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Part 246 General Provisions - Assessment of Public Comments

Overview

The Department has received thousands of comments concerning the regulatory schedule for implementing emission limitations and standards. The Department will address these comments at the outset.

Some commenters stated simply that the Department should finalize a regulation requiring power plants to reduce mercury emissions by 2010. See Comment 2. Some commenters stated that the Department should reduce emissions 90 percent by 2010 to protect the general health and welfare of humans and the environment. See Comment 3. Other commenters express the view that the Department should finalize a regulation requiring power plants to reduce their mercury emissions by 90 percent by 2010 due to the adverse impacts of mercury on public health and the contamination of fish and wildlife and water bodies. See Comments 3 and 4. Some commenters have stated that the Department should reduce emissions 90 percent by 2010 because of their concern of the increasing incidence of autism. See Comment 6. Some commenters have stated that the Department's docket letter submitted to the EPA for the proposed National Emission Standard for Hazardous Air Pollutant (NESHAP) expressed the view that the NESHAP emission limits must be implemented within three years to comply with the Clean Air Act's Section 112 provisions for establishing Maximum Achievable Control Technology Standards (MACT). See Comments 12 and 13. Other commenters have noted that other States are requiring 90 percent reductions in a timeframe more consistent with the MACT standard and so should New York.

The Department is anxious to reduce mercury emissions from coal-fired power plants and believes a strict emission limit that will achieve an overall 90 percent reduction in mercury emissions is both necessary and feasible. The Department does not, however, believe this level of reduction can be achieved by 2010 for New York facilities.

While the Department disagrees with the United States Environmental Protection Agency's (EPA) interpretation of Section 112 of the Clean Air Act (CAA), and the State is in fact challenging that interpretation in federal court, what Section 112 of the CAA means is irrelevant to this rulemaking. The responsibility to establish appropriate MACT standards and/or standards of performance for new sources rests squarely with EPA, not the Department and EPA has determined that mercury from coal-fired utilities should be regulated pursuant to Section 111 of the Act, not Section 112. The purpose of this rulemaking is to address the problem of mercury emissions in New York State, while at the same meeting the State's obligations under the federal Clean Air Mercury Rule (CAMR).

The Department is promulgating Part 246 pursuant to its statutory authority under the New York State Environmental Conservation Law (ECL). Part 246 will fulfill New York's obligation under the federal Clean Air Mercury Rule (CAMR), but will be significantly more protective of the public health and welfare of the people of the State than the federal rule. Neither CAMR, nor the ECL, imposes a three year deadline to implement the Phase II mercury emission limit in Part 246. This is important because the Phase II emission limits represent substantial reductions in mercury emissions over and above CAMR, and are more ambitious than any NESHAP or New Source Performance Standard (NSPS) EPA has proposed. The Department, taking into account all relevant statutory and regulatory considerations, reached a different determination with respect to the Part 246 Phase II emission limit.

As evidenced by the declaration of policy in ECL Article 19, the Department must balance both environmental and economic goals in carrying out its regulatory functions with respect to air pollution control:

ECL section 19-0103. The New York State Administrative Procedure Act (SAPA) provides a framework for the Department to utilize to meet these policy objectives in connection with rulemaking proceedings.

SAPA requires an agency to fully consider the regulatory impact of its action when it promulgates a rule or regulation. An agency must set forth its rationale for a proposed rule and consider "utilizing approaches which are designed to avoid undue deleterious economic effects or overly burdensome impacts of the rule upon persons, including persons residing in New York State's rural areas, directly or indirectly affected by it or upon the economy or administration of State or local government agencies. Such approaches shall include, but not be limited to, the specification of performance standards rather than design standards." SAPA section 202-a. An agency must address, among other things, the necessity for, and benefits derived from the rule, the costs of the rule, including the costs of implementation of, and continuing compliance with, the rule to regulated persons, alternative approaches considered and why they were not incorporated into the rule, and whether the rule exceeds minimum federal standards and why. Id.

The need to reduce mercury emissions into the atmosphere has never been in doubt. Nor is there any question that coal-fired electric utility units throughout New York State continue to emit significant quantities of mercury (Hg), estimated at 21.6 percent of the State's total anthropogenic mercury emissions from stationary sources. These emissions impact the State's natural resources and the health and welfare of New Yorkers, and pose a significant public health hazard, especially for children and pregnant women. Although the Department believed that effective nationwide control of mercury emissions can only be achieved through strict federal standards, we recognize that EPA's rules fall far short of providing adequate protection and are now moving forward with State regulations to reduce mercury emissions.

In determining the optimal schedule for implementing Part 246 emission reductions, the Department, as required by the ECL and SAPA, had to consider, along with the environmental and public health benefits of the rule, the impact of the rule on regulated entities. Specifically, the Department considered a number of relevant technical, economic, and regulatory factors, including: the feasibility of the 0.6 lb of mercury per TBtu emission limit; the extensive retrofit and reconfiguration of existing facilities that will be needed to achieve compliance with the 0.6 lb of mercury per TBtu emission limit; other State and Federal regulations that will come into effect during the same timeframe as Part 246; and the need for reliable supplies of electricity in the State.

Feasibility

The Department's decision with respect to the implementation of the 0.6 lb of mercury per trillion Btu (0.6 lb Hg/10¹² Btu) emission limit is driven in part by the stringency of the standard. For example, compared to the NSPS promulgated by EPA of 2.0 lb of mercury per trillion Btu for electric generating units firing bituminous coal, Part 246's Phase II emission limit of 0.6 lb/10¹² Btu is significantly more stringent. Under the former standard, total mercury emissions from coal-fired utilities would be 500 lbs per year based upon the average fuel firing from 2000 to 2004; under the Phase II emission limit, emissions would be approximately 150 lbs per year. Unlike CAMR, which allows facilities to emit mercury in excess of applicable emission limits by purchasing allowances, Part 246 requires facilities to achieve strict compliance with applicable emission limits. DEC recognizes that none of the eleven existing coal-fired steam generating electric units currently operating in the State, or the two units that are on "cold standby", can meet the Phase II emission limit with existing pollution control equipment or by switching from bituminous to sub-bituminous coal. These facilities will need to substantially reduce emissions of SO₂, NO_x and/or Particulate Matter, from current baseline levels and control these pollutants on an on-going basis in order to achieve compliance with the Phase II mercury emission limit.

The Department believes the 0.6 lb Hg/10¹² Btu limit is feasible, however, at the present time it is only being achieved by select facilities that have installed state of the art pollution control equipment within the past several years. The Department of Energy has funded demonstration studies/pilot projects at numerous electric utilities utilizing a variety of coal types, boiler types, control equipment to test the efficacy of mercury control technology utilizing activated carbon, oxidation catalysts, advanced baghouse configurations, as well as the implementation of a new continuous emission monitoring technology for the measurement of mercury. Trial studies involving slipstream tests and some full scale testing on a relatively short term basis have demonstrated significant reductions in mercury, but one of the most important aspects of the testing to date is that each electric utility is unique and one technology does not fit all scenarios. The most promising reductions were found using brominated activated carbon injection and subbituminous coal in achieving 90 percent mercury removal with varying particle control devices but this does not represent the technology currently employed in New York and New York's facilities will need to make changes to their particle control devices to achieve similar results. The excellent work done by the Department of Energy's National Energy Testing Laboratory (DOE/NETL) has shown that technology does exist and can be utilized at electric utilities but plant operators and owners need to begin testing and implementing control strategies to determine which technology will work at their plant. The acceptance of DOE/NETL's clean coal technology program is underscored by the fact that numerous other states have proposed rules more stringent than CAMR.

Coordination with Other Regulations

Part 246 is one of several regulations affecting electric generating units that will be implemented in the 2009-2015 timeframe and overlap in terms of affected pollutants. The Clean Air Interstate Rule (CAIR), Regional Greenhouse Gas Initiative (RGGI), State Acid Deposition rules and the next generation particulate regulations, which are based upon the required State Implementation Plan for PM_2.5, are being implemented on roughly the same schedule as Part 246. Each of these rules imposes significant and substantive requirements in terms of emission limitations and reduction targets, continuous emission monitoring and recordkeeping requirements. Several rules target the same pollutants. Nearly all of the rules will require facilities to undertake construction projects to install state-of-the-art pollution control equipment and/or emission monitoring equipment. Most of the construction work will need to occur during non-peak operating periods (Spring and Fall) to avoid straining the electric generating system during peak operating periods (Summer cooling season and Winter heating season).

The Department believes it is essential for regulated entities to have a consistent timeframe for meeting these overlapping regulatory requirements to ensure compliance and reliability in the supply of electricity. Accordingly, in setting an effective date for the Phase II emission limits, the Department made a deliberate effort to ensure that the implementation of Part 246 requirements coordinated with other regulations. Part 246 is designed to have similar dates for achieving emission reductions as the CAIR rule to create consistency for the regulated industry. The second phase of Part 246 commences in 2015 in conjunction with both RGGI and the second phase of CAIR. As CAIR implements another round of SO₂ reductions, it is logical to coordinate mercury reductions with SO₂ reductions since they involve the same pollutants and will likely be achieved with the same pollution control technology and emissions monitoring equipment. CAMR, with its second phase implementation in 2018, would have imposed an additional regulatory timeframe for the regulated community to contend with. The Department believes that a better approach is to have consistent implementation dates for these regulations.

Conclusion

In the Department's view, the 2015 implementation date addresses the legitimate concerns of the regulated community while providing New Yorkers with the promise of substantial emission reductions above and beyond the reductions which would be attained under CAMR or the proposed, but not finalized, NESHAP or NSPS.

1. Commenters (ATTACHMENT 1.) stated that the Department should finalize a regulation requiring power plants to reduce their mercury emissions 90 percent by 2010.

Response: An overwhelming majority of letters and petitions asked the Department to enact a rule which would reduce mercury emissions ninety percent by 2010. Comments ranged from single lines asking for reduction by 2010, to those stating reasons as identified in comments 2, 3, 4 and 5. The Department has been tracking mercury contamination in fish and wildlife for many years and has vigorously worked to identify all mercury sources that can be targeted for reductions. In the last several years, the Department has enacted stricter regulations than the federal National Emission Standard for Hazardous Air Pollutants (NESHAPs) for large municipal waste combustors, Part 219-7, and has recently enacted rules to reduce mercury from consumer products and dental offices. Coal-fired electric generating units (EGUs) and Portland cement manufacturing plants have been identified as the next two source categories that the Department needs to control to reduce mercury contamination of the environment.

2. Commenters (ATTACHMENT 2.) stated that the Department should finalize a regulation requiring power plants to reduce their mercury emissions 90 percent by 2010 because of the general health and welfare of humans and the environment.

Response: The Department is well aware of the devastating effects mercury exposure can have on human health and the welfare of the environment. Since 1994, Department staff have worked with the EPA to produce the first Mercury Report to Congress in 1997 as mandated by the 1990 Clean Air Act. Whereas the detrimental health effects of mercury exposure have been documented for many years, the methods for controlling mercury emissions and its movement in the environment has only been actively addressed by researchers and the federal government for the last decade. The control of trace amounts of mercury in the large air streams found within stacks of coal fired power plants is less well known and has been subject to major Department of Energy research effort. It is only now that a concerted effort is being made to address this source of mercury. As described in the opening summary comment. New York coal-fired power plants need significant upgrading to accomplish this task and the Department agrees we cannot follow the federal government's current plan. As science and engineering professionals, however, we believe those desired upgrades cannot occur within the timeframe of 2010. The Department has proposed a rule that will result in mercury emissions reductions that will be protective of public health and the environment.

