[Federal Register: July 12, 2007 (Volume 72, Number 133)]
[Notices]
[Page 38071-38072]
[DOCID:fr12jy07-48]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. OA07-12-002]

MidAmerican Energy Company; Notice of Filing

July 5, 2007.
    Take notice that on June 29, 2007, MidAmerican Energy Company
submitted an errata filing to clarify inconsistencies in its
supplemental filing in compliance with Order 890 dated June 26, 2007.
    Any person desiring to intervene or to protest this filing must
file in accordance with Rules 211 and 214 of the Commission's Rules of
Practice and Procedure (18 CFR 385.211, 385.214). Protests will be
considered by the Commission in determining the appropriate action to
be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a notice of
intervention or motion to intervene, as appropriate. Such notices,
motions, or protests must be filed on or before the comment date.
Anyone filing a motion to intervene or protest must serve a copy of
that document on the Applicant and all the parties in this proceeding.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper using the ``eFiling'' link at http://www.ferc.gov.
 Persons unable to file electronically

should submit an original and 14 copies of the protest or intervention
to the Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426.
    This filing is accessible on-line at http://www.ferc.gov, using the

``eLibrary'' link and is available for review in the Commission's
Public Reference Room in Washington, DC. There is an ``eSubscription''
link on the Web site that enables subscribers to receive e-mail
notification when a document is added to a subscribed docket(s). For
assistance with any FERC Online service, please e-mail
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For

TTY, call<PHONE_NUMBER>.
    Comment Date: 5 p.m. Eastern Time on July 10, 2007.

Kimberly D. Bose,
Secretary.
 [FR Doc. E7-13513 Filed 7-11-07; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register: May 27, 2010 (Volume 75, Number 102)]
[Rules and Regulations]
[Page 29656]
[DOCID:fr27my10-6]

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DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 71

[Docket No. FAA-2009-1181; Airspace Docket No. 09-ASW-36]

Amendment of Class E Airspace; Mountain View, AR

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Final rule.

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SUMMARY: This action amends Class E airspace for Mountain View, AR.
Decommissioning of the Wilcox non-directional beacon (NDB) at Mountain
View Wilcox Memorial Field Airport, Mountain View, AR, has made this
action necessary to enhance the safety and management of Instrument
Flight Rule (IFR) operations at the airport.

DATES: Effective Date: 0901 UTC, July 29, 2010. The Director of the
Federal Register approves this incorporation by reference action under
1 CFR part 51, subject to the annual revision of FAA Order 7400.9 and
publication of conforming amendments.

FOR FURTHER INFORMATION CONTACT: Scott Enander, Central Service Center,
Operations Support Group, Federal Aviation Administration, Southwest
Region, 2601 Meacham Blvd., Fort Worth, TX 76137; telephone (817) 321-
7716.

SUPPLEMENTARY INFORMATION:

History

    On March 15, 2010, the FAA published in the Federal Register a
notice of proposed rulemaking to amend Class E airspace for Mountain
View, AR, reconfiguring controlled airspace at Mountain View Wilcox
Memorial Field Airport (75 FR 12163) Docket No. FAA-2009-1181.
Interested parties were invited to participate in this rulemaking
effort by submitting written comments on the proposal to the FAA. No
comments were received. Class E airspace designations are published in
paragraph 6005 of FAA Order 7400.9T signed August 27, 2009, and
effective September 15, 2009, which is incorporated by reference in 14
CFR 71.1. The Class E airspace designations listed in this document
will be published subsequently in the Order.

The Rule

    This action amends Title 14 Code of Federal Regulations (14 CFR)
part 71 by amending Class E airspace for the Mountain View, AR area.
Decommissioning of the Wilcox NDB and cancellation of the NDB approach
at Mountain View Wilcox Memorial Field Airport has made this action
necessary for the safety and management of IFR operations at the
airport. Adjustment to the geographic coordinates also will be made in
accordance with the FAA's National Aeronautical Charting Office. With
the exception of editorial changes, and the changes described above,
the rule is the same as that proposed in the NPRM.
    The FAA has determined that this regulation only involves an
established body of technical regulations for which frequent and
routine amendments are necessary to keep them operationally current.
Therefore, this regulation: (1) Is not a ``significant regulatory
action'' under Executive Order 12866; (2) is not a ``significant rule''
under DOT Regulatory Policies and Procedures (44 FR 11034; February 26,
1979); and (3) does not warrant preparation of a regulatory evaluation
as the anticipated impact is so minimal. Since this is a routine matter
that will only affect air traffic procedures and air navigation, it is
certified that this rule, when promulgated, will not have a significant
economic impact on a substantial number of small entities under the
criteria of the Regulatory Flexibility Act.
    The FAA's authority to issue rules regarding aviation safety is
found in Title 49 of the U.S. Code. Subtitle 1, section 106, describes
the authority of the FAA Administrator. Subtitle VII, Aviation
Programs, describes in more detail the scope of the agency's authority.
This rulemaking is promulgated under the authority described in
subtitle VII, part A, subpart I, section 40103. Under that section, the
FAA is charged with prescribing regulations to assign the use of
airspace necessary to ensure the safety of aircraft and the efficient
use of airspace. This regulation is within the scope of that authority
as it amends controlled airspace at Mountain View Wilcox Memorial Field
Airport, Mountain View, AR.

List of Subjects in 14 CFR Part 71

    Airspace, Incorporation by reference, Navigation (air).

Adoption of the Amendment

0
In consideration of the foregoing, the Federal Aviation Administration
amends 14 CFR part 71 as follows:

PART 71--DESIGNATION OF CLASS A, B, C, D, AND E AIRSPACE AREAS; AIR
TRAFFIC SERVICE ROUTES; AND REPORTING POINTS

0
1. The authority citation for 14 CFR part 71 continues to read as
follows:

    Authority:  49 U.S.C. 106(g), 40103, 40113, 40120; E.O. 10854,
24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.

Sec.  71.1  [Amended]

0
2. The incorporation by reference in 14 CFR 71.1 of the Federal
Aviation Administration Order 7400.9T, Airspace Designations and
Reporting Points, signed August 27, 2009, and effective September 15,
2009 is amended as follows:
* * * * *

Paragraph 6005 Class E airspace areas extending upward from 700
feet or more above the surface.

* * * * *

ASW AR E5 Mountain View, AR [Amended]

Mountain View Wilcox Memorial Field Airport, AR
    (Lat. 35[deg]51'52'' N., long. 92[deg]05'25'' W.)

    That airspace extending upward from 700 feet above the surface
within a 6.4-mile radius of Wilcox Memorial Field Airport, and
within 1.8 miles each side of the 273[deg] bearing from the airport
extending from the 6.4-mile radius to 11.5 miles west of the
airport, and within 2 miles each side of the 093[deg] bearing from
the airport extending from the 6.4-mile radius to 12.1 miles east of
the airport.

    Issued in Fort Worth, Texas, on May 13, 2010.
Anthony D. Roetzel,
Manager, Operations Support Group, ATO Central Service Center.
[FR Doc. 2010-12362 Filed 5-26-10; 8:45 am]
BILLING CODE 4910-13-P


One commenter ( OAR 2002 0056 2535) stated that the AES Hawaii power plant should not be used to set the subbituminous emission limit for two reasons. First, the plant is an FBC unit, which relies on a fundamentally different combustion process and is not representative of the type of plant that burns subbituminous coal in the 48 contiguous States. Second, the plant burns Indonesian subbituminous coal, which is also not representative of the subbituminous coal burned in the 48 contiguous States. In addition to the coal not being representative, EPA must recognize that coal is our largest reserve of domestic fossil fuel, and should not be using a foreign coal to set a domestic standard. This goes against EPA's stated principle of not considering fuel switching as a viable method for setting a MACT floor. Use of Indonesian coal to set the MACT floor will result in more domestic coal being displaced from use in domestic coal fired power plants.

Response:

The AES Hawaii facility was one of nine subbituminous fired units used in establishing the revised new source NSPS emission limits. EPA did not feel that it would be appropriate to exclude this unit from the reanalysis because ( 1) at least one new subbituminous fired unit has received a permit based on the use of FBC technology in Utah ( and, thus, FBC technology is representative of the type of plant that could burn subbituminous coal in the contiguous 48 3 45 States), and ( 2) Indonesian coal was reported to be used by at least two other utility units in 1999 ( and, thus, could be used by other units in the U. S.).

Comment:

One commenter ( OAR 2002 0056 3437) requested that EPA examine the recent State MACT/ BACT decisions that have required ACI. In particular, Iowa set a case by case MACT limit equal to 1.7 lb/ TBtu based on ACI with 83 percent control efficiency using PRB coal.

Response:

As noted earlier, EPA does not believe that Hg specific control technologies, including ACI, are commercially available for nationwide application to the coal fired utility industry. Installation of such technologies on a limited number of units ( e. g., the one cited) is possible and will serve to advance the technologies such that they are widely for use in compliance with the phase II cap.

<IP_ADDRESS> Lignite fired Units Comment:

One commenter ( OAR 2002 0056 3469) supported the proposed limits. The commenter stated that despite flaws in the ICR data used to determine the emission limits, they supported the emission limits for existing units of 9.2 lb/ TBtu for Fort Union lignite fired units.

