We have decided to apply the percentage threshold on a per activity ( or aggregation of activities) basis. This is consistent with how major NSR has been applied in the past and will continue to the apply in the future, with the exception of those sources which establish a PAL. The major NSR program is a preconstruction program that requires applicability to be determined for a given activity at a facility and, as necessary, permitting to occur prior to the time activities are commenced. The major NSR program also requires applicability to be determined, in the first instance, based on an assessment only of the parts of a facility involved in the activity. Prospectively, a per activity basis works well with this approach. We are not going final with a component by component approach.

There would be obvious problems if we chose any of the other approaches suggested in the proposal or suggested by commenters ( for example, annual basis or 5 year rolling average). One of the primary concerns with applying the percentage to activities performed over a span of time is that we would be restructuring the major NSR program to operate based on after the fact determinations. This raises the difficult question of what happens under this type of approach if you learn after commencement of an activity that it does not qualify under the ERP. This situation is largely avoided by the per activity approach that we are establishing in the final rule. It should be noted that activities that are related must be aggregated under the ERP, in the same way as they would have to be aggregated for other NSR applicability purposes. We have rejected aggregation based on replacement activities which are largely unrelated, but which occur during the same equipment outage, such as replacement of turbine seals and replacement of superheater tubing sections. Also, non replacement activities that are part of a larger replacement activity should be included when calculating costs for a replacement activity against the capital cost threshold.

3.4 Definition of Process Unit Comment:

3.4.1 General Definition Several industry commenters ( 841, 896, 902, 951, 1050, 1066, 1078, 1083, 1090, 1091, 1096, 1100, 1124, 1132, 1138, 1159, 1212, 1292, 1465, 1866), a State/ local commenter ( 1240), and a Federal commenter ( 1101) supported the proposed general definition of " process unit," to apply to the equipment replacement cost percentage. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 26 One industry commenter ( 1105) urged EPA to allow flexibility in defining " plant," in order to suit the specific facility and owner circumstances.

Several State/ local commenters ( 1199, 1268, 1361, 1471) said the proposed definition is too vague or broad. One State/ local commenter ( 1206) said the process unit definition is inherently inconsistent. Another State/ local commenter ( 1361) added that the proposed definition is inconsistent with title V of the CAA. Another State/ local commenter ( 1199) urged EPA to change the definition of process unit to limit the scope of what is allowed in the replacement provision, so that the source of emissions ( for example, an entire coal boiler) would not be allowed to be replaced without NSR. The replacement unit's scope should be limited to an emission unit.

One industry commenter ( 1160) found two objections to the proposed definition: ( 1) It is unnecessarily complicated to use a different definition than that which serves as the basis for the maintenance allowance, and for the NSR source definition as a whole; and ( 2) allocating shared components and shared capacity would not work well. For these reasons, the commenter recommends using the entire facility as the basis for determining replacement costs.

As an alternative to the proposed definition of process unit, one industry commenter ( 1238) suggested that " process unit" be defined as " any collection of structures and/ or equipment that processes, assembles, applies, blends, or otherwise uses material inputs to produce or store a completed product."

One industry commenter ( 1124) supported the process unit definition on the condition that if NSR is triggered through it, it would be on an emissions unit basis.

Five industry commenters ( 1110, 1124, 1132, 1202, 1866) compared the RMRR proposal's definition of " process unit" ( toward producing or storing a completed product) to the definition that is used by section 112( g) and that appears in 40 CFR 63.41 ( toward producing or storing an intermediate or final product). One of the industry commenters ( 1866) supports the more narrow proposed definition. Two industry commenters ( 1124, 1202) said the RMRR rule's definition should be consistent with that used by section 112( g), broad enough to encompass interrelated operations. While supporting the RMRR proposal's definition, two industry commenters ( 1110, 1132) recommended that EPA provide regulatory flexibility by allowing a facility the option to choose which definition they will use.

Two industry commenters ( 841, 1090) believed the definition of " process unit" is sufficient for a determination without encumbering the rule with an exhaustive, but inevitably incomplete, list of process units throughout the industrial sector. Listing units may confuse rather than clarify. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 27 One industry commenter ( 1100) generally supported the proposed definition of " process unit" ERP, but this commenter believed that " the delineation of a process unit should be made by regulated entity rather than explicitly defined in a rule."

Three industry commenters ( 1129, 1204, 1346) asserted that pollution control equipment should be included in the process unit definition. One industry commenter ( 1346) said pollution control equipment is often integral to the process and may produce an intermediate product. One environmental commenter ( 1150) believed the proposed rule was unclear as to whether pollution control equipment is part of the process unit.

3.4.2 Definition Applied to Specific Industry Categories One industry commenter ( 1137) said some of the examples that are intended to illuminate what a process unit is ( that is, the industry category specific definitions) need to be revised or eliminated.

One State/ local commenter ( 1268) said the definition for pulp and paper mills is incorrect. One industry commenter ( 1465) did not support the detailed process unit definition for pulp and paper mills because the definition does not, and cannot, capture all possible elements and configurations. This commenter said the general process unit definition was sufficient.

One commenter ( 1124) supported the definition of a refinery process unit.

Two industry commenters ( 1138, 1212) provided a detailed description and figures illustrating a natural gas compressor station, and the commenters said each compressor system, together with its proportionate share of common support equipment, would logically be considered a separate process unit. Each engine/ compressor system operates independently. Another industry commenter ( 1367) said the proposed definition for natural gas pipeline compressor stations needed more clarification, or uncertainty regarding the scope and application of the equipment replacement exclusion would remain. This commenter explained that for the midstream segment of this industry, where internal combustion engines operate as components of compressor skid assemblies, and such assemblies can operate alone or in series, the final rule should include a narrative description of the natural gas compression process unit and cited 40 CFR 52.21( b)( 56)( ii). This industry commenter ( 1367) and another industry commenter ( 1096) offered the following clarification: " For facilities operating in the midstream segment of the natural gas industry, the compression process unit consists of those portions of a natural gas compressor station, natural as liquids extraction and production plant, and natural gas processing plant that contain the combination of equipment necessary to compress natural gas for the purpose of establishing and maintaining the process flow and delivery of such gas and liquids. Like kind and functionally equivalent replacement of equipment ( including, but not limited to, internal combustion engines) within the compression process shall qualify as RMRR." 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 28 Six industry commenters ( 902, 1082, 1129, 1368, 1399, 1629, 1794) supported the EPA's definition of process unit for a steam electric generating facility. One industry commenter ( 1629) recommended expanding the definition to include pumps, fans, cooling tower, and raw water and wastewater treatment systems. Another industry commenter ( 1794) stated that it was important not to exclude components which serve a dual purpose, such as low NOx burners. Referring to the description for pulverized coal fired facilities, one industry commenter ( 1129) said the ash handling equipment should be added and also said EPA should also clarify that administrative buildings ( including warehousing) are not included in the process unit. Two industry commenters ( 902, 1082) said equipment that does not contribute to the production of electricity should be excluded from the definition of process unit. The commenter gave the examples of water intake systems, cooling water towers, transformers and other downstream electrical equipment.

One industry commenter ( 1126) said the definition of " process unit" for the utility industry should be expanded to include the coal handling system, boiler, turbine, stack, and generator, as well as emission control equipment.

One industry commenter ( 1204) said the incinerator process unit definition should include pollution control equipment, because the pollution control equipment is, like refuse pits, steam generators, and fans, integral to the unit operation at waste to energy facilities.

One industry commenter ( 1238) said the process unit for tire manufacturing facilities should be the entire plant, just like EPA appears to consider a cement plant to be a single process unit.

For the flat glass industry, an industry commenter ( 1066) provided a description of the equipment necessary to produce a finished primary glass product and said each production line within a facility should be a separate process unit. Flat glass production is completed on a continuous line where raw materials are added at one end, a continuous ribbon of glass is formed, and finished glass is packaged at the other end. The flat glass production line consists of: the batch house, where raw materials are stored and weighed; the furnace and refiner, where the raw materials are melted; the bath, where the glass ribbon is formed; the lehr, where the ribbon is annealed; and the cutting and packaging equipment, where the glass is removed from the line for sale to customers or for additional processing later.

Fiberglass production was described by an industry commenter ( 1066). Fiberglass production is completed on a continuous line where raw materials are melted at one end to form a continuous strand of fiberglass that is packaged at the other end. The fiberglass production line begins with the batch house, where raw materials are stored and weighed. In the melter, forehearth, and refiner, the raw materials are melted and refined. From the refiner, glass fibers are formed through controlled bushings. From the bushings, the continuous strand fibers are either 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 29 directly cut or packaged or wound onto spools for packaging for sale to customers or for additional later processing.

An industry commenter ( 1066) said a process unit for production of precipitated amorphous silica includes, but is not limited to: raw material storage and handling equipment used for mixing sand and other raw materials prior to addition to the furnace; the furnace itself; the raw material storage and handling equipment for the cullet dissolving and silica precipitation process; all dissolving, precipitation, and filtration tanks and equipment; and drying equipment. Further, the process unit includes all the product packaging, storage, handling, and transfer equipment.

Two industry commenters ( 1066, 1110) suggested a definition of a complex chemical manufacturing process unit. The definition of a chemical manufacturing process unit could be modeled after the definition of a process unit in the Hazardous Organics NESHAP, suggested one industry commenter ( 1066). A chemical manufacturing process unit would include all the equipment assembled and connected by pipes or ducts to process raw materials and to manufacture an intended primary product and associated byproducts or intermediates. The process unit can consist of more than one unit operation. Chemical manufacturing process units may include, but are not limited to: raw material storage, and air oxidation reactors and their associated product separators and recovery devices; reactors and their associated product separators and recovery devices; distillation units and their associated distillate receivers and recovery devices; associated unit operations; associated recovery devices; and any feed, intermediate and product storage vessels, product transfer racks, and connected ducts and piping. A chemical manufacturing process unit includes pumps, compressors, agitators, pressure relief devices, sampling connection systems, open ended valves or lines, valves, connectors, instrumentation systems, and control devices or systems. One industry commenter ( 1110) commented that for a chemical manufacturing facility, there are several types of process units: those that separate and distill raw material feedstocks; those that change molecular structures through reactions or polymerization; those that " finish" the reacted or polymerized product, through compounding, blending, or similar operations; auxiliary facilities, such as boilers and byproduct fuel production; and those that load, unload, blend, or store products. Process equipment that acts to control emissions, such as condensers, recovery devices, and oxidizers, is considered part of the process unit.

The definition of a process unit in coatings manufacturing could be modeled after the Miscellaneous Organics NESHAP, suggested an industry commenter ( 1066). A coatings manufacturing process would include all equipment that collectively functions to product a product or isolated intermediate. It consists of one or more unit operations. A coatings process unit includes any, all, or a combination of raw material storage, reaction, recovery, separation, purification, blending or other activity, operation, manufacture, or treatment. Cleaning operations are part of the process. Nondedicated solvent recovery operations located within a contiguous area within the affected source are considered a single process. A storage tank that is used to 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 30 accumulate used solvent from multiple batches of a single process for purposes of solvent recovery does not represent the end of the process. Nondedicated formulation operations ( not including mixing, as defined) occurring within a contiguous area are considered a single process that is used to formulate numerous materials and/ or products.

Several sugar industry commenters ( 920, 921, 1123) gave two possible definitions of process unit for their industry. These commenters ( 920, 921, 1123) emphasized that the process unit should cover all of the regulated air emission points at the plant.

