§ 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis 1 EPA also considered other models that are more commonly used for private sector analyses but decided to focus its model selection process on models developed for public policy analyses.

NODA Version   March 12, 2003 B3 1 Chapter B3: Electricity Market Model Analysis INTRODUCTION The section 316( b) Phase II Existing Facilities Rule applies to a subset of facilities within the electric power generation industry. The rule applies to steam electric generating units that use cooling water withdrawn directly from waters of the U. S. Generating units with a non steam prime mover and those steam units that use cooling water from a source other than a water of the U. S. are not subject to this rule. In addition, this rule only applies to plants with a design intake flow of at least 50 million gallons per day ( MGD). However, due to interdependencies within the electric power market, impacts on in scope facilities may result in indirect impacts throughout the industry. Direct impacts on plants subject to the rule may include changes in capacity utilization, generation, and profitability. Potential indirect impacts on the electric power industry may include changes to the generation and revenue of facilities and firms not subject to the rule, changes to bulk system reliability, and regional and national impacts such as changes in the price and demand for electricity.

EPA used ICF Consulting's Integrated Planning Model ( IPM ® ) , an integrated energy market model, to conduct the economic analyses supporting the section 316( b) Phase II rule. The model addresses the interdependencies within the electric power market and accounts for both direct and indirect impacts of regulatory actions. EPA used the model to analyze two potential effects of the preferred option and other regulatory options: ( 1) potential energy effects at the national and regional levels, as required by Executive Order 13211 (" Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use"); and ( 2) potential economic impacts on in scope facilities.

The remainder of this chapter presents an overview of the IPM and the results of the IPM analysis for the preferred option. Chapter B8: Alternative Options  Electricity Market Model Analysis presents the IPM analysis for the alternative waterbody/ capacity based option.

B3 1 SUMMARY COMPARISON OF ENERGY MARKET MODELS EPA conducted research to identify models suitable for analysis of environmental policies that affect the electric power industry. Through a review of forecasting studies and interviews with industry personnel, EPA identified three potential models and considered each for the analyses in support of the Phase II rule: ( 1) the Department of Energy's National Energy Modeling System ( NEMS), ( 2) the Department of Energy's Policy Office Electricity Modeling System ( POEMS), and ( 3) ICF Consulting's Integrated Planning Model ( IPM). These models are widely used in the analysis of various issues related to public policies affecting the electric power generation industry and have been reviewed. 1 The three models considered by EPA were developed to meet the specific needs of different users; they therefore differ in terms of structure and functionality. EPA established a set of modeling and logistical criteria to select the model that is best CHAPTER CONTENTS B3 1 Summary Comparison of Energy Market Models. B3 1 B3 2 Integrated Planning Model Overview . . . . . . . . . . . B3 3 B3 2.1 Modeling Methodology . . . . . . . . . . . . . . . . . . . B3 3 B3 2.2 Specifications for the Section 316( b) Analysis . B3 6 B3 2.3 Model Inputs . . . . . . . . . . . . . . . . . . . . . . . . . . . B3 7 B3 2.4 Model Outputs . . . . . . . . . . . . . . . . . . . . . . . . . . B3 8 B3 3 Economic Impact Analysis Methodology . . . . . . . . B3 9 B3 3.1 Market level Impact Measures . . . . . . . . . . . . . B3 9 B3 3.2 Facility level Impact Measures . . . . . . . . . . . . B3 10 B3 4 Analysis Results for the Preferred Option . . . . . . . B3 12 B3 4.1 Market Analysis for 2010 . . . . . . . . . . . . . . . . B3 12 B3 4.2 Analysis of Phase II Facilities for 2010 . . . . . . B3 18 B3 4.3 Market Analysis for 2008 . . . . . . . . . . . . . . . . B3 24 B3 5 Uncertainties and Limitations . . . . . . . . . . . . . . . . B3 29 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B3 31 Appendix to Chapter B3 . . . . . . . . . . . . . . . . . . . . . . . . . . . B3 32 § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis 2 Please see Section B3 A. 1 of the appendix to this chapter for a comparison of the three electricity market models considered for this analysis.

B3 2 NODA Version   March 12, 2003 suited for the analysis of section 316( b) regulatory options. Modeling criteria refer to the models' technical capabilities that are required to provide the outputs necessary for the analysis of the section 316( b) regulation. They include the following:

< Redefining model plants   The energy market models considered by EPA aggregate similar generating units into model plants to reduce the amount of time required to run the model. However, such an aggregation is usable only if the aggregated units are similar in the base case and also have similar compliance requirements under the analyzed policy cases. The Phase II compliance requirements of in scope facilities are based on the location, design, construction, and capacity of their cooling water intake structures ( CWIS). In contrast, the existing aggregation of these models is based on factors including unit age, unit type, fuel type, capacity, and operating costs. Therefore, the model used for the Phase II analysis had to be able to accommodate a different aggregation scheme for model plants or even to run all in scope facilities as separate model plants.

< Predicting the economic retirement of generating capacity   Compliance with Phase II regulation may increase the capital and operating costs of some facilities to a point where it is no longer economically profitable to operate the facility, or one or more of its generating units. The economically sound decision for a firm owning such a facility or unit would be to retire the facility or unit rather than comply with the regulation. Therefore, the model needed to have the ability to project early retirements as a result of compliance with section 316( b) regulation and the market's response to such closures, including increased capacity additions or increased market prices. In addition, to support EPA's economic impact analysis, the model had to be able to map early retirements to specific facilities or units.

< Representing the impact of structural changes to the industry from deregulation   Assumptions regarding deregulation of the electric utility industry could impact a model's ability to accurately depict the profit maximizing decisions of firms. Deregulation of the wholesale market for electricity is expected to reduce wholesale prices as competition in markets increases. These changes may impact decisions regarding the retirement of existing generating units, investment in new generating units, and technology and fuel choices for new generation capacity. Therefore, it was necessary for the market model to reflect the most recent trends in the deregulation of wholesale energy markets.

EPA also considered a number of logistical criteria to determine the most appropriate model for the analyses of the Phase II rule. While a given model may be desirable from an analytical perspective, its use may be restricted due to other limitations unrelated to the model's capabilities. The logistical criteria used to evaluate each model refer to administrative issues and include the following:

< Availability of the model   Due to the tight regulatory schedule of the Phase II rule, the model selected for this analysis had to be accessible at the time data inputs were available, and had to be able to turn around the analyses in a relatively short period of time. Some of the models considered for this analysis are used to conduct analyses in support of annual reports. Such requirements may limit access to the model and the staff required to execute the model, and therefore prevent the use of the model for this analysis.

< Sufficient documentation of methods and assumptions   Sufficient documentation of the model structure and assumptions was required to allow for the necessary review of results and procedure. While it may not be possible to disclose specific details of the structure and function of a model, a general discussion of the mechanics of the model, its assumptions, inputs, and results was required to make a model useable for this analysis.

< Cost   EPA considered the cost of using each model together with each model's ability to satisfy the other modeling and logistical criteria in determining the most appropriate model for the analysis of this rule. The model had to be sufficiently robust with respect to the other criteria while remaining within the budget constraints for this analysis.

EPA assessed each market model with respect to the aforementioned modeling and logistical criteria and determined that the IPM was best suited for the Phase II analysis. 2 A principal strength of the IPM as compared to other models is the ability to evaluate impacts to specific facilities subject to this rule. Another important advantage of the IPM model is that it has a history of prior use by EPA. The Agency has successfully used the IPM in support of a number of major air rules. Finally, the IPM model has been reviewed and approved by the Office of Management and Budget ( OMB). § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis 3 The EPA Base Case 2000 is the latest EPA specification of the U. S. power market using the IPM. Past applications of the IPM for EPA analyses have used a predecessor EPA base case specification. Section B3 A. 2 of the appendix to this chapter contains a summary of the major differences between the EPA Base Case 2000 and the previous EPA base case specification.

4 EPA used the IPM to forecast operational changes, including changes in capacity, generation, revenues, electricity prices, and plant closures, resulting from the rule. In other policy analyses, the IPM is generally also used to determine the compliance response for each model facility. This process involves selecting the optimal response from a menu of compliance options that will result in the least cost system dispatch and new resource investment decision. Compliance options specified by IPM may include fuel switching, repowering, pollution control retrofit, co firing multiple fuels, dispatch adjustments, and economic retirement. EPA did not use this capability to choose the compliance responses of the facilities subject to section 316( b) regulation. Rather EPA exogenously estimated a compliance response using the costs of technologies capable of meeting the percentage reductions required under the regulation. In the postcompliance analysis, these compliance costs were added as model inputs to the base case operating and capital costs.

5 Since the EPA Base Case 2000 model plants were initially created to support air policy analyses, the original configuration was not appropriate for the section 316( b) analysis. See the discussion of model plant aggregation in Section B3 2.2 below.

NODA Version   March 12, 2003 B3 3 B3 2 INTEGRATED PLANNING MODEL OVERVIEW This section presents a general overview of the capabilities of the IPM, including a discussion of the modeling methodology, the specification of the model for the section 316( b) analysis, and model inputs and outputs.

B3 2.1 Modeling Methodology a. General framework The IPM is an engineering economic optimization model of the electric power industry, which generates least cost resource dispatch decisions based on user specified constraints such as environmental, demand, and other operational constraints. The model can be used to analyze a wide range of electric power market issues at the plant, regional, and national levels. In the past, applications of the IPM have included capacity planning, environmental policy analysis and compliance planning, wholesale price forecasting, and asset valuation. 3 The IPM uses a long term dynamic linear programming framework that simulates the dispatch of generating capacity to achieve a demand  supply equilibrium on a seasonal basis and by region. The model seeks the optimal solution to an " objective function," which is a linear equation equal to the present value of the sum of all capital costs, fixed and variable operation and maintenance ( O& M) costs, and fuel costs. The objective function is minimized subject to a series of userdefined supply and demand, or system operating, constraints. Supply side constraints include capacity constraints, availability of generation resources, plant minimum operating constraints, transmission constraints, and environmental constraints. Demand side constraints include reserve margin constraints and minimum system wide load requirements. The optimal solution to the objective function is the least cost mix of resources required to satisfy system wide electricity demand on a seasonal basis by region. In addition to existing capacity, the model also considers new resource investment options, including capacity expansion or repowering at existing plants as well as investment in new plants. The model selects new investments while considering interactions with fuel markets, capacity markets, power plant cost and performance characteristics, forecasts of electricity demand, reliability criteria, and other constraints. The resulting system dispatch is optimized given the resource mix, unit operating characteristics, and fuel and other costs, to achieve the most efficient use of existing and new resources available to meet demand. The model is dynamic in that it is capable of using forecasts of future conditions to make decisions for the present. 4 b. Model plants The model is supported by a database of boilers and electric generation units which includes all existing utility owned generation units as well as those located at plants owned by independent power producers and cogeneration facilities that contribute capacity to the electric transmission grid. Individual generators are aggregated into model plants with similar O& M costs and specific operating characteristics including seasonal capacities, heat rates, maintenance schedules, outage rates, fuels, and transmission and distribution loss characteristics.

The number and aggregation scheme of model plants can be adjusted to meet the specific needs of each analysis. The EPA Base Case 2000 contains 1,390 model plants. 5 § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis B3 4 NODA Version   March 12, 2003 PNW CALI NWPE AZNM RMPA MAPP SPPN SPPS ERCT FRCC ENTG TVA SOU MANO ECAO VACA MACS MACE LILC WUMS DSNYU UPNY MACW NENG MECS NYC c. IPM regions The IPM divides the U. S. electric power market into 26 regions in the contiguous U. S. It does not include generators located in Alaska or Hawaii. The 26 regions map into North American Reliability Council ( NERC) regions and sub regions. The IPM models electric demand, generation, transmission, and distribution within each region and across the transmission grid that connects regions. For the analyses presented in this chapter, IPM regions were aggregated back into NERC regions. Figure B3 1 provides a map of the regions included in the IPM. Table B3 1 presents the crosswalk between NERC regions and IPM regions.

Figure B3 1: Regional Representation of U. S. Power System as Modeled in IPM Source: U. S. EPA, 2002. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis 6 The IPM developed output for a total of five model run years 2008, 2010, 2013, 2020, and 2026. Model run years 2020 and 2026 were specified for model balance, while run years 2008, 2010, and 2013 were selected to provide output across the compliance period. Output for 2026 was not used in this analysis.

NODA Version   March 12, 2003 B3 5 Table B3 1: Crosswalk between NERC Regions and IPM Regions NERC Region IPM Regions ASCC   Alaska Not Included ECAR   East Central Area Reliability Coordination Agreement ECAO, MECS ERCOT   Electric Reliability Council of Texas ERCT FRCC   Florida Reliability Coordinating Council FRCC HI   Hawaii Not Included MACC   Mid Atlantic Area Council MACE, MACS, MACW MAIN   Mid America Interconnect Network MANO, WUMS MAPP   Mid Continent Area Power Pool MAPP NPCC   Northeast Power Coordination Council DSNY, LILC, NENG, NYC, UPNY SERC   Southeastern Electricity Reliability Council ENTG, SOU, TVA, VACA SPP  Southwest Power Pool SPPN, SPPS WSCC   Western Systems Coordinating Council AZNM, CALI, NWPE, PNW, RMPA Source: U. S. EPA, 2002.

d. Model run years The IPM models the electric power market over the 26 year period 2005 to 2030. Due to the data intensive processing procedures, the model is run for a limited number of years only. Run years are selected based on analytical requirements and the necessity to maintain a balanced choice of run years throughout the modeled time horizon. EPA selected the following run years for this analysis: 2008, 2010, and 2013.6 The model run years were selected before the proposal analysis for the following reasons:

< 2008 was selected based on the assumption that all in scope facilities would be required to comply with the requirements of the preferred option during the first five years after promulgation ( at the time, promulgation was scheduled for August 28, 2003 so that the compliance window would have been 2004 to 2008). Therefore, in 2008, all facilities would have been in compliance, and 2008 would have represented the post compliance state of the industry. < 2013 was selected based on the assumption that facilities costed with a cooling tower ( a requirement for some facilities under the two alternative options analyzed with the IPM at proposal) would have to comply by the end of the permit term of the first permit issued after promulgation ( at the time, this was 2004 to 2012). As installation of a cooling tower may require the temporary shut down of the facility, 2013 would have represented the first full, post compliance year for options requiring cooling towers. < 2010 was selected as an additional year during which facilities costed with a cooling tower may experience temporary connection outages during cooling tower installation and connection.

With the change in promulgation date from August 28, 2003 to February 16, 2004, EPA changed its compliance year assumptions by one year ( because start up activities are required for compliance with the Phase II rule, it will no longer be possible to comply in 2004). However, changing run years requires significant structural changes to the IPM. EPA therefore decided not to change the model run years selected at proposal for this NODA analysis.

