Report No. 86-689 ENR ."‘t'-”.' Congressional Research Service The Library of Congress Washington, D.C. —"= ESTIMATING ACID RAIN CONTROL COSTS: - ILLUSTRATIVE PROBLEMS FROM THE RECENT EEI-TBS STUDY OF H.R. 4567 Prepared at Congressional Request No ;>M3E& {TE ‘:5? E M735 -' _(.-«~». r 6, I -3 pvt a;Lafi€ KEEEPJVY ‘{§‘\§a§2%*:i:1;;:%ion Ufi'WFe'9I$Wf7 Larry B. Parker Specialist in Energy Policy Environment and Natural Resources Policy Division April 29, 1986 \\|\\Miii[@Qi91n}m\®@gig§\g@Wm»nu $3 st. Louis, Mo 63130 ESTIMATING ACID RAIN CONTROL COSTS: ILLUSTRATIVE PROBLEMS FROM THE RECENT EEI-TBS STUDY OF H.R. 4567 SUMMARY AND CONCLUSION In discussing the implications of potential acid rain control legislation, legislators and analysts naturally focus attention on control costs and their economic effects. In particular, interested parties examine projected electricity rate increases to residential and other electricity consumers. However, despite their importance, and the mounds of cost studies conducted, Congress is still faced with electricity rate projections that are sometimes an order of magnitude apart on the costs of controls. The most recent example of this situation relates to H.R. 4567. The bill involves States meeting a 1.2 lb. of S02 per million Btu statewide limit on utility emissions, along with other reductions by other indus- trial concerns, by whatever means States choose to comply. In introducing the bill, sponsors made explicit reference to provisions in the bill to help States prevent residential electricity rates from increasing more than 10 percent because of control equipment costs. This assistance comes in the form of an interest subsidy to be funded by a fee of l/2 mill per kilowatt-hour (kwh) on non-nuclear, non-hydro power generated or imported into the country. Four days after introduction, the Edison Electric Institute (EEI) released a study conducted by Temple, Barker & Sloane (TBS) stating that residential rate increases would be much more than 10 percent for many of CRS-2 the country's utilities--over 30 percent in the case of Kentucky Power Company. Regarding the interest subsidy, the EEI-TBS study suggested that no utility met the requirements of the interest subsidy despite the study's projected high residential rate increases. Like most other things involved with the acid rain controversy, cost studies have a political content. Because one can vary the decision-mak- ing process, the provisions of the proposed program, and the necessary cost assumptions in conducting cost analysis, it is not always easy to tell if a study's result flows from prior stated assumptions, or from result-oriented procedures that have to be understood before the study's usefulness can be assessed. This is particularly true of a bill like H.R. 4567 which is designed to provide maximum flexibility to States in implementing its provisions and whose deadlines are well into the future. The EEI-TBS report does not take advantage of the flexibility or opportunities for cost-effective or imaginative responses provided by H.R. 4567. This is somewhat paradoxical as utilities‘ concerns about constraints being imposed on how they could meet any acid rain requirement were a primary consideration to drafters of the bill in deciding to provide as much flexibility to States as possible in designing reduction strategies. Indeed, the compliance strategy chosen by TBS for the individual utility reanalyzed in this report was not the most cost-effec- tive available to the utility. The implication of the EEI-TBS study that utilities would not seriously examine opportunities for innovative and cost-effective responses in designing reduction strategies under H.R. 4567 seems questionable in light of State concerns and the utilities own self-interest. CRS-3 Utilizing some, but not all, of the flexibility provided by H.R. 4567, CRS analyzed one utility studied in the EEI-TBS report (Kentucky Power Company) and found compliance options necessitating rate increases substantially less than those projected by TBS.‘Using a range of possible control methods, CRS projected rate increases from Kentucky Power Company of between 4.3 percent and 10.4 percent first-year, and 1.8 percent and 6.5 percent average over 20 years. These results compare with a EEI-TBS estimate of an above 30 percent firstyear rate increase and a CRS recal- culation of the EEI-TBS scenario of 24.2 percent first-year and 10.2 percent average over 20 years. INTRODUCTION In discussing the implications of potential acid rain legislation, legislators and analysts naturally focus on control costs and their effects. However, despite their importance, and the mounds of cost studies conducted, Congress is still faced with estimates that are sometimes an order of magnitude apart on the cost of controls. The introduction of H.R. 4567 illustrates this situation. In introducing the bill, sponsors made explicit reference to provisions in the bill to help States prevent residential electricity rates from increasing more than 10 percent because of control equipment costs. However, four days after introduction, the Edison Electric Institute (EEI) released a study conducted by Temple, Barker & Sloane (TBS) stating that residential rate increases would be much higher, over 30 percent in the case of Kentucky CRS-4 Power Company. 