For a sugar mill, there are two types of process units. One type of process unit includes all of the portions of the plant that contribute directly to the production of steam. This process unit includes the combination of systems from the bagasse handling system through to the emission stack, including the bagasse handling equipment, feedwater system, combustion air system, boiler, burners, air preheaters, superheaters, flues, stack, and fuel oil storage and piping system. The second type of process unit includes those portions of the plant that contribute directly to the production of refined sugar from raw sugar and the associated packaging and shipping operations.

For a sugar mill, the process unit would consist of all regulated air emission sources at the plant. Excluded air emission sources are all unregulated and insignificant emission units as identified in the facility's title V operating permit.

One industry commenter ( 840) said underground mining equipment should be excluded from the industry specific lists of process units because it contributes very little to ambient air emissions, is heavily regulated with regard to respirable dust, and is a separate process unit.

One industry commenter ( 1129) agreed with EPA's proposal to proportionately allocate, based on capacity, those components shared by two or more process units. For electric utilities, another industry commenter ( 1136) supported allocating the cost of shared equipment based on a pro rata share of megawatts produced.

One industry commenter ( 840) believed underground mining equipment should be exempt from NSR, because it contributes very little to ambient air emissions, is heavily regulated by MSHA with regard to respirable dust, and is a separate process unit that provides ore to this commenter's entire facility ( six surface process units).

Response:

In the proposal, we raised the issue of what collection of equipment should be considered in applying the threshold under the ERP. We proposed the term " process unit" as the 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 31 appropriate collection to accommodate the intended coverage of activities under the ERP. The purpose of this term is, to the extent possible, to align implementation of the ERP with generally accepted and practical understandings of what constitutes a discrete production process. The general definition that we proposed was based closely on the definition of process unit contained in 40 CFR 63.41 and read as follows:

Process unit means any collection of structures and/ or equipment that processes, assembles, applies, blends, or otherwise uses material inputs to produce or store a completed product. A single facility may contain more than one process unit.

To help illustrate these concepts, we further proposed five industry specific examples of how this definition of process unit might be applied. The examples were drawn from five selected industry categories   electric utilities, refineries, cement manufacturers, pulp and paper producers, and incinerators.

We agree with the commenters who favor using a process unit as the basis for administering the ERP and including a definition of process unit in the final rule. We also agree with the commenters who suggested that the definition of process unit should be consistent with the definition in 40 CFR 63.41, which means that our proposed definition must altered for the final rule to include those processes that produce " intermediates." We acknowledge that the term " intermediates" is susceptible to misinterpretation, which can cause confusion and lead to less regulatory certainty. There is no intention for this rule to impart any regulatory significance to informal uses of the term " intermediate." By " intermediates," we mean a recognizable product of facility operations. For example, for an automotive manufacturing plant, while the completed product would be the driveable vehicle ready for shipping to the showroom, an intermediate product could be the engine block or the painted body shell. In this case, we would not consider smaller production operations, such as the production of the pistons or wheel well frame, to be an intermediate in the context of our final rule definition for process unit. Our primary goal in defining this term " process unit" is to encompass integrated manufacturing operations that produce a completed product, and those operations that produce a recognizable intermediate product.

We disagree with the commenters who wish to include pollution control equipment in the definition. We feel that periodic replacement of parts of emissions control equipment should be encouraged and would rarely lead to actual emissions increases. In instances where replacement of pollution control equipment may lead to emissions increases, you will either undergo major NSR for your increases or you may qualify for a Pollution Control Project exclusion. See 67 FR 80186. We do agree, however, that where the control equipment is an integral part of the process it should be included. Therefore, we are excluding associated pollution control equipment from the definition of the " process unit," except for control equipment that serves a dual purpose in the process. We know there are industries where 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 32 pollution control equipment performs a dual purpose; for example, condensers often serve to control emissions of organic air pollutants while serving as a integral part of the operation of a fractionation column. A low NOx burner is another example of a dual purpose part. In both cases, these pieces of control equipment are integral to the process and, thus, should be included as part of the process unit. We are also clarifying in the final rule that administrative buildings ( including warehousing) are not to be included in the process unit, but other types of nonemitting units that are integral to the processing equipment should be included.

We also have included in our final rule industry specific examples of how this definition might be applied. The examples are drawn for three selected industrial processing categories   electric utilities, refineries, and incinerators. We proposed each of these detailed definitions and received mostly support from commenters on their accuracy. While we also proposed detailed definitions for two other industries   pulp and paper and cement producers   we have decided not to finalize those definitions after receiving comments from the cognizant industry trade association asserting that the definitions did not, and could not, capture all of their industry's configurations and they believed the generic process unit was sufficient for their industry. Because of the centrality of the " process unit" concept to the usefulness of the ERP, it is our desire to include a version of these examples in the final rule to make sure sources have a benchmark against which they can evaluate with greater confidence whether a particular replacement comes within the ERP. We are not planning to finalize examples provided by other industries at this time, given that we would have to propose them first, as we did for the three industry specific process unit definitions being finalized today. However, provided below are the process unit definitions that commenters submitted to us and that we think comport well with the general definition of process unit promulgated today.

° For a natural gas compressor station, each compressor system, together with its proportionate share of common support equipment is a separate process unit. For facilities operating in the midstream segment of the natural gas industry, the gas compression process unit consists of those portions of a natural gas compressor station, natural as liquids extraction and production plant, and natural gas processing plant that contain the combination of equipment necessary to compress natural gas for the purpose of establishing and maintaining the process flow and delivery of such gas and liquids.

° For a flat glass manufacturing plant, each production line within a facility should be a separate process unit. Flat glass production is completed on a continuous line where raw materials are added at one end, a continuous ribbon of glass is formed, and finished glass is packaged at the other end. The flat glass production line consists of: the batch house, where raw materials are stored and weighed; the furnace and refiner, where the raw materials are melted; the bath, where the glass ribbon is formed; the lehr, where the ribbon is annealed; and the cutting and packaging equipment, where the glass is removed from the line for sale to customers or for additional processing later. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 33 ° For a fiberglass production facility, each production line is a separate process unit. Fiberglass is manufactured on a continuous line where raw materials are melted at one end to form a continuous strand of fiberglass that is packaged at the other end. The fiberglass production line begins with the batch house, where raw materials are stored and weighed. In the melter, forehearth, and refiner, the raw materials are melted and refined. From the refiner, glass fibers are formed through controlled bushings. From the bushings, the continuous strand fibers are either directly cut or packaged or wound onto spools for packaging for sale to customers or for additional later processing.

° For the production of precipitated amorphous silica, the process unit includes, but is not limited to: raw material storage and handling equipment used for mixing sand and other raw materials prior to addition to the furnace; the furnace itself; the raw material storage and handling equipment for the cullet dissolving and silica precipitation process; all dissolving, precipitation, and filtration tanks and equipment; and drying equipment. Further, the process unit includes all the product packaging, storage, handling, and transfer equipment.

° For a chemical manufacturing plant, the process unit would include all the equipment assembled and connected by pipes or ducts to process raw materials and to manufacture an intended primary product and associated byproducts or intermediates. The process unit can consist of more than one unit operation. Chemical manufacturing process units may include, but are not limited to: raw material storage, and air oxidation reactors and their associated product separators and recovery devices; reactors and their associated product separators and recovery devices; distillation units and their associated distillate receivers and recovery devices; associated unit operations; associated recovery devices; and any feed, intermediate and product storage vessels, product transfer racks, and connected ducts and piping. A chemical manufacturing process unit includes pumps, compressors, agitators, pressure relief devices, sampling connection systems, open ended valves or lines, valves, connectors, instrumentation systems, and control devices or systems. For a chemical manufacturing facility, there are several types of process units: those that separate and distill raw material feedstocks; those that change molecular structures through reactions or polymerization; those that " finish" the reacted or polymerized product, through compounding, blending, or similar operations; auxiliary facilities, such as boilers and by product fuel production; and those that load, unload, blend, or store products. Process equipment that acts to control emissions, such as condensers, recovery devices, and oxidizers, is considered part of the process unit.

° For a coatings facility, the process unit includes any, all, or a combination of raw material storage, reaction, recovery, separation, purification, blending or other activity, operation, manufacture, or treatment. Cleaning operations are part of the process unit. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 34 Nondedicated solvent recovery operations located within a contiguous area within the affected source are considered a single process unit. A storage tank that is used to accumulate used solvent from multiple batches of a single process for purposes of solvent recovery does not represent the end of the process unit. Nondedicated formulation operations ( not including mixing, as defined) occurring within a contiguous area are considered a single process unit that is used to formulate numerous materials and/ or products.

° At a sugar mill, there are two types of process units. One type of process unit includes all of the portions of the plant that contribute directly to the production of steam. This process unit includes the combination of systems from the bagasse handling system through to the emission stack, including the bagasse handling equipment, feedwater system, combustion air system, boiler, burners, air preheaters, superheaters, flues, stack, and fuel oil storage and piping system. The second type of process unit includes those portions of the plant that contribute directly to the production of refined sugar from raw sugar and the associated packaging and shipping operations.

Finally, we have made some slight corrections to the process unit definitions that we proposed based on comments we received on the proposed definitions.

There are numerous industries that have industrial boilers at their facility to provide electricity and steam to their operations. As a general rule, we would expect these boilers to be treated as a separate process unit from the other unit operations occurring at the facility.

We also decided to continue to require that owners or operators who have parts shared by two or more process units proportionately allocate, based on capacity, the cost of those parts. And we agree with the commenter that an equitable approach for electric utilities having parts shared by two or more process units is to allocate the cost of shared equipment based on the pro rata share of megawatts produced by each process unit.

3.5 Fixed Capital Cost Percentage Comment:

3.5.1 General Support for Proposal Many industry commenters ( 636, 840, 841, 865, 896, 900, 902, 910, 941, 942, 951, 1013, 1050, 1066, 1077, 1078, 1079, 1082, 1083, 1091, 1096, 1099, 1105, 1110, 1129, 1132, 1133, 1136, 1138, 1149, 1201, 1202, 1204, 1237, 1238, 1246, 1265, 1292, 1301, 1368, 1441, 1446, 1453, 1463, 1465, 1620, 1629, 1792, 1793, 1794, 1799, 1866) supported the proposed threshold of 50 percent of replacement cost as the upper limit on equipment replacement. Two university 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 35 commenters ( 901, 1477) and a legislative commenter ( 1411) also supported this 50 percent cutoff.

One industry commenter ( 1129) said the proposal is consistent with existing regulatory requirements and would accord the flexibility originally intended under the CAA for routine maintenance projects, while at the same time assuring that major, non routine projects remain subject to NSR applicability review. Another industry commenter ( 1066) believed the proposed approach is consistent with a commonsense interpretation of the regulations and is undoubtedly how many have already interpreted the requirements.

Several industry commenters ( 896, 951, 1110, 1132, 1265, 1453, 1465, 1793) believed a 50 percent cutoff to be consistent with reconstruction definitions used in many NSPS and NESHAP regulations. Two industry commenters ( 1465, 1793) stated that a 50 percent cutoff for the ERP would be valid for the same reason as for the NSPS reconstruction test; significant changes to a process unit are necessary before retrofit controls should be considered, provided there is no increase in emissions.