Another commenter ( OAR 2002 0056 2115) supported the proposed limit for lignite because it is the same level that would be required under the Clear Skies proposal. An unattainable Hg limit would result in a practical ban on lignite as fuel. Texas mines over 40 million tons of lignite coal per year for use as power plant fuel.

Response:

EPA concurs that the standards must be achievable by all coal ranks.

Comment:

One commenter ( OAR 2002 0056 3514) stated that currently, no technology has been shown to be effective in capturing Hg from lignite coals. Although EPA has proposed for lignite more reasonable emission limits, it still has not been shown that these levels can be met. Lignite and other low rank western coals face additional obstacles that do not affect other coals, namely higher ash, lower Cl and higher elemental Hg content. Accordingly, these factors make it impossible, at least currently, to attain the removal percentages being achieved with other coals.

One commenter ( OAR 2002 0056 2054) stated that the EPA has not proposed standards for new lignite fired units on a level of performance that is " achievable" by a unit that is " similar" 3 46 to most new lignite fired units. The commenter stated that the highest Hg removal rate of any lignite fired plant in the ICR data was 21 percent, and the plant that achieved this removal rate, Stanton Station, is a relatively small, older plant that is definitely not " similar" to a new lignite fired unit. According to the commenter, the agency did not base its new unit standard on performance, but rather on the lowest Hg coal; the result of this basis is to eliminate the vast majority of lignite reserves from any new units. The commenter asserts that the choice of best performing unit should comply with the direction given by the DC Circuit Court in National Lime Association v. EPA, 627_ F. 2d 416, 431n. 46( 1980). The commenter stated that this best performing unit is based, according to the court, on a level of performance that can be achieved " under the most adverse circumstance which can reasonably be expected to occur." Therefore, the " best controlled" source must be taken into account to predict emissions from any reasonable situation, including different lignites.

Response:

As noted above, EPA has revised the new source NSPS Hg emission limits based on a reanalysis of the available information, including permits. We believe that the revised emission limits address the commenters' concerns.

Comment:

One commenter ( OAR 2002 0056 3478) requested that any emission limits for lignitefired power plants include Gulf Coast lignite as a separate subcategory. Based upon their evaluation of the tested units, the commenter requested that EPA set any limit for Gulf Coast lignite fired units at a rate no less than 28 lb/ TBtu. The commenter stated that if EPA does not establish a separate subcategory for Gulf Coast lignite with a higher standard, then a percent reduction option and/ or a " safety net" must be offered so that units in Texas, Louisiana, and Mississippi can continue to utilize locally mined lignite as fuel.

Two commenters ( OAR 2002 0056 2915,  3463) stated that Gulf Coast lignite cannot achieve the reductions required to meet the proposed standard for lignite Because it was set with units firing North Dakota lignite. One commenter ( OAR 2002 0056 2915) stated that coal fired utility units already face emissions control requirements that are duplicative, contradictory, costly, and complex, and create enormous uncertainty for future investment and that adding Hg emissions regulations will create even greater challenges for coal fired utility units, and this is especially true for Gulf Coast lignite because its unique physical composition makes reductions in Hg emissions from utility units firing it very difficult to achieve and more difficult to achieve than for non lignite coal fired utility units.

One commenter ( OAR 2002 0056 4891) added that the proposed Hg rule rules should be revised to better recognize the high concentration and type of Hg present in Gulf Coast lignite and the difficulties associated with controlling its Hg emissions as compared to Hg emissions from other coal ranks. The commenter stated that without significant changes to the proposed Hg rule to lessen compliance costs, it is likely that most Gulf Coast lignite mines and some Gulf Coast lignite fired power plants will ultimately be forced to close. According to the commenter, power 3 47 grid stability would be compromised without the generation capacity provided by Gulf Coast lignite fired power plants, resulting in the potential for frequent and sustained power outages that would undermine economic stability and prospects for economic growth.

One commenter ( OAR 2002 0056 3478) believed the Hg content in Gulf Coast lignite is higher than the ICR data indicate, a more accurate analytical method for Cl in coal demonstrates that the Cl content in Gulf Coast lignite is much lower. The commenter also believed this revised information on Cl content may explain why lignite combustion results in a significant percentage of elemental Hg being emitted.

One commenter ( OAR 2002 0056 2929) expressed concern that facilities burning Texas lignite will be unable to comply with the proposed Hg emission limits because the best performing lignite units all fire cleaner burning North Dakota lignite.

Response:

As noted elsewhere, EPA does not see a basis at this time for further subcategorizing lignite coals.

Comment:

Several commenters expressed concern over the impacts resulting from the stringent rules for lignite coals. The commenters ( OAR 202 0056 1692,  2915,  3510,  3543,  4891) were concerned that stringent rules for lignite coal would result in fuel switching and have negative impacts on lignite burning units. One commenter ( OAR 2002 0056 2915) stated that EPA must ensure that the Hg rule does not disadvantage coal, especially Gulf Coast lignite, because doing so would aggravate the already precarious natural gas supply and price situation. The commenter stated that if the Hg rule was to even slightly decrease the dependence on coal, the natural gas supply and the price problems would increase. According to the commenter, it is estimated that forced replacement of coal with natural gas as fuel in electric generation would increase the demand for natural gas by about 35 percent and would increase natural gas prices by about 33 percent. According to one commenter ( OAR 2002 0056 3510), natural gas is not available to utilities in the winter when it is apportioned to residential users. One commenter ( OAR 2002 0056 1692) stated that the proposed lignite limit of 9.2 lb/ Btu is so stringent that it would preclude many southern lignite coals from future use and would promote the use of natural gas, especially in smaller plants, where the high cost of controls may not be justified given the anticipated life of the plant. According to another commenter ( OAR 2002 0056 3543), the current rule structure could cause generators to switch coal ranks, primarily from lignite and subbituminous to bituminous coal with resultant economic impacts. Without a higher limit for Gulf Coast lignite, commenters ( OAR 2002 0056 3510,  4891) stated that their State economies will suffer because lignite is an important fuel in their State. One commenter ( OAR 2002 0056 2915) stated that utility units designed to burn lignite cannot easily, quickly, or cheaply switch to burn other fuel types. According to the commenter, lignite's low heat content and its other properties would require time consuming and expensive alterations to allow them to burn non lignite fuels. The commenter further stated that lignite fired utility units are often 3 48 parties to long term contracts to purchase the lignite; therefore, even if such utility units could no longer burn lignite, they would still be required to purchase it pursuant to any such long term contracts. The commenter also added that Gulf Coast lignite fired utility units in Texas are located on the property from which the lignite is mined and that for many such units, rail lines that could be used to transport other types of fuel to the site would have to be constructed.

Response:

As noted elsewhere, EPA has reanalyzed the new source NSPS limits and believes that the emission limit being finalized is achievable and appropriate.

Comment:

Several comments addressed the control of Hg from lignite fired units. Three commenters ( OAR 2002 0056 3327,  3469,  4191) expressed concern regarding the availability of proven control measures. According to one commenter ( OAR 2002 0056 3469), the lack of availability on the market of proven cost effective control and monitoring equipment will make compliance with the proposed regulations difficult for utilities, particularly those burning lignite. The commenter supported proposals which give utilities flexibility in how they implement controls and comply with the regulations and which provide incentives to comply as quickly as practical and make the most cost effective investments that provide the largest emissions reductions. Thus, the commenter supported EPA's proposal to allow utilities to use facility wide averaging, system wide averaging, and use 12 month rolling averages to calculate emissions and demonstrate compliance. One commenter ( OAR 2002 0056 3327) was concerned that despite the progress made in their State and efforts to continue identifying new technologies to control emissions from coal fired power plants, the imposition of the proposed requirements will force the closure of lignite fired power plants prior to the time that effective emissions control technology can be developed and made commercially available.

One commenter ( OAR 2002 0056 3478) cited lignite properties in addition to monitoring technology as the main hindrance to pollution control companies providing a Hg removal guarantee. Citing the high degree of elemental Hg remaining in flue gases of lignite as well as lignite's tendency to have relatively high total Hg content, the commenter believed they have valid concerns that Hg control for lignite fired boilers will be more difficult and costly than for bituminous coal fired boilers. According to the commenter, coal analysis from one mine indicated that a 59  76 percent reduction in Hg emissions would be required. The commenter also reports that similarly, if they examine the 70 percent lignite/ 30 percent PRB data, a weighted average limit of 8.18 lbs/ TBtu would have to be met. According to the commenter, one pollution control company does have experience with an ACI system supplier that have given guarantees of 50 percent removal for PRB coals at a carbon consumption rate equivalent to an expenditure of ~$ 5M per year and subject to very specific restrictions and very limited liability, but no such guarantees to date have been given for lignite fired plants. The commenter further stated that the PRB guarantees to date have been predicated upon availability of necessary quantities of suitable activated carbon, total amount of Hg entering the system, and averaging period allowed to meet guarantees. According to the commenter, Hg control technologies are highly coal and 3 49 boiler/ AQCS configuration dependent, not to mention the issues with test accuracy when measuring Hg with a concentration six orders of magnitude less than SO2. The commenter stated that it will only be after multiple demonstrations have been completed before all the anomalies are sorted out in order for suppliers to take on the risk of Hg removal guarantees.

Response:

EPA believes that the regulatory approach being taken will address the commenters' concerns, particularly with regard to the flexibility afforded to a company. The flexibility afforded by the cap and trade approach will preclude any concerns about having to arbitrarily close coal fired utility units and provide the time necessary to fully develop the emerging Hgspecific control technologies. Further, EPA believes that reliable, cost effective Hg monitoring systems are available and will be further refined by the time utilities must be in compliance with the revised standards.