1/ This paper attempts to provide insight on the potential and pitfalls of acid rain cost analysis, using the EEI-TBS study of H.R. 4567 as an example. Many of the points raised are applicable to virtually all acid rain cost studies. The discussion is divided into four generic areas: (1) How the study handled H.R. 4567's decision-making process, (2) How the study interpreted H.R. 4567's various provisions affecting costs, (3)’ Methodological issues (including scope and assumptions), and (4) An example from the EEI-TBS report. It should be noted that the issues raised in this analysis are illustrative, not comprehensive.g/ Also, the analysis assumes a working knowledge of H.R. 4567 on the part of the reader. DECISION-MAKING The central decision-making authority under H.R. 4567 is the indivi- dual State government. The State may become as involved in the reduction process as it desires, including choosing sources to be controlled, methods to be used, and how costs are to be distributed. With the bill's statewide bubble and no restriction on control methods, the State may choose the most cost—effective control strategy for its consumers; or, using the bill's interest subsidy provision, the State may choose to l/ Temple, Barker, & Sloane, Inc. Economic Evaluation of H.R. 4567: The "Acid Deposition Control Act of 1986". Prepared for the Edison Electricity Institute, April 14, 1986. g/ For other cost-related issues in acid rain cost analysis, see Parker, Larry. Summary and Analysis of Technical Hearings on Costs of Acid Rain Bills. Prepared at the request of the Committee on Environment and Public Works, U.S. Senate. CRS unnumbered report, July 26, 1982. CRS-5 trade some cost-savings to electricity consumers for high-sulfur coal production savings for its coal miners by installing some less cost-ef- fective control technology. In either case, the State is in control. Attempting to put the above political decision-making process into an economic analysis presents difficulties for cost analysts. Generally, the analyst must put himself in the place of the State government and make basic assumptions on how the bill would be implemented. In many studies, including the EEI-TBS study, the State role is generally ignored and the individual utilities are the focus point of the analysis. Depending on the analyst, individual utilities may or may not be adopting cost-ef- fective strategies. For example, the EEI-TBS study assumes 74 gigawatts. of flue gas desulfurization (FGD) capacity would be installed under H.R. 4567. (FGD is the generally the most expensive and capital-intensive control technology). This compares with 10-30 gigawatts of FGD projected by the Congressional Office of Technology Assessment (OTA) and ICF, Inc. for reductions of similar magnitude. ;/ Such a fundamental difference in the estimated proportion of utilities choosing one or another control method (particularly a capital-intensive method such as FGD) has a dramatic impact on rate estimates. Since TBS assumes twice as much FGD as other studies, it is not surprising that its projected costs are §/ iThe difference probably results from differing definitions of cost-effectiveness. OTA and ICF define cost-effectiveness in terms of the control method which is least-cost to the utility. In its study of H.R. 3400 conducted in 1983, TBS defined cost-effective FGD candidates as generating units of 200 megawatts or more built since 1960, or remaining units built since 1965. This assumption results in considerably more FGD being installed than an assumption based on least-cost to the utility. As suggested by the example of Kentucky Power Company presented later in this paper, TBS may have used a similar definition for this analysis. CRS-6 higher, particularly during the first few years. Hence, how the analyst views the actual decision-making process of acid rain bills influences his results. The EEI-TBS study uses utilities as the focus of the study with FGD as the primary control technique. Such a focus does not necessarily model the actual decision-making process under H.R. 4567; and, it certainly does not result in the most cost-effec- tive strategy possible under the bill. H.R. 4567 PROVISIONS As written, H.R. 4567 is designed to provide maximum flexibility to the States in deciding how to reduce emissions. Important provisions in this regard include no restriction on control methods, a statewide emissions rate standard allowing bubbling 4/ of emission sources, and an interest subsidy for States who wish to protect their high-sulfur coal production without dramatic residential rate increases. As suggested above, this flexibility permits a State to choose a least-cost, pollu- ter-pays strategy, if it wishes; or, to protect its high-sulfur coal