One industry commenter ( 1866) added that EPA's concerns about an unbounded component replacement provision may be unfounded, because technological advances and obsolescence make it unlikely that replacement projects would eventually replace an entire source. This commenter said the NSPS reconstruction test, which is discussed as a possible approach to limit the ERP, has a long regulatory history and seems appropriate for differentiating between projects that are routine replacement and projects that are tantamount to creating a new process unit. Another industry commenter ( 951) believed there is no reason to use a lower cutoff.

One industry commenter ( 1204) only supported the 50 percent replacement value threshold if there are not mitigating factors. If a specific, unique, functionally equivalent replacement exceeds the threshold, there should be an available regulatory process to determine the actual environmental effects of the change. If the replacement can be shown to have no impact on emissions and is part of a non emitting portion of the unit, it should be viewed as an exempt replacement. Another industry commenter ( 1078) said the 50 percent cost threshold is reasonable, if it includes only the cost of the component itself and there is no aggregation of independent replacements. One industry commenter ( 1083) said a straightforward methodology for calculating costs is needed. One industry commenter ( 902) made clear that the commenter's support of the 50 percent cost threshold relies on an assurance that NSR applicability will not automatically be triggered when the capital cost exceeds the 50 percent threshold, as long as there is no increase in emissions from the RMRR activity.

One industry commenter ( 1078) said the ERP cost threshold test should be essentially equivalent to the NSPS reconstruction test, based on the proposed definition of process unit. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 36 Two industry commenters ( 1082, 1797) supported the 50 percent replacement value threshold, if replacement project costs are aggregated over a one year period. Another industry commenter ( 1446) supported the 50 percent replacement value threshold if applied to a collection of replacement activities. If instead the percentage is applied on a per component basis, these commenters ( 1082, 1446, 1797) recommended a threshold of 5 percent for the electric generating industry. Two of the commenters ( 1082, 1446) stated that the 5 percent threshold is based on an evaluation of some of the commenters' large routine replacement projects that electric generating units undertake: turbine blades; sections of the waterwall tubes; reheaters; superheaters; and economizers.

3.5.2 Opposition to Proposed Replacement Value Threshold Some commenters opposed any percentage; other commenters believed a 50 percent ERP cost threshold was too high.

Many State/ local commenters ( 946, 1146, 1199, 1206, 1268, 1270, 1361, 1448, 1471, 1622), two industry commenters ( 797, 898), an environmental commenter ( 1150), and two citizen commenters ( 784, 850) opposed the 50 percent replacement value threshold.

Three State/ local commenters ( 1199, 1471, 1622) believed the capital replacement percentage should be much less than 50 percent. One State/ local commenter ( 1622) preferred that the total replacement cost for a single process unit over any period of 5 consecutive years should not exceed 50 percent of the replacement cost of the process unit. One State/ local commenter ( 1270) said the replacement percentage should not be higher than 25 percent. One State/ local commenter ( 1146) suggested a replacement percentage of 5 to 10 percent if the ERP moves forward, to reduce the risk of replacement of an entire unit over time without installation of BACT. One citizen commenter said a more appropriate percentage for electricity producers is 0.1 to 1.0 percent. One State/ local commenter ( 1361) said the threshold should be 5 percent, 1 percent, or even less, as shown by the Tennessee Valley Authority ( TVA) case. One State/ local commenter ( 1268) suggested using a de minimis value, rather than 50 percent, if the ERP is included in the final rule. This commenter said an analogy to NSPS reconstruction is misplaced, because NSPS includes an emissions test as well as the cost threshold.

One State/ local commenter ( 1206) believed the 50 percent number has no practical effect in protecting public health and the environment, and the commenter is not aware of any projects that have exceeded 50 percent in cost. Another State/ local commenter ( 1448) was concerned that, whatever percentage is used for the ERP cost threshold, sources could abuse the ERP by either adding a new process unit or replacing an entire process unit piecemeal over several years. One State/ local commenter stated generally that the cost thresholds were too permissive, but this commenter did not provide any alternatives. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 37 One industry commenter ( 898) believed that EPA did not establish a reasoned basis to support 50 percent as the proper ERP cost threshold. The commenter stated that EPA should have used the WEPCO four factor test that considers the nature and extent, purpose, cost, and frequency of activities in order to establish that the given percentage has any connection to the concept of routine, because otherwise the rule is arbitrary and capricious. The commenter further added that if EPA fails to articulate the ERP cost threshold ( and to articulate six other issues listed by the commenter) before promulgating RMRR rules, the EPA will run afoul of section 553 of the Administrative Procedure Act (" APA").

While opposed to the ERP in general, one industry commenter ( 797) said the cost threshold for the ERP should be as high a percentage as possible, so as not to promote premature replacement of equipment that is repairable.

The environmental commenter ( 1150) opposed the equipment replacement approach in general but added that if EPA is to adopt a cost based exemption, the threshold should be much lower than 50 percent.

One citizen commenter ( 850) said the 50 percent number from the NSPS is archaic and environmentally nonprotective. This commenter suggested that the ERP cost threshold instead be 24 percent. The commenter believed this lower percentage is appropriate because the lifetime of high cost materials will considerably exceed 5 years.

Response:

The purpose of the cost based limitation on the scope of the ERP is to distinguish between those equipment replacement activities that should qualify as RMRR without further consideration and those activities that should undergo case specific consideration. This concept is borrowed from, and closely akin to, the long established reconstruction provision under the NSPS program. For the reasons explained below, we have decided to establish a 20 percent cost threshold under the ERP.

In the proposal, we observed that it may sometimes be difficult to determine where to draw the line between an activity that should be treated as an excluded replacement activity and one that should be viewed as a physical change that might constitute a major modification, when the replacement of equipment with identical or functionally equivalent equipment involves a large portion of an existing process unit. We solicited comment on a range of equipment replacement cost thresholds such as one based on the NSPS program. Under the NSPS program, when the cost of a project at an existing affected facility exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new unit ( that is, the current capital replacement value of the existing affected source), then the source must notify and provide information to the permitting authority. After considering a range of factors, including 3  Equipment Replacement 7In the proposal, it was incorrectly stated that applicability of the NSPS was triggered if a project exceeded 50 percent of the cost of replacing the affected facility. As stated in this notice, if an activity exceeds this cost threshold, that only triggers further evaluation, not the automatic application of the NSPS to the source.

Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 38 the cost of the project, the estimated life of the facility after the replacements, the extent to which the replaced equipment causes or contributes to the emissions from the source, and any economic or technical limitations on compliance with the NSPS, the reviewing authority determines whether the proposed project is a reconstruction. 7 We observed that, in some respects, an equipment replacement cost threshold set at the NSPS reconstruction test could be an appropriate approach for distinguishing between routine and nonroutine identical and functionally equivalent replacements under the major NSR program. As under the NSPS program, we do not believe it is reasonable to exclude from major NSR those activities that involve the total replacement of an existing entire process unit.

Finally, we noted that there are other considerations pointing in favor of a threshold lower than the 50 percent reconstruction threshold that may be appropriate to bound the ERP. For example, since under NSPS when a source replaces portions of an existing affected facility that amounts to half its capital replacement value, we believe its important to consider on a case by case basis whether such replacements constitute construction. It could be argued that some percentage lower than the 50 percent reconstruction threshold might be suitable in requiring consideration of the question whether equipment replacements constitute a modification of an existing process unit. We solicited comments on the appropriate level of any percentage.

We agree with those commenters who see a relationship between establishing a threshold under the major NSR program for the ERP and the threshold established for the NSPS program. However, we disagree that the thresholds for the two programs should be the same. The NSPS threshold was intended to identify those projects that, even though they did not qualify as a modification, nevertheless are of such magnitude that they should be given further consideration as projects possibly tantamount to new construction. The 50 percent NSPS threshold is not a bright line in the sense that all projects that exceed 50 percent are automatically considered as reconstruction. Rather, as discussed above, it is a threshold intended to alert permitting authorities to significant projects and allow case by case decisions based on a series of regulatory factors.

The ERP replicates the NSPS concept in some ways. It identifies a threshold below which there is no need for further inquiry into whether an activity qualifies for the ERP and above 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 39 which there is a need for a case by case determination. The major difference between the ERP and the NSPS reconstruction test is that the ERP deals with modifications, not reconstructions. This difference weighs in favor of establishing the equipment replacement threshold at something less than the reconstruction threshold. It is logical and practical to conclude, as some of the commenters do, that by using the word " modification" the CAA intended to capture projects on a smaller scale than reconstructions. As noted above, we have set the ERP cost threshold at 20 percent. This value is less than one half of the 50 percent reconstruction threshold and, therefore, fits well within this conceptual framework.

Another key factor in choosing an appropriate ERP cost threshold is the decision of the U. S. Court of Appeals for the Seventh Circuit in the Wisconsin Electric Power Company ( WEPCO) case. See 893 F. 2d 901 ( 7th Cir. 1990). This decision directly addressed the questions of what level of " like kind" replacement activities qualify as changes under the major NSR program.

In the WEPCO case, the Court considered a project involving 5 coal fired units at WEPCO's Port Washington plant. Each unit was rated at 80 megawatts of electrical output capacity. The project involved the replacement of numerous major parts. The information submitted by WEPCO showed that the company intended to replace several parts that are essential to the operation of the Port Washington plant. In particular, the WEPCO would replace the rear steam drums on the boilers at units 2, 3, 4, and 5. According to WEPCO, these steam drums were a type of " header" for the collection and distribution of steam and/ or water within the boilers. They measure 60 feet long, 50.5 inches in diameter, and 5.25 inches thick, and WEPCO viewed their replacement as necessary to continue operation of the units in a safe condition. In addition, at each of the emissions units, WEPCO planned to repair or replace several other integral parts, including replacement of the air heaters at units 1, 2, 3, and 4. The WEPCO also planned to renovate major mechanical and electrical auxiliary systems and common plant support facilities. The WEPCO intended to perform the work over a 4 year period, utilizing successive 9 month outages at each unit. The cost of the project was estimated in 1988 to be $ 87.5 million. The Court determined, at our urging, that the changes did constitute a " physical change" under the NSR rules.

In the case of a steam electric generating facility, the process unit definition provided in the final rule is nearly identical to the make up of the " comparable new facility" that was used in the NSPS evaluation of the WEPCO renovation project. However, one difference is that the cost of pollution control equipment is not considered in evaluating the changes in WEPCO against the process unit definition in the final rule. The WEPCO had electrostatic precipitators on each of its 5 process units, so this needs to be factored in. In addition, the WEPCO evaluation dealt with 5 boilers, each with its own turbine generator set; to be consistent with the final definition of steam electric generating facility, we would likely treat each boiler unit as belonging to a 3  Equipment Replacement 8 Using the Chemical Engineering Annual Plant Cost Index ( composite), $ 87.5 million in 1988 dollars is equal in real terms to ( 361.3/ 342.5) multiplied by 87.5 million, or $ 92.3 million in 1991 dollars. This cost index is found in Chemical Engineering magazine.

Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 40 different process unit. However, since all of the boilers underwent similar renovations, for simplicity we can assume that all of the process unit specific activity costs are equivalent.

