The commenter stated that it would be reasonable to expect that the timing of a Hg cap would not be very significant if two things could be assumed: ( 1) The implementation of the initial Hg cap coincides with any new SO 2 and NO x regulations   so that Hg reduction benefits resulting 9 85 from the installation of scrubbers and SCRs are available for complying with the Hg policy, and ( 2) There is sufficient time to install all compliance options ( and compliance options are commercially available) before the policy takes effect. The commenter stated that, unfortunately, neither can be assumed in this case. The commenter noted that under the MACT policy that EPA proposes, Hg regulation would be introduced two years before new regulations for SO 2 and NO x take effect. The commenter stated that this would result in unnecessary costs as coal units would need to comply with the Hg policy before controlling for SO 2 and NO x   lessening the ability of FGD and SCR co benefits to reduce the burden of Hg regulation. The commenter further stated that CCAP's results do not show this result because it modeled a different policy   Clear Skies   which requires new NOx controls to be in place fully two years before Hg regulations take effect ( 2008 vs 2010), and SO 2 controls to be in place at the same time Hg regulations take effect. According to the commenter, similarly, CCAP avoided genuine concerns over when ACI controls would become commercially available ( the commenter does not expect wide availability before 2010) and how quickly the U. S. coal fleet could be outfitted with ACI, FGD, and SCR controls by assuming everything would be universally available from the beginning of the run. The commenter stated that, therefore, any claim that timing does not matter is erroneous, predicated on modeling CSA as opposed to the relevant policies, and being over optimistic about the availability of controls.

The commenter stated that, likewise, it would be reasonable to expect that the stringency of Hg caps would not be significant if the cost of installing controls is low, the effectiveness of those controls is high, and the cost of substituting options other than coal fired generation is modest. The commenter, however, believed the cost of retrofits to be much greater than the estimates of CCAP, which used EPA assumptions, especially for the smaller units that would become the price setting units as the caps were made more stringent. The commenter also believed Hg EMFs to be larger ( i. e., the reductions smaller), and the cost of natural gas to be greater   which both increases the need, and the cost, of switching from coal fired generation to meet more stringent caps. It is the commenter's belief that more stringent caps would not be possible without greatly increasing the cost burden of Hg regulation.

Modeling Results Provided By CATF The commenter noted that the Clean Air Task Force (" CATF") performed two runs using EPA assumptions. The commenter stated that the first run shows CAMR MACT plus CAIR using EPA assumptions, which allows for a relatively direct comparison with the commenter's model results for CAMR MACT plus CAIR. According to the commenter, from this comparison, it is clear that EPA assumptions allow more pollution controls to be installed at lower costs than the commenter's assumptions allow   reducing the cost of regulation.

The commenter stated that the second run provided by CATF shows that EPA assumptions allow for a much more stringent MACT rate while significantly increasing regulatory costs by about 30 percent. The commenter further stated that this result is predicated on FGD and SCR combinations providing the 90 percent reduction needed for the stringent MACT for both bituminous and sub bituminous coal units. The commenter maintained that it is unlikely that an FGD and SCR combination could be depended on to meet such a strict standard, particularly for units burning sub bituminous coal. 9 86 Modeling Results Provided By EEI The commenter stated that EEI runs adopt the industry's view on FGD and SCR co benefits and other Hg emission factors, and therefore show higher annual Hg emissions under MACT policies than EPA assumptions produce. The commenter added that, in fact, EEI's forecast for emission levels are very similar to the emission levels shown in the commenter's filing. The commenter further added that even so, it could be said EEI's runs do not go far enough. The commenter believed EEI's assumptions for costs of emission control equipment were comparable to EPA's cost estimates. The commenter states that while energy demand growth assumptions were marginally increased from EPA's starting point, the growth rate is still fully one third below historical growth and far below what is likely to occur over the forecast period. The commenter further states that these assumptions serve to significantly reduce EEI's estimates of regulatory costs.

The commenter stated that, in sum, there are significant issues with the assumptions used by the other commenters in their modeling analyses, resulting in overly optimistic projections regarding control costs and achievability of reductions. Based on the foregoing, the commenter submitted that its assumptions are the most realistic and that its modeling, therefore, most accurately predicts the costs of the proposed rule as well as the achievability of the proposed timing. The commenter stated that EPA's final rule should include a series of analyses that factor in assumptions comparable to the commenter's assumptions.

Response:

EPA appreciates the commenters suggestions. A complete discussion of EPA's modeling of costs and energy impacts can be found in Chapter 7 of the Regulatory Impact Analysis. EPA also appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

The commenter ( OAR 2002 0056 5460) stated that ample evidence suggests that Activated Carbon Injection ( ACI) and other Hg control options are already commercially available. See Document ID No. OAR 2002 0056 3454 ( Institute of Clean Air Companies Comments); and No. OAR 2002 0056 2888 ( NESCAUM Comments). The commenter stated that given the evidence of commercial availability, EPA has not adequately explained its conclusion that ACI will not be available for commercial application until after 2010.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005). 9 87 Comment:

One commenter ( OAR 2002 0056 5548) stated that ACI or a similar Hg specific control technology will be necessary to meet any of the lower caps ( i. e., beyond co benefit reductions) under consideration ( e. g., EEl's 2015 cap or EPA's 2018 cap). However, many commenters have advocated that the allowance allocation adjustment factors for EPA's proposed Phase I 2010 cap ( or allowance adjustment factors proposed by others) continue on into later stages of the Hg program. Cinergy has stated that such allocation preferences should end with any cap beginning in 2015. The commenter agrees with Cinergy's position on this issue.

Response:

The final rule takes into account the different levels of mercury control that lignite, bituminous, and subbituminous coals can achieve using existing NOx and SO 2 controls and uses coal adjustment factors for determining the state emission budgets and determining unit level allocation under EPA's example allocation methodology for States. For further discussion see final rule preamble ( section IV. C. 4) and Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter ( OAR 2002 0056 5548) stated that ACI will be available for initial application by 2010 and for widespread commercial application by 2012 2015. EPA has staked its decision to lower the cap beyond co benefits on its expectation that " ACI technology would be available for commercial application after 2010 and that removal levels in the 70 percent to 90 percent range could be achievable." It is noteworthy that all of the modeling that EPA highlights in the NODA assumes some availability of ACI by 2010. In a July 20, 2004 report to EPA by DOE officials responsible for development of Hg specific control technologies such as ACI, DOE concluded " ACI works," but needs further demonstration, now underway, to be commercially available by 2010 2012. Hence, there is little question about the technology becoming available for all coal ranks.

The commenter believed that the issue of levels of control with ACI among coal ranks must be addressed. DOE reports that its near term goals remain to demonstrate 50 70 percent reduction on bituminous coals by 2005 and on lower ranks coals by 2007.6 Thus, DOE's near term goals do not show any variation by coal rank, and the later demonstration date of 2007 for lower rank coals is irrelevant for post 2014 application. To date, there is no basis to believe that DOE will not achieve its stated goals. As referenced in the NODA, early pilot testing of a COHPAC system on a bituminous unit ( Gaston) showed longer term testing removals of 78 percent, and ACI ( not COHPAC) testing at a subbituminous coal fired unit ( Pleasant Prairie) showed longer term testing removals in the range of 60 70 percent. Testing at two other bituminous plants ( Salem Harbor and Brayton Point) showed longer term removals at higher levels, although there are some concerns about whether either of these units is sufficiently representative for replication. 9 88 In its July report to EPA, DOE further states that its longer term goal is to demonstrate emission reductions of 90 percent by 2010. However, in the July presentation, its current projection (" DOE estimate for performance potential with ACI") for ACI/ COHPAC is 80 percent removal for a CS ESP bituminous unit, 70 percent removal for CS ESP and CS ESP/ FGD Dry subbituminous units, and 70 percent removal for all lignite units ( except that HS ESP/ FGD lignite units increase to 83 percent). It is these DOE projections upon which EPA is basing its proposed decision to implement a cap significantly lower than co benefits.

Based upon this information, the commenter believed that EPA must evaluate the equities of allowance allocation adjustments among coal ranks for post co benefits caps. The first risk to evaluate is technology/ compliance risk. There is a risk that the as yet unproven technologies upon which DOE relies will not work well, or will not work well at the levels predicted. However, this risk is generally equal among all coal ranks. The DOE currently has 41 field tests underway which will be completed by 2007. Of these 41 tests, 27 involve subbituminous or lignite coals. These extensive tests, the majority of which concentrate on low rank coals, indicate that DOE will be able to achieve its stated removal targets within the given timeframes. However, no coal rank has any more of guarantee that this will in fact come to pass than any other.

The commenter added that there has been short term testing is true for all coal ranks, and the fact that there might be a few more short term field tests for bituminous coal would seem to make little overall difference in technology/ compliance risk because there has been no substantial testing beyond short term field tests for any coal rank. Hence, the technology risks associated with DOE meeting its stated control technology goals remain equal among coal ranks.

The commenter also noted that there is no greater compliance risk for any coal rank because each coal rank has an available " backstop" technology that will allow it to comply. Bituminous units can install FGD to reach 60 percent removals, and subbituminous units can install FF to reach 65 percent removal ( CRA 2004 EMFs). The commenter did not believe there is any plausible basis to mandate these control technologies now solely for Hg removal, as EPA has concluded, when developing Hg specific control technologies show such promise and greater cost effectiveness. However, that conclusion becomes less appropriate for any post cobenefits caps. In the event that technology risk impacts one coal rank but not another in the compliance year, either coal rank has an available backstop compliance option, and therefore compliance risk remains equal among coal ranks for the later caps and cannot justify application of any allowance allocation factors ( the fact that the backstop technology for either coal rank may cost more than an ACI based alternative is not a relevant basis to adjust allocations because both subbituminous and bituminous coal users share equal technology development risk ACI, and their backstop technologies are both within the same range of cost effectiveness) .

Based on the above information, the commenter believed that EPA clearly cannot support an allocation adjustment ratio whereby bituminous coal is assigned a factor of 1 and lower ranks coals are assigned higher factors for post co benefits caps because that approach assumes that bituminous coals have no technology compliance risk, and that lower rank coals have greater technology/ compliance risk, which is simply not true. As well, an allocation ratio of 1.25 for subbituminous and 3 for lignite, and seemingly derived for a co benefits approach, bears no relationship to whatever differing levels of risk might be perceived among the coal ranks for Hg specific control technologies that have not been commercially deployed ( the control 9 89 differences are nominal ( 10 percent) and do not warrant those allocation ratios). Thus, there is nothing that is either " directionally correct" or " equitable" in awarding extra allowances to low rank coals that bears any relationship to the technical and compliance risks among coal ranks for post co benefits caps.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005). EPA's IPM modeling assumption for ACI are based on EPA's Office of Research and Development ( ORD) assessment. Although modeled in IPM to be available immediately for all coal fired generation as a simplification of modeling, ORD assessment concluded that ACI could not be fully deployed on all plants by 2010 timeframe.

The final rule takes into account the different levels of mercury control that lignite, bituminous, and subbituminous coals can achieve using existing NOx and SO 2 controls and uses coal adjustment factors for determining the state emission budgets and determining unit level allocation under EPA's example allocation methodology for States. For further discussion see final rule preamble ( section IV. C. 4) and Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter ( OAR 2002 0056 5548) noted that there is a 10 percent difference between DOE's removal targets for ACI applied to bituminous coal ( 80 percent) and the lower rank coals ( 70 percent) ( all ranks share an equal risk that these levels will not be achieved in practice). The difference between these controls levels is both small ( 10 percent) and equal to or above the nominal required reduction ( an aggregate 70 percent reduction in Hg for EPA's 15 ton cap). The commenter was not aware of any compelling reason to subsidize low rank coal users that may have nominally different control costs. Nor is the commenter aware of any compelling reason for EPA to require bituminous coal users to provide that subsidy ( in the form of lost allowances due to allocation ratios) to users of the other coal ranks.

