Observe that in contrast with modifications, a change in a facility can constitute a reconstruction irrespective of whether it increases emissions. But let's return to modifications.
EPA's definition of "modification" echoes the act's definition, 11 but also states six kinds of changes in a stationary source the Agency does not consider to be modifications—based on its view that Congress could not have intended that every change at a source, no matter how minor, would subject the source to heightened pollution-control requirements. Rather, eligibility for the RMRR exemption was through case-by-case analysis, "weighing the nature, extent, purpose, frequency, and cost of the proposed work, as well as other relevant factors, to arrive at a common sense determination.
Among the renovations proposed were repair and replacement of the turbine generators, boilers, mechanical and electrical auxiliaries, and the common plant support facilities. The extent of the work on the plant, said the court, was substantial and unprecedented.
Also, the purpose of the project "life extension" , its infrequency only once or twice in the unit's life , and its high cost all pointed to non-routineness.
In recent years, the RMRR exemption has assumed center stage. The curtain-raising act was the filing of CAA enforcement actions by the Clinton Administration against electric utilities across the Midwest and South involving 36 power plants, several owned by TVA , accusing them of making plant changes that exceeded "routine maintenance" without installing the more stringent NSR controls. Following this, in May, , President Bush's National Energy Policy Development Group issued a recommended national energy policy, directing EPA to review the impact of NSR on investment in new utility and refinery generation capacity, energy efficiency, and environmental protection.
This resulted in EPA's June, report to the President on the impact of NSR, which asserted the desirability of specifying certain categories of activities that categorically qualify as "routine maintenance.
EPA v. It embodied this determination in an administrative compliance order ACO. Note that this decision, important as it is to enforcement of the RMRR exception, did not speak to the contours of the exception itself. The October, final rule. According to the regulatory preamble, the new approach is "intended to provide greater regulatory certainty without sacrificing the current level of environmental protection For the moment, EPA is not taking action on the proposed annual maintenance, repair, and replacement "allowance.
The agency acknowledges that the new approach will allow replacement of components under more circumstances than the former case-by-case approach—the key trigger of the controversy over the new rules. NSR review has a far more sensitive trigger — a tonnage increase in pollutant output.
Because life extension does improve availability and reliability, it is likely to increase emissions over levels emitted before the life extension activities were undertaken. But how does one measure the change? What are the baselines 28? These issues came to a head in the late s when EPA decided to enforce NSR against facilities undergoing life extension efforts. In , the EPA ruled that a life extension project by Wisconsin Electric Power Company WEPCO met the trigger for NSR because of the potential for increased emissions from the facilities after the project compared with actual emissions from the facilities before the project.
After considerable litigation 29 and congressional debate, EPA modified this "actual to potential" emissions trigger with respect to electric utilities in Specifically, "actual emissions" equal the facility's average emission rate during a 2-year period out of the preceding 5 years before the proposed change. These are the current NSR regulations for utility plants. Fundamental to the debate on NSR enforcement with respect to existing facilities is the notion of "routine maintenance.
Among those activities exempted was: "maintenance, repair, and replacement which the Administrator determines to be routine for a source category Responding to this situation, utilities began to spread out their life extension efforts in an attempt to make them fit into their routine maintenance schedules.
These "rehabilitation" practices that extend the design life of a power plant represents a change in what had earlier been considered accepted maintenance practices: Before the early s, power plants were generally assumed to have fixed lives — years — after which they would be replaced or relegated to cycle or peaking duties.
Unit life is an estimate of the book life of the plant. The maintenance costs include sufficient funds to replace minor equipment that wears out before the unit life shown. In its cost analyses for coal-fired powerplants, this unit life was assumed to be 30 years. The flux in the notion of fixed powerplant lives was evident in the early s debate on proposed acid rain legislation.
In utility analyses of anticipated cost of retrofitting their existing powerplants with additional pollution controls, utilities split on the issue of retirement, either as a pollution control strategy, or as utility policy in general. For example, American Electric Power, a leading opponent of such legislation, conducted its cost analysis with assigned specific retirement dates for its existing powerplants ranging from years.
Indeed, it considered early retirement to be a viable, cost effective pollution control option. Up to this time, routine maintenance practices did not attempt to arrest or reverse the normal deterioration of the powerplant's performance over its life span.