Using 1991 dollars, consistent with the timeframe of the Seventh Circuit Court's decision, it appears that the value of the 5 process units at the 400 megawatt WEPCO Port Washington facility would be approximately $ 321 million based on 1991 model plant values provided by the International Energy Agency. The 1988 project cost of $ 87.5 million scaled up to 1991 dollars results in an adjusted project cost of $ 92.3 million. 8 Thus, the capital cost percentage for the replacement activities at WEPCO, averaged over its 5 process units, amounts to 29 percent. Alternatively, using the project cost of " at least $ 70.5 million" as cited in the 1991 decision by the Seventh Circuit, and using the same value for process unit cost, we compute 22 percent. The 20 percent threshold is, therefore, beneath the scope of the projects at issue in the WEPCO case. Therefore, while we recognize that the WEPCO court did not specifically endorse as RMRR all maintenance, repair and replacement activities falling below the cost percentage in that case, the percentages we are adopting today certainly does not run afoul of the limits established in WEPCO.

The 20 percent threshold also is supported by available data for the electric utility sector. We have a robust and detailed set of information available on maintenance, repair and replacement activities for the electric utility sector. Information about the electric utility sector assures us that we have established the right ERP threshold for this sector.

Two comment letters ( from the Utility Air Regulatory Group ( UARG) and from the American Lung Association ( ALA), et al.) were particularly helpful in understanding the issues associated with the electric utility sector. The UARG provided as an attachment to its comment letter a document describing major repair and replacement activities that its members believe must be undertaken at utility generating stations in order to keep those facilities operational. The UARG noted that capital costs incurred for repair and replacement activities at an individual process unit additionally include activities more minor than those addressed in the document. The UARG grouped repair and replacement activities into project families; within each project family were per component costs ($/ kW) for numerous equipment replacement activities. We have reviewed the list of projects supplied by UARG and have concluded that these types of replacement activities are necessary and helpful in maintaining, facilitating, restoring or improving the safety, reliability, availability, or efficiency of process units. Therefore, these types of individual activities and groups of activities should qualify for the ERP 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 41 and be excluded from major NSR without case specific review. We also believe that it is reasonably expected in the electric utility industry for groups of these activities to be implemented at the same time. Such groupings should also be excluded without case specific review. When we compare the 20 percent ERP cost percentage to the UARG data, we find that individual replacement projects would, in fact, qualify for the ERP and that limited groupings of these projects would qualify. However, larger groupings of these projects   groupings that are not usually seen in the industry   would not qualify for the ERP. This shows that the 20 percent threshold will be effective in distinguishing between activities ( and aggregations of activities) that should not require case specific review to be excluded from major NSR and those that do.

The ALA commenters provided with their comments the results of their analysis of projects at issue in an NSR enforcement case against Tennessee Valley Authority ( TVA). As shown in the ALA comment letter, the Clean Air Task Force and the Natural Resources Defense Council looked at costs for 14 projects on a process unit basis, in year 2001 dollars, from the publicly available record for the case. For all but one of the challenged projects, the ALA commenters calculated a cost of less than 4 percent of process unit replacement cost. The ALA commenters submitted results of this analysis with their opposition to a source wide, 5 percent maintenance allowance. For the reasons explained above, to the extent the projects addressed by ALA constitute identical or functionally equivalent replacements, we now believe that such projects should be encouraged because they maintain, facilitate, restore or improve the safety, reliability, availability, or efficiency of the process unit. Therefore, we believe such projects should qualify for the ERP in the future.

Comment:

3.5.3 Whether to Set Different Fixed Capital Cost Percentages for Different Industry Sectors Several sugar industry commenters ( 920, 921, 1123) believed an ERP cost threshold of 50 percent could be appropriate but preferred that EPA establish industry specific thresholds. However, these commenters stated that they did not have adequate data to suggest a specific percentage for their industry.

One State/ local commenter ( 1270) suggested that industry specific considerations should be taken into account in setting the cost threshold.

Two industry commenters ( 1110, 1132) favored applying the 50 percent cutoff to all industries because applying other percentages on an industry or process type basis would unnecessarily complicate the replacement analysis. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 42 One industry commenter ( 897) said the appropriate threshold percentages should be based on industrial standards but added that a facility with special circumstances should have the regulatory means to request an alternate method of calculating this threshold.

3.5.4 Information Provided on RMRR Activities and Costs in Specific Industry Sectors For natural gas transmission, one industry commenter ( 1138) performed an analysis of maintenance and repair costs at eighteen compressor stations under the proposed ERP framework ( see pp. 11 14, 51 52). This commenter's analysis concluded that the proposed 50 percent cost threshold on a process unit basis is appropriate for the natural gas transport industry, if replacement of non emitting units and catastrophically failed units is excluded. Two natural gas industry commenters ( 1096, 1138) asserted that the rule should encourage the practice of offsite maintenance. Both offsite and onsite maintenance should be counted against the 50 percent cost threshold. One of the industry commenters ( 1138) explained that the gas turbines ( internal combustion engines) used at natural gas compressor stations have been designed for offsite maintenance and often cannot be cost effectively maintained onsite. Instead, the manufacturer " changes out" the turbine by removing the components in need of maintenance ( typically the gas producer and power train) and replaces them with components from the manufacturer's inventory. Such change outs take place every 30,000 to 50,000 hours of turbine operation, or every 3 to 5 years. The national pipeline industry undertakes several hundred turbine change outs per year. A change out takes 2 days, where onsite maintenance of a turbine would take 6 weeks and would also increase the overall cost of gas transmission by increasing the need for backup compressor capacity. Further, offsite maintenance allows for verification in test cells that the changed out turbine components meet emission standards before they are returned to the fleet.

Several sugar industry commenters ( 920, 921, 1000, 1123) believed their industry should have a higher replacement percentage than other steam generating units due to the heat and corrosive compounds. The commenters explained that their bagasse fuel ( from sugar cane) has a high sand content, which is extremely corrosive. Moreover, the boilers are idle for several months per year, at which time they are subject to humidity and rain, leading to corrosion of tubes, components, and equipment. One of these commenters ( 1000) noted that boiler tubes, air heater tubes, superheater tubes, refractory, economizer tubes, and induced fan drafts routinely require maintenance or partial replacement.

The environmental commenter ( 1150) asserted that the total project expenditures to upgrade each of the three boilers at the Alcoa Sandow Betterment Project were less than 15 percent of the capital cost of a new unit.

The environmental commenter ( 1150) provided extensive information documenting RMRR costs for utilities, primarily from various court cases and enforcement actions. The 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 43 commenter ( 1150) noted that the following were not considered routine replacement in court cases: replacement of cyclones; replacement of lower furnace walls ( including headers and footers); replacement of waterwall tubes in front, rear and sidewalls of both furnaces; replacement of burner tube panels and superheater platen elements; replacements with redesigned components.

The environmental commenter ( 1150) stated that the following equipment replacement activities would not increase emissions and would therefore be exempt from major NSR regardless of a routine maintenance exemption: replacement of a pump associated with a distillation column; replacement of a pump associated with a distillation column; replacement of worn out pipes in a chemical process plant; and replacement of controllers at a series of batch digesters.

The environmental commenter ( 1150) stated that by the year 2000, almost 75 percent of power plants were more than 20 years old. The commenter noted that at 20 25 years, various major components of an electric generating unit wear out, a condition referred to as " component end of life." Absent replacement of the components, the decline continues after 20 25 years. The environmental commenter ( 1150) cited the component replacement schedule from Babcock and Wilcox's reference, Steam, Its Generation and Use.

One industry commenter ( 1213) has compiled data from DOE to produce curves that an electric utility owner/ operator could use to select replacement cost for a source based on size and fuel type. ( See Document ID 1215 in the docket.) This commenter also provided a paper describing major repair and replacement projects that are undertaken at utility generating stations in order to keep them operational. ( See Document ID 1221 in the docket.)

One industry commenter ( 1621) noted that re bricking of ovens, furnaces, and some boilers is a periodic maintenance requirement that is necessary to assure good product quality, process control, and fuel efficiency. Minor re bricking may occur on a yearly or bi yearly basis; major re bricking projects may be required every 10 to 15 years.

Response:

The 20 percent threshold also is supported by available data for the electric utility sector. We have a robust and detailed set of information available on maintenance, repair and replacement activities for the electric utility sector. Information about the electric utility sector assures us that we have established the right ERP threshold for this sector.

We have determined that two comment letters ( from the Utility Air Regulatory Group ( UARG) and from the American Lung Association ( ALA), et al.) were particularly helpful in understanding the issues associated with the electric utility sector. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 44 The UARG provided as an attachment to its comment letter a document describing major repair and replacement activities that its members believe must be undertaken at utility generating stations in order to keep those facilities operational. The UARG noted that capital costs incurred for repair and replacement activities at an individual process unit additionally include activities more minor than those addressed in the document. The UARG grouped repair and replacement activities into project families; within each project family were per component costs ($/ kW) for numerous equipment replacement activities. We have reviewed the list of projects supplied by UARG and have concluded that these types of replacement activities are necessary and helpful in maintaining, facilitating, restoring or improving the safety, reliability, availability, or efficiency of process units. Therefore, these types of individual activities and groups of activities should qualify for the ERP and be excluded from major NSR without casespecific review. We also believe that it is reasonably expected in the electric utility industry for groups of these activities to be implemented at the same time. Such groupings should also be excluded without case specific review. When we compare the 20 percent ERP cost percentage to the UARG data, we find that individual replacement projects would, in fact, qualify for the ERP and that limited groupings of these projects would qualify. However, larger groupings of these projects   groupings that are not usually seen in the industry   would not qualify for the ERP. This shows that the 20 percent threshold will be effective in distinguishing between activities ( and aggregations of activities) that should not require case specific review to be excluded from major NSR and those that do.

The ALA commenters provided with their comments the results of their analysis of projects at issue in an NSR enforcement case against Tennessee Valley Authority ( TVA). As shown in the ALA comment letter, the Clean Air Task Force and the Natural Resources Defense Council looked at costs for 14 projects on a process unit basis, in year 2001 dollars, from the publicly available record for the case. For all but one of the challenged projects, the ALA commenters calculated a cost of less than 4 percent of process unit replacement cost. The ALA commenters submitted results of this analysis with their opposition to a source wide, 5 percent maintenance allowance. For the reasons explained above, to the extent the projects addressed by ALA constitute identical or functionally equivalent replacements, we now believe that such projects should be encouraged because they maintain, facilitate, restore or improve the safety, reliability, availability, or efficiency of the process unit. Therefore, we believe such projects should qualify for the ERP in the future.

3.6 Basic Design Parameters Comment:

3.6.1 Generally Supportive Comments <IP_ADDRESS> EUSGUs 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 45 Several industry commenters ( 1099, 1136, 1213, 1629, 1792) supported the use of maximum heat input and fuel consumption as the appropriate design parameters for electric generating units. One industry commenter ( 1629) added that the final rule should clarify that the correct parameter is maximum hourly heat input. Two industry commenters ( 1099, 1213) requested that EPA provide sufficient flexibility in how the parameters are determined, and one industry commenter ( 1792) requested sufficient flexibility to account for problems that may have been corrected to obtain the true design rate of a unit.

One industry commenter ( 1794) stated that it may not be necessary to specify both the heat input and fuel consumption as design parameters for EUSGUs because fuel consumption is essentially duplicative of the heat input value. Also, the fuel consumption rate for coal fired units will vary depending on the quality of the coal for a given heat input. If EPA decides to retain fuel consumption as a design specification, then the industry commenter recommended that the minimum fuel quality based on Btu content should be used for coal fired units.