3. Commenters numbered 9632 to 9642,1158 and 397 stated "the Department should finalize a regulation requiring power plants to reduce their mercury emissions 90 percent by 2010 because of the following reasons:

a.) mercury is a dangerous neurotoxin, affecting the brain, which even in very small amounts greatly affects the developmental abilities of humans. Even low levels of mercury exposure in utero or during early childhood can cause poor attention span and language development, impaired memory and vision, difficulty processing information, and/or impaired fine motor coordination;

b.) the New York State Department of Health has advised against eating or limiting consumption of certain fish in water bodies throughout New York State due to elevated mercury levels found in many of New York's fish species particularly in the Adirondacks and Catskills;

c.) commenters state studies have clearly shown that mercury poisoned wildlife have reproductive and behavioral developmental problems. For example, fish have difficulty schooling and decreased spawning success; birds lay fewer eggs and have trouble caring for their chicks; and mammals have impaired motor skills that affect their ability to hunt and find food;

d.) not only does the mercury contamination in New York's fish create a public health threat to the approximately 1.5 million anglers who fish our waters every year, it also threatens the billion dollar recreational fishing industry in New York;"

Response: The Department agrees that the issues identified above are significant issues and the Department is actively committed to addressing these concerns. As stated in the Overview for numerous reasons the 2010 timeframe is not a realistic goal for coal-fired utilities operating in New York State to achieve compliance with the Phase II emission limit of 0.6 lbs Hg/10¹² Btu. The Department believes that the 2015 timeline will allow the regulated facilities to achieve significant reductions of mercury, SO₂, NO_x, PM and other hazardous air pollutants in a comprehensive manner. This will result in significant improvements in overall air quality.

4. Commenters stated the Department should finalize a regulation requiring power plants to reduce their mercury emissions by at least 90 percent by 2010 because of one or several of the following reasons:

a.) mercury is a dangerous neurotoxin, affecting the brain which even in very small amounts greatly affects the developmental abilities of humans. Even low levels of mercury exposure in utero or during early childhood can cause poor attention span and language development, impaired memory and vision, difficulty processing information, and/or impaired fine motor coordination;

b.) the New York State Department of Health has advised against eating or limiting consumption of certain fish in water bodies throughout New York State due to elevated mercury levels found in many of New York's fish species particularly in the Adirondacks and Catskills;

c.) commenters state studies have clearly shown that mercury poisoned wildlife have reproductive and behavioral developmental problems. For example, fish have difficulty schooling and decreased spawning success; birds lay fewer eggs and have trouble caring for their chicks; and mammals have impaired motor skills that affect their ability to hunt and find food;

d.) not only does the mercury contamination in New York's fish create a public health threat to the approximately 1.5 million anglers who fish our waters every year, it also threatens the billion dollar recreational fishing industry in New York;

e.) the contamination of New York's drinking water due to toxins such as mercury.

Response: The Department agrees that the issues identified above are significant issues and the Department is committed to addressing these concerns. As stated in the Overview, the 2010 timeframe is not a realistic goal for the reduction of mercury from this industry sector.

Mercury is a regulated contaminant under the federal Safe Drinking Water Act and the New York State Sanitary Code. In 1991, the United States Environmental Protection Agency established a standard (called the maximum contaminant level) of two micrograms per liter (2.0 ppb), to protect against the potential adverse health effects of exposure to mercury in public drinking water systems. Those individuals commenting on the potential contamination of drinking water should review Table 1 of Part 5, subpart 5-1 of the New York State's Department of Health (NYSDOH) maximum concentration levels (MCL) standards for public drinking water. The Safe Drinking Water Act requires public water suppliers to regularly monitor mercury in drinking water. Currently, all public water systems in New York are in compliance with the mercury MCL. If mercury levels are found to be consistently above the maximum contaminant level, a public water supplier must take steps to reduce the amount of mercury so that it is consistently below the MCL. The water supplier must also notify the public via newspapers, radio, TV or other means. Additional actions, such as providing alternative drinking water supplies, may be required to reduce the risks of health effects associated with mercury exposure. The public drinking water standard can also be used as a health guideline for private water supplies. In addition, mercury in surface water and groundwater is regulated under Part 701 of the New York State Water Quality Regulations.

The Department will continue in its efforts to reduce mercury releases from all sectors. Human exposure to mercury from drinking water supplies in New York is not a significant exposure pathway when compared to exposure from fish consumption. Mercury concentrations are much higher in fish than in the water in which they live. This is brought about by a process involving sediment microorganisms at the bottom of the water body and the entire food chain, resulting in certain fish species being contaminated with dangerous levels of mercury through the process of biomagnification. Humans, birds or mammals who frequently eat these fish could suffer potential health hazards.

The United States Environmental Protection Agency and the United States Food and Drug Administration have issued recommendations for selecting and eating commercial shellfish that may be contaminated with mercury. Of particular interest are the consumption guidelines for women of childbearing age and young children. This information is available on the EPA website.

The New York State Department of Health (DOH) issues an annual report "Chemicals in Sportfish and Game" Sportfish and wildlife taken in New York State may contain potentially harmful levels of various chemical contaminants, including mercury. The advisory is developed and updated annually and is available on the DOH website.

5. Commenters (ATTACHMENT 8.) stated that the Department should finalize a regulation requiring power plants to reduce their mercury emissions by at least 90 percent by 2010 because of their concerns of the increasing incidence of autism in our society and the potential that mercury could be a contributing factor.

Response: Mercury is a potent neurotoxin and the Department acknowledges the public's concern regarding a possible link between mercury exposure and developmental disorders such as autism. Autism is a complex neurodevelopmental disorder that is thought to involve an interaction between multiple, variable susceptibility genes, epigenetic effects as well as environmental factors. There is much controversy about the causes of autism and increasing prevalence rates, but presently there is no evidence of a causal association between environmental exposure to mercury and autism. Although mercury is ubiquitous in our environment, further research is needed to investigate levels of mercury exposure and adverse health effects during early childhood development. Part 246 provides a feasible, coordinated approach that will provide greater control than either the cap-and-trade approach or a MACT-based approach. Ultimately, with the more stringent mercury emission limit, our proposed regulation will effectively minimize the potential for mercury exposure and adverse health effects.

6. Commenter number 9632 states industry has claimed "yet another rule which will lead to power outages. This has been their claim for every rule put forward that causes them to invest in pollution equipment, including New York's Acid Deposition Reduction Program (ADRP), which was delayed for several years by industry litigation. ADRP is now in effect with no deleterious effects on the economy or ratepayers."

Response: The Department did not receive comments from industry in connection with this rulemaking claiming that Part 246 will lead to power outages. Potential interruptions in the supply of electricity were a concern of the Department's, however, and, as discussed in responses to other comments, the Department addressed this concern by imposing a 2015 deadline to meet Phase II emission limit requirements.

One significant difference between regulations controlling sulfur dioxide and nitrogen oxide for the reduction of acid rain precursors and the regulations reducing mercury emissions is that the technology needed to control mercury includes good sulfur dioxide, particle and nitrogen oxide control and in addition carbon injection to achieve mercury emissions at 90 percent or greater. The addition of activated carbon is a new process with varying outcomes when tested and sources will need the additional time to establish 90 percent control or better.

The best approach to control mercury is to focus on a multi-pollutant reduction strategy. At the same time, the Department needs to satisfy the federal requirement to reduce mercury from the coal-fired electric utility sector, it also needs to address issues such as seasonal ozone, acid rain and the emissions of fine particulate. To address these pollutants on an individual basis will cause an increase in other pollutants if not done correctly. For example, the injection of activated carbon through electrostatic precipitators has the potential to increase particulates. Also, facilities subjected to ADRP were able to satisfy these requirements by either buying credits or purchasing low-sulfur subbituminous coal. The purchase of low sulfur coal will not suffice in the control strategy of reducing mercury. The current pollution control equipment of New York State's coal-fired electric utility fleet cannot capture the mercury being emitted from subbituminous coal. This type of coal emits elemental mercury which remains in the gaseous state and will not be controlled by electrostatic precipitators alone. Some of New York's largest facilities currently have this type of particulate control. To control mercury and be in the position for the next round of significant sulfur reductions determined by Clean Air Interstate Rule, (CAIR) facilities will need to install controls such as wet scrubbers or dry scrubbing absorbent with lime injection followed by a fabric filter. These control options are more likely to be the best possible control option to deal with multi-pollutant capture and control scenarios.

7. Commenter number 9632 states "We have heard in the past that a shortage of boilermakers makes it difficult to meet compliance deadlines."

Response: The Department believes the Phase I and Phase II implementation schedules in Part 246 are workable and that facilities will be able to meet the compliance deadlines in the regulations. Several literature sources have mentioned that the availability of boilermakers has been difficult for the Selective Catalytic Reduction projects underway to control nitrogen oxides for the NO_x SIP Call. However, where shortages have been experienced in manning SCR construction projects with adequate numbers of boilermakers, manpower planning had been done with short notice. Many boilermakers travel to work sites that are out of their local area. A large project may require mobilization of several hundred boilermakers to a site, which will frequently require pulling members from other parts of the country. In the current, competitive environment for utilities, power plant owners are reluctant to provide advance notice of when outages will occur. Therefore, in some cases contractors must find manpower on very short notice. The boilermaker's union (The International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers) attempts to provide the necessary manpower to the contractors. However, with very short notice, it is sometimes difficult to move the manpower to the site in the short time desired. Nevertheless, the union has been successful in providing sufficient manpower to the project sites where they have had adequate advance notice.4 Therefore, although there is a problem with the availability of boilermakers, better coordination may have avoided the labor shortage problems. The Department is addressing these concerns with a phased implementation approach which gives facilities sufficient time to come into compliance.

8. Commenter number 9632 stated "As a compromise to the 2010 vs. 2015 debate, DEC may consider a hybrid approach, which would allow the 0.6 lb Hg/TBtu standard (roughly the 90 percent reduction) by 2010 for existing plants on a facility-wide basis, as the draft rule would currently do for existing facilities under phase I (2010-2014) except with deeper reductions. Phase II (2015 and beyond) could then use the same 0.6 lb Hg/TBtu on a unit-by-unit basis."

Response: The Department considered but did not include this option in Part 246 because in order to achieve mercury reductions of 90 percent, extensive modifications to all existing pollution control equipment is necessary. Pilot testing conducted by DOE/NETL over the past six years shows that activated or enhanced carbon injection alone will have varying degrees of success with facilities currently utilizing only electrostatic precipitators. The current fleet of New York's electric steam generating units needs to be upgraded significantly to meet 90 percent reduction of mercury emissions. As stated in other responses, because affected EGUs will be subject to other State regulations, the Department decided to coordinate the compliance dates. See Overview.

9. Commenters numbered 9633, 9637, 9638, 9640, 9641 stated "DEC did not require mercury limits at oil-fired power plants in its draft regulation."

Response: The Department understands the concern expressed by the comment that all sources of mercury, not just coal-fired electric utility units, contribute to health risks and should be considered for regulation. At this time, the Department is proposing to regulate mercury emissions from coal-fired utilities because this source category emits significantly more mercury than oil-fired utilities and the pollution control technology for oil-fired utilities is not as advanced as it is for coal-fired units. In February of 1998, the USEPA published the Report to Congress Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units (Study). This Report shows that mercury emissions from oil-fired units are trivial when compared to emissions from coal-fired units. Mercury emissions from oil-fired utilities were found to be less than 0.5 percent of the mercury emissions from coal-fired utilities. This equates to approximately 400 pounds of mercury emitted annually from oil-fired units across the United States compared to the estimated 103,200 pounds from coal-fired units.