The model assumes that capital investment decisions are only implemented during run years. Each model run year is mapped to several calendar years such that changes in variable costs, available capacity, and demand for electricity in the years between the run years are partially captured in the results for each model run year. Table B3 2 below identifies the model run years specified for the analysis of Phase II regulatory options, and the calendar years mapped to each. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis B3 6 NODA Version   March 12, 2003 Table B3 2: Model Run Year Mapping Run Year Mapped Years 2008 2005 2009 2010 2010 2012 2013 2013 2015 2020 2016 2022 2026 2023 2030 Source: IPM model specification for the Section 316( b) NODA Base Cases.

EPA mainly relied on data for 2010 in the analyses of the preferred option ( presented in this chapter) and on data for 2013 in the analyses of the waterbody/ capacity based option ( presented in the updated Chapter B8: Alternative Regulatory Options  Electricity Market Model Analysis). Section B3 4 below and Section B8 1 in Chapter B8 describe EPA's rationale for selecting these model run years.

B3 2.2 Specifications for the Section 316( b) Analysis The analysis of regulatory options considered for Phase II regulation required changes in the original specification of the IPM model. Specifically, the base case configuration of the model plants and model run years were revised according to the requirements of this analysis. Both modifications to the existing model specifications are discussed below.

< Changes in the Aggregation of Model Plants: As noted above, the IPM aggregates individual boilers and generators with similar cost and operational characteristics into model plants. Since the IPM model plants were initially created to support air policy analyses, the original configuration was not appropriate for the section 316( b) analysis. At proposal, the steam electric generators at facilities subject to the Phase II rule were disaggregated from the existing IPM model plants and " run" as individual facilities along with the other existing model plants. This change increased the total number of model plants from 1,390 to 1,777. For the NODA analysis, EPA also disaggregated non steam generators at Phase II facilities and generators at facilities subject to the upcoming Phase III regulation. This change increased the total number of model plants from 1,777 to 2,096.

< Use of Different Model Run Years: The original specification of the EPA Base Case 2000 of the IPM uses five model run years chosen based on the requirements of various air policy analyses. Because EPA assumed that all facilities subject to Phase II regulation would come into compliance within the first permitting cycle after promulgation in 2004 ( i. e., 2005 to 2013), the run years specified for the EPA Base Case 2000 are not of primary interest to this analysis. Therefore, EPA selected different run years for the section 316( b) analysis in order to obtain model output throughout the compliance period ( see discussion of run year selection in section B3 2.1. d above). The change in run years and run year mappings are summarized below.

Table B3 3: Modification of Model Run Years EPA Base Case 2000 Specification Section 316( b) Base Case Specification Run Year Run Year Mapping Run Year Run Year Mapping 2005 2005 2007 2008 2005 2009 2010 2008 2012 2010 2010 2012 2015 2013 2017 2013 2013 2015 2020 2018 2022 2020 2016 2022 2026 2023 2030 2026 2023 2030 Source: IPM model specifications for the EPA Base Case 2000 and the Section 316( b) NODA Base Cases. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis 7 Of the 540 surveyed facilities subject to the section 316( b) Phase II rule, nine are not modeled in the IPM. Three facilities are in Hawaii, one is in Alaska. Neither state is represented in the IPM. One facility is identified as an " Unspecified Resource" and does not report on any EIA forms. Four facilities are on site generators that do not provide electricity to the grid.

8 No facilities under the preferred option were costed with flow reduction technologies. However, 44 facilities were costed with flow reduction technology under the waterbody/ capacity based option.

9 The capital charge rate is a function of capital structure ( debt/ equity shares of an investment), pre tax debt rate ( or interest cost), debt life, post tax return on equity, corporate income tax, depreciation schedule, book life of the investment, and other costs including property tax and insurance. The discount rate is a function of capital structure, pre tax debt rate, and post tax return on equity.

NODA Version   March 12, 2003 B3 7 EPA compared the base case results generated from the two different specifications of the IPM model. The base case results could only be compared for those run years that are common to both base cases, 2010 and 2020. This comparison identified little or no difference in the base case results:

< Base case total production costs ( capital, O& M, and fuel) using the revised section 316( b) specifications do not change in 2010 and are lower by 0.1% in 2020. < Early retirements of base case oil and gas steam capacity under the section 316( b) specifications are lower by 850 MW. Early retirements of base case nuclear capacity decreased by 480 MW. There is no difference in the early retirement of coal capacity. < The change in model specifications results in virtually no change in base case coal and a 1.5 percent reduction in gas fuel use in 2010.

B3 2.3 Model Inputs Compliance costs and compliance related capacity reductions are the primary model inputs in the analysis of section 316( b) regulations. EPA determined compliance costs for each of the 531 facilities subject to Phase II regulation and modeled by the IPM. 7 For each facility, compliance costs consist of capital costs ( including costs for new screens or fish barrier nets, intake relocation, recirculating system modifications, and intake piping modification), fixed O& M costs, variable O& M costs, permitting costs, and capacity reductions ( for information on the costing methodology, see the Section 316( b) Technical Development Document, DCN 4 0004). 8 Capital cost inputs into the IPM are expressed as a fixed O& M cost, in dollars per KW of capacity. The capital costs of compliance reflect the up front cost of construction, equipment, and capital associated with the installation of required compliance technologies. The IPM uses two single up front cost values as model inputs ( one each for technologies with a useful life of 10 and 30 years, respectively) and translates these values into a series of annual post tax payments using a discount rate of 5.34 percent and a capital charge rate of 12 percent for the duration of the book life of the investment ( assumed to be 30 years for recirculating systems and 10 years for other compliance technologies) or the years remaining in the modeling horizon, whichever is shorter. 9 Fixed O& M cost inputs into the IPM are expressed in terms of dollars per KW of capacity per year.

Variable O& M cost inputs are expressed in dollars per MWh of generation.

Permitting costs consist of initial permitting costs, annual monitoring costs, repermitting costs ( occurring every five years after issuance of the initial permit), and, for some facilities, pilot study costs. Permitting cost inputs are expressed as follows: initial permitting and pilot study activities are necessary for the on going operation of the plant and are therefore added to the capital costs for technologies with a 30 year useful life; annual monitoring and annualized repermitting costs are added to the fixed O& M costs.

Capacity reductions consist of an energy penalty and a one time generator downtime. Energy penalty estimates reflect the long term reduction in capacity due to the on going operation of compliance technologies and are expressed in terms of a percentage change in capacity. Energy penalties were only applied to facilities estimated to install flow reduction technologies. The energy penalty consists of two components: ( 1) a reduction in unit efficiency due to increased turbine back pressure and ( 2) an increase in auxiliary power requirements to operate the cooling tower ( e. g., for pumping and fanning). EPA's estimate of O& M compliance costs already includes the auxiliary power requirement component of the energy penalty ( see Chapter B1 of the EBA, as published at proposal, http:// www. epa. gov/ ost/ 316b/ econbenefits/ b1. pdf). However, to fully capture the effect of the energy penalty in the market model analysis, both components of the energy § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis 10 For example, a facility with a downtime in 2008 was modeled as if 1/ 5th of its downtime occurred in each year between 2005 and 2009. A potential drawback of this approach of averaging downtimes over the mapped years is that the snapshot of the effect of downtimes during the model run year is the average effect; this approach does not model potential worst case effects of above average amounts of capacity being down in any one NERC region during any one year.

11 This information is provided in Schedule IV  Generator Information, Question 3. A ( Design flow rate for the condenser at 100% load). Design intake flow data at the generator level is not available for nonutilities nor for those utility owned plants with a steam generating capacity less than 100 MW. Generator level design intake flow data were not available for 57 of the 531 modeled facilities.

12 Repowering in the IPM consists of converting oil/ gas or coal capacity to combined cycle capacity. The modeling assumption is that each one MW of existing capacity is replaced by two MW of repowered capacity.

13 Nuclear plants are evaluated for economic viability at the end of their license term. Nuclear units that, at age 30, did not make a major maintenance investment, are provided with a 10 year life extension, if they are economically viable. These same units may subsequently undertake a 20 year re licensing option at age 40. Nuclear units that already had made a maintenance investment are provided with a 20 year re licensing option at age 40, if they are economically viable. All nuclear units are ultimately retired at age 60.

B3 8 NODA Version   March 12, 2003 penalty needed to be applied as a percentage reduction in capacity. To avoid double counting of the auxiliary power requirements, EPA did not apply the variable component of O& M compliance costs to facilities estimated to install flow reduction technologies ( the main component of variable O& M costs associated with recirculating systems are auxiliary power requirements). Generator downtime estimates reflect the amount of time generators are off line while compliance technologies are constructed and/ or installed and are expressed in weeks. In contrast to the energy penalty, the generator downtime is a one time event that affects flow reduction technologies and several other compliance technologies. Generator downtime is estimated to occur during the year when a facility complies with the policy option. Since the years that are mapped into a run year are assumed to have the same characteristics as the run year itself, generator downtimes were applied as an average over the years that are mapped into each model run year. 10 The IPM operates at the boiler level. It was therefore necessary to distribute facility level costs across affected boilers. EPA used the following methodology:

< Steam electric generators operating at each of the 531 modeled section 316( b) facilities were identified using data from Forms EIA 860A and 860B ( 1998 and 1999). < Generator specific design intake flows were obtained from Form EIA 767 ( 1998). 11 < Facility level compliance costs were distributed across each facility's steam generators. For facilities with available intake flow data, this distribution was based on each generator's proportion of total design intake volume; for facilities without available intake flow, this distribution was based on each generator's proportion of total steam electric capacity. < Generator level compliance costs were aggregated to the boiler level based on the EPA's Base Case 2000 cross walk between boilers and generators.

B3 2.4 Model Outputs The IPM generates a series of outputs on different levels of aggregation ( boiler, model plant, region, and nation). The economic analysis for the Phase II rule used a subset of the available IPM output. For each model run ( base case and each analyzed policy option) and for each model run year ( 2008, 2010, 2013, and 2020) the following model outputs were generated:

< Capacity   Capacity is a measure of the ability to generate electricity. This output measure reflects the summer net dependable capacity of all generating units at the plant. The model differentiates between existing capacity, new capacity additions, and existing capacity that has been repowered. 12 < Early Retirements   The IPM models two types of plant closures: closures of nuclear plants as a result of license expiration and economic closures as a result of negative net present value of future operation. 13 This analysis only considers economic closures in assessing the impacts of the preferred option and other regulatory alternatives. However, cases where a nuclear facility decides to renew its license in the base case but does not renew its license in the post compliance case for a given policy option are also considered economic closures and an impact of that policy option.

< Energy Price   The average annual price received for the sale of electricity. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis 14 EPA conducted model runs based on different electricity demand assumptions: ( 1) a case using EPA's electricity demand assumptions and ( 2) a case using Annual Energy Outlook ( AEO) electricity demand assumptions. The analyses presented in this chapter are based on EPA's electricity demand assumptions. The analyses of the waterbody/ capacity based option presented in Chapter 8: Alternative Options: Electricity Market Model Analysis are based on AEO electricity demand assumptions.

NODA Version   March 12, 2003 B3 9 < Capacity Price   The premium over energy prices received by facilities operating in peak hours during which system load approaches available capacity. The capacity price is the premium required to stimulate new market entrants to construct additional capacity, cover costs, and earn a return on their investment. This price manifests as short term price spikes during peak hours and, in long run equilibrium, need be only so large as is required to justify investment in new capacity.

< Generation   The amount of electricity produced by each plant that is available for dispatch to the transmission grid (" net generation").

< Energy Revenue   Revenues from the sale of electricity to the grid.

< Capacity Revenue   Revenues received by facilities operating in hours where the price of energy exceeds the variable production cost of generation for the next unit to be dispatched at that price in order to maintain reliable energy supply in the short run. At these peak hours, the price of energy includes a premium which reflects the cost of the required reserve margin and serves to stimulate investment in the additional capacity required to maintain a long run equilibrium in the supply and demand for capacity.

< Fuel Costs   The cost of fuel consumed in the generation of electricity.

< Variable Operation and Maintenance Costs   Non fuel O& M costs that vary with the level of generation, e. g., cost of consumables, including water, lubricants, and electricity.

< Fixed Operation and Maintenance Costs   O& M costs that do not vary with the level of generation, e. g., labor costs and capital expenditures for maintenance. In post compliance scenarios, fixed O& M costs also include annualized capital costs of compliance and permitting costs.

< Capital Costs   The cost of construction, equipment, and capital. Capital costs are associated with investment in new equipment, e. g., the replacement of a boiler or condenser, installation of technologies to meet the requirements of air regulations, or the repowering of a plant.

B3 3 ECONOMIC IMPACT ANALYSIS METHODOLOGY The outputs presented in the previous section were used to identify changes to economic and operational characteristics such as capacity, generation, revenue, cost of generation, and electricity prices associated with Phase II regulatory options. EPA developed impact measures at two analytic levels: ( 1) the market as a whole, including all facilities and ( 2) the subset of inscope Phase II facilities. Both analyses were conducted by NERC region. In both cases, the impacts of each option are defined as the difference between the model output for the base case scenario ( i. e., the model run in the absence of section 316( b) Phase II regulations) 14 and the post compliance scenario. The following subsections describe the impact measures used for the two levels of analysis.

B3 3.1 Market level Impact Measures The market level analysis evaluates regional changes as a result of Phase II regulatory options. Seven main measures are analyzed:

< ( 1) Changes in available capacity: This measure analyzes changes in the capacity available to generate electricity. A long term reduction in availability may be the result of the energy penalty associated with the installation of recirculating systems, and of partial or full closures of plants subject to the rule. In the short term, temporary plant § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis 15 Such short term capacity reductions would not be expressed as changes in available capacity but might affect electricity generation, production costs, and/ or prices.

B3 10 NODA Version   March 12, 2003 shut downs for the installation of Phase II compliance technologies may lead to reductions in available capacity. 15 When analyzing changes in available capacity, EPA distinguished between existing capacity, new capacity additions, and repowering additions. Under this measure, EPA also analyzed capacity closures. Only capacity that is projected to remain operational in the base case but is closed in the post compliance case is considered a closure as the result of the rule. An option may result in partial ( i. e., unit) or full plant closures. An option may also result in avoided closures if a facility's compliance costs are low relative to other affected facilities. An avoided closure is a unit or plant that would close in the base case but operates in the post compliance case.

< ( 2) Changes in the price of electricity: This measure considers changes in regional prices as a result of Phase II regulation. In the long term, electricity prices may change as a result of increased production costs of the Phase II facilities. In the short term, price increases may be higher if large power plants have to temporarily shut down to construct and/ or install Phase II compliance technologies. This analysis considers changes in both energy prices and capacity prices.

