Economic Impacts of Implementing a Regional SO 2 Emissions Program in the

1. Economic Impacts of Implementing a Regional SO2 Emissions Program in the Grand Canyon Visibility Transport Region Volume I Prepared for: Western Regional Air Partnership Market Trading Forum Prepared by: ICF Consulting September 2000

2. Outline • Study Goals • Overview of Study Approach • Analytic Framework • Assumptions and Data Sources • Results

3. Study Objectives • An economic assessment of alternative milestone levels and policy implementation approaches • Command and control methods • Regional SO2 cap under the assumption that the backstop trading program has not been triggered • Regional SO2 emissions cap with a backstop market trading program • Sector-by-sector analysis of all utility, industrial and other sectors • Description of the impact on the state, tribal and regional economy through 2018

4. REMI ICF’s IPM Overview of Analytic Approach Sources Characteristics Demand Levels Technology and Control Options/Characteristics Milestone Levels • Changes in: • Capacity and output levels • SO2, CO2 and NOx Emissions • Investment costs • Fuel consumption and production • Wholesale power prices • SO2 Allowance Prices • Changes in: • Employment • Output (GRP) • Disposable Income ICF’s IPM

5. Overview of Analytic Approach • ICF’s Integrated Planning ModelTM -- a detailed model of the power and industrial boiler sectors, modified to include other sources -- was used to project the economic impacts of the alternative scenarios. This model captures the complex interactions between electricity, steam, fuel and environmental markets. • The energy and environmental market impacts -- in terms of energy price impacts, consumption levels, investments, permit values, among other factors -- were used to drive a regional economic model to assess the impacts on the regional, state and tribal economies.

6. IPM Used in Many Similar Studies • IPM has been used for 20 years for power market analyses and forecasting, environmental policy and regulatory analyses and compliance planning. • IPM is used in support of EPA analyses of NOX, SO2, mercury, and CO2 emissions policies and power and industrial markets impacts. Used in support of the Clean Air Policy Initiative (CAPI), the OTAG process, analysis of the NAAQS, the SIP Call, the Section 126 analysis, and carbon policy analysis. • IPM was used for for FERC’s Order 2000. • IPM is used for industry clients in evaluating the impact of the SIP Call and other proposed regulations on the value of their existing and potential assets. Used for electric market assessments, forward price curves, and asset valuation.

7. Integrated Planning ModelTM

8. Montana PACNW Downstate NY COMED NEPOOL New York City Upstate NY WUMS MAPP MECS LILCO NWPP East PJM-W RMA PJM East NOCAL So. ECAR PJM South ILMO VIEP SPP-N SOCAL N-NM Arizona DUKE CP&L TVA SPP-W S-NM Entergy Southern SCEG ERCOT Florida IPMTM Regional Map

9. The Integrated Planning ModelTM • IPM is a detailed engineering-economic capacity expansion and production costing model for analyzing the electric power and industrial steam markets. • IPM is a multi-regional, dynamic linear programming model. It has explicit representation of interregional transmission linkages between 21 regional power markets. • IPM finds the least-cost solution to meeting electricity and steam demand subject to transmission, fuel, energy demand, reserve margin, and other system operating constraints, including simultaneous environmental requirements.

10. WSCP Oregon Idaho Wyoming Nevada Utah Colorado California WSCR CNV Arizona New Mexico GCVTC States in IPM Regions

11. Geographic Coverage • The EPA Winter 1998 Base Case implementation of IPM represents 21 regional electric power markets in the contiguous U.S. • IPM regions generally correspond to the regions and sub-regions defined by the North American Electricity Reliability Council (NERC).

12. Geographic CoverageContinued • The nine GCVTC States (AZ, CA, CO, ID, NV, NM, OR, UT, WY) are contained in IPM regions WSCP, WSCR and CNV (NERC region WSCC). • For WRAP, IPM was modified slightly to account for Tribal Areas. • IPM reporting modified to track impacts for the nine states and tribal area.

13. Steam Demand • Electric Demand • Gas Supply • Coal Supply Environmental ComplianceTechnologiesand Costs Existing and New Electric, CHP and Boiler Technologies Environmental IPM Regulatory Scenario • Capacity Additions • Fuel Prices • Electric Prices • Asset Values • Emissions • Retrofit Decisions • Compliance Costs

14. IPM’s Internal Structure • IPM is a dynamic optimization framework with an objective function of minimizing the present value of total system cost over the study horizon subject to: • Electricity & Steam Demand Constraints • Reserve Margin Constraints • Environmental Constraints • Transmission Constraints • Fuel Constraints • Other Operational Constraints • Detailed information on fuels, resource options, and environmental compliance technologies.