The Department's own inventory from 2002, which was used in the Northeast States for Coordinated Air Use Management (NESCAUM) update to its Mercury Study Framework for Action, conservatively estimated mercury emissions from oil-fired utilities to be 5 percent of all combustion related emissions in New York State. Part 246 addresses only coal-fired utilities because of the great percentage of emissions released into New York State and because it is required by federal law to address coal-fired utilities at this time. The technology to control mercury in oil and in the flue gas of oil-fired utilities lags behind coal-fired utilities and it would not be prudent for the Department to require a percent reduction of mercury from oil-fired EGUs until the Department has identified effective control options.

10. Commenters numbered 9633, 9636, 9637, 9638, 9639, 9640, 9641 stated "the lack of specific penalty provisions for non-compliance" is not included in this rulemaking."

Response: State law provides civil and criminal enforcement authority consistent with the Clean Air Act and 40 CFR Part 70. Penalty provisions regarding enforcement for violations of air pollution rules and regulations promulgated pursuant to Article 19 of the ECL are included in ECL Article 19 and Title 21 of Article 71 of the ECL. See ECL section 19-0305 (commissioner; enforcement power), 71-2103 (violations, civil liability), 71-2105 (criminal liability for violations). This authority allows for the recovery of penalties and fines in a maximum amount of not less than $15,000 per day of violation. The Department has traditionally conducted its air enforcement program, including the enforcement of applicable federal requirements and Title V operating permits, pursuant to its statutory authority and has not promulgated specific regulations setting forth criminal and civil liability for specific violations. This long-standing practice will continue with the implementation of Part 246. There is no need for a specific penalty provision in Part 246.

11. Commenters numbered 9633, 9636, 9637, 9638, 9639, 9640, 9641 states "Studies show that local power plants are a significant portion of the mercury contamination problem. The most recent information comes from an EPA-funded study in Steubenville Ohio, which found that about 70 percent of the mercury pollution from local coal plants fell within 60 miles. This puts a finer point on EPA's 1997 estimate that these types of mercury emissions travel 50-500 miles. The data make it clear that local controls will mean less mercury pollution falling into local waters."

Response: The Department recently reviewed the journal article these commenters refer to, Source of Mercury Wet Deposition in Eastern Ohio, USA by Gerald Keeler. The Department believes that the Northeast is a depository for mercury emissions from many regions of the country based upon sampling of lakes and fish within the Adirondacks and Catskill mountains. The Department's own analysis that resulted from the 1999 Information Collection Request (ICR) data revealed that the predominantly bituminous coal-fired utilities in the States east of the Mississippi should have mercury deposition from the Midwest states east to the Catskills and Adirondacks. This is due to the high percentage of reactive gas mercury (RGM) being emitted from Midwest facilities and RGM's water solubility which allows it to be deposited during rain events. The Electric Power Research Institute (EPRI) position is that most RGM converts to elemental mercury and becomes part of the global sink. This has never been the Department's position and work such as Keeler, et.al shows the potential of mercury depositing locally and within several hundred miles of major coal-fired utilities due to its content of RGM.

The Department believes it is taking the correct action to reduce mercury emissions and not participate in a cap-and-trade program mercury as described in the federal CAMR. The cap-and-trade program does not necessarily require facilities to achieve emission reductions only hold enough allowances to account for emissions. The purchasing of allocations can allow affected units to continue emitting at the same emission level until 2018 and beyond. The purchasing of emission allocations does not necessarily mean that actual emission reductions will occur at EGUs whose emissions impact New York. The trading allowances could translate into emissions being allowed to stay the same or possibly even increasing from neighboring states. Only real emission reductions would reduce the overall emission of mercury being deposited in New York State. As a forward thinking environmental agency, the Department believes that reducing emissions will likewise reduce detrimental impacts of mercury deposition and all States should make a similar effort to reduce their mercury emissions by 90 percent and not participate in the mercury cap-and-trade program.

12. Commenters numbered 9633, 9634, 9637, 9640, 9641 state "waiting until 2015 for full compliance is not in keeping with the agency's own interpretation of the Clean Air Act. DEC rebuked the EPA's 2018 timeline, asserting that "EPA is illegally extending the time for compliance by at least fourteen years" longer than the Clean Air Act allows. The language of the Clean Air Act is clear on the issue of compliance deadlines: three years from the date of promulgation. Please provide a detailed justification for the DEC decision to ignore the requirements of the Clean Air Act and delay the mercury reduction requirements until 2015."

Response: See Overview

13. Commenters numbered 9637, 9640, 9641 states "What data did DEC use to support its decision to not require a mercury reduction timeframe that is consistent with its own arguments to EPA on the matter?"

Response: See Overview

14. Commenters numbered 9633, 9634, 9637, 9640, 9641, 397 states "A number of other states have finalized plant-specific mercury limits in a timeline more consistent with the MACT standard, and others are in the process of doing so. New Jersey is requiring a 90 percent reduction at each plant by December 15, 2007, with flexibility provided for plants installing multi-pollutant controls. Connecticut is requiring a 90 percent plant-specific reduction by July 1, 2008. Massachusetts is requiring a reduction equivalent to New York's proposed standard by January 1, 2008 and then further reduction by 2012. Minnesota is requiring 90 percent reductions using dry scrubbers by 2010 (and wet scrubber by 2012). Illinois, a major coal-burning state has proposed requiring 90 percent reductions by July 1, 2009. Even Pennsylvania, the nation's second largest mercury emitter is in the process of finalizing a rule requiring an 80 percent reduction by 2010 and 90 percent reduction by 2015."

Response: See Overview

The Department does not believe it is appropriate to compare various States in terms of their mercury reduction programs. First, not all States are starting from the same baseline of mercury emissions per trillion Btu of heat input, (coal burned). Second, the number of affected facilities differs greatly in size, pollution control equipment and number of steam generating units per facility. Third, some affected facilities in other States have actively pursued Department of Energy grants and assistance.

First, not all States are starting from the same baseline of mercury emissions per trillion Btu of heat input, (coal burned). For example, according to the 1999 Information Collection Request (ICR), New York's 1999 state-wide average baseline emission rate was 6.2 lbs Hg/10¹² Btu. Part 246's Phase I will reduce emissions by implementing a state-wide cap which has the effect of reducing emissions 55 percent and equates to a state-wide average emission rate of approximately 2.3 lbs Hg/10¹² Btu until 2014. Pennsylvania's state-wide average baseline emission rate for the 1999 ICR was 8.5 lbs Hg/10¹² Btu heat input. Pennsylvania's regulation requires facilities to reduce mercury emissions by 80 percent by 2010 or the option of meeting a standard of 2.3 lbs Hg/10¹² heat input. Therefore, Pennsylvania's rule requiring an 80 percent reduction would equate to a state-wide average baseline emission rate of 1.7 lbs Hg/10¹² heat input but emissions would not be required by law to be below the 2.3 pounds lbs Hg/10¹² emission standard. Therefore, the two states would have equal outcomes with two different percent reductions scenarios. In 2015, Pennsylvania requires 90 percent or 1.15 lbs Hg/10¹² Btu whereas proposed Part 246 requires 0.6 lbs Hg/10¹² Btu or half the rate allowed in Pennsylvania.

Second, comparing New York State to other States who are declaring large reductions in the next few years is not appropriate. Connecticut currently has two facilities, AES Thames, equipped with a limestone dry scrubber and baghouse and would need little modification to achieve 90 percent reduction of mercury. The other facility, Bridgeport Harbor, has been burning significantly more oil and less coal. In 1999, the facility burned one hundred percent number 6 oil. New Jersey has six coal-fired plants, two are cogeneration plants and need little modification to achieve 90 percent mercury reductions and the other plants are designed similar to New York's larger plants with electrostatic precipitators for particle control and use low-sulfur complying coal. New Jersey Department of Environmental Protection staff have advised Department staff that New Jersey's largest plant, Hudson Generating, will not meet the regulatory deadline next year and will most likely use the option of multi-pollutant controls and mercury reduction by 2012. Illinois requirements are as follows: 90 percent reduction with intrastate averaging by June 2009; 75 percent individual plant reduction by June 2009; 90 percent individual plant reduction by the end of 2012. Illinois fires a substantial amount of subbituminous coal and the data collected through the pilot program initiated by the DOE/NETL has determined that subbituminous coal can be easier to control than bituminous coal. Some New York facilities have switched to subbituminous coal to meet the regulation Part 238 in New York State for the acid rain reduction program, but this fuel conversion is not Statewide and the Department does not believe that fuel conversion alone can solve the mercury problem. Improperly controlled subbituminous coal will actually increase mercury emissions. Michigan and Illinois will need to do extensive testing and trouble shooting to meet their 90 percent reduction coals statewide.

Lastly, the Commonwealth of Massachusetts has been working on a regulation to reduce mercury since 2000 and the rule was promulgated in May of 2004. In 2000, Massachusetts has four electric steam generating facilities, Brayton Point, Mount Tom, Salem Harbor and Somerset each using low sulfur complying coal and cold-side electrostatic precipitators for particle control. Brayton Point and Salem Harbor were chosen to be part DOE/NETL pilot projects to test the use of activated carbon injection for mercury control. The short term testing for Brayton Point was completed August 2002. The activated carbon was injected between the first and second cold-side ESPs. During baseline testing the average mercury removal ranged from 30 to 90 percent. For Salem Harbor, testing was completed in November of 2002. During baseline testing without activated carbon injection, average mercury capture was approximately 90 percent. According to NETL, the high baseline mercury removal was attributed to high levels of unburned carbon (Loss on Ignition was 25 to 30 percent) and low flue gas temperature (approx. 270°F). Baseline mercury removal decreased from approximately 90 percent to 20 percent while increasing flue gas temperature from 270 to 350°F. A maximum mercury capture of only 45 percent was achieved at 350°F with activated carbon injection. These tests are part of on-going pilot test projects conducted over short periods of time and only on a portion of the flue gas. As could be observed from these two facilities, varying degree of control was attributed to a variety of combustion factors. Any facility attempting to demonstrate mercury reduction based upon activated carbon must do intensive site specific testing to realize mercury reduction achieving 90 percent. Testing such as this is needed for New York State's facilities and the Department will be carefully evaluating Massachusetts's progress in achieving and monitoring these emission rates.

15. Commenters numbered 9637, 9640, 9641 states "DEC provides no justification for how credits were distributed among the facilities."

Response: The Department divided New York State's annual mercury budget of 786 pounds among the eleven currently operating coal-fired utilities, reserving a "set aside" of 40 pounds for new units and existing units on cold-standby, to establish an annual mercury emission limit. The Department created a mercury emission cap for each electric steam generating facility (Mercury Reduction Program Facility) according to the procedure used in the CAMR model rule. This is section 60.4142 of Subpart HHHH of 40 CFR 60. According to CAMR, the average of the three highest amounts of the facility's heat input (coal burned) for the years of 2000 through 2004 will be used to calculate a value representing an individual facility's average coal use (heat input) compared to the state-wide total heat input. This percentage of facility heat input compared to the total heat input was subsequently multiplied by the 746 pounds of mercury for each facility to establish a cap.

The Department opted to use the more conservative method in 40 CFR 60.4142 to establish the facility-specific emission caps. The methodology in 40 CFR 60.4142 requires the State to first multiply the facility's average coal use (heat input) from the three year average period by 1.0 for bituminous coal, 1.3 for subbituminous coal and 3.0 for lignite. EPA originally implemented this methodology because it was believed that mercury emissions from subbituminous coal was more difficult to control than bituminous coal and facilities burning subbituminous should be granted higher allocations under the cap-and-trade rule. With the extensive pilot and full scale demonstrations subsidized by DOE/NETL, and especially the Pleasant Prairie facility in Illinois, it was discovered subbituminous was not as difficult to control. However, EPA did not subsequently modify CAMR to remove this adjustment.

16. Commenters numbered 9633, 9636, 9637 states "Part 246.5 allows more than a third of the existing plants to at least double their mercury pollution from EPA estimates. According to Table 1, some coal-fired electric steam generating facilities were granted emissions greater than their current estimated emissions of mercury."