< ( 3) Changes in generation: This measure considers the amount of electricity generated. At a regional level, longterm changes in generation may be the result of plant closures, energy penalties, or a change in the amount of electricity traded between regions. In the short term, temporary plant shut downs to install Phase II compliance technologies may lead to reductions in generation. At the national level, the demand for electricity does not change between the base case and the analyzed policy options ( generation within the regions is allowed to vary). However, demand for electricity does vary across the modeling horizon according to the model's underlying electricity demand growth assumptions.

< ( 4) Changes in revenues: This measure considers the revenues realized by all facilities in the market and includes both energy revenues and capacity revenues ( see definition in section B3 2.4 above). A change in revenues could be the result of a change in generation and/ or a the price of electricity.

< ( 5) Changes in costs: This measure considers changes in the overall cost of generating electricity, including fuel costs, variable and fixed O& M costs, and capital costs. Fuel costs and variable O& M costs are production costs that vary with the level of generation. Fuel costs generally account for the single largest share of production costs. Fixed O& M costs and capital costs do not vary with generation. They are fixed in the short term and therefore do not affect the dispatch decision of a unit ( given sufficient demand, a unit will dispatch as long as the price of electricity is at least equal to its per MWh production costs). However, in the long run, these costs need to be recovered for a unit to remain economically viable.

< ( 6) Changes in pre tax income: Pre tax income is defined as total revenues minus total costs and is an indicator of profitability. Pre tax income may decrease as a result of reductions in revenues and/ or increases in costs.

< ( 7) Changes in variable production costs per MWh: This measure considers the regional change in average variable production cost per MWh. Variable production costs include fuel costs and other variable O& M costs but exclude fixed O& M costs and capital costs. Production cost per MWh is a primary determinant of how often a power plant's units are dispatched. This measure presents similar information to total fuel and variable O& M costs under measure ( 5) above, but normalized for changes in generation.

B3 3.2 Facility level Impact Measures EPA used the IPM results to analyze impacts on in scope Phase II facilities at two levels: ( 1) potential changes in the economic and operational characteristics of the in scope Phase II facilities as a group and ( 2) potential changes to individual facilities within the group of in scope Phase II facilities.

a. In scope Phase II facilities as a group The analysis of the in scope Phase II facilities as a group is largely similar to the market level analysis described in Section B3 3.1 above, except that the base case and policy option totals only include the economic activities of the 531 in scope Phase II facilities represented by the model. In addition, a few measures differ: ( 1) new capacity additions and prices are not relevant at the facility level, ( 2) the number of Phase II facilities that experience closure of all their steam electric capacity is § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis 16 Such short term capacity reductions would not be expressed as changes in available capacity but might affect electricity generation, production costs, and/ or prices.

NODA Version   March 12, 2003 B3 11 presented, and ( 3) repowering changes are not explicitly analyzed at the facility level. Following are the measures evaluated for the group of Phase II facilities:

< ( 1) Changes in available capacity: This measure considers the capacity available at the 531 Phase II facilities. A long term reduction in availability may be the result of the energy penalty associated with the installation of recirculating systems, partial or full plant closures, a change in the decision to repower, or a change in the choice of air pollution control technologies. In the short term, temporary plant shut downs for the installation of Phase II compliance technologies may lead to reductions in available capacity. 16 Under this measure, EPA also analyzed closures. Only capacity that is projected to remain operational in the base case but is closed in the post compliance case is considered a closure as the result of the rule. An option may result in partial ( i. e., unit) or full plant closures. An option may also result in avoided closures if a facility's compliance costs are low relative to other affected facilities. An avoided closure is a unit or plant that would close in the base case but operates in the post compliance case. At the facility level, both the number of full closure facilities and closure capacity are analyzed.

< ( 2) Changes in generation: This measure considers the generation at the 531 Phase II facilities. Long term changes in generation may be the result of a reduction in available capacity ( see discussion above) or the less frequent dispatch of a plant due to higher production cost as a result of the policy option. In the short term, temporary plant shut downs may lead to reductions in generation at some of the 531 Phase II facilities. For some Phase II facilities, Phase II regulation may lead to an increase in generation if their compliance costs are low relative to other affected facilities.

< ( 3) Changes in revenues: This measure considers the revenues realized by the 531 Phase II facilities and includes both energy revenues and capacity revenues ( see definition in section B3 2.4 above). A change in revenues could be the result of a change in generation and/ or the price of electricity. For some modeled 316( b) facilities, Phase II regulation may lead to an increase in revenues if their generation increases as a result of the rule, or if the rule leads to an increase in electricity prices.

< ( 4) Changes in costs: This measure considers changes in the overall cost of generating electricity for the 531 Phase II facilities, including fuel costs, variable and fixed O& M costs, and capital costs. Fuel costs and variable O& M costs are production costs that vary with the level of generation. Fuel costs generally account for the single largest share of production costs. Fixed O& M costs and capital costs do not vary with generation. They are fixed in the short term and therefore do not affect the dispatch decision of a unit ( given sufficient demand, a unit will dispatch as long as the price of electricity is at least equal to its per MWh production costs). However, in the long run, these costs need to be recovered for a unit to remain economically viable.

< ( 5) Changes in pre tax income: Pre tax income is defined as total revenues minus total costs and is an indicator of profitability. Pre tax income may decrease as a result of reductions in revenues and/ or increases in costs.

< ( 6) Changes in variable production costs per MWh: This measure considers the plant level change in the average annual variable production cost per MWh. Variable production costs include fuel costs and other variable O& M costs but exclude fixed O& M costs and capital costs.

b. Individual Phase II facilities To assess potential distributional impacts among individual Phase II facilities, EPA analyzed facility specific changes to a number of key measures. For each measure, EPA determined the number of Phase II facilities that experience an increase or a reduction, respectively, within three ranges: 1 percent or less, 1 to 3 percent, and 3 percent or more. EPA conducted this analysis for the following measures:

< ( 1) Changes in capacity utilization: Capacity utilization is defined as a unit's actual generation divided by its potential generation, if it ran 100 percent of the time ( i. e., generation / ( capacity * 365 days * 24 hours)). This measure indicates how frequently a unit is dispatched and earns energy revenues for its owner.

< ( 2) Changes in generation: See explanation in subsection a. above.

< ( 3) Changes in revenues: See explanation in subsection a. above. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis B3 12 NODA Version   March 12, 2003 < ( 4) Changes in variable production costs per MWh: See explanation in subsection a. above.

< ( 5) Changes in fuel costs per MWh: See explanation in subsection a. above.

< ( 6) Changes in pre tax income: See explanation in subsection a. above.

B3 4 ANALYSIS RESULTS FOR THE PREFERRED OPTION The remainder of this section presents the results of the economic impact analysis of the preferred option for the ten NERC regions modeled by the IPM. The analysis is based on IPM output for the base case ( using EPA electricity demand assumptions) and the preferred option. Results are presented at the market level and the Phase II facility level.

The main analysis in this chapter uses output from model run year 2010. Facilities subject to the preferred option are expected to come into compliance during the year of their first post promulgation permit ( 2005 to 2009). Therefore, 2010 is the first year during which all facilities are in compliance, but no facilities experience technology installation downtimes. 2010 thus represents the post compliance condition of the industry. EPA also analyzed potential market level impacts of the preferred option for a year within the compliance period during which some Phase II facilities experience installation downtimes. This secondary analysis represents potential short term impacts of the preferred option and uses output from model run year 2008.

B3 4.1 Market Analysis for 2010 This section presents the results of the IPM analysis for all facilities modeled by the IPM. The market level analysis includes results for all generators located in each NERC region including facilities that are in scope and facilities that are out of scope of Phase II regulation.

Table B3 4 presents the market level impact measures discussed in section B3 3.1 above: ( 1) capacity changes, including changes in existing capacity, new additions, repowering additions, and closures; ( 2) electricity price changes, including changes in energy prices and capacity prices; ( 3) generation changes; ( 4) revenue changes; ( 5) cost changes, including changes in fuel costs, variable O& M costs, fixed O& M costs, and capital costs; ( 6) changes in pre tax income; and ( 7) changes in variable production costs per MWh. For each measure, the table presents the results for the base case and the preferred option, the absolute difference between the two cases, and the percentage difference.

Table B3 4: Market Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change National Totals ( 1) Total Domestic Capacity ( MW) 887,915 887,933 18 0.0%

( 1a) Existing 787,280 786,500 ( 780) ( 0.1)%

( 1b) New Additions 79,683 79,770 87 0.1%

( 1c) Repowering Additions 20,951 21,662 711 3.4% ( 1d) Closures 14,122 14,556 434 3.1%

( 2a) Energy Prices ($ 2002/ MWh) n/ a n/ a n/ a n/ a ( 2b) Capacity Prices ($ 2002/ KW/ yr) n/ a n/ a n/ a n/ a ( 3) Generation ( GWh) 4,113,839 4,113,898 59 0.0%

( 4) Revenues ( Millions; $ 2002) $ 138,770 $ 138,719 ($ 52) 0.0%

( 5) Costs ( Millions; $ 2002) $ 87,486 $ 87,989 $ 503 0.6%

( 5a) Fuel Cost $ 47,789 $ 47,804 $ 15 0.0%

( 5b) Variable O& M $ 7,926 $ 7,931 $ 6 0.1% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 4: Market Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change NODA Version   March 12, 2003 B3 13 ( 5c) Fixed O& M $ 23,417 $ 23,848 $ 430 1.8%

( 5d) Capital Cost $ 8,354 $ 8,406 $ 52 0.6%

( 6) Pre Tax Income ( Millions; $ 2002) $ 51,284 $ 50,730 ($ 554) ( 1.1)%

( 7) Variable Production Costs ($/ MWh) $ 13.54 $ 13.55 $ 0.00 0.0%

East Central Area Reliability Coordination Agreement ( ECAR)

( 1) Total Domestic Capacity ( MW) 118,529 118,529 0 0.0%

( 1a) Existing 110,066 110,066 0 0.0%

( 1b) New Additions 8,394 8,394 0 0.0%

( 1c) Repowering Additions 70 70 0 0.0% ( 1d) Closures 0 0 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 22.63 $ 22.64 $ 0.01 0.0%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 56.08 $ 56.12 $ 0.04 0.1%

( 3) Generation ( GWh) $ 649,024 $ 647,985 ($ 1,040) ( 0.2)%

( 4) Revenues ( Millions; $ 2002) $ 21,317 $ 21,305 ($ 12) ( 0.1)%

( 5) Costs ( Millions; $ 2002) $ 12,492 $ 12,580 $ 88 0.7%

( 5a) Fuel Cost $ 6,367 $ 6,362 ($ 5) ( 0.1)%

( 5b) Variable O& M $ 1,585 $ 1,585 $ 0 0.0%

( 5c) Fixed O& M $ 3,570 $ 3,664 $ 94 2.6%

( 5d) Capital Cost $ 970 $ 969 ($ 1) ( 0.1)%

( 6) Pre Tax Income ( Millions; $ 2002) $ 8,825 $ 8,725 ($ 100) ( 1.1)%

( 7) Variable Production Costs ($/ MWh) $ 12.25 $ 12.26 $ 0.01 0.1%

Electric Reliability Council of Texas ( ERCOT)

( 1) Total Domestic Capacity ( MW) 75,290 75,290 0 0.0%

( 1a) Existing 71,901 71,728 ( 172) ( 0.2)%

( 1b) New Additions 2,053 1,880 ( 173) ( 8.4)%

( 1c) Repowering Additions 1,336 1,681 345 25.9% ( 1d) Closures 0 0 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 29.38 $ 31.18 $ 1.80 6.1%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 14.09 $ 4.26 ($ 9.83) ( 69.8)%

( 3) Generation ( GWh) 336,956 336,659 ( 297) ( 0.1)%

( 4) Revenues ( Millions; $ 2002) $ 10,961 $ 10,818 ($ 143) ( 1.3)%

( 5) Costs ( Millions; $ 2002) $ 8,000 $ 8,034 $ 34 0.4%

( 5a) Fuel Cost $ 5,241 $ 5,234 ($ 7) ( 0.1)%

( 5b) Variable O& M $ 699 $ 700 $ 1 0.2%

( 5c) Fixed O& M $ 1,730 $ 1,756 $ 25 1.5%

( 5d) Capital Cost $ 330 $ 344 $ 14 4.2%

( 6) Pre Tax Income ( Millions; $ 2002) $ 2,961 $ 2,784 ($ 176) ( 6.0)% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 4: Market Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change B3 14 NODA Version   March 12, 2003 ( 7) Variable Production Costs ($/ MWh) $ 17.63 $ 17.63 $ 0.00 0.0%

Florida Reliability Coordinating Council ( FRCC)

( 1) Total Domestic Capacity ( MW) 50,324 50,324 0 0.0%

( 1a) Existing 39,262 39,267 5 0.0%

( 1b) New Additions 11,062 11,057 ( 5) 0.0%

( 1c) Repowering Additions 0 0 0 0.0% ( 1d) Closures 812 812 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 29.39 $ 29.55 $ 0.16 0.6%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 37.79 $ 36.82 ($ 0.97) ( 2.6)%

( 3) Generation ( GWh) 189,076 188,878 ( 199) ( 0.1)%

( 4) Revenues ( Millions; $ 2002) $ 7,459 $ 7,435 ($ 24) ( 0.3)%

( 5) Costs ( Millions; $ 2002) $ 5,406 $ 5,445 $ 39 0.7%

( 5a) Fuel Cost $ 3,106 $ 3,114 $ 8 0.3%

( 5b) Variable O& M $ 364 $ 365 $ 2 0.4%

( 5c) Fixed O& M $ 1,184 $ 1,219 $ 35 3.0%

( 5d) Capital Cost $ 753 $ 747 ($ 6) ( 0.8)%

( 6) Pre Tax Income ( Millions; $ 2002) $ 2,053 $ 1,990 ($ 63) ( 3.1)%

( 7) Variable Production Costs ($/ MWh) $ 18.35 $ 18.42 $ 0.07 0.4%

Mid Atlantic Area Council ( MAAC)

( 1) Total Domestic Capacity ( MW) 63,784 63,784 0 0.0%

( 1a) Existing 56,355 56,355 0 0.0%

( 1b) New Additions 5,771 5,771 0 0.0%

( 1c) Repowering Additions 1,658 1,658 0 0.0% ( 1d) Closures 2,831 2,831 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 26.74 $ 26.75 $ 0.01 0.0%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 50.61 $ 50.36 ($ 0.25) ( 0.5)%

( 3) Generation ( GWh) 276,051 276,530 480 0.2%

( 4) Revenues ( Millions; $ 2002) $ 10,605 $ 10,605 $ 0 0.0%

( 5) Costs ( Millions; $ 2002) $ 6,124 $ 6,166 $ 41 0.7%

( 5a) Fuel Cost $ 3,066 $ 3,069 $ 2 0.1%

( 5b) Variable O& M $ 557 $ 559 $ 1 0.2%

( 5c) Fixed O& M $ 1,929 $ 1,966 $ 36 1.9%

( 5d) Capital Cost $ 571 $ 573 $ 2 0.3%

( 6) Pre Tax Income ( Millions; $ 2002) $ 4,481 $ 4,439 ($ 41) ( 0.9)%

( 7) Variable Production Costs ($/ MWh) $ 13.13 $ 13.12 ($ 0.01) ( 0.1)%

Mid America Interconnected Network ( MAIN)

