1 February 25, 2004 MEMORANDUM Subject: Response to Public Comments on Proposed Industrial, Commercial, and Institutional Boilers and Process Heaters NESHAP From: Jim Eddinger, ESD Combustion Group To: Robert Wayland, ESD Combustion Group On January 13, 2003, the U. S. Environmental Protection Agency ( EPA) proposed national emission standards for hazardous air pollutants ( NESHAP) for Industrial/ Commercial/ Institutional Boilers and Process Heaters. The proposed rule fulfills the requirements of the Clean Air Act ( CAA), which requires EPA to regulate emissions of hazardous air pollutants ( HAP) listed in section 112( b) of the CAA.

This document contains summaries of the public comments that EPA received on the Industrial, Commercial, Institutional Boilers and Process Heaters proposal to establish NESHAP for Industrial/ Commercial/ Institutional Boilers and Process Heaters. In this document, EPA responds to the public comments. This summary of public comments and EPA responses serves as the basis for revisions made to the Industrial/ Commercial/ Institutional Boilers and Process Heaters between proposal and promulgation.

The EPA received 191 comment letters for the Industrial, Commercial, Institutional Boilers and Process Heaters proposed rule before the comment period closed on March 14, 2003. These comments are contained in Docket ID No. OAR 2002 0058 ( formerly Docket No. A 96 47). Eight comments were received shortly after the March 14, 2003 deadline. These comments are contained in the same docket. The commenter, affiliation, and item number in Docket ID No. OAR 2002 0058 are listed in Table 1. 2 Table 1. List of Commenters on the Proposed NESHAP for Industrial, Commercial, and Institutional Boiler and Process Heaters Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 295 jeanpublic@ yahoo. com A 96 47, IV D 17 296 S. Kaderly Nebraska Department of Environmental Quality Lincoln, NE A 96 47, IV D 07 297 R. C. Abrams Kimberly Clark Corporation Everett Mill, Everett, WA A 96 47, IV D 18 320 C. Cary Biomass Combustion Systems, Inc. Princeton, MA 331 R. W. Gore Alabama Department of Environmental Management Montgomery, AL A 96 47, IV D 08 332 J. F. Stahl Los Angeles County Sanitation Districts Los Angeles, CA A 96 47, IV D 20 333 J. Wallen Hambro Forest Products, Inc. Crescent City, CA 334 G. Banks 335 J. Olashuk National Steel Corporation Mishawaka, IN A 96 47, IV D 21 336 J. Olashuk National Steel Corporation Mishawaka, IN A 96 47, IV D 12 337 H. G. Moore International Carbon Black Association Alpharetta, GA Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 3 A 96 47, IV D 11 338 J. T. Clapacs Indiana University Bloomington, IN A 96 47, IV D 10 339 H. Abrams R. J. Reynolds Tobacco Co. Winston Salem, N. C.

A 96 47, IV D 14 340 J. T. Higgins New York Department of Environmental Conservation Albany, NY A 96 47, IV D 09 341 L. Eagan STAPPA/ ALAPCO Washington, D. C.

A 96 47, IV D 15 342 D. Young Menasha Utilities Menasha, WI A 96 47, IV D 16 343 E. M. Adamo Air Products and Chemicals Allentown, PA A 96 47, IV D 01 344 P. Mayberry INDA Association of the NonWoven Fabrics Industry Falls Church, VA A 96 47, IV D 24 345 Randy Putnam Aurora, CO A 96 47, IV D 13 346 G. A. Wilkins Marathon Ashland Petroleum LLC Findlay, OH A 96 47, IV D 25 347 L. Knee Bowels Rice, McDavid Graff & Love PLLC Charleston, WV A 96 47, IV D 04 348 J. Jackson Cumberland Lumber & Mfg. Co., Inc. McMinnville, TN A 96 47, IV D 05 349 L. Eagan State of Wisconsin Department of Natural Resources Madison, Wisconsin Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 4 A 96 47, IV D 06 350 J. Paul Regional Air Pollution Control Association Dayton, Ohio A 96 47, IV D 03 351 T. Pugh American Public Power Association Washington, DC A 96 47, IV D 02 352 J. Bardi American Society for Testing and Materials ( ASTM) W. Conshohocken, PA A 96 47, IV D 57 353 A. R. Heighway Eli Lilly and Company Indianapolis, IN A 96 47, IV D 56 354 N. J. House BAE Systems Ordnance Systems Inc. Holston Army Ammunition Plant Kingsport, TN A 96 47, IV D 36 356 J. Allen Rochester Gas and Electric Corporation Rochester, NY A 96 47, IV D 35 357 D. Reiter U. S. Enrichment Corporation's Paducah Gaseous Diffusion Plant, Paducah, KY A 96 47, IV D 37 358 D. S. Hedrick Associated Electric Cooperative, Inc. Springfield, MO 359 S. Frey Wisconsin Public Power Inc. Sun Prairie, WI 360 C. P. Feerick Exxon Mobil 361 J. L. Nitzschke Deere & Company Moline, IL Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 5 362 J. L. Nitzschke Deere & Company Moline, IL 363 R. Merriman Peru Utilities Peru, IN A 96 47, IV D 123 364 Attachments to OAR 2002 0058 0366 A 96 47, IV D 102 365 D. Kolaz Illinois Environmental Protection Agency Springfield, IL A 96 47, IV D 123 366 T. G. Hunt American Forest & Paper Association, Inc. Washington, DC A 96 47, IV D 102 367 D. Kolaz Illinois Environmental Protection Agency Springfield, IL A 96 47, IV D 123 368 Attachments to OAR 2002 0058 0366 369 D. R. Schregardus Department of the Navy Washington, DC 370 P. A. Reinhardt University of North Carolina at Chapel Hill Chapel Hill, NC 371 M. C. Frank Boeing Company Arlington, VA 372 M. R. Weber CMS Generation Co. Dearborn, MI 373 D. G. Koster Holland Board of Public Works Holland, MI Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 6 374 D. M. Chari Rohm and Haas Company Philadelphia, PA 375 C. Clapsaddle MSI/ Mechanical Systems Inc. Raleigh, NC 376 J. Shefchek Alliant Energy Madison, WI 377 T. LaFond Battery Council International Washington, DC 378 R. G. Rao Indiana Municipal Power Agency Carmel, IN A 96 47, IV D 34 379 J. P. Witkowski South Carolina Chamber of Commerce Columbia, SC 380 L. Beal Interstate Natural Gas Association of America Washington, DC 381 H. P. Quinn, Jr. National Mining Association Washington, DC 382 J. C. deRuyter DuPont Engineering Wilmington, DE 383 R. Kaufmann and L. Otwell Georgia Pacific Corp. Atlanta, GA 384 S. Davis Pinnacle West Capital Corporation Phoenix, AZ Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 7 385 S. Davis Pinnacle West Capital Corporation Phoenix, AZ 386 S. Davis Pinnacle West Capital Corporation Phoenix, AZ A 96 47, IV D 122 387 R. Brear Domtar Industries Inc. Ashdown, AR 388 Attachments to OAR 2002 0058 0389 A 96 47, IV D 60 389 J. Summers Textile and Carpet Industry MACT Coalition Atlanta, GA 390 N. Burwell Lansing Board of Water and Light Lansing, MI 391 Attachments to OAR 2002 0058 0389 0392 Attachments to OAR 2002 0058 0389 A 96 47, IV D 108 393 Debra J. Jezouit Counsel to the Class of ' 85 Regulatory Response Group Washington, DC A 96 47, IV D 62 394 Springs Industries A 96 47, IV D 121 395 P. Maciejewski General Motors Corporation Troy, MI 396 D. F. Hunter ConocoPhillips Houston, TX 397 W. O'Sullivan New Jersey Department of Environmental Protection Trenton, NJ Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 8 398 M. F. Nitchals Willmar Municipal Utilities Willmar, MN A 96 47, IV D 61 399 J. M. Geers Cinergy Corp. Cincinnati, OH 400 R. D. Langford Celanese Americas Corporation Narrows, VA A 96 47, IV D 59 401 D. C. Reeves American & Efird, Inc. Mt. Holly, NC 402 K. Evans Phelps Dodge Corporation ______, __

403 S. E. Woock Weyerhaeuser New Bern, NC 404 T. S. Van Til Primary Power International Ithaca, MI 405 J. Wittenborn Counsel to Specialty Steel Industry of North America Washington, DC A 96 47, IV D 26 406 J. A. Fanjul Atlantic Sugar Association, Inc. Belle Glade, FL A 96 47, IV D 93 407 W. A. Raiola United States Sugar Corporation Clewiston, FL A 96 47, IV D 104 408 J. Alvarez Sugar Cane Growers Cooperative of Florida Belle Glade, FL Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 9 409 W. D. Herrin Southern Company Birmingham, AL 410 R. Karp American Petroleum Institute Washington, DC 411 Attachment to OAR 2002 0058 0410 A 96 47, IV D 72 412 M. Johnston Michigan Manufacturers Association Lansing, MI 413 G. Calvo Utility Air Regulatory Group Washington, DC 414 M. W. Stroben Duke Energy Charlotte, NC A 96 47, IV D 58 415 M. Murray National Wildlife Federation Ann Arbor, MI A 96 47, IV D 120 416 T. R. Weeks San Diego County Air Pollution Control Board San Diego, CA 417 D. A. McWilliams Counsel to American Municipal Power Ohio, Inc. Columbus, OH 418 D. A. McWilliams Counsel to Blast Furnace Operator Group Cleveland, OH 419 E. H. McMeekin PPG Industries, Inc. Allison Park, PA A 96 47, IV D 40 420 T. Woods Downingtown, PA Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 10 A 96 47, IV D 41 421 N. Kothari Manitowoc Public Utilities Manitowoc, WI A 96 47, IV D 42 422 J. Hunter City of Shelby Shelby, OH A 96 47, IV D 43 423 M. Green Central Electric Power Cooperative Chamois, MO A 96 47, IV D 44 424 C. Hornback Association of Metropolitan Sewerage Agencies Washington, DC A 96 47, IV D 45 425 J. Shumaker International Paper Memphis, TN A 96 47, IV D 46 426 P. T. Cavanaugh ChevronTexaco Washington, DC A 96 47, IV D 50 427 B. C. Thomas Alyeska Pipeline Valdez, AK A 96 47, IV D 47 428 M. Y. Kinter The Graphic Arts Coalition Fairfax, VA A 96 47, IV D 51 429 R. McMahon City of Painesville Painesville, OH A 96 47, IV D 52 430 R. Rawson American Boiler Manufacturers Association Arlington, VA A 96 47, IV D 53 431 D. C. Ailor American Coke and Coal Chemicals Institute Washington, DC Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 11 A 96 47, IV D 54 432 J. M. Meriwether New Hope Power Partnership South Bay, FL ( cover letter to 433)