One industry commenter ( 1078) stated that the use of the basic design parameters is a reasonable safeguard, but EPA should not include " fuel specifications" for EUSGUs. It is too vague and could encompass almost anything. EPA should either specify fuel consumption rates ( which is redundant with maximum heat input), or fuel type ( such as coal or oil).

One industry commenter ( 1129) said the primary design parameter for EUSGUs is the manufacturer's maximum designed steam flow rating or the maximum historical steam flow, whichever is higher.

One industry commenter ( 1794) recommended that the final rule clarify that the owner can establish the basic design for maximum heat input of an electric generating unit by referencing available credible information, including results of historic maximum capability tests, operating design information, or engineering calculations which may establish the heat input value the unit has demonstrated it is capable of achieving. Results from tests performed by electric utilities in the context of providing assurances to generation dispatch systems and regional or national power pools may be used to establish the unit's maximum heat input. A review of such data or other available operational data or design information can reveal the heat input which the unit is capable of achieving in its " pre change" configuration and this can be compared to a " post change" heat input value. This should be a case by case analysis and demonstration, not a simplistic formulaic test.

According to one industry commenter ( 797), replacement of power turbines and combustion units is called for every 30,000 to 50,000 hours of operation. Unless components are upgraded during these replacements, the heat input remains the same and so does the emissions rate. The commenter believes that such replacement should be considered routine maintenance. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 46 <IP_ADDRESS> Miscellaneous general comments on basic design parameters Several industry commenters ( 951, 1066, 1096, 1099, 1112) agreed with the EPA's use of maximum heat input and fuel specifications for basic design parameters. One industry commenter ( 1112) recommended that EPA provide sufficient flexibility for plant owners to determine how basic design parameters are determined.

One industry commenter ( 1100) supported the concept of using basic design parameters within the equipment replacement approach, but recommended further clarification be provided for efficiency improvements. The industry commenter recommended that an equipment replacement that improves a process unit's efficiency by enabling the unit to return to its original design parameters be considered RMRR even if current actual emissions increase as a result. For example, if boiler tubes or refractory are replaced on a boiler, these activities should be RMRR since they return the unit to its original design parameters and improve the unit's efficiency.

Several industry commenters ( 920, 921, 1000, 1123) supported maximum design heat input as the basic design parameter for boilers. These industry commenters ( 920, 921, 1000, 1123) noted that this parameter could also be expressed in terms of maximum design steam production rate, which is how Florida has permitted their bagasse boilers.

One industry commenter ( 1136) supported EPA's use of the term " process unit" to determine if there is a change in a design parameter.

One industry commenter ( 941) said EPA cannot practicably disallow changes in fuel or raw material input specifications for all complex industrial sources. Even where manufacturer's design specifications exist for a unit, they serve to define the unit's guaranteed maximum capacity rather than its actual maximum capacity. Many units routinely and properly operate above their design specifications.

<IP_ADDRESS> Look back period for determining basic design parameters Several industry commenters ( 941, 1050, 1099, 1112, 1123, 1368, 1629) recommended that a reasonable look back period should be used for establishing the pre change values for basic design parameters, not the condition of the process unit immediately before the change. The industry commenters suggested a 5 year look back period, consistent with that for the NSPS hourly emissions increase test.

<IP_ADDRESS> De minimis changes in emissions or basic design parameters One industry commenter ( 941) stated that because the results of RMRR are not always predictable in advance, the final rule should provide that unanticipated and unintended small 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 47 increases in hourly emission do not disqualify a project from the equipment replacement exclusion.

Two industry commenter ( 858, 896) and one university commenter ( 901) requested that a de minimis change in design parameters be allowed when making equipment changes because some effects resulting from the change may not be apparent before the change is made. One industry commenter ( 896) added that such a change be allowed as long as emissions do not increase above maximum design levels. The university commenter added that such a change be allowed as long as emissions do increase above the permitted maximum hourly emission rates.

<IP_ADDRESS> Develop basic design parameters for specific industries Two industry commenters ( 1138, 1446) supported the basic design parameter approach, but believed that the definition of basic design parameter for non utilities and non fossil fuel burning sources in the proposed rule is too rigid and is inconsistent with the natural gas transport industry conventions. One industry commenter ( 1138) urged EPA to modify the definition to allow for industry specific flexibility or specify additional source category specific parameters. For the natural gas transmission compressor stations, the commenter suggested using brake horsepower ( bhp) as the conventional design capacity parameter. All regulated natural gas transmission compressor stations maintain consistent, accurate, and certified records of process unit bhp capacity.

One State/ local commenter ( 1270) stated that while it would take considerable time and effort to develop basic design parameters, there is no other way to implement the proposed option since no two processes are the same.

3.6.2 Opposition to Basic Design Parameters <IP_ADDRESS> General opposition to basic design approach An industrial commenter ( 636) noted that in many cases, the boiler design fuel specification is fabricated to satisfy certain boiler design criteria with inherent operating latitude, and there is no actual fuel which can meet those specifications. Fuel changes should not be considered replacements.

One industry commenter ( 902) was strongly opposed to fully defining specific design parameters in the regulation because published design standards in the rule would quickly become outdated, thereby requiring frequent revisions in the regulation.

One industry commenter ( 1301) stated that requiring equipment replacements to not alter the basic design parameters of a process unit is a nebulous requirement that EPA should carefully 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 48 consider before going final. For the petroleum refining industry, the commenter was particularly concerned that the concept of material input specifications is a nominal one that has practical value only in the design phase but not in the operations phase.

One industry commenter ( 909) believed that activities intended to improve an affected unit's performance, beyond what would otherwise be reasonably achieved by the equipment absent a specific activity, clearly qualify as actions that extend beyond the reasonable definition of RMRR and should instead be subject to the full scope of NSR. The commenter further stated that the recent revisions to the NSR regulations ( 67 FR 80186) allow for reasonable actions to improve unit performance.

One industry commenter ( 942) opposed the basic design parameter constraints, stating that they would exclude projects that result in efficiency improvements.

One State/ local commenter ( 1012) said that RMRR should not be allowed for changes in basic design parameters.

An industry commenter ( 1238) urged EPA to eliminate the requirement that the new equipment not alter the basic design parameters of the unit. The commenter expressed concern that regulators may use the provision to bar changes that carry out the same function but do so through an improved design from qualifying for RMRR exclusion.

<IP_ADDRESS> Opposition to input parameters; preference for design specifications or emission rate Several industry commenters ( 814, 941, 1013, 1114, 1133, 1204, 1237, 1463) and two university commenters ( 901, 1477) noted that many pieces of equipment are not rated or specified based on " material input" or " fuel input." Instead, EPA should also define " design specifications" because many pieces of equipment are purchased based on their capacity or output. Therefore, EPA should rely on the manufacturer's documented design information to identifying the basic design parameters for any piece of equipment rather than attempting to specify it in the rule. Several of the industry commenters ( 941, 1013, 1114, 1133, 1237) said that a determination should be based on maximum hourly emissions before and after the change, and one industry commenter ( 1463) recommended using annual emissions. One industry commenter ( 941) added that this design based approach is already a condition of the RMRR allowance approach and has been used in other long established CAA programs like NSPS.

One industry commenter ( 1110) believed that the proposal suggests that basic design parameters are limited to the maximum fuel or material input specifications for non utility process units. Another industry commenter ( 1132) urged EPA to remove the basic design parameter requirements in light of other safeguards in the proposed rule. Both industry commenters 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 49 recommended that an increase in material input should be allowed as long as there is no increase in emissions above maximum achievable levels. Therefore, the safeguard that reads " does not alter the basic design parameters" should be replaced with " should not increase the maximum design emission rate."

In reference to the cement industry, one industry commenter ( 1283) stated that EPA should clarify the definition of basic design parameters. The current definition is ambiguous because maximum fuel and material input specifications have no relevance in this industry. The industry commenter recommended that maximum clinker generation capacity of the kiln system be used as the basic design parameter for the cement industry.

For surface coating operations, one industry commenter ( 1202) stated that there are problems with use of paint input as a basic design parameter. Any replacement of paint guns could affect paint usage and would be viewed as a basic design parameter change. Because maximum input varies with the paint type and characteristics, material input does not represent a basic design parameter for surface coating operations. The industry commenter recommended using transfer efficiency and quality of paint job, not material input rates, for the basic design parameters for automobile surface coating.

One State/ local commenter ( 1443) believes that defining the term " basic design parameters" solely based upon maximum heat input and fuel consumption specifications, or maximum material/ fuel input specifications, will, under the guise of " replacement," allow a wide range of changes that should be considered NSR modifications. There are many changes at air emission sources that do not alter maximum heat input and fuel consumption specifications, or maximum material/ fuel input specifications, yet involve significant modifications that are unrelated to routine replacement. The commenter suggested that any equipment modification resulting in a change in the equipment description in the permit should be subject to NSR.

An environmental commenter ( 1150) believed the basic design parameters of maximum heat input and fuel consumption are too narrow and will be difficult to administer. The environmental commenter also believed that changes in heat input or fuel consumption due to equipment replacement are difficult to evaluate. For example, some utilities have claimed that nameplate capacity only represented the manufacturer's guarantee and not the maximum capacity of the unit, thereby justifying an increase to a higher heat input rate. The commenter believed that many other basic design parameters should be included, but did not list these specifically. If EPA decides to retain the ERP, the commenter urged EPA to exclude equipment replacement that changes the basic design parameters of the process unit or results in an increase of total annual emissions.

An industrial commenter ( 1134) stated that for many industries, it is difficult to associate basic design parameters with either hourly emissions or input specifications. However, if EPA 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 50 includes a basic design parameter test in the final rule, the commenter urged EPA to allow flexibility to plant operators to establish what the measure of performance will be for process units, including the use of permit limits on amount of production.

A State/ local commenter ( 1199) recommended that any design parameter that could affect actual emissions should be considered a basic design parameter which may not be changed without agency approval.

<IP_ADDRESS> Oppose basic design parameter approach because functional equivalence is adequate Several industry commenters ( 1132, 1134, 1292, 1799, 1866, 1868) indicated that the functionally equivalent safeguard is sufficient to assure that replacement components cannot be designed to materially change the process unit.

Two industry commenters ( 1201, 1202) stated that the basic design parameter test introduces substantial confusion into the rule without adding any additional benefit that is not already inherent in the term " functionally equivalent." One of the commenters ( 1202) added that for the automobile surface finishing industry, the test would exclude the precise projects that the equipment replacement approach is designed to cover.

An industry commenter ( 1079) supported the concept of including in RMRR the replacement of existing equipment that serves the same basic function. However, EPA's proposal that basic design parameters of the affected process units not be changed is vague and subject to the same type of interpretive abuses by regulatory agencies that occur now. The commenter cites as an example of the impracticality of the design parameter limitation a crude oil distillation tower that may have several capacities that are a function of the type of crude that is to be processed. Of particular concern to this commenter was EPA's suggestion that changes in fuel or raw material input specifications be prohibited, and recommended an ERP under which the exclusive design criterion is whether a component is " identical or functionally equivalent" to the replaced component.

One industry commenter ( 1237) generally opposed the use of basic design parameters as the basis for evaluating whether equipment replacements are RMRR because this test could exclude many component replacements that can properly be deemed functionally equivalent. The commenter urged EPA to only use design parameters when they have been used to establish federally enforceable permit limits, similar to existing exclusions for changes in fuels or raw materials that a unit is otherwise capable of accommodating.