Response: As discussed above in comment number 15, the Department followed the methodology set forth in CAMR to distribute emissions among existing MRP units. In 1999, EPA initiated the Information Collection Request (ICR) mercury monitoring effort. Under the ICR, EPA stack tested 80 facilities and over 200 electric generating units in the nation to determine mercury emission reduction factors for a variety of fuels, boiler configurations, and pollution control equipment. Another part of the ICR was for each facility to monitor fuel use and mercury content of the fuel on a monthly basis. From this ICR effort, EPA was able to extrapolate emissions for every affected coal-fired EGU in the nation. Facilities with existing pollution control equipment capable of reducing mercury would have less actual emissions. For example, a facility with a wet scrubber will achieve an estimated 78 percent reduction of mercury while one with a hot-side electrostatic precipitator achieves virtually no mercury control. If these two types of facilities burned the same amount of fuel, their emission cap in Table 1 would be the same according to methodology described 40 CFR 60.4142. (see comment number 15) The two facilities in the above example with the same allocation of mercury based upon fuel heat input would not have the same actual mercury emissions because of the greater mercury reduction by the facility utilizing the wet scrubber.

The facility with the higher cap and lower actual emissions would not be able to increase its mercury emissions to the limit of the annual emission cap in Table 1 because coal-fired power plants operate at a near maximum potential year round; their mercury emissions may fluctuate slightly but will not increase significantly. Therefore, facilities operating below their allocated cap would be a net gain for the environment. The Department expects this to occur and the yearly mercury emissions will be below the 786 pound state-wide budget.

17. Commenters numbered 9633, 9634, 9635, 9636, 9637, 9640, 9641, 397 states "DEC's proposed rule allows almost 3000 more pounds of mercury pollution than setting unit specific limits in 2010."

Response: The Commenter claims that by not requiring 90 percent reduction by 2010, the Department will allow an additional 3000 pounds of mercury during the time period between 2010 and 2014. The Department does not believe that an additional 3000 pounds of mercury will be emitted. The Commenter calculates the 3000 pounds by subtracting the projected 150 pounds per year in 2015 from the 746 pounds allowed in 2010 and multiplying it by five. As the Department stated in the response to Comment 16, those facilities which emit below their annual emission cap will continue to do so. The Department estimates the annual emission rate from coal-fired electric steam generating facilities to be approximately 600 pounds in 2000 to 2014. The commenters' calculations also assume that affected facilities will increase control from 50 percent to 90 percent immediately and this cannot happen. Affected facilities will need to start construction of any needed pollution control equipment some time prior to 2015 to allow ample time to build, test, and troubleshoot their pollution control systems. It is more likely that a facility would be at the 90 percent emission rate prior to 2015, in 2014 for example, rather than 2015. Therefore, while the potential excess mercury emissions from 2010 to 2014 could be 3000 pounds, the actual mercury emissions are expected to be closer to 1800 - 2000 pounds for the time period between 2010 to December 31, 2014. ((600 lb/yr -150)*4 years).

18. Commenters numbered 9634, 9637, 9640, 9641 states "DEC comments on EPA's proposal repeatedly referenced the need to regulate both coal and oil-fired utility units as sources of mercury."

Response: The commenter is incorrect. The Department did not state that mercury should be reduced from coal and oil-fired utilities. The Department stated "The Department agrees with EPA's December 20, 2000 finding pursuant to CAA section 112(n)(1)(A) that it is appropriate and necessary to regulate coal- and oil- fired Utility Units under section 112(d). EPA lacks any authority to rescind this finding. EPA is obligated to promulgate appropriate MACT standards that would significantly reduce the current amount of emissions from Utility Units of mercury and nickel as well as other hazardous air pollutants." The Department was addressing the appropriateness of regulating nickel from oil-fired utility units, not mercury.

19. Commenter number 397 states "New York needs to put in place an immediate ban on any thermal reuse treatment of coal fly ash at or above this temperature. Because of the many mechanisms whereby mercury can be re-released from fly ash, any consideration of "beneficial use" schemes for coal fly ash should be halted."

Response: The commenter submitted data on all the beneficial use plans the Department has approved to date and states there is the potential for mercury reentrainment under thermal conditions when reusing this material. The Department agrees that coal's by-products have great potential to be released under thermal conditions and this issue needs to be evaluated when our Division of Solid Waste reviews any beneficial use determination. The Department intends to continue examining this issue as part of its overall state-wide mercury reduction strategy and future regulation of this material is possible. At the present time, however, the treatment of coal fly ash is not an issue that is addressed in CAMR and is beyond the scope of this regulation.

The Department will focus on the use of fly-ash as a material substitute in the Portland cement manufacturing industry. Portland cement manufacturing uses fly-ash to enhance certain metals, aluminum, iron and silicates in its raw ingredients and it is the captured mercury in the fly-ash which is reemitted once thermally treated. Due to greater stack controls of mercury, industry owners are concerned that the fly-ash will not be saleable. In papers presented at the DOE/NETL sponsored conference in Baltimore, August 28-31, 2006, industry representative estimated that the control of mercury and the potential loss of selling their fly-ash and combustion by products could increase the cost of control $20,000 per pound of mercury captured. DOE/NETL research has tried to address partitioning out the captured fly-ash with separate control devices to produce saleable fly-ash with minimal mercury content. The Department has addressed this issue in its Regulatory Impact Statement and estimates increase costs due landfilling of fly-ash to be between $2,000 and $20,000 per pound of mercury removed.

20. Commenter number 397 states "the use of coal as an energy source should be phased-out as soon as possible in New York State."

Response: This comment raises the question "What is an appropriate State Energy Policy?" This is beyond the scope of the proposed regulation. At this time, the Department needs to address the federal requirements of CAMR and CAIR which incorporates the use of coal as energy source.

21. Commenter number 397 states "NYSDEC to submit plans to USEPA by the deadline of November 17, 2006, in order to avoid compulsory compliance with EPA's laxer regulations and market-based "cap and trade" schemes."

Response: The Department agrees with the commenter and is working to ensure that all the necessary documents are filed with the United States Environmental Protection Agency in a timely manner.

22. Commenters numbered 9636, 9637, 9638, 9640, 9641 states "Why did DEC decide to grant a negative declaration under State Environmental Quality Review Act when considering this draft regulation? Commenters contend that the rulemaking process would have been better served if DEC compared the impacts of requiring 90 percent reductions at all mercury emitting units in 2010 versus coal-fired facilities in 2015 in a SEQRA analysis."

Response: The Department determined the significance of this rulemaking action in accordance with SEQRA and the Department's implementing regulations at 6 NYCRR Part 617. When the Department makes a determination of significance in connection with a rulemaking, the issue is not whether one regulatory alternative or emission standard is preferable to another. The issue is whether the adoption of the proposed regulation could be expected to cause a significant adverse impact to existing environmental conditions. The promulgation of Part 246 implicates none of the indicators of significant adverse impacts in 6 NYCRR 617.7(b), which include, among other things, a substantial adverse change in air or water quality or the creation of a hazard to human health. The adoption of Part 246 will have a significant positive impact on the environment by substantially reducing the amount of mercury emitted into the atmosphere and deposited into the environment by coal-fired utilities, one of the largest emitting source categories in the State. As the Department discussed in the Regulatory Impact Statement, reducing the deposition rate of mercury will reduce the mercury concentrations in fish and fish consumption is a significant exposure pathway for mercury as discussed in response to Comment 4. Consequently, because there are no adverse environmental impacts associated with this action, an Environmental Impact Statement is not required and the Department's issuance of a Negative Declaration is entirely appropriate under the circumstances.

See ECL section 8-0109, 6 NYCRR 617.7, Regulatory Impact Statement, Negative Declaration, Overview, and response to Comment 1.

23. Commenters numbered 9637, 9640, 9641 states "The first phase of DEC's draft regulation results in minimal mercury pollution reductions. DEC's allocation of 746 pounds of mercury, as in Phase I of the draft rule, guarantees only approximately 27 percent reductions from current emissions, using EPA's 1999 ICR Data."

Response: The commenters state correctly that if Mercury Reduction Program (MRP) facilities could emit at their potential capped emissions, the reduction in mercury emissions from the baseline levels as determined by the ICR and the Phase 1 cap would be 27 percent. As stated in Response to comments 16 and 17, MRP facilities that currently emit below their caps will not be increasing their emissions significantly above their baseline levels. The Department projects that the annual mercury emissions from the coal-fired electric utility sector are approximately 1,200 pounds, based upon coal use data and ICR emission factors. All facilities including those currently emitting below their allocated caps will equate to a yearly emission rate of 600 pounds in 2010, providing 50 percent reductions over baseline emissions in 2010.

24. Commenters numbered 9628 and 9631 states "the emissions testing requirement in Part 246.3(b) should be revised or eliminated. The subpart requires that all affected sources conduct two test series to determine speciated mercury concentrations upstream of all add-on air pollution control equipment (inlet) and also in the stack (or outlet) downstream of control equipment, and conduct fuel sampling and analysis for mercury and chlorine. We have two overarching concerns with the Part 246.3 testing requirements.

Response: First, the rationale for these two sets of stack tests is not included in the Rural Area Flexibility Analysis, Regulatory Flexibility Analysis for Small Business and Local Governments, Regulatory Impact Statement or Job Impact Statement. Second, the timeline for the tests, especially the second series, overlaps with other mercury stack testing required by the continuous mercury monitoring part of the rule, Part 246.7."

With regard to the requirement for inlet testing, the Department agrees that the same outcome can be determined with fuel sampling. Section 246.3(b)(iv) already requires fuel sampling during the required stack testing and the Department is revising the requirement in 246.3(b)(2) for inlet and outlet source testing in response to this comment. With regard to the second stack test requirement, the Department intended for this requirement to be satisfied with the stack testing requirements inherent in the Relative Accuracy Test Audit (RATA) procedures in Part 75. The commenters state "the specifications of the first test series required by 246.3 are inconsistent with the later mercury monitoring certification requirements." The Department does not believe this is the case unless the inlet requirement, which being revised, is what the commenters are referring too. The stack testing requirements in Section 246.3 are not intended to preclude the use of the same stack test requirements for the monitoring certification. For facilities not installing a continuous emission monitoring system and performing the required mercury monitoring certification requirements, 40 CFR section 75.20, the requirement for a second stack will remain and be used for low mercury emitting units to determine whether an affected unit is eligible to use the provisions under 40 CFR Subpart I, 75.81(c) for low mass emitting units. The Department will modify the express terms to remove any discrepancies.

25. Commenters numbered 9628, 9631 state they "are concerned about mercury monitoring technology and missing data substitution provisions, and additional monitoring requirements. There are at least two problems with the assumption that if mercury monitoring technology is advanced enough to support EPA's CAMR cap-and-trade program, then the technology is sufficient for the more aggressive New York State proposed command-and-control regulation…….However, while EPA's determination may be appropriate to ensure effective functioning of an allowance trading program, it is unnecessarily stringent for an emission rate program."

Response: The commenters contend that the monitoring technology may be valid with respect to a cap-and-trade program but is not valid for Part 246, which establishes definite emission limitations. The Department does not agree. EPA's Clean Air Market Division (CAMD) released an update to their February 2006 report in August 2006 entitled, "Mercury Emissions Monitoring Program for Coal-Fired Boilers under the Clean Air Mercury Rule Status Report: August 2006." As stated in the August update, there are still items that require further refinement in the area of a specific scenario related to stacks with high moisture concentrations, low mercury concentrations and low temperatures, much like a flue gas in a wet scrubbed control scheme. Control strategies employed in New York State will generate flue gas environments no different than any other state where a monitoring program and its associated monitoring systems are required. Part 246 will require the same level of sensitivity as those facilities participating in the federal cap-and-trade program under CAMR. As EPA is confident that the CAMR monitor certification deadline will be met, so is the Department. In the CAMD August update, EPA stated that it will continue to work with industry and with the equipment vendors to ensure that the CAMR emissions monitoring program is implemented on schedule.