A 96 47, IV D 54 433 J. M. Meriwether New Hope Power Partnership ( NHPP) South Bay, FL A 96 47, IV D 112 434 M. Vignovic Weirton Steel Corporation Weirton, WV 435 D. G. Pauken Muscatine Power and Water ( MPW) Muscatine, IO A 96 47, IV D 111 436 M. Cooke Counsel to Florida Citrus Processors Association Tampa, FL 437 S. Felton AK Steel Middletown, OH 438 Arch Coal, Inc. St. Louis, MO A 96 47, IV D 116 439 M. C. Malott Delphi Automotive Systems, LLC Troy, MI 440 R. Fellows Transprint USA Harrisonburg, VA 441 J. Idzorek NRG Energy, Inc. Minneapolis, MN A 96 47, IV D 118 442 K. Finemore New Hampshire Department of Environmental Services Concord, NH 443 D. J. Krouskop MeadWestvaco MD Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 12 A 96 47, IV D 115 444 J. Jackson Boise Cascade Corporation Boise, ID 445 J. W. Shipp Tennessee Valley Authority Chattanooga, TN 446 T. P. Walmsley Fibrowatt LLC Yardley, PA 447 T. J. Norberg Rubber Manufacturers Association Washington, DC A 96 47, IV D 96 448 J. Walke Natural Resources Defense Council Washington, DC A 96 47, IV D 119 449 Council of Industrial Boiler Owners 450 M. A. Peters Counsel to American Airlines Inc., OK A 96 47, IV D 113 451 EarthJustice Washington, DC A 96 47, IV D 106 452 G. Gesell American Ref Fuel Company Montvale, NJ A 96 47, IV D 49 453 Attachment to OAR 2002 0058 0454 A 96 47, IV D 49 454 G. Narum Simpson Tacoma Kraft Company, LLC Tacoma, WA A 96 47, IV D 49 455 Attachment to OAR 2002 0058 0454 Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 13 456 M. Round Northeast States for Coordinated Air Use Management Boston, MA 457 Attachment to OAR 2002 0058 0456 458 Attachment to OAR 2002 0058 0456 459 Attachment to OAR 2002 0058 0456 460 Attachment to OAR 2002 0058 0456 461 Attachment to OAR 2002 0058 0456 462 Attachment to OAR 2002 0058 0456 463 Attachment to OAR 2002 0058 0456 464 Attachment to OAR 2002 0058 0456 465 Attachment to OAR 2002 0058 0456 466 Attachment to OAR 2002 0058 0456 467 Attachment to OAR 2002 0058 0456 A 96 47, IV D 92 468 B. Sorensen Packaging Corporation of America Lake Forest, IL A 96 47, IV D 94, IV D 95 469 M. R. Perry City of Hamilton Hamilton, Ohio A 96 47, IV D 91 470 D. R. Steiner City of Orrville Orrville, Ohio A 96 47, IV D 90 471 G. Freewalt City of St. Mary's St. Mary's, Ohio A 96 47, IV D 89 472 S. Rentfrow Crisp County Power Commission Cordele, GA A 96 47, IV D 88 473 J. D. Bassett Vaughn Bassett Furniture Galax, VA Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 14 A 96 47, IV D 87 474 D. P. Maddox Stanley Furniture Company Stanleytown, VA A 96 47, IV D 32 475 M. Hohman US Steel Corporation Clairton, PA A 96 47, IV D 86 476 P. A. Lacey American Gas Association Washington, DC A 96 47, IV D 85 477 C. Jones Ohio Environmental Protection Agency Columbus, OH A 96 47, IV D 84 478 E. Clark Synthetic Organic Chemical Manufacturers Association Washington, DC A 96 47, IV D 83 479 N. Dee National Petrochemical & Refiners Association Washington, DC A 96 47, IV D 82 480 T. Shonkwiler Duncan, Weinberg, Genzer and Pembroke Washington, DC A 96 47, IV D 81 481 R. P. Hornrighausen City of Dover Dover, OH A 96 47, IV D 80 482 D. R. Adams Wisconsin Electric Power Company Milwaukee, WI A 96 47, IV D 33 483 O. M. Dominguez National Aeronautics and Space Administration Washington, DC A 96 47, IV D 38 484 J. J. Lyphout University of Notre Dame Notre Dame, IN Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 15 A 96 47, IV D 79 485 M. Martinez Merck & Co., Inc. Whitehouse Station, NJ A 96 47, IV D 78 486 R. J. Barkanic PPL Services Corp. Allentown, PA A 96 47, IV D 77 487 W. C. Herz The Fertilizer Institute Washington, DC A 96 47, IV D 29 488 J. R. Strenkowski Counsel to Association of Battery Recyclers Inc. Washington, DC A 96 47, IV D 76 489 R. P. Streiter The Aluminum Association, Inc. Washington, DC A 96 47, IV D 75 490 G. J. Dana Alliance of Automobile Manufacturers Washington, DC A 96 47, IV D 74 491 R. W. Schenker General Electric Company Fairfield, CT A 96 47, IV D 73 492 J. J. Mayhew American Chemistry Council Arlington, VA 493 Attachment to OAR 2002 0058 0448 494 Attachment to OAR 2002 0058 0448 495 Attachment to OAR 2002 0058 0448 496 Attachment to OAR 2002 0058 0448 A 96 47, IV D 39 497 B. Perdue American Furniture Manufacturers Association High Point, NC A 96 47, IV D 109 498 J. W. Snyder The Corn Refiners Association, Inc. Washington, DC Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 16 A 96 47, IV D 117 499 P. F. Faggert Dominion Glen Allen, VA A 96 47, IV D 114 500 J. Carson Ispat Inland, Inc., East Chicago, IN 501 D. A. Buff The Florida Sugar Industry Gainesville, FL A 96 47, IV D 55 502 E. Bulgin The Amalgamated Sugar Company, LLC Nampa, ID A 96 47, IV D 23 503 W. S. Kubiak US Steel Corporation Pittsburgh, PA A 96 47, IV D 27 504 W. S. Unruh US Steel Corporation Fairfield, AL A 96 47, IV D 68 505 J. Alexander US Steel Corporation Gary, IN A 96 47, IV D 67 506 J. F. Stevens City of Vero Beach Vero Beach, FL A 96 47, IV D 66 507 M. E. Ludecker Wood Mode, Inc. Kreamer, PA A 96 47, IV D 65 508 C. R. Titus Kitchen Cabinet Manufacturers Association Reston, VA A 96 47, IV D 30 509 W. E. Schwandt Moorehead Public Service Moorhead, MN Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 17 A 96 47, IV D 64 510 P. A. Bennett Molded Fiber Glass Companies Ashtabula, OH A 96 47, IV D 132 511 W. B. Vaughan Vaughan Furniture Company Galax, VA A 96 47, IV D 135 512 A. Johnston Clean Air Task Force Boston, MA A 96 47, IV D 133 513 J. R. Groves Century Furniture Industries Hickory, NC A 96 47, IV D 134 514 P. W. Craymer Bernhardt Furniture Co. Lenoir, NC A 96 47, IV D 22 515 R. Hahn Jones Hamilton Co. Walbridge, OH A 96 47, IV D 99 517 G. L. Kiser La Z Boy, Inc. Monroe, MI A 96 47, IV D 100 518 J. H. Beall Fairfield Chair Company Lenoir, NC A 96 47, IV D 101 519 D. L. Chapman Goodyear Tire & Rubber Company Akron, OH A 96 47, IV D 103 520 A. Lawrence Department of Energy ( DOE) Washington, DC A 96 47, IV D 97 521 W. Kjonaas Purdue University West Lafayette, IN Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 18 A 96 47, IV D 98 522 R. M. Ridgway Coalition of University Coal fired Boiler Owners West Lafayette, IN A 96 47, IV D 72 523 M. Johnston Michigan Manufacturers Association Lansing, MI A 96 47, IV D 107 524 S. H. Bruntz Alcoa Power Generating Plant  Warrick Power Plant Newburgh, IN A 96 47, IV D 28 525 T. Mangum Drexel Heritage High Point, NC A 96 47, IV D 124 526 H. Martin Pennsylvania House, Inc. Lewisburg, PA A 96 47, IV D 125 527 D. C. Foerter Institute of Clean Air Companies, Inc. Washington, DC A 96 47, IV D 126 528 M. Carey Ohio Coal Association Columbus, OH A 96 47, IV D 127 529 R. C. Methier Georgia Dept. of Natural Resources Atlanta, GA A 96 47, IV D 128 530 M. R. Benoit Cement Kiln Recycling Coalition Washington, DC A 96 47, IV D 129 531 S. M. Kincaid Kincaid Furniture Company, Inc. Hudson, NC A 96 47, IV D 130 532 J. M. Daniel Virginia Department of Environmental Quality Richmond, CA Docket No. Docket ID No. OAR 2002 0058 Commenter, Address, Title or Description 19 A 96 47, IV D 131 533 R. Purdue Citizens Thermal Energy Indianapolis, IN A 96 47, IV D 63 534 W. J. Haley Miami University Oxford, OH A 96 47, IV D 136 535 P. McPherson Michigan State University East Lansing, MI A 96 47, IV D 48 536 T. Pugh American Public Power Association Washington, DC A 96 47, IV D 105 537 W. M. Barfield South Carolina Pulp & Paper Association Bennettsville, SC A 96 47, IV D 71 538 D. J. Harvey Louisiana Pacific Corporation Portland, OR 539 T. J. O'Toole U. S. Steel  Mon Valley Works Dravosburg, PA 540 S. E. Woock Weyerhaeuser New Bern, NC 541 W. OSullivan New Jersey Department of Environmental Protection Trenton, NJ 542 Ohio Department of Development _____, OH 20 The summary of public comments and responses is organized as follows:

3.0 Definitions 4.0 Applicability 4.1 General 4.2 Exemptions 4.3 Lower size cutoff 4.4 Major source 4.5 Delisting 5.0 Format of the Standard 5.1 Surrogates ( general) 5.2 Surrogates ( HCl) 5.3 Surrogates ( CO) 5.4 Miscellaneous 6.0 Compliance Schedule 6.1 General 6.2 Compliance Schedule for New Units 6.3 Compliance Schedule for Existing Units 6.4 Performance Testing 6.5 Miscellaneous 7.0 Subcategorization 7.1 General 7.2 Additional Subcategories 7.3 Size Threshold 7.4 Fuels 8.0 MACT Floor 9.0 Options Beyond the MACT Floor 9.1 General 9.2 Carbon Injection 9.3 Fuel Switching 10.0 Work Practices Standards 11.0 Compliance 11.1 General 11.2 Monitoring 11.3 Operating Limits 21 11.4 Performance Testing 12.0 Recordkeeping and Reporting 13.0 Impacts 13.1 Control Costs 13.2 Cost of Monitoring 13.3 Methodology 13.4 Cost to Municipal Power Generators 13.5 Economic Impacts 13.6 Cost of Regulation 13.7 Miscellaneous 14.0 Interaction with Other Rules 14.1 General 14.2 Section 129 14.3 Section 112 14.4 NESHAP for Electric Utility Steam Generating Units 15.0 Emission Averaging 16.0 Administrative Requirements 16.1 Executive Order 12866 16.2 Paperwork Reduction Act 16.3 Small Business Regulatory Enforcement Fairness Act 16.4 Unfunded Mandates Reform Act 16.5 Executive Order 13211 17.0 Miscellaneous 17.1 General Provisions 17.2 Editorial Corrections 17.3 Miscellaneous 22 3.0 Definitions Comment: One commenter ( 343) requested that EPA clarify the definition for " reconstructed affected source." The commenter recommended that EPA add wording to clarify that if a facility reconstructed boilers or process heaters while an area source, that these units would also be classified as existing affected sources in the event that the facility's status later changes to a major source of HAP. Response: The final rule clarifies the requirements for area sources that become major sources. In § 63.7495( c)( 2) of the final rule, EPA allows an existing boiler or process heater located at an area source that increases its emissions or its potential to emit such that it becomes a major source of HAP to comply with the subpart within 3 years of the facility becoming a major source. The reconstructed source is defined in 63.7490( c) as " A boiler or process heater is reconstructed if you meet the reconstruction criteria as defined in § 63.2 of subpart A of this part, you commence reconstruction after January 13, 2003, and you meet the applicability criteria at the time you commence reconstruction." The applicability criteria includes the provision that an affected source is located at a major source of HAP emissions. Therefore, if you reconstruct a boiler or process heater at an area source, then the source would not meet the definition of a reconstructed source for the purposes of this subpart since it did not meet the applicability criteria at the time you commenced reconstruction ( i. e., it was not located at a major source of HAP emissions). In this case, the boiler or process heater would be considered an existing source in the event a facility later becomes a major source of HAP emissions since it did not meet the definition of reconstructed source under this subpart.

Comment: One commenter ( 491) stated that Subpart DDDDD inconsistently uses the terms " source" and " affected source." The commenter stated that the rule applies to an " affected source," a term defined in § 63.2 of the General Provisions. The commenter stated that the term " source" is not defined and therefore has an uncertain meaning. The commenter stated that the rule should avoid use of the term " source" and be consistent and accurate in the appropriate use of the term " affected source." Response: In the final rule, we clarified the definition of affected sources for the purposes of this subpart. For existing sources, the affected source is the collection of affected boilers and the collection of affected process heaters. For new sources, each boiler and process heater is considered an affected source. We also modified the language in the final rule to be more consistent with terminology and adopted the term " boiler or process heater" when discussing individual units.

Comment: Several commenters ( 346, 360, 364, 382, 392, 387, 388, 399, 400, 410, 419, 449, 479, 490, 492, 498, 523, 524, 533) suggested that EPA revise the proposed definition of affected source to be consistent with the definition of affected source in the General Provisions. The commenters added that the affected source would then be the collection of industrial, commercial, or institutional boilers and process heaters located at a major source of HAP emissions. The definition in the rule is much more narrow than that in the General Provisions, even though the General Provisions states that each standard will redefine " affected source" based on published justification as to why the definition would result in significant administration, practical or implementation problems. The commenters argued that EPA failed to provide 23 justification for the proposed definition of affected source, which is narrower than the definition of affected source in the General Provisions. Response: We agree with the commenters and in the final rule have incorporated the broader definition of affected source from the revised General Provisions. The General Provisions define the affected source as " the collection of equipment, activities, or both within a single contiguous area and under common control that is included in a section 112 © source category or subcategory..." Therefore, the definition of existing affected source in the final rule is the collection of existing industrial, commercial, or institutional boilers and process heaters within a subcategory located at a major source of HAP emissions.

