, solar, wind, geothermal, biomass, landfill gas, and fuel cells. Control technology percentages are approximations.

14. Impact on Electricity Prices of S.3135 • Retail electricity prices are expected to gradually decline with or without S.3135 because of efficiency improvements and ongoing restructuring in the electricity generating sector. • Under S.3135, retail electricity prices are expected to be slightly higher than the Base Case, as well as slightly higher than under Clear Skies (~ 0.2 cents/KWh). • Retail electricity price projections do not include the potential impacts of S.3135’s updating, output-based allocation system which would slightly lower the price. Note: Retail prices through 2003 are from AEO2000. Prices for the period after 2003 were calculated using the Retail Electricity Price Model.

15. The S.3135 CO2 Baseline is lower than EPA’s Base Case due to the “co-benefits” of controls on SO2,, NOx, and Hg. The S.3135 2008-2011 cap level is the AEO 2002 projection for emissions in 2005. The cap after 2011 is set at 2001 emissions (interpolated). The number of offsets required in a given year is the difference between the S.3135 CO2 Baseline and the S.3135 cap level. This analysis is conducted only for 2010 and 2020. There is no binding offset requirement in 2010, but offsets equivalent to 373 million short tons would be required by 2020. CO2 Offsets Analysis: Required Offsets under S.3135 Notes: 1) S.3135 allows “early reduction credits” of up to ten percent of 2008 emission levels (256 million short tons). We assume that these allowances are used between 2012-2015 to smooth the transition to the lower cap level. 2) S.3135 expresses the CO2 constraint in terms of “short tons of CO2.” One million short tons of CO2 is equivalent to .25 million metric tons of carbon.

16. CO2 Offsets Analysis: Cases Analyzed Offset Program Effectiveness • CO2 offset prices are highly dependent on the design of the offset program. Public awareness of the program, the complexity of the requirements, and the effectiveness of the approval process all influence offset prices. This analysis uses a methodology constructed in consultation with CEA for the Smith-Voinovich-Brownback analysis regarding the modeling of a stringent offset program. • S.3135 leaves offsets program design decisions to the Administrator and an Independent Review Board. Depending on the final program design, offset prices and total costs could be different from the results of this analysis. Transactions Costs • Certain “deal making costs” are incurred in the purchase of offsets. These include search costs, attorney fees, insurance costs, emissions monitoring, approval costs, etc. Transactions costs would add to the costs of offsets. • There is little experience with a functioning GHG offsets program and a lack of data on transactions costs, preliminary estimates suggest a range of $.50 to $1.00 per short ton of CO2 (~$2 to $4 per metric ton of carbon equivalent).

17. CO2 Offsets Analysis: Results* * Other analyses which do not model, for example, voluntary programs, non-CO2 or forestry abatement options, will likely find higher prices and abatement costs.

18. CO2 Offsets Analysis Note: No Need for International Offsets With reasonable assumptions regarding the international market for offsets and the Kyoto Protocol, analysis shows the international market price for offsets would be higher than the domestic price of offsets under S.3135, and affected sources would not have an incentive to seek international offsets. • Assuming that other countries implement the Kyoto Protocol, there would be an international GHG offset market in which the U.S. affected sources would compete. • As the U.S. is not a party to Kyoto, this analysis assumes that other countries will not be able to purchase offsets in the U.S. • Kyoto is currently silent on commitments after 2012 - this analysis assumes that the emissions targets remain unchanged through 2020. • Russia has significant excess emissions, (the so-called “hot air”) and likely has some control over the offset market. This analysis assumes that Russia withholds 800 million short tons worth of offsets to maximize the price it receives.

19. Potential Impacts of the Allocation Approach • The impacts that could result from the updating, output-based allocation methodology were studied using an offline spreadsheet model known as the Technology Retrofit and Updating Model. • Relative to a permanent allocation, the updating, output-based allocation system proposed by S.3135 would likely: • increase generation, in the range of 0.6%; • lower wholesale electricity prices by about 4.0%; • depress annual net revenues up to $4 billion per year by inadvertently lowering electricity prices; and, • have negligible impacts on the costs of emission reductions, adding less than $10 million annually (or less 0.25% of the total costs) -- well within the margin of modeling error. • The value of allowances received by coal units under S.3135’s updating system is less than under a permanent allocation, since a proportion of the allowances in S.3135 are shifted to new units, which are expected to be predominantly gas-fired plants or new non-fossil generation.