( 1) Total Domestic Capacity ( MW) 59,494 59,349 ( 145) ( 0.2)% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 4: Market Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change NODA Version   March 12, 2003 B3 15 ( 1a) Existing 51,551 51,121 ( 430) ( 0.8)%

( 1b) New Additions 7,943 8,228 285 3.6%

( 1c) Repowering Additions 0 0 0 0.0% ( 1d) Closures 5,191 5,625 434 8.4%

( 2a) Energy Prices ($ 2002/ MWh) $ 22.66 $ 22.60 ($ 0.06) ( 0.3)%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 54.31 $ 54.72 $ 0.42 0.8%

( 3) Generation ( GWh) 281,625 281,411 ( 214) ( 0.1)%

( 4) Revenues ( Millions; $ 2002) $ 9,607 $ 9,601 ($ 6) ( 0.1)%

( 5) Costs ( Millions; $ 2002) $ 5,795 $ 5,817 $ 22 0.4%

( 5a) Fuel Cost $ 2,930 $ 2,956 $ 26 0.9%

( 5b) Variable O& M $ 586 $ 584 ($ 2) ( 0.3)%

( 5c) Fixed O& M $ 1,710 $ 1,701 ($ 9) ( 0.5)%

( 5d) Capital Cost $ 569 $ 576 $ 7 1.2%

( 6) Pre Tax Income ( Millions; $ 2002) $ 3,812 $ 3,783 ($ 28) ( 0.7)%

( 7) Variable Production Costs ($/ MWh) $ 12.48 $ 12.58 $ 0.09 0.8%

Mid Continent Area Power Pool ( MAPP)

( 1) Total Domestic Capacity ( MW) 35,835 35,835 0 0.0%

( 1a) Existing 32,672 32,672 0 0.0%

( 1b) New Additions 3,163 3,163 0 0.0%

( 1c) Repowering Additions 0 0 0 0.0% ( 1d) Closures 476 476 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 21.86 $ 21.77 ($ 0.08) ( 0.4)%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 54.00 $ 54.47 $ 0.47 0.9%

( 3) Generation ( GWh) 181,713 181,598 ( 115) ( 0.1)%

( 4) Revenues ( Millions; $ 2002) $ 5,878 $ 5,878 ($ 1) 0.0%

( 5) Costs ( Millions; $ 2002) $ 3,430 $ 3,445 $ 15 0.4%

( 5a) Fuel Cost $ 1,722 $ 1,719 ($ 3) ( 0.2)%

( 5b) Variable O& M $ 381 $ 381 $ 0 0.0%

( 5c) Fixed O& M $ 1,017 $ 1,034 $ 18 1.7%

( 5d) Capital Cost $ 311 $ 311 $ 0 0.0%

( 6) Pre Tax Income ( Millions; $ 2002) $ 2,448 $ 2,433 ($ 16) ( 0.6)%

( 7) Variable Production Costs ($/ MWh) $ 11.57 $ 11.56 ($ 0.01) ( 0.1)%

Northeast Power Coordinating Council ( NPCC)

( 1) Total Domestic Capacity ( MW) 72,477 72,465 ( 12) 0.0%

( 1a) Existing 59,515 59,371 ( 143) ( 0.2)%

( 1b) New Additions 2,082 1,926 ( 155) ( 7.5)%

( 1c) Repowering Additions 10,881 11,168 287 2.6% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 4: Market Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change B3 16 NODA Version   March 12, 2003 ( 1d) Closures 4,107 4,107 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 29.88 $ 30.16 $ 0.28 0.9%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 43.23 $ 43.30 $ 0.06 0.2%

( 3) Generation ( GWh) 278,649 278,809 160 0.1%

( 4) Revenues ( Millions; $ 2002) $ 11,220 $ 11,305 $ 85 0.8%

( 5) Costs ( Millions; $ 2002) $ 7,732 $ 7,790 $ 57 0.7%

( 5a) Fuel Cost $ 4,479 $ 4,467 ($ 12) ( 0.3)%

( 5b) Variable O& M $ 376 $ 373 ($ 3) ( 0.7)%

( 5c) Fixed O& M $ 1,781 $ 1,846 $ 65 3.6%

( 5d) Capital Cost $ 1,096 $ 1,104 $ 7 0.7%

( 6) Pre Tax Income ( Millions; $ 2002) $ 3,488 $ 3,515 $ 28 0.8%

( 7) Variable Production Costs ($/ MWh) $ 17.42 $ 17.36 ($ 0.06) ( 0.4)%

Southeastern Electric Reliability Council ( SERC)

( 1) Total Domestic Capacity ( MW) 194,485 194,528 42 0.0%

( 1a) Existing 164,544 164,544 0 0.0%

( 1b) New Additions 29,941 29,983 42 0.1%

( 1c) Repowering Additions 0 0 0 0.0% ( 1d) Closures 0 0 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 24.64 $ 24.64 $ 0.00 0.0%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 48.23 $ 48.31 $ 0.09 0.2%

( 3) Generation ( GWh) 944,631 945,455 825 0.1%

( 4) Revenues ( Millions; $ 2002) $ 32,644 $ 32,678 $ 34 0.1%

( 5) Costs ( Millions; $ 2002) $ 19,753 $ 19,854 $ 101 0.5%

( 5a) Fuel Cost $ 10,314 $ 10,314 ($ 1) 0.0%

( 5b) Variable O& M $ 1,785 $ 1,789 $ 4 0.2%

( 5c) Fixed O& M $ 5,264 $ 5,344 $ 80 1.5%

( 5d) Capital Cost $ 2,389 $ 2,407 $ 19 0.8%

( 6) Pre Tax Income ( Millions; $ 2002) $ 12,891 $ 12,824 ($ 68) ( 0.5)%

( 7) Variable Production Costs ($/ MWh) $ 12.81 $ 12.80 ($ 0.01) ( 0.1)%

Southwest Power Pool ( SPP)

( 1) Total Domestic Capacity ( MW) 49,948 50,092 144 0.3%

( 1a) Existing 48,956 48,901 ( 55) ( 0.1)%

( 1b) New Additions 992 1,081 89 8.9%

( 1c) Repowering Additions 0 111 111 0.0% ( 1d) Closures 0 0 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 24.34 $ 24.30 ($ 0.04) ( 0.2)%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 40.97 $ 41.20 $ 0.23 0.6% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 4: Market Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change NODA Version   March 12, 2003 B3 17 ( 3) Generation ( GWh) 221,527 221,961 435 0.2%

( 4) Revenues ( Millions; $ 2002) $ 7,434 $ 7,453 $ 18 0.2%

( 5) Costs ( Millions; $ 2002) $ 4,254 $ 4,285 $ 31 0.7%

( 5a) Fuel Cost $ 2,701 $ 2,704 $ 3 0.1%

( 5b) Variable O& M $ 422 $ 422 $ 0 ( 0.1)%

( 5c) Fixed O& M $ 1,042 $ 1,057 $ 15 1.5%

( 5d) Capital Cost $ 88 $ 101 $ 13 14.8%

( 6) Pre Tax Income ( Millions; $ 2002) $ 3,181 $ 3,168 ($ 13) ( 0.4)%

( 7) Variable Production Costs ($/ MWh) $ 14.10 $ 14.09 ($ 0.01) ( 0.1)%

Western Systems Coordinating Council ( WSCC)

( 1) Total Domestic Capacity ( MW) 167,748 167,737 ( 11) 0.0%

( 1a) Existing 152,459 152,475 16 0.0%

( 1b) New Additions 8,283 8,288 5 0.1%

( 1c) Repowering Additions 7,006 6,974 ( 32) ( 0.5)% ( 1d) Closures 705 705 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 27.19 $ 27.18 ($ 0.01) 0.0%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 7.56 $ 7.58 $ 0.02 0.2%

( 3) Generation ( GWh) 754,587 754,611 24 0.0%

( 4) Revenues ( Millions; $ 2002) $ 21,645 $ 21,643 ($ 3) 0.0%

( 5) Costs ( Millions; $ 2002) $ 14,499 $ 14,574 $ 75 0.5%

( 5a) Fuel Cost $ 7,863 $ 7,865 $ 2 0.0%

( 5b) Variable O& M $ 1,171 $ 1,173 $ 2 0.2%

( 5c) Fixed O& M $ 4,189 $ 4,261 $ 72 1.7%

( 5d) Capital Cost $ 1,277 $ 1,275 ($ 2) ( 0.1)%

( 6) Pre Tax Income ( Millions; $ 2002) $ 7,146 $ 7,069 ($ 77) ( 1.1)%

( 7) Variable Production Costs ($/ MWh) $ 11.97 $ 11.98 $ 0.01 0.0%

Source: IPM analysis: Model runs for Section 316( b) NODA Base Case ( EPA electricity demand) and the preferred option.

Summary of Market Results at the National Level. The results presented in Table B3 4 show that capacity closures would increase by 434 MW, which represents less than 0.1 percent of total baseline capacity. An increase in new capacity additions ( 87 MW) and repowering additions ( 711 MW) would make up for this loss. Total costs of electricity generation would increase by 0.6 percent, largely because of a 1.8 percent increase in fixed O& M costs ( which includes charges for capital costs of compliance). Pre tax income would decrease by 1.1 percent. The preferred option would not lead to changes in total domestic capacity, net generation, or revenues.

Summary of Market Results at the Regional Level. At the regional level, the preferred option would result in the following changes: < ECAR, MAAC, MAPP, SERC, and WSCC, would experience increases in fixed O& M costs, driven by the capital costs of compliance with the preferred option, but overall cost increases in each region would be less than 1.0 percent. Pre tax income in these regions would decrease by between 0.5 and 1.1 percent. All other measures would change by less than 1.0 percent. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis B3 18 NODA Version   March 12, 2003 < FRCC would experience a 2.6 percent reduction in capacity prices. Revenues in FRCC would decrease by 0.3 percent and costs would increase by 0.7 percent ( largely due to an increase in fixed O& M costs of 3.0 percent), leading to a reduction in pre tax income of 3.1 percent. All other measures would change by less than 1.0 percent. < NPCC and SPP would experience changes in capacity additions from repowering and the construction of new capacity. However, these changes would represent less than 0.5 percent of overall capacity in the two regions. Similar to ECAR, MAAC, MAPP, SERC, and WSCC, these two regions would experience increases in fixed O& M costs. However, the overall effect in NPCC would be an increase in pre tax income, as revenues rise more than costs. In SPP, the decrease in pre tax income would be 0.4 percent. < MAIN is the only region that would experience an increase in post compliance capacity retirements. Most of the 434 MW increase in closures ( 0.7 percent of baseline capacity) is due to a nuclear facility that reached the end of its nuclear operating license. In the base case, this facility would have extended its license and continued operation until 2020. Under the preferred option, however, this facility is modeled to retire by 2008. An increase in new capacity additions of 285 MW would offset much of this retirement loss. MAIN would also experience an 0.8 percent increase in variable production cost per MWh, the highest increase in any region. This increase is partially due to the incremental loss of nuclear capacity, which has lower production costs than most other plant types. < ERCOT is projected to experience the most notable changes in electricity prices and new capacity among the ten NERC regions. Repowering additions would increase by 345 MW ( 0.5 percent of baseline capacity) under the preferred option. Repowering in the IPM is modeled as a conversion of one MW of existing coal or oil and gas steam capacity into two MW of combined cycle capacity. As such, repowering in ERCOT under the preferred option consists of the conversion of 172 MW of existing capacity into 345 MW of new repowered capacity. Since total capacity in ERCOT remains constant, this 173 MW net increase in capacity is offset by a 173 MW decrease in new capacity additions. Postcompliance energy prices are expected to increase by 6.1 percent. This increase is largely driven by relatively low profit margins in the region. ERCOT also experiences the largest reduction in capacity prices with almost 70 percent. This is partially due to the increase in energy prices, which allows facilities to bid their undispatched capacity at a lower price. Revenues and pre tax income in ERCOT would fall by 1.3 percent and 6.0 percent, respectively, the highest in any NERC region.

B3 4.2 Analysis of Phase II Facilities for 2010 This section presents the results of the IPM analysis for the Phase II facilities that are modeled by the IPM. Ten of the 531 Phase II facilities are closures in the base case, and 11 facilities are closures under the preferred option. These facilities are not represented in the results described in this section.

EPA used the IPM results from model run year 2010 to analyze impacts on Phase II facilities at two levels: ( 1) potential changes in the economic and operational characteristics of the in scope Phase II facilities as a group and ( 2) potential changes to individual facilities within the group of in scope Phase II facilities.

a. In scope Phase II facilities as a group This section presents the analysis of the potential impacts of the preferred option on the in scope Phase II facilities as a group. This analysis is similar to the market level analysis described above but is limited to facilities subject to the requirements of the section 316( b) rule. Table B3 5 presents the impact measures for the group of Phase II facilities discussed in section B3 3.2 above: ( 1) capacity changes, including changes in the number and capacity of closure facilities; ( 2) generation changes; ( 3) revenue changes; ( 4) cost changes, including changes in fuel costs, variable O& M costs, fixed O& M costs, and capital costs; ( 5) changes in pre tax income; and ( 6) changes in variable production costs per MWh of generation, where variable production cost is defined as the sum of fuel cost and variable O& M cost. For each measure, the table presents the results for the base case and the preferred option, the absolute difference between the two cases, and the percentage difference.