Comment: One commenter ( 491) stated that two or more boilers with a common fuel feed system, common baghouse and/ or common stack should be considered a single affected source. The commenter stated that requiring separation of boiler coal feed and combustion emission streams just for the purpose of complying with a rule written with the perspective of a single boiler or process heater is onerous and unreasonable. The commenter suggested changing the definition of boiler in § 63.7575 to read, " Boiler means an enclosed device using controlled flame combustion and having the primary purpose of recovering thermal energy in the form of steam or hot water. More than one enclosed device using controlled flame combustion and having the primary purpose of recovering thermal energy in the form of steam or hot water, and sharing the same fuel feed system, control equipment, and/ or emissions stack are considered to be a boiler if designated as such in the Notification of Compliance Status. Waste heat boilers are excluded from this definition." In addition, the commenter stated that the information required to be included in the Notification of Compliance Status pursuant to § 63.7545 needs to be expanded as follows: ( f) If you designate two or more enclosed devices using controlled flame combustion and having the primary purpose of recovering thermal energy in the form of steam or hot water, that share the same fuel feed system, control equipment and/ or emissions stack, to be a boiler, you must define those devices comprising the boiler in the Notification of Compliance Status report. Response: In the final rule, we revised the definition of existing affected source to be the collection of existing industrial, commercial, or institutional boilers and process heaters within a subcategory located at a major source of HAP emissions. We believe this change will resolve the commenter's concerns. Furthermore, we modified the fuel monitoring provisions of the rule from requiring daily fuel monitoring to requiring monthly fuel monitoring. This should provide relief for facilities that have units that share various components.

Comment: The commenter ( 492) suggested the term " deviation" should be changed to " excursion" to avoid confusion with Title V operating permit requirements and for consistency with other NESHAP ( e. g., HON). Response: We disagree with the commenter's suggestion. We recognize that the term excursion was used in the HON and other MACT rules. However, EPA's current policy is to use the term deviation to describe variances from the regulation. Anything not meeting the requirements from the standard is considered a deviation from the standard. We would like to clarify that deviations are only considered violations if the regulatory authority determines them to be violations of the standard.

Comment: Two commenters ( 447, 519) expressed concern over the EPA proposed definition of distillate oil. The commenter explained that the proposed rule defines distillate oil as 24 fuel oil number 1 or 2 as defined by American Society for Testing and Materials ( ASTM) with a nitrogen content of 0.05 or less. The commenters noted that the proposed rule references ASTM standard D396 78, which was the 1978 version. The commenters requested that EPA modify that reference to the most recent ASTM standard D396 02a. Secondly, the commenters noted that neither the specification nor the EPA includes a test method for determining nitrogen content. The commenters also questioned EPA's rationale in establishing a nitrogen content limit because EPA has not given any indication that nitrogen content is related to HAP emissions. The commenters believe that it is not appropriate to regulate distillate oils that have a nitrogen content higher than 0.05 percent as a residual fuel oil. The commenters requested that EPA delete any reference to nitrogen content in the distillate fuel oil definition. The commenter also stated that some fuel suppliers have been reluctant to certify that the oil they are supplying meets a certain ASTM specification. The commenters requested that EPA revise the proposed rule to allow for alternative means of demonstration that a boiler is consuming only non residual, or distillate oil. One commenter ( 529) questioned the definitions of " distillate oil" and " residual oil", asking for the purpose of using nitrogen content to determine fuel oil categories. One commenter ( 478) requested that EPA revise the definition of residual oil to not include number 2 oil. Response: In the final rule, we removed the nitrogen specifications that were contained in the proposed definitions of distillate and residual oil. We agree with the commenters that fuel oil should not be differentiated in this standard based on nitrogen content because such delineations are not appropriate for a standard regulating hazardous air pollutants. We also updated the ASTM standard reference for oil type determination. We believe that the proposed requirements for demonstrating whether you are not burning any residual oil is appropriate and did not change that requirement in the final rule. While fuel suppliers may not certify whether their oil meets an ASTM standard, suppliers typically categorize by ASTM oil numbers or by common names ( e. g., residual oil, distillate oil, kerosene, diesel).

Comment: One commenter ( 491) stated that the inclusion of " spray dryer" in the definition of dry scrubber is not necessary and adds confusion regarding the activity that is being defined. The commenter stated that in chemical manufacturing operations, a spray dryer typically refers to a unit operation other than scrubbing or emissions control. The commenter suggested the definition be clarified by either removing " spray dryer" or replacing it with another descriptive term as shown below: Dry scrubber means an add on air pollution control system that injects dry alkaline sorbent ( dry injection) or sprays an alkaline sorbent ( spray injection) to react with and neutralize acid gas in the exhaust stream, forming a dry powder material. Response: We retain the term " spray dryer" in the definition of dry scrubber because in some cases it does refer to a type of emission control device. Since there are no regulatory impacts of keeping this term in the definition and the context in which it is discussed clearly categorizes it as an emission control device, we do not believe that removing the term is justified.

Comment: One commenter ( 370) requested clarification of the definition of dry scrubber, which does not clearly include dry sorbent injection in circulating fluidized bed boilers as a dry scrubber. The commenter requested circulating fluidized bed boiler units with limestone and caustic sorbent injection to be considered control for inorganic acid gases. If the EPA does not intend to include circulating fluidized bed boilers with sorbent injection, then the commenter requested modification of the definition or modification of the rule. Response: In the final rule we included sorbent injection systems in fluidized bed boilers 25 in the definition of dry scrubbers. Since this type of control may be used to achieve compliance with the emission limits in this NESHAP, including sorbent injection systems will result in the sorbent injection rate being considered an operating limit for the purposes of ongoing compliance demonstrations.

Comment: One commenter ( 358) contended that EPA has redefined a utility boiler incorrectly by applying heat input to generator output. Response: The definition of electric utility steam generating unit in the proposal and in the final rule is consistent with the definition in section 112 of the CAA and in other EPA regulations. Since the definition is consistent with the CAA section that mandates the NESHAP program, we retain it in the final rule.

Comment: One commenter ( 529) questioned the definition of " biomass fuel," asking if wood residue and wood products include wood that contains some type of binder. Response: In the final rule, we clarify that biomass fuel includes unadulterated wood products. Plywood, particle board, oriented strand board, and other types of wood products bound by glues and resins are included in this definition. If the wood residue or wood product contains only binders and is not painted, pigment stained, or pressure treated with compounds such as chromate copper arsenate, pentachlorophenol, and creosote, then it is considered to be biomass.

Comment: One commenter ( 491) requested that EPA clarify the definitions of fuels to indicate that solid, liquid, and gaseous fuels are fuels and are not chemical feedstocks or something else. The commenter suggested the following clarifications: I. Solid fuel means fuel in solid form and includes, but is not limited to, coal, wood, biomass, tires, plastics, and other non fossil solid materials.

II. Gaseous fuel means fuel in gaseous form and includes, but is not limited to, natural gas, synthetic natural gas, process gas, refinery gas, gasified coal, biogas, and landfill gas, but does not include process vent streams burned to achieve emission control.

III. Liquid fuel means fuel in liquid form and includes, but is not limited to, distillate oil, residual oil, waste oil, and process liquids.

Response: We do not agree with the commenter's suggestion and retain the proposed definition for solid, liquid, and gaseous fuels in the final rule. We intended for the terms solid, liquid, and gaseous fuels to mean anything that is burned in a boiler or process heater. For example, if we incorporated the commenter's suggestion, a boiler that burns solid chemical feedstock and natural gas would be considered a gaseous fuel fired units, and would not have any emission limits. Since the solid chemical feedstock may contain regulated pollutants, by retaining the proposed definition of solid fuel, we at least require them to conduct a fuel analysis to determine if the pollutant content is lower than any applicable emission limit for solid fuel fired units.

Comment: Two commenters ( 490, 491) stated that the definition of " gaseous fuel" needs 26 to be modified to clarify that synthetic natural gas, gasified coal, and landfill gas are gaseous fuels so that boilers that fire these fuels will be considered to be in one of the gaseous fuel subcategories and not subject to emission limits. One commenter ( 490) stated that these fuels are gaseous and act like gaseous fuels in boilers. The commenter suggested revising § 63.7575 as follows: Gaseous fuel means fuel in gaseous form and includes, but is not limited to natural gas, synthetic natural gas, process gas, refinery gas, gasified coal, biogas, and landfill gas, but does not include process vent streams burned to achieve emission control. The other commenter ( 491) suggested that § 63.7575 be changed as follows: Coal means synthetic fuels, other than synthetic natural gas and gasified coal, derived from coal for the purpose of creating useful heat including, but not limited to, solvent refined coal, coal oil mixtures, and coal water mixtures, are included in this definition for the purpose of this subpart. Two commenters ( 335,336) suggested that the definition of gaseous fuels should be revised by adding coke oven gas ( COG) and blast furnace gas ( BFG) to the list of included gases to avoid confusion. Response: We agree with the commenters' suggestion for the definition of gaseous fuels and have modified the final rule to include these other gas types into the definition of gaseous fuel. With regard to blast oven gas, we have exempted units from this standard if they burn more than 90 percent blast furnace gas on an annual basis. Based on information provided by commenters, EPA agrees that blast furnace gas does not contain organic compounds and is comprised mostly of CO.

Comment: One commenter ( 491) urged EPA to provide that a process vent stream, which is routed to a boiler that serves as an emission control device, is not considered to be fuel for purposes of the boilers NESHAP. In addition, the commenter suggested that the gaseous fuel definition be changed to read, " Gaseous fuel includes, but is not limited to, natural gas, process gas, refinery gas, and biogas, but does not include process vent streams burned to achieve emission control." Response: We disagree with commenters' suggestion for the definition of gaseous fuels. As we explained in the previous comment, we intended to consider any gas burned in a boiler or process heater as a fuel, with the exception of blast furnace case. We do not believe that this is an issue, since existing gaseous fuel fired units do not have any emission limits, and new gaseous fuel fired units only have a carbon monoxide work practice standard.

Comment: One commenter ( 529) stated that because the term " other gases" is not defined in § 63.7575, it is assumed that the defined term " gaseous fuel" is consistent with the term " other gases." However, boilers and process heaters in one of the liquid fuel subcategories burning fossil fuels and other gases are not required to conduct a performance test. The commenter believed that allowing unspecified process gases to be combusted without determining compliance with standards provides no assurance of compliance. Response: In the rule, the use of the term other gases was intended to mean gaseous fuels as defined in § 63.7575. However, in developing the MACT floor for the boilers and process heaters subject to this NESHAP, there was no floor level of control. Therefore, no emission limits were applied to gaseous fuel fired units.

Comment: Several commenters ( 374, 388, 416, 449, 478, 491, 492, 498, 524, 533) requested that EPA revise the definition of hot water heaters to include liquid fuel fired hot water heaters and to adopt the higher pressure and temperature standards for hot water heaters 27 published by the American Society of Mechanical Engineers ( i. e., 160 p. s. i. and 250 degrees Fahrenheit). Response: In the final rule, we included liquid fuel fired water heaters under the definition of hot water heaters. However, we have retained the proposed temperature and pressure limitations for hot water heaters.

Comment: Several commenters ( 347, 353, 360, 364, 374, 379, 382, 387, 388, 396, 399, 400, 410, 439, 447, 449, 479, 482, 483, 485, 487, 490, 491, 492, 498, 519, 523, 524, 533) requested that EPA revise the definition of gaseous fuel fired units to allow a minimum annual capacity utilization ( hours of operation per year) on fuel oil, below which the affected unit would be classified as a gaseous fuel unit. The commenters explained that liquid fuel is used for a backup during periods of gas curtailment, gas supply emergencies, and other gas supply issues. Several commenters stated that the rule should specifically redefine gaseous fuel units to include units that have an annual capacity utilization on fuel oil of less than or equal to 10 percent ( 876 hours per year). One commenter ( 487) also requested that this exemption include periodic testing to ensure available and reliable fuel switching when needed. One commenter ( 483) cited Model Unit Development Memorandum, Docket A 96 47 item II B 6, because EPA concluded that units burning natural gas and Number 2 fuel oil would burn Number 2 fuel oil only as a backup fuel due to its costs and EPA assigned these units to the gas category. The commenter explained that incorrect assignment of these types of units into the liquid fuel subcategory would lead to unnecessary reporting and recordkeeping. One commenter ( 439) argued that imposing the particulate matter and hydrogen chloride limitations at all times for units that may burn liquid fuel less than one time annually is impractical and could result in higher emissions due to compliance testing that may take place more often than the alternative fuel is actually used. One commenter ( 410) noted that a number of California air pollution control districts provide for relaxation of emission limitations in recognition of natural gas curtailment. Response: We agree with the commenters that an allowance needs to be made to deal with periods of gas curtailment and gas supply emergencies. We recognize that such situations do not constitute normal operation, but are the result of extreme situations that are not controlled by the unit operator. Therefore, the final rule allows gaseous fuel fired boilers and process heaters to burn liquid fuel only during periods of gas curtailment or gas supply emergencies. We added a definition of " period of gas curtailment or supply interruption" and the final definitions of liquid fuel subcategory excludes units that burn liquid fuel during periods of gas curtailment or gas supply emergencies. We do not provide an allowance for units to test liquid fuel delivery systems as sources should maintain those systems during normal maintenance activities.

Comment: One commenter ( 519) requested that EPA modify the definition for new liquid fuel fired units so that units that fire residual oil less than 10 percent of the unit's capacity utilization would be subject to only the limited use standards. Response: We do not believe any change is necessary for the final rule. The proposed and final rule states that " Limited use liquid fuel subcategory includes any boiler or process heater that.... has a federally enforceable annual average capacity factor of equal to or less than 10 percent." We consider the definition to clearly identify units that are a part of the limited use subcategory. We also disagree with redefining liquid subcategories based on residual oil use only. While distillate oil and other liquids fired in boilers and process heaters are exempt from many of the rule requirements, these fuels are still liquids and units burning them alone or in combination 28 with a gaseous fuel should be considered when determining subcategories.