production. Models used by OTA, ICF, and Data Resources Inc. (DRI) permit analysts to incorporate much of the flexibility permitted by H.R. 4567 in their studies. Analysts still must guess the position of State Govern- ments in deciding overall strategy as discussed above; however, one can run different scenarios to indicated how differing State policies affect costs. For example, a recent ICF analysis for the Environmental Protec- 4/ A bubble permits a company (or State) to meet an average company- wide emission limit, rather than requiring compliance at each individual emission source. CRS-7 tion Agency (EPA) contained two scenarios each for a six and eight million ton reduction: (1) least-cost only, and (2) least-cost but including 27.2 gigawatts of the most cost-effective FGD. §/ Other studies have been conducted to include dry scrubbing and Limestone Injection Multi-stage Burners (LIMB) technology as additional control methods; these additional techniques are definite control possibilities for compliance with H.R. 4567, given the bill's 1997 compliance deadline for part 2. Different scenarios are not only useful in debating the cost of acid rain control, but also for identifying potential implementation strategies if such legislation is passed. The EEI-TBS study incorporates little, if any, of the flexibility of H.R. 4567 in its analysis; it does not make use of the 1.2 lb. of SO2 per million Btus statewide bubble, the potential for new technology, or least-cost strategies. The study defines the interest subsidy provisions in such a way as to provide no relief to utilities because no one is eligible (by TBS's definition). METHODOLOGY Methodology and assumptions inevitably affect conclusions, sometimes in non-obvious ways. Five categories of variations are described below. 1. Definition of Cost: Definitions of what should be included as acid rain "control costs" have a substantial impact on estimated program costs. Generally, incremental capital, operations and maintenance costs, and fuel costs for pollution control equipment or fuel switching are accepted as reasonable expenditures to be charged to an acid rain program. However, other costs, such as replacement capacity or energy for scrubber retrofits, are considered more §/ ICF Incorporated. Analysis of 6 and 8 Million Ton and 30 Year/NSPS and 30 Year 1.2 lb. Sulfur Dioxide Emission Reduction Cases. Prepared for the Environmental Protection Agency, February 1986. CRS-8 arguable. The EEI-TBS study mentions a 5.5 percent penalty for scrubber retrofits, but not how that penalty is assessed. The study also assumes that acid rain control would have an immediate and substantial price impact on the low-sulfur coal market, despite its current depressed state. Because of this assumption, the study assigns a cost premium to low-sulfur coal currently being burned by utilities. 2. Cost Estimates: Capital cost estimates for FGD used in acid rain analyses vary significantly: from $155 (TVA) to $450 (AEP) a kw in various utility studies. Similarly, premiums for low-sulfur coal also vary, from $0 to $30 a ton. The capital cost estimates used by TBS in their analysis are about 10-20 percent higher on average than EPA estimates. However, variable operations and maintenance costs used by TBS are almost 8 times greater. 3, Alternatives Available: Even through any acid rain program would not be fully implemented until the 1990s (the mid 1990s in the case of H.R. 4567), many acid rain analyses constrain their control alternatives to a couple of currently available technologies. Several technologies are emerging which may significantly reduce reduction costs. With the flexibility and relatively long lead times of H.R. 4567, this assumption is particularly important. The EEI-TBS study examines only three alternatives for control: wet FGD, fuel switching,'and plant retirement. 4, Financial Parameters: If the acid rain strategy being proposed is capital-intensive, financial parameters can have a significant impact on apparent costs. This impact can be emphasized by the way the study's results are presented. The EEI-TBS study provides few details on its financial assumptions. 5. Presentation: There are several ways to present acid rain costs. If the acid rain control strategy being proposed is capital-- intensive, first-year costs may be roughly double the average cost of the program over the life of the equipment. Also, because of the accelerated tax depreciation (ACRS) available, the first five-years of the program will be disproportionately higher than the rest of the program's life. A second aspect of presentation is the baseline chosen. For various reasons, many analyses present results in terms of rate increases from current or past rates. This method assumes that electricity rates will remain the same in real terms until the 19905 when the program would be implemented. The EEI-TBS focuses its presentation on first-year and five-year levelized costs and rate impacts. The base year used for the rate impact is not stated. No levelized rate impacts