The commenter was not aware of any policies or reasons supporting such subsidy because they appear not to have happened under similar circumstances. Thus, the commenter is not aware that EPA considered subsidizing bituminous coal under the CAIR because it would cost users of that coal rank significantly more to meet SO 2 caps than users of subbituminous coal. Nor is the commenter aware that EPA considered granting bituminous coal users extra SO 2 allowances under CAIR to help prevent such users from switching to subbituminous coals to meet their SO 2 requirements.

For similar reasons, the commenter found no plausible, equitable basis for awarding such subsidies here. If the market finds it more difficult or expensive to control Hg emissions from lower rank coals than from bituminous coals it will decide whether to buy allowances to cover 9 90 that shortfall, or it will switch coals, which is how it resolved control issues under Title IV ( Acid Rain) of the Clean Air Act Amendments of 1990, how it will resolve control issues under CAIR, and how it should resolve control issues under the Hg rule.

It is also important to note that a 70 percent Hg reduction for subbituminous coal results in essentially the same emissions as an 80 percent reduction on bituminous coal. The mean Hg content in subbituminous coal is 5.74 lb/ TBtu, and the mean Hg content for bituminous coal is 8.59 lb/ TBtu. If Hg emissions from each coal are reduced by 70 percent and 80 percent respectively, the resulting Hg emissions are 1.722 lb/ TBtu for subbituminous and 1.718 lb/ TBtu for bituminous coal, or no difference at all. In fact, on a risk basis, the less homogeneous nature of bituminous coals means that these equal aggregate numbers underestimate the greater reduction risk associated with bituminous coals.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The final rule takes into account the different levels of mercury control that lignite, bituminous, and subbituminous coals can achieve using existing NOx and SO 2 controls and uses coal adjustment factors for determining the state emission budgets and determining unit level allocation under EPA's example allocation methodology for States. For further discussion see final rule preamble ( section IV. C. 4) and Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter ( OAR 2002 0056 5548) noted that, in the NODA, EPA presented the results of a number of attempts to model the impact and costs of various proposed Hg rules. The significant divergence in the modeling results, even for ostensibly similar regulatory scenarios, demonstrates the fundamental problem in devising this rule given the high degree of uncertainty in the model inputs and assumptions. It argues strongly in favor of the commenter's original recommendation, to defer setting a hard cap until adequate information is available about the performance and cost of co benefit and Hg specific control technologies.

First, the commenter did not believe that EPA's, EEI's or Cinergy's model inputs are quite right, although each has developed appropriate inputs for individual components. The commenter also did not believe that EEI's model is correct because it has apparently assigned little or no cost to switching to subbituminous coal for SO 2 compliance, while both EPA and Cinergy have assigned costs to that action. This would tend to underestimate the level of FGD installation needed for compliance with the CAIR, and therefore underestimate co benefits. Hence, the commenter believes that either EPA's or Cinergy's inputs on the cost for coal switching should be used, and generally believes that Cinergy's formula presents a more comprehensive approach, although there may be little difference in results between Cinergy's or EPA's inputs.

Next, the commenter believed that EPA has significantly underestimated the cost of 9 91 control equipment. This would tend to overestimate the number of FGD units that would be installed to meet the CAIR, and hence overestimate co benefits. The commenter also believed that either EEI's numbers or Cinergy's pollution control cost numbers better reflect current reality. These two variables, plus the EMF factors, are what will most influence the final estimate of co benefits reductions, cost and performance. The commenter had no comment on growth numbers.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. See comment response above for EPA's response to commenter's criticism of EPA modeling. EPA agrees with the commenter that modeling that shows costs for coal switiching is a better representation of costs.

Comment:

One commenter ( OAR 2002 0056 5497) stated that in order to respond to this question, it is important to define what is meant by " availability." Four stages of development must be recognized in this context: ( 1) tests, ( 2) demonstrations, ( 3) commercially available at individual units, and ( 4) commercially available for the entire utility system. For a nationwide rulemaking that imposes controls on the entire population of coal fired boilers in this nation, commercial availability for the entire system of boilers in this nation is the most important issue.

A test is a short term evaluation of Hg removal as a function of different variables, such as injection rate of activated carbon, flue gas temperature, etc. and may gather information for a few hours to up to 30 days. A test might identify obvious balance of plant impacts, but not subtle impacts that will require more operating time. In the context of the ACI work completed to date, the commenter considered all field work with ACI/ ESP to be tests. A demonstration requires one to two years of operation, including an assessment of impacts on the plant that require the accumulation of significant operating hours. Commercial availability at a unit scale is where a utility can purchase an individual or limited number of processes, and receive credible performance guarantees. Also, unit scale Hg controls may only be commercially available for certain boiler types, unit configurations, or fuel types. The purchaser can access an experience base assuring risks to operation are commensurate with other aspects of plant operation ( e. g., the process does not risk operations any more than usual activities). Finally, commercial availability at the system scale requires both commercial availability at the unit scale, and the necessary infrastructure to provide reagents, construction material and manpower, and transport of key process requirements for the entire population of boilers. System availability is the ultimate goal that must be achieved to enable broad utilization of a technology.

The commenter had provided an estimate of the availability of ACI technology for each of these four stages of development. The earliest that any technology will be available on a system basis is 2011 and for some configurations of coal type, control technology and Hg reduction level availability on a system basis will not be achieved until 2014.

Finally, the utility industry has had many experiences that have demonstrated why several 9 92 years of demonstration effort are required before a new control technology should be applied broadly. For example, hot side ESPs were deployed without sufficient experience and resulted in many unanticipated problems. In the mid 1970s, the first hot side ESP applications on boilers firing western low sulfur coal found persistent particulate matter removal shortfalls, in contrast to performance predictions and guarantees offered by suppliers. Research was initiated in the early 1980s to provided an explanation of this behavior, which resulted in a solution five years after the problem was first identified and long after these ESPs were in commercial service.

This experience is significant for ACI, especially in applications at units with smaller ESPS. Carbon particles or fly ash co mingled with carbon may quickly accept   and then ultimately lose   the electrostatic charge so that a certain fraction of carbon injected could be released from the plate before rapping, to be either re entrained or to disturb the quiescent zone within the collection hopper. This complication has not been observed with ACI demonstrations to date for two reasons. First, the ESP units employed in the demonstration tests exhibit relatively generous specific collecting area so that any carbon material that eludes collection in the first few fields is ultimately collected in later fields. Second, the duration of tests has been limited. It is not clear how long it will take to establish steady state conditions within the collected ash layer. As demonstrated with the hot side ESP experience, steady state conditions with respect to electrical properties of the entire layer of ash must be established, not simply the outer layer adjacent to the flue gas.

The commenter suggested for these reasons, it would be imprudent to require the deployment of insufficiently demonstrated technologies to the entire population of coal fired utility boilers and to potentially jeopardize the reliability of the electricity supply in this nation.

Response:

EPA appreciates the commenter's input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

5. EEI estimated that ACI would be less expensive per pound of Hg removed than EPA estimated. Cinergy assumed higher capital costs for ACI than EPA. Are EPA's Hg control cost assumptions reasonable? EPA is seeking additional detailed data addressing the validity of the cost assumptions for ACI.

Comment:

One commenter ( OAR 2002 0056 5475) noted that highly effective Hg control technologies are available and cost effective. Two companies that supply bromated activated carbon injection ( B ACI) for utility power plants offer removal rate guarantees. The ACI industry reports that there is a sufficient supply of activated carbon to supply the anticipated demand for Hg control by the regulated industry. More than 800,000 tons of activated carbon are currently produced worldwide annually. The technology has proven to be more cost effective than initially thought by EPA. The cost of ACI has been reported to be ranging between $ 2,000 and $ 20,000 per pound of Hg removed, much less than the control cost of $ 50,000/ lb that was considered in 9 93 the proposed rule. The B ACI technique has reduced the amount of activated carbon necessary to create the same effect. By reducing the amount of activated carbon needed the B ACI technology will have a significant impact on the results of IPM modeling included in the proposed rule. This commenter stated that the impact from the use of B ACI will serve to positively enhance the economic viability of Hg control under MACT. It would also address any potential concerns regarding sufficient availability of activated carbon.

Response:

EPA appreciates the commenter's input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5510) stated that EPA should analyze supply and price response to demand created by the various ACI scenarios. The current supply of activated carbon is not sufficient to accommodate a substantial demand from the utility sector and it could take up to five years to bring activated carbon production facilities on line.

Response:

Given that the first phase cap is set at the Hg co benefits of CAIR, EPA does not project significant amount of ACI to be retrofitted until the 2018 timeframe. With regard to demand for activated carbon, EPA notes that markets respond to the demand for materials, much like under the NOx SIP call supply for catalyst increased with demand. See Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipollutant Strategies, EPA, October 2002, in docket.

Comment:

One commenter ( OAR 2002 0056 5488) stated that halogen impregnated sorbents have been shown to dramatically improve the effectiveness of sorbent injection systems, particularly for sub bituminous and lignite coals. These systems are also commercially available, as evidenced by the fact that construction of the subbituminous coal fired unit 4 of MidAmerican Energy's Council Bluffs power plant is moving forward under a permit that relies on their use or use of an equivalently effective control method. This unit was permitted with the condition that it achieve a high degree of Hg reduction, which was deemed achievable based on test results obtained for lignite coal with iodine impregnated carbon.

The combination of sub bituminous coal with a spray dryer for SO 2 removal has been viewed as a challenging configuration for Hg control, because the spray dryer is thought to remove halogens that are needed to enhance Hg capture from the flue gases. However, in recent tests at Sunflower Electric's Holcomb Station, 77 percent Hg removal was achieved through injection of a proprietary halogen treated sorbent offered by NORIT Americas, at a very low injection rate of just 0.7 lb/ MMacf. The cost of the sorbent was just $ 0.65/ lb, making it much 9 94 more cost effective than either iodine impregnated carbon or injection of untreated activated carbon ( at higher injection rates). Of note, rates of Hg capture at the Holcomb Station were also boosted significantly simply by blending the sub bituminous coal with a western bituminous coal that had higher chlorine content.

Recent test results achieved with brominated powdered activated carbon ( B* PAC) are also impressive. B* PAC has been tested at seven different power plants, including four full scale tests. Mercury removal rates ranged from 70 98 percent across a wide variety of coals and configurations. Researchers at DOE and Sorbent Technologies Corp. have estimated from these tests that with B* PAC costing about $ 0.75/ lb, Hg removal costs may be just 10 20 percent of DOE's baseline estimates.

Full scale tests with B* PAC have recently been conducted at Detroit Edison's St. Clair Power Plant, which typically burns 85 percent sub bituminous coal blended with 15 percent bituminous coal and is equipped with a cold side ESP. Mercury speciation upstream of the sorbent injection point is estimated to be 80 90 percent elemental Hg. Nevertheless, Hg removal rates of 90 percent or higher were achieved with B* PAC injection rates of just 3 lb/ MMacf, with no additional control equipment required. The B* PAC vendor estimates that with cold side ESP, 90 percent removal can be achieved at a cost of less than $ 9000 of sorbent per pound of Hg removed. Moreover, because B* PAC injection rates are so low, its use has negligible impact on characteristics of fly ash for use in cement.

Environmental Defense and Western Resource Advocates have produced a white paper entitled Mercury Air Pollution: The Case for Rigorous MACT Standards for Subbituminous Coal, which shows that there is no technical justification for a separate subcategory of Hg MACT standards for plants burning subbituminous coal. A copy of this paper was attached to our June 29, 2004, comments and is incorporated by reference herein. Although produced more than a year ago, that paper found that 90 percent Hg reduction is achievable at effectively the same costs irrespective of whether a plant burns bituminous or subbituminous coal or a blend of the two ( as is common practice), using activated carbon injection and either a fabric filter or an ESP with a compact baghouse for particulate collection.