Part 246 and 40 CFR Part 75 also allow for alternate monitoring techniques such as sorbent trap monitoring, if CEMs do not appear appropriate for a particular facility. Also, the low emitter exemption is available for facilities using technology to reduce mercury. Sources have eight years until they will be required to meet the 0.6 lbs of mercury per trillion Btu limit (lbs Hg/10¹² Btu) or a stack concentration of 0.6 µg/m³. Sources which need to reduce their mercury emissions to meet the Phase I caps will be closer to 2.0 to 3.0 of lbs Hg/Tbtu, averaged facility-wide and an averaged stack concentration of approximately 2.5 µg/m³.

26. Commenters numbered 9628, 9629, 9631 state "Proposed Part 246 contains unnecessary monitoring requirements. For example Part 246.1(b)(9) includes a moisture monitor in the definition of (continuous emission monitor systems) CEMS. Stack volumetric flow rate is always measured on wet basis. When the Hg CEMS also operates on a wet basis, the Hg mass emission rate can be calculated without a moisture measurement. Also, it is unnecessary to require [Part 246.1(b)(9)(ii)] Hg concentrations to be reported in units of micrograms per dry standard cubic meter when Hg is measured on a wet basis. The moisture measurement will contribute error to the reported value. Likewise, Part 246.1(b)(9)(iii)) should be modified to require a moisture monitoring system, as applicable."

Response: The language in Part 246 is directly from the CAMR Model rule 40 CFR 60.4102. While the Department believes the language in the federal rule could be clearer, we are obligated to meet the CAMR requirements and until EPA changes the language, all necessary model rule language will remain in Part 246. The Department also notes that the definitions cited do not establish that each CEMs necessarily needs to have every component listed in the definition. The commenter should remember these are definitions and are only stating what a CEMs can be, it does not mean each CEMs must have all these components.

27. Commenters numbered 9628, 9631 state "Part 246.1(b)(9)(iv) requires a CO₂ monitor or an O₂ monitor with sufficient software to calculate CO₂ concentrations monitor. Part 246.1(b)(9)(v) appears to also require an O₂ monitor. Requiring both an O₂ and CO₂ monitor is unnecessary and unprecedented in monitoring requirements. Therefore, we encourage DEC to consider deleting Part 246.1(b)(9)(v). The vast majority of the successful 40 CFR Part 75 continuous monitoring systems utilize dilution-based sampling probes. Of course, O₂ cannot be measured with a dilution-based system because the dilution air would overwhelm the O₂ concentration that is to be measured."

Response: See response to Comment 26.

28. Commenters numbered 9628, 9631 state "Compliance reporting periods should be consistent with the EPA 40 CFR Part 75. EPA requires submittals on a quarterly basis and the reporting format includes specific record types that list the quarterly emission totals and averages. This is particularly important because EPA reporting procedures confirm that quarterly totals are correct and label them as "official". Although the Hg reporting formats have not been announced there is no reason to believe that the new Hg reporting formats will vary from this approach. In order to eliminate the need to develop new reports for the CEMS data acquisition system and to use the "official" EPA data, DEC should use the information on those quarterly summary records. Therefore, we suggest that DEC consider revising the proposed 2010 - 2014 "12-month rolling average, rolled monthly" phraseology to "12-month rolling total, updated quarterly.""

Response: It was not the intention of the Department to require compliance reporting every month. Although, the Department will require compliance based upon a 12 month rolling total. Part 246 requires quarterly reporting to EPA and the Department, consistent with Title V requirements, so facilities can take advantage of a single reporting schedule for all applicable requirements CAMR requires rolling quarterly totals of mercury emissions but Part 246 requires 12 month rolling totals. The language in the regulation has been changed to state "12 month rolling total, rolled monthly, reported quarterly."

40 CFR 75.84(d), states "[t]he designated representative for an affected unit shall comply with all reporting requirements in this section and with any additional requirements set forth in an applicable State or Federal Hg mass emission reduction program that adopts the requirements of this subpart.

29. Commenters numbered 9628, 9629, 9631 state "Emissions limits for Phase 2 should be facility-wide, reported as 12-month rolling averages. The proposed unit level Hg emission limit is very aggressive, especially when we recognize Hg does not behave like other pollutants. …..Therefore, we recommend that compliance be on a 12-month rolling average, rolled and reported quarterly. Quarterly updating and reporting is consistent with existing 40 CFR Part 75 reporting requirements and would minimize the need for New York State-specific software development."

Response: The Department agrees that the 0.6 lbs/TBtu limit is an ambitious standard but it is one that is necessary for all the reasons articulated in this response to comments. The department will change the Phase II emission standard to reflect a facility-wide 30-day rolling average, rolled daily, reported quarterly. Total facility mercury mass emissions will be compared against total heat input generated from coal in all applicable units at a facility to determine compliance with Phase II emission standard. The Department accepts that the inherent variability of the concentration of mercury in fuel, fluctuation in pollution control equipment performance and calibration of monitoring systems can allow for slight deviations in the daily measured averages. When compared to the extremely low mercury flue gas concentrations expected through implementation of Part 246 those slight deviations could become significant to facilities close to the 0.6 lb/TBtu emission limit even though all control devices are operating properly. The Department believes this suggested approach will provide slightly more flexibility to facilities and avoid unnecessary non-compliance scenarios without a change to the overall mass emissions at a facility.

30. Commenters numbered 9628, 9629, 9631 state "We suggest 90 percent removal of the mercury in the coal as an alternative compliance option for Phase 2. The bulk of existing Hg emission data are based on snapshot (e.g., Ontario Hydro method) stack tests. Observations of Hg emissions from CEMs suggest values are much more variable than from either SO₂ or NO_x emissions. Based on the coal data from EPA's 1999 Information Collection Request (ICR), the average Hg concentration in bituminous coal was 8.6 lb/10¹² Btu. Achieving 0.6 lb/10¹² Btu, without allowing for variability, necessitates Hg removal efficiency of 93 percent which has not been demonstrated at full scale. In fact, one-fourth of bituminous coals exceed 9.8 lb/10¹² Btu, requiring even higher removals. For reasons noted above, we urge DEC to include in the unit level Hg emission limit a 90 percent removal option."

Response: The Department established the 0.6 lb/10¹² Btu standard based in part on the Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units; Proposed Rule, 69 FR 4652 - 4752 (January 30, 2004). In this proposal, EPA established a new source performance standard of 0.6 lb/10¹² Btu for bituminous coal and 2.0 lb/10¹² Btu for subbituminous coal. Second, according to the ICR, New York State's average emission rate was 6.26 lb/10¹² Btu. The Department determined that a 0.6 lb/10¹² Btu emission limit was appropriate based upon the federal new source performance standard. EPA allowed less stringent emission limits for facilities burning subbituminous coal in its NESHAP calculations because at the time mercury emissions from subbituminous coal was believed to be harder to capture and control. Studies conducted from 2002 and 2006 by DOE/NETL showed that this was not the case and in fact subbituminous coal could be reduced with activated brominated carbon injection. The Department is requiring this limit to be met in 2015.

Significant reductions of mercury are based upon units using add-on pollution controls thereby reducing emissions of SO₂, NO_x and particulate. New coal-fired sources built in the nation will utilize these controls under new source review regulations. As demonstrated under the NETL test projects, a source with wet scrubbers and an ESP, or dry lime scrubber and fabric filter technology can use activated carbon injection in conjunction with these other pollution control devices to meet a limit of 0.6 lbs/10¹² Btu. The Department believes New York's existing sources will meet 0.6 lbs/10¹² Btu due to the co-benefits from the implementation of CAIR. CAIR will require existing EGU sources to upgrade their pollution control technology and then use activated carbon injection or any other means available at that time to meet the 0.6 lbs/10¹² Btu standard in 2015.

31. Commenters numbered 9628, and 9631 state "Permitting Issues Section 246.4(a) of the proposed rule requires the owner/operators to apply to modify or renew their Title V permits to include applicable requirements from Part 246 within 18 months of the rule's effective date. Under the enabling legislation for DECs Title V permit program, DEC may only "require revisions to a permit to incorporate applicable requirements under state law or the [Clean Air] Act if the remaining permit term is three years or more." ECL 19-0311 (2)(j). The requirement in Part 246.4(a) of the proposed rule appears to be inconsistent with this statutory provision since it does not limit the revision requirements to permits for which the remaining permit term is greater than three years."

Response: The Department agrees that the current wording of section 246.4 could be more straightforward. The intent of the Department is to incorporate Part 246 requirements into Title V operating permits in a manner consistent with the State's approved Title V operating permit program (6 NYCRR Part 201). Section 201-6.5(i), "Permit re-openings for cause", sets forth the circumstances under which a Title V permit must be reopened and revised. When additional applicable requirements become applicable to a facility with a remaining permit term of three or more years, a reopening must be completed not later than 18 months after promulgation of the applicable requirement, unless the effective date of the requirement is after the expiration date of the permit. Section 201-6.5(i)(1)(i). A Title V permit shall also be reopened when the Department or the administrator determines that the permit must be revised or reopened to assure compliance with applicable requirements. Section 201-6.5(i)(1)(iii).

Part 246 requirements will begin to apply in 2009 and be implemented in two phases. Therefore, by 2009, Title V permits should include, at a minimum, the Phase I Part 246 requirements that will become applicable during the current permit term. Depending on when a facility's Title V permit expires, the Department will either incorporate the requirements of this Part into the renewed Title V permit or reopen and modify the existing Title V permit to include them. A facility whose permit will expire before 2009 can include Part 246 requirements in the Title V permit renewal application. The Title V renewal permit will incorporate these requirements. In the case of a facility whose permit expires on or after January 1, 2009, the Department will reopen the Title V permit to include Part 246 requirements consistent with the provisions of Part 201-6.5(i). Title V permits need not include requirements whose effective date is after the expiration date of the permit The Department believes this approach is consistent with Part 201 and will revise the express terms of Section 246.4 accordingly.

32. Commenters numbered 9629, 9631 stated "RMB Consulting & Research Inc., stated that the proposed ultimate limit of 0.6 lb Hg/TBtu is extremely close to the detection capability of the monitors currently available. Also, the specification under 40 CFR Part 75 for daily calibration checks is greater than this limit. As a result, it is impossible now and highly unlikely in the future that the affected sources can prove the accuracy of measurements at such low levels. Therefore, given the markedly increased stringency of compliance requirements between the two phases of the proposed Rule, IPPNY strongly recommends that Phase II be revised to make it consistent with Phase I. The revised Rule should stipulate a facility-wide limit of 1.0 lb Hg /TBtu (equal to the daily calibration test limit) utilizing an annual average value updated on a quarterly basis."

Response: The Department infers from this comment that the commenter believes there is only one available option for mercury mass emission monitoring, a mercury continuous emission monitoring system (CEMS). Part 246 offers multiple mass emission monitoring options which include continuous emission monitoring systems in addition to sorbent trap monitoring systems and for those units that qualify, periodic emission testing to quantify mercury emissions.

The Department believes that continuous emission monitor systems that have been field tested and are currently available for field deployment and have sensitivities well below future, Phase II Part 246 limit equivalent concentrations of 0.6 µg/scm (wet). In addition to CEMS, sorbent trap monitoring systems with ultimate analysis utilizing ambient air analyzers have the ability to monitor average mercury mass emissions over a time period of well below 0.1 µg/scm.