Industry aging trends with respect to powerplant performance with standard maintenance practices as suggested by the EPRI definition are well documented. Degradation of key components, such as turbines, waterwall tubing, and reheaters, slowly reduces a powerplant's efficiency in converting heat to steam and steam to electricity. The result is a higher heat rate and less output. As shown in Figure 1 , "average industry maintenance practice" results in heat rates increasing by about 0.
Likewise, the aging of components eventually increases the forced outage rate of powerplants as component failure becomes more frequent. As indicated in Figure 2 , reliability of coal-fired facilities peak at between 10 and 20 years of service and then begins to deteriorate. By 35 years of operation, a facility's forced-outage rate has increased by 10 percentage points. In particular, older facilities begin to have significantly longer outages as they age, in line with the failure of major equipment, such as the turbine-generator.
As indicated by the data presented in Table 3 , these documented trends based on "average industry maintenance practices" are not occurring. Heat rates for coal-fired facilities are remaining relatively stable while capacity factors are increasing substantially. It is obvious that the rehabilitation programs utilities initiated in the s and continuing to the present have been successful in dramatically reducing the aging process with respect to coal-fired facilities.
However, is this success a violation of the modification definition of NSR? If "routine maintenance" is defined in terms of "average industry maintenance practice" at the time of the or Clean Air Act Amendments, then a strong case can be made that it is — major components are being replaced or upgraded that would not have been under average industry maintenance practices of that time.
Yet, if "routine maintenance" is interpreted to mean industry practices at the current time, then one can argue that rehabilitation has become routine over the past 20 years, and thus does not represent a modification.
This is fundamental to the way one views the proposed clarifications to the definition of routine maintenance proposed by EPA. If one believes that EPA's routine maintenance exemption as enunciated in the s was delimited and not a license to rehabilitate existing facilities, then one would conclude that many of the industry's rehabilitation activities of the last 20 years go beyond what NSR requirements allow.
Thus, any argument by the current Administration that its proposed NSR revisions would reduce emissions beyond that required under current law would be untenable as enforcement of current law would require existing sources subject to NSR to meet the stringent standards of either BACT or LAER. This perspective that applying NSR requirements to rehabilitation would reduce emissions is consistent with the enforcement initiative of the Clinton Administration, an initiative for which the Bush Administration has stated its support.
In contrast, if one believes that an exemption for routine maintenance is appropriate and should be defined in terms of current industry practices, then one would conclude that the potential threat of NSR and the installation of BACT or LAER prevents owners from making cost-effective improvements in the overall performance and efficiency of their existing facilities e. From this perspective, NSR discourages plant owners from upgrading facilities operating with old, worn-out, inefficient components, thereby foregoing opportunities to conserve energy and to reduce carbon dioxide emissions by installing newer, more efficient components.
This perspective that NSR discourages energy efficiency is reflected in the Bush Administration's proposed revisions to routine maintenance published in December, This second view that rehabilitation is in fact routine also reflects the defense of many of the utilities sued by the Justice Department under the Clinton Administration.
For them, rehabilitation programs are the norm for the industry and, therefore, should not trigger NSR. In announcing the NSR suits in , the EPA Administrator stated that "controlling the sulfur dioxide and nitrogen oxides from these plants could lead to an 85 to 95 percent reduction respectively in these pollutants.
Also, given the widespread nature of life extension efforts, it is reasonable to assume that further reductions would be achieved as other utilities either installed BACT or retired their offending facilities. Thus, at first glance, it would appear that very substantial emission reductions could be achieved by rigorous enforcement of NSR's regulations using the existing definition of "routine maintenance" rather than EPA proposed new one.
The projected sulfur dioxide SO 2 and nitrogen oxides NOx results under these three scenarios are presented in Table 5.
As indicated, depending on one's expectation with respect to NSR enforcement in lieu of the EPA proposed rule on routine maintenance, the difference in emissions could be on the order of a factor of five. Table 5. However, the CAA is a complex piece of legislation built up over time.
Specifically, title IV limits total SO 2 emissions from utilities to 8. The cap is enforced through tonnage limitations at individual existing utility plants and by an emission offset requirement for new facilities.
SO 2 emissions from most existing sources are capped at a specified emission rate times a historical average fuel consumption level. Thus the tonnage limitation is based on preset and historical data, not regulatory limits. To implement the program, title IV created a comprehensive emissions allowance system. An allowance is a limited authorization to emit a ton of SO 2 during or after a specified year.