20. Additional considerations on costs… • The costs presented in this analysis are the result of a single modeling effort with numerous assumptions. There are many variables that could significantly affect the costs and others outcomes of the modeling. Most important among these are: • The Phase II Hg cap that was modeled in this analysis; at the lower end of the 5-16 ton range, costs would be significantly higher. • Preliminary estimates using the Technology Retrofit and Updating Model suggest that annual costs could rise by approximately $0.9 billion, or 10%, under a 5-ton cap in 2020. • The price for offsets, which could be higher depending on availability and transactions costs. • Analysis suggests that if there are fewer offsets available than modeled, costs would rise. • The price of offsets are not incorporated into the model’s solution for generation dispatch and could slightly affect the program costs, if incorporated. • The costs associated with the updating allocation system, which were discussed earlier.

21. Annual Human Health Benefits of Fine Particulate Matter (PM2.5) Reductions1 • Preliminary estimates indicate that, in 2020, Americans would experience approximately 17,800 fewer cases of premature mortality and $140 billion in health benefits each year under S.3135 (approximately $50 billion more than under Clear Skies in 2020). • For both S.3135 and Clear Skies, these benefit estimates include only health benefits due to reductions in PM2.5. These benefits do not include: Improvements in visibility in National Parks due to reductions in PM2.5 (these benefits would be approximately $3 billion per year under Clear Skies in 2020). Health and welfare improvements due to reductions in ozone. Many additional benefits that EPA is not currently able to monetize but that are expected to be substantial, including reductions in carbon dioxide and other greenhouse gas emissions, mercury exposure, and acid deposition. 1. All human health and environmental benefit projections were calculated in comparison to existing Clean Air Act programs. 2. The key assumptions, uncertainties, and valuation methodologies underlying the approaches used to produce the benefits of Clear Skies are detailed in Technical Addendum: Methodologies for Benefit Analysis of the Clear Skies Act, 2002. 3. Air quality and benefits modeling was not done for S.3135. These preliminary projections were estimated by comparing projected national S.3135 SO2 emissions reductions to previously modeled control cases, as described in the Benefits Methods slide that follows.

22. Attainment with the PM2.5 and 8-hour Ozone Standards 1 • In 2010, compared to the Base Case, S.3135 is expected to bring: • 48 additional counties into attainment with the PM2.5 standard; and • 10 additional counties into attainment with the 8-hour ozone standard • In 2020, compared to the Base Case, S.3135 is expected to bring: • 10 additional counties into attainment with the PM2.5 standard; and • 8 additional counties into attainment with the ozone standard. • Reductions in PM2.5 and ozone under S.3135 would bring the remaining nonattainment counties closer to attainment and provide additional improvements in areas that are expected to already meet the standards. 1. This analysis shows the counties that would come into attainment due to Clear Skies or S.3135 alone in 2010 or 2020. Additional federal and state programs are designed to bring all counties into attainment by 2017 at the latest. All human health and environmental benefit projections were calculated in comparison to the Base Case, which includes all finalized EPA regulations that are expected to be in effect in 2010 and 2020 (e.g., the NOx SIP Call, the Tier 2 rule). The Base Case does not include additional planned regulations that the states or EPA will pursue in order to lower emissions across the country. 2.To permit comparisons among various analyses, the air quality data used in the Clear Skies Act analysis were the most complete and recently available as of mid-2001 (1997-1999 ozone monitoring data and 1999-2000 PM2.5 data). More complete and recent air quality data for ozone and fine particles (1999-2001 data) is now available. This updated data indicate differences in the likely attainment status of some counties compared to what is shown here. 3. Air quality modeling was not done for S.3135. These preliminary projections were estimated by comparing projected national S.3135 SO2 or NOx emissions reductions to previously modeled control cases, as described in the Benefits Methods slide that follows.

23. Health Benefits and Attainment Methodology • Air quality and benefits modeling was not done for S.3135. These preliminary projections were estimated by comparing S.3135 to previously modeled control scenarios with similar reductions in national emissions: • Reductions in SO2 emissions were used to estimate health benefits and PM2.5 attainment. • Reductions in NOx emissions were used to estimate ozone attainment. • Because extensive emissions, air quality, and benefits modeling was not done for S.3135, the S.3135 analysis has additional uncertainty compared to the Clear Skies analysis. Several potential sources of uncertainty should be noted: • NOx emissions reductions are not taken into consideration to estimate the PM-related health benefits or the PM2.5 attainment. The S.3135 analysis, therefore, does not account for the potential contribution of NOx to these endpoints. • National emissions only were used in the interpolations. If there are differences in the spatial distribution of emissions between S.3135 and the modeled scenarios (e.g., if one scenario has a higher percentage of its emissions downwind from population centers), this analysis may underestimate or overestimate the magnitude of the benefits • A preliminary analysis of state-level emissions and benefits showed that, compared to certain modeled scenarios, S.3135 is expected to have a large percentage of reductions in states that contribute to fine particle concentrations in heavily populated areas of the East Coast in 2020. It is likely, therefore, that the S.3135 health benefits estimate underestimates the true benefits of the proposal in 2020.