Comment: Several commenters ( 364, 382, 387, 388, 399, 440, 449, 473, 474, 479, 492, 497, 498, 511, 513, 514, 517, 518, 524, 525, 526, 531, 533 ) supported the inclusion of firetube boilers in the small solid fuel subcategory definition. In addition, many other commenters ( 343, 345, 382, 388, 440, 449, 479, 492, 498, 524, 533) requested that EPA add fire tube boilers to the definition of small liquid or gas fueled units. Response: We agree with the commenters' request to add firetube boilers to the definition of small liquid fuel and gaseous fuel subcategories and have incorporated these changes in the final rule.

Comment: One commenter ( 490) stated that according to § 63.7575, " process heater means an enclosed device using controlled flame, and the unit's primary purpose is to transfer heat indirectly to a process stream ( liquid, gas, or solid) or to a heat transfer material for use in a process unit instead of generating steam. Process heaters are devices in which the combustion gases do not directly come into contact with process materials." The commenter interpreted that units used for providing space heating are not process heaters. The commenter requested confirmation that this interpretation was correct. The commenter stated that if EPA should disagree with this interpretation, or for some reason decide to cover these space heaters in the rule, the Agency's cost analysis must be significantly revised upward due to the huge capital and recordkeeping costs that would be imposed. Two commenters ( 371, 428) recommended that the process heater definition be revised to exclude make up air, room air, space, or comfort heaters, as well as heating devices for preparation of food. One commenter ( 428) recommended that the process heater definition be revised to include an explicit definition of a process unit. The commenter stated that without the definition of a process unit, there exists a very strong possibility that the regulation might be incorrectly applied to sources such as space and comfort heaters. One commenter ( 491) stated that the definition of " process heater" is sufficiently broad that one might interpret that indirect fired furnaces, autoclaves, dryers, etc. are process heaters. The commenter suggested revising § 65.7575 as follows: " Process heater means an enclosed device using controlled flame, and the unit's primary purpose is to transfer heat indirectly to a process stream ( liquid, gas, or solid) by way of a heat transfer material instead of generating steam. Process heaters are devices in which the combustion gases do not come in contact with process materials. Indirect fired process units such as furnaces, autoclaves, dryers, etc. are not process heaters." Response: We agree that comfort heaters and other types of units discussed by the commenters should not be subject to this NESHAP. It was not EPA's intention to regulate such systems in this standard. The majority of these systems are gas fired and are very small. Therefore, in the final rule we specifically excluded comfort heaters, space heaters, units used for food preparation for on site consumption, and autoclaves from the definition of process heaters.

Comment: One commenter ( 488) stated that the definition of process heater would include any enclosed device using a controlled flame where the unit's primary purpose is to transfer heat indirectly to a process material, instead of generating steam. The commenter stated that this definition could be interpreted to suggest that the boiler NESHAP applies to refining kettles at secondary lead smelters, which are already subject to the Secondary Lead MACT. The commenter suggested changing the language in § 63.7490( b)( 9) to read " A refining kettle that is 29 an affected source under 40 CFR part 63, subpart X." Response: We do not intend for the boilers NESHAP to affect units that are already regulated by another NESHAP. We clarified the applicability section of the final rule to ensure that this does not happen. Furthermore, § 63.7490 ( b)( 9) specifically excludes refining kettles covered by 40 CFR part 63, subpart X. We believe this to be sufficient and do not believe any further explanation/ changes are necessary for this specific piece of equipment.

Comment: One commenter ( 410) noted that the definition of process heater in § 63.7485( a) is not identical to the one in the definitions section of the rule and requested that the definition include heat transfer fluids. Response: We have removed the boiler and process heater definitions from § 63.7485( a) and only provide definitions for boilers and process heaters in § 63.7575. 30 4.0 APPLICABILITY 4.1 General Comment: One commenter ( 427) suggested a model to discretely define high risk urban areas at significantly lower costs than are in the proposed rule. The commenter also suggested limiting the rule's applicability to solid fuel fired sources. The commenter added that a facility would then be required to install whatever control device is necessary to comply and develop a site specific operation and maintenance plan that details how the source will be monitored and the device maintained. The commenter continued that sources would perform an initial test to validate monitoring parameters, and compliance with the operation and maintenance plan would constitute compliance with the MACT standard. The commenter added that control device performance summaries and excess emission reports could be summarized and submitted on an annual basis. Response: We disagree with the commenter. The CAA does not allow us to focus emission standards on only high risk urban areas in the NESHAP program. Additionally, we do not believe there is any legal justification for regulating only solid fuel fired units. The source category list does not differentiate boilers by fuel, but refers to all industrial boilers and all institutional and commercial boilers. We believe that the final rule meets the requirements of the CAA, but also limits the burden on subcategories where the MACT floor analysis indicates no emission reduction was determined. These subcategories include gas and liquid fuel fired units. Under the residual risk program outlined in section 112( f) of the CAA, we will review emissions from this subcategory and promulgate additional standards if necessary to provide an ample margin of safety to protect public health. With regard to compliance, you may use whatever control device or strategy you choose to meet the emission limits of this rule. You are not required to use the MACT floor level of control, but you are required to meet the emission limits that were based on the MACT floor level of control. We also allow you to petition the Administrator for approval of an alternative monitoring plan under § 63.8( f) of subpart A of part 63 if you want to develop a site specific monitoring plan that is different from those contained in the final rule.

Comment: One commenter ( 491) stated that boilers and process heaters located at area sources of HAP do not significantly impact air quality. The commenter supports limiting the boilers NESHAP applicability to a boiler or process heater that is located at a major source of HAP. However, another commenter ( 397) noted that similar sources affected by the boilers NESHAP also exist at area sources and would not be regulated by this NESHAP. The commenter expressed concern that the health risks from units located at nonmajor sources would be the same as those located at major sources, yet would go unregulated. Response: Per the requirements in section 112( d) of the CAA, the boilers NESHAP regulates only units located at major sources. We realize that similar sources affected by this rule also exist at area sources and are not regulated under this rule. However, EPA is also studying emissions from boilers and process heaters located at area sources. We will use the results of this study to make a decision on whether to regulate units located at area sources. We anticipate completing this study and determining if boilers and process heaters located at area sources should be regulated in the near future.

Comment: One commenter ( 491) stated that the boilers NESHAP attempts to establish 31 rule applicability in § 63.7485 and § 63.7490. The commenter stated that this complicates the understanding of applicability because it defines terms in the applicability sections that already have defined meanings arising from the definitions established in § 63.7575 and § 63.2. The commenter stated that terms appearing in applicable rule definition sections should not be redefined in another section of the rule. The commenter stated that redefining terms in § 63.7485 creates confusion and adds unnecessary narrative. The commenter suggested that EPA clarify § 63.7485 as follows: " You are subject to this subpart if you own or operate an industrial, commercial, or institutional boiler or process heater, as defined in § 63.7575, that is located at, or is part of , a major source, as defined in § 63.2, except as specifically exempted in § 63.7490." In addition, the commenter stated that the above change would require that § 63.7490( b) be revised as follows: " The affected source is each industrial, commercial, or institutional boiler or process heater, as defined in § 63.7575, that is not one of the types of combustion units listed in § 63.7490( b) ( 1) through ( 10)." Response: We agree with the commenters that the applicability section and definitions in the proposed rule overlap and may not be consistent with each other. In the final rule, we removed definitions from the applicability section and present them in only the definitions section of the final rule or refer you to the definitions contained in the General Provisions ( subpart A of part 63).

Comment: One commenter ( 485) noted that § 63.7495( c)( 1) is redundant with ( a)( 1) and ( 2), is unnecessary, and should be removed. The commenter also requested that § 63.7495( c)( 2) be included into § 63.7495( b). Response: We disagree with the commenter and made only minor changes to this section in the final rule. The provisions contained in § 63.7495( c) address compliance schedules for facilities that are area sources at the time the final rule is promulgated, but become major sources at a later date. The provisions in § 63.7495( a) and ( b) outline the compliance schedule for sources at facilities that are major sources at the time the final rule is published.

Comment: One commenter ( 369) requested that EPA clarify that sources reconstructed before January 13, 2003 are subject to the proposed rule's existing affected source requirements and not subject to the proposed rule's reconstructed affected source requirements. The commenter pointed out that the rule's applicability to reconstructed affected sources would not be limited to those reconstructed after the proposed rule's publication date based on the proposed rule. The commenter believes this would unreasonably limit the number of affected sources that would qualify as an existing affected source. Response: In the final rule, we clarify that sources that commence reconstruction before January 13, 2003 would be considered existing sources under this NESHAP. In the proposal, we inadvertently did not include a trigger date for reconstructed sources.

Comment: Two commenters ( 374, 400) requested that EPA clarify that if units that commence construction or reconstruction before January 13, 2003 and become subject to this standard after promulgation due to a change in operation ( e. g., no longer burn hazardous waste) would fall under the existing source category and not be classified as a new source. One commenter ( 374) proposed rule language to address this clarification. Response: In the final rule, § 63.7490( d) and ( e) state that you are a new or reconstructed source if you commence construction or reconstruction after January 13, 2003 AND you meet the 32 applicability criteria at the time you commenced construction or reconstruction. Furthermore, § 63.7490( f) states that a source is existing if it does not meet the definition of new or reconstructed. Based on these revisions, it is clear that any source that commences construction or reconstruction on or before January 13, 2003 is considered an existing source. Also, since the source the commenter alluded to was considered a hazardous waste boiler at the time of construction or reconstruction, it would be considered an existing source because the definitions of new and reconstructed units contained in § 63.7490( d) and ( e) state that you must meet the applicability requirements of this NESHAP at the time you commenced construction or reconstruction. As the source was subject to the hazardous waste NESHAP at the time it commenced construction or reconstruction, and did not meet the applicability requirements of this NESHAP at that time, any change in operation that would result in that source becoming subject to this NESHAP as an existing source.

Comment: One commenter ( 492) suggested that EPA clarify for the boilers NESHAP that retrofitting and control costs to comply with the boilers NESHAP are not considered reconstruction costs. The commenter proposed that the boilers NESHAP include language similar to that found in the Hazardous Waste Combustor NESHAP ( 40 CFR 63.1206( a)( 2)). Response: We agree with the commenter that retrofits and control equipment costs incurred in complying with the boilers NESHAP should not be considered reconstruction costs. This consideration is consistent with previous EPA regulatory decisions.

Comment: One commenter ( 410) requested EPA clarify that the components to be considered in judging whether reconstruction has occurred should include the entirety of the boiler or process heater, and that reconstruction must involve replacement of boiler or heater components amounting to 50 percent or more of the cost of the entire comparable new boiler or heater. The commenter provided a list of equipment components that are part of boilers and process heaters. Response: In the general provisions to 40 CFR part 63, reconstruction is defined as: " Reconstruction, unless otherwise defined in a relevant standard, means the replacement of components of an affected or a previously nonaffected source to such an extent that: ( 1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable new source; and ( 2) It is technologically and economically feasible for the reconstructed source to meet the relevant standard( s) established by the Administrator ( or a State) pursuant to section 112 of the [ Clean Air] Act. Upon reconstruction, an affected source, or a stationary source that becomes an affected source, is subject to relevant standards for new sources, including compliance dates, irrespective of any change in emissions of hazardous air pollutants from that source." Based on this definition and the definition of affected source in the final rule, you would have to spend 50 percent or more of the cost of the collection of all your affected existing boilers or the collection of all your existing process heaters to trigger reconstruction. Given the broad definition of existing affected source in the final rule, we do not specifically identify components that are considered in judging whether reconstruction has occurred. We have clarified in other responses to comments that retrofits and control equipment costs incurred in complying with the boilers NESHAP should not be considered reconstruction costs.

4.2 Exemptions 33 Comment: One commenter ( 491) stated that natural gas used to maintain coal boiler igniter/ pilot flame controls should be excluded from the regulation. The commenter stated that requirements to account for such small uses of gas ( e. g., in various recordkeeping, reporting, compliance determinations, and calculations in § 63.7530( c)) is onerous and has a negligible impact on environmental protection. The commenter suggested that EPA simplify recordkeeping, reporting, and compliance determination by excluding accounting for de minimis fuel burned for igniter/ pilot flame controls from the rule.

Response: We do not specifically exclude fuel used to maintain pilots or for flame control. In the final rule, we most liquid and gaseous fuel fired units are not subject to fuel monitoring requirements. We also reduced fuel monitoring frequency to once a month for sources that are required to monitor fuel use. Given these changes, we believe that the fuel monitoring burden is not significant. Furthermore, the amount of fuel used for these purposes may not be the same from source to source and some sources may also use these fuels as a significant source of heat input.