Such allowances may be used at the plant they are allocated to, or they can be traded or banked for future use or sale. Except that they both focus on existing facilities and SO 2 , they have little in common. Title IV doesn't address whether existing facilities continue operation or not, or whether a specific facility installs BACT or not; compliance with the cap is the determining criterion.
NSR is an enforcement mechanism to assure compliance with individual plant standards; title IV is a program to reduce aggregate SO 2 emissions by permitting utilities considerable flexibility in determining appropriate compliance strategies.
However, the allocations under title IV for existing coal-fired facilities is not as stringent and can be met with low-sulfur coal. Consequently, any reductions achieved because of NSR enforcement could be rendered moot by title IV, if the affected plant subsequently sold its SO 2 reduction to some other facility not covered by an NSR action.
Rather, the law explicitly bases its allowance allocations on historical data, not on any presumption of compliance with NSPS or SIP requirements. To avoid this "allowance trap," either Congress would have to change the law, or utilities would have to agree to surrender the excess allowances created by any NSR enforcement action.
Indeed, NSR settlements and agreements in principle resulting from EPA's enforcement initiative have included the retirement of SO 2 allowances that the utilities could have used to emit additional pollution elsewhere.
The situation with potential NOx reduction is more complex. This standard, set in , could be met with fairly simple combustion modifications or low-NOx burners, and did not require the installation of pollution control devices such as selective catalytic reduction SCR. Indeed, the standard did not reflect the state of the art with respect to low-NOx burners.
However, this new standard was challenged in court. In September, , the D. If the floor is the current modified NSPS as set in , reductions achieved by NSR enforcement would be considerably less than that suggested by some. In contrast, if the floor is the new NSPS, the reduction would be substantial.
Program elements. Each of the following program components helps create a feasible, flexible, and accountable emissions control program:. Phase I of the SO 2 reduction began in and affected mostly coal-burning electric utility plants located in 21 Eastern and Midwestern states. Phase II began in and tightened the emissions limits imposed on the large, higher-emitting plants and also set restrictions on smaller, cleaner plants fired by coal, oil, and gas.
The program affects existing utility units serving generators with an output capacity of greater than 25 megawatts and all new utility units. A significant portion of the reductions has been achieved by coal-fired utility boilers that are required to install low NOx burner technologies and to meet more recent emissions standards.
Permits and compliance. All affected sources must submit acid rain permit applications to an EPA-approved state or local permitting authority, which issues and administers the permit. Every acid rain permit is a portion of a larger Title V permit. Acid rain permits require that each affected source hold a sufficient number of allowances in its allowance account to cover the unit's SO 2 emissions in each year, comply with the applicable NOx limit, and monitor and report emissions.
To cover the SO 2 emissions for the previous year, affected units must finalize allowance transactions and submit them to EPA by March 1 to be recorded in their unit accounts. The amount of emissions is determined in accordance with the monitoring and reporting provisions. If the unit's emissions do not exceed its allowances, the remaining allowances are carried forward, or banked, into the next year's account, which then becomes the current compliance account.
If a unit's emissions exceed its allowances, the unit must pay a penalty and surrender allowances for the following year to EPA as excess emissions offsets. Each affected utility unit, corporation, group, or individual holding allowances has an account in the ATS and must notify EPA to have transfers recorded in their ATS account.
To further keep track of allowance transfers, each account is assigned an identification number and every allowance, a serial number. NOx budget trading programs were market-based cap-and-trade programs created to reduce the regional transport of NOx emissions from power plants and other large combustion sources that contribute to ozone nonattainment.
States participating in NOx budget trading programs developed NOx cap-and-trade regulations for implementation during the ozone season i. Under such programs, budget sources were allocated allowances by their state government. Each allowance permitted a source to emit 1 ton of NOx during the ozone season. Allowances could be bought, sold, or banked, which provided sources with compliance flexibility. The provisions of the NOx budget trading program were incorporated into a facility's Title V operating permit.
Each budget source was required to comply with the program by demonstrating at the end of each control period that actual emissions did not exceed the amount of allowances held for that period. In order to demonstrate compliance, budget sources had to monitor and report their actual emissions.
When fully implemented, SO 2 and NOx emissions were to be reduced by approximately 70 percent and 60 percent, respectively, from levels. However, on December 30, , the U. Court of Appeals for the D. Circuit issued a ruling to stay the CSAPR pending judicial review, which ultimately ended up with the court vacating the rule in August In April , the U.