Since that paper was issued in May 2003, many advances have been made in Hg control technologies. These technological advances, such as using halogenated sorbents in a sorbent injection system, advanced dry FGD, ECO technology, or even simply blending some higher chlorine bituminous coal at subbituminous or lignite fired power plants, are discussed in detail above. The pilot and full scale tests of these technological improvements continue to prove that high levels of Hg control can be cost effectively achieved at all coal fired power plants, regardless of the type of coal burned.

As mentioned above, the Iowa Department of Natural Resources( IDNR) recently imposed an emissions limit reflecting 83 percent reduction in Hg as MACT for a new unit burning subbituminous coal at MidAmerican Energy's Council Bluffs power plant. In doing so, the IDNR relied on results from a full scale test of activated carbon injection for Hg control at Great River Energy's Stanton Generating Station, which burns North Dakota lignite coal. Tests at Stanton found that on average 81 percent Hg removal could be obtained with the use of activated carbon and a spray dryer/ baghouse combination. Moreover, with the use of iodine impregnated activated 9 95 carbon, 97 percent Hg removal efficiency could be achieved. The IDNR determined that the subbituminous coal to be burned at the Council Bluffs plant was similar to lignite coal in terms of Hg emissions, and thus relied on the Stanton test to justify the MidAmerican permit limits. Subsequent tests at Stanton with B* PAC injection and the spray/ dryer baghouse combination have demonstrated nearly 90 percent removal with only 1 lb/ MMacf sorbent injection, at an estimated cost of only $ 2500 per pound of Hg removed. These tests demonstrate that the Stanton facility, burning lignite coal, could easily and cost effectively meet an emissions limit of 1 lb/ TBtu, almost a factor of 10 lower than EPA's proposed MACT for existing lignite facilities.

EPA's proposal to set disparate standards depending on rank of coal is thus unjustified and lacking in any reasoned basis. Moreover, the approach unfairly subjects those who live near power plants burning lower rank coal to much higher levels of Hg emissions. EPA must take into account recent information that shows technology is currently available to achieve high levels of Hg control on a cost effective basis regardless of the rank of coal to be burned and use this information to set uniform, protective standards.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The final rule takes into account the different levels of mercury control that lignite, bituminous, and subbituminous coals can achieve using existing NOx and SO 2 controls and uses coal adjustment factors for determining the state emission budgets and determining unit level allocation under EPA's example allocation methodology for States. For further discussion see final rule preamble ( section IV. C. 4) and Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005. EPA appreciates the commenter's input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter's ( OAR 2002 0056 5492) question: " EPA is seeking additional detailed data addressing the validity of the costs assumed for ACI."

The response to this question is divided into two parts: activated carbon availability and development of new sorbents.

Activated carbon availability: If the activated carbon industry converted to a 24/ 7 production scenario, then the productivity would conservatively lead to about 60,000 tpy of excess carbon available in the U. S. Assuming a 15 lb/ MMcfm activated carbon injection rate used in conjunction with CS ESP, the excess activated carbon production capacity could be used to control Hg emissions from about 6 GWe generating capacity. If one assumed that all units that were retrofitted with ACI also installed fabric filters, then the assumed injection rate would be lowered to about 1 lb/ MMcfm and about 105 GWe of capacity could be controlled using 9 96 activated carbon. Since EPA modeling suggests that about 2 GWe of ACI capacity will be required in 2015, the cost for commercially available activated carbon between now and 2010 should not be driven upward due to demand vs. supply constraints.

Other models project higher ACI installed capacity. In the Notice, EPA cited model results that projected 13 to 17 GWe of installed ACI capacity for cap and trade scenarios for 2010 annual Hg emissions between 25 34 tpy. For various MACT approaches, the installed ACI capacity was between 15 and 120 GWe. The worldwide excess production capacity is estimated to be 150,000 tpy of activated carbon. Depending on the injection rate, this would limit the installed ACI capacity to 15 22 GWe. Regulations which require more than 22 GWe of ACI capacity would cause a supply demand constraint and cause the price of activated carbon to increase in response to the demand. The activated carbon supply vs. the 2010 installed ACI capacity must be carefully studied.

Development of new sorbents; The activated carbon sorbent is the largest Hg control annual cost component. There have been numerous tests of brominated activated carbons on Powder River Basin and lignite coals. In those tests, significantly improved performance has been recorded. During a four week test program at the subbituminous coal fired, 360 MWe Sunflower Electric Holcomb Station, Hg removal increased from a baseline of less than 20 percent to over 90 percent for the entire period at injection rates less than 1 lb/ MMcfm. The projected cost of the sorbent is a factor of two higher than conventional activated carbons, but the usage rate is a factor of seven to ten less. This will result in a significant decrease in annual operating cost.

There is potential for activated carbon injection technology to reduce costs significantly, by a factor of 3 to 7 between now and 2010. Utilities can take advantage of improved carbon performance since they can change their carbon specifications after the equipment is installed.

Response:

Given that the first phase cap is set at the Hg co benefits of CAIR, EPA does not project significant amount of ACI to be retrofitted until the 2018 timeframe. With regard to demand for activated carbon, EPA notes that markets respond to the demand for materials, much like under the NOx SIP call supply for catalyst increased with demand. See Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipollutant Strategies, EPA, October 2002, in docket.

Comment:

One commenter ( OAR 2002 0056 5571) stated that while the technology vendors participate in conferences and announce the viability of control technologies ( mostly Activated Carbon Injection) for ~ 200 MW units, there have been known and guaranteed controls at < 200 MW units. Worse, virtually no vendors have focused on < 100 MW units. This commenter fully supported the comments submitted by UARG and the study conducted by Charles Rivers Associates ( CRA) on the inadequacy of a three year period for complying with EPA's MACT limits. EPA has the discretionary authority to extend the compliance deadline by a year. This commenter believes that EPA should use its discretionary authority under § 112( i)( 3)( B) and extend the deadline by a year for all units, and it should assist public power utility units needing 9 97 even more time in obtaining presidential extensions on a case by case basis.

The process of funding and installing a major retrofit is different for small public power systems than for larger investor owned systems. Public power units must normally obtain financing through publicly approved bonds. This is not a process that moves quickly, nor is it one with a guarantee of success. Once the funding approval process is completed, these small units most then compete with large, privately held units to obtain services from vendors of emission control equipment and to procure skilled labor to install that equipment. An equipment vendor is far more likely to be responsive to a large utility ( often an investor utility) seeking a number of multi million dollar retrofits than to a small public system with an environmental compliance staff of one or two Full time Equivalents ( FTEs) and a limited compliance budget.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. Given that EPA is finalizing a cap and trade approach, the program would not necessarily require the installation of coantrols on units less than 100 MW.

Comment:

The commenter ( OAR 2002 0056 5404) stated that currently, most power plants market some of their fly ash for use in ready mix concrete and other beneficial applications. The commenter added that some plants with scrubbers market gypsum produced in the wet flue gas desulfurization ( FGD) process for use in wallboard fabrication.

The commenter noted that as explained in their June 24 comments and the comments of others, installation of an activated carbon injection system to control Hg emissions would cause elevated carbon levels to prevent these beneficial uses of power plant fly ash. The commenter stated that activated carbon that has the greatest capture efficiency is in the 4 8 micron range. The commenter added that most of this activated carbon will be captured by the plant's ESP or fabric filter, and thus will be present in the fly ash. The commenter further added that testing experience has shown that, because of the small size of these carbon particles, some of the activated carbon is carried through into the scrubber system. The commenter stated that the presence of carbon in either fly ash or the gypsum produced by wet scrubbers is highly problematic to beneficial reuse.

The commenter stated that fly ash can be utilized as a substitute for cement in ready mix concrete   but to do so, it needs to comply with ASTM C618, which specifies the maximum acceptable carbon content for concrete filler applications. The commenter added that it is necessary to limit carbon content in concrete because carbon reduces the strength of the concrete and causes premature failure. The commenter noted that this result occurs because carbon inhibits air entrainment in the concrete. The commenter stated that air increases the strength of concrete and reduces the permeability of the concrete. ( The commenter noted that fly ash reduces the amount of Portland cement that needs to be used in the concrete.) According to the commenter, state transportation departments typically tighten the maximum allowable carbon content as compared to the ASTM standard. The commenter notes that the ASTM standard for 9 98 carbon content of concrete filler, as well as two state DOT specifications, are shown in Table 2 below.

The commenter notes that gypsum produced in wet flue gas desulfurization ( scrubber) processes is used in construction materials and wallboard. The commenter also notes that a portion of the gypsum is also used to produce spackling or " mud" for wallboard installation. The commenter further notes that for cosmetic reasons, gypsum needs to be high purity and white in color. The commenter added that, however, even very small levels of carbon in wallboard will cause the paper to peel, making the wallboard unusable. The commenter stated that, accordingly, to be usable, the gypsum material quality needs to be high with very small amounts of carbon. The commenter noted that gypsum specifications for wallboard use also are set forth in the table below. The commenter pointed out that, as noted above, however, because of the small size of the ACI carbon particles, some carbon will inevitably bleed through to the scrubber, resulting in gypsum product degradation ( and, as discussed in the commenter's June 24 comments, potential catastrophic scrubber foaming issues).

Table 2. Carbon Content Specifications for Product Streams Concrete/ Constructi on Pennsylvania Department of Transportation Texas Department of Transportation Wallboard Ash ASTM C618 < 6 percent ASTM C618 and < 4 percent ASTM C618 and < 3 percent NA Gypsum * NA NA *

* gypsum specification is  92 percent CaSO4 and  2 percent total inerts. Inerts include a combination of ash, limestone minerals and carbon.

The commenter stated that recently, some representatives of the control technology industry have claimed that the problem of increased carbon levels in fly ash and scrubber gypsum has been " solved." The commenter stated that, for example, one company has been aggressively marketing a brominated activated carbon technology. According to the commenter, they claim that, because the bromination results in less carbon being needed to achieve Hg removal, there is no issue of increased carbon levels in fly ash with this technology. The commenter stated that these assertions are, to date, unproven.

The commenter stated that this company has not claimed that anything in its process eliminates increased carbon levels in fly ash; it simply reduces the total amount of carbon used in the injection process. The commenter further stated that, however, carbon levels may still exceed ASTM or State standards ( or the specifications of the companies that are accepting the fly ash)   and may still be high enough to lower the structural stability of the concrete. The commenter stated that this is particularly the case because the DTE St. Clair plant on which the company's ACI was tested included an inordinately large ESP, one of the largest in the industry. The commenter stated that, indeed, this ESP was 700 SCA, as compared to much smaller ESP with an average size of 200 250 SCA for the rest of the industry. According to the commenter, as a result, the St. Clair plant was able to achieve a higher removal efficiency with a lower level of carbon injections than would be expected from most power plants, raising further concerns about 9 99 the actual levels of carbon that would be present in the fly ash. The commenter stated that, in addition, the tests at St. Clair were of very short duration and are not of sufficient length to be considered " commercial operation."

The commenter stated that even if the ash meets ASTM specifications, does not impact the structural stability of concrete and would otherwise be acceptable to concrete manufacturers, the levels of carbon present in the ash would discolor the concrete   and thus almost certainly render it unacceptable to most concrete manufacturers. The commenter added that, similarly, as noted above, even trace amounts of carbon ( which certainly would be expected even from the smaller amounts of brominated ACI proposed by the company) would render scrubber waste unusable as gypsum. The commenter stated that, thus, even if the carbon issue could be solved with respect to fly ash, it would not be solved with respect to scrubber gypsum.