<IP_ADDRESS> Oppose including efficiency as a basic design parameter 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 51 Several industry commenters ( 902, 920, 921, 951, 1000, 1013, 1078, 1112, 1123, 1213, 1368) said efficiency should not be a basic design parameter to avoid penalizing facilities for process efficiency enhancements.

The industry commenter ( 1794) supported EPA's statement that an improvement in efficiency does not change a process units's basic design parameters. The industry commenter ( 1794) recommended that EPA clarify in the final rule that efficiency improvements and the use of new technology are not considered changes in design parameters.

Two commenters ( 1799, 1868) believed that the basic design parameters safeguard has the potential to bar component replacements that achieve significant gains in efficiency, contrary to EPA's stated intent.

One industry commenter ( 1793) supported EPA's exclusion of efficiency as a basic design parameter. The commenter also recommended that this option specifically include work that enhances safety and reliability. The commenter stated that RMRR projects that enhance efficiency, safety, and reliability will invariably improve environmental performance. The commenter asserted that improved safety and reliability will result in more stable process operation and reduce periods of startup, shutdown, and malfunction and the increased emissions usually associated with them.

<IP_ADDRESS> Support including efficiency as a basic design parameter Several industry commenters ( 1132, 1201, 1202, 1866) stated that efficiency changes are likely to always affect basic design parameters because allowing a higher production rate per unit time will require a higher input rate. Two of the industry commenters ( 1201, 1202) suggested that an alternative safeguard would be that no permitted emission limits ( hourly, annual, or per unit of production limits) need to be revised .

One State/ local commenter ( 1268) urged EPA to include efficiency, operating rate, utilizations, fuel adaptability, and useful economic life as basic design parameters, in addition to the input parameters in the proposal.

One industry commenter ( 909) opposed excluding efficiency as a design parameter. The commenter explained that efficiency is a critical and fundamental aspect of a power generating unit's ability to maintain financial viability, particularly for those facilities participating in competitive markets, and should be considered a key design parameter for all power plants.

Response: 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 52 In the proposal, equipment replacements were only eligible for the ERP if they did not change the basic design parameters of the process unit. We proposed that maximum heat input and fuel consumption specifications for EUSGUs and maximum material/ fuel input specifications for other types of process units are basic design parameters. We solicited comments on limiting the eligibility of the ERP this way and on the basic design parameters we proposed.

We recognize that the proposed basic design parameters are inconsistent with some industry conventions, and that we should allow for industry specific flexibility or specify additional source category specific parameters. For example, for natural gas transmission compressor stations, commenters explained that brake horsepower is the conventional design capacity parameter. We received similar comments from other industries, including cement and surface coaters, who objected to limiting their facilities to the proposed basic design parameters. Accordingly, we have decided to provide flexibility to allow for facilities to propose alternative basic design parameters to their reviewing authority which would then be incorporated in a Federally enforceable permit such as a title V operating permit.

In addition to this flexibility, there may be a need for additional flexibility in using the basic design parameters that are spelled out in the final rule. For instance with boilers, maximum steam production rate is often used by the industry, and it may make sense in some cases to set the design parameters based on those values rather than on maximum heat input. Likewise, a crude oil distillation tower may have several capacities that are a function of the type of crude that is to be processed, and so a refiner may need to have a set of basic design parameters for their crude towers. These situations can be addressed by the source proposing alternative parameters or sets of parameters to their reviewing authority.

Also, there should be flexibility in how the basic design parameters are demonstrated. In order to establish the heat input value that the process unit has demonstrated it is capable of achieving, an electric generating unit should have the flexibility to reference available credible information, such as results of historic maximum capability tests, operating design information from the manufacturer, or engineering calculations. Results from tests performed by electric utilities in the context of providing assurances to generation dispatch systems and regional or national power pools may be used to establish the process unit's maximum heat input. A review of such data or other available operational data or design information can reveal the heat input that the process unit is capable of achieving in its " pre activity" configuration, and this can be compared to a " post activity" heat input value. Plant operators, where the specified basic design parameters are inappropriate for the process, can propose what the measure of performance will be for these process units, including the use of permit limits on amount of production, to their reviewing authority. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 53 Many pieces of equipment are purchased based on their capacity or output. Consequently, for both utilities and non utilities, we have modified the proposed basic design parameters to include output based specifications in the final rule. Also, for utilities, we added the basic design parameter of maximum design steam flow rating and clarified from the proposal that the correct parameter is maximum hourly heat input. Sources may request that their reviewing authorities specify fuel type ( such as coal or oil) when setting basic design parameters at a combustion device that can accommodate multiple fuel types, and, for coal fired units, they should consider that the fuel consumption rate will vary depending on the quality of the coal for a given heat input. When establishing fuel consumption specifications, the minimum fuel quality based on BTU content should be used for coal fired units.

Thus, an equipment replacement that improves a process unit's efficiency by enabling the unit to return to its original design parameters can qualify as RMRR even if current actual emissions increase as a result. For example, if boiler tubes or refractory are replaced on a boiler process unit, and these activities are beneath the capital cost threshold and return the unit to its original design parameters and improve the unit's efficiency, then they would qualify as RMRR under the ERP.

Several commenters supported maximum design heat input as the basic design parameter for boilers. This parameter could also be expressed in terms of maximum design steam production rate, which is consistent with how the Florida Department of Environmental Quality permits bagasse boilers.

In the rare cases where a facility does not have established design parameters, we believe that a reasonable look back period should be used for establishing the pre activity values for basic design parameters, rather than taking the condition of the process unit immediately before the activity. We have therefore established a 5 year look back period, consistent with that for the NSPS hourly emissions increase test, for these situations.

We were urged by some commenters to incorporate a de minimis increase level in the basic design parameters that would not make it impermissible under the ERP. They argued that this would help when replacing equipment because some effects resulting from the replacement may not be apparent before the equipment has been replaced. We do not believe this approach is necessary if accurate design parameters are established. If the basic design parameters of the process unit are exceeded by even a minimal amount, then the activity cannot qualify as RMRR under the ERP.

In sum, we continue to believe that an identical or functionally equivalent replacement should not qualify for the ERP if the activity causes the process unit to exceed specified basic design parameters. Without such a requirement, significant alteration of a process unit's fundamental design could be accomplished under the guise of the ERP. Such an outcome 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 54 obviously does not square with the idea that identical or functionally equivalent replacements are not " changes" under the major NSR program. Our final rule is different from the proposal, however, in that it provides greater flexibility in defining basic design parameters for process units. We were persuaded by commenters who expressed concerns that the proposed approaches did not adequately encompass all affected operations and industry sectors.

3.7 Definition of Functionally Equivalent Comment:

3.7.1 How to Define Functionally Equivalent <IP_ADDRESS> In terms of performance or function ( design parameters)

Industry commenter 1204 said EPA should consider the similarity of the equipment's performance or function such as the equipment's rating in term of the process input, output, or capacity, as documented by the manufacturer in determining functional equivalency. EPA should establish a allowable percentage difference or range that would be acceptable. Similarly, another industry commenter ( 1797) believed that equipment replacements that serve the same function as the original equipment and that do not change the unit's design parameters should be considered routine, regardless of their cost.

One industry commenter ( 1136) supported EPA's proposal to define " equipment replacement." The industry commenter suggested the following definition: " the replacement of a component of a process unit with a component that may be out of better materials or design, so long as the replacement component does not enhance the ability of the process unit to handle greater material inputs."

One industry commenter ( 1441) asserted that EPA has properly designed the proposal to include " functionally equivalent" component replacements, in addition to identical components. The commenter suggested the following revised definition functionally equivalent component:

Functionally equivalent component means a component that serves the same basic purposes as the replaced component. A functionally equivalent component need not be identical to the replaced component. A new component is functionally equivalent if it serves the same purpose or function but is different in some respect or improved in some way in comparison to the equipment that is removed.

One industry commenter ( 858) requested that the definition of functionally equivalent include a provision for a de minimis change in design parameters that may result when a component is replaced with another that is functionally equivalent. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 55 <IP_ADDRESS> In terms of emissions Several industry commenters ( 636, 1083, 1630) recommended that the equipment replacement option be revised to allow equipment to be replaced with the same, similar, or improved equipment so long as the replacement did not increase the process unit's maximum hourly emission rate. Under this revised option, the replacement could increase efficiency, so long as the maximum hourly emission rate did not increase. Two other industry commenters ( 927, 1204) also supported the functionally equivalent replacement provisions with no increase in emissions, but did not specifically mention hourly emissions.

<IP_ADDRESS> In terms of efficiency One industry commenter ( 1136) urged EPA to clarify that efficiency improvements that result from functionally equivalent replacements are desirable and are excluded from NSR. More specifically, another industry commenter ( 1110) asserted that sometimes functionally equivalent replacements increase efficiency and yield, which then allow for additional material input. The commenter believed that this safeguard is therefore contrary to EPA's stated position that efficiency should not be considered a design parameter and NSR should not impede energy and process efficiency improvements.

One industry commenter ( 577) concurred that an engine that is " uprated" at the time of overhaul should undergo NSR. " Uprates" are product enhancements that allow increased output for the same package.

<IP_ADDRESS> In terms of various factors An industry commenter ( 1204) said operators should be allowed to invest in more costly replacement equipment if that equipment is functionally equivalent to its replacement, enhances safety and lowers environmental impacts. The rule should specifically identify environmentally beneficial replacements as RMRR regardless of cost.

One university commenter ( 901) believed operators should be allowed to invest in functionally equivalent equipment replacement, regardless of cost, if it enhances safety.

Another industry commenter ( 1134) supported EPA's use of the phrase " serves the same purpose" to define functionally equivalent. The commenter stated that it is essential that any codification of the term assures that the replacement equipment does not need to be identical, can be made of better materials, and can increase productivity provided that the replaced equipment does not allow the process unit to do something it could not previously do. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 56 A State/ local commenter ( 1361) recommended that the definition of functionally equivalent component be revised. According to the commenter, the proposed definition of " a component that serves the same purpose as the replaced component" would allow replacement of an entire process unit ( such as a boiler). The commenter suggested adding language such as " considering functional equivalence, efficiency, capacity of the component, design specifications, etc."

<IP_ADDRESS> In general Industry commenter ( 1453) argues that definition of " identical and functional" must be flexible; equipment manufacturers often change designs so it is not always possible to buy exact duplicate equipment. Similarly, an industry commenter ( 1238) recommended that EPA define " functionally equivalent" broadly. Tire and engineered rubber products manufacturers often operate machinery for many years before it needs to be replaced. It is often impossible to find identical or nearly identical replacements, and often it would not make sense to do so. New replacement equipment might carry out a very similar function but still be distinct from, and appear fairly different than) the original equipment.

3.7.2 Generally Supportive Comments Several industry commenters ( 636, 927, 941, 1007, 1013, 1069, 1110, 1129, 1130, 1136, 1149, 1159, 1204, 1441, 1453, 1868) supported EPA's inclusion of functionally equivalent equipment replacements. Three State/ local commenters ( 1044, 1240, 1443) supported a narrow provision for replacement of " identical" components. One Federal agency commenter ( 1101) supported the exclusion for replacement of identical equipment and replacement with functionally equivalent equipment.