for the life of the equipment are provided. CRS-9 AN EXAMPLE: KENTUCKY POWER COMPANY In order to illustrate some of the considerations discussed above, a utility from the EEI+TBS study has been chosen for closer examination. The utility chosen is Kentucky Power Company (KPCo). KPCo is a 1097 megawatt utility with a two unit generating station--Big Sandy (unit 1: 281 Mw, 1963; unit 2: 816 Mw, 1969). Current S02 emissions from the plant are under 2.0 lbs. per million Btus and within SIP requirements. KPCo was chosen for this discussion for two reasons. First, accord- ing to the EEI-TBS report, KPCo will have the highest residential rate increase under H.R. 4567 at over 30 percent, showing that H.R 4567 would have very high costs for some utilities. §/ Second, for the purposes of this discussion, the utility does not have some of the complexities of other systems because KPCo has only one power station and no stage 1 reductions. Methodology Used To provide some comparability between the EEI-TBS analysis and the alternative scenarios developed by CRS, this CRS study employs TBS's allocation formula for KPCo. Based on 1983 excess emissions above 1.2 lb. per mmBtus, TBS estimates that KPCo would have to reduce S02 emissions by 6/ It is interesting to note that KPCo was the utility projected in 1982 by American Electric Power to experience a 106.4% rate increase from acid rain legislation proposed at that time (S. 1706). The same reduction method used in this older analysis is used by TBS in the EEI-TBS study, although the rate increase has dropped. See American Electric Power Service Corporation. Economic Impact on the AEP System of Compliance with the Mitchell Bill, February 23, 1982. CRS-l0 16,393 tons under H.R. 4567 from a total of 44,574 tons. 1/ This works out to a system reduction of 37 percent. To achieve this reduction, the EEI-TBS study assumes KPCo will install a wet scrubber on unit 2. Assuming proportionate emissions between the two units and 90 percent removal by the scrubber, this action would result in 29,841 tons of S02 removed. This is considerably more than is necessary, given TBS's allocation formula--particularly since the EEI-TBS report does not incorporate H.R. 4567's statewide bubble, and therefore assumes the utility will not be able to sell the excess reduction. §/ CRS developed five scenarios for KPCo to indicate the range of control possibilities available, and the influence of assumptions on costs. While these scenarios allow us to examine some of the issues raised above, they do not incorporate all the flexibility and cost effectiveness opportunities available in H.R. 4567. The scenarios are aso follows: 2/ 1/ It should be noted that this is not the allocation formula mandated under H.R. 4567 which has no baseline year or percentage reduc- tion requirement. It is employed here only to provide some comparability between the EEI-TBS report and the scenarios presented here. §/ Based on 1983 S02 emission rates as developed by Energy Ventures Analysis, Inc. for Big Sandy, the EEI-TBS scenario would result in a company-wide emission rate of .6 lb of S02 per million Btus. 1983 data from Energy Ventures Analysis, Inc. Evaluation of S02 Emissions and the FGD Retrofit Feasibility at the 200 Top Emitting Generating Stations. Prepared for the U.S. Environmental Protection Agency, January 10, 1986. 2/ Based on 1983 S02 emission rates as developed by Energy Ventures Analysis, Inc. for Big Sandy, the four CRS scenarios would result in a company-wide emission rate of 1.07 lb. of S02 per million Btus--sufficient to meet the 1.2 lb of S02 per million Btu average on a monthly basis as specified in H.R. 4567. 1983 emission rate data from Energy Ventures Analysis, Inc. Evaluation of S02 Emissions and the FGD Retrofit Feasi- CRS-ll Scenarios l. EEI-TBS. This scenarios assumes the reduction strategy as employed by TBS in their analysis. Cost assumptions are the same as in the report; however, other assumptions, including NOX costs, replacement costs, and financial parameters have been changed to make them consistent with the other scenarios. 2. Adeguate FGD. Under this scenario, unit 2 is equipped with a wet scrubber only sufficient to removed the S02 required. With a 90 percent efficient scrubber, 55 percent of unit 2's stack gases are scrubbed. Such a strategy would require a scrubber with about 450 Mw capacity. 3. Dry Scrubbing. Dry scrubbing is a recent technology particularly suited to plants which burn low to medium sulfur coals, such as Big Sandy. With the dry scrubber operating at 50 percent removal, all of unit 2's stack gases would be scrubbed under this scenario. 