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32 ELR 11091 | Environmental Law Reporter | copyright © 2002 | All rights reserved A Primer on New Source Review and Strategies for SuccessRolf R. von Oppenfeld, Eric L. Hiser, and Mark E. FreezeRolf R. von Oppenfeld is Managing Partner with the Team for Environmental Science and Technology Law (TESTLaw) Practice Group, operating under the law firm von Oppenfeld, Hiser & Freeze, P.C., with western regional offices in Phoenix, Arizona, and eastern regional offices in Columbia, South Carolina. The firm has been listed in the 2001 Martindale-Hubbell Bar Register of preeminent lawyers for environmental law. Eric L. Hiser heads the regulatory practice for the TESTLaw Practice Group. Mr. Hiser clerked for the U.S. Court of Appeals for the Tenth Circuit after graduating with honors from Duke University Law School and acting as Managing Editor on Duke Law Journal, 1988-1989. Mark E. Freeze heads the litigation practice for the TESTLaw Practice Group, and graduated law school from the University of Texas at Austin in 1988. New Source Review for the Prevention of Significant Deterioration Air pollutants affect both human health and the health of ecosystems. The U.S. Congress enacted the Clean Air Act (CAA) to try to reduce harmful air pollutants and protect health. While enacting the 1977 CAA Amendments, Congress recognized, based on a court case, that something must be done to keep clean air clean, rather than allow it to deteriorate and then attempt to clean it. Hence, the prevention of significant deterioration (PSD) program was developed. The PSD program places stringent limitations and restrictions on sources located in areas designated as "in attainment" with the national ambient air quality standards (NAAQS), which set limits on the amount of certain pollutants that may be emitted in a given area. The CAA specifically identifies five goals of the PSD program: (1) to protect public health and welfare from air pollutants; (2) to preserve, protect, and enhance air quality in national parks, national wilderness areas, national monuments, and other areas of special national or regional value; (3) to ensure economic growth in a manner consistent with clean air resources; (4) to assure that emissions will not interfere with maintaining air quality; and (5) to assure a careful and full evaluation of the impacts through a permitting process.1 PSD regulatory requirements can be found at two primary locations in the regulations. 40 C.F.R. § 52.166 delineates the minimum requirements for state-operated PSD programs. 40 C.F.R. § 52.21 sets forth the elements for the federal program, which the U.S. Environmental Protection Agency (EPA) has delegated implementation authority to some states. Determining applicability of the PSD program is a six-step process: . define the source; . define applicability thresholds for the major source as a primary activity; . define project emissions, i.e., potential-to-emit (PTE); . assess area attainment status, i.e., must have at least one criteria pollutant classified as attainment or unclassifiable for PSD to apply; . determine if the source is major by comparing PTE and threshold limits; and . determine pollutants subject to PSD review.2 Any major stationary source or major modification at a stationary source located in an area classified as in attainment or in an unclassifiable area emitting a regulated pollutant must comply with the PSD requirements and program elements.3 Sources unsure of whether changes will trigger PSD requirements may request an applicability determination from EPA, who will determine whether a proposed change would be considered a major modification and whether a significant emissions increase will occur.4 For determinations, the EPA considers the area class applicable to the source's location, the regulated pollutants for that area, the type of source, and the source thresholds along with the increments allowed in the class. Area Classes and Allowable Increments Attainment areas are classified based on the level of protection or allowable degradation of air quality determined appropriate for the area. The designations are Class I, II, and III with Class I areas, such as national parks, having the [32 ELR 11092] most stringent protections. Within each attainment classification are increments for three of the criteria pollutants (particulate matter less than 10 microns (PM[10]), sulfur dioxide (SO2), and nitrogen dioxide (NO2)) to limit allowable pollution from exceeding an established baseline. These PSD increments vary depending on the classification of the area. There are 158 mandatory federal Class I areas, located in 35 states and the U.S. Virgin Islands.5 These areas are deemed mandatory because they are specifically listed in the CAA and their designations cannot be changed. These areas are afforded the most protection because air quality and visibility has been identified by Congress as important values.6 The default classification for all other areas labeled as in attainment or unclassifiable is Class II. A Class III designation exists in theory, but not in practice. Redesignation of an area from Class II to either Class I or III is available under the statute, but rarely done.7 The PSD increments for PM[10], NO2, and SO2 are set forth in CAA § 163(b) and 40 C.F.R. §§ 51.166(c) and 52.21(c). Table PSD Maximum Allowable Increments ([mu] g/m3)
Any pollutant subject to regulation under the CAA is potentially subject to the PSD program requirements of best available control technology (BACT) and ambient air quality analysis.12 However, criteria pollutants in nonattainment areas are subject to nonattainment provisions and not PSD requirements. Additionally, hazardous air pollutants (HAPs) are excluded from PSD consideration under the 1990 CAA Amendments.13 The exclusion of the HAPs from PSD consideration, however, is limited to their status as HAPs and not as precursors or some other pollutants.14 First, HAPs are only excluded if they would not otherwise be regulated under a PSD regime. For example, lead compounds are HAPs, but elemental lead is a criteria pollutant and, thus, within the PSD program regulations. Similarly certain HAPs are considered volatile organic compounds (VOCs), which are regulated as ozone precursors under the PSD program.15 A state program may explicitly regulate some or all of the HAPs in the state PSD program. Second, the BACT determinations must consider HAPs in the impact analysis. Under the PSD program, a major source is any stationary source that emits or has the potential to emit . 100 tons per year (tpy) or more of a regulated pollutant emitted from a list of 28 different types of sources16; [32 ELR 11093] . any change at a stationary source that would result in a major stationary source itself.17 A stationary source is "any building, structure, facility, or installation which emits or may emit" any regulated air pollutant.18 A complete source is comprised of all emissions units and pollution emitting activities that emit or have the PTE a regulated pollutant. This includes all pollutant-emitting activities that . belong to the same industrial group, i.e., same first two-digit Standard Industry Classification (SIC) code; . are located on contiguous or adjacent properties; and . are under common control.19 However, even activities that do not fall under the same two-digit SIC code can be considered to belong under the same industrial group. In this situation the source is classified according to the primary activity at the site, which is determined by its principal product (or group of products) produced or distributed, or by the services it renders. Facilities that convey, store, or otherwise assist in the production of the principal product are called support facilities. . . . An emissions unit serving as a support facility for two or more primary activities (sources) is to be considered part of the primary activity that relies most heavily on its support.20 Note that if the primary source is minor and a supporting facility would be major on its own, then PSD regulations apply to the support facility but not to the primary source.21 Common control is determined at the time of the construction or modification. Common ownership clearly equates to common control. However, the determination is also based on a "common sense notion" of a source,22 and this element may be satisfied by indirect control and contractual relationships.23 In the situation where one company locates a facility on another company's property, a rebuttable presumption exists that a control relationship is present.24 Proximity can also be determinative in establishing common control. Because the regulations do not define "contiguous" or "adjacent," EPA has often utilized a dictionary to decide what should be considered common control. A common border is not required and distance is a factor, however, EPA has held that facilities located several miles apart can be contiguous and adjacent. In addition to distance, the relationship between the facilities, i.e., is one a support facility to the other or does it comprise part of the primary activity of the company, is also considered in this case-by-case determination.25 The obvious advantage of establishing facilities as separate and independent is to avoid PSD review. However, there are three decided advantages to grouping facilities together and undertaking a PSD review. First, PSD questions will be resolved forany future interdependence between the facilities. Second, credit emission reductions can be used between the facilities. And finally, it avoids any EPA investigation as to the properness of the determination and any possible subsequent enforcement action (which could lead to a PSD review and fines). Each regulated air pollutant emission from a source must be evaluated to determine if the source exceeds the threshold. If the threshold is exceeded, then the source is deemed a major source and subject to the PSD program. Emissions measurements are completed by evaluating the source's emissions and calculating its PTE. Since major source status is determined by the PTE, the PTE must be calculated for each regulated pollutant emitted from the source.26 PTE is defined at 40 C.F.R. §§ 52.21(b)(4) and 51.166(b)(4) as the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of a source to emit a pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be treated as part of its design if the limitation or the effect it would have on emissions is federally enforceable.27 This definition mirrors the PTE definition for the CAA Title V permitting and § 112 air toxics program. The starting point for defining PTE is the worst-case, uncontrolled emissions rate over a year. The starting baseline can be modified through the application of control equipment and limits on the facility that would help lower the PTE to below threshold limits. These limits commonly include . requirements to install and operate air pollution