The commenter stated that, in sum, the control technology industry has not yet come close to proving that the issue of increased carbon levels in fly ash is solved. The commenter added that yet a single power plant can generate thousands of tons of fly ash and gypsum per day, and if those wastes cannot be beneficially reused, they must be disposed of. The commenter further added that the cost and adverse environmental effects associated with that disposal would be further exacerbated by the fact that building materials and wallboard manufacturers would be forced to purchase natural gypsum instead of reusing the plant's byproducts. The commenter stated that, also, the more plants that are required to install activated carbon injection, the less gypsum would be available for use in wallboard manufacture   and the more mining that would be required. The commenter further stated that this major increase in mining activity would have additional significant adverse environmental impacts. The commenter stated that, finally, vast amounts of activated carbon will need to be produced and transported to support wide spread application of ACI technology for the control of Hg emissions. Accordingly, notwithstanding recent developments in ACI technology, the commenter believed that it would be inappropriate for EPA to base its Hg removal program on broad use of ACI without first considering the serious environmental impacts associated with disposal of millions of tons of new solid waste per year, as well as the environmental impacts associated with production and transport of activated carbon, and the mining of gypsum to replace that which currently comes from scrubber gypsum. The commenter stated that indeed, § 112( d)( 2) and § 111 ( d) both specifically require EPA to consider such " non air quality health and environmental impacts" when setting standards, thus mandating that EPA consider such effects before it can set standards that would require ACI.

Response:

EPA appreciates the commenter's input to the record on the status of control technologies. EPA also notes that ACI with a pulse jet fabric may be installed upstream of wet scrubber. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005). Given that the first phase cap is set at the Hg co benefits of CAIR, EPA does not project significant amount of ACI to be retrofitted until the 2018 timeframe. With regard to demand for activated carbon, EPA notes that markets respond to the demand for materials, much like under the NOx SIP call supply for catalyst increased with demand. See Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipollutant Strategies, EPA, 9 100 October 2002, in docket.

Comment:

One commenter ( OAR 2002 0056 5548) stated that the cost of activated carbon could significantly increase if the demand exceeds the supply. Depending on the final carbon specifications, the annual excess activated carbon capacity is 60,000 tpy ( US), 30,000 tpy ( Germany), and 60,000 tpy ( China) for a total worldwide excess capacity if 150,000 tpy. EPA's IPM modeling projects that 13 GWe of ACI could be installed by 2010. At a 15 lb/ MMacf injection rate, 13 GWe of capacity is equivalent to a consumption of 130,000 tpy of activated carbon. This is about 87 percent of the worldwide excess capacity. At a 10 lb/ MMacf injection rate, 13 GWe of installed ACI would consume about 87,000 tpy of activated carbon or 58 percent of worldwide excess capacity. This analysis assumes that ACI is installed only on units equipped with CS ESPs ( a conservative assumption). If a significant fraction of units were equipped with FF, then the carbon injection rate would be lowered to 4 to 5 lb/ MMacf. If all units retrofitted with ACI were equipped with FF, then the projected annual carbon usage would be 43,500 tpy, which is 72 percent of the excess US capacity.

If ACI installations were to exceed about 15 20 GWe, then the demand for activated carbon would exceed the supply and the delivered cost could increase dramatically. Greater demand could be offset by the construction of additional activated carbon production capacity. For example, RWE is one of the world's leading producers of activated carbon. Their product, " HOK," has been tested successfully for Hg reduction at power plants in the U. S., and is used for similar purposes in Europe. According to Juergen Wirling, RWE's international sales manager, " if appropriate supply and purchase agreements are concluded and economic efficiency is given, an [ additional] annual delivery quantity of over 100,000 tonnes of Activated Lignite will be possible. A prerequisite here is that for sales planning purposes or the initiation of measures aimed at stepping up production, a minimum lead time of three to four years will be available. The [ RWE] annual production capacity of Activated Lignite already amounts to approx. 200,000 tonnes today. The raw material lignite is extracted from the Group's own surface mines, so that, in this respect too, sufficient security is provided."

These data indicate that, while the supply of activated carbon is marginally sufficient to meet projected near term needs of about 10 GW capacity, there is reason for concern if ACI installations exceed expectations, and for the adequacy of longer term supply, if levels of ACI usage reach those projected by various modelers. EPA should consider explicitly the elasticity of ACI supply and demand in modeling the cost of ACI applications.

A second issue is the development of promoted ( e. g., brominated) activated carbons. According to NORIT, brominated carbon would cost about 30 percent more than the current NORIT FGD costs of about $ 0.50/ lb delivered, or $ 0.65/ lb to $ 0.70/ lb delivered. However, if, as projected based on recent research, the brominated carbon dosage is one seventh the standard carbon dosage for equivalent Hg removal, the cost of ACI would be significantly lower using brominated activated carbon. Assuming a 10 lb/ MMacf dosage for NORIT FGD and $ 0.50 lib carbon cost and a 1.42 lb/ MMacf dosage for the brominated carbon and a $ 0.70 cost, the use of brominated carbon would lower the sorbent cost by a factor of five. 9 101 There have been a number of intermediate term ( two week to one month tests) tests of brominated carbon. The Hg removal at a site burning PRB coals and equipped with a SDA/ FF averaged 93 percent at an injection concentration of 1.2 lb/ MMacf. The results support the significant reduction in carbon dosage rate. At the recent PowerGen Conference, Hg reduction vs. injection rate performance data were presented. For a plant burning PRB coal and equipped with a CS ESP, > 90 percent Hg reduction was achieved at a brominated carbon injection rate of about 1.5 lb/ MMacf. This is significantly better performance than NORIT FGD, which achieved 75 percent reduction at an injection rate of about 6 lb/ MMacf. For a 500 MWe boiler with a SDA/ FF burning a PRB coal, the NORIT FGD would cost $ 4,000,000 per year and the NORIT brominated carbon would cost $ 1,000,000 per year. The Hg removal cost effectiveness was lowered improved from $ 8,000/ lb to $ 2,000/ lb. Questions remain about the environmental impact of using brominated sorbents, but the performance and cost improvements suggested by these results warrant further evaluation. EPA should evaluate the cost impacts of advanced sorbents using the IPM model because significant advances in sorbent technology are occurring.

Response:

Given that the first phase cap is set at the Hg co benefits of CAIR, EPA does not project significant amount of ACI to be retrofitted until the 2018 timeframe. With regard to demand for activated carbon, EPA notes that markets respond to the demand for materials, much like under the NOx SIP call supply for catalyst increased with demand. See Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipollutant Strategies, EPA, October 2002, in docket. EPA has included the examination of technology improvement in its analysis of the costs of the final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of a second ACI using advanced sorbents, leading to lower capital costs. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5497) stated that it was inappropriate for an economic forecast to assume a decrease in fixed capital costs of Hg control technologies. The utility industry learned from its experience with SCRs that EPA's and state regulators' early estimates were far lower than actual capital costs. This is relevant because, like SCR, plant specific ACI costs and balance of plant issues remain uncertain and actual costs will be driven by those factors. In addition, costs will have to be adjusted higher to reflect the changes in the price and availability of steel. In the late 1990s, Northeast States for Coordinated Air Use Management ( NESCAUM) stated that most SCR applications would cost $ 80 90/ kW. EPA's Acid Rain Division estimated capital costs between $ 40 75/ kW and the Institute of Clean Air Companies ( ICAC) predicted capital costs around $ 50/ kW. In 2004, EPA is still publishing cost algorithms that generally argue the capital cost is less than $ 100/ kW. Two recent surveys to determine installed SCR equipment cost show actual incurred costs average $ 125 140/ kW, and for some installations approach $ 200/ kW.

From time to time, EPA and environmental groups assert that the costs of SO 2 control in 9 102 the Acid Rain program " proves" that costs of pollution control equipment are always much lower than originally estimated. This argument is a red herring. The costs of the SO2 program declined because of extrinsic economic factors that are unlikely to be repeated in any other situation. The federal government deregulated the railroad industry in the early 1990s, thereby vastly reducing the costs of transporting western low sulfur coal to the east. Many utilities were able to switch fuel supplies and avoid control technology costs altogether. This hardly shows that SO 2 control technologies dropped considerably. A more apt comparison ( but unlikely scenario) in this context would be an assumption that natural gas prices dropped so low that coal fired power plants were able to " lower" Hg control costs by switching from coal to natural gas.

A complete assessment of Hg control technology cost requires including the impact of elevated carbon in ash on solid byproduct management. Higher carbon in fly ash will compromise its market value, perhaps eliminating the resale option entirely, and requiring disposal and management. The utility industry has known for decades that when combustion NOx controls are utilized that higher carbon in ash can render fly ash unmarketable. This is especially true for concrete, which is the largest and most valuable byproduct use of fly ash. According to the American Coal Ash Association ( ACAA), fly ash for sale as concrete supplement derives the highest resale value ($ 20$ 45/ ton), and comprises by far the largest end use category. Virtually all Portland cement is prepared with several additives to enhance the following features: it must be " workable" or easy to pore into forms and shape; undamaged by exposure to alternating freeze and thaw environments; and consume a minimum amount much water to maximize ultimate strength. The problem with carbon in fly ash is that it interferes with all of these features in concrete.

In general, carbon content of fly ash must be 5 percent or less to be marketable, which is generally achievable for most units that fire their design coal and have properly tuned combustion systems. However, injecting ACI will generally elevate carbon in fly ash by approximately 4 percent above the 3 4 percent that would otherwise be expected. This tends to render concrete made from such ash discolored, weakened, more difficult to work, and less durable in freezing climates. These problems would likely worsen with halogenated ACI.

The impact of elevated carbon in fly ash on the cost of using ACI for Hg control is due to both loss of revenue from the sale of fly ash and the costs of permitting and disposing of material that previously was sold. The commenter's comments previously assumed that 35 percent of the fly ash generated in the U. S. would be rendered unmarketable and incur a charge of $ 24/ ton due to a revenue loss of $ 12/ ton and a disposal and management fee of $ 12/ ton. The commenter has now updated their prior estimates. The weighted value of the revenue from ash sales, using information from the ACAA, is about $ 24/ ton. The costs of disposal can vary widely on a case by case basis, but information provided by the ACAA supports an average cost of $ 12/ ton. Thus the cost to utilities that can do longer dispose of their fly ash because they are using ACI is probably closer to $ 36/ ton.

Response:

See comment response above for discussion of EPA modeling assumption for control technology costs. EPA also notes that ACI with a pulse jet fabric may be installed upstream of wet scrubber. The Agency's position on the state of Hg technology is contained in the EPA ' s 9 103 Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

6. Analyses of Hg trading programs by EPA and commenters indicate that variations in the first phase cap level and timing of the cap impact when the final cap level will be achieved. Although banking in the first phase impacts the timing of achieving the second phase cap, it should not affect the cumulative Hg emissions reduction ultimately achieved. EPA is seeking additional information on the impact banking may have on the timing of achieving the second phase cap.

Comment:

One commenter ( OAR 2002 0056 5561) stated that in addition, the commenter had the following specific comment on the environmental impacts of emissions banking, which is informed by the modeling that occurred within the commenter's Air Quality Dialogue. Modeling conducted in the commenter's Air Quality Dialogue indicated that emissions banking could be beneficial from an environmental standpoint, potentially resulting in important near term emissions reductions and environmental improvements that could outweigh the additional time required to meet a second phase cap. In a scenario without a Phase 1 emissions cap ( the Phase 2 cap was set at 10 tons in 2018), the modeling projects that firms would delay any action until the approach of the binding cap, resulting in 16 percent fewer reductions in Hg emissions on a cumulative basis through 2022 than under a comparable scenario that included a Phase 1 cap set at 26 tons. The cost savings from not having to meet a 26 ton Phase 1 cap were insignificant ( net present value of $ 0.3 billion for the 2005 to 2030 period) in the scenario without a Phase 1 cap, and the modeling showed a spike in costs just before the compliance year. Of course, the relative environmental and cost advantages of banking would depend on the chosen cap levels and timing. The commenter expected the near term environmental benefits of emissions banking would be reduced if the first phase cap is set at a co benefits control level.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The cap and trade program will include a provision for banking. See final rule preamble and Chapter 5 comment responses for further discussion of banking.