Comment:

One commenter ( OAR 2002 0056 3478) stated that regulations to control SO2 and NOx will require the installation of pollution controls that will also capture the forms of Hg that tend to deposit nearby. The commenter stated that, based on testing of SCR performance for Hg cobenefits on a lignite facility in North Dakota, SCR will not provide much, if any, Hg co benefit reduction. According to the commenter, SCR technology is ineffective in oxidizing Hg and that the saltation of calcium and sodium ash deposits fouls the catalyst rendering the SCR technology ineffective for NOx control.

Response:

EPA believes that the cap and trade approach being taken will address the commenter's concerns. For the new source NSPS Hg emission limits, EPA has not assumed any removal contribution by SCR units on lignite coal.

Comment:

One commenter ( OAR 2002 0056 4891) stated that, given the lack of scientific evidence linking health impacts to Gulf Coast lignite fired power plant Hg emissions and its insignificant contribution to Hg emissions relative to other sources and the global Hg emissions pool, there is no present justification for a regulation with as significant an economic impact as the proposed Hg rule.

Response:

EPA sees no basis for excluding Gulf Coast lignite from the revised standards.

Comment: 3 50 One commenter ( OAR 2002 0056 3398) stated that North Dakota lignite has a lower Cl content than subbituminous or bituminous coal and that Hg control from lignite is much more difficult, warranting a higher emission limit.

Response:

EPA concurs that lignite coal exhibits unique combustion and control characteristics and, as such, has placed lignite in a separate subcategory.

Comment:

Commenter OAR 2002 0056 5535 disagreed that the best performing lignite units fire North Dakota lignite and that North Dakota lignite is significantly different from other lignite. First, the commenter's analysis of the best performing units indicates that TXU's TNP One unit, which burns Texas lignite coal, is the best performing lignite unit. The commenter used EPA's methodology to estimate Hg emissions for every coal shipment fired by TNP One. When these estimates are averaged, the average annual emission rate is 1.29 lb/ TBtu B the best performance of any lignite fired unit. Second, although it is true that Texas lignite has a higher ash content than North Dakota lignite and that facilities firing Texas lignite are among the biggest Hg emitters in the U. S., none of these facilities has opted to participate in any of the DOE sponsored emissions tests aimed at evaluating Hg control technologies. The Monticello plant, which fires Texas lignite, is scheduled to be tested during the Phase II DOE tests ( mid 2005), but the test plan excludes the most promising technology for lower ranks coals B halogenated activated carbon sorbents. Consequently, it will not be possible to compare Monticello's performance with that of North Dakota facilities, which have been tested with these sorbents, achieving Hg emission reductions in excess of 90 percent. In addition, the commenter noted that one facility firing Texas lignite B the Big Brown plant B has been operating a COHPAC baghouse for a number of years. This small add on fabric filter is the key component of EPRI's patented TOXECON process, whereby activated carbon is injected upstream of the COHPAC. Tests of this configuration on low sulfur bituminous coal resulted in Hg capture averaging 86 percent over a 19 week period. Use of a COHPAC with a halogenated sorbent could result in very high Hg capture B even with Texas lignite B but, unfortunately, the test will not include this configuration. If EPA were to establish a more lenient standard for Texas lignites, it would have harmful environmental and health consequences. One outcome of a more lenient standard for these facilities is that they will continue to emit Hg in huge amounts. A second potential outcome of a higher emission rate B if EPA adopts its ill advised trading scheme B is that these facilities might decide to reduce their Hg emissions using the most promising technologies, and then to bank and sell a large number of Hg allowances, thereby allowing other polluters to avoid controls. Thus, convincing EPA that they are unable to control their Hg emissions ( in the absence of any data substantiating that assertion) is clearly in the financial interest of these companies and against the interests of public health and welfare.

Response:

As noted earlier, EPA continues to believe that placing lignite in a separate subcategory 3 51 is warranted but that further subcategorization into Fort Union and Gulf Coast lignites is not necessary. The revised new source NSPS Hg limits incorporate data from both types of lignite and, thus, are believed to be representative and appropriate. Further, as noted earlier, EPA does not believe that Hg specific control technologies are currently available for use as the basis of a national Hg standard. We believe that the declining cap under the cap and trade approach being finalized will ensure both development of the emerging Hg specific control technologies and continued Hg emission reductions by all utility units in the most efficient manner.

<IP_ADDRESS> Coal Refuse fired Units Comment:

One commenter ( OAR 2002 0056 2068) requested that the EPA not set emission limits for new and existing coal refuse fired plants so as to ensure that any limit is achievable and takes into account the wide variability within this important fuel supply.

Response:

The current subpart Db emission limits for PM, SO2, and NOx, are applicable to coal refuse fired units ( with an existing definition of " coal refuse") and EPA sees no basis to exclude such units from the Hg emission limits. EPA believes that the revised new source NSPS Hg emission limits for these sources are achievable and appropriate.

Comment:

Three commenters ( OAR 2002 0056 1766,  2162,  5495) opposed the proposed emission limits for coal refuse fired units. The proposed limits are more than five times more stringent, on a lb/ TBtu basis, than the proposed limits for the next most stringently regulated coal fired source category. The EPA selected this proposed standard based upon limited data from only two waste coal fired sources. Such an insignificant amount of data is an insufficient basis upon which to promulgate emission limits. Also, the EPA did not appropriately consider the variability inherent in the waste coal fuel source. Specifically, the characteristics of waste coal vary to a much greater extent than other coal ranks. Finally, the commenters stated that in addition to being inequitable and based on inadequate data, the proposed emission limit for waste coal fired sources may not be achievable. Commenter OAR 2002 0056 5495 thought the measured emissions from the test data used to set the limit were abnormally low due to a variety of factors.

Response:

The revised emission limits ( as noted earlier) for coal refuse fired units are based on data from units within the coal refuse subcategory. EPA believes that the stringency of the limits accurately reflects the performance on Hg emissions of controls used on such units. No data were provided during the public comment period that refuted the relative levels of control achievable by coal refuse fired units as evidenced by the Hg emission limits established in the rule. Further, EPA did consider the variability inherent in the fuel source in arriving at the final 3 52 emission limits. EPA disagrees with the commenters regarding the level of variability found in coal refuse related to other coal ranks. Some constituents ( e. g., ash, Btu content) do exhibit wider variability, as would be expected given the nature of the fuel source. However, other constituents ( e. g., sulfur, Hg) exhibit similar or less variability than do other coal ranks.

Comment:

One commenter ( OAR 2002 0056 2261) stated that the emissions limits for coal refuse fired units must be consistent with the current levels of Hg emissions from each of these sources to ensure that all coal refuse fired sources could comply with such levels, notwithstanding the inherently variable characteristics of the waste coal source. The commenter recommended that any such limit should be reflective of a 90 percent reduction in Hg, based upon the Hg content in the coal refuse prior to combustion, as measured by inlet and outlet concentrations evaluated during biennial performance testing. The commenter stated that such a limit would be consistent with the effective Hg control achieved by coal refuse sources.

Response:

EPA sees no basis for providing coal refuse fired units a different compliance approach than for other subcategories. Therefore, the 12 month rolling average and continuous monitoring requirements have been maintained in the revised standards. The revised standards are believed reflective of the expected performance of coal refuse fired units.

Comment:

One commenter ( OAR 2002 0056 3560) stated that the EPA did not gather information concerning a non CFB unit that burns coal refuse. Therefore, the proposed Hg emission limit for coal refuse units cannot be justifiably applied to a cyclone unit burning at least 25 percent coal refuse and the rest of the fuel input is essentially bituminous coal.

One commenter ( OAR 2002 0056 2826) points out that their member electric cooperative burns Illinois basin bituminous waste coal. Along with their electric cooperative, the commenter believes that EPA's data from units burning waste coals and the EPA's related analysis are neither complete nor representative of the emission characteristics of this coal rank. The commenter adds that there is apparently no information in the EPA database for a cyclone unit, such as their member cooperative's Unit 4, which burns a coal waste product as a significant portion of its fuel input. The commenter respectfully requests that EPA address the above issues as it finalizes its proposed rule.

One commenter ( OAR 2002 0056 2261) observed that the proposed rules establish Hg emission rates based on rank of coal, including waste coal, being burned. The commenter does not believe that the rates for existing and new units are reflective of either new or existing technology used to burn waste coal. According to the commenter, EPA must consider:

( 1) the difference and variation in the chemical quality of waste coal from different coal 3 53 fields in different parts of the country;

( 2) the technology used to clean the coal producing the waste coal;

( 3) the percent SO2 reduction required at the different waste coal plants and its impact on heat input and Hg emissions; and ( 4) NOx controls being implemented.

Response:

Such data as noted by the commenters ( e. g., non CFB units burning coal refuse; data on coal refuse from different parts of the country) were not made available to EPA during the public comment period. Units co firing coal refuse and other coal ranks would be subject to the provisions applicable to units that blend coal ranks. EPA believes that future units constructed to combust coal refuse will be similar in nature to existing units and, thus, that the final emission limits are reflective of units that will combust coal refuse.