Comment: Several commenters ( 402, 410, 479, 490) requested that EPA exempt units that are used to achieve emission reductions or are required for emission control. Several commenters ( 410, 479, 490) requested an exemption for incinerators, thermal oxidizers, and flares that are required or selected to comply with pollution regulations. They also requested exemption for flares installed for safe disposal of flammable gases released from a process unit due to abnormal process conditions. One commenter ( 402) noted that pre heaters for sulfuric acid plants used for emission control at copper smelting plants may be subject to the proposed NESHAP, but compliance with the emission standards and work practice requirements may interfere with the effectiveness of the acid plant as a pollution control device under the Copper Smelting NESHAP.

Response: The final rule clarifies that equipment that are included as part of the affected source in another NESHAP are not subject to the boilers NESHAP. However, we do not exempt boilers and process heaters that are used as control devices unless they are specifically considered part of another NESHAP's definition of affected source. Incinerators, thermal oxidizers, and flares do not generally fall under the definition of a boiler or process heater and would not be subject to this rule. However, if one of these types of units are subject to this rule, they typically burn gaseous and liquid fuels and existing sources firing gaseous and liquid fuels do not have any significant requirements under this NESHAP.

Comment: One commenter ( 491) supported the exclusion of waste heat boilers. Several commenters ( 360, 382, 388, 394, 449, 492, 498, 524, 533) recommended EPA exempt commercial and industrial solid waste incinerators ( CISWI units) with energy recovery from the definition of affected source. The commenters cited preamble language in the proposed rule that indicates that CISWI units with energy recovery will not be regulated by the boilers NESHAP. The commenters noted that the proposed regulatory language is not clear and should be revised to specifically exclude these units. Several commenters ( 410, 436, 479) requested that EPA revise the definition of boilers and waste heat boilers to exclude waste heat recovery devices and waste heat evaporators. Two commenters ( 410, 479) requested that EPA exempt waste heat boilers that have supplemental firing as long as the primary heat input is from waste heat. One commenter ( 529) recommended the phrase, " Waste heat boilers are excluded" be moved from 34 § 63.7485( a) to § 63.7490.

Response: The final rule excludes waste heat boilers and waste heat boilers with supplemental firing, as long as the supplemental firing does not provide more than 50 percent of the waste heat boiler's heat input. If your waste heat boiler does receive 50 percent of its total heat input from supplemental firing, it may be subject to the boilers NESHAP unless it is subject to another NESHAP. The final rule directly addresses sources that have been specifically listed as an affected source under another NESHAP but not making them subject to this standard.

Comment: One commenter ( 476) supported EPA's exclusion of residential natural gasfired hot water heaters from the proposed boilers NESHAP. One commenter ( 479) requested that EPA exempt liquid fuel fired hot water heaters from the final boilers NESHAP.

Response: We agree with the commenters regarding not requiring liquid fuel fired hot water heaters and liquid fuel fired hot water heaters to be subject to this rule, as long as they meet the size, temperature, and pressure criteria outlined in the definition section of the final NESHAP.

Comment: Two commenters ( 410, 497) requested that EPA exempt any boilers used to make steam or heated water solely or primarily for comfort heating.

Response: We specifically make comfort heaters not subject to the final rule. However, we do not provide a blanket exemption for boilers used to make steam or heated water for comfort heat. If your boiler meets the definition of a hot water heater, then it would not be subject to this rule. However, if the size, temperature, and pressure specifications of your boiler exceed the criteria specified for hot water heaters, then your boiler would be subject to this NESHAP.

Comment: Several commenter ( 343, 413, 491, 499) requested that EPA specifically exclude duct burners from the final NESHAP. One commenter ( 499) requested the rule clarify that " duct burners" for heat recovery steam generators are not affected sources for purposes of the MACT for small boilers and process heaters. One commenter ( 413) expressed concern that duct burners on combined cycle units would be affected under the proposed rule.

Response: In the final rule we do not make waste heat boilers ( or heat recovery steam generators) subject to this rule as long as their supplemental firing ( including duct burners) does not provide more than 50 percent of the heat input to the waste heat boiler. If your duct burner provides more than 50 percent of the total heat input to your heat recovery steam generator, then it would be subject to this NESHAP.

Comment: Several commenters ( 156, 335, 336, 371, 374, 376, 382, 388, 394, 434, 437, 449, 450, 487, 491, 498, 520, 524, 533) recommended that the final boilers NESHAP exempt units that have no emission limits or work practice standards from all monitoring, recordkeeping, and reporting requirements of the boilers NESHAP and the General Provisions. One commenter ( 489) expressed confusion over the applicability of notification, reporting and recordkeeping provisions to units without emission limits or work practice standards and requested clarification in the final rule on the requirements for affected sources that have no emission limits. However, 35 several commenters ( 343, 437, 491, 520) specifically requested that EPA not exempt these units from the startup, shutdown, and malfunction plan requirements of the NESHAP. Two commenters ( 376, 489) supported the proposed provisions stating that existing gas fired sources do not have emissions limits and do not need to follow work practice standards to maintain compliance. Several commenters ( 374, 382, 388, 394, 449, 487, 498, 524, 533) noted that other MACT standards provide this exemption and that the level of burden is not justified. The commenters suggested that if EPA does decide to impose some level of reporting for these units that it be limited to no more than an initial notification.

Response: We agree that sources that do not have any emission limits or work practice standards should not have to comply with monitoring, recordkeeping, and most reporting requirements, including startup, shutdown and malfunction plans. The final rule limits the monitoring, recordkeeping, and reporting requirements for sources that have no emission limits or work practice standards to initial notifications for larger sources, and no requirements whatsoever for smaller sources. We are also not requiring startup, shutdown, and malfunction plans for sources that do not have any emission limits or work practice standards. This is appropriate because no reports other than the initial notification would apply to these units. We do not believe the SSM plan to be necessary or required for these units because § 63.6( e)( 3) of subpart A of this part requires an affected source to develop an SSM plan for control equipment used to comply with the relevant standard. The proposed rule was not intended to require monitoring, recordkeeping, and reporting ( including startup, shutdown, and malfunction plans), other than the initial notification for sources not subject to an emission limit. We have clarified this decision in the final rule. We have also determined that existing small units, which are not subject to emission limits or work practices in this standard, and which are also not subject to such requirements in any other Federal regulation, should also not have to provide an initial notification. These small sources are generally gas fired and since they have minimal emissions, they are usually considered as insignificant emission units by State permitting agencies.

Comment: Several commenters ( 360, 364, 379, 382, 387, 388, 394, 399, 406, 407, 408, 430, 439, 449, 479, 487, 492, 498, 501, 524, 533) requested that EPA specifically exclude portable/ transportable units from the final rule. The commenters stated that facilities periodically use these units to supply or supplement other site steam supplies when there is a mechanical problem that takes a unit out of service or during planned outages. The commenters added that because they are used on a limited basis, portable units are not fully integrated with site control systems and most portable/ transportable units are owned by a rental company and may not be operated by the facility owner or operator. One commenter ( 479) that these types of units typically fire only natural gas or distillate oil. Several commenters ( 382, 406, 407, 408, 492, 501) also suggested revised rule language that would exclude rental or temporary boilers, as long as the units do not remain at one location for more than 12 consecutive months.

Response: We agree with the commenters that temporary/ portable units are used only on a limited basis and are not integrated into a facilities control system. In the final rule, we make gaseous and liquid fuel fired temporary boilers not subject to the requirements of this NESHAP. Units in the existing gaseous or liquid subcategories are not subject to emission limits or work practice standards. Consequently, we have decided to make temporary/ portable units not subject to the final rule. We have added a definition for temporary boiler to mean any gaseous or liquid fuel fired boiler that is designed, and is capable of, being carried or moved from one location to 36 another. A temporary boiler that remains at a location for more than 180 consecutive days is no longer considered to be a temporary boiler. Any temporary boiler that replaces a temporary boiler at a location and is intended to perform the same or similar function will be included in calculating the consecutive time period. We chose the 180 day time frame because that is the length of time a new source has after startup to conduct the initial performance test.

Comment: Several commenters ( 336, 339, 345, 356, 361, 362, 377, 395, 405, 427, 439, 489, 490, 523, 529) recommended exempting gaseous fuel fired units from the final rule. Two commenters ( 477, 510) requested that EPA exempt the small gaseous fuel fired category. The commenters noted that these units do not have any emission limits and that making them undergo the various recordkeeping and reporting requirements would be an unnecessary waste of resources. Several commenters ( 336, 339, 361, 362, 427, 529) requested that EPA exempt all existing liquid fuel fired units. The commenters questioned why EPA would still subject these units to the NESHAP when they have no emission limits or work practice standards. Two commenters ( 405, 529) suggested that all distillate oil fired units be exempted. One commenter ( 336) requested that EPA exempt existing small solid fuel fired units from the NESHAP. Many of the commenters stated these units are inherently low in HAP emissions and the EPA cannot quantify any environmental benefits from subjecting them to this NESHAP. One commenter ( 523) noted that since EPA did not set emission limits for these units, it indicates that they are not significant sources of HAP. In addition, the commenters stated that it will eliminate the large costs associated with recordkeeping and reporting and the requirement to install carbon monoxide monitors for new units. Commenters also claimed it would significantly reduce the burdens placed on permitting agencies to maintain permits for these facilities. One commenter ( 489) argued that including these sources in the rule has no environmental benefits and is in contravention of the purpose of the Paperwork Reduction Act of 1995. One commenter ( 490) stated that this solution would create an incentive for facilities to use this clean burning fuel when it is possible to do so.

Response: We are required by the Act to regulate sources on the source category list. The list includes industrial, commercial, and institutional boilers and process heaters. Consequently, all such units, regardless of size, are required by the Act to be regulated. At proposal, and in the final rule, we did separate sources into small, large and limited use subcategories for the reasons described in the proposal preamble and preamble to the final rule. As such, we determined that there were no MACT floors for existing small subcategories and limited use and large gaseous and liquid fuel subcategories. We revised the final rule to require existing units that do not have emission limits or work practice requirements to submit only an initial notification. For some smaller units with no emission limits or work practice standards, there are no requirements. New gaseous and liquid fuel fired units that have a capacity of 10 MMBtu/ hr to 100 MMBtu/ hr must conduct an annual test to maintain CO limits and must keep records of the annual test. Units larger than 100 MMBtu/ hr must install and operate CO CEMS. We consider these to be minimal requirements that will facilitate good combustion practices, and will not burden owners or operators of these units. New liquid and solid fuel fired units will be required to meet new source emission limits based on the results of EPA's MACT floor analysis for new units. Since these emission limits were developed in accordance with the procedures outlined in section 112( d), we must require these sources to meet at least the MACT floor level of control. To minimize the burden on affected sources, we revised the final rule to streamline the monitoring requirements of 37 this NESHAP.

Comment: One commenter ( 502) requested that EPA exempt boilers and process heaters at sugar beet facilities from the final boilers NESHAP. The commenter stated that the application of hydrogen chloride and acetaldehyde HAP potential to emit analysis to seasonal facilities greatly exaggerates HAP levels, categorizing them as major sources and will result in high costs with minimal environmental benefit. The facilities cannot be moved or closed without creating an economic disaster for sugar beet growers. The commenter pointed out that there are no MACT standards for sugar beet factories. The commenter pointed out that as a seasonal food processor, the commenter's facility generates small amounts of HAP as a by product of combustion or food processing, but it makes no sense to impose MACT standards on boilers for HAP released through vents or boilers that are not regulated through a permit. Both hydrogen chloride and acetaldehyde are subject to no emission limits or regulatory requirements.

Response: The only boilers and process heaters that will be affected by this NESHAP are those that are located at a major source. If you are a major source, then your facility must have a Title V Operating Permit. We are required to regulate all boilers and process heaters located at major sources according to the provisions of section 112 of the CAA and cannot exclude some sources due to cost. While no MACT standard for sugar beet factories may exist, boilers and process heaters are a listed source category under section 112 and must be regulated by a NESHAP program if they are located at a major source of HAP emissions.

Comment: One commenter ( 446) explained that their facility burns poultry litter and requested that EPA not regulate those types of units under this MACT standard because they are not " similar" types of sources and should be regulated under another category. The commenter further noted that tracking fuel suppliers and specifying fuel content is not workable for these types of units.

Response: We recognize the that the commenter burns a unique fuel. However, we consider units burning poultry litter to be part of the solid fuel fired subcategory and subject to the requirements of the rule. We revised the fuel sampling, monitoring, and recordkeeping requirements so the final rule accommodates more sources that burn fuel from many different suppliers. We also provide a compliance option that is based on fuel analysis. We believe that these changes will resolve the commenter's concerns regarding fuel monitoring may provide compliance relief if the fuel sampling strategy for compliance demonstration can be used.

Comment: One commenter ( 445) explained that some limited use boilers are simply used for the startup of larger, electrical utility boilers and that the cost of the equipment and maintaining the equipment needed to comply with the requirements for new, limited use gaseous or liquid fuel fired boilers does not seem reasonable. Therefore, the commenter requested that EPA exempt gaseous and distillate fuel fired boilers used only for the purpose of startup of electrical utility steam generators.