15. Sources: Electric Generator, Boilers, CHP, Process Sources Allowance Market Electric Generators Boilers Process Sources Repowered CHP Existing CHP New CHP Electric Demand Steam Demand Other Output

16. Sources Modeled • Affected sources include generators, boilers and other sources of SO2 over 100 TPY. • Generators, cogenerators, industrial boilers and other SO2 sources were modeled simultaneously. • Allows development of optimal long-term generating and boiler capacity expansion plans while meeting both steam and electricity demands. • Affected process emissions sources were added as producers of SO2 emissions and consumers of allowances under the cap and trade system. • Other sources -- emissions tracked and reduction options provided. Did not model output decisions of these sources.

17. Electric Load Modeling

18. Electric Load and Dispatch Modeling • Electricity demand is modeled in the form of a load duration curve by season and segment. • Generating units are dispatched by segment. • IPM performs accurate plant dispatch based on seasonal load curves. • Power plants are dispatched based on cost, and capacity, de-rated for their forced and planned outages. • Pollution control cost is endogenously modeled.

19. Environmental Capabilities • Multi-pollutant modeling capabilities (SO2, CO2, NOx, Hg, TSP) • Tonnage caps and rate limits • Emission policies: • Trading only • Trading and Banking • Banking and Borrowing over multiple periods • Command & Control • Progressive Flow Control • Input/Output based Allowance Allocation Schemes • Renewable Portfolio Standards.

20. Environmental Compliance Options • IPM can model a broad range of options to comply with the air emissions regulations, including: • Install pollution control equipment (e.g., scrubber) • Fuel switching (e.g., coal to gas) • Co-firing • Repowering of steam power plants to gas-fired combined cycle • Repowering of industrial boilers to CHP system with fuel switching • Changes in system dispatch • IPM evaluates economic early retirement of generating units.

21. Coal Supply Regions

22. Fuel Market Capabilities • IPM has an endogenous fuel supply capability • Separate coal supply and demand regions connected by a transportation network • Natural gas fuel supply curves available • Gas Transportation cost matrix • Seasonal price adders for natural gas • Produces gas and coal price and consumption forecasts. • Allows an integrated assessment of the Impact of environmental regulations on fuel markets.

23. Assumptions and Data Development

24. Data Development Process • Starting point for assumptions was U.S. EPA’s Winter 1998 Base Case, documented in “Analyzing Electric Power Generation Under the CAAA”, Office of Air and Radiation, March 1998, the basis for EPA’s regulatory and policy analysis. Details of EPA assumptions can be found at www.epa.gov/capi. • Emissions characteristics, controls, and stock were updated by ICF to reflect most recent available information (CEMs data, Form 479, and WRAP/MTF data) • Other key assumptions developed by MTF participants • Emissions baseline for non-utility, non-boiler sources (“Other” sources) based on IAS • Control Options for BART-eligible sources • Control technology options and characteristics

25. Key Assumptions • Electricity and Steam Demand • Bart-eligible sources, controls and characteristics • Technology Control Options and Characteristics for trading scenarios • Fuel Prices

26. Electric Demand Assumptions • Electricity demand growth of 1.85 % per year for 2000-2009 and 1.4 % per year for 2009 - 2030 based on WRAP directive. NERC ES&D 1999

27. Steam Demand • 1995 National Steam Demand1 2,766 TBtu. • Steam demand based on DRI forecasts. 1 EPA’s Industrial, Commercial and Institutional (ICI) Boiler Database 2 DRI-McGraw Hill Industrial Production Forecast published in GRI’s 1997 Baseline Report

28. Control Equipment Cost and Performance Options

29. Bart-Eligible Sources • Identified by MTF participants. Include 85 sources in the nine state region • Required to install controls in the command and control scenario beginning in 2013 • Sources with current controls of less than 70% efficiency are required to install control that achieve 85% efficiency • Sources with current controls of between 70% and 80% efficiency are required to increase control efficiency to 85% • Sources with current controls above 80% require no further abatement activity

30. Control Equipment Cost and Performance - Command & Control • Control options for the utility sector include lime spray dryers and incremental SO2 removal technology based on partial bypass option. • Costs for the dry scrubber was based on actual experience at Cherokee and Valmont units. Costs were adjusted to reflect unit size. • Boilers were given the same options, adjusted to reflect size impacts. • Cost and performance data for incremental SO2 removal technology were taken from the Craig report.