Comment:

One commenter ( OAR 2002 0056 5510) said that in regard to banking and the timing of achieving the second phase cap, the commenter had proposed an alternative cap and trade program, which, among other things, significantly reduces the amount of banking that can occur prior to 2018   increasing the likelihood that actual coal based power plant emissions in 2018 will be 15 tons.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a 9 104 phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The cap and trade program will include a provision for banking. See final rule preamble and Chapter 5 comment responses for further discussion of banking.

Comment:

One commenter ( OAR 2002 0056 5493) stated that pursuant to these regulatory proposals, EPA intends to reduce Hg emissions from coal fired power plants by 70 percent by setting a permanent 15 ton cap in 2018 regardless of the future growth in the energy sector. Thus, the cap would effectively become more stringent as more power plants are constructed in order to keep their collective emissions below 15 tons. EPA proposes to set the near term Hg emissions cap in 2010 at a level that can be achieved through the installation of FGD and SCR units that will be necessary to meet 2010 caps on SO 2 and NO x under existing cap and trade programs. The commenter agreed with EPA that this " multi pollutant" approach is the most effective and reasonable way to reduce emissions from coal fired power plants in the near term.

However, there is no provision in the proposed cap and trade approach that permits credit for reduction of Hg emissions achieved before the near term cap become effective in 2010. The Building and Construction Trades Department ( BCTD) of the AFL CIO agrees with the comments submitted by the Unions for Jobs and the Environment on June 29, 2004, that a mechanism should be incorporated in the proposed rule that affords credit for reduction of Hg emissions in advance of the 2010 cap date. Such credit would encourage the installation and/ or modification of technologies sooner than later thereby helping to avoid the inevitable last minute crunch that will create an unnecessary burden on the limited supply of skilled manpower available to install FGD and SCR units.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The cap and trade program will include a provision for banking. See final rule preamble and Chapter 5 comment responses for further discussion of banking. EPA is not including a provision for early reduction credits in the final rulemaking. See Chapter 5 response to comments for further discussion of ERCs.

Comment:

One commenter ( OAR 2002 0056 5502) stated that emissions were projected to be 15 tons by 2020 in every Cap and Trade case examined using the EPMM and reported to EPA in June 2004. In the NODA, EPA characterized the 2020 emissions estimates reported for EPMM Cap and Trade scenarios as, variously, either 23 or 24 tons. Additional examples are provided demonstrating the validity and robustness of the earlier projection of about 15 tons by 2020.

Response:

EPA has examined the commenters analysis and notes that its own analysis shows a more gradual emission glide path in meeting the second phase cap. See Chapter 7 of final rule RIA 9 105 for further discussion of EPA emissions projections.

Comment:

One commenter ( OAR 2002 0056 5535) stated that EPA seeks comment on a number of economic modeling analyses performed by different stakeholder groups. The commenter's primary comment on this aspect of the NODA was that it fails to honor the commitment Administrator Leavitt made to the public: to ensure that the rule will be " done in a way that will maximize the level of reductions" based on the available technology. In particular, the NODA does not present any new EPA analyses of stricter MACT scenarios, much less examine the different control options put forward by stakeholder groups participating in the Utility MACT Working Group.

A second concern the commenter had regarding the various cap and trade scenarios that were modeled was that none ensures that actual emissions will be equal to, or lower than, the cap level by the date the cap goes into effect. For example, the Center for Clean Air Policy ( CCAP) modeled a 7.5 ton cap in 2015, yet the results predict that 11 tons will still be emitted in 2020. EPA asks for comments on the so called " glide path" of the reductions, and the commenter reiterated their earlier comments that the safety valve provision and the facilities' unrestricted ability to borrow from future allowance years means that emissions will continue to exceed the cap far into the future, perhaps indefinitely. EPA must recognize that the cap and trade options all result in a cumulative loading of Hg into the environment for 10 to 20 years longer than a proper MACT standard, in far greater amounts. This additional loading of a persistent, bioaccumulative metal is unacceptable.

With regard to the specific modeling results, the analysis that was of most interest to the commenter was the Cinergy Corporation's ( Cinergy) " stringent MACT" modeling, and the commenter's assessment of that approach is discussed in detail below. Before turning to Cinergy's modeling, however, it bears reiterating our prior comments about the CCAP work. CCAP's report states:

Tightening the mercury emissions reduction cap from 15 tons in 2018 to 10 tons in 2018 is projected to increase total [ three pollutant program] compliance costs by approximately 5 percent ($ 3.1 billion in net present value terms). Further tightening the cap by advancing the compliance date to 2015 would add approximately another 5 percent to total 3P costs, and reducing the cap to 7.5 tons in the same compliance period would increase total 3P costs by an additional 4 percent. In addition, even the most aggressive of these options ( 7.5 tons cap in 2015) has almost no impact on wholesale electricity prices both nationally ( within 0.2 percent) and regionally ( 1.5 to 2.1 percent), reflecting how the cost may not be passed on directly to wholesale electricity consumers. Cumulative mercury emission reductions increase between 8 and 28 percent through 2022 with these more aggressive caps and timetables. Moreover, the impact of such changes on national and regional coal production is slight ( 1 to 5 percent).

What that means for present purposes is that even if EPA persists in its unlawful scheme to regulate Hg pollution under section 111 of the Clean Air Act ( which of course it should not do), a much more stringent approach is economically feasible. 9 106 Cinergy modeled a MACT control regime becoming effective in 2008 and reducing approximately 39 tons of annual Hg emissions ( an 81 percent cut). Even though Cinergy's assumptions included higher capital costs and less Hg co control by NO x and SO 2 controls than EPA's modeling, and also included the extreme assumption that activated carbon injection ( ACI) would not be available until after 2010, the commenter note that the average annual costs of control in 2010 and 2020 ( calculated by dividing the net present value of $ 130 billion in 2010 and 2020 by 20 years) are on the order of $ 6.5 billion, which is economically feasible. Although the NODA states that Cinergy's modeling of this scenario resulted in significant increases in power prices and fuel prices in the short term, the commenter was unable to verify that this is indeed the case as the full model results inexcusably were not included in the public version of Cinergy's comments. The public deserves the right to see the concurrent SO 2 reductions of Cinergy's stringent MACT scenario to see if the benefits of this scenario outweigh the costs. The commenter had every reason to believe they do.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. Discussion of EPA's cost modeling can be found in Chapter 7 of the final CAMR RIA. Further details on commenters analysis are found in their submittals to the docket.

Comment:

The commenter ( OAR 2002 0056 5455) noted that in studying Table 1 of the NODA, it appeared that it really was not much more expensive to control Hg emissions to 7.5 tons per year rather than 15 tons per year. A two phase cap of 15 tons was projected to cost $ 3.3 billion by 2010 and $ 6.7 billion by 2020. But a two phase cap of 7.5 tons was expected to cost $ 4.6 billion by 2010 and $ 7.1 billion by 2020. The difference by 2020 is only 6 percent. For all of EPA's sloppy calculations, incorrect assumptions, and failure to carry out a proper MACT determination, it only made a 6 percent difference in cost. It would be hard to overstate the level of disgust in the Indian community over the way EPA has handled this rulemaking.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. Discussion of EPA's cost modeling can be found in Chapter 7 of the final CAMR RIA.

Comment:

The commenter ( OAR 2002 0056 5404) stated that the NODA recognizes that "[ a] lthough banking in the first phase impacts the timing of achieving the second phase cap, it should not affect the cumulative Hg emissions reductions ultimately achieved under the program." 69 Fed. Reg. 69870. The commenter stated that EPA nonetheless requests comment on " the impact banking may have on the timing of achieving the second phase cap." Id. The commenter strongly supported unrestricted banking of Hg allowances; according to the commenter, indeed, 9 107 there is no policy basis to restrict trading, even if unrestricted banking delays the date by which sources achieve source specific limits that correspond to the Phase II emissions reductions on an annual basis.

The commenter stated that in addition to having no impact on the cumulative Hg emissions reductions ultimately achieved under a cap and trade program, if unrestricted banking means ( as it likely will) that the Phase II cap will not be achieved exactly by 2018, this will be the case because Phase I Hg reductions will have gone beyond what Phase I requires. According to the commenter, that is, Hg allowances have a vintage year before which they cannot be used; thus a source can exceed the Phase II cap in 2018 only if it has reduced emissions beyond what is required under Phase I, carrying Phase I allowances over to Phase II. The commenter stated that these greater emissions reductions achieved during Phase I arguably are preferable for the environment, but at a minimum are neutral from an environmental perspective.

The commenter stated that the fact that emissions in Phase II may exceed the cap because of surplus reductions in Phase I can pose no adverse environmental consequences unless the pollutant at issue poses significant acute health risks. According to the commenter, Hg is not such a pollutant; environmental issues associated with Hg result from the deposition of Hg on water is converted to methylmercury ( MeHg), which in turn can bioaccumulate in fish, and subsequently in people. The commenter stated that this is a long term process, however, and concerns regarding Hg emissions should focus on cumulative environmental loadings over time, not on local, short term emissions. According to the commenter, unrestricted banking cannot, by definition, allow cumulative emissions over the life of the program to exceed what they would be if banking were restricted. The commenter stated that, thus, no policy basis exists for any restriction on the banking of Hg emissions.

The commenter added that, moreover, there are significant policy benefits to allowing unrestricted banking. The commenter stated that banking can provide significant cost savings with respect, as well as promoting efficient emissions reduction. The commenter added that unrestricted banking will also provide affected sources with valuable compliance flexibilities and incentives for technological development. The commenter stated that, as noted in their June 24 comments, no currently available control technology exists that would enable the power generation sector to achieve a 15 ton cap. The commenter further stated that by permitting unrestricted banking, system owners and operators will have the incentive to reduce Hg emissions earlier and in amounts greater than the rule requires in order to bank allowances that they can use to facilitate compliance at the beginning of Phase II. The commenter stated that these allowance surpluses will give sources the compliance flexibility they need to experiment with promising new technologies   which may have the potential to reduce Hg emissions efficiently and cost effectively   without fear of consequences associated with non compliance. According to the commenter, unrestricted banking will thereby ease the regulatory burdens associated with achieving the 2018 cap because sources will have greater flexibility to identify and implement new, promising control technologies. The commenter stated that, moreover, as noted above, unrestricted banking results in no environmental disbenefits. The commenter further stated that to the extent that Hg emissions from power plants could be identified as a human health concern, such concern would be limited to the contribution of those emissions to the global pool. The commenter stated that in any event, a flexible cap and trade program with unrestricted banking would be an effective mechanism to reduce the contribution of the power generation sector to the 9 108 global Hg pool.

The commenter noted that, in sum, permitting sources to retain unused allowances from one calendar year for use in a later calendar year will encourage early emissions reductions, provide flexibility to affected sources to meet environmental objectives, and facilitate the development of new, innovative Hg reduction control strategies. The commenter stated that given that unrestricted banking provides the foregoing benefits with no corresponding environmental disbenefits, EPA should allow unrestricted banking in the final rule.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The cap and trade program will include a provision for banking. See final rule preamble and Chapter 5 comment responses for further discussion of banking.

Comment:

One commenter ( OAR 2002 0056 5548) stated that based on their review of the available information, the commenter could find no plausible basis to employ any allowance allocation adjustment factors by coal rank for any cap that is in effect after 2014. The level of the cap is irrelevant; because by 2014 EPA projects, and proposes to rely upon, the commercial availability of Hg specific control technologies, and these technologies are expected to deliver reasonably similar removals across all coal ranks.

Response:

The final rule takes into account the different levels of mercury control that lignite, bituminous, and subbituminous coals can achieve using existing NOx and SO 2 controls and uses coal adjustment factors for determining the state emission budgets and determining unit level allocation under EPA's example allocation methodology for States. For further discussion see final rule preamble ( section IV. C. 4) and Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter ( OAR 2002 0056 5548) stated that bituminous users and subbituminous users that do not comply with their Hg reduction obligations through co benefits will have to purchase allowances under the trading program, and that price will not vary depending on the rank of coal burned by the allowance purchaser. That is the very point of a trading program, which is, as EPA notes, " cost effective," because it allows sources that can reduce Hg more cost effectively to do so, and pass those savings on to other units that cannot make reductions that are as cost effective. In other words, under a trading program, sources with the lowest compliance costs bear the burden of control.