EPA's Clean Air Market Division (CAMD) released an update to their February 2006 report in August 2006 entitled, "Mercury Emissions Monitoring Program for Coal-Fired Boilers under the Clean Air Mercury Rule Status Report: August 2006." As stated in the August update, there are still items that require further refinement in the case of a specific scenario related to stacks with high moisture concentrations, low mercury concentrations and low temperatures, much like a flue gas in a wet scrubbed control scheme. Control strategies employed in New York State will generate flue gas environments no different than any other state where a monitoring program and its associated monitoring systems are required. Part 246 will require the same level of sensitivity as those facilities participating in the federal cap-and-trade program under CAMR. EPA is confident that the CAMR monitor certification deadline will be met and so is the Department. As stated in the CAMD August update, EPA will continue to work with industry and with the equipment vendors to ensure that the CAMR emissions monitoring program is implemented on schedule.

The commenters are correct in identifying that the "specification", the acceptable range of calibration error (±1 µg/scm) during a daily calibration error test when the span value is 10 µg/scm, is above the 30-day rolling average emission rate limit of 0.6 µg/scm. Part 75 monitoring does not only rely on daily calibration checks to verify that data monitored are accurate, but employs 7-day calibration error tests, relative accuracy test audits, cycle time tests, bias tests, a 3-level system integrity check and prohibition of biased low monitoring systems whether they be continuous monitoring systems or sorbent trap monitoring systems. A similar situation as described by the commenter was addressed by EPA with relation to Part 75 NO_x monitoring in low concentration gas streams. The allowance of five ppm is acceptable for span values less than 50 ppm but NO_x emission limits may be as low as two ppm, two and one half times the emission rate limit.

The Department agrees with the commenters that a facility average emission rate for Phase II would be acceptable, but as described above, the mercury emission rate limit of 0.6 lb/TBtu will remain. The Department will also maintain that compliance with the Part 246 Phase II emission rate limit of 0.6 lb mercury/TBtu will be determined on a 30-day rolling average, rolled daily and reported quarterly. The commenter has suggested an averaging range (quarterly) which is well outside of what EPA would consider as an acceptable averaging period robust enough to assure continuous compliance. EPA has stated that monthly averages at a minimum are required to demonstrate continuous compliance.

33. Commenters numbered 9629 stated "the proposed Mercury Rule needs to be reviewed in a comprehensive and cumulative manner, in the context of other environmental requirements, in order to ensure that our energy system maintains its reliability and fuel diversity and that New York's environmental initiatives do not push investors to other regions. Several reports indicate that New York will need additional generating facilities in the next few years to meet an ever-growing demand for electricity, and the Rule could deter investment in New York's energy marketplace."

Response: The Department proposed Part 246 taking into full consideration the above mentioned issues. The Clean Air Interstate Rule, Regional Greenhouse Gas Initiative (RGGI), State Acid Deposition rules and the next generation particulate regulations based upon the required State Implementation Plan for PM_2.5 are being implemented on roughly the same schedule as Part 246. Each of these rules imposes significant substantive requirements in terms of emission limitations and reduction targets, CEMs and record keeping requirements. Several rules target the same pollutants. Nearly all the rules will require facilities to undertake construction projects to install state-of-the-art pollution control equipment and/or emission monitoring equipment. Most of the construction work will need to occur during non-peak operating periods (Spring and Fall) to avoid straining the electric generating system during peak operating periods (Summer cooling season and Winter heating season).

The Department fully expects that the co-benefits associated with CAIR, as described in comment 32, will not make the requirements of Part 246 a limiting factor. In other words, air pollution control devices and monitoring equipment required for CAIR will also enable facilities to meet their Part 246 requirements. Further, as explained in the Regulatory Impact Statement, virtually the entire incremental electricity price impact of implementing CAIR and a mercury rule together is due to CAIR.

According to the North American Electric Reliability Council, New York will need an additional 4000 MW of generation by 2015, of which 2500 MW is currently under construction and the additional power will be met with the addition of renewable energy plants and natural gas plants. Two coal-fired electric utility plants are expected to be added to New York's fuel diversity by 2015. This need for additional supplies of electricity is likely to attract investment in the State. The Department does not believe that Part 246 will deter investment in New York especially considering that the other Northeast States operate under similar regulatory requirements with respect to their air pollution control programs. Therefore, the Department disagrees with the commenters' suggestion that Part 246 will deter business development.

Response: See Overview and Regulatory Impact Statement.

34. Commenter number 9629 stated "Cogeneration owners, such as Trigen-Syracuse, already are subject to Boiler MACT regulations (40 CFR Part 63), yet the Mercury Rule's definitions inappropriately would include these facilities in a manner that results in a double regulation of their mercury (Hg) emissions. Specifically, the Rule's Section 246.1 (4) defines a cogeneration unit as a stationary, coal-fired boiler, etc. However, cogeneration facilities exist with multiple boilers ducted to a common header feeding a steam turbine producing both electricity and process steam. Therefore, we suggest that the Rule's definitions be clarified regarding the cogeneration unit as being multiple units or a single unit."

Response: The definitions in Part 246 are directly from the CAMR model rule. The Department is obligated to meet CAMR's requirements and until EPA changes the language concerning rule applicability, all necessary model rule language will remain. The Department intends to revise the applicability section 246.2 to make this provision consistent with Model Rule requirements as contained in the Federal Register - Vol. 71, No.111, Friday, June 9, 2006, Reconsideration of Mercury Rule and of Regulatory Finding on Utility Emissions. Facilities which are covered under the Boiler MACT regulation and CAMR applicability (Part 246) need to address this issue with the EPA. It is not unusual for a stationary source to be subject to two or more regulations which cover the same pollutants. The regulated facility or unit must meet the more stringent of the two regulations.

35. Commenter number 9629 states "Section 246.1 (9) defines a continuous emission monitoring systems (CEMS) and includes carbon dioxide CEMS and oxygen. The word "and" should be changed to "or" in order to be consistent with 40 CFR Part 75 requirements."

Response: The language in Part 246 is no different from CAMR's model rule definitions. Part 246.2(9) states "Continuous emission monitoring system means the equipment required under sections 246.7 through 246.11 of this Part to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes using an automated data acquisition and handling system, a permanent record of mercury emissions, stack gas volumetric flow rate, stack gas moisture content, and oxygen or carbon dioxide concentration in a manner consistent with 40 CFR Part 75."

36. Commenter number 9629 states "DEC has allocated Hg emissions to facilities that the EPA already has confirmed are not subject to the requirements of the Acid Rain Program; therefore, these facilities do not have an existing CEMS for sulfur dioxide emissions that meets the requirements of 40 CFR Section 75.11 (b)(2) and the moisture monitoring. We recommend that non-Acid-Rain-facilities control Hg emissions through the implementation of the Boiler MACT regulations, instead of under the requirements of the proposed Mercury Rule."

Response: Boiler MACT regulations do not supplant CAMR and will not be incorporated into Part 246. The Department must satisfy the requirements of CAMR. All applicable sources must monitor their emissions with the requirements in 40 CFR 75 based upon the CAMR. Sources who currently do not have CEMs will either need to install the necessary components for CEMs or use alternate monitoring strategies of sorbent trap monitoring or qualify for the low-emitter exemption under 40 CFR 75.80. See: 40 CFR 75.80(d)(2).

37. Commenter number 9629 states "The DEC has not demonstrated that implementation of the proposed Rule would result in any further environmental benefit in New York State, beyond what already is required from CAMR."

Response: The Department disagrees with this comment. As explained in great detail in the Overview and the Regulatory Impact Statement, CAMR falls short of providing the State with the necessary reductions in mercury emissions needed to restore and ensure a sustainable environment in New York State and protect the public health and welfare. CAMR's deadline of 2018 for Phase II reductions is elusive: facilities have the option of purchasing allowances to meet their regulatory requirements rather than meet definite emission limits. New York State needs definite reductions in mercury emissions and a faster time table than provided by CAMR to ensure the viability of our natural resources, the health of our citizens, and the quality of our environment. See Overview and Regulatory Impact Statement.

38. Commenters numbered 9629 states "according to the Regulatory Impact Statement for the proposed Rule, DEC finds that one of the shortcomings of CAMR is that the federal cap-and-trade strategy will not mitigate the current "hotspots" created by localized deposition from coal-fired electric utilities who buy allowances rather than installing controls to reduce emissions. Conversely, according to a presentation by the Electric Power Research Institute (EPRI) on recent mercury research, most of the mercury emissions from electric generating facilities that remain after implementation of CAIR and CAMR are in the form of elemental mercury. Since elemental mercury deposits slowly from the atmosphere over hundreds to thousands of miles, elemental mercury from New York State generating facilities will not deposit in New York at the levels proposed in New York will cut mostly elemental mercury (since the divalent Hg(II) already will be controlled by federal requirements). As a result, deposition in New York is unlikely to change very much from increasing the reduction requirement from 70 percent to 90 percent."

Response: The Department finds this statement to be inaccurate. The Department's stated position is that the Northeast States are a hot-spot for the deposition of mercury based upon fish sampling the Department has conducted over the last thirty years. New information conducted by Gerald Keeler, et.al in a paper entitled Source of Mercury Wet Deposition in Eastern Ohio, USA 7 shows that emissions of mercury fall nearer to their sources of origin than industry representatives state. The Department contends that electric steam generating units burning bituminous coal which have a higher content of reactive gas mercury (RGM) as determined by the ICR data and RGM will deposit locally or travel, based upon meteorological conditions, but will ultimately wash out within 50 to 500 miles from origin.

The second part of the commenters' question states that the "federal" program will control the oxidized portion of mercury allowing New York's Part 246 to only control the remaining elemental portion. The proposed Part 246 addresses control of total mercury mass emissions and does not dictate nor focus on control of specific speciation or form of mercury. The Department does not refute that oxidized mercury would be controlled through application of CAIR and CAMR, only that to meet emission limitations imposed by Part 246 a greater degree of oxidation and subsequent capture may be required above and beyond the requirements of CAIR and CAMR. The Department believes the reduction of a toxic pollutant, such as mercury, should be controlled to its maximum potential.

39. Commenter number 9629 states "according to the Regulatory Impact Statement for the proposed Rule, the DEC anticipates that facilities will be able to meet the Rule's emission reduction requirement by installing carbon injection systems. However, according to the website of the Energy Information Administration, significant uncertainty exists about the degree to which mercury can be removed from some coals. The performance of activated carbon injection, even though it has been deployed in other industries, is uncertain in coal plants and still is in the process of being field tested on a limited basis for long-term use."

Response: To date the Department of Energy's National Energy Testing Laboratory (DOE/NETL) has tested or is in the process of testing 12 major plants under their Phase 1 to Phase III for carbon injection and sorbent injection technology. The Department expects existing facilities to meet Part 246's Phase I requirements with conventional pollution control equipment reducing nitrogen oxides, sulfur dioxide and particulates. If a facility does not choose to employ a multi-pollutant control strategy to meet Phase I mercury emission limitations, mercury-specific control technologies are available an as alternate strategy. According to DOE/NETL, testing will be completed and commercial deployment started by 2012 for sources to demonstrate 90 percent control or greater for mercury. The Department has provided ample time for facilities in New York to evaluate, test and install the necessary equipment to meet the compliance limits in Part 246.

40. Commenter number 9630 states "The Jamestown Board of Public Utilities (BPU) is requesting that the Department provide flexibility in setting limits for the BPU's existing Carlson Plant. The Department should consider that the plain language of the CAA requires that the BPU's units be included in Boiler MACT and not CAMR. Because its coal-fired boilers are equal to or less than 25 MWe, the BPU's units should have been included in the National Emissions Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters (Boiler MACT), not in the Clean Air Mercury Rule (CAMR)."