control equipment at certain proficiency levels; . restrictions on design capacity; . restrictions on hours of operation; and . restrictions on types or amount of material processed, combusted, or stored.28 One of the more contentious issues concerning PTE has been the requirement of federal enforceability. On July 21, 1995, the U.S. Court of Appeals for the D.C. Circuit remanded the PTE definition with regards to the CAA § 112 program and the "federally enforceable" requirement.29 In a subsequent case, the D.C. Circuit remanded and vacated the PTE rules for the new source review (NSR) and PSD programs.30 In light of these cases, EPA issued a memorandum in January 1996 on effective limits on PTE.31 EPA stated that the three "overarching considerations" governing effectiveness of limits on PTE are (1) enforceability as a practical matter, (2) compliance incentive effectiveness, and (3) state program effectiveness.32 The January 1996 memo provides two options to be discussed as ways to ensure compliance effectiveness: (1) state or locally enforceable limits; and (2) streamlined federal enforceability. As EPA notes, the "central question arising from the court decisions is whether sufficient compliance incentives exist if EPA and citizens cannot directly enforce PTE limits in federal courts. . . ."33 EPA wanted to explore these two options with stakeholders for a future rulemaking on PTE limits and enforceability. Fugitive and Secondary Emissions Fugitive emissions are defined as those "which could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening"34 and result from the construction or major modification of a source. Fugitive emissions that are quantifiable must be counted toward the PTE calculation if they occur at one of the following sources35 . any stationary source in one of the 28 listed category sources36; . any stationary source in a category regulated by new source performance standards (NSPS) under CAA § 111 as of August 7, 198037; and . any stationary source in a category regulated by a national emission standard for hazardous air pollutants (NESHAPs) under CAA § 112 as of August 7, 1980.38 Fugitive emissions from unlisted sources that have the same SIC code or sources that primarily support co-located sources may be counted in determining major source status.39 These fugitive emissions are only counted if the unlisted source meets the primary activity test.40 "Note also that, if a source has been determined to be major, fugitive emissions, to the extent they are quantifiable, are considered in any subsequent analyses (e.g., air quality impact)."41 Fugitive emissions at sources not listed above are not considered for the purposes of PSD applicability. Although if the source otherwise qualifies as major, they are to be considered in the air quality impact and other analyses to the extent quantifiable.42 Secondary emissions are those that would occur due to the operation or construction of a major source or a major modification, but are not from the source itself.43 These secondary emissions include emissions from off-site support facilities that would not otherwise emit pollutants and off-road vehicles and ships at dock.44 Motor vehicles regulated under CAA Title II are excluded from secondary emission consideration. Secondary emissions do not count toward PTE determinations,45 but are considered in air quality analyses if they are "specific, well-defined, quantifiable, and impact the same general area as the stationary source or modification undergoing review."46 EPA can authorize states to administer a PSD program. The state can either develop and implement an approved state implementation plan (SIP) for PSD requirements or the state can adopt the federal PSD program promulgated by EPA. All EPA-authorized programs have common elements and minimum standards prescribed by the federal regulations, including: an application submittal to the permitting authority; a completeness determination by the permitting authority; review by state and federal agencies; issuance of the draft permit; a comment period; and final issuance or denial of the permit. Whether the permitting authority is EPA or a state or local agency, the source must provide all information necessary to make an informed decision, which must include [32 ELR 11095] . a detailed schedule for construction of the source of modification; and . a detailed description as to what system of continuous emission reduction is planned by the source, emission estimates, and any other information as necessary to determine what BACT would be applied.47 If requested by the permitting authority, the owner or operator of the source must also provide . air quality impact of the source or modification, including meteorological and topographical data necessary to estimate such impact; and . air quality impacts and the nature and extent of any or all general commercial, residential, industrial, and other growth that has occurred in the area since August 7, 1977, that the source or modification would affect.48 In the application consideration phase, states with EPA-approved programs must adhere to the parameters set forth in 40 C.F.R. § 166(q). Upon receipt of an application, the permitting authority must notify the applicant within a specified time period of its completeness. Within one year of a completeness determination, the permitting authority must make a preliminary determination on whether the application should be approved or not, and make this draft permit available for public notice-and-comment procedures (including comments from EPA and any government agency that may be affected).49 After consideration of comments, the draft permit is either rendered final, approved with conditions, or disapproved. In a state-administered program, EPA may comment but has no formal review or veto powers. Judicial review of a permit follows state law and no review is available in federal court. Sources applying to EPA for PSD review follow the procedures set forth at 40 C.F.R. Part 124. Permit applications are submitted to the regional offices, and the applicant will be notified within 60 days of submittal whether the application is complete. Upon a determination of completeness, the applicant will receive a projected decision schedule.50 A tentative decision will be made regarding application approval, and if approved, a draft permit will be written. After a public notice-and-comment period,51 EPA may issue or deny the permit. A person has 30 days from issuance or denial to appeal the decision to the Environmental Appeals Board of EPA.52 Sources must apply for a permit prior to construction and the final permit must include emissions limits based onBACT, as discussed below. A source cannot begin actual construction prior to the issuance of a permit.53 Beginning actual construction is defined as an initiation of physical on-site construction activities on an emissions unit which are of a permanent nature. Such activities include, but are not limited to, installation of building supports and foundations, laying of underground pipework, and construction of permanent storage structures. With respect to a change in method of operation this term refers to those on-site activities, other than preparatory activities, which mark the initiation of change.54 Construction is defined to mean any physical change or change in method of operation, including the fabrication, erection, installation, demolition, or modification of an emissions unit.55 This prohibition includes entering into binding contracts for construction that cannot be cancelled prior to issuance of a permit. It is important to note that this construction ban prohibits these activities on emissions units, the definition of which includes source parts that emit any CAA-regulated pollutant, not just pollutants subject to PSD review.56 This distinction also means that a structure which is to house independent facilities, some of which are subject to PSD and some of which are not, may be constructed before a PSD permit is issued only if the building is a necessary part of the PSD-exempt project and if it is in no way modified to specifically accommodate the PSD-affected facilities.57 Sources unsure of whether changes will trigger PSD review may request an applicability determination from EPA, who will determine whether a proposed change would be considered a major modification and whether a significant emissions increase would occur.58 However, a PSD construction permit is not subject to the permit shield protection of operating permits, and the fact that an operator or owner has a permit will not protect the permittee from enforcement violations of any law.59 A major modification is "any physical change in or change in the method of operation of a major stationary source that would result in a significant net emissions increase of any [regulated pollutant]."60 A minor source that makes a [32 ELR 11096] change that on its own qualifies as a major stationary source is subject to PSD review.61 A "significant emissions increase" is defined as a net emissions increase that would equal or exceed the following rates for the listed pollutants, and any increase in emissions for regulated pollutants not on this list.62
Since a newly modified unit does not have emissions information, and PSD applicability is usually determined before construction, EPA generally used the PTE to determine the new level of actual emissions. This actual-to-potential test is used on a case-by-case basis when normal operations have not begun.65 The actual-to-potential PTE calculation is the default position, where the actual emissions are the average over the most recent two years and the potential is the PTE after the change. When construction has not yet occurred, a potential-to-potential test is used. Specific only to electric utilities, the Wisconsin Electric Power Company rule (see below) applies an actual-to-future test that allows the use of any two consecutive years of the last five years of data.66 If the proposed emissions increase at a major source is by itself (without considering any decreases) less than "significant," EPA policy does not require consideration of previous contemporaneous small, i.e., less than significant, emissions increase at the source. In other words, the netting equation (the summation of contemporaneous emissions increases and decreases) is not triggered unless there will be a significant emissions increase from the proposed modification.67 Debottlenecking may constitute a modification triggering PSD review. The PSD applicability calculation includes emissions increases from the new or modified emissions units and any other plantwide emissions increases that will occur as a result of the modification. If, as a result of the construction of the new or modified emissions unit, the effective capacity of another emissions unit (and therefore that unit's PTE) will increase, the emissions increase of that debottlenecked emissions unit must also be included in the PSD