Response: We do not provide a specific exemption for boilers used to startup electrical utility steam generators. Existing gaseous and liquid fuel fired units do not have any emission limits or work practice standards, and at most are required to submit an initial notification. 38 Therefore, we do not believe that there is a compliance burden for units used to startup larger electrical utility boilers. For new gaseous fuel fired units, there are no emission limits, and for limited use units and units smaller than 100 MMBtu/ hr that have an applicable work practice standards, the final rule requires only that you conduct an annual emission test for carbon monoxide. You are not required to install a CEMS for carbon monoxide. Distillate oil fired units that fall under the new or new limited use categories do have emission limits, but the only requirement for demonstrating compliance is to keep records that you are not burning any residual oil. For new distillate oil fired units less than 100 MMBtu/ hr and for new limited use distillate oil fired units with an applicable carbon monoxide work practice standard, you are not required to install a CEMS for carbon monoxide. You only have to conduct an annual performance test. New units larger than 100 MMBtu/ hr must install a CEMS for carbon monoxide. Given the revisions since proposal that provide additional flexibility and reduce the compliance burden for many affected sources, we do not believe that the cost of compliance are significant for these types of units.

Comment: One commenter ( 382) requested that EPA treat units that fire fuels meeting the comparable fuels limits similarly to distillate oil fired units and receive an exemption from the particulate matter and hydrogen chloride emission limits. Two other commenters ( 485, 492) suggested that EPA exempt units burning fuels comparable to distillate oil under 40 CFR 261.38 ( and not residual oils). One commenter ( 485) argued that imposing the liquid non fossil and residual oil requirements on comparable fuels would discourage their use, increase the use of fossil fuels, and increase the emissions of greenhouse gases.

Response: The EPA disagrees with the commenters request. The comparable fuels requirements in 40 CFR 261.38 distinguishes between materials that are considered hazardous solid waste and fuels. Based on the latest CISWI regulations all materials burned in boilers and process heaters are fuels. We believe it is inappropriate and unnecessary to incorporate a comparable fuels allowance for distillate oil in the final rule. We would also note that the rule considers a fuel to be distillate oil if it meets the ASTM requirements for distillate oil.

Comment: Several commenters ( 406, 407, 408, 501) requested that EPA exempt bagasse fuel from the boilers NESHAP. The commenters noted that bagasse is a clean fuel by nature, air dispersion modeling demonstrates no risk to the public from bagasse combustion, existing controls are adequate to control emissions below the proposed standards, and the rule would cause significant impacts with no benefit to the environment. The commenters provided emission, dispersion modeling, and fuel analysis data from bagasse fuel fired sources. Another commenter ( 446) argued that since renewable biomass sources only cycle mercury, rather than introducing new mercury, these types of sources should be considered de minimis sources of mercury and not regulated.

Response: We recognize that some biomass fuels have lower emissions of regulated HAP than other solid fuels. However, we maintain that biomass should still be regulated by this NESHAP because it emits some metals and inorganic HAP. Therefore, we do not exempt biomass from this NESHAP. In the final rule, we provide an option to demonstrate compliance with the emission limits of this NESHAP through fuel sampling. If the results of your fuel sampling ( in units of pounds of pollutant to the heat content of the fuel in MMBtu) show regulated pollutant levels less than your applicable emission limits, then you are in compliance 39 with this NESHAP and only monitor monthly fuel use and to conduct additional fuel sampling on that same fuel type once every five years. We provide this option for sources that burn fuel that inherently have low HAP content to minimize the compliance burden.

Comment: One commenter ( 500) stated that new blast furnace gas ( BFG) fired units that meet the definition of a process heater should be exempt from the 400 ppm CO standard. The commenter stated that the low heating value to volume ratio of BFG, its moisture variability, flame characteristics, variances in its generation rate, and Wobbie index due to normal blast furnace process adjustments make complying with this standard virtually impossible. In addition, the commenter stated that BFG fired process heaters and boilers have always been considered " clean" fuel units and should therefore be exempted from the boilers NESHAP unless EPA studies show otherwise.

Response: We recognize the unique properties of blast furnace gas having high CO emissions, agree that these sources could not meet the CO limit, and have determined that monitoring CO would not indicate that the unit was operating under good combustion practices or reducing organic HAP. As a result, we make units that receive 90 percent or more of their total heat input from blast furnace gas not subject to this rule.

Comment: Two commenters ( 358, 423) contended that EPA should exempt small utility boilers less than 25 megawatts from the rule. The commenters asserted that when the CAA established a threshold capacity for utility boilers, it intended to limit EPA's regulation of small utility boilers, therefore, categorically exempting them. The commenters expressed concern that EPA used this " regulatory limiting" exclusion to include small utility boilers in the proposed rule. One commenter ( 358) requested that EPA clarify its intent to regulate fossil fuel fired utility boilers within this regulation and EPA should address any concerns the regulated entities may have over its narrow definition of utility boilers. The commenter supported a fossil fuel fired boilers NESHAP that would evaluate the appropriateness of controls, the types of specific controls unique to the utility industry, and the specific HAP of concern, as determined by the Utility Boiler MACT Workgroup.

Response: The CAA requires us to study HAP emissions from fossil fuel fired utility boilers and we are in the process of evaluating these emissions. The results of that study will determine if utility boilers will be regulated under the NESHAP program. The CAA defines a utility boiler as " any fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one third of it potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale..." If your boiler does not fall under the above definition of a utility boiler and your boiler is located at a major source, then you are subject to this NESHAP.

Comment: Several commenters ( 345, 427, 428) recommended regulating only solid fuelfired units. One commenter ( 345) stated that by eliminating all categories except solid fuel would cause the emission reductions to be reduced by less than 1 percent, while the costs would be reduced by $ 39 million per year ( annualized) and $ 166 million capital. 40 Response: The CAA requires us to regulate sources on the source category list. The source category list includes all industrial, commercial and institutional boilers located at major sources, not just solid fuel fired units. Therefore, we are legally obligated to include liquids and gaseous fuel fired units in the boilers NESHAP. Additionally, we cannot use cost as a deciding factor in developing the MACT floor. Also, our MACT floor analysis shows that new liquid units should meet an emission limit and all new units should meet a CO work practice. Since the MACT floor level of control for existing gaseous and liquid fuel fired units was no control, we make these units not subject to most of the requirements of this NESHAP. For units that do not have emission limits under this NESHAP, we require them to do nothing more than submit a notification of their existence ( initial notification), and some have no requirements at all. All existing units less than 10 MMBtu/ hr have no requirements at all under this NESHAP, and an initial notification is the only requirement for existing large and limited use gaseous and liquid fuel fired units and for new small gaseous and liquid fuel fired units. We believe that these final requirements minimize the impact of the final NESHAP for thousands of non solid fuel fired units.

Comment: One commenter ( 416) suggested for combined cycle turbine power plants, the exemption in § 63.7490( b)( 3) should be clarified as to whether 25 megawatts applies only to the steam generation portion of the power plant or the power plant as a whole.

Response: As is consistent with Subpart Db, the 25 MW requirement refers only to the steam generation portion of the power plant.

Comment: Several commenters ( 360, 377, 382, 491) supported EPA's proposed list of excluded sources in § 63.7490( b). Several commenters ( 337, 360, 402, 410, 418, 431, 437, 475, 479, 489, 490, 503, 504, 505) requested specific exemptions from the boilers NESHAP because they were concerned that some equipment may become subject to more than one NESHAP. The specific equipment requested for exemptions included: process heaters at magnet wire facilities ( Surface Coating of Miscellaneous Metal Parts and Products NESHAP); boilers and process heaters at carbon black facilities ( Generic NESHAP); boilers and process heaters associated with a catalytic cracking, catalytic reforming, or sulfur recovery units ( Refinery MACT II); asphalt oxidizers subject to 40 CFR part 63, subpart LLLLL; direct fired cure ovens, spray booth air tempering systems, and because these are integral components of any surface coating operation ( Auto/ Light Duty Truck, Plastic Parts, and Miscellaneous Metal Parts NESHAP); units subject to 40 CFR part 63, subparts HH and HHH; blast furnace stoves; coke oven batteries; and annealing furnaces. One commenter ( 524) expressed concern over EPA's attempt to specifically list sources exempted from this rule because they are subject to another MACT standard. Two commenters ( 524, 489) suggested that EPA delete that exclusion list and replace it with a generic exemption that exempts units that are already, or will be, subject to another NESHAP. Another commenter ( 343) requested that EPA clarify the exclusion for boilers burning hazardous waste in § 63.7490( 4) to help sources determine applicability. In addition, the commenter stated additional wording should be provided to clarify that boilers required to have a permit under 40 CFR part 266, subpart H, " Hazardous Waste Burned in Boilers and Industrial Furnaces," are excluded from this NESHAP. One commenter ( 428) requested that an exemption specifically addressing press and other related types of dryers be included in the rule under § 63.7490( b). One commenter 41 ( 346) requested that EPA specifically list combustion sources ( e. g., incinerators and flares) that are not subject to this NESHAP and those that were listed in the proposal preamble. Other commenters ( 360, 377) expressed concern over the language in § 63.7490( b)( 9) because they thought that the term " covered by" was ambiguous and suggested more direct language to ensure the exclusion such as " an affected source under." Another commenter ( 369) requested that § 63.7490 be revised to identify affected sources that are not subject to any requirements.

Response: In the final rule, we provide a generically make sources that are specifically listed as an affected source in another standard under 40 CFR part 63 not subject to this rule. In addition we provide a specific list of sources that are not subject to this rule. We believe that this should address the commenters' concern over overlapping applicability. We have also excluded boilers that are required to have a permit under 40 CFR part 266, subpart H, " Hazardous Waste Burned in Boilers and Industrial Furnaces."

Comment: One commenter ( 376) strongly believes that biomass fired units should not be regulated under this MACT standard. The commenter noted that EPA lacked adequate data for biomass sources in setting the standard and that this regulation would place significant economic burdens on biomass fuel fired sources, thus discouraging biomass as a renewable energy source.

Response: We disagree with the commenter and do not exempt biomass fuel fired units from the boilers NESHAP. We are charged with regulating industrial, commercial, and institutional boilers and process heaters and many industrial boilers use biomass as a fuel. Consequently, we must regulate these units under this rule. Since proposal, we revised the boilers NESHAP to relieve the compliance burden for many sources. For example, we provide an option to demonstrate compliance with the emission limits through fuel analysis. If the results of fuel analysis ( in pounds of regulated pollutant contained in a fuel divided by the heat content of the fuel in Btu per pound) show that a fuel type meets the emission limit, then a source would not have to conduct performance testing and monitor pollution control device operation to demonstrate compliance. We believe that this compliance option will provide significant relief to biomass fuel fired sources. We also disagree with the commenter's assertion that insufficient data are available to set standards for these sources. A questionnaire sent during the ICCR process focused data gathering activities on non fossil fuel fired units. The majority of these units are biomass fired. Additionally, we gathered emission test reports from biomass boilers. In the proposed rule, we requested that any further test information be submitted. However, no additional test information on biomass units was provided by commenters. We concluded that the majority, if not all, the test reports for biomass fired units that were available were gathered for the rule. We believe that we have sufficient information on facilities, capacities, emissions and controls from the questionnaires and test reports to develop standards.

4.3 Lower size cutoff Comment: Numerous commenters ( 332, 339, 343, 347, 361, 362, 364, 374, 376, 379, 382, 383, 387, 388, 391, 392, 394, 395, 399, 401, 410, 416, 424, 428, 434, 439, 440, 447, 449, 473, 474, 478, 479, 483, 489, 491, 492, 497, 498, 507, 508, 511, 513, 514, 517, 518, 519, 524, 525, 526, 529, 531, 533) requested that EPA establish a lower size cutoff in the final boilers NESHAP. Several commenters argued that the benefits from requiring smaller units to install 42 controls would be minimal given the overall monitoring, recordkeeping, and reporting burden. Several commenters ( 473, 474, 497, 508, 511, 513, 514, 517, 518, 525, 526, 531) provided data showing a cost benefit for a small boiler of $ 250,000 per ton of metallic HAP removal. The commenters noted that cost increases for smaller units because those units must use the same control as much higher capacity units and provided cost data for a small unit. The commenters explained that EPA previously exempted units smaller than 30 MMBtu/ hr in the Industrial Boilers NSPS because EPA determined that it would be an unreasonable cost burden for smaller units to comply with the NSPS. Several commenters ( 347, 395, 410, 447, 479, 519) also requested lower size cutoffs to make this regulation similar to others established by EPA ( e. g, NSPS, NOx SIP Call).

Several commenters ( 388, 394, 449, 492, 498, 524, 533) noted recent court decisions in which the court has decided that a de minimis exemption is appropriate since the regulation of small sources would " yield a gain of trivial or no value" yet would impose significant regulatory burden. Some commenters ( 439, 489) argued that many of these smaller units are too small to typically require New Source Review permits, Minor Source Registration or inclusion on Title V Permits.