Response: Part 246 utilizes the heat input weighting system of section 60.4142 of Subpart HHHH of 40 CFR 60. At this time the Department does not believe an alternate weighting scheme is appropriate for those facilities that potentially emit a significant mass of mercury emissions. Furthermore, the applicability for Part 246 is based on CAMR and any deviation from that applicability would jeopardize the intent of Part 246 and in turn the acceptability of New York's Mercury State Plan by the federal government.

41. Commenter number 9630 states "the Department should adjust the BPU's allocation in accordance with comments" that EPA granted such provisions in the Clean Air Mercury Rule for small boilers."

Response: Part 246 utilizes the heat input weighting system of section 60.4142 of Subpart HHHH of 40 CFR 60. At this time the Department does not believe an alternate weighting scheme is appropriate for those facilities that potentially emit a significant mass of mercury. See comment number 40.

EPA believes that decisions regarding flexibility in allowance allocation, if a state opts to allocate allowances in a cap-and-trade program, can be left to the specific state because the manner of initial distribution of allowances will not affect the environmental outcome in an economic-driven cap-and-trade program. EPA recommends in the Final Rule Preamble - Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units that allowance set-asides may be used as an option for a state's Hg allocation approach. The Department, as discussed in the Regulatory Impact Statement and in these Responses, has opted not to participate in a cap-and-trade program and will not allocate allowances to units or facilities. This is based on the Department's view that a cap-and-trade approach to mercury control is not appropriate. Therefore allowance set-asides and allocation approaches are not included in this regulation.

42. Commenter number 9630 states "The Department addresses the impact of the proposed Rule on Jamestown in both the Regulatory Flexibility Analysis for Small Businesses and Local Governments (RFA) and the Regulatory Impact Statement (RIS). Both analyses fail, however, to use accurate or comparable data to address the cost implications of the Proposed Rule on the Jamestown BPU."

Response: The Department used all appropriate and available cost and operational information regarding the Jamestown S. A. Carlson generating station to develop specific study level, or better, cost estimates for annual financial impact and incremental costs on generation.

43. Commenter number 9630 states "The RFA is fundamentally flawed because the Department and the studies it relies on fail to address the feasibility and cost controls for Jamestown at the level of a 25 MWe boiler unit. The source the Department cites, ostensibly as a representative example of one of the 20 pilot studies, considers a 500 MW coal-fired unit-a vastly different unit than anything Jamestown operates. Significantly, the referenced source itself cautions against using a 500 MW unit as evidence of costs for different units."

Response: The Department believes the cost estimates for an activated carbon injection system under different carbon injection rates used in the RFA are most appropriate as a carbon injection system's capital cost is not scaled on electrical generation in the same fashion traditional air pollution control devices are. The ACI system components are the same regardless of the value of flue gas equivalence to be treated where variable operation and maintenance (O&M), which directly translates into reagent type and mass of reagent used, is the only adjustable cost estimate input. This variable O&M value depends greatly on the specific system, but more generally is related to the level of carbon removal desired.

44. Commenter number 9630 states ""Section 4 of the RFA entitled "Compliance Costs", the Department estimates Jamestown's associated incremental cost of generation in the range of 0.23 to 0.63 mills/kWh, but the Department fails to provide any citation or reference to the specific source of this information. Consequently, it is impossible to understand or evaluate these Department estimates."

Response: The costs range provided in the Regulatory Flexibility Analysis estimates the additional cost of generation over the four boilers and two generators subject to Part 246. The incremental cost of generation is based on the purchase and operation of an ACI system. The capital cost of an ACI system is $984,000 (year 2003) applying an approximate 12 percent charge rate yields an annual payment of $117,460. This value overestimates Jamestown's annual requirement. Jamestown BPU is not a for-profit corporation and therefore would not have the same cost of debt to equity ratio and in actuality would realize a lower annual cash requirement than modeled based upon the Science International Corporation document below.

Total annual flue gas flow rates from both the North and South Stacks from 2004, data as approved by EPA's Clean Air Market Division, were used as baselines to determine the amount of powdered activated carbon required to be injected annually at a ratio of 3.0 lb AC/mmacf. Also included in the incremental cost of generation was an estimate of increased landfill material and the associated increase in cost related to the increased fly ash mass. A value of $17/ton fly ash land filled was used. The estimates and assumptions used in this calculation are the same as those used to model ACI systems at all other utility units subject to the requirements of Part 246 and can be found in Preliminary Cost Estimate of Activated Carbon Injection for Controlling Mercury Emissions from a Un-Scrubbed 500 MW Coal-Fired Power Plant.

45. Commenter number 9630 states "the Department states that Jamestown "will experience a small increase in the cost of electric generation due to the adoption of Part 246 . . . [but] the more significant cost increase will occur as a result of EPA's promulgation of the federal Clean Air Interstate Rule (CAIR)." The Department makes an incorrect assumption about how Jamestown may meet the requirements of CAIR. Jamestown may comply with CAIR requirements through allowance purchases, in which case all control costs will be mercury-related, rendering the Department's conclusion incorrect regarding CAIR's higher relative control costs."

Commenter number 9630 states "the Department states that Jamestown "will experience a small increase in the cost of electric generation due to the adoption of Part 246 . . . [but] the more significant cost increase will occur as a result of EPA's promulgation of the federal Clean Air Interstate Rule (CAIR)." The Department makes an incorrect assumption about how Jamestown may meet the requirements of CAIR. Jamestown may comply with CAIR requirements through allowance purchases, in which case all control costs will be mercury-related, rendering the Department's conclusion incorrect regarding CAIR's higher relative control costs.

Response: Comment noted. The Department will revise the Regulatory Flexibility Analysis for Small Business and Local Government by removing reference to the comparative costs for Jamestown between Part 246 implementation and CAIR.

46. Commenter number 9630 states "The Department's suggestion that Jamestown can keep compliance costs low due to the flexibility of operating different units is illusory. In Section 6 of the RFA entitled "Minimizing Adverse Impacts," the Department suggests that Jamestown "can chose [sic] which units to control to meet the facility-wide cap, enabling them to target the most economically feasible units. Initially, the facility-wide cap is only applicable for 2010-2014 so this does not apply to Phase II controls."

Response: To enable Jamestown and other facilities to target the most economically feasible units for mercury control, the Department is modifying Part 246 to allow the Phase II emission standard to be a facility-wide 30-day rolling average, rolled daily, reported quarterly.

The Department agrees that the 0.6 lbs/10¹² Btu limit is an ambitious standard but it is one that is necessary for the protection of the environment and public health and welfare in New York State. Total facility mercury mass emissions will be compared against total heat input generated from coal in all applicable units at a facility to determine compliance with Phase II emission standard. The Department accepts that the inherent variability of the concentration of mercury in fuel, fluctuation in pollution control equipment performance and calibration of monitoring systems can allow for slight inaccuracies in the daily measured averages. When compared to the extremely low mercury flue gas concentrations expected through implementation of Part 246 those slight deviations could become significant to facilities close to the 0.6 lb/TBtu emission limit. The Department believes this suggested approach will provide slightly more flexibility to facilities and avoid unnecessary non-compliance scenarios without a change to the overall mass emissions at a facility.

47. Commenter number 9630 states "BPU requests that the Department set the BPU's allocation at the lowest of the Boiler MACT requirement for solid fuel fired units or 25 pounds annually."

Response: Section 246.2 applicability requirements come directly from the model rule in the March 15, 2005 CAMR promulgation. The Department is obligated to meet the Clean Air Mercury Rule requirements and until EPA changes the language, all necessary model rule language will remain. The definition for applicability was revised in the Federal Register - Vol. 71, No.111, Friday, June 9, 2006, Reconsideration of Mercury Rule and of Regulatory Finding on Utility Emissions June and these revisions will be incorporated into the final rule. Facilities which are covered under both the Boiler MACT regulation and CAMR applicability (Part 246) need to address this issue with the EPA. It is not unusual for a stationary source to be subject to two or more regulations which cover the same pollutant. The regulated facility or unit must meet the more stringent of the two regulations.

48. Commenter number 9630 states "The BPU requests clarification that under Part 246, new source allocations will be in addition to the Facility-wide allocation for existing units in Section 246.5(a)."

Response: Under Part 246, new MRP units built between rule promulgation and 2014 will be accounted for under the five percent set-aside for new units. A facility's cap will remain the same for the existing units and the new unit must meet the 0.6 lbs Hg/10¹² Btu. Existing facilities as defined in the definitions of 246.1 will be subject to a facility-wide emission limit in 2010 to 2014. Based upon comments on the rule, the Department has revised paragraph 246.6(b) to reflect a facility-wide emission limit in 2015 of 0.6 lbs Hg/10¹² Btu and not a unit-by-unit wide limitation.

49. Commenter number 9631 states "The RIS under-estimates costs when it claims that the incremental cost of generation for New York coal-fired units implementing a standard or enhanced powdered activated carbon system will be in the range of 0.37 to 1.66 mills/kWh. However, commenter (Ind-04) most recent cost estimates for installation of a baghouse and ACY system is approximately five mills/kWh."

Response: Facilities combusting a sub-bituminous fuel and utilizing a cold-side ESP for particulate control could easily control mercury by the operation of a powdered carbon injection system using an enhanced activated carbon as reagent. The cost range identified in the Regulatory Impact Statement covers costs of the installation of a carbon injection system and the fixed and variable operation and maintenance costs associated with the enhanced carbon injection system.

50. Commenter number 9631 states "the Department's position that the Adirondacks or Northeast region is a "hot-spot" due in part to persistent deposition of mercury from coal-fired electric utility sector is debatable"

Response: The commenter provides data to argue that the emissions from coal fired power plants contribute approximately 10 percent of all deposited emissions for a total of 4 µg/m²/year. The Electric Power Research Institute (EPRI), an industry-funded organization, claims that power plants in the surrounding states contribute significantly more deposited mercury in the Catskill Park in southern New York than 10 percent but the air dispersion modeling is as good as it can be at this time and model predictions on either side are always subject to interpretation and uncertainties. The commenter attempts to show that with the CAMR, the final deposition from coal-fired power plants will be 1.2 µg/m²/year in the year of 2018. However, EPA has stated these benefits will not be realized until 2022 due to the banking provisions in the federal cap-and-trade rule. The commenter states that the proposed Part 246 implementation of a 90 percent reduction scheme rather than the 70 percent reductions under CAMR is insignificant -- an approximately 0.4 percent change from the total impact of all sources and not just coal-fired power plants.

The Department disputes these conclusions and addresses these issues in the Regulatory Impact Statement and these Responses to Comments about the benefits that will be realized from the implementation of Part 246. If all states followed the 90 percent reduction program by 2015, the rate of mercury deposition would be 66 percent less (0.4/1.2 µg/m²/year) seven years earlier from the largest source of emissions of mercury, coal-fired EGUs. Models are effective tools but the largest single component of the models are the emissions. If emissions are significantly reduced from all sources, the rate of mercury deposition will decrease and both the environment and public health will benefit.

51. Commenter number 9631 states "(we) propose changing the proposed regulations so that they remain more stringent than CAMR but less stringent than proposed. …we propose to change the limit in Phase 2 to one µg/m³ from the 0.6 µg/m³ proposed."

Response: This comment is very similar to Comment 32 which states "RMB Consulting & Research Inc., stated that the proposed ultimate limit of 0.6 lb Hg/TBtu is extremely close to the detection capability of the monitors currently available. …… strongly recommends that Phase II be revised to make it consistent with Phase I. The revised Rule should stipulate a facility-wide limit of 1.0 lb Hg /TBtu (equal to the daily calibration test limit) utilizing an annual average value updated on a quarterly basis." See response to Comment 32.