Supreme Court reversed the D. Pollutants controlled. It is widely understood that emissions of SO 2 and NOx are capable of traveling hundreds, even thousands, of miles from their emissions point to contribute to poor air quality and exceedances of the NAAQS in downwind areas of the country.
Therefore, the agency proceeded with a regional emissions control strategy for the eastern United States. Each state determined which emissions sources to control and what control measures to adopt in order to meet the state pollutant budgets assigned by the EPA.
Based on these data and an assessment of the emissions contributing to interstate pollution transport, the EPA determined that the most substantial and cost-effective emissions reductions were available from the power generation industry. As a result, the EPA encouraged states to control power plants but offered two compliance options:.
Cap-and-trade program. The affected sources under the cap-and-trade program are EGUs, which are fossil fuel-fired boilers and turbines serving an electrical generator with a nameplate capacity greater than 25 MW and producing electricity for sale, except for cogeneration plants. The states then distribute those allowances to affected sources for use or trade. To remain in compliance, each affected source must hold sufficient allowances to cover its emissions each year, but the source may choose how to comply from several alternatives, including installing pollution control equipment, switching fuels, or buying excess allowances from other sources that have reduced their emissions.
The limited number of allowances available ensures that required emissions reductions are achieved. Affected areas for PM Affected areas for ozone only are subject to the ozone season NOx cap, and affected areas for both PM In order to facilitate and streamline various overlapping cap-and-trade programs, CAIR includes revisions to the SO 2 cap-and-trade provisions under the Acid Rain Program and provides for the NOx Budget cap-and-trade program to be replaced by the CAIR ozone season cap-and-trade program.
The EPA established a federal implementation plan FIP to implement cap-and-trade programs for power plants in states that failed to develop standards and incorporate them into their SIP.
Circuit found CAIR to be flawed but kept it in place while directing the EPA to issue a new rule governing the transport of air pollutants across state boundaries.
However, on December 30, , the D. On April 29, , the U. Supreme Court reversed the opinion of the U. It is widely understood that emissions of SO 2 and NOx are capable of traveling hundreds, even thousands, of miles from their emissions point to contribute to poor air quality and exceedances of an NAAQS in downwind areas of the country. Areas affected. The CSAPR establishes SO 2 and NOx emissions reduction requirements for power plants in 27 states, but supplemental rulemaking also requires ozone season emissions reductions in some states, bringing the total number of states regulated under the CSAPR to States may opt to replace the federal implementation plan with state regulations that are approved by the EPA and incorporated into the SIP.
However, sources subject to both the CSAPR and the Acid Rain Program will have separate allowance accounts to comply with each rule and cannot use allowances from one program to comply with the other.
The affected sources under the CSAPR cap-and-trade program are any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, on or after January 1, , a generator with nameplate capacity of more than 25 MW and producing electricity for sale. Under the cap-and-trade program, the EPA allocates emissions "allowances" for SO 2 and NOx to each state, which are then distributed to affected sources for use or trade.
To remain in compliance, each affected source must hold sufficient allowances to cover its emissions for the given compliance period annual or ozone season , but the source may choose how to comply from several alternatives, including installing pollution control equipment, switching fuels, or buying excess allowances from other sources that have reduced their emissions. Each state administers a permitting program for the construction of new sources and the modification of existing sources.
In most cases, the state programs extend permitting requirements to sources that emit below the major source thresholds, although the requirements may differ significantly from the major source requirements. In addition to the Title V program for major sources, states may also administer operating permit programs for sources that emit below the major source thresholds, although the requirements may differ significantly from the Title V requirements. Under the Clean Air Act, state regulatory agencies may develop general permits applicable to source categories that have similar operations, emissions, or regulatory requirements.
The general permit contains conditions that will be applicable to all sources within the applicable source category that wish to utilize the general permit, i. General permits undergo public review before becoming available to industry. Therefore, there is no requirement for public review before issuing general permits to individual sources.
This, combined with the preestablished permit conditions, requires less time for agency review of applications, which leads to lower costs for both the agency and industry. Federally enforceable means all limitations and conditions that are enforceable by EPA.
Examples of federally enforceable limitations and conditions include. Enforcement authority. EPA maintains the ultimate authority for enforcement of the federal CAA, even if authority to implement and enforce certain regulatory programs is granted to the state regulatory agency.