Table B3 5: Facility Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change National Totals ( 1) Total Domestic Capacity ( MW) 430,840 429,668 ( 1,172) ( 0.3)%

( 1a) Closures  Number of Facilities 10 11 1 10.0%

( 1b) Closures  Capacity ( MW) 13,151 13,585 434 3.3% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 5: Facility Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change NODA Version   March 12, 2003 B3 19 ( 2) Generation ( GWh) 2,299,197 2,280,130 ( 19,066) ( 0.8)%

( 3) Revenues ( Millions; $ 2002) $ 75,628 $ 74,960 ($ 668) ( 0.9)%

( 4) Costs ( Millions; $ 2002) $ 47,820 $ 47,705 ($ 115) ( 0.2)%

( 4a) Fuel Cost $ 25,242 $ 24,869 ($ 373) ( 1.5)%

( 4b) Variable O& M $ 5,092 $ 5,072 ($ 20) ( 0.4)%

( 4c) Fixed O& M $ 14,950 $ 15,363 $ 413 2.8%

( 4d) Capital Cost $ 2,537 $ 2,402 ($ 135) ( 5.3)%

( 5) Pre Tax Income ( Millions; $ 2002) $ 27,808 $ 27,255 ($ 553) ( 2.0)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 13.19 $ 13.13 ($ 0.06) ( 0.5)%

East Central Area Reliability Coordination Agreement ( ECAR)

( 1) Total Domestic Capacity ( MW) 82,313 82,313 0 0.0%

( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 1 1 0 0.0%

( 2) Generation ( GWh) 517,126 516,503 ( 622) ( 0.1)%

( 3) Revenues ( Millions; $ 2002) $ 16,237 $ 16,230 ($ 8) 0.0%

( 4) Costs ( Millions; $ 2002) $ 9,586 $ 9,671 $ 84 0.9%

( 4a) Fuel Cost $ 5,036 $ 5,027 ($ 9) ( 0.2)%

( 4b) Variable O& M $ 1,248 $ 1,249 $ 1 0.1%

( 4c) Fixed O& M $ 2,961 $ 3,054 $ 94 3.2%

( 4d) Capital Cost $ 342 $ 340 ($ 1) ( 0.4)%

( 5) Pre Tax Income ( Millions; $ 2002) $ 6,651 $ 6,559 ($ 92) ( 1.4)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.15 $ 12.15 $ 0.00 0.0%

Electric Reliability Council of Texas ( ERCOT)

( 1) Total Domestic Capacity ( MW) 43,522 43,412 ( 110) ( 0.3)%

( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 0 0 0 0.0%

( 2) Generation ( GWh) 158,462 155,729 ( 2,733) ( 1.7)%

( 3) Revenues ( Millions; $ 2002) $ 5,365 $ 5,153 ($ 211) ( 3.9)%

( 4) Costs ( Millions; $ 2002) $ 3,910 $ 3,859 ($ 51) ( 1.3)%

( 4a) Fuel Cost $ 2,203 $ 2,143 ($ 60) ( 2.7)%

( 4b) Variable O& M $ 426 $ 423 ($ 3) ( 0.8)%

( 4c) Fixed O& M $ 1,181 $ 1,206 $ 24 2.1%

( 4d) Capital Cost $ 99 $ 87 ($ 12) ( 12.2)%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,455 $ 1,294 ($ 160) ( 11.0)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 16.59 $ 16.48 ($ 0.12) ( 0.7)%

Florida Reliability Coordinating Council ( FRCC)

( 1) Total Domestic Capacity ( MW) 27,537 27,542 5 0.0% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 5: Facility Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change B3 20 NODA Version   March 12, 2003 ( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 812 812 0 0.0%

( 2) Generation ( GWh) 82,259 81,638 ( 621) ( 0.8)%

( 3) Revenues ( Millions; $ 2002) $ 3,433 $ 3,398 ($ 35) ( 1.0)%

( 4) Costs ( Millions; $ 2002) $ 2,021 $ 2,044 $ 23 1.2%

( 4a) Fuel Cost $ 1,154 $ 1,148 ($ 6) ( 0.5)%

( 4b) Variable O& M $ 188 $ 187 $ 0 ( 0.2)%

( 4c) Fixed O& M $ 673 $ 708 $ 35 5.2%

( 4d) Capital Cost $ 5 $ 0 ($ 5) ( 100.0)%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,412 $ 1,354 ($ 58) ( 4.1)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 16.31 $ 16.36 $ 0.05 0.3%

Mid Atlantic Area Council ( MAAC)

( 1) Total Domestic Capacity ( MW) 33,590 33,590 0 0.0%

( 1a) Closures  Number of Facilities 2 2 0 0.0%

( 1b) Closures  Capacity ( MW) 2,831 2,831 0 0.0%

( 2) Generation ( GWh) 167,239 167,643 403 0.2%

( 3) Revenues ( Millions; $ 2002) $ 6,151 $ 6,155 $ 4 0.1%

( 4) Costs ( Millions; $ 2002) $ 3,469 $ 3,509 $ 41 1.2%

( 4a) Fuel Cost $ 1,662 $ 1,666 $ 4 0.2%

( 4b) Variable O& M $ 341 $ 342 $ 1 0.3%

( 4c) Fixed O& M $ 1,359 $ 1,395 $ 36 2.6%

( 4d) Capital Cost $ 106 $ 106 $ 0 0.0%

( 5) Pre Tax Income ( Millions; $ 2002) $ 2,683 $ 2,646 ($ 37) ( 1.4)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.98 $ 11.98 $ 0.00 0.0%

Mid America Interconnected Network ( MAIN)

( 1) Total Domestic Capacity ( MW) 35,373 34,943 ( 431) ( 1.2)%

( 1a) Closures  Number of Facilities 2 3 1 50.0%

( 1b) Closures  Capacity ( MW) 4,698 5,132 434 9.2%

( 2) Generation ( GWh) 217,225 214,778 ( 2,447) ( 1.1)%

( 3) Revenues ( Millions; $ 2002) $ 6,748 $ 6,671 ($ 77) ( 1.1)%

( 4) Costs ( Millions; $ 2002) $ 4,050 $ 4,000 ($ 50) ( 1.2)%

( 4a) Fuel Cost $ 2,066 $ 2,055 ($ 11) ( 0.5)%

( 4b) Variable O& M $ 489 $ 485 ($ 4) ( 0.9)%

( 4c) Fixed O& M $ 1,390 $ 1,376 ($ 14) ( 1.0)%

( 4d) Capital Cost $ 106 $ 86 ($ 20) ( 19.0)%

( 5) Pre Tax Income ( Millions; $ 2002) $ 2,697 $ 2,670 ($ 27) ( 1.0)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.76 $ 11.82 $ 0.06 0.5% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 5: Facility Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change NODA Version   March 12, 2003 B3 21 Mid Continent Area Power Pool ( MAPP)

( 1) Total Domestic Capacity ( MW) 15,727 15,727 0 0.0%

( 1a) Closures  Number of Facilities 1 1 0 0.0%

( 1b) Closures  Capacity ( MW) 476 476 0 0.0%

( 2) Generation ( GWh) 108,584 108,584 0 0.0%

( 3) Revenues ( Millions; $ 2002) $ 3,177 $ 3,175 ($ 1) 0.0%

( 4) Costs ( Millions; $ 2002) $ 1,977 $ 1,995 $ 18 0.9%

( 4a) Fuel Cost $ 1,044 $ 1,044 $ 0 0.0%

( 4b) Variable O& M $ 222 $ 223 $ 0 0.1%

( 4c) Fixed O& M $ 597 $ 614 $ 18 2.9%

( 4d) Capital Cost $ 114 $ 114 $ 0 0.0%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,199 $ 1,180 ($ 19) ( 1.6)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.67 $ 11.67 $ 0.00 0.0%

Northeast Power Coordinating Council ( NPCC)

( 1) Total Domestic Capacity ( MW) 37,651 37,484 ( 167) ( 0.4)%

( 1a) Closures  Number of Facilities 4 4 0 0.0%

( 1b) Closures  Capacity ( MW) 4,107 4,107 0 0.0%

( 2) Generation ( GWh) 165,601 161,753 ( 3,848) ( 2.3)%

( 3) Revenues ( Millions; $ 2002) $ 6,503 $ 6,420 ($ 83) ( 1.3)%

( 4) Costs ( Millions; $ 2002) $ 5,114 $ 5,042 ($ 72) ( 1.4)%

( 4a) Fuel Cost $ 2,756 $ 2,652 ($ 104) ( 3.8)%

( 4b) Variable O& M $ 276 $ 269 ($ 7) ( 2.6)%

( 4c) Fixed O& M $ 1,242 $ 1,307 $ 65 5.2%

( 4d) Capital Cost $ 840 $ 815 ($ 25) ( 3.0)%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,389 $ 1,378 ($ 11) ( 0.8)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 18.31 $ 18.05 ($ 0.26) ( 1.4)%

Southeastern Electric Reliability Council ( SERC)

( 1) Total Domestic Capacity ( MW) 107,450 107,450 0 0.0%

( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 0 0 0 0.0%

( 2) Generation ( GWh) 639,276 638,076 ( 1,200) ( 0.2)%

( 3) Revenues ( Millions; $ 2002) $ 20,645 $ 20,624 ($ 21) ( 0.1)%

( 4) Costs ( Millions; $ 2002) $ 12,038 $ 12,081 $ 43 0.4%

( 4a) Fuel Cost $ 6,137 $ 6,105 ($ 31) ( 0.5)%

( 4b) Variable O& M $ 1,365 $ 1,366 $ 1 0.1%

( 4c) Fixed O& M $ 3,986 $ 4,060 $ 74 1.9%

( 4d) Capital Cost $ 550 $ 549 ($ 1) ( 0.2)% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 5: Facility Level Impacts of the Preferred Option ( NERC Regions; 2010)

Economic Measures Base Case Preferred Option Difference % Change B3 22 NODA Version   March 12, 2003 ( 5) Pre Tax Income ( Millions; $ 2002) $ 8,607 $ 8,543 ($ 64) ( 0.7)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.73 $ 11.71 ($ 0.03) ( 0.2)%

Southwest Power Pool ( SPP)

( 1) Total Domestic Capacity ( MW) 20,471 20,471 0 0.0%

( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 0 0 0 0.0%

( 2) Generation ( GWh) 109,901 109,194 ( 707) ( 0.6)%

( 3) Revenues ( Millions; $ 2002) $ 3,419 $ 3,401 ($ 17) ( 0.5)%

( 4) Costs ( Millions; $ 2002) $ 1,962 $ 1,959 ($ 2) ( 0.1)%

( 4a) Fuel Cost $ 1,148 $ 1,135 ($ 13) ( 1.2)%

( 4b) Variable O& M $ 248 $ 247 ($ 1) ( 0.6)%

( 4c) Fixed O& M $ 557 $ 570 $ 13 2.4%

( 4d) Capital Cost $ 8 $ 7 ($ 1) ( 13.4)%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,457 $ 1,442 ($ 15) ( 1.0)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.71 $ 12.65 ($ 0.05) ( 0.4)%

Western Systems Coordinating Council ( WSCC)

( 1) Total Domestic Capacity ( MW) 27,206 26,736 ( 470) ( 1.7)%

( 1a) Closures  Number of Facilities 1 1 0 0.0%

( 1b) Closures  Capacity ( MW) 226 226 0 0.0%

( 2) Generation ( GWh) 133,524 126,232 ( 7,293) ( 5.5)%

( 3) Revenues ( Millions; $ 2002) $ 3,952 $ 3,733 ($ 219) ( 5.5)%

( 4) Costs ( Millions; $ 2002) $ 3,694 $ 3,545 ($ 149) ( 4.0)%

( 4a) Fuel Cost $ 2,034 $ 1,893 ($ 141) ( 6.9)%

( 4b) Variable O& M $ 289 $ 282 ($ 7) ( 2.4)%

( 4c) Fixed O& M $ 1,004 $ 1,072 $ 68 6.8%

( 4d) Capital Cost $ 367 $ 298 ($ 69) ( 18.8)%

( 5) Pre Tax Income ( Millions; $ 2002) $ 258 $ 188 ($ 70) ( 27.0)%

( 6) Variable Production Costs ($ 2002/ MWh) $ 17.40 $ 17.23 ($ 0.17) ( 1.0)%

Source: IPM analysis: Model runs for Section 316( b) NODA Base Case ( EPA electricity demand) and the preferred option.

Comparison of Results for Phase II Facilities and the Market. The IPM results for the in scope Phase II facilities as a group ( presented in Table B3 5) are similar to the results at the market level ( presented in Table B3 4). On a percentage basis, the group of Phase II facilities generally experiences higher losses in generation, revenues, and pre tax income compared to the overall market. This is not surprising as in scope facilities become relatively less competitive compared to facilities not in scope of Phase II regulation and are therefore likely to lose some market share as a result of the preferred option. Total closure capacity among the Phase II facilities is the same as at the market level but represents a higher percentage of total base case capacity ( 0.1 percent at the national level). Fixed O& M costs of the group of Phase II facilities increase relatively more than at the market level because fixed O& M costs include the capital costs of compliance with Phase II regulatory options. In many regions, however, the other cost accounts decrease for the Phase II facilities because of the reduction in generation. On a per MWh basis, variable production costs also decrease in many regions because the higher § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis NODA Version   March 12, 2003 B3 23 cost units generate less electricity under the preferred option compared to the base case, reducing the overall average cost of generation.

Summary of Phase II Facility Results at the National Level. Table B3 5 shows that the preferred option would lead to the closure of one additional Phase II facility ( which accounts for approximately 0.1 percent of baseline Phase II capacity) thus increasing capacity closures by 434 MW. Total Phase II capacity would decrease by 1,172 MW, due to the capacity closure and several facilities that were projected to repower in the base case but do not under the preferred option. As a result, generation, revenues, and overall costs would decrease but by less than one percent. Pre tax income for the group of Phase II facilities would decrease by 2.0 percent.

Summary of Phase II Facility Results at the Regional Level. Results for the preferred option vary somewhat by region. For many regions, impacts follow the general pattern described in the comparison to the market level above: generation, revenues, and pre tax income decrease. Overall costs decrease in many regions due to lower levels of generation but increase in other regions, where the additional compliance costs outweigh the reduction in generation. The preferred option would result in the following changes: < ECAR, MAAC, MAPP, SERC and SPP, would experience reductions in pre tax income of between 0.7 and 1.6 percent. The changes in most other measures are less than 1.0 percent in these regions. < MAIN is the only region that would experience an incremental closure of a Phase II facility under the preferred option. This closure is responsible for the reduction in Phase II capacity in the region and would contribute to a decrease in Phase II post compliance generation and revenues ( see also discussion in Section B3 4.1 above). Total costs would also decrease, but variable production cost per MWh would increase because the projected incremental closure affects nuclear capacity which has lower production costs than most other plant types. < WSCC would experience the largest reduction in Phase II capacity, losing 470 MW, or 1.7 percent of base case capacity under the preferred option. This change is not the result of plant closures but is due to less Phase II capacity being repowered in the post compliance scenario. Phase II facilities in WSCC also experience reductions in generation and revenues of 5.5 percent because they bear a relatively high compliance cost per MW of capacity under the preferred option ( the highest of any of the 10 NERC regions). In addition, only a small percentage of total capacity in WSCC ( 27,200 MW out of 167,750 MW, or 16 percent) is subject to Phase II regulation. As a result, facilities not subject to Phase II regulation become relatively more competitive and assume some of the generation lost by Phase II facilities. Overall, costs for the group of Phase II facilities decrease. Fixed O& M costs, which include Phase II compliance costs, increase but fuel costs and variable O& M costs decrease because of the reduction in generation. However, the reduction in revenues outweighs the reduction in costs, leading to an overall reduction in pre tax income of 27 percent ($ 70 million), the highest reduction in any region. This relatively high percentage reduction is partially due to the low profit margins of Phase II facilities in WSCC in the base case. < Phase II facilities in ERCOT would experience reductions in generation ( 1.7 percent), revenues ( 3.9 percent), and pretax income ( 11.0 percent). Revenues decrease by a larger percentage than generation due to the large drop in capacity prices ( see Table B3 4). < Phase II facilities in NPCC would experience the largest reduction in generation ( 2.3 percent) of any region. However, revenues only decrease by 1.3 percent because of increases in both energy and capacity prices ( see Table B3 4). NPCC would also experience the second largest increase in fixed O& M costs ( 5.2 percent) as a result of bearing relatively high compliance cost per MW of capacity under the preferred option ( the second highest of any of the 10 NERC regions). < Phase II facilities in FRCC would experience an increase in total costs of 1.2 percent under the preferred option. Combined with a reduction in revenues of 1.0 percent, this would reduce pre tax income for Phase II facilities in FRCC by 4.1 percent.

b. Individual Phase II facilities In addition to effects of the preferred option on the in scope Phase II facilities as a group, there may be shifts in economic performance among individual facilities subject to Phase II regulation. To assess such potential shifts, EPA analyzed facilityspecific changes in ( 1) capacity utilization ( defined as generation divided by capacity multiplied by the number of hours per year   8,760); ( 2) generation; ( 3) revenues; ( 4) variable production costs per MWh of generation ( defined as variable O& M cost plus fuel cost divided by generation); ( 5) fuel cost per MWh of generation; and ( 6) pre tax income. For each measure, EPA determined the number of Phase II facilities that experience no changes, or an increase or a reduction within three ranges: 1 percent or less, 1 to 3 percent, and 3 percent or more.