<IP_ADDRESS> IGCC Units Comment:

One commenter ( OAR 2002 0056 2721) stated there has not been a full scale demonstration of sorbent bed technology on IGCC units with lignite or subbituminous coal. The commenter noted that the process addressed by EPA in the preamble for the proposed rule is for an industrial facility firing bituminous coal and producing a synthetic gas ( syngas) that is cooled to about 100

F. According to the commenter, not all IGCC units have a gas stream with a temperature that low. The commenter stated that sorbent beds do not work when temperatures are several hundred degrees. The commenter believes there is no justifiable basis to use this technology for setting. performance standards.

Response:

EPA agrees with the commenter that no IGCC unit utilizing syngas produced from subbituminous or lignite coals has been operated with a carbon bed for Hg removal. However, IGCC units have been operated on subbituminous and lignite coals in the U. S. ( OAR 2002 0056 5684). Application of the carbon bed to IGCC units burning such coals would not present any additional technical obstacles. EPA also concurs that the optimal temperature for carbon bed utilization is around 100

F. However, EPA disagrees with the commenter's inference that this temperature is not found in some IGCC applications. The DOE conducted a feasibility study to evaluate the cost of removal of Hg from IGCC units ( OAR 2002 0056 5685). This study found that the optimal location for the carbon bed was between the fuel gas cooling/ knockout unit and the acid gas removal unit ( and prior to the combustion turbine), a location likely to be found in any new IGCC installation. This location affords temperatures close to the optimal 100

F. Therefore, EPA believes that carbon bed technologies are 3 54 appropriate for use on new IGCC installations.

Comment:

One commenter ( OAR 2002 0056 3459) stated that ACI should be the basis of the standard for IGCC units. DOE has concluded Hg controls are available and applicable to IGCC units. The technology is already commercially demonstrated to remove greater than 90 percent Hg removal and was specifically applicable to gasification systems using high temperature slagging gasifiers and bituminous coal, which includes both of the IGCC plants currently in operation. EPA must establish emission limits that reflect at least 90 percent reduction in Hg emissions from IGCC units. Based on commenter's analysis, the rate should be 0.49 lb/ TBtu or 3.9 x 10 6 lb/ MWh ( output based standard based on 42.5 percent efficiency and conversion factor for mass/ 1012 Btu to mass/ MWh at 42.5 percent efficiency is 8 x 10 6 TBtu/ MWh).

Two commenters ( OAR 2002 0056 1852,  2160) opposed separate limits for new or existing IGCC units. According to one commenter ( OAR 2002 0056 2160), Hg capture from syngas has been proven to be readily available and inexpensive at the Eastman Chemical coal gasification plant in Kingsport, TN. There is no reason to establish separate and overly lenient limits for the two existing U. S. plants or for any new plants.

Response:

The existing units will be covered under the cap and trade portion of the final CAA section 111 rulemaking and, thus, will be subject to their respective State's Hg budget. Any new units would be subject to the more restrictive new source NSPS Hg emission limit which is based on the use of a carbon bed as at the Tennessee facility.

Comment:

One commenter ( OAR 2002 0056 4139) stated that the WEST Associates statistical model should not have been applied in developing the emission limits for IGCC units. Both Cl and Hg would be removed separately from the coal as part of the coal gasification process. Therefore, Cl and Hg could not interact as they are not present at the same quantitative levels as in the combustion process of coal fired boilers. This leads to an artificially high limit for new sources.

Response:

Analysis of variability is appropriate for IGCC units. It is true that Hg and Cl would be removed separately in an IGCC process; however, based on information available to EPA ( OAR 2002 0056 5685), the Hg would likely be removed prior to the removal of the Cl, and, thus, the Hg Cl interaction presumed in the current statistical analysis would still be valid.

<IP_ADDRESS> Blended Fuel fired Units 3 55 Comment:

One commenter ( OAR 2002 0056 2198) stated that the proposed limits for subbituminous coal are less stringent than those for bituminous coal. A unit that previously burned bituminous coal could choose to blend or switch to subbituminous coal and emit more Hg proportional to the ratio of subbituminous to bituminous coal. Because many units can burn either of the two ranks of coal, this commenter does not support this approach. The EPA should require sources that burn a blend of coal to be subject to the more stringent limit regardless of the coal or coal mixture being burned at any time.

One commenter ( OAR 2002 0056 2889) stated the proposed rule would allow units that blends coal ranks to average the standards for those coal. Facilities must compute the weighted average limit based on the proportion of energy input ( Btu) contributed by each coal rank burned during the compliance period. However, the rule does not specify how this is to be done. Because blending is typically done with a bulldozer, the quantity of each fuel is not determined with any precision. To avoid inaccuracies inherent in computing a limit for blended coal, the rule should require the facility to meet the most stringent standard of the fuels combusted.

One commenter ( OAR 2002 0056 3449) stated that limits for blended coals should not be prorated. Under the proposal, 50/ 50 blending of subbituminous coal with bituminous coal would increase allowable emissions for a facility previously burning only bituminous coal by almost 2 times. This type of coal blending is already popular for reducing SO2 and NOx emissions; the additional benefit of lower Hg emissions coupled with a higher limit would further increase the incentive. The fact that coal blending provides the benefit of a higher limit is a clear rationale that EPA should adopt one limit for subbituminous and bituminous coal. At the very least, the lowest applicable standard should apply to blended coal, not a prorated higher standard. The commenter's experience demonstrates that blended coal does not need a higher limit. Blending should be encouraged to reduce emissions, not increase allowable emissions.

Response:

EPA believes that it is appropriate to use the prorated approach as this is consistent with that already included in subpart Da.

Comment:

One commenter ( OAR 2002 0056 2247) disagreed with EPA's description of the importance of coal rank at units such that fuel switching will not occur. Given the demands of further NOx and SO2 reductions, fuel switching will continue, the EPA's proposal to proportion the Hg emissions limit between subbituminous and bituminous ( or between subbituminous and lignite) will result in emissions increases for the unit that switches. Rather than apportioning the limit between the percent of fuel burned, the limit should apply for the fuel used in the majority. Thus, any facility using up to 50 percent bituminous coal with subbituminous coal should meet a limit for bituminous coal. Because subbituminous coal has lower overall Hg content and bituminous appears to have sufficient Cl or oxidize Hg for downstream capture, a unit blending 3 56 coal should not have difficulty meeting the limit.

Response:

EPA believes that it is appropriate to use the prorated approach as this is consistent with that already included in subpart Da.

Comment:

One commenter ( OAR 2002 0056 2897) believed blending of different coal ranks can also be readily accommodated under a rule that includes subcategorization. Of the two options presented, the commenter recommended that the EPA proceed with a weighted average standard, as this will be less susceptible to " gaming."

One commenter ( OAR 2002 0056 2922) supported EPA's decision to utilize a blended emissions limit rather than attempt to establish a separate subcategory for blended fuel units, or to classify a unit based on the predominant coal it combusts.

One commenter ( OAR 2002 0056 2900) urged EPA to retain the five subcategories identified in the proposal. The commenter stated that the failure to do so would have an immediate impact on the balance of coal ranks burned in the U. S. and would jeopardize the nation's fuel diversity. For the same reasons, the commenter supported the Agency's proposed approach of addressing units burning blended coal by weighting the applicable Hg limit according to the amounts of the different coals that are burned.

One commenter ( OAR 2002 0056 2922) supported EPA's decision to utilize a blended emissions limit rather than attempt to establish a separate subcategory for blended fuel units, or to classify a unit based on the predominant coal it combusts.

Response:

EPA concurs with the weighted average approach endorsed by the commenters.

Comment:

One commenter ( OAR 2002 0056 2900) supported the EPA's proposed approach for a unit burning a blend of coals and a supplemental fuel that the supplemental fuel would not be taken into account for purposes of determining the unit specific emission limit that the unit must meet. However, the supplemental fuel's heat input and Hg emissions would be considered in determining the unit's compliance with the emission limit. The commenter requested that the regulatory text clearly reflects EPA's preamble language on this issue. In addition, the commenter requested that EPA clarify that units burning a single coal rank and a supplemental fuel would be treated the same as units burning a coal blend and a supplemental fuel. That is, the supplemental fuel would not be considered in determining the emission limit to which the unit is subject. The commenter explains the unit would be subject to the emission limit for the coal rank 3 57 it is combusting; however, for compliance purposes, the heat input and Hg emissions from the supplemental fuel would be taken into account.

Response:

EPA believes that the final regulatory language is clear.

Comment:

One commenter ( OAR 2002 0056 3517) pointed out that there has been little in depth study of plants that burn coal blends, and how that might impact or benefit Hg removal. The commenter stated that a case in point is the Valmont Plant in Colorado which burns a blend of low Hg, low Cl bituminous and subbituminous coal, both of which are mined in Colorado. According to the commenter, although it is recognized that these coals are low in Hg, there is still significant Hg reduction that occurs. The commenter request that EPA seek further information on coal blending as a potential option in addressing Hg reductions between the close of the comment period and the issuance of the final rule. The commenter stated they would like to retain the option to provide additional information on this topic as it becomes available.

Response:

The impact of intentional coal blending for the purpose of Hg removal is being investigated under the DOE Hg research program. EPA believes that this approach is yet another option that facilities may have in achieving compliance with the final emission limits.

Comment:

Two commenters ( OAR 2002 0056 1848,  2108) expressed concern about compliance burden on sources that blend coal and the State agencies that regulate them. According to the commenters, there are no industry wide blending procedures and the lack of specificity will lead to an inaccurate accounting of emissions.