applicability calculation. However, debottlenecking can occur only if the unused capacity of the emissions unit could not be used until after the modification took place. In other words, the emissions increase of the debottlenecked unit would not have occurred "but for" the construction of the new or modified emissions unit. EPA's interpretation of the regulation to date has been that when a particular physical change or change in method of operation would cause an increase in emissions from other emissions units, then those "other" emissions units must be included in determining PSD applicability for the particular change.68 "In calculating the emissions change resulting from the modification and debottlenecked units, EPA requires that the emissions change for these units be based on their allowable emissions after the change minus their current actual emissions."69 Thus, debottlenecked emissions are calculated using the same method for determining emissions increases from new or modified sources by using the "actual-to-potential" test. It is important to understand that an exempt modification under an applicable NSPS does not automatically exempt [32 ELR 11097] the same modification from PSD review, even though the definition of modification is identical under the CAA because the PSD program is ambient-based and the NSPS program is technology-based.70 PSD Exempt Physical and Operational Changes There are several physical and operational changes enumerated in the federal regulations that exempt a modification from PSD review.71 The most prominent exemption is for "routine maintenance, repair, and replacement."72 EPA explains that the "determination of whether the repair or replacement of a particular item of equipment is 'routine' under the NSR regulations, while made on a case-by-case basis, must be made on the evaluation of whether that type of equipment had been repaired or replaced by sources within the relevant industrial category."73 This traditionally expansive exemption has been curtailed in recent years by EPA in favor of a four-factor test: (1) nature and extent; (2) purpose; (3) frequency; and (4) cost, plus other factors as may be appropriate.74 The following types of changes are not routine and require further evaluation: . replacement of components with a new or different design; . increases in heat, work, or production rates; . changes that increase the working life of equipment beyond original specifications; . changes that restore lost capacity, e.g., eliminate "wear and tear" loss that would normally not be fixed or repaired in the industry; and . changes that eliminate previously unavoidable down time or eliminate a bottleneck. Certain uses of alternative fuels,75 increases in hours of operation or production rates (unless prohibited by permit conditions),76 and changes in ownership77 are exempt. Pollution control projects at electric utility plants, e.g., clean coal technology, have also been conditionally exempt from PSD requirements.78 After the Wisconsin Electric Power Co. v. Reilly (WEPCo)79 decision in 1992, EPA policy expanded the pollution control project exemption beyond electric utilities.80 These exemptions are case-by-case determinations to exclude pollution control projects from PSD review using two main qualifications. First, no project can cause or contribute to violation of an NAAQS, PSD increment, or air quality-related values (AQRVs) in a Class I area, and therefore an air quality impact assessment must be done. Second, the project must pass the environmentally beneficial test, which involves a consideration of the types and quantity of air pollutants emitted before and after the project, as well as other relevant environmental factors.81 However, EPA further explains in the guidance that the exclusion is limited to prevent all activity at a source from falling under the heading of a pollution control project. In order to limit this exclusion to the subset of pollution prevention projects that will in fact lower annual emissions at a source, permitting authorities should not exclude as pollution control projects any pollution prevention project that can be reasonably expected to result in an increase in the utilization of the affected emissions unit(s). For example, projects which significantly increase capacity, decrease production costs, or improve product marketability can be expected to affect utilization patterns. With these changes, the environment may or may not see a reduction in overall source emissions; it depends on the source's operations after the change, which cannot be predicted with any certainty. This is not to say that these types of projects are necessarily subject to major NSR requirements, only that they should not be excluded as pollution control projects under this guidance.82 If a project exceeds PSD thresholds, it may still be possible to net out of PSD review. The New Source Review Workshop Manual (NSRWM) gives the following formula for calculating net emissions changes: Emissions increases associated with the proposed modification Sourcewide creditable contemporaneous emissions decreases Sourcewide creditable contemporaneous emissions increases83 The contemporaneous period is a time frame set by the permitting authority, but it is usually five years. Emissions are creditable only if not addressed in the existing permit or any prior permit,84 and increases are creditable only if the new emissions levels exceed old levels. Decreases are creditable only if federally enforceable, they are of the same qualitative significance as the increase, and the old level of actual or allowable emissions (whichever is lower) exceeds the new actual emissions level.85 The old level is the average over the two-year period prior to the change. The new level is the post-modification PTE. If the net emissions exceed the significant levels, then PSD review is triggered. The procedures for determining the net emissions change at a source involves six basic steps: (1) Determine the emissions increases (but not decreases) from the proposed project. If increases are significant, proceed; if not, the source is not subject to review. [32 ELR 11098] (3) Determine which emissions unit at the source experienced (or will experience, including any expected decreases resulting from the proposed project) a creditable increase or decrease in emissions during the contemporaneous period. (4) Determine which emissions changes are creditable. (5) Determine, on a pollutant-by-pollutant basis, the amount of each contemporaneous and creditable emissions increase or decrease. (6) Sum all contemporaneous and creditable increases and decreases with the increase from the proposed project to determine if a significant net emissions increase will occur.86 These emissions changes are source-specific, therefore emissions reductions cannot be traded between sources.87 Accumulated emissions increases occur over time and, while not individually significant, when totaled over time may exceed the significance levels.88 These accumulated emissions, de minimis on their own, do not trigger PSD review if the projects are separate and unrelated.89 They do, however, consume increments and are considered when determining contemporaneous emission increases and decreases.90 Contemporaneous emission reductions not used in netting, i.e., leftover reductions, cannot be used in future netting transactions, as proper emissions calculations for netting purposes are considered in their entirety and do not result in leftover reductions.91 The permittee should ensure that the permit limitations adequately provide for emissions occurring during startups and shutdowns. In 1978, EPA took the position that all excess emissions were violations and there were no automatic exemptions (including excess emissions during startup, shutdown, and maintenance).92 These emissions are expected to be planned for and included in the implementation of operating procedures and processes. As a result, neither SIPs nor PSD permits can contain automatic exemptions for startups and shutdowns, according to EPA's position.93 Note that startup and shutdown exemptions under some NSPS are not applicable to PSD because the PSD program is designed to protect ambient air quality and is therefore ambient-based, while the NSPS program is technology-based. Malfunctions, defined as the sudden and unavoidable breakdown of process or control equipment, cannot realistically be planned for in permit limitations. However, a malfunction occurrence may be an affirmative defense to an enforcement for excess emissions, and will be considered at the discretion of enforcement authorities.94 Many sources perceive avoiding PSD review as advantageous because it avoids the delays and potential controls associated with BACT. There are several ways to avoid triggering the requirements, but sources must always consider the risk that avoidance will be characterized as PSD circumvention subject to enforcement. A basic way to avoid PSD review is to not trigger the major source emissions threshold and remain a minor source. If a source remains a minor source, then it is not subject to PSD permitting or technology control requirements. However, in order to be classified as a minor source, the source needs accurate measurements of its emissions. One frequently overlooked issue is whether a portion of the potential emissions from the facility could be identified as fugitive emissions, and thus be exempt from the major source permitting threshold calculation. Unless the facility has been specifically designated as one that must account for fugitive emissions by EPA rule or by a SIP, PSD review is not required if the total quantity of non-fugitive emissions does not exceed permitting thresholds.95 In order to prevail on this demonstration, the facility's legal counsel and technical staff will need to demonstrate that emissions from the facility's various emissions units do not currently pass through a stack, vent, or functionally equivalent device, that other industry members do not pass their emissions through a stack, vent, or other comparable device (at least at the time of construction or modification), and that there is no readily apparent technology that could be transferred from a similar operation. This demonstration will require marshaling technical evidence on sources of pollutants, their emission, collection, capture, and control techniques; the technical and economic feasibility of various capture and control techniques; and potentially historic practices. The demonstration will need to be structured in a way that is possible for both the permitting authority and a lay decisionmaker, such as a judge or jury, to understand and feel comfortable with deciding the issue on its merits. Even if a modification, either by itself or after netting, would result in a significant net emissions increase, a source may nevertheless avoid PSD review by agreeing to "federally enforceable" restrictions that would reduce the net