4. LIME Technology. LIMB (Limestone Injection Multi-Stage Burners) is a developmental technology which would probably be available for commercial use by the late 1980s or early l990s. "With 50 percent removal, all of unit 2's stack gases would be scrubbed under this scenario. \ 5. Fuel-Switching. Sited in the heart of eastern low-sulfur coal deposits, KPCo might very well decide to fuel-switch its facility to achieve the necessary reductions. Under this scenario, both unit l and unit 2 would switch their coal to compliance quality. Assumptions These five scenarios are compared with each other according to the below assumptions. Wet FGD Costs. For the EEI-TBS scenario, CRS used TBS's assumption of $280 a kilowatt installed for capital costs. Operations and main- tenance costs of $13 a kw for fixed costs and 1.7 mills per kwh for variable costs are assumed, as specified in the report. CRS assumes TBS's 1986 dollars are really end of 1985 dollars. bility at the 200 Top Emitting Generating Stations. Prepared for the U.S. Environmental Protection Agency, January 10, 1986. CRS-12 For the Adequate FGD scenario, CRS used EPA estimates for a 500 kilowatt scrubber burning 1.67 lb. of SO2 per million Btu coal inflated by the GNP implicit price deflator to end of 1985 dollars and incorporating a 1.3 retrofit factor. This resulted in a $235 a kilowatt capital cost. Operations and maintenance costs were derived similarly (including a 1.3 retrofit factor for fixed O & M), and were $11.7 per kw for fixed costs and .22 mills per kwh for variable costs. Dry Scrubbing Costs. For the Dry Scrubbing scenario, CRS used EPA estimates for a 500 kilowatt dry scrubber operating at 50 percent effi- ciency and burning 1.67 lb. of SO2 per million Btu coal inflated by the GNP implicit price deflator to end of 1985 dollars and incorporating a 1.5 retrofit factor. This resulted in a $125 a kilowatt capital cost. Oper- ations and maintenance were derived similarly, and were 1 mill per kwh. LIMB Costs. For the LIMB scenario, CRS used EPA estimates for a 500 kilowatt LIMB system operating at 50 percent efficiency and burning 1.67 lb. of S02 per million Btu coal inflated by the GNP implicit price deflator to end of 1985 dollars. This results in a $50 a kilowatt capital costs. Operations and maintenance were derived similarly, and were .7 mills per kwh. Coal Price Differential Current coal price differentials for low-sulfur coal range from $0 a ton to $5 in the current market. Under an acid rain bill, the demand for low sulfur coal could drive this differential back up to previous levels of $5 to $10 a ton. For this analysis, CRS assumed that the differential would be $10 a ton by the time the 1997 compliance deadline appeared. CRS-13 Upgrading Costs. it already burns might involve adjustments equipment such as grinders or the plant's ESP. Switching Big Sandy to even lower-sulfur coal than to the boiler or ancillary For this analysis, CRS assumed that these costs were $10 a kilowatt. Financial Parameters. Based on DOE data and CRS estimates, table 1 summarizes the financial assumptions made about KPCo. 10/ From these assumptions, nominal and real capital charge rates were calculated--l6.5 percent nominal, 11.8 percent real. of 1985 dollars. Table 1: All calculations are in constant end Financial Assumptions for Analysis Return on Equity Average Weighted Cost of Debt Debt ratio ‘ Nominal Discount Rate Real Discount Rate Percent of Investment as AFUDC Property Taxes/Insurance Equipment Service Life Tax Depreciation l4 10 percent percent 60 percent 10 percent 5 percent 10 percent 2 percent 20 years 5 year ACRS Electricity Demand. CRS assumed that increase at 1 percent a year from its 1984 of the program. NOX Costs. Big Sandy's N0x emissions NOX per million Btus. With a reduction of KPCo to meet H.R. 4567 NOX requirement, it kilowatt low-NOx burners assumed by TBS in lQ/ Department of Energy. Utilities, 1984. DOE/ETA-O437(84). KPCo electricity demand will levels during the 20 year life are approximately .8 lbs. of only 25 percent necessary for is not clear that the $10 a 75 percent of all cases would Financial Statistics of Selected Electric January l986. CRS-14 be necessary in this case. Therefore, for the purposes of comparison, NOX costs were not included in this analysis. This deletion does not represent a major cost item. Assuming KPCo chose to use low-NOx burners to achieve its reduction, a retrofit of unit 2 would be sufficient. Assuming TBS's $10 a kw cost estimate, this scenario would result in a .66 percent first-year rate increase and a .17 percent 20-year levelized rate increase. For readers which wish to include this N0x scenario to the S02 scenarios presented later, the results are additive. However, the NOx cost should not be added to the LIMB scenario as that technology is a simultaneous S02 and NOx reduction technology. Replacement Capacity. ‘Using EPA estimates, the capacity loss under the Adequate FGD scenario would be about 20 megawatts. CRS has assigned no cost to this loss in capacity because of the short and long term reduction in demand the increased costs of electricity from the retrofit would bring. Even if one assumes a low -.2 electricity price elasticity in the short-term and -.5 in the long term, the short and long term rate increases projected for this scenario should cause demand reductions sufficient to "replace" the capacity lost to the retrofit. 