Response:

EPA believes that the States are familiar with the weighted average approach being used in the final rule as it is currently a part of subpart Da for other pollutants.

<IP_ADDRESS> Cogeneration Units Comment:

One commenter ( OAR 2002 0056 2906) stated that the proposed emission rate calculation for cogeneration units appears to unfairly penalize these units for sales of any electric power less than the full generation capacity, contrary to the EPA's stated intent to advance the application of cogeneration facilities and thereby improve the nation's energy efficiency and 3 58 achieve greenhouse gas emission intensity reductions. In both the proposed rule and preamble, EPA applies the 18 CFR 292.205 efficiency methodology to cogeneration facilities ( implied to be limited to solid fuel fired facilities because gas fired units are not included in the rule applicability) ( 69 FR 4696 and 69 FR 4762). Application of that methodology appears to penalize those cogeneration facilities that sell only a portion of their total net electricity generation output to the grid. Irrespective of the comments relating to the need for annual net sales of electricity to the grid, the EPA approach would restrict the total output of energy in the denominator to only that electricity sold to the grid plus one half of the net steam output of the unit, assuming that any energy input that is not utilized through electricity sales is used as steam output ( 69 FR 4762). However, this penalizes a facility for using any electricity generated in the cogeneration facility within the manufacturing facility. Many cogeneration facilities are located within manufacturing plants that use most, or all of the generated electricity. The cogeneration unit only sells to the grid the excess power on an as available basis in order to maintain optimum overall system efficiency. For example, the methodology in the proposed rule was applied to a typical coal fired cogeneration facility. At a constant Hg lb/ hr emission rate, constant heat input to the boiler, and constant electricity generation rate, the calculated emission rate on a lb/ MWh basis would vary with the quantity of electricity sold to the grid. For this example, the lb/ MWh calculated emission rate would be 70 percent higher when selling 25 MWe to the grid than when selling 100 percent of generated electricity to the grid. This equation unfairly penalizes cogeneration facilities. The EPA needs to provide full consideration of the complexities of cogeneration units when trying to develop and utilize output based emission limits. An equitable and workable solution would be to follow past EPA practice in establishing emissions standards and allow cogeneration facilities the ability to use input based emission limits and calculations. With this approach, the boiler, fuels, and emissions controls will determine compliance without the apparent emission rate being unfairly skewed by the portion of electricity sold to the grid. The EPA should establish emissions standards that encourage installation and operation of highly efficient cogeneration facilities, and recognize their inherent variability in design and operating profiles versus typical single use electric utility units.

Response:

The commenter appears to believe that, for a cogeneration unit classified as a utility generating unit, reducing the percentage of electricity sold to the grid increases the emission rate for regulatory purposes. The commenter provided no calculations to support this contention, but, in any event, we believe the comment to be incorrect. If a unit's entire rated output is sold to the grid, the unit would be charged with emissions equivalent to full load. If the unit sells half of its rated output to the grid and the other half is used internally ( either as steam or as electricity), the unit would be charged only 75 percent of its entire emissions output ( all of the emissions from the 50 percent sold to the grid plus half of the emissions from the remaining energy used internally, or 25 percent, which totals 75 percent.

The boiler emits Hg for all the coal burned, whether the output is sold or used internally. EPA's proposed rule was formulated to be consistent with State implementation plan ( SIP) rules for NOx emissions under the provisions of the Acid Rain program and with the revised NOx emissions limits under subpart Da. 3 59 Comment:

One commenter ( OAR 2002 0056 2913) stated that the proposed output based limits should be modified to take into account the Hg emissions resulting from the combustion of fuel for co generating steam for uses other than electricity production.

Response:

The commenter implies that no emissions limit exists for fuel burned to produce steam not used for electricity sold to the grid. This assertion is incorrect. Emissions from fuel used for cogenerating steam are generated at the same time as those emissions resulting from fuel used for electricity generation. However, for purposes of determining the " output" from the unit, credit for the steam is given a 50 percent credit, versus 100 percent credit for electricity. As stated earlier, this policy is consistent with SIP rules for NOx emissions under the provisions of the Acid Rain program and with the revised NOx emissions limits under subpart Da.

3.2.5 Emissions Limit Averaging Period Comment:

Many commenters ( OAR 2002 0056 1803,  1969,  2067,  2365,  2535,  2634,  2661,  2721,  2827,  2867,  2900,  2918,  2922,  3403,  3432,  3444,  3463,  3478,  3509,  3513,  3514,  3539,  4891) supported EPA's proposal to determine compliance with emissions standards based on a 12 month averaging period. Reasons cited by the commenters included:

( 1) the large variability in coal Hg content. plant operations, and control technology performance;

( 2) Hg is not an acute health hazard and concerns about Hg arise from long term chronic exposure; and ( 3) the compliance period would provide greater certainty that units will consistently meet the limits, particularly given that operational and material related variability beyond the control of the owner/ operator can impact emission levels.

Response:

EPA concurs with this comment.

Comment:

Several commenters ( OAR 2002 0056 1969,  2260,  2721,  2830,  2835,  2850,  2918,  3449) supported using a 12 month averaging period but disagreed with using the proposed averaging method for computing the 12 month average based on averaging monthly average. Instead, the commenters recommended that the averaging method be revised to a simple average 3 60 of all valid hourly data from the previous 12 months. The commenters stated that this revision would equally weight all valid data over the 12 month period. The proposed rolling monthly average calculation method would place disproportionate weighting on hour values in months that include extended periods of lower loads, load following, or other operational variances.

Response:

To address the commenters' concerns, the final rule requires the 12 month rolling averages to be computed on a weighted basis. The rule requires valid Hg emissions data to be obtained for at least 75 percent of the unit operating hours in each month in which the unit operates. For each operating month, a monthly average Hg emission rate is calculated, which weights all of the hours of valid data equally. However, when the 12 month rolling average is calculated, each monthly average Hg emission rate is weighted according to the number of valid hours of data collected in that month. This ensures that the Hg emission rate for a month with few unit operating hours is not counted the same as the emission rate for a month in which the unit is in continuous operation. For any month in which less than 75 percent of the Hg emission data is captured, the rule requires a substitute Hg emission rate to be reported, and in the rolling average, the substitute emission rate is weighted according to the number of unit operating hours in that month.

Comment:

One commenter ( OAR 2002 0056 3210) objected to the 12 month average compliance determination because it further weakens the proposed standards. The purpose of the 12 month average is to adjust for variability in the process, fuel source, etc. However, variability is already overstated in the proposed emission limits resulting in many units being able to avoid controls. The 12 month average would be acceptable if the proposed standards were significantly more stringent.

Response:

EPA disagrees that the 12 month rolling average format weakens the standards. Further, as noted above, the new source emission limits have been revised which may also address the comment.

Comment:

Two commenters ( OAR 2002 0056 2835,  2922) noted that 40 CFR 60.50a( h)( 1), which covers calculation of mass Hg emissions from Hg CEMS and Method 324, calls for calculating the " arithmetic average of all weekly emission rates for [ Hg] for the 12 successive calendar months." Subsequent subsections refer to calculation of Hg mass emissions " over a month" from CEMS and over the " emission rate period" from Method 324. It is not clear why 40 CFR 60.50a( h)( 1) refers to calculation of weekly rates or how those rates fit into the more specific calculations. The EPA needs to correct this discrepancy. 3 61 Response:

Proposed Method 324 has been renamed as appendix K to 40 CFR part 75 and the method and regulatory text has been clarified.

Comment:

One commenter ( OAR 2002 0056 2889) stated that a correction is needed is 40 CFR 60.45a( a). This section refers to a 12 month rolling average and conflicts with 40 CFR 60.45( a)( 5) which refers to a monthly limit.

Response:

The commenter is correct in that the compliance monitoring period is based on a 12 month rolling average. However, in order to arrive at this average, monthly averages must be established on a continuous basis. Thus, EPA believes that 40 CFR 60.45( a)( 5) is correct as stated.

3.2.6 Emissions Averaging Comment:

Several commenters ( OAR 2002 0056 2634,  2830,  2835) requested that the EPA include facility wide averaging in the section 111 Emission Guidelines for existing sources as an additional compliance alternative. States should be encouraged to allow such flexible compliance alternatives if states decline to adopt a section 111 trading program, if that option is selected by the EPA. By including this type of flexibility mechanism, the EPA will ensure that those facilities located in States opting out of the trading program will retain some degree of flexibility when complying with the requirements of the Emission Guidelines. Similarly, facility wide emissions averaging provides a flexible compliance alternative to a cap and trade program in the event that neither cap and trade option can be authorized under the statute. Varying operational modes or combination of systems, e. g., wet/ dry scrubber, ESP or fabric filter, could be employed to provide the greatest potential to economically reduce Hg emissions to meet compliance requirements.

Response:

States and Tribes are free to allocate their Hg budgets as they see fit, whether they participate in the nationwide trading program or not, as long as the reductions are achieved from coal fired Utility Units. We believe that this will address the commenter's concerns.

Comment:

Several commenters ( OAR 2002 0056 2900,  3432) supported allowing facilities with both industrial boiler units and coal fired utility units to opt the industrial boiler units into the electric utility rule for purposes of meeting the emissions standard. The commenter believes a 3 62 final rule should allow affected facilities with both industrial boilers and coal fired utility units the compliance flexibility to meet one Hg emission limit through facility wide emissions averaging.