emissions increase to below significant levels. PTE generally [32 ELR 11099] refers to a source's maximum capacity to emit a pollutant under its physical and operational design.96 The calculation is based on an 8,760-hour per year operating schedule (24 hours per day, 365 days per year). However, physical or operational limits, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, may be taken to restrict a source's PTE if such limitations are "federally enforceable" or "enforceable as a practical matter."97 Previously, EPA allowed only "federally enforceable" restrictions to limit a source's PTE. However, on September 15, 1995, the D.C. Circuit vacated the federal enforceability requirement in the NSR regulations.98 EPA has since issued guidance clarifying that limitations taken to restrict a source's potential to emit must be "federally enforceable or legally and practicably enforceable by a state or local air pollution control agency."99 Therefore, as long as a restriction is practicably enforceable by a permitting agency and the local agency's rules allow the use of nonfederally enforceable limits for purposes of calculating PTE, then the restriction can be used on the modification to keep the net emissions under the significant levels that trigger review.100 A source may also avoid PSD review through the imposition of enforceable limitations based on a federally approved minor source NSR permit program or operating permit program. Within this approved program, a source can self-impose limits to reduce its PTE to below major source threshold levels, thus becoming a "synthetic minor source" and avoiding PSD review.101 However, according to EPA regulation, if the limits are relaxed and cause the source to become major, then the source is subject to PSD review as though construction had not yet commenced, which may result in expensive retrofitting of BACT.102 Even if a source effectively avoids PSD or NSR review through a synthetic minor status, the source still must obtain a general or minor NSR preconstruction permit under CAA § 110(a)(2)(c) and 40 C.F.R. § 51.160-.164 and in accordance with the applicable SIP. Synthetic minor source designation can be very useful to facilities that have a high PTE based on the design of their processes, but will not fully utilize that capacity in actual practice. BACT Analysis and Implementation Sources subject to PSD review must conduct BACT analysis and apply BACT to pollutants for which emissions are significant by rate or, for sources within 10 km of a Class I area, if ambient impact is at least 1 [mu] g/m3.103 BACT is an emissions limitation "based on the maximum degree of reduction" and is determined on a "case-by-case" basis.104 While the BACT limitation applies to each emissions unit at a new source or each modified unit in a major modification, it must separately address each regulated pollutant with a significant emissions increase.105 BACT is defined at CAA § 169(3) to mean an emission limitation based on the maximum degree of reduction of each pollutant subject to regulation under [the Act] emitted from or which results from any major emitting facility, which the permitting authority, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such facility through application of production processes and available methods, systems, and techniques, including fuel cleaning, clean fuels, or treatment or innovative fuel combustion techniques for control of such pollutant.106 The construction or modification of an emissions unit triggering PSD review107 requires a BACT analysis108 for each such emissions unit. A stationary source is any "building, structure, facility, or installation which emits or may emit" any regulated pollutant.109 EPA's NSRWM states,110 the "BACT requirement applies to each individual new or modified affected emissions unit . . . . Individual BACT determinations are performed for each pollutant, subject to a PSD review, emitted from the same emission unit."111 The NSRWM further asserts that step one of the BACT process involves identifying the emissions unit(s) to which BACT will apply.112 The final step involves selecting the most effective control option for "the pollutant and emission unit under review."113 Guidelines for BACT determinations were first issued in December 1978 to provide a consistent framework for sources.114 These guidelines have been superseded and now the standard reference is found in the 1990 NSRWM. BACTs [32 ELR 11100] are implemented through the production process, method changes, and other techniques or systems that control emissions.115 If any BACT is determined to be infeasible, BACT may be satisfied by "a design, equipment, work practice, operational standard, or combination thereof . . . and shall provide for compliance by means which achieve equivalent results."116 No BACT limitation can result in the source's emissions exceeding any applicable NSPS or NESHAPs under 40 C.F.R. §§ 60 and 61.117 In comparing NSPS and BACT, NSPS do not represent BACT, instead NSPS are the floor, whereas BACT is the greatest degree of control achievable.118 NSPS, therefore, provide a floor for BACT. Lowest achievable emission rate (LAER) determinations made pursuant to an NSR in a nonattainment area should be considered "in establishing the most stringent technology 'available'—i.e., the 'top' control option—for purposes of BACT analyses under the top-down methodology."119 BACT determinations are made "totally independent of the amount of increment or air resources available."120 EPA has taken the position that environmental assessments should be used only to make BACT more stringent, not less stringent, and hence BACT cannot be relaxed to avoid using up the increment.121 "The primary responsibility for defending the proposed control system must be placed on the source," due to a limitation of resources of the permitting authority, although the ultimate decision on what constitutes BACT lies with the permitting authority.122 Additionally, BACT is not established until the final permit is issued, and it is in the source's best interest to throughly evaluate the options in an attempt to preclude BACT from changing between the draft permit issuance and the final permit.123 Under the 1978 BACT Guidelines124 and the 1980 NSRWM,125 BACT analyses were conducted with a "bottom-up" approach. This position was abandoned in 1987 in favor of the "top-down" approach included in the 1990 NSRWM.126 Key Steps in the "Top-Down" BACT Process127 128 This evaluation should include control technologies from other countries and those applied by similar source categories.129 Determinations for LAER usually top the list of alternatives.130 The NSRWM provides a list of primary information sources for identifying control technologies, such as:. EPA's RACT/BACT/LAER Clearinghouse and Control Technology Center; . BACT Guidelines—South Coast Air Quality Management District; . control technology vendors; . NSR permits and associated inspection/performance reports; . environmental consultants; . technical journals, reports, and newsletters; and . EPA's New Source Review bulletin board.131 While not required, a source may propose "innovative technologies," which have not been demonstrated in practice "but would have a substantial likelihood of achieving greater continuous emissions reduction than any control system in current practice or of achieving at least comparable reductions at lower costs in terms of energy, economics, or non-air quality environmental impacts."132 This list of all available controls is then whittled down by eliminating those controls considered to be infeasible. If a control technology is demonstrated some place, i.e., permitted and in use at another similar facility, then it is feasible. Undemonstrated technologies that are commercially available and can be reasonably installed or operated are also considered feasible. A source may demonstrate technical infeasibility by evaluating the "pollutant-bearing gas stream characteristics and the capabilities of the technology."133 Technical infeasibility is based on technical assessments that consider "physical, chemical, and engineering principles and/or empirical data showing that the technology would not work on the emission unit under review, or that unresolved technical difficulties would preclude the successful deployment of the technique."134 Costs, however, do not render a control option technically infeasible, and the ultimate decision of feasibility lies with the permitting authority. After feasibility is determined, the remaining technologies on the list are then ranked in order from most to least effective for potential emissions reduction. This hierarchy of effectiveness includes: . expected emissions rates; . emissions performance levels; . expected emissions reductions; . environmental impacts; and . economic impacts.135 BACT selection takes into account energy, environmental, and economic considerations.136 The source is responsible for demonstrating the suitability or unsuitability of a control's application, which generally focuses on the direct impact of the control alternative.137 An energy analysis determines whether there are significant or unusual energy penalties or benefits.138 This analysis looks at the application of the control alternative and not the general energy impacts of the project.139 An environmental analysis must likewise identify significant and unusual impacts of the control alternative. These impacts are site-specific and must consider sensitive receptors in the area.140 Examples of environmental impacts include impacts on water, solid waste disposal, and irreversible commitments of resources. An initial screening is conducted to identify discharges causing adverse environmental impacts, and then the mass and composition of the discharge are quantified for the purpose of the assessment.141 This environmental analysis also includes consideration of the emissions of air toxics or HAPs. The BACT selection often can result in a reduction of toxic emissions, and this result "may support the selection of a control technology that yields less than the maximum degree of reduction in emissions of the regulated pollutant in question."142 The two economic criteria utilized in BACT selection involve average cost effectiveness, i.e., dollars per ton of pollutant emissions reduced, and incremental cost effectiveness, i.e., cost per ton reduced.143 Note that the economic impact analysis focuses on quantifying the cost of control and not on the fiscal health of the source. Estimating cost requires control system parameters that follow the guidelines in the NSRWM.144 To justify elimination of an alternative on these grounds, the applicant should demonstrate to the satisfaction of the permitting agency that costs of pollutant removal, e.g., dollars per ton removed, for the control alternative are disproportionately high when compared to the cost of control for the pollutant in recent BACT determinations. Specifically, the