One industry commenter ( 1136) stated that it is often impossible to find identical replacement parts, and it would be detrimental to their customers not to take advantage of material and engineering improvements of functionally equivalent parts that perform better. Thus, the equipment replacement approach will allow electric utilities to improve the efficiency of their boilers, system reliability, and equipment safety by replacing equipment with functionally equivalent equipment made of better materials.

An industry commenter ( 1110) stated that the key phrase " identical or functionally equivalent" will provide clarity and certainty for this provision because an identical replacement is not always possible.

Another industry commenter ( 1868) noted that in its permitting experience the only safe choice has often been to use only identical replacements, particularly during plant turnarounds 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 57 when the replacement could not be forecast until the plant was shutdown, and pursuing a permit determination would have taken too long. The proposal would help alleviate this problem.

Response:

We originally proposed to exempt the replacement of existing equipment with identical or " functionally equivalent" parts. An identical replacement is a replacement of a part with another part that is the same model number and size as the original part and may differ from the original part in only insignificant ways. A functionally equivalent replacement, on the other hand, occurs when a part is replaced with another part that serves the same purpose as the replaced part, but differs from the replaced part in a more noticeable way. For a functionally equivalent replacement, the replaced part may not only be a different model number or an equivalent model from a competitive manufacturer, but it may also be a part that has been updated or improved since the time of the original part's manufacture. This may include:

° replacing worn out pipes in a chemical process plant with pipes that are constructed of different metallurgy.

° replacing an analog controllers with a digital controllers, even though that the new controller would allow for more precise control.

° replacing an existing mill or pulverizer ( e. g., grinding clinker in a cement factory or coal for a boiler) with a new one of a different type because both new and old equipment serve the same purpose ( even if the characteristics of the ground material would be different before and after the replacement).

° replacing an old economizer in a boiler with a new one that contained different geometry, internal design and/ or metallurgy, even if the replacement improves fuel efficiency, or reduces erosion or plugging due to fly ash. The economizer's function is to do precisely that   help economize by reliably reducing fuel consumption per unit of output. Both new and old economizers serve that same function. The same logic holds for replacements of, or within, air preheaters and condensers, because these are heat exchangers designed to improve plant efficiency with a given amount of heat input. ° replacing existing spray paint nozzles with new ones that might atomize the spray better or have a higher transfer efficiency because the " before" and " after" nozzles serve the same function.

At the same time, there are numerous activities that occur at facilities that may fall within the bounds of the cost threshold percentage, basic design parameters, and other backstop features of the final rule, but nevertheless cannot qualify for the RMRR exclusion on the grounds that the equipment is neither identical nor functionally equivalent. An example of this would 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 58 include [ OUR EXAMPLE: a plant that changes a boiler from a forced draft to an induced draft fan configuration. Despite the relatively minimal cost of such an activity and the fact that the boiler continues to operate in fundamentally the same way after the change, the induced draft fan plainly represents a change from the forced draft fan system in numerous operational ways   REVIEW TEAM WILL OFFER A REPLACEMENT EXAMPLE??]. Consequently, this activity would not qualify as RMRR under the final ERP.

As we observed at the time of our RMRR proposal, we believe that most identical and functionally equivalent replacements are necessary for the safe, efficient and reliable operations of virtually all industrial operations; are not of regulatory concern; will improve air quality ( e. g., by decreasing startup, shutdown, and malfunctions); and thus should qualify for the ERP under the RMRR exclusion. We believe industrial facilities are constructed with the understanding that certain equipment failures are common and ongoing maintenance programs are routine. Delaying or foregoing maintenance could lead to failure of the production unit and may create or add to safety concerns. When such equipment replacement occurs, the replaced part is inherent to both the original design and purposes of the source, and there is no reason to believe that such activity will cause an emissions increase. Moreover, most of these replacements are conducted at industrial facilities to maintain proper operations and to implement good engineering practices.

As we also observed at proposal, when equipment is wearing out or breaking down, it often is replaced with equipment that serves the same purpose but is different in some respects or improved in some ways in comparison to the equipment that is removed. Moreover, the technology employed in certain types of equipment is constantly changing and evolving. When equipment of this sort needs to be replaced, it often is simply not possible to find the old style technology. Owners or operators may have no choice but to purchase and install equipment reflecting current design innovations. Even if it is possible to find old style equipment, owners or operators have obvious incentives for wanting to use the best equipment that suits the given need when replacements are needed.

We agree with the commenters who felt most of these identical and functionally equivalent replacement activities should be exempted as RMRR. We also agree with the commenters who believe that this provision will streamline the major NSR applicability process and will bring clarity. The provision we are finalizing will allow a source to make a simple determination as to whether a replacement piece of equipment qualifies as identical or functionally equivalent. This type of determination will be straightforward and easier for the source to implement than the current case by case analysis required to determine a replacement falls within the RMRR exclusion. We support the air pollution agencies that have already exempted this type of change from NSR, although as discussed below, we have concerns about doing so without appropriate backstops, even for identical equipment replacements. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 59 We disagree with those commenters who believe that this provision will create disincentives for sources to accept a PAL or have emission units designated as Clean Units. A PAL offers a source many incentives related to major NSR: ( 1) ability to bring on entirely new emissions units with no Federal preconstruction permit, as long as emissions caps are not exceeded; ( 2) ability to make modifications to existing sources without performing a major NSR applicability test; and ( 3) reduced need to keep records or otherwise track for major NSR purposes any maintenance, repair and replacement activities or modifications at the facilities. A Clean Unit designation offers the same advantages as a PAL except for the ability to bring on new emissions units. These advantages will still be the driving force for sources to elect a PAL or a Clean Unit, and we do not believe this final rule will significantly detract from their appeal.

We also believe that there is value in providing a clearer distinction between routine equipment replacement and major plant refurbishing. For pieces of equipment used at industrial facilities, most manufacturers have well established procedures for the inspection and replacement of parts of the equipment that are part of the regular maintenance necessary to provide for the equipment's safe, efficient and reliable operation. Some of these replacements are large in terms of cost and infrequent, but all are necessary to maintain the safe, efficient and reliable use of the process unit. We believe it is important to allow for these replacements within certain limits as discussed below.

We disagree with suggestions from commenters that the time period between activities, standing alone, provides an appropriate or clear distinction between routine and nonroutine activities. In fact, we think the major NSR applicability provisions impose constraints on capital planning and maintenance processes at industrial facilities. The effect of the existing provisions, such as the emissions baseline, is to force companies to plan maintenance actions on a relatively short horizon ( either 5 or 10 years, depending on the emissions baseline). Failure to address maintenance within this horizon creates potentially significant ramifications such as the need to accept permanent limits on your operations. This can force companies to act sooner than needed or to take steps that have no rational relationship to the circumstances, with the result that maintenance actions are dictated by regulatory constraints rather than by economic efficiency.

We disagree with commenters concerns about functionally equivalent replacements and we continue to believe such activities should be encouraged and should qualify as RMRR. Even though a functionally equivalent part varies in some respects from the replaced part, we feel the important factor to consider is whether the replacement will serve the same purpose as the replaced part. We acknowledge that a functionally equivalent replacement can result in an increase in efficiency and, consequently, productivity. In fact, our goal is to promote such outcomes. However, we believe that the basic design parameter safeguard that we proposed is appropriate to assure that the ERP only categorizes functionally equivalent replacements that do not result in a significant change to the fundamental characteristics of the process unit. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 60 Moreover, the two local programs that exempt the replacement of equipment with identical equipment also allow the replacement of equipment with functionally equivalent equipment without considering such action to be a modification. However, due to local air quality considerations, the local programs establish minimum pollution control requirements that are imposed in some circumstances when functionally equivalent equipment replacements occur. Nothing in the final rule would prevent a State or local program from imposing control requirements necessary to meet Federal, State or local air quality goals.

After reviewing the comments on our proposal, we have decided to promulgate what we proposed in December 2002 for the RMRR equipment replacement provision with relatively minor changes. We decided that another safeguard, in addition to the proposed safeguards, is necessary to emphasize the meaning of " functionally equivalent." The additional safeguard is that an exempted replacement cannot cause a revision of the source's emission limitation in its permit. More specifically, the final rule stipulates that activities that cause the process unit to exceed any emission limitation or operational limitation ( that has the effect of constraining emissions) that applies to any part of the process unit cannot qualify as RMRR under the ERP.

Thus, the final rule allow you to categorize identical and functionally equivalent equipment replacements as RMRR if the fixed capital cost of such replacement plus the cost of associated activities does not exceed 20 percent of the replacement value of the process unit, and if the replacement does not alter a basic design parameter of the process unit or cause the process unit to exceed any emission limitation or operational limitation ( that has the effect of constraining emissions) that applies to any part of the process unit.

3.8 Cost Basis for Equipment Replacement In reviewing comments, we recognized that some commenters appeared to direct their comments on the accounting methods at the annual maintenance, repair and replacement allowance, and not necessarily the ERP. Often, we came to this conclusion simply by the way the commenter organized their comments, and not by any specific statements in the comment letter. However, since we asked for comment on the accounting approaches as they would be applied to both the annual maintenance, repair and replacement allowance and the ERP, we believe that comments that appeared to be dedicated to the annual maintenance, repair and replacement allowance should also apply to our evaluation of the accounting for the ERP, except in the case where the commenter specifically walled off their comments on the proposed accounting methods from application to the ERP.

Comment:

3.8.1 General Support for Proposal 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 61 Several industry commenters ( 1066, 1105, 1110, 1143, 1301, 1346, 1441) supported determining applicability of the ERP on the basis of replacement cost.

One commenter ( 1346) believed data for invested costs become less available over time.

One commenter ( 1066) favored replacement cost over invested cost for several reasons. Replacement cost is more easily obtained than invested cost. Most manufacturers will have information concerning the replacement cost of a process unit, because such costs are commonly used when evaluating various business scenarios relating to manufacturing costs. Also, use of replacement cost is consistent with NSPS.

One commenter ( 1301) supported use of replacement cost for a facility for both the AMA and ERP approaches. The commenter believed that while the invested cost for a facility is typically available, it is obsolete after only a couple of years. The commenter also believed adjusting the invested cost for inflation using typically available inflation factors is inappropriate for use in the context of heavy industrial construction. Furthermore, the commenter believed that while there are specialized industry specific cost adjustment factors for various industries ( such as the Nelson Farr factors for the petroleum process industries), these are by necessity generic and do not take into account crucial factors such as facility location and seasonal cost variance.

While favoring replacement cost, one industry commenter ( 1105) said determining the replacement cost of a plant or component can be a daunting task, so the commenter recommended that EPA allow the use of installed cost as an option, indexed by a standard reference method such as the Handy Whitman index.

One industry commenter ( 1346) supported the use of replacement cost instead of invested cost in calculations for the AMA and the ERP threshold test. The commenter believed data for invested costs become less available over time making it difficult to reach agreement on the costs to be used. However, the commenter suggested that replacement costs are more readily available making it easier for both the regulated community and the agencies to perform the calculations and to reach agreement.

One industry commenter ( 1143) believed that replacement cost must be calculated based on " current" cost to replace a plant. Objective measurements, such as property records and insurance policies, used to establish casualty claims are sound basis for the use of replacement cost, and make more sense than original capital invested. The commenter asked that the final rule clearly define what is covered under replacement cost.

3.8.2 General Support for Other Methods for Cost Basis 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 62 Three industry commenters ( 1079, 1110, 1132) recommended that EPA allow the use of either a replacement cost estimate ( determined using cost estimation techniques currently employed by the company) or inflation adjusted original investment.