Table B3 6 presents the total number of Phase II facilities with different degrees of change in each of these measures. This table excludes 18 facilities with significant status changes including ( 10 facilities are baseline closures, one facility is a policy closure, and seven facilities that changed repowering decisions between the base case and policy case). These facilities are § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis B3 24 NODA Version   March 12, 2003 either not operating at all in the base case or the post compliance case, or they experience fundamental changes in the type of units they operate; therefore, the measures presented below would not be meaningful for these facilities. In addition, the changes in production cost per MWh and fuel cost per MWh could not be developed for 57 facilities with zero generation in either the base case or post compliance scenario. For these facilities, the change in production cost per MWh and fuel cost per MWh is indicated as " n/ a."

Table B3 6: Number of Individual Phase II Facilities with Operational Changes ( 2010)

Economic Measures Reduction Increase No Change N/ A </= 1% 1 3% > 3% </= 1% 1 3% > 3%

( 1) Change in Capacity Utilization 9 15 24 9 6 9 441

( 2) Change in Generation 7 1 44 10 3 17 431

( 3) Change in Revenues 80 27 42 100 22 15 227

( 4) Change in Variable Production Costs/ MWh 33 13 9 140 13 14 234 57 ( 5) Change in Fuel Costs 16 11 9 24 11 10 375 57 ( 6) Change in Pre Tax Income 105 113 199 22 13 37 24

a For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a percent. b The change in capacity utilization is the difference between the capacity utilization percentages in the base case and postcompliance case. For all other measures, the change is expressed as the percentage change between the base case and postcompliance values.

Source: IPM analysis: Model runs for Section 316( b) NODA Base Case ( EIA electricity demand) and the preferred option.

Table B3 6 indicates that the majority of Phase II facilities would not experience changes in capacity utilization, generation, or fuel costs per MWh due to compliance with the preferred option. Of those facilities with changes in post compliance capacity utilization and generation, most would experience decreases in these measures. The majority of facilities with changes in post compliance variable production costs per MWh would experience increases. However, more than 80 percent of those increases would not exceed 1.0 percent. Changes in revenues at most Phase II facilities would also not exceed 1.0 percent. The largest effect of the preferred option would be on facilities' pre tax income: over 80 percent of facilities would experience a reduction in pre tax income, with almost 40 percent experiencing a reduction of 3.0 percent or greater. These reductions are due to a combination of reduced revenues and increased compliance costs.

B3 4.3 Market Analysis for 2008 This section presents market level results for the preferred option for model run year 2008. Unlike the market level analysis for 2010 described above, model run year 2008 includes facilities that experience a one time downtime due to the installation of Phase II compliance technologies. This analysis therefore presents potential short term effects that may occur during the five year period ( 2005 to 2009) represented by model run year 2008. However, it should be noted that not all facilities are in compliance by 2008. Therefore, potential effects of installation downtimes may be mitigated by the fact that some facilities will not incur compliance costs until after 2008.

Table B3 7 below presents the following market level impacts for 2008: ( 1) electricity price changes, including changes in energy prices and capacity prices; ( 2) generation changes; ( 3) revenue changes; ( 4) cost changes, including changes in fuel costs, variable O& M costs, fixed O& M costs, and capital costs; ( 5) changes in pre tax income; and ( 6) changes in variable production costs per MWh. For each measure, the table presents the 2008 results for the base case and the preferred option, the absolute difference between the two cases, and the percentage difference. The table also repeats the percentage difference based on the market level analysis for 2010 presented in Table B3 4 above. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis NODA Version   March 12, 2003 B3 25 Table B3 7: Market Level Impacts of the Preferred Option ( NERC 2008 and 2010)

Economic Measures Base Case Preferred Option Difference % Change % Change 2010 National Totals ( 1a) Energy Price ($ 2002/ MWh) n/ a n/ a n/ a n/ a n/ a ( 1b) Capacity Price ($ 2002/ KW) n/ a n/ a n/ a n/ a n/ a ( 2) Total Generation ( GWh) 4,060,238 4,060,277 39 0.0% 0.0%

( 3) Total Revenues ( Millions; $ 2002) $ 154,018 $ 153,993 ($ 24) 0.0% 0.0%

( 4) Costs ( Millions; $ 2002) $ 86,389 $ 86,901 $ 513 0.6% 0.6%

( 4a) Fuel Cost $ 48,097 $ 48,172 $ 75 0.2% 0.0%

( 4b) Variable O& M $ 7,828 $ 7,828 ($ 1) 0.0% 0.1%

( 4c) Fixed O& M $ 23,643 $ 23,995 $ 352 1.5% 1.8%

( 4d) Capital Cost $ 6,821 $ 6,907 $ 86 1.3% 0.6%

( 5) Pre Tax Income ( Millions; $ 2002) $ 67,629 $ 67,092 ($ 537)  0.8%  1.1%

( 6) Variable Production Costs ($ 2002/ MWh) $ 13.77 $ 13.79 $ 0.02 0.1% 0.0%

East Central Area Reliability Coordination Agreement ( ECAR)

( 1a) Energy Price ($ 2002/ MWh) $ 22.66 $ 22.93 $ 0.26 1.2% 0.0%

( 1b) Capacity Price ($ 2002/ KW) $ 78.35 $ 78.14 ($ 0.21)  0.3% 0.1%

( 2) Total Generation ( GWh) 649,365 647,670 ( 1,695)  0.3%  0.2%

( 3) Total Revenues ( Millions; $ 2002) $ 23,972 $ 24,079 $ 107 0.4%  0.1%

( 4) Costs ( Millions; $ 2002) $ 12,731 $ 12,783 $ 53 0.4% 0.7%

( 4a) Fuel Cost $ 6,619 $ 6,587 ($ 31)  0.5%  0.1%

( 4b) Variable O& M $ 1,579 $ 1,578 ($ 1) 0.0% 0.0%

( 4c) Fixed O& M $ 3,569 $ 3,655 $ 86 2.4% 2.6%

( 4d) Capital Cost $ 964 $ 963 ($ 1)  0.1%  0.1%

( 5) Pre Tax Income ( Millions; $ 2002) $ 11,241 $ 11,296 $ 55 0.5%  1.1%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.62 $ 12.61 ($ 0.02)  0.1% 0.1%

Electric Reliability Council of Texas ( ERCOT)

( 1a) Energy Price ($ 2002/ MWh) $ 29.98 $ 30.08 $ 0.10 0.3% 6.1 ( 1b) Capacity Price ($ 2002/ KW) $ 0.00 $ 0.00 $ 0.00 0.0%  69.8 ( 2) Total Generation ( GWh) 325,835 325,835 0 0.0%  0.1 ( 3) Total Revenues ( Millions; $ 2002) $ 9,768 $ 9,802 $ 33 0.3%  1.3%

( 4) Costs ( Millions; $ 2002) $ 7,728 $ 7,765 $ 37 0.5% 0.4%

( 4a) Fuel Cost $ 5,211 $ 5,206 ($ 6)  0.1%  0.1%

( 4b) Variable O& M $ 673 $ 672 ($ 1)  0.2% 0.2%

( 4c) Fixed O& M $ 1,696 $ 1,713 $ 17 1.0% 1.5%

( 4d) Capital Cost $ 148 $ 174 $ 26 17.8% 4.2%

( 5) Pre Tax Income ( Millions; $ 2002) $ 2,040 $ 2,037 ($ 4)  0.2%  6.0% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 7: Market Level Impacts of the Preferred Option ( NERC 2008 and 2010)

Economic Measures Base Case Preferred Option Difference % Change % Change 2010 B3 26 NODA Version   March 12, 2003 ( 6) Variable Production Costs ($ 2002/ MWh) $ 18.06 $ 18.04 ($ 0.02)  0.1% 0.0%

Florida Reliability Coordinating Council ( FRCC)

( 1a) Energy Price ($ 2002/ MWh) $ 30.18 $ 30.38 $ 0.19 0.6% 0.6%

( 1b) Capacity Price ($ 2002/ KW) $ 63.07 $ 62.64 ($ 0.43)  0.7%  2.6%

( 2) Total Generation ( GWh) $ 186,234 $ 186,467 $ 233 0.1%  0.1%

( 3) Total Revenues ( Millions; $ 2002) $ 8,719 $ 8,741 $ 22 0.3%  0.3%

( 4) Costs ( Millions; $ 2002) $ 5,349 $ 5,389 $ 39 0.7% 0.7%

( 4a) Fuel Cost $ 3,129 $ 3,151 $ 23 0.7% 0.3%

( 4b) Variable O& M $ 354 $ 355 $ 1 0.4% 0.4%

( 4c) Fixed O& M $ 1,172 $ 1,193 $ 21 1.8% 3.0%

( 4d) Capital Cost $ 694 $ 688 ($ 6)  0.8%  0.8%

( 5) Pre Tax Income ( Millions; $ 2002) $ 3,370 $ 3,352 ($ 17)  0.5%  3.1%

( 6) Variable Production Costs ($ 2002/ MWh) $ 18.70 $ 18.81 $ 0.11 0.6% 0.4%

Mid Atlantic Area Council ( MAAC)

( 1a) Energy Price ($ 2002/ MWh) $ 26.82 $ 27.05 $ 0.23 0.9% 0.0%

( 1b) Capacity Price ($ 2002/ KW) $ 73.68 $ 74.00 $ 0.33 0.4%  0.5%

( 2) Total Generation ( GWh) 274,753 274,729 ( 24) 0.0% 0.2%

( 3) Total Revenues ( Millions; $ 2002) $ 12,024 $ 12,109 $ 84 0.7% 0.0%

( 4) Costs ( Millions; $ 2002) $ 5,985 $ 6,020 $ 35 0.6% 0.7%

( 4a) Fuel Cost $ 2,920 $ 2,921 $ 1 0.0% 0.1%

( 4b) Variable O& M $ 553 $ 554 $ 1 0.2% 0.2%

( 4c) Fixed O& M $ 2,125 $ 2,156 $ 30 1.4% 1.9%

( 4d) Capital Cost $ 386 $ 389 $ 3 0.8% 0.3%

( 5) Pre Tax Income ( Millions; $ 2002) $ 6,039 $ 6,089 $ 49 0.8%  0.9%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.64 $ 12.65 $ 0.01 0.1%  0.1%

Mid America Interconnected Network ( MAIN)

( 1a) Energy Price ($ 2002/ MWh) $ 22.68 $ 22.93 $ 0.25 1.1%  0.3%

( 1b) Capacity Price ($ 2002/ KW) $ 78.80 $ 78.10 ($ 0.69)  0.9% 0.8%

( 2) Total Generation ( GWh) 285,282 284,198 ( 1,085)  0.4%  0.1%

( 3) Total Revenues ( Millions; $ 2002) $ 11,208 $ 11,180 ($ 28)  0.3%  0.1%

( 4) Costs ( Millions; $ 2002) $ 5,940 $ 5,943 $ 3 0.0% 0.4%

( 4a) Fuel Cost $ 2,940 $ 2,967 $ 27 0.9% 0.9%

( 4b) Variable O& M $ 589 $ 587 ($ 2)  0.3%  0.3%

( 4c) Fixed O& M $ 1,949 $ 1,925 ($ 24)  1.2%  0.5%

( 4d) Capital Cost $ 463 $ 464 $ 2 0.4% 1.2% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 7: Market Level Impacts of the Preferred Option ( NERC 2008 and 2010)

Economic Measures Base Case Preferred Option Difference % Change % Change 2010 NODA Version   March 12, 2003 B3 27 ( 5) Pre Tax Income ( Millions; $ 2002) $ 5,268 $ 5,237 ($ 31)  0.6%  0.7%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.37 $ 12.51 $ 0.14 1.1% 0.8%

Mid Continent Area Power Pool ( MAPP)

( 1a) Energy Price ($ 2002/ MWh) $ 22.41 $ 22.66 $ 0.26 1.1%  0.4%

( 1b) Capacity Price ($ 2002/ KW) $ 78.32 $ 78.01 ($ 0.31)  0.4% 0.9%

( 2) Total Generation ( GWh) 179,067 178,978 ( 89) 0.0%  0.1%

( 3) Total Revenues ( Millions; $ 2002) $ 6,756 $ 6,790 $ 33 0.5% 0.0%

( 4) Costs ( Millions; $ 2002) $ 3,353 $ 3,369 $ 17 0.5% 0.4%

( 4a) Fuel Cost $ 1,740 $ 1,740 $ 0 0.0%  0.2%

( 4b) Variable O& M $ 366 $ 366 $ 0 0.0% 0.0%

( 4c) Fixed O& M $ 998 $ 1,015 $ 17 1.7% 1.7%

( 4d) Capital Cost $ 249 $ 249 $ 0 0.0% 0.0%

( 5) Pre Tax Income ( Millions; $ 2002) $ 3,404 $ 3,420 $ 16 0.5%  0.6%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.76 $ 11.76 $ 0.01 0.0%  0.1%

Northeast Power Coordinating Council ( NPCC)