applicant should document that the cost to the applicant of the control alternative is significantly beyond the range of recent costs normally associated with BACT for the type of facility (or BACT control costs in general) for the pollutant. This type of analysis should demonstrate that a technically and economically feasible control option is, nevertheless, by virtue of the magnitude of its associated costs and limited application, unreasonable or otherwise not "achievable" as BACT in the particular case. Total and incremental cost effectiveness numbers are factored into this type of analysis. However, such economic information should be coupled with a comprehensive demonstration, based on objective factors, that the technology is inappropriate in the specific circumstance.145 EPA produced a chart that provides comparisons of BACT for selection.146 The most effective control technology that has not been eliminated is selected as BACT, and this selection is made by the permitting authority. Source Impact on Ambient Air Quality (AAQ) Under 40 C.F.R. §§ 51.166 and 52.21 a source must determine the impact of its emissions to ensure that no pollutant emission exceeds either primary or secondary NAAQS.147 A permit application must contain an "analysis of [AAQ] in the area that the major stationary source or major modification would affect" for each pollutant emitted in a significant amount.148 Each regulated pollutant is subjected to an air quality analysis,149 as are non-criteria pollutants. The analysis [32 ELR 11102] is done through monitoring and modeling the pollutant impact.150 However, even if the modeling demonstrates a violation of NAAQS, the source can still be approved if the source's contribution to air quality is less than the significance level.151 A dispersion model is used to determine a project's effects on air quality by gathering data and comparing it to significant monitoring values. Based on this comparison, if a threat to NAAQS exists, then monitoring must be done. Dispersion modeling involves two phases: preliminary and fullimpact analyses. The preliminary analysis serves as a screening function and models only significant emissions.152 The preliminary analysis also: . determines whether the applicant can forego a full impact analysis for a particular pollutant; . may allow the applicant to be exempted from the ambient monitoring data requirements; and . is used to define the impact area within which a full impact analysis must be carried out.153 If monitoring is deemed necessary, pre-application monitoring data generally must be continuously gathered for one year prior to receipt of the application.154 A shorter time, but not less than four months, may be used if the permitting authority believes the shorter period will be adequate, and existing data may be used where the source can demonstrate that existing data is sufficient.155 For non-criteria pollutants, EPA generally does not require monitoring after modeling unless there is a standard for the pollutant, questions exist as to the reliability of the modeling data, or models, or terrain make it difficult to accurately assess air quality impact.156 A state may, in the SIP, allow sources to not conduct this analysis if the air quality impacts are below the following threshold amounts.157 No de minimis air threshold is provided for ozone, but any net increase of 100 tpy of VOCs subjects the source to PSD and an AAQ analysis.If a full impact analysis is required, i.e., the estimated pollutant concentrations exceed significant ambient impact levels, then the preliminary analysis is expanded to include proposed and existing sources and residential, commercial, and industrial growth that accompanies the new activity at the new source or modification, i.e., secondary emissions.158 A full impact analysis also requires emissions inventories of existing sources and explicit modeling of all nearby sources to establish background air pollutant concentrations.159 Inventories of increment consuming emissions160 and non-criteria pollutants161 are also required. One important aspect of dispersion modeling is determining the impact area, which is defined as "a circular area with a radius extending from the source to (1) the most distant point where approved dispersion modeling predicts a significant ambient impact will occur, or (2) a modeling receptor distance of 50 km, whichever is less."162 An impact area is initially determined for each averaging time, and the impact area must include stack emissions and fugitive emissions from the proposed source for each applicable pollutant. The impact area is used to: . set the boundaries for which AAQ monitoring data may need to be collected; . define the area over which a full impact analysis must be undertaken; and . guide the identification of other sources to be included in the modeling analyses.163 Post-construction monitoring may be required by the permitting authority164 when a valid reason exists, such as when the NAAQS are threatened or when the modeling databases contain uncertainties.165 Post-construction monitoring should generally not begin until the source is operating near its intended capacity and should be performed with PSD-approved monitors. The regulations require that an owner or operator "shall provide an analysis of the impairment to visibility, soils, and vegetation that would occur as a result of the source or modification and general commercial, residential, industrial, and other growth associated with the source or modification."166 The analysis for vegetation need only be performed for vegetation with a significant commercial or recreational value. The extent of this analysis depends on existing air quality, the quantity of emissions, current visibility, and the sensitivity of the local soils and vegetation.167 While small emissions increases will usually not have an impact, the additional analysis must still be performed.168 As a general rule, emissions below the secondary NAAQS will not be harmful to vegetation or soils, although certain sensitive vegetation species may be harmed.169 The visibility impact (which is distinct from the Class I visibility requirement) usually contains: . a determination of the visual quality of the area; . an initial screening of emission sources to assess visibility impairment; and . if warranted, in-depth analysis of computer models.170 The initial screening, or Level 1 analysis, involves conservative estimates with standardized values, and if the results exceed certain criteria then a Level 2 analysis is conducted using more source-specific values.171 Level 3 modeling is required when the screening results of Level 2 exceed certain criteria, and involves a plume visibility model with the purpose to provide "an accurate description of the magnitude and frequency of occurrence of impact."172 Another "additional impact" that must be considered is the air quality impact from the projected commercial, industrial, and residential growth associated with the source or modification.173 Note that this only applies to "associated" growth that is not a part of the source, and does not include "non-associated" growth projections required under 40 C.F.R. §§ 51.166(n)(3) and 52.21(n)(3).174 Mobile and temporary sources are not included in the calculations. The estimates of these associated growth emissions are combined with the direct emissions of the source for input into the air quality modeling analysis.175 In addition to the increment analysis for Class I areas, the applicant must perform an analysis of the potential impacts on such areas.176 The applicant must give notice of the proposed source or modification to the federal land manager (FLM)177 in charge of any potentially affected Class I area, and should contact the FLM in possible Class I areas for consultation. The National Park Service (NPS) and the U.S. Forest Service are the FLMs for the majority of the Class I areas. The notice must include all relevant information about the change and an analysis of the potential impacts on AQRVs, including visibility. Generally, this analysis occurs when a pollutant increases by more than 1 [mu] g/m3 in a Class I [32 ELR 11104] area, but may be less under certain circumstances.178 A permit can be denied for adverse impacts even if an increment is not violated.179 AQRVs represent the unique characteristics of the Class I area. These characteristics may vary between areas and are often expressed in broad terms.180 The NPS defines adverse impact to an AQRV as any impact that: "(1) diminishes the area's national significance; (2) impairs the structure or functioning of ecosystems; or (3) impairs the quality of the visitor experience."181 Examples of AQRVs and Potential Air Pollution-Caused Changes182
In preparing the analysis for the application, the applicant should: . identify all Class I areas within 62 miles (100 km) of the proposed source and any other Class I areas potentially affected185; . perform all necessary Class I increment analyses; . perform for each Class I area any preliminary analysis required by a reviewing agency to find whether the source may increase the ambient concentration of any pollutant by more than 1 [mu] g/m3 for a 24-hour average; . perform for each Class I area an AQRV visibility impact analysis; . provide all necessary information to conduct the AQRV impact analyses; . perform any monitoring within the Class I area required by the reviewing agency; and . provide the reviewing agency with any additional information requested by the reviewing authority.186 Nonattainment New Source Review (NA NSR) for Major Sources In contrast to the PSD program, the NA NSR program is less comprehensive. The NA NSR program concentrates on criteria pollutants, i.e., those subject to NAAQS, in nonattainment areas only. The regulations outlining the NA NSR are found at 40 C.F.R. § 51.165,and the statutory provisions are found in CAA §§ 181-191. Circumstances may require application of the codified offset ruling and construction moratorium in states without fully approved SIPs.187 Currently, every air quality control region (AQCR) in the country is in attainment for at least one criteria pollutant, and therefore subject to the PSD program. There are 107 areas in the United States that are in nonattainment for at least one criteria pollutant as of June 2001.188