Response:

Industrial boilers that do not meet the definition of an " electric utility steam generating unit" under either 40 CFR part 60, subpart Da or HHHH will not be subject to the final rule. Therefore, facility wide emissions averaging between such units and Utility Units will not be allowed.

Comment:

One commenter ( OAR 2002 0056 2922) supported EPA's proposal to allow emissions averaging as a compliance option for two or more coal fired units, including blended coal units, that are located at a single contiguous. However, the commenter suggested the following clarifications to provide for smooth implementation of averaging plans. First, one situation under which sources might wish to utilize averaging is where two or more units utilize a common stack. Common stack monitoring is allowed under the general provisions as long as the " monitoring is sufficient to demonstrate compliance with the relevant standard." However, the proposed rules do not make clear under what provision such units should report and whether EPA expects sources to submit averaging plans for such units. The EPA should revise the rule to address that point.

One commenter ( OAR 2002 0056 3398) recommended extension of emissions averaging to all units under common control within a State to add flexibility.

Two commenters ( OAR 2002 0056 1608,  2922) recommended that a Multi Source Averaging Plan ( MAP) to meet the Hg emission standards be based on the existing CAA Title IV NOx program. Although this approach for Hg averaging would benefit larger utility systems, it is of far less benefit to small systems. Instead, it could be altered to allow averaging among different owners and operators. The CAA Title V permit program could serve to ensure multi source compliance after a MAP is approved by EPA. Additionally, the MAP approach could be extended across state lines as appropriate, as is done in the CAA Title IV NOx program.

Response:

EPA believes that the cap and trade approach being finalized will adequately address the comment.

3.3 VARIABILITY Comment EPA used a similar variability methodology to calculate the new source NSPS limits as it did to select the MACT floor limits; the only difference is that it did not apply the inter variability 3 63 analysis. Thus, several of the commenters' concerns also apply to the selection of new source NSPS limits.

Many commenters explained that EPA improperly used a short term worst case analysis to develop a long term standard ( 12 month rolling average). EPA chose the 12 month rolling average emission limit format and then applied the industry's variability method to account for coal composition. The EPA's own variability analysis explained that it was inappropriate to apply its variability analysis where a long term compliance period is allowed. Commenter OAR 2002 0056 2878 stated that, given the long term format, there is no need for the industry's variability analysis; the 12 month averaging time provides more than enough buffer to address the worst foreseeable circumstances.

Commenter OAR 2002 0056 3459 stated that although EPA acknowledged that one method for dealing with variability was the length of the compliance period, EPA did not assess that option. Instead, EPA added an annual averaging time on top of is inflated variability approach and attempted to justify this double counting by stating that Hg poses a chronic and not acute health risk. Whether or not this justification is warranted, EPA neglected the effect of using a long term standard on the stringency of the standard. And because EPA proposed to determine compliance using a long term average, the compliance status of the unit will be unaffected by short term fluctuations in the coal characteristics of coal shipments and control equipment.

Commenter OAR 2002 0056 2920 stated that EPA must specifically explain why the 12 month averaging period is necessary and appropriate.

After applying the industry's variability analysis, EPA calculated the emission rate over the full range of coal compositions presumed to be used and sorted those emissions to obtain a cumulative frequency distribution and selected limits based on the 97.5 percentile ( compared to the 95 percent in the WEST analysis). Many commenters ( e. g., OAR 2002 0056 2920) noted that EPA provided no rationale for selection of the 97.5 percentile. This violates the CAA, is inconsistent with EPA's own guidance and past practices, and improperly results in emission limits that are many times higher than appropriate or allowed under State permits. Commenter OAR 2002 0056 3459 recommended that EPA use the mean calculated emissions from annual coal data rather than the 97.5 percent upper confidence limit of the mean. The arithmetic mean is consistent with the 12 month rolling average and consistent with EPA policy.

Commenter OAR 2002 0056 3449 criticized EPA's failures to consider data on management of Hg variability from operating facilities.

Two commenters ( OAR 2002 0056 2920,  3449) criticized in detail EPA's equations based on coal Cl content. EPA has not established a valid statistical relationship between Hg removal and coal Cl content.

State ( e. g., OAR 2002 0056 2660,  2823,  2889,  3210,  3449) and environmental group ( e. g., OAR 2002 0056 3459) commenters asserted that EPA has not established a valid statistical relationship between Hg removal and coal Cl content. Analyses conducted by WEST and DOE 3 64 demonstrate that there is indeed a valid correlation, particularly with respect to units equipped with a fabric filter/ spray dryer combination. To the extent coal rank is indicative of Cl content, coal rank may be an important factor with respect to the Hg removal fraction as the New Jersey Department of Environmental Protection suggests. However, the New Jersey Department of Environmental Protection incorrectly asserts that EPA should have used raw data rather than average Cl concentrations to develop its Equation ( 5). EPA's approach properly relies on average values because they provide less uncertainty as compared to raw data alone.

Commenter OAR 2002 0056 5498 provided detailed supplemental comments that address criticisms of EPA/ DOE's variability analysis. Their comments explain why EPA's analysis is both consistent with the CAA as interpreted by the D. C. Circuit and scientifically sound.

One commenter ( OAR 2002 0056 2835) stated that the variability factors used by the EPA in the proposal are appropriate.

Response:

EPA continues to believe that accounting for variability is required in the establishment of national emission standards. However, EPA concurs with those commenters who indicated that we had overstated the variability by using both a rigorous statistical analysis and a 12 month rolling average for compliance. Our revised analysis of the data and new source selection procedures are described elsewhere in this document. We believe that this adequately addresses the variability.

3.4 COAL ANALYSIS Comment:

One commenter ( OAR 2002 0056 3546) stated that the proposed rule does not specify protocols for determining rank classification of the coal burned in a unit. The EPA needs to propose a methodology for establishing and reporting coal rank classification for determining which of the emission limits is applicable to a given unit. The commenter asked if coal ranks will be based on coal samples taken at the mine or upon delivery point at the power plant, and who is ultimately accountable for conducting the ASTM coal rank tests; the supplier or the power plant owner/ operator.

Response:

It is the owner/ operator that is ultimately responsible for compliance with the final rules. How he/ she chooses to comply, however, is not specified. EPA believes that facilities are currently contracting for a certain rank of coal with specific properties best suited for the given boiler and, thus, are well aware of the rank of coal being utilized. EPA believes that reliance on the ASTM coal rank classification scheme is appropriate for this rule as it is a commonly accepted means of ranking coals. 3 65 Comment:

One commenter ( OAR 2002 0056 1969) stated that the proposed rule does not specify fuel measurement/ sampling method required to determine the Btu input contributed by each coal rank. The commenter recommended that EPA should make it clear that sources can use procedures already in place at the source for recording fuel type and monitoring fuel consumption.

Response:

The final rule does not require fuel measurement or sampling. Further, there are no specifications for fuel consumption monitoring procedures so the facility may continue to use procedures already in place.

3.5 NOTIFICATION, RECORDKEEPING, AND REPORTING 3.5.1 Recordkeeping Comment:

One commenter ( OAR 2002 0056 3543) stated that regardless of the approach taken, the requirements for emissions testing and recordkeeping must be sufficient to provide data for development of TMDL. These requirements will provide a rich source of data and should not be weakened.

Response:

EPA has not weakened its monitoring or recordkeeping requirements.

Comment:

Several commenters ( OAR 2002 0056 2634,  2718,  2922) stated that the preamble indicates that sources will be required to maintain monthly records of types of fuel burned, total fuel usage, and fuel heating value, but these requirements do not appear in the proposed rule. EPA should add a provision for recording those values consistent with existing company practices.

Response:

EPA believes that the final rule addresses the commenter's concerns.

3.5.2 Notifications and Reporting Comment: 3 66 Several commenters ( OAR 2002 0056 2634,  2718,  2922) stated that section 63.10030( e) states that a " Notification of Compliance Status" must be submitted for each " performance test" or " initial compliance demonstration" as specified in section 63.10007. Section 63.10007, however, only covers performance testing for " oil fired" units. Initial compliance demonstrations for coal fired units are addressed in section 63.10009. If EPA intends a " Notification of Compliance Status" to be submitted by coal fired units following the first 12 month period, a reference to section 63.10009 should be added. If EPA does not intend for coal fired units to submit that notice, the reference to the " initial compliance demonstration" should be removed or clarified.

Several commenters ( OAR 2002 0056 2634,  2718,  2922) stated that section 63.10030( a) requires compliance with many notices in the general provisions, including the " Notification of Compliance Status" in section 63.9( h). That requirement is confusing given that section 63.10030( e) sets out requirements for " Notification of Compliance Status" that are narrower than those in section 63.9( h) ( e. g., section 63.10030( e) only requires compliance with section 63.9( h)( 2)( ii)). EPA should review these provisions and address the inconsistencies and overlapping requirements to better explain to sources what is required in each applicable notice or report. Section 63.10030( a) also requires compliance with section 63.6( h)( 4) and ( 5). However, according to Table 4, those provisions, which relate to opacity and visible emissions observations are not applicable. As a result, they should be removed from section 63.10030( a).