There are those who might be concerned about allowance availability on a unit specific 9 109 basis, even though co benefits reductions will generate adequate allowances on an aggregate basis. While this potential concern is one that is equal across coal ranks, because there will be many bituminous units that will be relying on allowance purchases for compliance as well as units burning low rank coals, this concern is also easily addressed through restrictions on banking. If EPA makes adjustments to its banking provisions to largely prohibit banking, particularly in the first few years of any co benefits program, all allowances will be held on a " use it or lose it" basis, and consequently will be sold to those that need them for compliance. The commenter did not believe that allowance hoarding is a likely outcome, nor one that would become an extended practice, but a phase in provision for banking whereby banking is restricted in the early years would certainly address that issue. As an alternative, and likely a better solution, EPA could develop a conditional restriction on banking whereby allowance banking is prohibited unless the allowances are first offered for sale at an annual EPA auction, and, if not purchased by one that needs them for same year compliance, may be banked without restriction. This approach would only restrict banking to the degree necessary to ensure that all sources that must rely on allowance purchases to comply under a co benefits approach can obtain them. EPA can also help address allowance availability concerns, and provide an incentive for early adoption of Hg specific control technology, by restricting banking to those reductions that result from the application of Hg specific control technology, i. e., beyond simple co benefit reductions.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The cap and trade program will include a provision for banking. See final rule preamble and Chapter 5 comment responses for further discussion of banking. The final rule takes into account the different levels of mercury control that lignite, bituminous, and subbituminous coals can achieve using existing NOx and SO 2 controls and uses coal adjustment factors for determining the state emission budgets and determining unit level allocation under EPA's example allocation methodology for States. For further discussion see final rule preamble ( section IV. C. 4) and Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter ( OAR 2002 0056 5497) noted that EEI commissioned Charles River Associates ( CRA) to perform a number of sensitivity runs using EPMM to identify those factors that affect the " glide path" and the timing in achieving the second phase cap. CRA's analysis is being submitted as part of EEI's NODA comments ( see OAR 2002 0056 5469). The commenter refers EPA to EEI's NODA comments for the detailed presentation of CRA's work.

Briefly, CRA's work shows that the two factors that have the greatest impact on the " glide path" and the timing of emission reductions to achieve the second phase cap emission level are: ( 1) how closely the first phase cap is set to the true level of co benefits and ( 2) the duration of the first phase cap. If the first phase cap is set below the level of true co benefits, then more banking would occur during the first phase and full achievement of the second phase cap emission level would occur later. The longer the duration of the first phase cap, the greater the amount of banking and, again, deferred achievement of the second phase cap emission level. 9 110 Other factors with smaller effects on the " glide path" are the assumptions one uses about the growth in the use of low sulfur coal and the stringency of the second phase cap. Changes in assumptions about the growth of the use of low sulfur coal primarily affect the level of predicted co benefits in the first phase. The stringency of the second phase cap affects the ultimate cost of compliance and hence the desire of companies to put off the capital costs of second phase compliance by early banking. CRA found that changes in technology cost assumptions do not have a major impact on the " glide path."

These sensitivity results continue to point out the wisdom of the alternate Hg cap and trade proposal offered by the commenter and a variety of other industry commenters. That proposal would not set a " hard" cap" for the first phase; rather, the Hg co benefits would be what they are. Mercury trading would not be allowed during the first phase, but early reduction credits could be earned for installing Hg specific control equipment. A second phase would begin in 2015 with a cap of 24 tons of Hg per year. In the second phase, Hg allowances would be allocated and Hg trading would occur. The third phase would begin in 2018 with a cap of 15 tons per year.

Under this industry proposal, the first phase cap could not be set at a level below the true co benefits level; thus, the amount of banking could be expected to be less. Indeed, the only credits that would be accrued from 2010 to 2015 would be those associated with the early installation of Hg control equipment. Providing for early reduction credits would foster early reductions in Hg emissions and assist in identifying and solving technical issues that will undoubtedly arise when a new technology is installed. Beginning the second phase in 2015   only three years before the proposed third phase 15 ton cap would take effect   would limit the period during which allowances could be banked, making it likely that full achievement of the third phase cap emission limit would occur in or not long after 2018.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The cap and trade program will include a provision for banking. See final rule preamble and Chapter 5 comment responses for further discussion of banking. EPA is not including a provision for early reduction credits in the final rulemaking. See Chapter 5 response to comments for further discussion of ERCs.

Comment:

One commenter ( OAR 2002 0056 5469) noted that the EPMM model runs reported in the commenter's earlier submission ( see OAR 2002 0056 2929) projected that emissions of Hg would reach the level of the Phase II cap of 15 tons by 2020. It has been widely reported that EPA's analysis of the same scenario using its own assumptions and the IPM model did not come close to reaching the level of the Phase II by 2020, or even by the end of its 2026 model period. CRA's report, submitted with the commenter's comments, provided an explanation of the likely reasons for EPA's assumptions to have produced such a different glide path for the same scenario. There were three basic reasons: 9 111 1. EPA set the Phase I cap at 34 tons, which was equal to " co benefits" under EPA's modeling assumptions. Industry's assumptions implied that " co benefits" were substantially higher, at 39.9 tons. The main reasons for these differences in co benefits were:

a. EPA assumed greater incremental Hg control resulting from addition of FGD, and from adding SCRs to units with FGDs as well, particularly for subbituminous coals, but also for FGDs added at bituminous fired units. b. Even without consideration of the Hg co benefits from FGDs, EPA's assumptions led to a greater propensity to meet SO 2 caps through capital intensive FGDs rather than through use of lower sulfur coals.

2. EPA's marginal cost curve for addition of ACIs ( to achieve Hg controls beyond the cobenefits level) was higher and steeper than the technological cost and effectiveness assumptions used by industry.

The commenter noted that CRA explained how the net impact of these differences in assumptions was that EPA's model would find it cost effective to bank much larger amounts during Phase I of the proposed Hg cap and trade policy option ( when reductions could be met largely via co benefits that were relatively cheap compared to those assumed by industry) and to avoid for a relatively longer time the deeper cuts of Phase II ( which would require ACI investments that were relatively more expensive than assumed by industry). In other words, when the Phase I cap is set closer to co benefits, the glide path to the final level of the cap will be more extended during Phase II. The more costly the Phase II cap is to meet, the more extended the glide path will be ( i. e., more banking will occur in Phase I, thus lengthening the period of time until emissions would reach the final cap). By setting the Phase I cap at its model's estimated level of co benefits, and having a Phase II cap that would be relatively expensive to meet, EPA's was maximizing the chances that its model would project a long delay before annual emissions near the Phase II cap.

Industry analyses did not find this to be a realistic glide path if the cap were to be set at 34 tons, for the simple reason that industry's data indicate that a 34 ton cap would be far below the low cost zone of co benefits, and so the Phase I cap would quite expensive to meet in its own right. Thus, far less banking would be warranted in Phase I, and industry projects a quicker glide path to the proposed Phase II cap, with a much smaller bank to deplete, and thus relatively prompt attainment of the actual level of the Phase II cap.

The commenter stated that in response to the NODA, CRA has prepared a number of additional sensitivity cases using EPMM to substantiate the above logic, and to better elucidate the particular parameters that might most alter the length of the glide path to a Phase II cap. The commenter explored the role of ( a) uncertainties in EPMM assumptions that fundamentally determine the co benefits level; ( b) the stringency of the Phase II cap relative to the Phase I cap; ( c) impact of setting the Phase I cap closer to the expected level of co benefits; ( d) shortening the duration of Phase I, with alternative assumptions about the timing and phase in of an ultimate 15 ton cap; and ( e) the role of rate of technological improvement. Except where noted, all of the runs described in this section were prepared with the extended version of EPMM that includes a terminal model period at 2030. Thus, the 2020 emissions results that the commenter reported 9 112 here are not from a terminal period. Also, all of the runs assume a 2.5 percent per annum ( p. a). reduction in the variable cost of Hg control technologies except where the commenter specifically explore the role of alternative assumptions about technological change ( in Section III, see Document ID No. OAR 2002 0056 5469).

The commenter found that the most important determinants of the glide path are how close the Phase I cap is to the level of co benefits, and the duration of Phase I. These have the most direct connection to the size of the bank that can be built up at relatively low cost prior to entry into Phase II, and that, in turn, most directly affects the length of time before annual emissions must actually be at the Phase II cap. The commenter also found that the effects on the glide path of setting a Phase I cap set at or near co benefits levels can be offset effectively by an earlier introduction of Phase II, or even an interim cap before the 15 ton level. This two pronged adjustment to the proposed Hg cap appears to strike a good balance between a reasonable rate of introduction of new Hg control technology that can maximize the potential benefits of technological advancement, and avoiding significant delays in when actual annual emissions would be at the level of the 15 ton cap.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. EPA has examined the commenter's analysis and notes that its own analysis shows a more gradual emission glide path in meeting the second phase cap. See Chapter 7 of final rule RIA for further discussion of EPA emissions projections.

Comment:

One commenter ( OAR 2002 0056 5469) noted that they previously identified uncertainty in the amount of FGD that would be installed versus use of lower sulfur coals to meet SO 2 caps as one of the possible uncertainties in our estimate of co benefits. One assumption in EPMM that might affect the mix of SO 2 compliance choices regards the availability of lower sulfur coals. The standard EPMM assumptions have been to allow up to 2 percent p. a. growth in use of coals in each of several coal quality categories. However, recent experiences in coal markets have suggested that the lowest sulfur forms of Eastern bituminous coals may not have even that much potential for growth in supply without major cost increases.

The commenter decided to look at how the FGD choices might be adjusted if this coal were only allowed to grow at 0.5 percent p. a. All other coals continued to face 2 percent p. a. growth limits, except for the high sulfur bituminous coals, which were no longer constrained at all. This run did produce a fairly dramatic increase in the quantity of FGDs installed by 2010, and a correspondingly lower co benefits level. In 2010, it projects a co benefits level of 38.9 tons, as compared to 40 tons under our standard coal growth assumptions. While there are more FGDs in this case, there is a more gradual introduction of ACIs. The net effect is only a very modest change in the glide path. Emissions in 2020 are at 15.6 tons, compared to 15.4 tons in the standard case reported in Section I. A. ( see OAR 2002 0056 5469).

This scenario suggests that the role of a preference for FGD in determining co benefits 9 113 and a glide path to Phase II may be fairly minor. The commenter found that industry's estimate of 2010 co benefits might be as low as 38.9 tons, rather than the 39.9 tons originally reported ( which is now estimated at 40.0 tons using the version of EPMM with the extended model horizon). This difference does not affect the estimated present value cost of the Hg cap and trade proposal, which is $ 1.8 billion ( 1999 dollars) for both the lower or higher assumptions about low sulfur bituminous coal availability.

Another area of substantial uncertainty on co benefits relates to the specific assumptions that are made about the reductions that are associated with different configurations of PM, SO 2, and NO x controls. In particular, there has been much debate over whether SCRs produce additional Hg reduction when added to units with an FGD that are burning a lower rank coal. EPRI reports in its comments on the NODA that there may be some new evidence that there could be a very small amount of co benefits in such units. Although the evidence is from a single plant, and may not apply to all low rank configurations, the commenter tested the effect of adding a 5 percent co benefit from SCR to all subbituminous and lignite burning plants. This had almost no impact at all on our co benefits estimates: the 40.0 ton estimate from the base model was reduced to 39.9 tons.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. EPA agrees that different modeling assumptions can impact the projection Hg cobenefits from NOx and SO2 controls under CAIR. As discussed in the NODA, for the final rulemaking analysis, EPA has made changes to some of its co benefit assumptions for subbituminous units with SCR and FGD controls. EPA is also using a newer version of EPA's IPM for the final rulemaking. Changes to the modeling assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004). EPA has examined the commenter's analysis and notes that its own analysis shows a more gradual emission glide path in meeting the second phase cap. See Chapter 7 of final rule RIA for further discussion of EPA emissions projections.