EPA has stated in guidance documents that under Title V "federally enforceable" should be read to mean "federally enforceable or legally and practicably enforceable by a state or local pollution control agency" pending future rulemaking by EPA.
Previously, EPA relied solely on reference test methods as the means of demonstrating compliance with various emissions limits. A source's emissions can be constantly monitored by any number of variables.
More specifically, the rule allows EPA, state regulators, or private citizens to use data obtained from such methods as credible evidence in enforcement actions. Industry groups opposed to the rulemaking claim that the new evidentiary standard provides no definitive test to measure compliance and that it opens the door for any number of citizen suits and endless litigation.
EPA has attempted to calm fears by assuring industry that its focus will be on threats to public health and the environment and long-term threats that show a pattern of noncompliance, involve criminal conduct, or indicate illegal competitive advantage.
Facilities may also use any credible evidence to disprove alleged violations. The following are some suggestions that have proven valuable in managing an inherently prolonged and complex permitting process as painlessly as possible:. Make sure that your state-issued air permit is in sync with federal requirements. Federal authority to overrule state air permit decisions was substantially bolstered in a recent decision by the U. Supreme Court. Cominco applied for a PSD permit to increase nitrogen oxide NOx emissions in order to boost zinc production at a mine north of the Arctic Circle.
The proposal, which ADEC accepted, called for bypassing best available control technology BACT requirements for a generator and installing less expensive Low NOx technology on all of its existing generators, including those not subject to BACT, and on a proposed seventh generator. Allowances will be reduced to 15 tons beginning in However, because of the banking of emissions, annual emissions are expected to remain over 15 tons for some time after EPA c.
The caps are not expected to cause electricity-generating facilities to adopt strategies that lower national SO 2 and NO x. We are not expressing any judgment about whether the agency chose the caps correctly.
Clear Skies th Cong. Clear Skies would reduce NO x emissions from 5 million tons in to 2. The Clear Skies legislation would also codify the trading program proposed by WRAP to prevent degradation of visibility in the Southwest. Clear Skies has provoked opposition from the electricity-generating sector and other industrial groups, which say that the goals are too stringent, and from environmental groups, which contend that they are too lax.
Neither of those proposals has been endorsed by committee or reached the floor of the Senate or the House of Representatives, and their futures are unclear. In early , proponents of Clear Skies failed to persuade a majority of the Senate Committee on Environment and Public Works to report it to the Senate floor. That can occur because new sources must purchase allowances from existing sources.
If the emission cap is very tight, the cost of allowances will be high and operators of new sources might reduce their emissions lower than what NSR would require rather than purchase allowances. EPA, however, has not projected such an effect of CAIR except to the extent that the presence of a cap encourages investment in natural gas to reduce SO 2 emissions.
For similar reasons, it is unlikely that Clear Skies would reduce emissions from individual new sources. In addition, Clear Skies would exempt new electricity-generating facilities, and under certain conditions, it would exempt some modifying electricity-generating facilities from most NSR.
We are not expressing any judgment about the overall environmental effects of Clear Skies. NSR, as mentioned previously, requires new sources to meet strict technology-based standards as well as show that they will not damage air quality. In contrast, most existing sources those that do not go through reconstruction or modification need generally accomplish only as much emission reduction as is necessary to enable their locales to meet and maintain the NAAQS set by EPA; even those existing sources that are subject to the technology-based standard of reasonably available control technology RACT need not control as much as new sources.
That differentiation has attracted debate. Supporters assert that it is justified because new sources can most easily incorporate the latest pollution-control technology. In addition, supporters argue, tight regulation of new sources is the best way to ensure against future air-pollution problems and to guarantee that the turnover of capital stock results in reduced emissions.
Critics argue, by contrast, that the differentiation between old and new sources encourages industry to keep older, heavily polluting sources on line longer instead of building new, cleaner sources, thus potentially hindering environmental progress. Emission-trading advocates urge that it would be preferable to allow trading between sources, whether new or existing, to achieve the needed emission reductions.
Opponents of this suggested change argue that a trading approach by itself would not be sufficient to protect especially vulnerable areas from large new sources.
Alterations at existing plants pose an especially difficult question. Plants where physical or operational changes are occurring occupy a middle ground between new and existing sources. Inserting state-of-the-art technology when a source experiences a change is, at least sometimes, more problematic than including such controls in a new plant.