Response:

Part 60 does not have a requirement for a Notification of Compliance Status. The proposed amendments to subpart Da require for Hg and Ni emissions that the performance test data from the initial and subsequent performance test and from the performance evaluation of continuous monitors be submitted to the Administrator. Subpart Da also requires semiannual reports indicating whether: ( 1) The required continuous monitoring system calibration, span, and drift checks or other periodic audits have or have not been performed as specified. ( 2) The data used to show compliance was or was not obtained in accordance with approved methods and procedures of this part and is representative of plant performance. ( 3) The minimum data requirements have or have not been met: or, the minimum data requirements have not been met for errors that were unavoidable. ( 4) Compliance with the standards has or has not been achieved during the reporting period. Therefore, subpart Da with the proposed amendments would require that performance tests and semiannual compliance reports be submitted for both oil and coal fired units. Regarding the reference to the requirement to comply with section 63.6( h)( 4) and ( 5), 63.6 ( h) deals with compliance with opacity and visible emission standards. Section 60.48a in subpart Da with the proposed amendments does not have any compliance provisions for opacity and visible emission standards. Therefore this comment does not apply to the part 60 standards.

Comment:

Several commenters ( OAR 2002 0056 2634,  2718,  2922) stated that section 63.10009( d)( 4) requires reporting of the 12 month rolling average Hg emissions rate in the " first 3 67 semi annual compliance report." If the initial semi annual report will be submitted before 12 months of data have been collected, as section 63.10031 requires, it is not possible to report a 12 month rolling average. EPA should remove this requirement and clarify how and when results are to be reported ( e. g., first in the initial " Notification of Compliance Status" and thereafter in the next semi annual report).

Response:

This comment does apply to reporting of compliance with the Hg emission limit. Compliance cannot be determined until 12 months of data are available. This has been addressed in MACT standards with emission rates that are 12 month rolling averages, such as subpart SSSS ( the NESHAP for Surface Coating of Metal Coil, see 68 FR 12591, March 17, 2003 for correction notice) as follows for new affected sources: ( 1) The initial compliance period begins immediately upon start up or by ( data of publication of the final rule in the FR) and ends on the last day of the 12th month following the compliance date. If the compliance date falls on any day other than the first day of a month, then the initial compliance period extends through that month plus the next 12 months. ( 2) The first semiannual reporting period begins 1 day after the end of the initial compliance period described in ( 1) that applies to your affected source and ends 6 months later. Comment:

Several commenters ( OAR 2002 0056 2634,  2718,  2922) stated that table 2 in the proposed rule would require each coal fired unit subject to a limit in section 63.9990 must demonstrate " initial compliance" by establishing " a site specific [ Hg] limit according to the procedures in section 63.10009 and reporting the limit in your notification of compliance status." This articulation of the initial compliance demonstration is not consistent with the rules. Many units do not establish site specific limits, and it is not clear how simply reporting a limit establishes compliance. Section 63.10009 does not call for reporting of a limit, but rather calculation of a 12 month rolling average. Also, there is no requirement in section 63.10030( e), addressing " notification of compliance status," to report the applicable limit Response:

This does not apply to the proposed amendments to subpart Da. The Hg compliance provisions added as paragraph ( m) to Section 60.48a specify how Hg emissions will be calculated using data measured as specified in Section 60.49a. There is no mention of establishing a site specific Hg limit.

3.6 COMPLIANCE DATES Comment One commenter ( OAR 2002 0056 3449) disagreed with the EPA's preamble statement that overly ambitious Hg mandates in the near term could actually hamper innovation toward more cost effective and less costly technologies ( 69 FR 4687). It is more likely that EPA's 3 68 minimal reductions over the next decade would hamper innovation and improvement of public health. The sooner ACI with fabric filters or other control combinations are required, the sooner costs will drop. The costs are reasonably now and much less than the costs of Hg poisoning.

Response:

EPA stands by its position that Hg specific control technologies are not yet commercially available and that the regulatory approach being finalized is the best approach to both effect significant SO2, NOx, AND Hg emission reductions while also encouraging the further development of the emerging Hg specific technologies.

Comment:

One commenter ( OAR 2002 0056 1969) stated the concern that the monitoring and recording technology has not evolved to the level of reliability necessary to collect continuous Hg emissions data for compliance purposes and to report those results consistent with EPA's proposed requirements.

Response:

EPA believes that the monitoring and recording technology is available and reliable at this time sufficient to show compliance with the final emission limits. However, further developments are sure to ensue in the coming years such that the commenter's concerns will be alleviated.

Comment:

Several commenters ( OAR 2002 0056 2634,  2718,  2922) stated that under proposed compliance date provisions are confusing and conflicting. Under 40 CFR 63.9983( a) and 63.10008( d), new units must ( 1) install and operate monitors, and ( 2) comply with the " emissions limitations and work practice standards" upon the later of publication of the final rule, or startup. Under Section 63.10005, sources then have 180 days after the date for compliance with " emissions limitations and work practice standards" in Section 63.9983, to complete all performance tests, selection of operating parameters, and monitoring equipment performance evaluations. Under Section 63.9983( b) and 63.10008( d), existing units must ( 1) install and operate monitors, and ( 2) comply with " emissions limitations" by 3 years after the final rule is published. Section 63.10005 states that performance tests, operating limits and monitoring equipment performance evaluations also must be conducted by the compliance date in Section 63.9983 ( i. e., 3 years from publication of the final rule), but done so according to the applicable provisions in section 63.7( a)( 2), which ( unlike section 63.9983) allows 180 days from the compliance date for performance testing ( i. e., 3 years and 180 days after publication). For both new units and existing units, however, section 63.10009( d) states that " compliance monitoring" must begin on the " effective date of this subpart." For new units, the requirement to " comply" with " emissions limitations and work practice standards" on the date of publication of the final rule and 180 days before the deadline for performance testing, Section 63.10005 makes no sense. 3 69 Sources cannot be expected to comply without a performance test or monitoring system in place to establish compliance. For existing units, the rules also are in conflict as to whether an additional 180 days is allowed for performance testing, selection of operating parameters, and monitoring equipment performance evaluations. If the additional 180 days is provided, the deadline for compliance must also be extended. Moreover, for Hg, these provisions also fail to recognize that sources cannot establish compliance with the Hg emissions limitation until 12 months after the monitoring system evaluation has been completed and the required 12 months of compliance data have been collected. For both new and existing units, the requirement to begin " compliance monitoring" on the effective date of the rule, also makes no sense. It conflicts with the provisions in section 63.9983 establishing " publication" ( not the effective date) as the triggering point, ignores the fact that some new units may not even have started up, and ignores the additional 180 days that are supposed to be provided under section 63.10005. The EPA should follow the model in Part 75 and establish a deadline for applicability of the subpart and then a single deadline for installation, operation, and evaluation of monitoring systems and for performance testing and selection of operating parameters. For new units, the deadline for applicability of the rule would be the later of publication or unit startup. For existing units, the applicability date would be 3 years after the date of publication of the rule. The deadline for installation, operation, and certification of monitoring systems and for performance testing and selection of operating parameters ( i. e., the point when " compliance monitoring" is begun) would be 180 days later. The deadlines for establishing compliance with the Hg standard should be the end of the initial 12 month compliance period. At the time of the demonstration of compliance for the initial 12 month period, sources would be deemed to be in compliance for the prior 12 months. As a result, they would at that time have met the statutory deadline for compliance.

Response:

Although the commenters cited concerns with the proposed MACT standard, which is not being finalized, EPA believes that their concerns may also have been valid for the proposed subpart Da revisions. Section 60.8 Performance tests of the General Provisions to part 60 requires that within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of such facility... the owner or operator of such facility shall conduct performance test( s) and furnish the Administrator a written report of the results of such performance test( s). Therefore, a new facility has 180 days after initial startup or date of publication of the final rule to complete and report the results of the initial performance test. The timing of the initial compliance period and required reporting should be as follows: ( 1) The initial compliance period begins upon submitting the report of the initial performance test to the Administrator, but no later than 180 days after start up or ( data of publication of the final rule in the FR) and ends on the last day of the 12th month following the compliance date. If the compliance date falls on any day other than the first day of a month, then the initial compliance period extends through that month plus the next 12 months. ( 2) The first semiannual reporting period begins 1 day after the end of the initial compliance period described in ( 1) that applies to your affected source and ends 6 months later.


[Federal Register: November 9, 2007 (Volume 72, Number 217)]
[Notices]
[Page 63635-63636]
[DOCID:fr09no07-101]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-56739; File No. SR-NASDAQ-2007-082]

 Self-Regulatory Organizations; The NASDAQ Stock Market LLC;
Notice of Filing and Immediate Effectiveness of Proposed Rule Change
and Amendment No. 1 Thereto To Modify Fees for Members Using the Nasdaq
Market Center

November 2, 2007.
    Pursuant to section 19(b)(1) of the Securities Exchange Act of 1934
(``Act''),\1\ and Rule 19b-4 thereunder,\2\ notice is hereby given that
on October 1, 2007, The NASDAQ Stock Market LLC (``Nasdaq'' or
``Exchange''), filed with the Securities and Exchange Commission (the
``Commission'') the proposed rule change as described in Items I, II ,
and III below, which Items have been substantially prepared by the
Exchange. On October 31, 2007, Nasdaq filed Amendment No. 1 to the
proposed rule change. The Exchange filed the proposed rule change
pursuant to section 19(b)(3)(A) of the Act \3\ and Rule 19b-4(f)(2)
thereunder,\4\ which renders it effective upon filing with the
Commission. The Commission is publishing this notice to solicit
comments on the proposed rule change, as amended, from interested
persons.
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ 15 U.S.C. 78s(b)(3)(A).
    \4\ 17 CFR 240.19b-4(f)(2).
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I. Self-Regulatory Organization's Statement of the Terms of Substance
of the Proposed Rule Change

    Nasdaq proposes to modify pricing for Nasdaq members using the
Nasdaq Market Center. Nasdaq will implement this rule change on October
1, 2007.
    The text of the proposed rule change is available at Nasdaq, the
Commission's Public Reference Room, and http://www.nasdaq.complinet.com
.

II. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

    In its filing with the Commission, Nasdaq included statements
concerning the purpose of and basis for the proposed rule change and
discussed any comments it received on the proposed rule change. The
text of these statements may be examined at the places specified in
Item IV below. Nasdaq has prepared summaries, set forth in sections A,
B, and C below, of the most significant aspects of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

1. Purpose
    Effective October 1, 2007, Nasdaq is implementing a set of pricing
changes to its fees for routing to the New York Stock Exchange
(``NYSE'') that reflect recently announced changes to order execution
fees at that venue.\5\ The changes are designed to ensure that Nasdaq's
routing fees generally reflect the charges that Nasdaq Execution
Services, Nasdaq's routing broker, will incur when routing to NYSE,
with minimal markups or markdowns to reflect the value of Nasdaq's
services as a high-speed router and to provide incentives for firms to
enter orders that attempt to execute in Nasdaq for the full size of the
order prior to routing. Accordingly, Nasdaq's routing fees are being
decreased in instances where NYSE has lowered fees, and increased in
instances where NYSE has increased its fees. Specifically:
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    \5\ See Securities Exchange Act Release No. 56590 (October 1,
2007), 72 FR 57369 (October 9, 2007) (SR-NYSE-2007-88).
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     Nasdaq is eliminating the charge to route orders in
securities other than exchange-traded funds to the NYSE in instances
where the orders add liquidity on the NYSE, since NYSE is eliminating
charges for such orders.
     Nasdaq is increasing its fees to route other orders to
NYSE, to approximate NYSE's increased charge of $0.0008 per share for
orders that remove liquidity. As is currently true, Nasdaq's exact
charge varies depending on the overall volume of the member and the
exact characteristics of the routed order, but is generally within
$0.0001 of NYSE's charge. In addition, NYSE caps its execution fee at
$120 per trade, which translates to a cap on executions greater than
150,000 shares. Nasdaq does not apply a cap to its routing charges when
sending orders to the NYSE, because Nasdaq receives extremely few
executions for greater than 150,000 shares from the NYSE. Under the
revised pricing schedule, Nasdaq will charge:
    [cir] $0.00075 or $0.0008 per share executed for orders that
attempt to execute in Nasdaq for the full size of the order before
being routed, depending on whether the order is eligible to post
liquidity in Nasdaq or is designated only to remove liquidity before
routing;
    [cir] $0.0009 per share executed for Directed Intermarket Sweep
Orders and orders that attempt to execute solely against displayed
interest in Nasdaq before routing; and
    [cir] A variable charge of $0.0008 to $0.0009 for orders that do
not attempt to execute in Nasdaq before routing. For members with an
average daily volume in all securities during the month of more than 35
million shares of liquidity provided, the charge will be $0.0008; for
members with an average daily volume of more than 60 million shares of
liquidity routed to NYSE without attempting to execute in Nasdaq (other
than Directed Intermarket Sweep Orders), the charge will be $0.000825;
for members with an average daily volume in all securities of more than
20 million shares of liquidity provided, the charge will be $0.00085;
and for other members, the charge will be $0.0009.
    [cir] A fee of $0.0004 per share executed for an order that
executes in the NYSE opening or closing process as an ``at the
opening'', ``at the opening only'', ``market-at-the-close'', or
``limit-at-the-close'' order. Such orders receive a ``blended
execution'' rate at NYSE, reflecting the average between the $0.0008
charge to take liquidity and the $0 charge to add liquidity. Nasdaq
will pass this charge through directly.
    In addition to the foregoing changes, Nasdaq is also modifying fees
for routing orders to venues other than NYSE and the American Stock
Exchange (``Amex'') in circumstances where the orders do not attempt to
execute in Nasdaq for the full size of the order prior to routing.
Currently, Nasdaq charges $0.0035 per share for value-added orders that
attempt to execute only against displayed size or that are designated
as Directed Intermarket Sweep Order, and a slightly discounted fee of
$0.003 per share for other orders that do not check Nasdaq. Although
Nasdaq is retaining the discounted fee for orders routed to Amex and
for orders in exchange-traded funds (``ETFs'') routed to NYSE, Nasdaq
adopted the higher fee for orders routed to other venues. Nasdaq
believes that retaining

the discount for Amex and ETF orders routed to NYSE is warranted in
light of their historic status as primary listing markets and the
volume of ETF orders routed to them, but that a higher fee for other
orders that do not check the Nasdaq book is warranted in order to
encourage greater use of orders that do check the book. Finally, Nasdaq
is deleting several out-of-date references to fees in effect only
during the month of July 2007.\6\
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    \6\ All of the changes apply only to securities trading at $1
per share or more. All of Nasdaq's other fees, including its fees
for securities priced at less than $1, remain unchanged.
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2. Statutory Basis
    Nasdaq believes that the proposed rule change is consistent with
the provisions of section 6 of the Act,\7\ in general, and with section
6(b)(4) of the Act,\8\ in particular, in that it provides for the
equitable allocation of reasonable dues, fees and other charges among
members and issuers and other persons using any facility or system
which Nasdaq operates or controls. The change responds to fee changes
by NYSE effective on October 1, 2007, to ensure that Nasdaq's fees for
routing to NYSE are generally consistent with charges that NYSE imposes
on Nasdaq when it routes orders to it, and further clarifies incentives
of market participants to designate orders as eligible for execution on
Nasdaq prior to routing.
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    \7\ 15 U.S.C. 78f.
    \8\ 15 U.S.C. 78f(b)(4).
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B. Self Regulatory Organization's Statement on Burden on Competition

    The Exchange does not believe that the proposed rule change will
impose any burden on competition that is not necessary or appropriate
in furtherance of the purposes of the Act.

C. Self-Regulatory Organization's Statement on Comments on the Proposed
Rule Change Received From Members, Participants or Others

    Written comments on the proposed rule change were neither solicited
nor received.

III. Date of Effectiveness of the Proposed Rule Change and Timing for
Commission Action

    The foregoing proposed rule change is subject to section
19(b)(3)(A)(ii) of the Act \9\ and subparagraph (f)(2) of Rule 19b-4
thereunder \10\ because it establishes or changes a due, fee, or other
charge applicable only to a member imposed by a self-regulatory
organization. Accordingly, the proposal is effective upon Commission
receipt of the filing. At any time within 60 days of the filing of the
proposed rule change, the Commission may summarily abrogate such rule
change if it appears to the Commission that such action is necessary or
appropriate in the public interest, for the protection of investors, or
otherwise in furtherance of the purposes of the Act.\11\
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    \9\ 15 U.S.C. 78s(b)(3)(A)(ii).
    \10\ 17 CFR 240.19b-4(f)(2).
    \11\ For purposes of calculating the 60-day period within which
the Commission may summarily abrogate the proposed rule change under
section 19(b)(3)(C) of the Act, the Commission considers the period
to commence on October 31, 2007, the date on which Nasdaq filed
Amendment No. 1. See 15 U.S.C. 78s(b)(3)(C).
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IV. Solicitation of Comments

    Interested persons are invited to submit written data, views, and
arguments concerning the foregoing, including whether the proposed rule
change is consistent with the Act. Comments may be submitted by any of
the following methods:

Electronic Comments

     Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml.
 ); or     Send an e-mail to<EMAIL_ADDRESS>Please include

File Number SR-NASDAQ-2007-082 on the subject line.

Paper Comments

     Send paper comments in triplicate to Nancy M. Morris,
Secretary, Securities and Exchange Commission, 100 F Street, NE.,
Washington, DC 20549-1090.

All submissions should refer to File Number SR-NASDAQ-2007-082. This
file number should be included on the subject line if e-mail is used.
To help the Commission process and review your comments more
efficiently, please use only one method. The Commission will post all
comments on the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml
 ). Copies of the submission, all subsequent amendments,

all written statements with respect to the proposed rule change that
are filed with the Commission, and all written communications relating
to the proposed rule change between the Commission and any person,
other than those that may be withheld from the public in accordance
with the provisions of 5 U.S.C. 552, will be available for inspection
and copying in the Commission's Public Reference Room, 100 F Street,
NE., Washington, DC 20549, on official business days between the hours
of 10 a.m. and 3 p.m. Copies of such filing also will be available for
inspection and copying at the principal office of Nasdaq. All comments
received will be posted without change; the Commission does not edit
personal identifying information from submissions. You should submit
only information that you wish to make available publicly. All
submissions should refer to File Number SR-NASDAQ-2007-082 and should
be submitted on or before November 30, 2007.

    For the Commission, by the Division of Market Regulation,
pursuant to delegated authority.\12\
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    \12\ 17 CFR 200.30-3(a)(12).
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Florence E. Harmon,
Deputy Secretary.
[FR Doc. E7-21982 Filed 11-8-07; 8:45 am]

BILLING CODE 8011-01-P