. When the only pollutants emitted are those for which the area is classified as nonattainment, then only NA NSR is required. . When the applicable source threshold for NA NSR is lower than the PSD applicability threshold, then only the NA NSR may be required. The vast majority of definitions and regulatory schemes are paralleled in the PSD program, with only minor variations. For this reason, it is critical to review the PSD program to establish a foundation for understanding NA NSR. There are three major differences: the definition of a source, evaluated pollutants, and applicability thresholds. Additionally, the source wanting to construct or modify in the nonattainment area must first obtain emissions reductions, i.e., offsets, in the same area at least equal to the proposed increase. Applicability, Regulated Pollutants, and Procedural Aspects The NA NSR program applies only to criteria pollutants emitted by major sources in areas classified as in nonattainment.190 "Unlike the PSD program, the nonattainment analysis program does not require the covered source to evaluate all pollutants regulated under the federal CAA."191 Therefore, only those emissions units that emit the nonattainment criteria pollutant will be subject to the technology requirement, i.e., LAER, and the offset analysis. Unlike the PSD program, specific procedural requirements, such as time schedules, are absent from the NA NSR program. Instead, the procedures must only ensure that the substantive provisions of the program can be adequately dealt with and that a public comment process not less stringent than set forth in 40 C.F.R. § 51.161 be used. However, if the proposed source or modification will impact a federal Class I area, then there are specific procedural provisions that apply to the visibility and impact analysis. Definition of a Source and Source Thresholds Two potential definitions of "source" exist for NA major source permitting—plantwide and dual. The applicable definition is found in the SIP, and whichever definition the state chooses to use in its SIP, it must be used for permitting and review purposes.192 The most prevalent definition is the plantwide definition. In short, under the plantwide definition, only changes that result in a significant net emissions increase over the entire plant will trigger review.193 Therefore, emissions reductions elsewhere at the plant can offset the emissions increases caused by the addition of an emissions unit or a change in physical or operational nature of the source and thus avoid review. However, a change at a non-major source that would trigger the threshold itself is a major source and subject to review. The dual definition on the other hand, treats the source as both the entire facility and each specific emissions unit or piece of equipment. The dual definition is thus more stringent because emissions decreases at other pieces of equipment at the same facility cannot be used to net out of NSR review. A significant emissions increase under the NA NSR includes the following rates194:
NA NSR applies only to criteria pollutants emitted in nonattainment areas. If a source exceeds the major source threshold for a particular nonattainment pollutant, the source is major (and thus subject to NA NSR) for that pollutant alone. The source can be considered a minor source for other nonattainment pollutants if the source's emissions are below the threshold amount. In contrast, under the PSD program, if any regulated pollutant meets the threshold, then all attainment pollutants are subject to PSD review. The threshold amount to determine major source status differs with nonattainment classification of the area. Unlike the PSD program, there is no 250 tpy threshold, instead for the NA NSR program, the highest threshold is 100 tpy.
The determination for major modifications under the NA NSR program is almost exactly the same as the determination under the PSD program. There are two exemptions from major modifications under the PSD program that do not exist under the NA NSR program: (1) permanent clean coal technology demonstration project constituting repowering; and (2) the reactivation of very clean coal-fired electric utility steam-generating units.200 The netting procedures to determine modification emissions are also virtually identical to netting under the PSD program. Netting is different from offsets because netting determines whether a modification triggers review, while offsets are required once the review is triggered. Early reductions in the hazardous air pollutant program under CAA § 112 may be used for netting purposes but not for offsets.201 One area where netting is more complicated than in the PSD program involves netting for VOCs (or ozone) and nitrogen oxide (NOx) in serious and severe ozone nonattainment areas where all increases in VOCs and NOx over a five-year period (instead of the project) may be considered.202 In extreme ozone areas, no netting is allowed, and thus any net emissions increase triggers NA NSR. Each state must achieve attainment through the execution of a SIP by a certain date. States can determine how to reach attainment based on the use of controls on stationary sources, mobile sources, or both, and will list these sources with required [32 ELR 11107] emissions reductions in their SIPs.203 These lists can include specific sources required to reduce certain amounts of emissions or general pollution control requirements for categories of sources.204 Each facility's operating permit must comply with the SIP.205 The purpose of the SIP is to provide a plan for a state to come into attainment in the prescribed time.206 The purpose of the operating permit is to require a facility to implement required controls.207 The permit must include all SIP-mandated limitations so that the facility will operate in compliance with the SIP.208 Thus, the operating permit becomes a tool for implementing the SIP.209 All facilities must operate in compliance with the SIP through their permits. However, determining all the SIP requirements that apply to a particular source can be difficult, so EPA allows for a "good-faith estimate" when applying the state rules.210 The facility needs to adhere to SIP requirements, but also maintain operating flexibility so that process changes do not trigger permit and SIP revisions.211 EPA has encouraged states to preserve operational flexibility as they modify their SIPs, as expressed in the EPA White Papers.212 Substantive Elements of NA NSR The two most important and distinguishable elements of the NA NSR program are the LAER standard and the offset procedure. Additionally, sources must ensure that all major sources in the nonattainment area are in compliance with an EPA-approved and adequately implemented SIP. An alternative site analysis must also be completed which concludes that "an analysis of alternative sites, sizes, production processes, and environmental control technologies . . . [which] demonstrates that benefits of the proposed source significantly outweigh the environmental and social costs imposed as a result of its location, construction, or modification."213 The effects on federal Class I areas must also be evaluated.214 Another interesting element of NA NSR review is the Economic Incentive Program. Major sources and major modifications in areas in nonattainment for criteria pollutants are subject to LAER as the emission limitation for each emissions unit at the source, including fugitive emissions. LAER is defined in the regulation as: (A) The most stringent emissions limitation which is contained in the implementation plan of any State for such class or category of stationary source, unless the owner or operator of the proposed stationary source demonstrates that such limitations are not achievable; or (B) The most stringent emissions limitation which is achieved in practice by such class or category of stationary sources. This limitation, when applied to a modification, means the [LAER] for the new or modified emissions units within [a] stationary source. In no event shall the application of the term permit a proposed new or modified stationary source to emit any pollutant in excess of the amount allowable under an applicable new source standard of performance.215 Therefore, determining LAER requires looking to the SIP. The most stringent limitation in a SIP for that source's class or category is presumed to be LAER, unless more stringent controls have been achieved in practice or the source demonstrates that the SIP limitation is unachievable.216 The LAER is expressed in both a numerical emissions limit and an emissions rate. This presumption of SIP limitation applicability diminishes if: . no source exists to which the limitation applies; . it is generally acknowledged that the limitation cannot be complied with; or . the state has relaxed or is changing the limit.217 No LAER standard may allow an exceedance of an applicable NSPS.218 Technological considerations in determining LAER include emissions rate limitations, e.g., change in raw materials, process modifications, or add-on controls, and technology transfers, e.g., gas stream controls and process controls.219 For LAER determinations, "costs should be considered only to the degree that they reflect unusual circumstances which, in some manner, differentiate the cost of control for that source from the costs of control for the rest of that industry."220 An LAER is not considered achievable if the cost of control is so great that a major new source could not be built or operated. . . . If some other plant in the same (or comparable) industry uses that control technology, then such use constitutes evidence that the cost to the industry of that control is not prohibitive.221 Additionally, the energy and environmental considerations required in a PSD analysis are not required in an NA NSR analysis. LAER is not established until the final permit is issued, and the source should thoroughly evaluate the options in an attempt to preclude LAER from changing between the draft permit and the final permit issuance.222 A new source or modification in a nonattainment area must [32 ELR 11108] obtain offsets for each pollutant triggering NA NSR,223 offsetting requires emissions reductions in a ratio greater than the emissions increases based on the severity of the nonattainment area in order to achieve "reasonable further progress" toward attainment. This follows the idea of the "reasonable further progress" goal, where even with additional increases, the overall pollutant load decreases and the area has a positive gain in air quality. The following table shows the offset ratios required for different area classifications for ozone, and offsets for other pollutants in all classification areas must be greater than 1.1:1 and demonstrate a net air quality benefit. Offset Ratios for Ozone NA Areas