One commenter ( 507) explained that the proposed rule would affect only those facilities that have invested in more efficient water tube boilers and that the exemption for fire tube boilers puts owners of water tube boilers at a competitive disadvantage. The commenter also noted that the practical effect of the proposed regulation would extend the economically viable life of the less efficient fire tube boilers. One commenter ( 478) noted that this would significantly alleviate the impact on small businesses and focus the rule on significant sources of HAP.

One commenter ( 529) pointed out that smaller sources pose low risk, are easily identified, and may be revisited during the residual risk analysis in 8 years. A wide range of lower size cutoffs were suggested, including: All units: 400,000Btu/ hr; 1MMBtu/ hr; 5MMBtu/ hr; 10MMBtu/ hr; 50MMBtu/ hr; 100MMBtu/ hr. Gas: 15MMBtu/ hr; 100MMBtu/ hr; 250MMBtu/ hr; 330MMBtu/ hr. Liquid: 10MMBtu/ hr new liquid; 60MMBtu/ hr residual oil; 90MMBtu/ hr for distillate oil; 100MMBtu/ hr; 30MMBtu/ hr for residual oil; 100 MMBtu/ hr distillate oil. Solid: 100MMBtu/ hr for hydrogen chloride control on solid fuel fired units; 50 MMBtu/ hr for PM, metals, mercury, and CO control on solid fuel fired units. However, one commenter ( 448) said that EPA should not develop de minimis exemptions. The commenter noted that de minimis exemptions do not spare EPA's resources for use on other purposes and are not justified by reductions in industry burden or inconvenience. The commenter noted that EPA did not establish any administrative record justifying the de minimis exemption.

Response: We have reviewed the commenters arguments and all the data provided in the comment letters. We do not feel there is justification for developing a lower size cut off or de minimis level. We would also note the designation of large and small subcategories was not based solely on size of the unit. Large and small subcategories were developed because small units less than 10 MMBtu/ hr heat input typically use a combustor design that is not common in larger units. Large boilers generally use the watertube combustor design. The design of the boiler or process heater will influence the completeness of the combustion process which will influence the formation of organic HAP emissions. Additionally, the vast majority of small units use natural gas as fuel. The EPA chose to develop large and small subcategories to account for these differences and their affect on the type of emissions. The cut off between the large and small subcategories of 10 MMBtu/ hr was based on typical sizes for fire tube units, and also when considering cut offs 43 in State and Federal rules. Lastly, we would like to note that the final rule does not impose any requirements for existing units in any of the small subcategories.

Comment: Several commenters ( 376, 406, 407, 408, 497, 501) recommended that EPA exempt boilers and process heaters from the boilers NESHAP that are not major sources of HAP individually or are considered insignificant sources under approved Title V programs. One commenter ( 400) contended that sources that are subject to the proposed boilers NESHAP generally are not major sources and should not be subject to the regulation as such. One commenter ( 523) questioned how EPA concluded that a 10 MMBtu/ hr gas fired boiler would meet the definition of a " major source" of HAP under section 112 such that it warranted listing or regulation under section 112. Two commenters ( 478, 502) objected to the fact that the proposed rule would regulate boilers and process heaters that are not themselves a major source of HAP, but which are collocated at facilities with other HAP sources. One commenter ( 502) explained that HAP produced from other processes at a facility will trigger the major source definition and result in MACT technology being imposed on boilers that do not create the major source applicability. Several commenters ( 406, 407, 408, 501) requested EPA clearly state that units that are non major alone, although located at a major source of HAP, are not subject to the rule, other than notification requirements in 40 CFR part 63, subpart A. One commenter ( 478) requested that EPA establish a minimum threshold of 2,000 lb/ yr of actual HAP emissions. Several commenters ( 473, 474, 497, 508, 511, 513, 514, 517, 518, 525, 526, 531) noted that other MACT standards ( i. e., Wool Fiberglass Manufacturing, Natural Gas Transmission and Storage, Pharmaceutical Production, and Amino/ Phenolic Resins) contain exemptions for sources that emit less than 10 tons per year of HAP.

Response: The CAA requires that standards be developed for emission sources located at a major source. A major source is defined in the CAA as any stationary source or group of stationary sources located within a contiguous area and under common control that emits or has the potential to emit 10 tons per year or more of any HAP or 25 tons per year or more of any combination of HAP. Also, boilers and process heaters are listed source section 112 of the CAA that must be regulated by a NESHAP program. Therefore, we must develop standards for boilers and process heaters located at any major source, even if the source is only major because of emission points not related to boilers and process heaters. Due to these reasons, even if a boiler or process heater is not a major source in an of itself, it still must be regulated under the boilers NESHAP. We are also not going to provide a minimum threshold of HAP emissions that would trigger applicability. Since proposal, we have made several changes that will reduce the burden of this NESHAP on sources and have eliminated many requirements for gaseous and liquid fuel fired sources. Therefore, we do not believe an emission threshold that triggers applicability is warranted.

4.4 Major source Comment: One commenter ( 492) requested that when an area source becomes a major source, each boiler or process heater unit that exists prior to the date the area source becomes a major source should be required to meet existing source MACT even if it was constructed after January 13, 2003. The commenter explained that the new source definition in § 63.7490( c) defines new sources as meeting "... the applicability criteria at the time you commenced 44 construction." Therefore, if an area source contains boilers and/ or process heaters becomes a major source due to reasons not related to the boilers and/ or process heaters, then these units do not meet the applicability requirements of new sources. The commenter requested that EPA explicitly explain this result in the final rule, and provides a recommended revision to § 63.7490( c) to address this issue. The commenter also argued that sources that become subject to the boilers NESHAP after the promulgation date due to changes in their applicability status are existing sources if they were in existence prior to January 13, 2003 and should have up to 3 years to comply. The commenter noted as examples that hazardous waste combustors or commercial and industrial solid waste incinerators could become subject to the boilers NESHAP if they stopped burning wastes and used clean fuels instead. The commenter requested that the final NESHAP clarify that these units, if in existence prior to January 13, 2003, should be considered " existing" sources.

Response: In the final rule, § 63.7490( d) and ( e) state that you have a new or reconstructed source if you commence construction or reconstruction after January 13, 2003 AND you meet the applicability criteria at the time you commenced construction or reconstruction. Furthermore, § 63.7490( f) states that a source is existing if it does not meet the definition of new or reconstructed. If a boiler or process heater located at an area source commences construction or reconstruction after January 13, 2003, and that construction or reconstruction does not itself make the area source a major source, then the boiler or process heater would be considered an existing source if the area source later becomes a major source. This is due to the fact that the boiler or process heater did not meet the applicability criteria of this NESHAP at the time it commenced construction or reconstruction because it was located at an area source, and units located at area sources are not subject to this NESHAP. The final rule clarifies the requirements for area sources that become major sources. In § 63.7495( c)( 2) of the final rule, an existing boiler or process heater located at an area source that increases its emissions or its potential to emit such that it becomes a major source of HAP comply with the subpart within 3 years of the facility becoming a major source.

Comment: Two commenters ( 396, 410) requested clarification on the date by which a source must be below the major source potential to emit threshold in order to not be subject to the boilers NESHAP. Two commenters ( 396, 410) requested that EPA allow an affected source to switch to area source status by reducing its potential to emit at any time up until the compliance date, rather than the promulgation date, to avoid being subject to the boilers NESHAP and referenced previous EPA guidance and policy for this clarification, including a memorandum from John Seitz dated May 16, 1995. One commenter ( 396) explained that this deadline would give small emitters time to limit their potential emissions rather than comply with the boilers NESHAP. The commenter added that it would also be appropriate for sources that are above the major source threshold at rule promulgation to become area sources if they reduce emissions or take limits and requested that EPA provide guidance and specify any recordkeeping and reporting requirements that would be applicable. Two commenters ( 391, 392) expressed their belief that the " once in, always in" approach to the NESHAP program is contrary to the goals of pollution prevention, emission minimization, and the Administrative Procedures Act.

Response: We agree with the commenters that based on the John Seitz memorandum, a major source can switch to an area source any time before the compliance date, but not the promulgation date. However, units located at major sources at the promulgation date are still 45 required to submit an initial notification.

4.5 Delisting Comment: Several commenters ( 345, 349, 413, 427, 499) expressed support for delisting some subcategories under this NESHAP. One commenter ( 413) supported delisting subcategories based on CAA section 112( c)( 9) of the CAA and viewed it as a mechanism to limit costs and impacts of rules to those facilities that actually need to be regulated to protect public health. The commenter added that once EPA receives a petition to delist a subcategory, it should evaluate the petition to determine if each facility meets the criteria in section 112( c). The commenter continued that once EPA delists a subcategory, it should establish a procedure to evaluate petitions from other units that would like to be included in the delisted subcategory. Another commenter ( 345) recommended that EPA establish automatic subcategory delisting criteria where a facility that meets the criteria can apply for automatic delisting. The commenter stated that such criteria should be based on fuel type and usage as well as control efficiency, if any were used. In addition, the commenter stated that delisting those subcategories for which no reduction is predicted is the most cost effective solution, with no impact on emissions. One commenter ( 427) contended that the proposed MACT should be withdrawn and boilers and process heaters delisted or the rule should be limited in scope to those sources where the social benefits resulting from HAP emission reductions can be demonstrated ( e. g., solid fuel fired units in large urban areas). One commenter ( 499) stated that EPA should consider delisting small industrial/ commercial/ institutional boilers and process heaters as a source category under section 112( c)( 9) of the CAA and 40 CFR part 63, subpart C. The commenter stated that recent studies indicate that HAP emissions from virtually all small boilers in the U. S. represent a cancer risk of well below 1 in 1 million and that the non cancer risks are well below levels EPA considers to protect public health with an adequate margin of safety. In addition, the commenter stated there are a number of economic benefits of delisting small boilers and process heaters under the NESHAP program. One commenter ( 349) agreed with the concept of delisting subcategories before the MACT compliance date and explained that delisting after the compliance date can be problematic when sources do not comply with the current rule in the anticipation that they may be delisted. Several commenters ( 376, 413, 477, 336, 482, 536) requested that EPA exempt limited use boilers from the NESHAP. Two commenters ( 413, 482) noted that it is not cost effective to control HAP emissions for these units, and because these boilers emit low levels of HAP and do not threaten air quality. The commenter referenced the utility air regulatory group's comments and cost analysis. One commenter ( 413) provided an analysis of the costs and emission reductions associated with the complying with the limited use standards.

Two commenters ( 448, 512) opposed any plan to delist subcategories under the boilers NESHAP. One commenter ( 448) said that section 112( c)( 9)( B) does not give EPA authority to delist subcategories, including sources of carcinogens, from MACT standards. The commenter noted that the authority only applies to categories ( not subcategories) when all sources in the category meet the standard. The commenter stated that EPA can not establish a separate de minimis subcategory to delist sources and noted that section 112( c)( 9)( B) precludes development of de minimis exemptions that exceed its narrow authority. Another commenter ( 512) cautioned EPA from considering subcategories for the sole purpose of delisting them as " low risk" under the authority of section 112( c)( 9)( B). The commenter argued that this approach is unlawful. The commenter explained that EPA cannot subcategorize to enable a source category to avoid the language, intent, or deadlines of the CAA. To delist a source category, EPA must first find that 46 no source in the category will emit such HAP at a level that would cause a one in one million lifetime risk of cancer. The commenter argued that EPA's proposed delisting of a subcategory is inappropriate here because EPA has not made such a finding in this proposal.

Response: The final rule does not delist any subcategories. We do not consider it appropriate for this standard to de list any subcategories. However, we do recognize that some sources may have very low emissions of HAP and may pose a minimal health risk. Consequently, we have included in the final rule an alternative that allows sources that demonstrate emissions below a health threshold for some pollutants to not be subject to the emission limit requirements. Detailed discussions of the risk alternative is found in section 18 of this document. 47 5.0 Format of the Standard Comment: Two commenters ( 390, 413) supported emission limits based on heat input rather than on unit output. One commenter ( 413) added that output based limits would become overly complex without providing commensurate health benefits. The commenters explained that limits based on heat input would simplify many of the complex details that would have to be addressed with an energy output based limit. Commenters cited complex details such as cogeneration of steam where common systems serve more than one boiler and the complexity of the instrumentation needed to monitor the systems.

Response: We agree with the commenters and have not included output based emission limits in the final rule. Given the diversity of end uses for the boilers and process heaters regulated by this NESHAP, it would be impossible to develop an output based standard that could apply. Furthermore, we do not have enough data that show emission rates in terms of unit output to develop such a standard.

Comment: Several commenters supported percent reduction in combination with other means of compliance such as emission limits, concentration limits, pounds per heat input, and pounds of emissions per energy output. One commenter ( 390) asserted that the MACT standard should be flexible and should give the option of demonstrating compliance with either a percent reduction or an emission rate limit. One commenter ( 409) supported allowing a percent reduction approach as an alternative means of compliance because it would provide additional flexibility to the standard, alleviate concerns that one specific compliance measure is not sufficient to address variability, and reduce the necessity for sources to demonstrate compliance on a continuous basis. Another commenter ( 413) agreed that allowing compliance with either percentage reduction or emission limits would provide additional flexibility to a facility, stating that the option would allow units an efficient way of coping with the variability of their fuel supplies. Commenter ( 409) added that the percent reduction option would be consistent with the Hazardous Waste Combustion MACT standards. Three commenters ( 376, 445, 446) requested that EPA provide emission limits as a percent reduction and in pounds per heat input.