Plants where changes are occurring may often be better targets for regulation than unaltered existing sources. For instance, changes in existing plants, if unregulated by NSR, might keep such plants on line longer and slow their replacement with new, cleaner facilities.
On the other hand, it is also possible that regulat-. New electricity-generating facilities locating within 50 km of a Class I area, such as a national park, would have to conduct an analysis of the air-quality effects on the park.
Slowing replacement of existing plants may give them a competitive edge over new plants, therefore perpetuating high emissions. Furthermore, adding control technology at an existing source when it is undergoing modification may well be easier than installing such controls at an existing source that is not undergoing modification. For instance, a boiler modification will take a unit off line and thus make it possible to install, for example, an electrostatic precipitator with less disruption than trying to retrofit a unit not undergoing modification.
Those arguments are reflected in the different viewpoints about how the term modification should be defined. Environmental groups argue that a broad definition is needed because of the following:. Health and the environment may be endangered when existing sources increase emissions.
Narrowing the definition would interfere with enforcement actions that are permanently lowering emissions and thus bettering air quality. Congress intended a broad definition as a way of ensuring that older sources eventually would have to install the up-to-date pollution controls. A broader interpretation would discourage those renovations and instead lead to replacing the plants with new capacity that would be far cleaner than existing plants.
Industry groups counter by saying that a narrower definition is appropriate because of the following:. Many projects that would be covered under a broad definition do not increase emissions and in fact reduce them by replacing older equipment with less-polluting equipment. The programs are complex, and it is difficult to determine whether an NSR permit is required for a given change. Preparing a permit application, obtaining needed offsets, waiting for EPA or state officials to process the application, and complying with BACT for the modification may be expensive and burdensome.
The process of reviewing the application takes additional time that slows completion of the project. Other programs, such as caps on emissions from electricity-generating facilities, can constrain emissions at a lower cost than a stringent NSR program. That was done through a rulemaking in In , the D.
Circuit Court of Appeals in the Alabama Power decision overturned several important portions of the rules. EPA then promulgated new rules in 45 Fed. An increase in emissions was defined in terms of an increase in actual annual emissions, taking into account contemporaneous increases and decreases in emissions.
Emissions before the change were specified to mean the average emissions at the source over the previous 2-year period unless the source could show that a different consecutive 2-year period was more representative of normal source operation. The plant owner can escape coverage only by making a binding promise never to increase actual emissions significantly over prechange emission levels.
The Puerto Rican Cement case illustrates the workings of the test. The company planned to build a new cement kiln.
But if the unit operated at full allowable capacity, it would emit 1, tons of NO x and 1, tons. The statute does not expressly exclude routine maintenance. Presumably, as recently suggested by the D. EPA , F. This represented its potential to emit. EPA compared the latter numbers with the prechange annual tonnages of 1, and 1,, respectively, and ruled that construction of the new kiln would increase emissions within the meaning of its regulations and that, therefore, a PSD permit was required.
The U. Instead, the court reasoned EPA had decided to focus on the possibility that the introduction of new, more-efficient equipment would lead a company to produce at higher levels and therefore increase emissions. For instance, the court suggested, it might be irrational to assume that a replaced peak-load generator would run at full capacity.
Reilly , F. The plant consisted of five coal-fired steam-generating units placed in service in the period Over time, each had deteriorated from its design capacity of 80 megawatts MW , and one unit had been shut down because of the risk of catastrophic failure. The aim of the project was to keep the units operating until beyond their original retirement date.
As part of the project, WEPCO planned to replace air heaters, steam drums, and other major components on four units. EPA ruled that a PSD permit was required on the grounds that the project did not constitute routine maintenance, repair, and replacement and that it would increase emissions according to the actual-to-potential test. Hence, the dispute involved both the physical change and the emissions-increase aspect of modification.
The electricity-generating facility appealed to the U. Court of Appeals for the Seventh Circuit, which decided for EPA on the physical-change issue, although holding that the project would not increase emissions for NSR purposes. Reilly , The court held that, in contrast, actual annual emissions must increase for a project to be subject to NSR.
The court found it unreasonable for EPA to disregard past operating conditions at the plant and to regard the units as having never entered normal operation.
