1. Presented by: Eastern Research Group, Inc. May 10, 2005 Status Report to the Stationary Sources Joint Forum: Task 2: Control Technology Analysis

2. 2 Objective:Provide costs and impacts for options used to control emissions of NO x, SO 2, PM, VOC, and Ammonia NO x from EGUs EGUs firing coal – Draft report has been issued. EGUs firing oil and gas – Database of sources has been assembled. Working on identifying control options and costs and emission reductions of options. Other NO x from non-EGU’s SO 2 PM, VOC, and ammonia Overview

3. 3 Plan for NO x From Coal-fired EGUs Assemble database of all EGUs in WRAP Profile state of the art NO x combustion controls Identify control options Calculate costs and impacts of options

4. 4 Database of All EGUs in WRAP Data obtained from EPA databases  CAMD  EIA 767  EIA 423 Data from telephone contacts w/utilities  Coal and combustor properties Database is available on website

5. 5 Bins for Coal-fired EGU’s in WRAP EGU’s were grouped into bins based on similarities in combustor type, coal fired, and nitrogen content of coal. Bins were further specified by the generation of existing combustion control.  E.g., 1 st generation LNB, 2 nd generation LNB, State of the Art LNB Insufficient information was available on more specific combustor parameters (e.g., residence time, combustor volume, and heat release rate).

6. 6 Bins for Coal-fired EGU’s in WRAP (cont.) Bin IDBin Description# EGU’s in Bin 1aTangentially-fired, high N coal27 1bTangentially-fired, low N coal17 2Wall-fired, high N coal33 3Wall-fired, low N coal12 4Cyclone burners5 5Cell burners3 6CFB units2 7Dry bottom vertically fired4

7. 7 Summary of Combustor Configurations LNB = Low NO x burner, this includes an older low technology found on some tangentially-fired boilers and a technology used on tangential units. LNBO = Low NO x burner with over-fire air LNC1 = Low NO x burner with closed-coupled OFA LNC2 = Low NO x burner with separated OFA LNC3 = Low NO x burner with close-coupled and separated OFA OFA = Over-fired air SCR = Selective Catalytic Reduction

8. 8 Control Scenarios Identified 5-7 control options for bins (except for fluidized bed, cell, and cyclone burners). Options 1-3 are existing combustion controls that are widely used.  Most are variations of LNB and/or OFA Options 4-7 are next generation burners or state of art combustion controls.  E.g., ULNB, ULNB+OFA, ROFA

9. 9 Control Options Applied to Bin 1A

10. 10 Costs and Impacts of Scenarios Costs for LNB and OFA from CAMD analysis were updated to 2004 $. Vendor information on LNB and OFA in 2004 $ were compared to updated CAMD costs. If significantly different, vendor data used to reflect decrease in costs. O & M costs were based on CAMD data Vendor information used for new state of the art combustion controls.  Costs and emission reductions based on few data points

11. 11 Costs and Impacts Methodology Incorporated the generation of the control category to determine the baseline level of control Baseline NO x emissions were based on CEM information from CAMD Emission reductions were calculated using the percent reduction the control option can achieve, but bounded by the emission limit that can be achieved

12. 12 Results Costs and emission reductions for control options were compared to costs and emission reductions of applying SCR to only BART sources to meet the BART level of control (0.2 lb NO x /MMBtu). BART sources comprise 64 of 110 EGU’s. Additional 21 EGU’s are likely BART sources. To match the emissions reduction achieved by applying SCR, EGU’s would need to apply more advanced state of the art controls.

13. 13 Results (cont.)

14. 14 Results (cont.)

15. 15 Results (cont.)

16. 16 Example Scenarios

17. 17 Example Scenarios (cont.)

18. 18 Example Scenario by State

19. 19 Plan for Other Pollutants/Sources For EGU’s, identify unique units by ORIS codes. Identify highest emitting sources and SCC’s using latest inventory work. Use previous study (plus additional controls) to identify potential controls that may be used per source category.

20. 20 SO 2 Emissions by SIC

21. 21 SO 2 Emissions by State

22. 22 SO 2 Emissions by Process Group

23. 23 Group 1 Processes

24. 24 Group 2 Processes

25. 25 Group 3 Processes

26. 26 Group 4 Processes

27. 27 Group 6 Processes

28. 28 Group 11 Process

29. 29 SO 2 Emissions by Group with BART- eligibility

30. 30 Proposed BART Level of SO 2 Control for EGUs In establishing BART emission limits, States as a general matter, must apply EPA’s specified “Default Control Level” for each individual EGU greater than 250 MW. The “Default Control Level” for SO 2 is either:  SO 2 emissions from the EGU must be 95% controlled, OR  The EGU’s control(s) must achieve in the range of 0.1 to 0.15 lbs SO 2 /MMBtu. States may establish a different level of control if the State can demonstrate that an alternative determination is justified based on a consideration of evidence before it. EPA says that it will be extremely difficult to justify a BART determination less than the “default control level” for a plant greater than 750 MW, less difficult for a plant 750 MW or smaller.

31. 31 Rough Estimate of SO 2 Reductions due to BART for EGUs

32. 32 North Dakota SO 2 Emissions

33. 33 Colorado SO 2 Emissions

34. 34 Nevada SO 2 Emissions

35. 35 Washington SO 2 Emissions

36. 36 Montana SO 2 Emissions

37. 37 California SO 2 Emissions

38. 38 Idaho SO 2 Emissions

39. 39 South Dakota SO 2 Emissions

40. 40 Alaska SO 2 Emissions

41. 41 Next Steps Address comments on draft report. Obtain input on control scenarios for NO x from non-coal EGU’s, NO x from non-EGUs, SO 2 for non-Annex States, and PM, VOC, and ammonia from all sources.