( 1a) Energy Price ($ 2002/ MWh) $ 29.48 $ 30.06 $ 0.58 2.0% 0.9%

( 1b) Capacity Price ($ 2002/ KW) $ 68.95 $ 60.67 ($ 8.27)  12.0% 0.2%

( 2) Total Generation ( GWh) 277,871 277,553 ( 318)  0.1% 0.1%

( 3) Total Revenues ( Millions; $ 2002) $ 12,806 $ 12,402 ($ 404)  3.2% 0.8%

( 4) Costs ( Millions; $ 2002) $ 7,668 $ 7,716 $ 49 0.6% 0.7%

( 4a) Fuel Cost $ 4,459 $ 4,449 ($ 11)  0.2%  0.3%

( 4b) Variable O& M $ 376 $ 372 ($ 3)  0.9%  0.7%

( 4c) Fixed O& M $ 1,779 $ 1,833 $ 54 3.0% 3.6%

( 4d) Capital Cost $ 1,053 $ 1,062 $ 9 0.8% 0.7%

( 5) Pre Tax Income ( Millions; $ 2002) $ 5,138 $ 4,686 ($ 452)  8.8% 0.8%

( 6) Variable Production Costs ($ 2002/ MWh) $ 17.40 $ 17.37 ($ 0.03)  0.2%  0.4%

Southeastern Electric Reliability Council ( SERC)

( 1a) Energy Price ($ 2002/ MWh) $ 25.48 $ 25.57 $ 0.09 0.4% 0.0%

( 1b) Capacity Price ($ 2002/ KW) $ 68.91 $ 68.56 ($ 0.34)  0.5% 0.2%

( 2) Total Generation ( GWh) 924,991 927,605 2,613 0.3% 0.1%

( 3) Total Revenues ( Millions; $ 2002) $ 36,464 $ 36,589 $ 125 0.3% 0.1%

( 4) Costs ( Millions; $ 2002) $ 19,134 $ 19,301 $ 167 0.9% 0.5%

( 4a) Fuel Cost $ 10,337 $ 10,375 $ 38 0.4% 0.0%

( 4b) Variable O& M $ 1,760 $ 1,761 $ 2 0.1% 0.2%

( 4c) Fixed O& M $ 5,182 $ 5,252 $ 70 1.3% 1.5% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis Table B3 7: Market Level Impacts of the Preferred Option ( NERC 2008 and 2010)

Economic Measures Base Case Preferred Option Difference % Change % Change 2010 B3 28 NODA Version   March 12, 2003 ( 4d) Capital Cost $ 1,854 $ 1,912 $ 58 3.1% 0.8%

( 5) Pre Tax Income ( Millions; $ 2002) $ 17,330 $ 17,288 ($ 42)  0.2%  0.5%

( 6) Variable Production Costs ($ 2002/ MWh) $ 13.08 $ 13.08 $ 0.01 0.0%  0.1%

Southwest Power Pool ( SPP)

( 1a) Energy Price ($ 2002/ MWh) $ 25.17 $ 25.28 $ 0.11 0.4%  0.2%

( 1b) Capacity Price ($ 2002/ KW) $ 61.73 $ 61.23 ($ 0.50)  0.8% 0.6%

( 2) Total Generation ( GWh) 217,634 217,598 ( 36) 0.0% 0.2%

( 3) Total Revenues ( Millions; $ 2002) $ 8,503 $ 8,498 ($ 6)  0.1% 0.2%

( 4) Costs ( Millions; $ 2002) $ 4,214 $ 4,225 $ 11 0.3% 0.7%

( 4a) Fuel Cost $ 2,743 $ 2,746 $ 3 0.1% 0.1%

( 4b) Variable O& M $ 419 $ 420 $ 1 0.1%  0.1%

( 4c) Fixed O& M $ 1,031 $ 1,042 $ 11 1.1% 1.5%

( 4d) Capital Cost $ 21 $ 18 ($ 4)  17.8% 14.8%

( 5) Pre Tax Income ( Millions; $ 2002) $ 4,289 $ 4,273 ($ 16)  0.4%  0.4%

( 6) Variable Production Costs ($ 2002/ MWh) $ 14.53 $ 14.55 $ 0.02 0.1%  0.1%

Western Systems Coordinating Council ( WSCC)

( 1a) Energy Price ($ 2002/ MWh) $ 28.58 $ 28.59 $ 0.02 0.1% 0.0%

( 1b) Capacity Price ($ 2002/ KW) $ 18.17 $ 18.06 ($ 0.11)  0.6% 0.2%

( 2) Total Generation ( GWh) 739,205 739,644 439 0.1% 0.0%

( 3) Total Revenues ( Millions; $ 2002) $ 23,797 $ 23,805 $ 8 0.0% 0.0%

( 4) Costs ( Millions; $ 2002) $ 14,287 $ 14,390 $ 103 0.7% 0.5%

( 4a) Fuel Cost $ 7,999 $ 8,030 $ 31 0.4% 0.0%

( 4b) Variable O& M $ 1,160 $ 1,162 $ 2 0.2% 0.2%

( 4c) Fixed O& M $ 4,140 $ 4,210 $ 70 1.7% 1.7%

( 4d) Capital Cost $ 989 $ 988 ($ 1)  0.1%  0.1%

( 5) Pre Tax Income ( Millions; $ 2002) $ 9,509 $ 9,415 ($ 94)  1.0%  1.1%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.39 $ 12.43 $ 0.04 0.3% 0.0%

Source: IPM analysis: Model runs for Section 316( b) NODA Base Case ( EPA electricity demand) and the preferred option.

Summary of Market Results at the National Level. The results presented in Table B3 7 show that under the preferred option downtimes associated with the installation of compliance technologies would not lead to significant changes in economic impacts compared to the results for 2010 ( which represents the post compliance scenario in which no facilities experience downtimes). There would be an 0.2 percent increase in fuel costs in 2008, leading to an increase in variable production cost per MWh of 0.1 percent, and the rise in capital costs would be somewhat higher in 2008 than in 2010.

Summary of Market Results at the Regional Level. The following discussion highlights differences in the analysis results between 2010 and 2008: < In FRCC, SERC, and WSCC, most impact results for 2008 and 2010 are either the same or slightly lower in 2008. FRCC would experience a smaller decrease in capacity prices in 2008 which would result in higher revenues and a § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis NODA Version   March 12, 2003 B3 29 smaller loss in pre tax income compared to 2010. In SERC, energy prices and generation would increase more in 2008 than 2010, leading to an increase in revenues and a reduction in pre tax income loss. In WSCC, fuel costs would increase by 0.4 percent, resulting in an 0.3 percent increase in variable production costs per MWh. < ECAR, MACC, and MAPP would experience increases in energy prices between 0.9 and 1.2 percent in 2008. These increases would lead to higher revenues and increases in pre tax income of between 0.5 and 0.8 percent. < MAIN and NPCC would both experience increases in energy prices under the preferred option in 2008. However, capacity prices would decrease, leading to a reduction in revenues and pre tax income. < ERCOT would experience substantially lower price effects in 2008 compared to 2010. The increase in energy prices would be 0.3 percent compared to 6.1 percent in 2010. Capacity prices in 2008 are zero in both the base case and under the preferred option as a result of excess capacity in the region ( note that there are no new capacity additions in ERCOT in 2008). ERCOT would also experience an increase in revenues and a smaller reduction in pre tax income compared to 2010. < In SPP, energy prices under the preferred option would increase by 0.4 percent in 2008 while capacity prices would fall, resulting in a 0.1 percent reduction in revenues. The only other notable difference in results compared to 2010 is a relatively large percentage reduction in capital costs in 2008. This is the result of a minor delay in investment in new capacity additions under the preferred option: approximately 120 MW of capacity that is projected to be built in 2008 in the base case is postponed until 2010 under the preferred option. As a result, 2008 sees a reduction in capital costs while 2010 sees an increase. Overall, the reduction in capital costs in 2008 comprises less than 0.1 percent of total base case cost.

B3 5 UNCERTAINTIES AND LIMITATIONS There are uncertainties associated with EPA's analysis of the electric power market and the economic impacts of the preferred option:

< Demand for electricity: The IPM assumes that electricity demand at the national level would not change between the base case and the analyzed policy options ( generation within the regions is allowed to vary). Under the EPA Base Case 2000 specification, electricity demand is based on the AEO 2001 forecast adjusted to account for demand reductions resulting from implementation of the Climate Change Action Plan ( CCAP). The IPM model, as specified for this analysis, does not capture changes in demand that may result from electricity price increases associated with the preferred option. While this constraint may overestimate total demand in policy options that have high compliance cost and that may therefore lead to significant price increases, EPA believes that it does not affect the results analyzed in support of the preferred option. As described in Section B3 4 above, the price increases associated with the preferred option in most NERC regions are relatively small. EPA therefore concludes that the assumption of inelastic demandresponses to changes in prices is reasonable.

< International imports: The IPM also assumes that imports from Canada and Mexico would not change between the base case and the analyzed policy options. Holding international imports fixed would provide a conservative estimate of production costs and electricity prices, because imports are not subject to the rule and may therefore become more competitive relative to domestic capacity, displacing some of the more expensive domestic generating units. On the other hand, holding imports fixed may understate effects on marginal domestic units, which may be displaced by increased imports. However, EPA concludes that fixed imports do not materially affect the results of the analyses. Only four of the ten NERC regions import electricity ( ECAR, MAPP, NPCC, and WSCC) and the level of imports compared to domestic generation in each of these regions is very small ( 0.03 percent in ECAR, 2.4 percent in MAPP, 5.6 percent in NPCC, and 1.5 in WSCC).

< Repowering: For the section 316( b) analysis, EPA is not using the IPM function that allows the model to pick among a set of compliance responses. As a result, there is no iterative process that would adjust the compliance response ( and as a result the cost of compliance) if a facility chooses to repower. Repowering in the IPM typically consists of the conversion of existing oil/ gas or coal capacity to new combined cycle capacity. The modeling assumption is that each one MW of existing capacity is replaced by two MW of repowered capacity. This change in plant type and size might lead to a change in intake flow and potentially to different compliance requirements and costs. Since combined cycle facilities require substantially less cooling water than other oil/ gas or coal facilities, the effect of repowering is likely to be a reduction in cooling water requirements ( even considering the doubling of the plant's capacity). As a result, not allowing the model to adjust the compliance response or cost is likely to lead to a conservative estimate of compliance costs and potential economic impacts from the preferred option and the alternative regulatory options analyzed with the IPM. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis B3 30 NODA Version   March 12, 2003 < Downtime associated with installation of compliance technologies: EPA estimates that the installation of several compliance technologies would require the steam electric generators of facilities that are projected to install such technologies to be off line for between two weeks and seven months, depending on the technology. Generator downtime is estimated to occur during the year when a facility complies with the policy option. Since the years that are mapped into a run year are assumed to have the same characteristics as the run year itself, generator downtimes were applied as an average over the years that are mapped into each model run year. For example, years 2005 to 2009 are all mapped into 2008. Therefore, a facility with a downtime in 2008 was modeled as if 1/ 5th of its downtime occurred in each year between 2005 and 2009. A potential drawback of this approach of averaging downtimes over the mapped years is that the snapshot of the effect of downtimes during the model run year is the average effect; this approach does not model potential worst case effects of above average amounts of capacity being down in any one NERC region during any one year. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis NODA Version   March 12, 2003 B3 31 REFERENCES U. S. Environmental Protection Agency ( U. S. EPA). 2000. Section 316( b) Industry Survey. Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures and Industry Short Technical Questionnaire: Phase II Cooling Water Intake Structures, January, 2000 ( OMB Control Number 2040 0213). Industry Screener Questionnaire: Phase I Cooling Water Intake Structures, January, 1999 ( OMB Control Number 2040 0203).

U. S. Environmental Protection Agency ( U. S. EPA). 2002. Documentation of EPA Modeling Applications ( V. 2.1) Using the Integrated Planning Model. EPA 430/ R 02 004. March 2002. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3 B3 32 NODA Version   March 12, 2003 Appendix to Chapter B3 INTRODUCTION This appendix presents additional, more detailed information on EPA's research to identify models suitable for analysis of environmental policies that affect the electric power industry. In addition, this appendix presents a comparison of the specifications of the EPA Base Case 2000 and its predecessor Base Case specifications.

B3 A. 1 SUMMARY COMPARISON OF ENERGY MARKET MODELS EPA performed research to identify electricity market models that could potentially be used in the analysis of impacts associated with regulatory options considered for section 316( b) Phase II regulation. This research included reviewing available forecast studies and interviewing persons knowledgeable in the area of electricity market forecasting. EPA focused on identifying models that are widely used for public policy analyses, peer reviewed, of national scope, and have the capabilities needed to perform regulatory impact scenario analyses of the type required for the section 316( b) Phase II economic analyses. Based on this research, EPA identified three models that were potentially suitable for the analysis of the section 316( b) Phase II regulations:

< ( 1) The Department of Energy's National Energy Modeling System ( NEMS), < ( 2) The Department of Energy's The Policy Office Electricity Modeling System ( POEMS), and < ( 3) ICF Consulting's Integrated Planning Model ( IPM ® ) .

Each of these models was developed to meet the specific needs of different end users and therefore differ in terms of structure, inputs, outputs, and capability. Table B3 A 1 below presents a detailed comparison of the three models. The comparison comprises:

< General features, including a description of each model, their general applications, and their environmental applications.

< Modeling features, including each model's treatment of existing environmental regulations, of industry restructuring, and of economic plant retirements; their regional capabilities; their plant/ unit detail and data sources; their general data inputs and outputs; and their data inputs and outputs required for the section 316( b) analysis.

< Logistical considerations, including each model's costs, computational requirements, accessability and response time; their documentation and issues regarding disclosure of inputs or results; and general notes and references. CHAPTER CONTENTS B3 A. 1 Summary Comparison of Energy Market Models B3 32 B3 A. 2 Differences Between EPA Base Case 2000 and Previous Model Specifications. . . . . . . . . . . . . . B3 38 § 316( b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3 NODA Version   March 12, 2003 B3 33 Table B3 A 1: Comparison of Electricity Market Models Model DOE/ EIA: NEMS DOE/ OP: POEMS ( OnLocation, Inc.) EPA/ Office of Air Policy ( OAP): IPM ( ICF Consulting Inc.)

General Features Description Modular structured model of national energy supply and demand, includes macroeconomic, international, supply and demand modules, as well as an electricity market module ( EMM) that can be run independently. The EMM represents generation, transmission and prices of electricity.

Based on forecasts of fuel prices, variable O& M, and electricity demand, determines plant dispatch to achieve the least cost supply of electric power. POEMS is a model integration system that allows the substitution of the TRADELEC model for the EMM in NEMS. TRADELEC allows for a greater level of detail about the electricity sector than the EMM. Designed to examine the effect of market structure transformation of the electricity sector. It solves for the trade of the commodity as a function of relative prices, transmission constraints and cost of market entry by maximizing economic gains achieved through commodity trading. A production cost model based on linear programming approach, solves for least cost dispatch. Simulates system dispatch and operations, estimates marginal generation costs on an hourly basis.

Minimizes present worth of total system cost subject to various constraints.