In general, offsets can continue to exist as long as they are accounted for in each subsequent emissions inventory. They expire if they are used, or relied upon, in issuing a permit for a major stationary source or major modification in a nonattainment area, or are used in a demonstration of reasonable further progress.230 Offsets should be obtained as close to the source as possible to maximize the net air quality benefit, although the rules are relaxed for ozone and NOx offsets in the Ozone Transport Region. Five main factors are used when considering offsets: . the pollutants requiring offsets and amount of offset required; . the location of offsets relative to the proposed source; . the allowable sources for offsets; . the baseline for calculating emissions reduction credits; and . the enforceability of proposed offsets. Economic Incentive Programs (EIPs) States are required to adopt EIPs in extreme ozone non-attainment areas and serious carbon monoxide nonattainment areas when a milestone is missed.231 States are also encouraged to use EIPs in other areas and for other pollutants to improve air quality, while maintaining operating flexibility for facilities.232 EIP is defined broadly to give the states flexibility in designing a program, but EPA will only give credit for emissions reductions that are quantifiable, permanent, enforceable, and beyond reductions already required.233 A program can include benefits sharing between industry and the environment or trading to attain reasonably available control technology-level emissions reductions in aggregate at one source or between other sources.234 However, a program must include quantification information, monitoring, reporting, and recordkeeping requirements, and enforcement provisions.235 For over 20 years, the PSD and NA NSR preconstruction review programs have played an often controversial, but undoubtedly major role in shaping the nation's air quality. Since the initiation of the current NSR Enforcement Initiative in 1999, which has led to unprecedented settlements in terms of scope and penalties, implementation of the PSD and NA NSR programs has achieved heightened attention and increased calls for reform. While reform has picked up steam under the Bush Administration and various "Clear Skies" proposals, reform of the PSD and NA NSR programs has often foundered on the contentious politics and sheer complexity of the programs and issues involved. Prudent managers and counselors cannot rely upon possible reforms to meet present compliance obligations. Steps should be taken to ensure that potential PSD and NA NSR applicability is reviewed in a facility's decisionmaking processes and that the bases for determining whether the programs apply is clearly documented. Where appropriate, confirmation from relevant permitting authorities should be sought, although state agreement does not necessarily preclude subsequent EPA enforcement activity. Because of the complex nature of the program, high enforcement priority, and the overlapping and frequently divergent views of local and EPA regional officials, PSD and NA NSR issues are ignored only at great peril. 1. See 42 U.S.C. § 7470, ELR STAT. CAA § 160. 2. See U.S. ENVIRONMENTAL PROTECTION AGENCY (U.S. EPA), NEW SOURCE REVIEW WORKSHOP MANUAL A.27-28 (1990) (Draft) [hereinafter NSRWM]. 3. See 40 C.F.R. §§ 51.166(i), 52.21(i). 4. See, e.g., Letter from Francis X. Lyons, EPA Region V, to Henry Nickel, Counsel for the Detroit Edison Company (May 23, 2000) (applicability determination for Detroit Edison), at www.epa.gov/Region7/programs/artd/air/nsr/nsrmemos/detedisn.pdf [hereinafter Lyons Letter]. 5. See 42 U.S.C. § 7491(a)(2), ELR STAT. CAA § 169A(a)(2); 40 C.F.R. pt. 81, subpt. D. 6. 42 U.S.C. § 7475(d)(2), ELR STAT. CAA§ 165(d)(2). 7. See id. § 7474, ELR STAT. CAA § 164. To date, only Native American tribes have redesignated areas from Class II to Class I, often in an attempt to stop development, because the consequence of reducing the increments makes the location of industry in that area extremely difficult and expensive. See ARNOLD W. REITZE, AIR POLLUTION CONTROL LAW; ENFORCEMENT AND COMPLIANCE (forthcoming Environmental Law Institute 2001). 8. See NSRWM, supra note 2, at C.6. 9. Id. 10. See id. at C.8.
13. See id. § 7412(b)(6), ELR STAT. CAA § 112(b)(6). 14. See JOHN S. SEITZ, U.S. EPA, NEW SOURCE REVIEW (NSR) PROGRAM TRANSITIONAL GUIDANCE (1991). 15. See JAMES T. O'REILLY ET AL., CLEAN AIR PERMITTING MANUAL 11-16, 17 (Clark, Boardman, Callaghan 1997). 16. These sources are: fossil fuel-fired steam electric plants of more than 250 million British thermal units per hour (Btu/hr.) heat input; coal cleaning plants with thermal dryers; kraft pulp mills; Portland cement plants; primary zinc smelters; iron and steel mill plants; primary aluminum ore reduction plants; primary copper smelters; municipal incinerators capable of charging more than 250 tons of refuse per day; hydrofluoric, sulfuric, and nitric acid plants; petroleum refineries; lime plants; phosphate rock processing plants; coke oven batteries; sulfur recovery plants; carbon black plants (furnace process); primary lead smelters; fuel conversion plants; sintering plants; secondary metal production plants; chemical process plants; fossil fuel boilers (aggregated) of more than 250 million Btu/hr. heat input; petroleum storage and transfer units with total capacity greater than 300,000 barrels; taconite ore processing plants; glass fiber processing plants; and charcoal processing plants. See 40 C.F.R. § 51.166(b)(1)(i)(a). 17. See id. §§ 51.166(b)(1)(i), 52.21(b)(1)(i). 18. Id. §§ 51.166(b)(5), 52.21(b)(5). 19. See id. §§ 51.166(b)(6), 52.21(b)(6). 20. NSRWM, supra note 2, at A.3-4. 21. See id. at A.4. 22. See 45 Fed. Reg. 52676, 52695 (Aug. 7, 1980). 23. See Letter from Kathleen Henry, U.S. EPA Region III, to John Slade, Pennsylvania Department of Environmental Protection (undated, post-Dec. 1998) [hereinafter Henry Letter]; Letter from William A. Spratlin, U.S. EPA Region VII, to Peter R. Hamlin, Iowa Department of Natural Resources (Sept. 18, 1995). 24. See Letter from William A. Spratlin, U.S. EPA Region VII, to Peter R. Hamlin, Iowa Department of Natural Resources (Sept. 18, 1995). 25. See Letter from R. Douglas Neeley, U.S. EPA Region IV, to C.H. Fancy, Florida Department of Environmental Protection (Jan. 28, 2000); Henry Letter, supra note 23; Letter from Joan Cabreza, U.S. EPA Region X, to Andy Ginsberg, Oregon Department of Environmental Quality (Aug. 7, 1997). 26. Appendix C of the NSRWM details calculations and methods for PTE determinations. 27. 40 C.F.R. §§ 52.21(b)(4), 51.166(b)(4). 28. See NSRWM, supra note 2, at A.5. 29. See National Mining Ass'n v. EPA, 59 F.3d 1351, 25 ELR 21390 (D.C. Cir. 1995). The court remanded to EPA for an explanation as to "how its refusal to consider limitations other than those that are 'federally enforceable' serves the statute's directive to 'consider controls' when it results in a refusal to credit controls imposed by a state or locality even if they are unquestionably effective." Id. at 1364, 25 ELR at 21397. 30. See Chemical Mfrs. Ass'n v. EPA, 70 F.3d 637 (D.C. Cir. 1995). 31. See STEVEN A. HERMAN & MARY D. NICHOLS, U.S. EPA, "EFFECTIVE" LIMITS ON POTENTIAL TO EMIT: ISSUES AND OPTIONS (1996). 32. See id. at 3-4. 33. Id. at 5. 34. 40 C.F.R. §§ 51.166(b)(20), 52.21(b)(20). 35. See id. §§ 51.166(c)(3), 52.21(c)(3). 36. This list is the same as that for stationary source determinations. These sources are: fossil fuel-fired steam electric plants of more than 250 million Btu/hr. heat input; coal cleaning plants with thermal dryers; kraft pulp mills; Portland cement plants; primary zinc smelters; iron and steel mill plants; primary aluminum ore reduction plants; primary copper smelters; municipal incinerators capable of charging more than 250 tons of refuse per day; hydrofluoric, sulfuric, and nitric acid plants; petroleum refineries; lime plants; phosphate rock processing plants; coke oven batteries; sulfur recovery plants; carbon black plants (furnace process); primary lead smelters; fuel conversion plants; sintering plants; secondary metal production plants; chemical process plants; fossil fuel boilers (aggregated) of more than 250 million Btu/hr. heat input; petroleum storage and transfer units with total capacity greater than 300,000 barrels; taconite ore processing plants; glass fiber processing plants; and charcoal processing plants. 40 C.F.R. § 51.166(b)(1)(i)(a). 37. See NSRWM, supra note 2, at A.10. 38. See id. 39. See LYDIA N. WEGMAN, U.S. EPA, EPA RECONSIDERATION OF APPLICATION OF COLLOCATION RULES TO UNLISTED SOURCES OF FUGITIVE EMISSIONS FOR PURPOSES OF TITLE V PERMITTING (1995). 40. See id. The primary activity test is whether the unlisted source is a support facility or contributes to the "primary activity" of the company. 41. NSRWM, supra note 2, at A.10. 42. See Rolf R. von Oppenfeld & Eric L. Hiser, Legal Requirements for Proving the Fugitive VOCs Emissions Defense to an Alleged PSD Permit Violation, 29 Env't Rep. (BNA) 1612 (1998). 43. See 40 C.F.R. § 52.21(b)(18); see, e.g., EDWARD E. REICH, U.S. EPA, PSD APPLICABILITY—TEMPORARY EMISSIONS (1978) (construction-related emissions should not be considered in PSD review applicability determinations). 44. See NSRWM, supra note 2, at A.18; see also Natural Resources Defense Council v. EPA, 725 F.2d 761, 14 ELR 20191 (D.C. Cir. 1984). 45. See 40 C.F.R. §§ 51.166(b)(4), 52.21(b)(4). 46. NSRWM, supra note 2, at A.18. 47. 40 C.F.R. §§ 51.166(n), 52.21(n). 48. Id. 49. See id. §§ 51.166(q)(2), 52.21(q)(2). 50. See id. § 124.3. 51. See id. § 124.10. 52. See id. § 124.19. 53. See id. §§ 51.166(i)(1), 52.21(i)(1). 54. Id. §§ 51.166(b)(11), 52.21(b)(11). 55. See id. §§ 51.166(b)(8), 52.21(b)(8). 56. "Emissions unit means any part of a stationary source which emits or would have the [PTE] any pollutant subject to regulation of the Act." 40 C.F.R. §§ 51.165(a)(1)(vii), 51.166(b)(7), 52.21(b)(7). "It is important to note that an emissions unit may consist of a single piece of equipment, such as a valve, flange, or pump, since each of these fits the definition of emissions unit . . . ." Letter from Douglas M. Skie, U.S. EPA, to Brad Beckham, Colorado Department of Health (Feb. 6 1990). 57. EDWARD E. REICH, U.S. EPA, SOURCE CONSTRUCTION PRIOR TO ISSUANCE OF PSD PERMIT (1978). 58. See, e.g., Lyons Letter, supra note 4. 59. See 40 C.F.R. §§ 51.166(r), 52.21(r). 60. Id. §§ 51.166(b)(2)(i), 52.21(b)(2)(i). 61. See NSRWM, supra note 2, at A.33. Some states may use a lower threshold. For example, Arizona treats any change that exceeds a PSD threshold as triggering PSD. A.A.C. R18-2-401(9)(c). 62. See NSRWM, supra note 2, at A.6; see also 40 C.F.R. §§ 51.166(b)(23)(iii), 52.21(b)(23)(i). 63. See JOHN CALCAGNI, U.S. EPA, REQUEST FOR CLARIFICATION OF POLICY REGARDING THE "NET EMISSIONS INCREASE" (1989). 64. See 40 C.F.R. §§ 51.166(b)(2)(ii), 52.21(b)(2)(ii). 65. See O'REILLY ET AL., supra note 15, at 12-18. 66. So-named after Wisconsin Elec. Power Co. (WEPCo) v. Reilly, 893 F.2d 901, 20 ELR 20414 (7th Cir. 1990). See 57 Fed. Reg. 32314 (July 21, 1992); Letter from Richard R. Long, U.S. EPA Region VIII, to Dana K. Mount, North Dakota Department of Health (undated, post-Oct. 1998). See also In re Tennessee Valley Auth., No. CAA-2000-04-008 at 103 (E.A.B. Sept. 15, 2000). 67. See NSRWM, supra note 2, at A.36. 68. See Letter from EPA Region IV to the South Carolina Department of Health and Environmental Control (Mar. 14, 1997). 69. Letter from Kathleen Henry, EPA, to John M. Daniel, Virginia Department of Environmental Quality (Oct. 23, 1998). 70. See GERALD A. EMISON, U.S. EPA, PREVENTION OF SIGNIFICANT DETERIORATION (PSD) DEFINITION OF "MODIFICATION" (1986). 71. See 40 C.F.R. §§ 51.166(b)(2)(iii), 52.21(b)(2)(iii). 