Comment:

One commenter ( OAR 2002 0056 5469) noted that another possible factor that the commenter posited could lengthen the glide path is how stringently the Phase II cap is set relative to the stringency of the Phase I cap. To explore this possibility, the commenter considered the impacts of a Phase II cap set at 7.5 tons rather than 15 tons, while keeping the Phase I cap at 34 tons, the presumed level of the proposed Clean Air Mercury Rule ( CAMR). This would have the effect of making the marginal cost of meeting the Phase II cap once the bank is depleted much more costly relative to the marginal costs of exactly meeting the Phase I cap. The result should be an incentive to bank more during Phase I, in order to reduce the rate of increase of marginal costs of control ( also called emissions prices) back to about the corporate discount rate. If this were to happen, the glide path to the Phase II cap would be lengthened.

This is exactly what the commenter found in this scenario. The marginal costs, Hg 9 114 emissions, and cumulative amount of Hg emissions banked are shown in Table 4. The most dramatic effect of this scenario is that Phase II is not only delayed beyond 2020, but projected emissions are still well above the Phase II cap through the end of the terminal model period: projected emissions in 2020 2029 are 11 tons, and they are still 9.3 tons for the entire period 2030 2049. The 7.5 ton cap is never fully met until the first year after the model stops accounting for costs of control, in 2050. This delay is accomplished by accumulating a bank exceeding 86 tons during Phase 1. Even with this lengthy delaying action, the marginal cost of controls in 2020 is over $ 45,000/ lb ( 1999 dollars).

The commenter also found that the 7.5 ton Phase II cap increases the present value of the policy's cost quite significantly. Our estimated present value ( through 2020) of costs of the proposed Hg cap and trade policy is $ 1.8 billion ( 1999 dollars). With the same assumptions, a 7.5 ton cap in Phase II is estimated to be $ 4.6 billion. Tightening the Phase II cap in 2018 from 15 tons to 7.5 tons increases policy costs by 160 percent.

Table 4. Results of Scenario with 7.5 ton Phase II Cap in 2018 Hg Emissions ( tons per year) Hg Bank at Beginning of Period ( tons) Marginal cost of Hg controls in Period 2004 44.6 na na 2008 43.1 na na 2010 28.3 0.0 $ 25,691 2012 23.6 11.3 $ 28,872 2015 19.3 42.4 $ 34,435 2018 15.4 86.6 $ 41,098 2020 11.0 70.9 $ 45,586 2030 9.3 35.6 $ 99,693 The commenter also ran a case where no banking was allowed during Phase I, thus forcing the model to actually meet the 7.5 ton cap in 2018 and thereafter. The purpose of this was to determine the sensitivity of marginal costs to a cap of 7.5 tons. This case produced marginal control costs of $ 120,000/ lb in 2018, and $ 94,000/ lb in 2020 ( both 1999 dollars). The falling marginal control cost reflects the effect of the 2.5 percent p. a. decline in variable O& M costs of ACI. This rate of decline is not insignificant, but certainly insufficient to make attainment of a 7.5 ton cap occur without very high allowance prices.

The stringency of the 7.5 ton cap also is reflected in terms of its implications for retrofitting. When the 7.5 ton cap is met in 2018, fully 78 percent of existing coal capacity has been retrofitted by ACI at 90 percent controls, in addition to the usual large number of FGD and SCR installations ( about 107 GW and 56 GW of additional FGDs and SCRs, respectively, are also added by 2018). Clearly most plants are installing ACI as well as FGDs and SCRs.

The commenter found that this was a particularly interesting scenario in light of the comments that were submitted to EPA in June 2004 by the Center for Clean Air Policy ( CCAP), and which were summarized in the NODA. The NODA summarizes CCAP's views based on a comparable model run with IPM as " concluding that the incremental changes in the timing and 9 115 stringency of a Hg cap have, in CCAP's opinion, relatively modest cost implications." The commenter reviewed the detailed results of CCAP's runs, and found that our results are actually very similar to those found by CCAP for the 7.5 ton cap case:

° CCAP's scenario for a 7.5 ton cap in Phase II ( with Phase I banking) projects that emissions in 2020 2025 would still be 11.3 tons and the marginal cost of control in 2020 would be $ 88,060/ lb ( 1999 dollars).

° CCAP's results for a 7.5 ton cap in Phase II ( with no Phase I banking) projects that the marginal cost of meeting the 7.5 ton cap would be $ 165,500/ lb in 2018 and $ 129,500 in 2020 ( 1999 dollars).

° CCAP's costs of having a more stringent 7.5 ton cap in 2015 is also at least 150 percent more costly than a 15 ton cap in 2018, even based on much lower EPA gas price assumptions.

In brief, CCAP's analysis finds the 7.5 ton cap more costly to achieve than does CRA's analysis. There is obviously a " knee in the curve" of the marginal control costs at a cap level greater than 7.5 tons. The commenter therefore conclude that EPA's interpretation of the CCAP results, that the timing and stringency of the Hg cap " have relatively modest cost implications" is a judgment that the commenter found inconsistent with CCAP's own modeling results.

CCAP reports that it considered alternative levels of the Phase II cap in an effort to " identify a possible middle ground solution... in which a less stringent Phase I target is traded off against a more stringent Phase 2 target." The commenter's analyses suggested that increasing the stringency of the Phase II cap can be counterproductive. It can delay attainment of the Phase II cap for extended periods, while creating a much more rapid rate of investment in the emerging technology that may exacerbate efforts for a measured and cost effective phase in process. If one goal is to design a policy that will enable a gradual phase in of investments in emerging forms of control technology, thereby maximizing the opportunities and incentives for technological improvements to be gained, then it does not make sense to have a stringent Phase I cap, but it also does not make sense for the Phase II cap to be very stringent relative to the Phase I cap. A proposal for a cap as tight 7.5 tons is inconsistent with CCAP's much more important point, that a gradual phase in period, and incentives for early action are desirable elements of a sound policy where a control technology is still in an emergent stage.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale.

Comment:

One commenter ( OAR 2002 0056 5469) stated that there are some important merits to setting the Phase I cap at a level close to the " true" co benefits levels. Most importantly, development, testing, and commercialization of Hg control technology for electric generating 9 116 units is still at an early stage. The difficulties of achieving various levels of Hg control across the universe of generating units are highly uncertain and there is little if any experience with commercial installation. Because of this, rates of technological improvement in the technology are very high and a gradual phase in helps motivate more intensive research, while also enhancing potential for carrying the learning from the first several installations into the wider set of installations that will come with time. At the same time, there is a risk that setting the Phase I cap at the " true" co benefits level will create a longer than desirable glide path will be to the Phase II cap level.

Below, the commenter discussed results of a couple of scenarios evaluated to substantiate this point, and then the commenter turned to an alternative that more effectively resolves the glide path concern while preserving the benefits of setting Phase I cap at the " true" co benefits level ( see OAR 2002 0056 5469).

In CRA's analyses, the " true" level of co benefits emissions in 2010 is either 38.8 tons or 40 tons. It is 38.8 tons in 2010 under the assumption of 0.5 percent maximum annual growth in low sulfur bituminous coal, and it is 40 tons in 2010 under the assumption of 2 percent maximum annual growth in the same. The commenter's analyses of EPA's proposed cap and trade policy option, however, have used 34 tons as the Phase I cap. The commenter had used this value because EPA stated in its notice of proposed rulemaking that it would set the Phase I cap at the co benefits level, and also that it estimated co benefits to be 34 tons. A cap must be set at a welldefined level, and cannot vary depending on one's views about what might constitute the intended goal of co benefits. Although 34 tons was not the " true" co benefits level in our model, there is no reason to believe that EPA would select a Phase I cap at any level other than what it estimated as " true" co benefits ( see OAR 2002 0056 5469).

The commenter noted in our earlier submissions that EPA's projected glide path would be much longer than that projected by EPMM because the 34 ton cap was achievable solely by " true" co benefits in EPA's modeling, but was much lower than the EPMM co benefits level, and therefore more costly to meet in CRA's modeling. EPA's model would thus project much more banking in Phase I than would EPMM, thereby delaying full implementation of Phase II emissions levels in the Agency's runs. In the current analysis, the commenter simulated this effect in the EPMM model by running scenarios where the commenter set the Phase I cap at EPMM's projected co benefits levels, for the two sets of coal assumptions, respectively. The commenter left the Phase II cap at 15 tons, since this value appeared to have no connection to particular model assumptions.

Tables 5 and 6 contrast the timing of ACI and FGD installations, respectively, for the case of Phase I being set by the co benefits level, and the case of Phase I being set at a 34 ton cap. Figure 3 presents the glide paths of Hg emissions for both coal constraint cases. The predicted effect on the glide path is apparent. Projected emissions remain 2 tons above the Phase II cap until 2030 in the case where the Phase I cap is set at co benefits. This is the largest single source of glide path sensitivity that the commenter had found for a 15 ton Phase II cap. It would appear to explain much of the difference between the CRA projections of 2020 emissions reaching the national target level, and the more extended period to reach that target that has been reported as the EPA finding. 9 117 As noted, the advantage of a cap at co benefits levels in the early years is that it creates a better environment for a gradual and non disruptive commercial phase in of a technology that can best be described as still emergent. By setting the cap at this level, one creates desirable incentives for early action by allowing banking to occur. However, if the cap remains at the cobenefit level for an extended period of time, a relatively large bank may be possible to build up. This implies benefits from early reductions, but at the same time, it means that the rate of decrease towards the Phase II cap will be slowed. The best way to preserve the merits of a cap set at cobenefits level, while managing for a relatively prompt attainment of Phase II is to alter the length of Phase I. The next section turns to this prospect, exploring how the glide path can be managed while still setting the Phase I cap set at the estimated co benefits level.

Table 5. Quantities of New ACI Retrofits by Time Period ( MW)

Year Standard Low S Coal Assumptions ( 2010 co benefits= 40 tons) Low Supply Growth of Low S Bituminous ( 2010 co benefits= 38.8 tons)

Proposed Policy: Phase I cap at 34 tons Phase I cap at cobenefits Proposed Policy: Phase I cap at 34 tons Phase I cap at cobenefits 2004 1,050 244 1,050 244 2008 1 1 1 1 2010 16,835 4,537 11,660 5,679 2012 1,352 3,442 22,220 511 2015 16,398 11,092 19,848 15,158 2018 23,646 26,373 48,238 19,326 2020 49,079 51,067 22,220 56,514 2030 5,695 17,679 8,084 17,745 Table 6. Quantities of New FGD Retrofits by Time Period ( MW)

Year Standard Low S Coal Assumptions ( 2010 co benefits= 40 tons) Low Supply Growth of Low S Bituminous ( 2010 co benefits= 38.8 tons)

Proposed Policy: Phase I cap at 34 tons Phase I cap at cobenefits Proposed Policy: Phase I cap at 34 tons Phase I cap at cobenefits 2004 1,315 2,983 5,227 4,907 2008 8,159 5,936 6,907 6,677 2010 32,791 26,517 42,537 40,048 2012 13,678 19,816 6,457 8,686 2015 3,444 4,041 5,112 5,458 2018 12,024 10,710 17,893 17,481 2020 31,103 32,437 33,736 34,475 Year Standard Low S Coal Assumptions ( 2010 co benefits= 40 tons) Low Supply Growth of Low S Bituminous ( 2010 co benefits= 38.8 tons)

Proposed Policy: Phase I cap at 34 tons Phase I cap at cobenefits Proposed Policy: Phase I cap at 34 tons Phase I cap at cobenefits 9 118 2030 15,330 16,187 9,511 10,219 Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. The first phase cap is based on EPA modeling of the Hg co benefits of SO 2 and NOx controls installed for compliance with the CAIR rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for discussion of emissions projections.