General Applications Used to produce annual forecasts of energy supply, demand, and prices through 2020 for the Annual Energy Outlook. Can also be used to analyze effects of regulations. EIA performs studies for Congress, DOE, other agencies. Used by DOE's policy office to study the impacts of electricity market transformation/ deregulation through 2010. Supports the administration's 1999 bill on industry deregulation, the Comprehensive Electricity Competition Act ( CECA). Primary model used by EPA Air Program offices to evaluate policy and regulatory impacts through 2030. EPA Office of Policy also used this model for GCC and retail deregulation analysis. Used by over 50 private sector clients to develop compliance plans, price forecasts, market analysis, and asset valuation.

Environmental Applications Includes a Carbon Emission submodule. Can also calculate emissions. Produced " Analysis of Carbon Mitigation Cases" for EPA. DOE application generally not designed to perform environmental regulatory analysis. Examines a renewable portfolio standard. EPA/ ARD concluded that air emission estimates are low relative to IPM and other models. However, DOE contractor has performed analyses of environmental policies for private clients. Analyzes environmental regulations by simultaneously selecting optimal compliance strategies for all generating units. Can calculate emissions, and simulate trading scenarios. Used for ozone ( NOx), SO2, and mercury emissions control scenarios; implementation of NAAQS for ozone and PM; alternative NOx emissions trading and rate based programs for OTAG, CAAA Title IV NOx Rule; NOx control options; RIA for the NOx SIP call; and GCC scenarios. Possible to accommodate other environmental regulations. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3 Table B3 A 1: Comparison of Electricity Market Models Model DOE/ EIA: NEMS DOE/ OP: POEMS ( OnLocation, Inc.) EPA/ Office of Air Policy ( OAP): IPM ( ICF Consulting Inc.)

B3 34 NODA Version   March 12, 2003 Modeling Features Treatment of Environmental Regulations Reference case represents all existing regulations and legislation in effect as of July 1, 1998, including impacts of the Climate Change Action Plan and the NOx SIP call. EMM can analyze seasonal environmental controls to the extent that they match up with the seasonal representations in the model ( non sequential months are grouped according to similar load characteristics). Assumes existing regulations and legislation remain in place and facilities comply with existing regulations in the least cost way. Most recent reference case analysis includes NOx SIP call. Assesses a renewable portfolio in the competition case. Does not include other proposed or anticipated environmental regulatory scenarios in DOE analysis. The base case includes current federal and state air quality requirements, including future implementation of SO2 and NOx requirements of Title IV of the CAA, the NOx SIP call as implemented through a cap and trade program. Base case also includes assumptions regarding demand reductions associated with the Climate Change Action Plan.

Treatment of Restructuring All regions assumed to have wholesale competition. Only states with enacted legislation are treated as competitive for retail markets in base case. Has a competitive pricing scenario that assumes full retail competition. Designed to compare competitive wholesale and cost of service retail market structures to fully competitive market structure at the wholesale and retail levels. Compares prices and determines " stranded assets" at the firm level. Pricing modeled for 114 power control areas, assumes profit maximizing behavior. EPA uses assumptions in IPM that reflect wholesale competition occurring throughout the electric power industry. Work for private clients uses different assumptions.

Treatment of Economic Plant Retirements Uses assumptions about licencing and needs for new major capital expenses to forecast nuclear retirements. For fossil steam, model checks yearly to compare revenues at market price with future O& M and fuel costs to forecast economic retirements.

Results appear to have second highest forecast of fossil steam retirements compared to other models. Uses same method as NEMS for forecasting " forced" retirements of nuclear assets due to operating constraints such as licences. Economic retirements based on lack of ability to cover short term going forward costs and the cost of capacity replacement in the long term.

Results appear to have highest forecast of fossil steam retirements compared to other models. Uses assumptions about licencing in forecasting nuclear retirements. The IPM model retires capacity when unit level operating costs reach a level that total electric system costs are minimized by shutting down the existing unit.

Regional Capabilities Model runs analysis for 15 supply regions. Analyzes 114 power control areas connected by 680 transmission links. Analyzes 26 supply regions that can be mapped to NERC regions.

Plant/ Unit Detail Groups all plants into 36 capacity types based on fuel type, burner technology, emission control technology, etc. within a region. Units or plants can be grouped differently according to § 316( b) characteristics. Units are grouped according to demand and supply regions, fuel type, prime mover, in service period, similar heat rates. There are 6,000 unit groupings, an average of 55 per power control area. Plants can be re grouped for § 316( b). Groups approximately 12,000 generating units into model plants. Grouped by region, state, technology, boiler configuration, location, fuel, heat rate, emission rate, pollution control, coal demand region. Plants can be re grouped for § 316( b). § 316( b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3 Table B3 A 1: Comparison of Electricity Market Models Model DOE/ EIA: NEMS DOE/ OP: POEMS ( OnLocation, Inc.) EPA/ Office of Air Policy ( OAP): IPM ( ICF Consulting Inc.)

NODA Version   March 12, 2003 B3 35 Modeling Features ( cont.)

Plant/ Unit Data Sources Form EIA 860A ( all utility plants); Form EIA 867 ( nonutility plants < 1MW); Form EIA 767 ( steam plants < 10MW); Form EIA 759 ( monthly operating data for utility plants). Model includes " virtually all" currently existing generating units, including utility, exempt wholesale generators ( EWGs), and cogenerators. Over 12,000 generating units are represented in this model. Includes all utility units included in Form EIA 860 database. Plus IPPs and cogenerating units that sell firm power to the wholesale market. Also draws from other EIA Forms, Annual Energy Outlook ( AEO), UDI, and other public and private databases. In addition, ICF has developed a database of industrial steam boilers with over 250 MMBtu/ hr capacity in 22 eastern states.

General Data Inputs Demand, financial data, tax assumptions, EIA and FERC data on capital costs, O& M costs, operating parameters, emission rates, existing facilities, new technologies, transmission constraints, and other inputs from other modules. Inputs are similar to NEMS ( for demand, fuel price and macroeconomic data), and EIA reports. FERC filings for other inputs such as capacity, operating costs, performance, transmission, imports, and financial parameters. Some inputs are similar to NEMS, including demand forecast, and cost and performance of new and existing units. Emission constraints, repowering, and retrofit options are EPA specified. Fuel supply curves are used to model gas and coal prices.

Data Inputs for § 316( b) EA Would need to provide information on additional capital costs, O& M costs, study costs, outage period for technology installation, and changes in heat rate and plant energy use associated with each type of technology as it applies to each type of model plant. Would need to provide information on additional capital costs, O& M costs, outage period for installation, and changes in heat rate and plant energy use associated with each type of technology as it applies to each plant grouping. Would need to provide information on additional capital costs, O& M costs, outage period for installation, and changes in heat rate and plant energy use associated with each type of technology as it applies to each type of model plant.

General Data Outputs Retail price and price components, fuel demand, capital requirements, emissions, DSM options, capacity additions, and retirements by region and fuel type. Dispatch, electricity trade, capacity expansion, retirements, emissions, and pricing ( retail and wholesale) by region, state, and fuel type. Regional and plant emissions; fuel, capital, and O& M costs; environmental retrofits; capacity builds; marginal energy costs; fuel supply, demand, and prices ( primarily wholesale; one study focused on retail market). § 316( b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3 Table B3 A 1: Comparison of Electricity Market Models Model DOE/ EIA: NEMS DOE/ OP: POEMS ( OnLocation, Inc.) EPA/ Office of Air Policy ( OAP): IPM ( ICF Consulting Inc.)

B3 36 NODA Version   March 12, 2003 Data Outputs for § 316( b) EBA Results would include additional economic retirements, changes in generation, and changes in revenues for each region and fuel type. EMM cannot provide results on a state by state basis.

By design, it is not possible to map model plant results back to specific plant/ owner using current modeling approach. Results would include additional economic retirements, changes in generation, and changes in revenues for each region and plant grouping.

Could map costs to units and owners with some modification of structure. Results would include additional economic retirements, changes in generation, and changes in revenues for each region and model plant type.

Currently has ability to map back to specific unit and plant/ owner. While this process is automated, it requires 2 3 days of manual checking for every year modeled. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3 Table B3 A 1: Comparison of Electricity Market Models Model DOE/ EIA: NEMS DOE/ OP: POEMS ( OnLocation, Inc.) EPA/ Office of Air Policy ( OAP): IPM ( ICF Consulting Inc.)

NODA Version   March 12, 2003 B3 37 Logistical Considerations Costs ( cost estimates should be considered very preliminary) No out of pocket costs expected. Initial policy case using existing scenario: $ 15 20k. Setting up new base case scenario, performing several runs, and producing briefing: $ 40 60k. ( Assumes plant re grouping cost is included in second estimate only.) Initial policy case: $ 20 30k. Incremental cases $ 2 10k. Regrouping model plants would be labor intensive and add costs to analysis.

Computational Requirements Setting up a policy case may take two months. The model run time is two hours without iterating with rest of NEMS, four hours for total NEMS iteration. EIA runs NEMS on RS6000 workstations. Setting up and running policy case could take from a few days to a few weeks, depending on whether policy case builds on an existing scenario and the complexity of the policy scenarios. Depends on number of model plants and number of years in analysis. Base case approximately 4 6 hours.

Accessability and Response Time Access and response time dependent on agreement between EIA and EPA and EIA's schedule. Could be difficult to get results turned around in time to meet regulatory schedule, depending on EIA's reporting schedule. Access and response time potentially dependent on agreement between DOE and EPA and DOE's schedule. Model run by a contractor. ARD has impression that model has long set up time, model not set up to perform many iterations quickly. ICF is an EPA contractor. Assume that access and response time will be consistent with requirements of analysis.

Documentatio n and Disclosure of Inputs/ Results Documentation and results already available to public. Presented by year for fuel type and region. Could make aggregated results publicly available. EIA does not release plant specific results. Documentation and results of reference and competition cases are available to public on DOE's web page. Documentation of the EPA Base Case already available to public. Assume disclosure would be similar to that for NOx SIP call, etc. EPA/ ARD states that there is more in public domain regarding IPM than most models. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3 Table B3 A 1: Comparison of Electricity Market Models Model DOE/ EIA: NEMS DOE/ OP: POEMS ( OnLocation, Inc.) EPA/ Office of Air Policy ( OAP): IPM ( ICF Consulting Inc.)

B3 38 NODA Version   March 12, 2003 Notes The NEMS code and data are available to anyone for their own use. Anyone wishing to use NEMS is responsible for any code conversions or setup on their own systems. For example, FORTRAN compilers differ between the workstation and PC. Several national laboratories and consulting firms have used NEMS or portions of it, but the time investment is considerable. One out of pocket expense is the purchase of an Optimization Modeling Library ( OML) license. OML is used to solve the embedded linear programs in NEMS. In order to modify or execute one of the NEMS modules that includes a linear program ( EMM is one of them), an OML license is required. DOE's contractor stated that they may need to make some structural changes to the modeling framework to accommodate the requirements for § 316( b) analysis so that the model can incorporate the effects of the additional costs into the decision process ( either to continue running a plant or to retire and replace the plant). OAP sensitive to other EPA offices using another model or using IPM with different assumptions. Willing to coordinate and provide background and technical support.

The EPA Base Case has received some challenges over impacts of Climate Change Action Plan on end use demand. However, has cleared OMB review under other regulatory proposals.

References < Annual Energy Outlook 1999, Report#: DOE/ EIA 0383( 99); < Assumptions to the AEO99, Report#: DOE/ EIA 0554( 99); < EMM/ NEMS Model Documentation Report, Report#: DOE/ EIAM0689 99); < Personal communications with EIA staff: Jeffrey Jones ( jeffrey. jones@ eia. doe. gov) and Susan Holte ( sholte@ eia. doe. gov). < POEMS Model Documentation, June 1998; < Supporting Analysis for the Comprehensive Electricity Competition Act ( CECA), May, 1999, Report#: DOE/ PO 0059; < The CECA: A Comparison of Model Results, September, 1999, Report#: SR/ OAIF/ 99 04; < Personal communications with DOE staff: John Conti ( john. conti@ hq. doe. gov), EPA staff: Sam Napolitano ( napolitano. sam@ epa. gov), and contractor: Lessly Goudarzi ( goudarzi@ onlocationinc. com) . < Analyzing Electric Power Generation Under the CAA ( Appendix 2), March, 1998 ( EPA/ OAR/ ARD); < Analysis of Emission Reduction Options for the Electric Power Industry ( Chapter 2), March, 1999 ( EPA/ OAR/ ARD); < IPM Demonstration, May, 1998 ( slides by ICF); < Personal communications with EPA staff: Sam Napolitano ( napolitano. sam@ epa. gov), and contractors: John Blaney ( blaneyj@ icfkaiser. com).

Source: U. S. EPA analysis, 2002.

B3 A. 2 DIFFERENCES BETWEEN THE EPA BASE CASE 2000 AND PREVIOUS MODEL SPECIFICATIONS § 316( b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3 NODA Version   March 12, 2003 B3 39 Past applications by EPA of the IPM model have employed a predecessor base case specification. The previous specification of the IPM model, EPA Base Case 1998, was recently updated to the current EPA Base Case 2000. The revised specification used for the section 316( b) analysis uses more complete and current cost and performance data for new and existing facilities, updated demand growth forecasts, and revised financial, fuel cost, and regulatory assumptions. The primary differences between the IPM's EPA Base Case 2000 and its predecessor model specification are identified and discussed below. For more a more detailed discussion of the specification of the EPA Base Case 2000 see Documentation of EPA Modeling Applications ( V. 2.1) Using the Integrated Planning Model ( U. S. EPA, 2002).

< The National Electric Energy Data System ( NEEDS), the database containing location, operational, and emission data for each of the existing and planned committed generating units modeled in each IPM base case specification, was updated using 1998 EIA data taken primarily from Form EIA 860A, Form EIA 860B, Form EIA 759, and Form EIA 767. In addition, the update used data from the 1998 NERC Electric Supply and Demand database, second quarter values from EPA's 2000 Continuous Emission Monitoring System database, and the EPA 1999 Information Collection Request database.

< The EPA Base Case 1998 demand growth assumptions were updated for the EPA Base Case 2000 specification. The demand growth assumptions for the original specification were based on the 1997 NERC Electricity Supply and Demand forecast for Net Energy for Load in early years, and on the Data Research Institute ( DRI) 1995 forecast for later years. These original forecasts were adjusted based on EPA's estimate of the demand reductions resulting from implementation of the Climate Change Action Plan ( CCAP). The EPA Base Case 1998 electricity demand growth rate was 1.6 percent per year for 1997 2000, 1.8 percent per year for 2001 2010, and 1.3 percent per year for beyond 2010. EPA Base Case 2000 electricity demand growth is based on the AEO 2001 forecast. The AEO 2001 forecast was also adjusted to account for impacts of initiatives created under the CCAP in the revised base case specification. The EPA Base Case 2000 average annual growth rate in Net Energy for Load is 1.2 percent for 2000 2020.