24. Implementation: Engineering and Economic Analysis • Estimates for the resources required for the construction and operation of scrubbers, SCR and ACI under S.3135 were compared to their supply in today’s market. • Boilermaker labor is likely to be limiting and significant activated carbon production capacity will need to be added before the 2008. • Compared to the U.S. consumption of resources, S.3135 would require: • significant increase of activated carbon production capacity (to accommodate the projected ACI installations) by 2008; • less than 2% of the U.S. consumption (out to 2010) of limestone for scrubbers; • approximately 3% of the U.S. consumption (out to 2010) of ammonia for SCRs ; • 45% of the current cumulative SCR catalyst production capacity in 2005 (increasing to 47 % in 2010); • less than 0.1% of U.S. consumption of steel; and, • additional system hardware which is expected to be readily available. Resources Required for Construction and Operation of Control Technologies

25. Implementation: Engineering and Economic Analysis Labor Resources Required for Construction of Control Technologies • Boilermaker labor, used primarily by the electric utility industry, is expected to be limiting out to 2005. • 10 GW of the projected 47 GW of scrubbers may be completed by 2005 due to the simultaneous installation of SCRs for the NOx SIP call. • 37 GW of the projected 47 GW of scrubbers will likely be pushed back beyond 2005. • General construction labor requirements for control technology installations are expected to be less than 0.3% of the current national labor pool of workers.

26. Notes on Implementation and Administration of S.3135 GHG Offset Provisions • Independent review board (composed mostly of outside stakeholders) is given an inherently governmental function in conducting the administrative task of case-by-case review of projects, rather than the advisory function on the overall guidelines. • No specific criteria for developing guidelines for non-sequestration projects, similar to those specified for sequestration projects, are included. For example, lacks key provisions to address issues such as “leakage.” • Permits GHG reductions from “internationally recognized” reduction programs to be used for CO2 offsets without requiring that EPA certify the adequacy of the programs.

27. Notes on Implementation and Administration of S.3135 Caps and Emission Limits: • Non-utility electricity generating units are excluded from SO2 cap and trading program but included in NOx, Hg, and CO2 caps and trading programs. • SO2, NOx, and Hg caps sunset 20 years after enactment with no default annual emissions limits if EPA was not able to promulgate new caps. • CO2 cap in 2008 is based upon projections of 2005 emissions that will be made in the future and are not required to be subject to public review and comment. • The promulgation deadline of January 1, 2004, for the 2012 Hg cap, as well as for the NOx, Hg, and CO2 trading program and emissions monitoring rules, provides insufficient time to propose and finalize regulations. • EPA is directed to set an output-based emission rate as the facility-specific mercury limit starting in 2012, but no criteria are specified.

28. Notes on Implementation and Administration of S.3135 Allowance Allocations • NOx, Hg, and CO2 allocations for individual units must be recalculated each year based upon updated information. • EPA is required to establish set-asides for allocations to individual new units based on projected electricity output. Provision barring judicial review of individual allocations does not bar review of set-asides and underlying projections. • EPA is required to allocate “equitably” to cogeneration facilities (with respect to NOx and Hg) but does not direct EPA to include thermal output in determining NOx, Hg, and CO2 allocations. • NOx, Hg, and CO2 emissions may be monitored using less accurate methods than SO2 emissions, i.e., methods other than CEMS or an alternate method determined by EPA to have comparable precision, reliability, accuracy, and timing. • Change in NSR modification definition only applies in attainment areas. Other Provisions

29. Next Steps Further Actions to Consider: • Technical Memorandum detailing the results of analysis of the bill. • Memorandum summarizing EPA review of implementation and administration of S.3135. • Further analysis of existing IPM runs considering regional and state-specific emissions changes from the base case and other types of impacts. • Economic and Emissions Analysis • Sensitivity modeling of key elements such as the 2012 Hg of 5 - 16 tons. • Additional modeling that incorporates CO2 offset costs into dispatch decision-making. • More detailed engineering analysis. • Air Quality Analysis • More detailed benefits and air quality modeling. • Detailed Analysis of Allocation Approaches • Incorporate into the comprehensive Allocation Options Analysis. Next Phase of this Analysis