52. Commenter number 9631 states "that the set-aside of 40 pounds per year could potentially limit development of new clean coal generation capacity in New York. A single IGCC project with 90 percent capture could be on the order of 30 lbs of mercury per year making it impossible for more than one project to be built. It is also not clear how retirements will be handled, if new sources would have to share the allocation, or if the allocation is first-come first serve."

Response: The set-aside of 40 pounds would be in effect until December 31, 2014. It is estimated using a conventional boiler/turbine steam generator set that 5 pounds of mercury would be emitted per 100 MWe energy produced. Newer IGCC installations and new conventional boilers with super-critical and ultra-critical designs would produce 15 percent less mercury per kilowatt/hour generated, therefore 40 lbs would equate to about 900 to 1000 MW of new generation. At this time, the Department is aware of the installation of 50 MW of additional electric generating capacity by Jamestown and NRG announced the development of a 550 MW IGCC plant in June of 2006 with an expected operational date of 2014. Two additional existing sources are on cold stand-by and it equated to 1 pound of mercury if they operated at their 2000 levels or 12 pounds if they operated at faceplate capacity for 8,760 hours a year, an impossible scenario. Even with these two announced projects that could commence operation during Phase I, the Department is certain that neither the new source set aside nor the State's annual will be exceeded. After 2014, all new projects would need to meet an emission limit for mercury. In the case of retirement of existing units, the facility will not be able to bank any mercury reduction credits and will still need to meet the facility wide cap from 2010 to 2014 for total mercury emissions.

53. Commenter number 9631 states "what (we) contend is vague language is rule as it applies to new source mercury emissions in Phase II of the proposed rule. … One reading would suggest that Phase II eliminates existing facility allotments, and make no mention of statewide new source allotment, and so there is no statewide allotment limit in Phase II for new sources. But we believe an alternate interpretation could be argued would hold that in Phase II, the new source 40 lb/year statewide limit continues which will eventually preclude additional sources once that limit is reached."

Response: There will be no new source "allotments" in 2015. New Mercury Reduction Program units will meet the emission limit of 0.6 lb Hg/10¹² Btu. The 5 percent set aside for new sources only applies until December 31, 2014. After this date, all facilities will need to meet the 0.6 lb Hg/10¹² Btu emission standard. Language in paragraph 246.6(b) has been changed to allow a facility-wide emission limit in 2015 rather than strictly a unit-wide emission limit. The Department expects that the total mercury emissions from coal-fired utilities, including existing and proposed EGUs, will be 150 pounds annually in 2015. This ensures that the State will meet its annual mercury budget of 310 pounds per year as established by CAMR and that the State will be able to accommodate an increased coal and coal-derived fuel energy supply.

54. Commenter number 9643, EPA states "Sections 246.6 (a) and (b) establish a limit on mercury emission rates of 0.60 pounds per trillion BTU (0.6 lb/TBtu) for new Mercury Reduction Program (MRP) units in Phase 1, effective January 1, 2010, and for new and existing MRP units starting in Phase 2, effective January 1, 2015. The establishment of limits on mercury emission rates for all MRP units does not necessarily ensure that the State's total mercury mass limit (i.e., the State's annual electric generating unit (EGU) mercury budget for a given year) will not be exceeded. With regard to Phase 1 of the MRP, New York's current Part 246 imposes annual mercury mass limits on the facilities listed in Table 1 in section 246.5, however New York should clarify how they will impose mercury mass emission limits on existing MRP units not listed in Table 1 and how the set aside will be allocated to new units. With regard to Phase 2 of the MRP, Part 246 does not impose annual mercury mass limits on any existing or new facility or unit. Under 40 CFR 60.24(h)(3), each State must submit plans that will result in compliance with the State's annual EGU mercury budget for the appropriate periods. For New York, CAMR has established a statewide Phase 1 annual EGU mercury emission budget, for 2010-2017, of 0.393 tons (784 pounds) and a statewide Phase 2 annual EGU mercury emission budget, beginning in 2018 and thereafter, of 0.155 tons (310 pounds). While it is apparent that New York intends to establish a mercury mass cap for Phase 1, Part 246 needs to be revised to cover all categories of MRP units by mercury mass limits, not just the existing units in Table 1. To the extent Part 246 does not establish a Phase 1 cap or Phase 2 cap covering all new and existing units, New York needs to provide, as part of its State plan submittal to EPA, a demonstration that the State annual EGU mercury budget, as established at 40 CFR 60.24(h)(3), will not be exceeded in any year. EPA has provided guidance regarding the demonstration that is required at 40 CFR 60.24(h)(3) for states that choose not to place a cap on EGU mercury emissions. States can find this guidance at the following website: www.epa.gov/airmarkets/camr/stbudgets.html."

Response: The Department will revise Part 246 to incorporate CAMR's revised applicability provisions. This revision, however, will not affect MRP units subject to, or exempt from, coverage under Part 246.

Part 246 appropriately covers all existing MRP units in the State which are subject to CAMR including: 11 existing, currently operating coal-fired electric utility steam generating units (see Section 246.2(a)); 2 coal-fired electric utility steam generating units on standby which will become subject to Part 246 if they resume operations (see Section 246.2(b)), and new units (See Section 246.2(b)). As the Department noted in the Regulatory Impact Statement, this rule is intended to cover coal-fired electric utility steam generating units; municipal waste combustors are covered under separate regulatory provisions.

The Department did not specify mercury mass emission limits for the AES Hickling and Jennison facilities, which are currently on cold-standby, in Table 1 because these facilities, if they resume operations, will be subject to the 0.6 pounds per trillion Btu emission rate limit in Section 246.6(c). Mercury emissions from these existing facilities and from new facilities will be part of the five percent new unit set aside and cannot exceed 40 pounds per year.

The State Plan and Part 246 demonstrate that New York will not exceed the State annual EGU mercury budget. Eleven MRP units will be limited to 746 pounds of mass mercury emissions annually as provided in Section 246.5 Table 1. New MRP units and units not listed in Table 1 can collectively emit no more than 40 pounds of mercury annually. See attached sensitivity analysis, Appendix C.

55. Commenter number 9643, states "EPA would like to note that New York's Part 246 represents one of the required elements for submittal of a State plan under section 111(d) of the Clean Air Act. New York proposed the other required elements of the State plan on October 4, 2006. EPA will review and comment on the October 4, 2006 proposal separately, but notes that all required elements for a State plan submittal are found in 40 CFR part 60, subpart B entitled "Adoption and submittal of state plans for designated facilities." Subpart B identifies the general requirements that States must follow for submittal of an approvable State plan, including the following elements: demonstration of legal authority; identification of enforceable state mechanisms; an inventory of units and emissions (in this case, mercury); emission standards as protective as those in the emission guidelines; compliance schedules; testing, monitoring, recordkeeping, and reporting requirements; the record of public hearing; and provision for state progress reports. Many, but not all, of these required State plan elements are included in New York's proposed Part 246. As indicated in EPA's comment 1 above, New York's State plan needs to include the budget demonstration. Further, in accordance with subpart B, the State is conducting a public hearing prior to any adoption of its State plan."

Response: The State Plan discusses each of the required elements. Notice of the State Plan was published in the Environmental Notice Bulletin on October 4, 2006 and a public hearing was held on November 6, 2006. In response to EPA's comments, the Department is adding further clarification to the State Plan.

56. Commenter number 9643, states "As discussed below in the comments on section 246.2, the New York rule needs to cover at least the same units in New York that are covered by CAMR, i.e., the units covered by the definition of "Electric generating unit or EGU" in 40 CFR 60.24(h)(8), as revised by the final rule issued by EPA on June 9, 2006. In addition, the definitions of terms used in the EGU definition must be consistent with the respective definitions in 40 CFR 60.24(h)(8)."

Response: Terms used in the EGU definition and defined in 40 CFR 60.24(h)(8) include: "Boiler", "bottoming-cycle cogeneration unit", "Coal", "Coal-fired", "Cogeneration unit", "Combustion turbine", "Generator", "Gross thermal energy", "Maximum design heat input", "Nameplate capacity", "Potential electrical output capacity", "Sequential use of energy", "Topping-cycle cogeneration unit", "Total energy input", "Total energy output", "Unit", "Useful power", "Useful thermal energy, and "Utility power distribution system". The current section 264.1 includes definitions for these terms except for "Boiler", "Coal", and "Utility power distribution system"; the definitions in 40 CFR 60.24(h)(8) for these last three terms should be added to section 264.1.

Further, two of the definitions in the current section 264.1 differ from the definitions in 40 CFR 60.24(h)(8) in ways that need to be addressed. The changes described below are needed to make the section 264.1 definitions, and thus the applicability provisions, consistent with 40 CFR 60.24(h).

In the definition for "Maximum design heat input" in section 246.1(b)(17)(ii), the phrase "specified by the person conducting the physical change and" should be added before with word "demonstrated".

In the definition of "Nameplate capacity" in section 246.1(b)(i) and (ii), the word "unrestricted" should be removed, and the phrase "and during continuous operation (when not restricted by seasonal or other deratings)" should be added after the words "steady-state basis." In paragraph (ii) of this definition, the phrase "a change" should be revised to read "an increase," the phrase "such increased or decreased maximum" should be revised to read "such increased maximum," and the phase "specified by the person conducting the physical change and" should be added before with word "demonstrated." The current section 264.1 definition is confusing in that it suggests, contrary to 40 CFR 60.24(h), that a unit may derate (e.g., through relatively inexpensive adjustments to the generator to reduce capacity to 25 MWe or less) out of the State mercury requirements and leave what would otherwise be its share of the State mercury budget to be used by the units remaining in the State mercury program."

The Department will revise Section 246.2 to be consistent with the applicability provisions in 40 CFR 60.24(h)(8). In addition, the Department will revise or include definitions for the following terms to be consistent with federal regulations: "boiler"; "coal"; and "utility power distribution system". The Department will also revise the definition of "maximum design heat input" as requested by EPA. Although Section 246.2 will be revised to conform to federal regulations, the revisions do not change the sources affected by Part 246.

The Department disagrees that the current definition of "nameplate capacity" could be read, as EPA suggests, that a unit may derate out of Part 246 and leave its share of the State budget to be used by units remaining in the mercury program. MRP units in Table 1 have definite mass emission limits and the Department would have to undertake a formal rulemaking to alter them. Part 246 does not authorize the Department to increase these emission limits for any reason.

In addition, the Department does not interpret Part 246 as allowing a generator served by a unit to derate so that the unit may avoid Part 246 applicability. Part 246 applies to units serving at any time since commencing operation a generator with a nameplate capacity of more than 25 MWe. If at any point since the commencement of operation, the nameplate capacity of a generator served by a unit was greater than 25 MWe, that unit is subject to Part 246 notwithstanding a current rating less than 25 MWe.

57. Commenter number 9643, states "As discussed below in the comments on sections 264.7 through 264.13, under 40 CFR 60.24(h)(4), a State plan must require EGUs to meet the monitoring, reporting, and recordkeeping requirements of 40 CFR part 75 with regard to mercury mass emissions, whether or not the State plan adopts EPA's mercury trading program. In order to meet this requirement, the State plan must not only include the relevant requirements of 40 CFR part 75 (i.e., the provisions in 40 CFR 60.4170 through 60.4176 of EPA's model rule), but also include definitions of the terms used in those requirements (i.e., the definitions of those terms in 40 CFR 60.4102 of EPA's model rule). Even though New York is not adopting EPA's Mercury Trading Program, New York should use the language found in EPA's model rule."

Response: Terms used in 40 CFR 60.4170 through 60.4176 and defined in 40 CFR 60.4102 include: "Automated data acquisition and handling system or DAHS", "Commence commercial operation", "Common stack", "Continuous emission monitoring system or CEMS", "Heat input", "Heat input rate", "Hg designated representative", "Monitoring system", "Owner", "Operator", "Reference method"