Comment:

One commenter ( OAR 2002 0056 5469) stated that four ( 4) additional scenarios were run that explored alternative timings of a Phase II cap that might be paired with a Phase I cap set at " true" co benefits. Two scenarios were run assuming that the Phase II cap is implemented in 2015 instead of 2018 ( one for each set of coal supply assumptions, and hence with different assumptions about co benefits, to match the two scenarios described in comment above). The other two scenarios are the " Alternative Cap Proposal" ( see OAR 2002 0056 4894) that 9 119 commenter submitted to EPA on August 13, 2004 for each co benefits case. This alternative proposal would strike an intermediate ground by tightening the cap in the period 2015 2017, but only to 24 tons, with the 15 ton cap following in 2018.

Figure 4 compares the glide path of each of these four scenarios to those in the previous section where the commenter set the cap at co benefits in Phase I, but still allowing Phase II to enter force in 2018. Table 7 shows the associated quantities of ACI controls in each time step, which can be compared to the values in Table 5 as well. The early introduction of Phase II increases the rate of early action in Phase I, but still gets emissions to 15 tons by 2020. However, the commenter's proposed alternative scenario, with an intermediate cap at 24 tons, provides a similar reduction by 2020, but with a slower rate of investments in the early years, when the costs of control are the most uncertain.

The estimated costs are fairly sensitive to the decision on level of the cap during 2015 2017. As a point of reference, the estimated present value of the Hg cap as proposed ( i. e., 34 tons in Phase I, and Phase II starting in 2018) is $ 1.8 billion ( 1999 dollars). By allowing the Phase I cap to be set at co benefits ( as determined by the model), but continuing to keep Phase II in 2018, costs would fall to about $ 1.2 or 1.3 billion, and attainment of the Phase II cap could be delayed well beyond 2020. By introducing the 15 ton cap in 2015, costs would increase to about $ 2.6 or 2.8 billion, although emissions would be at 15 tons by 2020. In contrast, the alternative proposed by the commenter, would cost only $ 1.8 or 1.9 billion, and would still provide assurance of attainment of the 15 ton emissions level by about 2020.

Thus, a combination of a co benefits based cap in Phase I with a shorter duration of Phase I provides better assurance against excessive costs during program start up, as well as better assurance of reaching the 15 ton emission level somewhere in the 2020 time frame. If interim caps are used instead of bluntly moving the 15 ton cap forward in time, the policy costs need not increase, while still providing assurance of timely attainment of the 15 ton level of emissions.

The commenter's alternative cap proposal is very similar in nature to the simplistic sensitivity case that simply brings in a 15 ton cap by 2015. It has the same properties of requiring only cost effective early action through 2015, yet bringing emissions to 15 tons promptly. The mechanism for accomplishing this effect was the same: by tightening the cap in 2015 in such a way that an allowance bank would not continue to accumulate at increasing rates for three additional years before the imposition of Phase II. The main differences of the alternative proposed policy from simply introducing the Phase II cap by 2015 are:

° Under the commenter's proposed alternative there would be no formally binding cap in the 2010 2015 time frame, providing further guarantees that early reductions would be 9 120 Table 7. Quantities of New ACI Retrofits by Time Period ( MW) With Phase I Cap Set at Co benefits Level, for Alternative Timings of Phase II Cap Year Standard Low S Coal Assumptions ( 2010 co benefits = 40 tons) Low Supply Growth of Low S Bituminous ( 2010 co benefits = 38.8 tons)

15 ton cap by 2015 24 ton cap in 2015 2017 15 ton cap by 2015 24 ton cap in 2015 2017 2004 1,050 1,050 1,050 1,050 2008 1 1 1 1 2010 18,189 6,491 18,892 7,424 2012 15,715 12,029 18,204 14,466 2015 31,126 27,590 24,294 22,274 2018 17,417 23,780 22,792 26,686 2020 27,004 39,080 26,905 37,341 2030 4,044 5,024 2,902 5,469 against literal co benefits rather than against an inherently uncertain estimate of what that co benefit level would be. From a modeling perspective, where no uncertainties are simulated, this would have no impact on our results, but it obviously does have relevance to consideration of cost risks. 9 121 ° Another difference that remains open to deliberation is the precise level of the cap in the 2015 2017 period. In one sensitivity case the commenter used 15 tons, whereas the alternative proposal by the commenter allows it to be 24 tons, substantially less stringent. The correct level to choose for the interim cap could be informed by whether it significantly alters the timing of attainment of the 15 ton emissions goal. The commenter's analyses indicate that a 24 ton cap in 2015 would ensure the prospects of prompt attainment of the 15 ton goal while maintaining a relatively gradual rate of Hg control investments during Phase I and keeping policy costs low.

It is important to note that the modest impacts on costs from an early introduction of Phase II only occur when this acceleration is combined with a Phase I period that is truly set at co benefits ( either by providing early reduction credits or by setting the cap at an accurate estimate of the literal co benefits level). Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for discussion of modeling analysis.

7. Cinergy estimated a co benefit of Hg reductions associated with implementation of the proposed CAIR at 38 tons in 2010; EEI Estimated a co benefit level of 40 tons in 2010. EPA additional comment on the reasonableness of its IPM assumptions for co benefit reductions. EPA also sought comment on appropriate emission modification factors ( EMF)   a component of the estimated Hg co benefit reductions.

Comment:

One commenter ( OAR 2002 0056 5464) believed the modeled cost estimates were too high and the assumptions of co benefits from the proposed Clean Air Interstate Rule were lower than even EPA's projections.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for discussion of modeling analysis.

Comment:

One commenter ( OAR 2002 0056 5332) stated that EPA requests comments on the " co benefits" of Hg reductions associatewith implementation of the proposed CAIR. This issue is extremely important, as EPA is proposing to establish the Hg co benefits level as the first phase 9 122 emission limitation of its section 111 proposal.

Initially, the Agency had estimated a Hg co benefits level of 26 tons ( down from 48 tons); that is, it estimated that air pollution control devices installed to reduce the emissions of pollutants other than Hg from coal fired units would reduce Hg emissions by 22 tons, resulting in the incidental reduction of Hg emissions to a level of 26 tons. Based apparently on subsequent revisions to its modeling assumptions, EPA increased the co benefits level to the current estimate of 34 tons; that is, it concluded that incidental Hg removal would be less than originally estimated, 14 tons rather than 22 tons. Now, some stakeholders are suggesting that the co benefits level should be raised to something closer to 40 tons, meaning that incidental Hg reductions would be even lower ( only eight tons). Apart from the technical justification or lack thereof for this co benefits level ( see discussion below), the commenter noted that a cap and trade program with a 40 ton cap would free a great many sources from the need to make any reduction at all in their emissions of Hg. It would also allow many sources easily to over control in Phase I, bank the excess allowances, and use the banked allowances in future control years. This would push back the time that the Phase II cap will ultimately be achieved even further than is the case under EPA's currently proposed cap and trade proposal.

Based on its modeling, EPA concludes that average Hg removal from existing air pollution control devices across all coal types and control configurations is currently approximately 36 percent ( 48 tons emitted versus 75 tons contained in coal). EPA currently estimates that with the controls installed to comply with the CAIR proposal, annual Hg emissions from existing air pollution control equipment will drop further, from 48 tons to 34 tons per year, which represents about a 29 percent reduction from current emissions.

However, EPA's estimate of Hg co benefit levels reflect only incidental Hg reduction from control devices designed and operated to remove other air pollutants, such as SO 2, NO x, and particulate matter, with no attempt to optimize their operation for Hg removal. The commenter believed that the capture of Hg by existing controls can be increased significantly, simply by optimizing reductions from equipment installed to control other pollutants. A great deal of work is being done on measures that can be taken to optimize Hg reductions from existing air pollution control equipment, including the injection of oxidants ( e. g., chloride) into flue gas to promote the oxidation of elemental Hg from SCR at units burning lower rank coals ( which are typically low in chloride levels), and the addition of chemicals to enhance the removal of oxidized Hg in wet FGD systems and to prevent re emissions of Hg.

The commenter believed that the Hg co benefits of CAIR should perhaps be reduced from EPA's current estimate of 34 tons; in other words, the commenter's view was that reductions in Hg emissions achieved as a co benefit of efforts to control other pollutants are greater than EPA currently estimates. By the same token, the commenter did not believe that there would be any justification for increasing the Hg co benefits figure to more than 34 tons, as that would require the conclusion that other controls would not be as effective in reducing Hg emissions as the available data indicate. 9 123 Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The first phase cap is based on EPA modeling of the Hg co benefits of SO 2 and NOx controls installed for compliance with the CAIR rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for discussion of emissions projections. As discussed in the NODA, for the final rulemaking analysis, EPA has made changes to some of its co benefit assumptions for subbituminous units with SCR and FGD controls. EPA is also using a newer version of EPA's IPM for the final rulemaking. Changes to the modeling assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004).

Comment:

One commenter ( OAR 2002 0056 5446) said there is considerable uncertainty over the extent of " co benefit" reductions; however the current IPM assumptions fall within the likely range of co benefit reductions.

Care must be taken when assuming co benefit reductions as most reductions are calculated from analysis of the ICR emissions data which represent a limited snapshot of emissions from a few units taken over a very short period of time, with a limited number of coals. The data do not account for the wide variability of coals and process conditions encompassed by the full fleet of generator boilers. As stated previously the EPA must undertake some form of risk or probability analysis that considers variability in coal properties and unit performance to if it is to fully understand the implications of the proposed rule.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The first phase cap is based on EPA modeling of the Hg co benefits of SO 2 and NOx controls installed for compliance with the CAIR rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for discussion of emissions projections. As discussed in the NODA, for the final rulemaking analysis, EPA has made changes to some of its co benefit assumptions for subbituminous units with SCR and FGD controls. EPA is also using a newer version of EPA's IPM for the final rulemaking. Changes to the modeling assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004).

Comment:

One commenter ( OAR 2002 0056 5510) stated that in regard to co benefit reductions ( or corresponding emission modification factors, EMF), the commenter noted that most of the 9 124 estimates are based upon analysis of EPA's 1999 ICR data set. The commenter pointed out in comments dated May 14, 2004, the ICR emissions data represent a limited snapshot of emissions from a few units taken over a very short period of time, with a limited number of fuels. The data do not account for the wide variability of coals and process conditions encompassed by the full fleet of utility boilers. As a result, relatively little is known about long term Hg emissions performance of the units that were tested or what may be achieved through a broader application of co benefit technologies. Because of the lack of understanding associated with the level of Hg reductions that will be achieved through co benefit reductions or future removal technologies, the commenter had recommended an alternative cap and trade program. This alternative would provide for co benefit reductions in the first phase, coupled with an assessment of Hg emissions and performance characteristics of control technologies. An interim cap   effective in 2015   and coal type allocation adjustment factors would be based on this assessment. A final cap of 15 tons would be effective 2018.

The advantages to this proposal are: 1) it allows for the use of actual emissions data   as opposed to speculation about what may be achievable in the future   in the setting of the interim cap ( i. e., it provides for a target that is known to be achievable); 2) it will provide for a mechanism that allows EPA to ensure a balance regulatory approach to Hg reductions ( i. e., a rule that does not create regional disparities by advantaging one coal type over another). The commenter was particularly concerned about this issue because its members produce coal in every coal producing region of the US, and represent coals of every rank.

Proposed allocation adjustment factors are based EPA's assessment of the relative ease with which Hg can be removed from different coal types; their intent is to " level the playing field." Because reductions associated with cobenefits are still not well understood, and Hg specific control technologies will not be available until the 2010 time frame, the allocation adjustment factors should not be set until EPA has a better sense of the capabilities of these technologies.