11/ Hence, ll/ While electricity price elasticities for the residential sector are generally accepted to be -.2 (short-term) and -.7 (long-term), commercial and industrial elasticities are more uncertain. There is evidence that commercial electricity demand is elastic, more so than in the residential sector. On this point, see Parker Larry B. "Commercial Consumption", in J. Schanz. U.S. Energy Outlook: A Demand Perspective for the Eighties. A report for the Committee on Energy and Commerce, U.S. House, July 1981. There is also evidence that the industrial elasticity in the long-term is in the range of -.5 to -1.0 Hence, to be conservative, we have assumed inelastic short-term and long-term price elasticities of -.2 and -.5 respectively. For a general discussion of energy elasticities, including electricity price elasticities, see Bohi, CRS-15 replacement costs probably should not be charged to H.R. 4567 in this case. The same is true for the EEI-TBS scenario, and is so analyzed in this paper. Capacity losses under the Dry Scrubbing and LIMB scenarios would be about half those under the Adequate FUD scenario or less than 1 percent of KPCo total capacity. As with the FGD cases, it is assumed the demand reduction would be sufficient to cover the minor loss in capacity. Results Using a utility cost model developed by CRS, and assuming January 1, 1985 residential rates for KPCo as published by DOE lg/, table 2 presented projected first-year and 20-year levelized residential rate increases under the various scenarios. As indicated, the LIMB scenario is the least-cost strategy under the assumptions of this analysis, while the EEI-TBS scenario is the most expensive. Table 2: Residential Rate Increases Under Five Scenarios Scenario Adequate Dry Fuel EEI-TBS FGD Scrubbing LIMB Switching First-Year Rate Increase 24.2% 10.4% 9.6% 4.3% 7.8% 20-Year Levelized Rate Increase 10.2% 4.0% 3.5% 1.8% 6.5% Douglas R. Analyzing Demand Behavior: A Study of Energy Elasticities. Published for Resources for the Future, Baltimore: John Hopkins Univer- sity Press, 1981. ;g/ Department of Energy. Typical Electric Bills, January 1, 1985. DOE/EIA-OO40(85) December 1985. CRS-16 Several observations can be made. First, the CRS recalculation of the EEI-TBS scenario results in a considerably reduced first-year rate impact than that reported in the actual report--24.2 percent versus over 30 percent. There are probably several reasons for this difference. The primary reason is likely the removal of replacement costs from the analy- sis. ‘As noted earlier, the EEI-TBS mentions a 5.5% energy and capacity penalty in discussing its key financial assumptions. However, the report does not explain how it accounts for this penalty in terms of additional costs. Also, as noted previously, the EEI-TBS study includes costs for low—NOx burners, which this comparison does not. (Although as calculated earlier, this is only a minor cost addition.) Differences may also arise from different financial parameters, although there is no way of assessing the impact as they are not presented in the EEI-TBS report. Second, this example suggests that the EEI~TBS report is not strictly based on a least-cost implementation strategy, although H.R. 4567 provides that flexibility. The EEI-TBS study states that its assumed utility decision order for achieving S02 reductions is fuel switching first, scrubbing second, and retirement last. Such an order would suggest some roughly based cost-effectiveness criteria. However, assuming the EEI-TBS scenario presented here represents the scrubbing decision in the EEI-TBS report, it seems clear under the assumptions of this analysis that KPCO should follow the first decision and fuel-switch its plant to achieve the reduction under H.R. 4567. The cost differential identified in table 2 would be even greater if EEI-TBS study results were correct. A third observation which can be made is that if scrubbing is scaled back to that adequate for the H.R. 4567 reduction, the utility can CRS-17 achieve a significant savings over the EEI-TBS scenario. Indeed, under the assumptions of this analysis, partial scrubbing is competitive with fuel switching. Fourth, if available technologies are not constrained to a couple of currently available methods, recently developed and emerging technologies (at currently projected costs) could significantly reduce costs. In this analysis, dry scrubbing comes in at slightly less than the Adequate FGD scenario while the LIMB scenario is the most cost-effective alternative (even not including its simultaneous NOX reduction). The above rate impacts are based on first-year and 20-year levelized costs. Both numbers are presented to provide the reader with both the short-term and longer-term impact of the scenarios. To examine presen- tation issues more closely, figure 1 plots annual cost in mills per kwh for each of the five scenarios. The trends are quite revealing. As expected, the fuel switching trend is relatively flat as most of the additional cost is for fuel. 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