Response: We do not include a percent reduction option for emission limits in the final rule. As discussed in the preamble to the proposal ( see 68 FR 1671), this decision was based on the fact that we did not have sufficient data to determine the percent reduction of the floor level of control. We explained at proposal that we had insufficient data to propose a percent reduction option and requested additional data to evaluate a percent reduction option. We did not receive adequate data to develop a percent reduction option, therefore, we have not included one in the final rule.

Comment: Some commenters ( 442, 512) disagreed with percent reduction as an option. One commenter ( 442) believes that percent reduction based standards are more difficult to comply with than heat input based standards. To demonstrate compliance, inlet and outlet concentrations are required, increasing the costs and difficulty of proving compliance. The commenter ( 442) also believes it would be better to establish emission limits based on the pounds of emissions per energy output, thus encouraging energy efficiency. The commenter ( 512) noted 48 that a percent reduction requirement would limit the flexibility of the rule by requiring the use of a control device. However, the commenter recommended that EPA set output based emission limits to encourage and reward efficiency. One commenter ( 499) stated there is no reason why the " stack limit" approach and the " percent reduction" must be presented as an " either or" approach. The commenter stated that allowing an alternative means of compliance can only improve the flexibility of the rule. One commenter ( 340) recommended outlet concentration limits, rather than a percent reduction requirement. The commenter found this much simpler to monitor, keep records, report, and make compliance determinations, and was therefore cheaper than percent reduction requirements.

Response: In the final rule, we retained emission limits in the pound per million Btu format. We maintain that this the most effective and least burdensome format for the emission limits of this NESHAP. As discussed in the proposal preamble, we did not have enough data to establish a percent reduction option. Furthermore, we have also have not implemented an output based standard for the pollutants regulated by this NESHAP. We believe that attempting to establish an output based standard would not be appropriate given the diverse nature of application for the sources regulated by this NESHAP.

5.1 Surrogates ( general)

Comment: Many commenters ( 451, 512) disagreed with EPA's use of surrogates for HAP. Two commenters ( 512, 451) stated that EPA must set emission standards for all HAP emitted by this category. One commenter ( 451) claimed that the proposed standards are unlawful because EPA must establish standards for each HAP emitted from the source category regulated. One commenter ( 512) explained that the use of surrogates is acceptable if the surrogates ( 1) reflect the actual emissions of the represented pollutants; ( 2) the emission limit set for the surrogate is consistent with the emission limit calculated for the represented pollutants; and ( 3) have substantially the same properties as the represented pollutants and is controlled by the same mechanism. Based on these criteria, the commenter argued that EPA's selection of surrogates is inadequate. The commenter also provided more technical discussion of specific pollutant properties to support their argument. The commenter requested that if EPA chooses to promulgate standards using the surrogate pollutants, sources should be required to measure all pollutants represented by the surrogate.

One commenter ( 423) contented that the selection of pollutants and emission limits in the proposed rule is inconsistent with rules currently in place for large electric steam generating units. The commenter added that the proposed rule would impose more restrictions on HAP from small utility boilers and more controls than would be required for larger units not covered by the rule. The commenter stated that the only HAP currently under consideration for emission limits on large utility boilers is mercury.

Response: As discussed in the proposal preamble, we feel the use of surrogates for the HAP regulated is appropriate. Because of the large number of HAP potentially present, the disparity in the quality and quantity of the emissions information available, particularly for different fuel types, we chose to group HAP into four categories: mercury, non mercury metallic HAP, inorganic HAP, and organic HAP. In general, the pollutants within each group have similar characteristics and can be controlled with the same techniques. We then chose compounds that could be used as surrogates for all the compounds in each pollutant category. We have used 49 surrogates in previous NESHAPs as a technique to reduce the performance testing costs and believe that the use of surrogates is appropriate in this NESHAP.

For inorganic HAP, we chose to use HCl as a surrogate. The emissions test information available to us indicated that the primary inorganic HAP emitted from boilers and process heaters is HCl. Much smaller amounts of hydrogen fluoride and chlorine are emitted. Control technologies that would reduce HCl would also control other inorganic HAP. Additionally, we had limited emissions information for other inorganic HAP. By focusing on HCl, we have achieved control of the largest emitted and most widely emitted HAP, and control of HCl would also constitute control of other inorganic HAP.

For non mercury metallic HAP, we chose to use PM as a surrogate. Most, if not all, nonmercury metallic HAP emitted from combustion sources will appear on the flue gas fly ash. Therefore, the same control technology that would be used to control fly ash PM will control non mercury metallic HAP. A review of data in the emission database for PM control devices having both inlet and outlet emissions results shows control efficiencies for each non mercury metallic HAP similar to PM. Particulate matter was also chosen instead of a specific metallic HAP because all fuels do not emit the same type and amount of metallic HAP, but most generally emit PM that includes some amount and combination of metallic HAP. We maintain that particulate matter reflects the emissions of non mercury metallic HAP as these compounds usually comprise a percentage of the emitted particulate matter. Since the NESHAP program is a technology based standard, the technologies that have been developed and implemented to control particulate matter, also control non mercury metallic HAP. Furthermore, since nonmercury metallic HAP is a component of particulate matter, we continue to believe that we can use particulate matter as a surrogate for the purposes of this rule.

While we did use PM as a surrogate for non mercury metallic HAP, we also provided an alternative total selected metals emission limit based on the sum of the emissions of the eight most common and largest emitted metallic HAP compounds from boilers and process heaters. Again, a total selected metals number was used instead of limits for each individual metallic HAP because sufficient information was not available for each metallic HAP for every fuel type. However, a total metals number could be calculated for every fuel type.

We realize that mercury emissions can exist in different forms depending on combustion conditions and concentrations of other compounds. That is why we have mercury as a separate pollutant category in the final rule and do not provide for a surrogate.

For organic HAP, we chose to use CO as a surrogate to represent the variety of organic compounds emitted from the various fuels burned. Both organic HAP and CO emissions are the result of incomplete combustion of the fuel. Because CO is a good indicator of incomplete combustion, there is a direct correlation between CO emissions and minimizing organic HAP emissions. The extent to which CO and HAP emissions are related can also depend on sitespecific operating conditions for each boiler or process heater. This site specific nature may result in various degrees of correlation between CO and organic HAP emissions, but it is proven that reductions in CO emissions result in a reduction of organic HAP emissions. The control methods for both CO and organic HAP are the same, i. e., complete combustion. This result would not have been different if MACT floor analyses were conducted for specific organic HAP or for a surrogate compound such as CO. For boilers and process heaters, we have determined that CO is a reasonable indicator of incomplete combustion. Also, we did not set emission limits for each 50 specific organic HAP because we lacked sufficient information for many of the organic HAP for all the fuels combusted. We acknowledge that there are many factors that affect the formation of dioxin, but we also recognize that dioxin can be formed in both the combustion unit and downstream in the associated PM control device. We believe that minimizing organic HAP emissions can limit the formation of dioxin in the combustion unit. We reviewed all the good combustion practice ( GCP) information available in the boiler population database and determined that no floor level of control exists, except for limiting CO emissions, such that GCP could be incorporated into the standard. One control technique, controlling inlet temperature to the PM control device, that has demonstrated controlling downstream formation of dioxins in other source categories ( e. g., municipal waste combustors) was analyzed for industrial boilers. In all cases, no increase in dioxins emissions were indicated across the PM control device even at high inlet temperatures. However, we requested comment on controls that would achieve reductions of organic HAP, including any additional data that might be available. The EPA did not receive any additional supporting information or data. Additionally, more stringent options beyond the floor level of control were evaluated, but were determined to be too costly and emission reductions associated with the options could not be evaluated because no information was available that indicated a relationship between the GCP's and emission reduction of organics ( including dioxin).

Comment: Several commenters ( 479, 364, 387, 399, 479, 536) supported EPA's approach to using surrogates for all emitted HAP and the four HAP categories. Two commenters ( 353, 492) supported EPA's proposal to use surrogates as a method to determine compliance with this NESHAP and discussed EPA's legal authority to regulate HAP through the use of surrogates. Commenter ( 479) noted that EPA has the authority to use this approach as upheld in the National Lime case. However, the commenters ( 364, 399, 387) noted that particulate matter will not always be an ideal surrogate for metals given the different levels of metals in various fuels and agreed with EPA in providing an alternative metals limit. Other commenters ( 364, 399, 387, 403, 425, 443, 444, 397) supported EPA's inclusion of the total selected metals limit as an alternative to the particulate matter limit. One ( 444) commenter believes that the alternative will provide significant benefit for solid fuel fired units that burn predominantly wood or biomass. One commenter ( 376) supported EPA's allowance for solid fuel fired units to meet either a particulate matter or total selected metals emission limit.

Response: We agree with the commenters and maintain that the use of surrogates is appropriate for this NESHAP and retained them in the final rule. We also retained the total selected metals alternative to the particulate matter surrogate for sources due to the various levels of metals in different fuels.

Comment: One commenter ( 381, 451) stated that particulate matter is not a valid surrogate for total metal HAP since it is not a valid surrogate for volatile metal HAP such as cadmium and lead. Also, the commenter said that particulate matter is not a valid surrogate since factors other than particulate matter affect emissions of metal HAP. One commenter ( 381) noted that EPA's Criteria Document indicates metal content of particulate matter can vary widely depending on the type of source, metals content of fuels, control technology used, and other factors. The commenter concluded that the particulate matter standard would not reflect the 51 metal emission levels actually achieved. The commenter added that EPA may not use a surrogate where it results in regulations that do not include standards for each HAP or do not reflect the emission levels achieved by the best performers. The commenter referred to the National Lime court decision. One commenter ( 536) contended that setting a MACT standard for mercury is complicated because there are three forms of mercury possible, and the level of control varies widely depending on the relative concentration of each form and the installed control equipment, as well as the physical circumstances at the facility.

Response: In the preamble to the proposed rule, we stated that we chose particulate matter as a surrogate for non mercury metallic HAP because most, if not all, non mercury metallic HAP emitted from combustion sources will appear on the flue gas fly ash. Therefore, the same control technologies that would be used to control particulate matter would control nonmercury metallic HAP. We acknowledged that not all metallic HAP would be represented by particulate matter, but maintain that most would. Therefore, we continue to use particulate matter as a surrogate for non mercury metallic HAP in the final rule.

We maintain that particulate matter reflects the emissions of non mercury metallic HAP as these compounds usually comprise a percentage of the emitted particulate matter. Since the NESHAP program is a technology based standard, the technologies that have been developed and implemented to control particulate matter, also control non mercury metallic HAP. Furthermore, since non mercury metallic HAP is a component of particulate matter, we continue to believe that we can use particulate matter as a surrogate for the purposes of this rule. We also provide the option of measuring total selected metals, which includes cadmium and lead, instead of particulate matter when you conduct performance testing or fuel analyses to determine compliance. We include this option because we acknowledge that the metals content of fuels vary and some fuels may contain very little metals, but sources burning these fuels would have particulate matter emissions higher than the emission limit and would require control to meet the emission limit.

We realize that mercury emissions can exist in different forms depending on combustion conditions and concentrations of other compounds. That is why we have mercury as a separate pollutant category in the final rule and do not provide for a surrogate. Regardless of the form in which mercury exists when it leaves the stack, you are required to meet the emission limits for mercury. You are free to meet the mercury emission limit through the use of add on control devices or through fuel switching.

Comment: One commenter ( 451) contended that EPA did not explain why its only choice is either to set individual standards for each metal HAP or to use particulate matter as a surrogate for all of them. The commenter noted that in previous rulemakings EPA has grouped metals with similar characteristics together. The commenter ( 451) stated that one of EPA's rationale for using particulate matter as a surrogate for HAP metals is that it would reduce costs. The commenter ( 451) contended that cost concerns do not allow the EPA to use an inadequate surrogate.

Response: In the preamble to the proposed NESHAP, we explained that we chose to use surrogates to minimize the cost of compliance of this rule due to the many different types of pollutants emitted from these sources. We separated the HAP emitted from boilers and process heaters based on the physical and chemical characteristics of the pollutant and based on the methods used to control the different types of pollutants. For the non mercury metallic HAP 52 group, we determined that particulate matter was an appropriate surrogate because most nonmercury metallic HAP emitted from combustion sources will appear on the flue gas fly ash. Therefore, the same control techniques that would be used to control the fly ash particulate matter would control non mercury metallic HAP. We cannot use cost as a factor in setting the MACT floor; however, we are able to consider cost in the methods that we require to demonstrate compliance with this NESHAP. We have worked to minimize the compliance burden and costs in many areas related to compliance activities of this NESHAP and maintain that those approached are valid.

5.2 Surrogates ( HCl)