31. Control Equipment Cost and Performance - Policy Trading Scenarios • Additional controls were made available to affected sources in the policy trading scenarios. • Dry sodium injection (DSI) scrubbers achieving a 50% reduction was made available to utilities under the trading policy scenarios. • Costs for the DSI scrubber was based on actual experience at Arapahoe and Cherokee units. Boilers were given the same options, adjusted to reflect size impacts.

32. Control Costs for Utilities *Reference Size is 352 MW

33. Control Equipment - Policy Trading Scenarios (Continued) • Utilities were given the option to retire. • Non boilers, non utility control cost and performance were extracted from IAS. • Control cost for smelters and refineries were updated based on data provided by EPA. • Repowering options for utilities and boilers were taken from “Analyzing Electric Power Generation Under the CAAA”, Office of Air and Radiation, March 1998.

34. Control Costs for Other Sources

35. Control Costs for Other Sources • Control costs for smelters and refineries costs were based on industry review of current information and reflect current level of controls. Cost estimate was based on data provided by EPA. Cost estimates was based on EPA estimates.* * “Regulatory Impact Analysis for the Particulate Matter and Ozone National Ambient Air Quality Standards and Proposed Regional Haze Rule.” Appendix B, “Summary of Control Measures in the PM, Regional Haze, and Ozone Partial Attainment Analyses.”

36. New Capacity Performance and Unit Costs for Fossil and Nuclear Technologies (1997$) Regional Cost Multiplier for WSCC = 0.92

37. Performance and Unit Costs of New Co-generation Technologies (1997 $) Regional Cost Multiplier for WSCC = 0.92

38. Fuel Prices - Gas Delivered Natural Gas Prices (1997 $/MMBtu) Source: EIA’s Annual Energy Outlook 1999

39. Fuel Prices - Coal Delivered Coal prices (1997$/MMBtu) Source: Forecast based on WRAP Baseline Scenario. Cost Curve based on “Analyzing Electric Power Generation Under the CAAA”, Office of Air and Radiation, March 1998.

40. Scenarios Evaluated • Baseline scenario assumes existing environmental regulations (Title I and Title IV NOX, Title IV SO2, and the SIP Call regulations) • “Command and control” scenario • Bart-eligible sources retrofit with BART • IPM captures impacts on operation in the system. • Market Trading Program • Emissions limit (and interim milestones) imposed on all affected emissions sources with full trading among all sources; new units subject to the cap • Emissions control options include the control technologies supplied in the model, fuel switching to lower sulfur content fuels, or reducing output • Model determines the optimal mix of control, dispatch changes (including changes in imports/exports), fuel switching, new unit construction, existingunit retirements to meet the cap in a least-cost way (on a national level)

41. Results

42. Baseline Results

43. Baseline Results

44. Baseline Results • Baseline emissions estimates are reported only for affected sources. • Emissions from industrial boilers and cogenerators are flat since they operate at fixed capacity factors. • Emissions from smelters and other sources are assumed to remain flat over time based on 1998 levels provided by WRAP.

45. Baseline Emissions (Thousand Tons of SO2)

46. Trends in Baseline Emissions • Baseline emissions total 648 in 2018 for utility, cogenerators, boilers and other sources, declining by 50 tons (or about 12 percent) relative to 1999 levels. • Existing SO2 sources operate at maximum availability, thus reductions in the utility sector are due primarily to the addition of controls to existing units with all fully operational by 2006. • Small decline in 2013 emissions is due to planned retirement and small shifts in fuel quality in response to tightening national SO2 markets. 7 GW of low -efficiency existing oil/gas steams units are retired early, and 9 GW are repowered.

47. Projected Trend in Emission from Electric Utility Generators Actual CEMS Data Controls at Mohave units operational Coal plants operate at maximum availability. Repowering of old Oil/gas unit begins Reductions from Denver Front Range Plants fully operational New coal units come on line Scheduled retirement of some coal units

48. Trends in Emissions from Electric Generating Units (Continued) • New generation and capacity demand is serviced predominantly by new combined cycle units. • New coal plants, new gas cogenerators and new combustion turbines also come into the mix by 2018. • Average out-of-stack SO2 emission rate for new builds in 2018 is at 0.01 lbs/mmbtu. • Emissions from cogenerators and boilers are flat because all new additions are gas-fired. • Emissions from other sources are flat by assumption.

49. Denver Front Range units are controlled Mohave installs controls New Coal units come into mix Baseline Out-of-Stack Average Emission Rate for Electric Utilities

50. New Capacity and Generation in Baseline by 2018 16.9 GW 4.9 GW 2.3 GW