72. Id. §§ 51.166(b)(2)(iii)(a), 52.21(b)(2)(iii)(a). 73. 57 Fed. Reg. at 32326. 74. See In re Tennessee Valley Auth., No. CAA-2000-04-008 (EAB Sept. 15, 2000). 75. See 40 C.F.R. §§ 51.166(b)(2)(iii)(b)-(e), 52.21(b)(2)(iii)(b)-(e). 76. See id. §§ 51.166(b)(2)(iii)(f), 52.21(b)(2)(iii)(f). 77. See id. §§ 51.166(b)(2)(iii)(g), 52.21(b)(2)(iii)(g). 78. See id. §§ 51.166(b)(2)(iii)(h)-(k), 52.21(b)(2)(iii)(h)-(k). 79. 893 F.2d 901, 20 ELR 20414 (7th Cir. 1990). 80. See JOHN S. SEITZ, U.S. EPA, POLLUTION CONTROL PROJECTS AND NEW SOURCE REVIEW (NSR) APPLICABILITY (1994). 81. See id. at 13. This includes an "unacceptable increased risk" of air toxics assessment. 82. Id. at 11-12. 83. See NSRWM, supra note 2, at A.35. 84. See 40 C.F.R. §§ 51.166(b)(3)(iii), 52.21(b)(3)(iii). 85. See id. §§ 51.166(b)(3)(v),(vi), 52.21(b)(3)(v),(vi). 86. See NSRWM, supra note 2, at A.45. 87. See id. at A.35. 88. See CALCAGNI, supra note 63; RICHARD BIONDI, U.S. EPA, ACCUMULATION OF EMISSIONS (1983); SHELDON MEYERS, U.S. EPA, NET EMISSION INCREASE UNDER PSD (undated). 89. See NSRWM, supra note 2, at A.36 Attempts to circumvent PSD review by breaking an otherwise significant project into smaller projects is subject to an enforcement action. 90. See BIONDI, supra note 88. 91. See JOHN CALCAGNI, U.S. EPA, USE OF NETTING CREDITS (1989). 92. See KATHLEEN M. BENNETT, U.S. EPA, POLICY ON EXCESS EMISSIONS DURING STARTUP, SHUTDOWN, MAINTENANCE, AND MALFUNCTIONS (1982). The rationale was that SIPs are ambient-based. 93. See JOHN B. RASNIC, U.S. EPA, AUTOMATIC OR BLANKET EXEMPTIONS FOR EXCESS EMISSIONS DURING STARTUP AND SHUTDOWNS UNDER PSD (1993). 94. See STEVEN A. HERMAN, U.S. EPA, STATE IMPLEMENTATION PLANS: POLICY REGARDING EXCESS EMISSIONS DURING MALFUNCTIONS, STARTUP, AND SHUTDOWN (1999). 95. See von Oppenfeld & Hiser, supra note 42. 96. See 40 C.F.R. §§ 51.166(b)(4), 52.21(b)(4). 97. U.S. EPA, GUIDANCE ON LIMITING POTENTIAL TO EMIT IN NEW SOURCE PERMITTING (1989). 98. See Chemical Mfrs. Ass'n v. EPA, 70 F.3d 637 (D.C. Cir. 1995). 99. U.S. EPA, INTERIM POLICY ON FEDERAL ENFORCEABILITY REQUIREMENT FOR LIMITATIONS ON POTENTIAL TO EMIT (1996) (emphasis in original); see also U.S. EPA, SECOND EXTENSION OF JANUARY 25, 1995, PTE TRANSITION POLICY AND CLARIFICATION OF INTERIM POLICY (1998). 100. Even if the local agency rules do not specifically allow nonfederally enforceable limits, it may still be possible to use this approach in a delegated program or when other applicable law would provide a basis for following EPA's current policy. 101. O'REILLY ET AL., supra note 15, at 11-32. 102. See 40 C.F.R. § 51.166(r)(2). 103. See id. §§ 51.166(j), 52.21(j). See also NSRWM, supra note 2, at C.9. 104. See id. §§ 51.166(b)(12), 52.21(b)(12). 105. See NSRWM, supra note 2, at B.4. 106. 42 U.S.C. § 7491(3), ELR STAT. CAA § 169(3). 107. See 40 C.F.R. §§ 51.166(b)(3)(vii), (8), (11), (21)(i), 52.21(b)(3)(vii), (8), (11), (21)(i). 108. See id. §§ 51.166(j)(2), 52.21(j)(2). 109. See id. §§ 51.166(b)(5), 52.21(b)(5). n110 The Environmental Appeals Board (EAB) recently wrote that "while the NSR Manual is not a binding rule and is not accorded the same weight as an EPA regulation, it is considered by this Board to be a statement of the Agency's thinking on certain PSD issues." In re Steel Dynamics, Inc., 2000 EPA App. LEXIS 18, *45 n.22, PSD Appeal Nos. 99-4, -5 (June 22, 2000). The EAB also recognized that while the BACT analysis in the NSRWM was not binding, a deviation is more carefully scrutinized. See id. at *44. 111. NSRWM, supra note 2, at B.4. 112. Id. at B.5. 113. Id. at B.9. 114. See DAVID G. HAWKINS, U.S. EPA, GUIDANCE FOR DETERMINING BACT UNDER PSD (1979); see also U.S. EPA, GUIDELINES FOR DETERMINING BEST AVAILABLE CONTROL TECHNOLOGY (BACT) (1978). 115. See 40 C.F.R. §§ 51.166(b)(12), 52.21(b)(12). 116. Id. 117. See id. 118. See Letter from Gary McCutchen, U.S. EPA, to Richard E. Grusnick, Alabama Department of Environmental Management (July 28, 1987). 119. JOHN CALCAGNI, U.S. EPA, TRANSMITTAL OF BACKGROUND STATEMENT ON "TOP-DOWN" BEST AVAILABLE CONTROL TECHNOLOGY (BACT) (1989). 120. GARY McCUTCHEN, U.S. EPA, HUNTSVILLE INCINERATOR — DETERMINING BEST AVAILABLE TECHNOLOGY (1987). 121. See id. 122. HAWKINS, supra note 114; JOHN S. SEITZ, U.S. EPA, IDENTIFICATION OF CANDIDATES FOR BEST AVAILABLE CONTROL TECHNOLOGY (BACT) DETERMINATIONS (undated). 123. See JOHN S. SEITZ, U.S. EPA, BACT/LAER DETERMINATION CUTOFF DATE (1990). 124. U.S. EPA, GUIDELINES FOR DETERMINING (BACT), supra note 114. 125. U.S. EPA, NEW SOURCE REVIEW WORKSHOP MANUAL (1980). 126. See CALCAGNI, TRANSMITTAL OF BACKGROUND STATEMENT, supra note 119; NSRWM, supra note 2. 127. See NSRWM, supra note 2, at B.6, tbl. B-1. 128. See id. at B.10. 129. See id. at B.5. 130. See id. 131. See id. at B.11. 132. 40 C.F.R. §§ 51.166(b)(19); see NSRWM, supra note 2, at B.12-.13. 133. NSRWM, supra note 2, at B.19. 134. Id. at B.20. 135. See id. at B.25. 136. See 40 C.F.R. §§ 51.166(b)(12), 52.21(b)(12). 137. See NSRWM, supra note 2, at B.26. 138. See id. at B.29. 139. See id. at B.30. 140. See id. at B.47. 141. See id. at B.48. 142. Id. at B.53. 143. See id. at B.31. The NSRWM contains detailed descriptions of determining cost effectiveness at pages B.36 to B.44. 144. See id. at app. B. 145. Id. at B.45. 146. A sample chart of BACT comparisons for selections can be found in the NSRWM, supra note 2, at 28. 147. See 40 C.F.R. §§ 51.166(d), 52.21(d). 148. Id. §§ 51.166(m)(1), 52.21(m)(1); see also NSRWM, supra note 2, at C.51-.53. 149. See 40 C.F.R. §§ 51.166(m)(1), 52.21(m)(1); see also NSRWM, supra note 2, at C.1. 150. See 40 C.F.R. §§ 51.166(1), 52.21(1), 52, at app. W. 151. See Letter from James T. Wilburn, EPA Region IV, to W. Fin Johnson, North Carolina Department of Natural Resources and Community Development (June 12, 1984). 152. See NSRWM, supra note 2, at C.24. 153. See id. 154. See 40 C.F.R. §§ 51.166(m)(1)(iv), 52.21(m)(1)(iv). 155. See NSRWM, supra note 2, at C.18. 156. See id. at C.20. 157. See 40 C.F.R. §§ 51.166(i)(8)(i), 52.21(i)(8)(i). 158. See NSRWM, supra note 2, at C.25. 159. See id. at C.32. "It will be necessary to include in the NAAQS inventory those sources which have received PSD permits but have not yet begun to operate, as well as any complete PSD applications for which a permit has not yet been issued." Id. at C.34. 160. See id. at C.35-C.36. 161. See id. at C.37. 162. Id. at C.26. 163. See id. at C.31. 164. See 40 C.F.R. §§ 51.166(m)(2), 52.21(m)(2). 165. See NSRWM, supra note 2, at C.21. 166. 40 C.F.R. §§ 51.166(o)(1), 52.21(o)(1). 167. See NSRWM, supra note 2, at D.1. 168. See id. at D.2. 169. See id. at D.5. 170. See id. at D.6. 171. See id. at D.6-D.7. The initial screening model is typically the VISCREEN model, and the level 2 model is usually the FLUVUE II. 172. Id. at D.7. 173. See 40 C.F.R. §§ 51.166(o)(2), 52.21(o)(2). 174. See NSRWM, supra note 2, at D.3 fn.5. This also means that emissions from associated growth are secondary emissions and included in the air quality analysis but do not count toward PTE calculations. 175. See id. at D.4. 176. See 40 C.F.R. §§ 51.166(p), 52.21(p). This includes both mandatory and nonmandatory federal Class I areas. 177. The FLM has an "affirmative duty to protect the air quality related values (including visibility) . . . ." Id. §§ 51.166(p)(2), 52.21(p)(2). 178. See NSRWM, supra note 2, at E.16. 179. See id. at E.21. 180. See id. at E.10. 181. Id. at E.12. 182. Id. at E.11. 183. See id. at E.8. 184. See 40 C.F.R. §§ 51.166(p)(4), 52.21(p)(4). 185. See JOHN S. SEITZ, U.S. EPA, CLARIFICATION OF PREVENTION OF SIGNIFICANT DETERIORATION (PSD) GUIDANCE FOR MODELING CLASS I AREA IMPACTS (1992). 186. NSRWM, supra note 2, at E.18. 187. These are found at 40 C.F.R. pt. 51, Appendix S (offset ruling) and 40 C.F.R. § 52.24 (construction moratorium). 188. See U.S. EPA, USA AIR QUALITY NONATTAINMENT AREAS, available at http://www.epa.gov/airs/nonattn.htm (last visited Nov. 19, 2001). 189. See O'REILLY ET AL., supra note 15, at 11-32. 190. See 40 C.F.R. § 51.165(a)(2). 191. Bernard F. Hawkins Jr., The New Source Review Program: Its Prevention of Significant Deterioration and Nonattainment Analysis Programs, in THE CLEAN AIR ACT HANDBOOK 142 (David P. Novello & Robert J. Martineau Jr. eds., 1998). 192. See NSRWM supra note 2, at F.2. 193. See id. 194. See 40 C.F.R. § 51.165(a)(1)(x). 195. See id. § 51.165(b)(2). 196. See 45 Fed. Reg. at 52742. 197. See WALTER C. BARBER, U.S. EPA, DEFINITION OF "INSTALLATION" IN NONATTAINMENT REGULATIONS (1980). 198. CLEAN AIR PERMITS: MANAGER'S GUIDE TO THE 1990 CLEAN AIR ACT, at 36, Tab 400 (Thompson Publishing Group, David A. Slaughter ed., 2000). 199. 531 U.S. 457, 919 31 ELR 20512, 20517 (2001). 200. Compare 40 C.F.R. § 51.165(a)(1)(iv) with 40 C.F.R. § 51.166(b)(2)(i). 201. See 57 Fed. Reg. 13554 (Apr. 16, 1992). 202. See O'REILLY ET AL., supra note 15, at 14-19; see 61 Fed. Reg. 38298 (July 23, 1996). 203. See supra note 198, at 15, Tab 400. 204. See id. 205. See id. at 157, Tab 400. 206. See id. 207. See id. 208. See id. 209. See id. 210. See id. 211. See id. P472. 212. See id. 213. 42 U.S.C. § 7503(a)(5), ELR STAT. CAA § 173(a)(5). 214. See 40 C.F.R. § 51.307. 215. Id. § 51.165(a)(1)(xiii). 216. See id. § 51.165(a)(1)(xiii); see also JOHN CALCAGNI, U.S. EPA, GUIDANCE ON DETERMINING LOWEST ACHIEVABLE EMISSION RATE (LAER) (1989). 217. See NSRWM, supra note 2, at G.2. 218. See 40 C.F.R. § 51.165(a)(1)(xiii). 219. See NSRWM, supra note 2, at G.3. 220. CALCAGNI, GUIDANCE ON DETERMINING LAER, supra note 216. 221. NSRWM, supra note 2, at G.3. 222. See SEITZ, BACT/LAER DETERMINATION CUTOFF DATE, supra note 123; see also JOHN S. SEITZ, MEMORANDUM, CUTOFF DATE FOR DETERMINING LAER IN MAJOR NEW SOURCE PERMITTING (1989). 223. See 42 U.S.C. § 7503(c), ELR STAT. CAA § 173(c). 224. See 40 C.F.R. § 51.165(a)(3)(ii)(E). 225. See JOHN S. SEITZ, U.S. EPA, OFFSETS REQUIRED PRIOR TO PERMIT ISSUANCE (1994); DAVID G. HAWKINS, U.S. EPA, FEDERAL ENFORCEABILITY OF OFFSETS IN STATE IMPLEMENTATION PLAN PROGRAMS (1990). There is an exception for NOx offsets where the SIP provisions await EPA approval. See 57 Fed. Reg. 55620 (Nov. 25, 1992). 226. See EPA's Interpretative Ruling, codified at 40 C.F.R. pt. 51, Appendix S for more detail about how offsets are qualified. 227. See JOHN S. SEITZ, U.S. EPA, OFFSETS REQUIRED PRIOR TO PERMIT ISSUANCE (1994). 228. See NSRWM, supra note 2, at G.7. 229. Letter from William G. Rosenberg, U.S. EPA, to James M. Lents, South Coast Air Quality Management District (Feb. 28, 1992). 230. Letter from Stanley Meiburg, U.S. EPA Region VI, to William R. Campbell, Texas Air Control Board (Nov. 19, 1992). 231. See supra note 198, at 177, Tab 400 (codified at 40 C.F.R. § 51 subpt. U). 232. See id. See also 2001 EPA GUIDANCE FOR EIP (2001), available at epa.gov/ttn/oarpg/tlpgm.html. 233. See supra note 198, at 177, Tab 400. 234. See id. 235. See id. at 177-78. 32 ELR 11091 | Environmental Law Reporter | copyright © 2002 | All rights reserved |