One industry commenter ( 1368) endorsed UARG's method of using a dollar per kilowatt rate for calculating costs. This model is specific to source and fuel type and could be updated periodically. The commenter also believed site specific replacement costs should be allowed, where approved by the reviewing authority.

One industry commenter ( 1797) recommended that EPA identify a dollar per kilowatt value, periodically adjusted for inflation, for the replacement cost of a process unit rather than of the entire plant. The commenter suggested that a dollar per kilowatt value could be established for different size ranges of units, e. g., small, medium and large, for units burning different fuel types, and for different geographic regions.

One industry commenter ( 1469) preferred using the replacement cost method for both the AMA and ERP approaches; however, this commenter stated that invested cost adjusted for inflation may be the only option for traditional gas fired units at a steam electric generating unit or plant. The commenter also stated that an alternative would be to use a cost for a same capacity combined cycle unit( s) and that the rule should allow the owner/ operator and the permitting authority some flexibility to use alternative cost methods.

Four industry commenters ( 1001, 1082, 1201, 1202) suggested EPA affirm that replacement costs can be calculated by several different methods. The commenters suggested that EPA provide a list of acceptable options for calculating replacement value, such as current engineering appraisal, basis adjusted for inflation or according to an industry standard, or insurance coverage limits.

Response:

In the proposal, the accounting basis for the ERP discussed was the same as for the NSPS reconstruction provision, which is the fixed capital cost that would be required to construct an entirely new unit. We also discussed for the annual maintenance, repair and replacement allowance using the invested cost of a unit as the accounting basis. We proposed that it would be appropriate to require that costs be calculated using an approach along the lines set out in the EPA Air Pollution Control Cost Manual ( http:// www. epa. gov/ ttn/ catc/ dir1/ c_ allchs. pdf).

We are allowing sources to determine the applicability of the final rule on the basis of replacement value, with an option for sources to notify their reviewing authority in writing if they desire to use another option ( for example, invested cost or insurance value where the 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 63 insurance value covers only the complete replacement of the process unit). The equipment replacement cost should be based on the current replacement value of the entire process unit at the time of conducting the activity.

Typically, replacement value is more easily obtained than invested cost. Most manufacturers will have information concerning the replacement value of a process unit, because such costs are commonly used when evaluating various business scenarios relating to manufacturing costs. Also, use of replacement value is consistent with the NSPS provisions.

3.9 Calculating Costs Comment:

3.9.1 Cost Estimation Method <IP_ADDRESS> Use of EPA Air Pollution Control Cost Manual Most commenters did not support use of the EPA Air Pollution Control Cost Manual ( APCCM) to standardize calculations for replacement and repair costs for RMRR in general.

Two industry commenters ( 951, 1066) believed use of the APCCM alone is acceptable. One industry commenter ( 1066) supports use of the APCCM because it is based on standard cost estimation methods.

Two industry commenters ( 1301, 1463) and several State/ local commenters ( 519, 946, 1033, 1199, 1264, 1268, 1412) objected to the use of the APCCM. Two industry commenters ( 1301, 1463) asserted that EPA should not require the use of any specific document or method to calculate costs. Two State/ local commenters ( 946, 1199) stated that the APCCM should not be used to estimate costs for RMRR because the algorithms contained in EPA's APCCM do not relate to the determination of RMRR costs and it is inappropriate to apply them for this and other purposes unrelated to their intended use. Two State/ local commenters ( 1033, 1268) believed that the control cost manual is not readily applicable to standardize costs for the AMA because the APCCM covers costs for air pollution control devices and not the costs of process operations or maintenance activities. One of the State/ local commenters ( 1033) also stated that the proposed cost analysis is complex, costly, and time consuming. Most sources would have to hire outside consultants to perform the cost analysis which would subject sources to an economic burden just to keep their equipment running safely and properly. Two State/ local commenters ( 519, 1264) suggested EPA develop a costing manual specific to RMRR.

One industry commenter ( 1463) opposed mandatory use of the APCCM or other specific manuals to standardize calculations for the replacement cost basis and repairs. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 64 One industry commenter ( 1124) opposed use of the APCCM based on a detailed analysis of the manual. The commenter concluded that the methodology used in the APCCM would not be practical because: ( 1) The amount of highly specialized information required to develop reasonable cost estimates would make the use of a manual for estimating costs of individual process units plants extremely difficult; ( 2) in almost all cases, site specific information would be required; ( 3) substantial time and expense would be involved; and ( 4) the methodology would require specialized engineering.

<IP_ADDRESS> Choosing among identified cost manuals One industry commenter ( 951) believed that the APCCM is a worthy reference for costing but also that sources should not be limited to only one manual, because a single manual is likely to have shortcomings and not be able to represent every situation.

<IP_ADDRESS> Support other costing sources/ methods One industry commenter ( 858) suggested that the rule accommodate a facility's current accounting practices. One industry commenter ( 1132) recommended that EPA allow sources to determine replacement costs using cost estimation techniques currently employed by companies. One industry commenter ( 1138) recommended a flexible approach to determining " fixed capital cost." Another industry commenter ( 951) believed site specific information should be considered in calculating RMRR costs. One industry commenter ( 1105) suggested, as an alternative, that EPA state a presumptive cost metric, such as $/ kW, to be used as a baseline, with the presumption being rebuttable.

Several industry commenters ( 865, 1077, 1463) tended not to support a single method for determining the typical RMRR costs for particular industries. One commenter ( 1077) agreed that the APCCM could provide a useful methodology but cautioned that a detailed engineering cost estimate is required to calculate the replacement cost for a steam electric plant, and such a sitespecific cost estimate could be prohibitively expensive for the industry. This commenter recommended that EPA consider other methods that do not require site specific cost methods.

Two industry commenters ( 1112, 1212) believed EPA should allow for alternative methods of calculating replacement costs. One commenter ( 1112) suggested such methods could include the APCCM and methods previously accepted by FERC and the State utility commissions.

One industry commenter ( 865) recommended that EPA allow sources to use insurance valuation methods such as the Handy Whitman Index to determine replacement costs for electric utility replacement costs under both the AMA and ERP. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 65 In opposing use of any specific manual for cost calculations, one industry commenter ( 1463) said they use a variety of sources to compute costs, including values from the Nelson Refinery Construction Index Factors, Solomon Refinery Study, and licensors of the respective process unit ( Kellogg, UOP, etc.)

One industry commenter ( 858) said a uniform basis for determining facility replacement cost should be used to account for the variability of land and labor costs across the country. Also, a scheme should be developed to uniformly account for leased vs. owned facilities ( such as by requiring everyone to assume purchase instead of lease in cost development).

3.9.2 Including Costs of Control Equipment in Equipment Cost <IP_ADDRESS> Support including costs of control equipment in equipment cost Two industry commenters ( 1126, 1441) asserted that the costs of required air pollution control equipment should be included in the replacement cost for a stationary source/ process unit ( for both the AMA and ERP). Another industry commenter ( 1136) said pollution control costs should be included in replacement cost calculations ( for the AMA option). This commenter stated that to differentiate between costs of expenditures to maintain pollution controls and other generating equipment would add tremendous additional administrative costs and would call for multiple judgments. Second, the commenter said, pollution controls are inherent in the design and proper maintenance of combustion equipment. The design and maintenance of the firewalls of a boiler, burner nozzles, the even pulverization and distribution of coal into the firebox, and the efficient operation of superheaters and economizers ( bundles of water tubing) are related to complete and effective combustion and have a direct relationship on emissions from facilities, as well as the maintenance of fluidized combustion beds, precipitator and scrubber components. Moreover, if a facility has to be reconstructed or constructed anew, it must be equipped with pollution controls. Third, the commenter said, their operators do not distinguish between capital used for maintenance and capital for pollution controls.

Three industry commenters ( 896, 1110, 1346) believed pollution control equipment should not be excluded from the definition of " process unit" because such equipment is treated in many regulations and permits as an integral part of the overall process unit. The commenters believed all pollution control equipment should be considered part of the " process unit" in order to fully account for the investment included with a process, as well as to avoid potential confusion and regulatory ambiguity with regard to the scope of " process unit," given the extreme variability in types of process units and the frequent " dual purpose" nature of recovery and control equipment in chemical manufacturing processes. One commenter ( 1110) also suggested that having to split out the pollution control equipment and establish accounting systems that accomplish this would only add additional costs without any demonstrable emission reduction or cost improvement of the NSR program. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 66 One State/ local commenter ( 1270) recommended that pollution control equipment be considered part of the process unit when determining the basis for cost. The commenter believed that control equipment in most cases is required to be in place for the process line to operate and must be maintained in the same manner as process equipment and that there are a number of control devices that emit collateral pollutants when operating as designed.

In support of our proposal, four industry commenters ( 902, 1129, 1138, 1212) believed equipment serving a dual purpose of process equipment and control equipment should be considered process equipment and should be included in the replacement cost calculation basis. Two commenters ( 1138, 1212) stated that this is of particular importance to natural gas transport facility process units because the majority of pollution control has been and continues to be achieved through clean combustion technology. Such technology constitutes inherent pollution control, integral to the process unit combustion system design, without which the unit could not operate.

<IP_ADDRESS> Oppose including costs of control equipment in equipment cost Several industry commenters ( 840, 897, 910, 920, 921, 951, 979, 1000, 1096, 1109, 1123, 1212, 1367) opposed including pollution control equipment in the equipment costs for the ERP. One commenter ( 951) believed that add on or exhaust mounted control devices should not be included in either the AMA or the ERP cost estimate. Rules should be designed to apply uniformly, and excluding pollution control equipment helps achieve that purpose.

One industry commenter ( 1137) believed that EPA should authorize sources to determine whether pollution control equipment should be excluded from the ERP. This commenter believed that a blanket exclusion could create problems of interpretation because the term " pollution control equipment" is ambiguous when considering certain components.

One industry commenter ( 1138) supports the proposed approach, where the cost of addon pollution control equipment is not counted against a source's ERP allowance, but expenditures on equipment that serve both a pollution control and a process function are counted.

One industry commenter ( 910) believed RMRR activities performed on pollution control and dual purpose equipment should not be considered for either the ERP or the AMA, because these activities are separately addressed in the pollution control exception.

One industry commenter ( 1100) believed maintenance, repair, and replacement of air pollution control equipment or equipment used to determine compliance with emission limits such as continuous emission monitoring systems should always be considered RMRR. The commenter also believed that even though some air pollution control equipment ( such as a pneumatic transfer system utilizing a bagfilter) has a dual purpose as process equipment, this equipment should be 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 67 considered as air pollution control equipment if permit conditions require routine inspection and maintenance of the control equipment.

Two industry commenters ( 1050, 1213) believed EPA should expressly state in the rule language that MRR activities for pollution control equipment are not physical changes or changes in the method of operation under the NSR program.

One industry commenter ( 1399) believed the installation of pollution control equipment would be best addressed under the pollution control exclusion; pollution control maintenance and repair activities would not be expected to result in an emissions increase from the source, and thus they would not be modifications even if they were changes.

One industry commenter ( 942) proposed that maintenance and repair of pollution control equipment or monitoring equipment be categorically defined as RMRR. Another industry commenter ( 1159) believed a broad exclusion from NSR applicability should be provided for maintaining and installing pollution control equipment.

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