This rule excludes electricity-generating facilities from the actual-to-potential test as long as the proposed project neither adds a new unit nor replaces an existing one. Instead, the facility may compare prechange actual annual emissions with postchange projected annual emissions. If the electricity-generating facility concludes that there would be no significant increase in emissions, thereby exempting the project. In addition, the calculation of postchange emissions may exclude emission increases attributable to increased market demand rather than to the physical or operational change; this exclusion can apply to increases that legally and physically would have been feasible without the change.
EPA also altered the definition of prechange emissions for electricity-generating sources. Before the alteration, prechange emissions were calculated by averaging emissions over the 2 years before the change unless the source could show that a different 2-year period was more representative.
EPA changed the rule to allow electricity-generating sources to use any consecutive 2-year period in the preceding 5 years. Instead, as discussed later, EPA in issued a rule defining certain activities as exempt from NSR because they did not constitute physical or operational changes. Those changes were confined to electricity-generating facilities because EPA believed that it did not have enough knowledge of other source categories to allow the changes to be extended to them.
It formed a subcommittee of its Clean Air Act Advisory Committee composed of representatives of states, environmental groups, and industries. For several years, the subcommittee members discussed possible changes in the rules.
The proposal discussed the topics later covered in the rule for example, expanded use of the actual-to-projected-actual method , although the rule differs in important respects. The proposed. The proposal generated a great deal of comment. EPA did not complete the rule-making process before the end of the Clinton administration in January That issue became increasingly important in the late s. EPA, often joined by environmental groups and northeastern states, asserted that some large electricity-generating plants had been undertaking modifications without obtaining NSR permits.
According to EPA, those projects allow electricity-generating facilities to run the altered plants at higher capacity and therefore to increase emissions. In addition, EPA claimed that the projects allow the plants to remain on line longer instead of being replaced by new, cleaner plants that would decrease emissions substantially from present levels. The agency contended that, under the multifactor test used in WEPCO, the electricity-generating facility projects did not qualify for the routine-maintenance exemption and instead constituted physical or operational changes that increased emissions.
Electricity-generating facilities, in contrast, argue that such projects should be considered to constitute routine maintenance, repair, and replacement and therefore exempt from NSR. The projects, according to owners of electricity-generating facilities, have always been undertaken in the industry and are necessary to ensure adequate and reliable generating capacity.
A report by the National Coal Council states that coal-fired power plants more than 20 years old—a category that accounts for two-thirds of electricity generation from coal—have been derated reduced in power-generating capacity and that a substantial amount of generation capacity about 20, MW could be regained by addressing the causes of derating EPA EPA brought enforcement actions against electricity-generating facilities, alleging that the companies had undertaken major modifications without obtaining required NSR permits.
Those actions and their status as of August are listed in Table The action against TVA eventually was judicially invalidated on.
Whitman, F. Both of the suits brought by environmental groups have been dismissed by the district courts on procedural grounds and are presently on appeal. Several of the actions have been settled, as shown in Table It is possible that some of these reductions might have been required by other programs under the CAA, such as the NO x SIP call, although in many cases, the settlements brought about the reductions sooner.
Each settlement agreement requires the source to surrender SO 2 emission allowances annually. These surrenders would not have been required by other programs. Surrendered allowances are retired by EPA, and thus become unavailable for use by other sources. Similarly, the required reductions in NO x may not be used to generate NO x credits that can be sold to other sources. There are two exceptions. First, if the source had more allowances than its presettlement emissions, it must surrender the surplus allowances in addition to the allowances represented by the emission reductions required by the settlement.
The principle, therefore, is that a source need not surrender allowances that are necessary to keep it in compliance with cap-and-trade programs. The surrender of allowances in effect reduced allowable emissions below those permitted by the Title IV acid-rain program. The number of allowances surrendered will probably be reduced under CAIR, because that program considerably decreases the amount of SO 2 that can be emitted under an allowance, so the settling sources will need to keep their allowances to be in compliance.
The settling sources, as well as those against which enforcement actions are pending, are all in the CAIR region. The same will be true if Clear Skies is enacted. Table also shows estimates of the capital cost of the required reductions. These costs are stated in dollars as of the date of the settlement, and. In , EPA reached an agreement in principle to settle its action against Cinergy, Inc; the agreement has not been incorporated into a consent agreement, so litigation between the electricity-generating facility and EPA continues.
United States and State of New York, et al. American Electric Power Service Corp. AEP, et al. Judge Bullock; Environmental Defense v. Duke Energy Corp. Moreover, the cost figures are not annualized; therefore, they cannot be used to generate cost-effectiveness numbers.
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